Article

Play fairways of the Gulf of Guinea transform margin

November 2013
Geological Society London Special Publications 207(1):131-150

November 2013
207(1):131-150

DOI:10.1144/GSL.SP.2003.207.7

Authors:

Duncan Macgregor

Independent

Gerrard Spear

University of Plymouth

The margin between Côte d’Ivoire and the Niger Delta is a region with a common structural history, this being reflected in similarities in the stratigraphic response and play fairways identified across the region. There has been significant exploration on the narrow shelf characterizing the margin, resulting in a series of modest oil and gas discoveries. It is shown in this paper that many of the aspects of the plays in the unexplored deep-water regions of the margin are considerably more favourable to the development of giant fields than those on the shelf. This play-fairway review is based on the integration of existing publications with focused studies of multiclient 3-D seismic data over a number of areas. Play fairways are classified by seismic sequence and trap type, with an analysis of each undertaken. The most attractive deep-water play types are: (1) anticlinal traps involving late syn-transform (Apto-Albian) and early post-transform (Late Cretaceous) reservoirs, (2) combination traps involving ponded turbidites on the shoreward flanks of these highs, and (3) stratigraphic traps associated with large Late Cretaceous submarine fan complexes. The anticlinal play is associated with the terminations of the St Paul and Romanche fracture zones, with the more recent structuring generally associated with the latter. 3-D imaging and amplitude mapping is critical to prospect delineation, particularly for the combination and stratigraphic plays. Active kitchens are evidenced involving Early and Late Cretaceous source rocks in the Côte d’Ivoire and western Ghana to Nigeria segments of the region, which are consequently upgraded. Considerable volumetric potential is indicated that promises to make the region one of significant new exploration activity in coming years.

3D seismic analysis of Cenozoic slope deposits and fluid-flow phenomena along the Nigerian Transform Margin

Article

Full-text available

Dec 2023

3D seismic data provide new insights on ∼ 2 km thick Cenozoic post-transform slope sediments and fluid-flow phenomena along the Nigerian Transform Margin. The study documents large-scale mass-transport deposits (MTDs), deep-water channels, sediment waves, and a range of fluid flow phenomena such as pockmarks, pipes, seabed mound and gas-hydrates. They are observed from Pliocene-aged sediments and distributed above structural highs, regional faults and active and relic deep-water channels in the eastern part of the area, closest to the Niger Delta cone. The fluid flow features are interpreted to be indicative of an active petroleum system in the deeper subsurface, and from fluid migration along planes of deep-seated faults. MTDs are mapped at multiple levels and the volume of failed sediments increased through time within the western part of the study area. The repeated and increased volume of MTDs in the area is attributed to an increased rate of sedimentation through time and slope gradient during the late Cenozoic. The presence of repeated MTDs and fluid flow phenomena on the Nigerian Transform Margin has implications for installations of offshore facilities as they constitute potential geohazards. The study also documents, for the first time, polygonal fault systems offshore Nigeria.

3D SEISMIC ANALYSIS OF CENOZOIC SLOPE DEPOSITS AND FLUID FLOW PHENOMENA ALONG THE NIGERIAN TRANSFORM MARGIN

Preprint

Jan 2023

High-resolution 3D seismic data covering an area of 2,845 km2 provide new insights on slope deposits and fluid-flow phenomena along the Nigerian Transform Margin, focusing on the ~ 2 km thick Cenozoic post-transform succession. The study documents large-scale mass-transport complexes, deep-water channel complexes, sediment waves, and a wide range of fluid flow phenomena. The focused fluid flow phenomena include pockmarks, vertical pipes, seabed mounds and gas-hydrate related bottom simulating reflections. They are observed from Pliocene-aged sediments and distributed above structural highs, regional faults and active and relic deep-water channels in the eastern part of the study area, closest to the Niger Delta cone. The identified fluid flow features could be indicative of an active petroleum system in the deeper subsurface, and fluids could have migrated along planes of deep-seated, regional faults. The mass- transport deposits are mapped at multiple levels and the volume of failed sediments increased through time such that they constitute very significant portion of the entire stratigraphic succession (up to 25%) within the western part of the study area. The repeated and increased volume of mass transport deposit in the area is attributed to increased rate of sedimentation through time, slope gradient and probably increasing amplitude of sea level change during the late Cenozoic. The presence of repeated mass-transport deposits and fluid flow phenomena on the Nigeria Transform Margin has implications for installations of offshore facilities as they constitute potential geohazards. The study documents, for the first time, polygonal fault systems offshore Nigeria, adding to the global inventory of polygonally-faulted claystones, and suggesting a more oceanic dominated mudstone sedimentation than nearer the Niger Delta.

Sedimentation, depositional environments, and hydrocarbon potential of the Maastrichtian-Paleocene Araromi Formation, eastern Dahomey (Benin) Basin, southwestern Nigeria

Article

Full-text available

Aug 2021

The Cretaceous sediments in southwestern Nigeria are host to one of the largest bitumen deposits in the world. In the current paper, an integrated study on sedimentology, palynology, and applied petroleum geochemistry of the Maastrichtian-Paleocene Araromi Formation was used to determine the depositional environments and hydrocarbon potentials of the formation on the eastern Dahomey Basin. Four sedimentary lithofacies were identified from core samples, namely, lower limestone (F 1 ); medium to coarse-grained sandstone (F 2 ); lower loosely consolidated sandstone (F 3 ); and shale and siltstone (F 4 ). Sedimentation in the eastern Dahomey Basin occurred mainly in fluvial and shallow-marine (shelf) environments. The palynological assemblages of the Araromi Formation reflect deposition in coastal through brackish water to shallow shelf environment with periods of localized wind-induced storms. The shale and siltstone samples of the Araromi Formation are characterized by total organic carbon (TOC) values of up to 2.50 wt % and S 2 (hydrocarbon-generating potential) values ranging from 0.26 to 0.70 mgHC/g rock, indicating poor source rocks. Shales show poor quality and thermally immature organic matter at shallow depth and could neither have generated liquid hydrocarbon nor contributed to the heavy oil occurrence on the bitumen and tar-sand belt of eastern Dahomey (Benin) Basin.

Exploratory plays of the Foz do Amazonas Basin, NW portion, in deep and ultra-deep waters, Brazilian Equatorial Margin

Article

Jul 2021
J S AM EARTH SCI

A petroleum geology study was carried out at Foz do Amazonas Basin northwest portion, a new exploratory frontier basin on the Brazilian Equatorial Margin. Seismic and well data were interpreted to search similar play of some oil discoveries in correlated basins. The study area is in deep/ultra-deep waters, where the influence of the Amazon Cone is less expressive and 90 km east of Zaedyus oil discovery on Guiana-Suriname Basin. There were interpreted four seismic horizons, four chronostratigraphic intervals, two hypothetical petroleum systems, two exploratory Cretaceous plays, and an estimative of the source rock maturity. The petroleum systems are: Cassiporé/Codó–Limoeiro (late Aptian-Late Cretaceous) and Limoeiro–Limoeiro (Cenomanian/Turonian-Late Cretaceous). The top seismic horizons interpreted are Basement, Albian, Cretaceous, and Middle Miocene, determining four chronostratigraphic intervals: Early Cretaceous, Late Cretaceous, Paleocene to Middle Miocene, and Late Miocene to Recent. There were interpreted two Cretaceous plays: Slope to Plain and Deep/Ultra-Deep Waters. The main source rocks are the shales of the Codó Formation (late Aptian) and Limoeiro Formation (Cenomanian-Turonian). The Codó Formation reaches 10% TOC, has Type I kerogen, excellent potential for oil generation, and thermal maturity. The Limoeiro Formation may have 4,4% TOC, Type II kerogen, and very good petroleum potential. The reservoir rocks are Late Cretaceous Limoeiro Formation turbiditic sandstones. The seal rocks are marine shales from Late Cretaceous Limoeiro Formation. The traps are mainly stratigraphic (pinch-out). The migration routes are mainly lateral or, exceptionally, vertical, where the faults are present. The estimated source rock maturity indicates that at least one of them is below the oil window top. It was concluded that there is a great hydrocarbon exploratory potential to this part of the basin, similar to the discoveries that occurred in the correlated basins of the equatorial margins of Africa and South America.

Evolution of shallow and deep-water deposits included in the regressive drift succession of the Potiguar Basin (Brazilian Equatorial Margin) during the Late Cretaceous to Holocene

Article

Jun 2021
J S AM EARTH SCI

The regressive drift succession (late Campanian–Holocene) corresponds to the last major sedimentary cycle of the Potiguar Basin and includes shallow and deep-water deposits that have potential plays similar to other hydrocarbon discoveries in the Brazilian Equatorial Margin and the African conjugate margin. This study aimed to perform a stratigraphic analysis of regressive drift succession, seeking a better understanding of its evolution and characterization of potential hydrocarbon reservoirs. Based on the interpretations of five exploratory wells and seven seismic lines, this study identified five depositional sequences. In the most proximal regions, sequences 1 and 2 exhibit a dominance of slope facies and sigmoidal/tangential-oblique seismic patterns. In contrast, sequences 3, 4, and 5 show complex sigmoid-oblique seismic patterns. In addition, these last depositional sequences display significant sedimentation of the shelf facies. Sequence 3 marks a remarkable carbonate development in the shelf, whereas a notable siliciclastic input characterizes Sequence 4. Sequence 5, in turn, has its configuration defined by extensive migration of distal deposits toward the proximal portions. Finally, in the distal regions, the five depositional sequences exhibit a preponderance of hemipelagic deposits, with the presence of gravitational flow deposits that occur mainly in the two oldest sequences (1 and 2)

Evolution of shallow and deep-water deposits included in the regressive drift succession of the Potiguar Basin (Brazilian Equatorial Margin) during the Late Cretaceous to Holocene

Preprint

Jun 2021
J S AM EARTH SCI

The regressive drift succession (late Campanian–Holocene) corresponds to the last major sedimentary cycle of the Potiguar Basin and includes shallow and deep-water deposits that have potential plays similar to other hydrocarbon discoveries in the Brazilian Equatorial Margin and the African conjugate margin. This study aimed to perform a stratigraphic analysis of regressive drift succession, seeking a better understanding of its evolution and characterization of potential hydrocarbon reservoirs. Based on the interpretations of five exploratory wells and seven seismic lines, this study identified five depositional sequences. In the most proximal regions, depositional sequences 1 and 2 exhibit a dominance of slope facies and sigmoidal/tangential-oblique seismic patterns. In contrast, depositional sequences 3, 4, and 5 show complex sigmoid-oblique seismic patterns. In addition, these last depositional sequences display significant sedimentation of the shelf facies. Depositional Sequence 3 marks a remarkable carbonate development in the shelf, whereas a notable siliciclastic input characterizes Depositional Sequence 4. Depositional Sequence 5, in turn, has its configuration defined by extensive migration of distal deposits toward the proximal portions. Finally, in the distal regions, the five depositional sequences exhibit a preponderance of hemipelagic deposits, with the presence of gravitational flow deposits that occur mainly in the two oldest sequences (1 and 2).

