petroleum geology of the south caspian basin

Petroleum Geology of the

South Caspian Basin

ii Contents

Petroleum Geology of the

South Caspian Basin

Leonid A. Buryakovsky

George V. Chilingar

Fred Aminzadeh

Boston Oxford Johannesburg Melbourne New Delhi Singapore

Gulf Professional Publishing is an imprint of Butterworth–Heinemann. Copyright © 2001 by Butterworth–Heinemann A member of the Reed Elsevier group All rights reserved. No part of this publication may be reproduced, stored in a retrieval system, or transmitted in any form or by any means, electronic, mechanical, photocopying, recording, or otherwise, without the prior written permission of the publisher. Recognizing the importance of preserving what has been written, Butterworth–Heinemann prints its books on acid-free paper whenever possible.

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Contents v

Dedication

This book is dedicated to His Highness, the Amir of Kuwait,Sheikh Jaber Al Ahmed Al Sabah, for His outstanding supportof the petroleum industry and personal concern He has demon-strated for the well being of His people.

vi Contents

Special Acknowledgment

We especially wish to acknowledge the outstanding helpof academician John O. Robertson Jr., Ph.D., in prepara-tion of the illustrations. The help extended by Michael V.Garfunkel, Essam Al-Ajeel, and Khaled Ben-Ameirah is alsogreatly appreciated.

CHAPTER 1

CH

Contribution No. 10, Rudolf W. GunnermanEnergy and Environment Laboratory,University of Southern California, Los Angeles, California

Contents vii

Contents

Foreword, x

Preface, xii

Nomenclature, xv

Abbreviations, xix

Structures of Azerbajan Part of the South Caspian Basin, xx

CHAPTER 1

Geology of Azerbaijan and theSouth Caspian Basin ..................................................111

General Overview, 1. Geologic Setting of Super-DeepDeposits, 5. Saatly Super Deep Well, SD-1, 9.

CHAPTER 2

Mud Volcanoes ........................................................... 116Yasamaly Valley, 18. Alyaty Ridge, 20.

CHAPTER 3

Regional Distribution of Oil and Gas ....................... 122

CHAPTER 4

Lithostratigraphic Framework .................................... 127

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CHAPTER 5

Onshore Oil and Gas Fields ...................................... 132Region I: Apsheron Peninsula, 32. Region II:Pre-Caspian–Kuba Monocline, 43. Region III: LowerKura Lowland, 44. Region IV: Yevlakh-Agdzhabedi Area, 44.

CHAPTER 6

Offshore Oil and Gas Fields ........................................ 52Caspian Sea Overview, 52. Zone I: Western Portionof Apsheron–Pre-Balkhan Anticlinal Trend, 57. Zone II:South Apsheron Offshore Area, 91. Zone III: BakuArchipelago, 101.

CHAPTER 7

General Regularities in Oil andGas Distribution ..........................................................113

I. Azerbaijan Portion of the South Caspian Basin, 113.II. Turkmenistan Portion of the South Caspian Basin, 199.III. Regions Adjacent to the South Caspian Basin, 212.

CHAPTER 8

Conclusions (Chapters 1–7) ...................................... 239

CHAPTER 9

Mathematical Models in Petroleum Geology ..........243Introduction, 243. Mathematical Simulation of GeologicSystems, 244.

CHAPTER 10

Mathematical Models in Oil and Gas Explorationand Production (Static Geologic Systems) .............. 248

Mapping of Structures within the Apsheron–Pre-BalkhanAnticline Trend, 248. Reservoir Characterization Using

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Log Data, 254. Modeling of Sedimentary Sequences Basedon Well-Logging Data, 284. Entropy as Criterion ofHeterogeneity of Rocks, 290. Anisotropy of Stratified Rocks,297. Permeability of Reservoir Rocks, 302. Surface Activity ofRocks, 313. Models of Oil Composition and Properties, 324.

CHAPTER 11

Mathematical Modeling of Geological Processes(Dynamic Geological Systems) .................................347

Methodology of Simulation of Dynamic Systems, 347.Mathematical Simulation of Sediment Compaction, 355.Numerical Simulation of Oil- and Gas-Bearing RockProperties, 365.

CHAPTER 12

Other Applications of Numerical SimulationMethodology ................................................................384

Basic Principles and Calculation Techniques, 384.Simulation of Reservoir-Rock Properties, 386. Simulationof Petrophysical Properties of Rocks, 390. Simulation ofWater Invasion into Oil-Saturated Rocks, 398. Simulationof Pore-Fluid (Formation) Pressure, 400. Simulation ofHydrocarbon Resources and Evaluation of Oil and GasReserves, 403.

CHAPTER 13

Conclusions (Chapters 8–13) .................................... 408

Bibliography ................................................................410

CHAPTER 1

VH

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Foreword

If the end of cold war is the biggest news of the century in terms ofworld politics, the unleashing of the wealth in terms of untapped oil andgas reservoirs in the Caspian Sea region is probably the biggest economicnews of the same century. Addressing the petroleum geology of SouthCaspian Basin at this crucial time of energy awareness shows unparalleledwisdom, experience, and maturity of the authors. The timing for such auseful book on a region that is considered to be the next Persian Gulfcould not be more appropriate.

The news of petroleum discoveries in the Caspian Sea region continueto pour in. Only a few months ago, the news broke about the possibilityof discovering 50 billion barrel in the Kashagan offshore structure. If thisis true, as all indications are, this latest discovery will put Kashaganstructure second to only Saudi Arabia’s onshore Ghawar field, withremaining reserve of 70 billion barrels. Incidentally, Saudi offshore,Safaniya, the world’s currently known largest offshore deposit contains19 billion barrels. The book provides one with a treasure of informationon the most studied section of the Caspian Sea region. The book is writtenwith a comprehensive approach that includes the development of scientificbases, simulation techniques, and mathematical models of both static anddynamic geological systems. This approach is necessary if one is interestedin exploration, development, and production of a petroleum reservoir. Thecombination of science and engineering has been sought for a long time,and the book provides one with a fine example of how one shouldapproach in developing oil and gas fields in the 21st century.

As the world order is moving from the Modern to the Knowledge Era,the petroleum industry is creating a culture that requires combining cuttingedge science with engineering into the core of decision making structure.This, in petroleum vocabulary, means that the petroleum industry mustcombine geological and geophysical skills with petroleum productionengineering. This book collects this information from the anal of 150 years

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of exploration and production history of the Caspian Sea region andpresents them in a format that is useful for both scientists and engineers.The book is helpful for determining oil and gas potential as well asoptimum production strategies in the region.

The book takes the reader through some of the most fundamentaldescription of geological history in the region, and embarks into theapplication of advanced mathematical models and engineering techniques.The authors do this with impeccable dexterity and provides the reader witha powerful interdisciplinary tool for exploration, reserve evaluation, andproduction optimization. The authors take a bold approach to educatingengineers on some of the essential aspects of geology and geophysics. Iam not aware of another book that amalgamates geology, geophysics, andpetroleum engineering with such a seamless approach. I recommend thisbook to every geologist, geophysicists, practicing engineer, graduatestudent, and academic who is engaged in petroleum studies.

Rafiq IslamKillam Chair in Oil and GasDalhousie UniversityCanada

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Preface

The Caspian Sea is a highly promising oil- and gas-bearing province,because prolific oil and natural gas regions situated in the territoriesof Russia, Kazakhstan, Azerbaijan, and Turkmenistan extend to theCaspian Sea area (Figure 1-1). The Caspian Sea is the world’s largestsalt lake—its length from the north to south is 1,174 km/730 mi.,average width is 326 km/203 mi, and total area is 375,000 km2/145,000 mi2. Water depth in the middle of the sea ranges up to788 m/2,584 ft and in the southern part, up to 1,025 m/3,361 ft.The Caspian Sea has no outlet, and although the surface level fluc-tuates, it averages about 25 m/82 ft below ocean level according torecent measurements.

Geological studies in the Caspian Sea began in the second half ofthe 19th century. The South Caspian Basin, which comprises the SouthCaspian Sea, Eastern Azerbaijan, and Western Turkmenistan, with ahigh density of confirmed structures, was studied in greatest detail.Hydrocarbon accumulations have been discovered, explored and producedin areas with water depth up to 60 m/200 ft, and several oil and gasfields have been discovered in water depth up to 200 m/655 ft.

Azerbaijan is one of the independent countries in western Asia,bounded on the south by Iran (Province of Iranian Azerbaijan), on thenorth by Russia, on the west by Georgia and Armenia, and on the eastby the Caspian Sea. The country consists mainly of lowlands sur-rounded by the Kura River and its tributary, the Araks, which formsthe border with Iranian Azerbaijan. The landscape ranges from semi-desert to mountains of the Greater and Lesser Caucasus. Azerbaijancovers an area of about 86,600 km2 or 33,400 mi2.

Azerbaijan is one of the oldest oil- and gas-producing provinces inthe world. For example, the oldest oil-field, the Kirmaku, has beenknown from ancient times as a place of primitive production of oil

xii

and asphalt. The earliest date of Kirmaku field production is about1834. The first deep oil well in Azerbaijan was drilled in the Bibieibatoilfield in 1848.

Recoverable reserves of this unique oil- and gas-bearing provinceinclude about 1,700 MMtons/12 Bbbl of oil and 1 Tm3/35 Tft3 ofnatural gas. The main oil- and gas-bearing section in Azerbaijan is theso-called clastic Productive Series of Middle Pliocene age. It includesabout 90% of all the identified hydrocarbon reserves of Azerbaijan andadjacent offshore area of the South Caspian Basin. During the last 20years, a new type of reservoir rocks has been discovered in theterritory of central and western Azerbaijan, mainly in the centralportion of the Kura Depression. Commercial oil and gas reserves arepresent in the fractured Upper Cretaceous volcanic rocks.

Extensive offshore development in Azerbaijan began in 1949. Sincethen, numerous oil and natural gas fields have produced about halftheir recoverable reserves. All fields are multi-bedded with as manyas 30 producing zones in the Middle Pliocene sandstones and silt-stones. Exploratory and production drilling is carried out from indi-vidual platforms and piers. Also, floating and semi-submersible drillingrigs are used for exploration. At present, exploration drilling in theCaspian Sea is carried out in water depth of 200 m/655 ft; the deepestwell was drilled to a depth of 6,500 m/21,311 ft. Azerbaijan’s ApsheronPeninsula and adjacent offshore area is now being developed undermulti-billion dollar contract with Western oil companies.

Turkmenistan is located in Central Asia and is the southernmost ofthe CIS countries. The Turkmenistan Republic is bordered by theCaspian Sea to the west, Iran and Afghanistan to the south, Kazakhstanto the north, and Uzbekistan to the northeast and east. Its territoryextends 1,100 km east-west and 650 km north-south and covers anarea of approximately 488,000 km2 or 188,200 mi2. The climate ofthe country is dry and 80% of its territory is desert. Water resourcesare distributed by canal and irrigation systems. The petroliferous areasinclude the eastern portion of South Caspian Basin and the Amu-Daryaoil- and gas-bearing provinces.

The presence of seeps and mud volcanoes first attracted attentionto the eastern part of South Caspian Basin at an early date. Oil wasbeing produced from 3500 hand-dug wells and seeps on ChelekenIsland by 1938. About 28 fields have been discovered to date inwestern Turkmenistan (onshore and offshore). More than 48 fields have

xiii

been discovered since the beginning of petroleum exploration in theAmu-Darya area in 1929.

After Russia, Turkmenistan is the second largest gas-producingrepublic. In 1990, the gas production was 3,100 Bft3. Oil productiondecreased 30% after 1980, but was stable (50 Mbbl/yr) during the lastfive years of 1980s.

In Western Turkmenistan, the most promising area is probably theshallow offshore. With water depths of 50 m/164 ft or less, explorationand production techniques developed in the Gulf Coast area of U.S.could be applied here, i.e., using drilling barges and dredges in veryshallow water and jack-up rigs in deeper water.

Progress in the oil- and gas-producing industry is related closely tothe improvement in exploration techniques and increase in discoveryrates. Exploration and production of hydrocarbon resources must bebased on reliable scientific information. During more than 150 yearsof oil and natural gas exploration and production in Azerbaijan, a greatamount of geological, geophysical, petrophysical, geochemical, andengineering information has been gathered. This information will aidin estimating oil and gas reserves as well as improving field develop-ment technology. We used advanced mathematical methods to processthe geological, geophysical, and engineering data, and our investigationincluded development of simulation techniques and construction ofmathematical models of both static and dynamic geologic systems(geologic processes).

Leonid A. BuryakovskyGeorge V. ChilingarFred Aminzadeh

xiv

NomenclatureA areaAda diffusion-adsorption factorAt absolute geological ageB “benzine” (gasoline) contentCcarb carbonate cement contentCcl clay cement contentCsh shale cement contentD depthd diameterdw wellbore diameterdact actual wellbore diameterdnom nominal wellbore diameterdch pore-channel diameterdp,ave average pore diameterdp,Me median pore diameterF formation resistivity factorFp,t formation resistivity factor at reservoir conditionsF’ resistivity indexF’p,t resistivity index at reservoir conditionsG geothermal gradient∆G Gibbs free-energy differenceH entropy of informationHmax maximum entropyHr relative entropyHo zero hypothesish thicknessheff effective (net) thicknesshsh shale thicknessI quantity of information∆Iγ relative GR factor∆Inγ relative NGR factor

xv

K filtration coefficientKa pressure-abnormality factork permeabilityk|| permeability parallel to beddingk⊥ permeability perpendicular to beddingki modeling coefficientL ligroin contentL lengthLc length of capillariesM mathematical expectancym number of parameters in the data matrixm cementation exponentN number of measurements, tests or observationsn number of objects in the data matrixn saturation exponentpi probabilityp pressurepe external pressure, total overburden pressurepi internal pressure, pore-fluid pressurepeff effective (grain-to-grain) pressurepp pore pressurepr reservoir pressure∆p differential pressureQ100 cation-exchange capacity per 100 g of rockq volumetric flowrateqliq liquid production rateqoil oil production rateR resins plus asphaltenes contentRd rate of sedimentationR electric resistivityRa apparent resistivityRa(AO) apparent resistivity from lateral sonde of AO sizeRcr oil-saturated reservoir rock cut-off (critical) resistivityRg,r gas-saturated reservoir rock resistivityRoil oil resistivityRo,r oil-saturated reservoir rock resistivityRsh shale resistivityRt true resistivityRt,min minimum true resistivity

xvi

Rw water resistivityRo water-saturated reservoir rock resistivityRm drilling-mud resistivityRmf mud-filtrate resistivityRIL resistivity from Induction Logr correlation coefficientr radiusrc radius of capillariesSo oil saturationSo/g oil/gas saturationSo,r residual oil saturationSw water saturationSw,r residual water saturationScarb homogeneity of carbonatesSsort sorting factorSsh sorting of shalesSss sorting of sandstonessb specific surface area of pore space per unit of bulk volumesg specific surface area of pore space per unit of grain volumesp specific surface area of pore space per unit of pore volumeshf shape factor for poresT temperature∆t interval transit timet timetα probability index @ α confidence levelU relative change in volume of sediments∆USP relative SP factorV volumeVc volume of capillariesVs seismic velocityvλ variation of anisotropyvR variation of resistivityα probability error or confidence levelαSP SP reduction factorβ modulus of elasticityβc irreversible compaction factor (compressibility factor)γ densityη relative clay content in rockηp pore-pressure gradient

xvii

ηsh pore-pressure gradient in shalesηr formation-pressure gradient in reservoir rocksλ anisotropy coefficientµ dynamic viscosityν kinematic viscosityσ stressσ standard deviation, or mean square errorσR standard deviation of resistivityσr standard deviation of correlation coefficientτ electrical tortuosity of pore channelsτw thickness of pore-water filmφ porosityφ′ “residual” porosityφeff effective porosityφsh shale porosityχsh relative content of shalesω frequency or probabilityΣω cumulative frequency or probabilityΣ macroscopic cross-section of thermal neutron capture (absorption)

xviii

AbbreviationsAHFP abnormally high formation pressurebbl barrelsBbbl billion barrels of oilBcfg billion cubic feet of gasbpd barrels per daybopd barrels of oil per daycfd cubic feet per daycmd cubic meters per dayFSU Former Soviet UnionGKZ State Committee on Reserves (in FSU)GOC gas-oil contactGOR gas/oil ratioGWC gas-water contactHC hydrocarbonsMbpd thousand barrels per dayMcfd thousand cubic feet per dayMcmd thousand cubic meters per dayMD measured depthMMcfd million cubic feet per dayMMcmd million cubic meters per dayMMt million tonsMSE mean square errorMtd thousand tons per dayOWC oil-water contactPTD proposed total depthSEM scanning electron microscopeTcf trillion cubic feetTcfg trillion cubic feet of gastpd tons per dayTD total depthTOC total organic carbonTVD true vertical depth

xix

Structures ofAzerbaijan Part of theSouth Caspian Basin

After declaring independence in 1991, many structures, oil and gasfields, and prospects in Azerbaijan were renamed. For reference, a listof old and new names of most oil and gas fields and prospects locatedin the Azerbaijan part of the South Caspian Basin is provided below.In this book, only new names are used.

Old names: New names:

26th Baku Commissars Azeri28th of April Gyuneshli40th Anniversary of Azerbaijan AshrafiAbramovich KarabakhAliyev Guba DenizAndreyev Bank UmidAndriyevski Bank GilavarEast Andriyevski Bank KhazriArtyom Island Pirallaghi AdasiArzu ArzuAsadov ZirvaBakhar BakharBorisov Bank InamBulla Island Khara ZyryaBulla-moré Bulla DenizByandovan-moré Byandovan DenizDarvin Bank Darvin BankDuvanny Island Zenbil

xx


East Apsheron Shargi AbsheronGalyaba GalyabaGolovachev Bank AtashkyakhGryazevaya Sopka Palchygh PilpilasiGyandzhlik GyandzhlikGyurgyany-moré Gyurgyan DenizKalmychkov Bank Shirvan DenizKamen’ Ignatiya DashliKamen’ Persiyanina Aran DenizKamni Dva Brata GoshadashKamni Grigorenko KhaliKaradag-moré Karadag DenizKaragedov Bank Mugan DenizKaverochkin ChyraghKhamamdag-moré Khamamdag DenizKornilov-Pavlov Bank SabailKumani Bank Chigil DenizKurinskiy Kamen’—1 KyurdashiKurinskiy Kamen’—2 Araz DenizKyurdakhany-moré Kyurdakhany DenizKyzylburun-moré Kyzylburun DenizLenkoran’-moré Lenkoran DenizMaiskaya AirapaMekhdi Gusein-zadeh UfugMidiya MidiyaNakhichevanskiy NakhchevaniNardaran-moré Nardaran DenizNeftechala-moré Neftechala DenizNeftyanyye Kamni Neft DashlaryNeftyanyye Kamni—2 OguzNorth Apsheron Shimali AbsheronPeschany Island Gum AdasiPeschany-moré Gum DenizPogorelaya Plita Yanan TavaPromezhutochnaya KyapazPutkaradze SabaSamedov Seiyar

xxi


Samed Vurgun VurgunSangachaly-Duvanny-Bulla Sangachal-Duvanny Deniz-Khara

Island ZyryaSangi Mugan’ Sangi MuganSevindzh SevindzhShakhovo-moré Shakh DenizShapirovskiy DanulduzuSouth Kurinskaya Talysh DenizSouth Shirvanskaya Lerik DenizSovetabad-moré Shorabad DenizTopkhana Sumgait DenizTsyurupa Bank Agburun DenizTyurkyany-moré Tyurkyan DenizUzeir Gadzhibayev PeikWest Apsheron Garbi AbsheronYakubov KhamdemYalama Khudat Shollar DenizYashma-moré Yashma DenizYuzhnaya DzhanubYuzhnaya—2 Dzhanub—2Zhiloi Island Chalov AdasiZorat-moré Dzhorat Deniz

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1

CHAPTER 1

Geology ofAzerbaijan and the

South Caspian BasinGENERAL OVERVIEW

The territory of Azerbaijan (Figure 1-1) is part of the Alpine foldbelt and consists of folded systems, embracing the eastern parts ofthe Greater and Lesser Caucasus Mountains, the Kura IntermontaneDepression (Kura Lowland) separating them, and also the Middle andSouth Caspian basins (Figure 1-2). Thickness of the Earth’s crust hereranges from 38 to 55 km. The greater thickness occurs within theGreater Caucasus, the lesser in the Talysh foothills. In the submontanebelt of the Lesser Caucasus crustal thickness reaches 40 to 45 km, and50 km in the Kura Intermontane Depression.

Peculiarities of the folded system of the Greater Caucasus includea flysch-filled trough at the southern slope of the Greater Caucasuswith an extensive development of overlying structures. Where isolated,Early Jurassic, shaly copper-pyrite deposits occur. Within the Kura Inter-montane Depression, Mesozoic-Early Paleogene and Late Paleogene-Quaternary structures are clearly distinguished. The first stage ofMesozoic volcanogenic-sedimentary rocks forms a single unit withinthe folded system of the Lesser Caucasus in the south and the Vandamzone in the north. Within the depression, a thick sequence of LatePaleogene-Quaternary deposits is widespread, unconformably overlyingthe lower structures. The Lesser Caucasus was a zone of volcanismduring the Mesozoic, Paleogene, Miocene-Pliocene and Quaternary,and is characterized, in the central part, by an extensive ophioliticbelt—the eastern portion of the North Anatolia Belt.

2 Petroleum Geology of the South Caspian Basin

Jurassic and Cretaceous deposits are widespread in Azerbaijan.Lower Jurassic deposits (thickness of 2,000 m and more) are widelydistributed in the Greater Caucasus and are represented by slate andsometimes by sandstone, with intrusive sheets of diabase and gabbro-diabase. In its analogous terrigenous facies, the Lower Jurassic is moresparsely represented in the Lesser Caucasus and the Nakhichevanregion. Apparently, within the Kura Depression, the Lower Jurassicdeposits occur as equivalent, thin terrigenous facies.

The lowermost Middle Jurassic strata of the Greater Caucasus arecomposed of argillaceous slates with rare partings of sandstone,

Figure 1-1. Caspian Sea Region (Modified after National Geographic Societymap, Washington, D.C., 1999).

Geology of Azerbaijan and the South Caspian Basin 3

whereas the uppermost section (2,500 to 4,000 m thick) is dominatedby thick strata and beds of quartz sandstones with rare partings ofshales. In the Lesser Caucasus, terrigenous rocks (thickness of 120 m)of the lowermost Middle Jurassic [the main part of the section (2,000–3,000 m thick)] consists of lava sheets and diabasic volcanics. Quartzplagio-porphyrites with their volcaniclastic and sedimentary-volcanogenicsequences occur in the uppermost strata. In the Kura Depression thesedeposits are represented by similar facies.

The Upper Jurassic deposits in the northern slope of the GreaterCaucasus are composed of calcarenites and reef limestones (thickness

Figure 1-2. Structural pattern of Azerbaijan (Modified after the ExcursionGuide-Book for Azerbaijan SSR, Vol. II, 1984). A—Greater Caucasus Anti-clinorium; B—Kura Intermontane Depression; C—Lesser Caucasus Anti-clinorium; D—South Caspian Basin; I—Gobustan-Apsheron Trough; II—LowerKura Trough; III—Geokchai-Saatly Anticlinal Trend; IV—Yevlakh-AgdzhabedyTrough; V—Iori-Adzhinour Trough. 1—Quaternary, 2—Miocene–Paleogene,3—Mesozoic, and 4—consolidated crust.


of 300 m), and in the southern slope by flysch-like variegated, silici-fied, and carbonaceous shales (thickness of 500 m). These deposits inthe Lesser Caucasus and in the Kura Depression consist of reeflimestone and volcanogenic-clastic intervals (500–1,500 m).

Lower Cretaceous deposits of the Greater Caucasus consist ofcarbonaceous-terrigenous flysch (thickness of 500–2,000 m), whereasin the Lesser Caucasus and Kura Depression they are represented bytuffaceous-terrigenous and carbonaceous intervals.

Upper Cretaceous deposits of the Greater Caucasus (thickness of2,000 m) consist of terrigenous-carbonaceous flysch facies. Within theLesser Caucasus their content is decreased and within the Kura Depres-sion it greatly increased.

The Paleogene, Neogene and Quaternary deposits are widespreadwithin the Kura and Araks depressions, Kusary sloping plain, Gobustanarea, Apsheron peninsula, Talysh foothills and in a number of residualand superimposed depressions of the Greater and Lesser Caucasus.These deposits of considerable thickness in depressions constitute themain reservoir rocks for oil and gas accumulations in Azerbaijan.Paleogene deposits in the depressions consist of green-gray, blockyshales with partings of sandstones and marls. The thickness of depositsis 300–400 m in the Pre-Caspian region, 1,700 m in the Apsheronpeninsula, and 2,800 m in the Shemakha-Gobustan region. Within theKura Depression, a thicker accumulation of more than 3,000 m ischaracteristic of the Paleogene deposits.

Neogene deposits in regions adjacent to the Greater Caucasus consistof sandy shale in the lowermost strata and of more shallow, thicksandstones and coquina in the uppermost strata. Thickness ranges from1,700 m (Pre-Caspian region) and 4,500 m (Apsheron peninsula) to5,500 m (Gobustan area).

Quaternary deposits consist of marine, continental, and volcanogenicfacies. The thickest accumulation is observed within the Lower Kurasubdepression (more than 1,500 m), where, in the lowermost strata,they are represented by shallow marine deposits, whereas the upper-most strata consist of alluvial and delluvial deposits.

The above Phanerozoic deposits are submerged within Middle andSouth Caspian basins located to the east and the southeast of theAzerbaijan land area. Within the South Caspian Basin these depositsare buried at great depth, and thickness of the Paleogene-Quaternaryinterval increases. According to geophysical data in the South Caspian


Basin adjacent to the Lower Kura subdepression, thickness of thePaleogene-Quaternary interval reaches 20 km.

The modern structure of Azerbaijan and the South Caspian Basinoriginated during the last stage of Alpine folding. This explains whystructures are parallel to ancient structural elements that predate thelatest movement. Currently, this is a region of active folding, diapir-ism, fracturing, seismicity, mud volcanism, geysers, and thermal springs.

The presence of Middle Pliocene terrigenous strata 2,500–3,500 mthick (the Productive Series) with oil and gas fields, and the wide-spread distribution of mud volcanism in the south-eastern Caucasusand in the offshore area of the South Caspian Basin, are distinctivefeatures of Azerbaijan geology.

GEOLOGICAL SETTING OF SUPER-DEEP DEPOSITS

The deepest deposits occur within the Kura Intermontane Depres-sion, which is located between mountainous uplifts of Greaterand Lesser Caucasus mega-anticlinoria. Structurally, it is a mega-synclinorium that originated during the orogenic stage of Caucasusdevelopment. By its abyssal structure, the Kura Depression is dividedinto Upper, Middle, and Lower Kura troughs or subdepressions whichdemonstrate different mobility. The Middle Kura Trough with an extentof 300 km embraces the area from Tbilisi, Georgia, to the meridianof Kyurdamir, Azerbaijan. A wide, buried uplift extends toward Vandamfrom the region of Talysh foothills to the north. The Lower KuraTrough extends from the western Caspian abyssal fracture, locatedalong the eastern slope of Talysh-Vandam uplift, to the western shoreof the Caspian Sea. These geological features are separated by faultsof the northwest extension (Figure 1-2).

The surface of the Middle Kura intermontane area is named the Mil-Mugan steppe and is composed of the Quaternary alluvial-deluvialdeposits 800-m thick. The first indication of abyssal structure wasrevealed as a gravity maximum by a survey conducted in 1929–1931.The first investigator, V. V. Fedynskiy, named this gravity maximumas Talysh-Vandam. Detailed investigations of Talysh-Vandam gravitymaximum were conducted by geologists and geophysicists of Azerbaijanwho noted that the Saatly uplift region in latitudinal section is a blockof shallow (about 8 km) “basalt” rocks with a velocity discontinuityof 6.7–6.8 km/sec. Different tectonic regimes caused a change in


folding characteristics of the Middle Kura Trough. During Caledonian-Hercynic stages the trough was a part of the Transcaucasus anticline(the Median Masiff). Within this trough, the uplift, erosion, andformation of separate basement fault blocks predominate. The mainstructural elements of the Middle Kura subdepression originated duringthe earliest Alpine stage. These are the Geokchai-Saatly (or Kyurdamir-Saatly) uplift, Iori-Adzhinour, and Yevlakh-Agdzhabedy troughs (Fig-ure 1-2). During the Liassic time, the region of the modern KuraDepression was occupied by a shallow sea where terrigenous sedimentsaccumulated. During Middle and Late Jurassic, a 5,000-m volcanogenicsequence accumulated as a result of intensive volcanic activity. Carbo-nate reefs grew in the Late Jurassic–Early Cretaceous time. A secondstage of volcanic activity occurred during the Late Cretaceous timewhen volcanogenic sequence accumulated in separate parts of theTalysh-Vandam gravity maximum. The end of Late Cretaceous ismarked by the accumulation of Campanian-Maastrichtian carbonatesediments. Sedimentation occurred in the Iori-Adzhinour, Yevlakh-Agdzhabedy, and Lower Kura troughs.

The beginning of Oligocene-Miocene orogenesis altered the pre-existinggeotectonic regime in the Kura Depression, and was dominated bywarping with molasse accumulation. The Geokchai-Saatly zone of theburied uplifts is characterized by an elevated basement surface inthe eastern part of Middle Kura Trough. The Saatly-Kyurdamir andMil-Khaldan subzones (blocks) occur within the Geokchai-Saatly zone.

The Saatly-Kyurdamir subzone includes Karadzhaly, Sor-Sor, Dzharly,and Saatly local uplifts, whereas the Mil-Khaldan subzone experiencedMuradkhanly, Zardob, and Mil uplifts.

It is hard to investigate Saatly-Kyurdamir buried uplift because thereare no natural outcrops, and Cenozoic molasse deposits, overlappingMesozoic sedimentary-volcanogenic strata, are very thick. Drillingon various parts of the uplift, however, has produced new data onMesozoic magmatism. It was ascertained that the Mesozoic stage ofuplift involved volcanogenic-sedimentary deposition with a volcanogenic-plutonic association.

Seismic, gravity and magnetic investigations of the Earth’s crustalong profile, which crosses the uplift in a latitudinal direction, showthat a velocity model of the crust based on reflected waves is ratherinformative. Seismic observations were conducted by vertical seismicsounding by reflected waves. Observations were conducted only along


the sublatitudinal profile that crosses the uplift area. As a result, a moredetailed velocity model was obtained (Figure 1-3). According to thesedata, a high-velocity layer [V > (6.7–6.8) km/sec] is expected at adepth of 9 km.

It became evident that the Saatly-Kyurdamir gravity maximum isexpressed as a nose of the most ancient (Pre-Baikal) complex (Figure1-4). The nose is overlapped by a magmatic sequence of basic andintermediate composition, mainly of Mesozoic age. Its roots penetratedeep into the mantle to the west where the Zardob magnetic maximumis present.

These investigations show the development of Mesozoic magmatitesas thick, highly-magnetic strata. To confirm these data, it was decided

Figure 1-3. Seismic density model along the line of deep seismic sounding(Modified after the Excursion Guide-Book for Azerbaijan SSR, Vol. II, 1984).(a) Observed and calculated plots of gravity field for section; (b) Seismicdensity model; Curves: 1—observed, 2—calculated, 3—Cenozoic sequence,4—Mesozoic sequence, 5—sequence G (velocity analogous to that in “granitic”layer), 6—sequence B (velocity analogous to that in “basalt” layer), dividedinto two sub-sequences: Bu and Bl, 7—sequence B1 (supposed peridotitecontent), 8—boundary of velocity (density), 9—unconformities, 10—deep wells.


to drill a super-deep well. It was expected that on reaching a depthof 9 km, the super-deep well would penetrate a volcanogenic section.Disturbed deposits, which are the source of the regional Talysh-Vandam gravity maximum, are expected lower. The authors supposethat as a whole, these are primarily sedimentary, metamorphosed, andconsolidated deposits of the Upper Archean-Lower Proterozoic age.

Figure 1-4. Geologic and geophysical model of Saatly-Kyurdamir anticlinaltrend (Modified after the Excursion Guide-Book for Azerbaijan SSR, Vol. II,1984). 1—Cenozoic sequence-terrigenous deposits; 2—Mesozoic sequence:a. terrigenous-carbonate deposits, b. extrusive formations of basic andintermediate composition; 3—Baikal sequence, metamorphozed primary terri-genous formations; 4—Pre-Baikal sequence, gneiss and marl; 5—the oldestinterval, gneiss and amphibolite; 6—intrusive formations of basic and inter-mediate composition; 7—undivided extrusive-intrusive interval; 8—low densityrocks, serpentinites; 9—rocks of intermediate composition between crustand mantle; 10—position of upper mantle top; 11—zones of large faults; 12—deep wells.


It is possible that between the Mesozoic magmatic strata and the Pre-Baikal basement, there may occur somewhat thin intermediate deposits,which cannot be identified by common techniques.

SAATLY SUPER DEEP WELL SD-1

The Saatly Super Deep well SD-1, with a proposed depth of 15,000m/49,212 ft, was located within the Middle Kura Intermontane Depres-sion (Kura Lowland), where the Kura and Araks rivers convergeand the Mil and Mugan steppes join (Figure 1-5). It is a region ofwarm semi-desert and dry steppes with an arid climate. The averageannual temperature is +10°C. Annual precipitation does not exceed200–300 mm.

From December 1971 to August 1974, a preliminary well was drilledto 6,240 m/20,472 ft. The well penetrated Cenozoic molasse, MesozoicCarboniferous deposits, and from 3,550 m/11,647 ft to bottom of thewell, volcanogenic strata.

The Saatly Super Deep well was designed in accordance with a “Studyof the Earth’s mineral resources and super-deep drilling” conductedby the State Committee on Science and Engineering. The main goalof this program was to study the Earth’s crust in the MediterraneanAlpine geosynclinal belt, including the following investigations:

1. A detailed study of solid, fluid and gaseous phases of the Earth’scrust and their changes with depth.

2. The study of the geologic nature of seismic boundaries and theestablishment of the reasons for crustal foliation by geophysicalparameters.

3. The study of peculiarities of endogenic geologic processes mani-fested in deep parts of the Earth’s crust, including the processof ore generation.

During the first stage of the investigations, while drilling the Saatlywell to 8,000 m/26,247 ft, the main goal was to penetrate the sedi-mentary and volcanogenic section at a site of minimum thickness,according to geophysical study conducted in the area of Saatly localuplift. This was done (a) to study its composition, structure, occur-rence, and oil content; (b) to study the conditions of generation anddistribution of ores in the lower part of sedimentary-volcanogenicstrata; (c) to penetrate granitic rocks, to study their interrelation with


sedimentary-volcanogenic formations; and (d) to develop and improvethe drilling technology and methods of geological and geophysicalinvestigations at great depth.

In this section the following stratigraphic units were penetrated(Figure 1-6):

Post-Pliocene (Quaternary) deposits (0–860 m) are represented by theirregular alternation of gray, thick-bedded clay; gray, unconsolidatedsiltstone; medium-grained and coarse-grained sandstone with gritinclusions; thin-bedded intervals with grit inclusions; and thin-bedded intervals of continental origin.

Apsheronian Stage (860–1,930 m) is represented lithologically byalternation of sandy, silty and clayey rocks in the upper portion of

Figure 1-5. Location of Saatly Super Deep Well SD-1. Distances: Baku toSaatly: 180 km (112 mi); Baku to Alyat: 72 km (45 mi); Alyat to Kazi-Magomed: 46 km (28 mi); Kazi-Magomed to Ali-Bairamly: 13 km (8 mi); Ali-Bairamly to Sabirabad: 38 km (24 mi); Sabirabad to Saatly: 12 km (7.5 mi).


the section and with gray clay separated by silty, sandy and limyinterlayers in the lower portion.

Akchagylian Stage (1,930–2,250 m) is composed of gray silty claywith rare and thin partings of polymictic siltstone.

Middle Pliocene (2,250–2,780 m) is represented by brown-gray siltyclay alternating with polymictic sandstone.

Figure 1-6. Stratigraphic section (from cores and logs) of Saatly Super DeepWell SD-1 (Modified after the Excursion Guide-Book for Azerbaijan SSR,Vol. I, 1984). Aleurites = siltstones.


Sarmatian Stage (2,780–2,830 m) is represented by alternation of thin-bedded sandy argillaceous rocks and carboniferous rocks, overlyingMesozoic carbonate.

Cretaceous—Late Jurassic (2,830–3,529 m) is represented by thealternation of thick (200 m), fractured, pelitomorphic, siliceousmetamorphosed limestone and volcanogenic intervals (5 and 54 m,respectively).

Jurassic (3,529–8,230 m) is represented by thick volcanogenic strata.

The main attention was paid to the composition, structure, physicalproperties, and geochemical attributes of volcanogenic rocks. Coresamples from volcanogenic strata, studied petrographically in detail,give an idea of structure, composition, facies, and rock deformationof volcanogenic strata.

Volcanic facies on the SD-1 log are represented by two groups:(a) volcanic and (b) volcaniclastic. Volcanic facies are represented bya large number of genetic types, among which the leading ones arelava flows and lava breccias. Among rocks of the volcaniclastic facies,lavaclastites and hyaloclastites are widespread. Pyroclastic rocks (tuffs,tuff breccias), which belong to the same group of facies, are character-ized by a variety of fragments, color, structure, and size. Volcanogenic-sedimentary facies in the section of Jurassic volcanogenic strata arerepresented by thin tuffs, tuffites, tufogene-sedimentary rocks (tuffsandstones, tuff siltstones). Intrusive units are represented only by non-abyssal (hypabyssal) facies, i.e., sills and dikes. In these strata, volcano-genic facies predominate over volcanic ones. The great thickness ofvolcanogenic strata testifies that the penetrated section is confined tothe center of volcanic activity, in the region where a continuous supplyof volcanic matter masks sedimentation.

According to petrographic data, volcanogenic strata changed frombasalt to rhyolite. Most rocks belong to the porphyritic facies, and onlya small group (dikes and sills) consists of aphyric basalt. In porphyriticrocks, plagioclase and magnetite are the main minerals. They arejoined by dark-colored minerals, i.e., pyroxene, amphibole, and olivine.The contents of plagioclase, monoclinic pyroxene, amphibole, andmagnetite in the main petrographic groups of rocks have been studied.

Porphyritic basalts and andesite-basalts are very similar to each otherin the content of all rock-forming minerals. Plagioclase is present inboth and its content is approximately equal to that of bytownite-


anorthite. Clinopyroxenes are represented by subcalcic ferrous augites,characteristic of geosynclinal sequences of normal alkalinity. It issupposed that hyperalkalinity, sometimes noted in these rocks, isallogenic. The presence of amphiboles in hornblende-andesite andzeolitic metasomatites shows the volcanic origin of replaced rocks.

The data obtained from chemical analyses prove the association ofvolcanics with basalts, andesite-basalts, andesites, andesite-dacites,dacites and rhyodacites. According to silica and alkaline oxide ratios(Na2O/K2O), basalts, andesite-basalts, andesites, and dacites belong tothe limestone-alkaline gradation. Basalts and andesite-basalts arecharacterized by a high content of aluminia and low content of silica.In general, the composition of basic rocks of volcanogenic stratacorresponds to that of the high-aluminiferous basalts of the andesite-basalt series.

Acid and intermediate rocks are characterized by a low alkalicontent. Na2O predominates over K2O. High content of Na2O both inthe basic and acidic volcanics is due to autometamorphism. Lowcontent of TiO2 and low content of Fe2O3+FeO point to thegeosynclinal nature of basalts. Analyzed rocks, on the whole, arecharacterized by the low content of SiO2, Fe2O3+FeO, MgO, TiO2, andK2O, and high content of Al2O3 and Na2O.

Volcanogenic rocks can be differentiated on the basis of certainstructural features. Rocks of the upper and middle parts of volcanogenicstrata are of geosynclinal andesite-basaltic type, analogous to the MiddleJurassic (Bathonian) sequence, occurring within the Lesser Caucasus.

Rocks of the lower part of the section cannot be determined before-hand because their lower boundary was not penetrated. As acidicvolcanics predominate in the section, the rocks can be identified assodic rhyolites. It is possible that at deeper horizons the volcanics ofbasic composition are present; then, the sequence can be identified asbasalt-andesite-rhyolitic, analogous to the Lower and Middle Jurassicsequence of the Lesser Caucasus.

All the rocks of volcanogenic strata are metamorphosed. Secondaryminerals replace volcanic glass and primary minerals, and also infillcavities and fractures. Metamorphic minerals form varied mineralassociations, among which are clay minerals, chlorite, calcite, chalce-dony, quartz, albite, zeolite (laumonite), hematite, leucoxene, sphene,prehnite, epidote, pumpellyite, and sulphides. Acidic rocks, whichcompose the lower part of the strata, are silicified and calcitized.


In the lower part of the section some secondary minerals as quartz,chalcedony, sericite, and epidote are added to chlorite and calcite. Withincrease in depth, the low-temperature zeolites are replaced by morehigh-temperature epidote and then by prehnite-pumpellyite (greenschiststage of metamorphism). A low-temperature calcite-chlorite is alsodeveloped. A geochemical trend of main chalco-lithophylic elementsin volcanics coincides with that in calcic-alkaline extrusive series ofisland arcs.

Geochemical regularities in distribution of rare elements in rocksof volcanogenic strata correspond to those in volcanics, originated inzones of island arcs. In the SD-1 well section, the degree of heliumpreservation in volcanics is lower than in terrigenous deposits of the sedi-mentary sequence. Geochemical analyses of gases dissolved in interstitialsolutions and/or adsorbed in the rocks, showed that the main componentsof gases emanating from volcanic rocks are carbonic-acid, nitric-carbonic-acid, and hydrocarbons. The main hydrocarbon gas is methane.

According to the results of gravity and magnetic surveys, the regionof the Talysh-Vandam gravity maximum is structurally heterogeneous.Different areas of maxima (anomalies of the second order) are ofdifferent origin in the Earth’s crust. In the subsurface structure of theSaatly-Kyurdamir maximum, the projection of Pre-Alpine basement isinterpreted as the complex of Upper Archean and Lower Acheansequences with allochtonous features. In the Alpine complex over-lapping basement, products of Mesozoic magmatism of basic andintermediate composition are developed.

During the second stage of drilling (below 8,000 m), it is expectedthat the SD-1 well will penetrate magmatic rocks of Mesozoic or olderage; below 10,000 m, the older basement metamorphic rocks areexpected. Saatly SD-1 well is one of the first wells which will pene-trate rocks of great depth and answer many questions.

Scientific and practical findings from the first stage of drilling theSD-1 well are the following:

1. The Earth’s crust section 8-km thick has been penetrated. Thissection is a standard not only for Saatly-Kyurdamir buried uplift,where commercial oil is produced from the volcanogenic strata,but also for the whole Alpine zone of the southern part of theTranscaucasus, where deposits of the most important commercialminerals are located.


2. The volcanogenic section penetrated by the well is 5,000-m thick,which contradicts the existing opinion that the sedimentary-volcanogenic section overlying the Saatly local uplift is thin.

3. Microfauna (radiolaria) present at a depth of 6,560 m in siliceoustuff siltstones point to the deep accumulation of volcanogenicmaterial of Jurassic age. This changes the existing opinion on thetectonic-magmatic evolution of the region reflecting the geosynclinalregime of the Transcaucasus Median Masiff development.

4. The results of petrochemical and geochemical study of thevolcanics and the distribution of rare elements in the depositsshow that they have been derived from calcic-alkali magma ofthe same source formed in island arc zones.

5. According to the prognosis, within the Kura Depre ssion thetemperature must rise by 2–2.5°C per hundred meters of depth.This prognosis was not confirmed. At a depth of 8 km, thetemperature reaches only 140°C. Such a low temperature at greatdepth is caused by low heat flow from the interior of the Earth’scrust due to tectonic-magmatic evolution of the region.


16

CHAPTER 2

Mud VolcanoesMud volcanism and magmatic volcanism are two varieties of tec-

tonic activity. As distinct from magmatic volcanism, mud volcanismoriginates and is manifested in sedimentary cover of the Earth’s crust.The tectonic nature of mud volcanism is associated with prolongedand steady development of subsiding zones, which are filled mainlywith thick series of sandy-clayey rocks enriched with liquid and gas.Volcanism in general and mud volcanism, in particular, are closelyassociated with plicative, disjunctive and injective dislocations. Areasof volcanic activity are responsible for the transfer of huge masses ofnot only fluids but also breccia-plastic rocks. Thus, mud volcanism isan indicator of, and powerful factor for, transfer, dispersion, andconcentration of rocks, liquids and gases, including oil and natural gas.

Eastern Azerbaijan and Western Turkmenistan with adjacent sub-merged areas of the Caspian Sea are classic regions of mud volcanoesof different morphological types which eject solid, liquid and gaseousproducts at the surface. Roots of mud volcanoes reach to depths of10–15 km and more (Mesozoic) in the Apsheron Peninsula, in theGobustan area, Kura lowland, offshore areas of Apsheron and Bakuarchipelagoes and Apsheron Threshold, which are important oil- andgas-producing regions.

The total area of mud volcanism in Eastern Azerbaijan is 16,000km2, including more than 200 mud volcanoes (Figure 2-1). Scientistsbelieve that there are 150 underwater mud volcanoes in the SouthernCaspian Sea and 9 mud-volcanic islands. It is ascertained that mudvolcanoes are confined to the most deformed portions of late geo-synclinal trend (i.e., to molasse troughs), to the periphery of foldedsystems (i.e., to foredeeps), periclinal troughs of active geosynclinalfolded regions, where thickness of sedimentary fill exceeds 10 km. Thefollowing factors are prerequisites for generation of mud volcanoes:anticlinal structure, dislocations with breaks of continuity, plasticclays, buried formation water, accumulation of hydrocarbon gases andabnormally-high formation pressure.

Mud Volcanoes 17

Figure 2-1. Locations of mud volcanoes in the eastern Azerbaijan (Modifiedafter the Excursion Guide-Book for Azerbaijan SSR, Vol. I, 1984). a—Anticlines, b—mud volcanoes, c—areas with mud cones, d—boundariesbetween regions. The main structural areas: I—Pre-Caspian monocline,II—Shemakha-Gobustan area, III—Lower Kura Depression, IV—ApsheronPeninsula, V—Baku Archipelago.


Mud-volcano gases consist of saturated and unsaturated hydro-carbons (99% of which is CH4), a small amount of heavy hydro-carbons, CO2, N2, and other inert components (helium, argon). Thechemical composition of gases varies between different regions.Isotopic analyses show that these gases originated mainly in sedi-mentary strata.

Salinity and trace elements (I, B, Br) indicate that water from mudvolcanoes is similar to the formation water of oil and gas fields.Alkaline water of sodium bicarbonate type predominates.

Oligocene-Miocene and Pliocene deposits are dominated by frag-mental products of mud volcanoes eruptions. About 90 minerals andmore than 30 trace elements are present in mud-volcanic breccia.These include: boron, mercury, manganese, barium, strontium, rubi-dium, and copper. Volcanic mud is used widely for medicinal purposesincluding treatment of arthrithis and rheumatism.

YASAMALY VALLEY

The offshore portion of the Dzheirankechmes Depression inthe Central Gobustan area is located south of Baku Trough. It wasfilled with sediments of the Productive Series, and Akchagylian andApsheronian deposits. A number of narrow and wide anticlinal trendsare revealed within this depression. Anticlines are faulted; the faultsare associated with wide zones of breccia, to which centers of mudvolcanoes are confined. Mud volcanoes are widely distributed withinthe Dzheirankechmes Depression, where they reach large size: Lokbatan,Akhtarma, Kushkhana, Kyzyltepe, Shongar, Sarynja, Gyulbakht, Pilpilya,Otmanbozdag, Greater Kyanizadag, Tourogai, etc.

The Lokbatan-Otmanbozdag group of volcanoes (Figure 2-2) islocated in the northwestern portion of the Dzheirankechmes Depres-sion, whereas Greater Kyanizadag and Tourogai are situated in thesouthwestern part of this depression, south of the DzheirankechmesRiver. There are two anticlinal uplifts: dome-shaped Tourogai andbrachyform Kyanizadag, which are composed of deposits of ProductiveSeries in the crestal areas. These anticlines are faulted, and mudvolcanoes are confined to faults.

Lokbatan Mud Volcano is situated within the southern part ofYasamaly Valley and coincides with the Lokbatan oil field (Figure2-3). Here, Pleistocene terraces are widespread, as well as limestones

Mud Volcanoes 19

of the Apsheronian Stage (Late Pliocene) and Middle Pliocene sand-stones and shales. The mud volcano is located on the anticlinal archand is a dome-shaped uplift (80 m) with two culminations on the top,with crater in-between. Mud volcanic breccia is 150-m thick andoccupies an area of 425 hectares.

Lokbatan is one of the largest and most active mud volcanoes inthe world. It holds a record for the number of eruptions: since 1828,there have been 18. The last one occurred in 1980. The most intensiveeruptions of this volcano occurred in 1887, 1935, 1954, 1972, and1977. During the eruption of October 1977, the volcano spewed 30MMm3 of natural gas and more than 150,000 m3 of mud-volcanicbreccia. Solid ejecta include oil-saturated terrigenous and carbonaterocks of the Paleogene-Miocene and Late Cretaceous age. Volcanicactivity has not greatly influenced reservoir pressure and oil pro-duction. For 50 years, more than 27 MMt of oil and 2 Bm3 of naturalgas have been produced from Lokbatan field. Thus, volcanic roots arevery deep.

Figure 2-2. Distribution of mud volcanoes in the Lokbatan-Karadag area.


Figure 2-3. Lokbatan Mud Volcano (Modified after the Excursion Guide-Bookfor Azerbaijan SSR, Vol. I, 1984). 1—Fault, 2—mud-volcanic breccia, 3—gas,4—oil.

ALYATY RIDGE

Alyaty Ridge, which is situated near the Pirsagat River, is the easterncontinuation of the large Adzhichai-Alyaty anticlinal trend. This trendcorresponds to the deep-seated thrust which separates the Shemakha-Gobustan synclinorium of the Greater Caucasus and Lower Kura Depres-sion. The Alyaty anticlinorium is asymmetric: its northwestern slope dips

Mud Volcanoes 21

toward the Dzheirankechmes River, whereas its southwestern slope isoverturned in some places. Within Alyaty Ridge, there are more than12 mud volcanoes. Their roots reach Cretaceous deposits and pointto the oil and gas occurrence at deeper intervals.

Dashgil Mud Volcano is located 2–2.5 km north of Alyaty railwaystation, which is situated 60 km southwest of Baku. The volcanic coneis a flat uplift elongated in east-west direction. Tectonically, it isconfined to latitudinal faults extending along the western periclinal axisof the Dashgil structure.

Dashgil is one of the active mud volcanoes in eastern Azerbaijan.It has erupted in 1882, 1902, 1908, 1926, and 1958. The area ofvolcanic breccia extends over 470 hectares, with an average thicknessof 55 m. The volume of breccia spewed by the volcano is about 260MMm3. Presently there are 50 active vents around the crater, inten-sively erupting mud, gas and water with an oil film. The height ofthe vent cones ranges from 0.5 to 2.5 m. The diameter of the crateris more than 200 m. At its southern part, there are outcrops of charredargillaceous rocks of the eruption of 1958. Among solid ejecta of thevolcano are oil-saturated Miocene carbonate rocks and sandstones ofthe Middle Pliocene age.

Gegerchin (Kirdag) Mud Volcano is located 5.6 km northwest ofAlyaty railway station. With the Dashgil volcano, it forms an archedtrend in a north-south direction. Vents spew mud, gas and water withan oil film. Among solid ejecta are fragments of limestones, marls andsandstones saturated with oil.

Koturdag Mud Volcano is located 4 km southwest of Alyatyrailway station, forming an isolated uplift. In the west it is separatedfrom the Airantekyan uplift by a depression in which the oil-saturatedMiddle Pliocene sands were deposited. Koturdag mud volcano, whicherupted in 1966 and 1969, is confined to the crestal part of theKoturdag uplift.

Airantekyan Mud Volcano is located 10 km northeast of Atbulakrailway station and morphologically is one of the Alyaty trend uplifts.The last eruptions occurred in 1964 and 1969, when temperature inthe crater reached 800–1,000°C. In the crater area there are 70 mudvents, which spewed mud, gas and water with an oil film. The areaof volcanic breccia extends over 805 hectares.


22

CHAPTER 3

Regional Distributionof Oil and Gas

Azerbaijan is one of the oldest oil- and gas-producing provinces notonly in the former Soviet Union but in the world. Oil and gas havebeen produced commercially for more than 150 years. Occurrences inAzerbaijan have been studied by numerous scientists, petroleumgeologists, geophysicists and engineers: Gubkin (1937), Mirchink(1939), Abramovich (1948), Potapov (1954), Khain (1954), Krems(1954), Akhmedov (1957), Putkaradze (1958), Melik-Pashayev (1959),Samedov (1959), Babazadeh (1960), Ovnatanov (1962), Alikhanov (1964),Samedov and Buryakovsky (1966), Bagir-zadeh and Buryakovsky (1974),Yusufzadeh (1979), Ali-zadeh et al. (1985), and Buryakovsky (1993b,1993c, 1993d).

The oil and gas areas and their potential are shown in Figure 3-1,whereas play distribution is presented in Figure 3-2.

The Apsheron Oil and Gas Region includes the Apsheron Penin-sula and adjacent offshore area up to the Kyapaz Field. MiddlePliocene deposits (the so-called Productive Series) consist of well-sorted quartz sands and sandstones, which have good porosity andpermeability, and are separated by impermeable shales. Although theProductive Series remains the main play, there is definite interest inclastic and carbonate reservoirs of the Cretaceous age.

Several fields have already been discovered in the Productive Serieswithin the northern part of the Baku Archipelago Oil and GasRegion. Further prospects occur in the Lower Productive Series andOligocene and Miocene sandstones. Exploration efforts, however, havebeen disappointing in the central part of the region. But both central

Regional Distribution of Oil and Gas 23

Fig

ure

3-1

.R

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Aze

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Fig

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.O

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Regional Distribution of Oil and Gas 25

and southern parts still have good reservoirs with seals and structuresthat remain to be tested. Also, active mud volcanoes occur here.

The Lower Kura Depression is classified as having a first-ordercategory of prospective oil and gas fields; however, many fields herehave been already depleted. The potential for new oil and gas accumu-lations lies in parts of the Productive Series at great depth.

On the northeast border of the Yevlakh-Agdzhabedi Depression,oil accumulations have been discovered in the Upper Cretaceousvolcanic rocks and in the Eocene deposits in Muradkhanly and Zardobfields. This has been the basis for the interest in the Upper Cretaceousclastics-carbonates section, although there is still great interest inEocene deposits.

The Kura-Iori Interfluve became a first-category potential regionafter discovery of Tarsdallyar field in 1983. The primary play here isthe Upper Cretaceous and Eocene clastics-carbonates section.

In the Pre-Caspian-Kuba Oil and Gas Region, the main targetsare the Siazan Monocline and adjacent Talabi-Kainardzha anticlinal trend.On the Siazan Monocline, commercial oil accumulations have been foundin the reservoirs of Late Cretaceous through Miocene age. The Oligocene-Miocene deposits are being tested in the Talabi-Kainardzha zone.

In the Shemakha-Gobustan Oil and Gas Region, there is a greatinterest in southern and central Gobustan. In southern Gobustan,commercial oil and gas accumulations have been found in the Oligocene-Miocene (Maikop Stage and Chokrak Formation) and in the MiddlePliocene (the Productive Series) rocks. Prospects here are buriedPaleogene-Miocene structures of the Dzheirankechmes Depression.Another play is the Upper Cretaceous carbonate section of central andsouthern Gobustan.

In the Gyandzha Oil and Gas Region, small oil accumulationshave been discovered in Paleogene-Miocene rocks. This region isassessed as having poor potential.

In the deep-water part of the South Caspian Basin, seismic surveyand deep drilling have disclosed several favorable structures (from theProductive Series).

In the Adzhinour Region, geological surveys have disclosed stronglydeformed local highs in Pliocene-Quaternary deposits. The Paleogene-Miocene and Cretaceous deposits offer good possibilities here. Geo-physical surveys, however, have not been encouraging for deep intervals.


The Dzhalilabad Area has a thick Paleogene-Neogene section,which consists of volcanic and clastic deposits. Strong oil and gasshows have been found in several parts of the Tumarkhanly-Germelintrend, where the Maikop and Chokrak formations are prospective.

Areas with unknown oil and gas prospects are (1) the Alazan-Agrichai and Araks downwraps, (2) the Dzharly-Saatly and Mil-Muganzones of buried Mesozoic volcanic deposits, and (3) the Nakhichevandepression. Regional geophysical surveys and appraisal drilling arerecommended for these areas.

27

CHAPTER 4

LithostratigraphicFramework

Past environmental conditions and the lithology within the geo-synclinal regions are responsible for physical and chemical propertiesof sedimentary rocks. Post-depositional alteration (diagenetic andepigenetic) of sediments is dependent upon a great number of factors.Discovery of commercial oil and gas accumulations, and reserve evalu-ation, require the investigation of both reservoir and caprock properties.

This is especially important for young sedimentary basins, whichare characterized by thick, rapidly accumulated sand, silt, and shalesequences. A vivid example is the South Caspian Basin, which isdistinguished by a diverse and unique set of characteristics:

1. An exceptionally high rate of sediment accumulation of up to 1.3km/MMy.

2. Thick sedimentary cover (up to 25 km) including up to 10 kmof Quaternary-Pliocene deposits.

3. Siliciclastic (sand-silt-shale) type of sediments.4. Abnormally high formation pressures averaging up to 1.8 times

greater than normal.5. Low heat flow and formation temperature: at a depth of about 6

km, the temperature is approximately 105–110°C.6. An inverted hydrochemical profile: with depth, calcium chloride

and magnesium chloride waters change to sodium bicarbonatewaters, i.e., water salinity decreases with depth.

7. Widespread mud volcanism.

The main oil- and gas-bearing formation within eastern Azerbaijanand the South Caspian Basin is the Middle Pliocene Productive Series.The rocks of this formation, where oil and gas accumulations occur,have been the most thoroughly studied. Thickness of the ProductiveSeries increases toward the central part of the South Caspian Basin


in the southerly and southeasterly direction, from an average of1,500 m in the Apsheron Peninsula to 3,150 m within the ApsheronArchipelago, to 4,150 m in the South Apsheron Offshore Zone, andto 4,400 m within the Baku Archipelago.

Sedimentary rocks of Pliocene age (Pontian Stage, Productive Series,Akchagylian and Apsheronian stages) have been extensively studied.Pontian sediments (Lower Pliocene) consist of thinly-bedded, deep-water, gray and dark-gray, unconsolidated, limy shales; sands arerare. Characteristic fossils are Paracypria loezyi Lal., Leptocytherepraebacuana Liv., Loxoconcha alata Schn., Loxoconcha eichwaldiLiv., and other Ostracoda, and embryonic Pelecypoda.

The lithology of the Productive Series (Middle Pliocene) has beenstudied from outcrop samples, and cores and logs from deep wells.These deposits are devoid of fauna and, as a consequence, theirstratigraphic position is determined by faunal characteristics of theunderlying Pontian Stage and overlying Akchagylian Stage. Sub-division of the Productive Series is generally based on lithologicalchanges resulting from cyclic deposition.

The Upper Pliocene, which includes Akchagylian and Apsheroniansections, conformably overlies the Middle Pliocene Productive Series.The Akchagylian Stage, 50–70-m thick, consists of gray to green-gray,laminated shales with thin interbeds of fine-grained sands and volcanicash. The 700-m thick Apsheronian Stage is subdivided into threesections. The top of the upper section consists of coquina and detritallimestones, whereas the base consists of alternating fine-grained anddense sandstones, shales and detrital limestones. The middle sectionis represented by dark-gray sandy shales with thin interbeds of fine-grained sands and coquina. The lower section consists of dense sandyshales with thin sand interbeds.

Quaternary old Caspian Sea deposits are represented by the BakuStage, which is composed of dark-gray clays with thin interbeds of redsands. Thickness reaches 600 m. Recent sediments include coquina-ooze formations, and local, coarse-grained sands.

The Productive Series is divided into lower and upper divisions, andinto several suites according to lithological composition, depending ontheir sand/shale ratio. The set of rocks includes sand, sandstone,siltstone, loam, shale, and chlidolites (unsorted sediments1 ) (Figure 4-1).

1Chlidolites or unsorted sediments consist of equal amount (i.e., 1/3 each) of sandgrains, feldspar grains, and various rock fragments.

Lithostratigraphic Framework 29

Figure 4-1. Stratigraphic section of the Productive Series.


The lower division consists of (from bottom upward) the follow-ing suites:

1. Kala (KaS)2. Podkirmaku (PK)3. Kirmaku (KS)4. Nadkirmaku Sandy (NKP)5. Nadkirmaku Shaly (NKG)

The upper division consists of the following suites:

1. “Pereryv” (“first break in deposition”)2. Balakhany3. Sabunchi4. Surakhany

The lithological characteristics of the enumerated suites and units arepresented below.

Lower Division

The Kala Suite, in the Apsheron Peninsula and Apsheron Archipelago,consists of sandstones, siltstones, shales, chlidolites, and sandy loams,primarily of gray color. Thicker layers of sandstones and siltstones areidentified at the base of the upper portion of the suite. In the BakuArchipelago, the Kala Suite primarily consists of shale with interbedsof sandstones and siltstones. The Podkirmaku Suite, in the ApsheronPeninsula and Apsheron Archipelago, consists mainly of sands, sand-stones, siltstones, and unsorted sediments with some shales. In theBaku Archipelago, sandstones also predominate in the PK suite,alternating with shales, argillaceous siltstones and sandstones. TheKirmaku Suite, in the Apsheron Peninsula and Apsheron Archipelago,consists predominantly of shales, with lesser amount of sandstones andsiltstones. In the Baku Archipelago, the KS suite consists of grayshales with interbeds of fine-grained sandstones, with their contentincreasing toward the base of the suite, as well as toward the southeast,in the direction of subsidence. The Nadkirmaku Sandy Suite, withinthe Apsheron Peninsula and Apsheron Archipelago, is distinguishedfrom the underlying KS suite by an increase in the content of sandy-silty deposits. In the Baku Archipelago and Lower Kura regionthis suite is named Unit VIII. The Nadkirmaku Shaly Suite consists

Lithostratigraphic Framework 31

primarily of shales, loams, and sandy loams, with some thin sandstoneand siltstone beds in the lower portion.

Upper Division

The “Pereryv” Suite is composed predominantly of unsorted rocks, withrare sandstone and siltstone interbeds. To the south (Baku Archipelago,where it is named Unit VII), the suite consists primarily of shale. Inthe basal portion it is represented by loamy sands, and in the middleportion, by chlidolites. The Balakhany Suite is made up of sandstones,siltstones, shales, chlidolites, loams, and loamy sands. In the Apsheronand Baku archipelagoes, silty sandstones predominate at the base ofthe suite. The Sabunchi Suite consists of siltstones, poorly sortedsandstones, and shales. Sandy intervals IV, III, and II are present inthe southern portion of the Apsheron Archipelago, whereas in the BakuArchipelago, units IV and III consist of siltstones, with their contentincreasing in Unit III and alternating with shales. The Surakhany Suiteis made up of silty shales, argillaceous siltstones, sandstones, unsortedrocks, and rare gypsum interbeds.


32

CHAPTER 5

Onshore Oil and GasFields

Four major oil- and gas-bearing regions (Figure 5-1) exist onshorein Azerbaijan:

I. Apsheron PeninsulaII. Pre-Caspian–Kuba Monocline

III. Lower Kura LowlandIV. Yevlakh-Agdzhabedi Area

REGION I: APSHERON PENINSULA

Oil- and gas-bearing zones in the Apsheron Peninsula are mainlyof Middle Pliocene (Productive Series), Upper Pliocene (ApsheronianStage), and Miocene (Diatom Suite, Chokrak Formation) ages. Themain oil- and gas-bearing and productive interval here is the Produc-tive Series, which is subdivided into two divisions. The Upper Pro-ductive Series (i.e., the upper division) includes the following suites(from top to bottom): Surakhany, Sabunchi, Balakhany, and “Pereryv”(the first break in deposition). The Lower Productive Series (i.e., thelower division) includes the following suites (from top to bottom):Nadkirmaku Glinistaya (Shaly)—NKG; Nadkirmaku Peschanaya (Sandy)—NKP; Kirmaku—KS; Podkirmaku—PK; and Kala—KaS. Oil andgas fields of the Apsheron Peninsula and Apsheron Archipelagoare multi-bedded (up to 40 oil-bearing units). Most of the oil re-serves occur in fields of the central part of the peninsula: Balakhany-Sabunchi-Ramany, Surakhany, Karachukhur, Zykh and Gum Deniz(Table 5-1). Toward the east and southeast (Buzovny-Mashtagi,Kala, Zyrya, and other oil fields) and toward the northwest and west(Binagady, Chakhnaglyar, Sulutepe, and other oil fields) of the centralpart of the peninsula, oil saturation increases in the Lower Productive

Onshore Oil and Gas Fields 33

Figure 5-1. Oil and gas regional distribution, and fields and prospects of Azerbaijanand the South Caspian Basin (Modified after the Excursion Guide-Book for AzerbaijanSSR, Vol. I, 1984). 1—Boundaries between oil- and gas-bearing regions, 2—boundariesbetween oil- and gas-bearing areas, 3—oil fields, 4—gas and gas-condensate fields;Oil- and gas-bearing areas: 5—high oil and gas content, 6—moderate oil and gascontent, 7—potential structure, 8—structure with low potential. Oil- and gas-bearingregions and areas (areas are shown in circlets): I—Apsheron-Gobustan region (areas:1—Apsheron, 2—Shemakha-Gobustan); II—Pre-Caspian–Kuba region; III—Kura region(areas: 3—Lower Kura, 4—Kyurdamir, 5—Gyandzha, 6—Adzhinour, 7—Kura-Ioriinterfluve, 8—Alazan-Agrichai, 9—Dzhalilabad, 10—Baku Archipelago); IV—Araks area.Fields: 1—Balakhany-Sabunchi-Ramany, 2—Surakhany, 3—Karachukhur-Zykh, 4—GumDeniz, 5—Gousany, 6—Kala, 7—Buzovny-Mashtagi, 8—Darvin Bank, 9—PirallaghiAdasi, 10—Gyurgyan Deniz, 11—Chalov Adasi, 12—Azi Aslanov, 13—PalchyghPilpilasi–Neft Dashlary, 14—Dzhanub, 15—Bakhar, 16—Binagady-Chakhnaglyar, 17—Sulutepe, 18—Yasamaly Valley, 19—Bibieibat, 20—Puta-Lokbatan, 21—Kyorgyoz-Kyzyltepe, 22—Karadag, 23—Shongar, 24—Umbaki, 25—Duvanny, 26—Dashgil, 27—Chondagar-Zorat, 28—Siazan-Nardaran, 29—Saadan, 30—Amirkhanly, 31—EasternZagly, 32—Zagly-Tengialty, 33—Kyurovdag, 34—Karabagly, 35—Khillin, 36—Neftechala,37—Kyursangya, 38—Mishovdag, 39—Kalmas, 40—Pirsagat, 41—Malyi Kharami,42—Kalamadyn, 43—Muradkhanly, 44—Kazanbulag, 45—Adzhidere, 46—Naftalan,47—Mirbashir, 48—Sangachal, 49—Duvanny Deniz, 50—Khara Zyrya, 51—Bulla Deniz,52—Garasu.


Tab

le 5

-1C

om

par

iso

n o

f O

il R

eser

ves

in t

he

Cen

tral

Ap

sher

on

Pen

insu

la F

ield

s

Ba

lakh

an

y-S

ab

un

chi-

Su

iteR

am

an

yS

ura

kha

ny

Ka

rach

ukh

ur

Zyk

hG

um

De

niz

Mill

ion

Mill

ion

Mill

ion

Mill

ion

Mill

ion

Ton

s%

Ton

s%

Ton

s%

Ton

s%

Ton

s%

Sur

akha

ny6.

31.

35.

84.

2—

——

——

—S

abun

chi

200.

140

.260

.043

.710

.221

.7—

——

—B

alak

hany

147.

529

.528

.220

.511

.324

.42.

117

.717

.334

.1“P

erer

yv”

0.2

——

——

——

——

—N

KG

1.2

0.2

1.9

1.3

0.2

0.5

——

——

NK

P13

.52.

75.

03.

70.

81.

6—

—0.

61.

2K

S54

.810

.87.

45.

44.

08.

60.

21.

57.

314

.4P

K76

.515

.328

.620

.916

.334

.99.

971

.221

.241

.7K

aS—

—0.

40.

33.

88.

31.

39.

64.

48.

6T

otal

500.

110

0 .3

137.

310

0 .3

46.6

100 .

313

.510

0 .3

50.8

100 .

3


Series and decreases in the Upper Productive Series. Oil accumulationsin the Diatom Suite are present in the west and southwest of thepeninsula (Binagady, Lokbatan, Kergyoz, and other fields).

Different traps are present in the Productive Series of the ApsheronPeninsula: structural (anticlinal and faulted), stratigraphic, and combi-nation traps. Terrigenous (siliciclastic) reservoir rocks consist of sand,sandstone, and siltstone separated by shale interbeds. Reservoir rocksare highly porous and permeable.

The Baku Trough is a synclinal structure located between theKarachukhur-Zykh anticline to the east and Bibieibat uplift to the west.Rocks in the trough consist mainly of shale and sand alternating withlimestone beds. The latter compose the upper part of the sectionforming a bench around the trough composed of Late Pliocene andPost-Pliocene deposits.

Kirmaku Oil Field is located in the central part of the ApsheronPeninsula, 15 km north of Baku, and between two large oil-bearingregions: the Balakhany-Sabunchi-Ramany group of oil fields to thesoutheast and the Binagady-Chakhnaglyar-Sulutepe group of oil fieldsto the southwest.

Three topographic features are distinguished in the area of KirmakuField: the Kirmaku Ridge, Binagady Height, and Bogboga Mud Volcano.The highest point is Kirmaku Mountain (104.7 m) located in thesouthern part of the Kirmaku Ridge. The surface of the mountain iscovered with many tar pits and shallow wells, which produced oil inthe past.

Structurally, Kirmaku Field has an asymmetric, box-like shape(Figures 5-2 and 5-3). Dips are 40–50° on the eastern flank, and 60–70° on the western flank; dips decrease to 25° toward the crest, andon the periphery of the structure they decrease to 10°. The axis ofstructure extends about 3 km, and the width of the structure is about400 m. The core consists of Paleogene and Neogene rocks.

The Kirmaku structure is made up of the Neogene rocks (ProductiveSeries of Middle Pliocene and Pontian Stage of Lower Pliocene). Thecrest consists of Pontian shale surrounded by the Podkirmaku Suiteof the Lower Productive Series. The structure consists mainly of theKirmaku Suite deposits characterized by a frequent alternation of shale,silt and sand. Recent and old Caspian Sea deposits rest unconformablyon older Neogene rocks exposed by erosion.


Many geologists have studied the field structure. As a rule, however,they used rock samples only from outcrops. Additional detailed study,including exploratory drilling, was needed for field development. Inthe 1950s, 62 exploratory wells were drilled in three phases withinthe field area (Figures 5-2 and 5-3). Most of the wells were cored,and a total of 1,039 core samples were recovered and analyzed.

The major productive interval, the Kirmaku Suite (KS), is repre-sented by alternating shale, very fine- to fine-grained, argillaceoussand, and silt of brown and gray color. Total thickness of the suiteranges from 250 to 260 m. The KS interval is the most consistent inthickness and lithology over the whole section of the Productive Series.Quantitatively, sand and silt content prevail over that of shale. TheKS section consists of 74% sand, sandstone and silt, and of 26% shaleand sandy-silty shale. Thickness of sand and shale beds varies between

Figure 5-2. Geologic map of Kirmaku Oil Field (Modified after Alibekovet al., 1964). 1—Lower Balakhany Suite, 2—“Pereryv” Suite, 3—NKG Suite,4—NKP Suite, 5—KS Suite, 6—PK Suite, 7—Pontian Stage.


Figure 5-3. Structural map and cross-section of Kirmaku Oil Field (Modifiedafter Alibekov et al., 1964). (a) Structural map on the top of Pontian Stage:1—well, 2—contour line on top of Pontian, 3—outcrops of Pontian rocks; (b)cross-section.


1–2 mm to 10–20 cm. Among sandy-shaly alternations one can observethicker interbeds of sand and shale up to 3–4 m. The number andthickness of sandy-silty beds are higher in the lower portion of thesection. Average porosity of reservoir rocks is 26%, and the carbonatecement content is 8–16%.

The underlying Podkirmaku Suite (PK) is the second oil-bearingformation penetrated by boreholes both in the crestal area of thestructure and on its flanks. The PK Suite is the thickest (about 40 m)in the southern plunged portion of the structure. Toward the crest,thickness decreases significantly. The PK section is made up ofmedium- to coarse-grained quartz sand with large quartz grains andunevenly shaped pebbles. Sand is gray and light-gray in color, whereaspebbles are black. The upper part of the PK section contains medium-and fine-grained sand with some thin shale interbeds. In the lower andmiddle parts, grain size increases and shale interbeds disappear. Withinthe PK section, particularly in the lower part, one can observe inter-beds of very dense and hard calcareous sandstone. Thickness of thissandstone ranges from 10–20 cm to 50 cm. Average porosity of thereservoir rocks is 26–28%; carbonate cement content is 12–15%.

Kirmaku Oil Field has long been known as the place of oldestproduction of oil and asphalt. The precise date of earliest Kirmaku OilField production is unknown, but accounts date back as early as 1834.

Initially, oil was produced from shallow pits in outcrops usingbailers. Later, shallow wells with timber-lined walls were dug. Thesewells were situated, mainly, on the eastern and southern slopes ofKirmaku Mountain, and to a considerably lower extent, on the westernslope. Depending on the location within the area and on the depthof productive formation, well depth varied greatly. Average depth was50–60 m; however, some were up to 190 m deep. Some wells werevery shallow: no more than 10–20 m deep.

In the past, Kirmaku Field oil and gas wells were produced atmaximum rates with rapid reservoir depletion. In some cases, flow perwell reached 11–13 tpd (80–90 bpd). Production rate, however, couldbe sustained only for 1–2 months, and then declined to 1.0–1.5 tpd.Such practice, at that time, was believed to be normal, and most wellstypically produced for several months and sometimes even for years.As production rate declined, wells were deepened to the next pro-ductive bed.


Peak monthly oil production reached 4,500–5,000 tons before 1914and World War I. The total number of wells (in and out of operation)reached 1,500. About 50 of them (the most productive) were operateduntil 1926. Digging of new wells was stopped in 1913, and wasprohibited from then on. Maximum potential production rate was 3–5 m3/day and was based on well tests. The longest oil column encounteredduring well testing was 60–70 m at a depth interval of 100–120 m.In other wells, the length of oil column was smaller and, in somecases, wells were dry. As a rule, the wells produced no water. Waterfirst appeared in 1914–1917 at the northern part of the eastern flank.

Oil was characterized by the following properties: density = 0.958–0.988 g/cm3, Engler viscosity at 45°C = 10–16. A lighter oil withdensity of 0.903 g/cm3 and Engler viscosity of 6.84 was produced inWell 41 from a depth of 90–101 m.

At present, Kirmaku Oil Field is virtually depleted of moveable oiland should be considered as a deposit of bituminous sands.

Field development by routine well drilling probably will be quiteineffective. The use of one of the enhanced oil recovery methods (e.g.,heat stimulation or injection of solvents) probably will not be effective,because the oil-saturated rocks are penetrated by many wells whichwill be very hard and expensive to seal.

Field development by mining appears to be a reasonable one.However, considering that the area has been produced for a long periodof time, the advantage of this method should be verified by diggingat least one experimental, sloped tunnel (with a drilling chamber) atthe base of productive formation, for drilling updip boreholes.

Pilot horizontal wells (164, 72, and 187-m long) were drilled at thebase of the southern slope of Kirmaku Mountain in 1956. The wellswere drilled using water as a drilling fluid, and completed withoutcasing. This project demonstrated a real possibility of producing oilfrom such wells. At the maximum penetration into productive forma-tion (2.0 m), one of the flowing wells has been producing at approxi-mately 5 m3/day of total liquids including 40–60 kg of oil per day.Initial production was 10–11 m3/day of total liquids and 80–110 kgof oil per day.

Using geological, analytical, and field data, one can conclude thatdrilling horizontal wells from the ground level is the most reasonabletechnique for secondary development of bituminous sands of Kirmaku


Oil Field. The advantage of this technique is due to: (1) absence ofthick overburden, (2) absence of large volumes of liquids, (3) possi-bility for development of bituminous sands, and (4) presence of highly-developed infrastructure.

Bibieibat Oil Field occurs on a brachianticlinal uplift strikingNNW-SSE. The first oil well was drilled here in 1848. The oil fieldwas developed in the early 1870s. The entire Productive Series sectionis oil bearing.

Pliocene-Quaternary deposits are present in this area. The depositsform an asymmetric fold with steep western (up to 50°) and gentleeastern (15–27°) flanks. The anticline is broken by numerous trans-verse faults and its crest was penetrated by a mud volcano (Figure 5-4).

Deposits of Apsheronian Stage (Late Pliocene) and Pleistocene occurin the uplifts adjacent to the Baku Trough to the north, northwest andwest. These deposits extend as a wide ridge in a north-south directionand infill the syncline separating Bibieibat and Shubany uplifts. Fartheraway, these deposits crop out along the eastern slope of YasamalyValley and plunge toward the Caspian Sea.

Yasamaly Valley is a monoclinal valley where beds on the rightand left margins dip in the same direction. The rocks are of Late andMiddle Pliocene age, and constitute the eastern flank of the Atashkyah-Shabandag diapiric fold to the west of the valley.

The road from Volchy Vorota (Wolf Gate) to the Eibat railwaystation crosses deposits of Apsheronian Stage (Late Pliocene). Over-lying Akchagylian deposits are “disguised” under recent valley sedi-ments. Farther, one can observe outcrops of the Upper ProductiveSeries, consisting of alternating shale, sand and sandstone. The YasamalyValley Productive Series deposits in the eastern flank contain oil fieldsdiscovered in 1938 and wedge out toward the fold crest due to itsdiapiric structure.

Atashkyah structure is confined to the ridge of the same name. Thestructure is eroded, strikes north-south, and Oligocene-Miocene andLower Pliocene deposits crop out in the core; they are bordered bythe Middle Pliocene deposits. The western flank of structure dipssteeply (45–65°), whereas the eastern flank may be vertical or evenoverturned. The brachyanticline is complicated by two major longitu-dinal faults of overthrust character. Oil occurs in the Productive Series.

Shabandag Oil Field is also located in Yasamaly Valley. The fieldwas discovered in 1945. It is confined to an ENE flank of Shabandag


brachyanticline, filled with Middle and Upper Pliocene deposits. Thecore of uplift, which is dislocated, has diapiric structure. The SW flankis steep (50–70°), but dips more gently away from the axis of structure(Figure 5-5). Oil occurs in the Lower Productive Series. On the easternflank of the Shabandag uplift, Diatom Suite deposits are also oil bearing.

The offshore portion of Dzheirankechmes Depression of the CentralGobustan is located southwest of the Baku Trough. It is filled with

Figure 5-4. Structural map (a) and cross-section (b) of Bibieibat Oil Field.Stratigraphy: N2prd—Productive Series, N2ak—Akchagylian Stage, N2ap—Apsheronian Stage.


sediments of the Productive Series of Akchagylian and Apsheronianage. A number of narrow and wide anticlinal trends occur within thisdepression. Anticlines are faulted and wide zones of tectonic brecciaare associated with fault zones, with mud volcanoes occurring at theircenters. One of them is Lokbatan Mud Volcano, which is situated 15km southwest of Baku.

