500 KILOMETERS

LIBERIA

0°

5°W 0°

10°

5°

PORTONOVO

LAGOS

Ibadan

LOMÉ

ABIDJAN ACCRA

NIGERIA

BENIN

TOGO

GHANA

 CÔTE D'IVOIRE

GULF

OF

GUINEA

ATLANTIC

OCEAN

0 250

Niger

Delta

Geology and Total Petroleum Systems of the

Gulf of Guinea Province of West Africa

U.S. Geological Survey Bulletin 2207-C

U.S. Department of the Interior

U.S. Geological Survey
Geology and Total Petroleum Systems of 

the Gulf of Guinea Province of West Africa

By Michael E. Brownfield and Ronald R. Charpentier

U.S. Geological Survey Bulletin 2207-C

U.S. Department of the Interior

U.S. Geological Survey
U.S. Department of the Interior

DIRK KEMPTHORNE, Secretary

U.S. Geological Survey

P. Patrick Leahy, Acting Director

U.S. Geological Survey, Reston, Virginia: 2006

Posted online July 2006

Version 1.0

This publication is only available online at

http://www.usgs.gov/bul/2207/C/

For more information on the USGS—the Federal source for science about the Earth, its natural and living resources, 

natural hazards, and the environment:

World Wide Web: http://www.usgs.gov

Telephone: 1-888-ASK-USGS

Any use of trade, product, or firm names is for descriptive purposes only and does not imply endorsement by the 

U.S. Government.

Although this report is in the public domain, permission must be secured from the individual copyright owners to 

reproduce any copyrighted materials contained within this report.

Suggested citation:

Brownfield, M.E., and Charpentier, R.R., 2006, Geology and total petroleum systems of the Gulf of Guinea Province of

west Africa: U.S Geological Survey Bulletin 2207-C, 32 p.
iii

Foreword

This report was prepared as part of the World Energy Project of the U.S. Geological Survey. The purpose of the World Energy Project is to assess the quantities of oil, gas, and natural 

gas liquids that have the potential to be added to reserves within the next 30 years. These 

volumes either reside in undiscovered fields whose sizes exceed the stated minimum-fieldsize cutoff value for the assessment unit (variable, but must be at least 1 million barrels of oil 

equivalent) or occur as reserve growth of fields already discovered.

For this project, the world was divided into 8 regions and 937 geologic provinces, which 

were then ranked according to the discovered oil and gas volumes within each (Klett and others, 1997). Of these, 76 “priority” provinces (exclusive of the U.S. and chosen for their high 

ranking) and 26 “boutique” provinces (exclusive of the U.S. and chosen for their anticipated 

petroleum richness or special regional economic importance) were selected for appraisal of oil 

and gas resources. The petroleum geology of these priority and boutique provinces is described 

in this series of reports.

A geologic province is a region that characteristically has dimensions of hundreds of 

kilometers and that encompasses a natural geologic entity (for example, sedimentary basin, 

thrust belt, accreted terrain) or some combination of contiguous geologic entities. Province 

boundaries were drawn as logically as possible along natural geologic boundaries, although in 

some provinces their location is based on other factors, such as a specific bathymetric depth in 

open oceans.

The total petroleum system constitutes the basic geologic unit of the oil and gas assessment. The total petroleum system includes all genetically related petroleum that occurs in 

shows and accumulations (discovered and undiscovered) that (1) has been generated by a pod 

or by closely related pods of mature source rock, and (2) exists within a limited mappable 

geologic space, along with the other essential mappable geologic elements (reservoir, seal, and 

overburden rocks) that control the fundamental processes of generation, expulsion, migration, 

entrapment, and preservation of petroleum. The minimum petroleum system is that part of a 

total petroleum system encompassing shows and discovered accumulations along with the geologic space in which the various essential elements have been proved by these discoveries.

An assessment unit is a mappable part of a total petroleum system in which discovered 

and undiscovered fields constitute a single, relatively homogeneous population such that the 

chosen methodology of resource assessment based on estimation of the number and sizes of 

undiscovered fields is applicable.