Geology and hydrocarbon potential of the Nigerian sector of Dahomey Basin

Article

Full-text available

May 2021

This paper is a review of the geology, tectonics and hydrocarbon potential of the Dahomey Basin (Nigeria). The basin is sometimes referred to as an embayment as some authors argue it is not completely separated from the Niger Delta. The lithological continuity between the eastern end of the basin and the western end of the Niger Delta has further contributed to the complexity of formation discrimination and increasing popularity of the confusion in terminology; a problem arising from workers on the basin disagreeing with one another. The Dahomey Basin is part of the strings of basins formed during the opening of the Gulf of Guinea of West Africa in the Cretaceous. The Dahomey Basin was formed from a combination of basement subsidence and block faulting. The initial subsidence resulted in the deposition of thick arenaceous sediments during the Early Cretaceous. An attempt is made here to discuss some of the well-known authors' viewpoints and compare their classification and recommendation system. The petroleum prospect of the basin is subject to debate, although there are proven offshore hydrocarbon fields and enormous onshore deposits of heavy oil and tar sands. The hydrocarbons source calls for critical evaluation, as some authors believe the bituminous deposits are petroleum oil that had crept up-dip from the Niger Delta. Suitable hydrocarbon trapping mechanisms exist within the basin but are most in deep offshore.

Exploratory plays from NW section of foz do amazonas basin deep and ultra-deep waters, brazilian equatorial margin

Article

Dec 2020

Source rock maturity and petroleum generation in the Dahomey Basin SW Nigeria: Insights from geologic and geochemical modelling

Article

Aug 2020
J PETROL SCI ENG

Sedimentology, foraminifera paleoecology, geochemical and petroleum system modelling studies were performed on Cretaceous shales from onshore Orimedu-1 and offshore X (at a water depth of 914 m) wells in the Dahomey Basin, southwestern Nigeria to evaluate their maturity, hydrocarbon generation potentials, and regional significance for petroleum prospectivity. Foraminifera biofacies analysis of the studied shales suggests deposition in dominantly marine environments. The average total organic carbon content (TOC, wt%) and hydrogen index (HI, mgHC/gTOC) for Cenomanian, Turonian, and Coniacian shales in X-well are 1.3, 0.9, 1.3 and 406, 560, 214 respectively. While the Cenomanian and Turonian shales in Orimedu-1 have TOC (wt%) of 1.3 and 1.9, and HI (mgHC/gTOC) of 179 and 357 respectively. Well X source rocks contain predominantly marine-derived Type II kerogen, while Orimedu-1 well contain terrigenous-derived gas prone kerogen. The integration of recently acquired kinetic data from immature source rocks further constraints the prediction of petroleum generation in the study area.1D basin modelling of X well reveals that the Cenomanian Source Rock (CSR) is the most mature bed in the basin having attained the initial 10% transformation ratio (TR) at 87 Ma, got to peak TR (∼50%) at 86 Ma, and reached 83% at 53.6 Ma With a present-day thermal maturity of 0.95% VRo. The Turonian source in well X also attained the initial 10% TR at 87 Ma, got to peak (∼50% TR) at 86 Ma and 69% TR at 50 Ma. These modelled source beds are deeper than the source with 0.62 %VRo used for kinetic study. The observed maturity trend is mostly controlled by the regional erosive events associated with the West African rift system during Santonian and Eocene times. The source rocks in Orimedu-1 are immature. The timing of the generated and expelled hydrocarbons into the Cretaceous petroleum systems of Dahomey Basin is of regional significance with the entire Gulf of Guinea basins because of the similar evolution and sedimentation history along with recent discoveries and production of hydrocarbon.

Seismic stratigraphic patterns and characterization of deepwater reservoirs of the Mundaú sub-basin, Brazilian Equatorial Margin

Article

Feb 2020
MAR PETROL GEOL

In recent years, the Brazilian Equatorial Margin has drawn attention due to its similarity to areas with new hydrocarbon discoveries in the African conjugated margin, and in French Guiana. However, studies on the tectonic regimes associated with transform margins and their evolution, structures, and petroleum potential are still lacking due to the geological complexity of this region. To address this knowledge gap, research has been done to better understand the geological structures, as well as to identify potential hydrocarbon accumulations in the deepwater Ceará Basin. To achieve this, we performed an integrated interpretation of a large 2D seismic data, new exploratory borehole data, as well as older well data with revised biostratigraphy. This data analysis refines the basin architecture and the Cretaceous-Paleocene tectonic evolution, including implications for hydrocarbon prospectivity in the Ceará Basin deepwater. 2D seismic interpretation was performed using modern concepts of continental break-up. To accomplish this, the transition of continental-oceanic crust was taken into account for restoration of the sediments of the rift stage in the basin. The analysis also identifies potential hydrocarbon accumulations in turbiditic reservoirs and presents new insights about the dimensions of the underlying rift features situated in the continental slope. The results reveal a high potential for drift sequences in deepwater where the Late Albian-Early Cenomanian-Turonian sediments reach thicknesses of approximately 3048–4894 m. Moreover, this research shows evidence of Cretaceous to Paleocene magmatism, indicated by the well-imaged volcanoes and associated sills in the seismic data. This analysis indicates that the Mundaú sub-basin can be classified as a volcanic passive margin that was developed during the oblique dextral separation between South America and Africa. The variety of stratigraphic and structural features developed through the Cretaceous history of the Mundaú sub-basin offers a variety of potential hydrocarbon traps and plays in a number of rift and post-rift sequences.

Insights into the Early Evolution of the Côte d'Ivoire Margin (West Africa)

Article

Full-text available

Mar 2018

A tectono-stratigraphic analysis of a broadband 3D seismic survey over the outer slope of Côte d'Ivoire margin, west Africa, revealed that Cenomanian and younger strata seal well-developed rift fault blocks up to 15 km across. Growth strata indicate that these were formed during rifting that culminated in seafloor spreading in the late Albian, challenging existing plate reconstructions for the opening of the equatorial Atlantic ocean. A previously unrecognized system of volcanic edifices linked at depth to a network of sill complexes has also been identified. These are aligned along a NE–SW trend, concordant with kilometre-wide ridges, interpreted as folds formed by steep, crustal faults with an oblique-slip component. These trends are similar to those of fracture zones in the region and indicate that the Côte d'Ivoire was a transform margin in the late Albian. These results highlight the potential of offshore Côte d'Ivoire for deep-water rift plays with large traps formed by extensional fault blocks together with prospective Albian reservoirs ponded in their hanging walls. In addition, the volcanoes and ridges generated seabed relief along the newly created transform margin, forming confined basins for potential deposition of Turonian and younger turbidites and the generation of stratigraphic traps.

Paleogeographic and structural evolution of northwestern Africa and its Atlantic margins since the early Mesozoic

Article

May 2017
GEOSPHERE

The geological evolution of northwestern Africa and its continental margins is investigated in the light of nine Meso-Cenozoic paleogeological maps, which integrate original minimal extent of sedimentary deposits beyond their present-day erosional limits. Mapping is based on a compilation of published original data on the stratigraphy and depositional environments of sediments, structures, magmatism, and low-temperature thermochonology, as well as on the interpretation of industrial seismic and borehole data. We show that rifting of the equatorial domain propagated eastward from the Central Atlantic between the Valanginian (ca. 140 Ma) and the Aptian (ca. 112 Ma) as an en echelon strike-slip and rift system connected to an inland rift network. This network defines a six-microplate synrift kinematic model for the African continental domain. We document persistent, long-wavelength eroding marginal upwarps that supplied clastic sediments to the offshore margin basins and a large intracratonic basin. The latter acted as a transient sediment reservoir because the products of its erosion were transferred both to the Tethys (to the north) and the Atlantic Ocean. This paired marginal upwarp-intracratonic basin source-to-sink system was perturbed by the growth of the late Paleogene Hoggar hotspot swell that fragmented the intracratonic basins into five residual depocenters. By linking the evolution of the continental margins to that of their African hinterland, this study bears important implications for the interplay of long-wavelength deformation and sediment transfers over paired shield-continental margin systems.

Basin Scale Sand Injection and Extrusion in the Mid/late Miocene of the Northern North Sea - A Result Silica Diagenesis

Conference Paper

Full-text available

Jun 2012

Until recently, all sand body occurrences in most sedimentary basins were thought to be depositional in origin. Improved seismic imaging and integration with well data have revealed peculiar characteristics that are inconsistent with conventional sand deposition. This paper presents one out of many sandstone occurrences that has been formerly interpreted as depositional but recently proven as a product of post-depositional remobilization and injection of sand. Our study area encompasses the Snorre field area in which the Utsira Fm has recently been interpreted as an extruded body of sand (Lseth et.al 2012). Our independent observations are in agreement with their study and extend the concept of large-scale sand extrusion to include overpressures due to silica diagenesis of Opal A/CT over large parts of the northern North Sea Basin. This is the largest scale remobilization/injection complex found within a single basin and similar complexes occur at deeper stratigraphic levels but at smaller scales. In many cases sand injectites constitute significant oilfields, but in the northernmost North Sea, sand injectites occur at such a density that they may have completely invalidated most intra-Tertiary seals, posing challenges to the next phase of exploration in the northern North Sea.

