sandstone diagenesis and reservoir quality prediction ... · sandstone diagenesis and reservoir...

AUTHORS

Thomas R. Taylor � Shell International Ex-ploration and Production, Projects and Technol-ogy, 3737 Bellaire Boulevard, Houston, Texas77025; [email protected]

Tom Taylor has worked at Shell’s Bellaire Tech-nology Center since 1982 in research and ap-plications related to reservoir quality, diagenesis,

Sandstone diagenesis andreservoir quality prediction:Models, myths, and realityThomas R. Taylor, Melvyn R. Giles, Lori A. Hathon,Timothy N. Diggs, Neil R. Braunsdorf, Gino V. Birbiglia,

and rock properties. He holds a B.S. degreefrom Winona State University and a Ph.D. from

Mark G. Kittridge, Calum I. Macaulay, andIrene S. Espejo

Michigan State University.

Melvyn R. Giles � Shell International Ex-ploration and Production, 200 North DairyAshford, Houston, Texas 77079-1197;[email protected]

Melvyn R. Giles has a B.Sc. (honors) degree ingeology and chemistry from the University ofBristol and a Ph.D. from the University of Glasgow.He joined Shell’s Koninklijke/Shell Exploratie EnProduktie Laboratorium research center in 1980,where he has been active in diagenesis, basinmodeling, overpressure, rock property, and geo-physical research. He is currently the global themeleader for unconventional gas.

Lori A. Hathon � Shell International Ex-ploration and Production, Projects and Tech-nology, 3737 Bellaire Boulevard, Houston,Texas 77025; [email protected]

Lori Hathon worked in exploration and regionalstudies for Amoco Production Company priorto joining Shell International Exploration andProduction, Inc. in 1997. At Shell, she has per-formed research in reservoir quality and physicalrock properties modeling. She holds a B.S. de-gree from Michigan State University and a Ph.D.from the University of Missouri.

Timothy N. Diggs � Shell International Ex-ploration and Production, 200 North Dairy Ash-ford, Houston, Texas 77079-1197;[email protected]

Tim Diggs holds undergraduate and graduatedegrees from the University of Virginia and theUniversity of Texas at Austin. He has more than

ABSTRACT

Models and concepts of sandstone diagenesis developed overthe past two decades are currently employed with variable suc-cess to predict reservoir quality in hydrocarbon exploration.Not all of these are equally supported by quantitative data, ob-servations, and rigorous hypothesis testing. Simple plots of sand-stone porosity versus extrinsic parameters such as current sub-surface depth or temperature are commonly extrapolated butrarely yield accurate predictions for lithified sandstones. Cali-brated numerical models that simulate compaction and quartzcementation, when linked to basin models, have proven suc-cessful in predicting sandstone porosity and permeability wheresufficient analog information regarding sandstone texture, com-position, and quartz surface area is available.

Analysis of global, regional, and local data sets indicates thefollowing regarding contemporary diagenetic models used topredict reservoir quality. (1) The effectiveness of grain coatingson quartz grains (e.g., chlorite, microquartz) as an inhibitor ofquartz cementation is supported by abundant empirical dataand recent experimental results. (2) Vertical effective stress, al-though a fundamental factor in compaction, cannot be usedalone as an accurate predictor of porosity for lithified sand-stones. (3) Secondary porosity related to dissolution of frame-work grains and/or cements is most commonly volumetricallyminor (<2%). Exceptions are rare and not easily predicted withcurrent models. (4) The hypothesis and widely held beliefthat hydrocarbon pore fluids suppress porosity loss due toquartz cementation is not supported by detailed data and does

24 years of experience in clastic and carbonatepetrology, with more than 20 years at Shell work-ing on field- to regional-scale reservoir charac-terization. He has also worked extensively withnumerous types of unconventional reservoirs,including HPHT, oil shales, and fractured reservoirs.

Copyright ©2010. The American Association of Petroleum Geologists. All rights reserved.

Manuscript received July 13, 2009; provisional acceptance December 4, 2009; revised manuscriptreceived January 25, 2010; final acceptance April 21, 2010.DOI:10.1306/04211009123

AAPG Bulletin, v. 94, no. 8 (August 2010), pp. 1093– 1132 1093

Neil R. Braunsdorf � Shell InternationalExploration and Production, Projects and Tech-nology, 3737 Bellaire Boulevard, Houston,Texas 77025; [email protected]

Neil Braunsdorf holds undergraduate and grad-uate degrees from Stony Brook University andthe University of Michigan. He has more than25 years of experience in exploration and ex-ploration research with Shell, investigating variedaspects of rock and fluid properties and pore-pressure prediction. His current research inter-ests include unconventional reservoirs andpredrill rock property prediction in complexgeological settings.

Gino V. Birbiglia � Sarawak Shell Berhad,Locked Bag No.1, Miri, Sarawak, Malaysia98000; [email protected]

Gino Birbiglia joined Shell in 1997. He has abroad technical background, including previousroles as a development geologist, explorationgeophysicist, and regional exploration geologist.He has worked in deep-water, shelf, and on-shore environments, primarily in the United Statesand Southeast Asia. Presently, he is living andworking in Malaysia evaluating new explorationopportunities in Southeast Asia.

Mark G. Kittridge � Shell International Ex-ploration and Production, 200 North DairyAshford, Houston, Texas 77079-1197;[email protected]

Mark G. Kittridge is a principal technical expert(quantitative interpretation) and a regional dis-cipline lead in petrophysics with Shell Interna-tional EP Inc. He joined Shell in 1988 after earningB.Sc. and professional degrees in geological en-gineering from the Colorado School of Minesand an M.Sc. degree in petroleum engineeringfrom the University of Texas.

Calum I. Macaulay � Shell InternationalExploration and Production, Projects and Tech-nology, 3737 Bellaire Boulevard, Houston,Texas 77025; [email protected]

Calum Macaulay is a sedimentary petrologist.He holds a B.Sc. degree in geology and miner-alogy from the University of Aberdeen and aPh.D. in applied geology from the University ofStrathclyde. As a postdoc at the Scottish Uni-versities Research and Reactor Center and theUniversities of Glasgow and Edinburgh, he in-vestigated diagenetic processes for 10 yearsbefore joining Shell in 2001.

1094 Sandstone Reservoir Quality Prediction

not represent a viable predictive model. (5) Heat-flow pertur-bations associated with allochthonous salt bodies can result insuppressed thermal exposure, thereby slowing the rate of quartzcementation in some subsalt sands.

INTRODUCTION

The success of many hydrocarbon exploration efforts dependsin large part on finding sandstone reservoirs with sufficientporosity and permeability to support commercial develop-ment. Assessing reservoir quality risk is especially importantin plays and prospects where objective sandstones have beenexposed to elevated temperatures (>∼100°C) and/or high ef-fective stresses for significant periods of geologic time.

The detection of seismic bright spots and other direct hy-drocarbon indicators led to a boom in deep-water explorationin Tertiary basins worldwide in the 1980s and early 1990s.However, direct seismic detection of reservoir sandstones anddifferentiation of pore-fluid type are made problematic as a re-sult of changes in acoustic rock properties associated with pro-gressive diagenesis. Inmost of the cases involving highly lithifiedsandstones and bounding mudrocks, confidently distinguishingseismic impedance response associated with contrasting fluidtypes (brine, oil, or gas) from that attributable to variable sand-stone porosity is not possible (Kittridge et al., 2004a, b). Fur-thermore, seismic differentiation of sandstone reservoirs con-taining low-saturation gas from those with pore systems highlysaturated with oil becomes increasingly difficult as sandstoneporosity decreases. These factors, coupled with the degradationof seismic resolution with depth, make assessment of reservoirquality risk from seismic attributes alone highly suspect.

As a general rule, in first-cycle basins, sandstone porositydecreases with increasing depth (Figures 1, 2), giving rise to re-gional porosity-depth or porosity-temperature curves that havecommonly been applied in hydrocarbon exploration (Schmokerand Gautier, 1988; Schmoker and Schenk, 1994, Ehrenberget al., 2008). Occurrences of high-quality reservoir sandstonesthat deviate from normal porosity-depth trends are attributedto processes or conditions that have limited compaction and/or cementation, or to porosity enhancement by dissolution ofgrains or preexisting cements. Bloch et al. (2002, p. 301) definedanomalous porosity or permeability as “…statistically higherthan the values in typical sandstone reservoirs of a given li-thology, age, and burial/temperature. In sandstones contain-ing anomalous porosities, such porosities exceed the maximum

Irene S. Espejo � Shell International Ex-ploration and Production, 200 North DairyAshford, Houston, Texas 77079-1197;[email protected]

Irene Espejo has more than 18 years of industryexperience, having joined Shell in 2001. Herwork involves upscaling properties among thinsection, core, log, and subseismic scales, relat-ing them to depositional environments, prove-nance, rock properties, and reservoir qualitymodeling. Previous experience includes a researchassociate appointment at Rice University. Sheholds a doctorate degree from the University ofBuenos Aires.

ACKNOWLEDGEMENTS

The authors gratefully acknowledge Shell In-ternational Exploration and Production for thepermission to publish this article. NumerousShell colleagues have contributed to the ideasand analysis presented in this article by meansof spirited critical discussions. We also thankR. H. Lander, L. M. Bonnell, and R. E. Larese forthe permission to include data and illustrationsfrom their work. Editorial comments by L. I.Summa, L. M. Bonnell, K. Bjørlykke, and R. H.Lander are acknowledged and greatly appreciated.The AAPG Editor thanks the following reviewersfor their work on this article: Knut Bjørlykke,Linda Bonnell, and Lori Summa.

porosity of the typical sandstone subpopulation.” By this defi-nition, the term anomalous porosity could be applied, forexample, to sandstones with 25, 15, or 6% porosity dependingon the background porosity typically encountered. For exam-ple, in Miocene sandstones of offshore Texas (Figure 2), onemight consider porosities of about 22% or more at depthsgreater than 4000 m (∼13,000 ft) to be anomalous.

The complex and variable interplay of factors such as sandcomposition, texture, and fluid chemistry under conditions ofvariably increasing temperature and effective stress throughtime yields a wide range of potential outcomes with respect toreservoir porosity and permeability. The high-reservoir-qualityend of this range is not in the strict sense anomalous but rep-resents the reasonable consequence of a specific combinationof geologic factors.

Given the task of evaluating reservoir quality risk with littleor no data, the explorationist is forced to rely on geologicmodelsand concepts. Selecting the appropriate model or analog isnot always straightforward, especially in true frontier settings.Some models are supported by empirical and/or theoreticalevidence and have the potential to be applied in a predictivemanner. Others, although conceptually plausible, do not with-stand rigorous testing against geological and petrophysical datayet are widely accepted by exploration geoscientists within theindustry.

Significant progress has been made in recent years towardthe successful application of calibrated numerical models (e.g.,Exemplar, Touchstone) that forecast sandstone porosity andpermeability by modeling mechanical compaction and quartzcementation as a function of thermal and effective stress histo-ries (Lander andWalderhaug, 1999;Walderhaug, 2000; Landeret al., 2008). However, many of the key factors that influencethe modeled evolution of porosity and permeability (e.g., sandtexture, grain coats, carbonate cements, authigenic clays) are im-portant model inputs (Panda and Lake, 1994, 1995) that mustbe constrained via use of analog data or diagenetic models andconcepts.