A total petroleum system may equate to a single assessment unit, or if necessary may be 

subdivided into two or more assessment units such that each unit is sufficiently homogeneous 

in terms of geology, exploration considerations, and risk to assess individually.

A graphical depiction of the elements of a total petroleum system, in the form of an events 

chart, shows the times of (1) deposition of essential rock units; (2) trap formation; (3) generation, migration, and accumulation of hydrocarbons; and (4) preservation of hydrocarbons.
iv

A numeric code identifies each region, province, total petroleum system, and assessment 

unit; these codes are uniform throughout the project and throughout all publications of the project. The code used in this study is as follows:

Unit Name Code

Region Sub-Saharan Africa 7

Province Gulf of Guinea 7183

Total petroleum system Cretaceous Composite 718301

Assessment unit Coastal Plain and Offshore 71830101

The codes for the regions and provinces are listed in Klett and others (1997).

Oil and gas volumes quoted in this report are derived from Petroconsultants, Inc., 1996 

Petroleum Exploration and Production database (Petroconsultants, 1996) and other area reports 

from Petroconsultants, Inc., unless otherwise noted.

Figures in this report that show boundaries of the total petroleum system and assessment 

unit were compiled using geographic information system (GIS) software. Political boundaries 

and cartographic representations were taken, with permission, from Environmental Systems 

Research Institute’s ArcWorld 1:3 million digital coverage (1992), have no political significance, and are displayed for general reference only. Oil and gas field centerpoints, shown in 

these figures, are reproduced, with permission, from Petroconsultants (1996).
v

Contents

Foreword ........................................................................................................................................................iii

Abstract...........................................................................................................................................................1

Introduction.....................................................................................................................................................1

Geology of the Gulf of Guinea Province.....................................................................................................1

Pre-Transform Stage............................................................................................................................8

Syn-Transform Stage..........................................................................................................................19

Post-Transform Stage ........................................................................................................................19

Petroleum Occurrences in the Gulf of Guinea Province.......................................................................22

Hydrocarbon Source Rocks..............................................................................................................22

Hydrocarbon Generation and Migration.........................................................................................24

Hydrocarbon Reservoirs, Traps, and Seals ....................................................................................24

Total Petroleum Systems of the Gulf of Guinea Province .....................................................................25

Lower Paleozoic and Lower Cretaceous Total Petroleum Systems...........................................26

Cretaceous Composite Total Petroleum System (718301)............................................................28

Assessment Units of the Gulf of Guinea Province .................................................................................29

Coastal Plain and Offshore Assessment Unit (71830101).............................................................29

Summary........................................................................................................................................................29

Acknowledgments.......................................................................................................................................31

References Cited..........................................................................................................................................31

Figures

1. Location map of Gulf of Guinea Province, west-central Africa............................................2

2. Location map of Cretaceous Composite Total Petroleum System and

Coastal Plain and Offshore Assessment Unit ..........................................................................3

3. Map of the basins, exploration wells, and major hydrocarbon discoveries in

Gulf of Guinea Province...............................................................................................................4

4. Generalized geologic map of west Africa ................................................................................5

5. Paleogeographic maps of the Cretaceous separation of Africa and

South America...............................................................................................................................6

6. Maps of four stages of the Mesozoic breakup of Africa and South America

and the tectonic evolution of the Equatorial Atlantic.............................................................7

7. Generalized geologic map of Gulf of Guinea area, showing selected oil and

gas provinces ................................................................................................................................9

8. Sketch map showing major fracture zones, sediment thickness, and

oceanic-continental crust boundary.......................................................................................10

9. Generalized stratigraphic column within the Gulf of Guinea Province .............................11

10. Generalized composite stratigraphic column of offshore and onshore parts

of the Saltpond and Tano Basins .............................................................................................12

11. Generalized stratigraphic column of Dzita-1 drill hole, Keta Basin, Ghana......................13

12. Sketch diagram showing paleogeographic reconstruction of the

Silurian Period.............................................................................................................................14
vi

13. Generalized stratigraphic column for central and western parts of

Ivory Coast Basin........................................................................................................................15

14. Schematic cross section across the Belier and Espoir fields in

Ivory Coast Basin........................................................................................................................16