Shale 3D Flow and Interaction With Basement Faults in the Niger Delta Deep‐Water Fold and Thrust Belt

Article

Full-text available

Dec 2023
TECTONICS

Based on a large 3D seismic data set in the deep‐water domain of the Niger Delta, this study challenges previous interpretations involving the occurrence of multiple detachments and extensive thrust flats, illustrating timing and mode of shales flow at the toe of the gravity system. Five units of syn‐kinematic sediments, reaching a maximum thickness of ∼800 m, accumulated in the tectonically subsiding synclines during fold amplification between ∼9.5 and ∼1.4 Ma. The volumes of syn‐kinematic units roughly balance those of the shales accumulated in the thickened cores of WNW trending anticlines. This feature is consistent with folding resulting from buckling controlled by the competence contrast between isopach Cenozoic units and underlying overpressured shales of the Akata Formation. A dense network of NE‐SW striking oblique extensional faults offsets a prominent anticline characterized by a NE‐SW trend (which is almost perpendicular to the regional fold trend). These faults form a narrow, continuous deformation zone extending for tens of kilometers along and beyond the length of the anticline. The faults, rooting within the shales of the Akata Formation, formed since ∼5 Ma and deform the seabed. Displacement distribution suggests mechanical interaction between isolated fault segments within the deformation zone. The latter is interpreted as the shallow expression of a deep‐seated fault zone inherited from the segmented passive margin and marked by gravity and magnetic data. Our results, providing a comprehensive picture of active deformation features and their relationships with deep‐seated faults, shed new light into the modes of interaction between gravity systems and underlying basement structures.

Upper crustal tectono-structural geomorphology inferred from satellite gravity and aeromagnetic anomalies beneath a basement-sedimentary transition region, southwestern, Nigeria

Article

Full-text available

Nov 2020

This study interprets upper-crustal tectono structural geomorphology beneath a basement-sedimentary transition zone in southwestern Nigeria using aeromagnetic and satellite gravity data. The results are enhanced models of the tectono-structural relationships between the sedimentary basin (Dahomey) and its adjoining basement and basin which can guide further research and geological decision-making associated with natural resource mapping and development in the region.

Geochemistry and paleoecology of shales from the Cenomanian-Turonian Afowo formation Dahomey Basin, Nigeria: Implication for provenance and paleoenvironments

Article

May 2020
J AFR EARTH SCI

Cenomanian – Turonian (CT) Afowo shales selected from offshore X, and coastline Orimedu-1 and Ise-2 exploratory wells in the Dahomey Basin, southwestern Nigeria, were analyzed for foraminifera, major oxide and trace elements to evaluate their provenance and paleoenvironments. The hydrocarbon rich calcareous CT shale is about 100m thick in the coastline area and 300m thick in offshore area with abundant of marine planktonic and benthonic foraminifera. Benthonic species were significantly present in the coastline wells suggesting a shallow marine condition probably a neritic to inner shelf environments while abundant deep water Rotaliporid sp. and shallow water fauna heterohelix sp. in X well suggest inner shelf to bathyal (ca. >350 m) depositional environments. SiO2 and Al2O3 are the most abundant oxides of CT shale with average value of 46.4% and 12.7% in X, 57.1% and 15.65% in Orimedu-1 and 55.3% and 13.1% in Ise-2 respectively suggesting high influx of terrigenous and argillaceous sediments at the coastal area. Average Al2O3/TiO2 of 19.2 in X, 17.8 in Orimedu-1 and 19.3 in Ise-2 indicates that the sediments were sourced from intermediate igneous rock. Favorable oxic conditions for chemical weathering is more pronounce in the manganese concentration of 658–937 ppm in Orimedu-1 and 829–838 ppm in Ise-2 than 364–604 ppm in the shales from X well. Their degree of weathering estimated from chemical index of alteration (CIA) averaging 97 in the coastline wells is higher than 61 in X well, thus indicating high degree of oxidation in the depositional environments. Vanadium to nickel ratio ranging from 2.88 to 5.0 in X well suggest mixed marine and terrigenous source under dysoxic to oxic conditions for the shales while 0.48–1.2 values in Orimedu-1 further indicates a prevailing oxidizing condition at the time of deposition. Dysoxic-oxic and moderate deep-water conditions were more favorable in the offshore area and probably a significant paleo-factor for organic matter preservation of CT shales in the basin.

A Review of the Geology and the Petroleum potential of the Cretaceous Tano Basin of Ghana

Article

Full-text available

Dec 2019

This is a review of the geology and the petroleum potential of the Cretaceous Tano Basin of Ghana, one of the coastal sedimentary basins in Ghana. It is located on the West African Transform Margin. It initially evolved as a pull-apart basin and later became modified by wrench faulting in the Cretaceous period. It has been known to have potentials for hydrocarbons, as indicated by oils seeps observed in the late 19th century. The presence of active source rocks deposited in the Albian to Cenomanian as well as the Turonian charges the Upper Cretaceous reservoirs sealed by widespread marine shales, as well as faulted traps and pinch-outs, has spurred exploration efforts. Thus, as expected, commercial discoveries of oil and gas have been made in the Tano Basin which evidently has become a 'hot cake' in deepwater exploration, even though the ultradeep water could show even more exciting hydrocarbon plays.

A review of producing fields inferred to have upslope stratigraphically trapped turbidite reservoirs: Trapping styles (pure and combined), pinch-out formation, and depositional setting

Article

Full-text available

Dec 2019
AAPG BULL

Lawrence Amy

Provenance and Paleoenvironments reconstruction of Sandstones from Onshore Dahomey Basin, Southwestern, Nigeria: Implications for Reservoir Potential

Article

Full-text available

Dec 2022

The aquiferous sandstone units in Daniel-1, Olambe and Yakoyo boreholes located in the onshore part of the eastern Dahomey Basin, Southwestern Nigeria, were investigated through grain size, petrography and geochemical studies to evaluate their provenance, paleoenvironments and the preliminary aquifer or reservoir quality of the sandstones. Average mean, standard deviation (sorting), skewness and kurtosis across the three boreholes ranges from 0.37 mm-1.37 mm, 0.54 mm-0.82 mm, 0.18 mm-0.84 mm and 0.89 mm-2.07 mm respectively suggesting dominance of medium to coarse grain, and moderate to moderately well sorted sandstones. The mineral grain sizes, sorting and sub-angular to sub-rounded shapes indicate a sub-mature texture. Mineralogy reveals average 78 % quartz, 9 % feldspar and 13 % rock fragments typical of sub-arkose to quartz arenites sandstones. Major oxides of SiO2 ranges from 90.70-99.62 %, Al2O3 0.49-3.34 %, Fe2O3 0.07-1.65 %, while other oxides are less than 1.0 % further suggesting dominance of quartz mineral grains. Bivariate plots of Th, La, Sc, Co trace elements further revealed dominance of quartz minerals sourced from felsic granitic igneous rock of a passive margin continental basement. The sub-mature to mature textures and mineralogy coupled with their shallow depths of the sandstones at 130 ft-160 ft are suitable factors that enhances good porosity and permeability in an aquifer or reservoir rock. These are probably the positive attributes favouring the storage and efficient water production of the aquiferous sandstones. They have similar textural and mineralogy features with the Turonian-Coniacian Afowo sandstones reservoir producing oil and gas in the deep subsurface offshore area of the basin and the onshore Tar sand in Nigeria and part of Benin Republic, West Africa.

USING GEOGRAPHIC INFORMATION SYSTEM (GIS) TO DETERMINE THE MOST SUITABLE OIL/GAS PIPELINE ROUTE IN THE TANO BASIN, GHANA. AN INTEGRATION OF SEA FLOOR STUDIES TO HELP SELECT THE LEAST COST PATH.

Thesis

Nov 2020

Pius Boakye Amoateng

Optimum route planning in the marine environment and on the seafloor is a daunting problem that requires analytical techniques and many criteria to be met. Through researches we can identify and compare the different inevitable route planning conditions and through that offer a model of an integrated route planning system using the least cost approach. This study aims to uncover the appropriate and least costly route from the wells in the Erin block of the Tano basin, Ghana to the Atuabo Gas Plant and the Sanzule Gas Plant. Slope and existing pipelines (infrastructure) were considered to be obstacles that needed to be avoided. The study area has a rather gentle slope with some few areas having an undulating surface. Although a straight line from the wells to their various destinations is shorter, the cost involved in constructing a pipeline that can carry the crude oil or gas from the wells to their respective destinations would be more expensive than the least cost path done in this study, because such a straight path may present structures and a geology that may cause damages to possible pipelines. The least cost path was compared to the traditional method of using maps of the area to find the shortest path for a pipeline without having to use GIS to find the least cost path of the area as well as straight line from the various wells to the various destinations. This study integrated the main factors in routing a large-scale pipeline project into a relevant cost surface using similar studies from literature as context and as a guide, which was then able to conduct a least-cost path analysis and produce a connected route. It presents the least cost path from four wells (two oil and two gas wells) to the gas plants. The study concentrated on two different overlays which helped in finding the least cost route for the 4 wells. The least cost path from well 4 passes directly beside the current pipeline demonstrating how accurate the least cost route is.

Meta‐analysis of the long‐term stratigraphic evolution of rifted margin basins: The GeoDyNamical Analysis approach applied to the South Atlantic Ocean

Article

Full-text available

Dec 2022

Models of formation of rifted margins have significantly evolved over the last decades by identifying new styles of crustal thinning and magmatic production. However, the expression of these different processes in the depositional environments of the overlying basins remains to be determined. Using only published data, we integrated the sedimentary evolution of 21 basins of the Equatorial, Central and South segments of the South Atlantic that record various styles of crustal thinning and magmatic production. To compare these basins that underwent rifting at different times, we developed a new type of analysis allowing to evaluate statistically the (dis)similarities in depositional environment trends by normalizing them to the tectonic phases of the basin (syn-rift, transition and post-rift) rather than the stratigraphic or absolute ages: the GeoDyNamical Analysis. We show that the timing of the long-term retrograding mega-sequence driven by lithosphere thinning depends on the deformation style and magma production. Along oblique margins of the Equatorial Segment, deepening initiated during syn-rift because their narrow crustal thinning style favors rapid tectonic subsidence surpassing sediment supply. Along wide margins of the Central Segment, deepening initiated later, at the end of the transition phase, because depth-dependent thinning favors slow tectonic subsidence and late break-up. Along magma-rich margins of the South Segment, deepening initiated during the transition phase, after volcanics stopped filling accommodation created by subsidence. In the Central Segment, evaporites accumulated during the second half of the transition phase, when crustal thinning ceased in the proximal margin and migrated to its distal part. Immediately before and during evaporites accumulation, sediments recorded continental and coastal depositional environments resulting from the limited thermal subsidence in the proximal margin domain. Evaporite deposition lasted until the initiation of retrograding mega-sequence, at the onset of the post-rift phase and the end of crustal thinning in the distal margin.

