africa03 abstracts

Houston Geological Society and Petroleum Exploration Society of Great Britain Second International Symposium

“Africa: New Plays—New Perspectives” Houston, 3–4 September 2003

1

2000 USGS Assessment of African Petroleum Potential—An Update

R.R. Charpentier, T.R. Klett, and M.E. Brownfield U.S. Geological Survey, MS 939, Box 25046, Denver Federal Center, Denver, Colorado 80225 In 2000, the U.S. Geological Survey (USGS) published an assessment of undiscovered petroleum potential for most of the major non-U.S. geologic provinces of the world. The assessments for Africa will be reexamined in the light of several additional years of exploration.

The USGS World Petroleum Assessment 2000 was conducted over five years and released in

June of 2000. The 76 geologic provinces that accounted for more than 95 percent of the discovered non-U.S. petroleum were assessed, and an additional 26 geologic provinces were assessed because of possible significant future potential or exploratory interest. For Africa, 11 geologic provinces were assessed for undiscovered oil and gas resources. For sub-Saharan Africa, only the Atlantic coastal basins were assessed. Offshore resources were assessed to a water depth of 2000 meters, except for the Niger Delta and West-Central Coastal provinces, which were assessed to a depth of 4000 meters.

In order to have consistency among the hundreds of assessments worldwide in the USGS

World Petroleum Assessment 2000, only fields discovered before 1996 were used in the assessment process. Fields discovered after 1995 were considered as undiscovered for the assessment. The only exception to this rule was that 24 fields found from 1996 to 1998 in deepwater off Angola were considered discovered, but of unknown size at the time of assessment.

More than 20 billion barrels of oil (BBO) and 65 trillion cubic feet of natural gas (TCFG)

were discovered in new fields in Africa since 1995. This includes both areas assessed by the USGS in 2000 and areas not assessed. For both oil and natural gas, more than 80 percent of the newly discovered volumes were offshore.

Within those geologic provinces that were assessed by the USGS, results of additional

exploration were generally consistent with the assessed volumes. In the 2000 assessment, 93 BBO and 330 TCFG were estimated for undiscovered fields. In those provinces assessed, about 15 percent of the estimated oil and 11 percent of the estimated natural gas have been discovered since 1995. The sizes of new discoveries were also consistent with the estimated sizes.

In addition, large volumes of oil and natural gas were found in several provinces that were not

assessed by the USGS in 2000. Discoveries in the Murzuk Basin of Libya are estimated at almost 1 BBO. Resources in the Muglad Basin in Sudan were not assessed in 2000, but about 1 BBO was discovered since mid-1996. Similarly, about 25 TCFG were discovered in the Nile Delta since 1995.

Large volumes of petroleum were also added to reserves in previously discovered fields by

field growth. The volume of oil attributed to fields discovered before 1996 increased by about 30 BBO, an amount roughly 50 percent more than that added to reserves by new field discoveries. The volume of natural gas attributed to fields discovered before 1996 increased by about 150 TCFG, an amount more than twice that added to reserves by new field discoveries.

The comparison of exploration result to the USGS World Petroleum Assessment 2000 shows

good agreement for those geologic provinces that were assessed. The largest discrepancies were in unassessed provinces, thus suggesting areas of focus for future USGS assessments.

R.R. Charpentier, U.S. Geological Survey, Denver, Colorado [email protected]



2

The distribution of syn-rift and transition stage source rocks in time and space on the conjugate central / southern Brazilian and West African

margins.

Peter B. Gibbs, Consultant, Eugene R. Brush & Joseph C. Fiduk, CGG Americas.

Syn-rift and transition stage sediments, which underlie the autochthonous salt level, form important source rocks on both margins of the central South Atlantic. These margins demonstrate a classical four stage (pre-rift, syn-rift, transition and drift) passive continental margin evolution. The pre-salt section is often poorly imaged on seismic data due to distortion by the overlying salt. Therefore, it is important to understand the stratigraphic and structural configuration in good data areas to provide reliable models that can be applied to poor/marginal data areas. Sequential paleogeographical reconstructions allow prediction of the regional distribution of source intervals in time and space. Early syn-rift (late Berriasian to middle Barremian) freshwater shales that were deposited in deep narrow lakes locally form good source rocks. However, they generally suffer from a high clastic content that diminishes TOC concentration and thereby source effectiveness. Late syn-rift (middle to late Barremian) calcareous organic shales and marls were deposited in broad, shallower saline lakes. These deposits occur above a marked internal syn-rift unconformity and form the richest pre-salt source rocks. Organic shales were also deposited under saline conditions during the transition stage but in a basin margin position. These shales form the primary source rocks for basins adjacent to the main Aptian salt basin (e.g. Sergipe, Douala, Potiguar basins). Seismic examples are presented from southern Gabon, Angola and Brazil. Seismic imaging of the pre-salt section in the southern Campos Basin is exceptional and allows clear definition of the distribution of the main source interval. Contact: Peter B. Gibbs – [email protected] Eugene R. Brush – [email protected] Joseph C. Fiduk – [email protected]



3

SURVIVABILITY OF SYN-RIFT HYDROCARBON SOURCES: INSIGHTS FROM MODES OF EXTENSION MAPPED FROM BRAZILIAN AND WEST AFRICAN

MARGIN BASINS

Ricardo Perez Bedregal1, Felix Thadeu Texeira Gonçalves1, 1Universidade Federal de Rio de Janeiro

and Garry D. Karner2,

Lamont-Doherty Earth Observatory

Extension-related subsidence within the Sergipe-Alagoas, Camamu-Almada, and Jequitinhonha basins occurred as a series of discrete events: 1) a Berriasian event (142-137 Ma), 2) a Valanginian event (135-128), 3) a Barremian event (122-119 Ma) that evolved into 4) the climax of rifting in the late Aptian (117-113 Ma) and the regional deposition of evaporites. For events 1 and 2, the form of the early syn-rift subsidence appears to be unrelated to brittle deformation of the crust as indicated by an absence of stratigraphic growth across normal faults and a general eastward (seaward) dip of the stratigraphy. The creation of accommodation space is registered by the regional change in sedimentary facies from fluvial systems to deep-water lacustrine and deltaic sequences. During event 3, minor block rotation and wedge sediment geometries attest to minor syn-rift faulting. However, following minor but regional truncation associated with the development of the pre-Alagoas and Chela unconformities (Brazilian and West African margins, respectively), this fault-controlled subsidence was replaced by regional syn-rift sagging. Into this sag were deposited the evaporites of the Loeme and Ezanga (West Africa) formations and the Ibura, Taipus Mirim and Mariricu (Brazil) formations. On the West African margin, reflection seismic data indicate the existence of an outer Basin Sediment Wedge (also termed the pre-salt wedge and the pre-salt sag basin) developed seaward of the Atlantic hinge zone that is Neocomian to Aptian in age (based on ostracod dating) and is contemporaneous with sag deposits developed inboard of the Atlantic Hinge zone. Despite the fact that the Outer Basin Sediment Wedge is clearly a syn-rift deposit, as defined by its age-range, the pre-salt wedge exhibits none of the diagnostic characteristics of brittle deformation, such as the rotation of crustal blocks and wedge sediment geometries. We will present corroborative data and results of quantitative basin modelling to demonstrate this paradoxical situation. The regional distribution and thickness of the syn-rift and post-rift sediment packages across the Brazilian and West African margins are not consistent with the minor amounts of early Cretaceous brittle deformation observed in seismic sections across the margin. This observation requires that extension was vertically partitioned through the crust and lithospheric mantle. In particular, the subsidence patterns are best explained in terms of an intracrustal detachment, or mid-crustal weak zone, with a ramp-flat-ramp geometry. The ramp components are dipping to the west on the Brazilian margin and to the east on the West African margin - that is, the regional distribution of extension is basically symmetric. Lower crustal and lithospheric mantle plastic thinning beneath the “flat” component of the detachment helped maintain the extended region near sea level as break-up was approached.

(continued)



4 Bedregal Page 2 The extreme thinning of the lower crust ultimately engendered regionally-extensive, shallow water, restricted marine conditions across the entire margin between West Africa and Brazil immediately prior to breakup, the deposition of thick (> 1 km) evaporates, and the development of large post-rift subsidence of both margins. Those evaporites, therefore, are part of the late-stage syn-rift sediment package and the breakup unconformity, if it exists, separates the evaporites from the overlying Albian carbonates. The extension within the crust needs to be balanced by an equal amount of extension within the remainder of the lithosphere, although the lateral distributions of upper crustal, lower crustal and lithospheric mantle extension need not be the same. However, in order to have permanent subsidence in an extensional tectonic setting, the crust must be thinned. Since the pre-salt sag basins are not associated with basin-forming normal faulting, the upper crust immediately above the deforming lower plate cannot be involved in the extension process but the upper crust must be deformed in an adjacent region. Further, the negative exponential form of the post-salt subsidence requires that the lithosphere mantle was involved in the extension process, primarily because it is the cooling of the thinned lithosphere mantle that generates post-rift subsidence. The exact form and location of the counterbalancing upper crustal extension presumably exists in the vicinity of the ocean/continent boundary where the extensional balance through the crust occurs by a combination of thinned and “rafted” crustal blocks that exposes the continental mantle. The deformed upper continental crust adjacent to either the exposed continental mantle or ocean/continent boundary is likely to be highly intruded and overprinted by volcanism associated with rift-induced decompression melting. A direct consequence of ductile extension is the increased input of heat accompanying the rift stage in those areas dominated by syn-rift sag basin development, the distribution and amplitude of the heat pulse being governed by the geometry of the mid-crustal weak zone and the distribution and amplitude of the lower plate extension. Seaward of the West African and Brazilian hinge zones, the maximum heat flow is predicted to be in excess of 200 mW/m2 whereas between the hinge zones, the heat flow is significantly less and ranges between 20-100 mW/m2. With this distribution of late syn-rift heat flow, we explore the survival potential of syn-rift hydrocarbon sources in deep and ultra-deep water regions. Ricardo Perez Bedregal, Basin Modeling and Petroleum Geology, GIMAB/LAMCE/COPPE Universidade Federal de Rio de Janeiro, Rio de Janeiro, CEP 21949-900, RJ, Brazil [email protected]

Garry D. Karner, Lamont-Doherty Earth Observatory, Palisades, NY, 10964, USA [email protected]



5 Syn-rift and transpressional plays along the Equatorial Atlantic margins,

what can plate reconstructions tell us?

Ian Davison and Pedro V.A. Baptista Earthmoves Ltd

This paper examines the potential of the frontier syn-rift and transpressional plays along the Equatorial Atlantic margins from Cote D’Ivoire to Nigeria and the Brazilian margin. Correlation of rift structures and transpressional folds and faults between the Brazil and Africa margins indicates a coherent pattern of transpression, and extension which relates to the original configuration of the Mid-Ocean Ridge (MOR). The original MOR geometry was different from present-day configuration. The oceanic fracture zones are non-parallel between the Chain and St. Paul’s Fracture Zones, and the African half- spreading rate was more rapid (approximately 17 % greater) than the Brazilian half-spreading rate on the MOR segment between the Romanche and the St. Paul’s Fracture Zones. We attempt to define the configuration of the ocean-continental crust boundaries on both margins, which allows us to reconstruct the original mid-Ocean ridge geometry.

The earliest known sediments along the Brazilian Equatorial margin are Barremian age in the Jacuana Graben near Fortaleza. Barremian age syn-rift fill is also present in Benin, with reasonably good lacustrine source rocks present.

The Barremian to Albian rift sequence consists of a lower portion of shales and siltstones in syn-rift grabens followed by transgressive deeper marine siliclastics (100-300m water depth). The upper Albian is separated from the middle Albian by a discordance, which we interpret to mark the break up-unconformity, and the onset of ocean spreading. Hence, the rifting period is believed to be about 15 m yr extending from 125 Ma to 110 Ma.

The syn-rift structures in all the African Basins consist of extensional fault blocks which occur from Ivory Coast to Benin. These blocks average around 5 km in width with the main faults sub-parallel to the coastline and displacements of up to 2 km. Large closures with rotated fault blocks are developed in Cote-D’Ivoire (e.g. Baobab and Espoir Fields), and Pará- Maranhão and Barreirinhas Basins along the western part of the margin. However, the displacements on the syn-rift faults are not usually large enough to generate large back-rotated fault closures in the Tano, Salt Pond, Keta, Mundaú and Aracatí sub-basins in the eastern part of the Equatorial Margin.

Transpressional structures occur in the Keta Basin and Volta Fan, Benin-Togo area and in the Barreirinhas, Piauí-Camocím and Acaraú Sub-basins of Brazil which are associated with the Romanche Fracture Zone. The transpressional deformation on the African margin extends for approximately 200 km farther east than on the Brazilian margin. This may relate to the amount of dextral displacement, which occurred during the transpressional phase, which equates to a period of 10 m yr with a spreading rate of 2 cm a-1 during the late Albian to Cenomanian period.

The Albian reservoirs in the cores of the transpressional folds are poorly developed in Barreirinhas, with better marine sandstone reservoirs developed in Benin (Fifa-1 well). Better quality late Cretaceous (post-Cenomanian) reservoirs may be draped over, or onlap onto these transpressional folds, and these reservoirs have still to be properly tested. Ian Davison, Earthmoves Ltd., Chartley House, 38-42 Upper Park Road, Camberley, Surrey, UK. GU15 2EF [email protected]



6 An unusual play system on the West African margin: the folded belt of the marginal ridge, deep-water Cape Three Points, Ghana

Gabor C. Tari, Jim S. Molnar, and David W. Valasek Vanco Energy Company, One Greenway Plaza,Houston, Texas 77046

The fossil marginal ridge of Cote d'Ivoire and Ghana (CIGMR) is a prominent structural and topographic feature on the transform margin of equatorial West Africa. Due to strong academic activity for a number of years, the marginal ridge along the Romanche Fracture Zone became the unofficial “locus typicus” for a transform margin setting. Based on these academic efforts, the structural evolution of the CIGMR was subdivided into four major periods. These periods include: a) an early rifting and shearing of the southern border along the Romanche Fracture Zone during the Albo-Aptian; b) end of rifting and intracontinental transform faulting during the Late Albian; c) continent to ocean transform faulting from the Cenomanian until the Late Cretaceous(?); d) passive margin evolution since the Late Cretaceous. Reprocessing of the academic seismic data and the acquisition/interpretation of some 3000 kms of new seismic reflection data in the same area resulted in some preliminary observations which contradict the evolutionary scheme summarized above. Most importantly, the new Vanco seismic data clearly images a large landward-verging over-thrust system in the Cape Three Points segment of the CIGMR. The seismic reflectors associated with the individual thrust imbrications within this “nappe” were previously attributed to prograding sediments. However, the geometry of the allochthonous nappe system is identical to those observed at the leading edge of classical folded belts. Other evidence for compressional deformation is provided by a series of inverted syn-rift half grabens and a small, but very well-developed “foreland basin” due to the load of the incoming folded belt. Whereas these structures are undoubtedly the result of transpressional deformation along the transform margin, it is the dominating compressional component which is responsible for the presence of a number of plays identical to those found in folded belts. New exploration plays that Vanco has identified include from south to north: a) subthrust closures and stratigraphic terminations; b) en échelon anticlinal crests; c) closures in inverted syn-rift grabens and d) stratigraphic pinchouts within the foreland basin. The landward verging nappe complex had to form during a period in which continental crust existed on both sides of the transform margin, and, most likely, at a time of major plate reorganization between Africa and South America. Continued work interpreting detailed seismic stratigraphy in conjunction with biostratigraphic well data should help to pin-point when this event occurred and improve the overall understanding of the margin. Gabor Tari, Vanco Energy, Houston, Texas, [email protected]



7

An Emerging Petroleum Province Offshore Benin

Freyd Rad* and Paul Wellman, Kerr-McGee Oil & Gas Corporation

Tectonic evolution of Equatorial Africa was greatly influenced by transtensional forces related to the separation of Africa and South America, and strike-slip movements associated with the Romanche and Chain transform faults. Similar to the rest of the Atlantic margin, the Benin area experienced the general tectonic phases of rift, transition, and drift. The sedimentary section on the stretched continental crust offshore Benin has been interpreted as a generally transgressive depositional succession. Sedimentation began during the rift phase in Early Cretaceous (Neocomian to Aptian) with fluvio-deltaic and lacustrine deposits. As the sea level began to rise due to the breakup of South America from Africa, the depositional environment gradually transformed into shallow and/or restricted marine and eventually to deepwater. Seismic and well evidence suggest that a number of north-south trending fluvial systems were active during Cretaceous time. These drainage systems deposited a thick succession of mainly siliciclastics along the African equatorial margin. Later in the Tertiary, the drainage system feeding the Niger Delta emerged as the dominant sediment transportation force by capturing most of the pre-existing rivers. As a result, the main depocenter for the area shifted to the east and formed the Niger Delta where a thick Upper Tertiary section has been laid down. Sedimentation during the rift phase (pre-continental breakup) was dominated by fluvial and lacustrine deposits, including thick, sand-shale packages that have been reached by a few wells drilled on the present-day shelf. During the transitional phase in the Albian, sedimentation continued in a fluvio-deltaic regime that gradually transformed into a shallow marine environment in later Albian time. A thick sequence of sands, shales and interbedded carbonates were deposited over the entire continental margin that was stretched between Africa and South America. Continued separation of the continents accompanied by a regional transgression led to an increasingly marine and eventually deepwater sedimentation that lasted from the Late Cretaceous to the Present day. Hydrocarbons tested in wells located on the shelf (Seme area) and in recent deepwater wells (Fifa-1 and Hihon-1) as well as hydrocarbon seeps recovered in piston cores suggest that at least two, possibly three, petroleum systems are active in offshore Benin. The main source intervals in the area are believed to be within the pre-Albian (Aptian-Neocomian?), Albian and Ceno-Turonian sections as indicated by available geochemical and basin modeling data. Primary reservoir objectives on the continental slope, occupied by the northern half of Block-4, include:

Albian fluvio-deltaic to shallow marine sandstones Late Cretaceous turbidite sands Oligo-Miocene deepwater sandstones

A comparison of the sedimentary successions offshore Benin with its conjugate margin, the Ceara Basin of offshore Brazil, suggests that Cretaceous sandstones were mainly sourced by the African continental mass from the north-northeast. As a result, most of the sand carried into the newly formed basin between the separating continents was deposited on the African flank proximal to their provenance. Consequently, the Benin continental margin enjoys a favorable balance of sand and shale for generation, migration, and trapping of hydrocarbons. Two exploratory wells drilled by Kerr-McGee recently tested the Albian sands in deepwater offshore Benin (in excess of 2100 meters) and confirmed the Early Cretaceous petroleum system in Block-4. Potential hydrocarbon reserves discovered by these wells, although estimated to be sub-commercial for a deepwater development at this time, encourage further exploration. Furthermore, oil seeps sampled by a piston core east of the Fifa-1 well suggest the presence of a second active source rock of marine Late Cretaceous (Ceno-Turonian?) origin. A combination of proven petroleum systems, copious prospect inventory in Block-4, large source kitchen areas mapped by seismic, and multiple Cretaceous and Tertiary reservoir objectives, call attention to deepwater Benin as an emerging petroleum province in West Africa. Freyd Rad, Kerr-McGee Oil & Gas Corporation, 281-673-6942, [email protected] Paul Wellman, Kerr-McGee Oil & Gas Corporation, 281-673-6894, [email protected]



8

STRATIGRAPHIC TRAP EXPLORATION IN THE GULF OF GUINEA : A CASE STUDY OF GEOLOGICAL AND DHI PROSPECT ANALYSIS IN DEEP AND

SHALLOW ZONES

Duncan Macgregor and Ronaldo Miele Sasol Petroleum Exploration, London

It is expected that as hydrocarbon provinces become more explored, they will increasingly enter a phase of stratigraphic trap exploration. This paper evaluates the increasing proportion of stratigraphic trap discoveries in the Gulf of Guinea. The processes used to reduce risk within prospects of this trap type are considered, as is demonstrated in a series of deepwater blocks along the Equatorial Guinea-Cameroon margin where structural plays are rare. For the purposes of this paper, stratigraphic traps are defined as those requiring not only a top seal, but also a side- and/or bottom seal provided by a facies change. Critical factors for exploration in such trap types are usually trap effectiveness and charge. These can be evaluated with respect to a growing number of positive analogues in the region, including the Okume-Oveng complex in the Rio Muni basin, various stratigraphic discoveries in Cameroon, including the recent Coco Marine discovery, and the Bonga group of fields in Nigeria. In the EG-Cameroon study area, it would seem that large stratigraphic plays concentrate over a series of major sequence boundaries and the degree of detachment of major sand bodies seems to be high, with positive implications for seal risk. Petroleum systems are mapped out over this region and an intra-Tertiary system proposed, with lower charge risks for Tertiary stratigraphic leads. Migration models are also heavily influenced by unconformities, which seem to form routes for lateral migration, while vertical migration models are favoured by overpressuring or by salt or mud tectonics. Direct hydrocarbon indications clearly play an important role in reducing prospect risks and examples of relatively shallow undrilled stratigraphic traps with good Type 3 anomalies are shown. Not all stratigraphically trapped hydrocarbon pools can however be expected to show clear anomalies, particularly deeper ones. A series of clearly high reserves prospects in this group are illustrated, and a discussion initiated as to how these can be efficiently explored. Duncan Macgregor Chief Geologist (West Africa & New Ventures) Sasol Petroleum International 93 Wigmore Street London tel 020 7299 9108 mobile 07786 916 761 [email protected]