In this article, we critically evaluate existing methods anddiagenetic concepts that are commonly invoked to explain theoccurrence of anomalous, high-quality sandstone reservoirs atrelatively high temperatures and effective stresses. These in-clude (1) porosity-versus-depth trends, (2) influence of over-pressure on sandstone compaction and cementation, (3) inhibi-tion of quartz cementprecipitationby grain coatings, (4) porosityenhancement by dissolution of framework grains or cements,(5) preservation of porosity due to emplacement of hydro-carbon pore fluids and, (6) suppression of quartz cementation

Taylor et al. 1095

in subsalt settings.We then review the appropriatefunctions of these concepts in prospect and play riskassessment.

POROSITY-DEPTH TRENDS

Porosity-versus-depth curves are routinely employedto estimate sandstone porosity. Although instruc-tive in some respects, this approach is not a partic-ularly robust way of predicting reservoir quality forsandstones. These trends have proven useful in un-lithified sands with limited textural and mineral-ogic variability where mechanical compaction is thedominant porosity-reducing mechanism (e.g., Gulfof Mexico deep-water Tertiary turbidites). How-ever, simple extrapolation of compaction trends togreater depths where cementation rates increase isprone to significant error.

In the Gulf ofMexico, Pliocene–Pleistocene tolateMiocene sands are dominantly unlithified, andporosity tends to declinewith burial depth (Figure 1).Several factors contribute to the existence of thisstraightforward relationship. The data were derivedfrom clean sands with a relatively narrow range ingrain size and sorting (mean grain size∼80–120 mm,


moderately well sorted). The sands are dominantlycomposed of rigid framework grains of similar com-position and roughly similar mechanical properties.In the northern Gulf of Mexico deep-water region,overpressures related to compaction disequilibriumare established at relatively shallow depths andtend to increase in a predictable manner with depth(Ostermeier, 1995; Kittridge et al., 2004a).Depthbelow sea floor in this case is a proxy for system-atically increasing the vertical effective stress (VES).Because of the generally low thermal gradients inthe deep-water Gulf of Mexico region, the sands inthe data set are currently at less than 80°C and al-most entirely unaffected by quartz or other volu-metrically significant cementation. As such, fromsea bottom to approximately 4500 m (∼14,750 ft),mechanical compaction as a function of VES is thedominant control on sand porosity (Figure 1).

At greater depths (4500–7500 m [∼14,750–24,600 ft]) and higher temperatures, porosity indeep-water Gulf of Mexico sandstones is muchmorevariable and no longer follows a simple depth trend(Figure 1). This reflects the onset of significant quartzcementation (temperature >∼100°C) and, in somecases, greater porosity loss caused by mechanicalcompaction. Also plotted are data from two Gulf of

Figure 1. Porosity-versus-depth trendsfor sands from two Tertiary offshoredeep-water basins: the Gulf of Mexico(GOM) and offshore Niger Delta. Dataare derived from core and wireline logmeasurements. Gulf of Mexico wet-sandlog data (solid gray squares) representunlithified deep-water sands currentlyat their maximum burial depths and attemperatures less than 80°C. Log datafrom four deep Gulf of Mexico wells(solid black circles) correspond to deep-water Miocene sands at maximum burialdepths with temperatures greater than80°C. Core-porosity data from two Gulfof Mexico shelf wells (open triangles) arealso from Miocene sands with present-day temperatures in excess of 80°C.Offshore Niger Delta log porosity data(solid gray triangles) define a trend(dotted line) that provides a very poormatch to core-porosity data from anearby well (light-gray diamonds).

Mexico Basin shelf wells where higher thermalgradients push the onset of quartz cementation toshallower depths than observed in the deep-waterregion. Clearly, we can conclude from these datathat extrapolation of simple porosity-depth trendsinto the realm of high-temperature diagenesis isfraught with errors.

An additional pitfall associated with usingporosity-depth trends for reservoir quality predic-tion is the inappropriate application of trends de-rived from one basin to another basin. Data from asingle deep-water lease block, offshore Nigeria, areplotted along withGulf ofMexico data in Figure 1.The Nigeria wireline-log data define a trend with agreater porosity decline with depth than observed

in theGulf ofMexico data set.When core data fromthe same block are plotted, they define an evengreater rate of decline with depth. Several factorsare at play here. Sediments in offshore Nigeria arecharacteristically at hydrostatic or only mildly over-pressured conditions and are therefore exposedto much greater VES at a given depth than deep-water Gulf of Mexico sediments. In addition, Ni-ger Delta sands are characterized by amuch greaterrange of grain size and sorting (mean grain size∼120–500 mm; well to poorly sorted) resultingin a much greater span of initial depositional po-rosities than Gulf of Mexico sands. Furthermore,within areas like offshore Nigeria where widelyvariable sand textures are the norm, a single porosity

Figure 2. Compilation of petrophysical(core and wireline log) data for middleMiocene sandstones from 37 wells in theBrazos, Mustang Island, and MatagordaIsland areas of the Corsair trend, offshoreTexas. Extensive petrographic study hasshown that variable calcite cement abun-dance is the primary control on porosityvariation. Anomalously high porosity valuesoccur locally in some deeply buried sand-stones at Picaroon field (Brazos A-19, A-20).

Taylor et al. 1097

trend for all sands does a very poor job of describingnature.

In extreme cases, porosity-versus-depth plotsare essentially useless for accurate predrill predic-tion (Figure 2). Middle Miocene (∼15 Ma) sand-stones from the offshore Texas continental shelfexhibit a broad range in porosity over the depthrange of approximately 2000–6000 m (∼6500–19,700 ft). Petrographic and log analyses indicatethat varying quantities of pore-filling calcite cementis the main reason for such widely variable poros-ities (Vogler andRobison, 1987; Taylor, 1990; Taylorand Land, 1996). The mean porosity trend for thisdata set is meaningless with regard to predictingporosity for a given well or prospect.

OVERPRESSURES AND SANDSTONE POROSITY

Increasing effective stress caused by sediment load-ing is the major physical force driving the reductionin porosity of sandstones by compaction. Mechan-ical compaction is the dominant process by whichsand porosity is reduced from surface depositionalvalues of 40–50% to typical values of 25–32% priorto lithification (Houseknecht, 1987; Paxton et al.,2002). The development of fluid overpressures less-ens the VES, thereby reducing the load borne byintergranular and cement-grain contacts within bur-ied sand. Overpressures can slow the rate of com-paction but do not result in a bulk-rock volume (i.e.,porosity) increase. Both experimental and empiricalevidence indicates that compaction of sand is anirreversible process (Giles, 1997).

Significant porosity preservation is commonlysuggested to occur as a result of fluid overpressuresin sandstones (RammandBjørlykke, 1994;Wilson,1994; Osborne and Swarbrick, 1999). This hy-pothesis is taken further in most basin modelingprograms that assume that a simple dependenceof porosity on effective stress exists (Schneiderand Hay, 2001). An exploration strategy based onoverpressuring would thus predict more favorablereservoir quality in overpressured intervals thanin equivalent, normally pressured reservoirs. Twomechanisms have been proposed. First, porosity that


would otherwise be lost to compaction is held openby overpressures, resulting in anomalously poroussandstones at significant burial depths. Second,overpressures have been suggested to limit or pre-vent significant quartz cementation by forestallingthe onset of intergranular pressure solution, there-by eliminating a presumed primary source of silica(Osborne and Swarbrick, 1999; Walgenwitz andWhonham, 2003).

Effective Stress, Sand Composition, andPorosity Data

Sandstone compaction is dependent not only oneffective stress history, but also on the mechanicalproperties of the sand. The mechanical strengthsof the various individual detrital components andauthigenic cements combine to determine the bulkmechanical strength of a sediment, which deter-mines how a given sand will respond to increasingeffective stress.

Blochet al. (2002) examined relationships amongeffective stress history, detrital grain ductility, andthe onset of quartz cementation using numericalcompaction and cementation models. The modelscontrast hypothetical end-member quartz-rich (rigid)and lithic-rich (ductile) sands. For both lithic-richand quartz-rich sands, early overpressures providea depth window of potential porosity preservationuntil temperatures reach the point where signifi-cant quartz cementation can occur (>∼90°C). Latedevelopment of overpressures has a much smalleror negligible effect on porosity.Given sufficient timeand increasing temperature due to increasing burial,themodels predict that, in the absence of robust graincoats, intergranular porosity preserved by inhibitionof compaction will be filled with quartz cementnegating the positive effects of fluid overpressure.

Given the natural range of sand composition,one should clearly not expect a global VES-porosityrelationship to exist. Nonetheless, unlithified sandsof generally similar framework-grain composition fol-low fairly consistent local or regional VES-porositytrends (Giles, 1997). In these examples, present-dayVES represents the maximum historical effectivestress.Geologic situations inwhich present-dayVES

does not represent the historical maximum may in-volve uplift and/or late development of overpres-sures. In compressional settings, the maximum prin-cipal stress may not be the vertical component, andin such cases, one would not expect VES to berelated to sandstone porosity in anymeaningful way.

Examination of internally consistent, quanti-tative petrographic data collected by the authorsillustrates the difficulties of relating present-dayVES to reservoir properties in sandstones that havebeen subjected to various degrees of diagenesis.The data set consists of 645 analyses of sandstonesranging in age from Miocene to Permian and cov-ering a broad range in framework composition(Figure 3). All the sandstones included in the dataset have less than 5% detrital matrix clay, withmostcontaining less than 1%. A plot of intergranularvolume (IGV), a parameter used to gauge com-paction state (IGV = intergranular porosity + Spore-filling cements + matrix; expressed in terms ofthe percentage of bulk-rock volume) versus VES,shows a high degree of scatter with a general weaktrend of decreasing average IGV with increasing

stress (Figure 4A). An analogous plot of VES ver-sus thin-section porosity reveals no discernabletrend, only a tendency for maximum porosity todecline with increasing VES (Figure 4B). The largeoverall scatter observed is attributable to differencesin sand texture, composition, and cementation.

If the generation of dissolved silica by pressuresolution is a significant control on sandstone res-ervoir quality, a systematic trend toward increasedcompaction and quartz cement abundance withincreasing VES should be evident. Moreover, aninverse correlation between IGV and quartz ce-ment volume would be expected if the bulk vol-ume is reduced via dissolution at grain contactsand quartz cement is precipitated within the ad-jacent intergranular pore space. In the global dataset presented here, the volume of quartz cementshows no correlation with VES (Figure 5), suggest-ing that overpressured sands have had equal accessto sources of silica for quartz cementation. Clearly,VES alone does not provide the level of precisionrequired to assess reservoir quality risk for diage-netically modified sandstones prior to drilling.

Figure 3. Standard quartz,feldspar, and rock fragment plotfor global sandstone data setused in subsequent plots anddiscussions (Folk, 1974). GOM =Gulf of Mexico.