Mapping the structural configuration of the western Gulf of Guinea using advanced gravity interpretation methods

Article

Dec 2022
Phys Chem Earth

The western Gulf of Guinea has important implications for seismic-hazard estimates of the adjoining sub-Sahara West Africa region because of the presence of four active transform faults, namely the St. Paul, Romanche, Chain and Charcot fault zones. A satellite gravity data analysis was performed over the western Gulf of Guinea to delineate the structural configuration of the area. Initially, the energy spectrum analysis was used to determine regional and residual gravity effects. Further, the advanced techniques such as the tilt angle of the gradient amplitude (TAHG), the improved horizontal tilt angle (ITDX), the enhanced gradient amplitude (EHGA), and the fast sigmoid-based edge detection filter (FSED) were applied to the residual gravimetric anomaly to extract lineaments of the western Gulf of Guinea. The major trend of the detected lineaments has an ENE-WSW direction and depths of the gravity sources range from 3.4 to 13 km corresponding to widespread altered basalt, breccia, serpentinized peridotite and minor gabbro. Our findings closely agree with known information but are also able to confirm the presence of various other structures. Our results thus provide a structural map that helps us to have a better understanding of the tectonic and structural framework of the western Gulf of Guinea.

A Stratigraphic Discuss on the Current Knowledge of the Tano Basin: From Shallow Waters to Deep Waters

Conference Paper

Full-text available

Sep 2022

Hitherto, the Tano Basin, located along the West African Transform Margin (WATM) remains a prolific and the leading petroleum-bearing sedimentary basin in Ghana. Over the years, several attempts have been made to reveal the stratigraphic outlook of the Basin from drilled wells (cores, mud logs, wireline logs and biostratigraphy data) and seismic data. However, with over two hundred well locations drilled in the shallow to deep water regime, there is a crucial need to build on previous stratigraphic presentations and update the stratigraphic knowledge using recent, relevant data and available reports. Thus, this paper reviews the stratigraphy of the Tano Basin from available well data and reports. This review produced a summarized chronostratigraphic framework showing the various lithofacies distributions with the sedimentation periods through geologic time. However, the lithic fill in the Basin is controlled by notable structural configuration, a result of the rifting events which typically gave rise to two major depocenters suites amongst other depocentres. The stratigraphy of the Tano Basin is underlain by Precambrian Basement rocks, followed by sedimentation from the Pre-Aptian to Recent, associated with notable undifferentiated stratigraphic gaps, as either hiatuses or unconformities. The dominant lithofacies are claystone/shales, sandstone, siltstone, conglomerates and carbonates (limestone and dolomites), deposited with respect to the paleobathymetry of the Basin. A more interesting revelation has been the calcarenite sediments encountered at the Cenomanian level and an undifferentiated volcanic/ igneous intrusion within the Aptian to Albian interval farther in the deep-water regime. The authors recommend further studies to ascertain the provenance and depositional processes that geologically characterize some of these interesting revelations amongst others to collapse or validate the diverse proposed hypothesis.

FEATURES OF THE STRUCTURE AND OIL AND GAS CONTENT OF THE GUINEA GULF SEDIMENTARY BASIN

Article

Full-text available

Sep 2022

The article deals with the issues of the structure and development of the oil and gas content in the Guinea Gulf sedimentary basin located in the western regions of Africa and the Atlantic Ocean. The features of the basin formations are given that provided a complex structure and often ambiguous correlation of deposits. The factors that led to the development of the main hydrocarbon deposits in the province of the Niger Delta and other regions are identified. It is concluded that it is necessary to continue exploration work in the basin due to the increased prospects for oil and gas potential.

Paleoenvironment and paleoclimate of the Late Cretaceous Ise Formation, Eastern Dahomey Basin.

Preprint

Full-text available

Mar 2022

The paleoenvironment and paleoclimate of the Ise Formation remain poorly understood, despite its importance for the Late Cretaceous paleoenvironment and geology of the Dahomey Basin and Africa in general. This is due to the paucity of outcrops and drilled samples of the formation. This study investigates the paleoenvironmental and paleoclimatic setting of the Ise Formation through sedimentological and palynological analyses of fifty sediment samples. The sediments were recovered from four exposed sections of the formation, three of which are recently exposed, in the Eastern Dahomey Basin, SW Nigeria. The examined sediments are largely coarse-grained, poorly sorted, gravelly-sand to sandy-gravels, and are dominated by spores and pollens. The Laevigatosporites sp. and the Sapotaceae sp. are the most abundant spores and pollens in the sediments while minor occurrences of Monocolpites sp., Cyathidites minor, Retitricolporites sp., and Spinizonocolpites sp. were recovered. Concentricytes sp. was the only algae recovered, while microforaminiferal wall lining was the only foraminifera recovered. Textural properties of the sediments indicate textural immaturity and proximity to the source area. The occurrence of Monocolite sp., Foveotriletes margaritae, Echitriporites trianguliforms, Cyathidites, and Longapertites sp. indicate a Maastrichtian to Early Paleocene age for the Ise Formation. The vegetation cover was mainly mangrove with palms, shrubs, and forests, while the environment of deposition was swamp to marginal nearshore. A dominant mild to warm tropical climate during the deposition of the formation was inferred based on the recovery of Retitricolporites sp., Monocolpites marginatus, Sapotaceae sp., and Spinozonocolpites sp. from the samples. These conclusions support the hypothesis of a regional shallow environment setting during the Maastrichtian and a warm regional climate in Africa during the Early Paleocene.

Depositional Model for Turbidite Lobes in Complex Slope Settings Along Transform Margins: The Motta San Giovanni Formation (Miocene—Calabria, Italy)

Article

Full-text available

Nov 2021

Intraslope lobes, or perched lobes, are attracting scientific interest because they represent a key archive between the shelf and the deep basin plain when looking at a complete source-to-sink depositional system across a continental margin and can form significant offshore hydrocarbon plays. In this study, we focus on a detailed characterization of intraslope lobes of the Motta San Giovanni Formation (Miocene, Calabria), which were deposited in confined conditions during the Miocene along a transform margin. We determine the typical facies associations and stratigraphic architecture of these intraslope lobes using a 3D digital outcrop model resulting from a combined Uncrewed Aerial Vehicle (UAV) and walking acquisition, together with sedimentological logging and geological mapping. We propose recognition criteria for the identification of intraslope lobes, including facies and geometries, integrated within a depositional model. A comparison with other well-known intraslope and confined lobes, as well as basin floor lobes, is finally discussed, to highlight the peculiarities of intraslope lobes deposited along transform margins. The diagnostic depositional model for these types of intraslope lobes includes four main stages of evolution: 1) Stage 1—isolated detached lobe precursor in response to a flushed hydraulic jump, 2) Stage 2—prograding and aggrading lobe elements associated with a relatively stable and submerged hydraulic jump in the Channel-Lobe Transition Zone (CLTZ), 3) Stage 3—major bypass associated with lateral accretion and local aggradation interpreted as a renewal of a normal hydraulic jump in the CTLZ, and 4) Stage 4—erosion and bypass then abandonment. The development of intraslope lobes along active transform margins is allowed by tectonically induced slope segmentation and local confinement. In such a context, flow stripping and overspill processes occurred. Resulting lobes appear to be particularly small and relatively thin sandy deposits. They could be considered end-member in a lobe classification based on the Net-to-Gross content (high) and taking into account their thickness/width ratio (intermediate between 10:1 and 100:1 lines).

Basement Structure Offshore Dahomey Basin, Nigeria: New Insights from Aeromagnetic and 3D Seismic Interpretation

Conference Paper

Full-text available

Sep 2021

Exploration plays of the Potiguar Basin in deep and ultra-deep water, Brazilian Equatorial Margin

Article

Jul 2021
J S AM EARTH SCI

Following the discoveries on West Africa conjugated margin since 2007 (Jubilee, Tweneboa, Venus, Mercury, and other fields) and in the Guiana-Suriname Basin since 2011 (Zaedyus field and Liza Complex/Exxon's Stabroek block), the Potiguar Basin deep/ultra-deep waters represents one of the most important exploratory frontier basins, like others on the Brazilian Equatorial Margin. Aiming to apply similar plays of these discoveries, was performed a 2D seismic interpretation supported by well data in deep/ultra-deep waters of the Potiguar Basin. Thus, based on the seismic horizons corresponding to the main tectono-sedimentary events, five chronostratigraphic intervals were interpreted: U1, U2, U3, U4, and U5. Moreover, there were interpreted three petroleum systems: Pendência-Pescada (!), Alagamar–Alagamar (!) and Quebradas-Ubarana (.). Pendência Formation source rocks are late Berriasian-early Barremian lacustrine shales. Alagamar Formation source rocks are Aptian-Albian evaporitic marine shales and marls of the Galinhos Member and Ponta do Tubarão Beds. Quebradas Formation source rocks are Cenomanian-Turonian deep water marine shales. Among these source rocks, the best is Galinhos Member/Ponta do Tubarão Beds, reaching up to 21% TOC, Type I, II, and III kerogens, excellent petroleum potential for oil/gas generation, and with thermal maturity at the studied area. Quebradas Formation, which is correlated to Cenomanian-Turonian source rocks of the West Africa Equatorial Margin and Guyana-Suriname basins, reaches up 6% TOC, Type I/II kerogen, very good to excellent petroleum potential for oil generation, and adequate thermal maturity at the studied area. Three plays were interpreted: Strike-slip, Anticlinal, and Late Cretaceous Turbidite, whose water-depth varies from 1,500 m to 1,900 m. Considering the sea bottom as a datum, reservoir rocks (fluvio-deltaic and turbidites sandstones) are about 3,050 m to 5,800 m, and source rocks nearly 3,500 m to 6,500 m. Seal rocks could be Late Cretaceous marine shales. Traps are mainly stratigraphic (pinch-out). Migration pathways are mainly lateral (Late Cretaceous Turbidite Play) or also vertical through transtensive faults (Strike-slip and Anticlinal plays). The oil window top estimated depth based on well geochemical profiles is about 2,600 m below the sea bottom. Besides that, studies in West Africa Equatorial Margin basins state the oil window top occurs approximately at 2700 m below the sea bottom. Therefore, all the source rocks to the three interpreted plays are below the oil and/or gas window top. In such a way, the studied area in deep/ultradeep waters of PB has great exploration potential for both oil and/or gas.