Lokbatan Oil Field is located in the area of Lokbatan mud volcano.This field was discovered in 1932, when Well 62 blew out from UnitII of the Upper Productive Series (flow exceeded 1 Mtd or 7.3 Mbd).An oil gusher (up to 20 Mcmd or 706 Mcfd) blew out from Unit 4ain 1933, in Well 45 drilled in mud volcanic breccia 1,500 m east ofthe volcanic vent. The entire section of the Productive Series is oilbearing. There are 16 oil- and gas-saturated intervals.

The field is an asymmetric brachianticline trending latitudinally. Theeastern flank is steep (about 55°), whereas the northern one is gentle(30–40°). The Productive Series rocks crop out at the crest of anticline,and are more argillaceous in comparison with those of the Bibieibatand Shubany fields. The argillaceous Oligocene-Miocene section ispenetrated at the northern flank in Well 616. The anticline is compli-cated by a longitudinal fault (amplitude = 500 m), to which theLokbatan mud volcano is confined (Figure 2-3); the southern flank iselevated. The fault becomes a thrust fault to the east (Figure 5-6).

Figure 5-5. Geologic cross-section of Shabandag Oil Field. Stratigraphy:K—Cretaceous, P3—Oligocene, N1

1—Lower Miocene, N21—Lower Pliocene,

N22—Middle Pliocene, N2

3—Upper Pliocene.


Shemakha-Gobustan Area. In this area oil and gas occurs only inCretaceous, Paleogene, Miocene, and Pliocene deposits. Here, UmbakiOil Field is being produced; oil pools are confined to Maikop Suiteand Chokrak Formation. Also, Duvanny Gas Field is under production.

REGION II: PRE-CASPIAN–KUBA MONOCLINE

The Pre-Caspian–Kuba Monocline is situated along the northeasternslope of the southeastern termination of the Greater Caucasus meganti-clinorium (Figure 5-1). Here, the Siazan Monocline is oil and gas bearing.It is located on the northeastern overturned slope of Tengiz-Beshbarmak

Figure 5-6. Structural map (a) and cross-section (b) of Lokbatan Oil Field.


anticlinorium, complicated by the large Siazan fault. Most of the oiland gas occurs in the Upper Cretaceous, Paleogene and Lower Miocenedeposits (Chandagar-Zorat, Siazan-Nardaran, Saodan, Amirkhanly,Zagly-Zeiva fields).

REGION III: LOWER KURA LOWLAND

Region III includes Pirsagat-Khamamdag, Kalamadyn-Byandovan,and Kyurovdag-Neftechala anticlines, extending southeast into theCaspian Sea (see Figure 5-1). These anticlinal uplifts are complicatedby faults and mud volcanoes. Mainly, the Productive Series and somedeposits of Akchagylian and Apsheronian stages are oil bearing.

Oil and gas reservoirs are multi-bedded and most are confined tothe Upper Productive Series. Kyurdamir, Karabagly, Neftechala, Pirsagat,Kyursangya, Kalmas, and other oil fields are being produced now.Many uplifts are expressed as topographic highs caused by mud volcanoes.

REGION IV: YEVLAKH-AGDZHABEDI AREA

Region IV embraces lower portions of the Kura and Araks riversand is situated along the axis of Saatly-Kyurdamir uplift (Figure 5-1). Inthis area, several local uplifts were found by geophysical explorationand drilling. The rocks in this region comprise Pre-Upper Jurassic andLower Senonian intrusives of basic composition, Upper Jurassic—Lower Cretaceous carbonates (reef limestones), Upper Senonian carbo-nate rocks, and terrigenous rocks of Paleogene-Quaternary age. Com-mercial oil and gas accumulations are confined to the fractured UpperCretaceous igneous rocks and to the Eocene and Chokrak deposits(Muradkhanly Oil Field). The region is prospective for discovery ofnew oil and gas fields.

Muradkhanly Oil Field. Different types of reservoir rocks havebeen identified during the last 20 years in the territory of Central andWestern Azerbaijan (Figures 3-1 and 3-2). The most interesting reser-voir rocks are found at the Muradkhanly Oil Field in the center ofthe Kura Depression (Figure 5-7). Commercial oil reserves are asso-ciated with the fractured Upper Cretaceous volcanic rocks. Productivityof terrigenous, carbonate, and pyroclastic rocks of Eocene age is lowerthan the Upper Cretaceous. Small commercial oil reserves have alsobeen discovered in the Middle Miocene terrigenous-carbonate rocksof the Chokrak age.


Fractured volcanic rocks play an important role in creating reservoirsand traps for hydrocarbon accumulation. Reserve estimation in suchtraps requires sophisticated methods of studying reservoir rock proper-ties, such as density of fractures, specific surface area, width offractures, irreducible fluid saturation, pore space structure, porosity andpermeability (Kondrushkin and Buryakovsky, 1987, Abasov et al., 1997).

Logs from the Muradkhanly Oil Field show that an anticline ispresent above the volcanic rocks at a minimum depth of 3,000 m.Within the 4,200 m contour line, the overall field size is 15 × 11 km.The dips vary from 10 to 20°. The structure has two faults and, hence,is divided into three separate blocks (Figures 5-7 and 5-8). Oil reservesare concentrated in the crestal area (the first block) and at the westernflank of the structure (the second block).

The Upper Cretaceous section includes undisturbed volcanic rocks:pyroxene-andesite; biotite-, hornblende-, and pyroxene-trachyandesite;

Figure 5-7. Structural map on the top of volcanic rocks of Muradkhanly OilField. 1—Faults, 2—contour lines on top of volcanic rocks, 3—initial OWC.


porphyry and amygdaloidal basalts; and products of alteration due toweathering of volcanic rocks with admixture of clastic material (tuff-sandstones, tuff-breccia, and tuff-gritstone). Penetrated thickness ofsedimentary and volcanic rocks ranges from 3 to 1,952 m (Figure 5-9).Strata correlation in some sections is very difficult.

Reservoirs have been formed in the weathered volcanic rocks of theupper portion of the Upper Cretaceous section. Oil traps here wereformed by transgressive overlapping by Maikop shales in the shallow-est part, and by Eocene terrigenous-carbonate rocks on the westernflank. Porosity and permeability were measured at a depth of 450 to500 m from the top of volcanic rocks. Deeper intervals, i.e., from1,000 to 2,000 m (Wells 3 and 6), are dry or showed insignificant flowof water. The most productive zone is the upper section of volcanicrocks, 25–30-m thick. Here, one can observe uniform and extensivesecondary rock alterations and strong oil flow in most of the wells.The oil-saturated intervals are distributed from the top of volcanic

Figure 5-8. West-east cross-section of Muradkhanly Oil Field. 1—Volcanicrocks, 2—clay/shale, 3—alternation of sand, silt and shale, 4—marl, 5—topof the volcanic rocks, 6—boundaries between Chokrak and Eocene deposits,7—OWC in the volcanic reservoir, 8—oil reservoir, 9—zone of absence ofreservoir rocks in Eocene deposits. Stratigraphy: K2—Upper Cretaceous, P2—Eocene, P3—Oligocene, N1—Miocene, N2—Pliocene, Q—Quaternary.


Fig

ure

5-9

.Lo

g co

rrel

atio

n in

vol

cani

c ro

cks

of M

urad

khan

ly O

il F

ield

. 1—

Per

fora

tions

, 2—

slot

ted

stra

iner

, 3—

open

hole

, 4—

form

atio

n te

st,

5—co

re r

ecov

ery.


rocks to a depth of 10–50 m in some wells, and to a depth of 100 mand deeper in others. As shown in Figure 5-8, the bottom of oilaccumulation is located at different depths in different volcanic rocks.This means that there is no continuous and flat oil-water contact;instead, it has a wave-shaped form. The real oil-reservoir boundariesintersect the contour lines on the top of volcanic rocks, and oil ispresent in the secondary porosity of these rocks.

The reservoirs are characterized by non-uniform oil content, bothin lateral and vertical directions. Consequently, production rates varywithin wide limits, i.e., the initial oil production rate varies from 1 to30 tpd (7 to 220 bpd) in 48% of wells, from 30 to 100 tpd (220 to750 bpd) in 35% of wells, and more than 100 tpd (750 bpd) in 17%of wells. The maximum initial water production in most wells (58%)is 10 m3/day. The initial reservoir pressure and temperature are 55 MPaand 125°C, respectively. The initial reservoir pressure is higher thanthe bubble-point pressure by 40 MPa and higher than the normalhydrostatic pressure by 20 MPa. Gas content in oil is 30 m3/ton andthe average oil density is 0.880 g/cm3 under standard conditions. Theoil is paraffinic, with low sulfur content.

The porosity of volcanic rocks is of fracture-vuggy and intergranulartype. Large intergranular pores, vugs and fractures are present in thecore samples (Figure 5-10). Large pores are 1 mm (average) in diameter,whereas vugs have diameters of 2 cm (average). Microfractures, whichcontain mainly calcite and argillaceous cement, have widths of 0.1 mmand wider. Oil is present in large intergranular pores, vugs, andfractures. During drilling, lost circulation (up to 100 m3/day) and highoil flows (up to 500 tpd) in several wells suggest that there are longand wide fractures in the volcanic rocks.

Petrographic studies show that reservoir properties depend on thedegree of weathering of volcanic rocks. The formation of large poresand vugs is due to the plagioclase dissolution. Sometimes, whenplagioclase and other minerals are dissolved, microcaverns are formed.

Microfractures have been studied in 4 × 5-cm thin-sections. Micro-fracture porosity ranges from 0.04 to 0.004%, fracture permeabil-ity varies from 0.16 to 6.90 mD, and average density of fractures is0.30 cm/cm2.

Scanning Electron Microscope (SEM) micrographs show that the vol-canic rock texture depends on the original properties of the unweatheredrocks and subsequent weathering and alteration (Figure 5-11). Alteration


Figure 5-10. Oil-saturated core sample from the volcanic rocks of MuradkhanlyOil Field. Well No. 66, depth interval of 2,956–2,962 m (9,698–9,718 ft); andesite.

Figure 5-11. SEM microphotograph of the volcanic rock sample from Muradk-hanly Oil Field. Well No. 6, depth interval of 3,027–3,031 m (9,931–9,944ft); magnification = ×100.


of ash resulted in the formation of montmorillonite, chlorite and biotiteduring diagenesis and catagenesis. Matrix secondary pores range insize from 1 to 200 µm. These pores are often connected by irregularlycurved fractures, 10–600 µm long and 0.5–10 µm wide.

Mercury injection studies show that the volcanic rock matrix withinthe unproductive and/or low-productive sections contains up to 60–75% of small pores with radii less than 0.1 µm, i.e., subcapillary poreswhich are not involved in fluid migration. Diameters of pore channelsimportant for fluid movement are within the range of 0.25 to 6.3 µm.A power-law correlation between the pore channel diameter and matrix(intergranular) permeability is as follows:

k = 0.0525dch

2.85

where: k is permeability in mD, and dch is pore channel diameter in µm.The porosity of volcanic rocks studied in core samples by the

saturation method varies within a wide range (0.6 to 28%) and theaverage value is 13%. The intergranular permeability is low; it variesfrom 0 to 10 mD, with an average value of 1 mD. The unusualcombination of high porosity and very low permeability is due to thecomplex and non-uniform structure of the porous space. Finely porousrocks have complex pore structure and curved channels. The 0.1-µmsubcapillary pores are not involved in fluid migration. The secondarymatrix porosity includes pores (0.25 µm to 1 mm in size) and vugs(larger than 1 mm in size). Commonly, these pores and vugs are partlyfilled with kaolinite, illite, montmorillonite, ferro-oxides, and zeolites,some dispersed and highly swelling. Clay-mineral content (mainlyauthigenic clay minerals) in rocks is variable and can reach 40% ormore. The petrophysical study shows that if the content of highlydispersed clay is more than 40%, then the water saturation of rocksis almost 70% and even higher. Under these conditions, rocks are notconsidered to be productive.

Oil is present both in the rock matrix (pores and vugs) and in themicro- and macro-fractures. The intergranular matrix permeability isvery low, and the oil saturation of reservoir rocks is distributedunevenly. Oil is mainly produced from zones which have hydro-dynamic connections with the fracture systems. For quantitative evalu-ation of volcanic reservoirs, core samples from in-perimeter wells withoil production and out-perimeter wells without fluid flow were analyzed.


The two statistical distributions of porosity were compared, and theaverage porosity values were determined. The secondary porosity (φ1)(vugs and fractures) can be determined using the following formula:

φ1 = (φ

2 – φ

3) / (1 – φ

3)

where φ2 is the porosity within the productive zones in the inside-perimeter wells, and φ3 is the porosity within the unproductive (dry)zones in the outside-perimeter wells.

The average secondary porosity is 1.8%. Depth intervals with highporosity (the secondary pores, vugs, and fractures) were determinedusing log data (electrical, radioactive, sonic, and caliper) and well testdata. Thickness of these intervals can be considered as the effective(oil-bearing) reservoir thickness (net pay). These intervals have beenidentified using porosity determined from log data. Two porosity cut-offs were identified: (1) the lower limit: for impermeable, unproductiverocks, porosity is less than 7–8%; and (2) the upper limit: for rockswith content of highly-dispersed clay minerals higher than 40%. Theupper limit identifies water-bearing intervals, with the total porosityexceeding 20%. Electrical logs were used to estimate the intergranularporosity and initial oil saturation. Based on the log analysis, theoil saturation in fractures is about 100%, whereas, the oil saturationin the matrix is about 50%. Weighted average oil saturation of thewhole formation (including the secondary pores, vugs, and fractures) isabout 90%.

Gyandzha Area. Oil production in the Gyandzha area (includingKazanbulag, Adzhidere, Naftalan, and Mirbashir oil fields) is low andis confined to the Foraminiferal interval (Eocene) and Maikop Suite(Oligocene-Miocene).


52

CHAPTER 6

Offshore Oil andGas Fields

CASPIAN SEA REGION

The Caspian Sea is a highly promising oil- and gas-bearing regionbecause oil and gas provinces situated on the territory of Russia,Azerbaijan, Turkmenistan, and Kazakhstan expand to the Caspian Seaarea (Figure 6-1). The Caspian Sea is the world’s largest salt lake. Itslength from north to south is 1,174 km, average width is 326 km, andtotal area is 375,000 km2. Water depth in the middle of the CaspianSea ranges up to 788 m and in the southern part, up to 1,025 m. Ithas no outlet, and although the surface level of water fluctuates, itaverages about 25 m below sea level according to recent measure-ments. Total area of the FSU portion of the Caspian Sea is 322,000km2, including the shelf zone. To a depth of 200 m, the area is 240,000km2. The general overview of hydrocarbon potential of the CaspianSea area shows that in such a vast area almost no portion is withoutprospects for discovering oil and gas. About 150 prospective structureshave been discovered; however, some 350 structures may be present.More than 45% of the total offshore area has water depth less than50 m, and about 10% has water depth ranging from 50 to 100 m.About two-thirds of the Caspian Sea has water depth less than 200 m.

The basin is a part of the eastern portion of the Pre-Tethys Seawhich began to develop during the Early Paleogene time with Alpine-Himalayan orogenic movements. The area of Caspian Sea includesthree major geotectonic elements: Pre-Caspian region of the RussianPlatform to the north; Scythian-Turanian Epi-Hercynian Platform inthe middle portion of the sea; and Alpine geosynclinal zone to thesouth. Three distinct sub-basins (Northern, Middle and Southern) arerelated to these major structural elements.

Offshore Oil and Gas Fields 53

The South Caspian Basin, with its high number of confirmed struc-tures, is the most studied. The middle and northern basins have notbeen studied as well (Figure 6-2). Hydrocarbon accumulations havebeen discovered, explored and produced in areas with water depthup to 60 m, and five oil and gas fields have been discovered inwater depth up to 200 m. Hydrocarbon potential from 33 oil and gasfields is estimated at 10 Bt. Thirty-one of the fields are in the SouthCaspian Basin: 23 in Azerbaijan and eight in Turkmenistan. Two arein Kazakhstan in the north.

Figure 6-1. Caspian Sea area.


Figure 6-2. Oil and gas possibilities of the Caspian Sea area. 1—Highlyfavorable areas, 2—areas favorable for oil and gas discovery, 3—discoveredlocal structures, 4—oil and gas fields, 5—southern limit of areal extent ofsalt domes, 6—boundary between Pre-Paleozoic Russian Platform andEpihercynian Scynthian-Turanian Platform, 7—southern limit of EpihercynianScynthian-Turanian Platform, 8—Alpine mountain system.


At present, Caspian Sea exploration is carried out in offshore areasof Azerbaijan, Turkmenistan, Kazakhstan, and Russia. The main goalof deep exploration drilling in Azerbaijan and Turkmenistan portions ofthe Caspian Sea (Apsheron and Baku archipelagoes, western portionof Apsheron–Pre-Balkhan anticlinal trend, and eastern portion ofApsheron–Pre-Balkhan anticlinal trend) is to discover new oil and gasfields, and to deliniate those already discovered in the Middle Pliocenedeposits (Productive Series in Azerbaijan and Red-Bed Series inTurkmenistan). In Kazakhstan and Russian parts of the Caspian Sea,it is advisable to study the oil and gas potential in Mesozoic deposits.

At present, geological and geophysical investigation revealed morethan forty anticlinal structures within the western part of South CaspianBasin. Most are prospects for oil and gas. Darvin Bank, PirallaghiAdasi, Gyurgyan Deniz, Chalov Adasi, Dzhanub Bank, PalchyghPilpilasi, Neft Dashlary, Gyuneshli, Azeri, Gum Deniz, Bakhar,Sangachal–Duvanny Deniz–Khara Zyrya, Bulla Deniz, and other oiland gas fields are on production. Among them, Neft Dashlary, Bakhar,Sangachal–Duvanny Deniz–Khara Zyrya, and Bulla Deniz are thelargest fields. Exploration continues on more than 10 structures.

Intensive offshore development in Azerbaijan began in 1949. Sincethen, 23 fields have produced 12 MMt of oil and condensate, and 11Bm3 of gas, about half of their recoverable reserves. All fields aremulti-bedded with 3 to 30 producing zones in the Middle Pliocenesandstones and siltstones. More than 3,000 wells have been drilledfrom over 1,000 platforms.

In the Caspian Sea, exploratory drilling is carried out from individ-ual platforms. Until recently, platforms were built for 40 m waterdepths; at present, platforms can be installed in water depth of 110 mand more. Floating rigs are used for exploration. At present, 8 suchrigs are in operation. Five of them are self-lifting and can operate in70-m water depth and drill to a depth of 6,500 m. Also, three semi-submersible drilling rigs are operating on the Gyuneshli and Chyraghstructures in 165 m of water. At present, exploration drilling in theCaspian Sea is in water depth of 200 m, with the deepest well drilledto a depth of 6,500 m.

The South Caspian Basin is characterized by deep water on the westand shallow water on the east. It is separated from the Middle CaspianBasin by the Caucasus-Kopet-Dagh fault. The Apsheron–Pre-Balkhananticlinal trend extends NW-SE between Apsheron and Cheleken


peninsulas and forms a narrow topographic high on the seafloor. Allmajor fields in the area are located on this regional anticlinal trend(Figure 6-3).

There are three offshore oil- and gas-bearing zones in the Azerbaijanportion of the South Caspian Basin:

I. Western portion of Apsheron–Pre-Balkhan Anticlinal TrendII. South Apsheron Offshore Zone

III. Baku Archipelago

Figure 6-3. Location of structures on the Apsheron Threshold (Modified afterBagir-zadeh et al., 1974). A—Oil and gas fields; B—prospects: 1—Goshadash,2—Apsheron Bank, 3—Agburun Deniz, 4—Gilavar, 5—East Gilavar,6—Danulduzu, 7—Ashrafi, 8—Karabakh, 9—Mardakyan Deniz, 10—Darvin Bank,11—Pirallaghi Adasi (Northern Fold), 12—Pirallaghi Adasi (Southern Fold), 13—Gyurgyan Deniz, 14—Dzhanub, 15—Khali, 16—Chalov Adasi, 17—Azi Aslanov,18—Palchygh Pilpilasi, 19—Neft Dashlary, 20—Gyuneshli, 21—Chyragh, 22—Ushakov, 23—Azeri, 24—Kyapaz, 25—Shakh Deniz, 26—Gum Deniz, 27–Bakhar,28–Livanov-West, 29–Livanov-Center, 30–Livanov-East, 31—Barinov, 32—Gubkin(Western, Central, Eastern), 33—Zhdanov (Western, Eastern, Pre-ChelekenDome), 34—LAM, 35–Cheleken.


Two more zones are in the Turkmenistan portion of the SouthCaspian Basin:

IV. Eastern portion of Apsheron–Pre-Balkhan Anticlinal TrendV. Chikishlyar-Okarem Zone

The Deep Water Zone is located between these two portions of theSouth Caspian Basin.

ZONE I: WESTERN PORTION OF APSHERON–PRE-BALKHAN ANTICLINAL TREND(APSHERON ARCHIPELAGO AND THRESHOLD)

The main oil- and gas-bearing rocks of the Apsheron–Pre-Balkhananticlinal trend (the Apsheron Threshold) are of Middle Pliocene age(Productive Series). About 90% of all the identified hydrocarbonreserves of the South Caspian Sea are located here. According to foldingintensity and the occurrence of oil and gas fields, the Apsheron Thresholdis subdivided into two areas: western, i.e., Apsheron Archipelago, andeastern, i.e., Turkmenian Shelf (Figures 6-2 and 6-3). A conventionalline between them can be drawn along the far eastern pericline ofdeeply buried Kyapaz structure.

The region of the Apsheron Archipelago deserves special attentionas the location of large oil and gas fields: Darvin Bank, PirallaghiAdasi, Gyurgyan Deniz, Dzhanub Bank, Chalov Adasi, PalchyghPilpilasi, Neft Dashlary, Gyuneshli, Chyragh, Azeri and a number ofprospects. The Pirallaghi Adasi Field has been producing for about acentury, whereas the Gyuneshli, Chyragh, and Azeri fields werediscovered only recently.

Within the Apsheron Archipelago, three anticlinal trends have beenrecognized (system of the East Apsheron anticlinorium), including thefollowing structures (from northwest to southeast) (Figure 6-3):

1. Goshadash, Agburun Deniz, Apsheron Bank, Gilavar, Danulduzu,and Ashrafi.

2. Darvin Bank, Pirallaghi Adasi, Gyurgyan Deniz and Dzhanub.3. Khali, Chalov Adasi, Azi Aslanov, Palchygh Pilpilasi, Neft Dashlary,

Oguz, Gyuneshli, Chyragh, and Azeri.

All these anticlinal structures have been considerably eroded, andthe deposits of the Upper Productive Series have been subjected to


erosion. The larger longitudinal thrust faults, both in amount ofdisplacement and in extent, are located along the axis of the structures.Transverse faults, although of small amplitude, played an importantrole in the distribution of oil accumulations.

Quaternary and Neogene (Pliocene and Miocene) deposits constitutethe stratigraphic column of the Apsheron Archipelago. The ProductiveSeries of the Middle Pliocene consists of interbedded sandstones,siltstones and shales up to 3,000 m in thickness. It is subdivided onthe basis of the predominance of sandy or shaly sediments into theKala (KaS), Podkirmaku (PK), Kirmaku (KS), Nadkirmaku Sandy(NKP), and Nadkirmaku Shaly (NKG) suites in the Lower ProductiveSeries; “Pereryv”, Balakhany, Sabunchi, and Surakhany suites in theUpper Productive Series. Table 6-1 shows a comparison of the thick-nesses of individual suites at some offshore areas.

The oil potential of the Apsheron Archipelago structures is asso-ciated mainly with the Lower Productive Series, where the Podkirmakuand Kirmaku suites are the most productive in the area. The thicknessof Podkirmaku Suite decreases in the northern fields (Darvin Bank andPirallaghi Adasi) as a result of wedging-out of the basal strata, whereasfor the Kirmaku Suite there is a decrease in oil-saturated thickness(net pay) toward the southeast as the clay content increases. The KalaSuite is oil-saturated everywhere throughout its area of distribution;its absence in the Darvin Bank and Pirallaghi Adasi areas is explainedby the fact that during the time of deposition of the Kala Suitesediments, there were areas of erosion and removal of terrigenousmaterial. To the south, the thickness and oil saturation of the KalaSuite significantly increase. The Nadkirmaku Sandy Suite and also thebasal parts of the Nadkirmaku Shaly Suite are oil-bearing mainly inthe structures of the southeastern part of archipelago.

The Upper Productive Series deposits are present only at the NeftDashlary, Gyuneshli, Chyragh and Azeri oil fields, and at the Dzhanubgas and gas-condensate field, where the conditions were favorable fortheir preservation. In the remaining structures of archipelago, the rocksof Upper Productive Series have been significantly eroded and do notcontain commercial accumulations of hydrocarbons.

Among the enumerated fields, Neft Dashlary is a pioneer in thedevelopment of offshore oil and gas fields. Exploration for the NeftDashlary area and subsequent development marked the beginning ofexploration and development on other structures situated farther


Tab

le 6

-1C

om

par

iso

n o

f T

hic

knes

ses

of

Dif

fere

nt

Su

ites

in

th

e O

ffsh

ore

Are

as o

f A

psh

ero

n A

rch

ipel

ago

Ave

rage

Thi

ckne

ss i

n M

eter

s

Sui

teP

iral

lagh

i A

dasi

Gur

gyan

y D

eniz

Dzh

anub

Cha

lov

Ada

siN

eft

Das

hlar

yZ

yrya

Gum

Den

iz

Sur

akha

ny—

600

1,09

040

026

01,

350

1,20

0S

abun

chi

—39

11,

390

355

350

1,42

31,

440

Bal

akha

ny40

060

51,

655

400

370

1,70

21,

806

“Per

eryv

”10

017

51,

159

110

100

1,10

51,

120

NK

G17

512

51,

112

130

110

1,13

51,

120

NK

P14

014

81,

155

136

130

1,14

611

,64

KS

255

269

1,22

227

625

01,

250

1,26

2P

K18

014

81,

110

108

100

1,14

81,

120

KaS

—26

01,

355

270

320

1,25

01,

228


offshore. Consequently, a special attention is devoted to the historyof exploration and development of this oil field.

Neft Dashlary Oil Field

Location and History

Neft Dashlary Oil Field is situated in the western part of theApsheron Threshold (see Figure 6-3), which is a connecting linkbetween the southeastern end of the Greater Caucasus and the Pre-Balkhan zone of Western Turkmenistan uplifts. The Apsheron Thresholdis the northern bounding tectonic element of the South Caspian Basin,one of the most explored and promising zones of the Caspian Sea.

Neft Dashlary Oil Field is the easternmost structure exposed abovethe water surface along the submerged ridge of the Apsheron Threshold,and is situated 55 km southeast of Pirallaghy Adasi and 110 km eastof Baku (Figure 6-4). Communication with the shore is accomplishedusing helicopters and boats. The field is produced from the piers andindividual platforms. The piers extend in rows of parallel lines/branches to the individual platforms. Total length of the piers is morethan 200 km.

Neft Dashlary Field is situated in open water with depths of 15–25 m.The seafloor is composed of sandy-shaly rocks, with some densesandstones. Detrital deposits consist of sand and shells. Bottom relief

Figure 6-4. Location of the offshore Neft Dashlary Oil Field.


reflects bedrock structure and lithology. Boulders of well-cementedsandstones of the Productive Series are exposed above the watersurface. They are spread over an area of more than 12 km2; the lengthof the boulder exposure is about 6–7 km, whereas its width is 2–3km. Some boulders emerge 2–3 m above water level, whereas othersare seen only in rough waters. These exposures extend from northwestto southeast, flanking the crest of a big anticlinal structure. Sandstoneboulders continuously bleed oil and gas to the sea surface. Thismanifestation is so intense that in calm weather an oil film covers thewater surface, and the escaping gas creates a “boiling” appearance.Wind and waves carry oil to sandstone outcrops, the surfaces of whichare covered by an oil film. Because of the oil coating on these exposedrocks, this area is called Neft Dashlary or Oil Stones.

The main climatic features of the region is the prevailing strongwind from the north with an intensity of 5 to 9 points by Beaufortwind scale (Sheriff, 1984). Calm weather is not prevalent more than30–35 days per year. Maximum wave height is 11–16 m, whereas thewave intensity during 75–80 days per year exceeds 5 points by theDouglas sea-state scale (Sheriff, 1984).

The earliest published geological report on Neft Dashlary Oil Fieldwas written by the noted academician G. V. Abikh (1863), who describedthe area as “a small archipelago of underwater stones and boulders.”He also discussed hydrocarbon gases and oil seeps.

G. Sögren (1892) and N. A. Lebedev (1902) also provided descrip-tions of tectonics and stratigraphy of the Neft Dashlary area. Later,the geological structure of the area was considered by S. A. Kovalevskiy(1926), S. M. Apresov (1933) and M. F. Mirchink (1939). In 1945–1949, the Azerbaijan Oil Survey of the Academy of Sciences of theUSSR under the leadership of A. K. Aliyev investigated the NeftDashlary area. A preliminary geological map of the area was compiledalong with a plan for exploration of the region.

In August 1949, exploration began in the Neft Dashlary area. Thefirst well, which was drilled in November 1949, flowed oil at 100 tpd(7,300 bpd) from the Productive Series through a 5 mm choke at awellhead pressure of 7 MPa. The rate of exploration drilling increased;it was ascertained that the whole sequence of the Productive Seriescontained commercial oil and gas accumulations.

The first well was rigged up in a short period of time on the largestoutcrop projecting above sea level. A small house with a radio station,


providing contact with the shore, was built for the drilling crew onpiles sunk into the seafloor. The crew was led by toolpusher M. P.Kaverochkin. Drilling was carried out under very difficult conditions,with severe storms and strong winds.

The second well in the Neft Dashlary area was constructed on aplatform of “MOS” type designed by A. A. Mezhlumov, S. A. Orudzhevand Yu. A. Safarov in 1949. A young toolpusher, K. A. Abasov, wascharged with drilling this well.

To allow access to greater water depths, seven old ships were movedonto the inhospitable and dangerous “Black Rocks,” placed in asemicircle, and sunk in shallow water. They formed an artificial islandwhich was called “The Island of Seven Ships.” Mechanical workshops,storehouse and an office were built on the ships’ decks, whereas cabinswere used for crew housing and canteen. It was decided to connectthe rock outcrops with each other to form an artificial island in theopen sea. For the first time in the USSR, tens of meters of piers spreadfrom this island far into the open sea. They were constructed byB. A. Roginskiy, A. Asan-Nuri, N. S. Timofeyev and other specialists.The subsequent long-term offshore field development (pier method)under extreme hydrometeorological conditions proved to be successfulin water depths of 10-40 m. On February 18, 1951, the first oil tankerleft the open-water moorage of a new town built in the open sea(Samedov, 1959).

Today, this first attempt at Caspian offshore oilfield production hasdeveloped into a complex of hydrotechnical installations spreadingover 200 km. All necessary conditions for work and recreation havebeen provided for offshore oilmen. There, one can see a residentialdevelopment, Palace of Culture, shops, hospital, cinema, etc. Anautonomous power station, also erected offshore, provides the powersupply for field facilities and the town. At present, “The Island ofSeven Ships” has been transformed into a five-story apartment hotelwith swimming pool, compressor station, etc. (Yusufzadeh, 1979).

Geology

Since the beginning of exploration, more than 1,000 exploratory,producing and injection wells have been drilled in the Neft Dashlaryoilfield area. The oil production was first obtained from the south-western flank and then from the southeastern flank of anticline.Geology of the field is now known in detail.


The stratigraphic sequence in the anticlinal structure of Neft DashlaryField was studied from Koun (Eocene) to Apsheronian (Upper Pliocene)deposits. Outcrops of the Productive Series rocks, bordering a narrowband of Akchagylian and Apsheronian stages (Upper Pliocene), werepresent at the core of the structure.

Tectonically, the field is a large brachyanticline, trending northwestto southeast (Figure 6-5a). The structure extends northwest-ward to asaddle separating this structure from Palchygh Pilpilasi Oil Field. TheNeft Dashlary structure is asymmetrical: the southwestern flank dips35–40°, whereas the northeastern flank dips 45–50° (Figure 6-5b). Thestructure is cut by transverse and longitudinal faults which cross theentire Productive Series. A large longitudinal fault extends along thenortheastern flank of the structure; the southwestern flank thrusts overthe northeastern one. Mud volcanism occurs along this fault. Thestructure is cut by a series of transverse faults. Most of these faultsoffset the main longitudinal fault and cut the entire Productive Series.Fault planes, with dips ranging from 60 to 90°, trend mainly insoutheastern direction. Bed displacement is maximum over the crestand dies out toward the flank of anticline.

Neft Dashlary Field is divided into five fault blocks according tooil and gas saturation and trap conditions (Figure 6-5a):

I. Northwestern part of the fieldII. Central part of southwestern flank

III. Central part of northeastern flankIV. Southeastern plunge of southwestern flankV. Southeastern plunge of northeastern flank

Oil- and gas-producing zones of Neft Dashlary Field include theProductive Series, which in turn is divided into the following suitesand units (upwards): Kala Suite, which is subdivided into units KaS1,KaS2, KaS3, and KaS4; Podkirmaku Suite, which is subdivided intounits PK1, PK2, and PK3; Kirmaku Suite, which is subdividedinto units KS1 and KS2; Nadkirmaku Peschanaya (Sandy) Suite—NKP; Nadkirmaku Glinistaya (Shaly) Suite—NKG; “Pereryv” Suite;Balakhany Suite, which is subdivided into units V, VI, VII, VIII, IXand X; Sabunchi Suite, which is subdivided into units II, III and IV;and Surakhany Suite (units I and I′) (Figure 6-6a and 6-6b).

(text continued on page 67)


Figure 6-5. Structural map and cross-section of Neft Dashlary Oil Field.(a) Structural map on the top of PK Suite: 1—Diatom and Maikop (Oligocene-Lower Miocene) crumpled rocks, 2—dislocation with a break in continuity,3—oil accumulation, 4—well; (b) geologic cross-section: 1—oil, 2—gas,3—dislocation with a break of continuity, 4—Diatom and Maikop (Oligocene-Lower Miocene) crumpled rocks, 5—Koun (Middle Eocene) crumpled rocks.


Figure 6-6a. Typical logs (Resistivity and SP) of the Productive Series inNeft Dashlary Oil Field: NW portion of field, NE wing (block I) and SW wing(block Ia).


Figure 6-6b. Typical logs (Resistivity and SP) of the Productive Series inNeft Dashlary Oil Field: SE portion of field, SW wing (blocks II and IV) andNE wing (blocks III and V).


Field Development

From the very beginning of development of Neft Dashlary Field,different methods of waterflooding of productive intervals were usedin order to maintain reservoir pressures.

The main productive intervals in Neft Dashlary Field are the fol-lowing: Kala, Podkirmaku, Kirmaku, Nadkirmaku Sandy, “Pereryv,”and Balakhany suites. About 30 oil- and gas-saturated intervals havebeen identified.

In the second fault block (main block), according to log and thewell-test data, three separate sandy-silty productive units, divided bythick shale interbeds, are identified in the Kala Suite. Among themunits KaS1 and KaS2 are characterized by high oil saturation and oiloutput. Unit KaS2 has a large gas cap, and Unit KaS3 is gas bearing.

The main productive interval of the field is the Podkirmaku Suite.The first wells which penetrated this oil-bearing sequence had highinitial flow rates. The entire Podkirmaku Suite is saturated with oil.The suite is divided into two main productive formations, PK1 andPK2, which are separated by shale layer 2–5 m thick. Average thick-nesses of PK1 and PK2 are 40 and 45 m, respectively. At the trap crest,thickness of the shale layer between PK1 and PK2 decreases andsometimes shale disappears. Thickness of the shale layer increasesaway from the crest toward the flanks. Reservoirs of the PodkirmakuSuite are characterized by water drive; gas caps are lacking.

Figure 6-7a shows the distribution of producing and injection wells,whereas Figure 6-7b shows the production history of Unit PK1 in thesecond fault block. Figure 6-8a is a map of OWC migration due towaterflood front advance during the Unit PK1 production, whereasFigure 6-8b is a map of water encroachment rate in the same unitexpressed as water-cut (%).

Only the Lower Kirmaku Suite is oil-saturated (79–80 m from thebottom). The oil-saturated section includes two separate productiveunits, KS1 and KS2; the upper KS1 is less productive.

In the third, fourth, and fifth fault blocks, oil saturation is confined(besides the above described productive units) to the NadkirmakuSandy and “Pereryv” suites and to the Upper Productive Series.Nadkirmaku Sandy Suite is distinguished by the high oil content

(text continued from page 63)


throughout the entire thickness. The “Pereryv” Suite consists of fourto five individual beds separated by thin shale interbeds. These bedsare unevenly saturated. Units X, VI, V, IV, III, I and I’ are oil bearingwithin the same beds as the “Pereryv” Suite. Units IX, VIII and VIIhave the most widespread distribution of oil saturation. In spite of theshallow depth (100 to 500 m), these units are characterized by highoil output.

Figure 6-7. Distribution of producing and injection wells in Neft Dashlary OilField (a) and production history of Unit PK1 (b). 1—Producing wells, 2—injection wells, 3—1961 OWC, 4—initial OWC; Pav-average reservoir pressure,atm; Qw-water-injection rate, m3/day; N-number of producing wells; Qo-oilproduction, t/day; Qo′-oil production under natural depletion drive, t/day.


The oil in these productive intervals is saturated with hydrocarbongases; in addition, free-gas accumulations also occur here. The hydro-carbon gas of Neft Dashlary Field is largely methane. Wellhead gascontains admixed CO2. The composition of gas (vol-%) is presentedin Table 6-2. On an average, natural gas of Neft Dashlary Fieldcontains 68.1 to 96.7% methane, 0.64 to 5.14% ethane, 0.13 to 1.58%propane, 0.06 to 1.58% butane, and 0.13 to 2.54% heavier hydrocarbons.

Figure 6-8. Annual (1953–1961) migration of oil-water contact (a) and corres-ponding water-cut (b) at Neft Dashlary Oil Field (Modified after Samedov andBuryakovsky, 1966).


Tab

le 6

-2C

om

po

siti

on

of

Gas

fro

m t

he

Nef

t D

ash

lary

Oil

Fie

ld

Spe

cific

Con

tent

of

Gas

Com

posi

tion

(vol

%)

Gra

vity

C5+

(g/

m3

of

Sui

te/U

nit

Met

hane

Eth

ane

Pro

pane

But

ane

C5+

CO

2(t

o

Air

)B

ulk

Vo

lum

e)

NK

P89

.73.

241.

261.

111.

166.

40.

6832

47.4

KS

81.8

1.25

0.86

0.21

0.35

16.0

0.72

8312

.6P

K1

81.3

2.20

0.91

0.75

0.85

14.0

0.73

6630

.3P

K2u

ppe r

82.4

2.50

0.91

0.86

1.37

12.0

0.72

1753

.3P

K2l

owe r

88.0

2.80

0.71

0.39

0.65

7.6

0.66

1625

.3K

aS1

91.3

2.18

0.63

0.53

1.01

4.3

0.64

2439

.4K

aS2

94.3

1.16

0.87

1.16

1.16

1.4

0.62

2746

.4K

aS3

87.4

2.76

0.82

0.50

1.76

6.6

0.68

8470

.4K

aS4

92.9

2.14

0.67

0.43

1.04

2.8

0.62

6940

.0


The CO2 content by volume is 1 to 23%. Specific gravity of gas withrespect to air ranges from 0.5814 to 0.8846. The gas is dry, althoughseveral analyses show a content of heavy hydrocarbons up to 100 g/m3.

Gas saturation increases with an increase in clay content and witha decrease in sand content of reservoir rocks. A decrease in thicknessof sand beds is accompanied by a change in grain size: the contentof grain fraction less than 0.01 mm in size increases.

For example, the Podkirmaku Suite contains an average of 65–70%sands, with about 20% content of fractions less than 0.01 mm in size.The initial gas/oil ratio (GOR) was 35–40 m3/m3. The Kirmaku Suiteis characterized by a high content of shale beds and very thin sandy-shaly interbeds. Individual beds may be as thin as 1 cm. Sand layersconstitute no more than 45–50% of the entire suite; moreover, fractionsless than 0.01 mm in size constitute 25% of sands. The initial GORof the Kirmaku Suite was almost twice that of the Podkirmaku Suite,reaching 70–75 m3/m3. At the beginning of production, accumulationsin both formations had the same reservoir pressure. Lithologic featuresof the Podkirmaku Suite (predominance of sandstones in the section,excellent sorting, coarser grain size, and high permeability) were notconducive to the accumulation of free gas; the latter is due to the greatmobility of gas moving into the Kirmaku Suite above, which consistsof thin sandy-shaly interbeds with a high specific surface area.

A characteristic feature of the Kala Suite is the change of oil inKaS2 to gas on the far southeastern, down-dip part of the anticline(the fourth fault block). From the crest to the southeastern plunge,grain size decreases and the shale content of the reservoir increases.This is shown clearly in the KaS2 interval where, as a result, gas hasaccumulated with only a small oil fringe extending along the south-eastern plunge of structure. The boundary of gas-saturated reservoirintersects the structural contour lines of the stratum from higher levelsto lower. A similar change from oil to gas is observed in the otherunits of the southeastern plunge area; however, in these cases the gasis concentrated close to the crest of structure and forms a gas cap.

The relationship between the oil and gas variations during fieldproduction depends on differing physical and geological conditions(energy state, drainage mechanism, etc.). In a single-phase reservoir,oil is either completely saturated by gas or it is undersaturated. Thedegree of undersaturation is determined by the ratio of gas to liquidhydrocarbons at a pressure below reservoir pressure. The degree of


undersaturation of reservoir oil is the difference between the reservoirpressure and bubble-point pressure. At the beginning of production ofNeft Dashlary Field, the degree of undersaturation of oil ranged from0.6 to 3.0 MPa; gas was dissolved in oil and separated from it onlyin the borehole above the perforated interval. High pressure, existingwhen gas-saturated oil reservoirs were penetrated, permitted all the gasexcept methane, CO2, and a portion of ethane to be retained in solutionin the oil. With a drop in pressure as a result of production, otherhydrocarbons begin to appear in the gas phase. Gas is enriched inethane, propane, butane, and heavier hydrocarbons. As a consequence,the specific gravity of the gas increases, depending on the durationof production and the rate of reservoir pressure drop. In the crestalarea, pressure drops faster and the oil here is less compressed; there-fore, the methane content increases from the crestal area towards theflanks of the structure, in the same direction of decrease in specificgravity of the gas. The Podkirmaku reservoir is a good example ofthis behavior (Table 6-3).

Long before the beginning of production, the oil in crestal portionsof the structure lost gas, mostly methane, in larger quantities than didthe oil present on the flanks. As a result of redistribution of oil andgas within the reservoir, the difference between the gas/oil ratio invarious parts of the accumulation should disappear with time. Losses

Table 6-3Methane Content in Gas and Specific Gravity of Gas with Respect

to Air vs. Depth in Neft Dashlary Oil Field

Well Perforated Methane Specific GravityNo. Interval, m Content, % of Gas

34 1,536–5421, 68.1 0.883862 1,690–6951, 68.7 0.876377 1,845–8511, 77.7 0.778118 1,918–9211, 77.4 0.774273 1,909–9131, 85.8 0.642559 1,965–9671, 80.7 0.757317 1,960–9681, 88.8 0.667855 1,244–1,276 94.3 0.5972


of methane at the crestal area and its transfer along the bedding fromthe margin to the crest take place simultaneously. Ultimately, this leadsto some decrease in the methane content and to an increase in thespecific gravity of the gas in crestal portions of the accumulation.

Upon the successful development of Neft Dashlary Field, drillingof exploratory wells was carried out in areas adjacent to the field.

Palchygh Pilpilasi Oil Field


Palchygh Pilpilasi (meaning “Mud Volcano” in Azery language) OilField is located in the Caspian Sea east of Baku and southeast ofPirallaghi Adasi (see Figure 6-3). The main base for exploration anddevelopment is at Neft Dashlary Field, 4 km southeast.

Seismic surveys conducted during 1953–1957 outlined the structurebetween Chalov Adasi and Neft Dashlary and discovered anotheranticline Palchygh Pilpilasi (Samedov et al., 1960). Later, in 1963–1965, one more uplift, named Azi Aslanov, was discovered betweenChalov Adasi and Palchygh Pilpilasi structures.

By 1953, commercial oil saturation was established in nine unitson both flanks of the Neft Dashlary anticline. The initial flow rateswere high, over 50 tpd (365 bpd). Because Palchygh Pilpilasi area lieson the northwestern extension of the Neft Dashlary Oil Field andincludes the same Middle Pliocene formations, it was suggested thatthe same units may be productive there. During the first few years ofexploration (1952–1955), the objective was to penetrate the entireProductive Series and to study its lithology, stratigraphy, structure andpetroleum potential. The first well (22) was spudded on August 10,1952, over the most elevated area of the southwestern flank. This well(TD = 1,003 m), along with platform, was destroyed by a severe stormon December 11, 1952. By 1956, eight wells were completed. The crestalWell 20 tested oil with gas from Kala Suite and 0.5 to 1 tpd (3.6 to7.3 bpd) of heavy oil (density = 0.945 g/cm3) from Podkirmaku Suite.

Commercial flows from the exploratory wells spaced over 4 kmwere considered as indications of the high potential of the structure.An appraisal drilling program for the Palchygh Pilpilasi area wasprepared by F. I. Samedov and A. M. Polaudin and approved on June30, 1956. The program envisioned the drilling of 20 wells with


proposed depth ranging from 1,000 to 1,900 m along seven profilesextended across the strike of the structure and encompassing both ofits flanks. The spacing of profiles was 800 to 1,000 m. The appraisaldrilling program was supposed to take two years (including the con-struction of offshore platforms). Some wells were proposed to bedeviated and drilled from the existing platforms or platforms underconstruction at that time. The drilling program for 1956 included12,000 meters with the remainder to be drilled in 1957. To study theKaS accumulation discovered in the northwestern area of the NeftDashlary Oil Field, the drilling of four wells was proposed.

Actually, five wells were drilled in 1956, with two wells yieldingcommercial oil production (18 and 45 tpd or 131 and 328 bpd). Fourwells out of those drilled in 1957 flowed oil (15 to 22 tpd or 109 to160 bpd), whereas one well flowed gas from Unit KaS4. Four of thesewells, along with the other two which were not completed, have beendestroyed by the hurricane on November 21, 1957. The hurricaneseverely affected the exploration and development program: no wellswere drilled in 1958, and only one, in 1959. Nevertheless, the initialdrilling program with some adjustments, was completed by 1958. Asa result, oil accumulations have been discovered in KaS and PK suitesand substantial amount of knowledge was gained about the geologyand petroleum potential of the region.

The most intensive drilling was conducted in 1960-1961. During thatperiod, 12 wells were drilled that delineated discovered oil accumu-lations. Five of the wells tested oil (10 to 50 tpd or 73 to 365 bpd),four were water wet, one was plugged and abandoned, and two wellsremained uncompleted. No wells were drilled in 1963. One well wasdrilled each year in 1964 and 1965, three in 1966, two in 1967 andfive in 1968. A total of 46 exploratory and appraisal wells were drilledby 1969. Thirty-five of these wells were cored.

The average profile spacing was 1,000 m, whereas the well spacingwas 300 m. The profile spacing corresponded to the drilling program,whereas the well spacing was smaller due to drilling of some infillwells required by the complexity of the structure and lithology.

Geology

During the initial exploration period, it was believed that PalchyghPilpilasi Oil Field was a northwestern plunge of the large Neft Dashlary


structure. Exploration from 1952 to 1955 allowed structural maps tobe revised, showing an independent brachianticlinal uplift of PalchyghPilpilasi. It is separated from the Neft Dashlary structure by a smallsaddle (Figure 6-9).

The stratigraphic section of the Palchygh Pilpilasi has been studiedexclusively by deep drilling. Sediments of Pliocene age (Productive

Figure 6-9. Structural map on top of the Kala Suite of Palchygh Pilpilasi OilField (a) and geologic cross-section (b). 1—OWC, 2—contour lines on topof the Kala Suite, 3—fault.


Series and Pontian Stage) have been encountered and studied. Pontiansediments are represented by deep-water facies, which are gray to darkgray in color, unconsolidated, and contain thin limey shale beds. Sandyvarieties are rare. Characteristic fossils include Paracypria loezyi Lal.,Leptocythere praebacuana Liv., Loxoconcha alata Schn., Loxoconchaeichwaldi Liv., and other ostracods, pelecypod embryos, and others.

The Productive Series deposits, where the oil accumulations occur,have been thoroughly studied. Largely, deposits of the upper and lowerdivisions of the Productive Series have been encountered. The baseof the upper division occurs as deep as 260 m rising from zero, whererocks of the lower division crop out on the seafloor, to 500 m onthe plunge of the structure. Rocks of the Kirmaku and NadkirmakuSandy (NKP) and Nadkirmaku Shaly (NKG) suites occur along thecrest of the structure. Total thickness of the Lower Productive Seriesis 900 m on the average and ranges from 700 to 1,200 m. The sectionis represented by the following formations, from the bottom up:

The Kala Suite rests directly on Pontian sediments and is com-posed largely of interbedded sands, sandstones, shales, and siltstones,with rare admixtures of gravel. The total thickness of the sand-shalemembers of the Kala Suite is about 300 m. Shale predominates oversand and constitutes 60% of the total thickness. In the area of PalchyghPilpilasi Field, the Kala Suite is subdivided into four sandy units, withthickness ranging from 20 to 30 m, separated by thick shale partings(Figure 6-10).

The sandy unit is represented by gray to light-gray medium-grainedquartz sand and sandstone with some fine-grained clayey varieties.Impermeable partings are gray to light-gray sandy shales. Sands of theKala Suite are characterized by variation in grain size. The averagegrain-size distribution is as follows: >0.25 mm—6.9%; 0.25 to 0.1mm—27.5%; 0.1 to 0.01 mm—37.2%; <0.01 mm—28.4%. Carbonatecement content is 14.2%, ranging from 4 to 39.4%. Average porosityis 17% with a range of 8.3 to 33.4%. Permeability ranges from a fewmillidarcies to 500 mD.

According to a petrographic analysis, the KaS reservoir is charac-terized by the following content of light minerals: quartz— 53.3%;feldspar—17%; rock fragments—29.6%, and glauconite— 0.1%. Theheavy minerals include the following: pyrite—14%; magnetite-ilmenite—2%; nonmetallic (opaque)—13%; micas and chlorite—8%; andglauconite—19%. The contents of limonite, garnet, zircon, tourmaline,biotite, kyanite, staurolite, and sillimanite is about 1% each.


Figure 6-10. Correlation of electric logs on top of the Kala Suite in PalchyghPilpilasi Oil Field.


The Podkirmaku Suite has an average thickness of 100 m and isrepresented by gray quartz sand and sandstone with some admixed clayminerals. Shale beds in the Podkirmaku Suite are few—up to 30% ofthe total thickness. Two separate units are identified in the PodkirmakuSuite: PK1 and PK2, each of which is represented by sandy bedscontaining up to 3–4 strata. Shaly beds of variable thickness dividePK1 and PK2. Sands are poorly sorted and were determined micro-scopically to be fine- to medium-grained. Shales are poorly beddedand often sandy. Average grain size of reservoir rocks is as follows:>0.25 mm—1%; 0.25 to 0.1 mm—24.8%; 0.1 to 0.01 mm—45.7%;and <0.01 mm—28.5%. Carbonate cement content is about 10%.Average porosity is 20%, and permeability is on the order of 100–120 mD.

The Kirmaku Suite is a uniform unit of interbedded fine-grainedsands and sandstones, shales, and argillaceous sands with an averagethickness of about 300 m. This alternation extends to small-scalebedding where the sandy beds vary from 1 to 5–7 m in thickness. Themost sandy strata occur in the middle and lower parts of the suite.The middle sandy member with a thickness of 10–15 m is distin-guished by high resistivity on the electric log. The lower memberattains a thickness of 50 m. The light minerals of sand include 50%quartz, 42% feldspar, and 8% rock fragments. The heavy mineralsinclude 72% pyrite, 11% mica and chlorite, 10% opaque nonmetallicminerals, and 5% glauconite.

The Nadkirmaku Sandy Suite consists of medium- and coarse-grained quartz sands with beds of sandstones, which are largely presentat the base. Shale beds are rare and thin. The average thickness is 35m. Sands constitute about 70% of the total thickness.

The Nadkirmaku Shaly Suite consists largely of shales with rare thinbeds of sands and siltstones. The shaliness of the section increasesfrom the base toward the top. The thickness of the Nadkirmaku ShalySuite is 125 m. Shales of this suite are dark gray and brownish gray,bedded, and plastic. Sands are gray to light gray, fine grained; theyconstitute 20% of the total thickness.

The “Pereryv” Suite and the base of the Balakhany Suite includerocks of the Upper Productive Series and compose the marginalparts of the structure. The basal portion of this interval about 100 min thickness is composed of medium- and coarse-grained sandsand sandstones.


Sediments of Balakhany Suite are more or less fully represented onthe marginal parts of the structure where their thickness reaches 400m. In the other parts of Palchygh Pilpilasi structure, only the basalportion of this suite is found, and its thickness is no more than 150 m.

Average values of the reservoir-rock properties for the suites ofPalchygh Pilpilasi Oil Field are presented in Table 6-4.

The Palchygh Pilpilasi brachianticline is located on a regionaltectonic trend which extends from the Khali structure on the southeastthrough Chalov Adasi, Azi Aslanov, Palchygh Pilpilasi, and NeftDashlary structures; it is a local uplift along this trend. The length ofthe structure is more than 6.5 km. The structural surface on the topof Podkirmaku Suite, plotted using deep-well logs, is shown on Figure6-9a. The crest extends as a narrow ridge, and is 4 km long and 0.4to 0.5 km wide within the 500 m structural contour. The crestal areais located eccentrically with respect to the periclinal closures and isclose to the saddle that separates it from the Neft Dashlary structure.Toward the southeast and northwest, the crest constitutes about one-fourth of the entire structure. The northwestern plunge makes a gentleturn to the west, and axis of the structure follows a curved lineoriented on an azimuth of 100° to 135°. Due to this bending of theaxis, the northeastern flank of the structure is longer than the south-western flank. The structure is somewhat asymmetric. The southwesternflank dips 35–37°, whereas the northeastern flank dips 40–45° (Figure6-9b). Dip of the southeastern closure is about 16°, and that of thenorthwestern plunge is on the order of 10–12°. Dip increases withdepth due to thickening on the flanks. Increased dip on both flanksof the structure is shown in Table 6-5.

A large longitudinal fault extends along the crest of the structure,and is a continuation of a regional longitudinal fault that has beentraced through Neft Dashlary and Chalov Adasi structures. An offshoreseismic survey confirmed the existence of this fault.

A mud-volcano vent observed near exploration Wells 75 and 79 resultedin the entire area being named Palchygh Pilpilasi or Mud Volcano.

Field Development

According to core and log data, productive zones of the LowerProductive Series (KaS, PK, and KS) are oil saturated. The higherzones do not contain oil. According to the electric logs, oil-bearing sand


Tab

le 6

-4R

eser

voir

-ro

ck P

rop

erti

es o

f P

alch

ygh

Pil

pil

asi

Oil

Fie

ld

Gra

in-s

ize

Dis

trib

utio

n, %

Car

bona

te>

0.25

0.25

–0.1

0.1–

0.01

<0.

01C

emen

tP

oros

ity,

Per

mea

bilit

y,S

uite

/Un

itm

mm

mm

mm

mC

on

ten

t, %

%m

D

KS

12.7

13.8

53.5

30.0

19.9

22.3

154

PK

13.7

24.7

47.3

24.3

18.4

24.1

150

KaS

111

.513

.555

.729

.310

.322

.117

8K

aS2

19.4

28.3

36.6

25.7

19.6

20.4

289

KaS

310

.922

.240

.526

.412

.719

.612

9K

aS4

11.5

26.6

36.4

25.5

10.6

20.5

136


units of the Kala Suite are distinguished by peaks from 15 to 50ohm • m, with individual peaks reaching 70 ohm • m. The SP curvesare hard to interpret, although negative anomalies with amplitudes ofup to 10 mV are observed opposite porous, permeable strata. Unitsof the Podkirmaku Suite are distinguished by the resistivity rangingfrom 20 to 60 ohm • m and by negative SP anomalies, whereas inter-vals devoid of oil exhibit resistivity of 3 to 8 ohm • m. In the KirmakuSuite, the basal member has a resistivity of up to 10 ohm • m, whereasthe middle part exhibits resistivity of up to 25 ohm • m. The rest ofinterbedded sand-shale intervals devoid of oil have resistivities rangingfrom 1 to 5 ohm • m.

The main oil-producing interval in the field is the Kala Suite. Oilflow was obtained from wells located in the crestal area and on thesouthwestern flank of anticline. Two wells located at the crestal areaflowed gas. Table 6-6 shows characteristics of the initial period of oilproduction from the Kala Suite. Gas wells flowed 50 to 100 Mcmd(1,765 to 3,530 MMcfd).

Comparison of electrical logs and well-test results indicates anuneven oil saturation depending on location of the well on the struc-ture. Oil saturation of the Kala Suite improves markedly toward thenorthwestern plunge and on the southwestern flank of structure.Density of the oil ranges from 0.9208 to 0.9438 g/cm3 with an averageof 0.9290 g/cm3. The oil has a high viscosity, which was determinedat 20°C only for light oil. The rest of the oils do not flow at 20°C.Comparing the properties of oil of the Kala Suite of Palchygh PilpilasiField with those of the Kala Suite of Neft Dashlary Field, it is noted

Table 6-5Comparison of Dips in Palchygh Pilpilasi Anticline

Dips in Degrees

Suite NE Flank SW Flank

NKG 38 35NKP 42 36KS 43 36PK 45 37KaS 46 38


that oil at Palchygh Pilpilasi Field is heavier, more viscous andcontains more tar; its properties are close to those of the oil fromChalov Adasi Field.

During exploration, formation water was recovered from intervalsof the Podkirmaku and the Kala suites. Water drive is prevalent here.The formation water of the Palchygh Pilpilasi Field is alkaline ofsodium bicarbonate type, with an absence or a very low content ofsulfates (up to 0.8 mg-equ per 100 g of water). Total salinity averages62.7 mg-equ per 100 g of water ranging from 52.4 to 81.4 mg-equper 100 g of water. (Total salinity is 22.2 g/L ranging from 20.0 to27.6 g/L.) Palmer characteristics are: S1 = 81.5, A1 = 15.9, A2 = 2.6.The Na/Cl ratio ranges from 1.03 to 1.5, whereas Ca/Mg ratio variesfrom 1 to 2. Average contents of anions (in mg-equ per 100 g of water)are as follows: Na+K—30.8; Ca—0.5; and Mg—0.3. The content ofnaphthenic acids is 0.7 mg-equ per 100 g of water. The formationwater of the Palchygh Pilpilasi Field is more saline than that of theNeft Dashlary Field, but is of the same type: alkaline water. (SeeChilingar, 1957, 1958.)

Dzhanub Gas Field


The Dzhanub structure is the southeastern culmination of the axisof the Darvin Bank—Pirallaghi Adasi—Gyurgyan Deniz anticlinal

Table 6-6Initial Period of Oil Production Rate and Wellhead Pressure

at the Kala Suite, Palchygh Pilpilasi Field

Well No. Production Rate, tons/day Wellhead Pressure, MPa

179 32 0.5261 40 3.0290 22 0.6295 37 2.2370 20 —450 17 0.5460 15 0.3465 42 1.8505 17 1.4


trend (see Figure 6-3), and is the southernmost explored structure ofthis trend. Dzhanub Gas Field was discovered by seismic surveybetween 1945 and 1959 (with interruption). Based on the seismic data,the structure is a gentle, terrace-like salient on the far plunge of theChalov Adasi southwestern flank. The Dzhanub (meaning “Southern”in Azeri language) structure was so named because of its locationsouth of Chalov Adasi Field.

Based on the seismic reconnaissance survey of 1945, a schematicstructural map of the phantom horizon at the top of the BalakhanySuite was prepared. The map showed structural flattening southwestof Chalov Adasi structure. The area south of this structure was studiedin more detail in 1949.

The first exploratory Well 1 with proposed total depth of 3,800 mwas spudded over the crest of the structure. It was abandoned due tomechanical problems at TD of 3,661 m (in Kirmaku Suite). The UnitsV and VI of the Balakhany Suite and the NKP Suite had favorablepetrophysical properties.

In 1959, additional seismic work was conducted to clarify thestructure of the crestal area of structure. After reprocessing all avail-able seismic data in 1960, the anticline was delineated.

In 1961, the exploratory Well 2 with proposed total depth of 4,400m was spudded 700 m northwest of Well 1. The well was halted atTD of 3,707 m because of drilling problems. The well tested gas fromPK Suite at a rate of about 450 Mcmd (15.9 MMcfd) with conden-sate, through a 7-mm choke at wellhead pressure of 24.5 MPa.

Along with the exploratory drilling, a seismic survey was conductedin 1963 in order to study the NW plunge of the Dzhanub structurewhere it joins the Gyurgyan Deniz structure. A small salient extendingfrom the Gyurgyan Deniz plunge toward the Dzhanub structure wasmapped. The NW plunge of the Dzhanub structure is en-echelon withthis salient.

Further drilling program on the structure was proposed in 1962 byKh. B. Yusufzadeh, L. A. Buryakovsky and R. M. Dadashev. By the timethe program was prepared, several prospects, out of many structuresdiscovered within the Apsheron Archipelago, have been evaluated andput on-line (Gyurgyan Deniz, Chalov Adasi, Neft Dashlary, PalchyghPilpilasi, etc.). To determine the potential of the field, the programsuggested the number and locations of exploratory wells. They formedtwo intersecting profiles along and across the structure. The programenvisioned drilling of 16 wells to study the oil and gas potential in


the entire Productive Series and the tectonics of the field. Later,14 more wells were drilled to evaluate the potential and to delineatethe gas-condensate accumulations. Maximum spacing was 1,360 m,whereas the minimum, was 660 m.

As a result of exploration, the entire Productive Series was studiedand commercial gas reserves were discovered in the Balakhany (UnitsV and VI), NKP, KS and PK suites. The rest of the Balakhany units,as well as the “Pereryv” and Kala suites, displayed favorable logcharacteristics; however, some tests were unsuccessful.

Geology

The complete section of the Productive Series is penetrated only infour wells. Eight wells encountered a fairly complete section. The topof Productive Series, which is located at a depth of about 1,000 m, isalmost horizontal (Figure 6-11).

Upper Productive Series reaches 2,300 m in thickness. SurakhanySuite (average thickness = 1,090 m) is represented by brown and dark-gray shale, with thin layers of fine- to very fine-grained, gray andbrown sand. The number and thickness of these layers increase downthe section. The formation has low resistivity (1–2 ohm • m), withsome higher resistivity peaks (5 ohm • m). The SP curve is poorlydifferentiated, and characterless.

Sabunchi Suite is separated from the previous one by a 50-m thickshale member and is composed of shale and sand (sometimes loose).The light to dark-gray shale is quite sandy and dense. The sand is grayto dark gray in color, fine to very fine grained, consists mainly ofquartz, and is limy. Average thickness of the suite is 390 m. Similarto the Surakhany Suite, the Sabunchi Suite has low resistivity withsome peaks not exceeding 3-5 ohm • m.

Balakhany Suite (655 m thick) is quite sandy and is subdividedinto several units. Inasmuch as it is the shallowest commerciallyproductive formation in the area, some of the units deserve a moredetailed description.

Unit V (70-m thick) is separated from the Sabunchi Suite by a 35-m thick gray shale member (Unit IVcde). The unit represents a thininterbedding of shale and sand, with prevalence of sand. The sand, whichis only slightly compacted, is very fine, fine, and sometimes mediumgrained. The sandstone has carbonate cement and is very hard.


Figure 6-11. Structural map on top of the PK Suite of Dzhanub Gas Fieldand geologic cross-section (by Kaspmorneftegazprom, 1985). 1—Deviatedwell with TD shown, 2—contour lines on top of the PK Suite, 3—fault, 4—direction of cross-section, 5—OWC.


Unit VI (183-m thick) is represented by sand, sandstone, and shale,with a significant prevalence of the former. The sand is gray to lightgray in color, carbonaceous, and very fine- and fine-grained. The shaleis gray to dark gray in color and dense. Based on petrophysicalparameters, the unit is subdivided into two parts, 70-m thick each. Theupper one (VIupper ) is separated from the lower one (VIlower) by a43-m thick sand aquifer. The unit is characterized by a clearly outlinedresistivity (up to 15 ohm • m) and SP curves.

Unit VII (102-m thick) is separated from the preceding one by a3-m thick shale. It is composed of (1) gray, light-gray, brownish-gray,very sandy shales, dense, with slickensides, and (2) brownish-gray tolight-gray, very fine- and fine-grained sandstones, with a bituminousodor and thin layers of sands. Sand layers in the lower and middleportions of the unit (5–8 m) are 2 to 3 times thicker that in the upperone (2–3 m).

Unit VIII (105-m thick) is formed by interbedded sands and shales.The sand beds are much thicker and reach 12 to 16 m in thickness.The sand is light gray to gray in color, very fine-, fine- and medium-grained, loose, and is slightly water wet. The shale is dark-gray to grayin color, dense, and sometimes deformed.

Unit VIII overlies thin intercalating shaly and sandy members (thelatter are sometimes indurated), which compose Unit IX (95-m thick).Unit IX is very similar to the Unit VIII, except that the highestresistivity (10 ohm • m) is associated with the middle portion of theunit. Over the rest of the unit resistivity is low (2–3 ohm • m). TheGR and SP curves are well defined.

Unit IX gradually changes into Unit X (100-m thick.). The latterhas somewhat shalier upper and sandier lower portions. The lower onehas only two 2-m thick shale layers; the upper one has 7 shales, eachone up to 8–10 m in thickness. Some 2–3-m thick sandstones are alsopresent; they are indurated, water wet and contain mica. Resistivityreaches 10 ohm • m. Type of the GR and SP curves together with theresistivity data indicate predominant water-saturation of the sands.

“Pereryv” Suite (159-m thick), is composed of gray, light-gray,sometimes whitish, and fine- to medium-grained sand. The sandcontains angular, black, quartz fragments (1.5 to 2 mm in size) andis very carbonaceous. There are several firmly indurated fine- tomedium-grained sandstones with gravel-size, black, quartz fragments.The shale, which is gray to light-gray, dense, and laminated, is quite


rare. Resistivity is high (up to 23 ohm • m) and SP and GR curvesare clearly defined.

NKG Suite (112-m thick) is composed of dense gray to light-gray shale with thin intercalations of sandstone and siltstone. Thethicknesses of the interbeds increase down the section; the resistivityis low and does not exceed 1.5 to 4–6 ohm • m in the lower portionof NKG Suite. The SP and GR curves are poorly defined.

NKP Suite (55-m thick) is composed of fine-, medium- and coarse-grained, gray to light-gray, sands and sandstones, with rare shalelayers. The total sand thickness does not exceed 35 m. There are threehigh-resistivity (up to 30 ohm • m) members, 6 to 12-m thick, eachone with well-expressed strong anomalies on the SP and GR curves.

KS Suite (222-m thick) is very shaly. It is composed of interbeddedsands, siltstones and shales, with thicknesses increasing down thesection. The shale is gray to light gray, dense, and laminated. Sandsand sandstones are similarly gray to light gray in color, fine-to very fine-grained. The entire suite is subdivided into two parts:KS1 (over 180-m thick) and KS2 (about 50-m thick). Petrophysically,the KS1 is represented by a monotonous resistivity curve (upto 5 ohm • m). The KS2 consists of two shaly sand members withresistivity ranging from 10 to 20 ohm • m. The SP and GR curves arepoorly defined in the upper interval and have some anomalies in thelower one.

PK Suite (110-m thick) is represented by fine- to medium-grainedsands with rare layers of shale. The sand is dark gray to light brownin color. The sandstone is light to dark gray in color and is present inthe middle portion of the suite. Shale is gray to dark gray, dense, andlaminated, with thin layers of fine-grained sand. The resistivity is veryhigh compared to the other suites (up to 80 ohm • m). The SP and GRcurves are clearly defined; the anomalies correspond to the high-permeability sands. The PK Suite is subdivided into two parts: PKupper(40-m thick) and PKlower (65-m thick), with a 5–9-m thick shaleseparating them.

KaS Suite is fully penetrated (355 m) in Wells 12, 22 and 25. Itconsists of interbedded shales, fine- to very fine-grained sands andsandstones. Shale constitutes 60% of the total thickness. The sandlayers are grouped into four members: KaS1, KaS2, KaS3 and KaS4separated by thick shale beds. The sand members have high resistivity(up to 50 ohm • m). The SP and GR curves are poorly defined.


Twenty to twenty-five meters of the Pontian Stage were penetratedin wells Nos.12 and 22 where it is represented by gray to dark-gray shales.

Average values of the reservoir-rock properties for the units andsuites of Dzhanub Gas Field are presented in Table 6-7.

The Dzhanub structure is a gentle anticline with 150 m of closureover the saddle separating it from the Chalov Adasi structure. The sizeof Dzhanub structure within the 3,820-m contour is 5.4 by 3.1 km.The axis trends NW to SE until it reaches a transverse fault where itturns 20° to the east and trends almost west to east. The anticline issomewhat asymmetric, with a gentler northeastern flank (3° to 5°) anda steeper southwestern flank (8° to 11°); it flattens at the top of theProductive Series. Dips increase down the section (see Figure 6-11b).

The PK Suite was penetrated at the crest of structure at a depth of3,660 m (Well 23). The closure is 155 m. The TVD difference betweenthe crest and the southeastern plunge is 153 m (Wells 23 and 12).

The structure has a transverse fault cutting the southeastern plunge(see Figure 6-11a). Displacement is relatively minor and changes from40 m in the southwest to 10 m in the northeast. The northeastern blockis upthrown relative to the southeastern block. It is believed that thefault cuts the entire Lower Productive Series, down to the underlyingformation. The lower portion of the Upper Productive Series graduallydies-out up the section.

Field Development

The Dzhanub Gas Field is characterized by the tilted GWC, usuallydipping in the northwest direction. This may be caused by the regionalflow of the formation water from the deepest portions of the SouthCaspian Basin towards its periphery. Commercial gas accumulationsare mainly controlled by the structure and are unevenly distributed,both laterally and vertically. Anticlinal and fault traps are present.

Unit V of Balakhany Suite is penetrated by 20 wells. Hydrocarbonsaturation, based on logs, is observed in eight wells. Tests wereconducted in Wells 2 and 5, which flowed gas (150–180 Mcmd or 5.3–6.35 MMcfd) and condensate (3 tpd or 21.9 bpd). Three accumu-lations are present in Unit V. The major one is located northwest ofthe fault on the uplifted part of the structure. Average subsea depthto the accumulation is 2,545 m, net pay is 8.7 m, and the trap reliefis 35 m. Two other accumulations were found within the southwestern


Tab

le 6

-7A

vera

ge

Res

ervo

ir-r

ock

Pro

per

ties

of

Dzh

anu

b G

as F

ield

Gra

in-s

ize

Dis

trib

utio

n, %

Car

bona

teU

nit

or>

0.25

0.25

–0.1

0.1–

0.01

<0.

01C

emen

tP

oros

ity,

Per

mea

bilit

y,S

uite

mm

mm

mm

mm

Co

nte

nt,

%%

mD

V10

.121

.053

.624

.410

.623

.325

5V

I10

.410

.359

.621

.719

.522

.729

8V

II13

.546

.316

.333

.919

.817

.1n.

aV

III

12.8

38.5

42.6

16.1

10.0

22.6

166

IX14

.754

.826

.913

.615

.922

.1n.

aX

13.5

39.6

42.6

14.3

10.4

20.0

184

“Per

eryv

”11

.038

.532

.518

.013

.717

.318

5N

KP

18.7

22.1

46.0

23.2

15.7

21.7

145

KS

12.4

19.7

57.5

20.4

19.8

15.5

n.a

PK

12.1

40.0

45.8

12.1

16.4

21.2

275


fault block. The first one, in the upper section, was penetrated by Wells1, 5 and 8, with commercial gas found in Well 5. The second one, inthe lower section, was not tested, but is revealed by the E-logs ofWells 1 and 8.

Unit VI of Balakhany Suite is located over the crest of structure.Gas saturation, based on petrophysical data, is observed in Wells 2,6, 7, 9, 20, and 23. Well 7 tested gas (250 Mcmd or 8.8 MMcfd) witha small amount of condensate (1 tpd or 7.3 bpd).

Units VII, IX and X were penetrated in Wells 2, 9, and 23. Theywere not tested but were considered gas-saturated based on log data.The accumulations occupy a small area of the northwestern block closeto the crest of structure.

“Pereryv” Suite was penetrated in 18 wells. Well 5 of the south-eastern block tested water from 3,239.5–3,196.5 m. This, together withthe petrophysical data, led to the conclusion that the accumulation isdeveloped only within the northwestern block.

Gas and oil accumulations are present in the Nadkirmaku SandySuite (NKP) in both fault blocks. Four wells have been tested withinthe southwestern block and produced commercial gas (100 to 300Mcmd or 3.5 to 10.6 MMcfd) and condensate (40 tpd or 292 bpd).Apparently, the gas-condensate accumulation of the southeastern faultblock has an oil rim (Well 12 yielded oil). The OWC was determinedin this well. Initial gas-water contact (GWC) at the northwestern flankwas determined from the test results of Wells 17 and 18, whichproduced gas and formation water.

The KS section was penetrated in 15 wells. The lower portion ofthe section is gas-saturated over the entire evaluated portion of thestructure. Gross sand pay is 60 m, whereas the net pay is about 11 mthick. The KSlower interval within the northwestern fault block (Well3) tested gas (65 Mcmd or 2.3 MMcfd). Within the southeastern block(Wells 4 and 5), water having chemical composition foreign to the KSformation was discovered.

The PK Suite was penetrated in a number of wells. It is easilyrecognized on E-logs by very high resistivity in the 150 to 300ohm • m range. The SP curves, although generally having small anoma-lies against the pays, are poorly defined due to the closeness offormation water salinity and that of drilling fluid. Based on E-logs,the PK Suite is gas-bearing over the up-thrown northwestern faultblock and over the southeastern part of the structure. Test results,


however, were quite different: in the first case, wells flowed gas at arate of 500 to 1,000 Mcmd (17.65 to 35.3 MMcfd) and condensate ata rate of 50 to 90 tpd (365 to 660 bpd); in the second case, wellsproduced only formation water. Therefore, most of the commercial gasaccumulations are present in the northwestern fault block.

The lowermost producer, KaS Suite, is insufficiently studied. OnlyWell 12 on the southeastern plunge penetrated the entire section (394m). Well 23 drilled through 270 m of the section, whereas Wells 4,9, 14, and 15 barely penetrated the top of the suite. The formationhas high resistivity (80 to 120 ohm • m). Well 12 tested the lowersection, whereas Well 4, the upper part. Both tests yielded formationwater. These wells are located over the southeastern, deeper portionof the structure. During testing, the two intervals (3,798–3,792 m and3,940–3,930 m) in Well 23, initially produced gas with water, whichin about one day turned to all water.

ZONE II: SOUTH APSHERON OFFSHORE AREA

Anticlinal trends of the Apsheron Peninsula extend southward. Mostof the anticlinal trends are located onshore and the oldest large oil andgas fields occur along these trends. These trends continue offshore tothe south across the shelf, forming the South Apsheron offshore zone(see Figure 6-3). The Gum Deniz, Bakhar and Shakh Deniz structureslie on a continuation of the Central Apsheron anticlinorium. Individualstructures generally have steep dips and high relief, and are of diapiricnature with mud piercement to the surface. Oil and gas seeps and mud-volcano eruptions have been known from antiquity.

Bakhar Oil and Gas-Condensate Field


Bakhar structure was discovered in 1956–1957 by using seismic andelectrical offshore surveys. There were numerous indications of highpotential of the Bakhar prospect (located near the Makarov Bank mudvolcano): (1) an intermittent mud volcano spewing sand and sandstoneof the Productive Series; (2) location of the prospect on the southernoffshore continuation of the Fatmai–Gum Adasi anticlinal trend; and(3) discovery in the Lower and Upper Productive Series of the GumAdasi anticline of large oil and gas accumulations.


The seismic survey conducted in 1950–1953 was not conclusive dueto difficult mapping conditions, the presence of dead zones, and a thicklayer of seafloor sediments. In 1956, a detailed survey was begunusing electric, gravity, magnetic, and seismic techniques. As a result,four versions of the structural map were prepared for the top ofSabunchi Suite of the Makarov Bank area. One of them showed amajor fault along the structural axis. The fault was identified on thesouthwestern flank and the southeastern plunge of the Gum Adasistructure, and extended across the saddle to the southwestern flank ofthe Makarov Bank structure.

In 1951–1952, field mapping from barges was conducted at theMakarov Bank area. It was discovered that the seafloor was coveredwith a thick layer of loose detritus, 15–20 m of which could bepunched by a drill bit even without rotation, under its own weight. Abank was found around the mud-volcano crater composed of volcanicbreccia and expressed in seafloor topography.

Core hole 1 penetrated 1,211 m of breccia alternating with thin oldCaspian (Lower Quaternary) sediments. Cores included oil-saturatedsandstone fragments from the Productive Series.

A comprehensive core-drilling program in the Makarov Bank areawas impossible due to deep water, thick silt layer, and the absence ofaccurate geophysical data. In order to accelerate the process, explora-tory drilling was begun in 1955. Well 1 did not discover a commercialaccumulation and was plugged and abandoned at a depth of 3,384 m.Well 2 was spudded in 1961.

The first exploration program was prepared for the Makarov Bankarea in 1963. The objective of the earlier phase of the program wasthe total penetration of the Productive Series, and the study of itslithology, structure, nature of contact with the underlying sediments,petroleum potential, and partial delineation of discovered oil and gasaccumulations. The program envisioned drilling of 15 wells (total of75,984 m). The wells were drilled along four profiles (three wellseach), and the remaining three wells were situated between the profilesand on the southeastern plunge of the anticline. The proposed spacingwas 1 to 3 km, with TD’s of 5,000 to 5,300 m.

Exploratory well No. 3 was spudded in 1967 over the crest of thenorthwestern area. While drilling, it was found that units V throughVII of the Balakhany Suite had favorable petrophysical characteristics(resistivity ranging from 12 to 16 ohm • m). To test these targets, the


well was halted at TD of 3,933 m. Units VII and VI were tested(respective test intervals of 3,897–3,907 m and 3,732–3,764 m) andflowed gas (300 and 350 Tcmd or 10.6 MMcfd and 12.36 MMcfd)and condensate (40 and 100 tpd or 290 and 730 bpd). The chokesize was 10 mm, and the wellhead pressure was 20.0 and 26.5MPa, respectively.

High gas potential was established in the Balakhany Suite of theProductive Series in 1968. It caused the acceleration of appraisaldrilling and the offshore platform construction program. By year’s end,three wells had been spudded, with seven more wells in 1969.

Unit X of the Balakhany Suite was first proven to be commerciallyproductive in 1969, when Well 11 tested 300 Mcmd (10.6 MMcfd) ofgas and 100 tpd (730 bpd) of condensate from the 4,324–4,290 minterval at a wellhead pressure of 26.5 MPa.

In 1970, eleven more wells were spudded and three earlier spuddedwells were completed on the Bakhar prospect. Despite the fact thatexploratory wells did not penetrate the Lower Productive Series, it wasdecided to prepare the appraisal program. Due to significant thickness(over 2,000 m), large PTD’s (3,600 to 6,000 m), and a great numberof productive units, three appraisal phases were proposed, includingdrilling of eleven well profiles across the structural axis. Proposed profilespacing was 1.5 to 2.5 km, with well spacing of no more than 1 km.

The first phase encompassed the appraisal of the Upper ProductiveSeries (drilling to be halted after reaching the top of the NGK Suite)and drilling of 26 wells (total of 126,400 m) with TD’s of 4,800–5,150m. Upon completion of the first phase of program, the units IX andX and the “Pereryv” Suite would be prepared for development.