9

New Perspectives - New Plays in the Douala Basin of Cameroon R.J. Bray* and S.R.Lawrence, Exploration Consultants Ltd., Henley-on-Thames, England S. E. Angoua Biouele, Société Nationale des Hydrocarbures, Yaounde, Cameroon Drilling in the onshore Douala Basin commenced in the 1950’s encouraged by surface oil seepages and resulted in small oil and gas discoveries in Cretaceous and Tertiary sands. Samples from the Upper Cretaceous from a Logbaba gas field well were used by French workers in the early development of source rock geochemistry in the 1970’s as type section for gas-prone Type III kerogen. These results were used as a text book case-study by Tissot and Welte (1978) to illustrate gas-prone kerogen and since that time the Douala Basin has suffered the reputation of being gas-prone, despite having the largest concentration of surface oil seeps in Africa and several oil discoveries. In December 2002 ConocoPhillips announced an oil discovery in a Lower Tertiary reservoir in well Coco Marine-1, opening-up a new oil play for the offshore Douala Basin. Work carried out in 2001 by ECL in conjunction with SNH on the geochemistry of seepage and reservoired oils from the Douala Basin has distinguished two oil families, interpreted to originate from Cretaceous and Tertiary source rocks respectively. The oils data combined with new source rock geochemistry have allowed recognition of source rocks in the mid to late Cretaceous (Albian-Cenomanian) and in the Tertiary (Paleocene/Eocene or early Miocene). Thermal history has been investigated by AFTA which shows repeated episodes of uplift and erosion in the late Cretaceous and in the mid and late Tertiary. Source maturation history is correspondingly complex, with maturity enhanced by burial prior to the uplift and erosion. The recognition of a mature Tertiary oil-source, in addition to the deeper Cretaceous sources, raises the possibility of a Tertiary-sourced petroleum system in the offshore and puts a new perspective on the prospectivity of the Douala Basin, both in Cameroon and neighboring parts of Equatorial Guinea. Reference: Tissot B.P. and Welte D.H. 1978 Petroleum Formation and Occurrence, Springer-Verlag. e-mail: [email protected], [email protected], [email protected]



10 Recent Exploration Success in the Douala Basin, Offshore Cameroon

Xijin (CJ) Liu* and Ritchie Wayland

ConocoPhillips, Houston, Texas, ConocoPhillips and Petronas Caragali drilled an oil discovery in Permit PH 77, located in the Douala Basin offshore Cameroon, which tested 3000 bopd and 1.8 mmscfgd in December 2002. The Coco Marine 1 well proved a liquid petroleum system and the viability of Lower Tertiary stratigraphic traps as exploration targets. Excellent reservoir quality sandstones were found within the submarine channel complex. The prospect was identified and drilled based on 2D seismic data. The Coco discovery has the potential to completely change the exploration landscape in a presumed “gas-prone” basin. A large 3D seismic survey (2900 km2) has been acquired to assess the discovery and evaluate additional play potential, to address key questions on the turbidite depositional systems interpreted in the permit, and to refine hydrocarbon distribution models in the basin. The proprietary 3D data set is currently being processed and will be interpreted beginning in late 2003. The 3D data will also allow delineation of several other plays identified on the 2D seismic data, including large Oligocene and Cretaceous toe-of-slope turbidite fan complexes. The current inventory of exploration leads and prospects in Permit PH 77 are all stratigraphic traps, but the 3D seismic may define fault-related structural leads in the Lower Tertiary and Cretaceous sections. Given the newly proven oil-rich Tertiary petroleum system and the potential for additional liquid hydrocarbon discoveries in the Cretaceous, the future for exploration in the Douala Basin looks bright. Xijin (CJ) Liu, ConocoPhillips, 6OO North Dairy Ashford, Houston, Texas, 77079 [email protected]



11

Salt tectonics in Gabon - generic model for pre-salt and post-salt structures in West Africa

Dave Quirk, Guy-Bruno Minko, Jean Tsire, Roberto Barragan, Heitor D'Arrigo,

John Boucher, Jon Clemson, Mark Katrosh

Amerada Hess Corporation The structure and stratigraphy in the proven oil fairways of onshore and shallow water Gabon are strongly influenced by salt tectonics. The salt is of Aptian age and occurs in swells, rollers, walls and stocks associated with normal faults in the overburden. Upper Cretaceous strata on opposing flanks of individual salt structures show asymmetric geometries with strata on one side tilted down and thickening towards the dome and strata on the other side tilted up and pinching out towards it, separated by a growth fault which detaches down the flank of the salt structure. Over time, normal faults often switched from side to side leading to complex geometries. The salt structures were most active during periods of extensional growth in the Albian, Turonian, Campanian and late Palaeocene. The late Palaeocene event is associated with a tectonic unconformity which has had major effect on trap integrity. Salt reached surface at this time and flowed into hangingwall depressions on the downtilted side of controlling faults. Many of the faults and the majority of the salt domes stopped moving thereafter. Observations on thickening versus pinch-out, discordance and onlap geometries and discordance versus concordance at the salt-sediment interface can be used to constrain the movement history of the salt and associated faults. The formation of these structures can be explained by a reactive salt model linked to simple extensional shear of the overburden. Salt flowed into low pressure zones in the footwalls of normal faults associated with stress decoupling and fault block rotation. With this model it becomes clear what controls many sub-salt and post-salt structures in West Africa, for example, why raft tectonics did not develop in Gabon but did in Angola. It also helps constrain the interpretation of poorly-imaged salt domes for drilling or PreSDM modelling. Dave Quirk, Amerada Hess, [email protected]



12 Pre-Stack depth migration as an aid to exploration in a mature province - A Case study

from the pre-Salt of southern Gabon.

Kathy Bardwell – Sasol Petroleum International Rufin Moussavou – DGH Gabon

Over the past decade pre-stack depth migration has become an increasingly common tool in the quest to better image geologic structure. With advances in technology and computing power it is now possible to depth migrate larger datasets using more sophisticated algorithms and better subsurface models than ever before. This case study details the key challenges faced during depth migration of a 3D seismic dataset offshore southern Gabon, it shows how these challenges have been met and goes on to discuss the advantages and limitations of the resulting data in the context of exploration in this mature province. The Dussafu Marine permit, formerly known as Phenix Marine, lies within the southern Gabon salt basin in water depths between 0 and 200m. In August 2001 Sasol West Africa Ltd (SPWAL) signed a one year technical evaluation agreement (TEA) for the permit. During the TEA period Premier Oil farmed into the block for 25% interest and in May 2003 the TEA was converted to a PSC with SPWAL operating the block. The block covers an area of 2800 km2 and is partially covered by a 1000 km2 3D seismic survey acquired in 1994. Twenty one wells have been drilled on the block of which two have found significant hydrocarbon in the pre-Salt section. The main pre-Salt reservoir is the Aptian aged Gamba sand which is ubiquitous and good quality in this area. As there is good evidence for an active hydrocarbon system, the main reason for failure of wells is the failure to identify a valid structure. Pre-Salt structures are typically low relief and are overlain by a very complex section of high velocity carbonates and mobile salt. The complex structure of the overlying section and large lateral velocity variations within the carbonates result in severe distortion of the seismic time structure and a poor image of the pre-Salt section. As the key to successful exploration in the block is the identification of valid structures, a clear image of the pre-Salt section and a detailed understanding of the overlying velocity field are essential. Under terms of the TEA, time reprocessing and depth migration of the 3D data was commissioned by SPWAL. All processing was carried out by Geophysical Development Corporation (GDC) in Houston. Reprocessing of the seismic data in the time domain was focused on removal of multiple energy, originating from the high velocity carbonates. GDC used full elastic modelling techniques to optimise parameters for three passes of radon de-multiple and to guide velocity analysis. Integration of interpreted horizons was key to optimising the stacking velocity field. For depth migration, a five layer velocity model was developed down to base Salt. Particular attention was paid to the carbonate section which was divided into two layers on the basis of results from a geological study into the relationship between velocity, stratigraphy and facies. Depth migration was performed using full wave equation technology resulting in superior steep dip imaging particularly on the diapir flanks, adding confidence to the salt model and improved imaging of the base Salt reflector itself. The resulting depth migration shows a significant improvement in pre-Salt imaging over the original time dataset. The structure at base Salt level is significantly different in the time and depth domains and a number of prospects and leads have been identified from the depth data. These vary in size from structures with 10-20m of relief to structures with up to 100m of relief. Pre-stack depth migration, if performed correctly, will give the optimum seismic image. However, the velocity required to image correctly is not the same as the velocity measured at the wells or that required to convert from seismic time to depth. An attempt has been made to quantify the depth uncertainty associated with the pre-stack depth migration and incorporate this into our risk criteria for the identified prospects and leads. One measure of depth uncertainty can be gained by looking at residual depth error in the wells, another can be made by estimating the range of velocities over which the optimum seismic image, determined by flatness of depth gathers, is achieved. Both of these methods indicate a depth uncertainty of approximately 1.5 % of depth at target level (40-50m). In an area such as this, where the key to successful exploration is the identification of low relief structures beneath a complex overburden, depth migration is a very useful exploration tool and can reveal structures which are poorly imaged or not apparent in the time domain. However, it is very important that the depth uncertainty associated with the migrated data is understood, quantified and incorporated into the risk criteria for the identified prospects and leads. Prospects with relief equal to or lower than the depth uncertainty threshold must be considered to have a high trap presence risk compared with those which exceed this limit. Kathy Bardwell – Sasol Petroleum International [email protected]



13

New Exploration Opportunities in Angola

Mateus Brito, Director, Exploration, Sonangol In recent years, Angola has become a prominent global player in deepwater exploration and production. Numerous world-class discoveries have been made, and at present two deepwater fields are in production. As a result of these successes, we expect Angola’s oil production to increase to about 1,200,000 BOPD by the year 2004 from a current of 900,000 BOPD. Several significant events will contribute to an anticipated bright future for Angola exploration. First, we expect that gas will soon become an exploration focus as we progress planning of Angola’s first LNG production. Second, we recognize the importance of rapidly advancing technologies. For example, in the more mature portions of the prolific deepwater trends, we are finding that new processing and acquisition techniques have played a role in finding new reserves. Still, new plays and reservoirs remain to be tested. In the emerging deep and ultra-deepwater, the combination of these new technologies with the testing of new ideas will likely yield additional giant field discoveries. There also exists a renewed interest in other emerging or frontier offshore and onshore opportunities. New concepts for prospects are being generated in the offshore Kwanza, Benguela and Namibe basins, where large exploratory acreage tracts are still available. In the onshore areas of Kwanza, Lower Congo and Cabinda, efforts are underway to nominate leases, identify areas for new seismic acquisition, and initiate secondary recovery techniques from older fields. Sonangol also sees a potentially bright future for Angola’s interior basins. Prominent Neoproterozoic to Paleozoic interior basins remain untested that have many petroleum system elements in common with the Parana basin of Brazil, where considerable oil and gas discoveries have been made. Efforts to evaluate the basins are currently underway with initial Aero-Gravity/Magnetic surveys followed by seismic acquisition and stratigraphic well drilling. Angola is poised for the ever-changing business and commercial climate as we enter new phases of petroleum exploration and production. In addition to continuing to host the world’s large multi-national energy companies, Sonangol anticipates there will be an increase in the number of mid-size companies and even small independents investing in the country’s petroleum sector. Additionally, the role of new private sector, national companies will become increasingly important. Several of these are being given initial support by Sonangol, and will soon likely play a critical role in partnerships with foreign operators. Also, besides the traditional PSA, several novel ideas are on the table to award exploration rights. In summary, the level of current and planned activity suggests a continued promising exploration future for Angola. It will be good and opportune time for independents to invest in the oil sector of the country. Brito Mateus, Director, Exploration, Sonangol [email protected]



14

Three-dimensional geometry and displacement configuration of a fault array from a raft system, Lower Congo Basin, Offshore Angola:

implications for the Neogene turbidite play

David.M.Dutton¹, Dustin.Lister², Bruce.D.Trudgill³, Kapela Pedro4

¹ Imperial College, London, ² Colorado School of Mines, Golden, Colorado ³ WesternGeco, Schlumberger House, Gatwick, London, U.K. 4 Sonangol DPP, Luanda, República de Angola

We investigate fault growth and linkage during development of a rafted terrain in the Lower Congo Basin, offshore Angola. Miocene thin-skinned extension has led to the development of isolated raft blocks separated by a graben filled with syn-deformational strata. Angular unconformities together with thinning and onlapping of intra-raft strata onto salt bodies suggest that thick salt was mobile during thin-skinned extension. 3-D fault array geometries and displacement patterns record the subsequent deformation history of the graben during further thin-skinned extension. The mode of thin-skinned extension has important consequences for the Neogene turbidite hydrocarbon play associated with the rafted province of the Lower Congo Basin. The presence of thick mobile salt will influence pre-salt source rock maturation and the development of pre-salt/post-salt hydrocarbon migration windows. David M. Dutton, Department of Earth Sciences and Engineering, Imperial College, RSM Building, Prince Consort Road, South Kensington, London, SW7 2BP [email protected] ² Department of Geology and Geological Engineering, Colorado School of Mines, Golden, Colorado, USA ³ WesternGeco, Schlumberger House, Gatwick, London, U.K.

4 Sonangol DPP, Rua 1° Congresso do MPLA, N.º 8-16, Caixa Postal 1316, Luanda, República de Angola



15 Structural restoration of minibasins translating down a basement ramp in

the deepwater Kwanza Basin, Angola

Martin P. A. Jackson* and Michael R. Hudec Bureau of Economic Geology, Jackson School of Geosciences, The University of Texas at Austin.

The 25-to-85-km-wide Monocline Province is located on the lower continental slope of the Kwanza Basin. The significance of this province lies in its accurate record of basinward translation of the cover during gravity spreading. The timing and amount of translation strongly constrain estimates of updip extension and downdip shortening in the basin as a whole. While sliding basinward, thin Aptian salt and its overburden were draped as a broad, gentle monocline above several basement ramps (the largest of which is the Atlantic Hinge Zone). Bathymetric paleoscarps formed in the upper hinge of the monocline above the basement ramps. Strata onlapping these paleoscarps were buried and translated progressively seaward down the monocline, as if on a conveyor belt lubricated by salt. The downdip width of the onlap surfaces across the Monocline Province records the magnitude of translation of cover over the basement ramp. Translation since the Miocene ranges along strike from 18 to 28 km. A wide variety of stratal patterns formed during translation. Structural restoration and forward modeling show that the geometry was affected by the sedimentation rate, translation rate, number and geometry of ramps, and position of salt structures. In its simplest form, the onlap surface gradually climbs landward through progressively younger strata until surfacing at the modern scarp. Typically, the pattern is more complex. Periods of faster sedimentation buried the paleoscarp; this temporarily ended onlap and created discrete jumps in the landward climb of the onlap surface. Where two adjoining basement ramps are present, each created its own onlap surface, so that two onlap surfaces were obliquely stacked. Small anticlines were also translated down the monocline on the tectonic “conveyor belt.” The basinward limbs of the anticlines were onlapped, whereas their landward flanks are generally concordant to overlying strata. This onlap asymmetry reflects their former position at the top of the monocline. Diapirs were translated seaward along with the rest of the encasing cover. Their transport was temporarily impeded above basement ramps. There the diapirs were squeezed by continued translation of cover on their landward side. Impedance caused the onlap surface to jump abruptly to younger strata as the onlap surface crossed the diapir. Three types of onlap minibasins were translated seaward. (1) Large, landward-tilted onlap basins formed seaward of the scarp above the monocline limb by translation across the basement ramps. (2) Small dish onlap basins between reactivated diapirs and small anticlines formed by shortening above basement ramps. (3) Basinward-thinning wedge onlap basins formed landward of the monocline. Martin P. A. Jackson, Bureau of Economic Geology, Jackson School of Geosciences, The University of Texas at Austin. [email protected]



16

WEDNESDAY POSTERS: SOUTH ATLANTIC Page # Tectonic plate reconstructions of the Atlantic Oceans Dale Bird, Bird Geophysical, Houston, Texas

17

Atlantic Basin Deep Water Play K A Nibbelink, Devon Energy

18

Sub Sub-salt geologic framework and new plays - Aptian Salt Basin of West Africa Al Danforth, Houston, Texas and Steven G. Henry, Innovative Exploration Services, Houston, Texas

19

Petroleum Geochemistry as an exploration tool applied to the South Atlantic Margin Craig Schiefelbein & Rick Requejo, Geochemical Solutions International, Inc., James Brooks & Bernie Bernard, TDI-Brooks International

20

EQUATORIAL ATLANTIC BASINS

Tectonic and Stratigraphic Evolution and Implications for Hydrocarbon Potential of the Tano Basin, Ghana By Thomas Manu, Anthony Assiamah, James Agbenorto of GNPC, and Nat Smith* of CGG

21

Equatorial Margin Basin Analysis (Brazil and West Africa) using a Combined Geophysical and Geochemical Approach William Dickson, Dickson International Geosciences, Mark Odegard, GETECH, Houston Craig Schiefelbein, Geochemical Solutions International, Inc.

22

GULF OF GUINEA: Nigeria - Equatorial Guinea

Offshore Play Generation using Integrated Geo-spatial Data-sets: Examples from the W. African margin. M. Broadley, M. Oehlers, A. Williams -Nigel Press Associates, UK.

23

A Multi-Disciplinary Approach to Nigerian Data Interpretation Price, Antony D.*; Schwartz, David M; Anderson, Brian A., Fugro-LCT, Houston

24

Reducing Exploration Risk in Africa with Gas Chimney Technology Fred Aminzadeh, and David L. Connolly, dGB-USA, Sugar Land, TX

25

Sequence Stratigraphic Analysis of the Douala Basin Wornardt, Walter W. Jr., MICRO-STRAT INC., Jory Pacht, Seis-Strat Services, Houston, Texas, Marcel Batupe, National Hydrocarbons Corporation, Republic of Cameroon

26

Seismic Data Processing of Large Volumes in West Africa Constantine Tsingas, Ruben Martinez, Maurice Gidlow, Andy Wrench and Steve Pitman, PGS Geophysical, London, UK.

27

APTIAN SALT BASIN: Gabon - Lower Congo - Kwanza Basins Gabon’s Offshore Plays - The Regional-to-Prospect “Keystone” Marianne Parsons * 1, David Cameron 2, Robert Pawlowski 1, David Schwartz 1, John Bain 1, Shawn Mulcahy 1, Antony Price 1, 1 Fugro-LCT Inc., Houston, Texas 2 VAALCO Energy, Inc., Houston, Texas

28

Gas hydrate and free gas reservoir occurrence in West Africa, and their detection in offshore Angola Gordon E. Davison* and George A. McMechan, Center for Lithospheric Studies, The University of Texas at Dallas

29

3-D Seismic expression of salt-related structures in the Espirito Santo Basin, Brazil and its conjugate margin in the lower Congo Basin, Angola, Africa. Eugene R. Brush*, Joseph C. Fiduk, Lynn E. Anderson, CGG, Americasand Peter Gibbs, Consultant.

30

Getting more from your potential field data Offshore Angola & Brazil, a case study. Mark A Davies, Paul Versnel* & Jonathan A. Watson, ARK Geophysics Ltd.