Taylor et al. 1099

GRAIN COATINGS AND RESERVOIRQUALITY PRESERVATION

In most sandstone reservoirs with quartz cement,the cement crystals nucleate on detrital quartz grains.These overgrowth crystals have the same crystal-lographic orientation as their grain substrates.Authigenic quartz crystals of this type grow into theadjacent pore space and commonly result in signif-icant progressive loss of intergranular porosity withincreasing temperature (Bjørlykke and Egeberg,1993; Giles et al., 2000; Walderhaug, 2000). Em-pirical and theoretical studies have shown thatquartz cementation in sandstones is controlled bythe rate of precipitation, which is highly sensitiveto temperature (Oelkers et al., 1996; Walderhaug,1996). Experimental and empirical evidence in-dicates that precipitation rate is also influenced bythe grain size of the quartz substrates (Lander et al.,2008). The volume of quartz cement can thereforebe directly related to an integrated time and tem-


perature function, the size distribution of potentialquartz substrates, and the quartz surface area avail-able for precipitation (Walderhaug, 1996, 2000;Lander andWalderhaug, 1999; Lander et al., 2008).The formation of grain coats on the surface of de-trital quartz grains prior to the onset of significantquartz precipitation is thought to inhibit cementa-tion by forming a barrier that prevents widespreadnucleation of quartz. The most effective types ofgrain coats observed in sandstones are clay mineralsand microcrystalline quartz. Other less effectivetypes of grain coats include detrital clay rims andfine crystalline carbonates (e.g., siderite).

Clay Coats

The importance of clay mineral coats in preservingporosity in sandstones has been recognized in nu-merous studies (Heald and Larese, 1974; Thomson,1979; Pittman et al., 1992; Ehrenberg, 1993; Blochet al., 2002; Anjos et al., 2003; Taylor et al., 2004).

Figure 4. Thin-section data versus present-day vertical effective stress (VES) for the global sandstone data set. (A) Intergranularvolume (IGV) versus VES. (B) Thin-section porosity versus VES.

These reports present examples in which sand-stones that lack or have poorly developed clay coatsare highly cementedwith authigenic quartz,whereasidentical sands with robust grain coats contain muchlower volumes of quartz cement.Authigenic chloriteis the most important and effective grain-coatingmineral in terms of limiting extensive quartz ce-mentation in sandstones. This is in large part due tothe strong tendency of chlorite to form continuouslayers that line the interface between detrital grainsand intergranular pore space (Figure 6). Authigenicillite and mixed-layer clays are less frequently re-ported as grain coatings (Storvoll et al., 2002). Ingeneral, detrital clay rims, formed by processessuch as mechanical infiltration, are less continuousthan authigenic coatings and therefore less effec-

tive in inhibiting quartz cement nucleation (Wilsonand Pittman, 1977; Bloch et al., 2002) althoughauthigenic clay coats may form in part from detritalprecursors.

A prime example of the effectiveness of con-tinuous chlorite coats is the Jurassic Norphlet For-mation in Mobile Bay, offshore Alabama (Dixonet al., 1989; Taylor et al., 2004; Ajdukiewicz et al.,2010, this issue).At this location, the eolianNorphletis an excellent gas reservoir with porosities com-monly in the range of 15–20% at depths of 6600–7000 m (21,600–23,000 ft) below the sea floor.Most detrital grain surfaces are coated with chlo-rite, and only minor amounts of quartz cement arefound (Figure 7A). Where small discontinuities inthe chlorite rims occur in the uppermost part of the

Figure 5. Volume of authigenic quartzcement from thin-section versus present-day vertical effective stress for the globalsandstone data set.

Taylor et al. 1101

section, authigenic quartz has nucleated on the un-coated surface and filled the adjacent intergranularpore space (Figure 7B).

Quantitative data confirm the observations asto the importance of clay coats in limiting porosityloss due to quartz cementation. For example, aninverse relationship exists between the volume ofquartz cement and the percentage of detrital quartz-grain surface coatedwith clay in Jurassic andTriassicsandstones from the North Sea (Figure 8). Thesereservoirs are currently at their historical maximumtemperatures of approximately 130–160°C. Thescatter in the data is attributed to natural variationsin composition, texture, and local burial histories.In comparison, data from the Norphlet Formationfollow a much steeper trend (Figure 8). Norphletreservoirs at this location are currently at temper-atures greater than 200°C and have been hotterthan 100°C for approximately 100 m.y. (Tayloret al., 2004). This comparison illustrates the strongtemperature dependence of quartz precipitationrate. Furthermore, it is evident that, for higher tem-


perature reservoirs, much greater grain-coat cov-erage is required to preserve significant amounts ofporosity. Numerical models for quartz cementa-tion also predict that increasingly complete graincoats are needed to preserve porosity given highthermal exposures (Bloch et al., 2002; Lander et al.,2008).

Chlorite has been the subject of many diage-netic studies; however, no proven method of pre-dicting chlorite coats in data-poor frontier settingsexists (Bloch et al., 2002). In more mature settingswhere core data are available, the probability ofchlorite coatings can be assessed using sedimento-logical and petrographic analog data. Further study,more data from modern analogs, and experimentsare needed to decipher the mechanisms of chloriteauthigenesis, including the potential impact of bio-logical controls (Needham et al., 2005).

Several of the most important examples of chlo-rite coatings preserving economic reservoir qualityare from deltaic and near-shore marine sandstonefacies (Ehrenberg, 1993; Hillier, 1994; Grigsby,

Figure 6. Scanning electronmicroscope photomicrographs ofgrain-coating authigenic chlo-rite in a Miocene sandstone fromthe Gulf of Mexico. (A) Low-magnification view reveals nearlycontinuous chlorite coats on de-trital quartz grains. (B) Highermagnification view correspond-ing to the box in panel A.

Figure 7. Thin-section photo-micrographs of eolian sandstonefrom the Jurassic Norphlet For-mation, offshore Alabama, Gulf ofMexico. (A) Detrital grains arelined with highly continuouschlorite rims. Only minor amountsof quartz cement are present.(B) A small discontinuity in thechlorite coating (arrow) allowsauthigenic quartz to nucleate anddevelop a syntaxial overgrowth.

2001). These are typically iron-rich varieties of chlo-rite and are associated with areas of river dischargeinto marine environments. Examples of deeply bur-ied, porous eolian sand reservoirs with highly con-tinuous,Mg-rich chlorite grain coats (e.g.,Norphlet,Rotliegend) are found in association with evaporitedeposits (Kugler and McHugh, 1990; Hillier et al.,1996). The alteration of volcanic rock fragmentsand glass provides internal sources for the elementalcomponents required to form authigenic chlorite in-

dependently of depositional environment (Thomson,1979; Pittman et al., 1992; Anjos et al., 2003).

Microcrystalline Quartz Coats

The occurrence of microcrystalline quartz coatingson detrital quartz grains has been identified as apotentially effective mechanism for inhibiting theformation of pore-filling quartz overgrowths (Aaseet al., 1996). Because of the crystal size, microcrys-talline quartz is difficult to detect in thin sectionusing standard light microscopy but easily identifiedusing standard scanning electron microscope (SEM)secondary electron images (Figure 9). Microquartzcoats consist of a layer of approximately 1–15-mm,prismatic quartz crystals with randomly orientedc-axis directions. The morphology of microcrystal-line quartz is thought to be a result of rapid crys-tallization from silica-supersaturated solutions.

Dissolution of siliceous sponge spicules, a vari-ably abundant but common component of shallow-marine Jurassic and Cretaceous sandstones in theNorth Sea, provides a mechanism for creating andmaintaining elevated concentrations of dissolvedsilica at relatively low temperatures. Dissolutionof amorphous, silica-rich volcanic glass also repre-sents a potential detrital source for generating silicasupersaturation.

Although initially it seems peculiar to proposethat one morphology of quartz would inhibit orprevent the nucleation of another, growing empiri-cal, theoretical, and experimental evidence support

Figure 8. The volume of quartz cement and the percentage ofcoated quartz surface area, both determined petrographically,are plotted for Jurassic and Triassic sandstones from the centralNorth Sea and for the Jurassic Norphlet sandstones of MobileBay in the Gulf of Mexico.

Figure 9. Scanning electronmicroscope photomicrographsof microcrystalline quartz inJurassic Fulmar Formation sand-stones of the central North Sea.(A) Minute crystals of quartz linethe surfaces of detrital quartzgrains in this example. The crys-tals range from approximately 1–15 mm in length measured alongthe c axis. (B) High-magnificationview of microquartz crystals.
The c-axis directions are generallynot aligned with the c axis ofthe underlying detrital quartz grain.
Taylor et al. 1103

such a mechanism (Bonnell et al., 2006a, b; Landeret al., 2006). Documented examples of micro-quartz coats in deeply buried, porous sandstonesare from Jurassic and Cretaceous intervals of theNorth Sea (Aase et al., 1996; Ramm et al., 1997;Jahren and Ramm, 2000; Aase and Walderhaug,2005) and from Devonian sandstones of westernBrazil (Lima and De Ros, 2002). In these examples,sand intervals that contain robust microcrystallinequartz coats have significantly lower amounts ofquartz overgrowth cement and have higher inter-granular porosity than associated sandstones thatlack well-developed microquartz coats.

The apparent capacity formicrocrystallinequartzto inhibit the development of pore-filling quartzovergrowths is likely related to crystal growth me-chanics (Lander et al., 2006). The random c-axisorientations of microquartz crystals (Haddad et al.,2006) may prevent their merging into larger syn-taxial, quartz overgrowths. Laboratory experimentsand numerical modeling studies (Bonnell et al.,2006a, b; Lander et al., 2006) indicate that quartznucleation and growth on amicrocrystalline quartzsubstrate are significantly slower than on a mono-crystalline quartz host. Additional experiments(Lander et al., 2008) strongly suggest that growthrates slow greatly once quartz crystals achieveeuhedral form. Smaller crystals growing next tolarger crystals in the experiments achieve euhedralterminations much sooner. From that point for-ward, the growth rate for small euhedral crystalsis radically diminished, whereas the larger crystalscontinue to grow. The growthmechanisms revealedin these experiments are potentially analogous tothe effects of microcrystalline quartz in naturallyoccurring sandstones.

RESERVOIR QUALITY ENHANCEMENT:SECONDARY POROSITY

The term secondary porosity refers to pore spaceresulting from postdepositional dissolution of detri-tal grains or cements. Petrographic evidence for sec-ondary porosity produced by leaching of feldspars,lithic fragments, and carbonates is very commonlyobserved and has been documented in numerous


reports (Loucks et al., 1979, 1984; Schmidt andMcDonald, 1979; Mathisen, 1984; Taylor, 1990;Ehrenberg and Jakobsen, 2001). In the 1970s and1980s, the notion that porosity in deeply buriedsands was dominantly secondary porosity producedintense debates. Based mostly on qualitative petro-graphic observations and interpretations, this ideawas accepted by many as fact (Loucks et al., 1979;Schmidt and McDonald, 1979). Opposing viewscentered on the apparent lack of viable geochemicalmechanisms by which dissolution and mass trans-fer could occur in the deep subsurface (Bjørlykke,1984; Bjørlykke and Brendsdal, 1986; Lundegardand Land, 1986; Giles, 1987; Giles and de Boer,1990; Bjørlykke, 1998; Chuhan et al., 2001).