The next phase of program envisioned drilling of another 26 wells(140,670 m; PTDs of 5,200 to 5,700 m) for the appraisal of NKP, KS,and PK suites. At that phase, the PK Suite was supposed to be ready fordevelopment, with reserves being evaluated for the KS and NKP suites.

The third phase was planned for the study of Kala Suite. At thatstage, one accumulation should have been delineated and fully pre-pared for the commercial production, whereas the remaining accumu-lations should have been appraised. This phase included proposeddrilling of fourteen wells (83,050 m).

Upon completing this program, it became obvious that severalseparate high-potential accumulations were not studied. That is whyadditional wells were recommended using existing offshore platforms


for delineation and commercial appraisal of gas in the Upper BalakhanySuite (Units V through VIII), NKP Suite, and Upper KaS Suite.Therefore, to appraise the petroleum potential of the Productive Seriesat Bakhar Field, it was planned to drill, during the first phase, 34 wells(161,150 m); second phase, 30 wells (160,570 m); and third phase,16 wells (94,250 m). The total number of additional wells was pro-posed to be 80 (415,970 m) over the 10-year period starting in 1980.Well inventory in accordance with exploration phase and productiveformation is shown in Table 6-8.

The stratigraphic interval, which includes the productive formations,embraces the Productive Series section from the top of BalakhanySuite through the PK Suite. Interval thickness is about 2000 m, andthe following productive units were identified here: V, VI, VII, VIII,IX, X (all in the Balakhany Suite), “Pereryv,” NKP, and PK suites.These productive units are separated by shale beds and differ fromone another by fluid and petrophysical properties.

Geology

Geophysical study and deep exploratory drilling demonstrated thatthe Bakhar brachyanticline, along the northern plunge, is separated

Table 6-8Exploration History of the Bakhar Field

Number of Wells

Exploration Stage Unit or Suite Drilled Tested

I V 71 —VI 71 19VII 68 18VIII 68 13IX 66 20X

upper58 37

Xlower

50 23“Pereryv” 45 22

II NKP 27 14PK 22 18

III KaS 14 No play


from the Gum Deniz anticline by a distinct saddle. The southernplunge, according to seismic data, is separated from Shakh Denizanticline by elongated gentle saddle.

The Bakhar structure is defined by more than 120 exploratory anddevelopment wells. The structure is a north-south-trending brachyanti-cline with a length of 9.5 km and width of 3.5 km, within the 4,500-m contour line on top of Unit IX. Vertical relief is 400–450 m. Thestructure is slightly asymmetrical; the western flank dips 16–18°, theeastern flank, 19–20°, the northern plunge, 6–7°, and the southernplunge, 17–18°. The structure is divided into eight fault blocks byfaults (Figures 6-12 and 6-13).

The western flank is complicated by a curved, longitudinal faultwhich intersects the whole structure and cuts the entire productivesection. Fault dislocation is about 250 m at the southern plunge nearthe mud volcano, but gradually decreases to 100 m in the central partof west flank and to 50 m northwest. In addition to the longitudinalfault, four transverse faults cut the western flank. These faults separateindividual blocks IV to VIII. Apparent displacement of beds in adja-cent fault blocks is up to 250–300 m, but the displacement betweenthe Blocks IV and V is only 25 m.

The main portion of the Bakhar structure includes the central part,eastern flank and plunge areas, and is divided into three fault blocks(I, II, III) by two transverse faults. The transverse faults, whichseparate the northern plunge (Block I) from the central portion ofstructure (Block II) are clearly identified. The top of PK Suite is offset100 m relative to the central portion of structure, but this offsetdecreases to 25 m in the upper intervals. The southern fault separatesblocks II and III with a displacement not exceeding 20–25 m.

Transverse faults between Blocks I, II and III are characterized bysmall displacements, which explains why these faults were barriersonly before the beginning of production. Different locations of originalgas and oil pool outlines serve as evidence for this statement. Thesefaults became avenues of migration during gas and oil production.

The southern plunge of the structure is complicated by the largeMakarov Bank mud volcano (see Figure 6-12). The volcanic crater,distinctly identified at the seafloor, is composed of mud-volcanic breccia.



Figure 6-12. Structural map on top of the Unit IX of Bakhar Oil and GasField (Modified after Theory and Practice…, 1997). 1—Faults, 2—cross-section line, 3—contour lines on top of the Unit IX, 4—wells, 5—mud-volcanicbreccia, 6—breccia outcrops on the seafloor.


Fig

ure

6-1

3. G

eolo

gic

cros

s-se

ctio

n of

Bak

har

Oil

and

Gas

Fie

ld (

Mod

ified

aft

er T

heor

y an

d P

ract

ice…

, 19

97).

1—

Sa

nd

, 2

—sh

ale

, 3

—in

terb

ed

de

d s

ilt a

nd

sa

nd

, 4

—in

terb

ed

de

d s

an

dst

on

e a

nd

sh

ale

, 5

—g

as

acc

um

ula

tion

, 6

—o

ilac

cum

ulat

ion.


Heterogeneous gas, oil and gas-condensate reservoirs typically occurat great depths (3,650–5,350 m), and exhibit considerable tectonicdeformation. These factors gave rise to a variety of geological andthermobaric characteristics for different oil and gas accumulations.These characteristics are shown in Table 6-9. Average reservoir-rockproperties for the units and suites of Bakhar Field are presented inTable 6-10.

Field Development

Regularity of oil and gas distribution along the stratigraphic sectionindicates that these multi-bedded gas and oil accumulations occurwithin a single hydrodynamic system. Gas accumulations containsignificant amount of condensate, which increases from 150 to 210g/m3 with depth. One of the characteristic features of gas-condensateaccumulations in the Bakhar Field is the residual oil saturation (up to37%) in the gas reservoirs. This particular feature is of great impor-tance in reserve estimation and field development.

Reservoir rocks (sandstones and siltstones) are of good quality.Average porosity varies from 14 to 22%, average permeability rangesfrom 12 to 166 mD, and water saturation changes from 8 to 56%.

The pilot production of gas-condensate pools with oil rims (UnitX) was carried out without reservoir-pressure maintenance. Significantgas withdrawal and decrease in the initial reservoir pressure causednoticeable retrograde condensation. This phenomenon was more visiblein wells located in the gas-condensate zone of Unit X. Average initialoutput of stable condensate in Wells 7, 10 and 26 was 205 g/m3, andgas/condensate ratio was 4,880 m3/t. During the pilot production ofUnit X, with reservoir pressure decrease of more than 6 MPa, theabove parameters varied up to 175 g/m3 and 5,676 m3/t, respectively.A noticeable decrease in the stable condensate yield was caused byretrograde losses occurring with liberation of light hydrocarbons fromreservoir gas system, their solution in liquid phase, and adsorption onthe pore surfaces.

Subsequently, producing wells in Unit X were drilled to the GOC.These wells simultaneously drained both gas-condensate zone and oilrim. During this phase of production, waterflooding for reservoir-pressure maintenance was not carried out. The advantages of this



Tab

le 6

-9C

har

acte

rist

ics

of

Oil

an

d G

as A

ccu

mu

lati

on

s in

th

e B

akh

ar F

ield

Oil-

and

Gas

-A

vera

geIn

itial

Res

ervo

irC

onde

nsat

eB

eari

ngU

nit

orD

epth

,P

ress

ure,

Con

tent

in

Gas

,In

terv

alS

uite

mM

Pa

Type

of

Acc

umul

atio

n g

/m3

IV

3,70

038

Gas

-con

dens

ate

100

VI

3,80

039

Gas

-con

dens

ate

150

VII

4,00

041

Gas

-con

dens

ate

160

VII

I4,

200

43G

as-c

onde

nsat

e18

0IX

4,40

045

Gas

-con

dens

ate

190

Xup

per

4,50

046

Gas

-con

dens

ate,

Oil

200

Xlo

we r

4,60

047

Oil

, G

as-c

onde

nsat

e21

0II

“Per

eryv

”4,

700

48O

il—

NK

P5,

000

51G

as-c

onde

nsat

e15

0


Tab

le 6

-10

Res

ervo

ir-r

ock

Pro

per

ties

of

Bak

har

Fie

ld

Gra

in-s

ize

Dis

trib

utio

n, %

Car

bona

teU

nit

or>

0.25

0.25

–0.1

0.1–

0.01

<0.

01C

emen

tP

oros

ity,

Per

mea

bilit

y,S

uite

mm

mm

mm

mm

Co

nte

nt,

%%

mD

V10

.012

.068

.129

.913

.511

.516

VI up

per

10.5

17.4

59.7

22.4

11.3

16.7

29V

I mid

dle

10.7

28.4

51.8

19.1

10.4

18.5

58V

II14

.828

.449

.817

.010

.317

.279

VII

I13

.030

.049

.217

.819

.518

.054

IX10

.619

.959

.819

.719

.916

.841

Xup

per

12.3

35.5

45.8

16.4

19.1

16.9

50X

low

e r13

.735

.247

.014

.118

.816

.648

“Per

eryv

”19

.845

.132

.312

.817

.214

.838

NK

P15

.422

.352

.819

.518

.314

.136

PK

17.9

32.3

36.8

13.0

15.6

13.0

33


method of development were preservation of GOC level, preventionof oil movement into the gas zone, with consequent losses of liquidhydrocarbons. For recovery of the remaining oil reserves, subsequentproducers were drilled and waterflooding was initiated.

Production of gas and gas-condensate reservoirs without oil rims(Units V, VI, VII, VIII, and IX) was due to depletion-drive mechanism.Condensate recovery factor was assumed to be 50%. The rate of gaswithdrawal from each reservoir was proportional to the in-place gasreserves. Many non-productive wells drilled to lower units wererecompleted in upper units and used for gas production.

ZONE III: BAKU ARCHIPELAGO

Baku Archipelago is situated on the offshore continuation of theLower Kura and Dzheirankechmes troughs (see Figure 6-3). Sixanticlinal trends can be distinguished here (brachyanticlinal structures).They are cut by longitudinal (axial) and transverse faults, with largemud volcanoes, many of which are active. Within the area are theSangachal–Duvanny Deniz–Khara Zyrya Oil Field, and the BullaDeniz Gas-Condensate Field.

Sangachal–Duvanny Deniz–Khara Zyrya Oil Field


Sangachal–Duvanny Deniz–Khara Zyrya Oil Field is located on thesoutheastern, offshore plunge of Utalgi-Kyanizadag anticlinal trend,and was discovered in May 1963, when 250 tons of oil per day flowedfrom Well 24 from Unit VII.

Geological study of Baku Archipelago area began in the 1930s whenthe area was studied using geophysical surveys. Seismic surveys wereconducted from 1951 to 1955, and individual uplifts were delineated.Further exploration was carried out in stages: the first stage—Unit VII(“Pereryv” Suite according to the stratigraphic column of the Apsheronarea), the second stage—Unit VIII (NKP Suite in the Apsheron areasection), and the third stage—PK Suite. On the crests of uplifts, wheredepth of drilled wells was relatively shallow (about 2,600 m), thesecond and third stages were combined. On the flanks, where depthto Unit VIII reaches 5,800 m, the PK Suite was allocated to the thirdexploration stage.


Geology

The Sangachal–Duvanny Deniz–Khara Zyrya Oil Field forms threeindividual uplifts/culminations which are separated by narrow, shallowsaddles. The total length of the structure is 23 km. It is slightlyasymmetrical with a steep northeastern flank (dips are about 28°) andrelatively gently sloping southwestern flank (dips are about 15°). Thestructure is cut by two axial (longitudinal) and several transversefaults. These faults divide the whole structure into nine fault blocks(Figure 6-14). The crestal area, located between two longitudinalfaults, is raised above both flanks and has a horst character. Displace-ment of Fault 1 is 200–500 m, whereas that of Fault 2 is 80–90 m.

The Sangachal uplift is located south of Sangachal Cape. It is 8 kmlong and 7.5 km wide. Two transverse faults (3 and 4) cut its north-eastern flank. Near-longitudinal fault displacements are about 50 mand decrease to 30 m on the plunge of anticline. The Duvanny Denizuplift is located southeast of the Sangachal uplift. This anticline is 10km long and 7.5 km wide. Two transverse faults (5 and 6) cut thenortheastern flank. Near-longitudinal displacement of Fault 5 is about50 m and decreases toward the edge of the structure. Fault 6 is oneof the largest transverse faults and its displacement is 170 m. This faultseparates the Duvanny Deniz and Khara Zyrya structures.

Commercial oil was found in Unit V (Unit VIII in the Apsheronarea) and in Unit VII (“Pereryv” Suite in the Apsheron area). Com-mercial oil and gas-condensate was found in Unit VIII (NKP Suite inApsheron area). All accumulations are located on the northeasternflank of anticline. The accumulation in Unit VIII is slightly shiftedtoward the flank relative to that of Unit VII. That is why wells drilledon the crest of structure produced commercial oil from Unit VII andonly water from Unit VIII.

Oil saturation of Unit VII within the limits of the Sangachal upliftwas found at a depth of 3,600–5,240 m; at 2,200–4,200 m, at the DuvannyDeniz anticline; and at 3,700–4,500 m, at the Khara Zyrya anticline.

Reservoir rocks consist of sand, sandstone, and siltstone with lateraland vertical heterogeneity. Porosity varies from 17.7 to 23.6% andpermeability from 5 to 540 mD. Reservoir rock properties improvefrom the crestal area in two directions: from the northeast to southwest(to the flank of structure) and from the northwest to southeast (to theplunge of structure). The basal member of Unit VII has the bestreservoir-rock properties.


Fig

ure

6-1

4. S

truc

tura

l m

ap o

n to

p of

the

Uni

t V

II o

f S

anga

chal

–Duv

anny

Den

iz–K

hara

Zyr

ya O

il F

ield

(M

odifi

ed a

fter

The

ory

and

Pra

ctic

e…,

1997

). 1

—F

ault,

2—

cros

s-se

ctio

n lin

e, 3

—co

ntou

r lin

es o

n to

p of

the

Uni

t V

II,

4—in

itial

OW

C.


The primary oil-bearing reservoir is Unit VII, where crude oil is ofparaffinic-naphthenic type, wax-bearing, and devoid of sulfur. Oildensity is 0.865 g/cm3 and crude oil viscosity at reservoir conditionsis 1–2 cP. A gas cap is found only at the crest of the Sangachal uplift.Dissolved gas is dry with a methane content up to 95%.

Initial reservoir pressure adjusted for the OWC level exceededhydrostatic pressure by 7 MPa. Bubble-point pressure was below initialreservoir pressure by 5–7 MPa and increased with depth. Initialreservoir drive was elastic water drive. Because of the pressure dropin zones of extensive oil withdrawal and well operation with very highdrawdowns (up to 20 MPa), the dissolved gas drive became operativein some areas of reservoir. The average initial GOR based on theanalyses of downhole samples and surface measurements during theinitial phase of development varied within the limits of 100–125 m3/t.

Field Development

Pilot production of Unit VII at the Sangachal area began in July1965. During initial production, oil withdrawal was very high, thereservoir pressure decreased significantly (0.6–1.0 MPa per month) anddropped below bubble-point. Flow rate decreased to one-third (from150 to 45 tpd or from 1,095 to 292 bpd), and the gas/oil ratio in somecrestal wells increased from 120 to 1000 m3/t due to gas-cap expan-sion. Waterflooding for reservoir-pressure maintenance was initiatedin August 1971. Although its implementation was efficient, decreasein the reservoir pressure did not stop completely.

Pilot production of Unit VII at Duvanny Deniz (Fault Blocks II, IIIand IV) began in May 1963. Flow rates were up to 350 tpd (2,555bpd), with significantly lower drawdown (6–8 MPa) than that at Sangachalarea. A decrease in reservoir pressure and daily oil-production, andan increase in GOR took place during reservoir production becauseformation stimulation was not implemented. Waterflooding wasinitiated in July 1971, for reservoir-pressure maintenance. Waterinjection resulted in increased flow rate from wells located near theinjection wells.

Reservoir stimulation at Duvanny Deniz area was more successfulthan at Sangachal because of better reservoir-rock properties. Waterinjection resulted in a decrease in GOR and higher production rates(Table 6-11). After two years, reservoir pressure increased from 18 to


Tab

le 6

-11

Co

mp

aris

on

of

Wel

l P

aram

eter

s B

efo

re a

nd

Aft

er W

ater

flo

od

ing

at

the

Du

van

ny

Den

iz A

rea

Wel

l P

aram

eter

s B

efor

e W

ater

flood

ing

Wel

l P

aram

eter

s A

fter

Wat

erflo

odin

g

Cho

keW

ellh

ead

Oil-

flow

Cho

keW

ellh

ead

Oil-

flow

We

llB

lock

Dia

me

ter,

Pre

ssu

re,

Ra

te,

GO

R,

Dia

me

ter,

Pre

ssu

re,

Ra

te,

GO

RN

o.

No

.m

mM

Pa

ton

s/d

ay

m3 /

ton

mm

MP

ato

ns/

da

ym

3 /to

n

115

II15

2716

31,

623

1630

160

200

117

II14

3819

01,

489

2817

204

194

119

III

1552

160

2,07

125

1716

136

022

7IV

1492

110

1,58

229

1631

215

8


22 MPa (at a depth of 3,761 m) and some wells began flowing inresponse to reservoir-pressure maintenance.

Another productive interval is the gas-condensate pool in Unit VIII.This accumulation was discovered in 1968 by Well 58. Gas andcondensate flowed from a depth interval of 4,569–4,589 m at a rateof 500 Mcmd (17,650 MMcfd) at wellhead pressure of 28 MPa.Subsequent wells produced gas and condensate from an interval of3,762–5,040 m at wellhead pressure of 10–20 MPa. Flow rate of gasvaried from 300 to 600 Mcmd (10,590 and 21,180 MMcfd), whereasthe condensate production varied from 50 to 150 tpd (365 to 1,095 bpd).

At present, this reservoir is producing from nine wells which aresufficient for reservoir depletion in the absence of an oil rim.

Bulla Deniz Gas-Condensate Oil Field


The Bulla Deniz structure is located within the northern portion ofthe Baku Archipelago, southeast of the large Sangachal–DuvannyDeniz–Khara Zyrya Oil Field (see Figure 6-3). Geological explorationof the structure began in the 1930’s when the geophysical surveys wereconducted at the Baku Archipelago. Pendulum gravimetry, regulargravimetry, and electrical surveys, however, did not discover the BullaDeniz structure. Offshore seismic survey conducted in 1951 alongseveral profiles identified an independent brachianticline. In 1953–1955, the brachianticline was fully delineated and the southeastwardplunge outlined. In the 1960s the Productive Series was studied and,sometimes, the underlying Miocene-Paleocene deposits were alsoexamined. Since 1974, CDP seismic has been conducted, mainly (since1976) on the northeastern flank and southeastern plunge.

Drilling shallow wells for mapping purposes was started in the BullaDeniz area in 1955 and continued intermittently in 1958, 1960–1964,1965, and 1970. Due to the great thickness of loose sediments, therewere no positive results prior to 1970, when indurated Quaternarysediments were penetrated beneath the soft shales. In 1965, coredrilling was begun to study the structure, lithofacies and petroleumpotential of the Apsheronian Stage and the Upper Productive Series.Two transverse profiles of the core wells (Wells 1, 2, and 3 over the


central portion of the structure, and Wells 4 and 5 northwestward ofWell 1) penetrated rocks of the Quaternary, Apsheronian, Akchagylianand, in part, Productive Series section. Well 2 revealed gas show at adepth of 1,413 m while drilling in the Productive Series.

The anticlinal structure of the Bulla Deniz Field, and the gas showsand oil gushers obtained from the Productive Series at the nearbyKhara Zyrya structure encouraged exploratory and appraisal drilling.The appraisal program included the drilling of 32 wells in sevenprofiles across the axis of anticline. The profile spacing was 2 km overthe crest and 2.5 km over the plunges. The well spacing was 1,200 mand 1,500–2,250 m, respectively. Two wells were proposed to bedrilled over the axial zone of the southeastern plunge of anticline ata distance of 2.5 km from each other (Figure 6-15).

One group of wells (25 in number) had been proposed to penetratethe Productive Series down to the units VII–VIII to study the lithologyand the presence of oil and gas. The second group (5 wells) was intendedto penetrate the entire Productive Series with the same basic objective.

At the first stage of the drilling program (1966–1972), three wellswere drilled. One of them penetrated Unit VII, whereas the other two,located on the southwestern flank of anticline (they were 200–300 mdeeper than PTD) failed to reach Unit V. They were plugged andabandoned. Analysis of the well data indicated that the target unitswould be penetrated at a depth of about 6,000 m (Figure 6-15b).

In September 1973, Unit VII at the northeastern flank of anticline,and in April of 1974, Unit V were tested in Wells 18 and 14. Theyflowed gas (1 MMcmd or 35.3 MMcfd, and 400 Mcmd or 14.1MMcfd) and condensate (250 tpd or 1,825 bpd and 70 tpd or 511 bpd),respectively. These results caused reconsideration of the drillingprogram design. The drilling was then concentrated over the north-eastern flank and over the axial zone of anticline, to delineate accumu-lations of units V and VII.

The appraisal drilling resulted in the evaluation of (1) gas accumu-lation with an oil rim in Unit V, (2) gas-condensate accumulation inUnit VII, and (3) petroleum potential of the Lower Productive Series.In July 1982, Well 56 on the northwestern plunge penetrated Unit VIII(NKP Suite in the Apsheron Peninsula section). It tested gas (1,100Mcmd or 38.8 MMcfd) and condensate (550 tpd or 4,015 bpd). A fewdays after the well was put on-line, oil appeared in the production.


Figure 6-15. Structural map on top of the Unit V of Bulla Deniz Gas andOil Field (a) and geologic cross-section (b) (Modified after Theory andPractice…, 1997).

Geology

It was believed that the Productive Series Formation was 4,000-mthick over the crest and increased to 4,500 m on the flanks of anticline.Its upper, shaly part was not subdivided. Beginning at the top andcontinuing to Unit V, this interval was 3,200–3,350 m thick. It con-sisted of a monotonous shaly sequence with rare thin sands. The lower


section (down from Unit V) was analogous to the Units VIII–IXof the Apsheron Peninsula section and was a favorable oil-gas target.It was 135-m thick and consisted of interbedded thick sandstones,sands, siltstones, and shale. Sandstones and sands were light- todark-gray, slightly bluish, fine- and very fine-grained, carbonaceous,and often with gas odor. The shale was dark-gray to gray, bluish,brownish and reddish, sometimes slightly sandy, dense, carbonaceous,with slickensides. Petrophysically, the unit can be subdivided intotwo members. The upper one was shalier and had resistivitiesin the range of 3 to 5 ohm • m. The lower one was sandier withresistivities of 10 to 20 ohm • m, and the permeability was highaccording to SP data. On the average, net sand thickness reached 50%of the section.

Units V and VII were separated by a uniform shale member, 325m in thickness, with resistivity of 2 to 4 ohm • m and an almostundifferentiated SP curve. Some thin sands appeared in the lowersection. The sand content of the entire unit was 10%.

Unit VII was equivalent to the “Pereryv” Suite of the ApsheronPeninsula and consisted of light- to dark-gray, carbonaceous, fine- tovery fine-grained quartz sand with oil and gas odors. Shale was darkgray, sometimes dark gray and brown, dense, carbonaceous and sandy.The sands had resistivities of 10 to 20 ohm • m, with peaks of up to40 ohm • m; shales had resistivities of 3 to 5 ohm • m. Unit VII hadthe greatest net sand content of up to 65%.

The NKG Suite consists of shale (90% of the section) and thin sand.The thickness ranges from 180 to 250 m. This suite had been com-pletely penetrated in Well 56 (220 m).

Unit VIII (the NKP Suite at Apsheron Peninsula) consisted of gray,fine-grained, carbonaceous, sandstones and sands with thin shalelayers. The thickness was about 50 m, with the net gas pay of approxi-mately 10 m. The sand layers were 4 to 5-m thick and representedup to 70% of the section. The apparent resistivity was 10 to 15ohm • m and the SP curve was clearly defined.

The Bulla Deniz structure is located within the northern anticlinaltrend of the Baku Archipelago, which includes other anticlinal trendsand about 30 local uplifts. The area is characterized by large axialfaults over structural crests. Many such faults, with displacement ofup to 1,000 m, were observed along the entire length of the anticlines.Mud-volcano activity (with gas seeps and oil film) were frequentlyassociated with these faults.


At the top of Unit V, the Bulla Deniz is a large northwest-trendingbrachianticline, 19 by 9 km, with the closure of up to 1,600 m on thenortheastern flank (see Figure 6-15). The structure is slightly asym-metric. The dips change from 22° near the crest to 20° at the north-eastern flank and from 20° to 16° at the southwestern flank, respectively.The far northwestern plunge joins the southwestern flank of the KharaZyrya structure, over a narrow syncline. The southwestern flankmerges with a broad Kichikdag-Umid synclinorium. The southeasternplunge turns east and forms a structural nose with a small separatehigh discovered by seismic survey.

The crest of the anticline and the adjoining southwestern flank arecut by two northwest-southeast trending longitudinal faults confirmedby seismic and drilling data (see Figure 6-15). In the wedge betweenthe faults, seismic data acquisition was difficult, and steep dips wereencountered in wells. For instance, core measurements in Wells 10,30, and 36 showed angles greater than 70°, whereas on the flanks theywere less than 20°.

Longitudinal (axial) faults subdivide the anticline into several faultblocks. The northeastern block is upthrown against the central portionof the structure and the southwestern block. The longitudinal faultseparating the northeastern flank from the southwestern flank and thecentral portion of the structure has a displacement of about 500 m.The wedge is upthrown against the southwestern flank by more thana thousand meters on the second longitudinal fault.

At Unit V, two transverse faults (and three fault blocks) are observedon the northwestern flank. The fault between Blocks I and II hasa displacement of 70 to 80 m and is characterized by difficult acqui-sition of seismic data. The fault separating Blocks II and III has15–20 m of displacement and is intersected by Well 13, in whichthe thickness of Unit V is decreased to 85 m at the expense ofthe lower portion cut by the fault (the average thickness is 136 m).Unit V in Well 16 (4,618–4,614 m interval) tested water (280 cmd or2,044 cfd).

Three fault blocks of the southeastern flank form a step-like struc-ture. The westernmost Block IV is downthrown 1000 m against thecentral block. The easternmost Block VI is upthrown 300 m against it.

Therefore, the Bulla Deniz structure, like the other structures ofthe Baku Archipelago, is a complicated anticline broken into separatefault blocks.


Field Development

Oil and gas accumulations within the Bulla Deniz Field are asso-ciated with the Productive Series (Middle Pliocene). Commercialproduction was obtained from Units V, VII and VIII on the north-eastern flank. These units were not penetrated in the exploratory wellsof the southwestern flank. The entire section shallower than Unit Vwas of no commercial interest.

The first gas (1 MMcmd or 35.3 MMcfd) and condensate (250 tpdor 1,825 bpd) in the field were produced in September 1973, duringthe test of Unit VII in Well 18 (5,190–5,203 m interval). In April 1974,Well 14 flowed 400 Mcmd of gas and 70 tpd of condensate (respec-tively, 14.1 MMcfd and 511 bpd) from Unit V (4,615–4,592 m interval).In June 1982, Well 56 tested 800 Mcmd (28.5 MMcfd) of gas and250 tpd (1,825 bpd) of condensate from Unit VIII.

Based on the test results and pilot production, a gas-condensateaccumulation within the small oil rim was established in Unit V. InUnit VII, a gas-condensate accumulation was proven, with an oil rimin the lower portion of the southeastern plunge. Unit VIII accumulationis gas-condensate-oil; a few days after putting Well 56 on-line, someoil began to appear in the output.

Unit V was penetrated in 24 wells. Five of them were tested; Wells14 and 23 produced commercial gas and condensate, Well 9 flowedcommercial oil, and Wells 16 and 23 produced water.

Gas-oil contacts (GOC) within Block II were determined from Wells14, 9 and 23. Based on the Well 9 data, it was found that the GOC islocated at the upper level of the perforated interval: 4,811 m (–4,828m subsea). The well was put on-production in May 1975, with theinitial flow rate of 168 tpd of oil and 60 Mcmd of gas (respectively,1,226 bpd of oil and 2.1 MMcfd of gas), through a 12-mm choke. InAugust, it began to produce gas (166 Mcmd or 5.9 MMcfd) andcondensate (139 tpd or 1,015 bpd). Such a rapid change in the typeof produced fluid indicated that the perforated portion of the reservoirwas within the oil zone, close to the GOC. This assumption wassupported by the performance of Wells 14 and 23 with gas andcondensate flow.

The OWC within Block II was established from the Well 9 test andfrom microlog data in the closely located Well 45, which was corre-lated with Well 9. Based on logs, the OWC was established at 4,848.5 m


(–4,865.5 m subsea), which is 6.5 m deeper than the lowermostperforations in Well 9 (which produced oil with no water).

Unit V was not tested in Block III. Gas saturation there was estab-lished from logs. The location of OWC was based of the lowermostoil-saturated layer in Well 35 (5,618 m or –5,633 m subsea). It wasbelieved that the oil rim width here is similar to the one in the testedBlock II.

The accumulation outline in Unit V was drawn considering the factthat the accumulation top does not coincide with the stratigraphic topof the unit, due to the presence of a 62-m thick shale in Block II anda 76-m thick shale in Block III. The structure was mapped at thestratigraphic top of the unit, whereas the GWC was taken from thecross sections which reflect the oil saturation.

Unit VII was tested in 26 wells. The gas-condensate accumulationin Block II was outlined at 6,172 m (–6,189 m subsea) based on testresults from Well 38, which produced gas (400 Mcmd or 14.1 MMcfd)and condensate (130 tpd or 950 bpd). All wells within this outline didnot produce water, which led to the belief that the GWC was locateddown-dip from Well 38. Calculation results for Well 25 showed thatGWC is at 6,518 m; with the necessary corrections, its subsea depthin Block II is at –6,537 m.

In Block I, Unit VII was tested in Well 58 (October 1983). Therewas a flow of gas (500 Mcmd or 17.1 MMcfd) and condensate (100tpd or 730 bpd) from the 6,135–6,098 m interval. Size of accumulationwas tentatively defined by the deepest structural contour at –6,000 msubsea. The gas-condensate accumulations are probably present withinBlocks V and VI on the southwestern flank. The accumulation outlinethere was postulated from an analogy with the developed part of BlockII at –6189 m.

Unit VIII was tested in the exploratory Well 56 in July 1982. Thewell flowed 800 Mcmd of gas (28.2 MMcfd) and 250 tpd of conden-sate (1,825 bpd) from the 6,097–6,088 m interval. Some oil appearedin the production, which suggested the presence of an oil rim.

Commercial accumulations within the Bulla Deniz Field were estab-lished in Units V, VII and VIII over the northeastern flank. Futurepotential will be established upon the additional appraisal of Units Vand VII at the plunges and the southwestern flank and upon penetrationof the Lower Productive Series where Unit VII is the prime target.

113

CHAPTER 7

General Regularitiesin Oil and Gas

Distribution

I. AZERBAIJAN PORTION OF THESOUTH CASPIAN BASIN

Environments of Deposition

One of the most important aspects in reservoir characterization isan understanding of depositional environments in the area under study.Depositional environments and facies relationships, diagenesis andcatagenesis strongly affect the size, shape, pore-space geometry,porosity, permeability, and location of clastic deposits.

The main oil- and gas-bearing region in Azerbaijan and the SouthCaspian Basin is the western portion of Apsheron–Pre-Balkhan anti-clinal trend (Figure 7-1) and the main oil- and gas-bearing formationwithin this region is the Productive Series of Middle Pliocene (Figure7-2). The Productive Series is separated into two divisions (lower andupper) and into several suites according to their lithological composi-tion, i.e., prevalence of sands or clays. The rocks include sands,sandstones, siltstones, loams, clays, shales and unsorted rocks (chlidolites).Middle Pliocene deposits within the area under study are devoid offauna. As a consequence, their stratigraphic position in the section isdetermined by the faunal characteristics of the underlying (Pontian)and overlying (Akchagylian) deposits. The separation into divisionsand suites is generally made on the basis of lithology, taking intoconsideration the rhythmic deposition of the Productive Series sediments.Thus, the lower division consists of (from bottom upward) the following


Fig

ure

7-1

. S

truc

tura

l m

ap o

f th

e A

pshe

ron

Arc

hipe

lago

(M

odifi

ed a

fter

Bag

ir-za

deh

et a

l., 1

974)

. 1—

Isos

eism

s in

met

ers

on t

op o

f th

e P

lioce

ne;

2—is

obat

hs i

n m

eter

s; 3

—fa

ults

; 4—

zone

s of

abs

ence

of

refle

ctio

ns,

asso

ciat

ed w

ith f

aults

;5—

abse

nce

of r

efle

ctio

n zo

nes;

6—

faul

ts b

ased

on

seis

mic

sur

vey

data

.

General Regularities in Oil and Gas Distribution 115

suites: Kala (KaS), Podkirmaku (PK), Kirmaku (KS), NadkirmakuPeschanaya (Sandy) (NKP), and Nadkirmaku Glinistaya (Shaly) (NKG)suites. The upper division consists of the following suites: “Pereryv,”Balakhany, Sabunchi, and Surakhany suites (Figure 7-2). The thicknessof the Productive Series increases in the direction of the centralpart of the South Caspian Basin from 1,500 m within the ApsheronPeninsula to 3,150 m within the Apsheron archipelago, to 4,150 mwithin the South Apsheron Offshore Zone, and to 4,400 m within theBaku Archipelago.

The terrigenous (siliciclastic) rocks of the Productive Series havegray color in the lower division, whereas above they are grayish

Figure 7-2. Typical logs (Resistivity and SP) of the Productive Series.


brown. The rocks within the Apsheron Peninsula are composed ofquartz and feldspar, whereas within the Apsheron and Baku archi-pelagoes they become polimictic-arkose, arkosic-graywacke andgraywacke. The cement is usually composed of clays and carbonateswith a significant predominance of clays. The cement types include(1) intergranular, (2) cement between the grains, and (3) cement filmon pore walls. Sorting of the siliciclastics improves noticeably upwardin each sedimentary sequence.

Core data, paleontological and log analyses suggest that the ProductiveSeries sediments were deposited in a relatively shallow-water, fluvial-deltaic environment (Figure 7-3). The large volume of clastics, formingthe Productive Series, indicates proximity of sediment sources. TheRussian Platform, Kilyazi-Krasnovodsk anticlinal trend, islands existingnorth of the Apsheron Peninsula and the Apsheron Archipelago, and

Figure 7-3. Pliocene paleogeoraphic (depth) curve (1) and subsidence curve(2) for the Apsheron Peninsula and Apsheron Threshold areas.


the southeastern slope of the Greater Caucasus, served as primarysources for clastic material (Apsheron type of lithofacies) for theApsheron Peninsula and the adjacent Caspian Sea offshore. Weatheringof older Mesozoic-Paleogene volcanic and sedimentary rocks from theGreater and Lesser Caucasus and Talysh mountains, served as primarysources (Gobustan type of lithofacies) of sediments for the Lower KuraRegion and the Baku Archipelago. The clastics were transported anddeposited by Paleo-Volga, Paleo-Ural, Paleo-Kura, and other paleo-rivers.

The major distribution pattern for reservoir rocks in the ApsheronOil and Gas Region as a whole, and within individual areas in particu-lar, is a systematic change in mineral composition and decrease ingrain size with increasing distance from the provenance (Buryakovsky,1970b, 1974a). With increasing distance to the south and southeastfrom the paleo-shoreline of the North Caspian Sea, depth to theproductive reservoirs increases, sand content decreases, and shale andsilt content increases. More drastic changes occur in the transition zonefrom the Apsheron Peninsula, Apsheron Archipelago and South ApsheronOffshore Zone to the northern Baku Archipelago, where Apsheron-typelithofacies, although preserving their main features, include moreGobustan-type lithofacies. For instance, (1) shale content increasesfrom 15% to 40%, (2) sand content decreases from 40% to 15%,(3) grain size decreases from 0.08 to 0.02 mm, and asymmetry ofstatistical distribution of grain size increases slightly (0.8 to 1.1). Atthe same time, silt content changes from 40 to 62%, which causes thesorting to remain practically the same (3.0 to 3.9).

The Productive Series is divided into seven sedimentary sequencesaccording to the transgressive/regressive cycles during development ofthe sedimentary basin (Figures 7-2 and 7-4).

In the lower section there are three sequences:

1. Kala Suite2. Podkirmaku and Kirmaku suites3. Nadkirmaku Sandy and Nadkirmaku Shaly suites

In the upper section there are four sequences:

4. “Pereryv” Suite, and Units X and IX of the Balakhany Suite5. Units VIII, VII and VI of the Balakhany Suite6. Unit V of the Balakhany Suite, and Units IV, III and II of the

Sabunchi Suite7. Units I, I′, A, B, C, D of the Surakhany Suite


Each sequence displays fining upward, from coarse-grained sandsat the base to the finer sands, siltstones and shales at the top. Further-more, in each sequence, the shale content increases and the sandcontent decreases up the stratigraphic column. For instance, within thefifth sequence at the Bakhar Field, shale content increases from 17.8%in Unit VIII to 29.9% in Unit VI; silt content changes, respectively,from 49.2% to 69.1%; and sand content decreases from 33.0 to 2.0%.This deposition pattern is dependant on the tectonic regime anddepositional environments of the South Caspian Basin.

Shallow-marine fossils, fresh-water ostracods, and glauconite in coresamples indicate a mingling of marine and continental environmentsespecially at the base of each transgressive/regressive cycle. Individuallayers in the suites of the Productive Series have been identified as

Figure 7-4. Cross-section of third, fourth and fifth sedimentary sequencesof the Productive Series along the line Karadag area—Artyom Island (PirallaghiAdasi). 1—clay/shale, 2—sand, 3—sand with gravel admixture.


either stream-mouth bar deposits, distributary channel-fill sands, point-bar sands, crevasse sands, or transgressive-sheet deposits. Stream-mouth bar and point-bar deposits often occur as a deltaic couplet withpoint-bar sands of the delta plain prograding across underlying stream-mouth bars of the delta front. These delta-plain deposits either cut intoor are slightly separated from the underlying delta-front deposits. Sucha deltaic couplet is often found throughout the Apsheron Peninsula andApsheron Archipelago at the base of “Pereryv” Suite (the first breakof deposition). The upper intervals of each transgressive/regressivecycle, however, are characterized by more distinctive rocks. Thisportion of the upper parts of transgressive/regressive cycles appearsto indicate the migration of the delta or distributary-channel system,so the delta began building elsewhere. Many of these rocks appear tobe crevasse sands formed as the distributary reached the flood stageand broke through a levee into adjacent interdistributary bay areas.

Principles of cyclic sedimentation were applied for subdividing thesedimentary section and for selecting intervals for reserve estimation(Abasov et al., 1997).

To analyze the sequences of the Productive Series sedimentarysection within the Azerbaijan onshore and South Caspian offshoreareas, these authors used a parameter which demonstrates relative sandcontent within an individual transgressive/regressive cycle. The indi-vidual cycle consists of two layers, i.e., sand-silt (reservoir rock) andshale (non-reservoir rock). Ratios of sand-silt and shale layers withineach individual transgressive/regressive cycle allow plotting of thecurve of sand content variation in the entire sedimentary sequence.When the individual cycles are combined to constitute a sequence ofhigher order, sand content decreases and shale content increases towardthe sequence top. On this basis, the authors have defined the followinglevels of cyclic sequences: “elementary” (with two layers), “pack”(with 4 to 6 layers), “group” (with 8 to 12 layers), and “formation”(with 12 to 30 layers and more). Individual layers can be defined asthe “group of layers” level where one observes a large increase inshale content toward the sequence top. This provides a systematiccorrelation within the area and indicates the oil and gas contents.“Formation” level applies to thick sequences (suites), which have beenidentified at the Apsheron Peninsula by many scientists on the basisof grain-size distribution and mineral composition of sedimentary rocks(Potapov, 1954, 1964). This procedure is used for log correlations.


Oil and Gas Traps

The oil and gas accumulations in the Productive Series are restrictedto anticlines and are limited to their crestal portions and to thesouthwestern and, sometimes, northeastern flanks. These anticlines,like the accompanying faults, belong to the Upper Mesozoic tectonicevent. The faults almost always govern the distribution of oil and gasin individual strata.

The classification of oil and gas traps, in general, and of Azerbaijanoil and gas fields, in particular, has long been studied by numerousworkers, including Abramovich (1948), Babazadeh (1960), Brod (1945,1951), Gubkin (1937), Khain (1954), Krems (1954), Mirchink (1939),Potapov (1954), and Vassoyevich (1930). Within the Apsheron oil- andgas-bearing region, four types of oil and gas traps are distinguished(Figures 7-5 and 7-6):

1. Anticlinal non-faulted traps2. Anticlinal faulted traps3. Stratigraphic traps4. Lithologic traps

Examples of each type of traps are shown in Tables 7-1 to 7-4. Table7-5 summarizes some statistics on the trap-size distribution.

For example, within the Apsheron Archipelago, anticlinal faultedtraps as well as non-faulted traps containing oil accumulations areassociated with the Kirmaku and Podkirmaku suites of Darvin Bank—Pirallaghi Adasi (Northern Fold)—Gyurgyan Deniz oil fields (Figure7-7). Similar types of reservoirs, but separated into fault blocks, arerestricted to the Kirmaku, Podkirmaku, and Kala suites at Neft Dashlaryand Palchygh Pilpilasi fields (Figures 6-5 and 6-9).

Stratigraphic traps wedging-out upward along the slope have beenfound in lower units of the Kala Suite at Palchygh Pilpilasi and ChalovAdasi fields, where they rest with stratigraphic unconformity on theunderlying deposits. Stratigraphic traps may include only oil accumu-lations in the Kala Suite of Gyurgyan Deniz Field (southern plungeof Pirallaghi Adasi Field). Accumulations in the Upper ProductiveSeries at Dzhanub, Neft Dashlary, Gyuneshli, and Azeri fields arefaulted traps. At Neft Dashlary Field, they have been separated intonumerous fault blocks and are restricted to the southeastern flank of



Figure 7-5. Examples of structural (anticlinal) traps/reservoirs within theApsheron oil- and gas-bearing region. 1—Bibieibat Field, structural, slightlyfaulted oil reservoir in Unit XI-XII; 2—Karachukhur Field, structural, moderatelyfaulted oil reservoir in Unit KS4; 3—Kala Field, structural, highly faulted oiland gas reservoir in Unit II; 4—Surakhany Field, structural, highly faultedoil reservoir in Unit C; 5—Bibieibat Field, structural trap cut by longitudi-nal fault in PK Suite; 6—Kala Field, block-faulted oil reservoir in PK Suite;7—Mishovdag Field, block-faulted oil reservoir in Unit I; 8—Surakhany Field,two block-faulted oil reservoirs in PK Suite; 9—Kyurovdag Field, block-faultedoil reservoir along longitudinal fault in Unit I; 10—Chalov Adasi Field, oilreservoir in underthrust block in PK Suite.


Figure 7-6. Examples (maps and cross-sections) of stratigraphic and lithologictraps/reservoirs within the Apsheron oil- and gas-bearing region. 1—Binagady-Chakhnaglyar Field, stratigraphic trap: up-dip pinchout of PK Suite reservoirrocks; 2—Shabandag–Yasamaly Valley Field, stratigraphic trap: up-dip pinch-out of KS Suite reservoir rocks; 3—Duvanny Field, lithologic trap: shale-outof gas reservoir in Unit V; 4—Gezdek Field, lithologic trap in Unit VIII.


Figure 7-7. Distribution of oil accumulations in the PK and KS suites ofthe Darvin Bank–Pirallaghi Adasi–Gyurgyan Deniz anticlinal trend (Modifiedafter Bagir-zadeh et al., 1974). 1—Structural contour lines in meters on topof the PK Suite, 2—faults, 3—outline of pinching-out of the PK Suite, 4—oilaccumulations.


Table 7-1Examples of Anticlinal Traps in the Apsheron Oil- and Gas-Bearing Region

Trap Relief, m

Unit Trap Trapor Transverse Longitudinal Width, Length,

Field Suite Cross-section Cross-section m m

Balakhany I 300 100 750 2,300Sabunchi- II 250–400 500 1,200 5,000Ramany

Surakhany C 10–40 — 300–1,200 2,300II 20–100 50 500–2,000 4,700V 80–120 100 600–2,000 4,500

Karachukhur- II 80 80 1,500 3,000Zykh IV–V 75 50 1,500 3,500

VI 60 50 900 2,500NKP 40 50 750 1,250KS 300 — 1,200 2,000

Kala II 120 100 1,000 1,900V 70 90 800–1,200 2,500NKG 100 100 1,200 2,800NKP 80 50 900 2,200

Binagady KS1–2 200 300 700 1,800KS4 300 — 200–700 4,000

Atashkyah- NKP 50 270 700 1,000Shubany

Bibieibat V 340 — 2,000 4,500XI–XII 150 120 1,200 3,000NKP 350 400 1,600 4,000KS1 500 500 1,600 6,500PK 20–200 700 800–1,500 5,500

Puta- IV 300 200 500 3,550Lokbatan VI 300 200 150–300 3,750

VII 400 300 600–800 5,000VIII 600 500 400–600 4,000

Pirsagat I, II, III 100 — 600 2,600

Duvanny VII 175 175 1,400 4,000


Table 7-2Examples of Fault Traps in the Apsheron Oil- and Gas-Bearing Region

Trap Relief, m



Balakhany- KS 1,600 1,950 1,250–2,000 8,000Sabunchi- PK 1,200–1,600 2,500 1,200–2,000 9,000Ramany

Surakhany KS 480–560 120 800 3,000PK 380–450 100 400–900 7,500

Karachukhur- KS 600 — 1,000 3,700Kykh PK 875 750 2,000 7,500

KaS 750 750 1,600 7,000

Buzovny- V 20 20 250 1,500Mashtagi NKP, NKG 50 100 700 3,250

KS 80 40 500–1,000 7,000PK 100 80 500–2,000 7,000

Pirallaghi Adasi KS 400 500 600–1,200 2,800(North) PK 450 450 1,200–1,400 5,000

Pirallaghi Adasi KS 300–500 400 300 2,100(South) PK 600 600 750 2,800

Neft Dashlary Balakhany 800 1,000 1,200 3,000NKPSW flank 400 800 700 3,500NKPNE flank 1,000 1,200 1,500 5,000KSSW flank 1,000 1,200 1,800 5,000PKSW flank 1,000 1,400 1,200 6,000PKNE flank 800 1,200 1,500 3,500KaSSW flank — 1,400 1,500 6,000KaSNE flank 600 400 750 2,500

Chalov Adasi PKoverthrust 200 350 450 1,800PKunderthrust 100 800 1,000 3,000KaSunderthrust 700 700 800 4,200

Darvin Bank KSSW flank 600–1,000 300 750–1,000 7,500

Gyurgyany Deniz PK 100–120 200 600 2,500

Karadag V–VI — — 1,500 8,500VII 3,500 — 5,000 12,000

Kyurovdag I 700 700 3,000 10,000

Mishovdag I 500 700 2,500 4,000

Kalmas I 250 300 2,500 5,000


the structure. Accumulations of this type are present in the NadkirmakuSandy Suite at Neft Dashlary Field.

Lithology and Properties of Reservoir Rocks

Within the Apsheron Peninsula and the adjacent South Caspianoffshore areas, clastics of Productive Series are composed mainly ofquartz, feldspar and various rock fragments. The distribution of rocktypes in each suite reflects the cyclic structure of the section. Thesection is composed of sandstones, siltstones, shales, unsorted sedi-ments, and evaporates.

The thickness of the Middle Pliocene deposits increases toward thecentral portion of the South Caspian Basin, from 1,500 to 3,200 m.The distribution of rock types in every suite of the lower and uppersections of the Productive Series proves the rhythmic nature of depo-sition, related to the transgressive/regressive cycles in the sedimen-tation basin.

The mineral composition of the Middle Pliocene deposits is charac-terized by several varieties of associations of both light and heavy


Table 7-3Examples of Stratigraphic Traps in the Apsheron Oil- and Gas-Bearing Region

Trap Relief, m



Binagady- KS5–6 1,250–1,600 — 2,000 9,000Chakhnaglyar PK 1,000–1,600 — 1,400–2,000 9,000

Sulutepe KS 700 — 2,000 4,000PK 250 — 600 3,500

Shabandag KS 1,600 — 1,600–2,000 9,200

Yasamaly PK 500 — 600 5,000Valley

Kala KaS 200 100 1,200 3,200


minerals. The quantitative alternation of minerals makes it possible todistinguish different lithofacies types. Rocks of the Middle Pliocenesequence are characterized by the quartz and feldspar-quartz compo-sition. Siliceous rocks are predominant in the detrital rocks. Heavyminerals include muscovite, biotite, chlorite, epidote, ore minerals(magnetite, pyrite, limonite), and stable minerals (zircon, garnet,tourmaline); kyanite, staurolite, and occasional sillimanite are presentin almost all detrital rocks. This association of light and heavy mineralsrepresents the Apsheron type of lithofacies in accordance with thesuggestion of V. P. Baturin (1937).

Table 7-4Examples of Lithologic Traps in the Apsheron Oil- and Gas-Bearing Region

Trap Relief, m



Binagady NKP 400 — 350 1,800KS1–4 200–700 — 200–450 6,000

Kergez- V 150–200 — 600 2,400Kyzyltepe VI 50 — 150 1,400

VII 100 — 200 1,400

Gousany KaS2 500 — 1,400 2,500KaS3 300 — 1,600 2,500

Pirallaghi KSIV 200 300 1,200–1,400 2,600Adasi

Duvanny V 285 — 600 3,600VIII 400 400 1,200 3,600

Neftechala I 200 — 600 2,400II 100 — 200–600 1,400III 150 — 600 1,400

Karadag- VIII 1,000 — 2,000 5,000Kushkhana

Gezdek VIII 300 300 1,000 2,000


Tab

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f Tr

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3,35

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3.54

3.28

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4.52

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11.3

17.5

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381.

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520

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3.68

13.4

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54.

362.

70


Petrography of the Productive Series was examined mathematically(Buryakovsky, 1970a; Buryakovsky and Kukhmazov, 1975). Therelationship of the heavy mineral assemblage to rock composition wasdetermined. Five heavy mineral groups were identified: ore minerals(pyrite, magnetite, limonite, leucoxene), stable minerals (garnet, zircon,tourmaline, rutile), kyanite or disthene (disthene, staurolite, silli-manite), micas, and glauconite. The distributions (contents) of thesemineral groups in rocks is shown in Figure 7-8.

Figure 7-8. Statistical distribution of heavy-mineral content (%): a—oreminerals (Co), b—stable minerals (Cs), c—kyanite (disthene) group (Ck),d—micas (Cm), e—glauconite (Cg).


The triangular diagrams show rock composition: quartz (Q), feldspar(FS), and rock fragments (RF). Figure 7-9 shows the lines of equalconcentration of heavy minerals with the mineral composition of hostrocks. The content of stable minerals is generally 1 to 8%; the relativefrequency of this range is 63%. Content less than 1% is observed in8% of the cases and more than 8% in 28% of the cases. The contentof stable minerals decreases from pure quartz rocks (10%) to lithite(4%). (Lithite is a rock composed of rock fragments of sand-sizegrains.) The kyanite group of minerals is absent in 68% of the rocks

Figure 7-9. Variation in heavy-mineral content (solid curved lines) dependingon the composition of rocks (quartz, Q; feldspar, FS; rock fragments, RF).a—ore minerals, b—stable minerals, c—kyanite (disthene) group, d—micas.


studied. Their content is at a maximum in monomineralic quartzsandstones (3.8%) and a minimum in lithite (0.2%). The relationshipof reservoir-rock properties (clay content, porosity and permeability)to mineral composition of rocks is shown in Figure 7-10. Petrographicand mineralogic composition and reservoir-rock properties of terri-genous (siliciclastic) rocks discussed here are presented in Table 7-6.

The argillaceous fraction (over 65%) is represented by illite, mont-morillonite, chlorite, vermiculite, sepiolite, palygorskite, and mixed-layered minerals (alternating layers of illite and montmorillonite, illiteand chlorite, and montmorillonite and vermiculite). The kaolinitecontent in the Middle Pliocene rocks generally varies from 10 to 25%,whereas chlorite content varies from 5 to 15%.

The sandstones and siltstones are gray in color in the Lower Produc-tive Series; above, they have a grayish-brown color and become denserocks: polymictic-arkose (Apsheron Peninsula and Archipelago), arkosic-graywacke, and graywacke (Baku Archipelago). Cement is oftencalcareous-argillaceous, with predominance of argillaceous material insome cases. Occasionally, glauconite forms the cement (e.g., in the“Pereryv” Suite at the base of Upper Productive Series), whereasanhydrite is present in the Lower Productive Series (KaS and NKPsuites). Sometimes zeolite becomes one of the important componentsof cement (Bakhar Field). Chlorite and limonite cements predominatein clastic rocks of the Baku Archipelago. Cement types include “pore-filling” and “meniscus-type.” Sometimes, pores are either cementedcompletely or have a cement film on pore walls. The sorting of sand-silt deposits improves downward along the section, changing from 2.0–2.1 to 1.5–1.7.

Unsorted sediments are present in almost all stratigraphic units ofthe Productive Series. They consist of loam, sandy loam, and chlido-lite. Their color within the section is the same as in the other rockvarieties, from which they are distinguished by grain size.

Argillaceous rocks are usually gray in color in the Lower ProductiveSeries, whereas in the Upper Productive Series they have a grayish-brown color. All argillaceous rocks are generally calcareous andmassive (rarely laminated); sometimes they are pelitic or silty-pelitic.

Evaporites include anhydrite and gypsum. Anhydrite forms interbedsfrom 0.5 to 2 cm in thickness and alternates with other rock types.Gypsum is present as cement in various rocks. Color of the evaporitesis white with grayish and cream coloration.



Fig

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General Regularities in Oil and Gas Distribution 133Ta

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Experimental studies of reservoir-rock properties at formation pres-sure and temperature corresponding to the depth of occurrence areimportant. Reserve estimation and development of oil and gas fieldsdepends largely on reservoir-rock properties, such as cement content,porosity and permeability. Reservoir-rock properties of the ProductiveSeries vary both areally and with depth (Figure 7-11). Reservoirquality is very high (see Tables 6-4, 6-7 and 6-10). Table 7-7 showsa classification of reservoir rocks of the Productive Series within theApsheron Peninsula and Apsheron Threshold (Buryakovsky, 1970a,1985a). In the Apsheron Peninsula and Apsheron Archipelago, porosityvaries from 15 to 30%, and permeability varies from 10 to 1,000 mD.The best reservoir-rock properties are observed in the Podkirmaku,Nadkirmaku Sandy, “Pereryv” and lower portion of Balakhany suiteswhich contain most of the sand reservoirs. Table 7-8 shows petro-physical parameters of reservoir rocks of the Upper Productive Seriesat major oil and gas fields within the Apsheron Peninsula. Table 7-9shows a comparison of average values of porosity and permeabil-ity of the reservoir rocks in the section of the Neft Dashlary andGyuneshli fields.

In the Apsheron Archipelago, the total thickness of the LowerProductive Series is 900 m on the average and ranges from 700 to1,200 m. The section consists of the following formations (from thebase upwards):

The Kala Suite (KaS) rests directly on Pontian sediments and iscomposed of interbeded sands, sandstones, siltstones, and shales withrare gravel inclusions. Thickness of Kala Suite is about 250–300 m.Shales predominate over sands, constituting 60% of the total thicknessof the suite. In the area of Neft Dashlary and Palchygh Pilpilasi fields,the Kala Suite is divided into three to four sandstone units withthickness ranging from 20 to 30 m, separated by thick shale beds.

Quartz sands and sandstones are gray to light gray in color, medium-grained, with some fine-grained argillaceous varieties. Partings betweenquartz sands and sandstones consist of gray to light-gray sandy shales.The sands and sandstones of the Kala Suite are characterized by thefollowing grain sizes: fraction >0.25 mm—6.9%; fraction 0.25 to 0.1




Figure 7-11. Variation of porosity (a, b) and permeability (c, d) with depthfor the northwestern slope of the South Caspian Basin. (Modified afterBuryakovsky et al., 1991b.) a, c—Sandstones; b, d—siltstones. Oil and gasfields and prospects: 1—Dzhanub, 2—Zyrya, 3—Surakhany, 4—Karachukhur,5—Zykh, 6—Gum Deniz, 7—Gousany, 8—Bibieibat, 9—Patamdar, 10—Karadag, 11—Padar, 12—Kyurovdag, 13—Karabagly, 14—Kalmas.


Tab

le 7

-7C

lass

ific

atio

n o

f R

eser

voir

Ro

cks

of

the

Pro

du

ctiv

eS

erie

s o

f th

e A

psh

ero

n O

il-

and

Gas

-Bea

rin

g R

egio

n

Res

ervo

ir R

ock

Pro

pert

ies

Cla

yC

arb

on

ate

Co

nte

nt,

Co

nte

nt,

Por

osity

, %

Per

mea

bilit

y,C

lass

Type

Qua

lity

%%

Tota

lE

ffec

tive

mD

IU

ncom

pact

ed s

orte

d sa

ndV

ery

high

<6

<3

>31

>26

>1,

000

IIS

haly

-sil

ty s

and

Hig

h6 –

153–

525

–30

20–2

430

0 –1,

000

III

San

dy l

oam

,S

ilts

tone

Med

ium

15–2

35–

1021

–28

16–2

110

0 –30

0IV

aC

hlid

olit

e,L

oam

Low

23–3

210

–15

16–2

411

–17

30–1

00IV

bS

andy

-sil

ty s

hale

Bad

32–4

015

–20

15–2

010

–13

10–3

0V

Den

se s

ands

tone

Non

-res

ervo

ir r

ock

—>

20<

10<

6<

10an

d si

ltst

one


Tab

le 7

-8R

eser

voir

Ch

arac

teri

stic

s o

f S

abu

nch

i an

d B

alak

han

yS

uit

es o

f th

e A

psh

ero

n P

enin

sula

Car

bona

teG

rain

-siz

e D

istr

ibut

ion,

%W

eigh

ted

Ave

rage

Cem

ent

>0.

250.

25–0

.10.

1–0.

01<

0.01

Gra

in S

ize,

Con

tent

,P

oros

ity,

Per

mea

bilit

y,U

nit

or

Su

item

mm

mm

mm

mm

m%

%m

D

II0.

34.

353

.741

.70.

040

13.1

24.0

106

III

0.4

9.6

53.8

36.2

0.07

210

.725

.024

1II

I–IV

0.3

5.4

64.8

29.5

0.04

912

.927

.014

1IV

2.2

21.5

52.2

24.1

0.07

49.

925

.031

3IV

a1.

323

.150

.924

.70.

072

11.5

26.0

369

IVb

1.8

22.2

55.2

20.8

0.07

611

.024

.050

3IV

c0.

45.

153

.840

.80.

042

15.6

25.0

282

IVd

0.7

4.7

61.5

33.1

0.04

612

.727

.027

5IV

e0.

66.

857

.934

.70.

047

12.0

25.0

215

Ave

rage

Sab

unch

i0.

79.

555

.734

.10.

051

12.0

25.0

230

V1.

521

.950

.426

.20.

072

11.7

24.0

305

V–V

I0.

713

.060

.625

.70.

059

11.3

24.0

232

VI

2.1

29.4

51.3

17.2

0.08

710

.727

.015

4


mm—27.5%; fraction 0.1 to 0.01 mm—37.2%; and fraction less than0.01 mm—28.4%. Carbonate cement content is 14.2%, ranging from4 to 39.4%. Average porosity is 20%, varying from 8.3 to 33.4%.Permeability ranges from a few to 300 mD.

Petrographic analysis of KaS reservoir rocks shows the followingcomposition of the light mineral fraction: quartz—53.3%; feldspar—17%; rock fragments—29.6%, and glauconite—0.1%. The heavymineral fraction includes: pyrite—14%; magnetite-ilmenite—2%;nonmetallic (opaque)—13%; micas and chlorite—8%; and glauconite—19%. The contents of limonite, garnet, zircon, tourmaline, biotite,kyanite, staurolite, and sillimanite are about 1% each.

The Podkirmaku Suite (PK) has an average thickness of 100 m andis represented by two units of gray quartz sands and sandstones withsome shale interbeds. Shale interbeds in the PK Suite are few: lessthan 30% of the total thickness of the section. Two separate units inthe PK Suite are PK1 and PK2, each consisting of 3 to 4 sand beds.Separating these units are shale beds of variable thickness. Sands arepoorly sorted and are fine- to medium-grained. Shales are poorlylaminated and often sandy. Average grain size of reservoir rocks is as


Table 7-9Average Values of Porosity and Permeability of the Neft Dashlary and

Gyuneshli Reservoirs

Neft Dashlary Gyuneshli

Porosity, Permeability, Porosity, Permeability,Suite % mD % mD

Surakhany 23 302 21 212Sabunchi 22 283 20 167Balakhany 23 287 20 163“Pereryv” 23 287 19 133NKG 21 117 17 46NKP 23 280 19 121KS 23 139 17 48PK 23 298 18 109KaS 22 174 17 160


follows: fraction >0.25 mm—7.0%; fraction 0.25 to 0.1 mm—34.8%;fraction 0.1 to 0.01 mm—35.7%; and fraction <0.01 mm—22.5%.Carbonate cement content is about 10%, average porosity is 23%, andpermeability ranges from 300 to 700 mD.

The Kirmaku Suite (KS) consists of alternating fine-grained sandsand sandstones, shales, and shaly sands with an average thickness ofabout 300 m. Sand beds are 1 to 5-7 m thick. The two most sandyintervals occur at the base of the suite: the 10–15-m lower interval isdistinguished by high resistivity; the upper interval is 20 m thick. Lightminerals are: 50% quartz, 42% feldspar, and 8% rock fragments.Heavy minerals consist of 72% pyrite, 11% mica and chlorite, 10%opaque (nonmetallic) minerals, and 5% glauconite.

The Nadkirmaku Sandy Suite (NKP) consists of medium- to coarse-grained, quartz sands with interbeds of sandstones, predominantly atthe base. Shale beds are rare and thin. Average thickness is 35 m, withsands constituting about 70% of the total thickness of the suite. Atthe base of the suite, the layer of black and colored gravel and debrisof hard rocks occurs.

The Nadkirmaku Shaly Suite (NKG) consists of shales with rare thininterbeds of sands and siltstones. Shale content increases from thebottom toward the top. Thickness of the suite is 120 to 140 m. Shalesof the NKG Suite are dark gray and brownish gray, laminated, andplastic. Sands, which are fine-grained and gray to light gray in color,constitute 20% of the total thickness of the suite.

The sandy sequence at the base of the Upper Productive Series,which is called the “first break of deposition” or “Pereryv” Suite, isabout 100–120 m thick. The “Pereryv” Suite consists of medium- tocoarse-grained, thick sands and sandstones with thin layers of shale.

Deposits of the Balakhany Suite occur on plunges of the NeftDashlary and Palchygh Pilpilasi anticlines (Apsheron Archipelago),where their thickness reaches 400 m. The Balakhany Suite, at deeperfields of the Apsheron and Baku archipelagoes, is represented by analternation of sand, silt and shale, with the predominance of sand andsilt. Sands and sandstones are grouped into the Units V, VI, VII, VIII,IX and X, separated by shales. Sand content increases toward the baseof the suite in Unit X, and in Units VII, VI and V as well. The totalthickness of the Balakhany Suite is 610 to 750 m, with Unit X (50–80 m thick) being the most petroliferous.


The total thickness of the Sabunchi Suite is 320 to 440 m, withalternating sand, silt and shale beds. Thicknesses of sand Units II, IIIand IV are 30 to 70 m each.

The Surakhany Suite, which consists of shales with thin sand andsilt interbeds, is 950 to 1,150 m thick. Only one sand Unit I isidentified in the section.

Composition and Properties of Argillaceous Rocks

Argillaceous rocks with their interstitial fluids are important indi-cators of post-sedimentary transformations. First, the clay minerals areextremely sensitive to thermobaric factors, i.e., pressure and temper-ature. Second, clay beds contain large volumes of gas and water, whichalso affect the degree and character of diagenetic and catagenetictransformations of sedimentary rocks.

Cenozoic argillaceous rocks are widespread in Azerbaijan and theSouth Caspian Basin. Argillaceous rocks make up 50 to 95% of thesection and play a key role in the formation of lithologic, mineralogic,geochemical, and thermobaric characteristics of the basin (Buryakovsky,1974a, 1993c, 1993d). Following are the results of a study of argillaceous-rock cores recovered from deep onshore and offshore exploratory andproducing wells (Buryakovsky and Dzhevanshir, 1985, 1986b).

The primary targets of investigation were argillaceous rocks fromthe Middle Pliocene Productive Series from northern and western areasof the South Caspian Basin. Large amounts of data have been col-lected, including results of clay-mineral study over a long interval, upto 6.5 km. More than 5,000 X-ray diffractometer, thermographic,electron-microscope, and other analyses have been performed. Figure7-12 is an example of diffractogram, thermogram, and electron-microscope photographs of a clay sample from the South CaspianBasin. The authors examined clay-mineral distribution in the Produc-tive Series by using X-ray methods and the scanning electron micro-scope (SEM), for over 200 samples of argillaceous-rock cores recoveredfrom wellbores. The X-ray data obtained by Kheirov (1979), whostudied samples from mud-volcano eruptions from depths of 8 to 12km, were also used.

Pliocene clays and shales were studied at depths of 1,400 to 6,000 mat various locations of the Apsheron Peninsula, Apsheron Archipelago,South Apsheron Offshore Zone, Baku Archipelago, and Lower Kura


region (Buryakovsky and Dzhevanshir, 1985c, 1986b; Buryakovsky etal., 1988).

Shale is dark gray in color, with silt intercalations and occasionalstringers of light-gray argillaceous siltstones. Microscopic examination ofthin sections shows that shale is silty, pelitic, macrolayered, and mottled.

Figure 7-12. Characteristic diffractogram (A), thermogram (B), and electronmicrophotograph (C) for South Caspian Basin clay (Bulla Deniz Field, Well38, depth: 6,183–6,186 m/20,285–20,295 ft). A: a—air-dry sample; b—samplesaturated with glycerin; c—sample heated to 580°C (numbers on curves aregiven in angstroms); and B: 1—differential heating curve, 2—loss in weight.


The pelitic content of argillaceous rocks, i.e., the fraction withparticle size less than 0.01 mm, accounts for 51–83% (average of 69%)of the total rock mass. The sand content of argillaceous rocks accountsfor 1.5%, on the average; the silt content ranges from 11 to 50%(average of 21%); and the average content of carbonate cement is 10%.At a depth of 2,000–6,000 m, porosity of normally consolidatedargillaceous rocks fluctuates within the 3–12% range; whereas porosityrange for the unconsolidated rocks is 10–28%. The correspondingpermeability ranges are (7.5–0.36) • 10–7 mD and (230–6.2) • 10–7 mD(Table 7-10).

Most of the clay minerals in the Productive Series belong to thesmectite and illite groups. Kaolinite content varies from 15 to 20%,chlorite from 5 to 10%, and mixed-layer minerals from traces up to5% (Figure 7-13). Smectites occur in fairly irregular aggregates withvague outlines. Illite is represented by fairly well-outlined and tabularparticles, elongate to isometric.

The X-ray analysis showed the variations in clay-mineral contentswith depth, with no clear-cut regularity. Montmorillonite is present inlarge amounts (40% on the average, reaching 75% in some cores)throughout the Productive Series. Apparently, there has been notransformation of montmorillonite to illite in these clays, at least downto a depth of 6,200 m. Table 7-10 (depth of occurrence) and Table 7-11(location) present the contents of montmorillonite, illite and otherclay minerals in sedimentary rocks of the (1) Apsheron Archipelago(Oguz, Palchygh Pilpilasi, Dzhanub-2, and Gyuneshli offshore areas);(2) the South Apsheron Offshore Zone (Bakhar Field); (3) the BakuArchipelago (Sangachal—Duvanny Deniz—Khara Zyrya, Bulla Deniz,Alyaty Deniz, Khamamdag Deniz, Garasu, Sangi-Mugan, and AranDeniz offshore areas); and (4) the Lower Kura Region (Kyurovdag andKarabagly onshore areas).

Argillaceous rocks within the Apsheron Peninsula are primarilycomposed of illite. Illite (I) content averages 48%, whereas smectite(S) content is 24% (Figure 7-14); thus, S/I = 0.5. The section of theseoccurrences is quite heterogeneous in clay-mineral contents. Smectitecontent varies from 5 to 40%, in a few cases reaching 45%, whereasthe illite content ranges from 20 to 60%. The X-ray difractometerstudies of clay minerals for various suites of the Productive Series ofthe Apsheron Peninsula and adjacent offshore area are summarized inTable 7-12. The Surakhany and Sabunchi suites of the Upper Productive


Tab

le 7

-10

Cla

y-M

iner

al C

om

po

siti

on

an

d V

aria

tio

n w

ith

Dep

th o

f P

oro

sity

, P

erm

eab

ilit

y, a

nd

Po

reS

ize

in t

he

Ap

sher

on

Arc

hip

elag

o F

ield

s (a

vera

ge

valu

es a

re s

ho

wn

in

th

e d

eno

min

ato

r)

Dep

thC

lay-

Min

eral

Com

posi

tion,

%

Ran

ge,

Mix

ed-

Por

osity

,P

erm

eabi

l ity,

Por

e S

ize,

mM

on

tmo

rillo

nite

Illite

Ka

olin

iteC

hlo

rite

La

yere

d%

10–7

mD

µm

1,00

0–10

–45

35–6

515

–20

5–10

Tra

ces

22–3

335

–250

1.7–

3.9

2,00

032

.543

.517

.56.

528

142

2.7

2,00

0–35

–70

20–4

00–

150–

10T

race

s15

–28

8–35

1.3–

3.1

3,00

045

.035

.013

.07.

020

222.

1

3,00

0–15

–50

30–6

05–

205–

150–

58–

243–

81.

0–2.

54,

000

36.0

42.0

14.0

7.0

1.0

176

1.6

4,00

0–15

–70

10–6

00–

200–

100–

302–

211.

5–3

0.7–

2.0

5,00

040

.038

.012

.55.

54.

014

21.

3

5,00

0–5–

6520

–65

0–30

0–15

0–15

0–18

0.8–

1.5

0.5–

1.5

6,00

039

.039

.015

.55.

01.

512

10.

8

>6,

000

5–70

20–6

010

–25

0–10

0–25

0–16

0.6–

0.8

—36

.037

.515

.54.

07.

010

0.7


Fig

ure

7-1

3. C

onte

nts

of c

lay

min

eral

s in

the

Pro

duct

ive

Ser

ies

of B

aku

Arc

hipe

lago

. a—

Mon

tmor

illon

ite,

2—ill

ite,

c—ka

olin

ite,

d—ch

lori

te,

and

e—m

ixed

-lay

er m

iner

als.


Series are characterized by the highest content of smectite (31 and35%, respectively), whereas in the Balakhany Suite, smectite contentdecreases to 21.1%. The NKG and KaS suites of the Lower ProductiveSeries have the highest smectite content (30%).

Figure 7-14 shows the smectite and illite contents in rocks of the(1) Apsheron Archipelago (Oguz, Palchygh Pilpilasi, Dzhanub-2, andGyuneshli offshore areas), (2) South Apsheron Offshore Zone (BakharField), (3) Baku Archipelago (Sangachal—Duvanny Deniz—Khara

Table 7-11Clay-Mineral Composition of Argillaceous Rocks in the Azerbaijan and the

South Caspian Fields (Average Values are Shown in the Denominator)

Clay-Mineral Composition, %

Mixed-Field Montmorillonite Illite Kaolinite Chlorite layered

Bibieibat tr.–30 40–65 10–30 tr.–5 tr.–517 53 26 3 1

Palchygh Pilpilasi 10–35 45–60 20 tr.–5 tr.24 51 3.8

Gyuneshli 40 40 15–20 tr. tr.–517.5 2.5

Bakhar 10–55 30–55 15–25 tr.–10 tr.–527.7 46.1 20.4 4.2 0.8

Duvanny-Khara Zyrya 5–60 5–60 tr.–20 tr.–15 tr.–541 39 13 6 1

Bulla Deniz 5–70 5–70 tr.–35 tr.–10 tr.–1039 37 16 4 4

Alyat Deniz 45–50 25 15 5 5–1047 8

Khamamdag Deniz 30–75 10–45 10–15 tr.–10 tr.49 28 12.5 5

Kyurovdag & Karabagly 40–75 10–35 tr.–20 tr.–15 —53 23 12 10


Zyrya, Bulla Deniz, Alyaty Deniz, Khamamdag Deniz, Garasu, Sangi-Mugan, and Aran Deniz offshore areas); and (4) Lower Kura Region(Kyurovdag and Karabagly onshore areas).

In the Baku Archipelago and Lower Kura Region, the smectitecontent (38%) is approximately equal to the illite content (39%) asshown in Table 7-11. In contrast to the region of the Apsheron Penin-sula and adjacent offshore area, this section is, in general, characterizedby a more stable mineral composition, preserving a significant amountof swelling clay minerals (smectites). This results in the low perme-ability of argillaceous rocks, and ensures good sealing properties ofshales (caprocks) that overlie reservoir rocks.

Figure 7-14. Montmorillonite (1) and illite (2) contents in argillaceous fraction(<0.01 mm) of Middle Pliocene clays. a—Apsheron Archipelago and SouthApsheron Offshore Zone; and b—Baku Archipelago and Lower Kura Depression.


Oligocene to Miocene shales have been studied onshore (MuradkhanlyOil Field in the Middle Kura trough). The cores of Chokrak rocks,which were studied from a depth of 2,825–2,830 m, contain mont-morillonite and mixed-layered clays with chlorite, illite, and ash.Organic matter is represented by the skeletons of coccoliths (marinemicroorganisms). The Chokrak rocks are fairly loose and unconsolidated.

The Maikop rocks have been studied from cores taken from depthsof 3,080–3,085 m and 3,287–3,292 m. These rocks of marine origincontain montmorillonite clay with some volcanic ash. The ash (glass)is often altered to montmorillonite. Montmorillonite, chlorite andmixed-layered clays are widespread. Broken grains of pyroxenes andamphiboles with a typical cleavage are locally present.

The distribution of clay minerals is due to (1) different sources ofclastic material brought to the different parts of the sedimentary basin,(2) predominantly allothigenic origin of clay minerals, and (3) varia-tions in the rate of sedimentation. The Russian Platform, the Kilyazi-Krasnovodsk Zone of Uplift, the islands existing north of the ApsheronPeninsula and Archipelago, and the southeastern slope of the GreaterCaucasus Mountains served as the primary source of clastic materialfor the Apsheron Peninsula and the adjacent Caspian Sea area. Themore ancient (Mesozoic—Paleogene) magmatic and sedimentary rocksof the Greater and Lesser Caucasus and Talysh mountains served as

Table 7-12Clay-Mineral Content in the Productive Series, Apsheron Peninsula andAdjacent Offshore Areas (average values are shown in the denominator)

Smectite, Illite, Smectite, Illite,Suite % % S/I Suite % % S/I

Upper Productive Series Lower Productive Series

Surakhany 10–45 35–60 0.67 NKG 25–35 30–50 0.7331.0 46.3 30.0 41.3

Sabunchi 25–45 35–40 0.93 KS 10–30 40–60 0.4035.0 37.5 20.0 50.0

Balakhany 10–40 40–55 0.42 KaS 10–40 40–60 0.6721.1 50.6 30.0 47.0


the primary source of sediments for the Lower Kura region and theBaku Archipelago.

Pores exceeding 5 µm in size were studied in thin sections underthe optical microscope, whereas those less than 5 µm in size werestudied with the scanning electron microscope (SEM) on freshlybroken surfaces of rocks. Magnification of ×100, ×300, ×1,000, ×3,000,and ×10,000 were used in the SEM. A total of 102 electron microscopephotographs have been taken. The photographs showed the geometryof pore space and the shape of clay particles. They also showed thatshale is incompletely consolidated and poorly sorted, with fairly highinteraggregate and intergranular porosity.

Photomicrographs were taken in planes parallel, oblique, and perpen-dicular to the bedding. Groundmass of argillaceous rocks (and ash) isfairly homogeneous at magnifications of ×100 and ×300. Details ofpore space geometry appear only at magnifications of ×1,000 and×3,000. Individual grains, pores, and fractures are clearly visible. Thepores and fractures are identified by the appearance of grain separationand by a considerably lower intensity of illumination, which allowsmeasurement of pore sizes and fracture lengths and widths. Pore cross-sections were measured directly in the photographs taken at magnifi-cation of ×3,000.

With increasing depth, the pore size of shales progressively decreases(Figure 7-15) according to the following equation:

dp,Me = 4.6e–0.3D

where dp,Me is the median pore size, in µm; and D is the depth, in km.

Pressure and Temperature

During the initial period of penetration of the reservoir rocks, theformation fluids had high pressures and wells were flowing. The petro-physical and geological characteristics of the rocks (permeability,fracture width and density, porosity, clay content, etc.) exerted the maininfluence on the amount and rate of fluid flow. The initial reservoirpressure was always higher than the hydrostatic pressure (Figure 7-16).

Temperature measurements in deep wells in the areas of the SouthCaspian Basin and onshore of Azerbaijan show that the averagegeothermal gradient is approximately 16°C/km. The temperature at adepth of about 6 km does not exceed 110°C.


Table 7-13 shows the initial pressure and temperature in someoffshore fields. Tables 7-14 and 7-15 show variation of pore pressuregradient and geothermal gradient with depth in some oil and gas fieldsof onshore Azerbaijan and the South Caspian Basin.

Numerous measurements of the initial formation pressure in reser-voir rocks and wireline logging determination of pore pressure inargillaceous rocks reveal the pattern of the abnormally high formationpressure (AHFP) distribution throughout the section at the north-western flank of the South Caspian Basin (Table 7-16). The averagegradients of the initial formation pressure in the reservoir rocks, ηres,and of the pore pressure in shales, ηsh, are (in MPa/m): 0.0106and 0.0120 for the Apsheron Archipelago; 0.0119 and 0.0145 for theSouth Apsheron Offshore Zone; and 0.0138 and 0.0182 for the BakuArchipelago and Lower Kura region. A significant difference betweenthe initial formation pressures in reservoir rocks and pore pressuresin shales (by a factor of over 1.5) exists in the Baku Archipelago,where the average thickness of shales, hsh, is particularly higher thanin other regions of Azerbaijan. Generally, AHFP rises with the relativecontent of shales, χsh, throughout the section (Table 7-16) and within

Figure 7-15. Relationship between the pore size in argillaceous rocks anddepth in the Baku Archipelago area.


the reservoir. The highest pore pressures in shales are associated withshale sequences in the Baku Archipelago and Lower Kura region withtheir extraordinarily high porosity, φsh, owing to rapid sedimentationand slow compaction.

Abnormally High Formation Pressures

Abnormally high formation (pore) pressure (AHFP) or “overpressure”is encountered worldwide in sand-shale or massive carbonate-evaporite

Figure 7-16. Changes with depth in pore pressure in argillaceous rocks (solidcircles) and of initial formation pressure in reservoir rocks (open circles) inthe Baku Archipelago area (η is the pressure gradient, MPa/m). (Source:Buryakovsky et al., 1986c.)