31

Pacassa Reservoir: Integrated Reservoir Modeling of an Albian Carbonate Ramp Margin, Congo Basin, Offshore Angola Alda Agostinho*, Ernesto Taia, Donald Twaddle*†, Ron Martin*, Ricardo Hartanto, Joël Le Calvez* Sonangol E&P, *Schlumberger

32

Angolan Slope tectonics with emphasis on the formation of Frontal Fold and Thrust Belt Marton, L. György 1, Greg Schoenborn 2, Danielle L. Carpenter 3, Thomas E. Cool 3, Benjamin J. Sloan 3, Ana Villella 3 (1) Independent Consultant, Houston, TX, (2) ChevronTexaco, San Ramon, CA, (3) ChevronTexaco, Houston, TX

33

Effects of basement uplift in deep water: Kwanza Basin, Angola Michael R. Hudec, Martin P. A. Jackson , Bureau of Economic Geology, The University of Texas at Austin

34



17 POSTER

Tectonic plate reconstructions of the Atlantic Oceans

Dale Bird, Bird Geophysical, Houston, Texas

In this research, relative motion between tectonic plates in the Atlantic Ocean is determined in relation to the axis of spreading at the Mid-Atlantic Ridge (MAR). Control points, located at the intersections of linear magnetic anomalies and fracture zones, are used to estimate stage poles for reconstructing the Atlantic relative to the MAR. Magnetic anomalies are produced when the earth’s magnetic field changes due to geomagnetic polarity reversals as new oceanic crust is accreted at the spreading center. The anomalies are produced as the Earth’s geomagnetic field changes, and are typically oriented parallel to the spreading axis. Fracture zones are the off-axis extensions of transform faults, which connected segments of the active spreading ridge, and they reflect the relative motion between two plates. Intersections of fracture zones and magnetic anomalies provide control points that record the position of points along the spreading axis through time. Satellite-derived free air gravity anomalies are used to map fracture zones, and the intersections of these with interpreted marine magnetic anomalies are used to estimate stage poles for reconstructing the position of spreading plates relative to the MAR. Reconstructed maps of gravity and topography for the Central and North Atlantic were generated by using the calculated stage poles to rotate mapped data to paleo-geographic positions. Similar work is planned for reconstructing the South Atlantic, which is intended to enhance correlations between Africa and South America and interpretations of the conjugate margins. Present-day North Atlantic and South Atlantic maps will be shown as well as 107 Ma reconstruction of the North Atlantic. Dale Bird, Bird Geophysical, 16903 Clan Macintosh, Houston, Texas 77084 [email protected] http://www.birdgeo.com



18 POSTER

Atlantic Basin Deep Water Play

K A Nibbelink, Devon Energy

Most of the oil discovered in deep water is around the margins of the greater Atlantic Basin, including the Gulf of Mexico, Brazil and West Africa. Four critical factors are common in these prolific hydrocarbon systems; 1) mature Cretaceous to Lower Tertiary source, 2) excellent reservoir sandstone from a major drainage or paleo-drainage, 3) structure produced from salt, shale or inversion and 4) seismic definition of reservoir fluids. Since most of the world’s open oceans have good circulation, anoxic conditions needed for preservation of organic material is rare in deep water. Good source rocks can be formed in protected or embayed areas which allow restriction of circulation, upwelling of nutrient rich waters that produce local anoxic conditions, or in lacustrine environments that have latter subsided into deeper water. The Upper Cretaceous anoxic event is the exception where rich source rocks were deposited over the entire central Atlantic. A major drainage system or paleo-drainage is required to provide enough overburden for maturation of the source and to provide good quality reservoirs. Structure in the deep water play can be provided by salt or shale mobile substrates or inversion related to strike slip reactivation along transform faults. The ideal structures are growing contemporaneous with deposition where ponded reservoir sandstones are later inverted into the highest trapping position. Slow velocity, under compacted deep water sediments may provide significant leverage for seismic definition of reservoirs, fluid types and oil/water contacts defined by flat events and down dip conformance of amplitude and structure. Ken Nibbelink, Devon Energy Corporation, Houston, Texas, [email protected]



19 POSTER

Sub-salt geologic framework and new plays -Aptian Salt Basin of West Africa

Al Danforth, Consultant and Steven G. Henry, Innovative Exploration Services, Houston, Texas Exploration along the West African margin has focused on plays that have been successful. Too often, however, the basics of understanding the petroleum system is forgotten and plays with equally high potential are overlooked. In this paper, the pre-salt structural framework, from Angola to Gabon will be presented, with an emphasis on how this framework has influenced the deposition of pre-salt source rocks, reservoirs and seals. Through the generation of paleographic maps, a new understanding of the pre-salt petroleum system has lead to the identification of new, untested plays. In the late 1990’s Western-Geco acquired a grid of deep and ultra-deepwater 2D lines with a general spacing of 5 to10 kms. This was the first data set that provided adequate coverage for mapping major structural features and also provided local sub-salt imaging that has been used for determining seismic stratigraphic relationships. Paleogeographic maps were generated and a new model for the opening of the South Atlantic developed. These maps cover an area that is approximately 1600 by 400 kms. By making maps, the “one-line” interpretation pitfall was avoided, and features were identified that were consistent over a number of seismic lines. The new ideas in this rifting model consisted of a westward migration of active rifting. This resulted in the development of thermal subsidence basins (Sag Basins) overlying the abandoned rift segments, while active rifting continued to the west. The second new idea developed from the seismic stratigraphic relationships of sediments deposited on what appears to have been a sub-aerial volcanic crust that developed after the break-up, but before the development of true seaward dipping reflectors and subsequent oceanic crust. The structural framework can also be seen to develop through time. By defining rifting as the period of active extension of the brittle crust, then rifting ends when normal faulting ceases. Rifting is followed by thermal subsidence and the deposition of sediments in sag basins. These sediments are seen to onlap rotated syn-rift blocks on the basin flanks, to both the east and west. Understanding the development of the pre-salt structural framework is fundamental to being able to predict where source rocks, reservoir and seals will be deposited. Pre-salt source rocks were deposited in both the syn-rift and sag, with the more widely deposited and richest source rocks being in the sag. Based on seismic stratigraphic interpretations, good source and seals were developed in the late sag, with the potential for marine transgressive sandstone at the end of sag deposition. Based on the paleographic mapping, new plays have been identified. Excellent marine sandstone reservoirs have been drilled and are known to exist directly beneath the overlying salt, which provides an excellent seal. Identifying the pre-salt structural highs, over which these sands have been deposited, is a play that exists in the deepwater and should be tested. Carbonate facies with reservoir potential are also known to exist within the late sag and offer one of a number of additional new pre-salt plays. By understanding the geometry of the sag basin, and the knowledge that it contains rich source rock, new pre and post salt plays should developed on the western flank of these basins. In particular, by associating the known basin geometry of the Cabinda area, a similar setting should be found on the western flank of the sag basins, opening the potential for new Albian discoveries in the deepwater. The assumption that pre-salt exploration objectives seaward of the “Atlantic Hinge” are too deep, is outdated. The West African margin is extensive, with pre-salt objectives providing new plays on the flanks of the Kwanza and Benguela basins. By identifying the structural framework of the pre-salt and understanding the petroleum system, new discoveries will be on the horizon. Al Danforth, Consulting Exploration Geologist, Houston Texas, [email protected] Steven G. Henry, Innovative Exploration Services, Houston Texas, [email protected]



20 POSTER

Petroleum Geochemistry as an exploration tool applied to the South Atlantic Margin

Craig Schiefelbein & Rick Requejo, Geochemical Solutions International, Inc., James Brooks & Bernie Bernard, TDI-Brooks International

Petroleum geochemistry, a fundamental component of regional exploration and production programs, is applied here to better understand and predict the occurrence of crude oil in the marginal basins of Brazil and West Africa. This approach is supplemented by results obtained from other exploration tools such as surface geochemistry and basin modeling. For exploration companies to be successful in these areas, a firm understanding of the operative petroleum systems is necessary to make intelligent choices with regard to projects and lease acquisition. This paper compares geochemical data from representative crude oils, source rocks and piston cores from the marginal basins of Brazil and West Africa and results are used to identify, evaluate and compare the various petroleum systems that have contributed to reserves. This approach is possible since crude oils are the compositional derivatives of their sources. Consequently, oil geochemistry can be used to determine the number of discrete sources in a basin and their respective stratigraphic and areal distribution, source age, lithology, organic input (marine, non-marine, lacustrine), thermal maturity, and depositional environment. In addition, areas with overlapping petroleum systems can be identified in relation to possible oil mixing from two or more sources. Processes active in the basin that act to modify the original composition of the oils can also be assessed. Because oil properties (quality) often determine the economics of exploration on a prospect-by-prospect and/or basin-wide scale, it is imperative to understand and, if possible, predict oil property determinants prior to obtaining acreage or drilling. In addition, results from surface geochemical and basin modeling studies are interpreted within the petroleum system concept established by the oil chemistries and conclusions are supported by seismic data. Surface geochemical exploration studies (piston coring) and remote sensing techniques (SAR) are cost effective means of obtaining information ahead of the drill bit. The high cost of offshore exploration has made the identification of seeps or slicks a well-accepted risk assessment methodology. The advantages of piston coring are that the presence of macro-seepage and/or micro-seepage of oil and gas in near-surface seafloor sediments provides evidence of active oil generation and migration, it allows assessment of most prospective areas, and it provides an integrated seep signal over time. In addition, samples are available to characterize oil properties, maturity and source rock type. Similarly, the application of remote sensing techniques to identify natural oil slicks has historically provided invaluable information to oil explorationists. Foremost, they indicate the presence of generative hydrocarbon source rocks, without which there can be no accumulations. In addition, the spatial coincidence of surface slicks and geologic structure allows for the identification of the loci of natural hydrocarbon seepage and to infer possible migration pathways from the reservoir to the sea floor. Craig Schiefelbein, Geochemical Solutions International, Inc., [email protected]



21 POSTER Tectonic and Stratigraphic Evolution and Implications for Hydrocarbon Potential of the Tano Basin, Ghana By Thomas Manu, Anthony Assiamah, James Agbenorto of GNPC, and Nat Smith* of CGG Located offshore of Ghana and Ivory Coast, the Tano-Ivory Coast Basin is roughly 300 km by 100 km in extent and oriented in an east-west direction. 2-D transects have been extracted from two 1999 3-D seismic surveys on the Ghana side of the Tano-Ivory Coast Basin. These sections extend from near shore to water depths of 2000 meters and have been interpreted to highlight the basin history that includes: 1) Paleozoic and Precambrian pre-rift basement and sediments, 2) Early rifting starting in the Mid-Barremian along the major bounding Lagunes Fault, 3) Open marine conditions evolving by the Late Albian, 4) Rapid basin subsidence beginning in the Upper Cretaceous, and 5) Punctuations caused by several major relative sea level changes including the Oligo/Miocene Unconformity. A wide range of reservoir, source, and trap style possibilities are present in the Tano Basin. Syn-rift Aptian and Albian continental to marginal marine facies are the reservoir intervals in the shallow water North Tano Development Area. In slightly deeper water to the southwest the reservoir for the WT-1X and 2X discoveries are post-rift Upper Cretaceous turbidites. The most significant source rocks in the basin are Albian syn-rift lacustrine shales, which locally are over 4000 meters thick. Upper Cretaceous Turonian marine shales could also be potentially rich source rocks. Another possible source rock in the basin is the Devonian Takoradi shale, which is the source in the adjacent basin for the nearby Salt Pond field. The Takoradi Shale could charge Paleozoic and synrift reservoirs in the near shore portion of the Tano basin. Structural trap styles in the Tano-Ivory Coast basin include rotated fault blocks seen below the break-up unconformity and faulted or ponded channel systems above the unconformity. Producible stratigraphic traps have been encountered in Maastrichtian and Campanian deep-water fans but have not yet been drilled as primary targets. The Tano-Ivory Coast Basin has a hydrocarbon system evidenced by numerous onshore oil seeps, tested flow rates of 7000BOPD and 20MMCFGPD offshore Ghana, and established fields offshore Ivory Coast. The proven hydrocarbon potential of the basin, limited drilling coverage, and the range of untested structural and stratigraphic plays indicates that continued exploration of the Tano Basin is clearly warranted. Contacts: GNPC, Thomas Manu, [email protected] CGG, Nat Smith, [email protected]



22 POSTER

Equatorial Margin Basin Analysis (Brazil and West Africa) using a Combined Geophysical and Geochemical Approach

William Dickson, Dickson International Geosciences Mark Odegard, GETECH, Houston Craig Schiefelbein, Geochemical Solutions International, Inc.

The continental margin basins of Brazil and West Africa share similar tectono-stratigraphic units resulting from their proximity in late Jurassic/early Cretaceous time. The paleogeographic ties between the South American and African plates mean that oil habitats of the marginal basins of both continents can often be correlated. The tectonic evolution and possible mechanistic causes have been discussed elsewhere (Lehner and De Ruiter, 1977; Rabinowitz and La Brecque, 1979; Torquato and Cordani, 1981; Karner and Driscoll, 1997; and references therein). In general, five stages of continental margin basin development can be described (Horn, 1980): pre-rift intracratonic; continental rift; evaporite (the well-known Aptian salt); post-evaporite transgressive; and post-evaporite regressive. Substantial oil production has been established along both sides of the South Atlantic margin between the Walvis Ridge and Guinea Rise of West Africa and the corresponding eight thousand km stretch from the Florianopolis Ridge to the Foz Amazonas of Brazil. The majority of historic production has been generated from lacustrine sediments deposited during Neocomian rifting (Brice, et al., 1980, Mello, et al., 1988a and b; Burwood, 1997; and references therein). Late Cretaceous post-evaporite sediments with liquid hydrocarbon source potential were laid down in shallow marine and fluvial-deltaic environments as spreading continued (Mello, et al., 1988a and b; Teisserence and Villemin, 1990; Sofer, 1993; Burwood, 1997; Katz, et al., 1997; and references therein). These latter sources appear poised to dominate future production. The purpose of this investigation is to analyze the Equatorial Margin basins (EMB) using both geophysical and geochemical data. Geophysical data include seismic reflection profiles, gravity, magnetics and bathymetry, plus extensive stratigraphic literature. Specialized software permits the paleo-reconstruction of arbitrary data sets, enhancing the ability to define the continental - oceanic crust boundary (COB) and crustal types along both margins. This assists defining the controlling structural/tectonic features that influenced basin and source rock development, and reservoir emplacement. Results tentatively identify correlations between sediment pathways and gravity signatures, redefining depo-centres in the EMB. Geochemical data representing basins along both margins include oil chemistries based on an evaluation of about a thousand samples (of which 1/4 are in the EMB) with supplementary data obtained from surface geochemical techniques and basin modeling. Initial correlations reinforce the definition of sub-basins and demonstrate the influence of transforms/zones of weakness that segment margins and separate oil types. Our talk illustrates the interpretation process with examples of clear and unclear correlations and remaining questions. William Dickson, Dickson International Geosciences (DIGs) [email protected]



23 POSTER

Offshore Play Generation using Integrated Geo-spatial Data-sets: Examples from the W. African margin.

M. Broadley, M. Oehlers, A. Williams -Nigel Ppress Associates, UK.

The generation of new plays concepts in offshore West Africa has been achieved by the interpretation and integration of several geo-spatial data-sets covering both the shallow and deep-water areas of the entire South Atlantic. This has enabled the South Atlantic margin to be divided into approximately forty discrete segments. Segment boundaries have been defined largely on the basis of free-air gravity patterns, although in some cases the shapes of coastlines and the limits of drainage basins have also been important. In form, segments are controlled by the interplay of original rift faulting and subsequent volcanism and current and palaeo-sedimentation. Their boundaries are in some cases parallel to fracture zones and in others at right angles to coastlines, but in many cases neither of these simple relationships applies. Post-breakup volcanism has been particularly important in the segmentation of some regions.

Small-scale bathymetric maps show the locations of the seaward edge of the shelf-edge free-air high and of the continent-ocean boundary (COB), as indicated by the region of steepest Bouguer gravity gradient. Segments are further classified by type, the 4 principal types are:

1. Fan delta, where there is an obvious young deltaic wedge associated with a major drainage basin.

2. Parallel, where sediments are transported from a number of drainage basins and build a shelf roughly parallel to the coastline.

3. Fracture-controlled, where oceanic fracture zones converging on the coasts at small angles have controlled sediment distribution in deep water.

4. Intruded, where the margin has been significantly modified by post break-up igneous activity.

Shelf-breaks and COBs are further categorized in terms of gradients. Regions where a COB gives rise to only moderate gradients of Bouguer gravity, and/or where the seafloor seawards of a COB remains at depths of less than 2500 m over significant areas, are identified as having significant potential for deep water discoveries. Bathymetric gradients in the upper and lower continental slopes provide guides to the potential of the slopes to retain sediment. Shallow slopes not only have significant potential for retaining sediment close to the shelf-break but also are often indicators of thick sediment accumulations further offshore.

The integration of multi-temporal radar imagery to map repeating oil-seeps on the sea-surface then allows further high grading of the margin. The clustering of the oil seeps in the shallow and deep-water regions where significant sediment thickness has been interpreted (as outlined by the segmentation method detailed above) has led to the identification of a number of prospective new play fairways along the West Africa margin.

Mark Broadley, [email protected]



24

POSTER A Multi-Disciplinary Approach to Nigerian Data Interpretation

Price, Antony D.*; Schwartz, David M; Anderson, Brian A. Fugro-LCT, Houston

Offshore Nigeria has been explored extensively, with seismic surveys and drilling moving into ever deepening waters. Gravity and magnetic data have also been collected on most of these surveys so that an extensive database has been accumulated over a number of years. Compilation of the individual surveys into a unified network provides a resource that can be “mined” for specific prospects, or for use in regional studies. Such a compilation is now available. An integrated interpretive geophysical approach allows these shipborne gravity and magnetic data to be used to augment seismic imaging and to eliminate or reduce ambiguities that arise from using one method alone. Global gravity maps derived from satellite altimetry are used to understand large-scale structures that are related to crustal tectonic features that can be compared across the Atlantic to corresponding petroleum systems on the conjugate South American margin. Large-scale tectonic structures from these regional studies are also used to aid definition of the geologic fabric of the Niger Delta. Shipborne gravity and magnetic data have been used in conjunction with seismic data to model structural and stratigraphic elements in and around the delta for a higher order understanding of the subsurface. Our work focuses on determining if it is possible to discern the typical targets in the deepwater: anticlines, thrusts and stratigraphic traps that populate the fan system, which are normally difficult environments for potential field methods. This study utilizes seismic data in conjunction with potential field data to enhance the imagery of these target structures in the deepwater areas, with models constructed along the seismic lines to fully exploit the integrated approach. Acknowledgements: Thanks to: Fugro-LCT, Inc. and Mabon, Ltd. for permission to show the merged gravity and magnetic data, Marathon Oil and Gibson Consulting for permission to show their Satellite Gravity Atlas of Rifted Margins of the World. Price, Antony D., (Fugro-LCT, Houston), [email protected]



25 POSTER

Reducing Exploration Risk in Africa with Gas Chimney Technology

Fred Aminzadeh, and David L. Connolly

dGB-USA, Sugar Land, TX

Gas chimneys have been proven to be a very effective exploration tool. Many basins in Western and Southern parts of Africa contain some of the most prolific gas chimney occurrence. Several case histories from those regions will be used to explain applications of this technology. In general, gas chimney methodology focuses on highlighting anomalous and chaotic events on the seismic data and establishing a link between chimney characteristics (occurrence, type and extent) and different geological features. Seismically derived gas chimneys can be used to determine oil and gas migration paths, seal integrity and hydrocarbon phase. The emphasis here will be on how this methodology has been applied to different exploration targets in Africa and what was learned. Specifically, we will use examples from Nigeria and South Africa to show the benefits of gas chimney processing and interpretation.

Fred Aminzadeh, dGB-USA, One Sugar Creek Center Blvd., Suite 935, Sugar Land, TX, 77478, [email protected]



26 POSTER

Sequence Stratigraphic Analysis of the Douala Basin

WORNARDT, WALTER W. JR., MICRO-STRAT INC., JORY PACHT, Seis-Strat Services, Houston, Texas, MARCEL BATUPE, National Hydrocarbons Corporation, Republic of Cameroon

The Douala Basin is a divergent basin along the West African Coast, which developed by rifting between Africa and South America during break-up of Gondwanaland. This rifting resulted in formation of a break-up unconformity near the beginning of Albian time. Biostratigraphic analysis of the Kribi R-1, Kribi N-1 and Campo R-1 wells indicates that the breakup unconformity developed at approximately 107.5 million years ago. Although the break-up unconformity developed by tectonic processes, erosion along it was increased by sea-level fall. Wells, which penetrate this unconformity, exhibit thick Sequences of nonmarine sands. Seismic interpretation was mostly in Upper Cretaceous through Pliocene strata. Upper Cretaceous strata are relatively thick in the central and northern portion of the Basin and thin near structural highs in the vicinity of the Kribi R-1, Kribi N-1, and Kribi B-1 wells and the Campo R-1 and D-1 wells. Seismic data indicates that strata thicken to the north. The Upper Cretaceous Sequences identified are the 98.0 Ma, 94.0 Ma, 90.0 Ma, 80.0 Ma, 77.5 Ma, 75.0 Ma, 71.0 Ma and 68.0 Ma Boundaries. Deposition occurred in outer neritic water depths over much of the basin including near the Kribi R-1, and the Campo R-1 wells. The onshore Kwa-Kwa and offshore Yassoukou Marine are slope deposition. This indicates that the basin extended for some distance into onshore Cameroon along an embayment separated from offshore Niger Delta by the Cameroon Volcanic Line. WORNARDT, WALTER W. JR., MICRO-STRAT INC, Houston, Texas, [email protected]



27 POSTER

Seismic Data Processing of Large Volumes in West Africa.