Airborne magnetic and radiometric mapping for litho-structural settings and its significance for bitumen mineralization over Agbabu bitumen-belt southwestern Nigeria

Article

Apr 2021
J AFR EARTH SCI

Abstarct Interpretation of the aeromagnetic and radiometric data over the Agbabu bitumen-belt reflects the litho-structural features affecting the area and its significance over bitumen mineralization. The orientations of lineaments from magnetic images are predominantly ENE-WSW/W-E. Magnetic sources from Euler and SPI depth estimations compare reasonably well and range from 76m to 1395m and 217m to 731m respectively. The shallow depths coincide with the depth at which bitumen deposit was detected in geological boreholes within Agbabu and Ilubirin. This suggests that the bitumen mineralization is structurally controlled and hosted by shallow sources. Radiometric maps have been used to delineate the boundaries of lithologies, especially basement-sedimentary boundaries and the rise of the basement. It appears that the key factor influencing the distribution of bitumen deposits is the ENE-WSW/W-E trend corridor, lithological boundaries, and basement rise. These results will provide a valuable framework for guiding further research and bitumen mineral exploration within the study area.

The Barreirinhas Basin internal architecture and the evidence of transform movements along the Romanche Fracture Zone, Brazilian Equatorial Margin

Article

Nov 2020
J S AM EARTH SCI

The Barreirinhas Basin, located in the central part of the Brazilian Equatorial Margin, was originated by Pangea breakup during Early Cretaceous time. The Romanche Fracture Zone played an essential role during the entire tectono-stratigraphic evolution of the Barreirinhas Basin. This fracture zone divided the basin in two sub-basins to the south and north with distinct structural style printed on the basin internal geometry. This study is aimed to investigate how the tectonic and sedimentary evolution in the onshore, shallow and deep-water Barreirinhas Basin, were influenced by the Romanche Fracture Zone. Eight 2D seismic sections, subjected to seismic attributes to enhance the seismic stratigraphic horizons and structural features, and supported by five well profiles, allowed analyzing the basin infill, major faults, and the spatial relationship with the fracture zone. The basin evolution and the tectono-stratigraphic architecture are marked by structures from rift to drift stages. The rift sequences are composed of four seismic units (U1-U4) delimited on top by the horizon R4. The sag and drift sequences are composed of six seismic units (U5-U10) delimited between horizons R4-R10. The structural architectures are dominated by transtensional regimes, such as negative flower faults, tilted blocks, and wipeout zones, whereas transpressional tectonics is also present by reverse faults and positive flowers, which are fingerprints of Romanche Fracture Zone. Especially in the southern sub-basin, the transform tectonic activity deformed the entire basin from Aptian to Holocene. These structures correspond to those in Africa conjugate basins, where recurrent dextral strike-slip plate motions caused transtensional and transpressional deformations in the sedi-mentary pile since separation of South America and Africa. Asymmetric basin architecture, intensity and asyn-chrony of tectonic regimes distinguish the Atlantic Equatorial basins.

INTERNATIONAL JOURNAL FOR INNOVATIVE RESEARCH IN MULTIDISCIPLINARY FIELD HYDROCARBON EXPLORATIVE STUDY OF THE BAHIA FIELD, BLOCK JAGO-A, OFFSHORE, COTE D'VOIRE, WEST AFRICA. CHIGOZIE ABRAHAM OKAFOR 1 . AZUBUIKE-IJOMAH, KELECHI

Article

Full-text available

Feb 2017

The Bahia field was discovered by Phillips Petroleum in 1981 through the test of the Bahia structure with well JAGO-A. Integration of detailed 3D seismic interpretation, composite log and other well information has been carried out in this study to unravel the potential complexities relating to time-depth conversion, size of the hydrocarbon pool and fluid types associated with the Albian reservoir. Key Words: Offshore, Reservoir, Seismic, Albian.

Potential Source Rock of Albian of the Benin Coastal Sedimentary Basin.

Article

Jan 2018

Long-term evolution of the West African Transform margin: Estimates of denudation from Benin using apatite thermochronology.

Article

Sep 2018

The Benin continental margin was formed during the breakup of Gondwana through oblique rifting along transform faults. The evolution of topography following breakup directly affects the evolution of sedimentary basins, which has major implications for hydrocarbon exploration in the region. Quantitative constraints on erosion across Benin are limited to the Cenozoic, based on analysis of dissected lateritic palaeolandscapes. To resolve the Mesozoic erosion history, we have obtained apatite fission-track and single-grain (U–Th–Sm)/He data from 18 samples collected across a 600 km long transect through Benin. We invert these data, including available geological and geomorphological constraints, to obtain time–temperature paths, which are used to estimate magnitudes of denudation over the last 200 myr. Our study suggests that denudation was focused over a c. 300 km long seaward sloping limb of the marginal upwarp and at the southern margin of the interior Iullemmeden Basin from 140 to 100 Ma with lower magnitudes of denudation characterizing the continental interior and post-Cretaceous evolution of the margin. Models are consistent with modest burial ( c. 1 km) of the Iullemmeden Basin between 120 and 85 Ma, and of the continental margin between 85 and 45 Ma. By the Eocene the first-order relief of Benin had developed, with regional erosion rates <20 m Ma ⁻¹ since then. Supplementary information: Full details of the analytical data and modelling results, including the various constraints, and further data on denudation and burial magnitudes and rates are available at https://doi.org/10.6084/m9.figshare.c.4220804

Thrusting in oceanic crust during continental drift offshore Niger Delta, equatorial Africa

Article

Full-text available

Feb 2009

Eugene Briggs

Cenozoic sediment budget of West Africa and the Niger delta

Article

Full-text available

Mar 2018
BASIN RES

Long-term (106-7 yr) clastic sedimentary fluxes to the ocean provide first-order constraints on the response of continental surfaces to both tectonic and climatic forcing as well as the supply that builds the stratigraphic record. Here we use the dated and regionally correlated relict lateritic landforms preserved over Sub-Saharan West Africa to map and quantify regional denudation as well as the export of main catchments for 3 time intervals (45-24, 24-11 and 11-0 Ma). At the scale of West Africa, denudation rates are low (~7 m Myr−1) and total clastic export rate represents 18.5 x 103 km3 Myr−1. Export rate variations among the different drainage groups depend on the drainage area and, more importantly, rock uplift. Denuded volumes and offshore accumulations are of the same magnitude, with a noticeably balanced budget between the Niger River delta and its catchment. This supports the establishment of the modern Niger catchment before 29 Ma, which then provided sufficient clastic material to the Niger delta by mainly collecting the erosion products of the Hoggar hotspot swell. Accumulations on the remaining Equatorial Atlantic margin of Africa suggest an apparent export deficit but the sediment budget is complicated by the low resolution of the offshore data and potential lateral sediment supply from the Niger delta. Further distortion of the depositional record by intracontinental transient storage and lateral input or destabilization of sediments along the margin have been identified in several locations, prompting caution when deducing continental denudation rates from accumulation only. see https://onlinelibrary.wiley.com/journal/13652117 https://www.altmetric.com/details/22346205

Petroleum systems asymmetry across the South Atlantic Equatorial Margins

Article

Mar 2016

We describe an examination of two lines of evidence, tectono-structural evolution and hydrocarbon geochemistry, of asymmetric opening of the Atlantic Equatorial Margin. Our structural mapping used compilations of geophysical data and a review of both published literature and oil company public presentations. Geochemically, we accessed regional non-exclusive oil studies of the conjugate margins of Africa and South America, plus considerable published material. A group of non-exclusive oils was refined to 286, which clustered into five families, all represented along the NE Brazil margin but only one along the West African Transform (WAT) margin. Multiple lacustrine-sourced oils were seen around the South Atlantic, including NE Brazil, but a rich, oil-prone lacustrine source was not indicated offshore Ivory Coast and Ghana. Despite minor evidence of mixed source, possibly lacustrine stringers within an alluvial to marine setting, the predominant source is marine Cretaceous (Cenomanian–Turonian and possibly Albian). We find that opening asymmetry (a) biased the location of lacustrine (Early to mid-Cretaceous prerift to early synrift) source rocks to the NE Brazil margin and (b) locally narrowed the width of the optimal marine (Mid-Late Cretaceous postrift) WAT Margin source kitchens. Burial of the latter has aggravated the risk of late charge from light (condensate and gas) hydrocarbons.

Role of Equatorial Fracture Zones on Fluid Migration across the South Atlantic Margins

Article

Jan 2013

Othniel Likkason

The continental margin basins of Brazil and West Africa share very similar tectono-stratigraphic megasequences that are recognizable in petroliferous basins, as a result of the Late Jurassic-Early Cretaceous rifting of the South Atlantic basins. A number of oil families present along the South Atlantic conjugated margins are composed of genetically related oils of mixed provenance. Motion of tectonic plates and their configurations which depend so much on the nature of the boundaries and their orientations strongly influence fault tectonics within both continents The tectonic evolution of the plates leads to the formation of fracture zones parallel to the direction of plate motion. The Middle Benue Trough of Nigeria and by extension, the whole Benue Trough, is bound by two offshore transform faults (the Chain and the Charcot Fracture Zones). These faults are asymmetric longitudinally with an oblique transverse fault bounding the basin, and have been outlined by the presence of magnetic lineation. Five E-W profiles across the Middle Benue Trough were selected for the application of Werner deconvolution and subjected to harmonic analysis. The magnetic dataset was used in concluding that the Equatorial Fracture Zones (EFZ) in the South Atlantic Ocean extending from South America into the Gulf of Guinea are mainly responsible for long distance migration of marine hydrocarbons from the West Africa margin to the offshore of Brazil.