Table 7-13Initial Reservoir Pressure and Temperature in Various Fields of

Apsherton and Baku Archipelagoes

Average Reservoir FormationUnit or Fault Depth, Pressure, Temperature,Suite Block M MPa °C

Palchygh Pilpilasi Field

KaS1 I, III 830 10.9 44KaS2 -”- 900 11.6 45KaS3 XVI, XVIII 995 12.2 46KaS4 -”- 1,140 13.6 48KaS1 XII, XIII 985 12.4 46KaS2 -”- 1,100 13.4 47KaS3 -”- 1,250 15.2 49KaS4 -”- 1,475 17.3 53KaS1 IX, X, XI 985 14.4 45KaS2 -”- 1,100 15.6 46KaS3 -”- 1,250 17.7 48KaS4 -”- 1,475 19.5 52

Gyuneshli Field

X II 2,842 34.0 69“Pereryv” -”- 2,898 34.1 71NKP -”- 3,018 38.8 72PK -”- 3,358 40.6 77KaS -”- 3,683 51.2 79

Bakhar Field

VI II 3,760 39.6 80VII III 4,400 43.4 85VIII II 4,060 42.3 97IX VII 4,390 45.4 89Xupper I 4,500 45.2 91Xlower III 4,460 47.6 92“Pereryv” I 4,880 49.8 91NKP II 4,920 51.3 97

Bulla Deniz Field

V I 5,300 55.6 108-”- II 4,500 53.2 95-”- III 5,200 55.3 106VII I 5,800 71.9 116-”- II 5,600 71.3 113-”- V 6,125 72.8 121-”- VI 5,970 72.4 119VIII I 6,075 75.3 120-”- II 5,875 74.8 117


sequences from shallow to great depths, in formations as old asCambrian (Dickinson, 1953; Foster and Whalen, 1966; Fertl, 1976;Fertl and Chilingarian, 1977; Dobrynin and Serebryakov, 1978; Magara,1982; Buryakovsky et al., 1986; Aleksandrov, 1987; Dobrynin andSerebryakov, 1989). The ability to locate and evaluate overpressuredformations is critical in drilling and completion operations, and indeveloping exploratory and reservoir engineering concepts. Althoughimproved during the last decade, the overpressure prediction methodsare still far from being perfect. This has been identified as one of thechallenges of geoscience technologies.

For predicting formation pressure, the paragraphs below describe thegeophysical and drilling data-processing procedures used.

Overpressure can be calculated from resistivity logs. This methodinvolves first separating the shales from the sands, and then correctingthe shale resistivity for formation temperature. The temperature correc-tion is based on an empirical relationship derived for the region orarea under study. Once the temperature correction is applied, a normal

Table 7-14Variation of Pore-pressure Gradient in Shales and Geothermal Gradient

with Depth (average values are shown in the denominator)

Depth Pore-pressure GeothermalRange, Gradient, Gradient,

m MPa/m °C/km

1,000–2,000 0.012–0.020 10–150.016 12

2,000–3,000 0.013–0.021 10–120.017 11

3,000–4,000 0.014–0.022 8–110.018 10

4,000–5,000 0.015–0.023 15–190.019 17

5,000–6,000 0.015–0.023 21–230.019 22

>6,000 0.016–0.024 15–250.020 20


compaction trend is established for the well. The overpressured zonesare delineated by the deviation from the normal trend of pore pressuregradient. The same method can be applied for determining over-pressure from sonic logs.

If wells exhibit different and distinct pressure gradient patterns, eachwell represents a separate pressure compartment. Layering and varia-tions in the overpressure are sometimes caused when pressure buildsup along the shale zones and bleeds off into the associated permeablesands and sandstones. Excellent prediction criteria and sensitivityanalysis of formation pressure in sealed layers were proposed byKhilyuk et al. (1994).

Pore pressure and fracturing pressure can be computed using sonicvelocity and empirical relationships among sonic velocity, rock density,and Poisson’s ratio. A typical methodology is as follows: (1) thestacking velocity information from seismic data is calibrated using wellvelocities; (2) a normal pressure gradient curve is calculated for thesonic velocity curves; (3) pore pressure is computed from the seismicvelocity data using the normal-trend curve; thus, pore pressure distribu-tion in a section is established; and (4) the fracture-pressure gradient isthen computed from the pore-pressure gradient, the interval velocities andthe empirical relationships among velocity, density and Poisson’s ratio.

Table 7-15Pore-pressure Gradient in Shales, and Geothermal Gradient in the Fields

of Azerbaijan and the South Caspian Basin

Pore-pressure GeothermalGradient, Gradient,

Field MPa/m °C/km

Bibieibat 0.0125 28.5Palchygh Pilpilasi 0.0135 26.0Gyuneshli 0.0146 24.0Bakhar 0.0166 28.0Duvanny-Khara Zyrya 0.0171 16.0Bulla Deniz 0.0182 16.0Alyat Deniz 0.0178 16.0Khamamdag Deniz 0.0176 16.0Kyurovdag and Karabagly 0.0176 16.0


Tab

le 7

-16

Var

iati

on

wit

h D

epth

of

(1)

Ave

rag

e T

hic

knes

s o

f S

hal

e ( h

sh),

(2)

Sh

ale

Po

rosi

ty (

φφφφ φ sh),

(3)

Po

re-p

ress

ure

Gra

die

nt

in S

hal

es (

ηηηη η sh),

an

d (

4) P

ore

-pre

ssu

re g

rad

ien

t in

th

e R

eser

voir

Ro

cks

( ηηηη ηre

s) i

n A

psh

ero

nA

rch

ipel

ago

, S

ou

th A

psh

ero

n O

ffsh

ore

Zo

ne,

Bak

u A

rch

ipel

ago

, an

d L

ow

er K

ura

Dep

ress

ion

Bak

u A

rchi

pela

go a

ndA

pshe

ron

Arc

hipe

lago

Sou

th A

pshe

ron

Off

shor

e Z

one

Low

er K

ura

Dep

ress

ion

Dep

th,

h sh,

φ sh,

η sh,

η res,

h sh,

φ sh,

η sh,

η res,

h sh,

φ sh,

η sh,

η re,

mm

%M

Pa

/mM

Pa

/mm

%M

Pa

/mM

Pa

/mm

%M

Pa

/mM

Pa

/m

2,00

050

120.

0122

0.01

1625

015

0.01

370.

0124

900

210.

0167

0.01

353,

000

4018

0.01

250.

0108

235

120.

0146

0.01

1972

518

0.01

790.

0137

4,00

030

150.

0120

0.01

0018

510

0.01

490.

0116

460

160.

0187

0.01

405,

500

2013

0.01

100.

0098

150

180.

0148

0.01

1635

013

0.01

930.

0142


Overpressure can be estimated using drilling and well-logging data.To predict pressure from the drilling and log data, fuzzy logic has beenused by Aminzadeh et al. (1994). This method was first applied to datafrom the South Caspian Basin. Drilling parameters such as the bitweight, rate of penetration, and the changes in the rate of penetrationwere used for this purpose. The information obtained from pressureprediction is used to choose the required drilling mud density. Also,lithology can be predicted from the pressure data (Aminzadeh et al.,1994; Dunan, 1996; Lee, 2000).

Many factors contribute to the magnitude of abnormal formationpressure. These include: (1) mechanical (compactional) deformation ofrocks with a change in porosity; (2) mass transfer fluxes; (3) tempera-ture changes; (4) diagenetic transformations; (5) chemistry of inter-tstitial solutions; (6) lithology and mineralogy; (7) sand/shale ratio;and (8) distribution of porosities and permeabilities of associated sandsand shales.

The abnormally-high pressures in the argillaceous sequences maysubstantially affect the geological processes at depth. They evidentlyhave played an important role in folding, clay diapirism, mud volcan-ism, and earthquakes. The models of these phenomena are describedby Coulomb’s law and by rheological models of various theoreticalbodies. According to Coulomb’s law, resistance to shearing in shalesis the first power function of normal compressive stress. As abnormalpore pressure in shales increases, the intergranular stress (effectivestress) decreases, down to very low values under certain conditions.Resistance to shearing, determined by friction, decreases corres-pondingly. This leads to an intergranular sliding and facilitates to aconsiderable extent the development of shearing. In such instances,plastic argillaceous sequences become quite mobile at a high shalepore pressure and are displaced. Depending on the geological environ-ment and duration, this process may lead to the development of folds,diapirs, mud volcanoes, or earthquakes. In the South Caspian Basinand onshore Azerbaijan, such geologic setup is quite typical of thickPaleogene to Miocene argillaceous sequences with extremely high,quasigeostatic values of AHFP, with shale pore pressure gradients of0.020–0.023 MPa/m (Buryakovsky et al., 1986c, 1995).

Development of abnormal pore pressures in shales of the SouthCaspian Basin and onshore Azerbaijan has been experimentally demon-strated by elastic compression of hermetically sealed cores of Cenozoic


shales. Figure 7-17 shows that the pore pressure in the core rises withincreasing external confining pressure and then decreases as theconfining pressure decreases, but always remaining higher than in thecase of increasing load, evidently as a result of residual (irreversible)deformation of the rock (see Rieke and Chilingarian, 1974).

Of special interest are the young sedimentary basins, which arecharacterized by the presence of thick, rapidly accumulated sand/shalesequences. A vivid example is the South Caspian Basin, which isdistinguished by a diverse and rather unique association of the follow-ing parameters: (1) an exceptionally high rate of sedimentation (up to1.3 km/my); (2) a very thick (up to 25 km) sedimentary column;sediments of Quaternary—Pliocene age account for up to 10 km (sand-silt-shale); (3) argillaceous rocks make up 50 to 95% of the sectionand play a key role in determining the mineralogic, lithologic, geo-chemical, and thermobaric characteristics of the basin; (4) abnormallyhigh pore pressure in shales (average factor of abnormality1 up to Ka= 1.8); (5) low heat flow and low formation temperature (at depthsaround 6 km, the temperature is approximately 105–110°C); (6) aninverted character of the hydrochemical profile (the chemistry of waterchanges with depth from calcium chloride and magnesium chlorideto sodium bicarbonate type, i.e., freshening of water with depth); and(7) wide development of mud volcanism.

The abnormally high formation (pore) pressure (AHFP) in reservoirsis known to be caused by several diverse factors. It appears, however,that the most probable mechanism of AHFP development in regionswith thick sedimentary rocks (sand/shale sequence) is a rapid sedimen-tation and gravitational compaction. This leads to significant under-consolidation (undercompaction) of rocks and to a development ofAHFP. Abnormal pressures in reservoir rocks are often caused bythe influx of water from overpressured shales. Pressures in sandstonesand shales approach each other only in moderately thick beds. Theregionally developed reservoirs have a better pressure distribution thanthat in shales; consequently, their pore pressure usually is lower thanthat in the enclosing shales (Figure 7-18).

In the South Caspian Basin, the drilled Pliocene terrigenous sectionis 6.5 km thick, with unevenly distributed AHFP, both vertically and

1Abnormality factor Ka

= pa/p

n, where p

a is abnormally high formation pressure and p

n is the

normal hydrostatic pressure.


Figure 7-17. Experimentally determined relationship between the pore pres-sure pp in an argillaceous rock core and the external (confining) pressure σ.Arrows show increasing and decreasing confining pressure.

Figure 7-18. Pore-pressure gradient as a function of relative clay content χsh(Modified after Buryakovsky et al., 1995). 1–3—argillaceous rocks from threeregions in Azerbaijan; 4–6—reservoir rocks (sandstones and siltstones)saturated with: 4—water, 5—oil, 6—gas.


laterally. Presence and magnitude of AHFP are determined by studyingthe lithofacies of the oil- and gas-bearing rocks, structure of the uplifts,sand/shale thickness ratio, influx of water from shales into sands,integrity of caprocks, distribution of faults and fractured zones, etc.

An important regional feature is a very high porosity of argillaceousrocks, much higher than those at similar depths in other areas of theworld (Buryakovsky et al., 1982a; Dzhevanshir et al., 1986). As shownin Figure 7-19, porosity of Pliocene shales in the South Caspian Basin

Figure 7-19. Relationship between porosity φsh and depth H (in m) forargillaceous rocks (Modified after Buryakovsky et al., 1995). 1—Devonian(Weller, 1959); 2—Mesozoic (Proshlyakov and Dobrynin, 1961); 3—Oligocene-Miocene (Vassoyevich, 1960); 4–6—Middle Pliocene (Durmishyan et al.,1973); 4—Apsheron Archipelago, 5—South Apsheron Offshore Zone, 6—BakuArchipelago and Lower Kura Depression.


at depths of 4.0–5.5 km is several times higher than in the consolidatedshales present in other regions at the same depth. Such a differenceis the effect of geological age, relative contents of clay and sand,temperature, and other factors. The abnormally high porosity of shalesis primarily the effect of the slower rate of compaction compared tothe subsidence rate, due to the slow pore water removal from thecompacting argillaceous rocks during rapid sedimentation. This processwas crucial in development of AHFP in the South Caspian Basin.

It should be noted that AHFP in argillaceous sequences is oftenattributed to the montmorillonite dehydration as it is altered to illite(hydromica). Field data, however, shows (see Figures 7-13 and 7-14)that a practically unaltered montmorillonite is present in the BakuArchipelago deposits at depths down to 6 km, i.e., throughout theentire drilled section. This indicates a subordinate role of montmoril-lonite dehydration in the total process of AHFP development in theSouth Caspian Basin and onshore Azerbaijan.

Montmorillonite and illite-montmorillonite minerals may be trans-formed to illite during diagenesis1 and catagenesis2 , as described foralmost all major sedimentation basins throughout the world. Thesechanges in clay minerals during catagenesis are most probable (notsimply possible, as in diagenesis), due to increase in temperature andpressure as the sediments are buried. Consequently, during late cata-genesis, the clay-mineral assemblage consists of two components (illiteand chlorite), no matter what the initial composition.

On the other hand, virtually unaltered montmorillonite has beenobserved at great depths and in large amounts by Kheirov (1979). Heexplained that the almost unaltered montmorillonite found at a depth of6,026 m in the Pliocene beds of the Baku Archipelago is due to specificsedimentation conditions, the composition of the initial material, and theabnormally low temperatures, i.e., these sediments lie in the earlydiagenetic zone. In some cases, absence of potassium ion could explainthe absence of montmorillonite-to-illite transformation.

Of great importance is the study of regularities in the distributionof clay minerals over the entire section, the identification of basic

1,2Diagenesis—includes all physical, chemical, and biochemical processes which occur in thesediments after sedimentation and through lithification at near-surface temperature andpressure. Catagenesis—comprises all physical and chemical processes which occur in sedi-mentary rocks at high temperatures after lithification and up to metamorphism.


factors influencing the transformation of montmorillonite to illite, andthe prediction of catagenetic changes at greater depths not yet reachedby boreholes. The results, however, do not always allow one todetermine the origin of clay minerals, i.e., whether they are primaryor secondary. For example, Milleau (1968, see Buryakovsky et al.,1989b) noted that the montmorillonite formed at the final stage of illitedegradation does not differ from the primary montmorillonite, asevidenced by the X-ray analysis.

Photomicrographs of fresh broken surfaces of argillaceous rocks ofthe Productive Series of the Baku Archipelago (depths of 1,400–5,200m) were taken with scanning electron microscope (Buryakovsky et al.,1986c, 1988). The surfaces were examined in sections cut parallel,perpendicular, or oblique to the bedding. The mineral compositions ofthese rocks are on the whole the same throughout this depth range.The main clay minerals are illite and montmorillonite, with smallamounts of kaolinite and chlorite. The rocks have a honeycomb-liketexture, which is clearly seen in oblique sections.

The SEM results indicate that there are both “forward” and “reverse”clay-mineral transformations, which occur simultaneously as the rocksare buried. The cores from the depths of 1,400–1,800 m show onlyvery slight changes in the clay minerals, although one can identifydamaged sublayers (twisting) at the edges, as well as secondary poresand cracking in some illite grains. There are also microcavities formedby diagenetic processes. Cores from depths greater than 4,000 m showgreater evidence of transformation. Illite and montmorillonite predomi-nate, with the montmorillonite being of both primary and secondary origin.The secondary montmorillonite occurs in the interstices between the illitegrains, at their edges and in cracks. The primary montmorillonite isdisrupted or twisted at the edges and the secondary pores are present.

These Pliocene beds show degradation not only of the primarymontmorillonite but also of the illite, which changes to montmoril-lonite. These transformations are probably largely responsible for theretention of the same illite to montmorillonite ratio at depth.

Transformation of clay minerals during catagenesis is a complexprocess, proceeding over a long period of geologic time under theinfluence of interrelated and interdependent factors. It is extremelydifficult to determine the effect of various factors, i.e., to give aquantitative estimate of the magnitude of influence of each one. Thesolution to this problem probably lies in future investigations. The


effect of thermobaric and hydrochemical factors on the post-sedimentary(diagenetic and catagenetic) alteration of these Pliocene clays shouldbe studied using the data on chemical analyses of formation waters(e.g., the availability of potassium ion), formation temperatures, andpore pressures determined from logs.

Effect of Pressure and Temperature

The abnormally low temperatures may be responsible for the absenceof clear-cut clay-mineral transformation. Khitarov and Pugin (1966)and Magara (1982) have indicated that temperature is a major factorinfluencing montmorillonite degradation. Also of interest is the effectof illite degradation on the geothermal gradient. Inasmuch as hydrationof clays is an exothermic reaction, there may be elevated gradients atdepth ranges where the illite is transformed to montmorillonite, allother conditions being equal.

In the areas of the South Caspian Basin and onshore Azerbaijan,the average geothermal gradient is approximately 16°C/km, and thetemperature at a depth of about 6 km does not exceed 110°C. Acharacteristic feature is that the geothermal gradient becomes lowerat a depth of approximately 4 km (Table 7-14).

The increased geothermal gradient at a depth of approximately 4km may be related to illite-to-montmorillonite transformation, whichreleases heat. At a depth of approximately 4 km, the transformationrate exceeds some limit, which causes hydration to predominate overdehydration. One should, therefore, consider the effects of temperatureon diagenetic and catagenetic processes.

An increase in temperature may accelerate the process of montmoril-lonite catagenetic transformation into non-swelling minerals (illite andchlorite). Consequently, if true, sections with high geothermal gradientshould be characterized by a small montmorillonite content. On theother hand, inasmuch as a temperature decrease retards the processof montmorillonite transformation, sections with a low geothermalgradient should be characterized by a high montmorillonite content.

Figure 7-20a shows the dependence of montmorillonite content onthe geothermal gradient in shales of the South Caspian Basin. Thehighest montmorillonite contents are found in the shales of the BakuArchipelago and Lower Kura Region, which are characterized by alow geothermal gradient (16°C/km). The Apsheron Peninsula and the


Fig

ure

7-2

0. R

elat

ions

hip

betw

een

the

mon

tmor

illon

ite c

onte

nt a

nd g

eoth

erm

al g

radi

ent

(a)

and

pore

-pre

ssur

e gr

adie

nt(b

) (M

odifi

ed a

fter

Bur

yako

vsky

et

al.,

199

5).


adjacent offshore areas, which have a higher geothermal gradient(24.0–28.5°C/km), are characterized by lower montmorillonite contents.

Low temperature apparently does not favor the transformation ofmontmorillonite to illite; this reduces the montmorillonite transfor-mation rate. Under otherwise equal conditions, the transformationincreases with depth, which means that some additional factors mustbe influencing the transformation. One of these factors, discussed bySerebryakov et al. (1995), is the lack of potassium ion in interstitial water.

Inasmuch as the transformation of montmorillonite into illite pro-ceeds with the removal of interstitial water, conditions at whichdesorbed water leaves the pore space without hindrance will befavorable for the development of this process. Factors opposing thewithdrawal of fluids from the interlayer space of clays, therefore, maylead to slowing down or cessation of transformation of montmorilloniteinto illite or chlorite. The writers believe that such a factor is theabnormally high pore pressure, which occurs virtually throughout thesection of the area under study. The hydrostatic pressure gradients inthe pores of shales at 1,000–6,000 m are based on more than 2,000determinations and range from 0.012 to 0.024 MPa/m, with a meanof 0.018 MPa/m (see Figure 7-16 and Table 7-14).

The dependence of the montmorillonite content on the pore pressuregradient in shales is shown in Figure 7-20b. There is a close correlationbetween these two parameters. In regions of the Baku Archipelago andLower Kura Depression, characterized by intense development of AHFP(pore pressure gradients in shales of 0.018–0.019 MPa/m), the montmoril-lonite content in shales reaches an average of 53%. In regions withmoderate development of AHFP (Apsheron Archipelago and the SouthApsheron Offshore Zone), the montmorillonite content decreases to 17%.

These authors found no adequate discussion in relevant literatureon the role of pore pressure in shales on clay-mineral diagenesis andcatagenesis. It can be shown theoretically that rising pressures reducethe dehydration rates. The production of illite in shales involves anincrease in the free water volume as a result of the release of boundwater, which is denser than free water. A factor opposing this increasein volume (such as high pore pressure in shales) will reduce thedehydration rate. This agrees well with the conditions which exist inthe above-described sections.

On the other hand, AHFP can lead to transformation of illite tosecondary montmorillonite by the absorption of water. At AHFP,


smaller grain size of the clay minerals favors transformation of illite,as shown by the relationship between the pore size and depth (Table7-10 and Figure 7-21; pore sizes were determined from SEM data).

The writers propose the following scheme for the relationshipbetween clay-mineral transformation and the thermobaric conditions:

In a basin where the subsidence rate is equal to the rate of accumu-lation of sediments, the depth at which catagenetic transformation(desorption of water) begins remains more or less the same and islargely determined by the geothermal gradient. Inasmuch as the desorbed(interlayer) water is added to the interstitial water, abnormally highpore pressures may develop if the water cannot escape. Under someconditions, the rising pore pressure in shales may reduce the mont-morillonite dehydration rate and release of water. The result will besimilar to that arising from a low geothermal gradient, i.e., reductionin the rate of illite formation. Under favorable conditions, the illitemay be hydrated, which is accompanied by a release of heat and theirtransformation to secondary montmorillonite. The relative rates ofdehydration (illite formation) and the illite hydration (formation ofsecondary montmorillonite) may determine the pore pressure.

The sedimentation rate and the sediment sources do not remainconstant with time. Thus, different zones may differ in the dehydrationrate because of changes in the sedimentation rate or type of sedimen-tary material. Transitions from a zone with normal pressures andnormal dehydration rate to an AHFP zone may indicate either the effectof diagenetic and catagenetic processes or a lag in development ofthese processes. The montmorillonite content may remain the same oreven increase with depth. This, however, does not mean that theprocess of dehydration of montmorillonite to illite is replaced by theillite hydration, although this is possible. Instead, it could mean thatdehydration process in the AHFP zones is slow; therefore, these zonesmay be characterized by higher (or equal) montmorillonite contentsthan those in the younger zones with normal shale pore pressure.

Effect of Hydrochemical Environment

The hydrochemical environment in a basin of sedimentation hassignificant influence on the intensity of post-sedimentary transforma-tions. Thus, it is important to ascertain the nature of the hydrochemicalregime observed in the Cenozoic complex of the South Caspian Basin,


Figure 7-21. Pore size distribution of argillaceous rocks from the ProductiveSeries of Baku Archipelago. ω is relative frequency (Modified after Buryakovskyet al., 1986c). a—Duvanny Deniz, well 529, depth interval of 1,415–1,420 m/4,642–4,659 ft and 1,450–1,455 m/4,757–4,774 ft; b—same but depth inter-vals are 1,700–1,705 m/5,577–5,594 ft and 1,785–1,790 m/5,856–5,873 ft;c—same field but Well 275 and depth interval of 3,323–3,328 m/10,902–10,919 ft; d—Sangachal, Well 534, depth interval of 4,295–4,303 m/14,091–14,117 ft; e—Bulla Deniz, Well 537, depth interval of 4,993–5,000 m/16,381–16,404 ft; f—same field but Well 15 and depth interval of 5,128–5,132 m/16,824–16,837 ft.


namely: whether it is a consequence of diagenetic and catageneticprocesses in shales and the transformation of clay minerals, or it isformed predominantly as a result of the action of other factors (e.g.,compaction; see Rieke and Chilingarian, 1974). In this connection, theproblem presenting the greatest interest is the origin of invertedhydrochemical profile in the section of the South Caspian Basin, i.e.,with depth, calcium chloride waters are replaced by less saline sodiumbicarbonate waters. The writers obtained numerous data from thelaboratory analyses and field observations, indicating a decrease in themineralization of pore waters in sands with depth. Replacement ofcalcium chloride water by alkaline sodium bicarbonate water is morecharacteristic for the AHFP zones in the South Caspian Basin areas(Buryakovsky, 1974a). Analogous data on the decrease of formationwater salinity with increasing pressure were also noted in the Gulf ofMexico (Fertl, 1976).

The appearance of hydrochemical inversion in the stratigraphicsection of the South Caspian Basin may be explained by the geneticrelationship between the hydrochemical regime and the developmentof abnormally-high pore pressures in shales. The water of primarilysodium bicarbonate type characterize the most pronounced AHFPzones in the Baku Archipelago and Lower Kura Depression.

Chemistry of pore waters are determined largely by the compactionprocesses in argillaceous rocks and squeezing out of pore water(Chilingarian et al., 1994). The hydrochemical environment influencesthe diagenetic and catagenetic transformation (of clay minerals) processes.

Figure 7-22 shows the dependence of montmorillonite content onthe total salinity of formation water for the calcium chloride andsodium bicarbonate types of pore waters in sands, which are charac-teristic for the South Caspian Basin. As shown, a direct relationshipexists for the sodium bicarbonate type of water, i.e., with increasingwater salinity, the conditions for preservation of montmorillonite areimproved and its content in the clays increases. Increase in the totalsalinity of water is caused by an increase in the content of carbonateand bicarbonate salts of alkali-earth metals. Sodium bicarbonate typewaters are present in the Baku Archipelago and the Lower KuraDepression, as well as in the rocks from the Lower Productive Seriesof Apsheron Peninsula and adjacent offshore area, i.e., sections inwhich the argillaceous rocks are characterized by higher montmorillonite


content. There is an inverse relationship between the montmorillonitecontent and the presence of calcium chloride type of waters. Thechloride content [in particular sylvite (KCl)] increases with increasingwater salinity.

Thus, the alkaline medium is favorable for the formation andpreservation of montmorillonite. This was also confirmed by the resultsof computer geochemical simulation (Buryakovsky et al., 1990c).

The RAMIN program was utilized, which is similar to the geo-chemical model proposed by Kharaka and Barnes (1973). The RAMINprogram makes it possible to simulate the equilibrium distribution ofthe majority of elements present in the pore solutions at temperaturesup to 350°C on the basis of data on the chemical composition offormation water, temperature, pH and Eh. For determination of the

Figure 7-22. Relationship between the montmorillonite content and formationwater salinity (Modified after Buryakovsky et al., 1995). 1—Sodium bicar-bonate water, 2—calcium chloride water.


possibility of dissolution or precipitation of one or another mineral,calculation of ∆G values of the Gibbs free-energy difference is in-cluded in the program.

The results of the chemical analyses of formation water in Wells96 and 521 of the Unit VII of the Sangachal–Duvanny Deniz–KharaZyrya Field served as initial data for the computer-based simulation(Table 7-17). Average depth and formation temperature are as follows:Well 96: –3,091 m, +80°C; Well 521: –4,320 m, +97°C. The pH valueused averaged 7.0–7.5.

Table 7-18 gives the results of determination of the Gibbs free-energy difference, ∆G, for various clay minerals. As shown, withinthe pH interval of 6 to 8, in most cases ∆G values for minerals ofthe montmorillonite and kaolinite groups exceed zero. This indicatesa possibility that they are of authigenic origin. The values of ∆G forillite are always less than zero, which indicates the possibility of itsprecipitation from solution.

Thus, the geochemical environment at great depths in the SouthCaspian Basin deposits is not only conducive to the preservation ofallothigenic montmorillonite, but possibly allows the transformationof illite into secondary montmorillonite.

Secondary Montmorillonite

According to the data cited above, a rather close relation existsbetween the various clay mineral contents and the thermobaric and

Table 7-17Chemical Analyses of Formation Water from Wells 96 and 521, Unit VII,

Sangachal–Duvanny Deniz–Khara Zyrya Field

Concentration, Concentration,Components mg/liter Components mg/liter

Cl– 709.0 Ca2+ 8.02

SO42– 211.2 Mg2+ 2.44

HCO3– 195.2 Na++K+ 618.7

CO32– 36.0 Al3+ <0.1

RCOO– 17.7 SiO2 70.0


hydrochemical characteristics of the section in the South Caspian Basinand onshore of Azerbaijan. The stability of montmorillonite at greatdepths depends on many parameters. In the section of the BakuArchipelago at depths greater than 4–5 km, formation of secondarymontmorillonite from illite was observed using scanning electronmicroscope (SEM). This is explained by the relatively low tempera-tures, abnormally high pore pressures in shales, and the alkaline porewater enriched in Mg2+, Na+, and Ca2+ ions.

Particle (or aggregate) sizes of primary and secondary montmoril-lonite at great depths were established. This was achieved by quantita-tive analysis of SEM data. The writers used photomicrographs ofsurfaces cut parallel to bedding of a shale sample from a depth intervalof 5,128–5,132 m in the Bulla Deniz gas-condensate oilfield. Differ-ences between the primary and secondary montmorillonites wereestablished clearly using magnifications of ×1,000 and ×3,000.

Statistical analysis of the data on particle sizes of the primary andsecondary montmorillonites is presented in Table 7-19. As shown, theparticle sizes for primary montmorillonite are within the 0.5–11.2 µmlimits, whereas the size of secondary montmorillonite ranges from 0.6to 6.5 µm. The average particle sizes for the primary and secondary

Table 7-18Gibbs’ Free-Energy Difference (∆G) for Various Clay Minerals at Different pH

∆G @ pH

Clay Mineral 6 7 8

Well 96: 7.34 5.46 1.99Ca-montmorillonite 6.97 5.08 1.60K-montmorillonite 7.44 5.55 2.08Na-montmorillonite 7.38 5.49 2.01Kaolinite 5.91 3.84 0.48

Well 521: 6.14 3.20 –0.52Ca-montmorillonite 5.61 2.67 –1.07K-montmorillonite 5.94 3.00 –0.72Na-montmorillonite 6.21 3.27 –0.47Kaolinite 4.72 1.37 –1.84


montmorillonites are very close. Some differences were observed usingphotomicrographs with magnifications of ×1,000 and ×3,000, because,using a magnification of ×3,000, it is possible to observe a greaternumber of smaller particles. This, naturally, yields a somewhat smalleraverage value of the clay particle sizes (Figure 7-23).

As shown in Table 7-19 and Figure 7-23, the distributions of particlesizes are right-asymmetric, close to log-normal law. In all cases, theaverage values of the particle sizes exceed the median by 0.3–0.7 µm.It is significant that sizes of the montmorillonite particles are closeto those of the pores, as established by SEM data.

Utilizing the data obtained, the writers estimated the primary andsecondary montmorillonite contents (Table 7-20). On the average, thetotal montmorillonite content (percent of the total area of photo-micrographs) reached 19.2% (13.2% for primary and 6% for secondarymontmorillonites). The secondary montmorillonite fraction constituted31.5% (average) of the total montmorillonite mass. This indicates arather high rate of secondary montmorillonite formation from illite atgreat depths.

The post-sedimentary (diagenetic and catagenetic) transformation ofMiddle Pliocene shales of the South Caspian Basin is characterized

Table 7-19Statistical Analysis of Particle Sizes of Primary and Secondary

Montmorillonites at Two Different Magnifications (×1,000 and ×3,000)

Particle Size, µm

StandardDeviation, Variance,

Magnification Range Median Average µm %

Primary Montmorillonite

×1,000 0.9–11.2 1.9 2.6 3.3 127 0.58×3,000 0.5–5.1 1.5 1.9 2.1 122 0.53

Secondary Montmorillonite

×1,000 0.9–6.5 2.0 2.7 2.9 107 0.70×3,000 0.6–4.8 1.6 1.9 2.2 116 0.52

Asymmetryof Particle-

SizeDistribution


by the retardation of transformation of montmorillonite into illite orchlorite at great depths, and the replacement of this process by theprocess of transformation of illite into highly-swelling minerals of themontmorillonite group. These processes are closely related to the lowgeothermal gradient and increasing pressure at depth. The invertedhydrochemical profile of these deposits is possibly a consequence ofthe relationship between the transformation of clay minerals andthermobaric conditions at depth. On the basis of compaction experi-ments, Rieke and Chilingarian (1974) suggested that compaction fluidsbecome saltier as they move upwards.

Figure 7-23. Histograms of the distribution of particle sizes for primary (a,c) and secondary (b, d) montmorillonite (Bulla Deniz Field, depth interval of5,128–5,132 m/16,824–16,837 ft); (a, b) ×1000; (c, d) ×3,000; ω is relativefrequency (Modified after Buryakovsky et al., 1995).


Distribution of Oil Reserves

The areal extent of commercial oil accumulations within a strati-graphic sequence often shifts relative to the accumulations in otherstratigraphic units. This shift depends on lithofacies characteristics ofthe reservoirs and the paleotectonic history, which is reflected in thedistribution of oil reserves both areally and in the stratigraphic section.

Distribution of oil reserves in the Middle Pliocene Productive Seriesof the Apsheron oil and gas region (Apsheron Peninsula and Archipelago)were examined. The analysis was based on changes in the relativevolumes of original oil-in-place reserves in the individual fields, suites,and units, as well as in all of the Productive Series (see Figures 3-1,3-2, and 5-1).

The largest oil field of the Apsheron Peninsula is the Balakhany-Sabunchi-Ramany Field, which contains about 500 MMT or 20% ofthe total oil reserves of the Apsheron oil and gas region. The NeftDashlary Field located in the Apsheron Archipelago and BibieibatField contain 250 MMt each or 10% of total reserves. The Kala,Lokbatan-Puta-Kushkhana, Gyuneshli, Surakhany, and Sangachal—Duvanny Deniz—Khara Zyrya fields contain from 100 to 175 MMtor 4% to 7% each. These eight fields contain about 70% of the oil inthe region and the remainder of the fields (31 fields) contain up to1% each.

Table 7-20Portions of Primary and Secondary Montmorillonites at Two Different

Magnifications (×1,000 and ×3,000)

Content of Montmorillonite, %

Portion ofTotal Secondary

Photomicrograph Content, Montmorillonite,Number Magnification Primary Secondary % %

1 ×3,000 14.5 7.1 21.6 32.92 ×1,000 13.5 6.5 20.0 32.54 ×3,000 10.5 5.4 15.9 34.05 ×1,000 14.3 5.2 19.5 26.7


The Lower Productive Series contains more than 1.0 MMt or 42%,whereas the Upper Productive Series contains about 1.5 MMt or 58%of the total oil reserves in the Apsheron oil and gas region. In theUpper Productive Series, oil is present in 21 fields, whereas oil in theLower Productive Series is present in 27 fields.

The largest field in the Lower Productive Series is the Balakhany-Sabunchi-Ramany Field (19% of oil reserves), followed by the NeftDashlary Field, which contains 14% of oil reserves. The Binagady-Chakhnaglyar-Sulutepe Field contains 9% of oil reserves; the DarvinBank Field contains 7%; the Bibieibat, Buzovny-Mashtagi, PirallaghiAdasi, and Kala fields contain 6% each. The Surakhany Field contains5% of oil reserves (see Figure 5-1). The remainder of fields containless than 1% each of the oil reserves in the Lower Productive Series.

The Kirmaku Suite (KS) contains the largest deposits of oil in theProductive Series (19%), which constitutes 46% of the oil within thelower division of the Productive Series. The next largest petroliferousformation is the Podkirmaku Suite (PK), which contains 15% of theoil in the Productive Series and 36% of the oil in the lower divisionof the Productive Series. The Kala Suite (KaS) contains 3% and 7%of oil deposits in the Productive Series and in the lower division,respectively. The Nadkirmaku Sandy Suite (NKP) contains 5% and10% of oil, respectively. The NKG suite contains only small oilreserves in the eastern part of region.

The Kala Suite (KaS) contains commercial oil reserves in ninefields in the eastern part of the region (Figure 5-1). The largest fieldsare the Palchygh Pilpilasi Field, containing 38% of oil reserves (seeFigure 6-9), the Neft Dashlary Field containing 29% (see Figure6-5), and the Karachukhur, Kala, and Chalov Adasi fields containingfrom 5% to 8% each. The remaining four fields contain 2% of the oilreserves each.

Unlike the KaS, the zone with maximum oil reserves in the PK Suiteis confined to the Balakhany-Sabunchi-Ramany Field, which contains22% of the oil, due to areal extension of oil-bearing formations towardthe west. The oil reserves in the PK Suite gradually decrease fromthe Apsheron Archipelago to the Apsheron Peninsula, and then fartherto the west and southwest. For example, the PK Suite in the NeftDashlary Field contains 19% of the oil reserves; the Surakhany Fieldcontains 10%; the Pirallaghi Adasi Field contains 9%; the Kala andKarachukhur fields contain 5% each; the Buzovny-Mashtagi Field


contains 4%; and the remainder of fields contain from 1% to 2% eachof the oil reserves.

Considering the oil reserves in the KS Suite, the largest field is theBalakhany-Sabunchi-Ramany Field, which contains about 22% ofthe reserves in this suite. This field is followed by: the Binagady-Chakhnaglyar-Sulutepe Field containing 16% of oil reserves; theDarvin Bank Field containing 13.4%; and the Shabandag-YasamalyValley, Buzovny-Mashtagi, Pirallaghi Adasi, Neft Dashlary, Kala, andBibieibat fields containing from 6% to 9% each. Oil reserves in eachone of the remaining eight fields varies from 0.5% to 3%.

Due to the absence of separate oil reserves data for the NKP andNKG suites, oil distribution in both of these suites is describedtogether. Both the NKP and NKG suites contain about 3% of theProductive Series oil reserves in the region. Eighty-eight percent ofthis amount has been accumulated in five fields: the Neft DashlaryField (27%), the Bibieibat Field (18%), the Balakhany-Sabunchi-Ramany Field (17%), the Lokbatan-Puta-Kushkhana Field (16%), andthe Kala Field (10%). The remaining 12% is almost equally distributedamong 12 fields.

There was a break in sedimentation after deposition of the NKGSuite sediments, which resulted in the partial erosion of the depositseast of the Binagady-Atashkyah fields (Figure 5-1). Deeper erosionoccurred in the central portion of the Apsheron Peninsula wherethe thickness of the NKG Suite decreases to 30–40 m (Binagady,Surakhany, Bibieibat, and other fields). Prior to the deposition ofUpper Productive Series sediments, the eroded zone was filled withvery large lense of “Pereryv” facies. Lens sediments in the peninsulaare composed of shallow marine deposits. Apparently, this resulted inan offset of the “Pereryv” Suite commercial oil-bearing zone towardthe southeastern portion of the region.

The “Pereryv” Suite contains significantly more oil than the NKPand NKG suites; oil has accumulated in six fields located offshore.These fields are: Gyuneshli (38%), Chyragh (21%), Neft Dashlary(15%), Azeri (10%), Bakhar (10%), and Bibieibat (7%). The valuesshown above indicate that 83% of the oil reserves in the “Pereryv” Suiteaccumulated in the Neft Dashlary, Gyuneshli, Azeri, and Chyragh fields.

Almost half of the oil in the Upper Productive Series accumulatedin the Balakhany-Sabunchi-Ramany Field. The Bibieibat and Sangachal-Duvanny Deniz-Khara Zyrya contain 12% each of the Upper Produc-


tive Series oil. The Neft Dashlary, Surakhany, and Gyuneshli fieldscontain 8% each; the Lokbatan-Puta-Kushkhana Field contains 6%; andthe Chyragh Field contains 4% of the oil reserves. These eight fieldscontain about 85% of the oil in the upper division of Productive Series.Each one of the remainder of the fields contains no more than 1% ofthe oil. Generally, unlike the reserves in the Lower Productive Series,the oil reserves of the upper half of the Balakhany (above Unit X),Sabunchi, and Surakhany suites are concentrated only within the fivefields located both onshore and offshore. The reserves are distributedas follows: Neft Dashlary Field contains 30–35%, Balakhany-Sabunchi-Ramany Field contains up to 20%, and the remaining five fieldscontain up to 10–15% each.

Thus, the oil of the Apsheron oil and gas region has primarilyaccumulated in the Apsheron Peninsula (60%) and the ApsheronArchipelago (30%). The remainder of the oil is located in the northernportion of the Baku Archipelago (Figure 6-3). A gradual and significantdecrease in the oil reserves occurs in the direction of regional dip ofthe Productive Series formations toward the south and southeast, dueto a decrease in sand content in the stratigraphic section and anincrease in gas accumulation.

Oil in the Kirmaku Suite and the upper parts of the Balakhany,Sabunchi, and Surakhany suites is mainly concentrated in the north-western part of the region. Allthough it accumulated within a smallarea, reserves are very high because of more favorable lithofacies andstructural scenarios.

Oil Composition and Properties

Many methods of classification of crude oils have been devised. Arational basis of classification is found in some expression of thecomposition of oils. Composition of an oil is determined by separatingit into fractions according to the boiling point (molecular weight),followed by establishing the hydrocarbon groups present in eachfraction. To determine the fractional composition of oil, one can usea method of separating it into fractions according to boiling point. Thismethod is called fractional distillation. Fractional composition reflectsthe relative content in percent by weight (wt %) of different oilfractions boiling within definite boiling-point ranges. The followingmain fractions are distinguished: “benzine” fraction with boiling points


Table 7-21Fractional and Hydrocarbon Group Composition of Crude Oils

from Apsheron Peninsula and Archipelago

Hydrocarbon GroupComposition, %

Boiling-pointRanges of FractionFractions, Yield, Density, Molecular

°C wt % g/cm3 Weight Aromatic Naphthenic Paraffinic

Average from 14 Fields

<65 0.5 — 89 — — —65–95 1.5 0.725 97 4.9 43.5 51.695–122 2.4 0.749 108 5.6 50.7 43.7122–150 3.4 0.773 122 7.7 55.8 36.5150–175 3.8 0.796 135 11.6 60.0 28.4175–200 4.2 0.816 150 15.1 64.5 20.4200–225 5.1 0.835 166 18.6 61.1 20.3225–250 5.8 0.852 185 23.8 54.8 21.4250–275 5.9 0.867 203 30.0 50.6 19.4275–300 6.4 0.880 225 29.9 40.9 29.2300–325 6.0 0.892 247 30.1 35.4 34.5325–350 5.8 0.902 272 34.1 31.7 34.2

Average From 56 Zones/Suites

<65 0.4 0.687 88 — — —65–95 1.5 0.726 96 4.0 48.5 47.595–122 2.6 0.749 108 5.1 53.3 41.6122–150 3.7 0.773 121 7.5 57.1 35.4150–175 4.1 0.796 135 10.8 59.2 30.0175–200 4.4 0.816 150 15.6 61.1 23.3200–225 5.3 0.834 166 18.2 59.2 22.6225–250 6.2 0.850 184 22.8 51.6 25.6250–275 6.1 0.866 204 28.6 49.3 22.1275–300 6.3 0.876 225 28.5 40.4 31.1300–325 6.0 0.888 247 28.3 33.8 37.9325–350 5.8 0.900 272 31.8 31.1 37.1


ranging from 40 to 200°C, “ligroin” fraction with boiling points rangingfrom 200 to 350°C, and residual oil with boiling points ranging from350 to 500°C.3

In addition to fractional composition, to evaluate geochemical historyof oils, hydrocarbon group composition is widely used, i.e., the contentof paraffinic (methanic), naphthenic, and aromatic groups of hydro-carbons. Besides hydrocarbon components, different non-hydrocarbon

Figure 7-24. Geochemical relationships for oils. a—Oil-fraction yield vs.temperature, b—oil density vs. temperature, c—molecular weight vs. temp-erature, d—oil density vs. molecular weight of oil residue.

3 According to American terminology, benzine fraction, as used in Russia, includes lightnaphtha, gasoline, and heavy naphtha; ligroin fraction includes kerosene, stove oil, and lightgas oil; residua includes heavy gas oil, lubricating oil, vacuum gas oil, etc.


components are present in crude oils. The major non-hydrocarboncomponents are asphalts/asphaltenes/resins and sulfur-bearing compounds.

Table 7-21 gives averaged data from 56 zones/suites of 14 oil fieldsin the Apsheron Peninsula and Archipelago (Ashumov, 1961). Withincreasing boiling point, the yield, density and molecular weight of

Figure 7-25. Hydrocarbon group [paraffinic (methanic), naphthenic, andaromatic] composition of light fractions of the crude oils from ApsheronPeninsula and Archipelago (data points are oil densities in g/cm3).


residua also increase. It should be noted that relations are not linear(Figure 7-24).

The hydrocarbon group composition of crude oils can be plotted ona triangular diagram (Figure 7-25). This ternary diagram was basedon the experimental data (Table 7-21) with fractions boiling between65 and 350°C. Figure 7-25 shows that with increasing temperature,

Figure 7-26. Relationship between the content of various hydrocarbon groups(paraffinic, naphthenic, and aromatic) and boiling point of different fractionsof crude oils of Apsheron Peninsula (Modified after Ashumov, 1961; Dobryanskiy,1948; and Kartsev, 1950). a—Crude oils from Apsheron Peninsula (solid lines)and average “world” crude oil (dashed lines); b—crude oils from Neft DashlaryField (dashed lines) and Palchygh Pilpilasi Field (solid lines) and average“world” crude oil (lines with dots).


the class of crude oil changes from the paraffinic-naphthenic tonaphthenic-paraffinic, and then to paraffinic-naphthenic-aromatic, withan increase in density from 0.73 to 0.90 g/cm3.

Figure 7-26a shows the relationship between the content of varioushydrocarbon groups (paraffinic, naphthenic, and aromatic) and theboiling point of different fractions of crude oils of the ApsheronPeninsula (Ashumov, 1961). The results obtained by Dobryanskiy(1948) and Kartsev (1950) for “world” crude oils (weighted averagedata from many oil fields) are presented for comparison purposes inFigure 7-26a. Similar studies were carried out for offshore oil fieldsof the Apsheron Archipelago (Figure 7-26b). As shown in thesefigures, with increasing boiling point, the aromatic hydrocarbonscontent in the fraction increases, whereas the paraffinic hydrocarbonscontent decreases.

Based on Figure 7-26, the crude oils of the Apsheron Peninsula andArchipelago are of paraffinic-naphthenic or naphthenic-paraffinic type.The amount of paraffinic hydrocarbons in the “benzine” fraction variesfrom 37 to 75%, and in the “ligroin” fraction, from 28 to 55%. Thenaphthenic hydrocarbons content varies, respectively, from 24 to 61%and from 35 to 67%; aromatics, from 1.5 to 6.7% and from 3.3 to 21%.The oils are predominantly devoid of sulfur, and the content of paraffinis insignificant. High-paraffin oils (up to 4% solid paraffin) have beenfound in the southeastern plunge of the Neft Dashlary Oil Field.

Physical properties of oils of the Apsheron Peninsula and Archipelagohave been extensively analyzed. Figure 7-27 shows the data on oildensity, content of asphalts/asphaltenes/resins (R), and “benzine” (G)content from the Neft Dashlary Oil Field in the Apsheron Archipelago(Buryakovsky, 1974a) presented as histograms.

The oil density varies from 0.81 to 0.93 g/cm3. The crude oils ofthe northwestern part of the archipelago, as compared with those ofthe southeastern part, contain more resins (37.2 and 22.7%, respec-tively) and less low-boiling fractions (respectively, 1.54 and 7.4%“benzine,” and 7.4 and 9.6% “ligroin”). Consequently, their densitiesare greater (0.914 ± 0.024 g/cm3) than those of the crude oils of thesoutheastern part of the archipelago (0.880 ± 0.038 g/cm3). A total of1,642 analyses have been made for the northwestern part of the archi-pelago and 820, for the southeastern part.

On the whole, over the northwestern part of the Apsheron Archipelago(Darvin Bank, Pirallaghi Adasi, and Gyurgyan Deniz fields), averages


of crude oil properties [with evaluation of their changes within two-sigma limits (95% of confidence)] based on 1,642 analyses can bewritten as follows: γave = 0.9137 ± 0.0006 g/cm3; Rave = 37.2 ± 0.37%;Bave = 1.54 ± 0.03%; and Lave = 7.4 ± 0.03% where γ is oil density ing/cm3, R is content of resins, asphaltenes, and asphalts in wt %, B iscontent of “benzine” in wt %, and L is content of “ligroin” in wt %.

Over the southeastern part of the Apsheron Archipelago (ChalovAdasi, Palchygh Pilpilasi, and Neft Dashlary fields) based on 820analyses, these properties can be written as follows: γave = 0.8800 ±0.0013 g/cm3; Rave = 22.7 ± 0.41%; Bave = 7.4 ± 0.26%; and Lave =9.6 ± 0.28%.

Figure 7-27. Histograms of crude oil density (a), and contents of resins (b)and “benzine” (B or G) (c) in crude oils from Neft Dashlary Field. ω is relativefrequency. 1—Balakhany Suite, 2—“Pereryv” Suite, 3—Nadkirmaku SandySuite, 4—Kirmaku Suite, 5—Podkirmaku Suite, 6—Kala Suite.


Using both numerical characteristics and histograms, one can solvedifferent geological and geochemical problems. For example, Figure7-28 shows a comparison between the distribution of densities of crudeoils from different suites of the Neft Dashlary Oil Field. With in-creasing burial depth, density of oil and resin content increase, whereasthe “benzine” content decreases. These regularities, however, do notexist in the Upper Productive Series. Increase in density in the UpperProductive Series is related to oxidation of the crude oil by near-surface agents, which results in an increase in the asphalts/asphaltenes/resins content and decrease in the “benzine” content.

Gas saturation and physical and chemical properties of crude oilsof the Apsheron Peninsula and Archipelago change regularly accordingto the three main trends presented in Figure 7-29. The space-timepattern of changes in the properties of the fluids may be subdividedinto changes of first and second order.

First-order pattern within the fields, grouped together on the basisof common geotectonic conditions, include the following changesbased on decrease in scale:

I. Regional, with transition from structure to structure along themain anticlinal trends.

II. Local, through the stratigraphic section, with change in depthof the unit or suite.

III. Interreservoir, dependent on change in the topographic depth ofthe individual reservoir.

During the process of field development, the above pattern has beenassociated with changes in the properties of oil and water with time.

Second-order patterns, also having a definite regularity, may bequalitative or quantitative depending on different factors: lithology,reservoir-rock properties, the total salinity and ionic composition ofthe formation waters, migration of the subsurface fluids, etc.

In the direction of submerging of the second anticlinal trend ofDarvin Bank—Pirallaghi Adasi—Gyurgyan Deniz—Dzhanub, a decreasein the crude oil density has been recorded, with transition in theDzhanub Gas Field toward gas and gas-condensate accumulations,present in all units and suites. Thus, from the Darvin Bank Fieldthrough Pirallaghi Adasi (Northern and Southern folds) to the GyurgyanDeniz Field, the oil density (in g/cm3) varies as follows: KSupper:0.923–0.916–0.916–0.901; KSlower: 0.925–0.917–0.916–0.886; PK:0.928–0.920–0.913–0.888.


Figure 7-28. Variation curves for crude oil density from the Neft DashlaryField. a—Unit X of Balakhany Suite, b—“Pereryv” Suite, c—NadkirmakuSandy Suite, d—Kirmaku Suite, e—Podkirmaku Suite, f—KaS Suite. Faultblocks: 1—II, 2—IV, 3—III, 4—V.


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The southeastern part of the Apsheron Archipelago and the thirdanticlinal trend (Khali—Azeri) are also characterized by a decrease incrude oil density from northwest to southeast. Commercial oil accumu-lations have not been found so far at the Khali structure. In thedirection from the Chalov Adasi Oil Field to the Palchygh PilpilasiOil Field and to the Neft Dashlary Oil Field, a decrease in densitieshas been recorded through the Podkirmaku Suite from 0.910 to 0.888g/cm3, and through the Kala Suite, from 0.917 to 0.922 to 0.900 g/cm3.As is evident, the whole archipelago is, in the regional plan, a regionwhere the oil density increases upward along the regional slope (seeFigure 7-29, type A). This corresponds to the spatial diagrams ofgradual migration or differential entrapment of hydrocarbons bySavchenko (1952), Maksimov (1954, 1962), Gussow (1955), Fyodorov(1962), Bagir-zadeh et al., 1974c, etc.

Another pattern, established for various fields, concerns the increasein crude oil density with increasing stratigraphic depth. The differencein oil density through the productive section of the Darvin Bank Fieldis 0.005 g/cm3; of the Pirallaghi Adasi Field, 0.004 g/cm3 (NorthernFold) and 0.002 g/cm3 (Southern Fold); of the Gyurgyan Deniz Field,0.012 g/cm3; of the Chalov Adasi Field, 0.008 g/cm3; and of the NeftDashlary Field (the Lower Productive Series), 0.037 g/cm3. An excep-tion is the Upper Productive Series of the Neft Dashlary Field, whererelatively more oxidized and heavier crude oils occur, and the KalaSuite of the Palchygh Pilpilasi Field.

Within some reservoirs, an increase in crude oil densities has beenobserved with an increase in depth of occurrence as a result ofoxidation by waters around the oil-water contours. On the other hand,in the higher portions of exposed accumulations, the density of crudeoils are higher as a result of oxidation of the oils near the surface.There is a tendency toward a certain increase in the density of crudeoils with time.

Natural Gas Properties

In the Productive Series of the Apsheron Peninsula and Archipelago,the crude oil is accompanied by natural gas (mainly hydrocarbons),either dissolved, forming gas caps, or accumulating in the form ofindependent gas or gas-condensate pools (sometimes in secondary trapsabove). The discovery in 1961–1962 of large gas and gas-condensate


accumulations in the Dzhanub Prospect has considerably increased thegas potential of this region.

The northwestern group of fields of the Apsheron Archipelago,excluding Dzhanub, is much poorer in gas reserves than the south-eastern group. Gas accumulations have not been found at the DarvinBank, Pirallaghi Adasi or Gyurgyan Deniz fields. Most of the gas isapparently dissolved in the oil, and a small gas cap was present onlyin the Kirmaku Suite in the eastern flank of the Darvin Bank Fieldbefore development (see Figure 7-7).

The Dzhanub Gas Field is located southwest of the Chalov AdasiOil Field (see Figure 6-11). Its discovery completely supported theconcept of gas occurrence on the submerged portions of the anti-clinal trends of the Apsheron Archipelago, proposed by Samedov andBuryakovsky (1961). The number of productive zones here reaches six(units V and VI of the Balakhany Suite, and the NKP, KS, PK, andKaS suites), and the contours of gas-bearing rocks expand downward.Gas flows obtained in the wells indicate the presence of large reserves.

In the crestal portion of the northwestern flank of the Chalov AdasiOil Field, two exploratory wells have revealed the presence of a thickgas cap, restricted to the basal parts of the Kala Suite. Gas productionreached 100 to 500 Mcmd (3,530 to 17,650 Mcfd), with a wellheadpressure of 10–20 MPa. The other units of KS, PK, and KaS suitesdo not contain gas caps, but gas is dissolved in oil: the gas/oil ratio(GOR) reaches 50–90 m3/ton. The gases of the individual units ofChalov Adasi Field have a similar composition and differ from thegases of Neft Dashlary Field in a smaller content of heavy hydro-carbons (26 and 40 g/m3, respectively). Characteristics of the gasesof Chalov Adasi Field are presented in Table 7-22.

In the Palchygh Pilpilasi Oil Field, the gas flows from the PK suiteand KaS5 unit in the crestal parts of anticline indicate the presence ofgas caps in these reservoirs.

It has been shown that the unit KaS3 on the southwestern flank ofthe Neft Dashlary Oil Field contains only gas and, possibly, an insigni-ficant oil fringe. In the crestal portion of the unit KaS2 of the samefield, a gas cap is present. In the other units, especially in the plungeof anticline, gas caps are also present. A significant amount of naturalgas is dissolved in the oil; according to the data from downhole oilsamples, the solubility factor is on the average 0.46 cm3/cm3 per 1 atmof differential pressure. The GOR varies over a wide range from 10


to 1,000 m3/ton. (For gas composition at the Neft Dashlary Field seeTable 6-2.)

The overall pattern in the distribution of gas saturation in thereservoirs of the Apsheron oil- and gas-bearing region is the increasein the relative amount of gas and the replacement of the oil accumu-lations by oil-gas and gas-condensate types in the direction of sub-mergence of the anticlinal trends (from northwest to southeast), whichis associated with a decrease in the crude oil densities in this direction.Consequently, the potential of Apsheron Archipelago, and especiallyits southeastern continuation, is increasing as a region with significantgas reserves.

For the natural gases associated with crude oil, linear relation-ships have been developed empirically between the density and thecontents (% by volume) of methane (CH4) and carbon dioxide (CO2)(Figure 7-30):

γ = (155.3 – CH4)/100

γ = (0.918 CO2 + 60)/100

The accuracy of these formulae has also been established in thefields of other regions of the Former Soviet Union. This was done onthe basis of 71 gas analyses from 14 fields. These formulae havereceived wide acceptance.

Using the CH4 and CO2 contents of gas (% by volume), the contentof C 2

+ hydrocarbons (ethane and heavier) can be found according tothe following formula:

Table 7-22Composition of Gas from the Chalov Adasi Field

Gas Composition, Vol %

Unit or Density, Content of C5+,

Suite Methane Ethane Propane Butane C5+ CO2 g/cm3 g/m3

PK1 87.8 1.74 0.12 0.06 0.12 19.8 0.6592 4.46PK2 83.8 2.59 0.16 0.16 0.74 12.6 0.7084 28.7KaS 88.0 2.26 0.37 0.48 0.93 17.8 0.6718 35.9


C2+ = 100 – (CH

4 + CO

2).

The content of heavier hydrocarbons (C5+) in g/m3 can be calculated

from the volume percents of C2+ using the following formula:

C5+ = 40 C

2+.

If the gas contains no foreign admixtures, then, knowing its density(specific gravity), a rough determination of gas composition can bemade using these formulae.

Formation Water Properties

The formation waters of the Productive Series of the Apsheron oil-and gas-bearing region, are those of the South Caspian Basin. Thereis a very slow movement of formation waters from the more submerged

Figure 7-30. Relationships between the specific gravity of gas (compared toair) and the contents of CH4 and CO2.


parts of the basin toward the higher parts, where discharge zones arelocated (Samedov and Buryakovsky, 1966).

In the Productive Series, the formation waters are predominantly ofthe sodium bicarbonate type. These waters are typical of all units ofthe Lower Productive Series and of certain (lower) units of the UpperProductive Series. The waters from the Upper Productive Series havehigh total salinity and are of calcium chloride and magnesium chloridetypes. Tables 7-23 and 7-24 illustrate total salinity and chemicalcomposition of formation waters from the fields of Apsheron Peninsulaand Apsheron Archipelago, respectively.

According to Chilingar (1957) the relationship between the chemicalcomposition of Apsheron Peninsula waters and the stratigraphic depthis subject to the following rules:

1. The water salinity decreases with the stratigraphic depth (alsosee Rieke and Chilingarian, 1974, pp. 265–269; Samedov andBuryakovsky, 1966).

2. Cl–, Ca2+, and Mg2+ contents decrease with depth.3. (Na+ + K+) and (HCO3

– + CO32– + H+ + K+) contents gradually

increase with depth.4. The transition from hard to alkaline water occurs at a maximum

concentration of not exceeding 100 mg-equ per 100 g of water(50–65 g/l). As a rule, the water is hard at concentrations above100 mg-equ.

5. The HCO3– content (in mg-equ) does not exceed the Cl– content

(A1 ≤ S1).6. Usually, the water does not contain SO4

2– anion. If present,however, its concentration does not exceed 0.4 mg-equ per 100 gof water.

Mekhtiev (1956, in: Rieke and Chilingarian, 1974, p. 265) alsoshowed that in the Azerbaijan oil fields water salinity decreases withstratigraphic depth, and calcium-chloride water [(r Cl– – rNa+)/rMg2+

> 1, where r = percent equivalent] is gradually replaced by bicar-bonate water [(rNa+ – r Cl–)/rSO4

2– > 1]. For magnesium chloride typeof water: [(r Cl– – rNa+)/rMg2+ < 1]. For details on classification ofwaters, see Chilingar (1956, 1957, 1958), Samedov and Buryakovsky(1956, 1966), and Buryakovsky (1974a).

The chemical composition and total salinity of the formation waterregularly change areally and vertically in the section of individual


Tab

le 7

-23

Tota

l S

alin

ity

and

Ch

emic

al C

om

po

siti

on

of

Fo

rmat

ion

Wat

ers

fro

m O

il an

d G

as F

ield

s o

f th

e A

psh

ero

n P

enin

sula

Ani

on (

a) a

nd C

atio

n (c

) C

ompo

sitio

nm

g-eq

uiva

lent

s/10

0g w

ater

Ave

rag

eTo

tal

Uni

t or

Dep

th,

Sal

inity

,H

CO

3–∑

(a+

c)N

aN

a–

Cl

Cl–

Na

Ca

Su

item

g/l

Cl–

SO

42–

+C

O32

–C

a++

Mg+

Na+

+K

+m

g-e

qu

Cl

SO

4M

gM

g

A1,

320

155

272.

8—

0.3

23.4

37.5

212.

254

60.

78—

1.63

0.62

B1,

400

151

263.

60.

10.

326

.432

.720

4.9

528

0.78

—1.

800.

81C

1,45

014

024

5.3

0.2

0.5

24.6

33.0

188.

449

20.

82—

1.73

0.75

D1,

530

128

222.

00.

10.

925

.015

.818

2.2

446

0.84

—2.

521.

58I

1,56

012

421

5.7

0.1

0.7

22.8

12.1

181.

643

30.

82—

2.82

1.88

II1,

610

129

225.

10.

10.

319

.023

.218

3.3

451

0.82

—1.

810.

82II

I1,

675

127

222.

40.

20.

920

.321

.518

1.7

447

0.82

—1.

890.

95IV

1,72

511

729

4.6

0.2

1.1

21.8

15.9

168.

341

20.

82—

2.28

1.37

IVa

1,75

011

620

1.0

0.1

2.3

21.5

15.1

166.

940

70.

83—

2.24

1.42

IVb

1,77

011

119

1.4

0.2

2.2

17.1

14.0

162.

838

80.

86—

2.22

1.22

IVcd

1,79

017

212

9.9

0.1

4.6

3.0

7.0

125.

027

00.

97—

0.7

0.43

IVe

1,81

016

098

.30.

15.

91.

33.

010

0.7

210

1.02

24.0

—0.

43V

1,86

015

792

.60.

16.

61.

02.

196

.920

01.

0442

.0—

0.49

VI

1,92

014

568

.60.

19.

70.

30.

678

.115

81.

1395

.0—

0.50

VII

1,96

014

058

.40.

110

.70.

40.

568

.613

91.

1710

2.0

—0.

80V

II1,

030

138

54.1

0.1

12.0

0.1

0.2

66.2

133

1.23

121.

0—

0.50

IX—

X1,

100

136

51.2

0.2

11.8

0.1

0.2

63.2

127

1.23

60.0

—0.

50“P

erer

yv”

1,25

014

056

.80.

111

.80.

10.

568

.413

81.

2011

6.0

—0.

20N

KG

1,35

014

467

.60.

110

.00.

20.

377

.515

61.

1499

.0—

0.70

NK

P1,

400

136

54.3

0.2

7.8

0.2

0.3

62.0

125

1.14

38.5

—0.

70K

S1,

570

120

25.9

0.1

8.7

0.1

0.2

34.7

170

1.34

88.0

—0.

50P

K1,

740

119

8.6

0.3

7.2

0.1

0.2

16.2

133

1.88

25.3

—0.

50K

aS2,

630

113

12.7

0.5

8.9

0.1

0.2

22.2

145

1.71

19.0

—0.

50


structures. With depth, the total water salinity decreases, whereas thealkalinity increases depending both on the stratigraphic and topo-graphic position of the suite (Tables 7-23, 7-24, and 7-25).

Differences in water salinity between adjacent units are not distinct,but are more or less gradual from unit to unit. The individual unitsare distinguished mainly by the average values. Overlap in watersalinity of individual units may be due to lithology, grain-size, andmineralogic composition of the rocks. The total water salinity increaseswith increasing content of clay minerals in rocks. This is possibly due toa decrease in permeability of the reservoir rocks with increasing claycontent, resulting in slow water exchange and an increase in stagnation.

There is a general trend of decreasing salinity of produced waterwith time, probably due to the influx of fresher water from the shalesinto associated sandstones. Upon initiation of waterflooding, however, thistrend becomes obscure due to mixing of injection and formation waters.

In the Apsheron Archipelago, there is a decrease in total watersalinity on moving from the uplifted structures to the deeper ones.Within the northwestern group of fields (through all the units of theKirmaku and Podkirmaku suites) the formation waters move from thecentral field of Pirallaghi Adasi to the peripheral fields of Darvin Bankand Gyurgyan Deniz. For the southeastern part of the archipelago, itis assumed that the fields of Neft Dashlary and Palchygh Pilpilasi arecentral, whereas the Chalov Adasi and the Gyuneshli structures areperipheral. This may indicate a marked stagnation of formation watersin the central uplifted structures of the anticlinal trends, which mayhave contributed to an increase in the total water salinity. Table 7-26shows this trend using the total salinity of formation waters.

The formation water on the southwestern flanks of all the structuresis less mineralized than that on the northeastern flanks. This suggeststhat the general direction of water movement is from the southwesternto the northeastern flanks, along the regional rise of the structures.This regularity is shown in Table 7-27 using the total salinity offormation waters.

Oil and Gas Migration and Accumulation

The patterns of spatial distribution of oil and gas accumulations andchanges in the properties of the crude oil and formation water have



Tab

le 7

-24

Tota

l S

alin

ity

and

Ch

emic

al C

om

po

siti

on

of

Fo

rmat

ion

Wat

ers

fro

m A

psh

ero

n A

rch

ipel

ago

Fie

lds

Ani

on (

a) a

nd C

atio

n (c

) C

once

ntra

tion

in m

g-eq

uiva

lent

s/L

Tota

lU

nit

orS

alin

ity,

∑(a

+c)

Na

Na

–C

lS

uite

g/l

Cl–

SO

42–

HC

O3–

CO

32–

Ca+

+M

g++

Na+

+K

+N

. A

cid

sm

g-e

qu

Cl

SO

4

Nef

t D

ashl

ary

Fie

ld

VI

56.1

73.0

0.1

12.4

0.3

0.4

4.0

83.0

1.4

174.

91.

1?

VII

I56

.880

.70.

27.

8—

2.4

5.4

81.5

0.5

178.

61.

0?

X49

.573

.50.

38.

20.

60.

33.

076

.50.

615

8.0

1.1

45“P

erer

yv”

39.5

50.5

0.1

4.4

—0.

21.

657

.90.

311

9.8

1.1

45N

KP

32.1

39.9

0.5

7.9

1.6

1.1

1.4

47.1

0.4

97.2

1.1

28K

S1

27.8

33.2

0.2

5.3

0.8

0.3

0.4

39.7

0.4

80.8

1.2

32K

S2

26.8

34.0

0.5

5.0

0.6

0.3

0.3

40.7

0.6

82.4

1.2

13P

K1

25.6

24.7

0.8

7.6

0.6

0.4

0.4

34.2

0.9

70.3

1.4

12P

K2

22.0

19.5

0.7

6.8

0.3

0.5

0.6

27.9

1.0

58.0

1.4

12P

K3

19.0

15.0

0.6

7.3

0.4

0.4

0.5

22.8

0.6

48.0

1.5

18K

aS1

14.9

11.1

0.4

5.5

0.5

0.4

0.4

17.4

0.4

36.6

1.6

16K

aS2

16.1

12.6

0.4

5.6

0.8

0.3

0.4

19.8

0.5

40.9

1.5

18K

aS3

18.2

15.7

0.1

4.8

0.4

0.2

0.2

22.2

0.6

45.2

1.4

65K

aS4

19.0

16.1

0.3

5.3

1.0

0.3

0.3

22.7

0.5

46.6

1.3

22

General Regularities in Oil and Gas Distribution 193P

alch

ygh

Pil

pila

si F

ield

PK

19.7

19.0

0.2

6.7

0.4

0.3

0.6

26.4

0.5

47.7

1.4

1K

aS1

18.4

17.8

0.3

5.4

0.8

0.3

0.6

24.8

0.4

50.7

1.4

1K

aS2

17.7

15.9

0.3

5.8

0.7

0.6

0.5

22.6

0.5

47.3

1.3

1K

aS3

19.1

19.0

0.4

5.7

1.0

0.6

0.6

23.3

0.1

50.8

1.3

1K

aS4

16.2

15.1

0.1

6.4

—0.

30.

321

.70.

344

.51.

41

Dzh

anub

Fie

ld

NK

P37

.032

.51.

6—

—0.

30.

235

.6—

—1.

4—

PK

16.9

16.3

1.2

2.3

0.6

0.2

0.1

22.0

1.4

44.9

1.5

15K

aS1

17.6

15.7

1.3

2.3

0.5

0.1

0.1

21.6

1.6

43.7

1.3

4.5

KaS

217

.816

.43.

01.

90.

50.

50.

621

.60.

945

.41.

41.

7K

aS3

17.7

16.2

3.1

1.6

0.3

—0.

222

.51.

145

.41.

32.

3K

aS4

17.2

16.6

2.6

1.8

0.3

0.3

0.2

22.8

1.2

46.3

1.0

2.4


Table 7-26Salinity of Formation Water (grams per liter) from

Offshore Oil and Gas Fields

Suite

Field NKP KSupper KSmiddle KSlower PKupper PKlower KaSupper KaSmiddle KaSlower

Darvin Bank — 27 18 16 14 — — — —Pirallaghi Adasi 90 39 30 25 18 — — — —Gyurgyany Deniz 80 — — 20 17 15 13 12 —Chalov Adasi — — — 27 25 24 23 20 25Palchygh Pilpilasi — — — — — — 22 21 26Neft Dashlary 32 — — 31 28 23 22 21 24

Table 7-27Trend in Formation-Water Salinity (grams per liter)

within the Apsheron Archipelago

Kirmaku Suite Podkirmaku Suite Kala Suite

Field SW NE SW NE SW NE

Chalov Adasi 22 33 24 25 21 25Palchygh Pilpilasi — — — — 23 24Neft Dashlary 28 32 24 26 19 28

Table 7-25Formation-Water Salinity vs. Depth in the Neft Dashlary Field

Total Salinity of Formation Waters from Various Suites, g/l

DepthInterval

m KS2 PK1 PK2 KaS1 KaS2 KaS3

200–400 29.5 31.5 25.0 18.5 — —400–600 30.5 28.0 24.0 16.5 — —600–800 30.2 26.4 23.0 15.6 15.8 25.0

800–1,000 26.9 25.6 20.7 15.1 15.5 19.01,000–1,200 25.5 25.3 20.8 14.2 14.9 18.01,200–1,400 27.0 19.5 20.5 15.5 19.5 15.01,400–1,600 — — — 15.5 15.5 18.01,600–1,800 — — — — 17.5 —


apparently been genetically controlled by the migration and accumulationprocesses of both the hydrocarbons and the associated waters. A study ofsuch patterns may serve as a basis for explaining the mechanism offormation of the oil and gas accumulations (Bagir-zadeh et al., 1974c).

The following migration processes were considered by the writers:First, the lateral migration of hydrocarbons either in a dissolved stateor as a gas-vapor phase, along the strata of the Lower ProductiveSeries, led to the oil and gas differential entrapment. This was accom-panied by a regular decrease in the oil density going up along theregional rise: oil accumulations → oil and gas → gas and gas-condensate→ absence of commercial oil accumulations (Khali, Apsheron Bankand Mardakyany Deniz structures). This pattern may be traced alongboth anticlinal trends of the Apsheron Archipelago.

Second, vertical migration within individual structures, which isassociated with the regularity in the distribution of the oil propertiesin the vertical section, and changes in the chemical composition offormation waters, were studied. This pattern is apparent in the NeftDashlary and Dzhanub fields, where hydrocarbon accumulations existin the Upper Productive Series. The absence of hydrocarbon accumu-lations in the Upper Productive Series in the greater part of thearchipelago is apparently explained by the presence of faults, avenuesfor the migration of oil and gas.

Potential of Very Deep Oil- and Gas-Bearing Deposits

Forecasting the presence of deep hydrocarbon-bearing and, in partic-ular, gas-bearing deposits attracts much attention.

The current investigations show that there is a high content of totalorganic carbon in the Cenozoic-Lower Paleozoic sedimentary rocks,and an increase in the organic matter bituminization with depth. Someinvestigators believe that the processes of oil and gas generation at adepth interval of 4.5 to 8.0 km has not been completed in some basins,particularly, in basins in-filled either with salt-bearing strata or withshales having abnormally high pore pressures and low formationtemperatures. The most favorable geochemical and lithological condi-tions for gas and oil generation are associated with young oil- and gas-bearing basins with very thick Cenozoic deposits. One of these basinsis the South Caspian Basin.



The South Caspian Basin and the adjacent land area of EasternAzerbaijan and Western Turkmenistan is characterized by: (1) anexceptionally high rate of sediment accumulation (up to 1.3 km/millionyears); (2) a very thick (up to 25 km) sedimentary cover, in general,and the Quaternary-Pliocene sediments (up to 10 km), in particular;(3) interbedded sands, silts, and shales; (4) abnormally high porepressure in shales (average abnormality factor = up to 1.8); (5) lowheat flow and low formation temperature (at depths of 6 km thetemperature is about 100–110°C); (6) an inverted hydrochemicalprofile (with depth, calcium chloride and magnesium chloride waterschange into sodium bicarbonate type of formation waters); and(7) extensive development of mud volcanism. Argillaceous rocks makeup from 50 to 95% of the section thickness and play a key role inthe formation of the lithologic, mineralogic, geochemical, and thermo-baric characteristics of the basin.

Petroleum potential of the super-deep deposits, the other factorsbeing equal, depends on two key factors: (1) sealing properties ofcaprocks, and (2) reservoir-rock properties.

As for the first factor, an important question is as follows: what isthe depth limit for hydrocarbon occurrence considering the sealingcapabilities of argillaceous rocks due to the preservation of mont-morillonite under given pressure and temperature? Khitarov andPugin (1966) estimated the occurrence depth for montmorilloniteunder various conditions. For example, when the geothermal gradientchanges from 40 to 10°C/km, the limiting depth of occurrence formontmorillonite changes from 3 to 16 km. Inasmuch as the averagegeothermal gradient in the Baku Archipelago is 16°C/km, the limitingdepth may be 8–9 km. On the basis of the data obtained by Khitarovand Pugin (1966), the writers suggested the following equation relatingthe depth of montmorillonite occurrence D in km to the geothermalgradient G in °C/km:

D = 261G –1.23

Stratigraphic sections with abnormally high pore pressures, however,may have even greater limiting depths. Inasmuch as there is a linearrelationship between pressure and depth, the limiting depth, Dlim, canbe determined as follows:

Dlim = 261KaG –1.23


where Ka is a dimensionless factor to account for the pore-pressureanomaly (abnormality factor, which is equal to the ratio of actual (orpredicted) pore pressure to the hydrostatic pressure).

Prediction of clay-mineral transformations in the South CaspianBasin at depths exceeding 6.5 km is of great importance. Data obtainedfrom extrapolation and from physical and mathematical simulation(Buryakovsky et al., 1982a) indicate that conditions at depths of 9 kmor more in the South Caspian Basin do not favor catagenesis ofargillaceous rocks. As shown by Buryakovsky et al. (1982a), theporosity of shales at depths of more than 9 km can be as high as 10%,which indicates the presence of abnormally high pore pressure. Usingthe equation above, at G = 16°C/km and Ka = 1.8, the limiting depthsare found to be 15–17 km in the center of basin. This indicates thatthe overpressured shales retain their sealing properties because ofcontinuing squeezing-out of pore water.

Usually, for estimating the potential reservoir quality in undrilledareas, one can use a statistical distribution of geological and petro-physical parameters of known deposits in the region. Estimation ofreservoir quality is often limited by insufficient information. Primarily,this refers to the South Caspian offshore fields with complexgeologic conditions for drilling deep exploratory wells using separateoffshore platforms. Productive formations occur at depths of 5–6 kmor deeper, and pore pressure and formation temperature exceed 70 MPaand 110–120°C, respectively. While drilling, there are problems withoverpressured formations, such as “kicks” and strong gas shows. Thisresults in limitation in core recovery, which, in turn, limits the knowl-edge of petrophysical properties (mainly porosity and permeability) ofreservoir rocks. The collected information on the reservoir-rock quality,both for the Apsheron oil- and gas-bearing region and for the SouthCaspian Sea areas, is used for estimating reserves.

Grain-size distribution in clastic rocks changes on moving awayfrom the source and further offshore. With progradation of ancientshoreline to the south and southeast of the Apsheron Peninsula, thereis a decrease in sand content and an increase in silt-clay content. Thischange in lithology affects the reservoir-rock properties (mainlyporosity and permeability) in more deeply buried anticlinal zones.Smaller grain size and better sediment sorting characterize the silty-clayey rocks in these zones. Thus, there is development of abnormallyhigh pore pressures due to underconsolidation (undercompaction) of


sediments in downwarped zones. This explains the relatively highporosity and permeability of rocks (Buryakovsky et al., 1991b).

The lithology of productive strata and pressure-temperature condi-tions has been taken into consideration for statistical correlations ofporosity, permeability and other reservoir properties of rocks in thenew deep offshore fields. Data on lithologic and reservoir-rock prop-erties have been evaluated using mathematical statistics (Griffiths,1971; Harbaugh and Bonham-Carter, 1974; Krumbein and Graybill,1969; Buryakovsky et al., 1982a, 1990b; Rodionov et al., 1987;Sharapov, 1965).

The following relationships were established:

1. Variation of porosity (φ, %) and permeability (k, mD) of sand-stones and siltstones with depth (D, km) up to 6 km have beenstudied. Porosity and permeability at depths ranging from 500to 6,000 m may be obtained using the following correlations:

Sandstones: φ = 25.5 – 2.0D; logk = 2.80 – 0.20DSiltstones: φ = 26.5 – 2.3D; logk = 2.40 – 0.16D

These mathematical models enabled prediction of porosity at adepth of 9 km: 8% for sandstones and 6% for siltstones. Perme-ability at a depth of 9 km was estimated to be 10 mD forsandstones and 8 mD for siltstones.

2. Regression models were established for porosity and permeabilityversus depth, taking into account clay cement content (Csh,%) andcarbonate cement content (Ccarb,%):

φ = 27.91 – 2.66D + 0.00007Csh2 – 0.483lnCcarb

k = 597.97 – 164.01D1/2 – 39.76Csh – 31.99Ccarb1/3

Coefficients of correlation are 0.92 and 0.78, whereas standarddeviations are 0.03 and 0.09, respectively. The equations areaccurate with a confidence level of 0.95, and degrees of freedomof 2 and 172, and 2 and 168, respectively.

The presence of abnormally high formation pressures and relativelylow temperatures suggests presence of hydrocarbons. Thus, the SouthCaspian Basin may have commercial accumulations of oil and gas atdepths of 9 km or even deeper.


II. TURKMENISTAN PORTION OF THESOUTH CASPIAN BASIN

The onshore Turkmenistan portion of the South Caspian Basinincludes the Cheleken Peninsula and coastal areas to the north and south.The offshore region includes the eastern portion of Apsheron–Pre-Balkhan anticlinal trend and the Chikishlyar-Okarem zone (Turkmenianstructural terrace) (see Figure 6-2). Oil seeps and dozens of mudvolcanoes are found in Turkmenistan (Figure 7-31). At least two giantfields have been found in the Turkmenistan portion of the SouthCaspian Basin: Cheleken and Kotur-Tepe (Figure 7-32). Many largestructures have been drilled onshore (Nebit-Dag, Kum-Dag, Kyzyl-Kum, Kara-Tepe, Boya-Dag, etc.) and offshore (Pre-Cheleken Dome,

Figure 7-31. Location map of prominent mud volcanoes in South CaspianBasin (Modified after Bredehoeft et al., 1988).


Fig

ure

7-3

2. O

il an

d ga

s fie

lds

of t

he S

outh

Cas

pian

Sea

are

a (M

odifi

ed a

fter

Oil

& G

as J

ourn

al,

Oct

ober

12,

198

1).