Constantine Tsingas, Ruben Martinez, Maurice Gidlow, Andy Wrench and Steve Pitman, PGS Geophysical, London, UK.

Interpretive full prestack processing of Large Volumes (> 2000 sqkm) in an acceptable turn

around time still remains a challenge. In order to make cost effective decisions, the processing

team should have access to an integrated processing system which combines high end, multi-

volume visualization technology with robust and high precision software.

During this presentation we are going to depict via real data examples from West Africa, a

variety of seismic data processing technologies which incorporate anisotropic parameters and

aim to correct the kinematics and dynamics of the seismic wave propagation in isotropic and

anisotropic media. Time imaging algorithms operating in the prestack domain will show the

effect of incorporating not only the NMO velocity for horizontal reflector (V(0)NMO) but also

the anellipticity coefficient η. Depth imaging algorithms, however, will depict that the above

two parameters are not sufficient to properly position the structures at the correct spatial and

depth locations. In this paper, we will demonstrate that for a proper prestack depth migration

methodology, one needs to incorporate Thomsen’s parameters ε and δ in addition to Vo in

order to obtain the correct travel times required during an anisotropic PSDM procedure.

In addition, the high correlation between processing anisotropic parameters and lithological

sand-shale type zonation will be effectively demonstrated. Constantine Tsingas,, PGS Data Processing, London [email protected]



28 POSTER

Gabon’s Offshore Plays - The Regional-to-Prospect “Keystone”

Marianne Parsons * 1, David Cameron 2, Robert Pawlowski 1, David Schwartz 1, John Bain 1, Shawn Mulcahy 1, Antony Price 1

1 Fugro-LCT Inc., Houston, Texas

2 VAALCO Energy, Inc., Houston, Texas

A regional-to-prospect scale exploration approach can provide valuable insight into Gabon’s offshore oil and gas opportunities. Geologic information, non-exclusive geophysical data, and proprietary work on a producing prospect demonstrate the inherent richness of the regional-to-prospect information spectrum. A similar process has proven fruitful in recent large Gulf of Mexico discoveries (e.g., Thunder Horse). An analogous outcome is anticipated for offshore Gabon’s salt provinces. Since Gabon’s offshore discoveries generally involve pre-salt and/or post-salt structures, prospect-level seismic imaging alone can be challenging. With regard to the regional-to-prospect exploration concept, principal components of the process are presented en echelon. Firstly, regional studies based on satellite data are reviewed. One regional study describes the relationship between South America and Africa via a series of filtered gravity anomaly maps. The other regional study focuses more closely on offshore Gabon’s tectonic framework. Continental/oceanic boundaries are discussed, as are sediment fairways and regional depocenters. Secondly, the analysis proceeds with examination of a regional airborne magnetic survey data set, something both figuratively and literally closer to the petroleum reservoir than the satellite data. Interpretation of filtered magnetic anomaly maps for basement trends, as well as magnetic basement depth estimations, provide information on what is typically a very difficult geologic horizon to image beneath salt. Third and lastly, a prospect-level example involving a process for better imaging salt wall flanks is presented. Here, high-resolution marine gravity data are modeled to assist with the 3-D seismic processing iteration/workflow – this for improved definition of salt wall geometry. Marianne Parsons, Fugro-LCT Inc., 6100 Hillcroft, 5th Floor, Houston, Texas 77081, USA, [email protected] David Cameron, VAALCO Energy, Inc., 4600 Post Oak Place, Suite 309, Houston, Texas 77027, USA



29 POSTER

Gas hydrate and free gas reservoir occurrence in West Africa, and their detection in offshore Angola

Gordon E. Davison* and George A. McMechan, Center for Lithospheric Studies, The University of Texas at Dallas Gas hydrates are a form of ice clathrates that trap molecules of natural gas, primarily methane. Gas hydrates form in deep-sea sediments under certain conditions of temperature and pressure. Where they do form, they often reduce the porosity and permeability of the sediments, forming seals to trap free gas underneath the base of the gas hydrate stability zone. This physical boundary between the gas hydrates and the free gas exhibits itself on a seismic section as a bottom-simulating reflection (BSR). BSR occurrences are well documented in offshore West Africa, especially offshore Nigeria and Angola. Gas hydrates represent a huge potential energy resource, as each cubic meter of gas hydrate can release 164m3 of natural gas upon dissociation. The free-gas reservoirs underneath the BSRs are a viable secondary objective. The problem lies in the fact that both the gas hydrates and free gas beneath them are hazards to deep-sea drilling, which is another reason why these occurrences are still being studied rather than exploited. Drilling through gas hydrate-bearing sediments can result in blowouts to wells and platforms, casing failures, etc., and exploration companies tend to avoid drilling these zones. Deducing the concentration of gas hydrates in a sedimentary section is important not only for exploitation of the methane within, but also for drilling safety. In areas where BSRs mark the base of the gas hydrate stability zone, this reflection is only seen because there is free gas trapped beneath. If there is no free gas under the gas hydrates, the BSR will not be present to indicate the presence of the gas hydrates; other parameters, such as seismic inversion and velocity analysis are employed to detect the presence of the gas hydrates. We propose to look at the extent and concentration of gas hydrates in a 3D seismic data set from offshore Angola. In the first stage of our research, we used reflectivity modeling to check to seismic response at the physical and/or lithological boundaries of interest at two locations. The first (“control”) location we were fairly certain did not have any gas hydrates; the second (“experiment”) location we were fairly certain contained gas hydrates and free gas below due to the presence of a BSR underlain by a thick and very reflective zone. By modeling the two locations, we ascertained that the control site did not have gas hydrates based on the final model velocity profile. The experiment site had a very different model velocity profile, indicating the presence of free gas trapped beneath the gas hydrate zone. The velocity data will be used in the next step, impedance inversion, as no well log data are available in the area this shallow in the section. The deduced velocity profiles are compared to Hamilton's (1980) data to validate the results. Gordon E. Davison, Center for Lithospheric Studies, The University of Texas at Dallas [email protected]



30 POSTER 3-D Seismic expression of salt-related structures in the Espirito Santo Basin, Brazil and

its conjugate margin in the lower Congo Basin, Angola, Africa.

Eugene R. Brush*, Joseph C. Fiduk, Lynn E. Anderson, CGG, Americas and Peter Gibbs, Consultant.

3-D pre-stack time migrated seismic data were used to examine salt-related structures in the Espirito Santo Basin, Brazil and the lower Congo Basin, Africa. The Espirito Santo 3-D covers approximately 11,000 square kilometers and the lower Congo Basin 3-D covers approximately 4,380 square kilometers (Angola Block 33). Comparing the conjugate Espirito Santo and lower Congo basins suggests that the central South Atlantic, containing these two basins, evolved as a large roughly symmetrical basin containing a central/axial basement high. We interpret that the axial high was associated with the eventual line of opening. The now ruptured axial high forms outer basement highs in the deep water close to the continent-ocean boundary of both basins. These basement highs act as a possible trigger mechanism for the formation of linear compressional salt fronts identified on the two 3-D data sets. Only a small amount of the Aptian age salt remains at its original autochthonous level in both the Espirito Santo and lower Congo Basins. Cretaceous to Early Tertiary minibasins evacuated salt into adjacent stocks and salt walls leaving numerous turtle structures and peripheral sinks grounded above the primary weld. Most of the salt now resides in diapiric stocks or laterally extruded salt tongues, many or most of which are detached from the original source layer. There are some contractional structures in the shallow section of both conjugate margins. These consist of thrust faulting in front of allochthonous salt, thrusting of section up the back of shallow salt, and the lifting of section above it’s regional level. All of these features could be produced by down slope gravity gliding. Contacts: Eugene R. Brush [email protected] Joseph C. Fiduk [email protected] Lynn E. Anderson [email protected] Peter Gibbs [email protected]



31 POSTER Getting more from your potential field data Offshore Angola & Brazil, a case study.

Mark A Davies, Paul Versnel* & Jonathan A. Watson ARK Geophysics Ltd.

Frontier passive margin exploration has benefited from large-scale remotely sensed data compilations and their derivative products. Many of these results have remained qualitative with little regard to forging a link to hydrocarbon systems. This presentation will show the results of a logical but quantitative approach to extract a basement horizon from potential field and seismic data. This paper will not only focus on traditional methods such as structural mapping and depth to basement estimates, but by using sophisticated 3D modelling techniques, we will show how it is possible to back-strip individual layers to isolate the gravity signature from petroliferous syn-rift source rocks. Establishing areas of syn-rift sequence beneath post–rift salt accumulation can be problematic across vast areas of Brazil and Angola. Often, when interpreting seismic data, interpreters can easily pick horizons down to the top and base salt. However, it is difficult to accurately interpret deeper structures beneath these horizons. Having applied ‘back-stripping’ techniques to isolate the gravity signature of the synrift deposits, 3D gravity inversion techniques are then used to model the position, shape and volume of said deposits. Maps may then be generated highlighting areas of syn-rift deposits in relation to other more traditional potential field interpretation, such as salt windows and migration pathways. The resulting regional basement surface provides a bird’s eye view of the rift architecture therefore determining the location of the early rift sediments. Paul Versnel, ARK Geophysics Limited, United Kingdom, [email protected]



32 POSTER

Pacassa Reservoir: Integrated Reservoir Modeling of an Albian Carbonate Ramp Margin, Congo Basin, Offshore Angola

Alda Agostinho, Ernesto Taia, Donald Twaddle*†, Ron Martin*, Ricardo Hartanto, Joël Le Calvez*

Sonangol E&P, *Schlumberger

†Present address: Petroleum Development Oman

An integrated study in the Albian carbonate system of the Congo Basin offshore Angola led to the drilling of a number of successful wells over a two-year period. Within the study area, offshore seismic data show gravitationally-driven extension and downdip lateral migration of several approximately 40-m-thick Albian Pacassa dolomite blocks. The rafted blocks belong to the widespread carbonate ramp environment that developed over the thick Early Aptian evaporitic layer associated with the breakup of Pangaea. Understanding the carbonate facies within four of the largest rafted blocks in the study area was critical to a successful drilling program.

Integration of core data and petrophysical results with 3-D seismic data indicates that variations within these dolomitic reservoirs can be modeled using log and seismic attributes. The dissolution porosity developed in the studied dolomite reservoirs is found in oolitic shoals oriented sub-parallel to palaeo-coastline. Seismic amplitude variations and characters of the seismic, as supported by eight wells drilled in the study area, are seen to be predominantly a function of porosity distribution, which is in turn a function of facies. Fracture distribution is also related to facies and structural flexing of the rafted blocks.

Lateral distribution of potential reserves was assessed using a structural time-model of the Pacassa horizon and a variety of seismic attributes that were determined over the gross Pacassa interval. Four attributes consisting of amplitude, frequency, phase, and reflection strength were combined to create a seismic facies map. Porosity from well control was used to “train” the seismic facies map using the Fisher Discriminate method to create a porosity (a Pacassa facies) map. The porosity map combined with a depth-structure map was used during the two-year period to select locations. As well control increased through drilling, the porosity map was updated. Patterns observed on a Fisher-derived porosity map and on a permeability map appear to be related to the expected facies distribution from regional mapping.

The static layered-model incorporating porosity distribution, structures, and fault patterns was constantly updated to increase the accuracy of the dynamic simulation to forecast pre and post drill reserves on four of the rafted blocks. Contacts: Ron Martin, Joel Le Calvez, Schlumberger DCS, College Station [email protected],



33 POSTER

Angolan Slope tectonics with emphasis on the formation of Frontal Fold and Thrust Belt

Marton, L. György 1, Greg Schoenborn2, Danielle L. Carpenter3

Thomas E. Cool3, Benjamin J. Sloan3, Ana Villella3

(1) Independent Consultant, Houston, TX (2) ChevronTexaco, San Ramon, CA (3) ChevronTexaco, Houston, TX

In the Angolan segment of the westward dipping African passive margin strikingly different tectonic style is observed in the syn-rift to early post-rift (Jurassic to Barremian) than in the Albian to Recent post-salt section. While below the salt basement-involved rift tectonics dominate, above the Aptian salt layer (originally up-to 1.5 km thick), gravity-driven thin-skinned deformation resulted in a predictable succession of salt-cored features. These range from extensional structures up-dip to well defined compressional structures down-dip. The Aptian salt layer (decoupling zone), has been severely modified and re-distributed during the evolution of the slope system, including regional-scale up-dip evacuation and down-dip accumulation of salt. Inspection of regional dip transects across the Lower Congo and Kwanza Basins offshore Angola reveals four major salt tectonic domains. The four domains are: eastern raft, central diapir/turtle, canopy and massive salt / folded belt domain at the leading edge to the west. The amount of original salt generally increases from north to south, while the amount of Tertiary overburden broadly decreases, resulting in variations in the appearance of these basic domains. In front of the Congo fan, up to 4000 m of Oligo-Miocene sediment were deposited above southward increasing amount of salt. During the Oligo-Miocene salt-withdrawal synclines became local depocenters, while the salt accumulated in large diapirs and salt cushions. Major loading triggered updip extension and downdip shortening in the Late Miocene, when a tectonic episode with several kilometers of displacement started that is still active. Most of the compression is concentrated in the salt with diapirs being squeezed and salt canopies flowing out. The frontal compressional belt can be divided into a northern folded belt and a southern fold and thrust belt. The southern zone experienced more compressional strain. It appears that the mainly Miocene age frontal structures developed above an up-to 30 km wide Cretaceous deep salt canopy. To the north, inflation of the deep canopy and continued compression resulted in long wavelength large amplitude folds, involving the Oligo-Miocene and Cretaceous section. Further south, where the Oligo-Miocene section is thinner, shorter wave-length folds often developed into fault propagation folds and thrusts. Eastward from the frontal fold and thrust belt, a Late Miocene? to Recent salt canopy belt is observed, where individual canopies often coalesce. It is speculated that the shallow canopy belt developed above the continent-ocean boundary zone, where abrupt elevation changes may have localized the deep-seated salt feeder systems, necessary for the canopy development. György L. Marton, Independent Consultant, Houston, TX , [email protected]



34 POSTER

Effects of basement uplift in deep water: Kwanza Basin, Angola

Michael R. Hudec, Martin P. A. Jackson Bureau of Economic Geology, Jackson School of Geosciences, The University of Texas at Austin,

The Thickened Salt Plateau and Angola Salt Nappe in the deepwater Kwanza Basin

together form one of the largest salt massifs in the world, measuring roughly 400 × 75 km in area. In most places, the autochthonous salt is 2–4 km thick beneath the sediments that blanket the salt plateau. The plateau formed during the Campanian (~75 Ma), as recorded by a change to condensed sedimentation in the uplifted suprasalt section.

Significantly, the top of salt is generally at least 1 km above the equivalent stratigraphic level on the basement highs that flank the plateau. That is, salt is almost everywhere above its regional in the deepwater Kwanza Basin. How can this be? Normally salt will rise above its regional only if it is displaced by an equivalent volume of sediments that sink below regional. However, on our regional section the area of salt above regional exceeds the area of sediment below regional by a ratio of more than 13:1. This observation holds true for all eight of our regional seismic profiles, and it appears to be characteristic of the entire Thickened Salt Plateau.

The only plausible explanation for this widespread uplift of salt and overburden is basement uplift beneath the plateau. Accordingly, we propose ~1 km of uplift beneath the salt plateau, starting in Campanian time. Uplift may have been a byproduct of the Santonian plate reorganization that reactivated basement structures in the onshore Kwanza Basin, or it could be related to the Late Cretaceous magmatism both onshore and offshore.

Uplift of the Thickened Salt Plateau has a major effect on the salt tectonics. Elevation of the overburden relative to the adjacent abyssal plain created a 400-km-long bathymetric escarpment at the seaward end of the salt system. Salt then broke through this slumping and eroding escarpment to form the extrusive Angola Salt Nappe. Advance of the nappe since the Late Cretaceous has carried sediments more that 20 km across the abyssal plain, making it by far the largest contractional structure in the Kwanza and Benguela basins.

Michael R. Hudec, Bureau of Economic Geology, Jackson School of Geosciences, The University of Texas at Austin, Austin, TX, [email protected]



35

Analysis of the Lacustrine Basin Petroleum System in South Angola

Inkollu, Murthy*, Eurico Setas Pires, Carlos Figueiredo and Mateus Brito Direction of Exploration, SONANGOL, Luanda, Angola

The regional rift basin system of the Angolan margin indicates that the southern portion is characteristic of upper Plate features. Deep rift basins are recognized at the accommodation zones. The region is under explored. However, the few exploration wells present indicate a prevailing lacustrine hydrocarbon system. Within these lacustrine basins, mature source rocks with generative hydrocarbons are identified. Until now, no exploration effort has targeted the lacustrine section on the margin. A deep rift basin located at the basement hinge zone in a rift accommodation zone is interpreted. The Top Basement, Top Neocomian, Top Barremian levels show a rift basin configuration. The basin is bounded by major listric faults and also has characteristic intra-basinal horsts. Thick source development in the basin and reservoir presence around the basinal horsts is inferred from analogue basins. A key seismic 2D line in the basin was used for Temis 2D basin modeling with a focus on hydrocarbon generation and migration. The modeling yielded results for compaction, thermal sensitivities, thermal maturation (expressed in vitrinite reflectance-equivalent units), liquid saturation, total generated hydrocarbons, expelled hydrocarbons and hydrocarbon flow. From this analysis, we propose that the middle Barremian source rock interval has significant generative potential with a peak hydrocarbon generation, expulsion & true flow that occurred from about 40 MA to Present. A profound fluid flow is identified in the Barremian. Extrapolation of the results to a basin scale suggests that the focus for hydrocarbons would be pre-salt traps around basement horsts and post-salt traps that overlay the basement highs. This scenario is consistent with the recognized pre-salt, lacustrine petroleum systems of the Cabinda and Lower Congo Basins. Murthy Inkollu, Direction of Exploration, SONANGOL, Luanda, Angola [email protected]



36

THE PROSPECTIVITY OF THE UNEXPLORED DEEP-WATER BASINS OF SOUTHERN ANGOLA

Michael J. Cope, Douglas G. Evans and John A. English

Reservoir Services, WesternGeco, United Kingdom The deep and ultra-deep basins of southern Angola (Kwanza, Benguela and Namibe) are poorly explored with only eight wells drilled in some 150,000 km2 of potentially prospective continental shelf. Industry perspectives on these areas are strongly influenced by sometimes erroneous comparisons with the prolific Lower Congo Basin. The basins themselves, however, offer ample geological and geophysical evidence to highlight their own intrinsic prospectivity. The Ultra-Deep Kwanza Basin is a strongly salt-influenced basin prospective for Tertiary and Cretaceous reservoirs. In spite of the lack of success in the relatively few adjacent deep water wells, the presence of a working petroleum system in this area cannot be discounted and many very large salt supported anticlines, a structural style not yet tested, remain undrilled. The application of AVO techniques to some of the identified structures may help reduce the risk on likely hydrocarbon charge. In the Benguela Basin the Semba-1 oil discovery established the existence of an effective petroleum system. The well targeted a salt-withdrawal anticline structure and is believed to have produced from both Tertiary and Cretaceous reservoirs. Similar prospective structures can be seen on seismic data on unlicensed blocks within the basin. Available 3D seismic data also help identify previously unrecognized Tertiary channel systems. The Namibe Basin is characterized by an absence of salt, but offers a wide variety of structural and stratigraphic trapping styles. Cretaceous syn-rift plays are predominantly structural, whereas plays in the Cretaceous and Tertiary post-rift sequence are predominantly stratigraphic. The basin is entirely un-drilled, but oil seeps are recorded at the basin margins onshore. Notwithstanding the water depths and geological risks of the prospective structures identified in these unexplored areas, a strong case for exploration can be made on the basis of favorable project economics. Some examples of positive NPV and EMV outcomes for a range of reserve and risk combinations will be illustrated. Michael J. Cope, Reservoir Services , WesternGeco, Schlumberger House Buckingham Gate, Gatwick RH6 0NZ, United Kingdom [email protected]



37 A new deep water 2D survey reveals new prospects for oil and gas off South

Africa’s west coast

D van der Spuy, N A Jikelo, Petroleum Agency SA

T Ziegler, PGS PGS has recently acquired a regional 3660 km non-exclusive 2D seismic survey over the deep water Orange Basin off the west coast of South Africa, split into two distinct programmes; an area in the north covered by 1408 line km, and a larger programme in the south that consists of 2250 line km. Both the syn-rift and post-rift successions are revealed to consist of a surprisingly thick sedimentary sequence that offers a variety of viable exploration objectives. The survey confirms the existence of a spectacular complex of growth fault and toe thrust structures developed in the northern part of the area. In addition, numerous seismic amplitude anomalies throughout the area highlight the presence of turbidite deposited drape sands and basin floor fans that may form traps within the Cretaceous and Tertiary sediments and enhance the hydrocarbon prospectivity. Traps imaged on the new data include structural, stratigraphic and combination types. Possible structural traps occur within the large fault blocks of the syn-rift succession. In the shallower water areas of the survey, structural traps can be seen where shelf sediments have collapsed against fault closures. The toe-thrust province in the north also provides several opportunities for the formation of structural traps. A large number of stratigraphic / combination traps, in the form of high amplitude channel turbidites and basin floor fans, have also been identified throughout the survey in both the Cretaceous and Tertiary. There are a number of known petroleum systems operating in this basin, and thee is good prospectivity for both oil and gas over a range of water depths and at various stratigraphic levels. The deep water west coast will be open for licence applications in August this year. D. van der Spuy, Petroleum Agency SA, [email protected]



38

Progressive Seismic Data Mining for Reservoir Characterization

Strecker1, U., Berge2, T., Smith1, M. Taylor1, G.