3D Seismic Stratigraphic Analysis of sedimentation and fluid flow on the Nigeria Transform Margin

Conference Paper

Sep 2015

Niger Delta gravity-driven deformation above the relict Chain and Charcot oceanic fracture zones, Gulf of Guinea: Insights from analogue models

Article

Mar 2015

The Niger Delta is a classic example of a passive margin delta that has gravitationally deformed above an overpressured shale decollement. The outboard Niger Delta clastic wedge, including the Akata Formation overpressured shale decollement, is differentially thickened across relict oceanic basement steps formed at the Chain and Charcot fracture zones. In this study, five analogue models were applied to investigate the effects of a differentially thickened overpressured shale decollement across relict stepped basement on Niger Delta gravity-driven deformation. Gravity-driven delta deformation was simulated by allowing a lobate, layered sandpack to deform by gravity above a ductile polymer. A first series of experiments had a featureless, horizontal basement whereas a second series had differentially thickened polymer above Niger Delta-like basement steps. Two syn-kinematic sedimentation patterns were also tested. Surface strains were analysed using digital image correlation and key models were reconstructed in 3D. All five model deltas spread radially outward and formed plan view arcuate delta top grabens and arcuate delta toe folds. The arcuate structures were segmented by dip-oriented radial grabens and delta toe oblique extensional tear faults, which were formed by along-strike extensional strains during spreading. Basement steps partitioned delta toe gravity spreading into dual, divergent directions. Similarities between the analogue model structures and the Niger Delta strongly suggest a history of outward radial gravity spreading at the Niger Delta. The Niger Delta western lobe has potentially spread downdip more rapidly due to a thicker or more highly overpressured underlying Akata Fm. shale detachment. Faster western lobe spreading may have produced the Niger Delta toe ‘dual lobe’ geometry, perturbed up dip Niger Delta top growth fault patterns, and implies that western lobe toe thrusts have been very active.

Architecture and exploration target areas of the Senegal Basin, West Africa-NC-ND license (http://creativecommons.org/licenses/by-nc-nd/4.0/)

Article

Jun 2024

Shallow Strata Expressions of Leakage and Seepage Structures Associated With Hydrocarbon Migration: a Seismic Analysis on Offshore Barreirinhas Basin, Brazilian Equatorial Margin

Preprint

Full-text available

Apr 2024

The Brazilian Equatorial Margin (BEM) is an oblique-transform segment with counterparts in the Gulf of Guinea on the West Africa Margin, inherited from the Pangea breakup and Atlantic Ocean opening. These areas are exploratory frontiers where recently petroleum systems were found in deep- and ultra-deep waters. The strike-slip Barreirinhas Basin, at the central portion of the BEM, is conjugated with the oil and gas producers Ivory Coast and Tano basins, whereas the Barreirinhas Basin has currently no relevant discovered petroleum reservoirs. This present study aimed to identify and map distribution patterns of leakage and seepage features in shallow strata, indicating potential hydrocarbon migration and accumulation along the offshore Barreirinhas Basin. The investigation used conventional 2D seismic reflection data with additional application of seismic attributes, including RMS amplitude, instantaneous amplitude, instantaneous frequency, and chaos. Diverse hydrocarbon leakage and seepage structures were identified, including faults, gas chimneys, pockmarks, hydrocarbon-derived diagenetic zones, bottom simulating reflectors, and mounds. Regional morphological and stratigraphic structures constrain the zones of fluid leakage and seepage, which indicate potential hydrocarbon migration pathways. In the eastern lower continental slope and continental rise, regional faults and gas chimneys control seep formation. On the central to northern sectors of the continental rise and abyssal plain, several deep-water mounds are linked by large gas chimneys and faults. There are gravitational gliding systems on the western and central portions of the basin, where the extensional domain is characterized by listric faults, negative flower structures, and gas chimneys that produce cold seeps on the outer shelf and upper slope. These structural controls are related to the compressional domain of the lower continental slope and continental rise, where the decollement zone and a series of faults and folds are correlated to pockmarks and deep-water mounds. Near the western compressional domain, igneous intrusions control the development of leaking faults, gas chimneys, bright spots, and pockmarks. These hydrocarbon-derived structures, seeps, and pathways of fluid migration in deep-water indicate potential petroleum systems in the Albian to Turonian-Oligocene tectono-sedimentary sequences in the central sector of the Brazilian Equatorial Margin.

Architecture and exploration target areas of the Senegal Basin, West Africa

Article

Mar 2024

Sequence stratigraphy and organic geochemistry: An integrated approach to understand the anoxic events and paleoenvironmental evolution of the Ceará basin, Brazilian Equatorial margin

Article

Apr 2021
MAR PETROL GEOL

An organic geochemical investigation combined with sequence stratigraphy was performed in the Ceará Basin, an offshore basin located in Northeastern Brazil. The information available from 30 well logs (gamma-ray, resistivity, density), besides geochemical (TOC, and pyrolysis indexes) and isotopic (δ 13 C) data, aided the preparation of a dataset for this study. The application of sequence-stratigraphic methods helped classify and correlate seismic and organic facies. Four key petroleum source-rock units were identified, from the oldest to the youngest: (1) Mundaú Formation-top of the Rift Sequence (Berriasian-Aptian); (2) Paracuru Formation-Breakup Sequence (Aptian-Albian); (3) Itapajé Member of the Ubarana Formation-Continental Drift Sequence (Albian-Turonian), and (4) Uruburetama Member of the Ubarana Formation-Continental Drift Sequence (Turonian-Maastrichtian). The J o u r n a l P r e-p r o o f geochemical characteristics of the Mundaú Formation (high total organic carbon (TOC), hydrogen index (HI), relative hydrocarbon potential (RHP = (S1 + S2)/TOC)) point to a typical transgressive sequence. Six transgressive-regressive (T-R) cycles were recognized in the entire Paracuru Formation. The best geochemical marker is related to the top of the Paracuru Formation. This stratigraphic unit can be correlated to a major anoxic event and is the best source rock of this basin. Evaporitic facies found in this top section, maximum RHP values (anoxic conditions), and maximum flooding surfaces related to transgressive events characterize this interval. Moreover, the wide spatial cover of organic-rich rocks, carbon isotopic data, and the recognition of favorable characteristics for anoxia in other basins of the Equatorial Margin are suggestive of the Aptian-Albian Oceanic Anoxic Event (OAE-1b) occurring in the Ceará Basin. The Ubarana Formation represented by the Uruburetama Member and the Itapajé Member yields the least promising source rocks. However, high TOC values suggest the occurrence of the late Cenomanian-early Turonian Oceanic Anoxic Event (OAE-2), when organic-rich strata started to deposit in deep-water regions. The predominance of a regressive interval in the Uruburetama Member points to oxic or sub-oxic conditions. Additionally, the correlations between the Brazilian Equatorial Margin and its African counterpart, and the organic geochemical characterization allied to the definition of depositional systems for these regions proved to be useful for oil exploration. Legend of the graphical abstract: Flowchart representing the steps of this research. A) Database components. B) Data interpretation. C) Relative hidrocarbom potential (RHP) variations revealing changes in oxic conditions at depth and correlations with gamma-ray (GR) and lithofacies (Facies) stacking patterns. D) Sections showing the results obtained from data interpretation. E) A simplified model for the Paracuru Formation.

Geochemistry, Mineralogy and Petrogenesis of the Vein-Type Barites of Some Portions of the Benue Trough, Nigeria

Article

Nov 2020

Advances in Elemental Spectroscopy Logging: A Cased Hole Application Offshore West Africa

Article

Full-text available

Nov 2017

Rising costs for exploration and developments and more stringent need to secure any additional drop of oil have put operators’ margins under increasing pressure. Coupled with the recent oil price decline, this call for efficiency and diligence to be the main drivers for any formation evaluation and planning for development and production. The reservoirs in Western offshore Africa are so diverse in the settings that two reservoirs hardly show any correlation. The complexity associated with the Rifting of African plate from South American plate has introduced significant geological challenges, adding to even bigger challenges in Petrophysical analysis. The mineralogy is complex; clay characterization is often unsolved. The formation waters are fresh with variable salinity and there is occurrence of thin shale laminations and grain size variations contributing to low resistivity low contrast pay generation. Advanced and fit-to-purpose logging technologies and computational methods are needed for rock quality and potential. Moreover, in some cases the accessibility of the target reservoir is difficult and risky, so that formation evaluation must be performed behind casing.The high definition spectroscopy tool is the latest development in wireline spectroscopy measurements. Its technological advances revolutionize the neutron-induced gamma ray methodology to support robust lithology and saturation interpretation in formations with complex mineralogy and fluid content. The ability to determine both the matrix mineral composition and total organic carbon (TOC) are instrumental to the geoscientist, the petrophysicist, the reservoir engineer, and the completion engineer. In the region, the use of high definition spectroscopy measurement has been pioneered while pursuing better understanding of rock composition and more accurate reservoir models in complex lithology and fresh formation waters with low resistivity contrast. The results are beneficial at the various stages of a field development and provide critical input to the petrophysical reserves estimate.In the example described in this paper, the new technology has proven to be critical to evaluate a complex reservoir system independent of the water salinity and resistivity offshore Gulf of Guinea, even with logging behind casing. A comprehensive set of quality outputs is made available for accurate reservoir quality; the logs data processing is performed within the critical-hours after logging to enable informed decision making.

Tar sand occurrence: Implications on hydrocarbon exploration in the offshore Benin Basin

Article

Mar 2017

The Benin Basin, just like other marginal basins in the Gulf of Guinea, evolved in the Cretaceous following the opening of the Atlantic. These other basins have recorded significant oil and gas discoveries offshore unlike the Benin Basin that has records of only large tar sand deposits onshore. A review of key play elements of the basin is carried out to assess the possible occurrence of oil and gas in its offshore part. The basin holds a high prospect for both oil and gas in the offshore with the oil kitchens probably occurring within the lower to upper Cretaceous sediments. Besides containing shales deposited during the world-wide Turonian anoxic event that could serve as source rock, the Turonian sequences also have shelf to slope deposits, which are likely to be turbidite of deep-water environments. These turbidites could serve as an excellent reservoir in the basin. Several thick shale sequences within the Cretaceous to Tertiary could provide enough seal for hydrocarbons. In addition, unconformity surfaces marked by reflection terminations that are very significant during pre-drift and syn-rift tectono-stratigraphic development of the basin point to existence of stratigraphic traps in the basin. Concentration of these petroleum elements within the Cretaceous sequences suggest that exploration efforts should be geared toward the Cretaceous, particularly the Turonian sequences in the basin.