Zhdanov Bank, Gubkin Bank, LAM Bank, Livanov Bank, etc.) on therelatively broad continental shelf area in water less than 250 m deep.On the east, the shelf extends 175 km offshore. Part of the basin issituated in water depths of 500 to 1,000 m. The oil and gas historyof the area has been described by Alikhanov (1964, 1978), Maksimov(1987) and Meyerhoff (1982).

Geologic Structure

The Turkmenian portion of South Caspian Basin is bordered to theeast by the Kopet-Dagh foldbelt, whereas to the south it is borderedby the Elburz range in Iran. Rows of sub-parallel folds are presentthroughout the area (Figure 7-33). Some of the folds have shalediapirs, whereas others have active mud volcanoes. Two structuralstages have been identified in the South Caspian region. The first oneranges in age from the Mesozoic to Lower Neogene time and thesecond one from Upper Neogene through Quaternary (Neo-AlpineOrogeny). The structural trends of the two stages are similar. TheMesozoic to Lower Neogene trends are generally much broaderthan the younger ones. Due to continental collision and consequent“tectonic escape,” the trends of the fold axes change dramatically fromonshore to offshore in the Turkmenian portion of the South Caspianarea. Due to direct collision, the onshore trends are curvilinear andare concave to the southeast. Owing to generalized NNE-SSW com-pression, the offshore fold axes trend northwest (Figure 7-33).

Sediments in the South Caspian Basin are underlain by oceaniccrust. According to Berberian (1983), the oceanic crust is a Tethys Searemnant which was not subducted during the Alpine-Himalayan oro-genies. Ulmishek and Klemme (1990) suggested that the ocean crustmay have formed during the Middle Cretaceous time associated withrifting. The writers do not agree with these views, because the analysesof these authors do not take into account the regional evolution of theCaucasus, the type of volcanism present through geologic time (partic-ularly the Mesozoic), the closing of Paleo-Tethys, and the opening ofthe Neo-Tethys Ocean when the “Kimmerian Archipelago” was collid-ing with Eurasia in Late Triassic-Middle Jurassic time. The writers,however, agree with the thorough and consistent analyses of Adamia(1982) and Zonenshain et al. (1986), in which the South Caspian Basinopened as a back-arc-type basin.


Fig

ure

7-3

3. L

ate

Alp

ine

(Lat

e P

lioce

ne)

fold

axe

s in

the

Sou

th C

aspi

an B

asin

.


Regional Stratigraphy

The deposits found in the Turkmenian side of the South CaspianBasin are composed mostly of Mesozoic and Cenozoic sediments.

The Lower-Middle Jurassic deposits consist mainly of sandstonesinterlayered with shales, some gypsum, and coal. Onshore, these rocksreach a maximum thickness of 4,000 m. The Upper Jurassic to Neocomiandeposits are up to 3,000 m in thickness and consist of limestones withterrigenous interlayers at the base and at the top of the section. Theserocks may be potential reservoir rocks; however, their depth of burialmay be excessive for preservation of porosity and good reservoirquality. The Aptian to Cenomanian complex (up to 3,000 m in thick-ness) is made up of a lower unit consisting of siltstones and shaleswhich are dark gray, micaceous, and, locally, calcareous. The upperpart consists of mainly shales and some sandstones. The shales aredark gray to gray in color, locally silty, and are calcareous in the lowerpart. The sandstones are light gray in color and fine-grained. The abun-dance of shale in the section may indicate that this unit may be a goodcaprock as well as source rock if degree of maturation was sufficient.

The Turonian to Paleogene interval is approximately 2,000-m thickand consists of interbedded limestones, shales, and marls. Minorreservoir rocks occur in this section, which is mainly a caprock.

Miocene rocks unconformably overlie the Paleogene rocks. Thesestrata are approximately 1,000-m thick. The interval consists of shaleswith minor limestones, marls, and sandstones in the upper part,whereas shales and some sandstones constitute the lower part.

The Lower Pliocene is about 500-m thick and consists of gray-green,olive-colored clays with some siltstones. This unit is unconformablyoverlain by Middle Pliocene strata.

The South Caspian Basin underwent rapid and continual subsidencethrough Middle and Late Pliocene time. It was filled with deltaicsediments of large rivers flowing from the north, east, and west. Thecomplex of deltaic sands and clays is called the Productive Series inAzerbaijan, and the Red-Bed Series in Turkmenistan. Lithology of theRed-Bed Series is shown in Figure 7-34. The Middle Pliocene issubdivided into the Lower and Upper Red-Bed Series. The Lower Red-Bed Series consists of gray, fine-grained, micaceous sandstones,interbedded with brown to gray siltstones and shales. The UpperRed-Bed Series are composed of fine-grained sands and sandstones


interbedded with dark gray to gray shales. The total thickness of theRed-Bed Series is about 3,000 m.

Upper Pliocene rocks unconformably overlie Middle Pliocene deposits.The Upper Pliocene deposits consist of two stages: the Akchagylianand the Apsheronian. The Akchagylian Stage consists of light gray togray siltstones, silts, and clays, whereas the Apsheronian Stage consistsof light gray to gray, plastic, poorly laminated clays, with subordinatecontents of gray, fine-grained sandstones and siltstones. The UpperPliocene deposits are up to 2,500 m in thickness.

Figure 7-34. Lithofacies and thickness map of Red-Bed Series (Modified afterAliyev, 1988). 1—Coarse-grained sands and loams, 2—predominantly sandsand siltstones with thin interbeds of shale, 3—interbedded sand-siltstoneand shale, 4—predominantly shale interbedded with sands and siltstones.Isopachs are in meters.


Fine-grained sandstones, siltstones and clays constitute the Quaternaryrocks. This section is up to 1,500 m in thickness. Pliocene throughQuaternary deposits may attain a thickness of up to 7,500 m on theTurkmenian shelf.

Source Rocks

Good quality, mature source rocks are present in Turkmenistan, butare poorly studied because of the great depth of burial. The mainsource rocks for oil and gas in the Pliocene reservoirs, which arelocated in the Cheleken Peninsula, other coastal areas, and offshore,are probably of the Upper Miocene to Lower Pliocene age, as postu-lated for the Azerbaijan offshore portion of the South Caspian Basin.Middle Miocene shales (Sarmatian age) are postulated to be the sourcerocks for oil and gas present in the Upper Miocene reservoir rocks.Oil and gas plays found onshore (but not in the coastal areas) in theOligocene-Lower Miocene reservoirs were probably generated in theOligocene-Miocene Maykop Series. The latter consists of bituminousclaystones (mudstones) rich in fish fossils. The organic matter in thesemudstones are sapropelic (TOC content ranges from 1.3 to 3.5%).Meyerhoff (1982) suggested that the main source rocks in the SouthCaspian Basin are the Middle Pliocene shales in the Productive Series.The writers believe that the source rocks are of Upper Miocene-LowerPliocene age. The potential source rocks are immature to a depth of4026 m, because of the low geothermal gradient of the basin (16oC/km). Temperatures at a depth of 6 km do not exceed 100oC (Samedovand Buryakovsky, 1966; Bredehoeft et al., 1988).

As most of the prospective oil and gas deposits in the South CaspianBasin are of Upper Neogene age and the local structures were formedonly recently (Middle-Late Pliocene), the oil and gas began to migrateinto the traps in the Late Pliocene time. Nearly 80% of all hydrocarbonsprobably migrated by the end of the Pliocene in the deep deposits of SouthCaspian Basin. Along the Turkmenian shelf and in other areas of the basinmargins, oil and gas migrated slightly later than on the Azerbaijan side,i.e., during the Late Pliocene to Middle Pleistocene. Due to Quaternarytectonic movements, some secondary oil and gas migration from thedeeper oil pools to the shallower ones continues to this day.

Migration of hydrocarbons in the South Caspian Basin is related toabnormally high formation pressures present throughout the basin.


Such pressures are caused by the rapid deposition of thick sand/shalesequences. Some sandstone beds and faults act as avenues for thepressurized fluid migration. Fluids (water, oil, and gas) migrate fromareas of high pressure to areas of lower pressure. This process,however, can also lead to the loss of hydrocarbons (as in the case ofmud volcanoes).

The geochemical studies recently carried out on some oils from thePre-Cheleken Dome and Zhdanov fields (offshore Turkmenistan) havesupplied evidence that mature (≈0.70 Ro eq.) source shales of theUppermost Miocene-Lowermost Pliocene age are present on the northernside of the Apsheron–Pre-Balkhan ridge (Kelkor Trough). If this istrue, then all the offshore structures on the Turkmenian side of theApsheron Threshold will contain hydrocarbons migrating up-dip fromtwo different troughs, of which the northern one would be the mostimportant. This interpretation would explain why the northern flanksof the structures in the Turkmenian sector are hydrocarbon-bearing,whereas the southern flanks of traps are either devoid of hydrocarbonsor contain less oil and gas.

Reservoir Rocks

Clastic and carbonate reservoir rocks exist in the Mesozoic-Cenozoicsection, but large-scale commercial production has not yet beenobtained from the Mesozoic interval. Jurassic limestones and sand-stones could also act as reservoir rocks along the basin margins.Cretaceous carbonates (fractured, karsted, reefs) also constitute poten-tial reservoirs; they also are likely to be limited to the shallow basinmargins. Oil seeps from Mesozoic rocks have been found in areas ofbasin margins.

In the Turkmenistan portion of South Caspian Basin, the bestpotential reservoir rocks are the Upper Neogene sandstones andsiltstones. Middle Pliocene sandstones and siltstones of the Red-BedSeries are the key reservoir rocks in such oil fields as the Pre-ChelekenDome, Zhdanov Bank, Gubkin Bank, LAM Bank, and Livanov Bank(Table 7-28). Similar silisiclastic reservoir rocks exist in the ProductiveSeries of the Azerbaijan portion of South Caspian Basin and have beendescribed in detail (Buryakovsky, 1985). According to Mekhtiyev(1977), oil can exist above a depth of 3,500 m, whereas condensatecan be found down to depths of 5,000 to 7,000 m.


Tab

le 7

-28

Rel

atio

nsh

ip b

etw

een

Lit

ho

log

ical

an

d M

iner

alo

gic

al C

om

po

siti

on

(in

%)

of

the

Red

-Bed

Ser

ies

Ro

cks

of

Ch

elek

en-L

ivan

ov

An

ticl

inal

Tre

nd

Qua

rtz

Fel

dspa

rR

ock

Fra

gmen

tsA

vera

ge V

alue

s

Ro

ckA

vera

ge

Lith

olo

gy

Gu

bki

nL

AM

Zh

da

no

vG

ub

kin

LA

MZ

hd

an

ov

Gu

bki

nL

AM

Zh

da

no

vQ

ua

rtz

Fe

ldsp

ar

Fra

gm

en

tsb

y R

ock

s

San

d—

54.3

74.0

—20

.710

.0—

25.0

16.0

59.0

18.0

23.0

3.5

Sil

t22

.847

.428

.314

.218

.417

.216

3.0

34.2

54.5

40.0

17.5

42.5

43.8

Loa

m—

42.0

37.7

—32

.012

.610

0.0

26.0

49.8

34.7

13.2

52.1

9.2

Sha

le17

.422

.912

.117

.819

.718

.518

5.0

67.3

79.4

13.5

18.0

68.5

49.5

Ave

rage

16.0

41.4

20.2

11.0

16.5

10.4

173.

042

.169

.428

.517

.554

.010

0.0

by f

ield

s


Traps and Seals

Most of the traps in the South Caspian Basin are structural. Numer-ous anticlines and shale diapir structures are present in the Turkmenianpart of the basin. The diapirs are typically distinguished by negativegravity and low heat anomalies (Grachevskiy, 1982). The diapirspenetrate the overlying rocks and cause the mud volcanoes to form, whichusually result in some loss of hydrocarbons. On the other hand, moregentle diapiric activity results in the formation of localized structuraltraps. Many diapir-caused structures have not been drilled in theTurkmenian part of South Caspian Basin. Diapiric structures and asso-ciated faults decrease in number and magnitude toward the basin center.

Many anticlinal traps formed as a result of the Late Alpine tectonicactivity during the Late Middle Pliocene time (Figure 7-35) (Narimanov,1986). Folds in the Azerbaijan portion of the South Caspian Basin areshallow and of low amplitude, whereas folds along the Turkmenianshelf are drape folds with deep-seated cores (Lebedev, 1978). The topof the Middle Pliocene deposits in most structures along the basinmargins occurs at a depth of 1,000 to 1,200 m. In the deep parts of thebasin, however, this depth increases to 6,000–7,000 m (Mekhtiev, 1977).

Fault traps also exist in the Turkmenian part of the South CaspianBasin. Basement faults, which penetrate Mesozoic strata, could formtraps. Faults in younger strata, formed as a result of the Late Alpinetectonic activity, are more common and could also cause the entrap-ment of hydrocarbons at shallower depths (secondary oil and gasmigration). Growth faults with associated traps probably are alsopresent. Other possible traps include: (1) lenticular sandstone bodies,(2) pinch-outs, (3) turbidite deposits, (4) reefs, (5) fractured andkarsted carbonate rocks, and (6) stratigraphic traps in the carbonatesat the basin margins onshore. Such traps are possible in both theMesozoic and Cenozoic deposits.

Caprock potential can be considered fair to poor in the SouthCaspian Basin. There are no thick evaporite or shale sections to actas regional seals for the hydrocarbons of Jurassic or Neogene origin.

The abundance of mud volcanoes caused by diapirism, faulting, andrecent tectonic activity indicate the absence of shallow seals. Theabsence of regional seals in the South Caspian Basin downgrades itspotential. Local seals do exist, however, and are responsible for trappingsignificant oil and gas reserves in the Azerbaijan and Turkmenistanportions of the South Caspian Basin.


Fig

ure

7-3

5. L

ocal

str

uctu

res

of t

he S

outh

Cas

pian

Bas

in.


Oil and Gas Potential

The oil and gas potential of the area has been summarized byAlikhanov (1964, 1978), Maksimov (1987) and Meyerhoff (1982).

The presence of seeps and mud volcanoes first attracted attentionto the area of Cheleken Peninsula and adjacent offshore areas at anearly date. The Cheleken structure is 15 km wide and 45 km long.Wells were drilled at Cheleken to depths of 160 to 170 m in the UpperPliocene sandstones, from 1907 to 1912. From 1948 through 1957,the field was extended east and west. Three structures were drilled[Zapadno (West) Cheleken (in 1950), Dagadzhik (in 1955), and Aligul(in 1957)] to the Middle Pliocene zones at depths of 958 to 962 mand 2,100 to 2,500 m. Deeper Miocene production was establishedlater. To date, approximately 28 fields have been found in WesternTurkmenistan, four offshore and 24 onshore (see Figure 7-32). Produc-tion is primarily from Pliocene deposits (depths of 350 to 4,600 m).The exploration effort resulted in the discovery of two giant fields:Cheleken and Kotur-Tepe. The Cheleken Field has estimated 640million bbl of recoverable oil reserves and 1 TCF of gas, which wasmostly flared. The Cheleken Field produced 9,500 Bopd in 1988.

The Kotur-Tepe Field is located on the continuation of the Apsheron–Pre-Balkhan anticlinal trend on the Cheleken Peninsula (Figure 7-36).The Upper and Lower Red-Bed Series, Akchagylian and Apsheroniandeposits are the main producing zones. The reservoir rocks are sand-stones and siltstones. At least, seventeen units are productive in theeastern part of the field. Porosity ranges from 18% to 29% andpermeability varies from 40 to 1,600 mD. The Kotur-Tepe Field hasestimated ultimate recovery of 4 Bbbl of oil and 2.1 Tcf of gas.

The oils from the Upper Neogene reservoirs are paraffinic-naph-thenic in composition (Danchenko et al., 1982). They have low densityand low resin content.

Future Exploration Potential

In the Former Soviet Union, the South Caspian Basin has been thefocus of extensive exploration efforts after the Western Siberia Basin.There are six or seven jack-up rigs, four semi-submersible rigs, andtwo new Finnish drilling ships operating offshore. Geologists haveclaimed that over 200 structures exist in this region, most of whichhave not yet been drilled (see Figure 7-35). The Apsheron Threshold


Fig

ure

7-3

6. K

otur

-Tep

e O

il an

d G

as C

onde

nsat

e F

ield

(T

urkm

enne

ft d

ata)

(M

odifi

ed a

fter

Mak

sim

ov,

1987

). a

—S

truc

tura

lm

ap a

t th

e to

p of

Red

-Bed

Ser

ies,

b a

nd c

—ge

olog

ic c

ross

-sec

tions

, rig

ht c

olum

n—se

ctio

n of

pro

duct

ive

port

ion

of d

epos

its.

1—

Fa

ult

s, 2

—zo

ne

of

bu

rie

d m

ud

co

ne

s, 3

an

d 4

—o

ute

r co

nto

urs

of

Str

atu

m I

II o

il p

rese

nce

an

d g

as

pre

sen

ce,

resp

ectiv

ely.


still has a number of undrilled structures that could easily contain largequantities of oil and gas. Many structures are located in the center ofthe basin and probably contain only condensate and gas, due to depthof the source rocks and reservoir rocks.

Other potential targets include deeper Triassic deposits. Reefs havebeen targeted in many areas, including the LAM Bank (east shelf) andGryaznyy Vulkan (south) at the basin margins. Most exploration wellsare projected to be drilled to a depth of 6,500 m.

Out of 50 structures drilled, only two were found to be unpro-ductive. Meyerhoff (1982) has estimated the resources of 10 Bbbl and2 Tcf gas in the Apsheron and Cheleken regions alone. The writersbelieve that these figures should be at least doubled. The basin willalso yield more gas from its deeper offshore portion. Fewer reservoirrocks, however, are probably present in the deeper portion of the basin.

III. REGIONS ADJACENT TO THESOUTH CASPIAN BASIN

Amu-Darya Basin

Amu-Darya province is located in the central and eastern parts ofTurkmenistan and western part of Uzbekistan. It covers 360,000 km2

(138,800 mi2) (Figure 7-37). The province extends into Afghanistanfor an additional area of approximately 45,000 km2 (17,350 mi2).

Petroleum exploration in the Amu-Darya area started in 1929 (Clarke,1988; Maksimov, 1987; Meyerhoff, 1982), whereas the first structuralboreholes were drilled in 1936. The first commercial field (SetalantepeField) found in this area in 1953 is located in the Uzbekistan portionof the Amu-Darya Basin. The first discovery in the Turkmenistanportion of the basin (Darvaza Field) was in 1956. Since then, morethan 48 fields have been discovered. Dauletabad-Donmes Field is thelargest field discovered in the Turkmenistan. The estimated recoverablereserves are 60 Tcf of gas.

Geologic Structure

The structure of the Amu-Darya Basin is presented in Figures 7-38,7-39, and 7-40. The main structural elements are the Karakum Uplift,Kopet-Dagh Foredeep, Bukhara Step, Charjou Step, Zaunguz Low,



Fig

ure

7-3

7. O

il an

d ga

s fie

lds

of t

he A

mu-

Dar

ya B

asin

(M

odifi

ed a

fter

Mak

sim

ov,

1987

).


Fig

ure

7-3

8. J

uras

sic

stru

ctur

e of

Am

u-D

arya

Bas

in (

Mod

ified

aft

er O

’Con

nor

and

Son

nenb

erg,

199

1).

A—

Kar

akum

Upl

ift,

B—

Kop

et-D

ag F

ored

eep,

C—

Buk

hara

Ste

p, D

—C

harj

ou S

tep,

E—

Bes

hken

t Lo

w,

F—

Zau

nguz

Low

, G

—M

alay

Hig

h, H

—K

arab

ekau

l Lo

w,

I—M

ary-

Ser

akh

Hig

h, J

—M

urga

b Lo

w,

K—

Bad

khyz

-Kar

abil

Ste

p.


Fig

ure

7-3

9. N

orth

-sou

th c

ross

-sec

tion

of A

mu-

Dar

ya B

asin

. Lo

catio

n of

cro

ss-s

ectio

n on

Fig

ure

7-38

(M

odifi

ed a

fter

O’C

onno

r an

d S

onne

nber

g, 1

991)

.


Fig

ure

7-4

0. E

ast-

wes

t cr

oss-

sect

ion

of A

mu-

Dar

ya B

asin

. Lo

catio

n of

cro

ss-s

ectio

n on

Fig

ure

7-38

(M

odifi

ed a

fter

O’C

onno

r an

d S

onne

nber

g, 1

991)

.


Malay High, Beshkent Low, Karabekaul Low, Murgab Depression,Mary-Serakh High, and the Badkhyz-Karabil Step (O’Connor andSonnenberg, 1991; Clarke, 1988).

Basement consists of slightly metamorphosed folded Paleozoicrocks, deformed as a result of the Hercynian Orogeny. The depth tothe basement is 1.5 to 3 km at the Karakum arch, 12 to 15 km at theKopet-Dagh foredeep, more than 4 km in the Zaunguz low, approxi-mately 4 km at the Malay-Bagadzha high, 5 to 6 km at the Karabekaullow, 4 to 5 km at the Beshkent low, 1 to 2 km at the Bukhara step,2.8 to 4 km at the Charjou step, and 10 to 12 km in parts of theMurgab depression (Clarke, 1988).

The Amu-Darya Basin is classified as a supra-rift syneclise (Khainet al., 1991). According to St. John et al. (1984), the basin can alsobe classified as a peri-sutural foredeep basin dominated by blockfaulting using the Bally and Snedon classification, and as a closed,crustal collision zone, continental multi-cycle basin using the Klemmebasin scheme.

Structural development of the basin started in the Permian time,possibly at the end of Carboniferous, when a major north-south riftsystem developed across the region (Figure 7-41) (Khain et al., 1991).

Regional Stratigraphy

Regional stratigraphy is presented in Figures 7-39, 7-40, and 7-42.The Permo-Triassic interval consists of coarse-grained red beds (typicalmolasse) and volcanics. These units represent the initial basin fill andare thickest in the paleo-rift areas (East Zaunguz and Tedzhen-Murgab)(Figure 7-41). These deposits experienced folding (Kimmerian Orogeny)in the Late Triassic time (Aksenov et al., 1985; Clarke, 1988).

During the Jurassic time, the Amu-Darya region became a linear sagthat trended more east-west than the previous rift (Ulmishek andKlemme, 1990). The Lower Jurassic rocks, which unconformablyoverly the Triassic rocks, consist of clastic continental deposits. Theoverlying Middle Jurassic rocks consist of marine clastics and carbon-ates. The Lower-Middle Jurassic deposits range in thickness from lessthan 200 m on the Karakum high to 400 m on the Charjou step, to1,000 m in the Murgab depression. The Upper Jurassic rocks are repre-sented by the Callovian, Oxfordian, Kimmeridgian, and Tithonian series.



Figure 7-41. Aral-Murgab rift system (Modified after Khain et al., 1991).


Figure 7-42. Stratigraphic column of Central Amu-Darya Basin (Modified afterO’Connor and Sonnenberg, 1991).

The Callovian-Oxfordian deposits consist predominantly of carbon-ates, which constitute the main reservoir rocks. Total thickness ofCallovian-Oxfordian limestones (with some reefs) reaches 500 to 600 m.These carbonates are overlain by Kimmeridgian-Tithonian evaporitesof the Gaurdak Formation, which form the main (regional) seal forthe Callovian-Oxfordian reservoirs. The evaporate basin covers an areaof 300,000 km2 (see Figure 7-38). The evaporites consist of anhydriteand salt. The Kimmeridgian-Tithonian evaporites, up to 650 m thick,are overlain by Upper Tithonian Red-Beds. The Upper Jurassic (Callovian-Tithonian) rocks range in thickness from 1,500 m in the southeast toless than 100 m in the northwest (Karakum High).

The Lower Cretaceous is generally placed stratigraphically at thetransition from continental red-beds of Upper Jurassic age to marinedeposits. The Lower Cretaceous rocks are up to 1,200 m thick, andare represented by the following stages: Berriasian, Valanginian,


Hauterivian, Barremian, Aptian, and Albian. These units consist ofclastic and carbonate rocks of marine as well as continental origin.

The Berriasian-Valanginian rocks range in thickness from 105 to 155m, and consist of silty, clayey, detrital, carboniferous, and dolomiticlimestones. The Hauterivian deposits consist of lower red-bed unit(siltstones and sandstones) and upper unit (siltstones, shales, lime-stones, marls, dolomites, and gypsum). The lower unit is up to 140m in thickness, whereas the upper unit is up to 70-m thick. Theoverlying Barremian deposits, which consist of oolitic limestones,clayey limestones, marls, gray shales, and dark shales, are about 163to 180 m in thickness. Aptian age oolitic and silty limestones, marls,and shales conformably overlie the Barremian. The unit is 70 to 100-m thick. The Albian deposits are up to 580-m thick and consist of darkgray shale, siltstone, and limestone.

Upper Cretaceous rocks lie unconformably on Lower Cretaceousdeposits. The Cenomanian rocks consist of gray sandstones, whichrange in thickness from 170 to 300 m. The Turonian rocks are up to247 m in thickness and consist of gray shale in the lower part andsandstone in the upper part. The Conacian deposits, which consistof sandy-clayey rocks and limestones, range in thickness from 20to 164 m. The overlying Santonian deposits consist of shales, silt-stones, sandstones, and limestones, and are 95 to 260 m thick. TheMaastrichtian deposits consist of a lower sandstone unit and an uppercarbonate unit. They range in thickness from 10 to 34 m. The UpperCretaceous section is 1,300 to 1,500 m in thickness on the Mary Highto Beshkent Low areas and thins to less than 400 m on the Karakum High.

Paleogene deposits (Paleocene, Eocene, and Oligocene) consist oflimestone, dolomite, gypsum, and shale; they range in thickness from240 to over 500 m. The Neogene rocks are widely distributed across thebasin, and consist of continental clay/sand formations that range in thick-ness from 100 to 1,500 m. Quaternary and Holocene deposits consistof fluvial and eolian clastic rocks that are less than 100-m thick.

Source Rocks

At least three major source rocks are recognized in the Mesozoicsection of the Amu-Darya Basin (Chetverikova et al., 1982; Kingston,1990; Ulmishek and Klemme, 1990; Maksimov et al., 1987):(1) Lower-Middle Jurassic, (2) Oxfordian-Kimmeridgian, and (3)Lower Cretaceous Aptian-Albian shales.


The organic matter in the Lower-Middle Jurassic shales is largelyhumic, with some lacustrine algal organic matter being present, partic-ularly in the Middle Jurassic strata (Aksenov et al., 1985). The organiccarbon content can be as high as 4.35%. Ulmishek and Klemme (1990)stated that the major source rocks for gas, gas-condensate, and oil isthe Upper Oxfordian-Kimmeridgian black bituminous shales of theKhodzhaipak Formation, which underlie the thick Kimmeridgian-Tithonian evaporites in the basin. This source rock potential is partic-ularly pronounced in the eastern portion of the basin (Figure 7-43).Condensate accumulations are particularly abundant in the areas wherethis source rock is highly mature. Oil accumulations are also mainlyderived from this source rocks.

The Aptian-Albian marine shales (Type II kerogen) may also haveacted as source rocks, although their importance is not well docu-mented by the oil-source rock correlation data. These younger sourcerocks contain 1.1 to 1.3% TOC (Kingston, 1990).

Petroleum migrated into Upper Jurassic reefs sealed by salt, and intothe Lower Cretaceous sandstone reservoirs in the areas where theregional salt seal pinches out. The time of maturation of source rockswas the Late Tertiary (Ulmishek and Klemme, 1990). Source rocksin the deeper parts of the basin may have matured earlier. The deepersource rocks (Jurassic) in this province entered the oil window duringthe Early Cretaceous and now reside in the gas window (Aksenov etal., 1985). Early formed traps may have been site of oil accumulation;however, the liquid hydrocarbons trapped in many of them havesubsequently been cracked to gas (Kingston, 1990). The gas-pronenature of the Amu-Darya province is due in large part to the highmaturity of the Jurassic source rock complex. The maturity values,however, are highly variable in this large basin, and the opportunityof finding oil is high only in the marginal parts of the basin (e.g., theAmu-Darya portion of Uzbekistan).

Reservoir Rocks

Five reservoir rocks are recognized in the Amu-Darya gas- andoil-bearing province (Clarke, 1980; Khodzhakuliev et al., 1985):(1) Lower and Middle Jurassic clastics, (2) Upper Jurassic carbonates,(3) Lower Cretaceous clastics, (4) Albian-Cenomanian sandstones, and(5) Paleogene Bukhara carbonates. The main reservoirs are UpperJurassic carbonates and Lower Cretaceous clastics. The Lower-Middle


Fig

ure

7-4

3. U

pp

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en

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co

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(Mod

ified

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199

1).


Jurassic rocks consist of shales, siltstones, and sandstones. The thicknessof these reservoir rocks ranges from 100 to 400 m. Gas has been foundin structural traps in the Beurdeshik, Naip, Sakar, and Gugurtly fields.Porosity ranges from 7% to 14.3% (Maksimov, 1987). Structuresassociated with these reservoir rocks grow in size with depth. Theshallower zones have already been tested in many cases (Clarke,1988). Gas in these reservoir rocks has been found mainly in thenorthwestern portion of the basin.

The Upper Jurassic carbonate reservoirs exist throughout the prov-ince. The carbonate section is Callovian-Oxfordian in age and is upto 500 m in thickness. Carbonates represent the main reservoirs in thebasin (Clarke, 1988). Reefal (organogenic), organoclastic, oolitic, andalgal facies are common in the Callovian-Oxfordian section (Belyakova,1982; Clarke, 1988; Radyushkina and Smakhtina, 1982). Conditionsfavorable for the reef growth existed in Turkmenistan during the LateOxfordian time (Amanniyazov et al., 1979). Study of the reefs in theUzbekistan part of the Amu-Darya Basin suggests that they are diverselyoriented, linear and/or solitary, and developed on the paleo-geomorphichighs (Ryzhkov et al., 1983; Livshits, 1982). Both limestones anddolomites form the reservoir rocks (Khodzhakuliev et al., 1985). Sixtypes of porosity are recognized: (1) intergranular, (2) cavernous-intergranular, (3) fracture-intergranular, (4) fracture-cavernous-intergranular, (5) fracture-cavernous, and (6) fracture (Gordon, 1982).In some cases dolomitization gave rise to porosity.

The Lower Cretaceous clastics are subdivided into two units: Neo-comian and Albian. The Neocomian rocks, which range in thicknessfrom 200 to 400 m, consist largely of carbonates in parts of theZaunguz and Murgab lows. The Shatlyk Formation, which containsthe main gas reserves of the southeastern Turkmenistan, is productivein several of the large fields, including Dauletabad-Donmez andShatlyk in the southern part of the basin. The Shatlyk Formation isdescribed as a fine- to medium-grained reddish brown sandstone, withthin beds of argillaceous siltstone.

The Albian-Cenomanian reservoirs (sandstones and siltstones) aregas-bearing in the northwestern part of the Turkmenian portionof Amu-Darya province. Paleogene reservoirs are carbonate rocks(Kingston, 1990), which are productive in the Karabil Field, locatedin the southern part of the province.


Traps and Seals

The vast majority of traps in the Turkmenian part of Amu-Darya prov-ince are classified as structural (sheet-type arched or massive sheet-typearched) (Maksimov, 1987). One notable exception is the Dauletabad-Donmez Field, which has a hydrodynamic trapping component.

Two generations of structural traps are present (Kingston, 1990), andthe earliest was the one formed during the Jurassic time, consistingof low-amplitude drapes or fault traps. The amount of closure of theold structures decreases upwards from a maximum in the Jurassic rocksto a minimum in the Lower Tertiary rocks. The younger traps formedduring the Alpine orogeny, which was caused by the collision ofArabia and India with Eurasia, that occurred during the Early Neogeneto Quaternary times. Many traps reached their present shape in the MiddlePliocene time (Mal’tsev, 1983; Solov’yev, 1982; Sokolov et al., 1979;Yaneva and Mamedov, 1982). Some of the pre-existing traps also experi-enced further structural modifications during this time period.

The Kimmeridgian-Tithonian evaporites (Figures 7-38 and 7-42)constitute the main caprock in the province. This caprock separatesthe stratigraphic column into two main parts (pre-salt and post-salt).The Upper Jurassic carbonates are prospective where the salt caprockis present. In the absence of a salt caprock, which occurs towards theflanks of the basin, hydrocarbons migrated into the overlying LowerCretaceous reservoir rocks. The Upper Jurassic reservoirs are generallyoverpressured in areas where the salt caprock is present.

Cretaceous and Tertiary shales form caprocks for the Cretaceous andPaleogene reservoirs. The caprocks for the Lower Cretaceous reser-voirs are Late Aptian and Albian claystones, whereas caprocks ofAlbian-Cenomanian reservoirs are claystones of Turonian age. Thecaprocks for the Paleogene carbonates are the Upper Paleocene andLower Eocene claystones.


The Amu-Darya Basin is gas-prone, and oil production occurs onlyin the northeastern part of Turkmenistan. Total production through thebeginning of 1981 was 35 Tcf of gas. Gas production in this basinwas 3.6 Tcf in 1990. To date, production has been mainly from theCretaceous sandstones. Future production probably will be obtainedfrom the Upper Jurassic pre-salt carbonates. There are, at least, 48 fieldsin the Turkmenian portion of the Amu-Darya Basin (see Figure 7-37).


The Dauletabad-Donmez Field is located in the southern part of theAmu-Darya province along the border with Iran (Figure 7-44). Thefield was discovered in 1974 and produced from the Lower CretaceousHauterivian, Shatlyk sandstone. Major north-south trending faults arepresent on the east and west sides of the field. In addition, east-westtrending high-angle normal faults are present in the central part of thefield. The field is broken into southern, central, and northern faultblocks. The overall structure of the field is monoclinal: the southernblock is located on Dauletabad Arch, whereas the northern block issituated on the Donmez Nose. The structural elevation of the producing

Figure 7-44. Structural map of Dauletabad-Donmez Gas Field on the topof the Lower Cretaceous Shatlyk Formation (Modified after Maksimov et al.,1987 and Clarke and Kleschev, 1990).


zone is 2,400 m in the south and 3,450 m in the north. The ShatlykFormation consists of fine- to medium-grained sandstone. The sand-stone thins toward the south and becomes conglomeratic. Thicknessof the reservoir ranges from 10 to 17 m; porosity ranges from 18%to 21%; and permeability varies from 200 to 700 mD. The field islocated where the regional Kimmeridgian-Tithonian evaporite caprockspinch out (Figure 7-45). This occurs in the vicinity of the DonmezNose. The origin of gas appears to be from both Jurassic and Cretaceoussource rocks. The trap appears to be a combination of structural,stratigraphical, and hydrodynamic. Gas reserves of the Dauletabad-Donmez Field, the largest gas field in Central Asia, are 60 Tcf.

Figure 7-45. South to north profile along line I—I′ of Figure 7-44 (Modifiedafter Maksimov et al., 1987 and Clarke, 1990).


The Shatlyk Field, which is located 80 miles northwest of Dauletabad-Donmez Field (Figure 7-46), produces from two brachyanticlines.Exploratory drilling began in 1967 and the field was discovered in1968; field development began in 1973. The structural relief is 232m, whereas the gas column is 227 m high. Depth to the ShatlykFormation is approximately 3,219 m. Thickness of the producing zoneis 47 m. Porosity averages 21%, whereas permeability is around 210mD. Cumulative production from the field through January 1, 1980,was 5.5 Tcf gas. Gas reserves as of January 1, 1980, were estimatedat 28.9 Tcf (Clarke, 1988). Shatlyk Field reached full productioncapacity in 1977 when it produced 1.2 Tcf gas (Shabad, 1986).

The Kokdumalak Field is located along the Turkmenistan-Uzbekistanborder (Figures 7-47 and 7-48) in the Charjou gas-oil area. The fieldwas discovered in 1985 and brought into commercial production in1989 (Sagers, 1991). The field is one of the largest discovered inUzbekistan or Turkmenistan. Reserves are estimated at 700 million bblof oil and 5.8 Tcf gas (Sagers, 1991; O’Connor and Sonnenberg,1991). Kokdumalak Field is a bioherm (Figure 7-48). The height ofthe trap is approximately 250 m, whereas the height of the pool isapproximately 240 m. The field has an oil ring 30 to 40 m in thick-ness. The reef is Oxfordian in age and is overlain by Kimmeridgian-Tithonian evaporites. This field illustrates the potential for futurediscoveries of reef traps in the Turkmenistan.

Gases from pre-salt Upper Jurassic deposits contain up to 6% H2Sand are overpressured. Natural gas produced in the Amu-Darya Basincontains 52.45 to 98.96% of methane; ethane content ranging from 0to 7.98%. The propane content ranges from 0 to 3.8%; butane contentranges from 0 to 1.63%; and the content of pentane and heavierhydrocarbons ranges from 0 to 1.98%. Nitrogen and rare gases contentranges from 0 to 47.3%. Carbon dioxide content ranges from 0.1 to10.7%, and hydrogen sulfide content from 0 to 6.4% (Maksimov, 1987).

Many of the gas pools also produce condensate, with density rangingfrom 0.728 to 0.844 g/cm3. The content of n-paraffin hydrocarbonsranges from 2.5 to 91%; naphthenic hydrocarbons content ranges from5.0 to 92.5%; and the content of aromatic hydrocarbons varies from1.0 to 73.2%.

Isolated oil pools are also present in the Jurassic and Lower Cretaceousreservoirs. The density of oil ranges from 0.856 to 0.970 g/cm3. The



Figure 7-46. Shatlyk Gas-Condensate Field. (a) Structural map, (b) Cross-section, (c) Section of pay zone (c1—Valanginian, c2—Hauterivian, c3—Barremian) (Modified after Clarke, 1988, and Shabad, 1986).


Fig

ure

7-4

7. C

harj

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rea

(Mod

ified

aft

er O

’Con

nor

and

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erg,

199

1).


Figure 7-48. Kokdumalak field example (Modified after O’Connor andSonnenberg, 1991).

sulfur content of the oils varies from 0.28 to 2.81%. The oils havehigh contents of resins (10.0 to 26.4%) and low contents of asphaltenes(0.7 to 5.3%).


Clarke (1988) summarized the future exploration potential of theTurkmenistan portion of the Amu-Darya province as follows:

1. Exploration for pre-salt Upper Jurassic carbonates. O’Connor andSonnenberg (1991) suggested that reefs are present over largeareas in the southern part of the province.

2. Exploration for the structural traps in Cretaceous and Jurassicdeposits at the province margins.

3. Exploration for structural traps in the Lower and Middle Jurassicclastics.



4. Evaluation of the oil and gas potential of the Kopet-Dagh foredeep.5. Exploration for the stratigraphic traps in areas where Cretaceous and

Jurassic deposits pinch out in the Badkhyz-Karabil anticlinal trend.

The greatest potential is in the Jurassic section that underlies theKimmeridgian-Tithonian salt bed (O’Connor and Sonnenberg, 1991).Potential also exists in the Kimmeridgian-Tithonian carbonates, whichare interbedded with evaporites. Oil and gas shows in the latter intervalhave been reported at two new fields: Yashlar and Iolotan.

South Mangyshlak Basin

The South Mangyshlak Basin is located in Kazakhstan and UzbekistanRepublics. The basin is an elongated depression situated to the northof Kara-Bogaz Arch and to the east of Caspian Sea (Figure 7-49). Itis approximately 300 km long in an east-west direction and 150 kmwide. It covers area of 35,000 km2 (13,500 mi2).

Geologic Setting

The South Mangyshlak Basin is bordered to the north by a zone offaulted anticlines characterized by a shallow Permo-Triassic basement.The basin is filled with up to 9,000 m of Paleozoic, Mesozoic, andCenozoic deposits. The basement of this basin is composed of UpperPaleozoic and Precambrian sedimentary, volcanic, and metamorphicrocks. The location of the basin (and its prominent oil fields, Zhetybayand Uzen) is shown in Figure 7-50.

This basin is essentially a fault-bounded depression. The southboundary is a major east-west fault with up to 1,000 m of basinaldisplacement. The basin’s basement dips steeply along its northern andsouthern boundaries towards the center. The basement dips much moregently in the eastern part of the basin and in the west beneath theCaspian Sea (Figures 7-51 and 7-52). The two most prominent regionsare the Zhetybay-Uzen Step (west) and the Shakhpahty Step (east).Basement rocks are found at a depth of less than 3,500 m in the stepregion. Nearly all of the oil and gas fields in the South MangyshlakBasin are present in this step region (12 out of 15 fields).

Large structures, which are present within the basin, are sometimescontrolled by basement faults. Clastic sediment deposition was con-trolled by basement faults in the older Permo-Triassic prospects.



Fig

ure

7-4

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Structural amplitude often increases with depth. Possibly, stratigraphictraps are also present, especially in the Middle Jurassic deposits, whichexhibit lateral variability.

There are several structures in the South Mangyshlak depressionwhich are not productive. The structures located in the central part ofthe basin are considerably deeper than those to the north.

Stratigraphy (Source and Reservoir Rocks)

Permian and Carboniferous rocks are present in the South MangyshlakBasin, with meager information available on the Carboniferous sedi-mentary rocks. Widespread Permian deposits, which are composed ofsandstones and black shales, are locally metamorphosed. Permian rockscould have acted both as source rocks and reservoir rocks. Permo-Triassic rocks have been encountered while drilling in the SouthMangyshlak Basin with shows of hydrocarbons. This sequence is thetarget for oil and gas exploration in the basin. The Permo-Triassicrocks, however, do not have good reservoir-rock characteristics:porosity is low (less than 6%) as well as permeability (0 to 0.1 mD)(largely carbonates). Fracturing of these carbonates, however, mayincrease permeability considerably.

The thickness of Permo-Triassic rocks ranges from 2,000 to 4,000m. The Middle Triassic Olenek Formation, which consists of black andgray shales, siltstones, limestones, and sandstones, is over 600 m inthickness at some localities. It is a potential source rock with oil-prone,sapropelic, organic matter and TOC values up to 9.8%. It is buried toa depth of up to 6,000 m and, therefore, may be overmature. TheUpper Triassic rocks are not present in the subsurface. A non-conformity exists between the Middle Triassic and Jurassic deposits.

Middle Jurassic deposits in the Uzen area lie directly over LowerTriassic rocks. The basal part of the Middle Jurassic section is a non-marine clastic sequence (lacustrine), which includes dark gray to blackshales, mudstones, siltstones, and sandstones. The Lower-MiddleJurassic black shales are source rocks for the oil (paraffinic) and gaspresent in this basin (e.g., Uzen Field). The upper part of the LowerJurassic section is composed of shallow marine clastics and mudstone.

Upper Jurassic rocks are of shallow-marine origin and includesandstones, siltstones, shales, and some limestones and dolomites.



Upper Jurassic deposits are also potential source rocks containinghumic and sapropelic-humic organic matter. The Jurassic section isbetween 270 and 1,250 m in thickness and is the major explorationtarget for oil and gas in the South Mangyshlak Basin. Numeroussandstones are productive in the basin, most of the production beingparaffinic oil. This suggests a lacustrine algal origin.

The thickness of Cretaceous deposits in the South Mangyshlak Basinis as high as 2000 m. They consist of shallow and platform marinerocks including sandstones, siltstones, shales, and carbonates. LowerCretaceous rocks are productive in the basin but do not have sourcerock potential. Upper Cretaceous rocks are productive in the giantUzen Field.

Tertiary sediments are also present in the South Mangyshlak Basin.Paleogene and Neogene sediments were deposited under shallow-watermarine and continental environments. Throughout the basin theirthickness varies between 1,100 and 2,100 m.

Jurassic rocks contain oil in some localities at a depth as shallowas 100 to 500 m; this suggests stratigraphically controlled updipmigration. Many authors contend that deeper Triassic and even Permiansource rocks exist in the basin. It is believed, however, that Triassicand Permian source rocks are mature to overmature in much of thebasin. The region of highest maturity is in the western and deepestportion of the basin. Very few mature source rocks exist in the easternportion of the basin (Kraychik, 1980).

The abnormally high formation pressure is widespread in theMangyshlak region. Origin of the abnormally high formation pres-sure in the Mangyshlak fields have been discussed by Gurevich andChilingar (1997).


According to Meyerhoff (1982), the Uzen Field has ultimate recov-erable reserves of 3.6 Bbbl and 350 Bcfg. On the other hand, Ulmishek(1981) assigned 7.3 Bbbl and 42 Bcfg recoverable to this field.Zhetybay Field is credited with 1.0 Bbbl and 1.1 Tcfg gas. Othernotable fields include the Yuzhno-Zhetybay, Aktas, Tasbulat, Asar, andTenge gas fields located in the western part of the basin, and the Kansuand Shakhpahty gas fields on the east. Probably, deep-basin gas fieldsof small size do exist.


The Shakhpahty Field, which was discovered in Uzbekistan, islocated on the South Mangyshlak structural nose. Four sandstone andsiltstone reservoirs of Middle and Upper Jurassic age produce gas.Porosity and permeability are about 20% and 100–312 mD, respectively.


The potential of finding oil and gas in the South Mangyshlak Basinis good. The offshore Caspian Sea portion of the basin probably holdsthe greatest promise of discovering large oil and gas fields offshorein water depths of 200 m or less. There are no known deep-basin gasfields (onshore or offshore). Gas and oil fields will be found onshorein deeper basins and in Triassic or Permian reservoir rocks. Onshorefields are likely to be smaller than those offshore. Combined onshoreand offshore recoverable oil and gas reserves (remaining) are possibly1 to 10 Bbbl and 10 to 25 Tcfg.

239

CHAPTER 8

Conclusions

The distribution patterns of oil and gas presence in the onshore andoffshore areas, and the principal reservoir and sealing properties ofthe oil- and gas-bearing formations in the South Caspian Basin canbe summarized as follows:

1. The main oil- and gas-bearing formation in the Eastern Azerbaijanand the offshore areas of Apsheron and Baku archipelagoes is theMiddle Pliocene Productive Series. In the Western Turkmenistan andthe adjacent shelf areas this formation is named as Red-Bed Series.The section is composed of sands, sandstones, siltstones, loams, shalesand unsorted rocks. The Productive/Red-Bed Series is separated intotwo divisions, lower and upper, and into several suites according tolithology, i.e., prevalence of sandstones or shales.

2. Core data, paleontological studies and log response suggest thatsediments of the Productive Series were deposited in a shallow-water,fluvial-deltaic environment. The large volume of clastics present in theProductive Series indicate a proximal source of sediments. The RussianPlatform and islands, which existed north of the Apsheron Peninsulaand Apsheron Archipelago, as well as the southeastern slope of theGreater and Lesser Caucasus, served as the primary sources for clasticmaterial for the Apsheron Peninsula and adjacent areas of the CaspianSea. The clastics were deposited by the Paleo-Volga, Paleo-Ural, Paleo-Kura, and other rivers. The Productive Series is divided into sevensedimentary sequences according to the transgression/ regression cyclesduring the basin development.

3. Mineral composition of the Middle Pliocene section is charac-terized by several associations of both light and heavy minerals. Lightminerals include quartz, feldspar, glauconite, and fragments of variousrocks. To the south, quartz content decreases, whereas the content ofrock fragments increases due to remoteness from quartz-feldsparsources within the Russian Platform to the north. Rock fragments hereowe their origin to the sedimentary and volcanic rocks of the Greater

(Chapters 1 to 7)


and Lesser Caucasus. Heavy minerals include five groups: ore minerals,stable minerals, kyanite or disthene group, micas, and glauconite. Aclassification of clastic rocks is presented here based on the petro-graphic attributes and reservoir-rock properties.

4. Reservoir-rock properties of the Productive Series, which are verygood, vary both within the section and over the area. In the ApsheronPeninsula and Apsheron Archipelago, porosity varies from 15 to 30%,with permeability ranging from 10 to 1,000 mD. The cement is usuallyclayey-carbonate with a predominance of clay minerals. Severalstatistical correlations were obtained, including relationships amongporosity, permeability and depth of occurrence. These correlations canbe used for estimation of reservoir-rock properties in undrilled areasand at great depths.

5. Paleogene to Neogene argillaceous rocks (shales, mudstones, etc.),which are widespread in the geologic section of the Azerbaijan andthe South Caspian Basin, make up 50 to 95% of the section and playa key role in establishing lithologic, mineralogic, geochemical, andthermobaric characteristics of the basin. Most clay minerals in theProductive Series belong to the smectite (montmorillonite), mixed-layered and illite groups. Presence of smectite results in low perme-ability of argillaceous rocks and ensures their good sealing properties(caprocks overlying reservoir rocks).

Onshore, the Oligocene to Miocene argillaceous rocks (shales,mudstones, etc.) are higher in volcanic ash content, owing to theirproximity to the Lesser Caucasus, than the Pliocene argillaceous rocksof the South Caspian Basin. The most characteristic feature of theTertiary argillaceous rocks in Azerbaijan and the South Caspian Basinis their undercompaction and the presence of numerous pores ofvarious sizes (measured by SEM). Their effective porosity (as usedin USA) ranges from 3 to 20%.

6. The montmorillonite content of the Baku Archipelago shales isconstant down to depths of around 6.5 km, because the formation ofsecondary montmorillonite from illite predominates over the trans-formation of primary montmorillonite to illite. Abnormally-high porepressures in shales hinder the dehydration of montmorillonite and favorthe transformation of illite to secondary montmorillonite, which producesheat. The produced heat, in turn, causes an increase in temperature,which results in the transformation of montmorillonite to illite. All

Conclusions 241

these transformations are characteristic of young basins with rapidlyaccumulated thick argillaceous sediments.

7. Undercompaction of argillaceous rocks, even at depths down to6.5 km, is explained by the comparatively young age, a high sedi-mentation rate (up to 1 km per million years), their great thickness,and incomplete squeezing-out of pore water. As a result, such argil-laceous rocks have abnormally high pore pressures, often higher by afactor of 1.5 (and more) than hydrostatic pressure. The sealing propertiesof the udercompacted shales in the South Caspian Basin are deter-mined mainly by their AHFP and still continuing squeezing-out of porewater. The sealing properties of argillaceous rocks (caprocks) are veryeffective and are determined by the progressively rising capillarypressures as the pore channel (throat) diameters decrease.

8. The sealing properties of argillaceous rocks (caprocks) at depthsgreater than 6.5 km still persist, because of the presence of largeamounts of montmorillonite clay. If accompanied by (1) good reservoirrocks, (2) abnormally-high pore pressures in shales and sandstones,and (3) relatively low formation temperatures (which allow hydro-carbons to persist), the South Caspian Basin may contain commercialoil and gas accumulations at depths of 9 km and deeper.

9. The oil and gas potential increases considerably in a southeasterlydirection. The principal types of traps are structural (anticlines and faults).

A decrease in density and increase in gas saturation of crude oilsoccur in the direction of regional sinking of the anticlinal trends fromnorthwest to southeast. In the reservoirs, the crude oil density increasesdownward along the dip toward the oil-water contact. In the exposedaccumulations, on the other hand, density increases upward along thebedding. With time, there is a trend of a certain increase in oil densityupon the field development.

10. The formation waters of the Productive Series (South CaspianBasin formation waters) are characterized by a regional, very slowmovement of the waters from the more depressed portions of the basintoward the higher parts having discharge zones.

The Lower Productive Series is characterized by the low-salinityformation water of the sodium bicarbonate type, whereas the UpperProductive Series includes more saline water, as the primary alka-linity is replaced by a secondary salinity. The total water salinitydecreases with depth and with increasing alkalinity of the water.


The effect of lithology is superimposed on the above trends of formation-water chemistry.

In the offshore area, water salinity increases from the more depressedto the more uplifted structures, and also with transition from thesouthwestern flanks of the local uplifts toward the northeastern flanks.This may indicate movement of the water from southwest to northeastand stagnation of water in the uplifted structures.

11. The above described patterns of changes in the properties ofcrude oils, gases, and formation waters vertically and laterally suggestthe migration of hydrocarbons along the strata and their accumulationin the structural traps, with differential entrapment according to thephysical and chemical properties of migrating fluids. Migration withinthe individual structures led to the distribution of crude oil propertiesin the vertical section.

12. Development of abnormally-high pore pressures may lead to thelateral variation of rock density and, under certain geologic conditions,to folding, clay diapirism, mud volcanism, and earthquakes.

243

CHAPTER 9

MathematicalModels in

Petroleum GeologyINTRODUCTION

The progress in the oil- and gas-producing industry is related closelyto the acceleration of discovery rates, exploration, and productionof hydrocarbon resources. Exploration and development of hydro-carbon resources must be based on scientific information, which helpsto predict subsurface conditions and properties of the oil- and gas-bearing formations.

Main oil and gas reserves are found in sedimentary basins composedof both terrigenous (siliciclastic) and carbonate rocks. Preservation ofhigh pore pressure and good properties of reservoir rocks and sealsin these basins depends greatly on their evolution. The processes ofsedimentation, diagenesis, and catagenesis cause a chain of changeswhich may be of practical use in the prediction of oil and gas potential.Consequently, both mathematical simulation of the processes of deposi-tion, diagenesis, and catagenesis of sediments and concurrently crea-tion of principles for predicting reservoir pressures, oil and gascomposition, and petrophysical properties of reservoir rocks andcaprocks are goals of high priority.

One must develop the ability to model the increase in depth, withconsequent increase in the complexity of geological conditions thataffect the exploration for oil and gas, and subsequent development ofnew onshore and offshore fields. All this requires the application of aset of mathematical models to process geological and geophysical datain order to aid exploration, and the estimation and evaluation of oiland gas resources (Miller and Kahn, 1965; Krumbein and Graybill,


1969; Krumbein et al., 1973; Merriam, 1981; Harbaugh and Bohnam-Carter, 1974; Rodionov et al., 1987).

The use of mathematical methods and computers increases the scopeof problems that can be solved on the basis of integrated geologicaland geophysical information. Mathematical methods using computerprocessing of the current geologic information accelerate the processof regional and local prediction of oil and gas potential, that, in general,increases the economical and geologic efficiency of exploration, develop-ment, and production of oil and gas fields (Buryakovsky et al., 1982a;Buryakovsky and Kuzmina-Gerasimova, 1983; Dzhafarov and Dzhafarova,1983; Buryakovsky et al., 1990a, 1990b; Buryakovsky, 1992).

MATHEMATICAL SIMULATION OFGEOLOGIC SYSTEMS

In the field of petroleum geology, the discovery and developmentof oil- and gas-bearing basins, regions, zones, etc. may be consideredas integral objectives which can be predicted. An important featureof these systems (basins, regions, zones, etc.) is that division intosubsystems of (1) reservoir (permeable) rocks and (2) caprocks or seals(impermeable rocks) is possible. The presence of these two subsystemsdefines oil- and gas-bearing trap. Absence of any one of these sub-systems (reservoir rock or seal) indicates the absence of such a trap.

Geological systems of oil- and gas-bearing basins, regions, zones,etc. are parts of the more extensive systems of lithosphere. Due to theabsence of distinct boundaries, these systems exchange fluids, energy,etc. with the external medium. The geologic systems also develop intime. They, however, provide a certain stability and inherit mainstructural and behavioral features. Depending on the kind of exchangebetween the geologic system and external medium (exchange of matter,energy, or information, separately or simultaneously), one can constructmaterial-structural, material-functional, energy-functional, and infor-mation models of oil- and gas-bearing systems. Any of these models, limit-ing the variety of natural geologic systems, allows the systems forecast.

Scientific bases, simulation techniques, and constructed mathe-matical models of both static and dynamic geological systems havebeen developed (Buryakovsky, 1992). The other goal of these investi-gations was the modeling of the actions which must be taken by earthscientists. All this is necessary in order to study and predict the

Mathematical Models in Petroleum Geology 245

Fig

ure

9-1.

Flo

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rela

tions

bet

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form

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n an

d pr

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ure

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logy

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Mathematical Models in Petroleum Geology 247

structure and properties of geologic systems during all phases ofexploration and development of oil and gas fields.

Basic theoretical and methodological principles of simulation andprediction of geologic systems (their structure and behavior) aredefined by postulates. The principles or postulates establish the re-quirements, which are necessary (and sufficient) for the mathematicalsimulation of geologic systems and necessary actions by earth scientists.The principles or postulates include the following:

1. Principle of consideration of the system’s nature, which requiresa separate simulation of geologic, technologic and experimentalsystems with different objectives required by the “real world.”

2. Principle of system’s development (evolution), which requires thesimulation of systems with consideration of the time factorand the system’s subdivision into three time scales: (a) geologic,(b) technologic, and (c) experimental.

3. Principle of consideration of comparative size and complexity ofgeologic and experimental systems, which requires simulationof a sequence of systems from an oil- and gas-bearing basin scalethrough the core sample scale.

4. Principle of consideration of the information growth, whichrequires simulation of the activities of earth scientists. These in-clude the successive phases of prediction of oil and gas presenceand existence of traps, and discovery, exploration, reserve esti-mation, development and production of oil and gas fields.

The definition of these principles provides a systems approach bothin the development of the scientific foundations, and in the simulationtechnology of geologic systems. The relations among simulationprinciples are given as flowchart in Figure 9-1. An important elementof this chart is the feedback, which allows improving the present anddeveloping the new methods for investigation and simulation ofgeologic systems.

The technological chart (Figure 9-2) distinguishes three inlet blocks:(1) theoretical foundations (basic principles), (2) initial information,and (3) technical means (facilities). This chart also contains thefeedback, which provides improvement of theoretical foundations forthe simulation of geologic systems.


248

CHAPTER 10

MathematicalModels in Oil and

Gas Exploration andProduction (StaticGeologic Systems)

MAPPING OF STRUCTURES WITHIN THEAPSHERON–PRE-BALKHAN ANTICLINE TREND

The Apsheron–Pre-Balkhan Trend is one of the most prospectiveregions in the South Caspian Basin. Many oil and gas fields werediscovered there. The area between the Neft Dashlary Field in the west(Azerbaijan portion the Apsheron–Pre-Balkhan Trend) and the BarinovField in the east (Turkmenistan portion the Apsheron–Pre-BalkhanTrend) was not studied by using seismic survey for a long time. Thereasons for that were: deep water, the lack of technology needed todevelop the region and the lack of urgent need.

Azerbaijan Portion the Apsheron–Pre-Balkhan Trend

The situation changed following the discovery of the Gyuneshli OilField when the “Kaspmorneftegazprom” Production Association obtainedmodern floating deep-water drilling rigs. Subsequently, detailed CDPsurveys were conducted on the structures discovered in the region, andthe Azeri and Chyragh structures were delineated. Most of the largestructures, however, were studied only by the wide-spaced seismic

Mathematical Models in Oil and Gas Exploration and Production 249

surveys, and the broad band of offshore area immediately adjacent tothe Neft Dashlary Field is not surveyed at all. The reason for this isthe technical difficulties in conducting the seismic surveys near thefixed platforms, and the well-developed network of cat-walks connect-ing them.

These difficulties led to the decision to use the mathematical approachfor discovering the pattern of formation of anticlines in the south-western portion of the Apsheron Threshold, in order to increase thequality of already acquired data. Well data from the following areaswere used: (1) Dzhanub-2 prospect, (2) southeastern part of theDzhanub Field, (3) southern and eastern parts of the Neft DashlaryField, (3) Oguz prospect, and (4) Gyuneshli Field. On these structures,the “Pereryv” Suite base (one of the best and most continuous markerhorizons) was used for structural mapping. Some depth informationwas obtained from CDP lines.

To accomplish this task, the Double Fourier Series with the non-uniform input data distribution was used (Buryakovsky et al., 1990b).The second-power term coefficients of the series were calculated (thewave lengths of λ1, λ2, λ1/2 and λ2/2 for the depth of top of the“Pereryv” Suite in the southwestern part of Apsheron Threshold). Inview of a very high coverage coefficient (91.2%), the higher powermaps were not prepared although the program is capable of handlingthe data up to the fourth power.

The following conclusions are based on the interpretation of theprepared map (Figure 10-1).

First, the region’s structural pattern was confirmed, which provedthe validity of the map as the end product of mathematical simulation.In particular, the following structures were delineated: Neft Dashlary,Gyuneshli, Chyragh, the up-dip trend of the deposits toward theDzhanub Field, and depressions between the Neft Dashlary, Oguz andGyuneshli structures. The map shows that the Gyuneshli and Chyraghstructures form a single elongated swell with two domes of similarsize. The postulated high of the Dzhanub-2 prospect does not appear.Instead, deposits here appear to form a homocline. At the samestratigraphic level, there is only a very minor high at the Oguzstructure, between two synclines. Contrary to the results of the seismicsurvey, this feature does not represent the southwestern plunge ofthe Neft Dashlary anticline. In addition, a new hemi-anticline, upto 9 km in width, was found between the southern flank of Neft


Fig

ure

10-

1. S

imul

ated

str

uctu

ral

map

at

the

base

of

“Per

eryv

” S

uite

of

the

Pro

duct

ive

Ser

ies

of A

zerb

aija

n (M

odifi

edaf

ter

Bur

yako

vsky

et

al.,

199

0b).


Dashlary anticline and the northwestern plunge of the Gyuneshli andChyragh uplifts.

The other noteworthy feature of the discussed map is an independenthigh south of Neft Dashlary anticline. According to the map, there isa closed longitudinally striking fold there. Based on reliable data, thesize of this fold is substantial: 12 by 2.5 km. This suggested that thisanticline is slightly asymmetric. The eastern plunge is shorter, whereasthe western one is longer. The eastern plunge is getting flatter towarda small synclinal low. The western plunge is rather narrow, turnsslightly northwestward, and extends toward the Dzhanub-2 structure.Over the narrow saddle in the northeast, this anticline is connectedwith the Neft Dashlary structure. The southern flank is steeper thanthe northern one. A detailed analysis of the available CDP data sup-ports these conclusions.

In 1981, the area was covered by the peripheral part of anotherseismic survey. Its interpretation tentatively showed the homoclinalnature of the structure. In 1981, the hydrogeological and gaseoussurveys were conducted there (Ismailova, 1981). The contents ofhydrocarbons dissolved in water were abnormally high, which indicatesthat beneath the recorded anomaly there is a source of hydrocarbonscontinuously emitting hydrocarbons. This can be associated with(1) a fault, (2) an underwater mud volcano, (3) an anticline or (4) areservoir pinch-out. It is worth noting that over the suggested anticlinethere is a local gravity anomaly.

Undoubtedly, the results of a mathematical simulation are notsufficient to indicate a definite presence of an anticline there. It canbe a flexure on the broad homoclinal plunge of the anticline. This isrecorded south of the Gyuneshli and Chyragh structures, where a broadlow-angle Ushakov anticline was discovered.

The area of suggested anticline and the structural nose should bestudied using detailed exploration techniques. The suggested high isin the shallow water (mostly, shallower than 50 m) and the nose is ina slightly deeper water (up to 80 m). The area is close to the infra-structure of the Neft Dashlary Field and, in the case of discovery ofhydrocarbons, could be rapidly developed.

Turkmenistan Portion the Apsheron–Pre-Balkhan Trend

The Turkmenistan Shelf is the most prospective for oil and gasexploration in the Pliocene deposits. Oil and gas accumulations there


were discovered in the Cheleken Dome, Zhdanov Bank, LAM Bank(LAM is an abbreviation of the Laboratory of Airborn Methods forExploration), Barinov Bank, and East Livanov Bank, where the unitsIV through VIII of the Red-Bed Series and the Units IX and X of thePre-Red-Bed sequence are oil- and gas-bearing. The accumulations arenarrow and associated with the fault blocks.

The exploratory drilling was begun, and is still continuing, basedon the structural map prepared from the seismic surveys. The drillingdata (Zhdanov Bank—120,500 m, and LAM Bank—64,000 m) demon-strated significant discrepancies between the seismic and drillingstructural pattern (this is one of the main reasons why the wells didnot penetrate the target formations). Numerous and different structuralinterpretations led to an increased number of wells drilled in theunfavorable structural positions (for instance, in the LAM Bank).

To clarify the structural pattern and to discover new prospectivestructures for oil and gas exploration, the mathematical simulationusing the Double Fourier Series was conducted (Buryakovsky et al.,1990b). The top of the Pre-Red-Bed deposits (which, at the same time,constitutes the base of major producing and potential sandy-silty UnitVIII of the Productive Series) was studied. Analysis of the resultingschematic map (Figure 10-2) gives a general idea of the structure,including the connections between the local highs.

According to the map, the Turkmenistan portion of the Apsheron–Pre-Balkhan Trend (within the studied area) is comprised of threelarge (up to 25 km long) anticlines the widths of which, within theclosed contours, are up to 6 km. The connections between the highsare quite clear.

The important features of the map are as follows:

1. The northwestern plunge of the East Livanov uplift appears tomerge with the southeastern plunge of the next anticline. This,of course, could have resulted from the incorrect interpretationbecause of insufficient data. The southeastern plunge includes asmall Barinov anticline which was not shown on the map.

2. The Gubkin uplift appears as a single anticline; however, basedon the detailed seismic survey of 1964, it is comprised of threelocal highs. One interpretation made later (Veliyev and Narimanov,1979) also showed the structure as a long single anticline witha fault along its axis and a number of smaller faults separatingit into fault blocks.


Fig

ure

10-

2. S

imul

ated

str

uctu

ral

map

at

the

base

of

Uni

t V

III

of t

he R

ed-B

ed S

erie

s of

Tur

kmen

ista

n (M

odifi

ed a

fter

Bur

yako

vsky

et

al.,

199

0b).


3. The large Zhdanov uplift is combined with a smaller ChelekenDome into a single anticline.

4. The three small uplifts distinguished over the LAM Bank areaare shown as a single narrow anticline with an extended easternplunge. The map displays an almost straight-line elongation ofthe fold, whereas the previous interpretation showed the bend ofthe eastern plunge toward northeast, where the first Wells (17,19 and 20) have been drilled.

5. The LAM anticline is separated from Gubkin and the Zhdanovstructures by a narrow syncline, which opens westward.

6. A new high is possible along the extension of the LAM structure.

Taking into account a high degree of coverage (91%), therefore, itcan be stated that the map adequately reflects the structural patternand can be recommended for practical use. A number of wells weredrilled in the Zhdanov structure at unfavorable structural positions,outside the closed contours. On the LAM Bank, Wells 15 and 17(which produced water from the Unit VIII) and Wells 18 and 19(which were abandoned for the mechanical reasons) have also beendrilled outside the closed contours. Wells 16 and 20 were spudded inunfavorable positions and are likely to be outside the Unit VIII. It isrecommended to use the existing platforms for drilling deviated wells,which could penetrate the discovered accumulation. The East Livanovand Gubkin structures need additional CDP coverage and exploratorywells. A CDP survey is recommended over the eastern plunge of theLAM Bank, which may discover a new anticline.

RESERVOIR CHARACTERIZATION USING LOG DATA

Many years of scientific research, accompanying the reserves esti-mations and the development design on new offshore oil, gas andcondensate fields in the South Caspian Basin (specifically, as appliedto the Productive Series), led to the integrated procedure of processingthe geological, geophysical and petrophysical data (Buryakovsky,1977a, 1985a; Buryakovsky et al., 1991a; Theory and Practice . . . , 1997).

Two major types of stratigraphic sections are distinguished in theProductive Series of the Apsheron Peninsula and the adjacent offshoreareas for which log interpretation has certain differences. The differ-ences in stratigraphy are caused by the rhythmically changing deposi-tional environments.


The first type of stratigraphic section includes the KS and NKGsuites of the Lower Productive Series and the upper portion of theUpper Productive Series. This type of section was formed during thetransgressions period, in a relatively deep-water environment with adiminished influence of water movement. Typical features of thissection include: the abundance of very fine- and fine-grained clasticmaterial; the prevalence of the silty sediments over the sandy ones;relatively high content of clay; low carbonate content; insignificantthickness of individual layers; and frequent intercalation of thin shale,siltstone and sand beds, creating a heterogeneous medium.

The second type of stratigraphic section is comprised of the PK,NKP, and “Pereryv” suites and lower portion of the Balakhany Suite.It was formed at the very beginning of transgressive events in ashallow marine environment, with the active participation of the shelfwater movements and currents. As a result, the clays and silts werewashed out and the sediments were enriched in sand. Typical featuresof this section are: high sand content in the reservoir rocks and lowercontent of silts; low clay content; increased carbonate cement content;and greater thickness of the individual beds.

Difference in the reservoir types is caused by the rhythmical deposi-tion of the Productive Series sediments, which is expressed by the finergrain size and increased shale content toward the top of each rhythm.Typical for the Productive Series is an almost total lack of cleanlithological varieties: sandy-silty reservoirs include clays, whereasshales always contain sand and silt.

The reservoirs are identified on the basis of logs. The following logsand particular features of the curves are regularly used: bi- or tri-modalmulti-laterologs; negative reading on the SP curves; caliper logswherever they show the wellbore narrowing due to thick mud-cakeformation or the nominal wellbore diameter; low or medium readingon the gamma-ray (GR) curve; and positive readings on the neutron-gamma-ray (NGR) curve.

To determine the regularities in the relationships between the dataobtained from utilized log techniques and the data of tested formations,the factor analysis was applied. The data from the “Pereryv” Suite atthe offshore Bakhar Field was used as the field information. In thetested wells, the detailed measurements using each logging techniquewere recorded for each layer. The matrix selection so developed wasthen subjected to the factor analysis.


Taking the log combination for a single information system andbased on the interpretation results of matrix factor load, it was possibleto distinguish three main factors carrying 86% of information:

1. All E-logs—57% of information. The informative value decreasesalong with the dimension of the log; also, the differential param-eter of SP log.

2. 15% of information (related mainly to the mud invasion zone)is carried by the relative change in well diameter and by the 0.5-meter lateral log.

3. 14% of information is carried by the radioactive logs; GR andNGR logs both have high factor loads but with the opposite sign.

Rotation of the factor load matrix screens out the features ofequivocal informativity. For instance, the second factor in the factorload matrix includes the neutron-gamma-ray readings along withthe other main factors. After rotation, this feature becomes non-informative, and the quantitative informativity index of the mainfactors increases.

The interpretation strategy must be structured correspondingly, i.e.,the major attention should be devoted to the E-log data, followed bythe effect of the mud invasion zone, and then by the radioactivitylog data.

In order to determine potentially productive reservoirs using resis-tivity logs, production-test results must be compared with the trueformation resistivity. Wells selected for this comparison should beevenly distributed over the entire field area. For proper evaluation ofoil-saturation, well data of the initial period of field developmentshould be used. As need arises, data from sites not yet developed mayalso be used. Because of limited data available from the tested water-saturated formations, all data related to these formations are used forthe evaluation of resistivity.

The true resistivity value, Rt, which establishes the differencebetween the oil-bearing and water-bearing beds, may be used todetermine the critical cut-off point Rcr with high level of reliability.The Rcr is determined graphically using the procedure known as“hypothesis testing” (Smirnov and Dunin-Barkovskiy, 1965). Statisticaldistributions of the electrical resistivity of oil-bearing and water-bearing beds are converted into cumulative probability curves (i.e.,continuous cumulative distribution functions), which are compared on


a single plot. A vertical line is drawn to separate beds with differentsaturation of fluids based on resistivity data. Such curves are plottedfor each productive unit taking into consideration the lithologicalchanges over the field area (Figure 10-3).

Because of the statistical relationship between the electrical resis-tivity and the fluid saturation of reservoirs, statistical distributions ofresistivity of oil-bearing and water-bearing beds overlap forming anarea of “uncertainty” (Smirnov and Dunin-Barkovskiy, 1965).

Thus, when evaluating reservoir-fluid saturation using formationresistivity, determination of the resistivity cut-off point, Rcr, is depen-dent on the development objectives. If the objective is to miss aminimum number of oil-saturated beds (type I error), the boundary isshifted to the left, and the probability of water production increasesin beds to be tested. If, on the other hand, the objective is to increasethe probability of oil production (type II error), the boundary is shiftedto the right (Figure 10-3). Usually, for reserve estimation, the Rcr valueis established in such a way that the separation of two resistiv-ity distributions leads to the equality of errors of type I and II in“hypothesis testing,” so that the bed to be tested falls into the oil-saturated category.

Figure 10-3. Cumulative probabilities of electrical resistivity. a (left)—LokbatanField, b (right)—Bibieibat Field. 1—Oil-bearing beds with Rt,min, 2—all oil-bearingbeds.


If the distribution of resistivity of water-bearing reservoirs Ro is notavailable, it is impossible to separate oil-saturated and water-saturatedbeds using formation resistivity. In this case, the minimum trueresistivity Rt,min of all tested oil-bearing beds may be used as the Rcrvalue. However, using Rt,min = Rcr without proper evaluation of reli-ability and repeatability, usually leads to its underestimation. In thiscase, if there are a priori data to evaluate the possible error of type I(passing-up an oil-bearing bed, α), Rcr is established considering thevalue of this error.

Techniques are proposed for establishing the resistivity cut-offs forthe oil-bearing beds using the distribution of Rt,min values for oil-bearing beds. These beds are identified in stratigraphic sections eitheras single tested beds with Ro = Rt,min, or as beds with Ro = Rt,minselected from the entire tested interval. Of course, this procedure has somesubjective errors, but a skilled interpreter can easily avoid these errors.

Using these techniques, the Rcr value is established as a mean (ormedian) value of Rt,min. Thus, the standard deviation σR

2 [or MeanSquare Error (MSE) σR], the sample variation vR, and variation ofmean value vR

* are determined simultaneously. Numerical charac-teristics of distributions of minimum resistivity of oil-bearing bedsallow one to evaluate the reliability and repeatability of the mean valueRt,min

(Me), which is used as the resistivity cut-off point Rcr. The valueRcr = Rt,min

(Me) acquires inherent probability features in an explicitform, because Rcr is specified within a confidence interval as Rt,min

(Me)

± tασR, and limits of its variation are indicated. The probability indextα (i.e., the t statistic having a t-distribution) may be equal to 1 or 2.

Thus, the following three techniques may be used for statisticaldetermination of Rcr :

1. Using distributions of resistivity of oil- and water-bearing beds,including evaluation of errors of types I and II.

2. Using distribution of resistivity of oil-bearing beds, consideringonly an a priori estimate of type I error.

3. Using distribution of minimum true formation resistivity of oil-bearing beds, including evaluation of mean (median) value andstandard deviation of Rcr.

The latter technique was tested at Lokbatan and Bibieibat oil fields.Table 10-1 shows a comparison of results obtained from calculationsof Rcr using this technique at Lokbatan Field, and data obtained fromcalculations of Rcr considering a priori error of type I.

Mathematical Models in Oil and Gas Exploration and Production 259Ta

ble

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lati

on

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ccu

racy

of

Eva

luat

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esis

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ints

at

the

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kbat

an F

ield

Num

ber

of O

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6

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sn′

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s w

ith

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n″ =

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ian

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var

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re s

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Differences between Rcr values determined by both techniques fallwithin the limits of 0.2 to 2 ohm • m; i.e., relative variation of 3 to16%. Cut-off Rcr = Rt,min

(Me), determined using the distribution ofminimum true formation resistivity, is somewhat higher than the Rcrcalculated using resistivity distribution of all oil-bearing beds con-sidering type I error. Figure 10-3a illustrates cumulative probabilitycurves for beds with Rt,min (curve 1), and for all oil-bearing beds (curve2) of Unit III within the Upper Productive Series at Lokbatan Field.

To establish cut-off resistivity at Bibieibat Field, the minimum trueresistivity of oil-bearing beds was used due to the scarcity of testedwater-saturated beds within some units, and the total absence of suchbeds within other units. Using cumulative probability curves (Figure10-3b), a median value of Rt,min

(Me) was determined and used asresistivity cut-off point (Table 10-2). In addition, for Units I KS, IVKS and V KS, where more representative samples of oil-bearing beds

Table 10-2Calculation (and Accuracy of Evaluation) of Resistivity Cut-off Points

at the Bibieibat Field

Rt,min(Me), αR, VR, VR

*,Unit n ′′ Ohm • m Ohm • m % %

I + II 29 3.5 0.6 17.1 3.2III 85 2.5 0.6 24.0 2.6V 21 6.0 2.0 33.3 7.2VIII + IX 19 5.0 1.6 32.0 7.4XIVupper 34 10.2 1.9 18.6 3.2XIVlower 55 11.0 2.2 20.0 2.7XVI 28 8.0 1.7 21.8 4.1NKG 23 14.0 2.8 20.0 4.2NKPupper 20 25.0 3.6 14.4 3.2NKPlower 37 15.0 3.5 23.3 3.8I KS 34 7.2 1.4 19.4 3.4II KS 18 8.0 1.4 17.5 4.2III KS 37 9.0 2.0 22.2 3.6IV KS + V KS 72 9.6 1.2 12.5 1.5PK 13 14.5 4.0 27.5 7.6

See Table 10-1 for definitions of variables.


(72 to 174 beds) were available, resistivity cut-off points were deter-mined using this method and considering a priori error of type I.Figure 10-3b illustrates cumulative probability curves for minimumresistivity of oil-bearing beds (curve 1), and for resistivity of alloil-bearing beds (curve 2). Cut-off point, Rcr, determined from curve2, corresponds to the median value Rt,min

(Me) from curve 1, consideringthat error α = 20%.

As shown in Tables 10-1 and 10-2, variation of Rt,min is within limitsof 9 to 33%, averaging 22%. This shows both a limited variation inRt values of these beds and repeatability of the Rt,min

(Me) value usedas cut-off point of resistivity. Small variation of the mean value, whichfalls within limits of 2–7%, also proves this.

Comparison of results using different techniques for determining theresistivity cut-off points shows agreement between them. A statisticalapproach was applied to different distributions: (1) oil- and water-bearing beds, (2) oil-bearing beds, and (3) oil-bearing beds withminimum resistivity.

If all distributions are symmetric and satisfy normal distribution (i.e.,normal law), the number of beds n″ in the Rt,min distribution is twicethat of beds n′ determined by equation n′ = αn, where α is the typeI error and n is the number of oil-bearing beds in the Rt distribution.Because of this, stability of cut-off points determined by the thirdtechnique is higher than those obtained from the comparison betweenRo and Rt. The amount of required initial data is also less, becauseestablishing Ro distribution is not required.

Thus, the writers are proposing the determination of resistivity cut-off points for oil-bearing beds using minimum true formation resis-tivity from tested beds. Such an approach allows one to achieve acomprehensive evaluation of Rcr, determining confidence limits andresistivity variation. The scope of work is reduced because distributionof water-saturated reservoir resistivity need not be determined. In thosecases, when data on the water-saturated reservoir resistivity is notavailable, the proposed procedure is more reliable compared to thetechnique with a priori setting of error of type I.

In order to identify the productive reservoirs at the Palchygh PilpilasiField, 99 test results were compared with the true resistivity (Figure10-4). These reservoirs included those which yielded pure oil, oil withwater, water, and those which were tested dry. As shown in this figure,the cut-off point is around 10 ohm • m.


More elaborate mathematical techniques (Sharapov, 1965) can beused to determine the cut-off point (Rcr). In particular, one can com-pute frequencies for the events corresponding to the cut-off points foroil or water flows from the tested reservoirs with this Rcr, and todetermine correlation between this events. The combination of eventsis demonstrated in Table 10-3.

The problem boils down to the determination of correlation betweenthe events A and B or A

– and B

– at certain Rcr values near the boundary,

which must be established as a cut-off point. The evaluation of thecorrelation coefficient, r, can be made using the following equation:

rAB AB AB AB

A B B B= ( )( ) – ( )( )

( )( )( )( )(1)

Correlation coefficient error is determined from the following equation:

σrl r

N= – 2

(2)

Figure 10-4. Relationship between the number of tests and reservoir resis-tivity for Palchygh Pilpilasi Field. a—oil, b—water.


If the correlation coefficient is not less than 3σr, then the correlationis reliable.

To calculate the correlation coefficient, the point diagram (Figure10-4) for 99 tested reservoirs (Table 10-4) was used. Calculation ofthe correlation coefficient for the seven points on both sides of theassumed boundary between the water-bearing and oil-bearing reservoirs(Table 10-5) allows determination of the maximum correlation coeffi-cient which indicates the cut-off position. The cut-off point is betweenthe true resistivity values of 9 and 10 ohm • m (Figure 10-5). If oneaccepts 10 ohm • m as a reliable cut-off point, a water-bearing reser-voir would not be confused with an oil-bearing one. The triple mean-square deviation is within the range of 0.15 to 0.24, which proves thereliability of correlation between the events A and B, and A

– and B

–.