(1) Rock Solid Images, Houston TX (2) ForestOil, Denver CO

Seismic interpreters are required to work with larger and larger seismic volumes as the amount of seismic data we acquire and process continues to increase. Rapid advances in seismic attribute methods further increase our data-set sizes by providing many coincident seismic attribute volumes for each data set. These exponential increases in available data represent huge data management and data interpretation challenges to our industry. There are clear similarities between the seismic exploration industry and the Internet in terms of the volume of information that is available for analysis, and therefore it makes sense to deploy data mining tools and methodologies developed for other industries to address the needs of the oil and gas exploration business. We employ some aspects of the data mining workflow in a case study from South Africa to enrich and discover knowledge about productive regions within 3D seismic data volumes. Seismic data mining is applied to multiple seismic attribute volumes calculated from a 3D dataset acquired over the Ibhubesi Field in the Orange River Basin, RSA. Large amplitude anomalies are present on the full-stack data, also discernible when transitioning from near to mid angle sub-stacks. Most wells exhibiting a Class III AVO anomaly tested productive, however, the dilemma of just using the seismic amplitude response as a fluid discriminator is that the sand in the well bore associated with the largest Class III AVO anomaly tested wet. Integration of well data driven synthetic seismic data is critical to finding attributes to constrain the Class III AVO response. The analysis of the well data indicated the importance of Poisson’s Ratio for discriminating pay from wet sands. Attributes derived from band-limited inversion of the seismic sub-stacks retain the discrimination observed in the well data. Additionally, other seismic attributes that discriminate facies and fluid types, can utilize a further data mining technique employing neural network technology to generate a single attribute volume of the multi-attribute response. The results of this study demonstrate the value of applying data mining techniques to seismic data volumes to rapidly seek prospective zones using some well calibration, thereby mitigating future drilling risk. Uwe Strecker, Rock Solid Images, 2600 S. Gessner, Suite 650, Houston TX 77063 USA, [email protected] ForestOil, 1600 Broadway, Suite 2200, Denver CO 80202 USA



39

Petroleum Systems of the East Africa Rift System: Prospectivity of Kenya, Tanzania, and Uganda

Daniel M. Jarvie1, Brenda L. Claxton1, Mark Tobey1, Hossein Alimi1, Albert Maende2, Flora

Panju3, Meshack Kagya3, Rueben Kashambuzi4, and Ernest Rubondo4

1 Humble Geochemical Services, Humble, Texas 2 National Oil Corp. of Kenya, Nairobi, Kenya 3 Tanzania Petroleum Development Corp., Dar es Salaam, Tanzania 4 Petroleum Exploration and Production Department, Entebbe, Uganda

The existence of petroleum systems in East Africa is confirmed by the existence of commercial production of hydrocarbons from the Songo Songo gas field, offshore Tanzania. However, the presence of other prospective petroleum systems is evinced by the presence of DST oils recovered from wells in the Lokichar and Anza basins of Kenya, and the presence of numerous seeps in Tanzania, Kenya, and Uganda. Our study involves the analyses and interpretation of recovered oils, condensates, seeps, and source rocks found in the East African countries of Kenya, Tanzania, and Uganda. This includes oils, seeps, and source rocks recovered from the following locations:

Sirius-1 well, Anza Basin, Kenya Loperot-1 well, Lokichar Basin, Kenya Loperot-1 well source rock samples, Lokichar Basin, Kenya Songo Songo condensates, Mafia Basin, Tanzania Kibiro, Paara, and Kibuko oil seeps, Albertine Graben, Uganda Waki-1 source rocks, Albertine Graben, Uganda

Thus, key components of functional petroleum systems have been identified in East Africa and the need for further testing of play concepts and prospects is obvious. The risk factors are primarily reservoir rock characteristics, trap size, and sealing efficiencies as lacustrine and marine source rocks have been located or inferred. Daniel M. Jarvie, Division of Humble Instruments & Services, Inc., P.O. Box 789, Humble, Texas 77347 Tel: 281-540-6050, [email protected]



40

HYDROCARBON POTENTIAL OF ANZA AND MANDERA BASINS IN KENYA”.

Authors: NOCK STAFF David Bundi M’ANAMPIU *

The Anza Basin is one in a series of Cretaceous-Tertiary failed rifts that trend across the Central African Craton from Benue Trough in Nigeria through Chad and Central African Republic(CAR), the Sudan and Kenya. It covers 94,220 sq kms and trends in the same direction as Muglad, Melut and Blue Nile Basins of Sudan, where proven vast hydrocarbon reserves are present. The Gambela, just to the north in Ethiopia, also has reserves. The Anza Basin contains the triple junction of a failed Mesozoic rift. The sediments are mainly Cretaceous-Tertiary fluvio-deltaic deposits overlying occasional Upper Jurassic marine deposits. Intermittent volcanics occur in the column. Source rocks are a Lower Cretaceous gas prone one and an Upper Cretaceous Lacustrine oil prone one. Oil, from Cretaceous source, has been recovered from Sirius-1 well, and oil and gas shows have been encountered in seven out of eleven wells drilled in this basin. Anza Basin is analogous to basins of Southern Sudan and has a lot of potential for hydrocarbons. The Mandera Basin is a Late Paleozoic rift extending from Kenya northwards to Ogaden Basin in Ethiopia and Somalia, and covers 51,920 sq kms on the Kenyan side and is well covered in geophysical data. Its stratigraphy ranges from Precambrian basement to Upper Cretaceous with major boundaries that record punctuation in rifting and subsidence during this basin’s development. Positive highlight is that this basin has no volcanic intervals and has proven reserves in Ethiopia. It has NNE-SSW trending structures parallel to and controlled by strike of the Karoo graben, and NNW-SSE trending structures parallel to the Lagh Bhogal fault. Mandera Basin is analogous to Karoo basins associated with Gondwana break-up, with correlative beds in Lamu Basin (Kenya) and Morandava Basin in Madagascar. Toarcian-Kimmeridgian shales of marine Murri Limestones and Didimtu Formations contain potential source rocks. Reservoirs are marls, claystones and mudstones interbedded with carbonates of Seir and Dakacha formations. Others are tidal channels sandstones and siltstones of Golberobe and Danissa Formations. The rolling of sediments against NW-SE faults form anticlinal features and are structural exploration leads. New analysis of Tertiary Loperot trough shows there could be up to 10BBO in place in this sub-basin of Tertiary rift. David Bundi M’ANAMPIU, Head of Geology section, National Oil Corp. of Kenya, [email protected]



41

Hydrocarbon Potential of Madagascar

David Clark1 & Lalaniriana Rasoanandrianin 2

1Clark Research Limited, 2.Antananarivo, Madagascar Three large sedimentary basins are present on the western side of Madagascar. These basins started to form with the onset of rifting in the Permian but the main development took place in the Mesozoic and Tertiary, as Madagascar drifted southwards away from Africa. Two large heavy oil fields were discovered in the northern Morondava Basin in the early 1900s but since then exploration drilling has been disappointing with only two small gas discoveries and one small light oil discovery being made. The lack of success is surprising because good reservoirs, seals and source rocks are known to be present and several trapping styles have been identified. Misconceptions exist, however, concerning the structural and stratigraphic history of the basins, the distribution of source rocks and the timing of trap formation in relation to oil migration. It is important to develop a better understanding of these factors in order to identify any remaining hydrocarbon potential in the onshore basins, and to assess any future potential in the offshore area. Previously, only one continuous phase of rifting was recognised in western Madagascar, with separation from Africa taking place in the Oxfordian. In fact, two separate phases of rifting can be distinguished, one in the Permo-Triassic and the other in the Late Liassic. A narrow intracontinental rift propagated through western Madagascar in the Early Permian. Crustal extension continued into the Early Triassic, accompanied by symmetrical rifting and the uplift of the graben shoulders. This was followed by thermal subsidence and basin sag in Late Triassic times, when the rift essentially failed. A new rift formed to the West of the failed rift in the Late Liassic and a series of half-grabens developed. Madagascar then started to drift southwards away from Africa in the Bajocian, and a passive margin developed along the western coast. Renewed tectonic activity occurred in the Late Cretaceous when Madagascar separated from India. This was accompanied by wrench faulting and compressional folding. The failed rift is characterised by potential reservoirs in the Lower Sakamena, Upper Sakamena and Isalo Sandstones. A thick seal is provided by the Middle Sakamena Shale which also forms the principal source rock. Three trapping styles can be recognised, namely tilted fault blocks, drape anticlines and roll-over anticlines. The tilted fault blocks are ineffective because they are dependent on up-dip fault seals. The drape anticlines form more effective traps provided that sealing shales are present but they normally occur at relatively shallow levels above large tilted fault blocks and are associated with heavy, biodegraded oil. Roll-over anticlines are found at deeper levels on the downthrown sides of larger fault blocks. These have yet to be tested but they may contain lighter, unmodified oil, away from the influence of meteoric water. The passive margin is characterised by potential reservoirs in the Middle Jurassic Bemaraha Limestone and the Cretaceous Tsiandava and Sitampiky Sandstones. Seals are provided by the Late Liassic Beronono/Andafia Shale, the Callovian Beboka Marl and various Cretaceous shales. Potential source rocks occur in the Beronono/Andafia and in the slope and basin-plain carbonates of the Bemaraha. Three trapping styles are developed, namely tilted fault blocks, compressional anticlines and stratigraphic traps. The tilted fault blocks are unattractive because the crests are not always covered by a seal and no reservoirs are present. The compressional anticlines are usually associated with good quality Cretaceous sandstone reservoirs and locally with porous limestones in the Bemaraha. These anticlines formed after oil migration but some are charged with gas in more westerly coastal and offshore locations. Possible stratigraphic traps are well-developed in the Cretaceous in the form of lowstand wedges and base-of-slope and basin-floor fans. These traps offer the best chance of finding commercial oil accumulations on the passive margin. Recently published seismic data suggests that another arm of the failed Permo-Triassic rift may be present in the offshore basins. This raises the possibility of localised occurrences of the Middle Sakamena source rocks together with Lower Sakamena and Isalo reservoirs in deep water areas. Late Liassic half-grabens also appear to be present suggesting that Beronono/Andafia source rocks might be widely developed. The potential reservoirs of the Bemaraha, Tsiandava and Sitampiky are unlikely to extend offshore but lowstand submarine fans of Cretaceous and Tertiary age may be present in places. As with the onshore basins, the burial history of the source rocks in relation to trap formation is problematic but the offshore thinning of the Cretaceous and Tertiary sediment wedge should mitigate this to some extent. David Clark, Clark Research Limited, 31A Rectory Avenue, High Wycombe, HP13 6HN, Buckinghamshire, UK [email protected] Lalaniriana Rasoanandrianin, BP 7745, Antananarivo 101, Madagascar [email protected] .



42

New Exploration in Chad

Paul Winder*, Alastair Hill, Simon Youens, Carmen Neufeld, Bill Bergman, & Marian Warren,

EnCana Corporation, Calgary, Alberta, Canada First oil production and export from Chad is expected in Q3 2003. Production will come initially from the Doba basin, one of a series of oil-prone rift basins currently undergoing renewed exploration in Chad. The basins are immature in exploration terms, due to the remote location and previous lack of export route. Active petroleum systems have been proven in 4 basins, with oil recovered on testing in 18 of the 36 exploration wells drilled in Chad to date. The majority of discoveries were made in the 1970’s and 1980’s, though it was 2000 before the first commercial development at Kome in the Doba Basin was commenced. This development involves 3 fields with combined reserves of approximately 950 MMBO, operated by ExxonMobil. The Chad rift basins evolved during the Cretaceous and Tertiary. A combination of laterally extensive lacustrine source rocks of Early Cretaceous age, fluvio-lacustrine and marine clastic reservoir systems of Early-Late Cretaceous age, plus thick regional mudstone sealing horizons, has created widespread and prolific petroleum systems in these basins. Transpression and inversion, related to strike-slip movement along the Central African Fault Zone during the Late Cretaceous to Tertiary, created an abundance of prospective hydrocarbon-trapping folds. Encana’s Permit ‘H’ exploration program is currently focussed on the Bongor and Lake Chad Basins, where over 5000 km of new 2D seismic has been acquired since late 2001. Evaluation of 4 additional rift basins in southern Chad is also ongoing. Airborne gravity and magnetic data has been acquired over 3 areas totaling 30,000 km2, and a multi-well exploration drilling program is expected to commence in late 2003. This presentation will provide an overview of the current exploration situation in Chad, and will assess key exploration risks in the quest to find large accumulations of flowable hydrocarbons. Paul Winder, EnCana Corporation, 150 9th Av. Sw, Calgary, Alberta, Canada; [email protected]



43 Cretaceous subsidence, Tertiary uplift and petroleum system of The Mamfe

Basin in SW Cameroon, Central Africa.

Bill Fitches1, Martin Abolo2, Patrick Barnard1, Serge Edouard Angoua Biouele2, Mark Bastow1, Alan

Collins1 & Jean Jacques Koum².

1 Robertson Research International, North Wales 2 Société Nationale des Hydrocarbures, Yaounde, Cameroon.

The Mamfe Basin, a WNW-trending branch of the Lower Benue Trough, is a frontier basin: heavily forested with few outcrops, no exploration wells nor seismic data. This study is based mainly on recent field studies and newly acquired biostratigraphic, petroleum geochemical and apatite fission track data, and interpretation of satellite imagery and aerial photographs. The Mamfe Basin has been regarded as a rift, largely from interpretation of sparse potential fields data and the sedimentary facies association. However, no firm evidence of WNW-striking border faults in Cameroon has been obtained in the field or from satellite images and airphotographs. The presence of large N-S faults within the basin is inferred from geophysical data and from satellite images, probably recording reactivation of Precambrian basement structures during and/or after sedimentation. The subsidence history of this Basin appears to be closely linked with the Early Cretaceous transtensional separation of South America from Africa. In the Aptian and Albian, southern parts of the Benue Trough became submerged by a shallow marine gulf of the proto-Atlantic Ocean. The Mamfe Basin branched off the eastern flank of the gulf during this interval and was the site of non-marine sedimentation: predominantly high-energy alluvial and fluvial sandstones and conglomerates with lacustrine shales and siltstones. It is believed that up to 7000m of sediment were deposited within this basin between the initiation of sedimentation in the Barremian (?) and probable termination in the Coniacian-Santonian. During the “Santonian squeeze” caused by readjustment of plate movements, the Abakaliki region in the Benue Trough NW of the Mamfe Basin was uplifted and deformed by NE-trending folds. In the Mamfe Basin, there are indications of folds with large wavelengths and gently inclined limbs (15o – 20o): but they are E-W. Their age is uncertain. As sedimentation ceased within the basin, progressive uplift appears to have begun starting in the latest Cretaceous. This paper will present the results of the various laboratory studies including evidence for the burial and uplift history, the ages of the sediments at outcrop and the petroleum source potential and current maturity of the sediments. Conjecture as the future petroleum potential of the basin will be drawn from the data presented. Bill Fitches 1 Robertson Research International, Llanrhos, Llandudno, North Wales, UK LL30 1SA

[email protected]



44

New Insights Into Old Discoveries In Northwest Africa

– Dome Flore and Dome Gea

Laurie Brown, Peter Dolan, Robert Hall, Richard Higgins, Justin Norris, Michael Purves, Mark Sofield, Alan Stein, Jonathan Taylor.

Fusion Oil & Gas plc

The Dome Flore Concession lies in the offshore territory administered by the Agence de Gestion et de Coopération entre la Guinée-Bissau et le Sénégal (“AGC”) which is a joint commission established to administer the maritime border zone between Senegal and Guinea Bissau. Previous drilling in the period 1967-1971 has established that the Dome Flore acreage has access to a world class petroleum system, which has generated significant quantities of oil. Most of the oil discovered to date is heavy crude that would be uneconomic to develop with current technology. Since discovery of the Dome Flore and Dome Gea accumulations, much of the subsequent activity focussed on potential development of these heavy oil reserves however current activity is directed towards a better understanding of the exploration potential for light oil within this prolific system. Indications of light oil have been encountered in both Tertiary and Upper Cretaceous reservoirs during previous drilling on Dome Flore and Dome Gea, and regionally in Lower Cretaceous reservoirs.

The Dome Flore petroleum system is driven by the same regional Cenomanian-Turonian source rock system that is proven to be effective to the north offshore Mauritania. However, there is strong evidence to suggest that there are also deeper source rocks in the Aptian and Albian that could have a significant effect on prospectivity.

Of the thirteen wells and one core-hole in the block, most were shallow tests drilled between 1967 and 1971, with only two wells drilled in the last thirty years. A 3D seismic survey acquired in 1992 was unable to accurately image the deeper reservoirs which are the focus of the current activity. A new 3D survey was recently acquired using acquisition parameters fully optimised for the deeper exploration objectives and the whole volume has undergone pre stack depth migration.

The new 3D seismic data provides new insight into some old discoveries within an emerging frontier petroleum province.