The Sierra Leone and Liberia Margin : An emergent Deep-water Province

Data

Full-text available

Jun 2016

Advanced logging and analytical methods unlock producibility potential in fresh formation water — A case study from offshore West Africa

Article

May 2016

The sedimentary basins of West Africa encompass a vast diversity of geologic depositional settings, in and from which hydrocarbons are being explored and produced. The siliciclastic rock units can be structurally heterogeneous, the reservoirs distribution and quality is highly variable, and formation waters have changing salinity values. The fresh to very fresh formation water diminishes the contrast to hydrocarbon complicating any salinity-based measurement technique, such as resistivity. As a result, the reservoir potential might be under- or overestimated by conventional methods; hence, an intelligent petrophysical evaluation and a fit-to-purpose solution become essential to enable the most appropriate development and production strategy. As part of an extended portfolio of wireline logging technology, dielectric dispersion measurement is a critical contribution to the logging programs across the region. The advanced measurement provides dielectric permittivity and conductivity at multiple depths of investigation through the use of multiple frequencies, receiver spacing, and polarizations that are adequately fit into an innovative mandrel design. Robust inversion of all measurements enables solving for salinity, invasion profile, water fraction, shallow zone resistivity, and saturation even when it is hard to distinguish oil from freshwater. We have developed a remarkable example of intelligent logging assessment in highly complex reservoir units where the novel dielectric dispersion measurement is combined with high-resolution magnetic resonance for improved formation evaluation and reservoir management. An integrated data analysis workflow enables fast determination of pay zones and movable fluids independently from and to support saturation equation and input parameters setting. Comparison of the results from well testing confirms the improvement in reservoir description with additional advanced logging measurements (at an early stage of reservoir development) into reservoir models. The information provided is vital to guide perforation and completion designs. © 2016 Society of Exploration Geophysicists and American Association of Petroleum Geologists.

The Sierra Leone-Liberia Emerging Deepwater Province, West Africa

Conference Paper

Full-text available

Jun 2009

The offshore West African margin located between Guinea Conakry and Ivory Coast is a frontier area. The neighboring offshore regions of Sierra Leone and Liberia have had only a few exploration wells drilled on the continental shelf. Exploration focused on the classical Aptian-Albian tilted block play that produces in the Baobab, Espoir, Lion, and Tano fields of Ghana and Ivory Coast. The deep-water areas of this steep morphological margin are undrilled, and the details of its history remain largely unknown. The main play in the slope is Upper Cretaceous turbidites, consisting primarily of amalgamated channel-levee complexes, pinching-out towards the steep continental slope in stratigraphic traps. Post-rift Albian and Cenomanian-Turonian shales constitute the main potential source rocks of the deep-water part of the margin. The structure of the margin is the result of Early Cretaceous low-angle extensional tectonics, and gravitational extension and related toe-thrusting associated with Late Cretaceous to Tertiary uplift on the shelf.

Hydrocarbon source rocks in sedimentary basins of continental margins in the Middle-Late Paleozoic

Article

Jul 2014

Alexander. Ivanovich. Konyukhov

The second half of the Paleozoic was marked by amalgamation of large continental blocks. The collision between the Laurentia and Baltica continents in the Devonian culminated in the formation of Laurussia. This event was followed by accretion of the Siberian and Kazakhstan continental blocks after the closure of the Uralian marine basin in the terminal Carboniferous-initial Permian. These processes were responsible for the formation of the Pangea supercontinent at the end of the Permian Period. They were accompanied by climate changes reflected in the alternation of warming and cooling epochs. One of these cooling epochs was terminated by large-scale glaciation of Gondwana at the end of the Carboniferous Period. Nevertheless, the most significant process, which drastically changed the existing paleogeographic situation, was colonization of continents by plants and animals, and, thus, accumulation of coaliferous formations in them. The lacustrine and sea basins also accumulated humic and mixed humic/sapropel organic matter (OM) in addition to pure sapropelic sediments.

Tectonic evolution of the equatorial South Atlantic

Article

Full-text available

Jan 2000

Renato Darros de Matos

The Brazilian and West African Equatorial margins comprise an unique example of a transform margin, characterized by a series of on- and offshore Mesozoic-Cenozoic basins, distributed over 2,200 km along the South Atlantic. Although a multi-stage stretching process evolved throughout the Aptian-Cenomanian, an almost instantaneous Aptian stage was responsible for a wide-spread fracturing of the Equatorial Atlantic. Conventional extensional processes can not explain the kinematics and rift geometry of the Equatorial South Atlantic basins. Accepted pure-shear or simple-shear rift mechanisms, typical of divergent margins, cannot be promptly used in basins generated as a response to major transform motions along a continental-scale plate boundary. The commonly accepted causal processes for rifting, such as passive/active or diffuse/discrete rifting, can not accommodate the South Atlantic Equatorial data set. Even though shearing signatures and pull-apart features are easily recognized throughout the margin, their magnitude and basin architecture varies significantly as a function of the distance from the main transform faults. These factors resulted in significant differences in thermal evolution, tectonic subsidence, facies distribution and uplift history. The tectonic evolution of the sedimentary basins along the Equatorial Atlantic is better understood by considering three stages: pre, syn and post-transform movements. These are related to kinematic and dynamic controls provided by the emplacement of fractured swells as proto mid ocean ridges, followed by the creation of oceanic crust and the onset of transform shearing between Africa and Brazil.

Continental Margin Off Western Africa: Angola to Sierra Leone

Article

Jan 1975
AAPG BULL

Elazar Uchupi K. O. Emery

About 30,750 line-km of geophysical traverses (seismic reflection and refraction, magnetics, and gravity) were made in the Gulf of Guinea and vicinity aboard R/V Atlantis II during 1972 and 1973 as part of the International Decade of Ocean Exploration program. These traverses, supplemented by about 50,000 line-km of previous ones by other ships, provide a basis for mapping and understanding the geologic structure, history, and origin of the region. The deep indentation of the outline of western Africa is paralleled by a similar bend of the Mid-Atlantic Ridge and by the prominent bulge of northeastern Brazil. These sharp bends are the result of left-lateral offsets by many transform faults in a belt of equatorial fracture zones. Some of the fracture zones continue eastward and intersect the entire length of the east-west coast of the Gulf of Guinea and penetrate the continent at the Benue trough or graben. The valleys of the fracture zones have been sites of sediment deposition, whereas the ridges have served as dams that force the sediment to move westward. Where enormous quantities of sediment have been delivered to the ocean by the Niger-Benue Rivers, a large delta has deeply buried the irregular topography of the fracture zones. In this entire belt of fractured ocean floor the structure, physiography, and stratigraphy have been controlled by lateral movement, or translation, of the ocean floor with respect to the continent. In contrast, the regions southeast and northwest of the belt of equatorial fractures have fewer large fracture zones, smoother topography, and simpler sediment wedges. These two regions owe their origin to simple divergence during sea-floor spreading, when new oceanic basement added at the Mid-Atlantic Ridge increased the distances between the African continent, the Mid-Atlantic Ridge, and the American continents. Deposition of sediments along the margins of the originally narrow Atlantic Ocean was dominated early by coarse-grained and largely nonmarine sediments. South of the Gulf of Guinea these deposits were followed by evaporites as products of restricted water circulation in a long narrow arm of the ocean. There was little flow of water across the equator because of the sliding-v lve nature of the region of translation between the two regions of divergence. As spreading continued, the ocean widened, and thick prisms of marine sediments were deposited on the continental margins. Large deltas in western Africa first began at the south, with the now submerged deltas of the Orange and the Congo Rivers being chiefly Mesozoic in age and having no present coastal projection. The Niger delta farther north is mostly Cenozoic in age. Petroleum prospects appear to be far greater in the Niger delta and the region of divergence south of it than in the entire region west of the delta. The favorable continental margin contains thicker sediments, large ancient and modern deltas, and salt and mud diapirs. End_Page 2209------------------------------

Trap styles - a new classification based on sealing surfaces

Article

Jan 1992

A new scheme is proposed in which traps are classified by trapping mechanism. One-seal traps are those in which closed contours exist at the base of the top of the sealing sequence. Poly-seal traps are those in which closed contours do not exist on a single sealing surface (the base of the top seal). A secondary subdivision is by the relationship of the sealing surfaces to the sealing lithologies (e.g., conformable, unconformable, tectonic, or facies change), and a third subdivision is by the sealing sequence itself. The risk of success or failure of the trap is carried entirely by the efficiency of the sealing surfaces, which is determined by the nature of the surfaces and the sealing lithology. -from Authors

Niger delta petroleum systems, Nigeria

Article

Jan 2000

Regional integration of results from conventional exploration geochemistry, structural analysis, and gravity-magnetic data provide a comprehensive new understanding of Niger Delta petroleum systems. Nigeria is the 12th largest producer of crude oil in the world. Daily oil production from the Niger Delta is 2.1 million bbl, and recoverable reserves are estimated to be about 22.5 billion bbl. Historically, structural play types have dominated, although large stratigraphic traps have also been discovered. The basin has matured through one cycle of successful exploration, and future success depends on linking the geology of the shelf and onshore areas to deep-water areas and exploiting new play types in older producing areas. Three petroleum systems are present in the Niger Delta and delta frame: Lower Cretaceous (lacustrine), Upper Cretaceous-lower Paleocene (marine), and Tertiary (deltaic). One biodegraded seep oil from Nigerian tar sands along the northern flank of the Dahomey Embayment has been correlated to Neocomian source rocks in Ise-2 well. A source rock extract and pyrolyzate of the seep are similar to the Bucomazi petroleum system in the Lower Congo Basin. Oil recovered from Paleogene sandstones in Shango-1 well are inferred to be derived from Upper Cretaceous-lower Paleocene source rocks identified in Epiya-1 well, consisting of type II and II-III kerogens. The principal source for oil and gas in the Niger Delta is the Tertiary deltaic petroleum system, consisting of type II, II-III, and III kerogens. On the basis of oils and source rocks, source fades variation characteristic of this system has been regionally mapped in the northwestern part of the delta. Similar trends exist delta-wide and are responsible, along with burial, for controlling the complex distribution of gas and oil across the delta.