Volume Considerations: How MuchSecondary Porosity?

Porosity related to framework-grain dissolution(e.g., feldspars) can be recognized and statisticallyquantified by most capable and experienced sand-stone petrographers. Dissolution of pore-filling ce-ments (e.g., calcite) is less commonly recognizedand more difficult to quantify. The absence of ce-ment should not be interpreted as secondary po-rosity unless considerable petrographic evidenceof its former presence can be established. For thisreason, careful consideration must be given to thecriteria used to classify porosity. In our opinion, acritical eyemust be cast on conclusions derived fromlarge public data sets due to the application of in-consistent, subjective criteria, made by multiplepetrographers of varying levels of experience, re-garding quantities of secondary porosity. As a re-sult, the volume of secondary porosity is probablyoverstated in some publications.

In the following analysis, only petrographic datacollected by the authors using consistent standardsfor determining porosity types are used. For thisreason, a high degree of confidence is placed in thevolume of porosity attributed to the dissolution offramework grains in this data set, as summarizedin Table 1. These data are representative of sand-stones from a variety of depositional environments,basin settings, geological ages, geothermal gradientsand thermal maturities.

The total thin-section porosity is the sum ofvisible intergranular porosity and framework-graindissolution porosity. In Figure 10, these two po-rosity types are plotted versus themaximumburial

temperature as determined from basin modelingstudies. No simple relationship exists in our data setbetween framework-grain dissolution porosity andtemperature. The greatest volume (mean=4.8 ± 2%)

Table 1. Summary of Global Petrographic Porosity Data

Thin-Section Porosity
Framework-Grain Dissolution Porosity
Mean
Max Min StandardDeviation N Mean Max
Taylor e

Min

t al.

StandardDeviation

Gulf of Mexico, Eocene
17.3 27.0 3.5 6.4 129 1.7 5.0 0.0 1.1 North Sea, Jurassic 19.7 29.6 6.6 5.6 101 4.8 9.3 0.1 2.0 Gulf of Mexico, Miocene1 20.3 33.0 0.0 7.6 116 1.0 5.3 0.0 1.1 Gulf of Mexico, Miocene2 14.5 29.6 1.3 7.8 66 1.6 6.3 0.0 1.4 Gulf of Mexico, Jurassic 9.2 19.0 0.0 4.8 63 0.2 2.0 0.0 0.4 North Sea, Triassic 12.3 23.0 5.0 4.2 68 1.1 3.3 0.0 0.9 West Africa, Oligocene 22.8 35.0 12.7 5.3 20 1.2 4.3 0.0 1.0 North Sea, Permian 21.1 25.7 15.3 3.4 13 2.9 5.8 0.4 2.2
Figure 10. Porosity types derived fromthin-section analyses versus maximum his-torical temperature for a global sandstonedata set. The open symbols represent the totalthin-section porosity (TSf) and the filledsymbols represent the volume of framework-grain dissolution porosity (FGDf). GOM =Gulf of Mexico.

1105

occurs in Jurassic sandstones from the North Seaand is primarily the result of feldspar dissolution(Haszeldine et al., 1999; Taylor et al., 2005). All ofthe other sandstones average 2% or less framework-grain dissolution porosity (Table 1). Two sandstoneunits with mean values of less than 1.1%, the Tri-assic Skagerrak Formation from the central NorthSea and the Jurassic Norphlet Formation from the


Gulf of Mexico, are highly feldspathic sands thathave been exposed to high temperatures for ex-tended geologic periods. We can conclude fromFigure 10 that although porosity from framework-grain dissolution can be important in some situa-tions, it generally represents aminor fraction of totalporosity. Further evidence is revealed in a largeregional data set (750 point-count analyses) fromthe EoceneWilcox sands of the Texas Gulf Coast,collected by a single petrologist. The volume offramework-grain dissolution porosity varies, aver-aging 1.7%, and shows no discernable trend withdepth (Figure 11). Total thin-section porosity de-creases with depth due primarily to the precipita-tion of intergranular pore-filling cements. Althoughthe proportion of framework-grain dissolution po-rosity to total visible porosity increases with depth,the absolute volume is statistically constant.

An additional important question regarding theformation of secondary porosity from dissolutionof aluminum-silicate framework grains is whetherporosity or permeability is significantly enhanced asa result of the overall process (Bjørlykke, 1984;Gilesand Marshall, 1986). At issue is the effective masstransfer of the products of dissolution and the scaleon which it occurs (Hays and Boles, 1992). If theframe of reference is a standard thin section, oneend-member case is that in which all the compo-nents of framework-grain leaching (e.g., feldspars)are precipitated in the pore network as an authigenicphase (e.g., kaolinite, illite), resulting in an insig-nificant change in total porosity and a significantdecrease in permeability (Figure 12A). The oppositeend-member case results in most of the dissolvedcomponents being transported out of the frame of

Figure 11. Porosity types derived from thin-section analysesversus burial depth for Eocene Wilcox sandstones from the TexasGulf Coast. The open symbols represent the total thin-sectionporosity (TSf) and the filled symbols represent the volume offramework-grain dissolution porosity (FGDf).

Figure 12. Thin-section photo-micrographs showing examplesof framework-grain dissolution.(A) Feldspars and volcanic rockfragments show evidence ofextensive dissolution. Abundantauthigenic chlorite and illite claysline and partially fill pore space.(B) Feldspar-grain dissolutionresults in secondary porosity,and insignificant amounts ofauthigenic clay are found.

reference, leading to a net increase in porosity with-out a reduction of permeability (Figure 12B). Inthe collective experience of the authors, the mostcommon result for dissolution of aluminum silicateminerals is nearer to the first end member whereclay minerals are precipitated in roughly equal pro-portions to the dissolved solid volume. Cases of trueporosity enhancement due to dissolution of feldsparsand lithic grains are less frequently encountered.

Chemical Drive for SecondaryPorosity Generation

In the 1980s and early 1990s, attempts were madeto reconcile the observed occurrence of framework-grain dissolution pores and the lack of geochemicalmodels capable of explaining their formation. Theefforts to predict the development and location ofsecondary porosity in the subsurface were directedat identifying the geochemicalmechanisms bywhichsubsurface dissolution could occur.

Carbon Dioxide and Organic AcidsThe production of CO2 by thermal decarboxyla-tion of organic matter was initially proposed as amechanism for generating carbonic acid, presum-ably driving dissolution and development of sec-ondary porosity (Schmidt and McDonald, 1979;Franks and Forester, 1984). The results of mass bal-ance calculations, however, indicate that the amountof CO2 generated by this process cannot accountfor the volumes of secondary porosity commonlyobserved in sandstones (Bjørlykke, 1984; Lundegardet al., 1984; Giles and Marshall, 1986; Lundegardand Land, 1986). This mass-balance discrepancy isparticularly evident when one considers that in-organic chemical equilibria between pore fluids,feldspars, clay minerals, and carbonates controlpCO2 in clastic reservoirs (Smith and Ehrenberg,1989; Hutcheon et al., 1993). Large perturbationsin pCO2 and carbonic acid concentration are there-fore not possible in these strongly rock-buffered,clastic systems.

Surdam and coworkers (Surdam et al., 1984,1989; Crossey et al., 1986; Surdam and Yin, 1994)proposed that short-chained carboxylic acids, gen-erated from maturation of kerogen within source

rocks, supply the chemical drive for the formationof secondary porosity in sandstones. Expulsion andmigration of thesewater-soluble organic compoundswere seen as a practicalmechanism linking inorganicand organic diagenesis in the creation and filling ofreservoirs. On the basis of formation water analyses(Carothers andKharaka, 1978;Hanor andWorkman,1986; Kharaka et al., 1986; Lundegard and Kharaka,1990; MacGowen and Surdam, 1990), a tempera-ture window from 80 to 140°C was hypothesizedas optimal for secondary porosity generation. Theproposed effect of these organic acids at their peakconcentrations was to decrease the stability of bothcarbonate and aluminosilicate minerals. In addi-tion, carboxylic acids were thought to inhibit theprecipitation of authigenic clay by complexing alu-minum derived from feldspar dissolution.

The hypothesized link between organic acidsand porosity enhancement in sandstones sparkedconsiderable research. However, numerous lines ofevidence and extensive further research cast se-rious doubt on the proposed mechanisms. Objec-tions were raised on a series of issues:

1. Detailed chemical analyses of formation watersindicate that most contain concentrations of or-ganic acids that are too low to significantly in-fluence bulk rock-water equilibria (Barth andBjørlykke, 1993; Lundegard and Kharaka, 1994).

2. Mass-balance calculations reveal that the vol-ume of organic acids that can be derived fromtypical source rocks is insufficient to account forthe observed volumes of secondary porosity(Lundegard and Land 1986; Giles and Marshall1994; Pittman andHathon, 1994; Giles, 1997).

3. Geochemical studies have failed to substantiatemeaningful levels of Al-complexing by organicacids, a potentially instrumental factor for sig-nificant feldspar dissolution (Bevan and Savage,1989; Stoessell and Pittman, 1990; Manninget al., 1991; Giles and Marshall, 1994; Harrisonand Thyne, 1994).

4. Geochemical modeling using experimental andestimated thermodynamic data indicates that or-ganic acid anions haveminimal influence on rock-water reactions in natural systems (Harrison andThyne, 1994; Hyeong and Capuano, 2001).

Taylor et al. 1107

For more extensive discussion, the interestedreader is directed to the references above and otherscited in those articles.

Equilibrium Water-Rock ReactionsDiagenetic reactions in intermediate to deep burialregimes are rock buffered (Smith and Ehrenberg,1989; Land andMacpherson, 1992;Hutcheon et al.,1993; Hanor, 1996; Giles, 1997). Reactions involv-ing the dominant aluminum silicate and carbonateminerals found in most siliciclastic rocks controlthe evolution of aqueous pore fluids in sedimentarybasins. As a consequence of relatively lowporosities,pore fluids represent comparatively small volumesand thus cannot dissolve large volumes of solidminerals unless extremely high (unrealistic?) flowrates are involved (Giles, 1997). This has impor-tant implications with regard to understanding andmodeling howmuch secondary porosity can in factbe formed during burial diagenesis.