Alan Stein. Fusion Oil & Gas plc, PO Box 596, West Perth, Western Australia, [email protected]



45

PLAY TYPES OF THE MSGBC BASIN EMERGING PLAYS – REVITALIZED PLAYS

John Dombrowski, Fortesa International MSGBC is an acronym derived from the five countries comprising the basin, Mauritania, Senegal, Gambia, Bissau and Conakry. Located in the NW portion of Africa, the basin was formed as a result of the opening of the central Atlantic. This area has undergone a complex history of pre-rift (Upper Proterozoic – Paleozoic), syn-rift (Permian – Lower Jurassic) and post-rift (Mid Jurassic - Present) tectonic events. To date, there has been little commercial production from the basin. However, multiple robust Petroleum Systems are present. In the southern portion of the MSGBC, the Dome Flore/Gea offshore field contains reserves between 500 Million to 1.0 Billion barrels of oil on two diapiric salt structures. A lack of sufficient overburden has caused the oils to be biodegraded and thus non-commercial. It should be noted that middle gravity oils were recorded deeper, along the flanks of these diapirs. There has been significant recent success in the northern portion of the MSGBC in Mauritania. Chinguetti was discovered by the Woodside group in 2001, and has reported reserves of between 140 - 150 MMBO recoverable. A year later the Banda discovery was announced, located 20 km east of Chinguetti. Banda is thought to have reserves of 100 MMBO and as much as 1.0 TCF of gas. An assessment of the commerciality of these fields is presently underway. The recent Chinguetti and Banda discoveries, along with the enormous volume of biodegraded oil present at Dome Flore/Gea, have generated a new round of interest in the MSGBC basin. Some exploration continues on proven play types. Older plays are being revitalized through the application of newer technology. New and emerging play types hold the promise of more discoveries like Chinguetti and Banda. The following play types are evident. Established Play Types

Delta Front – productive onshore Senegal, present in the shallow waters of Bissau and Conakry, Cretaceous and possibly Tertiary in age

Revitalized Play Types

Salt Basins – salt related structures throughout the basin mapped using 3D and PSDM Emerging Play Types

Deep Water – channels and fans in combination structural/stratigraphic traps throughout the basin of Tertiary and Cretaceous age

Shelf Edge – Cretaceous fault traps and truncation plays in Guinea Bissau

Channel Head – Tertiary and Cretaceous aged proximal, distributary channel systems throughout the basin

Carbonate Bank – Jurassic and Lower Cretaceous reefs, karst and deep burial diagenesis offshore along the basin margin and onshore in Senegal

Newly acquired and recently reprocessed seismic data along with maps and geologic sections will be used to illustrate the play types. John Dombrowski, Exploration Manager Fortesa International, 2470 Gray Falls, Houston, Texas 77077 USA,

[email protected]



46

Correlation of Crude Oils from the African, European, South American, and North American Margins of the Central Atlantic

John Zumberge*, Nick Cameron, and Stephen Brown

GeoMark Research, Houston Texas The analyses of 70 crude oils provide the foundation for this study, the results from which are integrated with the regional geology to identify and characterize the Petroleum Systems of the Central Atlantic. A number of Oil Families, previously thought to be geographically isolated, are now known to be related. Extended family links of this type can only emerge when global scale data sets are available. The outcome is a range of entirely new exploration opportunities. Nine Oil Families with more than one oil member were identified within the study area, all but one of which are related to marine source rocks. Dominant is the KS Oil Family, related to the Turonian to Cenomanian aged OAE2 event. It is developed in the Americas from Suriname to Barbados and in North West Africa from the AGC to Senegal and Mauritania. Supra-regional control shows that this family extends eastwards though the Equatorial Atlantic into the South Atlantic. There are two lesser marine Oil Families, JC and JS, in North West Africa. Within the study area, both are single member families and both are only found in Morocco. However, the supra regional control suggests that they will ultimately prove to be of regional extent since closely related oils are present in Portugal and Spain. Liassic source rocks are widely present in Morocco and North West Europe. In the latter area they are commonly referred to as the Posidonia Shale. Liassic and younger Jurassic shales sourced oils of Family JS while Family JC oils were probably derived from Kimmeridgian/Oxfordian carbonates. Source units appear to be less well developed off the East Coast of the USA. However, the prospectively of this margin may be more encouraging that presently believed. A match of Sunniland (South Florida) oils with the Heron oil from the South Whale basin suggest that there may be overlooked carbonate bank top and bank slope plays. The enhanced area of middle and early Jurassic source rocks now known to exist off the Morocco region supports this observation. Cretaceous aged, shelf slope and top, carbonate sources could exist in North West Africa. The Central Atlantic is commonly treated as being source poor, perhaps because of the discouraging results of the initial offshore drilling campaigns. It is now clear, both from the analytical results and the regional geology, that multiple source horizons are present, many of which are both richly oil-prone and thick, notably along the North West African margin. In most cases, the risk related to source is now whether there is sufficient maturity and volume of generation, rather than one of quality. John Zumberge, GeoMark Research, Houston Texas, [email protected] (or [email protected] )



47

West Delta Deep Marine, offshore Nile Delta – Aggressive Exploration Program Commercialized through ELNG

Nick Steel (Rashpetco/BG Group) & Mohamed Nashaat (Rashpetco/EGAS)

Sixteen E&A wells have been drilled between 1998 and 2002 in the West Delta Deep Marine concession with a 100% success rate. The concession, located in the Egyptian deepwater Nile Delta, was awarded to BG and Edison Gas in 1995 and is now operated by Rashpetco on behalf of the Burullus Gas Company (a joint venture company formed by BG, EGAS, and Petronas – replacing Edison), where the success story continues with an aggressive technology-enabled exploration and development program.

The first discoveries, Scarab and Saffron, were brought onstream in March 2003 delivering gas to the domestic market. This is the largest gas field development in Egypt, the first sub-sea completion in the region, and has one of the longest tie-backs in the world. Six of the other discoveries - Simian, Sienna, Sapphire, Serpent, North Sequoia and Saurus – discovered between 1999 and 2001 will be commercialized by export through Egyptian LNG. Train 1 production is scheduled for 2005 with Train 2 following in 2006, representing a world-class time-to-market performance.

Depositional models for the prolific WDDM reservoirs have been developed through the integration of extensive well data, particularly cores and borehole image logs, 3D seismic and analogues. The discoveries have been made in a variety of Pliocene deep marine turbidite systems – from base of slope fans to slope channel complexes.

The early acquisition of high quality 3D seismic surveys and the utilization of seismic attributes and techniques has enabled the gas accumulations to be effectively imaged, thus reducing the gap between exploration and development, effectively saving the cost of additional drilling.

Twenty-eight wells have been drilled to date in successive exploration and development campaigns, providing the opportunity to gather extensive datasets to calibrate the seismic response. Advanced open hole logging programs including NMR technology, FMI and MDT Dual Packer formation testing in combination with core data has enabled the evaluation of additional pay and gas reserves within low resistivity, thin-bedded sand reservoirs. The quality and volume of data gathered now enables well-testing operations to be restricted to non-conventional pay intervals, effectively reducing cost and minimizing HSE risks.

Detailed reservoir models were constructed by integrating subsurface data and interpretations using deterministic and stochastic geological model-building techniques. Full-field reservoir models and high-resolution sector models are used for development planning and scenario analyses.

Effective teamwork, between subsurface disciplines, drilling and Project teams, has ensured that exploration and development programs have retained flexibility to ensure aggressive schedules are maintained whilst critical data is gathered, and lessons learned are integrated. Numerous contributors have played a key role in shaping our knowledge and establishing the commercial position of the concession.

The strong support that shareholding partners and the Egyptian government have provided has enabled rapid commercialization of the multi-tcf reserves in the concession, enabling the Nile Delta to become the major gas province in the Eastern Mediterranean region. Nick Steel, Rashpetco/BG Group, Cairo, Egypt. [email protected] or [email protected]



48

Eastern Mediterranean – Exploration Potential of the Levantine Basin Region

David Peace AOA Geophysics Europe London David Meaux AOA Geophysics Inc Houston Bob Pawlowski AOA Geophysics Inc Houston Mike Johnson Spectrum EIT Ltd London Alan Taylor AT Energy Ltd London

The exploration potential of the greater Eastern Mediterranean region is just starting to be unravelled. To date there has been very limited exploration in most of the region, and NO exploration licencing at all covering offshore Lebanon, Syria or Cyprus. This area is largely characterised by the Levantine basin which itself is little understood This represents an excellent first-time opportunity to participate in new exploration in untested basins adjacent to proven hydrocarbon reserves. To date the main discoveries in the region have been the spectacular large gas discoveries by British Gas and partners in the shallower Pliocene section of the Nile Delta and later in Israel and Gaza to the east. Some wells have also discovered significant condensate volumes and one or two wells are believed to have found just oil with some associated gas. Water depths vary from shallow coastal waters to just over 2000 mtrs in the deeper western parts of the region. In preparation for future licence rounds, recent data acquired in the region over the last 2-3 years includes regional gravity and magnetic data, SAR seep data and some 22,000 kms of seismic data including much new data recorded down to 12 seconds twt. The regional gravity and magnetic data provides some insights into the early history of the basin, while the seismic data shows the presence of thick and laterally extensive basins systems, with many very interesting structural and stratigraphic leads. Many DHI’s and gas chimney’s are seen present in association with these leads. The new seismic data also shows that the geometries in the Levantine Basin are much larger, thicker and deeper than was previously thought. Similarly around the Latakia thrust front many structural leads are observed in the northeast part of the basin where southward thrusting has caused many attractive looking anti-clinal structures to be formed. These deeper basins have not yet been drilled. The only deep wells in the region have been far to the west in the outer Nile Delta in the Nemed block (recent Shell wells). Early evaluation of these data sets confirms the Levantine basin as a major deep basin with a totally untested section. This paper discusses some of the early history of the basin, reviews the general shape and structure of the basin and shows examples of the variety, and style of exploration leads evident from the seismic data. David Peace, AOA Geophysics -Europe, London [email protected]



49

TECTONIC EVOLUTION AND ITS EFFECT ON BASEMENT DEVELOPMENT AND OIL GENERATION IN LIBYA.

Saad Z Jassim, Ian Somerton and Simon Campbell.

GETECH, University of Leeds, Leeds UK

The Phanerozoic tectonic events of Libya are the product of the plate movements of Africa, influenced by inherited Late Precambrian Pan African trends. Most of these tectonic events are associated with the more mobile Late Precambrian accretionary terranes. The “Caledonian” phase can divided into an Early Caledonian phase (NNW Highs in Murzuk) of the Early Ordovician age and a Late Caledonian phase (ENE Gargaf High) of Middle to Late Silurian age in Central Libya. The “Hercynian” tectonic event occurred during the Late Carboniferous to Early Permian (Early Hercynian), producing a broad arch covering the areas of the Kufra-Tibesti and the Sirte basin. Late Hercynian arches (Permo-Triassic) are generally narrower and extend in E-W direction, such as the Nafousa arch in NW Liby. The two main Paleozoic events resulted in the exposure of the area of the Sirte basin for long periods of time during the Paleozoic. Mesozoic events can be related to the Syrian Arc system which resulted in the development of E-W arches in central Libya. These events were intensified during the Early Cretaceous, producing narrow active grabens and associated highs. They are related to the opening of the Mediterranean ocean during the Triassic and Jurassic and the development of the African Rift System associated with the opening of the S Atlantic during the Early Cretaceous. The most prominent event in Libya is the Sirte trans-extensional system associated with the African rift system and the associated sub-plate adjustments. This event resulted in the subsidence along three main directions, NNW, NNE and E, producing important depocentres and oil plays. The various petroleum systems of Libya are discussed on the basis of this tectonic evolution. Ian Somerton, GETECH, University of Leeds, Leeds LS2 9JT,United Kingdom [email protected]



50

Basin development, deformation and fluid migration in northern Tunisia from the Triassic to the present day.

BAIRD, ALASTAIR W1., CHRIS J. CLAYTON1, HANS E. MADEISKY2 and ABDELBAKI MANSOURI3.

1 Kingston University, United Kingdom 2 HEMAC Exploration Ltd. Vancouver, Canada 3 Office National Des Mines, Tunis, Tunisia

The northern half of Tunisia contains superb field evidence of a polyphase history of

basin development and deformation, culminating in the growth of the Atlas mountains in the extreme north. Three main hydrocarbon source rocks have undergone variable burial, leading to variable maturation, hydrocarbon migration and active seepage from a number of small, but potentially viable petroleum systems.

We present maps, block diagrams, cross-sections and burial history graphs for northern Tunisia to illustrate the geography and geometry of the Mesozoic to Paleogene basins and their deformation during the Atlassic orogeny.

In northern Tunisia the gypsiferous “evaporitic” Triassic rock is a pre-rift sedimentary sequence which subsequently occupied the elevated footwalls of the Mesozoic to Paleogene basin margin faults. During Atlassic thrusting the crests of the extensional fault blocks were often decapitated and Triassic sediment carried laterally into the adjacent basins. This sequence of events explains the geometrical relationship of Triassic rocks to hydrocarbon seeps and Pb-Zn mineralisation, without recourse to the frequently published ideas of diapirism and/or submarine extrusion of “salt glaciers” of Triassic evaporites.

We summarise a detailed study (using extensive unpublished drilling and mining data and detailed surface mapping at a scale of 1:2500) of the relationship between Pb-Zn deposits, polyphase basin development and Atlassic deformation in the Mejerda zone. We describe the geometry of a major, near-surface, blind thrust which is locally intensely mineralised and oil stained and we show how this geometry was controlled and modified by fluid flow from the adjacent basins. BAIRD, ALASTAIR W., School of Earth Sciences & Geography, Kingston University, Penrhyn Road, Kingston upon Thames, Surrey, United Kingdom1 [email protected]



51 Petroleum Potential of the Poorly Explored South Central Region of the Murzuq

Basin, Libya D. D. Clark-Lowes* Clark-Lowes Consulting, UK, and D. R. D. Boote London UK

The Murzuq Basin of Southwest Libya is still only partially explored. The Lower Paleozoic Memouniat/Haouaz-Tanezzuft Petroleum System is now well established in the north, but little is known of the remote region to the south. The basin underwent a complex geological evolution with repeated marginal uplifts and perhaps several periods of hydrocarbon expulsion and migration from basal Tanezzuft (hot shale) source rocks. The Memouniat/Haouaz reservoir sequence has been subject to sometimes quite pronounced regional tilting, unroofing and freshwater flushing. Some measure of the potential of the south central region can be assessed by identifying the more critical stratigraphic and structural criteria controlling the distribution of the oil fields in the north and projecting these criteria to the south. This approach is adopted in this paper and the data of the northwest is used to build a case for the prospectivity of the south central region. Regional isopach mapping of the key stratigraphic intervals, combined with simple maturity modelling, suggests that many of the northern fields were charged from a late Paleozoic-Mesozoic depocentre located immediately to their northwest. Reconstruction of this now partially exhumed depocentre suggests that it was once part of a larger basinal sag with a second depocentre in the south central Murzuq. While the subsequent late Tertiary uplift and unroofing would have been locally very destructive, there is a reasonable possibility that more robust trapping in the central part of the basin may have produced quite significant oil accumulations, with sizes perhaps comparable to the Elephant field i.e. in the range 500-600 million barrels recoverable. Indeed if the trapping style is more comparable to that of the Al Sharara field then reserve sizes of over a billion barrels are realistic. In this central part of the basin the effects of post-charge tilting and flushing were more subdued. Although the southerly extent of the Tanezzuft source rock remains uncertain, there is some evidence to suggest it extended far south and was capable of significant hydrocarbon charge during the Cretaceous and early Tertiary. In the northern part of the basin, deposition of the organic rich facies is seen to have been confined by the residual post-Memouniat paleotopography and a similar distribution can be expected to the south. This would suggest that its apparent absence given current well control could reflect the positive position of well locations drilled on prominent topographic highs. The better quality reservoirs are found in the coarser grained glaciogenic clastic facies of the Memouniat which appear to be restricted to erosional paleotographic lows on a regional second order sequence boundary. This suggests a similarly irregular distribution to the south with important implications for prospect definition. Whilst this assessment of the exploration potential of the central and southern Murzuq Basin must remain speculative it is demonstrated that it is possible to constrain the uncertainty by undertaking a regional synthesis of the basin’s structural history and hydrocarbon environment. Although in no way definitive or conclusive, the analysis presented suggests that it may be extremely prospective. D. D. Clark-Lowes* (Clark-Lowes Consulting, Oak Court, Siver Street, Wiveliscombe, Somerset TA4 2PA UK, [email protected]) D. R. D. Boote (12 Elsynge Road, London SW18 2HN UK, [email protected] ).



52

Untapped potential of the Rif Fold and Thrust Belt of Morocco - an overlooked hydrocarbon province of the future?

Dr Andrew Carr1, Richard Moreton2*, Martin Whitehead2

1 Advanced Geochemical Systems Ltd 2 Granby Enterprises Ltd

The Rif Fold and Thrust Belt is one of the few remaining underexplored Tethyan margins, where prolific quantities of hydrocarbons have been found to date. Its affinities relate both to Africa and Europe, and geometrically the thrust belt forms a prominent arc, at the westernmost margins of the major Alpine fold and thrust system of the Western Mediterranean. The area has had an exploration history which focused from an early stage on the most external parts of the thrust belt / foreland margin where traps are shallow, small and leaky and only small amounts of hydrocarbons have been produced to date. Oil quality is however good and there is proven potential for biogenic gas. We demonstrate how, by shifting attention and focus slightly more internally, there are much larger and deeper undrilled structures to pursue with all the necessary components to produce a potentially significant hydrocarbon province. The stratigraphy of the area is varied and complex from the relatively stable, undeformed foreland, to complex flysch nappes (both rooted and rootless) and the intensely deformed internal zones. Reservoirs are developed at a number of horizons (Jurassic through to Tertiary) and seals are common throughout the section. Careful integration of the available geological and geophysical data across the thrust belt has allowed the definition of numerous new prospects and leads having a variety of trap forms with fault propagation folds / ramp anticlines and steeply dipping thrusted imbricates being commonplace. Tertiary stratigraphic traps (with amplitude anomalies) are also proven in the region – and may occur within prominent ‘piggy back’ basins of clastic turbidite deposition. Main source rocks are proposed in the Lias and Cretaceous (Cenomanian-Turonian) although others may occur. Important basin modelling demonstrates that traps formed as late as the Pliocene can receive hydrocarbon charges from these sediments. The role of pressure in the generation and expulsion history of the area is discussed. Release of regional pressure cells during tectonism may in part explain the vertical uniformity of hydrocarbons found to date. Dr Andrew Carr, Advanced Geochemical Systems Ltd. 1 Towles Fields, Burton on the Wolds, Leicestershire, LE12 5TD, United Kingdom Richard Moreton, Granby Enterprises Ltd, PO Box 3191, 55 Longmore Avenue, Barnet, EN4 9WG, UK [email protected] Martin Whitehead, Granby Enterprises Ltd, PO Box 3191, 55 Longmore Avenue, Barnet, EN4 9WG, UK [email protected]



53

THURSDAY POSTERS: ORANGE BASIN Namibia – South Africa Page # The Orange Basin of Namibia –Tectono-Stratigraphic Evolution and Petroleum Systems Roger Swart NAMCOR (Pty) Ltd, Windhoek, Namibia

54

EAST AFRICA

Tectonics of the Western Indian Ocean Bill St. John

55

Hydrocarbon Prospectivity of the “Pemba Segment”, Tanzania Keith Skipper, Antrim Resources (Tanzania) Limited

56-57

The Petroleum Potential of the Mandawa Basin, onshore Southern Tanzania S. Massay, G. Kibakaya, G. Ngwale, Tanzania Petroleum Development Corporation, Dar es Salaam, Tanzania

58

Evidence for multiple oil-prone sources horizons in coastal Tanzania, Chris Matchette-Downes, JEBCO (UK) Limited

59

The Petroleum Potential Of Rovuma Basin Nelson Ocuane & José Branquinho, National Directorate for Coal and Hydrocarbons, Maputo, Mozambigue

60

The South African East Coast: Evidence for an Active Petroleum System within the Tugela Fan, Durban Basin V Singh1, D van der Spuy1 and N.R. Cameron2, Petroleum Agency SA1, Global Exploration Services2

61

East Africa – Madagascar Paleogeographic Evolution andSsource Rock Distribution Donald C. Rusk & Robert G. Bertagne

62

Occurrence and Distribution of Potential Source Rocks in Western Madagascar David Clark1 & Lalaniriana Rasoanandrianina2 1Clark Research Limited, 2.Antananarivo, Madagascar

63

West Madagascar continental margin analysis: Crustal classification, regional geologic structure and sedimentary thickness. Samuel D. LeRoy1 and Ralph Stone2, 1 EarthView Associates, Inc, 2 Consulting geologist, Houston

64

Prioritising exploration leads in Sudan using magnetic alteration seepage signatures recognised in high resolution aeromagnetic data. Vaughan C. A. Stone (GETECH), J. Derek Fairhead (GETECH, Leeds University), W. Heiko Oterdoom (Petronas Carigali White Nile (5B) Ltd – formerly of Lundin Sudan BV)

65

NORTHWEST AFRICA

Salt Tectonics in the Ras Tafelney-Safi Segment of the Moroccan Atlantic margin Tari, G., Molnar, J. and Thompson, P., Vanco Energy Company, Texas

66

Benin to Mauritania Petroleum Systems Overview David Johnstone, Alan Collins, Carl Watkins, Peter Ellwood, Chris Veale, Mike Hawkins, Steve Thompson, Robertson Research International Limited

67

Petroleum Play Systems & Hydrocarbon Potential of the Offshore Boujdour Area of North West Africa Alan Jessup and Al Salman, AA International Petroleum Management

68

NORTHEAST AFRICA / Mediterranean

Elements Of Success: Graphic Correlation And Quantitative Biostratigraphy In The Nile Delta, Egypt William N. Krebs*, Anthony Gary, Energy & Geoscience Institute,

69

NORTH AFRICA

Geochemical Exploration in North Africa: Recent Successes from Algeria, Tunisia and Egypt Dietmar Schumacher and Daniel Hitzman, Geo-Microbial Technologies, Inc.