Application of Multi-Dimensional StatisticalMethod and Non-Parametric Criteria

Buryakovsky and Dzhafarov (1984a) have proposed a definitive rulefor including the studied layers into groups, which are distinguishedon the basis of test results, with the use of non-parametric criteria,the Kulbach informativity measure (J ), and the Diagnostic Coefficient(DC). This problem was solved using the “Pereryv” Suite withinBakhar Field as an example.

A combination of nine petrophysical parameters was used as thecharacteristic feature: the apparent resistivity recorded by the fivedifferent tools of multi-laterolog complex; the actual borehole diameter;and SP, GR and NGR readings.

Table 10-3Combination of Events During the Reservoir Tests

Resistivity Typical for:

Water-bearing Oil-bearingDefinition of Event Reservoir B Reservoir B

–Total

Water-bearing Reservoir A A–

B AB–

AOil-bearing Reservoir A

–AB A

–B–

A–

Total B B–

N


Using the cluster analysis, the multitude of layers was sudivided intofour groups: productive (Group I) and non-productive (Group II)reservoirs; and tight rocks (Group III) and shales (Group IV) (Figure10-6). Using the non-parametric Kolmogorov-Smirnov criterion allowsdetermination of the petrophysical parameters, which are informativefor each pair of groups. For this purpose, all readings of the givenparameter (for two groups) are listed in the increasing order. For eachgroup, the frequencies and cumulative frequencies are calculated. Bydividing the frequencies and cumulative frequencies by the number ofparameters for each group, the frequencies of occurrence column foreach group is prepared.

Let us assume that ωi(x) and ωi(y) are cumulative frequencies forboth groups I and II. Now let us determine the differences ηi = ωi(I)– ωi(II) and determine which one of them is greater.

Table 10-4Resistivity Distribution Based on Test Results of 99 Reservoirs

in the Palchygh Pilpilasi Field

Resistivity, Ohm • m

<6 7 8 9 10 11 12 13 >14 Total

Reservoir Yielded Water

Numberof tests 11 3 4 3 3 2 — 3 10 39

Reservoir Yielded Oil

Numberof tests — — 1 — 6 2 3 2 30 44

Reservoir Yielded Oil, Water and Emulsion

Numberof tests 2 2 — — — — — — 3 7

No Flow

Number of tests 1 — — 1 — — — — 7 9


Figure 10-5. Coefficient of correlation between two resistivities attributed tothe events of obtaining oil or water. 1—selected data, 2—all data.

Table 10-5Calculation of Correlation Coefficient for Different Events

Resistivity, ohm • m

Event 7 8 9 10 11 12 13AB 17 21 25 29 31 32 34AB

–28 24 20 16 14 13 11

A–

B 0 1 1 4 8 10 13A–

B–

54 53 53 50 46 44 41A 45 45 45 45 45 45 45A–

54 54 54 54 54 54 54B 17 22 26 33 39 42 47B–

82 77 73 66 60 57 52N 99 99 99 99 99 99 99r 0.50 0.54 0.58 0.60 0.50 0.53 0.51αr 0.08 0.07 0.07 0.06 0.07 0.07 0.08


If the maximum difference is large enough, then the zero hypothesisHo (i.e., that the selections are identical) is rejected. It means that theparameter is informative. After that, the following value λ2 is calculated:

λ2 2=+

Dn n

n nI II

I II

where nI is the number of values in the Group I. This value is thencompared with the cut-off values, which are determined by the levelof significance: λ0.05

2 = 1.84, λ0.01 = 2.65.If λ2 > λ0.01

2, then Ho is rejected, i.e., the parameter is informative.If λ2 « λ0.05

2, the opposite conclusion is true. If a parameter is determined

Figure 10-6. Bed classification using a set of petrophysical parameters forBakhar Field (Modified after Buryakovsky et al., 1990b).


to be non-informative for all groups under consideration, it is no longertaken into account.

Following is an example of determining the information value ofparameters using the non-parametric Kolmogorov-Smirnov criterion:the ratio of the actual to the nominal diameter (dact/dnom) and therelative GR reading (∆I γ) for distinguishing between the productive(Group I) and non-productive (Group II) reservoirs (Table 10-6).

Let us determine, from Table 10-6a, max[ωi(I) – ωi(II)] = 0.474, and

λ2 2 20 47484 2184 21

3 77=+

=+

=Dn n

n nI II

I II

.*

.

λ2 > λ0.012 = 2.65; therefore, Ho is rejected, i.e., the actual diameter

is an informative parameter.Then, max[ωi(I) – ωi(II)] = 0.15 is determined from Table 10-6b, and

λ2 20 1584 2184 21

0 44 1 84=+

= <. **

. .

Ho is accepted, i.e., the parameter is non-informative.Based on the figures in the tables, a conclusion can be drawn that

while separating productive reservoirs from non-productive ones, theborehole diameter is an informative parameter, whereas the GR read-ings are non-informative. Table 10-7 shows the results of informationvalue assessment for different petrophysical parameters using the non-parametric Kolmogorov-Smirnov criterion. All groups of layers distin-guished using the cluster-analysis technique are reflected.

For the informative parameters, their information value is evaluatedusing the Kulbach informativity measure. Informativity, or informationvalue, is understood as a value characterizing the degree of influenceof a factor (parameter) X for the image recognition, i.e., the factorinformation value after Kulbach gives the quantitative estimate of thedifference between the groups.

The computation procedure is as follows: (1) the range of variationsfor a studied parameter for two groups is subdivided into ten equalintervals; (2) the frequency of parameter within each interval is countedfor each group; and (3) the obtained data are converted into percentage(the sum of frequencies for both groups in all intervals is 100%).


268 Petroleum Geology of the South Caspian BasinTa

ble

10-

6A

sses

smen

t o

f th

e In

form

atio

n V

alu

e o

f S

elec

ted

P

etro

ph

ysic

al P

aram

eter

s: d

act/d

no

m a

nd

∆I γ

Val

ue o

fF

requ

ency

Cum

ulat

i ve

Fre

quen

cyR

elat

i ve

Fre

quen

cy

para

met

erG

roup

IG

roup

II

Gro

up I

Gro

up I

IG

roup

IG

roup

II

Di ff

eren

ce

a) P

aram

eter

dac

t/dno

m

0.84

20

20

0.02

40.

000

0.02

40.

894

26

20.

071

0.09

50.

024

0.93

20

82

0.09

50.

095

0.00

00.

951

19

30.

100

0.14

30.

043

0.96

02

95

0.10

00.

240

0.14

00.

972

511

100.

130

0.47

60.

346

0.98

21

1311

0.15

00.

520

0.37

10.

991

214

130.

167

0.62

00.

453

1.00

267

4020

0.47

60.

950

0.47

41.

0212

052

200.

620

0.95

00.

330

1.03

20

5420

0.64

00.

950

0.31

01.

0410

064

200.

760

0.95

00.

190

1.05

50

6920

0.82

00.

950

0.13

01.

067

076

200.

900

0.95

00.

050

1.07

30

7920

0.94

00.

950

0.01

01.

085

084

201.

000

0.95

00.

050

1.13

01

8421

1.00

01.

000

0.00

0

b) P

aram

eter

∆I γ

02

12

10.

024

0.04

80.

024

30

12

20.

024

0.09

50.

071

42

04

20.

048

0.09

50.

047


31

73

0.08

30.

143

0.06

06

40

113

0.13

00.

143

0.01

37

01

114

0.13

00.

130

0.06

08

10

124

0.14

00.

190

0.05

09

10

134

0.15

00.

190

0.04

010

30

164

0.19

00.

190

0.00

011

11

175

0.20

00.

238

0.03

813

82

347

0.40

00.

330

0.07

014

11

358

0.42

00.

380

0.04

015

31

388

0.45

00.

380

0.07

017

61

4610

0.55

00.

480

0.07

018

50

5110

0.61

00.

480

0.13

020

20

5310

0.63

00.

480

0.15

021

13

5413

0.64

00.

620

0.02

022

20

5613

0.67

00.

620

0.05

023

31

5914

0.70

00.

670

0.03

024

30

6214

0.74

00.

670

0.07

026

30

6714

0.79

80.

670

0.12

828

20

6914

0.82

00.

670

0.15

029

01

6915

0.82

00.

710

0.11

031

51

7416

0.88

00.

760

0.12

033

12

7518

0.89

00.

860

0.03

035

10

7618

0.90

00.

860

0.04

036

01

7619

0.90

00.

900

0.00

037

20

7819

0.93

00.

900

0.03

038

10

7919

0.94

00.

900

0.04

040

00

8019

0.95

00.

950

0.04

041

01

8020

0.95

00.

950

0.00

046

10

8120

0.96

00.

950

0.01

047

11

8221

0.97

61.

000

0.02

456

10

8321

0.99

01.

000

0.01

0


Tab

le 1

0-7

Info

rmat

ion

Val

ue

of

Pet

rop

hys

ical

Par

amet

ers

as D

eter

min

edfr

om

th

e N

on

-par

amet

ric

Sm

irn

ov-

Ko

lmo

go

rov

Cri

teri

on

Ra(

AO

) in

ohm

•m

Gro

up

sd ac

t/dno

m∆ U

SP

∆ Iγ

∆ Inγ

Ra(

0.5

)R

a(1

.05

)R

a(2

.25

)R

a(4

.25

)R

a(8

.5)

I an

d II

3.77

7.7 *

0.4*

1.4*

5.9 *

6.1

8.6

9.2

9.8

II a

nd I

II2.

906.

9 *0.

4*3.

9*0.

9*5.

77.

67.

67.

6II

I an

d IV

0.5*

1.3*

3.6 *

3.5*

1.2*

2.8

4.6

5.5

4.6

* =

Non

-inf

orm

ativ

e pa

ram

e te r

De f

init

ions

of

v ari

able

s:

d a ct

= a

c tua

l di

ame t

e r o

f w

e llb

ore

d nom =

nom

inal

dia

me t

e r o

f w

e llb

ore

∆USP

= r

e lat

ive

SP f

acto

r∆I

γ= r

e lat

ive

GR

fac

tor

∆Inγ

= r

e lat

ive

NG

R f

acto

rR

a(A

O)

= a

ppar

e nt

resi

stiv

ity

from

lat

e ral

son

de o

f A

O s

ize

(siz

e in

me t

e rs)

, oh

m•m


An example of the Diagnostic Coefficient (DC) and the Kulbachmeasure (J) computations for the two parameters (ratio of the actualto nominal diameter of borehole and the GR reading) is given inTable 10-8.

For each interval, the weighted average values (smoothed frequen-cies of occurrence) are calculated using the sliding average method:ωave = (ω1 + 2ω2 + 4ω3 + 2ω4 + ω5)/10. Then the Diagnostic Coefficientis determined: DC=10logΥIΥII and, from the Kulbach equation:

I x DC x P x I P x IIji

ji

ji

ji( ) ( ) . [ ( ) / – ( ) / ]= 0 5

where P(xji)/I is the probability for the parameter numbered j, from

interval i, to get into the Group I. The information value of theparameter number j is:

I x I xj j

i

i

n

( ) ( )==∑

1

The parameter is informative if I(xj) ≥ 0.5.Table 10-9 shows calculated information values for each parameter

for different classifications. To classify the section with respect to thefluid saturation and lithology, the diagnostic tables are prepared.Depending on the nature of classification, the diagnostic table forthe respective groups of layers (distinguished on the cluster-analysistechnique) is constructed.

Table 10-10 presents the Diagnostic Coefficients (DC) for the testedproductive (Group I) and non-productive (Group II) reservoirs (herethe classification is based on the oil or water saturation). Based onthe Diagnostic Coefficient, the cut-off point is 45. Using this as acriterion, it is possible to assign each evaluated layer to a group witha high degree of reliability.

Application of the Technique of Group Arguments (GMDH)

The “Pereryv” Suite is the sandiest in the Upper Productive Series ofthe Bakhar Field. The sand and shale contents are 73% and 27%, respec-tively; based on logs and cores, 10% of the sands are actually sandstones.




ble

10-

8A

sses

smen

t o

f th

e D

iag

no

stic

Co

effi

cien

t ( D

C)

and

th

e K

ulb

ach

Mea

sure

(J )

on

Sel

ecte

d P

etro

ph

ysic

al P

aram

eter

s: d

act/d

no

m a

nd

∆I γ

Ra

tioR

elat

ive

Fre

quen

cy,

%

Bet

wee

nIn

terv

alM

easu

rem

ent

Fre

quen

cyA

ctua

lS

moo

thed

Sm

ooth

edN

o.R

ange

Gro

up I

Gro

up I

IG

roup

IG

roup

II

Gro

up I

Gro

up I

IF

requ

enci

esD

CJ

a) P

aram

eter

da c

t/dno

m

10.

800–

0.83

50

00

00.

90.

950.

95–0

.23

0.00

002

0.83

5–0.

870

20

20

2.0

1.9

1.05

0.22

0.00

013

0.87

0–0.

905

42

59.

53.

27.

60.

42–3

.75

0.08

304

0.90

5–0.

940

20

20

6.3

14.3

0.44

–3.5

60.

1428

50.

940–

0.97

53

84

38.1

12.0

25.7

0.47

–3.3

10.

2250

60.

975–

1.01

029

1034

.547

.623

.026

.70.

86–0

.65

0.01

227

1.01

0–1.

045

240

28.5

023

.513

.31.

772.

470.

1265

81.

045–

1.08

020

024

018

.85.

23.

605.

580.

3780

91.

080 –

1.11

50

00

07.

70.

968.

029.

040.

3050

101.

115 –

1.15

00

10

4.8

2.4

1.9

1.26

1.01

0.00

25

b) P

aram

eter

∆I γ

10–

711

413

1913

.313

.80.

96–0

.16

0.00

042

7–14

244

2919

20.6

16.7

1.20

0.91

0.01

543

14–2

119

523

2420

.718

.21.

100.

560.

0050


Tab

le 1

0-9

Info

rmat

ion

Val

ue

of

Pet

rop

hys

ical

Par

amet

ers

as D

eter

min

ed f

rom

th

e K

ulb

ach

Mea

sure

(J )

Ra(

AO

) in

ohm

•m

Gro

up

sd ac

t/dno

m∆U

SP

∆ Iγ

∆ In γ

Ra(

0.5

)R

a(1

.05

)R

a(2

.25

)R

a(4

.25

)R

a(8

.5)

I an

d II

1.33

1.4

0.1*

1.4

1.3

2.9

2.6

1.4

1.6

II a

nd I

II4.

8 16.

01.

6*3.

10.

92.

73.

52.

94.

0II

I an

d IV

1.11

1.1

4.9*

1.4

1.0

2.3

3.1

2.6

4.6

* =

Non

-inf

orm

ativ

e pa

ram

e te r

See

Tabl

e 10

-7 f

or d

e fin

itio

ns o

f v a

riab

les.

421

–28

151

185

16.8

13.4

1.30

0.98

0.01

945

28–3

57

48

1910

.313

.30.

77–1

.11

0.01

706

35–4

24

25

95.

99.

00.

66–1

.83

0.02

807

42–4

92

12

52.

95.

70.

51–2

.93

0.04

008

49–5

61

01

01.

52.

00.

75–1

.25

0.00

309

56–6

31

01

00.

80.

51.

602.

040.

0030

1063

–70

00

00

0.3

00

00.

0000


Tab

le 1

0-10

Cal

cula

tio

n o

f th

e R

esis

tivi

ty C

ut-

off

Po

int

Usi

ng

th

e D

iag

no

stic

Co

effi

cien

t ( D

C)

Ra(

AO

) in

ohm

•m

Bed

No.

d act/d

nom

∆ US

P∆ I

γ∆ I

n γR

a(0

.5)

Ra(

1.0

5)

Ra(

2.2

5)

Ra(

4.2

5)

Ra(

8.5

)D

C

Pro

duct

ive

Bed

s

15.

5813

.03

0.56

1.37

6.89

–2.5

1–1

.85

–0.1

9–0

.24

22.6

42

5.58

13.0

30.

91–4

.98

6.89

–0.0

49.

64–2

.63

2.63

36.2

9

3–3

.75

1.75

0.91

1.86

–4.1

5–0

.04

–1.8

5–0

.19

–0.2

4–5

.70

40.

228.

510.

911.

37–4

.15

–2.5

1–1

.85

–0.1

9–0

.24

2.07

5–3

.75

–2.3

20.

911.

37–4

.15

–0.0

4–1

.85

–0.1

9–0

.24

–10.

266

5.58

–2.3

2–1

.83

1.08

6.89

–6.3

1–6

.01

–4.2

24.

90–1

4.20

72.

47–6

.15

0.91

2.69

3.18

–2.5

1–6

.01

–4.2

2–0

.24

–9.8

88

5.58

–7.2

80.

561.

376.

89–2

.51

–1.8

52.

63—

8.02

95.

58–6

.15

–1.2

51.

533.

18–2

.51

–1.8

5–0

.19

2.63

–1.9

010

–3.7

5–2

.32

–2.9

31.

37–4

.15

–0.0

4–2

.75

–0.1

9–0

.24

–9.5

011

0.22

–1.7

5–1

.83

1.37

–4.1

5–0

.04

–1.8

5–0

.19

–0.2

4–8

.46


5.58

13.0

3–0

.16

5.23

6.89

——

9.42

–0.2

449

.65

135.

588.

510.

98–1

.08

6.89

——

9.42

9.66

39.9

614

5.58

13.0

30.

981.

536.

89—

——

—28

.01

155.

5813

.03

0.91

1.86

6.89

——

9.42

—37

.69

165.

5813

.03

0.56

1.37

6.89

——

——

27.4

317

–0.6

5—

0.56

1.53

3.18

——

2.63

9.66

16.9

118

–0.6

58.

510.

915.

596.

89—

——

—21

.25

195.

58–2

.32

0.16

1.86

6.89

——

——

11.8

5

Non

-pro

duct

ive

Bed

s

2011

.06

15.3

55.

14—

0.28

3.98

10.6

14.1

415

.56

76.1

121

11.0

63.

420.

46—

0.28

8.96

14.3

14.1

415

.56

68.1

022

11.0

63.

42–3

.47

—1.

253.

9810

.614

.14

15.5

656

.54

2311

.06

10.7

50.

46—

0.73

0.90

6.07

8.81

8.49

45.8

124

11.0

615

.35

—7.

244.

598.

9614

.3—

15.5

677

.07

See

Tabl

e 10

-7 f

or d

e fin

itio

ns o

f v a

riab

les.


Sixty layers were selected from the tested wells. For each well, thesame nine petrophysical parameters were recorded. To normalize theparameters, their relative values were taken as follows:

1. x1 is the ratio of actual to nominal diameter of wellbore (dact/dnom);

2. x2 is the relative SP parameter (∆USP)3. x3 is the relative GR parameter (∆Iγ)4. x4 is the relative NGR parameter (∆Inγ)5. x5 through x9 are the relative parameters representing the ratio

of apparent resistivity ratio of the formation to the mud-filtrateresistivity

To train the program, the selected 60 layers were subdivided intothree equal classes. Class I includes the productive reservoirs; ClassII comprises the non-productive (water-saturated) reservoirs; and ClassIII includes non-reservoirs. The goal was to find the decision rulewhich would allow scientists to attribute an observation to one of thesethree classes based on the combination of petrophysical parameters.

The input data matrix is represented as follows:

Class I Class II Class III

X1,1,...,X1,20 X1,21,...,X1,40 X1,41,...,X1,60

X2,1,...,X2,20 X2,21,...,X2,40 X2,41,...,X2,60............... ............... ...............

X9,1,...,X9,20 X9,21,...,X9,40 X9,41,...,X9,6

The loss matrix was chosen as follows:

L =

0 2 3

2 0 1

3 1 0

The solution procedure starts from the subdivision of data in eachclass into two equal groups (training and verifying). For this purpose,the variations are counted in each class by the column, the data is



positioned in the order of diminishing variation and is sorted in sucha way that the odd columns belong to the training succession and theeven columns, to the verifying one.

The next stage includes the subdivision of input variables into threelevels. Each variable was ranked in the increasing order; the intervalsizes (between the adjacent values) were recorded; and the values forthe middle of the interval were determined. If a value differed fromthe preceding one by more than the average interval value, it wasassigned a level greater by one than that of the preceding value;otherwise, the same level was preserved. Therefore, after subdivisioninto three levels, the data matrix will be composed only of ones, twosand threes.

The algorithm works consecutively with each pair of arguments. Ifthe number of parameters m = 9, then there will be d = C9

2 = 36different pairs. Each variable can have three different values so thatthere will be nine possible combinations for a pair of variables: (1,1),(1,2), (1,3), (2,1), (2,2), (2,3), (3,1), (3,2), and (3,3).

Then, the experimental matrices L for the training and verifyingsuccessions are constructed for each of 36 pairs, each one assumingnine possible values.

The matrix, which displays frequencies of appearance (by theclasses) for the training and verifying successions of a pair of variables(X1, X3), is shown in Table 10-11. The pair (X1, X3) in Class I of thetraining succession two times assumed the values (1,1), four times thevalues (3,1), etc.

After that, the class is determined to which the current combinationof values can be attributed with the minimum risk. For instance, fora combination X1 = 1, X3 = 1 of the training succession, the frequenciesare: P1 = 2, P2 = 5 and P3 = 0. The risk of attributing the combinationX1 = 1, X3 = 1 to the class j is determined from the following equation:

d L P jj if ij

= ==

∑ , , ,1 2 31

3

and

d1 = 0*2 + 2*5 + 3*0 = 10

d2 = 2*2 + 0*5 + 1*0 = 4

d3 = 3*2 + 1*5 + 0*0 = 11


The pair (X1 = 1, X3 = 1), therefore, can be attributed with a minimumrisk to Class II, because mindj = 4.

The classes obtained with a minimum risk for all nine combina-tions are: 2, 2, 1, 1, 2, 3, 1, 1, 3, which can be represented in thefollowing form:

Combination Combinationof values Class of values Class

1,1 2 2,3 31,2 2 3,1 11,3 1 3,2 12,1 1 3,3 32,2 1

This allows one to attribute the combination (1,1) of the pair (X1, X3)to the Class I, the combination (X1, X2) to the Class II, etc.

Now, one can examine the verifying succession. The variable com-bination (1,1) in the Class II of the verifying succession is encountered3 times, the combination (1,2) in the Class II, 1 time, etc. The result is:

Table 10-11Matrix of Pair-Variable Empirical Probabilities of Training

and Verifying Successions by Classes

Training Succession Verifying Succession

Pairs ofVariables Class I Class II Class III Class I Class II Class III

(1,1) 2 5 0 1 3 0(1,2) 0 2 0 0 1 0(1,3) 1 1 0 1 0 0(2,1) 0 0 0 2 0 0(2,2) 0 2 2 1 5 2(2,3) 0 0 3 0 0 5(3,1) 4 0 0 2 0 0(3,2) 2 0 1 2 0 0(3,3) 1 0 4 1 1 3


Combination Combinationof values Class Frequency of values Class Frequency

1,1 2 3 2,3 3 51,2 2 1 3,1 1 21,3 1 1 3,2 1 22,1 1 2 3,3 3 32,2 2 5

Thus, the number of the correct solutions for the pair (X1, X3) in theverifying succession is: 3 + 1 + 1 + 2 + 5 + 5 + 2 + 2 + 3 = 24.

The described procedure is repeated for all 36 pairs of variables.For each pair, the number of correct solutions in the verifying succes-sion is determined. Nine pairs which are the best, i.e., have a greaternumber of correct solutions (with respect to the input parameters) areselected, and the matrix for the first row of selection is constructed.Each column of the matrix includes the class numbers to which thepair (X1, Xm) can be assigned with a minimum risk.

The multi-series algorithm of the decision making envisions thechange in the loss matrix L. The values of each column dj of thematrix L after each row are multiplied by the relative recognitionaccuracy in the j-th class (for correct recognition). As a result of thistraining of the loss matrix, the convergence of the multi-series algor-ithm to the optimum solution is accelerated. As soon as the solutionsremain unchanged with the transition to the next row, the matrix Ladjustment process is stopped. The obtained constant matrix representsthe optimum matrix because it corresponds to a maximum accuracyof the solution by the class. In the above described example, followingthe corrections, the L matrix after the i-th row will be:

L =

0 16 44 24

13 33 0 8

20 0 8 22 0

,

,

, ,

The solution procedure starts from the subdivision of data in eachclass into two equal groups (training and verifying). Generation of theinput matrix for the next series of selection finalizes the first iteration.Whereas during the first series of selection the variables were X1, X2,..., X9, then during the second series of selection the variables will be:


Y1=(X1, X3) Y2=(X3, X6) Y3=(X3, X7)Y4=(X3, X8) Y5=(X1, X4) Y6=(X1, X5)Y7=(X3, X5) Y8=(X3, X9) Y9=(X7, X9)

The new matrix is produced by replacing the variable combinations(X1, Xm) with the minimum risk class number. For instance, if the inputmatrix included variable values X1 = 1,3,..., X3 = 2,1,..., then thevariable Y1 will assume values 2,1,..., obtained from the solution matrix.

The number of selection series is determined from the followingcondition: R ≥ log2m (where m is the number of variables). Forthe four selection series, produced solution matrices are shown inTable 10-12.

At the second stage of the calculation procedure, the recognitionproblem is solved for the elements of introduced data matrix usingthe solution matrices constructed during the first stage. The data matrixis subjected to the subdivision into the three levels (as defined at thefirst stage).

Let us assume that an element of the data matrix has the followingcombination of parameters: X = {2,2,2,2,2,3,2,2,2}. It is necessary todetermine to which class it belongs. The best solution is always foundin the first column of the solution matrix. In this particular case it is(U4, U8), i.e., d(U4, U8) = 1. Following is the solution as obtained bythe procedure:

d(U4) = d(Z1, Z8) = d(1,2) = 1 d(Y2) = d(X3, X6) = d(2,3) = 1d(U8) = d(Z3, Z5) = d(2,1) = 1 d(Y4) = d(X3, X8) = d(2,2) = 2d(Z1) = d(Y1, Y2) = d(2,1) = 1 d(Y7) = d(X3, X5) = d(2,2) = 2d(Z8) = d(Y4, Y7) = d(2,2) = 2 d(Y1) = d(X1, X3) = d(2,2) = 2d(Z3) = d(Y1, Y4) = d(2,2) = 2 d(Y4) = d(X3, X8) = d(2,2) = 2d(Z5) = d(Y2, Y4) = d(1,2) = 1 d(Y2) = d(X3, X6) = d(2,3) = 1d(Y1) = d(X1, X3) = d(2,2) = 2 d(Y4) = d(X3, X8) = d(2,2) = 2

To validate the algorithm recognition quality for the tested wells,which were not included in the training process, the testing data matrixwas selected. It included 33 layers: 23 from Class I, 6 from Class II,and 4 from Class III (Table 10-13). The recognition results are: Class Iincludes layers 1 through 4, 7 through 12, 14 through 23 and 31; ClassII includes layers 24, 26, 27, and 29; Class III includes layers 5, 6, 13,27, 28, 30, 32 and 33. As shown, only six layers were chosen incorrectly.



Table 10-12Solution Matrices for Pairs of Variables

Pairs X1X3 X3X6 X3X7 X3X8 X1X4 X1X5 X3X5 X3X9 X7X9

(1,1) 2 2 2 2 2 1 1 2 2(1,2) 2 1 1 1 1 2 2 1 2(1,3) 1 1 1 1 2 2 1 1 1(2,1) 1 2 2 2 3 3 3 2 1(2,2) 2 2 3 2 3 2 2 3 1(2,3) 3 1 1 1 2 3 1 3 3(3,1) 1 1 1 1 3 3 3 1 1(3,2) 1 3 3 3 1 3 3 3 3(3,3) 3 3 3 3 1 1 3 3 1

Pairs Y1Y2 Y1Y3 Y1Y4 Y1Y8 Y2Y4 Y2Y8 Y3Y7 Y4Y7 Y4Y8

(1,1) 1 1 1 1 1 1 1 1 1(1,2) 1 1 1 1 1 1 1 3 1(1,3) 1 1 1 1 1 1 2 1 1(2,1) 1 1 1 1 1 2 2 2 1(2,2) 2 2 2 2 2 2 2 2 2(2,3) 1 3 1 3 1 3 1 3 3(3,1) 1 1 1 1 1 1 1 1 1(3,2) 1 1 1 1 1 1 3 1 1(3,3) 3 3 3 3 3 3 3 3 3

Pairs Z1Z8 Z1Z3 Z1Z5 Z2Z8 Z1Z9 Z2Z8 Z3Z4 Z3Z5 Z3Z6

(1,1) 1 1 1 1 1 1 1 1 1(1,2) 1 1 1 1 1 1 1 1 1(1,3) 1 1 1 3 1 1 3 1 1(2,1) 1 1 1 1 1 1 1 1 1(2,2) 2 2 2 2 2 2 2 2 2(2,3) 3 1 1 3 1 1 1 1 2(3,1) 1 1 1 1 1 1 1 1 2(3,2) 1 1 1 1 1 1 1 1 2(3,3) 3 3 3 3 3 3 3 3 3

Pairs U1U8 U1U3 U1U5 U1U8 U2U3 U2U8 U3U4 U3U5 U3U9

(1,1) 1 1 1 1 1 1 1 1 1(1,2) 1 1 1 1 1 1 1 1 1(1,3) 1 1 1 1 1 1 1 1 1(2,1) 1 1 1 1 1 1 1 1 1(2,2) 2 2 2 2 2 2 2 2 2(2,3) 1 1 1 1 1 1 1 1 1(3,1) 3 3 1 3 1 3 3 1 1(3,2) 3 3 1 3 3 3 3 3 1(3,3) 3 3 3 3 3 3 3 3 3


ble

10-

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Bed

No.

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427

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273

See

Tabl

e 10

-7 f

or d

e fin

itio

ns o

f v a

riab

les.


MODELING OF SEDIMENTARY SEQUENCES BASEDON WELL-LOGGING DATA

For the purpose of classification and detailed correlation of thestratigraphic sections in the oil and gas fields of the South CaspianBasin it was found expedient to subdivide and model the section as astratigraphic sequence of different lithologic units (Buryakovsky andDzhafarov, 1984a).

Lithologically, the Productive Series represents a rather monotonoussuccession of sands, silts and shales, with the sand-silt to shale ratioof about 1:1. The thickness of the Productive Series (offshore SouthCaspian) reaches 3,500 m. Quite frequently, the base of the ProductiveSeries is not penetrated by wells, which makes it difficult to correlateit with the paleontologically defined underlying Pontian shales (LowerPliocene). The top of the Productive Series is penetrated at a depthof 1,000 to 2,500 m. The overlying Upper Pliocene is subdivided intothe Apsheronian and Akchagylian intervals, which are comprised of shaleswith interbeds of sands, siltstones, marls, and, sometimes, limestones.

Core samples from the offshore Caspian Sea areas were obtainedfrom drilled wells. The macrofossils were rarely recovered due to thesmall diameter of cores and intense mechanical deformations in theprocess of drilling. Microfossils (foraminifera and ostracods) are moredependable for the correlation purposes, in particular, for the Pliocenesection. For example, a sufficient number of foraminifera, ostracods,radiolaria and pelecypoda species are described for the stratigraphicsubdivision of the Pliocene into stages (Pontian, Productive Series,Akchagylian and Apsheronian). The paleontological information,however, is not sufficient for a more detailed subdivision of theProductive Series into sub-stages.

The major obstacle for the stratigraphic subdivision based on micro-fossils, however, is the scarcity of core samples in complicated sub-surface conditions. In fact, there are only a few of them. In addition,the exploratory wells are positioned on the single-well offshore plat-forms. Boreholes may be as deep as 6,000 m, with complex deviation.Thus, most of the information on the penetrated section is based on logs.

Buryakovsky and Dzhafarov (1984a) proposed a technique formodeling of a common, average, normal (not overturned) section based



on the petrophysical parameters measured in wells. This multi-dimensionalproblem required the application of the cluster analysis and Markov’smodeling procedure.

When m parameters is measured in n objects, the multitude of dataforms the [n × m] order matrix. The crux of the cluster analysis isobtaining a symmetrical matrix of the [n × m] order using one of thesimilarity measurements, such as the correlation coefficient:

r = cov(x,y)/[var(x) • var(y)]1/2

or the standardized n-dimensional Euclidian distance:

d X X mij ik jkk

m

i j

n

=

==

∑∑ ( – ) /,

2

11(5)

where i,j = 1,...,n and k = 1,...,m.One must obtain a hierarchical object grouping based on estimates

of their similarity. The Markov’s first-order chain can be defined asthe description of the transitions between different events, when theprobability of each transition directly depends on the previous event.

The chosen procedures were implemented on the Bulla Deniz Field,where the section in Wells 29 and 32 was subdivided into layers fromthe base of Unit VII to the top of Unit V (the Upper ProductiveSeries). Twenty-six layers were chosen in Well 26, and 66 layers inWell 32. The following parameters were determined for each layer:thickness h; actual borehole diameter dact from caliper log; apparentresistivity Ra from 5 multi-laterologs; the resistivity Ra,lat from latero-logs; and relative SP, αSP, and GR, ∆Iγ, readings. The result was theinput data matrix [n × m], with n = 92 layers and m = 10 parameters.

Using the normalized parameters and the BESM-6 mainframe com-puter, both the correlation coefficients and the standardized Euclidiandistance were determined. The dendroid diagrams for 92 reservoirswere constructed utilizing the weighted average pair-by-pair grouping.As shown in Figure 10-7, there are five distinct groups of layers inthe Units V through VII interval in the Bulla Deniz Field. Based oncore analyses, log studies and test results, these groups could beassigned to certain lithologies and types of fluid saturations. Table 10-14displays the ranges and average values of major petrophysical param-eters of these groups.


There are two lithologically different reservoir types in the sectionunder study. The first one has higher relative SP amplitudes (0.31 to0.90) and lower resistivities (6.5 to 15 ohm • m). The second one haslower relative SP amplitudes (0.17–0.41) and higher resistivities (16.5– 29 ohm • m).

On the basis of the results of layer classification by the correlationcoefficient and by the standardized Euclidian distance, the matriceswere constructed for the transition frequency from one layer to the

Figure 10-7. Classification of beds (a) and modeling (b) of Units V to VIIsection of Bulla Deniz Field (Modified after Buryakovsky et al., 1990b). 1—Silty-shale beds, 2—shale, 3—sandy-silt non-productive beds, 4—sandy-siltproductive beds, 5—same, tight beds.


Tab

le 1

0-14

Cla

ssif

icat

ion

of

Lay

ers

Bas

ed o

n P

etro

ph

ysic

al P

aram

eter

s (r

ang

e/av

erag

e)

Nu

mb

er

h,R

a(2

.25

),R

IL,

Rt,

d act,

Gro

upof

Lay

ers

moh

m •

moh

m •

moh

m •

mα

SP

∆ Iγ

mm

Inte

rpre

tatio

n

I39

2.4–

29.2

2.4–

7.0

1.6–

4.4

1.6–

5.5

0.03

–0.2

60.

21–0

.64

216–

351

Sil

t an

d sa

nd9.

54.

62.

83.

30.

140.

4226

1

II14

2.8–

21.0

2.8–

9.0

1.7–

4.4

1.9–

6.5

0.02

–0.1

40.

70–0

.94

215–

243

Sha

le9.

55.

33.

13.

80.

100.

8123

0

III

121.

6–12

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5–13

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53.

4–9.

00.

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0.33

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2–23

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cing

5.1

8.4

5.4

5.5

0.23

0.55

212

(sha

le)

rese

rvoi

r

IV11

1.6–

10.4

6.5–

15.0

5.0–

11.0

4.2–

10.0

0.31

–0.9

00.

12–0

.59

186–

223

Pro

duci

ng h

igh-

qual

ity

6.0

10.2

7.2

6.5

0.55

0.23

200

rese

rvoi

r

V10

1.6–

6.8

16.5

–29.

07.

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.010

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8.0

0.17

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10.

34–0

.66

201–

231

Pro

duci

ng l

ow-q

uali

ty4.

322

.812

.813

.00.

290.

4921

7re

serv

oir

(tig

ht)


other. From the respective frequencies, the matrices were constructedfor the probabilities of the transition (Table 10-15). These matriceswere used for section modeling (see Figure 10-7).

Modeling of the stratigraphic sequence using the transition proba-bility matrix consists of the following steps: (1) random selection ofthe initial layer belonging to one of the groups; (2) selection of thesubsequent layer according to the transition probability of the firstlayer into the second from the transition-probability matrix line thatcorresponds to the selected layer group; and (3) continuation of theprocedure until the number of transitions is exhausted.

In the process of modeling the stratigraphic sequence (i.e., con-structing the artificial section), therefore, the rock type selection isperformed according to the transition probability matrix. In the appliedalgorithm, each layer is characterized by a single thickness equal tothe average thickness of all layers in the section. A more sophisticatedalgorithm allows one to model the section with the consideration ofmeasured layer thickness distribution within each lithologic group. Thesection obtained can be used as the composite geological-geophysicalsection. The tie-in of this section to the actual stratigraphic section isdone with the help of log markers. In this particular case, the latterare the shale interbeds between Units V and VII and the base of UnitVII (which is the top of the Nadkirmaku Clayey Suite).

Following is the summary of procedures leading to the constructionof the stratigraphic section:

1. Based on a set of logging measurements, the layers were identi-fied within the section under study; the petrophysical parametersof each layer were determined.

2. The matrix [n × m] was constructed, where n is the number oflayers and m is the number of the petrophysical parameters.

3. The matrix was processed to classify the layers into groups.4. The groups so obtained were compared with the core description,

logs, and test results for the purpose of describing the lithologyand the fluid saturation of the layer groups.

5. The matrix was constructed for the transition probability ofdifferent layer groups in the section under study.

6. The average section was modeled according to the Markov’sprocedure of succession for different layer groups in the section.

7. The constructed section was then compared with the stratigraphicsection of the region in order to determine the age of the deposits.


Table 10-15Matrices of Transition Frequencies (Upper Figure) and

Probabilities (Lower Figure)

Subsequent Class

PrecedingClass I II III IV V Sum

a) Based on the Correlation Coefficient

I 23 8 2 6 0 390.59 0.21 0.05 0.15 0.00 1.00

II 6 3 4 1 2 160.38 0.19 0.25 0.06 0.12 1.00

III 2 5 1 4 2 140.14 0.36 0.07 0.29 0.14 1.00

IV 6 0 4 5 0 150.40 0.00 0.27 0.33 0.00 1.00

V 0 1 2 0 4 70.00 0.14 0.28 0.00 0.58 1.00

b) Based on the Euclidian Distance

I 27 6 3 7 0 430.63 0.14 0.07 0.16 0.00 1.00

II 4 4 3 0 2 130.31 0.31 0.23 0.00 0.15 1.00

III 3 4 2 2 3 140.21 0.30 0.14 0.14 0.21 1.00

IV 6 0 2 2 0 100.60 0.00 0.20 0.20 0.00 1.00

V 1 1 3 0 6 110.09 0.09 0.27 0.00 0.55 1.00


ENTROPY AS CRITERION OF HETEROGENEITYOF ROCKS

A study of geologic bodies, from the viewpoint of their hetero-geneity, may be carried out with an aid of the theory of information.Any communication is a sum-total of information on some real system.In geologic terminology, this may be reports on the various analysesof rocks, oils, gases, or natural waters, which are being received forprocessing in the laboratory. Any one of these communicationsdescribes the extent or level of knowledge of some geologic bodytreated as a system.

There would be no sense in sending and receiving communicationson analyses of properties or measurements of the state, if the properties(or the state) of a geologic body are already known. The commu-nications become meaningful only if the state of the system is notknown beforehand or is inadequately known. The value and meaning-fulness of information on the given system will be greater in inverserelation to the state of knowledge of that system prior to the receptionof communications.

The entropy, a special index in the theory of information, is em-ployed as a criterion of the a priori (before the communications werereceived) indefiniteness of the system. The concept of entropy, bor-rowed from the fields of thermodynamics and statistical physics, is abasic concept in the theory of information. The entropy, H, is deter-mined by the following formula:

H p pi ii

N

==∑– log

1(7)

where pi is the probability of state of any one of the N componentsconstituting the system.

The “minus” sign is introduced, in order to make the entropypositive, inasmuch as pi ≤ 1 and log pi ≤ 0.

The H entropy is related to the S entropy (commonly employed inthermodynamics) using the Bolzmann’s constant k, namely:

S k p pi ii

N

==∑– log

1(8)


The entropy has the following properties:

1. It becomes zero, if one of the states of the system is fully known(pk = 1) and the others are impossible (p1 = p2 = ... = pk–1 = ...= pn = 0).

2. At a given number of states, it becomes maximum, if all thestates are equally probable, but increases with the increasingnumber of states.

3. It is additive, i.e., it is possible to add up entropy of differentsystems.

In the theory of information, entropy is generally calculated in thebinary system, although natural or decimal logarithms are often moreconvenient to use. The shape of the –plogp function, in natural anddecimal logarithms, is presented in Figure 10-8.

The quantity of information on the state of a real system is measuredby the decrease in the entropy of this system. The ultimate quantityof the information, I, is equal to H, namely:

I p pi ii

N

==∑– log

1(9)

Figure 10-8. The –plogp function plotted versus p in natural (1) and decimal(2) logarithmic scales.


Thus, the information I is the logarithm of probability of the generalstate, with the reverse sign, weighted with respect to every state ofthe system. The information may be recorded also as a mathemati-cal expectancy:

I = M[–log pi]. (10)

If the states of the system have different probabilities, the infor-mation, by the different communications, will be unequal. The fullestinformation is borne by communications about events which are theleast probable, a priori. For example, the communication to the effectthat the given reservoir rock has a porosity of 0.2 carries less infor-mation than the communication that the porosity of that rock is 0.5.

The entropy expresses indefiniteness of the state of a system, in thetheory of information, even as in thermodynamics. The entropy of asystem increases with increasing indefiniteness of the system. In a fullydefinite system (of which everything is known or which has the highestorderliness), the entropy equals zero. Chaotic state, disorderliness, lackof sorting, heterogeneity, or indefiniteness of the state increase theentropy of the system.

Consequently, the magnitude of entropy, which expresses the degreeof heterogeneity or indefiniteness, may be used in geologic studies andgraphic representations of heterogeneity of various geologic objects(Buryakovsky, 1968). For example, in facies maps, zones with charac-teristically high entropy (low information capacity), i.e., the zoneswhere different facies are mixed in approximately equal proportions,will differ from areas occupied by similar facies high in informationcapacity (smaller entropy). In the case of a zone containing one faciesonly, the entropy of the system equals zero and the information is ata maximum (Miller and Kahn, 1965).

Relative entropy is the ratio of determined to the maximum entropy,obtained for a given number of components:

H p p Hr i ii

N

=

=

∑– log / max1

(11)

where pi is the fraction (probability) of the i-th component of theN-component system.


The maximum possible entropy Hmax is determined as follows:

H N N Ni

N

max – / log / log= ==∑1 1

1(12)

The relative entropy, Hr, even as H entropy, becomes the maximumHmax, when all the component fractions are equal to each other, andthe minimum, when one of the components is certain and the othersare impossible.

The relative entropy, Hr, is convenient in quantitative studies andgraphic representations of relative heterogeneity of multicomponentsystems. It may be employed in investigations of heterogeneity ofsediments (or rocks), areally or in vertical sections, as well as instudies of ternary mixtures encountered in lithology, geochemistry, andother geologic sciences. A triangular diagram of a three-componentmixture, with plotted isolines of relative entropy, is presented in Figure10-9. A point within the triangular field, in the baricentric coordinates,will be represented by a number expressing the degree of heterogeneityof the system. The maximum relative entropy (1) lies in the center ofthe triangle and the minima (zeros) at the apexes.

Figure 10-9. Relative entropy of ternary mixture.


A quantitative rating of the degree of heterogeneity of different typesof clastic rocks can be made by using this triangle. The classificationdiagram of clastic rocks, according to Pustovalov (1940), includes 8major types of rocks (Figure 10-10). The most homogeneous ones(sandstone, siltstone, and shale) have the relative entropy of 0.45. Theleast homogeneous rocks (silty-clayey sandstone, sandy-clayey andclayey-sandy siltstone, and silty-sandy shale) have the relative entropyof 0.78. Sandy and clayey chlidolites have the relative entropy of 0.83;

Figure 10-10. Classification of Kirmaku (a, c) and Podkirmaku (b, d) clasticrocks in the southeastern (a, b) and northwestern (c, d) Apsheron Archipelago(Modified after Buryakovsky, 1985a). I—Sand, II—clayey-silty sand, III—loam,IV—silt, V—unsorted sediments, VI—clayey loam, VII—sandy-silty shale,VIII—shale.


clayey-sandy chlidolites, 0.85; sandy loams and clayey loams, 0.90;and pure chlidolites (a mixture of equal proportions, by weight, ofsand, silt, and clay), about 1.

Thus, the rocks can be classified and rated quantitatively, on thebasis of degree of heterogeneity. A rock with the relative entropybelow 0.5 may be considered as a very homogeneous one, composedof grains of similar size, whereas the unsorted rocks have relativeentropy higher than 0.5.

In calculating the entropy, only the frequencies (probabilities) ofevery constituent of the system are taken into account; absolutemagnitudes of the constituents are not considered. This may be ashortcoming, in case the properties of the mixture depend upon theabsolute magnitudes of its constituents (or of their ratios), which doesoccur in rocks; for example, where porosity of the mixture dependsnot only on the proportions of all fractions in the rock, but also onthe mean diameter of the grains in every fraction. In such a case, themost heterogeneous rocks, with the lowest porosity, will not fall inthe center of the triangle but will be somewhere between the fractionswith the largest and smallest mean diameters of the grains.

The merit of rating the indefiniteness or heterogeneity of a realsystem by means of its entropy lies in its quantitative expression byone single number and not by several numbers (three or even more).

The use of the relative entropy has another advantage, because itsmagnitude has the upper and lower limits (0 ≤ Hr ≤ 1). The otherparameters of heterogeneity of a system (range of variation, scattering,variations coefficient, etc.) have no upper limit, so that the use of therelative entropy makes it possible to rate the degree of heterogeneityof a rock without resorting to comparisons with others.

As an example of application of the relative entropy in ratingheterogeneity of the rocks, the grain-size composition of rocks of theKala Suite of the Apsheron oil- and gas-bearing region was analyzed.The most homogeneous section of this suite was found in theGum Deniz and Turkyany areas and the least homogeneous, in theKarachukhur-Zykh area and in the southeastern part of the ApsheronArchipelago. Upon consideration of the “interior” heterogeneity (ormicroheterogeneity) of the individual types of rocks determined fromcores (see Figure 10-9), the relative entropy is found to increase. Ageneral increase of the relative entropy, however, has no significanteffect on variations in relative entropy of the whole area.


Heterogeneity in individual deposits can be extended to the arealvariations in lithology. Entropy isolines are plotted on the map andthen interpreted to decipher the paleogeography of the area, sedimen-tation scenario, and subsequent diagenetic and catagenetic alterationsof sediments and rocks. For example, homogeneity of the Kala Suiterocks increases with increasing depth of sedimentation (under a calmhydrodynamic regime) (Table 10-16).

The relative entropy progressively decreases with the burial depthof the Karachukhur–Zykh–Gousany–Gum Deniz–Turkyany anticlinaltrend; the entropy increases along the Gyurgyany Deniz–Chalov Adasi–Palchygh Pilpilasi–Neft Dashlary anticlinal trend (offshore oil and gasfields of the Apsheron Archipelago). There is an inverse depth-entropyrelationship in the individual areas.

As far as the basic relationship in spatial distribution of the Hr ascriteria of heterogeneity of the sediments is concerned, there is adecrease in Hr and a better sorting of the sediments with increasingdepth. This relationship is typical for both the individual anticlinalzones and for the entire area of sedimentation during the Kala time.

Table 10-16Evaluation of Heterogeneity Entropy for the Kala Suite Reservoirs

AverageNumber of Depth, without micro- with micro-

Area Reservoirs m Entropy heterogeneity heterogeneity

Gyurgyany Deniz 156 2,160 1.580 0.72 0.83Chalov Adasi 120 2,720 1.933 0.88 0.92Palchygh Pilpilasi 159 1,130 1.699 0.77 0.87Neft Dashlary 170 1,010 1.904 0.87 0.90Karachukhur-Zykh 164 2,790 1.816 0.83 0.91Gousany 180 4,010 1.597 0.73 0.80Gum Deniz 125 3,500 1.410 0.64 0.65Tyurkyany 165 3,760 1.423 0.65 0.67Kala Suite,as a whole 746 — — 0.71 0.76

Relative Entropy


Thus, the conclusions can be summarized as follows:

1. Entropy of a real system may serve as a criterion of its hetero-geneity. This makes it possible to use entropy as a quantitativerating of heterogeneity of rocks and formations.

2. Relative entropy is a convenient method of measuring hetero-geneity of rocks and can be calculated using natural logarithmictables.

3. Heterogeneity of different rocks, in relation to their grain-sizedistribution, and heterogeneity of formations, in relation to theproportions of different rock types in the section, may be ex-pressed as entropy.

4. In studying degree of heterogeneity of rocks, the concept ofentropy may prove to be useful not only in the field of litho-logy and petrography, but also in the field of geochemistry andhydrochemistry.

ANISOTROPY OF STRATIFIED ROCKS

The migration and accumulation of hydrocarbons in stratified hetero-geneous deposits differs from those in massive homogeneous reservoirs.The fluid motion in various directions is subject to a considerableanisotropy, because the permeability of the stratified rocks is dependenton the direction of flow. One needs to determine the anisotropycoefficients for such rocks to simulate hydrodynamic scenarios.

The first purpose of this study was to improve analytical methods,whereas the second one was to determine the anisotropy coefficientsfor a particular field in the South Caspian Basin on the basisof geologic data (stratigraphic section) (Buryakovsky, 1974b; Buryakovskyand Dzhafarov, 1980a).

For a three-component medium composed of layers of good-qualityreservoir rocks, low-quality reservoir rocks, and non-reservoir rocks,the permeabilities can be defined as follows:

k2 = α k

1 and k

3 = βk

1(13)

where k1, k2, and k3 are the permeabilities of the above three classesof rocks, respectively, whereas α and β are empirical factors less than 1.

The initial equation for the permeability parallel and perpendicularto the bedding, using Equation 13, are as follows:


k k h k h k h h h h

k h h h h h h

= + + + +

= + + + +

( ) / ( )

( ) / ( )

1 1 1 2 1 3 1 2 3

1 1 2 3 1 2 3

α β

α β(14)

and

k h h h h k h k h k

k h h h h h h

⊥ = + + + +

= + + + +

( ) / ( / / / )

( ) / ( / / )

1 2 3 1 1 2 2 3 3

1 1 2 3 1 2 3

α β

α β(15)

The anisotropy coefficient can be expressed as follows:

λ

α β α β

=

= + + + + + +

⊥( / )

[( )( / / )] / ( )

/

/

k k

h h h h h h h h h

1 2

1 2 3 1 2 31 2

1 2 3

(16)

or in terms of the relative thicknesses,

λ α β α β= + + + +[( )( / / )] /h h h h h h10

20

30

10

20

30 1 2 (17)

where hio = hi/∑hi and the hi

o is the relative frequency of a layer havinga permeability ki.

The last two equations show that the anisotropy coefficient isdependent on the proportion of strata with a given thickness and onthe empirical factors. Inasmuch as the anisotropy coefficient is dimen-sionless, it is dependent on the ratios of permeabilities and not on thepermeabilities themselves.

The empirical factors α and β are constant for each particularformation or group of similar formations as a whole. For example, theBalakhany Suite of the Bakhar Field consists of five productiveformations, where k1ave = 61 mD, k2ave = 5 mD, and k3ave = 0.5 mD.Therefore, α = 0.082 and β = 0.0082. The values of ki (i = 1, 2, 3)and α and β average out the theoretical values of λ. Measurementsof λ, however, show that theoretically the thicknesses of the bandshave the main effect (Buryakovsky, 1974b); this is also evidenced bythe experimental and field data presented here. Therefore, if only thehi for each borehole is known, one can still calculate the anisotropycoefficients from Equations 16 or 17.


This conclusion can be extended to multi-component and multi-layermedia, as shown by the following formulas:

λ α β ω α β ω= + + + + + + + +[( )( / / / )] /h h h h h h h hn n10

20

30 0

10

20

30 0 1 2K K

or

λ α α=

==∑∑ ( ) ( / )

/

h hi i ii

n

i

n0 0

11

1 2

(18)

The median and geometric-mean permeabilities are also used some-times. From Equation 13, for a three-component multi-layer medium, thegeometric-mean permeability (kgeom) is equal to:

k k k

k h h h h h h

geom =

= + + + +

⊥( )

[( ) / ( / / )]

/

/

1 2

1 1 2 3 1 2 31 2α β α β

(19)

or in terms of the relative thicknesses,

k k h h h h h hgeom = + + + +1 10

20

30

10

20

30 1 2[( ) / ( / / )] /α β α β (20)

The geometric-mean permeability differs from the anisotropy coeffi-cient in being dependent not only on the relative proportions of thevarious strata and the empirical coefficients, but also on the meanpermeability (the base permeability). Thus, kgeom retains the dimensionsof a permeability.

In the case of a multi-component multi-layer medium, kgeom isequal to:

k k h he ii

n

i

n

geom av=

==∑∑ ( ) / ( / )

/

α α10

10

11

1 2

(21)

where kave is the average (mean) permeability of the reservoirs. Thehi

0 in Equations 18 and 21 is the relative frequency of each empir-ical factor.


The Balakhany Suite of the Upper Productive Series in the BakharField was used as an example to show how the anisotropy was esti-mated. For this formation, 356 determinations were made of permea-bility from electric resistivity logs, on the basis of the observedrelationship between the permeability and the formation resistivityindex for the oil- and gas-bearing reservoir rocks, which have aresidual water saturation of 35% on the average. Inasmuch as theserocks lie at a considerable depth (3,500–4,500 m), corrections weremade for the pressure and temperature. The permeability data wereprocessed in order to determine the anisotropy coefficients, averagepermeability (Table 10-17), and variation of anisotropy (Figure 10-11).

As mentioned previously, the section of the Productive Series in theApsheron Peninsula and adjacent offshore areas of the Caspian Seais of rhythmic (cyclic) nature. At the bottom of the rhythms (cycles)there are thick and persistent reservoir-rock beds with shale interbeds,whereas the reservoirs at the top are thin-bedded.

Some units in the Balakhany Suite can be grouped on the basis ofsimilarity in the thicknesses of individual layers. For example, one cancombine units at the bases of the sediment rhythms into a single group(Units VII, VIII, and X), which includes the thick layers (thicknessranges from 3 to 20 m; average = 8 m). The top Units VI and IX,which are made up of the thin layers (thickness ranges from 2 to 12 m;average = 5 m), form another group. In the first case (thick beds) theanisotropy coefficients are higher (λ = 4.4), whereas λ = 3.0 for thesecond case (thin beds). The mean anisotropy coefficient for the entireBalakhany Suite is 3.9.

The value of λ allows one to determine the sequence of thicknessesof beds from thinner to thicker: the sequence can be based on aniso-tropy data obtained from cores examined in the laboratories.

Von Engelhardt (1964) presented results for the Dogger sandstonesof Valanginian and Liassic age (oil and gas fields in the northern partof Germany). In all cases, the permeability parallel to the bedding washigher than the permeability perpendicular to the bedding. On theaverage, the k k/ ⊥ ratio was 1.9, which gives a mean anisotropycoefficient of 1.38.

Mirchink’s (1948) data for sandstones in various USA fields showthat the anisotropy coefficient increases from 1.3 to 1.86 with a meanof 1.71 as the permeability increases from 3 to 770 mD. Generally,the median permeability of the clastic rocks varies from 10 to 100 mD,whereas the anisotropy coefficient fluctuates around 1.5.


Tab

le 1

0-17

Th

ickn

esse

s an

d P

erm

eab

ilit

ies

Use

d i

n C

alcu

lati

ng

An

iso

tro

py

Ave

rage

Gro

ss T

hick

ness

,A

vera

ge P

erm

eabi

lity,

Per

mea

bilit

y,m

mD

mD

Res

ervo

ir R

ock

No

n-

Res

ervo

ir R

ock

Non

-V

aria

tion

of

Hig

hLo

wre

serv

oir

Hig

hLo

wre

serv

oir

Ani

sotr

opy

Ani

sotr

opy

Un

itQ

ua

lity

Qu

alit

yR

ock

Qu

alit

yQ

ua

lity

Ro

ckk ||

k ⊥λ

Vλ

VI

2669

105

885

0.5

141

0.89

3.8

0.34

VII

2524

160

765

0.5

119

0.88

4.6

0.22

VII

I40

5716

558

50.

511

71.

153.

70.

30IX

3136

195

235

0.5

116

0.83

2.6

0.31

X51

1916

462

50.

512

51.

064.

80.

21


Figure 10-11 shows that there is a numerical sequence in theanisotropy coefficients, which ranges from microanisotropy (laboratorycore data) (the median value of λ = 1.5) to macroanisotropy (loggingdata) (the median value of λ = 3 for thin-bedded formations and λ = 4.4for thick-bedded ones). (See theoretical analysis by Buryakovsky, 1974b.)

The λ values may be useful in development and production of oiland gas fields, and of value in elucidating the history of formationand accumulation of oil and gas, and destruction of fields.

PERMEABILITY OF RESERVOIR ROCKS

Experimental and field studies of reservoir-rock properties at reser-voir conditions are of great importance. Successful development of oiland gas fields depends largely on the knowledge of such reservoir-rock properties as porosity and permeability. Although permeability isone of the most important parameters describing a porous medium,

Figure 10-11. Statistical distribution and cumulative probability of permeabilityanisotropy. 1—Lower portions of sedimentary rhythms (Units VII, VIII and X); 2—upper portions of sedimentary rhythms (Units VI and IX); 3—average value forBalakhany Suite; 4—average value for microanisotropy from experimental data.


its measurement normally requires a rock sample that is of a suitablesize (e.g., 5 cm × 5 cm × 5 cm) and has a simple geometric shape(e.g., a cylinder or a cube). The geometric requirements of a samplefor measuring the other petrophysical properties of rocks, such asporosity, pore-size distribution, grain-size distribution, and specificsurface area, are less restricted. Correlations between the permeabilityand other easier-to-measure quantities, therefore, have been studiedextensively both experimentally and theoretically. The most oftenreported correlation is that between permeability and porosity (e.g.,Samedov and Buryakovsky, 1957; Buryakovsky, 1959; Buryakovskyand Samedov, 1961; Chilingar, 1964).

Theoretical and Empirical Equations Relating Porosity,Permeability, and Surface Area

In a reservoir modeled by a bundle of capillary tubes, the rate offlow q is given by the Hagen–Poiseuille equation:

q = Nπrc4∆p/8µL

c(22)

where q is the volumetric flowrate, cm3/sec; N is the number ofcapillaries; rc is the capillary radius, cm; ∆p is the differential pressureacross the capillaries, dyne/cm2; µ is the fluid viscosity, poises, andLc is the length of capillaries, cm.

The Darcy equation for rate of flow q is:

q = kA∆p/µLc

(23)

where q is the volumetric rate of flow, cm3/sec; k is the permeability,darcys; A is the total cross-sectional area, cm2; ∆p is the differentialpressure, atm; µ is the fluid viscosity, cP, and Lc is the length of theflow path, cm.

If, instead, viscosity is expressed in poises and differential pressurein dynes/cm2, then:

q = 9.869 × 10–9k∆p/µLc

(24)

The porosity φ of this bundle of capillary tubes may be expressedas the capillary volume Vc per unit of bulk volume, Vb:


φ = Vc/ V

b = Nπr

c2L

e/AL

c = Nπr

c2/A (25)

Thus, the total cross-sectional area A of the bundle of tubes is:

A = Nπrc2/φ (26)

The average capillary tube radius rc may be found by combiningEquations 22, 23, and 26:

rc = 2(2k/φ)1/2 (27)

The surface area per unit of pore volume sp is given by:

sp = N 2πr

cL

c/Nπr

c2L

c = 2/r

c(28)

On substituting the value of the capillary tube radius from Equa-tion 27 into Equation 28, the specific surface area sp can be ex-pressed as:

sp = (φ/2k)1/2 (29)

Solving Equation 29 for permeability yields:

k = φ/(2sp2) (30)

Inasmuch as a porous rock is more complex than a bundle ofcapillary tubes, a constant Kcf is introduced. Thus, the equation forpermeability becomes:

k = φ/(Kcf s

p2) (31)

Equation 31 is the familiar Kozeny–Carman equation (see Carman,1937). Carman (1937) noted that the constant Kcf is actually a complexcombination of two variables: shape factor for pores shf and tortuosityfactor τ:

Kcf = (s

hf)(τ) (32)

Tortuosity is equal to the square of the ratio of the effective lengthLe to the length parallel to the overall direction of flow of the porechannels L:


τ = (Le/L)2 (33)

Chilingar et al. (1963) developed the following relations for sand-stones: (a) shf = 1.55 Kcf

0.455; (b) shf = 2.24 Fφ; (c) Kcf = 2.24 (Fφ)2.2;and finally, (d) sp = (2.11 × 105)/(F 2.2 φ1.2k)1/2 (empirical relationship),where permeability k is in millidarcys; sp is the specific surface areaper unit of pore volume in cm2/cm3; τ= (Fφ)1.2; F = Ro/Rw, where Rois the electrical resistivity of a formation 100% saturated with forma-tion water and Rw is the formation water resistivity. As far as carbon-ates are concerned, the “problem” of establishing correlation betweenporosity and permeability was solved by Chilingarian et al. (1992) byintroducing two additional variables: (1) irreducible liquid saturationand (2) specific surface area, which incorporates the influence of micro-fractures (very small, <1%, on porosity and very large on permeability).

Kozeny–Carman constant Kcf is a function of both the shape of eachparticular pore tube and its orientation relative to the overall directionof fluid flow.

Kotyakhov (1949) developed the following formula for surface areaper unit of bulk volume (cm2/cm3) of sandstones:

sb = 7,000(φ3/k)1/2 (34)

where φ is the fractional porosity and k is the permeability expressedin darcys.

This equation is another version of the Kozeny–Carman equation:

k = (108φ3)/(shfτs

b2) (35)

assuming that for a consolidated rock: shf = 2 and τ = 1, which, in effect,means that the rock sample is equivalent to a bundle of capillary tubes.

It is clear that Kotyakhov’s (1949) equation is an oversimplificationfor rock samples. If values of τ = 1.25 and shf = 2.5, representativeof unconsolidated sands or calcarenites, are inserted in Equation 35, thenthe surface area may be expressed as:

sb = 5,650(φ3/k)1/2 (36)

where sb is the surface area in cm2 per unit (cm3) of bulk volume; φis the fractional porosity; and k is the permeability in darcys.


Equation 36 should give a good approximation of surface area forunconsolidated sediments, but should not be used for consolidated rocks.

Shirkovskiy (1969) proposed the following formula for determiningspecific area (surface area/unit bulk volume), sb, of fragmental rockwithout interstitial water, in cm2/cm3:

s kb = φ τ3 2 1 2 1 22/ / // ( ) (37)

where φ is the fractional porosity; k is the permeability expressed inperm. units (permeability in c.g.s. units; 1 darcy = 1.02 × 10–8 perm.);and τ is the tortuosity.

The specific surface area in cm2/cm3 with correction for interstitialwater is equal to:

sbw

= sb(1 – S

w)3/4 (38)

where Sw is the interstitial water saturation, fractional.The following empirical equation was developed for sandstones by

Schlumberger, based on the work of Kozeny (in Monicard, 1980, p. 83):

k1/2 = 250(φ3/Swi

) (39)

where k is in mD, and φ and irreducible water saturation Swi arefractions. The last two variables can be deduced from logs.

According to the Bureau of Mines—Continental Oil Co.—Shell OilCo. (in Monicard, 1980, p. 83), Kozeny’s equation can also be ex-pressed as follows:

k = φ3/[5.0sg2(1 – φ)2] (40)

where sg is the specific surface area per unit of grain volume, k is inmD, and φ is fractional.

Buryakovsky and Samedov (1957, 1961) proposed the followingformula for the specific surface area per unit of grain volume of rockconsisting of equal-size spheres:

sg = A/V = Nπd 2(1 – φ)/V

sph = 6Nπd 2(1 – φ)/Nd 3π = 6(1 – φ)/d (41)

where A is the surface area in cm2; V is the bulk volume of rock incm3; Vsph is the total volume of spheres; N is the number of spheres


per volume unit; d is the diameter of sphere in cm; and φ is theporosity, fractional.

If spheres (grains) are unequal in size, then the specific surface areaof a such rock may be calculated using the following formula:

sg = [6(1 – φ)/100]∑(C

i/d

i) (42)

where di is the average diameter of grains which constitute an i grain-size fraction with weight content of Ci in wt %. (Total grain-size distri-bution is expressed as follows: C1 + C2 + … + Ci + … + Cn = 100%).

Inasmuch as the main influence on the specific surface area iscaused by the clay content, Ccl , the empirical equation developed forthe Productive Series reservoir rocks is as follows:

sg = 75(1 – φ) C

cl + 532(1 – φ)(75 C

cl + 532)(1 – φ) (43)

Assuming that φave = 0.25, the average correlation between sg andCcl will be as follows:

sg = 56.3C

cl + 400 (44)

Several empirical relationships were developed for the ProductiveSeries reservoir rocks of Azerbaijan (see Buryakovsky, 1985a). Rela-tionships between the permeability, k, and clay content, Ccl, for variousrocks are as follows:

Sand and silt: lgk = 7.0 – 0.222Ccl

(45)

Shaly silt: lgk = 7.5 – 0.182Ccl

(46)

Chlidolite: lgk = 3.8 – 0.200Ccl

(47)

A more complex relationship between the permeability and clay cementcontent and carbonate cement content was developed as follows:

k = (6,700 – 130Ccl)exp[–(0.000172C

cl2 – 0.01172C

cl – 0.1)C

carb] (48)

where Ccl is the clay cement content in wt % and Ccarb is the carbonatecement content in wt %.

Another relationship among the permeability, porosity, clay cementcontent, and carbonate cement content may be expressed as follows:


lgk = 3.935 + 0.02φ – 0.075Ccarb

– 0.05Ccl

(49)

with a correlation coefficient of multi-variable regression of 0.8.

Determination of Permeability from Resistivity Logs

Resistivity of rocks is measured by E-logs (combination of thenormal and lateral resistivity logs and the spontaneous potential, SP,curve). The method of the multi-lateral electric sonding, using severalsonds of different size, was used to obtain the true resistivity. Theinduction log and laterolog were used also. The electric resistivity canbe used to estimate porosity, water saturation and, in some cases,permeability. The method of determining permeability from resistivitydata is based on the following assumptions.

The content of residual (irreducible) water in oil reservoirs dependson the content of very fine-grained material in the reservoir rocks.High residual water saturation generally characterizes very fine-grainedand clayey sands and siltstones. The amount of residual water isconsiderably lower in the coarse-grained sands and sandstones. Highcontent of residual water in fine-grained, low-permeability rocks is dueto the large specific surface area of pore space and by the presenceof subcapillary pore channels in which the water is retained bycapillary force. The amount of residual water, Sw,r, can be calculatedfrom the following formula:

Sw,r

= sgτ

w/φ (50)

where sg is the specific surface area per unit of grain volume (in cm2/cm3), φ is the porosity (in decimal fractions), and τw is the thicknessof water film on pore and channel walls (in microns). The sg valuecan be determined from Equation 42.

Taking into account the Kozeny–Carman equation, a theoreticalrelationship between the permeability, k, porosity, φ, and the specificsurface area per unit of grain volume, sg, is expressed by the follow-ing equation:

sg = (φ3/2k)1/2 (51)

If porosity is expressed in percent, permeability in millidarcies, andspecific surface area in cm2/cm3, then:


sg = 220(φ3/k)1/2 (52)

For sands and sandstones of the Productive Series of the NeftDashlary Field in the South Caspian Sea, the following formula wasobtained on the basis of experimental data (Buryakovsky, 1959, 1960):

sg = 340(φ3/k)1/3 = 340φ/k1/3 (53)

For the Karagan and Chokrak sands and sandstones of the Groznyregion of North Caucasus, the following relationship was obtained:

sg = 140(φ3/k)1/3 (54)

A relationship can, thus, be established between the residual watersaturation and permeability, by combining Equations 50 and 53:

Sw,r

= 340τw/k1/3 (55)

Equation 55 is represented as a graph in Figure 10-12. A similarrelationship of water saturation to permeability is given by M. Muskat,Park J. Johns, and others (see Pirson, 1961).

On the basis of theoretical and experimental studies, the watersaturation, Sw, and the formation resistivity index, F′ are related as follows:

F ′ = (100/Sw)n (56)

where the formation resistivity index F′ equals to the ratio of trueresistivity of oil-saturated reservoir rock, Rt , at Sw% of water saturationto resistivity of the same rock, Ro, at 100% water saturation.

For the sands of the Productive Series of the Neft Dashlary Fieldthe saturation exponent n equals 2, which was determined on the basisof laboratory studies and logs. Therefore,

F ′ = (100/Sw)2 (57)

Thus, a relationship can be established between the permeability andthe resistivity index, by substituting Sw from Equation 57 into Equation55 (see Figure 10-13):

k = 40τw

3(F ′)1.5 (58)


Figure 10-12. Interrelationship among the residual-water saturation Sw,permeability k, and water-film thickness τw.

Figure 10-13. Calculated interrelationship among the resistivity index F ′,permeability k, and water-film thickness τw.


An error in calculation of the permeability is dependent on the errorin determining the parameters F ′ and τw. The relative error of afunction equals the product of the maximum absolute error of theargument times the derivative of logarithm of the function. Thus, thedifferential ratio for errors using Equation 58 is as follows:

∆k/k = 1.5(∆F ′/F ′) + 3(∆τw/τ

w) (59)

Thus, the relative error of permeability calculated using Equation58 is 1.5 times larger than the relative error of F ′ and three timeslarger than the relative error of τw (the error introduced due to inac-curate determination of the thickness of water film is two times greaterthan the error due to inaccurate determination of parameter F ′).

Equation 58 was tested experimentally for siliciclastic rocks ofthe Productive Series of the Neft Dashlary Field on the basis of acomparison of the resistivity index F ′ calculated using the electric logsof oil-saturated rocks with permeability of these rocks determined inthe laboratory and/or from the productivity index of the wells. A totalof 48 determinations were made, which were plotted in Figure 10-14.The experimental data are concentrated largely in a band correspond-ing to a value τw of 0.4µ, which is close to the actual thickness of thewater film.

The importance of increasing the water-film thickness becomesapparent from the following discussion. The more water-saturatedrocks (τw ≥ 0.5µ) compared to the less water-saturated rocks (τw ≤0.2µ), with identical permeabilities, have a lower resistivity index ora lower true resistivity. This agrees with the idea of the dependenceof true resistivity on the water saturation. On the other hand, the morewater-saturated rocks have greater permeability than the less water-saturated rocks at equal resistivity index.

Taking the value τw = 0.4µ for the limit below which the water isimmobile (irreducible), and τw = 0.6µ for the limit above which thewater is flowing, the following holds true:

1. If the resistivity index and absolute permeability data points aredistributed above the curve with τw = 0.4µ, then the water-freeoil should be obtained regardless of the value of resistivity index.Thus, the absolute permeability is equal to the permeability forthe pure oil phase.


2. If the data points are distributed between the curves with τw =0.4µ and τw = 0.6µ, then oil may have a water-cut. This is moreprobable with increasing proximity to the curve with τw = 0.6µ.

3. If the data points are located below the curve with τw = 0.6µ,then there is a greater probability of obtaining water without oil,regardless of the resistivity index.

Equation 58 was used for determination of permeability of thereservoirs at the Neft Dashlary Field.

The average thickness of the water film was determined by usingthe following equation:

τw = S

wφ/s

g(60)

The calculated average thicknesses of the water film are presentedin Table 10-18.

Figure 10-14. Actual interrelationship among the resistivity index F ′, permea-bility k, and water-film thickness τw.


The data on the residual water saturation, porosity, and specificsurface area were obtained from laboratory and field studies. The dataof the true resistivity of the saturated rocks were determined fromlaterologs. The data on the resistivity of the water-saturated rocks Rowere calculated by assigning a value of porosity and formation waterresistivity Rw according to the equation:

Ro = R

wφ–1.6 (61)

which was determined experimentally for siliciclastic rocks of the NeftDashlary Field.

At a constant salinity of the formation water both inside and outsidereservoir limits, the resistivity of rocks outside of the field margin(where there is 100% water saturation) may be taken as Ro. Thepermeability was determined from the resistivity index and a selectedthickness of the residual-water film (Figure 10-13). For an approximatedetermination of permeability, τw was assumed to be equal to 0.40–0.45µ. More than 290 determinations of permeability (average) weremade for various lithological units. Permeability was also determinedfrom cores and well testing (Table 10-19).

SURFACE ACTIVITY OF ROCKS

Surface activity characteristics of more than 860 cores obtained fromthe Productive Series of Azerbaijan and adjacent offshore areas weredetermined. The cores from Baku Archipelago, South Apsheron Offshore

Table 10-18Estimation of Thickness of Water Film on Various Rocks

Specific AverageResidual Oil Surface Thickness ofSaturation, Porosity, Area, sg Water Film,

Suite % % cm2/cm3 µ

KS 33 23.6 1,600 0.48PK 17 23.3 1,000 0.39KaS 23 23.4 1,200 0.45


Zone and Lower Kura Depression were tested. Almost 4,000 analysesof sands, silts, and shales were made (Buryakovsky et al., 1986a).

Dependence of Surface Activity of Rocks onGrain Size and Mineralogy

The main parameters characterizing the surface activity of rocks arethe cation-exchange capacity Q100 (in mg-equivalents of exchangeableions per 100 g of rock) and diffusion/adsorption factor Ada (in mV).The reservoir-rock properties studied are as follows: Csh = shale/clay

Table 10-19Permeabilities of Productive Series Rocks

Core/Well TestUnit or Number of Number of Permeability,Suite Wells Beds Range Average mD

Upper Productive Series

I′ 1 1 — 360 —I 1 2 320–350 335 —IV 1 8 240–2,000 965 —V 1 3 360–700 555 —VI 2 3 190–750 430 —VII 1 1 — 670 —VIIa 3 6 140–930 380 —VIII 4 13 160–2,100 525 —IX 4 8 190–1,900 710 —X 4 12 160–1,200 485 —“Pereryv” 4 13 220—1,800 600 —

Lower Productive Series

NKP 7 17 220–1,600 710 600KS 14 16 90–1,250 310 300PK1 43 58 130–2,500 1,150 950PK2 28 37 160–2,500 1,060 850KaS1 21 38 80–1,000 690 400KaS2 21 28 80–1,100 445 250KaS3 11 26 60–1,000 340 350

Permeability, mD


content in wt %; Ccarb = carbonate cement content in wt %; φ—porosity in %; k—permeability in mD; relative shale/clay content η= (1 – φ)Csh/[(1 – φ)Csh + φ]. Figure 10-15 shows the statistical distri-butions of reservoir-rock properties and surface activity parameters.

At first the surface activity parameters were determined for differentrock types. Table 10-20 gives the results of data processing of Adaparameter taking into consideration the grain size. This table allows(1) approximate determination of lithology in studied sections,(2) estimation of an average Ada based on lithology, and (3) analysisof Ada distribution in all rocks. The same types of rocks in offshoreareas have lower Ada than in onshore areas. This difference is largelydue to the grain size: sands—approximately 2.1 to 4.2 times lower;silts—1.2 to 1.7 times lower, and argillaceous rocks—1.1 times lower.

The grain-size characteristics alone, however, do not determine thesurface activity parameters. The mineralogy is also of great importance(Buryakovsky, 1985a). The rocks of the North Baku Archipelago andSouth Apsheron Offshore Zone are composed of quartz and quartz-feldspar grains (these rocks belong to oligomictic and mesomicticclasses, Table 10-18). The rocks of the Lower Kura Depression belongmainly to polymictic and graywacke classes (Table 10-18) having alow quartz content, high feldspar content, and different rock fragments(clayey, flinty, effusive). Figure 10-16 shows a tendency of Q100 andAda parameters to decrease with increasing quartz content. Close tozero Ada is predicted in oligomictic rocks with quartz content higherthan 75%. With decreasing quartz content to 30–40% and increasingfeldspar content to 50–60%, Ada increases up to 50 mV.

In addition to grain size and mineralogical composition, the surfaceactivity is greatly influenced by the content and type of clays, whichare present mainly as a cementing material in reservoir rocks.

The X-ray analyses of core samples from the Lower Kura Depres-sion are correlatable with the surface activity of these rocks. The mainclay minerals are: montmorillonite (40% to almost 100%) and illite(0 to 35%); the content of kaolinite, chlorite and mixed-layeredminerals is approximately equal to 0 to 15–20%. The average contentsof clays are: montmorillonite, 75%; illite, 12%; kaolinite, 5%; chlorite,4%; and mixed-layered, 4%.

The difference in content of montmorillonite and other clay mineralsin these two regions is quite small, except for clays present in the



Figure 10-15. Histograms of the surface activity and other reservoir-rock properties of the Productive Series (Modified after Buryakovsky et al.,1986a). 1—Baku Archipelago and South Apsheron Offshore Zone, 2—LowerKura Depression.


Tab

le 1

0-20

Dis

trib

uti

on

of

Ad

a P

aram

eter

in

th

e R

ock

s o

f B

aku

Arc

hip

elag

o a

nd

Lo

wer

Ku

ra D

epre

ssio

n

Bak

u A

rchi

pela

go (

N*

= 1

59)

Low

er K

ura

Dep

ress

ion

( N*

= 1

96)

Fre

quen

cy (

in %

) of

Ada

Int

erva

lsM

ean

Fre

quen

cy (

in %

) of

Ada

Int

erva

lsM

ean

(in

mV

)A

da,

(in

mV

)A

da,

Typ

e of

Roc

k0–

1515

–30

30–4

545

–60

>60

Σm

V0–

1515

–30

30–4

545

–60

>60

Σm

V

Coa

rse

sand

3.8

——

——

3.8

7.5

——

——

——

—M

ediu

m/f

ine

17.6

3.1

——

—20

.79.

71.

58.

73.

1—

—13

.324

.2sa

nds

San

dy l

oam

5.7

3.8

——

—9.

513

.51.

58.

75.

61.

0—

16.8

28.0

Chl

idol

ite

——

——

——

—1.

56.

12.

61.

0—

11.2

26.6

San

dy s

ilt

11.3

0.6

——

—11

.98.

3—

1.5

4.6

0.5

—6.

635

.1S

ilt

4.4

11.3

3.2

——

18.9

21.5

—1.

50.

50.

5—

2.6

31.5

Cla

yey

silt

0.6

7.6

12.6

0.6

—21

.430

.90.

58.

718

.411

.20.

539

.438

.5L

oam

—0.

6—

——

0.6

22.5

—2.

11.

51.

50.

55.

638

.8S

andy

-sil

ty s

hale

——

2.5

5.7

1.3

9.5

50.3

——

—3.

61.

04.

655

.8S

hale

——

—3.

10.

63.

755

.0—

——

——

——

For

all

roc

ks43

.427

.018

.39.

41.

910

022

.45.

037

.436

.319

.32.

010

033

.9

N*

= n

umbe

r of

sam

ple s

.


Figure 10-16. Dependence of surface activity parameters on the mineralcomposition of rocks (Modified after Buryakovsky et al., 1986a). a—BakharField, b—Sangachal—Duvanny Deniz—Khara Zyrya Field.


reservoir rocks. The montmorillonite content of the clay cement ofreservoir rocks of the Lower Kura Depression is almost twice higherthan in the reservoir rocks of the Baku Archipelago and South ApsheronOffshore Zone. This explains why the surface activity of reservoirrocks of the Lower Kura Depression is higher than that in the offshoreareas. The Ada is practically the same when the montmorillonite contentin clays is the same. Thus, the above mentioned difference in the Adafor different rocks is due to different clay content. It is well knownthat the surface activity of montmorillonite clay is higher in com-parison with other clay minerals.