Continental margin off western Africa: Angola to Sierra Leone

Article

Jan 1975

Africa's petroleum systems: Four tectonic 'Aces' in the past 600 million years

Article

Nov 2013

We relate the depositional and structural histories of the sedimentary rocks containing Africa's primary petroleum systems to four tectonic intervals, which in the light of their widespread and beneficial consequences we designate as 'Aces'. The Ace of Clubs was the assembly of Gondwana by continental collision and the collapse and erosion of the mountains constructed during that assembly, which generated accommodation space through thermal subsidence over a vast area. Africa's oldest great reservoir rocks accumulated in that space during Cambro-Ordovician times (520-440 Ma). After a short-lived glacial interval, Silurian and Devonian source rocks formed parts of a thick section that was deposited as long-term subsidence continued. The Ace of Diamonds consists of the collision of Baltica with Laurentia at c.380 Ma and the collision between Gondwana and Laurussia at c.310 Ma. It also includes the intracontinental deformation and orogenic collapse associated with the latter event, during the course of which regionally important structures and rifts now containing hydrocarbon-bearing fill were generated. Productive petroleum systems involving older Palaeozoic source rocks are concentrated in the rifts and sedimentary rocks of this phase. The two other aces relate to the plume-dominated break-up of Pangaea. The Aces of Hearts and Spades were the eruption of the Karroo Plume at 183 Ma and the eruption of the Afar Plume at 31 Ma. These plumes, because they both generated huge volumes of basalt during brief intervals, are considered to have come from the deep mantle where, for more than 200 million years there has been a discrete large volume of hot rock over which Africa has been slowly rotating. Perhaps as many as six other deep-seated plumes have risen from that deep hot volume. The importance of the Karroo and Afar Plumes comes from the fact that they arrested the motion of the African Plate and, on each occasion, fostered the establishment of a new shallow-mantle convective circulation pattern. Intracontinental rifts, basins and swells developed above the new convection pattern after both arrests. Organic-rich sedimentary rocks deposited in rifts and at continental margins that formed in response to the Karroo-Plume-induced plate-pinning episode (K-pippe, 183-133 Ma) are being buried today under piles of sedimentary rock eroded from swells that have been rising since the later Afar-Plume-induced plate-pinning episode (A-pippe) began at 31 Ma. The Afar Plume eruption is designated 'Ace of Spades' because oil and gas generated following source-rock burial by sediments eroded from Africa's active swells during the past 31 Ma together make up three-quarters of Africa's hydrocarbon resource. In addition, half of that petroleum lies in reservoirs deposited during this phase.

Three-dimensional seismic interpretation: Espoir Field area, offshore Ivory Coast

Article

Jan 1985

The Espoir oil field, located approximately 13 km offshore Ivory Coast, was discovered in 1980 by a joint venture comprised of Phillips Petroleum Company, AGIP, SEDCO Energy, and PETROCI. Following the discovery, a three-dimensional seismic survey was recorded by GSI in 1981-1982 to provide detailed seismic coverage of Espoir field and adjacent features. The seismic program consisted of 7700 line-km of data acquired in a single survey area that is located on the edge of the continental shelf and extends into deep water. In comparison with previous two-dimensional seismic surveys, the three-dimensional data provided several improvements in interpretation and mapping including: (1) sharper definition of structural features, (2) reliable correlations of horizons and fault traces between closely spaced tracks, (3) detailed time contour maps from time-slice sections, and (4) improved velocity model for depth conversion. The improved mapping helped us identify additional well locations; the results of these wells compared favorably with the interpretation made prior to drilling.

The distribution of petroleum reserves in basins of the South Atlantic margins

Article

Sep 1999

This paper is part of the special publication No.153, The oil and gas habitats of the South Atlantic. (eds: N.R. Cameron, R.H. Bate and V.S. Clure). The opening of the South Atlantic created a series of passive margin basins on both sides of the new ocean. This paper reviews the distribution of petroleum reserves in these basins in terms of their tectono-stratigraphic position within the framework of the rift-drift succession. Seven megasequences are recognized. Three are in the drift succession, three are in the rift succession and one comprises the pre-rift succession. Ninety- three per cent of the presently discovered recoverable hydrocarbons are reservoired in the drift succession, 6% are located in the rift succession and 1% is associated with the pre-rift units. The basins group geographically into seven sectors within which both margins share some common features. Sixty-five per cent of the reserves are contained in Sector V which is dominated by the Niger Delta, and 28% are positioned in Sector III, which includes the Campos and Lower Congo Basins. The new deepwater giant discoveries of Angola, which are located in Sector III, are the Africa counterparts of the earlier deepwater Campos Basin discoveries. In general sectors III-IV, located between the Walvis Ridge and the Equatorial Atlantic transforms, are most favourable as they are characterized by the most prolific source rocks at all horizons.

Shallow structures and evolution of the Ivory Coast and Ghana transform margin

Article

Feb 1988
MAR PETROL GEOL

Seismic profiles across the transform continental margin off the Ivory Coast and Ghana (Western Africa) illustrate the structural style resulting from the early Cretaceous phase of shear stress which leads to the final separation between the African and Brazilian continental margins in this area. Most of the characteristic tectonic features observed along this portion of margin (asymmetric grabens on the Ghanean platform, folds of the deep Ivory Coast basin, the Ivory Coast—Ghana marginal ridge) are believed to result from progressive transform contacts between the African and Brazilian continents as their margins were created during early Cretaceous time. A major tectonic unconformity inferred to be of upper Albian-lower Cenomanian age, may be a direct consequence of the final separation of the continental margins. The later evolution of the transform margin is chiefly explained by thermal subsidence.

Shallow structures and evolution of the Ivory Coast and Ghana transform mar-gin Africa's petroleum systems: four tectonic aces in the past 600 million years (eds) Petroleum Geology of Africa: New Themes and Developing Technologies

Jan 1988
54-64

E Mascle
J Burke
K Macgregor
D S Cameron

References BLAREZ, E. & MASCLE, J. 1988. Shallow structures and evolution of the Ivory Coast and Ghana transform mar-gin. Marine &Petroleum Geology, 5, 54-64 BURKE, K., MACGREGOR, D. S. & CAMERON, N. R. 2003. Africa's petroleum systems: four tectonic aces in the past 600 million years. In: ARTHUR, T. J., MACGREGOR, D. S. & CAMERON, N. R. (eds) Petroleum Geology of Africa: New Themes and Developing Technologies. Geological Society, London, Special Publications, CHIERCHI, M. A. 1996. Stratigraphy, palaeoenvironments and geological evolution of the Ivory-Coast-Ghana Basin. Bulletin Centres des Recherches Exploration-Production Elf Aquitaine, 16, 293-303.

Petroleum system of the Ivorian/Tano Basin in the W Tano contract area, offshore west Ghana. Petroleum Systems and Developing Techno-logies in African Exploration & Production

Apr 2000

J Craven

CRAVEN, J. 2000. Petroleum system of the Ivorian/Tano Basin in the W Tano contract area, offshore west Ghana. Petroleum Systems and Developing Techno-logies in African Exploration & Production, Geologi-cal Society~Petroleum Exploration Society of Great Britain Conference, May 2000, London, Abstracts Vol-ume.

Benin hydrocarbon potential looks promising

Jan 1985
126

A Elvsborg
J Dalode
Elvsborg A.

ELVSBORG, A. & DALODE, J. 1985. Benin hydrocarbon potential looks promising. Oil and Gas Journal, 83 (6), 126-131.

Continental margin off western Africa: Angola to Sierra Leone. Bulletin of the Amer-ican Association of Petroleum Geologists

Jan 1975
2209-2265

K O Emery
E Uchupi
J Phillips
C Brown
J Mascle

EMERY, K. O., UCHUPI, E., PHILLIPS, J., BROWN, C. & MASCLE, J. 1975. Continental margin off western Africa: Angola to Sierra Leone. Bulletin of the Amer-ican Association of Petroleum Geologists, 59, 2209-2265.

Niger Delta petroleum systems (eds) Petroleum Systems of South Atlantic Margins American Association Petroleum Geologists Memoirs

Jan 2000
213-232

R C Haack
P Sundararaman
J O Diedjomahon
N J Xiao
N J Gant
E D May
K Kelsch

HAACK, R. C., SUNDARARAMAN, P., DIEDJOMAHON, J. O, XIAO, N. J., GANT, N. J., MAY, E. D. & KELSCH, K. 2000. Niger Delta petroleum systems. In: MELLO, M. R. & KATZ, B. J. (eds) Petroleum Systems of South Atlantic Margins. American Association Petroleum Geologists Memoirs, 73, 213-232.

Stratigraphy, palaeoenvironments and geological evolution of the Ivory-Coast-Ghana Basin

Jan 1996
293

M A Chierchi
Stratigraphy
Chierchi M. A.

Presentation at Africa Upstream Conference

N Nana

The role of transform faulting in the formation of hydrocarbon traps in the Gulf of Guinea

Jan 2000

B St John
St John B.

Petroleum Systems and Developing Technologies in African Exploration & Production, Geological Society/Petroleum Exploration Society of Great Britain Conference

J Craven

Aspects of the Tano Basin stratigraphy revealed by recent drilling in Ghana

J W Tucker

Petroleum system of the Ivorian/Tano Basin in the W Tano contract area, offshore west Ghana 2000 Petroleum Systems and Developing Technologies in African Exploration & Production, Geological Society/Petroleum Exploration Society of Great Britain Conference

Jan 2000

J Craven
Craven J.

Aspects of the Tano Basin stratigraphy revealed by recent drilling in Ghana 1992 13 Geologie Africaine

Jan 1992
153

J W Tucker
Tucker J. W.

Tectono-stratigraphy of the Keta Basin, Ghana, with emphasis on late erosional episodes 1991 13 Geologie Africaine

Jan 1991
55

A Kjemperud
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T Agdestein
C Gustafsson
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Three-dimensional seismic interpretation, Espoir Field area, offshore Ivory Coast 3-D Seismic Interpretation

Jan 1991
214

L R Grillot
P W Anderton
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Grillot L. R.

Prospectivity of offshore Ghana

Jan 2000

N Nana
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The distribution of petroleum reserves in basins of the South Atlantic margins The Oil and Gas Habitats of the South Atlantic

Jan 1999
101

M Coward
E G Purdy
M A C Ries
D G Smith
N R Cameron
R H Bate
V S Clure
Coward M.

Play fairways of the Gulf of Guinea transform margin

Abstract

No full-text available

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