70

Sequence stratigraphy, structural evolution and petroleum systems in the Ghadames Basin, Libya Dardour, A. M., Boote, D. R. D., Baird, A. W. and Wigley, P., Kingston University, UK

71

Algeria’s Deepwater Margin: an Unexplored Frontiers Basin Michael J. Cope, Reservoir Services, WesternGeco, Gatwick, United Kingdom

72



54 POSTER

THE ORANGE BASIN OF NAMIBIA - TECTONO-STRATIGRAPHIC EVOLUTION AND PETROLEUM SYSTEMS

Roger Swart NAMCOR (Pty) Ltd, Windhoek, Namibia The Orange Basin of south-western Africa is a known hydrocarbon province but is relatively underexplored in comparison to its potential. The basin lies offshore of a major river system that in the Cretaceous was comparable to the Tertiary Niger and Congo River systems. Several commercial to sub-commercial gas fields have been discovered and oil shows are present in the South African portion of the basin. Two source rocks have been proven in the basin. These are the Upper Jurassic-Neocomian lacustrine source rocks and the Aptian marine source. In addition an older Permian, lacustrine source succession may be present at depth and is well developed in the onshore regions. A marine Turonian-Cenomanian source may also be present, in particular in the deeper sections. Geomorphological work done for the exploration for diamonds onshore indicates that the river was several times larger in the Cretaceous than it is today, providing siginificantly more sand to the system so the potential for deep submarine fan systems (such as found offshore the Congo) is high. At least three sandstone reservoir types have been proven in the Kudu and Ibhubesi gas field. These are the aeolian sandstones known from Kudu which are of outstanding quality, lower quality shallow marine sandstones in Kudu and the fluvial sandstones at Ibhubesi. The details of the petroleum systems operating in this basin are still not clear mainly because of the lack of good biomarker data. A recent study on onshore Kudu equivalents has suggested that the Kudu interval is equivalent in age to the onshore Kalkrand lavas onshore Namibia which are of Early-Middle Jurassic age. If this is the case then it has major implications for the models of the tectonic development and consequently the exploration philosophy offshore Namibia. However our work that involves seismic interpretation, links between the onshore geomorphology and the offshore, biostratigraphy, volcanic geochemistry and potential field does not support this interpretation. New work on the organic geochemistry of the petroleum systems in Namibia and a new seismic programme undertaken by VeritasDGC in conjunction with NAMCOR is aimed at resolving some of the uncertainties involved in exploration in the Orange Basin. New fields are waiting to be discovered in the basin. Roger Swart, NAMCOR (Pty) Ltd, Windhoek, Namibia [email protected]



55 POSTER

Tectonics of the Western Indian Ocean

Bill St. John

Initial breakup of Gondwana, sea floor spreading and appearance of oceanic crust was preceded by continental sag and development of the Late Carboniferous-Early Jurassic Karoo basins. The first oceanic crust appeared in the Middle Jurassic as the Africa-Arabia plate moved northward relative to the India-Seychelles-Madagascar-Australia-Antarctica plate. The north-south separation continued through the Neocomian. A jump in the spread center occurred in earliest Barremian with Antarctica-Australia separating from India-Seychelles-Madagascar. Madagascar began to move away from India-Seychelles via a transform fault along Madagascar’s east coast. The trans-tensional transform evolved into a spread center during the Middle Cretaceous as oceanic crust appeared. The mantle plume-derived volcanic rocks of India’s Deccan Traps first appeared near the Cretaceous-Tertiary boundary. The Seychelles began to separate from India in the early Paleocene. By the close of the Paleocene, a broad expanse of oceanic crust separated the Seychelles and western India and the mantle plume formed an extensive oceanic ridge that would become the Laccadives-Maldives-Mascarene Plateau. The ongoing spread center broke apart the oceanic ridge, beginning in the Eocene and continuing through the Oligocene. North of the spread center, plume activity extended the Laccadives-Maldives to include the Oligocene-age Chagos Archipelago, while south of the spread center, the Mascarene Plateau basalts continued as the Saya de Malha and Nazareth Banks. Plume extrusion continued to the south as the plate moved northward, creating Mauritius Island during the Miocene and Reunion Island during Pliocene-Recent. Bill St. John New Ventures, LLC P. O. Box 185 Vanderpool, Texas 78885 Tel 830-966-5174 Fax 830-966-6147 [email protected]



56 POSTER

Hydrocarbon Prospectivity of the “Pemba Segment”, Tanzania

Keith Skipper Antrim Resources (Tanzania) Limited

The “Pemba Segment” is located offshore Kenya and northern Tanzania and is defined on the basis of regional free air satellite gravity data and reflection seismic data. Three key ingredients for a prolific petroleum system are now recognized in the Pemba Segment, namely, the possibility of a “world class” Upper Cretaceous source rock in the oil window and confirmed by a surface oil seep, the presence of good quality potential reservoir intervals, both in structural and stratigraphic traps, and the presence of large roll-over structures, frequently incorporating “collapsed crest” structures, overlying diapiric features cored by salt or shale. The segment is bounded on the northeast by an area of regional gravity high (NW-SE orientation) offshore Kenya which results from Cenozoic basement inversion and defines the Davie Ridge structural trend. The southern boundary is marked by a similar gravity high which includes the island of Zanzibar. A major NNW-SSE dislocation, as evidenced by reflection seismic data occurs to the north of Zanzibar Island and represents early lateral crustal movements. The total surface area of the Pemba Segment down to the 3,000 m isobath, is in excess of 100,000 km2 with evidence of culminations below both Pemba and Simba on the gravity derivative. The Pemba Segment is composed of a thick succession of Mesozoic and Cenozoic sediments up to 9 km in thickness. The Cenozoic sediments represent the Tertiary Sag Basin. The NE-SW Pemba-Simba structural high trend is the dominant structural feature as evidenced on both regional gravity and seismic data. In Tanzania, this trend is exposed on the island of Pemba. The Tundua oil seep on Pemba Island has been previously correlated to the Upper Cretaceous “hot shales” on the onshore Dar es Salaam platform to the south. An early well (Pemba 5) drilled in 1961 penetrated the Cenozoic and reported live oil shows in the Tertiary. Tertiary source rocks, immature at this location, may be sources for oil generation in the basin lows. Potential oil and gas-prone source rocks occur in the Middle Jurassic, Upper Cretaceous, Paleocene and Eocene. The most significant oil-prone shales occur in the Middle Jurassic, Upper Cretaceous and Eocene sections. Simplistic burial modeling suggests that while the Jurassic shales are likely to be over-mature throughout most of the central and eastern parts of the area, the Upper Cretaceous and Eocene shales are interpreted to lie within the oil window over a wide area including Pemba Island. If maturation projections allow for Jurassic shales to be in the oil window, then prolific hydrocarbon volumes may have been generated in the deep-water areas of the Pemba Segment. The area has good reservoir potential in the Triassic, Middle Jurassic, Lower Cretaceous, Paleocene, Eocene and Oligocene. Potential reservoirs are mainly sandstones, including resedimented facies, although carbonates do occur in the Middle Jurassic and Eocene. Most

(Continued)



57

Skipper pg2. potential reservoirs are overlain by thick claystones and shales, which provide good seals both vertically and across faults. At the present time, the extensive anticlinal play on the Pemba-Simba trend is considered to be the most important of the structural plays identified. Two large closures have been mapped within the play fairway at North Pemba and South Pemba (held under the Pemba-Zanzibar Production Sharing Agreement by Antrim at 100% working interest), although all can best be described as leads at this time pending the acquisition of new data to confirm details of the structures. Of these, the North Pemba structure is the most attractive in view of its size, timing of development, location with respect to oil-prone Upper Cretaceous source rocks within the oil window, and proximity to the Pemba Island oil seep. Other features are known to the north of the Antrim licence offshore Kenya. Paleogeomorphic plays (represented as “resedimented facies” in submarine fan plays) predominate in the Lower Tertiary and Upper Cretaceous interval and are primary targets in the deep-water areas. Legacy seismic data, acquired before the mid 1990’s, is frequently inadequate to map the perceived geological potential due to shallow “penetration”. However, reprocessing of these data has revealed diapiric and inversion phenomena on the Antrim licence as recently reported in the Pemba Segment by other workers. This diapiric activity is thought to be related either to lutokinesis or the mobility of Jurassic aged salt (halokinesis), known to characterize other basins along the East African margin (Mandawa, Majunga, Lamu?). The acquisition of modern seismic data planned for 2003-2004 will lead to a greater appreciation of the structural style and hydrocarbon trap potential on the Antrim licence. This Pemba Segment is worthy of additional evaluation and may offer the potential for significant hydrocarbon (oil) accumulations. Recent leasing and entry activities by major players, in particular Shell and Woodside, indicate an exciting period of frontier exploration lies ahead. Keith Skipper, Antrim Resources (Tanzania) Limited, [email protected]



58 POSTER

THE PETROLEUM POTENTIAL OF THE MANDAWA BASIN, ONSHORE SOUTHERN TANZANIA

S. Massay, G. Kibakaya, G. Ngwale; Tanzania Petroleum Development Corporation

The Mandawa basin is a major Jurassic salt depression with excellent source rock potential. It is situated between the metamorphic basement outcrop to the west and the coastal ridge to the east. To the south, it is defined by shallow basement uplift, to the north it has no defined limits due to lack of data. Intracontinental rifting was accompanied by the deposition of continental fluvial and lacustrine sediments of the Permo-Triassic Karroo system within the NE-SW trending rift basins. Early Jurassic rifting with a fault trend suggesting a triple-junction was associated with the break-up of Gondwana and separation of Madagascar from Africa. The southern arm of the junction, the Mandawa basin was formed in a restricted marine setting and infilled with organic-rich anoxic shales and thick evaporates including several hundred metres of salt. Deposition in the Mandawa Salt Basin ceased in Mid- Cretaceous where thick sediments continued to accumulate elsewhere in the coastal basin. The Lower Jurassic Nondwa Evaporites and Mbuo Formation are excellent source rocks with TOC values up to 8.4% (avg 4.7%) and HI of 997. The section is over 1,000 m and consists of type I/III kerogen. VR indicate from immature to overmature for oil. The Mihambia Formation, overlying the Nondwa Evaporites contains similar source rocks with TOC of 4%. Earlier exploration efforts identified basal sandstone reservoir underlying the salt above the metamorphic basement. These sands had log porosity of 12% and were fractured and in Mbuo-1 had oil fluorescence and gas shows (C1 to C4). Abundant hydrocarbon odour and cut with oil extracts from shale cores are documented in BP reports on Mandawa-7. New reservoir was identified in the Bajocian Aalenian section, the Mihambia Formation. In E. Lika-1, 200ft of loose sand with log porosity of 17% to 26% was encountered below Middle Jurassic Unconformity. In Mita G-1 100 ft of basal sands with avg log porosity of 13% were encountered. RFT data indicated permeability of up to 92mD in the basal sands. The well encountered good light oil and strong gas. These shows were logged over 443 ft reservoir. The primary plays are submarine sand fans below the Mid Jurassic unconformity. These are believed to be with shale seals. The older Karroo sandstone is its likely source. Pre-Mid Jurassic structural traps include tilted fault blocks and stratigraphic plays. Others are Cretaceous structural and stratigraphic play associated with salt tectonics and rollover on the down thrown side of the growth fault. The most effective seal in the Mandawa basin is the Nondwa Evaporite. Other extensive regional seals include Mbuo shales, Marls and on the flank of the basin, the Upper Cretaceous shales. S. Massay, Tanzania Petroleum Development Corporation, P.O. Box 5233, Dar es Salaam, Tanzania, [email protected]



59 POSTER

Evidence for multiple oil-prone sources horizons in coastal Tanzania

Chris Matchette-Downes, JEBCO (UK) Limited Abstract. Examination of the biomarkers from a comprehensive suite of oils from wells, onshore and island seeps, and local origin, beach tars reveals that Tanzanian margin is characterised by multiple active sources. Confirmed source ages vary from Tertiary to mid-Jurassic. Many of these sources are rich. The degree of maturity of the oils ranges from 0.6% to in excess of 1.0% Ro. These results are presented in terms of the structural evolution of the continental margin of Tanzania, from the time of the formation of the Indian Ocean and including the ongoing events related to the development of the East Africa Rift System. Kitchens are constrained using Potential Fields data. The results reveal that the Tanzanian margin is considerably more prospective than has been realised. TPDC, Aminex plc, Antrim Energy and GES provided the raw material used for this compilation. Chris Matchette-Downes, JEBCO Seismic (UK) Limited, Old Westminster House, 38 Upper Mulgrave Road, Cheam, Surrey, SM2 7AZ, UK [email protected]



60 POSTER

THE PETROLEUM POTENTIAL OF ROVUMA BASIN

Nelson Ocuane & José Branquinho, National Directorate for Coal and Hydrocarbons, Maputo, Mozambigue

The Rovuma Basin is about 400 km long by 160 km (250 by 100 miles) centered on the Rovuma Delta near the border between Mozambique and Tanzania. The basin is both onshore and offshore. Nearly 30,000 sq. km (12,000 sq. miles) of the Rovuma Basin lies within Mozambique. The highly prospective offshore area of the Rovuma Basin includes outstanding features like the Ibo High horst trend in the south, with mapped structural closure of 1,200 km2 (450 sq miles) and is associated with multiple reservoir objectives within the Karoo Supergroup, Jurassic and Cretaceous. To the north of basin a Tertiary Delta is also present. The water depth ranges from 550 to 770 m. Several other structural and stratigraphic leads have been identified as well as play types that have been conceptualized for the onshore part of the basin. A number of oil and gas seeps have been identified in both the Mozambican and Tanzanian part of the basin, proving active petroleum systems to explore. Few wells have been drilled up to the present date. The Mocimboa-1 onshore well was the only well drilled in the Mozambican part of the basin, by Esso in 1986. Strong gas shows, and possibly condensate in Albian sands were encountered. A total of 5,600 km of 2D seismic was acquired offshore and onshore from the 80`s up to 1998 and 15,000 km aeromagnetic data. Potential source rocks are considered to be present throughout the basin, in the syn-rift and early drift section. Good quality reservoir rocks with high porosity have been identified.

Nelson Ocuane & José Branquinho National Directorate for Coal and Hydrocarbons 285 Samora Machel Avenue, 5th floor flat 10 MAPUTO - MOZAMBIQUE [email protected]



61 POSTER

The South African East Coast: Evidence for an Active Petroleum System within the Tugela Fan,

Durban Basin

V Singh1, D van der Spuy1 and N.R. Cameron2 Petroleum Agency SA1, Global Exploration Services2

The offshore Durban Basin, located on the eastern continental margin of South Africa, developed during the end Jurassic to early Cretaceous break-up of Gondwana. The early Cretaceous was characterised by the movement of the Maurice Ewing Bank (Falklands microplate) from its original position adjacent to the Durban Basin. DSDP wells 330 and 511, located on the Maurice Ewing Bank, intersected thick oil prone source rocks of Kimmeridgian to Aptian age. Identical source rocks are postulated to occur within the Durban Basin in the rift and early drift succession that underlies the Tugela Cone. The hydrocarbon potential of the Durban Basin has been tested by only four wells. Jc-D1 (2000), although classified as a dry well has provided the first evidence of the predicted Petroleum System. Jc-D1 mud gas values indicate a trend of increasing wetness index {(C5/�(C1to C5)} with depth. Anomalies within this maturity curve correspond with thin sandstone units. At the base, the wetness index exceeds 25%. In addition, fluid inclusion studies of Jc-D1 samples reflect bacterial sulphate reduction in the presence of seeping light hydrocarbons. An extract at this interval yielded lightly biodegraded oil. Fluorescence was also observed at this interval. The basal section of the well is characterised by bitumen staining and fluorescence. An extract from this interval yielded light oil derived from a distal marine claystone of Cretaceous to Jurassic boundary age. These results augur well for the future exploration of the large-scale channel and fan systems present in the Tugela Cone of the Durban Basin. V Singh, Petroleum Agency SA, [email protected]



62 POSTER

EAST AFRICA – MADAGASCAR PALEOGEOGRAPHIC EVOLUTION AND SOURCE ROCK DISTRIBUTION

Donald C. Rusk & Robert G. Bertagne

During the Karoo rift phase of East Africa, Carboniferous to late Triassic (in places, early Jurassic) cycles of extensional faulting associated with tectonic subsidence created an extensive network of basins with graben and half-graben configurations, which were generally aligned either NE-SW to NNE-SSW or N-S. Continental clastic deposition, which included organic-rich lacustrine shale, was dominant during this period. A transition phase, the period between the rift and drift phases, occurred during early Jurassic, marked by the end of rift-related faulting and the beginning of thermal subsidence. Subsidence along the future plate margins resulted in widespread deposition of lagoonal to shallow marine evaporites, oil-prone black shale and sandstone. The separation of the Madagascar-India-Antarctica plate from East Africa, the drift phase, took place from middle Jurassic to Aptian along a right-lateral transform system, the Davis Fracture Zone. This movement was accompanied by continued thermal subsidence and expanding marine deposition in the developing peripheral basins. Throughout this phase, in most of the subject basins, there was a consistent depositional increase in shale and oil source characteristics from the landward basin flanks to the slopes and basin centers. During the post-drift phase, from Albian to Eocene, passive margin subsidence associated with mostly marine shale deposits prevailed in all depocenters of the region. Organic-rich (typeII) Cretaceous shale sequences have been identified in several basins. In addition, from middle Jurassic to Eocene, conditions favorable for oil generation were probably enhanced by circulation restriction caused by recurrent transpressional uplift along segments of the Davie Fracture Zone. Donald C. Rusk, Houston Texas, [email protected]



63 POSTER

Occurrence and Distribution of Potential Source Rocks in Western Madagascar David Clark1 & Lalaniriana Rasoanandrianina2

An understanding of the distribution and burial history of source rocks in western Madagascar is necessary to help explain the lack of commercial hydrocarbon discoveries in the onshore area and to assess the potential of deepwater plays in the Mozambique Channel. Four potential source rocks have been identified, namely the lower Sakoa (Late Permian), the basal Middle Sakamena (Early Triassic), the Andafia/Beronono Shale (Late Liassic) and the slope deposits of the Bemaraha Limestone (Middle Jurassic). The Middle Sakamena is the richest and most important source rock followed by the Andafia/Beronono, although much less is known about the quality and distribution of this unit. The Bemaraha is also possibly a good source rock in places but very little is known about the quality of this unit. Additional source rocks have been postulated in the Upper Jurassic and Cretaceous but no evidence has been found to confirm their existence. The lower Sakoa is about 150 m in thickness and comprises a succession of coals (TOC 27-70%) and organic-rich shales (TOC 1-17%) deposited in terrestrial or coastal swamp environments. Individual coal beds vary from 4-10 m in thickness. These sediments occur at outcrop and in shallow boreholes in the Sakoa coalfield, in the southern Morondava Basin, and in isolated half-grabens in the deeper subsurface, elsewhere in Permo-Triassic rift complex. The coalfield sediments are middle to post mature for oil generation, and immature to mature for gas generation. No information is available about the quality and maturity levels of the more deeply buried coals, and there are no known examples of seeps or shows that can be attributed to a Sakoa source. The Middle Sakamena consists of organic-rich shales (TOC 1-6%) deposited in restricted marine environment with a strong input of freshwater algae and terrestrial plant debris. These shales occur in eastern Permo-Triassic rifts of the Morondava Basin, Majunga Basins and also the Ambilobe Basin but they are not developed on the western passive margins of the basins. Oil extracts from the Middle Sakamena match closely with migrated oils found at Bemolanga, Manandaza-1, Maroaboaly-1 and Tsimiroro. The tars and heavy oils occurring at Bemolanga, Maroaboaly and Tsimiroro comprise heavily biodegraded and flushed oils, whereas the Manandaza oil is a light, sweet crude with no evidence of biodegradation or water flushing. The Andafia and Beronono are made up of organic-rich of shales (TOC 2-69%) deposited in a restricted marine environment. These shales are found in the Late Liassic half-grabens of the passive margin of western Madagascar, where they form wedge-shaped bodies. Originally, the shales probably extended and thinned westwards, across the Permo-Triassic rifts, as indicated by remnants preserved today in the Ankara Graben. The shales are widely distributed in the subsurface of the W Morondava and the NW Majunga and Ambilobe Basins and they crop out in the central parts of the Morondava and Majunga Basins, and in the coastal area of the Ambilobe Basin. Outcrop samples from the Ambilobe Basin are late to post mature whereas they are generally immature or early mature in Majunga Basin. Bitumen impregnation is common at outcrop in coastal areas of the Ambilobe and northern Majunga Basins, and subsurface shows of oil and wet gas are common in the Cretaceous sandstones and the Bemaraha Limestone. These shows are tentatively attributed to an Andafia/Beronono source. The Bemaraha source rock comprises dark grey or black, organic-rich (TOC up to 5%), laminated carbonate mudstones deposited in slope and basin-plain environments. These mudstones form a lens up to 300 m in thickness to the W or NW of the Bemaraha carbonate platform. The lens extends N-S across the passive margin of the Morondava Basin and NE-SW through the Majunga and Ambilobe Basins. Subsurface samples from the central Morondava Basin are post-mature for oil generation. 1 Clark Research Limited, 31A Rectory Avenue, High Wycombe, HP13 6HN, Buckinghamshire, UK ([email protected] ) 2 BP 7745, Antananarivo 101, Madagascar ([email protected]).