Dissolution and replacement of detrital potas-sium and plagioclase feldspar are natural conse-quences of diagenesis under conditions of increas-ing burial and temperature. No unusual or specialsource of acidic pore fluids is required (Giles and deBoer, 1990). Under the most common circum-stances, unstable feldspar grains react to formmorestable authigenic phases (e.g., albite, kaolinite, illite)with the pore waters acting primarily as transportagents. As pore fluids reach equilibrium with thereacting feldspar phases, mass transport must oc-cur for further reactions to proceed. The scales ofmass transport determine whether reservoir poros-ity and permeability are indeed enhanced by theoverall process. As stated above with regard to feld-spar dissolution, most cases studied by the authorsinvolve little or no net gain in sandstone porosity andpermeability. Exceptions are the Jurassic FulmarandHeather sandstones of the deep central grabenof the central North Sea where the observed vol-ume of secondary porosity attributable to feldspardissolution exceeds the volume of authigenic clayminerals on the thin section or core scale (Haszeldineet al., 1999; Taylor et al., 2005). Another rare de-viation from the norm is the Jurassic NorphletSandstone in Mobile Bay (offshore Gulf of Mex-ico), where detrital K-feldspar grains have authi-


genic K-feldspar overgrowths andwhere little or noevidence is found for feldspar alteration despiteburial to temperatures in excess of 200°C (Tayloret al., 2004). The evident stability of K-feldspar isrelated to the chemistry of pore fluids in the Nor-phlet. Formation waters from Mobile Bay fields areextremely saline brines (∼300 g/L total dissolvedsolids [TDS]) with exceptionally high concentra-tions of dissolved potassium (∼13–17 g/L). Thesebrines are in equilibrium with K-feldspar, and nosignificant chemical drive exists for further reaction.

Dissolution of significant amounts of carbonatecements and detrital carbonate grains in sandstonesis of debatable importance (Taylor, 1990; Hesseand Abid, 1998). The greater solubility of carbon-ate minerals compared to aluminum silicate min-erals suggests that porosity enhancement couldmorereadily occur without precipitation of byproducts(i.e., clay minerals) that negatively impact perme-ability. Nevertheless, carbonate dissolution is sub-ject to similar mass balance and rock-dominatedequilibrium constraints as feldspar dissolution. Porewaters equilibrate relatively quickly with carbonateminerals in the subsurface. The volume of solidcarbonateminerals that can be dissolved by a singlevolumeof pore fluid is necessarily small given typicalwater/rock ratios. The removal of a large enoughquantity of carbonate material to significantly im-pact reservoir quality hence requires fluid flow toreplenish the systemwith undersaturated solutions.Given that the rates of compactional fluid flow indeep subsurface environments are extremely lim-ited (Bethke, 1985; Giles, 1987, 1997; Harrisonand Summa, 1991), porosity enhancement by dis-solution of carbonate minerals is not likely to becommonplace.

One areawhere carbonate dissolution is thoughtto be a factor in reservoir quality enhancement isthe Corsair trend (offshore Texas, Gulf of Mex-ico). Deeply buried middle Miocene–aged sand-stones are frequently cemented with calcite alongthe more than 100-mi (161-km)-long Corsair faultsystem (Vogler and Robison, 1987; Taylor, 1990).Reservoir quality is significantly impaired by thepresence of pore-filling calcite in most locationsas evidenced in numerous unsuccessful explora-tion tests along the trend that have encountered

sandstones with marginal or noneconomic poros-ity. Thick sandstones with anomalously high po-rosities (>20%) are found at only a few locations, themost notable being Picaroon field.

The anomalous nature of the high porosities atPicaroon field is clearly seen in a porosity-versus-depth plot for middle Miocene–age sands of theCorsair trend (Figure 2) and in a porosity-versus-permeability plot (Figure 13). At depths greater thanapproximately 4200 m (∼13,800 ft), Picaroon area

sands fit the definition of anomalous porosity quotedpreviously (Bloch et al., 2002). A detailed petro-graphic study has established evidence for partialdissolution of pore-filling calcite cement and de-trital carbonate grains in the most porous sands atPicaroon (Figure 14), which is lacking in the sandswith typically lower porosity from the region (Taylor,1990; Taylor and Land, 1996). Additional quartzcementation following calcite dissolution is inhib-ited by the presence of grain-coating chlorite that

Figure 13. Porosity versus permeabilityfrom laboratory core analyses of middleMiocene deltaic sandstones from the Corsairtrend, offshore Texas. Sandstones fromDoubloon and Plank locations lack evi-dence of calcite dissolution and significantsecondary porosity. The highest porositiesat Doubloon are approximately 15–21%,and the maximum for Plank is 17%. NearbyPicaroon area sands span the same rangebut extend to porosities in the range of20–29%. Petrographic examination indi-cates that dissolution of calcite occurred inthe high porosity and permeability sand-stones from the greater Picaroon area.

Figure 14. Thin-section photo-micrographs of middle Miocenereservoir sandstones from Pica-roon field, offshore Texas. (A) Ahighly corroded detrital calcitegrain (center) is typical of thosefound in highly porous (20–29%)reservoir sandstones from Pica-roon. Small, irregularly shapedremnants of ferroan calcite ce-ment (arrows) occur nearby.(B) Corroded remnants of ferroan
calcite cement (mauve) are com-mon in highly porous reservoirsandstones from Picaroon.
Taylor et al. 1109

formed prior to calcite cementation. Statistical com-parisons using thin section and core analysis dataindicate that deep sandstones fromPicaroon have onaverage 4–6% greater porosity than equivalent-agesands from nearby locations (Taylor and Land, 1996).Although obtaining conclusive proof is impossible,carbonate dissolution has probably been a signifi-cant factor in contributing to the observed anom-alous porosities.

Understanding the reasons why carbonate dis-solution is substantial at Picaroon but not at other,geologically similar locations is important if predrillprediction of comparable anomalous deep porosityis to be achieved. Evidence is found in the chemicalcomposition of produced formation waters fromPicaroon andDoubloon fields, located approximately6 mi (9.6 km) apart (Taylor and Land, 1996). For-mation waters from Doubloon field are moderatelysaline Na-Cl brines (62–75 g/L TDS), typical ofthose found in theGulf ofMexicoCenozoic section(Morton and Land, 1987; Land and Macpherson,1992). In contrast, formationwaters produced fromPicaroon are highly saline Na-Ca-Cl brines (150–244 g/L TDS) with uncommonly high concentra-tions of Sr, Ba, Fe, Pb, and Zn. The major and traceelement compositions and isotopic signatures ofPicaroon brines are comparable to brines producedfrom underlying, deep, high-temperature reservoirsof Mesozoic age (Taylor and Land, 1996). The asso-ciation of chemically distinct, allochthonous brineswith anomalously high porosities and ample pet-rographic evidence for calcite dissolution stronglysuggests a link between a deep source of fluid andthe diagenetic evolution of these sands. Taylor andLand (1996) proposed a model in which highly sa-line brines in chemical equilibrium with sedimen-tary rocks at very high temperatures (>∼250°C)are episodically injected along the Corsair faultcausing focused dissolution in sandstones in thegreater Picaroon area. The fact that this processdoes not operate everywhere along the Corsair re-gional growth-fault system suggests that the geo-logical conditions that provide access to deep-fluidsources are somewhat extraordinary. Examplesfrom isolated fields in onshore south Texas presentsimilar evidence of calcite dissolution and associ-ated saline Na-Ca-Cl brines in the Oligocene Frio


Formation (Diggs, 1992; Diggs and Land, 1993).In contrast to the Picaroon example, however, con-tinued postdissolution diagenesis obscures any sig-nificant porosity gain in the Frio reservoirs. Gilesand de Boer (1989) proposed a comparablemodelthat could result in calcite dissolution in sandstonesadjacent to fault zones. Driven by the retrogradesolubility of calcite coupled with fluid migrationalong porous fault zones, localized dissolution zonescould potentially develop where permeable sandsprovide a conduit for cooling fluids.

POROSITY PRESERVATION:THE HYDROCARBON EFFECT

The idea that the presence of hydrocarbon porefluids in sandstones could influence porosity lossby inhibiting cementation was offered many yearsago (Johnson, 1920). The concept has been widelyaccepted by geologists and geophysicists as amechanism for porosity preservation in sandstonesthat have been exposed to high temperatures. Theextent to which this process might operate is im-portant because, if found to be effective, the focusof reservoir quality modeling changes from inor-ganic diagenetic reactions toward prediction of earlyhydrocarbon migration and trapping.

Examples of high porosity at structural crestsand declining porosity toward structural flankswithin an existing hydrocarbon accumulation, orcontrasts in porosity across oil-water contacts, arecommonly cited as evidence that hydrocarbon em-placement inhibits diagenesis (Emery et al., 1993;Gluyas et al., 1993; Marchand et al., 2000, 2001).Lower reservoir quality in water-bearing sands is in-ferred to be due to continued diagenesis (e.g., quartzor carbonate cementation, authigenic clay forma-tion) in the water leg.

The existence of oil-bearing fluid inclusions inquartz cement is cited as evidence to the contrary,proving that cementation continues with some frac-tion of hydrocarbon fluids present in the pore sys-tem (Ramm, 1992; Saigal et al., 1992;Walderhaug1996). Hydrocarbon fluid inclusions also occur incarbonate and albite cements. Authigenic illite inthe Garn Formation (Norwegian continental shelf)

shows no significant change in abundance acrossseveral oil-water contacts (Ehrenberg and Nadeau,1989), suggesting that illite precipitation continuesin the oil columnwithin the continuous water phaseor precipitated throughout prior to hydrocarbonemplacement. Illite K-Ar ages have been used toinvestigate the possibility of diagenesis influencedby hydrocarbon charge (Burley and Flisch, 1989;Hamilton et al., 1992; Darby et al., 1997;Wilkinsonet al., 2006), but analytical issues involving sepa-ration of detrital and authigenic phases cloud theinterpretation of these data.

Worden and coworkers (Worden et al., 1998;Barclay and Worden, 2000; Worden and Morad,2000) presented a thorough review of the empir-ical and theoretical arguments for and against po-rosity preservation by hydrocarbon emplacement.For water-wet sands under conditions of high hy-drocarbon saturation, advective transport of silicainto sands (e.g., from mudrocks) essentially stopsbecause of the very low relative permeability towater. Similarly, advective transport of the chem-ical components needed for carbonate cementationwould be impeded. Diffusive transport of silica (orCa2þ; Mg2þ; CO�

3 ) within a static but connectedwater phase could still proceed. However, at lowto irreducible water saturations, diffusion must oc-cur through much longer and more tortuous paths.The rate of diffusive transport of silica in solutionmay become progressively slower as the oil satura-tion increases and water saturation decreases. Ulti-mately, at very lowwater saturation, diffusion couldslow by up to two orders of magnitude (Wordenet al., 1998), supplanting quartz precipitation as therate-controlling step and essentially halting quartzcementation. For the relatively rare case of oil-wetsands, the mechanism is much like grain-coatingchlorite, effectively isolating detrital quartz grainsfrom the aqueous pore fluids.

Proposed Field Examples: How Strong isthe Evidence?

Despite anecdotal evidence beingwidespreadwithinthe industry, convincing documented cases of hy-drocarbons inhibiting diagenesis are rare. In mostinstances, the lack of conventional core in general

or from the water leg in particular precludes thequantitative comparison of cement volumes and po-rosity types required to rigorously evaluate the po-tential effect of pore-fluid type on diagenesis. As aresult, porosity preservation by hydrocarbon em-placement is sometimes advocated as a modelwithout examining other possible causes. These in-clude differences in grain size and sorting (relatedto depositional environment or facies), sand com-position (facies or provenance related), and diage-netic alteration (i.e., cementation or porosity en-hancement unrelated to the present hydrocarbonand water distribution).