Relationships Between Reservoir-rock Propertiesand Surface Activity

Figures 10-17 and 10-18 show correlations between the reservoir-rock properties and surface activity in the form of average (orthogonal)regression lines in one graph for two regions: (1) Baku Archipelagoand South Apsheron Offshore Zone and (2) the Lower Kura Depres-sion. The correlation coefficient (r) is presented in all cases. Thecorrelation coefficients and criteria of their significance (three timesthe standard deviation sr) are presented in Table 10-21.

From 32 correlations studied, only one differs slightly from zero ata significance level α = 0.05 (when α = 0.01, this correlation issignificant). This correlation is the dependence of permeability on theclay content of the rocks of Lower Kura Depression. All other corre-lations are reliable enough and have a high statistical stability, i.e.,they are controlled by geological factors.

Comparison of data for both regions shows that correlations obtainedfor Baku Archipelago and the South Apsheron Offshore Zone are morestable in general. The relationships between the (1) weighted andrelative clay content and surface activity parameters (Q100 and Ada);(2) Q100 and Ada; and (3) porosity (φ) and Ada are the most reliablecorrelations in the offshore areas. Such correlations validate thedetermination of porosity and clay content using SP logs. The correla-tions among reservoir-rock properties are good and depend on thesimilarity in lithology.

In the Lower Kura Depression, correlations between the clay contentand porosity, on one hand, and surface activity parameters, on the other



Fig

ure

10-

17.

Cor

rela

tions

bet

wee

n re

serv

oir-

rock

pro

pert

ies

and

surf

ace

activ

ity p

aram

eter

s of

roc

ks o

f th

e P

rodu

ctiv

eS

erie

s (M

odifi

ed a

fter

Bur

yako

vsky

et

al.,

198

6a).

1—

Bak

u A

rchi

pela

go a

nd S

outh

Aps

hero

n O

ffsho

re Z

one,

2—

Low

erK

ura

Dep

ress

ion.

Cs

= C

sh =

cla

y/sh

ale

cont

ent;

Cc

= c

arbo

nate

con

tent

.


(and also between Q100 and Ada) are quite reliable. In general, however,these correlations are less reliable than in the offshore fields. Amongother correlations, relationship between porosity and permeability(controlled by a considerable effect of carbonate cement on bothparameters) is the most reliable. This is due to wide carbonate cementcontent range (up to 44%) in comparison with the rocks of the BakuArchipelago and South Apsheron Offshore Zone (up to 26%).

Figures 10-17 and 10-18 show that for the Lower Kura Depression,with the exception of permeability vs. clay content and porosity, allother correlations have a higher position on the figures with respectto the abscissa. This means that, for example, at the same clay content

Figure 10-18. Interrelationship among the reservoir-rock properties, surfaceactivity parameters, and relative clay content of the Productive Series rocks(Modified after Buryakovsky et al., 1986a). 1—Baku Archipelago and SouthApsheron Offshore Zone, 2—Lower Kura Depression. η = see p. 315.


ble

10-

21C

oef

fici

ents

of

Co

rrel

atio

n b

etw

een

Var

iou

s V

aria

ble

s an

d T

hei

r A

ccu

racy

Bak

u A

rchi

pela

go a

nd

Eq.

Type

of

Sou

th A

pshe

ron

Off

shor

e Z

one

Low

er K

ura

Dep

ress

ion

No.

Cor

rela

tion

N|r

|σ r

3σr

N|r

|σ r

3σr

1φ–

Cca

rb28

70.

192

0.05

70.

171

524

0.49

00.

033

0.09

92

k–C

carb

167

0.39

00.

060

0.18

025

40.

510

0.01

60.

140

3φ–

Csh

273

0.47

30.

047

0.14

143

00.

228

0.04

60.

133

4k –

Csh

165

0.44

20.

063

0.18

919

80.

131

0.06

20.

186

5φ–

η28

20.

574

0.04

00.

120

532

0.54

10.

031

0.09

36

k–η

162

0.55

50.

054

0.16

223

70.

570

0.04

40.

132

7k –

φ16

20.

530

0.05

70.

171

252

0.71

50.

031

0.09

38

Q10

0–C

sh24

60.

610

0.04

00.

120

284

0.52

20.

043

0.12

99

Ada

–Csh

163

0.71

80.

038

0.11

419

90.

256

0.06

60.

198

10Q

100–

η24

70.

626

0.03

90.

117

341

0.40

00.

045

0.13

511

Ada

–η16

10.

715

0.03

90.

115

252

0.39

70.

053

0.15

912

Q10

0–φ

243

0.43

30.

052

0.15

628

40.

381

0.05

10.

151

13A

da–φ

157

0.63

10.

048

0.14

420

30.

418

0.05

80.

174

14Q

100–

k15

00.

360

0.07

10.

213

151

0.35

10.

071

0.21

315

Ada

–k19

90.

576

0.06

70.

201

139

0.46

80.

066

0.19

816

Q10

0–A

da15

70.

670

0.04

40.

132

169

0.40

80.

064

0.19

2

De f

init

ions

of

v ari

able

s:

N =

num

ber

of t

e sts

r=

abs

olut

e v a

lue

of c

oeff

icie

nt o

f c o

rre l

atio

nσ r

= s

tand

ard

dev i

atio

nφ

= p

oros

ity

k =

pe r

me a

bili

ty

Csh

= s

hale

/cla

y c e

me n

t c o

nte n

tC

c arb

= c

arbo

nate

ce m

e nt

c ont

e nt

η =

re l

ativ

e c l

ay c

onte

ntQ

100

= c

atio

n-e x

c han

ge c

apac

ity

Ada

= d

iffu

sion

-ads

orpt

ion

para

me t

e r


the reservoir-rock properties (porosity φ and permeability k) anddiffusion-adsorption factor (Ada) in the Lower Kura Depression havehigher values than for the offshore areas. The curves of φ, k and Adavs. Q100 exhibit the same behavior (see Figure 10-15). The relation-ships between the surface activity parameters of rocks and theirporosity and clay content (Q100 and Ada vs. φ, Csh and η curves) andtheir relationships between each other (Q100 vs. Ada, and φ vs. Csh andη) are very useful.

The average regression lines were approximated by analyticalequations. Sixteen correlations between various variables (reservoir-rock properties and surface activity parameters) are presented in Table10-22. These include: permeability vs. porosity, weighted and relativeclay content, cation-exchange capacity and diffusion-adsorption param-eter. Included is also the effect of carbonate cement content on reservoir-rock properties. These equations can be generalized as the followingsingle model:

Fi(y) = a

i + b

if(x

i) + c

iψ(x

i) (62)

Empirical coefficients a, b, and c for two regions studied arepresented in Table 10-23.

Table 10-22Correlations Between Surface Activity Parameters and

Reservoir-Rock Properties

Eq. No. Equation Eq. No. Equation

1 φ = a3 – b3Ccarb + c3Ccarb2 19 Ada = a9 + b9√Csh

2 lgk = a4 – b4Ccarb 10 Q100 = a14 – b14η + c14η2

3 φ = a1 – b1lgCsh 11 Ada = –a15 + b15η4 lgk = a2 – b2Csh 12 lgQ100 = a10 – b10φ5 φ = a6 – b6η 13 Ada = a11 – b11φ6 lgk = a7 – b7η 14 Q100 = a12 – b12lgk

7 lgk = a5 + b5φ 15 Ada = a13 – b13lgk

8 Q100 = a8 + b8Csh 16 Ada = –a16 + b16√Q100

See Table 10-21 for definitions of variables


Conclusions can be summarized as follows:

1. Based on a large volume of experimental data, correlationsamong surface activity parameters, reservoir-rock properties, andgrain size and mineralogy of terrigenous rocks of the ProductiveSeries of the Azerbaijan part of South Caspian Basin have beenestablished. Also, the diffusion-adsorption parameter and cation-exchange capacity for different rock types have been determined.

2. Correlation equations obtained may serve as petrophysical modelswhile interpreting SP logs, and also planning and carrying outwaterflooding operations.

MODELS OF OIL COMPOSITION AND PROPERTIES

Crude oil is a complex natural system consisting of various com-ponents with a considerable predominance of different hydrocarbon

Table 10-23Empirical Coefficients of General Equation of Correlation

Baku Archipelago andSouth Apsheron Offshore Zone Lower Kura Depression

i a b c a b c

1 30.0 1.632 0.0237 31.5 1.355 0.01852 3.48 0.194 — 3.0 0.171 —3 36.6 15.8 — 52.6 23.8 —4 3.30 0.113 — 3.78 0.108 —5 0.30 0.300 — 0.35 0.35 —6 4.00 6.67 — 4.2 6.75 —7 2.70 0.242 — 3.01 0.202 —8 0 0.480 — 0 0.48 —9 21.1 9.4 — 17.5 10.0 —

10 0 5.1 51.1 0 6.5 57.011 15.8 78.8 — 8.1 81.1 —12 1.91 0.061 — 1.96 0.045 —13 68.6 2.86 — 80.0 2.50 —14 14.2 4.37 — 18.0 6.17 —15 29.7 10.3 — 42.4 11.6 —16 18.7 13.3 — 20.7 14.7 —


groups. Data on hydrocarbon-group composition of oil are of great impor-tance for understanding its origin and preparing genetic classifications.

Hydrocarbon Group Composition andMain Properties of Crude Oil

Composition of crude oil is determined by dividing it into fractionsaccording to the molecular weight, followed by estimation of hydrocarbon-group composition of each fraction. Division of crude oil into fractionscan be made according to their boiling point ranges. Fractional compo-sition shows relative contents in percent by weight (wt %) of differentoil fractions boiling within definite boiling-point ranges. The followingmain fractions are distinguished in Russia and other CIS countries:“benzine” with boiling point range of 40 to 200°C, “ligroin” withboiling point range of 200 to 350°C, and “residual oil” with boilingpoint range of 350 to 500°C. “Benzine” fractions of the Azerbaijanoils constitute 40% of distillate at 100°C. (See p. 177.)

Entropy, as a measure of heterogeneity of crude oil composition,differs in fractions having different boiling-point ranges (Buryakovsky,1968). If relative entropy of oil as a heterogeneous system of light-boiling fractions (from 65 to 150°C) is 0.6–0.7, it increases to 0.8 infractions with boiling-point range of 150 to 225°C. For high-boilingfractions (from 225 to 350°C), the relative entropy reaches a maximumvalue of 1.

Entropy evaluation, as a measure of complexity of an oil compo-sition, has a certain advantage over the other classifications of oils,because it allows one to assign a numerical value to the oil hetero-geneity. The values range from 0 to 1, with 0 characterizing vertexesof the mixture triangle, and 1 characterizing the center of the triangle(see Figure 10-9).

In order to evaluate the geochemical history, in addition to thefractional oil composition, hydrocarbon-group composition of differentfractions is also used (content of paraffinic, naphthenic, and aromaticgroups of hydrocarbons). The hydrocarbon-group composition of crudeoil can be clearly presented on a mixture triangle (Gibbs’ triangle).Based on more than 100 samples of oils from the Apsheron Archipelagofields, hydrocarbon-group composition of light fractions of crude oil(gasoline and ligroin) is plotted on a triangular diagram in Figure 10-19.


According to the experimental data, Figure 10-20 shows the depen-dence of content of various hydrocarbon groups on boiling point forcrude oils of the Apsheron Archipelago. The results obtained byDobryanskiy (1948) and Kartsev (1950) for “world” oils (weightedaverage data for many oil fields) are given for a comparison. Withincreasing boiling point, the aromatic hydrocarbons content increases,whereas the content of paraffinic hydrocarbons decreases.

Besides hydrocarbon components, different non-hydrocarbon com-ponents are present in the crude oil. Asphaltenes and resins constitutethe major portion of non-hydrocarbon components.

Crude oil density and contents of asphaltenes and resins, gasoline,and ligroin of the crude oil from Neft Dashlary oilfield in the Apsheron

Figure 10-19. Hydrocarbon-group composition of light fractions of oils fromNeft Dashlary Field (Modified after Buryakovsky and Dzhevanshir, 1992).• = “benzine” (gasoline); x = “ligroin.”


Archipelago (Buryakovsky, 1974a) are presented as histograms inFigure 10-21.

In the northwestern part of the Apsheron Archipelago (Darvin Bank,Pirallaghi Adasi, and Gyurgyany Deniz fields), average crude oil param-eters [with evaluation of their variation within two-sigma limits (95%of confidence)], based on 1,642 analyses, can be presented as follows:

γ = 0.9137 ± 0.0240 g/cm3 γave = 0.9137 ± 0.0006 g/cm3

R = 37.2 ± 15.1% Rave = 37.2 ± 0.37%B = 1.54 ± 1.20% Bave = 1.54 ± 0.03%L = 7.4 ± 1.3% Lave = 7.4 ± 0.03%

where γ is density, R is the content of asphaltenes and resins, B isthe “benzine” (gasoline) content, and L is the content of ligroin.

Figure 10-20. Hydrocarbon-group composition of crude oils. 1—Average“world” crude oil according to A. A. Kartsev; 2—average “world” crude oilaccording to A. F. Dobryanskiy; 3—oil from Neft Dashlary Field; 4—oil fromPalchygh Pilpilasi Field (Modified after Buryakovsky and Dzhevanshir, 1992).


Based on 820 analyses, in the southeastern part of the ApsheronArchipelago (Chalov Adasi, Palchygh Pilpilasi, and Neft Dashlaryoilfields) these crude oil parameters are equal to:

γ = 0.8800 ± 0.0380 g/cm3 γave = 0.8800 ± 0.0013 g/cm3

R = 22.7 ± 11.8% Rave = 22.7 ± 0.41%B = 7.4 ± 7.5% Bave = 7.4 ± 0.26%L = 9.6 ± 8.0% Lave = 9.6 ± 0.28%

Figure 10-21. Histograms of crude oil density (a), content of resins (b), and“benzine” (gasoline) content (c) in the crude oils of Neft Dashlary Field(Modified after Buryakovsky and Dzhevanshir, 1992). 1—Balakhany Suite, 2—“Pereryv” Suite, 3—NKP, 4—KS, 5—PK, 6—KaS.


The crude oil of the northwestern part of the Apsheron Archipelagocontains more asphaltenes and resins and less low-boiling fractions;hence, its density is higher than that of the oil from the southeasternpart of archipelago.

Using both numerical characteristics and histograms or as frequencydistributions (relatived frequencies), one can solve different geologicaland geochemical problems. For example, Figure 10-21 showsthe distribution of oil densities, content of asphaltenes and resins,and gasoline content in different suites of the Neft Dashlary Field.With increase in burial depth, density of crude oil and contentof asphaltenes and resins increase, whereas the gasoline contentdecreases. These trends, however, are not present in the Upper Produc-tive Series. The increase in density of oil in the Upper ProductiveSeries is related to the oxidation of oil by near-surface agents, whichincreases the content of asphaltenes and resins and decreases thegasoline content.

Relationship between Composition andProperties of Crude Oils

There are correlations between the crude oil parameters and itscomposition and among the various parameters and content of traceelements. These variables can be studied by correlation and regressionanalyses. The correlation analysis shows the presence, strength, andsign of the relationship between the correlated parameters, whereas theregression analysis enables one to establish the type of relationshipor to develop models. For example, correlation matrices for differentcrude oils from offshore oilfields of the Apsheron Archipelago wereobtained from correlation analysis. Several types of correlation matriceswith a different number of analyses and, therefore, with differentreliable values of the correlation coefficient, were calculated. Table 10-24 is a generalized matrix of correlation coefficients for the fields ofthe Apsheron Archipelago. Instead of numerical values of correlationcoefficients in this table, only the signs of coefficients with reliablevalues are presented.

Due to different interrelationships, estimation of a certain numberof parameters of a given crude oil may be sufficient to estimate valuesof other parameters. The simplest, and at the same time one of themain properties of crude oil, is its density, which is closely dependent


Tab

le 1

0-24

Sig

ns

of

Co

rrel

atio

n C

oef

fici

ents

bet

wee

n C

rud

e O

il P

aram

eter

s (G

ener

aliz

ed M

atri

x)

Con

tent

of

Cok

ing

Res

ins

and

Tra

ce E

lem

ents

Par

amet

ers

Abi

lity

Aci

dity

Vis

cosi

tyA

spha

ltene

sV

Fe

Ni

Cr

Ti

Co

Mo

Be

Sr

Sn

V/N

i

Den

sity

++

++

++

+C

okin

g ab

ilit

y+

++

++

++

+A

cidi

ty+

++

++

Vis

cosi

ty+

++

Con

tent

of

resi

ns+

++

+an

d as

phal

tene

sT

race

ele

men

ts:

V+

++

++

Fe

++

Ni

++

Cr

Ti

+C

o+


on the fractional composition and the content of asphaltenes and resinsin the crude oil. Interrelationship among the major crude oil parametersis of great interest from the point of view of petroleum geochemistry,and equations derived by regression analysis can serve as mathematicalmodels of the crude oils. Crude oils of some fields of the Apsheronoil- and gas-bearing region and adjacent offshore areas of theCaspian Sea were thoroughly studied. These oils are of high-quality,naphthenic-paraffinic type. Their densities range from 0.81 to 0.93 g/cm3 and depend on the contents of heavy resins and asphaltenes, andlight gasoline and ligroin.

The influence of these components of crude oil on density can bestudied by means of correlation for four parameters: (1) γ = oil densityin g/cm3, (2) R = content of resins and asphaltenes in wt %, (3) B =content of gasoline in wt %, and (4) L = content of ligroin in wt %.Based on 820 analyses, the correlation between the oil density andcontent of resins plus asphaltenes was tabulated (Table 10-25) as anexample. Empirical equation of relationship between the density andcontent of resins plus asphaltenes in crude oil in the form of regressionR on γ is as follows:

γ = 0.826 + 0.00237R (63)

or in the form of regression γ on R:

R = 212(γ – 0.778) (64)

The coefficient of correlation between the R and γ is 0.710.It is not always convenient to have two different regression equa-

tions (Equations 63 and 64). Thus, it is desirable to have a singleequation, for example, an equation of orthogonal regression as sug-gested by Nalimov (1960), Smirnov and Dunin-Barkovskiy (1965),Griffiths (1971), Buryakovsky et al. (1974c), Rodionov et al. (1987),and Buryakovsky and Agamaliyev (1990a).

To calculate the orthogonal regression, it is necessary to give theprobability of belonging of the experimental data to the ellipse ofcorrelation, i.e., Q(χ). If the probability Q(χ) is given, then one cancalculate the ellipse parameter χ by using the following formula:

χ = (–2ln[1 – Q(χ)])1/2 (65)


Tab

le 1

0-25

Co

rrel

atio

n b

etw

een

th

e C

rud

e O

il D

ensi

ty a

nd

Co

nte

nt

of

Res

ins

Plu

s A

sph

alte

nes

Den

sity

(g/

cm3 )

Con

tent

of

Res

ins

Plu

s A

spha

l tene

s (w

t %

)

Ra

ng

eA

vera

ge

5–10

10–1

515

–20

20–2

525

–30

30–3

535

–40

40–4

545

–50

∆γγ a

ve7.

512

.517

.522

.527

.532

.537

.542

.547

.5N

γ

0.81

5-0.

825

0.82

211

20.

825-

0.83

50.

833

1311

311

90.

835-

0.84

50.

841

1012

011

413

50.

845-

0.85

50.

853

2013

511

816

60.

855-

0.86

50.

8616

124

111

112

153

0.86

5-0.

875

0.87

1413

214

711

119

40.

875-

0.88

50.

8813

132

130

156

1313

227

0.88

5-0.

895

0.89

1311

319

516

313

177

0.89

5-0.

905

0.90

112

139

143

1612

192

0.90

5-0.

915

0.91

111

117

110

1817

21

136

0.91

5-0.

925

0.92

114

1814

11

118

0.92

5-0.

935

0.93

111

1311

12

118

0.93

5-0.

945

0.94

111

1111

113

NR

959

162

341

191

3218

44

820

Nγ

= n

umbe

r of

cru

de o

il d

e nsi

ty d

e te r

min

atio

ns.

NR =

num

ber

of d

e te r

min

atio

ns o

f re

sins

plu

s as

phal

tene

s c o

nte n

t.


Thus, when Q(χ) = 0.98, the ellipse parameter is χ = 2.8. The higherthe probability Q(χ), the greater is the ellipse parameter χ.

Having available data on the values of χ, Rave, γave, δR, δγ, and ZRγ,one can estimate parameters of the orthogonal regression equation.This equation represents the main axis of the correlation ellipse, wherecoordinates of the ends in a normalized scale are calculated by thefollowing formulae:

aR = χ [(1 + Z

Rγ)/2] δR and aγ = χ [(1 + Z

Rγ)/2] δγ (66)

For Q(χ) = 0.98 and χ = 2.8, calculation according to Equations66 yields:

aR = 15.22 and aγ = 0.0516

In a natural scale, the corresponding coordinates can be written asfollows: R1,2 = Rave ± aR, i.e., R1 = 22.75% + 15.22% = 37.97% andR2 = 22.75% – 15.22% = 7.53%; and γ1,2 = γave ± aγ, i.e., γ1 = 0.9316g/cm3 and γ2 = 0.8284 g/cm3.

The equation of the main axis of the correlation ellipse at a givenprobability Q(χ) (the equation of orthogonal regression) may beobtained as an equation of a line passing through two points withcoordinates (R1, γ1) and (R2, γ2). The corresponding points are (37.98,0.9316) and (7.53, 0.8284). For these points, the equation of ortho-gonal regression can be written in the following form:

R = 295(γ – 0.805) or γ = 0.0034R + 0.805 (67)

Both Equations 67 are equivalent. Conjugated equations of regres-sion (Equations 67 and 64) represent the conjugated axes of thecorrelation ellipse.

From Equations 67 it follows that the crude oil having density of0.805 g/cm3 does not contain resins and asphaltenes. It is noteworthythat the value of 0.802 g/cm3 corresponds approximately to the densityof ligroin obtained by refining crude oil from fields of the Apsheronoil- and gas-bearing region. If the content of resins and asphaltenesvaries from 57 to 87%, the density reaches 1.0–1.1 g/cm3, i.e., crudeoil changes into asphalt.

Besides coefficients of correlation, the eccentricity e of the correla-tion ellipse may be used as a measure of tightness of correlation links:


e = c/a (68)

where c is half the distance between the foci, and a is half the lengthof the main axis of the ellipse.

To calculate the distance between the foci, one should estimate thecoordinates of the ellipse foci according to the following formulae (innormalized scale):

fR = χZ1/2δ

R and fγ = χZ1/2δγ (69)

Substituting values of parameters for variables, one obtains fR = 13.8and fγ = 0.0468. In a normalized scale, CR = fR and Cγ = fγ. Therefore,e = 13.8/15.22 = 0.905.

The ellipse eccentricity e does not depend on the probability Q(χ).The value of this probability defines only the number of data pointsbelonging to the ellipse of correlation. One can compute the numberof data points beyond the limits of the correlation ellipse accordingto the following formula: Nbeyond = N[1 – Q(χ)]. In the given case,Nbeyond = 16 with Ntotal = 820.

Conjugated and orthogonal lines of regression, the equations ofwhich were given earlier, are presented in Figure 10-22a. Lines ofequal probability of the pairs γ and R are drawn in accordance withthe correlation table (see Table 10-25). As shown, the form and thetightness of the contour lines along the main axis may also show asufficiently close relation between density and content of resins andasphaltenes in crude oil. Variations in parameters are equal to: vR =26.0% and vγ = 2.2% for R and γ, respectively. This shows that thecontent of resins and asphaltenes varies more than density, the stabilityof which is dependent on the stability of major crude oil components.

The crude oil density is greatly affected by the content of low-boiling components. With increasing content of gasoline and ligroin,the density of oil decreases. Based on 792 analyses of crude oil,equations for the relationship between the oil density, γ, and gasoline(“benzine”), B, content were calculated as follows:

γ = 0.9063 – 0.00380B (70)

B = 143.7 – 155γ (71)

The equations of the line of orthogonal regression (the main axisof the correlation ellipse) can be presented as follows:


Fig

ure

10-

22.

Ort

hogo

nal

and

conj

ugat

ed r

egre

ssio

n lin

es f

or r

elat

ions

hips

in

oils

fro

m N

eft

Das

hlar

y F

ield

. a—

Oil

dens

ity (

g/cm

3)

vers

us t

he c

onte

nt o

f re

sins

(R

, %

); b

—oi

l de

nsity

ver

sus

“ben

zine

” (g

asol

ine)

con

tent

(B

, %

). 1

—R

egre

ssio

n of

γ o

n R

and

B,

2—re

gres

sion

of

R o

r B

on

γ, 3

—eq

ual-

freq

uenc

y cu

rve,

4—

ellip

se o

f co

rrel

atio

n, 5

—m

ajor

axi

s of

the

elli

pse

(lin

e of

ort

hogo

nal

regr

essi

on),

6—

min

or a

xis

of t

he e

llips

e.


γ = 0.915 – 0.0500B or B = 200(0.915 – γ) (72)

The correlation coefficient of 0.760 indicates a sufficiently close,reverse, linear relation between γ and B. At γ = 0.915 g/cm3, crudeoil no longer contains gasoline fraction. The coefficient of variationfor distribution of gasoline content is 51.4%, whereas for density itis 2.2%. Lines of equal probability form concentrically situated ovalsstretched along the main axis (Figure 10-22b). The eccentricity of theellipse is 0.94.

Calculated values of all coefficients of correlation for paired corre-lations are presented in Table 10-26. Having available data on allpaired correlations, one can derive an equation of multiple regressioncontaining all three main parameters. The equation of multiple regres-sion is a linear function:

γ = γo + aR + bB + cL (73)

where a, b, and c are numerical coefficients, and γo is the density ofcrude oil when R = B = L = 0.

The multiple regression equations for various oilfields in the Azerbaijanportion of the South Caspian Basin are as follows:

1. Darvin Bank, Pirallaghi Adasi and Gyurgyany Deniz Fields:

γ = 0.9805 + 0.00009R – 0.00910B – 0.00796L

Table 10-26Coefficients of Correlation of Paired Relationships

between Crude Oil Parameters

Relationship CorrelationBetween Coefficient

γ and R +0.71γ and B –0.76γ and L –0.47B and R –0.60L and R –0.12L and B +0.64

γ and R, B, L 0.83


2. Chalov Adasi Field:

γ = 0.9190 + 0.00046R – 0.00481B – 0.00208L

3. Palchygh Pilpilasi Field:

γ = 0.9258 + 0.00017R – 0.00131B – 0.00139L

4. Neft Dashlary Field:

γ = 0.8640 + 0.00210R – 0.00230B – 0.00140L

The general equation relating γ, R, B, and L is as follows:

γ = 0.864 + 0.0021R – 0.0023B – 0.0014L (74)

As shown in Table 10-26, the coefficient of multiple correlation, ishigher than any paired coefficient of correlation. Thus, the equationof multiple correlation (Equation 74), which takes in consideration theinfluence of every parameter, describes the experimental relationshipsmore reliably than the paired equations of regression. In deriving thisregression, some parameters were fixed at average levels.

To expedite the calculations, a nomograph (Figure 10-23) wasconstructed according to the Equation 74. For example, at the givenvalues of R = 23%, B = 7.2%, and L = 7.0%, γ = 0.882 g/cm3.

Inasmuch as the dependence of density on variations in ligroincontent in the crude oil is weak, the term in the equation of multiplerelationship (Equation 74) corresponding to the influence of ligroinon density may be replaced by a constant value. In this case theequation is written in the following way:

γ = 0.8707 + 0.0013R – 0.0027B (75)

The coefficient of multiple correlation is 0.830. Graphically thisrelationship is presented in Figure 10-24. As shown, the dependenceof crude oil density on content of resins, asphaltenes, and gasoline(ligroin influence is excluded) is clearly expressed graphically and canbe used in calculations.


Fig

ure

10-

23.

Nom

ogra

ph o

f re

latio

nshi

ps a

mon

g oi

l de

nsity

and

con

tent

s of

res

ins,

“be

nzin

e” (

gaso

line)

and

lig

roin

.


Dobryanskiy (1948), Bagir-zadeh et al. (1974c), and Leontaritis andMansoory (1988) have shown that the content of paraffins in the crudeoil increases with decreasing density. High-paraffin crude oil containsmany light fractions (boiling point up to 150°C) and very smallamounts of asphaltenes and resins. On the other hand, the paraffincontent in the crude oil which is close in consistency to asphalt ispractically equal to zero.

Experimental data exists (Gadzhi-Kasumov, 1971; Dzhevanshir etal., 1994) on the content of resins and paraffins in the crude oils of

Figure 10-24. Interrelationship among the oil density and contents of resinsand “benzine” (gasoline).


Apsheron oil- and gas-bearing region and the adjacent offshore areasof the Caspian Sea (Table 10-27). The data presented in Table 10-27and Figure 10-25 show the relationship between the content of paraf-fins (P) and content of resins (R) in the crude oils. An empiricalequation of this relationship is as follows:

P = 30/(R – 4) (76)

Crude Oil Viscosity

Relationship between the viscosity and density of crude oil (chang-ing simultaneously with increasing temperature) is considered next.Crude oils from the same fields of Azerbaijan have been investigated.Depth of burial of productive reservoirs varies from 500 to 3,500 m,while the reservoir temperature ranges from 30 to 90°C. Due to theinfluence of various factors, density of crude oils varies from 0.83 to0.93 g/cm3.

Dynamic viscosity µ and kinematic viscosity ν are related as follows:

ν = µ/γ (77)

where γ is the density of liquid.Table 10-28 shows the dependence of crude oil viscosity on density

at five different temperatures: 10, 20, 30, 40, and 50°C. This table isbased on 580 analyses. Figure 10-26 shows the dependence of vis-cosity on temperature. Logarithmic scale was used for viscosity,transforming asymmetric empiric distribution into symmetric one, closeto the normal law. This figure shows that viscosity and temperatureare related by logarithmic or power law.

Interrelationship among kinematic viscosity, density, and temperatureis presented in Figure 10-27. This interrelationship is best describedby an exponential function:

ν = νoexp(–bT) (78)

where T is the oil temperature in °C, νo is the kinematic oil viscosityin centistokes at T = 0°C, which is equal to:



Table 10-27Contents of Resins and Paraffins in the Crude Oils from Apsheron

Oil- and Gas-Bearing Region

Content, wt %

Field Suite or Unit Resins Paraffins

Binagady NKP 35.0 0.20Balakhany-Sabunchi-Ramany PK 32.0 0.15Surakhany Sabunchi 16.5 2.48

“ PK 25.6 2.07“ KaS 24.0 3.71

Karachukhur Balakhany 17.0 16.0“ NKG 17.0 4.95“ PK 18.6 4.95“ KaS 21.4 4.95

Gum Deniz VIII 15.8 18.6“ IX 15.2 16.5

Kala KaS 36.8 2.92Gousany KaS 19.8 6.33Lokbatan NKP 22.5 13.7Karadag VII 16.0 19.3

“ VIII 13.0 17.5Sangachal-Duvanny Deniz VII 25.3 15.8Darvin Bank PK 45.0 0.03Pirallaghi Adasi PK 34.0 0.13Chalov Adasi KaS 36.0 0.12Palchygh Pilpilasi KaS 37.0 0.66Neft Dashlary Sabunchi 29.3 1.72

“ Balakhany 24.6 1.08“ “Pereryv” 21.6 0.79“ NKP 17.7 2.50“ KS-1 28.2 0.41“ KS-2 22.6 0.69“ PK-1 22.4 0.58“ PK-2 23.8 0.56“ PK-3 23.6 0.89“ KaS-1 24.7 0.64“ KaS-2 16.5 0.49“ KaS-3 24.7 0.38


Figure 10-25. Relationship between the content of resins and contentof paraffins.

Table 10-28Kinematic Viscosity of Crude Oils as Related to Density and Temperature

Temperature, °C

Average Density,g/cm3 10 20 30 40 50

0.82 5.6 4.2 2.8 2.8 1.40.83 5.6 5.6 4.5 3.9 2.50.84 11.2 9.9 5.6 5.4 4.30.85 14.0 12.9 7.9 5.8 5.20.86 20.5 13.7 9.4 6.5 5.60.87 22.4 20.3 12.4 10.5 7.60.88 39.2 23.2 18.3 11.7 10.30.89 53.0 32.6 21.9 14.4 11.00.90 86.4 50.3 30.9 22.7 15.10.91 118 94.5 50.5 30.2 24.10.92 — 133 89.2 53.7 33.60.93 — 356 178 111 55.80.94 — — 178 178 89.2


Figure 10-26. Statistical distribution (a) and cumulative probability (b) of oilviscosity at five different temperatures (Modified after Buryakovsky andDzhevanshir, 1992).


Figure 10-27. Interrelationship among the kinematic viscosity (ν), oil density(γ) and temperature (Modified after Buryakovsky and Dzhevanshir, 1992).


νo = aexp(cγ) (79)

where γ is the crude oil density in g/cm3 and a and c are empiricalnumerical coefficients, a being the crude oil viscosity when T = 0 andγ = 0. The numerical coefficient b in Equation 78 also depends onthe crude oil density according to the following equation:


b = mγ – n (80)

where m and n are numerical coefficients that can be estimated fromthe experimental data.

Substituting Equations 79 and 80 into Equation 78, one obtains:

ν = aexp(cγ – mγT + nT) (81)

or, after taking logarithms, one can obtain the equation in the follow-ing form:

lgν = ao + a

1γ – a

2γT + a

3T (82)

Coefficients ai of Equation 82 are calculated from the data presentedin the correlation tables and Figures 10-26 and 10-27.

Substituting numerical values of coefficients ai into Equation 82,one obtains:

lgν = 16.6γ – 0.100γT + 0.072T – 12.8 (83)

In SI units Equation 83 becomes:

lgν = 0.0166γ – 0.0001γT + 0.072T – 12.8 (84)

where γ is in kg/m3, T is in °C, and ν is in m2/sec.Dynamic viscosity, on the other hand, is equal to:

µ = aγexp(cγ - mγT + nT) (85)

Substituting Equation 67 into Equation 81, one obtains an expressionrelating the kinematic crude oil viscosity to the content of asphaltenesplus resins:

ν = a′exp(c′R – m′RT + n′T) (86)

where a′, c′, m′, and n′ are empirical coefficients.After taking logarithms of Equation 86, one obtains:

lgγ = 0.6 + 0.0565R – 0.00034RT – 0.083T (87)


Discussion of Results and Conclusions

1. Empirical equations of interrelationships among composition,parameters of the crude oil, and temperature were derived usingthe experimental data. These equations are not only of practicalvalue but also of theoretical interest. Equations 83 and 87 providetheoretical correlations among the crude oil parameters and maybe used in calculations involving temperature, density, and con-tents of asphaltenes plus resins and low-boiling fractions.

2. From the practical point of view, extrapolation of graphical oranalytical models beyond the limits of the experimental data isinteresting. For example, extrapolation of graphs in Figure 10-27 or using Equation 83 for temperatures above 50°C enablesone to predict the viscosity of crude oils of different densitiesat temperatures up to 100–120°C (at depths of 5,500–6,000 m).Deposits located in the more bathypelagic parts of the Apsheron–Pre-Balkhan Threshold occur at such depths. These deposits aremost likely to contain gas-condensate fluids due to the lowviscosity of fluids at reservoir temperatures.

3. In the near-surface rocks (with an average annual temperature of+14.5°C) crude oil is degraded into an asphalt-like material witha density of 1.0–1.1 g/cm3. Similar deposits of bituminous sandsare known to occur at outcrops of oil reservoirs in different partsof the world.

347

CHAPTER 11

MathematicalModeling of

Geological Processes(Dynamic Geological

Systems)METHODOLOGY OF SIMULATION OFDYNAMIC SYSTEMS

Objects of geological study, i.e., geologic systems, with subsequenttechnologic impact (e.g., secondary and tertiary recovery) on them, aredynamic systems. They change either in “geologic” or “technologic”time scale. Thus, to develop adequate dynamic models of geologic andtechnologic processes, it is necessary to introduce time factor.

The rather conflicting methodological approaches, such as system-structural and genetic-historical, are merged in the modeling of thedynamic geologic systems. Merger of the structural and historicalapproaches in one model treats a geological system as a naturalphenomenon which, on one hand, is relatively stable at a certain timestage, and on the other hand, is evolving during a sufficiently extendedinterval of the geologic time.

The necessity to take geologic time into account meets with signi-ficant difficulties. This often causes an unwillingness to construct thegeologic models when they should reflect the dynamics of geologicphenomena and processes.

One of the reasons for this difficulty is the use of absolute andrelative geologic time. The difference between them is substantial: the


absolute time has the beginning common for the entire Earth, whichis not an attribute of the relative time scale based on paleontologyand stratigraphy.

Another reason is the lack of reproducibility of the geologic timein physical and chemical experiments, and practical impossibility to elimi-nate this obstacle using the similarity method and the dimensional analysis.

The time factor is of a special importance for the problems offorecasting. Such problems indeed call for the creation and applicationof the mathematical models. The successful forecast may depend onthe retrospective historical evaluation of the geologic system under study.

Two methods in constructing such models may be offered: analyticaland statistical. The better approach in modeling such systems is acombination of the mathematical analysis (i.e., differential equations)with the statistical-probabilistic expression of the numerical values forthe parameters, causing the change in a dynamic geologic systems.This approach allows to describe in the deterministic way mainfeatures in the dynamics of the geologic systems. At the same time,it includes the statistical-probabilistic nature of various geologicparameters which cause the evolution of the systems. The implemen-tation of analytical solution is accomplished using the statisticalsampling technique (Monte Carlo method).

Analytical Approach

Two important issues must be addressed before constructing ana-lytical models.

1. The important properties of the system under study, as well asthose of the surrounding lithosphere, should be defined. Theseproperties should be described by strictly defined quantitativeconstraints.

2. The limitations assumed in describing these properties should beclearly delineated and should reflect the substance of a particulargeologic system.

It is natural to choose as the main parameters those properties ofthe system and of the surrounding rocks that would stimulate orrestrain the course of the geologic processes. If a process can becharacterized by a single parameter, for instance, the hydrocarbonreserves, this parameter should be used as the main one.

Mathematical Modeling of Geological Processes 349

In the following discussion, the writers use as synonyms the proper-ties of the geologic system and their respective parameters. They mayhave a dual nature, i.e., they may be either deterministic or stochastic,depending on the formalization approach at each stage of the modelingof a geologic system.

Two major assumptions should be made while developing thedifferential equations of geologic processes.

1. The rate of change in the geologic system, or the speed of thegeologic process, is proportional to the state of the system.

2. Influence of various natural factors is proportional to the productof the number (or quantitative estimates) of the events acceler-ating the process by the number (or quantitative estimates) of theevents retarding the process.

The first assumption leads to differential equations similar to:

dx/dt = ε(t)f(x) (88)

where x is a variable (quantitatively measured natural factor) describ-ing the evolution of geologic system; ε(t) is a coefficient of propor-tionality (generally time-dependent); and f(x) is a function of thevariable x.

In the case of a multi-phase process, a system of Equations 88-typeis written jointly.

The second assumption puts together a system of differential equationsthat takes into account the effects of interrelationships among variables:

dx1/dt = ε

1(t)f

1(x

1) + γ

12(t)f

1(x

1)f

2(x

2) (89)

dx2/dt = ε

2(t)f

2(x

2) + γ

21(t)f

1(x

1)f

2(x

2)

where x1 and x2 are variables (natural factors) accelerating and retard-ing the process, respectively; γ12(t) and γ21(t) are interdependencyquotients of these variables (or natural factors), which are generallytime-dependent.

In some particular cases, the factors ε and γ may not be time-dependent, i.e., they are constant. In those cases, Equation 88forms the so-called model of “proportional effects,” or an “organismgrowth model.”


Various functions of the affecting parameters can be used inEquations 88 and 89. This creates the necessary diversity in analyticaldescriptions of the dynamics of the geologic systems. For example,when f(x) = x, the process in Equation 88 is described by the exponen-tial curve; when f(x) = x(a – x), where a = constant, process isdescribed by the logistical curve (S-like or Gompertz curve), etc.

The signs of ε and γ quotients in Equations 89 may vary. If the firstequation has positive ε1 and negative γ12, then the two sign combina-tions are possible for the ε2 and γ21 in the second equation. In the caseof negative ε2 and positive γ21, the processes of construction anddestruction are antagonistic. In the case of positive ε2 and negativeγ21, the processes merge into a single process controlled by the samenatural factors, and the prevalence of the constructive component overthe destructive one depends on the relation between these factors.

Depending on the signs of ε and γ, the geologic processes can bestable or unstable in time. The former case is characterized by a point(center) or a convergent spiral on the phase plane in the coordinates(x1, x2). The latter case is characterized by a saddle or a divergent spiral.

These models (Equations 88 and 89) are widely used in ecology(Kemeny and Snell, 1972; Volterra, 1976) and can be applied togeology, economics, social domain, etc.

Using analytical models (Equations 88 and 89), one can study theevolution of a dynamic system in time. Based on the structure of thelithospheric space-time continuum, it is possible to equate the evolu-tion of the geologic systems in depth to their evolution in the reversedtime. In this sense, the geologic forecast is actually a reversed forecast,or “retrocast,” because it is directed backwards (in time) and isdirected onwards in depth (in space).

Taking into account the specifics of geologic time-space continuum,the analytical models (Equations 88 and 89) forecast the behavior andstructure of a geologic system at depths not yet studied throughgeologic techniques, provided the normal stratigraphic succession ofconsecutive time intervals.

Statistical Approach

The statistical approach, based on the empirical data, is simpler thanthe analytical one and still sufficiently justified from the viewpointof lithosphere evolution. It is based on the inference of interconnections


through generalization, analysis, and comparison of the structural-functional features of geologic systems at certain discrete moments ofthe geologic time. Approximation of the discrete (discontinuous) databy a continuous function obtains an empirical equation for a parameter(or a set of parameters) of the geologic object under study as afunction of time.

As an example, the equation expressing relationship between shale(clay) porosity (and density) and geologic age and taking into accountburial depth and lithology, can be presented here (Buryakovsky et al.,1982a, 1990b).

The relationship between porosity of shales (clays) and depth ofburial was studied by numerous investigators (e.g., Rieke and Chilingarian,1974). As shown on Figure 11-1, this relationship varies from one areato another. This is because porosity of argillaceous sediments is acomplex function of numerous natural factors, often superimposed oneach other. These factors include:

11. geologic age12. effective stress (total overburden stress minus the pore pressure)13. lithology14. mineralogy15. tectonic stresses16. speed of deposition of sediments17. thicknesses of sedimentary formations18. shape and sorting of grains19. amount and type of cementing material10. chemistry of interstitial fluids

This multitude of variables complicates the quantitative evalua-tion of the influence of individual factors on the porosity of argilla-ceous sediments.

One method of solving this important problem is by establishingdependence of porosity of argillaceous sediments on the most impor-tant natural factors, the influence of which considerably overshadows(or incorporates) the influence of other factors. It is also necessary toremember that these predominant factors may have good correlationwith each other.

Buryakovsky et al. (1982a) studied dependence of shale (clay)porosity on geologic age, depth, and lithology of siliciclastics. Theyutilized data obtained by Dobrynin (1959, 1970), Vassoevich and


Bronovitskiy (1962), Weller (1959), Proshlyakov (1974), and Durmishyan(1973) for the shales from different regions.

The following formula by Dobrynin (1970), for example, enablesquantitative evaluation of the role played by various factors in formingporosity of shale (clay):

Figure 11-1. Relationship between porosity and depth of burial for shalesand argillaceous sediments. 1—Proshlyakov (1960); 2—Meade (1966); 3—Athy(1930); 4—Hosoi (1963); 5—Hedberg (1936); 6—Dickinson (1953); 7—Magara(1968); 8—Weller (1959); 9—Ham (1966); 10—Foster and Whalen (1966)(Modified after Rieke and Chilingarian, 1974, fig. 17, p. 42).


φ = φoexp(–0.014β

cD) (90)

where φo is the initial porosity of shale (clay); φ is the porosity ofshale (clay) at a depth D (in m); and βc is coefficient of irreversiblecompaction (MPa–1).

Using this formula, the writers plotted a family of straight lines onsemilogarithmic paper (Figure 11-2). The actual compaction curves ofargillaceous rocks are superimposed on this figure. Inasmuch as thecoefficient of irreversible compaction βc (in 10–3, MPa–1) for each oneof the straight lines (Equation 90) is known, it is possible to determinegraphically its average value for actual curves: Weller (1959) =58.5; Proshlyakov (1974) and Dobrynin (1970) = 42.8; Vassoyevichand Bronovitskiy (1962) = 33.6; Apsheron Peninsula and ApsheronArchipelago = 42.1; southwestern part of Apsheron Peninsula andnorthern part of Baku Archipelago = 27.1; and southern part of BakuArchipelago = 19.3.

As shown in Equation 90, with the exception of depth, the effectsof all other variables are included in the coefficient of irreversiblecompaction βc. Correlation of this coefficient with geologic age andlithology becomes apparent upon comparison of curves of differentgeologic age obtained by Weller (1959), Vassoyevich and Bronovitskiy(1962), Dobrynin (1970), Proshlyakov (1974), and Durmishyan (1973)with curves corresponding to deposits of the same geologic age inAzerbaijan, obtained for areas having different lithologies (Figure 11-2).

Experimental data obtained by Terzaghi (1961), Dobrynin (1970),Rieke and Chilingarian (1974) and others, indicate that coefficient βcdepends on the duration of sample loading. As far as lithology isconcerned, extensive investigations by Durmishyan (1973), Rieke andChilingarian (1974), Fertl (1976), Buryakovsky (1985a), Dzhevanshiret al. (1986) and others, showed that in the areas where argillaceoussediments experience rapid deposition, upward squeezing out ofcompaction fluids is impeded. This increases the pore fluid pressure,sometimes approaching geostatic, giving rise to the regional, abnor-mally high formation pressure. With increasing thickness of claydeposits and decreasing number of interstratified porous and permeablerocks (sands), the clay remains more porous (undercompacted) becauseof greater difficulty of fluid expulsion from clays.

Although many other factors influence compaction, geologic age andlithology (ratio of shales to the total thickness of deposits) affect the


complex diagenetic processes occurring in a subsiding basin sediments,with a distinct geothermal gradient. The coefficient of irreversiblecompaction, βc, is related to the geologic age and lithology as follows:

βc = (26.61 logA

t – 8.42) • 10–3 (91)

βc = (14.0 – 166.6 logχ) • 10–3 (92)

Figure 11-2. Relationship between porosity and depth of burial for various shales.1—Weller (1959); Aralsor super-deep well SG-1 (USSR); 3—Vassoyevich andBronovitskiy (1962); 4—Apsheron Peninsula and Archipelago (Azerbaijan);5–southwestern part of Apsheron and northern part of Baku Archipelago(Azerbaijan); 6—southern part of Baku Archipelago and Lower Kura Depres-sion (Azerbaijan); 7—family of calculated porosity/depth curves (Modified afterBuryakovsky et al., 1982a).


where At is the geologic age in millions of years, and χ is a ratio ofthickness of clays to the total thickness of siliciclastics.

On combining Equations 90, 91 and 92, an equation relating porosityto geologic age, lithology and depth is obtained:

φ = φoexp[–0.014(13.3logA

t – 83.25logχ + 2.79) • 10–3D] (93)

where φo is the initial porosity of argillaceous sediments, and D is thedepth in meters.

A nomograph, presented in Figure 11-3, enables rapid solution ofEquation 93. This nomograph was used to test the results obtained by(a) Hedberg (1926) for the Tertiary clays of Venezuela, (b) Stetyukha(1964) for the Tertiary clays of the northeastern part of Pre-Caucasus,and (c) Durmishyan (1973) for the Kala Suite of Apsheron Peninsulaand Archipelago. Comparison of data obtained from Figure 11-3(nomograph) and actual field data is presented in Figure 11-4. Theabsolute error does not exceed 3%. Relative error gradually increaseswith increasing absolute value of porosity and, on the average, variesfrom 5 to 30%. The difference between the calculated values andactual field data is probably because calculated values do not take intoconsideration all the factors which influence porosity. Nevertheless,Equation 93 gives satisfactory, practically usable results.

MATHEMATICAL SIMULATION OFSEDIMENT COMPACTION

Post-sedimentational changes (during the diagenetic and epigeneticstages) of sediments depend on a great number of natural processes(including compaction) which result in the transformation of sedimentsinto rocks.

The diagenetic stage of rock transformations includes all physical,chemical and biochemical processes modifying sediments betweendeposition and lithification at low temperatures and pressures charac-teristic of surface and near-surface environments. In general, diagenesisis divisible into pre-, syn-, and post-cementation or lithificationprocesses. Diagenesis takes an intermediate position between syn-genesis and epigenesis, the former grading into diagenesis by syndia-genesis, and the latter grading into metamorphism. Under unusualconditions, however, diagenesis as defined here may grade directly into


Figure 11-3. Nomograph for determination of porosity at a particular depthof burial using geologic age and lithology (ratio of thickness of shales/totalthickness of terrigenous complex) as controlling factors. R = χ (Eq. 93).


metamorphism (see epigenesis). Because reef limestones, and otherlimestones which are constructed in-situ by organic frame-builders, arelargely lithified to a degree, the definition must be expanded for thisparticular group of limestones to include the interactions betweensediments and the fluids contained within them below the temperatureand pressure levels of metamorphism sensu stricto, and in a similarsense between fluids and framework, infilled detritus framework, andcombinations thereof.

The catagenesis (or epigenesis) stage includes all processes at lowtemperature and pressure that affect sedimentary rocks after diagenesisand up to metamorphism. Epigenesis has been subdivided into juxta-and apo-epigenesis (Wolf, 1963b, 1965c, in: Chilingar et al., 1979, pp.393, 395). It is possible that under unusual conditions syngenesis anddiagenesis grade directly into metamorphism. For example, unconsolidatedsediments may be exposed to volcanic high temperatures and metasomatic

Figure 11-4. Comparison of actual porosity and that obtained from nomograph(Modified after Buryakovsky et al., 1990b). a (left)—Venezuela; b—Pre-Caucasus; c (right)—Apsheron Peninsula and Archipelago. 1—Actual porosity,2—calculated porosity.


material and undergo metamorphism before diagenesis. Also, sedimentspartly undergoing cementation may be metamorphosed by shallowintrusions causing an increase of temperature and possibly pressurebefore epigenesis could occur.

As a result of compaction of sediments, a decrease in thickness andin porosity and an increase in the density of sedimentary rocks takeplace. The most characteristic indicators of the process of sedimentcompaction are curves of the dependence of rock porosity on the depthof burial. Figure 11-5 shows such curves for sandstones, siltstones,carbonate rocks, and clays (shales), based on data of many experi-mental investigations: Athy (1930), Hedberg (1926, 1936), Dickinson(1953), Weller (1959), Foster and Whalen (1966), Ham (1966), Meade(1966), Magara (1968), Proshlyakov (1974), Rieke and Chilingarian(1974), Buryakovsky (1985a), and Aleksandrov et al. (1987).

Studying the process of compaction of sediments and their trans-formation into rocks at the present-day scientific and technical level,it is necessary to develop a mathematical description of this processand to construct a mathematical model capable of describing thecompaction process. One should be able to reconstruct the history ofthe formation of the original sediments and to predict their propertiesin regions and at depths that are not sufficiently studied by directgeological and geophysical methods.

Previous Investigations

The problem of mathematical description of the process of sedimentcompaction is considered to be rather complicated due to both a greatnumber of parameters affecting the consolidation of sediments and tothe lack of quantitative information about the behavior of theseparameters at different stages of consolidation of sediments andsedimentary rocks. In most cases, a researcher is forced (1) to workwith data on the already-formed formation and (2) to rely on theavailable data on the dependence of degree of consolidation on thedepth of burial (e.g., see Figure 11-5).

Another source of information is experimental investigation of rocksat conditions simulating reservoir conditions, i.e., at high pressures andtemperatures, corresponding to the depth of burial of formation beingstudied. Nevertheless, a combination of this data plus informationobtained by geophysical and geochemical investigations of the upper


Figure 11-5. Relationship between porosity and depth of burial for varioustypes of sediments and rocks (Modified after Buryakovsky et al., 1990b).(a) Sandstones, and (b) siltstones (after Buryakovsky, 1985); deposits of thenorthwestern boundary of the South Caspian Dpression: 1—Dzhanub, 2—Zyrya,3—Surakhany, 4—Karachukhur, 5—Zykh, 6—Gum Deniz, 7—Gousany, 8—Bukhta Il’icha, 9—Patamdar, 10—Karadag, 11—Padar, 12—Kyurovdag, 13—Karabagly, 14—Kalmas. (c) Carbonates (after Aleksandrov et al., 1987);Regions: 1—Scythian Plate, Upper Cretaceous limestones; 2—Western KubanTrough, Upper Devonian limestones; 4–8—Southern Florida, Cenozoic andMesozoic carbonates: 4—average, 5—Eocene, 6—Paleocene, 7—limestone,8—dolomite, 9–10—deepwater carbonate mud, 11–12—chalk. (d) Argillaceoussediments and rocks (after Rieke and Chilingarian, 1974): 1—Proshlyakov;2—Meade; 3—Athy; 4—Hosoi; 5—Hedberg; 6—Dickinson; 7—Magara; 8—Weller; 9—Ham; 10—Foster and Whalen.


layers of the lithosphere enables one to start solving the problem of amathematical simulation of the consolidation process of sedimentary rocks.

Many attempts were made to construct a mathematical model. Someof them dealt with such properties of sediments and compacting rocksas elasticity, plasticity, viscoelasticity, thixotropy, etc., that are rathervariable depending on the type of sediment. Various differentialequations were analytically derived, which enabled one to describe theprocesses of rock changes in a space-time continuum of upper layersof lithosphere. For example, R. Berner (1971, see Chilingarian andRieke, 1976, p. 59) suggested a differential equation to evaluate therate of sediment compaction (as a change in porosity) as follows:

dφ/dt = (Rd/γ

ma)[1/(1 – φ)](dφ/dD)

t(94)

where φ is the porosity (fraction); D is the depth of burial; Rd is therate of sedimentation (weight of a sediment per unit of area per year);γma is the density of solid phase (matrix) of formation; and t is theduration of compaction. The (dφ/dD) term can be determined fromdepth-versus-porosity curves (e.g., see Figure 11-5).

On the basis of a joint solution of the Darcy and material balanceequations, Buryakovsky and Dzhevanshir (1976a) obtained the follow-ing model of clay compaction:

φ = φo - [4(1 – φ

o)KDt]/h2 (95)

where K is the filtration coefficient; D is the depth; h is the thicknessof a compacting clay layer; and t is the duration of compaction.

This model is helpful in determining the sealing properties of theclay caprocks in different regions of Azerbaijan (i.e., the central andsouthwestern portions of Apsheron Peninsula; the northern and southernportions of Baku Archipelago; and the Lower Kura Depression). Inorder to compare Pliocene formations with the more ancient ones, thesealing properties of caprocks of Mesozoic age in the West Siberianlowland and rocks of Devonian age in the Volga-Urals oil and gasprovince were evaluated.

As mentioned above, the application of differential and other analy-tical equations is not the only mathematical method to account for timewhen simulating geological systems. An empirical approach is simplerand sufficiently reliable when used for the history of the development


of the upper part of lithosphere. It is based on a comparison betweenconsolidation curves (Figure 11-5) of rocks of different ages and onthe approximation of discrete age data by a continuous function.Equation 93 may be given as an example of dependence of shaleporosity on the geologic age, taking into account the depth of burialand lithology of rocks studied.

Many equations were obtained on the basis of experimental investi-gations of rocks at high pressures and temperatures (Dobrynin, 1970;Pavlova, 1975). One of the limitations in using these models forregional lithological studies is that they are all able to consider onlyelastic deformation of sediments and rocks occurring as a result of thecompaction process under the pressure of overburden (thickness of theoverlying sediments). Using such models, it is impossible to take intoaccount irreversible deformations resulting from other processes ofdiagenesis and catagenesis. Additionally, a geologic time factor is notpresent in these models, i.e., the models cannot be related as dynamicmodels, which does not correspond to the systems approach to theproblem of prediction of properties of rocks.

Compaction of Terrigenous (Siliciclastic) Rocks

The rate of compaction of terrigenous sediments depends on thelithology, rate of sedimentation, and tectonic regime of the sedimen-tation basin. Compaction of sandy-silty and clayey sediments takesplace at different rates and differs from compaction of carbonate andevaporite deposits. One of the most important properties determiningthe degree of compaction of sediments is the ease of release (expulsion)of interstitial waters: sand gives up pore waters easier than clay. Thepresence of thick strata of water-saturated clays in a sedimentarysection retards the compaction. A rapid rate of sedimentation alsoretards the compaction process. Conversely, intensive tectonic activitymay result in rapid lithification. Generally, the rate of sedimentationis determined by the rate of tectonic movements and depends on theinterrelationships among the rate of influx of sedimentary material,washout of sediments, and the rate of subsidence of the basin floor[or uplift of the onshore area (mainland)].

Geosynclines are characterized by a rate of sedimentation of ap-proximately 100–200 meters per million years, whereas platforms havea rate of 20–30 meters per million years. Taking into account a


simultaneous process of consolidation of sediments, the rate of their accu-mulation in subsiding areas (depressed zones) may be ten times higher.

An attempt was made by Buryakovsky et al. (1982a) to describesystematically the process of sediment compaction. The curves show-ing changes in the porosity with depth may be described by the so-called “organism-growth model,” equivalent to the “model of propor-tional effects.”

The difference between the “model of organism growth” and the“model of proportional effects” is as follows: the former is based onthe equality of the rate of change of parameter y of some process tothe value of this parameter reached at a certain moment of time t, i.e.,

dy/dt = cy, (96)

which leads to an exponential dependence of the parameter y on time t:

y = yoect (97)

where c is the factor of proportionality.The second model is derived from the equality of absolute change

of the parameter y to the value of this parameter reached at a certainmoment of time, i.e.,

dy/dc = cy (98)

resulting in an exponential dependence of the parameter y on the factorof proportionality c:

y = yoec (99)

If the process is affected by the sum of different factors, then theequation becomes:

y y co ii

n

=

=

∑exp1

(100)

This model can be transformed into a multiplicative model:

y y Xo ii

n

==

∏1

(101)


where Xi = exp(ci), and i

n

=∏

1Xi is a generalized measure of the change

in parameter y.Based on the principle of equality of the degree of evolution of the

compaction process to the obtained value of some parameter charac-terizing this process, the writers obtained a number of models:

(a) Model of the degree of sediment compaction (compaction modelof K. Terzaghi, 1961):

Ut = 1 – h

t/h

o = 1 – {[h

minexp(c

hh

mint)]/[h

min – h

o(1 – exp(c

hh

mint))]} (102)

where ho, ht, and hmin are thicknesses of the layer before compaction,at time t, and for the completely compacted rock (lowest, minimumvalue), respectively; ch is the factor of proportionality.

(b) Model of density change:

γt = [γ

oγ

maxexp(cγγmax

t)]/[γmax

– γo(1 – exp(cγγmax

t))] (103)

where γo, γt, and γmax are rock densities before compaction, at time t,and the highest value for the completely compacted rock, respectively;cγ is the factor of proportionality.

(c) Model of porosity change:

φt = [φ

oexp(–cφt)]/[1 – φ

o(1 – exp(–cφt))] (104)

where φo, and φt are porosities before and during the process ofcompaction of sediments and rocks; and cφ is the factor of proportionality.

Models based on Equation 101 were widely used in predictingreservoir rock properties and physical properties of terrigenous rocksat different geological and physical conditions of the South CaspianBasin, Daghestan Plain, and the Middle Caspian Basin at depths of6–9 km. Many examples are given by Buryakovsky et al. (1982a, 1990b).

Compaction of Carbonate Rocks

There are a number of major differences between the compactionof terrigenous and carbonate rocks, with the early lithification ofcarbonates. Most researchers (Proshlyakov, 1974; Pavlova, 1975;Bagrintseva, 1977; Chilingarian et al., 1979; and Chilingarian et al.,1995) consider the changes in the carbonate rock properties, includingthose due to burial, to be caused by different physicochemical processes


occurring in the pore space of sediments and rocks. In this case,influence of gravitational compaction plays a secondary role. Otherresearchers (Dobrynin, 1970; Bezborodova, 1977; and Aleksandrov,1987) consider the geostatic load to be the main factor affecting thecompaction of carbonates, i.e., the effective pressure, which is equalto the difference between the total overburden load and the pore(reservoir) pressure. According to these authors, secondary processeschange sediments and rocks only locally, distorting general regularitiesof their compaction with depth. This is particularly true in the caseof compaction of chalks. The problem lies in the retention and develop-ment of secondary porosity, e.g., solution porosity (vugs, etc.) andporosity created by dolomitization.

The initial porosity of carbonates often approaches that of sand-stones in that their structure consists of aggregates of oolites, grains,and crystals, whereas the sandstones are granular. Carbonates also havea more heterogeneous pore structure. The initial (primary) porosity ofcarbonates depends on their genetic type to a great extent: it isthe largest in biogenetic, biomorphic and clastic (detrital) varieties,whereas it is considerably lower in cloddy and the chemogenic ones(excluding chemogenic oolitic limestones). According to the data ofAksenov et al. (1986), values of maximum porosity of carbonate rocksconsidering structural-genetic types are: biogenetic rocks—24% andseldom 26%; biogenetic-detrital—24% and seldom 34%; clotted-cloddy—13% and seldom 17%; crystalline-granular—4% and seldom6%; pelitomorphic—2% and seldom 6%; and oolitic and pisolitic—24% and seldom 34%.

As in the case of terrigenous rocks, carbonate rocks which hadhigher initial porosities, underwent the most intensive epigeneticchanges. It should be noted that lithification of carbonate rocks takesplace much faster than that of sandstones and siltstones. This resultsin an earlier completion of the process of mechanical compaction.

More than 30 different processes, which are controlled both by localand regional factors, occur during the diagenesis and catagenesis(Larsen and Chilingar, 1983). Lithification of carbonate sediments isof biochemical, physicochemical, and mechanical nature. To somedegree these processes occur simultaneously and change both composi-tion and pore geometry of sediments. With time, their rates are reduced.

An essential difference between mechanical and biochemical-physico-chemical processes is that the former acts in one direction with results


being irreversible. Biochemical and physicochemical processes, on theother hand, can take place in different directions; thus, increase anddecrease in secondary porosity of carbonate rocks can occur periodi-cally depending on the environmental conditions. For example, dia-genetic dolomitization may give rise to 13% porosity, which can belater destroyed by cementation or enhanced by dissolution.

Inasmuch as the mechanical processes are unidirectional and usuallyirreversible, possibly they play a major role in changing the original(primary) porosity of carbonate rocks. Thus, there is similarity withcompaction of terrigenous rocks. The process of compaction in car-bonates is quite different depending on the structural-genetic typeof carbonate.

Degree of consolidation, dissolution and cementation under theinfluence of geostatic pressure are all important. Increase of geostaticload as a result of subsidence of sediments leads to the solution ofcrystals under pressure, i.e., differential solution takes place in morestrained parts of grains with a subsequent deposition of material onthe surfaces having lower potential energy. In addition, grains (andcrystals) may get flatter parallel to the surface of stratification. Theseprocesses decrease the initial porosity both in carbonate and terri-genous rocks.

NUMERICAL SIMULATION OF OIL- ANDGAS-BEARING ROCK PROPERTIES

Methodology of Numerical Simulation

The modeling of physical properties of rocks for predicting theseproperties in the unexplored areas, in general, and at great depth, inparticular, indeed is important (Krumbein and Graybill, 1969; Harbaughand Bonhem-Carter, 1974; Griffiths, 1981; Merriam, 1981; Magara,1982; Buryakovsky et al., 1982a, 1990b, 1991b; Buryakovsky, 1992).

The main factor of post-sedimentational changes of any deposit isthe compaction under the pressure of overlying strata, resulting in thecontinuous decrease of the initial porosity of sediments and rocks withdepth. Figure 11-5 shows the dependence of porosity of terrigenousand carbonate sediments and rocks on the depth of burial as obtainedby different investigators. As shown in Figure 11-5, curves for allrocks of various composition may be described by an exponent; this


indicates similarity in the process of consolidation of sediments ofvarious origins. All this suggests a single concept for the solution ofthe problem of mathematical simulation of the processes of compactionand lithification of sedimentary rocks (Buryakovsky, 1993a).

In general, the problem of simulation of the process of sedimentaryrock compaction for prediction of the physical properties of rocks maybe solved by using three assumptions and their implication:

1. The process of post-sedimentational changes and consolidationof sediments is affected by many natural factors.

2. The effect of each factor is unique and differs from those of otherfactors.

3. The final result is the sum of individual influences of all naturalfactors on sediments during their transformation into rocks.

Thus, assumptions (1) and (2) indicate that individual influences ofany factor on the overall result of consolidation are small and areinversely proportional to the number of factors. Assumption (2) indi-cates that the influence of each factor is not equal to that of others.

The above discussion allows one to reach the following conclusions:(1) Small influences of each i-th factor resulting in a relative change

in the volume of consolidating sediments (U) can be represented asdUi /Ui, whereas the cumulative influences of all the factors can berepre-sented by ∫dUi /Ui. This expression is somewhat analogous toHooke’s law: dUi /Ui = –βσ where β = modulus of elasticity and σ =acting stress. If βσ is understood not only as the effect of static load,but also as the influence of any i-th factor, one would obtain:

dU U ci i ii

n

U

U

o

/ ==∑∫

1(105)

where ci is the influence of i-th factor.Hence, one can derive the following equations:

U U co ii

n

=

=

∑exp1

(106)

and

U Uo ii

n

==

∏ x1

(107)


where xi = exp(ci), and xii

n

=∏

1 is a generalized measure of a change in

parameter U.(2) Differences in the physicogeological nature of factors require

that those affecting rock consolidation be presented in the form ofrelative dimesionless values that also correspond to a formal type ofindividual influence dUi /Ui. The influence of the i-th factor (dUi /Ui ~ci) is evaluated (a) from the results of direct laboratory measurementson cores (reproduction of Hooke’s law), (b) by using analogies whendirect physical simulation is impossible, or (c) by actual field observa-tions and measurements.

Based on the above conclusions, a multi-variable model was pro-posed for evaluation of the degree of compaction and diageneticchanges of sediments after their deposition in the sedimentary basin.The general form of this model is:

U U xo ii

n

t ==

∏1

(108)

where Uo is the degree of the initial compaction of sediments and Utis the degree of compaction at a given depth and at a certain geologictime t; and xi is the modeling coefficient.

In selecting the modeling coefficients, one must consider:(1) conditions of accumulation of terrigenous and carbonate sediments,(2) their post-sedimentary changes (diagenesis and catagenesis orepigenesis), and (3) the structural evolution of the region. One shouldrecognize the role of different factors, such as: external (pressure,temperature, etc.) and internal (lithology, mineralogic composition,cementation, etc.).

The characteristic features of coefficients xi is their independence,which is a necessary condition for the model (Equation 108). Numer-ical values of coefficients xi corresponding to the factors ci are givenin Table 11-1. Their evaluation is carried out according to the initialdata of experimental and field studies (Dobrynin, 1970; Pavlova, 1975;Bagrintseva, 1977) using concept of the fuzzy sets theory (Buryakovskyand Kuzmina-Gerasimova, 1982b).

Modeling coefficients take into account the influence of majorgeological (natural) factors on compaction and other diagenetic changesof rocks (Buryakovsky et al., 1981, 1982a, 1990b). These factors areas follows: (1) geologic age (in million years—my), (2) number of


Tab

le 1

1-1

Nu

mer

ical

Val

ues

of

Fac

tors

Det

erm

inin

g t

he

Deg

ree

of

Co

mp

acti

on

Nor

mal

ized

Sca

le,

TI

00.

10.

20.

30.

40.

50.

60.

70.

80.

91.

0

Fac

tor

Sca

les

of A

bsol

ute

Val

ues

of F

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rs

Abs

olut

e ge

olog

ical

age

,0

5010

015

020

025

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0A

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atio

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171.

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601.

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ture

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, °C

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0R

ate

of s

edim

enta

tion

, R

d, m

/my

2030

5080

100

200

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800

1000

2000

Con

tent

of

quar

tz i

n sa

ndst

ones

,10

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tent

of

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enta

tion

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ex,

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%0

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ting

of

sand

ston

es,

S ss1

23

45

67

89

10—

Sor

ting

of

shal

es,

S sh—

109

87

65

43

21

Hom

ogen

eity

of

carb

onat

es,

S c r0

12

34

56

78

910


tectonic (orogenic) cycles (in dimensionless tectonic—stratigraphicunits), (3) depth of burial (in kilometers), (4) temperature (in °C),(5) rate of sedimentation (in meters per million years), (6) content ofquartz in sandstones (in wt %), (7) content of smectites (montmoril-lonite) in shales (in wt %), (8) degree of cementation (content ofCaCO3 in wt %), (9) sorting coefficient of Trask, and (10) degree ofhomogeneity of carbonate rocks (dimensionless).

Ranges in the absolute values of natural factors are shown inTable 11-1. Scales of absolute values of natural factors are presentedin this table. Model (Equation 108) requires a normalized form ofnatural factors. Normalization equations for natural factors are shownin Table 11-2. These equations, which relate the absolute and thenormalized scales, were obtained from data in Table 11-1.

The number of natural factors used in Equation 108 varies depend-ing on the type of rocks. The degree of influence of a particular factoris also different for each type of rocks. There are three types of naturalfactors with a different degree of influence on rocks: strong, moderate,and weak.

Table 11-2Equations of Normalization

Factor Equation of Normalization

Absolute geological age, At, my T

A = 0.002A

t

Dynamic deformation, N, TN = 0.2 + 1.46logN

tectonic-stratigraphic units

Depth of burial, D, kilometers TD = 0.167D

Formation temperature, T, oC Tt = 0.005T

Rate of sedimentation, Rd, m/my T

R = 0.5(logR

d – 1.3)

Content of quartz in sandstones, Q, wt % TQ = 1 – 0.01Q

Content of smectites in clays, M, wt % TM = 0.02M

Cementation index, C, wt % TC = 0.033C

Sorting coefficient of sandstones, Sss

Tss = 0.1(S

ss – 1)

Sorting coefficient of shales, Ssh

Tsh

= 0.1(11 – Ssh

)

Homogeneity of carbonates, Scr

Tcr

= 0.1Scr


The “strong” factors affecting the compaction of sandstones aregeologic age and depth of burial. The factors of “moderate” influenceare: the number of tectonic cycles (epochs), quartz content, and degreeof cementation (CaCO3 content). The “weak” factors are: rate ofsedimentation, sorting coefficient of Trask, and temperature. Thus,eight natural factors affect compaction of sandstones.

Five natural factors affect the compaction of carbonate rocks. The“strong” factors are: geologic age, the number of tectonic cycles, depthof burial, and temperature. The “moderate” factors are the degree ofheterogeneity and degree of cementation.

For shales, there are eight natural factors. The “strong” factorsare: geological age, depth of burial, and rate of sedimentation. The“moderate” factors are: the number of tectonic cycles, content ofsmectites (montmorillonite), and degree of cementation. The “weak”factors are: the sorting coefficient and temperature.

Modeling coefficients are calculated using the following equation:

xi = exp(–a

jT

i) (109)

where aj is the coefficient of influence of normalized value Ti of anynatural factor on the various rock properties xi (Table 11-3). Coeffi-cients aj were obtained by examining numerous experimental data(Buryakovsky et al., 1982a; Chilingar, Bissell, and Wolf, 1979).

Using modeling coefficients, one can calculate the Z factor:

Z U U xt o ii

n

= ==

∏/1

(110)

The Z factor characterizes the relative degree of compaction andother diagenetic changes of sediments, i.e., the relative degree of rock

Table 11-3Coefficient aj

Degree of Influence of Natural Factors

Rock Type Strong Moderate Weak

Reservoir Rocks 0.968 0.714 0.511Caprocks 2.996 1.833 1.309


consolidation. This factor is used for calculation of rock propertiesusing the following equations (Buryakovsky, 1993a):

Porosity φ = φoZ

1(111)

Permeability k = ko(Z

1)4 112)

Density γ = γma

(1 – φoZ

1) (113)

where φo and ko are, respectively, the initial values of porosity andpermeability before compaction of sediments; γma is the density ofmatrix of consolidated rocks, and Z1 is equal to:

Z x x Z Zi ii

n

i

n

111

1 1 1 1=

===

∏∏ / – – / [ – ( – )]φ φo o (114)

Z1 is the relative change in porosity: φ/φo.

Calculation Technique

The technique of numerical simulation of the rock properties iscomputerized (Buryakovsky and Kuzmina-Gerasimova, 1982a, 1983;Buryakovsky, 1993a). The Monte Carlo method was used in calcu-lations using probable database intervals as an input. Thus, one canobtain statistical characteristics and histograms of rock properties. Thealgorithm of solution is presented in Figure 11-6. The main blocksshown in the flowchart in Figure 11-6 are as follows:

Block 1: Input of initial information.Block 2: Selection of rock type, using the following keys: KE = 1

for sandstones, KE = 2 for carbonate rocks, KE = 3 for shales.Block 3: Input of minimum CA(i ) and maximum CB(i ) absolute

values of numerical quantities of natural factors for each type of rocks.All factors are shown in Table 11-1 in the form of absolute scales. Inaddition, this block provides for an input of probable intervals of initialporosity and permeability values, and probable matrix density intervalsfor each rock type.

Block 4: Calculation of normalized T values of natural factors inthe limit of [0; 1], in the form of minimum T(2i – 1) and maximumT(2i) values, according to the equations of normalization in Table 11-2.

Block 5: Calculation of the modeling coefficients xi in the limit of[0; 1] in the form of minimum C1(i) and maximum C3(i) values for


Fig

ure

11-

6. P

roce

dure

for

the

res

ervo

ir-r

ock

prop

erty

sim

ulat

ion.


“strong,” “moderate,” and “weak” factors using Equation 109 andTable 11-3.

Block 6: Calculation of average values of the modeling coefficientsusing equation C2(i) = [C1(i) + C3(i)]/2.

Block 7: Creation of the file of random numbers by standard subroutine.Block 8: Simulation of parameters xi, φo, ko, γma by Monte Carlo

method in the form of triangle distribution of random values.Block 9: Simulation of relative degree Z of rock compaction accord-

ing to Equation 110.Block 10: Calculation of value Z1 using Equation 114.Block 11: Porosity simulation according to Equation 111.Block 12: Permeability simulation of sandstones according to Equa-

tion 112.Block 13: Density simulation according to the Equation 113.Block 14: Printing out of statistical characteristics of distributions

of rock properties: average value, standard deviation, variance, mini-mum and maximum values, and also the data to plot histograms andcumulative curves either in absolute frequencies or in relative frequencies.

The above described block-diagram was used to create a programin BASIC for numerical simulation of petrophysical parameters ofrocks (see Buryakovsky, 1993a).

Examples of Numerical Simulation

As examples of numerical simulation of petrophysical properties ofrocks, the following formations were used: (a) Mesozoic terrigenousand carbonate reservoir rocks and shales in the East Pre-Caucasus oil-and gas-bearing province and in the adjacent offshore areas of theMiddle Caspian Basin, and (b) Neogenic sandstones in the Apsheronoil- and gas-bearing region and in the adjacent offshore areas of theSouth Caspian Basin.

The method and software for numerical simulation of petrophysicalproperties of rocks can be applied to any geologic and stratigraphic attri-butes independent of the age and post-sedimentary changes of the rocks.

A. The Numerical Simulation of ReservoirA. Properties of Mesozoic Sandstones

Model Input. Geological age: 140–190 my; dynamic deformation:1.8–2.2 tectonic-stratigraphic units (dimensionless); depth of burial:


Permeability distribution: mean = 25.39 mD; minimum = 11.42 mD;maximum = 53.30 mD; standard deviation = 5.84 mD; and variance= 22.99%.

2.0–2.5 km; formation temperature: 85-95°C; rate of sedimentation:100–200 m/my; quartz content: 60-80%; degree of cementation: 12–18%; Trask sorting coefficient: 3–4; initial porosity before compaction:0.35–0.45; initial permeability before compaction: 1,000–2,000 mD;and density of rock matrix: 2.6–2.7 g/cm3.

Model Output:

1. Simulation of porosity

Statistical Distribution

CumulativeRelative Relative

Minimum Maximum Frequency Frequency Frequency

0.118 0.130 34 0.113 0.1130.130 0.142 106 0.354 0.4670.142 0.154 109 0.363 0.8300.154 0.167 43 0.143 0.9730.167 0.179 6 0.020 0.9930.179 0.191 2 0.007 1.000

Range in Porosity,Fraction

Porosity distribution: mean = 0.144; minimum = 0.118; maximum= 0.191; standard deviation = 0.0117; and variance = 8.13%.

2. Simulation of permeability




11.422 18.402 25 0.083 0.08318.402 25.382 138 0.460 0.54325.382 32.362 105 0.350 0.89332.362 39.342 27 0.090 0.98339.342 46.322 3 0.010 0.99346.322 53.302 2 0.007 1.000

Range in Permeability,mD





2.166 2.200 11 0.037 0.0372.200 2.233 39 0.130 0.1672.233 2.267 88 0.293 0.4602.267 2.301 100 0.333 0.7932.301 2.334 48 0.160 0.9532.334 2.368 14 0.047 1.000

Range in Bulk Density,g/cm3

Bulk density distribution: mean = 2.270 g/cm3; minimum = 2.166g/cm3; maximum = 2.368 g/cm3; standard deviation = 0.0378 g/cm3;and variance = 1.67%.

B. The Numerical Simulation of the Mesozoic Carbonate Rock Properties

Model Input. Geological age: 140–190 my; dynamic deformation:1.8–2.2 tectonic-stratigraphic units; depth of burial: 2.0–2.5 km;formation temperature: 85–95°C; homogeneity of rocks: 0.7–0.9; initialporosity before compaction: 0.35–0.45; and density of rock matrix:2.67–2.75 g/cm3.

Model Output





0.109 0.119 27 0.090 0.0900.119 0.128 89 0.297 0.3870.128 0.137 85 0.283 0.6700.137 0.146 63 0.210 0.8800.147 0.156 28 0.093 0.9730.156 0.165 8 0.027 1.000


3. Simulation of density







2.296 2.322 9 0.030 0.0302.322 2.348 27 0.090 0.1202.348 2.375 79 0.263 0.3832.375 2.401 85 0.283 0.6672.401 2.427 65 0.217 0.8832.427 2.453 35 0.117 1.000


Density distribution: mean = 2.385 g/cm3; minimum = 2.296 g/cm3;maximum = 2.453 g/cm3; standard deviation = 0.0326 g/cm3; andvariance = 1.37%.

C. The Numerical Simulation of the Mesozoic Shale Properties

Model Input. Geological age: 140–190 my; dynamic deformation:1.8–2.2 tectonic-stratigraphic units; depth of burial: 2.0–2.5 km;formation temperature: 85–95°C; rate of sedimentation: 100–200 m/my; content of smectites: 30–40%; degree of cementation: 10–12%;Trask sorting coefficient: 3–4; initial porosity before compaction: 0.45–0.55; and density of rock matrix: 2.6–2.7 g/cm3.

Model Output

1. Simulation of porosityStatistical Distribution



0.097 0.118 21 0.070 0.0700.118 0.138 70 0.233 0.303








2.082 2.139 11 0.037 0.0372.139 2.195 43 0.143 0.1802.195 2.252 103 0.343 0.5232.252 2.309 95 0.317 0.8402.309 2.365 36 0.120 0.9602.365 2.422 12 0.040 1.000



D. The Numerical Simulation of Reservoir Properties ofD. Neogene Sandstones

Model Input. Geological age: 10–12 my; dynamic deformation:1.1–1.2 tectonic-stratigraphic units; depth of burial: 2.0–2.5 km;formation temperature: 85–95°C; rate of sedimentation: 500-800 m/my; quartz content: 60-80%; degree of cementation: 10–15%; Trasksorting coefficient: 3–4; initial porosity before compaction: 0.35–0.45;initial permeability before compaction: 2,000–3,000 mD; and densityof rock matrix: 2.6–2.7 g/cm3.