64 POSTER

West Madagascar continental margin analysis: Crustal classification, regional geologic structure and sedimentary thickness.

Samuel D. LeRoy*1 and Ralph Stone2

1 EarthView Associates, Inc, Houston Texas 2 Consulting geologist, Houston, Texas Evaluation of the deep water Mozambique Channel suggests that the petroliferous Morondava Basin extends 300 km offshore from Madagascar and is a target for future hydrocarbon exploration. New 2-D seismic data combined with regional geology, wells, satellite and shipborne gravity and magnetic data differentiate contrasting crustal types, prospective structures and depositional units offshore western Madagascar. Gravity and bathymetry data differentiate contrasting crustal types offshore western Madagascar. A major gravity maximum over the plateau can best be accommodated by hypothesizing a failed rift zone, filled with probable Triassic and younger sedimentary rocks. The presence of 9-10 km of sedimentary fill across this area is supported by recent seismic imaging. The gravity minima associated with the bathymetric highs of the Davie Ridge are best explained by recognizing that it is a thick sequence of dominantly sedimentary rocks, probably deposited on thinned continental crust bordering the central failed rift. Results:

• The broad deep water plateau between the Davie Ridge and the western Madagascar shelf break is underlain by sedimentary fill as much as 9-10 kilometers thick, in water depths of 1500-2500 meters.

• The bathymetric expression of the Davie Ridge, within the limits of new seismic acquisition, is a younger, post-Upper Cretaceous fold trend forming a discontinuous, but relatively resistant, cuesta near the outboard western edge of the Malagasy sub-plate. In the subsurface, Davie Ridge structures consist of folded and faulted sedimentary section, apparently cored by evaporite and/or shale diapers.

• Seismic, magnetic and gravity data indicate that the Cretaceous volcanic rock sequences present in wells just offshore from the western coast of Madagascar are limited in areal distribution and do not uniformly blanket the area.

• Apparent salt tectonics and salt basins, when restored to their pre-drift positions, lie contiguous with salt basins recognized offshore from Tanzania and Kenya.

• Multiple types of trapping structures observed in the data represent potential targets for oil exploration. In size, structures range from the Davie Ridge trend fold complexes of 25-30 km apparent width to simple dip reversal features on the order of 10-15 km width.

• Reservoir rocks of Jurassic and Cretaceous age are inferred from seismic imaging and regional geology seen in coastal wells.

Samuel D. LeRoy, EarthView Associates, Inc, 12000 Westheimer, Suite320, Houston Texas, 77077 [email protected] 1Ralph Stone, Consulting Geologist, Houston, Texas, [email protected],



65 POSTER

Prioritising exploration leads in Sudan using magnetic alteration seepage signatures recognised in high resolution aeromagnetic data.

Vaughan C. A. Stone, (GETECH), J. Derek Fairhead, (GETECH, Leeds University),and W. Heiko Oterdoom, (Petronas Carigali White Nile (5B) Ltd – formerly of Lundin Sudan BV) Evidence is presented of seep-related magnetic signatures in the Muglad Basin of Southern Sudan indicating the likely proximity of oil accumulations. A coherent low amplitude magnetic aureole is observed to correlate with a known oilfield in the Muglad Basin. Such aureoles are understood to arise as a result of redox and/or bacteriological effects in response to hydrocarbon seeps. Unattributed aureoles in the same region are observed to correlate closely with the margins of structural highs interpreted from the gravity and seismic data. Similar observations in other parts of the world lead us to consider that these aureoles are in all likelihood located closely (subject to seep routes) to hitherto unsuspected hydrocarbon deposits and so provide potentially decisive criteria for prioritising exploration prospects and leads. This micromagnetic technique requires relatively close line spacing, low ground clearance and a high sensitivity specification. It appears that the areal extent and amplitude of a seep-related aureole, rather than being proportional to the field's physical size, are more strongly functions of: (i) seep duration, (ii) seep rate, (iii) timing, (iv) overpressure, (v) water-table conditions and (vi) sub-soil geo/biochemistry. Smaller oil fields therefore should generally be no more difficult to detect by this method than larger fields. Numerous papers spanning the 1940s to 1990s have been published on this subject (e.g. Jenny, Dovovan et al., Machel and Burton etc.) however, little momentum has been gained in recent years for general acceptance of this approach, nor in developing the processing techniques to routinely seek such aureoles. Whilst this has perhaps been a ‘missed opportunity’ for the industry, it is strongly recommended that as world oil output drops and smaller oilfields become economic to exploit, this method should become a standard exploration tool. Vaughan C. A. Stone (GETECH), [email protected]



66 POSTER Salt Tectonics in the Ras Tafelney-Safi Segment of the Moroccan Atlantic margin

Tari, G., Molnar, J. and Thompson, P.

Vanco Energy Company, One Greenway Plaza, Houston, Texas 77046 The large Triassic/Jurassic salt basin offshore Morocco is associated with the early rifting of the Central Atlantic region. The progressive deformation of the vast amount of syn-rift salt created a basin with a large number of salt-related structures. These include a poorly developed raft domain in the upper slope and numerous allochthonous salt structures basinward, such as salt canopies, sheets and tongues. Also, a zone of prominent toe-thrust anticlines developed at the leading edge of the salt basin. The temporal evolution of the salt basin is similar to that of other salt basins, e.g. the Gulf of Mexico. During the Mid-Late Jurassic the thermal subsidence of the Atlantic oceanic crust created a pronounced basinward slope which resulted in the formation of antecedent folds. After a period of relative tectonic quiescence in the Early-Middle Cretaceous, the salt structures were reactivated at the end of the Cretaceous forming several allochthonous salt features. These structures were further enhanced during mid-Tertiary times, partly driven by the inversion of the Atlas Mountains onshore. The most obvious suprasalt exploration targets due to salt tectonics are the large anticlines of the toe-thrust zone. Significantly more complex subsalt traps are associated with the numerous allochthonous salt sheets and canopies. Gabor Tari, Vanco Energy Company, [email protected]



67 POSTER

Benin to Mauritania Petroleum Systems Overview David Johnstone, Alan Collins, Carl Watkins, Peter Ellwood, Chris Veale, Mike Hawkins, Steve Thompson Robertson Research International Limited, Llandudno, North Wales, LL30 1SA A regional petroleum systems analysis has been undertaken covering the shelf and deepwater areas from Benin to Mauritania in northwest Africa. This has involved a synthesis of available biostratigraphic and geochemical data along with production of source, reservoir and play fairway maps. Maturity modelling and an onshore hinterland drainage net study have provided supporting evidence for the source kitchen and reservoir mapping. The petroleum systems formed in the syn- and post-rift sections of the evolving Central Atlantic. Sporadic exploration has taken place over the past century with limited success. The reasons for failure of some wells are variable and include the lack of a coherent seal, biodegradation at higher levels in some areas, and the absence of a mature source rock. The structural history shows a marked Santonian inversion event, which has halted source rock maturation in some areas. However, there are several features of the region, which give cause for a more positive view. There are good quality source rocks in at least 7 stratigraphic levels from the Palaeozoic to the Mesozoic and they span the whole range from immature to gas mature. Limited oil to source correlations prove the existence of at least 2 active source rocks, Albian and Turonian. Reservoirs are present at several stratigraphic levels and the limited public domain data suggests that younger more marine reservoirs are of better quality than syn-rift fluvial-lacustrine ones, which often have reduced porosity and permeability due to quartz overgrowths and authigenic kaolinite. Recent discoveries, in Mauritania appear to have successfully targeted Neogene deepwater sands. Trapping styles do vary, though the presence of salt along the Atlantic margin gives a greater number of possible trapping styles. Along the equatorial margin the proven traps are predominantly structural, related to tilted normal fault blocks (Albian) or reactivated and inverted normal faults (Turonian and Maastrichtian) Integration of the petroleum geological database with reservoir and source rock maps has been used to provide a series of play fairway maps for this region. The number of dry holes indicates that exploration in the region carries considerable risk; one key factor appears to relate to the presence of a mature good quality source rock in this structurally complex region. Further research is required, particularly in the area of geochemistry. Data gaps include oil to source rock correlation, and geothermal information was sparse. Regional depth structure maps also need to be drawn to cover the whole region to further refine the structural history and basin modelling. David Johnstone: Robertson Research International, Tyn-y-coed Site, Llanrhos, Llandudno, North Wales, UK LL30 1SA [email protected]



68 POSTER

Petroleum Play Systems & Hydrocarbon Potential of the Offshore Boujdour Area of North West Africa

Alan Jessop and Al Salman, AA International Petroleum Management Around 15,000 line Km of good quality long offset, 12 second records 2D seismic data were acquired by TGS-NOPEC during the period 2002-2003 in the offshore areas of the Cape Boujdour (or Cap Bojador) basin. An interpretation of the seismic data integrated with available well data provides a picture of the geology of the Boujdour offshore areas through a presentation of a regional breakdown of the major seismic stratigraphic sequences, geological facies and structural habitats of the basin, covering approximately 110,000 sq. Km of offshore shelf to deep marine environments. The Cape Boujdour basin is classified as “Frontier” in terms of relative exploration maturity as only three exploration wells (with oil shows) have been drilled in the shelf areas in 1969-1970. The report delineates a number of likely established petroleum systems ranging from Upper Jurassic to Tertiary in age but most significantly within the Cretaceous. The viability of these systems is discussed in light of available information. Virtually all trap types and styles are represented and found widespread throughout the basin. These are depicted by massive deep water turbidites compacted fan and channel systems (canyons) within the basinal and shelf slope parts, fault controlled structural traps within the shelf edge and slope, anticlinal structures at the foot of the shelf slope areas, carbonate platform “reef accumulation structures” within the Upper Jurassic and a number of stratigraphic traps within the deltaic shelf parts of the Lower Cretaceous of the basin. Further, Tertiary stratigraphic and fault controlled structural traps cannot be excluded. Reservoir types vary from biogenic carbonate shelf deposits within the Jurassic to typical passive margin deposition Cretaceous deepwater marine turbidite fan and massive upwardly compacted channel (canyon) complexes featuring good coincidence with structures, while smaller meander channel sequences and compacted sand lenses within the Lower Cretaceous deltaics are also evident from the data. Some of the deep water fan and channel systems and deltaic sand lens reservoirs show indications of what might be associated anomalous seismic amplitudes. In most neighbouring West African post rift passive margin depositional systems, carbon rich mature oil and gas prone source rocks have been encountered within the Lower and Middle Cretaceous where total organic carbon content might reach 11% and higher. In the basinal parts of Cape Boujdour areas however, no exploration wells have penetrated the large thickness (up to 3000 m) of deepwater marine sediments of the Cretaceous sequences to test for hydrocarbon source, but some anomalous seismic amplitudes appear evident in some of the deep water fan systems that may be indicative of hydrocarbon presence. The likely coincidence of traps, reservoirs and source rocks may yet present ample new exploration opportunities for finding large hydrocarbon reserves in these huge untouched frontier areas. Alan Jessop and Al Salman, AA International Petroleum Management, [email protected] [email protected]



69 POSTER

ELEMENTS OF SUCCESS: GRAPHIC CORRELATION AND QUANTITATIVE BIOSTRATIGRAPHY IN THE NILE DELTA, EGYPT

William N. Krebs*, Energy & Geoscience Institute, Houston, Tx Anthony Gary, Energy & Geoscience Institute, Salt Lake City, UT

The Nile Delta composite standard is a unique paleontological database that was developed at Amoco and donated to the Energy & Geoscience Institute (EGI) by BP in 1999. It consists of nearly 500 extinction events recorded during the last 24 million years, thus providing an average resolution of about 50,000 years during the late Tertiary. Using this database, microfossil occurrences from Nile Delta wells are cross-plotted against absolute geologic time to construct lines of correlation (LOCs). The LOC illustrates the relationship between a rock section and absolute geologic time. It typically consists of oblique line segments that are separated by horizontal segments or terraces. These terraces represent stratigraphic discontinuities such as hiatuses or fault planes. Their length equates to their duration in absolute time. The oblique line segments define graphic-correlation sequences which are characterized by uninterrupted deposition. The steepness of these oblique line segments is directly proportional to the rate of accumulation of the graphic-correlation sequence. The duration of hiatuses and the accumulation rate of sequences can thus be derived from LOCs. In addition, LOCs facilitate correlations in both dip and strike directions. Finally, the LOC is exported to the workstation as a log curve for geologic and seismic integration. In this manner, seismic and geologic data are calibrated to absolute geologic time. When the Upper Tertiary section of the Nile Delta is analyzed by graphic correlation, it reveals at least 10 graphic-correlation sequences separated by depositional hiatuses. These sequences are highly variable in thickness, and hiatuses may merge to eliminate sequences that exist elsewhere. Some hiatuses, such as those during the Messinian, represent widespread unconformities, while those during the Pliocene coincide with regional flooding. These Pliocene flooding events, easily identified by graphic correlation but difficult to detect with seismic data, are gas seals. For example, in the western Nile Delta, stacked channel gas sands are capped and sealed by Pliocene condensed sections which appear as terraces on graphic correlation plots. IPS (Integrated Paleontologic System), an integrated computer application for the quantitative analysis of biostratigraphic data, provides estimates of relative paleowater depth and can define high-order transgressive/regression shifts within graphic-correlation sequences. Seals are identified as condensed sections having deepwater faunas with high abundance and diversity of microfossils, whereas reservoirs are characterized by influxes of shallow water microfossils. Application of both graphic correlation and IPS analysis to the pre-Pliocene section of the Nile Delta will produce detailed paleoenvironmental reconstructions that are well constrained by chronostratigraphy. These results will be valuable in mapping seismic facies for future offshore plays in the Nile Delta. William N. Krebs, Energy & Geoscience Institute, 16000 Memorial Dr.,Suite 245, Houston, TX 77079 [email protected] Anthony Gary, Energy & Geoscience Institute, 423 Wakara Way, Suite 300, Salt Lake City, UT 84108; [email protected]



70 POSTER

GEOCHEMICAL EXPLORATION IN NORTH AFRICA: RECENT SUCCESSES FROM ALGERIA, TUNISIA, AND EGYPT

Dietmar Schumacher* and Daniel Hitzman, Geo-Microbial Technologies, Inc., Ochelata, OK

Detailed geochemical and research studies document that hydrocarbon microseepage from petroleum accumulations is common, is predominantly vertical (with obvious exceptions in some geologic settings), and is dynamic (responds quickly to changes in reservoir conditions). Since microseepage is nearly vertical, the extent of an anomaly at the surface can approximate the productive limits of the reservoir at depth. Furthermore, the detailed pattern of seepage can discriminate between charged and uncharged compartments, and identify areas of by-passed pay.

Results of microbial and soil gas surveys in the deserts of North Africa establish the value of hydrocarbon microseepage data for high-grading basins, plays, and prospects. These surveys were conducted by Geo-Microbial Technologies in the Ghadames basin in Algeria and Tunisia, and in the Western Desert of Egypt. The Algeria survey documented hydrocarbon microseepage to the surface in spite of the presence of 200-400 meters of halite above Triassic reservoirs, and the composition of the migrating hydrocarbons correctly predicted the composition of the reservoired hydrocarbons. Results from the Algeria, Tunisia, and Egypt surveys successfully discriminated prospects on basis of hydrocarbon charge.

Geochemical exploration surveys such as these require close sample spacing and are most effective when results are integrated with subsurface data. The need for such integration cannot be overemphasized. Seismic data will remain unsurpassed for imaging trap and reservoir geometry, but only detailed geochemical surveys can reliably image hydrocarbon microseepage from those same reservoirs. High-resolution microseepage surveys offer a flexible, environmentally friendly, low risk and low cost technology that complements traditional geologic and seismic methods. Properly integrated with other exploration data, their use has led to discovery of new reserves and drilling of fewer dry or marginal wells.

Dietmar Schumacher, Geo-Microbial Technologies, Inc, Box 132, Ochelata, OK 74051 [email protected]



71 POSTER

Sequence stratigraphy, structural evolution and petroleum systems in the Ghadames Basin, Libya

DARDOUR, A. M., BOOTE, D. R. D., BAIRD, A. W. and WIGLEY, P. School of Earth Sciences & Geography, Kingston University,UK.

The Ghadames Basin of northwest Libya, although smaller and less prolific than in eastern Algeria, is a major hydrocarbon province with a total of more than 600MMbbls of oil within Paleozoic reservoirs.

Borehole data and regional 2D seismic lines have been used to establish the Paleozoic

and Mesozoic sequence stratigraphy of the Basin. Data from adjacent areas have been used to constrain the Late Mesozoic and Tertiary history of the basin. Sequence diagrams have been constructed and analysed to quantify the uplift and erosional histories of the major Palaeozoic unconformities in the basin.

We have constructed (a) isopach maps of the sequences in the basin and (b) “restored”

isopach maps of the sequences, prior to local erosion. A series of maps has been drawn to show the burial history of the Silurian Tanezzuft Shale which is the main source rock in the basin. Simple basin modelling of the few wells in the basin that contain maturity data has been used to establish the onset of maturity and migration of oil from the source rock.

The palaeobathymetry of the basin throughout its complex evolution has been

considered and used to construct a series of maps showing the subsidence and uplift history of the Upper Silurian Acacus Sandstone, the main reservoir horizon in the basin. This has facilitated an analysis of hydrocarbon migration pathways in the basin, assuming that oil migration has been driven by gravity, an assumption which is tested by considering the distribution of hydrocarbons throughout the basin. DARDOUR, A. M, Kingston University, UK School of Earth Sciences & Geography, Kingston University, Kingston upon Thames, Surrey KT1 2EE, UK. [email protected]



72 POSTER

ALGERIA'S DEEP WATER MARGIN: AN UNEXPLORED FRONTIER BASIN

Michael J. Cope Reservoir Services, WesternGeco, Gatwick, United Kingdom

The Algerian deep-water margin offers one of the few remaining unexplored frontiers around Africa. The entire continental shelf is covered by some 9100 km of new 2D seismic survey, designed to image below the widespread Messinian salt layer and identify prospective structures in the underlying Miocene basins and pre-Miocene section. The principal reservoir targets are Upper to Middle Miocene deep-water facies sandstones known from the Ain Zeft and Tliouanet oil discoveries in the onshore Chelif Basin and present in the Habibas-1 offshore exploration well. Secondary targets include deeper Paleogene to Cretaceous carbonates in the deformed pre-Miocene section and Pliocene sandstones in the post-salt section. Primary source potential is in Miocene shales, locally occurring as the Upper Miocene Tripolis Marls which show up to 3 % TOC content. More regionally the Middle Miocene Alcanar Marls are also a known source rock in the Valencia Basin. Developed offshore these formations would be buried to optimum oil window levels of maturity. Secondary source potential is recognized in the Turonian-Cenomanian shales developed throughout northern Algeria. The Messinian evaporite layer provides a regional seal to any Miocene petroleum system, but intra-formational seals are probably effective at all stratigraphic levels. In circumstances of salt-withdrawal it is possible to breach the Messinian seal and allow hydrocarbons to migrate into the shallow Pliocene section. Amplitude anomalies at this level conformable with trap geometries indicate the likelihood of effective hydrocarbon charge. A variety of trapping styles have been identified including Miocene and Pliocene drape anticlines, pinch-outs and truncations, and pre-Miocene anticlines and fault blocks. A number of significant sized leads with multi-target potential can be illustrated from the seismic data. Michael J. Cope, Reservoir Services, WesternGeco, Schlumberger House, Buckingham Gate Gatwick RH6 0NZ, United Kingdom, [email protected]

africa03 abstracts

Documents