Suppression of Quartz Cement PrecipitationIn a study of the Middle Jurassic sandstone res-ervoirs of the North Sea Brent Group, Giles et al.(1992) compiled data from 44 wells over a broadgeographic area. The data span a wide range ofburial depths and temperatures. This extensive anddetailed data set was used to show that reservoirquality is primarily related to depositional facies,compaction, and quartz cementation. A compar-ison of measured porosities for 2917 samples ofBrent Group sandstones shows that no systematicdifference between the porosity can be expectedin the hydrocarbon zones as opposed to the water-bearing zones. Molenaar et al. (2008) comparedthe porosity and volumes of quartz cement in oil-and water-bearing Cambrian sandstones from theBaltic Basin and reported no significant differencerelated to pore-fluid type.

Other studies that have made arguments for acausal link between oil emplacement and suppres-sion of quartz cementation in central North Sea Ju-rassic sandstones (Emery et al., 1993; Gluyas et al.,1993) present virtually no quantitative data regard-ing facies, sandstone texture and composition, quartzcement abundance, or porosity types. Furthermore,no mention of the presence or absence of grain-coating clay is made. The lack of these key datamakes it impossible to critically assess whether hy-drocarbon pore fluids have in fact influenced thediagenesis of these sands.

More recent investigations reached conflictingconclusions regarding the diagenesis of the Juras-sic Brae Formation sandstones from Miller field

Taylor et al. 1111

(south Viking Graben, North Sea) (Figures 15, 16).Marchand et al. (2000, 2001) presented data in-dicating that the average volume of quartz cementincreases from 6% in the oil-bearing zones at thestructural crest to 13.2% in the water-bearing sandsalong the structural flank. Statistical data are in-cluded to demonstrate that sand composition, grainsize, and sorting do not vary significantly as a func-tion of structural or paleodepositional position. Theresults of kinetic modeling calculations are inter-preted to show that oil emplacement has signifi-cantly retarded the rate of quartz precipitation.

Subsequent studies (Aase and Walderhaug,2005; Bonnell et al., 2006a, b) present data andevidence that contradict the previous work. Addi-tional petrographic data from core material notused in the original study reveal that highly quartz-cemented sandstones occur in the oil column as wellas in the water leg (Figure 17). When all data are


taken into account, no discernable relationship be-tween quartz cement volume and pore-fluid type isapparent. Detailed petrographic analyses employ-ing the SEM (Figure 18) document the presenceof microcrystalline quartz coats in the sandstoneswith comparatively low volumes of quartz cement(Bonnell et al., 2006a, b).When petrographic datafrom threewells are plotted versus depth, sandstoneswith the highest grain coat coverage and lowestquartz cement are evidently confined to the upper-most sands in the J stratigraphic unit (Figure 17A,B). The stratigraphically controlled distribution ofmicrocrystalline quartz coats at Miller field likelyreflects the concentration of detrital sponge debrisrelated to favorablemarine conditions present at thetime of deposition.

The relative timing of quartz cementation insandstones and maturation of the source rocks mustbe considered when evaluating the possible effectsof hydrocarbon emplacement on porosity evolu-tion. Both processes are highly dependent on ther-mal exposure (temperature over time)with the rateof quartz cement precipitation increasing exponen-tially as temperature exceeds approximately 80°C.The rate of oil generation from source rocks com-monly peaks between temperatures of approximately110 and 140°C. Peak generation temperature for in-dividual source rocks is a function of organic mattercomposition, heating rate, and geologic time.

To illustrate the potential consequences of thedifference in relative timing of inorganic and organicdiagenetic processes, three simple geologic scenar-ios are considered. Touchstone modeling softwareis used to calculate and compare the volumes ofquartz cement that would be generated in each setof geologic circumstances. Two well-sorted, 0.12–0.16-mm (0.004–0.006-in.), quartz-rich sands (Q:∼80; F: ∼7; R: ∼13) were used as starting materialfor the diagenetic simulations. Grain coatings wereassumed to be negligible. Model parameters forquartz precipitation kinetics and compaction wereobtained from internal studies and held constant inall the model runs.

In the first case, the reservoir sandstone is bur-ied to a maximum depth corresponding to a tem-perature of 80°C (Figure 18A). An older, organic-rich source rock occurs considerably deeper in the

Figure 15. Quartz cement volume determined from thin sectionversus depth for Jurassic sandstones from the Miller field, UnitedKingdom North Sea (data from L. M. Bonnell, R. E. Larese, andR. H. Lander, 2006, personal communication). Points A, B, and C arereferenced and explained in Figure 16. OWC = oil-water contact.

section at a temperature of 120°C and has reachedits oil generation peak. At the hypothetical welllocation, quartz cementation in the reservoir wouldbe in an incipient stage with only minor volumes(<1%) of authigenic quartz present (Figure 19,model 18a). Following the migration of oil into thereservoir, a well penetrationwould encounter highlyporous, oil-bearing sandstone. Given this situa-tion, the emplacement of hydrocarbons has hadno factor in influencing cementation and reservoirporosity.

The second scenario considers the case of asandstone reservoir juxtaposed with an organic-richsource rock (Figure 18B). The reservoir-source rockpair follows virtually the same burial history, en-tering the greater than 80°C temperature windowfor quartz cementation long before the source rockreaches peak oil generation.During this time, quartzprecipitation occurs forming volumetrically signifi-cant amounts of cement (4.6–5.5%) prior to oil em-placement (Figure 19, model 18b). Oil-bearing fluidinclusions in quartz cement and albitized feldspar

grains may form during the filling of the reservoir.Given the proximity of the source rock, migrationand charge would be geologically simultaneous. Ifwe assume that peak oil charge occurs at 120°C andno further burial or heating occurs, then the sand-stone would exhibit no discernable evidence of ce-ment suppression due to hydrocarbon charge. Fluidinclusions in quartz cement and authigenic albitewould yield homogenization temperatures of lessthan approximately 120°C.

A modification of the previous configurationin which subsequent burial and heating to 150°Coccur (Figure 18C) could yield evidence at the hy-pothetical well location that would allow the eval-uation of the hypothesized hydrocarbon effect. Ifhydrocarbon emplacement occurred at 10Mawhentemperatures reached approximately 120°C andimpeded further precipitation of quartz cement,fluid-inclusion evidence would reflect this uppertemperature limit. Furthermore, approximately 2–3% quartz cement would be found in the reservoirif oil emplacement halted cementation (Figure 19,

Figure 16. Photomicrographsof Jurassic Brae Formation sand-stones at Miller field, United King-domNorth Sea (fromL.M. Bonnell,R. E. Larese, and R. H. Lander,2006, personal communication).(A) Low-magnification SEM viewshowing the surfaces of detritalgrains within an intergranularpore. This sample has high poros-ity and low quartz cement (point Ain Figure 15, hydrocarbon leg).(B) High-magnification view. De-trital quartz grain surfaces arecoated with microcrystallinequartz in this highly porous res-ervoir interval. (C) Thin-sectionphotomicrograph of lower poros-ity interval with abundant over-growth quartz cement (point B inFigure 15, hydrocarbon leg).(D) Scanning electron microscopephotomicrograph of lower poros-ity interval (point C in Figure 15,
water leg). Note the lack of micro-crystalline quartz and develop-ment of large quartz overgrowths.
Taylor et al. 1113

Figure 17. Petrographic data from Jurassic Brae Formation sandstones at Miller field, United Kingdom North Sea, plotted versusdepth (TVDSS = true vertical depth subsea). Provided by L. M. Bonnell, R. H. Lander, and R. E. Larese (2006, personal communication).(A) Sandstones with grain coat coverage of greater than 30% (primarily microcrystalline quartz) are found exclusively in the J-levelstratigraphic unit at Miller field. (B) Samples with lower amounts of quartz cement are concentrated in the J-level sandstones at Miller field.The low volumes of quartz cement correspond to higher degrees of grain coat coverage and greater intergranular porosity. Note thatabundant quartz cement occurs at the top of the structure in close proximity to microquartz-bearing samples with low cement abundances.OWC = oil-water contact.


model 18c-HC). In comparison, Touchstone calcu-lations made assuming that hydrocarbon pore fluidsdo not significantly impede cementation (Figure 19,model 18c) predict much greater amounts of quartzcement (8.0–9.4%). If aqueous fluid inclusions werepresent in these cements, homogenization tempera-tures would approach an upper threshold of 150°C.Associated hydrocarbon-bearing inclusions mightbe expected as well.

The hydrocarbon filling history of most sand-stone reservoirs is undoubtedly more complicatedthan the three hypothetical examples presentedabove. Nonetheless, these end-member scenariosare useful when considering the types of data andevidence that are required to thoroughly evaluatewhether hydrocarbon pore fluids have influencedquartz cementation rates.

The Fulmar Formation of the central North Seahigh pressure-high temperature area provides anopportunity to test whether hydrocarbon porefluids have had any discernable effect on quartz

cementation. Cores from Shearwater field, a largegas condensate accumulation, and theMartha well(22/30a-1), a water-bearing Fulmar section, havebeen studied and compared in detail (Taylor et al.,2005). Porosities commonly range between 24 and33% at depths of 4500–5800m (∼14,750–19,000 ft)(Figure 20) and temperatures are approximately145–170°C. Extreme overpressures are encoun-tered in this area with the highest fluid pres-sures approaching lithostatic levels (Cayley, 1987;Gaarenstroom et al., 1993; Darby et al., 1996). Themain hydrocarbon source rock in the area is theUpper Jurassic Kimmeridge Clay, which occursstratigraphically above the Fulmar. Hydrocarboncharge modeling indicates that oil generation andmigration began at approximately 100 Ma andpeaked at 70–60 Ma, whereas peak gas generationoccurred from 15 to 0 Ma (Winefield et al., 2005).

Porosity generally decreases with depth belowthe top of the Fulmar in Shearwater wells that pen-etrate the gas-water contact (Figure 20). However,

Figure 18. Schematic cross sections depicting reservoir sandand source rock configurations. (A) At the well location, a sand-stone reservoir occurs at a depth where temperatures havereached approximately 80°C. The hydrocarbon source rockoccurs at greater depth where the in-situ temperature is about120°C. (B) The sandstone reservoir and hydrocarbon sourcerock are juxtaposed. At the well bottom, the temperature hasreached approximately 120°C. (C). The sandstone reservoir andhydrocarbon source rock shown above in panel B have under-gone greater burial where the bottom-hole temperature is ap-proximately 150°C.

Taylor et al. 1115

visual examination of the core slabs and thin sec-tion analyses indicate that porosity decline is dueto the transition from relatively clean upper shore-face sands to bioturbated, clay-rich, lower shorefacesands. The present-day gas-water contact occurs farbeneath the porosity drop. The Martha well pene-trated anentirelywater-bearing Fulmar sectionwithcomparatively low porosity at the top that increaseswith depth (Figure 21).

The composition and texture of the Fulmarsandstones at the two locations are similar (Table 2).The amounts of detrital quartz, feldspar, and lithicgrains are comparable. The range of IGV valuesoverlaps, indicating analogous levels of mechanicalcompaction. Quartz cement volumes are roughlythe same with a slightly greater average abundanceat Shearwater. Total authigenic pore-filling andreplacement clay (chlorite and illite) is on average


4% greater at Shearwater. As a result, Fulmar sandsat the Martha well have proportionally greaterintergranular porosity. Framework-grain dissolutionporosity is significant in both locations but some-what higher at Martha.