0.130 0.159 102 0.340 0.6430.159 0.180 74 0.247 0.8900.180 0.201 27 0.090 0.9800.201 0.222 6 0.020 1.000


Model Output





0.225 0.243 30 0.100 0.1000.243 0.261 87 0.290 0.3900.261 0.278 113 0.377 0.7670.278 0.296 57 0.190 0.9570.296 0.313 11 0.037 0.9930.313 0.331 2 0.007 1.000



2. Simulation of permeability




299.21 372.45 10 0.033 0.033372.45 446.28 72 0.240 0.273446.28 519.81 116 0.387 0.660519.81 593.35 75 0.250 0.910593.35 666.88 23 0.077 0.987666.88 740.42 4 0.013 1.000

Range in Permeability,mD

Permeability distribution: mean = 492.30 mD; minimum = 299.21mD; maximum = 740.42 mD; standard deviation = 72.00 mD; andvariance = 14.62%.




Discussion of Results and Conclusions

The results of the numerical simulation show that the modelingcoefficients xi represent adequately the influence of many geologicalfactors on the petrophysical properties of rocks (Figure 11-7).

Thus, the results of numerical simulation show that there is asignificant difference between the reservoir properties of Mesozoicand Neogene rocks (Figures 11-8 and 11-9). Geological time is themain factor determining the degree of rock compaction: porosity ofMesozoic sandstone is about two times lower than that of Neogenesandstone (Figure 11-8a). Permeability of Mesozoic sandstone istwenty times lower than that of Neogene sandstone (Figure 11-8c), asindicated by tabulated data of example 1 versus example 4. Theseresults are in agreement with the data cited by many researchers (e.g.,Magara, 1982; Larsen and Chilingar, 1983).

Comparison of the results obtained by simulation of the clasticreservoir rock properties (sandstones) with those of the carbonaterocks shows that carbonate rocks become compacted and consolidatedfaster than sandstones. This is obvious from the results of examples1 and 2 (Figures 11-8 and 11-9). These results are in agreement with




1.792 1.839 3 0.010 0.0101.839 1.886 35 0.117 0.1271.886 1.933 88 0.293 0.4201.933 1.980 92 0.307 0.7271.980 2.027 62 0.207 0.9332.027 2.074 20 0.067 1.000



Figure 11-7. Results of numerical simulation of Mesozoic reservoir-rockproperties (Modified after Buryakovsky, 1993a). a—Porosity, b—permeability,c—density. 1—Average curve, 2—confidence limits.

those obtained by many investigators (e.g., Chilingar et al., 1979;Larsen and Chilingar, 1983).

The results of numerical simulation presented in examples 1 and 3(Figures 11-8 and 11-9) indicate that clays become compacted andconsolidated faster than sands. Extensive data on compaction of claysand sands were provided by Chilingarian and Rieke (1972); Rieke andChilingarian (1974); Magara (1982); and Larsen and Chilingar (1983).

The results of the numerical simulation indicate that statisticaldistributions of porosity and density obey the normal law (Figure 11-8a,b), whereas the distribution of permeability obey the log-normal law(Figures 11-8c). These results are in agreement with those of Harbaughand Bonham-Carter (1974) and Buryakovsky et al. (1982a).

A multi-variable model of lithification (compaction and other dia-genetic changes) of both terrigenous and carbonate sediments intorocks was constructed. This model is an integral part of models for


Figure 11-8. Statistical distribution of petrophysical properties of rocks(Modified after Buryakovsky, 1993a). a—Porosity, b—density, c—permeability.Mesozoic rocks: 1—sandstone, 2—carbonates, 3—shale; Cenozoic rocks:4—sandstone. ω—frequency.

the properties of oil- and gas-bearing rocks, such as porosity, permea-bility and bulk density. The relationships between absolute and norma-lized values of geologic factors were established on the basis ofexperimental and field data. The models for the evaluation of bothreservoir rock and caprock properties were proposed.


Fig

ure

11-

9. C

umul

ativ

e pr

obab

ility

cur

ves

for

petr

ophy

sica

l pr

oper

ties

of r

ocks

(M

odifi

ed a

fter

Bur

yako

vsky

, 19

93a)

.a—

Por

osity

, b—

dens

ity.

Mes

ozoi

c ro

cks:

1—

sand

ston

e, 2

—ca

rbon

ates

, 3—

shal

e; C

enoz

oic

rock

s: 4

—sa

ndst

one.


Software was developed for calculation of rock properties. Theproposed models and computer program allow one to obtain boththe reservoir rock and caprock properties at reservoir temperatureand pressure. The proposed method of numerical simulation of oil-and gas-bearing rock properties was verified by numerous exam-ples provided.


384

CHAPTER 12

Other Applications ofNumerical Simulation

MethodologyBASIC PRINCIPLES AND CALCULATION TECHNIQUES

With increasing depth of exploration, one of the major problems isthe estimation of influence of natural factors (overburden and effectivepressures, reservoir pressure, formation temperature, lithology, porespace geometry, etc.) on the petrophysical properties of sedimentary rocks.

Mathematical models of the processes which describe the influenceof pressure, temperature, and structural and lithological factors onpetrophysical properties of sedimentary rocks can be presented usingtwo approaches: deterministic (analytical) and probabilistic (statistical).Both of these approaches are mutually dependent and their combina-tion enables the generalization of studied processes.

Statistical methods can be used only when sufficient data exists. Thedata is obtained either at the stage of completion of exploration orduring subsequent development of a deposit. Obtaining the representa-tive data can be very expensive. Therefore, a new procedure shouldbe developed for prediction of rock properties when data are sparse.Such studies are especially appropriate for the exploration and develop-ment of offshore oil and gas field of the offshore areas of Azerbaijanand Turkmenistan. In the Caspian Sea, the productive formations (1)occur at great depths; (2) are widespread with abnormally high porepressures; and (3) the problems of drilling, coring and logging do notallow acquisition of reliable data for the evaluation of reservoir rockand caprock properties, especially at the early stage of exploration.

Data collection first involves determination of petrophysical proper-ties of rocks if cores are available. Secondly, one must determine the

Other Applications of Numerical Simulation Methodology 385

limiting values (cut-offs) of any parameter used for identification ofbeds (a typical problem of the pattern recognition theory). Both ofthese present problems in the simulation of rock properties.

The main principles used in simulation are as follows:

1. The most complete quantitative characteristics of geologic and petro-physical parameters are delineated by their statistical distributions.

2. The distributions of geologic and petrophysical parameters aresimulated on the basis of their mathematical descriptions (models),which may be probabilistic as well as deterministic.

3. In the case of scarcity of data, the artificial distributions ofmodel input data are formed by means of their interval-probablepresentation, and the Monte Carlo technique is used for plottingsuch distributions.

4. For the purposes of prediction of petrophysical properties ofrocks, simulation of statistical distributions is required on thebasis of models with variable input data depending upon changesin the regional geologic environments.

5. For the purposes of identification of formations, simulation ofmore than one statistical distribution and the determination of thecut-off points for the simulated parameters (which allows strataclassification) are required.

The characteristic feature of construction of artificial distributionsfor solving geologic modeling problems is that the decision about theinfluence of various natural factors upon the parameter under studyis often made only at the intervals of their variation, which indicatesthe presence of fuzzy data (Zadeh, 1980). In such a case, the interval-probable determination of the input data and the subsequent calculationresults provide consideration of the indeterminate form of the basic factors.

Figure 12-1 shows a functional block-diagram of parameter imitationon the basis of which the simulation algorithm was developed. Nota-tions in the diagram are as follows: LP—Leading Procedure (Predic-tion or Identification); MD 1, ..., MD N—Mathematical Descriptions(Models) of parameters; PBDF—Procedure of Basic Data Formation;PORV—Procedure for Obtaining the Random Variables; PFU, PFN,PFT—Procedures for Formation of random variables with Uniform,Normal or Triangular distributions; PSP—Procedure for StatisticalProcessing; PObD, PPD, POD—Procedures for Obtaining, Processing,and Output of Data; CP—Control Procedure for selection of the type


Figure 12-1. Block-diagram of simulation of petrophysical properties (nota-tions in the block-diagram are discussed in the text).

of problem. If a prediction problem is to be solved, the control istransferred to the procedure of formation of basic data with the aimof changing the influence of input factors while preserving the modeltype. If an identification problem is to be solved, the control is trans-ferred to the choice of the required models (mathematical descriptions).

SIMULATION OF RESERVOIR-ROCK PROPERTIES

To solve the problems of numerical simulation of reservoir rock andcaprock properties, mathematical models of various parameters ofrocks (and the basic geologic data of different accuracy and reliability)


were used. The theory, methods and computer technique have beendescribed above.

The most important reservoir rock and caprock properties areporosity, permeability, oil or gas saturation, and density. The modelsof porosity φ, permeability k, and formation bulk density γ were usedas mathematical descriptions of the rock properties (see Equations 111,112, 113 and 114). Initial oil or gas saturation was evaluated from thefollowing equation:

So/g

= 1 – ak–b (115)

where the empirical coefficients a and b have the following (average)values for the region under study: a = 0.80 and b = 0.225.

In determining the baseline for coefficients xi, conditions of rockoccurrence in the areas of the northern, northwestern and northeasternflanks of the South Caspian Basin were assumed. In this region theoil- and gas-bearing formations belong to the Productive Series (inAzerbaijan) or to the Red-Bed Series (in Turkmenistan) of the MiddlePliocene age (10–12 million years). The region under study wassubjected to the action of one Alpine Orogeny (Khain, 1954; Potapov,1964). The intensity of subsidence of the sedimentary basin floorduring the Middle Pliocene time decreased with depth, and increasedin the direction from the Apsheron Peninsula to the Apsheron and Bakuarchipelagos and from the Cheleken Peninsula to the Turkmenian shelf,i.e., southward. The mineralogical composition of sediments is mainlyquartz (40 to 80%); Trask sorting coefficient of grains is 2–4; degreeof cementing is moderate (CaCO3 content in sandstones is 8–12%).Properties of reservoir rocks and caprocks of oil- and gas-bearingformations and aquifers at the formation pressure and temperature weredetermined at depths of up to 6,500 m (at this depth formation temp-erature is 105 to 110°C).

The parameters under study were estimated up to a depth of 9,000m (Figures 12-2 and 12-3). These figures show that as stratigraphic(to the bottom of the Middle Pliocene interval) and hypsometric (alongthe same bed) depths increase, the absolute and effective porositydecrease from 19–20 to 14–15% and from 14–15 to 9–10%, respec-tively. The corresponding permeability of sandstones and siltstones



Fig

ure

12-

2. R

esul

ts o

f si

mul

atio

n of

res

ervo

ir-r

ock

prop

ertie

s in

the

Sou

th C

aspi

an B

asin

(M

odifi

ed a

fter

Bur

yako

vsky

et a

l., 1

990b

). a

—P

oros

ity,

b—pe

rmea

bilit

y, c

—de

nsity

. 1—

Ave

rage

cur

ve,

2—co

nfid

ence

lim

its,

3–4—

core

dat

a, 5

—st

atis

tical

dis

trib

utio

n of

act

ual

(mea

sure

d) p

erm

eabi

lity.


Fig

ure

12-

3. R

esul

ts o

f si

mul

atio

n of

pet

roph

ysic

al p

rope

rtie

s of

roc

ks (

vari

atio

n w

ith d

epth

) (M

odifi

ed a

fter

Bur

yako

vsky

et a

l., 1

990b

). a

—R

eser

voir

roc

ks f

rom

Aps

hero

n re

gion

: 1—

poro

sity

, 2—

perm

eabi

lity,

and

3—

dens

ity.

b—S

hale

s fr

omth

ree

regi

ons

of t

he S

outh

Cas

pian

Bas

in:

4, 5

, 6—

poro

sity

, an

d 7,

8,

9—de

nsity

.


decreases from 130–150 to 40–60 mD. At a depth of 9,000 m, porosityvaries from 7 to 10%, whereas permeability changes from 2 to 11 mD.Tables 12-1 and 12-2 show the predicted values of reservoir-rockproperties of the Productive Series of the offshore fields in the Apsheronand Baku archipelagoes, respectively.

SIMULATION OF PETROPHYSICALPROPERTIES OF ROCKS

Mathematical Model of Electrical Resistivityof Sedimentary Rocks

For a homogenous, isotropic medium with resistivity R, changes ofoverburden pressure dpe, changes of pore (reservoir) pressure dpi, andchanges of temperature dT, will result in the changes of electricalresistivity of rocks as follows:

dR = (∂R/∂pe)dp

e + (∂R/∂p

i)dp

i + (∂R/∂T)dT (116)


Table 12-1Predicted Reservoir-Rock Properties of Different Suites of the

Productive Series in Offshore Areas

Oil/gas EffectiveDepth, Porosity, Saturation, Porosity, Permeability,

Suite m % % % mD

Surakhany 200–1,500 23 77 18 302Sabunchi 200–2,000 23 77 18 283Balakhany 200–2,500 23 76 18 287“Pereryv” 200–2,500 23 76 18 287NKG 300–2,500 21 71 15 117NKP 300–2,500 23 77 18 280KS 400–1,500 23 73 17 139PK 500–2,000 23 77 18 298KaS 700–2,200 22 74 16 174


or

dR/R = (1/R)(∂R/∂pe)dp

e + (1/R)(∂R/∂p

i)dp

i + (1/R)(∂R/∂T)dT (117)

Assuming that pe, pi and T are independent of R, the followingapproximate solution was obtained (Dobrynin, 1970):

R(pe, p

i, T)/R ≈ [R(p

e)/R] • [R(p

i)/R] • [R(T)/R] (118)

If one assumes that only pe, pi, or T influence the resistivity R atone time, the influence of the next parameter begins when the actionof the previous one ends. In such a case, a mathematical model canbe constructed where the influence of each one of the parameters isexpressed by a certain coefficient. Each one of these coefficients isrelated to resistivity R, with the influence of certain parameters on theoriginal resistivity R0. The overall effect of these parameters onresistivity is a product of influences of individual parameters. Eachone of these coefficients is greater than 1 when the parameter influenceincreases the resistivity and is smaller than 1 if reverse is true.

If other factors, such as lithologic or structural, are involved, thismodel is broadened, and coefficients can be derived. The overall effectcan be presented as a product series:

R R ki i ii

n

i

m

i

L

/ /0111

= ====

∏∏∏ α β (119)

Table 12-2Predicted Reservoir-Rock Properties of Some Offshore Fields in the

Apsheron and Baku Archipelagoes

Oil/gas EffectiveDepth, Porosity, Saturation, Porosity, Permeability,

Field m % % % mD

Khamamdag Deniz 3,200–4,100 20 73 15 164Garasu Deniz 3,900–4,500 19 71 14 107Sangi Mugan 3,900–4,500 19 71 14 107Aran Deniz 3,700–4,300 19 72 14 109Dashly 4,800–5,300 17 69 12 172


where L = m + n, α > 1, and β > 1.This is a general statistical model describing all parameters influ-

encing resistivity of sedimentary rocks.The proposed statistical model reflects the nature of various phe-

nomena if the following conditions are met:

1. All proposed coefficients ki take into account the total influenceof thermodynamic and lithologic factors on R in the naturalsetting. These coefficients are obtained empirically by testingrock samples using equipment capable of simulating naturalconditions.

2. Numerous experiments confirmed the influence of differentthermodynamic and lithologic factors on resistivity of rocks.

3. Results obtained using the preceding model are in agreement withthose obtained from well-logging. The Rn/R0 ratio obtained fromthe statistical model (Dzhafarov and Buryakovsky, 1979) closelyagree with ratios obtained from well-logging.

4. The statistical model is a generalization of the deterministicmodel and is a result of logical extension for any number of factors.

Calculations are carried out by simulation of coefficients ki usingthe Monte Carlo techniques in intervals given on the basis of experi-mental and field data. In studying the resistivity changes with depth,experimental functions of R versus pe, pi, and T are transformeddepending upon the depth only. Then the resistivity values are simu-lated by Equation 119 for successive points at different depth takinginto account coefficients ki. The distributions of coefficients can beuniform, triangular, normal, lognormal, etc.

An example of such resistivity calculation for water-saturatedsandstones of the Apsheron oil and gas reservoirs is presented inFigure 12-4. The experimental results are in good agreement with thoseobtained from theoretical model.

The same statistical model can be constructed using a wider systemsapproach (Middleton, 1962). If one assumes that at moment ti resis-tivity is Ri and at moment ti-1 it is Ri-1, and that their difference isproportional to original resistivity, then:

Ri – R

i–1 = k

i(R

i–1) (120)

where ki is the independent coefficient of proportionality.


On the basis of previous assumptions it follows that:

Ri = R

0(k + 1) (121)

As n → ∞ one obtains:

R R kni

n

= +=

∏01

1( ) (122)

that is, we have a multiplication model.As a rule, such models lead to lognormal distribution (Middleton,

1962). There is a lognormal distribution of resistivity, which occursin nature.

If one assumes that R0 is the original resistivity of formation witha given distribution g(R) (R0 is constant for given conditions), and kiare coefficients determining this resistivity (these coefficients couldbe either greater than 1 or less than 1; coefficients ki are independentof each other and their individual effects do not depend on the pre-vious resistivity of rock), then after n changes resistivity of a givenrock will be equal to:

Rn = R

0• k

1• k

2• ... • k

n(123)

This statistical model is a function of time: the resistivity Rn is afunction of time tn. In certain geological scenarios, however, time andspace coordinates become mutually interchangeable.

The predicted value of Rn, therefore, can be interpreted also as afunction of space, at a particular depth. In this statistical model, Rn isanalogous to R(pe, pi, T) where pe is the effective (grain-to-grain)pressure, pi is the reservoir (pore) pressure, and T is the formationtemperature. This model can be used for predicting resistivity at agiven depth, under certain lithologic and thermobaric conditions. Atdifferent depths, the resistivity R(pe, pi, T) varies identically to theresistivity R0.

The coefficients ki, which include the influence of lithology andsaturating fluids on resistivity, are as follows (Figure 12-5): (1) packing;(2) compressibility of fluids saturating the pore space; (3) com-pressibility of the cementing material (argillaceous, argillaceous-calcareous or calcareous); (4) influence of the relative content and


types of clays in sandstones on the surface electrical conductivity;(5) thickness of the double electrical layer; (6) geometry of the porespace; and (7) temperature.

The coefficients ki were used for determining corrections (Table 12-3)(for the effective pressure pe and formation temperature T ) for the trueresistivity Rt and formation resistivity factor (F ) of water-saturatedcore samples measured under atmospheric conditions.

Figure 12-4. Results of simulation of the effect of temperature, pressure, rocktexture and lithology on the electrical resistivity of water-saturated sandstones(Modified after Buryakovsky et al., 1990b). Type of pore cement: a—carbonate,b—clay-carbonate, c—clay.


Figure 12-5. Fuzzy relations Fi for model of sedimentary-rock resistivityconsidering the following effects. Effect of differential pressure: 1—effect onmatrix; 2—electrolyte; 3–5—cement: 3—clay, 4—clay-carbonate, 5—carbonate;6—clay content; 7—double-electrical layer; 8—pore-space geometry. Effectof temperature: 9–11—effect on rock skeleton and cement: 9—clay, 10—clay-carbonate, 11—carbonate; 12—electrolyte.

Other Mathematical Models of PetrophysicalProperties of Rocks

Two important problems of petroleum geology (modeling of petro-physical properties of oil- and gas-bearing formations) have beensolved: (a) identification of reservoir beds and (b) identification ofproductive formations. Any of the parameters listed below may be usedas a cut-off (identifying) parameters:


1. true resistivity, Rt2. interval transit time, ∆t3. macroscopic cross-section of thermal neutron absorption, ∑4. formation bulk density, γ

Information about the types of fluid saturating the rocks is providedby resistivity. Although various models of petrophysical properties ofrocks are used, the most commonly used are the following relationships:

Rt = R

wτφ–mS

w–n (124)

Rt,a

= Rt/[k

sh(R

t/R

sh – 1) + 1] (125)

∆t = φ∆tf + (1 – φ)∆t

ma(126)

Table 12-3Corrections to the (1) Resistivity and (2) Formation Resistivity Factor for

Effective Pressure and Temperature In Situ

Depth, Correction in Rt Correction in Rt Correction in Fm for peff for peff and T for peff and T

Clay Cement

2,000–3,000 1.78 0.66 1.613,000–4,000 1.88 0.62 1.744,000–5,000 2.06 0.58 1.785,000–6,000 2.05 0.52 1.75

Clay-Carbonate Cement

2,000–3,000 1.45 0.61 1.483,000–4,000 1.52 0.57 1.694,000–5,000 1.51 0.52 1.615,000–6,000 1.45 0.47 1.58

Carbonate Cement

2,000–3,000 1.23 0.57 1.323,000–4,000 1.25 0.52 1.434,000–5,000 1.25 0.48 1.385,000–6,000 1.22 0.43 1.33


∑ = φ∑w + φ (1 – ∑

w)∑

o + (1 – φ)∑

ma(127)

γ = φγf + (1 – φ)γ

ma(128)

where Rt, Rt,a, ∆t, ∑, and γ are the true resistivity of isotropic (Rt)and heterogeneous (Rt,a) rocks, interval transit time in rocks, macro-scopic cross-section of thermal neutron capture (absorption), andformation bulk density, respectively. Subscripts f, w, o, and ma denotethe fluid, water, and oil filling the pore space, and the rock matrix,respectively; Rw and Rsh are the resistivities of formation water andshale; ksh is volume content of clay in an laminated shaly reservoirrock; τ is the electrical tortuosity of pore channels; and m and n arethe empirical coefficients (m = 1.6 and n = 2.0 for the rocks of regionunder study; average values).

Heuristic formulas were used for determining the cut-off (separating)values of parameters. To distinguished the water- and oil-saturated bedsusing their resistivity, the following criteria for determining the cut-off values of Rt,cr were used:

Rt,cr

= [(DoR

w – D

wR

o) + (D

wD

o(R

o – R

w)2

– (Do – D

w)lnD

o/D

w)]1/2/(D

o – D

w) (129)

Rt,cr

= 1/2(Rw,max

+ Ro,min

) (130)

Rt,cr

= (Rw,md

• Ro,md

)1/2 (131)

where Rw, Ro, Rw,md, and Ro,md are average and median values, whereasDw and Do are standard deviations of resistivity in water- and oil-saturated layers.

The calculations show that the cut-off values of petrophysicalparameters depend considerably upon the geometry of the pore space,the degree of cementation, the clay content in reservoir rocks, and thesalinity of formation water. For example, with the increase in claycontent in the reservoir rocks and transition from isotropic to aniso-tropic layers, the cut-off value of resistivity of the oil- and gas-bearingformations decreases from 10–15 to 4–8 ohm • m.

Thus, the use of static (for identification) as well as dynamic (forforecast) stochastic models in geologic studies allows solution of anumber of important practical problems when data are scarce by usingartificial distributions of various geologic and petrophysical parameters.


SIMULATION OF WATER INVASION INTOOIL-SATURATED ROCKS

The simulation of dynamic geotechnological systems on using themethodology described above, gave rise to two groups of mathematicalmodels of changes in the petrophysical properties of reservoir rocksduring oil displacement by water (Buryakovsky, 1985a; Buryakovskyand Chilingarian, 1991c):

1. Model of water invasion into the oil reservoir during the waterdrive. In the course of oil displacement by water, water saturation Swof the reservoir increases from the value equal to the residual watersaturation (Sw,1 = Sw,r) to the value of the pore volume minus theresidual oil saturation [Sw,2 = (1 – So,r)]. A dynamic model [Sw = f(t)]with a Sw range between Sw,r and (1 – So,r) can be constructed. Onecan use Equation 88 at f(x) = x(1 – x), where x = Sw. With the initialand final conditions taken into account, the solution of Equation 88can be presented as follows:

Sw = [(1 – S

o,r)S

w,rexp((1 – S

o,r)εt)]/[(1 – S

o,r)

– Sw,r

+ Sw,r

exp((1 – So,r

) εt)] (132)

where t is the duration of oil displacement by water.The change of water saturation versus time is shown on Figure 12-

6 (curve 1).2. Models of variation in the petrophysical properties of reser-

voirs during waterflooding. The electrical resistivity Rt of an homo-geneous oil-bearing bed changes according to the following equation:

Rt = R

t,0{[(1 – S

o,r) – S

w,r + S

w,rexp((1 – S

o,r)εt*)]/[(1 – S

o,r)

× Sw,r

exp((1 – So,r

)εt*)]}n (133)

where Rt is the electrical resistivity of the reservoir rock at any Sw;Rt,0 is the electrical resistivity when Sw = Sw,r; and t* is the dimen-sionless time (t* = t/tmax).

Other petrophysical parameters can be represented in a similar way.As Figure 12-6 demonstrates, the change in water saturation from 0.2to 0.8 causes:


a. A 13-fold decrease in the electrical resistivity Rt of a homogen-eous oil-bearing reservoir (curve 4);

b. Greater than 3-fold decrease in the electrical resistivity Rt,a of aheterogeneous reservoir (curve 3); and

c. A 1.27-fold decrease in the acoustic interval transit time ∆t(curve 2) at a constant salinity of the reservoir water and geome-try of the pore space.

The above described dynamic models of certain petrophysicalparameters of the oil-saturated reservoirs allow one to achieve two goals:

1. To follow closely the changes in these parameters occurringduring oilfield development.

2. To apply the models for observation of the water invasion intothe reservoir and of movement of the oil-water contact (basedon well-log information).

Figure 12-6. Results of simulation of petrophysical properties (variation withtime). 1—Water saturation Sw. G/G0 ratio for: 2—acoustic transit time ∆t;3—anisotropic true resistivity Rt,a, 4—isotropic true resistivity Rt. G = petro-physical parameter, G0 = initial value of G.


The specific feature of the models (Equations 132 and 133) is thatthey take into consideration the so-called “technological” duration ofthe process of reservoir development. The model (Equation 132),which describes the dynamics of water movement in oil-saturatedreservoir in the process of its development, can be changed into amodel of lateral migration of oil (if the water is replaced by the oil).

SIMULATION OF PORE-FLUID (FORMATION) PRESSURE

The description of processes of pore-fluid pressure generation anddestruction is obtained from Equations 89, where f1(x1) = p1 and f2(x2) =p2 are pore-fluid pressures in the process of their increase and decrease,respectively. This dynamic model satisfied the following conditions:

1. A current pore-fluid pressure at any moment of time is a resultof dynamic equilibrium among the synchronous processes ofgeneration/dissipation of these pressures in a given geologicobject.

2. Natural factors affecting generation/dissipation of pore-fluidpressures are permanent.

3. The rate of change in pore-fluid pressure in a given geologicobject is proportional to the current pore-fluid pressure.

4. Pore-fluid pressures increase/decrease so that a constant portionof the current pore-fluid pressure increases/decreases per unit oftime (the given condition is not obligatory).

5. Factors of pressure drop act so that a portion of pressure de-crease per unit of time is equal to the product of increasingportion of the pressure by its decreasing portion.

Dynamic models can be described by a system of nonlinear differ-ential first-order equations as follows:

dp1/dt = ε

1p

1 – γ

12p

1p

2(134)

dp2/dt = –ε

2p

2 + γ

21p

1p

2

where p1 = p1(t) is the pore-fluid pressure during the period ofits increase; p2 = p2(t) is the pore-fluid pressure during the period of itsdecrease; ε1 and ε2 are coefficients of pore-fluid pressure changeduring the periods of its increase and decrease, respectively; and γ12


and γ21 are coefficients of interaction of natural factors determiningeither preservation or change of the pore-fluid pressure.

The system of Equations 134 describe the theoretical processes ofgeneration, stabilization, preservation, and dissipation of pore-fluidpressures. Due to the difficulty in simultaneous experimental deter-mination of the coefficients of pressure change and coefficients ofopposite influence of some natural factors, numerical simulation usingthe models is possible in a practical case only when the coefficientshaving opposite influence may be neglected. For γ12 = γ21 = 0, Equa-tions 134 are reduced to two equations, one of which describes theabnormal pore pressures, and the other, a drop to normal hydrostaticpressure. At actual conditions, it is necessary also to take into accountthe self-retarding effect of the process, leading to the following equation:

p1 = [p

maxp

oexp(ε

1p

maxt)]/[p

max – p

o(1 – exp(ε

1p

maxt))] (135)

where po is the initial value of the pore pressure (hydrostatic pressureof water at a depth where sedimentation began), pmax is the maximumpossible pore pressure at given conditions, and t is time. The coeffi-cient of proportionality calculated for the South Caspian Basin averages0.02 (MPa per million years)–1.

The change in pressure with depth is assumed to be analogous tothe change in time and may be described by an equation similar toEquation 135. This assumption is probably true for the South CaspianBasin, taking into account a relatively young age of rocks, absenceof noticeable faulting, one-phase formation of folded structure, normalbedding of sequential stratigraphic intervals, etc. Other factors can alsoinfluence the development of abnormal pore pressure, butin the South Caspian Basin they probably play a subordinate role(Buryakovsky et al., 1986c).

Using Equation 135, it is possible to describe the dynamics of thepore-fluid pressure (Figure 12-7a) and to forecast the pore pressurein the reservoir rocks and caprocks at various depth (Figure 12-7b)for the various regions of the South Caspian petroleum province(Buryakovsky and Chilingarian, 1991c).

Fertl (1976), Fertl and Chilingarian (1976), and Magara (1982)pointed that the abnormally-high pore pressures have different originand can be caused by various natural factors superimposed upon eachother. In the South Caspian Basin, for example, with accumulation of


thick sand-shale sequences (mainly shales), the most probable mech-anism for abnormally-high pore pressure development is gravitationalconsolidation with upward filtration of fluids. Gravitational consolida-tion prevails over the upward flow of fluids at rapid rates of sedimen-tation. This leads to a considerable undercompaction of sediments(mainly shales) and development of abnormally high pore pressures.

It has been shown (Buryakovsky et al., 1986c) that hydrostaticpressure gradients in shales at the depth interval of 1,000–6,000 m

Figure 12-7. Results of pore-fluid pressure simulation. a—Variation in pore-fluid pressure with time; b—variation in pore-fluid pressure with depth, forthree regions of the South Caspian Basin. ph = hydrostatic pressure, pmax =total overburden (geostatic) pressure.


(over 2,000 determinations by well-logging) range from 0.012 to 0.024MPa/m with an average value of 0.018 MPa/m (Figure 12-8).

SIMULATION OF HYDROCARBON RESOURCES ANDEVALUATION OF OIL AND GAS RESERVES

The model of determining hydrocarbon resources (a material-functional model of Equations 89 type, at f1(x1) = V1 and f2(x2) = V2,where V1 and V2 are hydrocarbon volumes in increasing (V1) and

Figure 12-8. Pore-fluid pressure in clays versus depth in the South CaspianBasin (Modified after Buryakovsky et al., 1986c). η = pore-fluid pressure gradient.


decreasing (V2) accumulations) was described by Buryakovsky (1977b).At one-stage oil accumulation, the model is analogous to Equation 135:

V1 = [BV

oexp(ε

1Bt)]/[B – V

o(1 – exp(ε

1Bt)] (136)

where B is the volume of reservoir containing a hydrocar-bon accumulation.

This model allows to forecast the extent of the oil-gas accumulationand to evaluate the hydrocarbon resources locally or for a region as awhole (Figure 12-9). As a forecast target, reservoirs of the deep-waterzone of the South Caspian Basin have been used. They were studiedby seismic surveys only (Buryakovsky, 1983).

Using Equation 136, a model of hydrocarbon reserves evaluation inindividual traps was obtained. This model is a derivative of Equation 136and is formally similar to the Equation 108, where xi are reservoirparameters for hydrocarbon reserves estimation using the volumetricmethod. The volumetric method used in the evaluation of hydrocarbonreserves appears to increase the reliability of estimated reserves.

Figure 12-9. Results of simulation of hydrocarbon accumulation in traps.B = pore volume of the reservoir, V = volume of trapped hydrocarbons.


The formula used in calculating crude oil volume in-situ isas follows:

V = Aheff

φSo

(137)

where V is the volume of oil accumulation, A is the reservoir area,heff is the thickness of oil-bearing formation (net pay), φ is the porosity,and So is the oil saturation.

Equation 137 can be simplified if φSo is replaced by the “effectiveoil saturated porosity” φeff :

V = Aheff

φeff

(138)

It should be noted that some offshore structures in the South CaspianBasin are studied only by a sparse grid of seismic lines, and offshoreareas adjacent to the oil and gas fields were not studied duringexploration. In view of this problem, it was decided to use mathe-matical methods. An algorithm and computer program using DoubleFourier Series for uneven spacing of the initial data were developed.Examples of structural mapping on top of the Lower Productive Seriesalong the northern slope of South Caspian Basin are presented inFigures 10-1 and 10-2.

Effective oil and gas saturated thickness of a reservoir (net pay) wasdetermined through the identification of layers using a cluster-analysistechnique, i.e., by means of recognition without preliminary training.For this purpose, sections studied using well logs were utilized. Eachsection was divided into groups of layers with definite reservoir-rockproperties. These groups were identified by means of comparison withthe well-testing results. As a measure of reliability in division intogroups of beds, the Correlation Coefficient (see Equation 5) andgeneralized Euclidian Distance (see Equation 6) were used.

An example of identification of beds is shown in Figure 10-7. Inthe algorithm, each bed has a thickness equal to the average thicknessof all beds in the section. A more complex algorithm allows simulationof sections taking into account distribution of bed thicknesses basedon lithology.

The φSo (see Equation 137) of reservoir rocks was evaluated bysimulating processes of compaction and other diagenetic changes ofsediments, as described above. Examples of simulation of reservoir-


Figure 12-10. Statistical distributions of calculated values of petrophysicalproperties and water saturation (Sw). a—Porosity (fraction), b—permeability,c—water saturation (fraction). Formations: 1—Balakhany Suite; 2—“Pereryv”Suite; 3—NKP Suite; 4—PK Suite.


rock properties are presented in Tables 12-1 and 12-2 (or in Fig-ure 12-10).

Hydrocarbon volumes were calculated using the Monte Carlo tech-nique (see Equations 137 or 138) at the interval-probable setting ofreservoir parameters. As discussed by Abasov et al. (1984), suchmethod of reserves evaluation is more preferable than evaluation usingthe average parameters. This allows one to obtain not an average valueof reserves but their distribution. Consequently, reliable intervals ofreal values of reserves (with the reliability coefficient fixed in advance)can be obtained.


408

CHAPTER 13

Conclusions

The above-described approach to modeling of the geologic systemsallows one to solve theoretical as well as some applied problems.

The theoretical problems include:

1. Compaction and other diagenetic alterations of sediments.2. Formation and evolution of the geofluidal (pore-fluid) pressures.3. Formation of hydrocarbon resources.4. Problems of regional sedimentation and the role of endogenic and

exogenic factors in the processes of tectogenesis, folding, mudvolcanism, and earthquake forecast.

The applied problems include:

1. Estimation of hydrocarbon reserves in various traps.2. Prediction of petrophysical properties of rocks and pore-fluid

pressures at depths not yet studied by geologic and geophysicaltechniques.

3. Estimation of the degree of water invasion into the reservoirduring its development.

In the studied region of the South Caspian Basin, on the otherhand, the described approach allowed to solve the following practi-cal problems:

1. Evaluation and prediction of the petrophysical properties ofreservoir rocks and caprocks. Bulk density, porosity, permeability,residual water saturation, electric resistivity, etc. are used as inputparameters at reservoir conditions in situ.

2. Evaluation and prediction of the pore-fluid pressures in reservoirrocks and caprocks; estimation of the sealing properties ofcaprocks.

3. Evaluation and prediction of the volume of hydrocarbon accumu-lation, and estimation of oil and gas reserves in various traps.

(Chapters 9 to 12)

Conclusions 409

The systems approach to geology is both a sophisticated philosophyand a scientific method for investigation of very complicated geologicsystems. As applied to petroleum geology, it includes the method-ological base and technology of mathematical simulation used formodeling geologic systems, the systems which have been previouslyinvestigated and estimated by using experimental data and/or fieldstudies. Because geologic systems develop in time, it is very importantto simulate them as dynamic systems. The necessity of consideringthe geologic time factor does not eliminate the possibility of develop-ing, along with the dynamic models, also of the static and structuralmodels. It is imperative, however, to remember that geology is ahistoric discipline, and the relative lack of success in its mathe-matization is associated to a significant degree with difficulties inconsidering the time factor.


428

CHAPTER 29

Author IndexAbasov, M. T., 119, 407, 410, 411, 422Abikh, G. V., 61Abramovich, M. V., 120Agamaliev, R. A., 221, 320, 321, 331, 412,

415Akhmedov, A. G., 202, 410Akhmedov, A. M., 202, 410Akhmedov, G. A., 22, 410Akhundov, A. R., 410Aksenov, A. A. , 221, 410Aleksandrov, B. L. , 152, 358, 359, 364, 410Alibekov, B. I. , 411Aliev, R. A., 155, 411Alikhanov, E. N., 22, 36, 37, 201, 210, 411Aliyarov, R. Yu., 140, 155, 402, 403, 414, 415Aliyev, A. K., 61Aliyev, A. I., 23, 24, 208, 411Aliyev, A.D., 411Ali-Zadeh, A. A., 411Amanniyazov, K. N., 223, 411Aminzadeh, F., 153, 155, 411, 418, 420, 421Apresov, S. M., 61Arkharova, I. M., 320, 321, 415Arps, J. J., 411Asan-Nuri, A., 62Ashirmamedov, M. A., 411Ashumov, G. G., 178, 179, 180, 411Athy, L. F., 358, 411Avchan, G. M., 411Babajev, F. R., 22, 114, 185, 339, 412Babazadeh, B. K., 22, 120, 412Bagir-zadeh, F. M., 22, 56, 114, 185, 339, 412Bagrintseva, K. I., 363, 367, 412Bairamalibeili, N. I., 331, 413Barnes, H.,, 167, 421Baturin, V. P., 412Belyakova, G. M., 412Berner, R., 360Bezborodova, I. V., 223, 364, 412Bissell, H. J., 357, 363, 370, 380, 417Bonham-Carter, G., 198, 380, 420

Bredehoeft, J. D., 199, 412Brod, I. O., 120, 412Buryakovsky, L. A., 22, 56, 69, 83, 114,

119, 129, 140, 155, 157, 158, 162,167, 185, 186, 189, 198, 202, 250,252, 263, 266, 284, 297, 303, 326,327, 328, 343, 331, 339, 351–352,353, 354, 357, 359, 362, 365, 370,389, 394, 401, 407, 410, 412–416,425, 426

Carman, P. C., 416, 417Chapman, R. E., 419Chetverikova, O. P., 220, 417Chilingar, G. V., 153, 155, 157, 158, 162,

163, 167, 189, 198, 237, 303, 357,363, 364, 370, 380, 416, 417, 420,421, 422, 426

Chilingarian, G. V., 152, 156, 166, 171,189, 353, 358, 359, 360, 363, 380,392, 398, 401, 416, 417, 419, 401,419, 425

Clarke, J. W., 212, 217, 221, 223, 225, 226,227, 230, 418

Dadashev, R. M., 83, 413Danchenko, K. V., 210, 418Davis, J. C., 244, 365, 420Dickinson, G., 152, 352, 358, 418Dikenshtein, G. Kh., 234, 418Dobryanskiy, A. F., 179, 180, 339, 418Dobrynin, V. M., 152, 326, 351, 352, 353,

361, 364, 367, 418Donaldson, E. C., 363, 417Doveton, J. H., 244, 365, 420Dunan, J. P., 155, 418Dunin-Barkovskiy, I. V., 256, 257, 331, 426Durmishyan, A. G., 352, 353, 355, 418Dzhafarov, I. S., 119, 250, 252, 263, 266,

284, 297, 354, 357, 359, 362, 365,370, 389, 394, 407, 410, 412, 413,414, 415, 418, 419

Dzhafarova, N. M., 410, 419

Author Index 429

Dzhalilov, D. G., 186, 425Dzhevanshir, R. D., 140, 155, 157, 158,

162, 167,198, 250, 252, 266, 326,327, 328, 343, 351, 354, 357, 359,362, 365, 370, 389, 392, 394, 410,411, 412, 414, 415, 416, 419, 422

Efendiev, G. M., 155, 411Engelhardt, W. V., 419Fedynskiy, V. V., 5Fertl, W. H., 152, 353, 401, 419Foster, J. B., 152, 352, 358, 419Fyodorov, S. F., 185, 419Gadzhi-Kasumov, A. S., 339, 419Gadzhiyev, B. A., 419Geodekyan, A. A., 235Godin, Yu. N., 419Gordon, Z. S., 223, 419Grachevskiy, M. M., 208, 420Graybill, K. A., 198, 243, 365, 422Griffiths, J. C., 198, 331, 365, 420Gubkin, I. M., 22, 120, 420Gurevich, A. E., 153, 237, 420, 421Gussow, W. C., 185, 420Gyul’, K. K., 420Ham, H. H., 352, 358, 420Harbaugh, J. W., 198, 244, 365, 380, 420Hedberg, H. D., 352, 355, 358, 420Hosoi, H., 352, 420Hotz, R. F., 419Ismailova, Kh. G., 257Johns, P. J., 309Kahn, J. S, 243, 292, 424Kalinko, M. K., 420Karimov, K., 418Kartsev, A. A., 179, 180, 326, 421Kasumov, S. M., 413Katz, S. A., 153, 163, 421, 426Kauffman, M. E., 244, 422Kaverochkin, M. P., 62Kazi, A., 166, 417Kemeny, J. G., 350, 421Kevorkov, F. M., 202, 410Khain, V. Ye., 22, 120, 387, 421Khanin, A. A., 421Kharaka, J. K., 167, 421Kheirov, M. B., 140, 159, 415, 421Khilyuk, L., 153, 421Khitarov, N. I., 161, 421Khodzhakuliyev, Ya. A., 221, 421Kingston, J., 220, 221, 223, 224, 421Klemme, H. D., 256, 257, 331, 426

Kleschev, K., 418Kolmogorov, A. N., 270Kondrushkin, Yu. M., 410, 421Kotyakhov, F. I., 422Kovalevskiy, S. A., 61Kozeny, J., 422Kravchik, M. S., 237, 422Krems, A. Ya., 22, 120, 422Krumbein, W. C., 198, 243, 244, 365, 422Kukhmazov, M. S., 129, 413Kuliev, R. D., 415Kuliyev, G. G., 422Kuzmina-Gerasimova, V. L., 244, 367, 371,

414Langnes, G. L., 422Larsen, G., 364, 422Law, B. E., 422Lebedev, L. I., 422Lebedev, N. A., 61Lee, S., 155, 422Leibenzon, L. S, 422Leontaritis, K. J., 339, 423Listengarten, B. M., 331, 411, 413Livshits, M. G., 223, 423Madera, E. R., 414Magara, K., 152, 161, 352, 379, 401, 423Main, R., 417Maksimov, S. P., 185, 210, 211, 212, 213,

220, 225, 226, 423Maltsev, N. G., 224, 423Mamedov, B. M., 224, 423, 426Mamedov, M. M., 426Mamedzadeh, R. N., 411Mansoory, G. G., 339, 423Matveyenko, A. A., 411Mazzullo, S. J., 417McCammon, R. B., 244, 422Meade, R. H., 352, 358, 423Mekhtiev, Sh. F., 208, 423Mekhtiev, U. Sh., 410Melik-Pashayev, V. S., 22, 423Merriam, D. F., 244, 365, 420, 424Meyerhoff, A. A., 201, 205, 210, 212, 424Mezhlumov, A. A., 62Middleton, G. M., 393, 424Miller, R. L., 243, 292, 424Mirchink, M. F., 22, 61, 120, 300, 424Monicard, R. P., 306, 424Muskat, M., 309Nalimov, V. V., 331, 424Narimanov, A. A., 252, 424


O’Connor, R. B., Jr. , 214, 215, 216, 217,219, 222, 227, 229, 230, 231, 424

Orudzhev, S. A., 62Ovnatanov, S. T., 22, 424Pashaly, N. V., 423Pavlova, N. N., 361, 363, 367, 424Pirson, S. J., 309, 424Potapov, I. I., 22, 119, 120, 425Proshlyakov, B. K., 352, 353, 358, 425Pugin, V. A., 161, 421Pustovalov, L. V., 294, 352, 363, 425Putkaradze, A. L., 22, 425Rachinskiy, M. Z., 410Radyushkina, T. T., 223, 425Rieke, H. H., III, 156, 166, 171, 189, 353,

358, 359, 360, 380, 417, 425Robertson, J. O., Jr., 422Rodionov, D. A., 198, 244, 331, 425Roginskiy, B. A., 62Ryzhkov, O. A., 223, 425Safarov, Yu. A., 62Sagers, M. J., 227, 425Salayev, S. G., 411Samedov, F. I., 22, 62, 69, 186, 189, 202,

303, 410, 412, 425Sapozhok, V. M., 411Savchenko, V. P., 187, 426Serebryakov, V. A., 152, 163, 418, 426Shabad, T., 227, 426Sharapov, I. P., 198, 262, 426Shekinskiy, E. M., 411Sheriff, R. E., 61, 426Shikhalibeili, E. S., 411

Shirkovskiy, A. L., 306, 426Sinnokrot, A., 417Slavin, V. I., 422Smirnov, N. V., 256, 257, 270, 331, 426Snell, J. L., 350, 421Sogren, G., 61Sokolov, I. P., 224, 426Solov’yev, N. S., 224, 426Sonnenberg, S., 214, 215, 216, 217, 219,

222, 227, 229, 230, 231, 424St. John, B., 426Stefankevich, Z. B., 411, 415Stetyukha, Ye. L., 270, 355, 426Tagiev, S. O., 167, 415Terzaghi, K., 353, 426Timofeyev, N. S., 62Tkhostov, B. A., 426Ulmishek, G. F., 223, 237, 256, 257, 331,

422, 426Ushakov, A. P., 426Vassoyevich, N. B., 120, 351-352, 353, 354,

426Veliyev, M. M., 252Volterra, V., 350, 426Weller, F. A., 158, 352, 353, 354, 358, 426Whalen, H. E., 152, 352, 358, 419Wolf, K. H., 357, 363, 370, 380, 417Yakubov, A. A., 426Yanena, R. I., 224, 426Yen, T. F., 363, 417Yusufzadeh. Kh. B., 22, 62, 83, 202, 410, 426Zadeh, L. A., 385, 426Zeinalov, Z. I., 426


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431

A

Abnormally-high formation pressure, 149,150, 155, 401, 402, 403

Age, Albian, 223, 224Alpine, 208Aptian, 203Callovian-Oxfordian, 223Cambrian, 152Carboniferous, 9, 217, 336Cenomanian, 203, 223, 224Cenozoic, 8, 195, 203, 208, 231, 359,

382, 140, 155, 164, 195Cretaceous, 2, 4, 21, 22, 25,44,45, 46,

201, 219, 220, 221, 223, 224,225, 226, 227, 230, 231, 237, 359

Cretaceous-Late Jurassic, 12Devonian, 158, 359Eocene, 25, 63, 220, 224, 359Holocene, 220Jurassic, 1, 2,3, 12, 44, 201, 203, 214,

217, 219, 221, 222, 223, 224,226, 227, 230, 231, 236, 237, 238

Mesozoic, 6, 7, 8, 9, 16, 26, 55, 158,201, 203, 208, 220, 231, 359,360, 375–377, 379, 380, 382

Miocene, 32, 57, 147, 155, 203, 205,206, 210

Neocomian, 203, 223Neogene, 4, 35, 58, 201, 205, 206, 210,

220, 224, 237, 240, 373, 377, 379Oligocene, 147, 205, 220Oligocene-Miocene, 18, 42Oxfordian, 223Paleogene, 4, 25, 35, 155, 203, 220,

224, 237, 240, 359Paleozoic, 195, 217, 231Permian, 217, 236, 237, 238

Permo-Triassic, 236Pleistocene, 18, 40Pliocene, 18, 19, 21, 22, 25, 28, 32, 35,

40, 55, 113, 126, 127, 140–141,156, 158, 159, 161, 170, 172,196, 251, 284, 202, 203, 204–205, 206, 208, 210, 224, 387

Middle, 11post, 10

Quaternary, 4, 5, 28, 58, 107, 196, 201,205, 220, 224

Triassic, 212, 217, 238Turonian, 203, 224Upper Archean-Lower Proterozoic , 8

Anisotropy, coefficients, 258–300Anisotropy, permeability, 298, 301

stratified rocks, 297–302Anticlinal trend, Adzhichai-Alyaty, 20

Apsheron-pre-Balkhan, 55–91, 113, 199,210

Badkhiz-Karabil, 231Fatmai-Gum Adasi, 91Geokchai-Saatly, 3Kalamadyn-Byandovan, 44Khali-Azeri, 185Kilyazi-Krasnovodsk, 116Kyurovdag-Neftechala, 44Pirsagat-Khamamdag, 44Saatly-Kyurdamir, 8Talabi-Kainardzha zone, 25Utalgi-Kyanizadag, 101

Anticline (also see structure), 18Anticlinorium, Greater Caucasus, 3

Lesser Caucasus, 3Tengiz-Beshbarmak, 43–44

Arch, Dauletabad, 225Kara Bogaz, 231, 232Kara-Kum, 217, 232

Subject Index


Archipelago, Apsheron, 16, 28, 30, 31, 32,34, 55, 57–91, 114, 115, 116,117, 119, 120, 134, 140–142,147, 149, 154, 158, 163, 172,173, 175, 176, 178–180, 182,185–191, 239, 240, 295, 325,326–327, 328, 329, 353, 355,357, 360, 387, 390

Baku, 16, 17, 28, 30, 31, 55, 56,101–112, 115, 116, 117, 140–141,142, 144, 146, 148, 149, 150,158, 159, 160, 161, 163, 165,166, 172, 175, 200, 239, 240,319, 320, 321, 322, 324, 353,360, 387, 390

Kimmerian, 201Artyom Island (Pirallaghi Adasi), 118

B

Baku, City of, 10, 42, 60Basin, Amu-Darya, 212–231

source rocks, 220–221statigraphy, 217–220structure, 212, 215

Azov-Kuban, 232back-arc, 201Kura, 232Middle Caspian, 4, 55Murgab, 218North Stavropol, 233South Caspian, 1, 3, 4, 5, 25, 27, 55,

199–242South Mangyshlak, 231–238, 237, 238subsidence rate, 164Tedzhen-Murgab, 217Terek-Kuma, 232Uchyacan, 232Ustyurt, 233Western Siberian, 210

Beaufort wind scale, 61Belt, North Anatolia, 1

ophiolitic, 1“Benzine” fractions, 325Boltzmann’s constant, 290Brachyanticline, 62, 227

Bakhar, 94Bulla Deniz, 109–110Lokbatan, 42Palchygh Pilpilasi, 79Shabandag, 41, 146, 241

C

Caprock, 158, 203, 208, 224, 241, 360, 387,401

Cape, Sangachal, 102Caspian Sea, general description, 52Catagenesis, 243, 357Catagenetic transformation, 161, 164, 166,

170Cation-exchange capacity, 319CDP surveys, 248, 251, 254Clay, dehydration rate, 163–164

minerals, 140–146transformation, 197, 240–241water, bound, 163

desorbed, 164free, 163interstitial, 164

Cluster-analysis technique, 264Coefficient of correlation, 265, 319, 322,

324, 331–337, 405analysis, 329elipse eccentricity, 333–336

Compaction, carbonate rocks, 363–365mathematical simulation, 355–361siliciclastic rocks, 361–363

Compressibility factor, 353, 354Coulomb’s law, 155Crust, collision zone, 217

earth, 1, 6, 9, 14, 15oceanic, 201

D

Darcy equation, 303Deep water, South Caspian Basin, 404

zone, 57Dendroid diagram, 285Density, simulation, 375, 376Depression, Araks, 4

Beshkent, 214, 217, 220Dzheirankechmes, 18, 25, 41intermontane, Kura, 1, 3Kazakh, 234Kura, 3, 4, 5, 6, 9, 16, 25, 44Lower Kura, 17, 20, 148, 149, 150, 154,

158, 161, 163, 166, 319, 320,321, 322, 324, 360

Murgab, 214, 217Nakhichevan, 26North Ustyurt, 234

Subject Index 433

Yevlakh-Agdzhabedi, 25Zaunguz, 212, 214, 217

Diagenesis, 159, 161, 166, 170, 243, 355Diagnostic coefficient, 263, 271, 272–273,

274Diapirism, 5Diapirs, 208Diffusion-adsorption factor, 314Dome, Cheleken, 252, 253, 254

pre-Cheleken, 199, 206Double Fourier Series, 405Douglas Sea-State Scale, 61Downwarp, Alazan-Agrichai, 26

Araks, 26Dzhalilabad area, 28

E

Entropy, chaotic state, 290heterogeneity of rocks, 290–297maximum, 293of information, 291, 292relative, 292–293, 295, 296

Epigenesis (see Catagenesis), 355, 357–358Equations of normalization, 369Euclidian distance, 405

F

Fault, Caucasus-Kopet-Dagh, 55fluid migration along, 206Siazan, 44

Foldbelt, Alpine, 1, 5, 6Kopet-Dagh, 201North Anatolia, 1

Foredeep, 16Kopet-Dagh, 212, 214, 217, 230, 232

Formation, Albian-Cenomanian, 221Amu-Darya, 221Aptian-Albian marine shales, 221Bukhara carbonates, 221Dogger sandstones, 300Gaurdak, 219Khodozhaipak, 221Olenek, 236Shatlyk, 223, 225, 226, 227

Formation pressure, sensitivity analysis,153

Fuzzy set, 395

G

Gas field, Dauletabad, 212, 223, 224, 225,226, 227

Donmez, 212, 223, 224, 225, 226, 227Dzhanub, 182, 186, 193, 195, 365

Gas, carbon dioxide (CO2), 71, 72, 187composition, 187condensate, 186ethane, 187methane, 187

generation, 14natural, 70, 72

properties, 185–191specific gravity, 188

Geologic time, relative, 347–348, 349absolute, 347–348

Geosycline, 16Mediterranean Alpine, 9

Gibbs’ composition triangle, 325, 326Gibbs’ free energy difference, 168, 169Gradient, formation-pressure, 153, 154

geothermal, 153, 154pore-pressure, 153, 154, 157

Gravity, 9Saatly-Kyurdamir gravity maximum,

7, 14Talysh-Vandam gravity maximum, 8, 14

H

Hagen-Poiseuille equation, 303Heterogeneity, 290–297Heuristic formulas, 397Hooke’s law, 367Hydrocarbon inversion, 166, 189Hydrochemical effect, 164–168Hypothesis testing, 256

zero, 266

I

Island arc, 14Seven Ships, 62

Isoseisms, Apsheron, 114

J

Jurassic Salt, 213, 214


K

Kolmogorov-Smirnov criteria, 266, 270Kozeny-Carman equation, 304–305, 306,

308Kulbach informativity measure, 266, 271,

272–273Kura Lowland (also see: Depression, Kura),

1, 16, 23, 24Kusary sloping plain, 4

L

Leptocythere praebacuana Liv., 28, 76Ligroin fraction, 177, 180Lithofacies, 204

Apsheron, 127Gobustan, 117

Lithology, 126, 198, 206Lithostratigraphy, 27–31Loxoconcha alata Schn., 28, 76Loxoconcha eichwaldi Liv., 28, 76

M

Markov’s modeling procedure, 285, 288Mathematical, 249

Double Fourier Series, 249, 252models, 243regional structural pattern, 249simulation, 243, 244–247simulation, principles, 247

Matrices, transition frequencies, 289Mean Standard Error (MSE), 258Median Masiff, Trans-Caucasus anticlinal,

6, 15Microcavities, 160Microfauna (radiolarians), 15Migration, fluids, along faults, 206Model, analytical, 348–350

cluster-analysis technique, 405density change, 363deterministic (analytical), 384dynamic, 400dynamic, stochastic, 397, 399dynamic, time, 347–348evaluation of oil reserves, 403–407lognormal, 393numeric simulation, examples, 373–379numerical simulation, methodology,

384–407

oil composition, 324properties, 325–329

molecular weight, 325“organism growth,” 349, 362petrophysical, 395–397pore-fluid, 400–403porosity change, 363probabilistic (statistical), 384–385proportional effects, 349reservoir rock property, 372simulation of rock properties, 386–390statistical, 348, 350–355Terzaghi compaction theory, 363water invasion, 398–400

Modeling coefficient, 367Modulus of elasticity, 366Monocline, Siazan, 25Monte Carlo technique, 348, 371, 407Mountain system, Alpine, 54Mountains, Kirmaku, 35, 39

Elburz, 201Greater Caucasus, 1, 2, 3, 4, 5, 20, 23,

24, 117, 147, 235, 239, 240Lesser Caucasus, 1, 3, 4, 5, 13, 23, 24,

117, 147, 239, 240Talysh, 117, 147Ural, 360

Mud volcanism, (see: volcanic, mud)Multi-Dimensional Statistical method,

263–271

N

Nose, Donmez, 225, 226

O

Offshore Zone, Apsheron, 115, 117, 119,140–141, 142, 149, 158, 163,166, 205

South Apsheron, 319, 320, 321, 322, 324Oil and gas field, Adzhidere, 51

Agburun Deniz, 56, 57Aktas, 237Alan, 229Alyat Deniz, 145, 146, 153, 391Amirkhanly, 44Apsheron Bank, 56, 57Aran Deniz, 146Arystan, 234Asar, 237

Subject Index 435

Ashrafi, 56, 57Atashkyah , 124, 174Azeri, 55, 56, 57, 120, 174Azi Aslanov, 56, 57Bagaja, 216Bakhar, 55, 56, 94–101, 118, 142, 145,

153, 174, 255, 263, 266, 271,298, 300

Balakhany, 32, 34, 35, 124, 125, 147,172, 173, 174, 175, 341

Barinov, 56, 248, 252Beurdeshik, 216, 223Bibieibat, 40, 41, 42, 121, 124, 135,

145, 172, 173, 174, 257, 258, 260Binagady, 32, 35, 122, 124, 126, 127,

153, 174, 341Bota, 229Bukhta Il’icha, 359Bulla Deniz, 55, 101, 102, 103, 106,

108, 110–112, 142, 145, 146,153, 165, 169, 171, 285, 286

Buzovny, 32, 125, 173, 174Chakhnaglyar, 32, 35, 122, 126, 173,

174Chalov Adasi, 55, 56, 57, 59, 73, 82,

83, 120, 125, 173, 181, 185, 186,187, 191, 194, 296, 328, 337, 341

Chandagar-Zorat, 44Cheleken, 56, 199, 200, 210Chyragh, 56, 57, 174, 175Darvaza, 212Darvin Bank, 55, 56, 57, 58, 82, 120,

123, 125, 173, 174, 180, 182,185, 186, 191, 194, 327, 336, 341

Denguizkul Khauzak, 215, 229Duvanny Deniz, 43, 101, 102, 103, 104,

105–106, 122, 124, 127, 142,145, 153, 165, 168, 172, 174, 341

Dzhanub Bank, 55, 56, 57, 58, 59,82–91, 120, 136, 142, 249

Dzhanub-2, 145, 249, 250Dzhanub-3, 250East Gilavar, 56Garasu Deniz, 146, 391Gezdek, 122, 127Gilavar, 56, 57Goshadash, 56, 57Gousany, 127, 135, 296, 341, 359Griaznyi Vulkan, 212Gubkin Bank, 56, 201, 206, 207Gugurtly, 223

Gum Deniz, 33, 55, 56, 59, 135, 295,296, 341, 359

Gyuneshli, 56, 57, 58, 120, 134, 138,142, 145, 153, 172, 174, 175,186, 191, 248, 249, 250, 251

Gyurgyany Deniz, 55, 56, 57, 59, 82,120, 123, 125, 180, 182, 185,191, 194, 296, 327, 336

Inchkhe-more, 233Iolotan, 231Kala, 32, 121, 124, 126, 172, 173, 174,

341Kalmas, 44, 125, 135, 359Kandym, 229Kansu, 237Karabagly, 44, 142, 145, 146, 153, 359Karabakh, 56Karabil, 215, 223Karachukhur, 32, 34, 121, 124, 125,

135, 173, 296, 341, 359Karadag, 125, 127, 135, 341, 359Kazanbulag, 51Kergez, 35, 127Khali, 56, 57, 195Khamamdag Deniz, 145, 146, 153, 391Khara Zyrya, 101, 102, 103, 106, 142,

145, 153, 168, 172, 174Kirmaku, 35, 36, 37, 38–40Kokdumalak, 227, 229, 230Korganov, 56 Kotur-Tepe, 199, 200, 210, 211Kuba, 25Kuruk, 216Kushkhana, 127, 172, 174, 175Kyapaz, 22, 56Kyurdakhanly, 56Kyurdamir, 44Kyurovdag, 121, 125, 142, 145, 146,

153, 359Kyursangya, 44Kyzyltepe, 127LAM (Laboratory of Air-born Methods

for exploration) Bank, 56, 201,206, 207, 212, 252, 253, 254

Livanov Bank, 201, 206Livanov- East, 56, 252, 253Livanov-Center, 56Livanov-West, 56Lokbatan, 18, 35, 42, 43, 124, 172, 174,

175, 257, 258, 259, 341Makarov Bank, 92


Oil and gas field (continued)Mardakyan Deniz, 56Mashtagi, 32, 125, 173, 174Mirbashir, 51Mishovdag, 121, 125Muradkhanly, 25, 44, 45, 46, 47, 147Naftalan, 51Naip, 223Nardaran Deniz, 56Neft Dashlary, 55, 56, 57, 58, 59,

60–73, 74, 75, 120, 125, 126,134, 138, 172, 173, 174, 175,179, 180, 181, 182, 183, 185,186, 187, 191, 192, 194, 195,248, 249, 250, 296, 309, 309,311, 312, 326, 327, 328, 329,337, 341, 391

Neftechala, 44, 127Oguz, 57, 142, 145, 249Ozek-Suat, 233Padar, 359Palchygh Pilpilasi, 55, 56, 57, 62,

73–82, 120, 134, 142, 145, 153,173, 179, 185, 186, 191, 193,194, 296, 327, 328, 337, 341

Patamdar, 135, 359Pirallaghi Adasi, 120, 123, 125, 127,

173, 174, 180, 181, 182, 185,186, 194, 327, 336, 341

northern fold, 55, 56, 57, 58, 82southern fold, 56, 57, 58, 59

Pirsagat, 44, 124pre-Cheleken Dome, 206Puta, 124, 172, 174, 175Rakushechnoye-more, 233Ramany, 32, 34, 35, 124, 125, 172, 173,

174, 175, 341Sabunchi, 32, 34, 35, 124, 125, 147,

172, 173, 174, 175, 341Sakar, 223Samantepe, 216, 229Sandykachi, 215Sangachal, 101, 102, 103, 142, 145, 165,

168, 172, 174, 341Sangi Mugan, 146, 391Saodan, 44Setalantepe, 212Shabandag, 40–41, 42, 122, 126, 174Shakh Deniz, 56Shakhpahty, 237, 238Shatlyk, 223, 227, 228

Shorabad Deniz, 56Shubany, 42Shurtan, 216, 229Siazan-Nardaran, 44Starogroznenskoye, 233Sulutepe, 32, 35, 126, 173, 174Surakhany, 32, 34, 121, 124, 125, 135,

147, 172, 173, 175, 341, 359Tarsdallyar, 25Tasbulat, 237Tenge, 237Turkyany, 295, 296Udchaji, 215Umbaki, 43Urtabulak, 229Ushakov, 56Uzen, 231, 233, 234, 236, 237Yasamaly Valley, 122, 126, 174Yashlar, 215, 231Yashma Deniz, 56Yuzhno-Zhetybay, 237Zagly-Zeyva, 44Zardob, 25Zevardy, 229Zhdanov Bank, 201, 206, 207, 252, 253Zhetybay, 231, 233, 237Zykh, 32, 34, 124, 125, 135, 359Zyrya, 32, 59, 359

region, Adzhinour, 25Apsheron Peninsula, 2, 32–43Baku Archipelago, 22Bukhara, 229Charjou, 227, 229Gyandzha, 25, 51Kura-Iori Interfluve, 25Monocline, pre-Caspian-Kuba,

43–44Monocline, Siazan, 43Paleogene-Miocene, 24Sangachal-Duvanny Deniz-Khara

Zyrya, 55Shemakha-Gobustan, 25, 42Talabi-Kainardzha, 25Yevlakh-Agdzhabedi, 44–51

fractured volcanic, 45, 46, 47, 48,49, 50, 51

petrographic studies, 48porosity, 48resistivity logs, 47

Oil, accumulations, 191–195“benzene content,” 182

Subject Index 437

boiling point, 175, 176, 177, 179classification, 176–180coking ability, 330composition, 175–185, 176, 177–179,

184composition vs. properties, 329–340deep accumulations, 195–198density, 176, 178, 180–185, 195,

326–329, 329–331, 338, 339, 340,342, 344–346

dynamic viscosity, 340, 345–346dissolved gas, 186entropy, 325fraction yield, 176fractional composition, 175gas saturation, 182gasoline content, 335, 338, 339GOR, 186kinematic viscosity, 340, 342, 343,

344–346maturity value, 221migration, 195potential, 210properties, 175–185resin content, 335, 338, 339, 342viscosity, 340–345

Orogenesis, Oligocene-Miocene, 6Orogeny, Alpine-Himalayan, 201, 224, 387

Hercynian, 217Hercynic stage, 6Himalayan, 52Neo-Alpine, 201

Ostracods, 28, 76Overpressured formations (see Reservoir,

pressure, abnormally high)

P

Pair-Variable empirical probabilities,278–281

Paleogeographic curve, Apsheron, 116Paleo-Tethys, 201Paracypria loezyi Lal., 28, 76Pelecypod embryos, 76Pelecypods, 28Peninsula, Apsheron, 4, 16, 17, 22, 28, 30,

32, 34, 35, 55–56, 91, 108, 109,115, 116, 117, 119, 120, 134,140–141, 142, 147, 161, 166,172, 173, 175, 176, 178–180,182, 185–191, 199, 200, 239,

240, 252, 253, 254, 300,331–337, 353, 355, 357, 360, 387

Cheleken, 55–56, 199, 200, 204, 205,210, 387

subsidence, 116, 117Permeability, 50, 76, 102, 134, 302–308Petrophysical parameters, 266, 268–269,

270, 287Photomicrographs, 148, 160, 169, 172Plain, Daghestan, 363Plate, Scythian, Cretaceous limestones, 359Platform, Russian, 52, 54, 116, 147, 239

Scythian-Turanian Epi-Hercynian, 52, 54Poisson’s ratio, 153–155Pore pressure, computation, 153Porosity, mercury injection, 50, 51

secondary, 51Pressure, abnormality factor, 156Pre-Tethys Sea, 52Probability curves, 382

R

RAMIN program, 167Rate of sedimentation, 361, 362Reefs, 223, 230Region, Apsheron, 117, 295, 340, 373, 389,

392Gobustan, 4, 16–18, 20, 25, 41Groznyy, 309Karachukur-Zykh, 295Karadag, 118Lower Kura, 30, 117, 140–141, 142, 146Nakhichevan, 2Sangachal, 104Talysh, 23, 24Uzen, 236

Reservoir, caprock, 146, 241carbonate content, 307characterization, 113classification, rock type, 133, 136clay content, 307effect of faults, 120electrtical properties, 390–395, 397flow rate, 303formation resistivity factor, 153formation resistivity index, 309, 311,

312gas gravity, 72gas/oil ratio, 72lithology, 319


Reservoir (continued)logging, 255–263migration, 242permeability, 76, 102, 134, 302–308

calculation, 308–313log calculation, 308

petrophysical properties, 303porosity, 102, 134

carbonates, 223pressure, abnormally high (AHFP), 149,

150–152, 155–164, 166, 196, 237,241, 242, 402

confining, 156gradient, 149, 150, 152, 154, 163pore, 161–164

relative clay content, 321–323reserves, 243residual water saturation, 308residual water saturation vs.

permeability, 310resistivity, 255–263

cut-off points, 256–263, 274–275index vs. permeability, 310

rock characteristics, 137properties, 319–324property distribution, 132–140

seals (see also caprock), 208source rocks, 205–206, 220–221specific surface area, 306surface activity, 319, 323temperature, 148, 150–164tortuosity, 304traps, 120–126, 205, 208, 221, 224, 241water invasion, models, 398–400waterflooding, 104, 105

Rheological models, 155Ridge, Alyaty, 20, 21

Apsheron-preBalkhan, 206Karpinskiy, 232, 233Kirmaku, 35

Rift system, 217, 218Aral-Murgab, 218

River, Araks, 9, 10, 44Dzheirankechmes, 18, 21Kura, 9, 10, 44, 117paleo-Kura, 239paleo-Ural, 239paleo-Volga, 239Pirsagat, 20Ural, 117Volga, 117, 360

Rocks, andesite-basalt, 12, 13argillaceous, 140–148carbonate, 4, 6, 21Cenozoic molasses, 9core data, 116, 140, 160, 284deformation, 156diabase, 2, 3gabbro-diabase, 2flysch, 1, 4modeling, petrophysical, 381ophiolitic, 1particle size histogram, 171permeability, 141pore size vs. depth, 148–149pore water, chemistry, 166, 168pore-size distribution, 165porosity, 198porosity vs. depth, 158, 352, 354, 356,

357, 359, 360porphyritic basalts, 12quartz sandstones, 3reef , 3, 4, 6, 212sand/shale sequences, 156sandstone, 2silt fraction, 141slate, 2terrigenous, 3, 35tuffaceous-terrigenous, 4volcanic, 6, 12, 13, 26

clastic, 4Mesozoic, 1metamorphosed, 13–14

S

Saatly, town of, 10Sand-silt ratio, 284Scanning electron microscope (SEM), 140,

148, 160, 169, 170, 172Sea, shoreline, North Caspian, 117Sediments, alluvial, 4

-deluvial, 5argillaceous, 2, 140–148breccia, 18

-plastic, 16chlidolites, 28clay, 140–146, 147

distribution, 147transformation, 142, 159, 160,

161–164, 168

Subject Index 439

coefficient of irreversible compaction,353, 354–355

compaction, 171, 355, 358–365carbonate, 363–365terrigenous, 361, 362

deltaic, 4, 119, 203depositional pattern, 118–119diatoms, 62distribution of clays, 131

of heavy minerals, 129–133foraminiferal interval, 51geochemical, 14, 15geometry of, 148grain-size, 197hydrochemical effect, 164–168Kimmeridgian-Tithonian, 221, 226,

227, 231macrofossils, 284microfossils, 284molasse, 6

troughs, 16numerical simulation, 365–371rapid deposition, 206regression models, 198salinity vs. clay content, 167sedimentation rate, 164Tertiary, 221, 224, 355Trask sorting coefficient, 370, 387

Seeps, 91gas, 61offshore, 60oil, 199

Seismic sounding, 7density model, 7

Sequences, Lower Archean, 14Upper Archean, 14

Shelf, Turkmenian, 57, 204, 205, 251–254,387

Siberian, western lowlands, 360South Offshore Zone, Apsheron, 140–141,

142Specific surface area, 303–308Stage, Akchagylian, 11, 18, 28, 40, 41, 44,

107, 113, 204, 210, 284Albian, 220Apsheronian , 10, 18, 19, 28, 32, 40,

44, 106, 107, 204, 284Aptian, 220Baku, 28Barremian, 220Berriasian, 219, 220

Calovian, 217, 219Cenomanian, 220Chokrak, 25, 26, 32, 43, 44, 147Conasian, 220Diatom, 32, 41Hauterivian, 220Kimmeridgian, 204, 217, 219Koun, 63, 64Liassic, 6, 300Maastrichtian, 220Maykop Series, 25, 26, 43, 51, 205Pontian, 28, 35, 37, 76, 113, 134, 284pre-Baikal, 8, 9Productive Series, 5, 18, 22, 24, 25, 27,

28, 29–30, 32, 35, 40, 41, 42, 44,57, 58, 76, 78, 84, 88, 91, 92–93,106, 107, 108, 110, 112, 113,115, 116, 117, 118, 119, 126,134, 138–140, 140, 142, 143,144, 150, 160, 165, 172–175,182, 185, 188–191, 203, 205,239, 240, 241, 249, 250, 254,255, 263, 271, 284, 300, 307,309, 311, 320, 321, 324, 329,387, 390, 405

core data, 239lithology, 28, 30, 113petrography, 129stratigraphy, 29, 113, 116

Red Bed Series, 55, 203, 204, 206, 207,210, 211, 219, 220, 239, 252,253, 387

Sarmatian, 12, 205Senonian, 44Tithonian, 217, 219, 221, 224, 226, 227,

231Turonian, 220Valanginian, 30, 219, 220

Step, Badkhyz-Karabil, 214, 217Bukhara, 212, 214, 217Charjou, 212, 214, 217Shakhpahty, 231Uzen, 231Zhetybay, 231

Steppe, Mil-Mugan, 5, 9Stratigraphic section, Saatly, 11Stratigraphy, regional, 203–205Structure, Aligul, 210

Apsheron Bank, 195Atashkyah, 40Azeri, 248


Structure (continued)Azi Aslanov, 79Bakhar, 91, 94Barinov, 252Boya-Dag, 199Bulla Deniz, 106, 109, 110Chalov Adasi, 79, 83, 88Chyragh, 248, 250, 251Dagadzhik, 210Dashgil, 21Duvanny Deniz, 102Dzhanub, 83, 88Dzhanub-2, 251Gum Adasi, 91, 92, 94Gum Deniz, 91Gyurgyan Deniz, 83Kara-Tepe, 199Khali, 79, 195Khara Zyrya, 107, 110Kum-Dag, 199Kyapaz, 57Kyzyl-Kum, 199Makarov Bank, 92Mardakyany Deniz, 195Neft Dashlary, 79, 83, 252Palchygh Pilpilasi, 79, 83pre-Caspian monocline, 17Shakh Deniz, 91, 94Ushakov, 251Zapadno Cheleken, 210

Subsidence, Apsheron Peninsula, 116, 117Subzone (block), Mil-Khaldan, 6

Saatly-Kyurdamir, 6Suite, Balakhany, 31, 32, 34, 58, 59, 62,

67, 78–79, 83, 84, 8, 90, 92–93,94, 115, 117, 134, 137, 138, 139,181, 183, 186, 255, 298, 300,302, 328, 341, 390, 406

Kala (KaS), 30, 32, 34, 58, 59, 62, 67,71, 73, 74, 75, 76, 79, 81, 82,84, 87, 91, 93, 115, 117, 120,125, 126, 127, 134, 138, 145,150, 173, 181, 183, 185, 186,187, 190, 192, 193, 194, 295,296, 328, 341, 355, 390

Kirmaku (KS), 30, 32, 34, 35–36, 38,58, 59, 62, 67, 71, 76, 78, 79,81, 83, 84, 87, 90, 93, 115, 117,120, 121, 122, 123, 124, 125,126, 127, 138, 139, 173, 174,

175, 181, 183, 186, 190, 191,192, 194, 255, 260, 328, 390

Nadkirmaku Clayey (Shaly) (NKG),30–31, 32, 34, 62, 115, 117, 124,125, 138, 139, 173, 174, 181,182, 183, 190, 255, 288, 390

Nadkirmaku Sandy (NKP), 62, 58, 59,67, 76, 78, 83, 84, 87, 90, 93,94, 101, 102, 107, 109, 115, 117,124, 125, 126, 127, 134, 138,139, 145, 150, 173, 174, 186,190, 192, 193, 194

Pereryv, 31, 32, 34, 58, 59, 62, 67, 68,78, 84, 86, 90, 93, 94, 101, 102,107, 109, 115, 117, 119, 134,138, 139, 150, 174, 181, 183,190, 192, 249, 250, 255, 263,271, 328, 341, 390, 406

Podkirmaku (PK), 30, 32, 34, 35, 38,58, 59, 62, 67, 71, 72, 74, 78,79, 82, 84, 85–86, 87, 88, 90, 93,94, 95, 101, 115, 117, 120, 121,122, 123, 124, 125, 126, 138,150, 173, 181, 182, 183, 185,186, 187, 190, 191, 192, 193,194, 260, 328, 341, 390, 406

Sabunchi, 31, 32, 34, 58, 59, 62, 84, 92,115, 117, 137, 138, 140, 142,341, 390

Surakhany, 31, 32, 34, 58, 59, 62, 84,115, 117, 138, 140, 142, 390

Surface activity, 319–324Survey, CDP, 248, 251, 254

gravity anomaly, 251Synclinorium, Kichikdag-Umid, 110

Shemakha-Gobustan, 20

T

Talysh foothills, 1, 4region, 23, 24

Technology, simulation, flowchart, 246Tectonic escape, 201Temperature, geothermal gradient, 148, 149,

152, 161–164, 196, 205, 354Tethys Sea, 201Theory of information, 290–293Thermobaric conditions, 164Thermographic studies, 140Thickness of pore-water film, 309, 313

Subject Index 441

Threshold, Apsheron, 16, 56, 57–91, 134,200, 210–212, 249

Traps, anticlinal faulted, 120, 128nonfaulted, 120, 128

classification, 120distribution, 120lithologic, 120, 128stratigraphic, 120, 128

Trend, Apsheron—pre-Balkhan, 248,248–251, 251–254

Tumarkhanly-Germelin, 26Trough, Baku, 18, 35, 40, 41

Dzheirankechmes, 101Gobustan-Apsheron, 3Iori-Adzhinour, 3, 6Kelkor, 206Kura, 3, 6Lower Kura, 101Middle Kura, 147South Mangyshlak, 234, 236Western Kuban, 359Yevlakh-Agdzhabedy, 3, 6

molasse, 16periclinal, 16

U

Undercompaction, 241Uplift (see also high), Airantekyan, 21

Alyaty, 21Azi Aslanov, 73Bibieibat, 35, 40Chyragh, 251Duvanny Deniz, 102Dzharly, 6Geokchai-Saatly, 6Gubkin, 252, 253, 254Gyuneshli, 251Karachukhur-Zykh, 35Karadzhaly, 6Karakum, 212, 217, 219, 220Kilyazi-Kransnovodsk Zone, 147Koturdag, 21Kyanizadag, 18Kyurdamir-Saatly, 6, 14, 44Livanov-East, 252, 253Malay, 214–217Mary-Serakh, 214, 217, 220Mil, 6Muradkhanly, 6

Saatly, 5, 6, 15Sangachal, 102, 104Shabandag, 41Shubany, 40Sor-Sor, 6Tourogai, 18Zardob, 6Zhdanov, 254

V

Viscosity, crude oil, 340oil, Engler, 38

kinematic, 340, 342–346Volcanic, breccia, 19, 21

chemical analyses, 13magmatic, 16

Volcanoes, mud, 5, 16–21, 62, 208Airantekyan, 21Akhtarma, 18Bogboga, 35cones, 17Dashgil, 21definition, 16gases, 18Gegerchin (Kirdag), 21Greater Kyanizadag, 18Gyulbakht, 18Koturdag, 21Kushkhana, 18Kyzyltepe, 18Lokbatan, 18-20, 42Lokbatan-Otmanbozdag group,

18–19Makarov Bank, 95Otmanbozdag, 18Pilpilya, 18region of, 16–17Sarynja, 18Shongar, 18Tourogai, 18trace elements, 18Turkmenistan region, 199

Volchy Vorota (Wolf Gate), 40

W

Waterflooding, 398


Water, chemical composition, 189formation, properties, 188–191Productive Series, 189salinity, 189–191, 192–194saturation, 308, 310

Well logs, Resistivity logs, calculation ofpressure, 152

sonic, 153Well, super deep, Saatly, SD-1, 9–15

X

X-ray diffractometer, 140, 142, 160

Y

Yasamaly Valley, 18, 19, 40

Z

Zardob magnetic maximum, 7Zone, Alpine, 14

geosynclinal, 52Chikislyar-Okarem, 199Dzharly-Saatly, 26island arc, 15Mil-Mugan, 26Transcaucasus, 14Vandam, 1

petroleum geology of the south caspian basin

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