Both aqueous and liquid petroleum fluid in-clusions are present in quartz cement in samplesfrom Shearwater field, indicating that quartz pre-cipitation was active during filling of the reservoir.Homogenization temperatures for the aqueousinclusions range from 126 to 155°C, approachingpresent-day bottom-hole temperatures (∼165°C).Log, core, and geochemical analyses of the Fulmarat the Martha location have uncovered no indica-tion of a previous static hydrocarbon accumulation.However, quartz cement contains some liquid pe-troleum fluid inclusions as well as aqueous inclu-sions, suggesting that hydrocarbons have periodically

Figure 19. Touchstone model results forthree schematic burial histories, models18a–c, corresponding to scenarios illus-trated in Figure 18. Model 18c-HC rep-resents the results assuming that oil em-placement occurs at 10 Ma and stopsfurther formation of quartz cement (seethe text for an explanation).

migrated through the Fulmar atMartha (Winefieldet al., 2005).

Basin modeling indicates that during peak oilgeneration andmigration, temperatures in theFulmarsands at both Martha and Shearwater were between75–84°C. If hydrocarbon pore fluids had signifi-cantly slowed quartz precipitation, one would ex-pect to find that quartz cement formed at a muchslower rate at Shearwater given present-day tem-peratures and their comparable thermal histories.Numerical modeling of compaction and quartz ce-mentation using Touchstone indicates that quartzcement precipitation occurred at similar rates in theFulmar sandstones at both Shearwater and Martha(Figure 22). A single set of model parameters forboth compaction and quartz precipitation kineticsyields consistently good fit for both data sets de-spite the clear differences in their exposure to hy-drocarbon pore fluids. These model parametershave been successfully applied in a predrill predic-tion mode for other locations (Taylor et al., 2005).Themodel results, data, and observations, alongwith

the fact that wet Fulmar sands at Martha are equallyor more porous than gas condensate-bearing sandsat Shearwater, clearly indicate that hydrocarbonpore fluids did not significantly influence quartzcementation rates and reservoir quality.

THERMAL ANOMALIES NEAR SALT:A POROSITY PRESERVATION WINDOW

The results of basin modeling predict that a zoneof suppressed temperatureswill occur beneath thicksalt sequences (Mello et al., 1995). This phenom-enon is caused by the high thermal conductivityof salt (KB ≈ 6.0 W m−1 K−1 at ∼100°C) relativeto shale and sand (KB ≈ 1.5 and 3.5 W m−1 K−1 at∼100°C, respectively), allowing for heat to be morerapidly transmitted away from the underlying strata(the thermal conductivity of salt is highly tempera-ture dependent and decreases with increasing tem-perature, thus the contrast is greatest at shallowdepths of burial). As a consequence, temperatures

Figure 20. Wireline logsthrough the Fulmar sandstonegas reservoir at Shearwater field(United Kingdom central NorthSea, 22/30b) reveal a decreasein porosity with depth. Uppershoreface sands dominate theupper Fulmar, whereas the lowerFulmar is composed of lowershoreface, bioturbated sands.As seen in the resistivity log re-sponse, the current gas-watercontact is found well below thepoint where porosity decreasesfrom approximately 25–30% tovalues of approximately 20%.Open circles represent porosityanalyses of core samples.

Taylor et al. 1117

above large salt bodies are typically elevated com-pared to laterally depth-equivalent strata fartheraway from salt. The properties of the sediments,structural configuration, depth of salt, thickness ofsalt, and the timing of salt emplacement control themagnitude of this effect.

The volume of quartz cement precipitated ina sandstone per unit time is primarily controlledby temperature and the available quartz substratesurface area. The rate at which quartz cement pre-cipitates increases exponentially with temperature,rising by a factor of approximately five between 70and 100°C and another factor of five between 100and 135°C. Suppression of temperature over timecould clearly have a significant impact on the loss ofporosity due to quartz cementation. This can be par-


ticularly important in sandstones that lack significantgrain-coating clay and are therefore highly suscep-tible to quartz cementation at high temperature.

Gulf of Mexico Examples

Wells that penetrate the thick allochthonous saltin the Gulf of Mexico have frequently encounteredsubsalt sedimentary sections that are substantiallycooler than predicted by regional geothermal gradi-ents. For example, at Tahiti field in the deep-waterGulf of Mexico (Green Canyon 640), wells pene-trate approximately 3000 m (∼9800 ft) of alloch-thonous salt prior to encountering Miocene reservoirsands at depths of more than 7000 m (∼23,000 ft)below the sea floor. Subsalt well temperatures aredepressed approximately 30°C relative to the re-gional trend for nonsubsalt wells at depths of 5800–7500m (19,000–24,600 ft) (Figure 23). In contrast,at a well location more than 200 km (124 mi)away (Poseidon; Mississippi Canyon 727), roughly1200 m (3900 ft) of salt section was drilled aboveMiocene-aged sands found at depths of approxi-mately 5200–7500 m (17,000–24,600 ft). In thiscase, subsalt temperatures are consistent with thehigher regional geothermal gradient for the Mis-sissippi Canyon area.

Petrographic analysis of core material fromTahiti wells indicates the presence of minor amountsof quartz cement (1–2%) in clean sands with po-rosities that range between 21 and 24% (Figure 24A)at depths of more than 7000 m (23,000 ft). In starkcontrast, sandstones of equivalent-age and compar-able composition from Poseidon (Figure 24B),where temperatures are more than 40°C hotter atroughly the same depth, have substantially morequartz cement (2–7%) and porosities of only 12–17%. The differences in porosity are mostly attrib-uted to differences in quartz cement volumes, a di-rect result of the contrasting thermal histories.

The timing, thickness, burial depth, and verti-cal separation of salt from the underlying objectivesandstone reservoir may all be important factorsin determining the magnitude of the thermal sup-pression effect on quartz cementation. A thermalmodeling exercise using stratigraphic data andmodelparameters appropriate for the Gulf of Mexico,

Figure 21. Wireline logs through the Fulmar sandstone res-ervoir at the Martha well location (22/30a-1; United Kingdomcentral North Sea). The well encountered highly porous, water-bearing sandstone with no evidence of significant hydrocarbons.Open circles represent porosity analyses of core samples.

deep-water Mississippi Canyon area illustrates thedirection and potential magnitude of change asso-ciated with these factors. The resulting temper-ature histories brought about by simulated varia-

tions in the timing of salt emplacement and theinduced effects on quartz cementation are shownin Figures 25–27. Eleven Gulf of Mexico Miocenesandstone samples, for which petrographic data wereavailable, were used as starting material for Touch-stone simulations (Table 3). Appropriate modelparameters for mechanical properties of the ma-jor framework grains and for quartz precipitationkinetics were taken from previous unpublishedstudies of Gulf of Mexico Miocene sands. Thesewere held constant for all simulation scenarios tocompare only the effects of thermal history on po-rosity evolution. Note in the following discussionthat these results apply to the specific cases pre-sented. Different results are likely where geologicfactors and rock properties depart significantly fromthose assumed here.

• Presence of salt. The impact of the presence orabsence of allochthonous salt is illustrated bycomparing a thermal model derived assuming nosalt in the sedimentary section to another withapproximately 1500 m (4921 ft) of salt. Saltemplacement is modeled to occur from 9.4 to9.2 Ma (Figure 25A). The temperature historiesdiverge at the initiation of salt emplacement andfollow different paths to the present at which

Table 2. Summary of Porosity, Grain Size, and Compositional Data for Fulmar Formation Sandstones from the Shearwater (22/30b)
and Martha (22/30a-1) Wells
Martha
Shearwater
Mean
Standard Deviation N Mean Standard Deviation
Taylor et al. 11

N

Core analysis porosity
30.7 1.7 15 29.2 1 9 Grain size (mm) 0.16 0.02 16 0.14 0.03 24 Intergranular porosity 16.2 3.5 16 10.9 3.7 24 Secondary porosity 5.9 1.7 16 4.2 1.1 24 Total clay 6.9 1.4 16 11.4 3.3 24 Quartz 42.4 4.2 16 43.1 6.1 24 K-feldspar 4.5 1.8 16 4.4 1.4 24 Plagioclase 7.8 2.4 16 5.4 2.7 24 Shale rock fragments 1.9 1.1 16 3.6 2.4 24 Quartz cement 3.7 2.9 16 4.4 1.6 24 Ankerite 0.8 1.3 16 1.1 1 24 Intergranular volume 27.2 2.3 16 27.2 4.3 24 Total cement 9.3 2.4 16 13.2 3.5 24
Figure 22. Touchstone quartz cementation model calibrationresults for Fulmar sandstones from the Shearwater and Marthawells. A single set of quartz precipitation kinetic parameters canbe used to accurately reproduce measured quartz cement vol-umes within a model tolerance of ±3%.

19

point the salt-free model is 23°C hotter. Thetwo temperature paths yield significantly dif-ferent amounts of quartz cement and porosity(Figure 25B, C), with predicted porosity valuedfor the salt-free scenario approximately 5–7%lower porosity than those predicted using the1500-m (4921-ft) salt model.

• Thickness of salt. The potential influence ofoverlying salt thickness is demonstrated by a


comparison of thermal models for stratigraphicsections containing 1500 and 3000 m (4921and 9842 ft) of salt (Figure 26). The emplace-ment of salt occurs over the same time interval(11.7 to 9.1 Ma) but at double the rate for thethicker salt scenario. The results for the 3000-m(9842-ft)-thick salt scenario are roughly 22°Ccooler than those for the 1500-m (4921-ft) saltmodel (Figure 26A). The Touchstone models

Figure 23. Measured temperature versusdepth for two deep-water Gulf of Mexicowells. The Green Canyon (GC) and Mis-sissippi Canyon (MC) regional thermal gra-dients are shown for reference. The blockarrows depict the approximate thicknessesand depth positions of salt encounteredin the two wells.

Figure 24. Equivalent-agedMiocene sands from two subsaltwells in the deep-water Gulf ofMexico differ in the amount ofporosity and quartz cement.(A) Thin-section photomicrographof Tahiti well reservoir sand-stones. These sands containapproximately 1–2% quartz ce-ment. (B) Thin-section photo-micrograph of Miocene sand-stone from the Poseidon well.
Sandstones at Poseidon contain2–7% quartz cement.

predict that given these two thermal histories,doubling the salt thickness will result in about3–5% less quartz cement and greater inter-granular porosity (Figure 26B, C).

• Timing of salt emplacement. The possible ef-fects of the timing of salt emplacement relativeto the reservoir interval are evaluated by con-trasting twomodels in which 1500m (4921 ft)

Figure 25. Burial history and Touchstonesimulations designed to evaluate the po-tential effects of the presence of thick salton porosity loss due to quartz cementa-tion. (A) Temperature versus time for twohypothetical burial history scenarios, withand without the presence of 1500m (4921 ft)of overlying salt. Salt emplacement occursbetween 9.4 and 9.2 Ma. (B) Porosity andquartz cement volumes for clean sandstonessubjected to the thermal history for 1500 m(4921 ft) of salt shown in panel A. (C) Po-rosity and quartz cement volumes forclean sandstones subjected to the thermalhistory for the salt-free scenario shownin panel A.

Taylor et al. 1121

of salt is emplaced. In one case, salt is emplacedfrom 15.6 to 14.8Ma and in the other case from9.4 to 9.2 Ma (Figure 27A). The final tempera-tures are essentially the same in these two mod-els, but the temperature paths as a function of


time differ. In this example, the resulting effecton quartz cement and porosity volumes is rela-tively small (1–2% bulk volume), with early em-placement producing marginally higher porosityvalues (Figure 27B, C).

Figure 26. Burial history and Touchstonesimulations designed to simulate the po-tential effects of the variable salt thicknesson porosity loss due to quartz cementation.(A) Temperature versus time for two hy-pothetical burial history scenarios, one with1500 m (4921 ft) and the other with 3000 m(9842 ft) of salt. Salt emplacement occursbetween 11.7 and 9.1 Ma. (B) Porosity andquartz cement volumes for clean sandstonessubjected to the thermal history shownin panel A for 1500 m (4921 ft) of salt.(C) Porosity and quartz cement volumes forclean sandstones subjected to the ther-mal history shown in panel A for 3000 m(9842 ft) of salt.

Application in Predictive Mode: Gulf of MexicoThe subsalt cooling model was used to predict po-rosity for a prospective deep-water Gulf of Mexicosubsalt well prior to drilling. The Perdido fold-beltarea contains several subsalt prospects and discov-

eries with varying thicknesses of salt cover (Fiduket al., 1999; Trudgill et al., 1999). This extremevariation in salt thickness results in extreme dif-ferences in predicted temperature at a given depthbelow the sea floor. The prospect modeled here

Figure 27. Burial history and Touchstonesimulations designed to evaluate the po-tential effects of the variable timing of saltemplacement on porosity loss due toquartz cementation. (A) Temperature ver-sus time for two hypothetical burial historyscenarios; one in which salt emplacementoccurs between 15.6 and 14.8 Ma and theother where salt emplacement occurs be-tween 9.4 and 9.2 Ma. (B) Porosity andquartz cement volumes for clean sand-stones subjected to the thermal historyshown in panel A in which salt emplace-ment occurs from 9.4 to 9.2 Ma. (C) Porosityand quartz cement volumes for cleansandstones subjected to the thermal historyshown in panel A in which salt emplace-ment occurs from 15.6 to 14.8 Ma.

Taylor et al. 1123

targeted Eocene Wilcox sands as potential res-ervoir intervals beneath approximately 2200 m(7200 ft) of salt. A porosity versus temperature


regression, based on regional well data, had beenpreviously employed as a method to forecast po-rosity for exploration prospects in the area. Thetemperature regressions predicted an average po-rosity of roughly 14 ± 4% for the upper Wilcox ob-jective and about 9 ± 5% for the lower Wilcox ob-jective (Figure 28) at the prospect well location.Alternative predictions were made using a three-dimensional (3-D) basin model (Cauldron) for theprospect and a Touchstone model calibrated withWilcox sands from regional analogs. The Cauldronand Touchstone models predicted mean porosityvalues of approximately 24 ± 2% for the upperWilcox sand and roughly 17 ± 2% for the lowerWilcox sand (Figure 28). The subsequent well pen-etration encountered Wilcox sandstones with po-rosity values consistent with the Touchstone modelpredictions and significantly higher than fore-casted using the simple temperature regressions(Figure 28).

As discussed in a previous section, using present-day measured parameters such as depth or tem-perature to predict porosity in sandstones is prone toerrors in all but the most simple, low-temperature

Table 3. Summary of Textural and Compositional Data for Gulf
of Mexico Miocene Sands Used as Input for Touchstone ModelSimulations Shown in Figures 25, 26, and 27
Mean
StandardDeviation N
Mean grain size (mm)
0.10 0.02 11 Sorting (Trask [P75/P25]) 1.54 0.14 11 Intergranular porosity 19.94 2.34 11 Secondary porosity 1.36 0.54 11 Matrix, pore-filling 0.44 0.79 11 Mono quartz 63.19 2.77 11 Poly quartz 4.59 2.68 11 K-feldspar 2.56 1.22 11 Plagioclase 0.91 0.51 10 Shale/silt RF* 0.70 0.37 8 Chert 1.15 0.89 10 Volcanic RF 0.25 0.22 7 Metamorphic RF 1.02 0.76 10
*RF = rock fragments.

Figure 28. Present-day temperatureversus porosity for Eocene Wilcox Groupsandstones from the Perdido area, Gulf ofMexico. The regional T-porosity trend rep-resents a regression fit to regional data(small filled circles). Touchstone modelscalibrated with regional analogs and cou-pled with 3-D burial history models thatconsider the effects of thick allochthonoussalt on thermal evolution predicted sig-nificantly higher porosity prior to drillingof the well (large circles: bar equals ± 1standard deviation). The well results (solidsquares) are in good agreement with theTouchstone model predictions.

burial scenarios. The success of our approach topredict porosity in Wilcox sandstones at this pros-pect validates both the general methodology ofburial history–based reservoir qualitymodeling andthe subsalt porosity preservation mechanism.

DISCUSSION AND SUMMARY

Assessing reservoir quality risk for sandstones thatare currently, or have in the past been subjectedto extensive diagenetic alteration, remains a majorchallenge for geoscientists in the petroleum indus-try. Current approaches are applied with widelyvariable success, attesting to the difficulty in mak-ing quantitative predictions of complex geologicsystems.

Empirically calibrated kinetic models for quartzcementation (Walderhaug, 1996; Lander and Wal-derhaug, 1999), albitization of plagioclase (Perezand Boles, 2005), smectite illitization (Pytte andReynolds, 1988; Velde and Vasseur, 1992; Huanget al., 1993; Elliott andMatisoff, 1996), and fibrousillite formation (Lander and Bonnell, 2010, thisissue) have been shown to be applicable for sand-stones and mudrocks. Numerical forward model-ing of sandstone compaction and quartz cementa-tion (e.g., Touchstone) linked to thermal and stresshistories derived from rigorous basin modeling rep-resents the present state of the art for quantitativeporosity and permeability prediction. As its usehas grown among petroleum industry sedimentarypetrologists and basinmodelers, the need formoreaccurate ways to constrain key model inputs isevident.

Global applications of quartz cement modelsbased on the premise that the rate of quartz ce-mentation is controlled by the kinetics of precip-itation (Walderhaug, 1994, 1996; Oelkers et al.,1996; Lander and Walderhaug, 1999) strongly sug-gest that the sources of silica are readily availableon the geologic time scales at which significantvolumes of quartz cement form. Potential intra- andextraformational sources of silica in clastic mudrockand sandstone systems are many (McBride, 1989;van de Kamp, 2008), and the sizable majority of

analyzed formation waters are saturated or super-saturated with respect to silica (Land, 1997). Con-sequently, the supposition in many basin modelingprograms that quartz cementation can be linked to asingle source such as stress-induced intergranularpressure solution (i.e., chemical compaction) im-plies systematic covariations between quartz ce-ment, IGV, and effective stresses that are inconsis-tent with data from reservoir sandstones (Figure 5).Reservoir quality potential for many deeply buriedsandstones therefore hinges on issues of surfacearea (e.g., grain size, sorting, composition) and thepresence and efficiency of grain coatings, most fre-quently chlorite. Various sedimentological and geo-chemical conditions that favor the formation ofgrain-coating chlorite have been identified, butaccurate prediction remains elusive in most data-poor exploration settings. Studies of the controlson chlorite formation in sandstones may result inbetter methods to quantitatively predict chloritecoatings prior to drilling.

Rigorous evaluation of available field data andevidence does not support the concept that thepresence of hydrocarbon pore fluids measurablyretards quartz cementation in sandstones. This sug-gests that the underlying hypothesized processis either not operative or extremely rare. Greaterunderstanding of wettability may reveal conditionswhere oil-wet behavior is favored and the effects ofhydrocarbon pore fluids on cementation are po-tentially more substantial. Little is known aboutthe possible effects of hydrocarbon pore fluids oncarbonate cementation in sandstones although fieldexamples have been reported (e.g., de Souza andde Assis Silva, 1998). Given the current state ofknowledge, the proposed hydrocarbon fluid effectdoes not represent a viable model for predictingporosity preservation in sandstone reservoirs.

Although secondary porosity due to framework-grain dissolution (primarily feldspars) is almostubiquitous, it represents a relatively minor propor-tion of total porosity in most cases. Exceptions areknown but not necessarily well understood, accu-rately predicted, or important on a global scale.Porosity enhancement due to dissolution of car-bonate cements and grains is also rare. To date, wehave documented suchdissolution in one casewhere

Taylor et al. 1125

deep fluids were introduced into shallower sandsalong fault zones. Efforts to predict the local occur-rence of porosity enhancement related to deep-basinfluid migration are limited by the quality of deepseismic imaging of faults and the limitations ofexisting geochemical and fluid-flow models.

Closer integration of diagenetic, depositional,and 3-D basin models holds promise for more ac-curate predictions. Regional variations in geother-mal gradients in basins such as the Gulf of Mexico(Nagihara and Smith, 2008) along with differ-ences in sediment composition can drive very dif-ferent diagenetic patterns as evidenced by thedominance of carbonate cement in the offshoreTexas Miocene versus quartz cement in the off-shore Louisiana Miocene. On a smaller scale, theevolution of temperature over time in clastic sedi-ments near allochthonous salt can potentially leadto acceleration and suppression of rates of impor-tant diagenetic reactions depending on location andproximity. The development of 3-D basin modelsthat more realistically simulate salt emplacementthrough time is needed to delineate prospect-scalethermal histories and their effects on diageneticreactions.

The development of fully coupled, diageneticand basin models that integrate processes operat-ing on a broad range of length scales may representthe way forward for reservoir quality predictionin sandstones (Giles, 1997; Tuncay and Ortoleva,2004). Pore-scale mineral precipitation or dissolu-tion reactions can be affected by processes that oc-cur on much smaller scales (Parsons et al., 2005;Lüttge, 2006) or onmuch larger scales (Ayalon andLongstaffe, 1988; Taylor and Land, 1996; Schulz-Rojahn et al., 1998). Under some conditions, thesemay couple to reinforce or cancel each other, po-tentially influencing the development of diagenet-ically induced reservoir quality heterogeneity ofimportance at well, field, or basin scales. To be suc-cessful, future models must move beyond present-day reaction-transport models by incorporating amore quantitative treatment of rock microstrucuregeometries and the effects of mineral surface prop-erties on reactivity (Lasaga andLüttge, 2003, 2004).Although these models will by necessity be mathe-matically based and require the application of su-


percomputers, natural and experimental rock dataderived using established and new petrographic,geochemical, and petrophysical techniques are es-sential for calibration and validation (Ullo, 2008).The ultimate success of such an approach will bejudgedby its ability to predict the reality imposed bycomparison with quantitative rock data.

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