15. Generalized stratigraphic column for offshore part of Benin Basin..................................17

16. Generalized geoseismic cross section for offshore part of Benin Basin..........................18

17. Generalized geoseismic cross section for offshore part of Keta Basin,

eastern Ghana.............................................................................................................................21

18. Modeled burial history curves and vitrinite reflectance and temperature plots

for Dzita-1 well, Keta Basin, Ghana .........................................................................................23

19. Schematic cross section showing common trap types and oil- and

gas-field analogs in Gulf of Guinea Province.........................................................................26

20. Events chart for the Lower Paleozoic Total Petroleum System in the Saltpond,

Keta, and Tano Basins, Gulf of Guinea Province...................................................................27

21. Events chart for the Lower Cretaceous Total Petroleum System in the

Ivory Coast, Tano, Keta, and Benin Basins, and the Dahomey Embayment,

Gulf of Guinea Province.............................................................................................................27

22. Events chart for the Cretaceous Composite Total Petroleum System (718301)

in the Ivory Coast Basin, Gulf of Guinea Province ................................................................28

Tables

1. Summary of estimated undiscovered volumes of conventional oil, gas, and

natural gas liquids for undiscovered oil and gas fields for the Coastal Plain

and Offshore Assessment Unit in the Cretaceous Composite Total Petroleum

System of the Gulf of Guinea Province, west Africa, showing allocations of

undiscovered volumes to the offshore....................................................................................30

2. Summary of estimated undiscovered volumes of conventional oil, gas, and

natural gas liquids for undiscovered oil and gas fields for Sub-Saharan

Africa, showing allocations by oil and gas province............................................................30
Abstract

The Gulf of Guinea Province as defined by the U.S. 

Geological Survey (USGS) consists of the coastal and offshore 

areas of Côte d’Ivoire, Ghana, Togo, and Benin, and the western part of the coast of Nigeria, from the Liberian border east 

to the west edge of the Niger Delta. The province includes the 

Ivory Coast, Tano, Central, Saltpond, Keta, and Benin Basins 

and the Dahomey Embayment. The area has had relatively 

little hydrocarbon exploration since 1968, with only 33 small 

to moderate-sized oil and gas fields having been discovered 

prior to the USGS assessment. Most discoveries to 1995 have 

been located in water depths less than 500 m. Since 1995, only 

eight new offshore discoveries have been made, with four of 

the discoveries in the deep-water area of the province.

Although as many as five total petroleum systems exist 

in the Gulf of Guinea Province, only one, the Cretaceous 

Composite Total Petroleum System, and its assessment unit, 

the Coastal Plain and Offshore Assessment Unit, had sufficient 

data to allow assessment. The province shows two important 

differences compared to the passive-margin basins south of the 

Niger Delta: (1) the influence of transform tectonics, and (2) 

the absence of evaporites and salt deformation. The province 

also lacks long-lived, large deltaic systems that typically result 

in rapid source rock burial and abundant high-quality hydrocarbon reservoirs.

The USGS assessed the potential for undiscovered conventional oil and gas resources in the Gulf of Guinea Province 

as part of its World Petroleum Assessment 2000, estimating 

a mean of 1,004 million barrels of conventional undiscovered 

oil, 10,071 billion cubic feet of gas, and 282 million barrels of 

natural gas liquids. Most of the hydrocarbon potential is postulated to be in the offshore, deeper waters of the province. Gas 

resources may be large, as well as accessible, in areas where 

the zone of hydrocarbon generation is relatively shallow.

Introduction

The U.S. Geological Survey (USGS) assessed the 

potential for undiscovered oil and gas resources in the Gulf of 

Guinea Province (7183) as part of its World Petroleum Assessment 2000 (U.S. Geological Survey World Energy Assessment 

Team, 2000). The province extends from the Niger Delta west 

to Liberia, and includes the coastal and offshore areas of Côte 

d’Ivoire, Ghana, Togo, Benin, and westernmost Nigeria (fig. 1). 

At least five total petroleum systems have been identified in the 

province, but existing exploration and production data in the 

province are mostly limited to the Cretaceous rocks. Therefore, 

only the Cretaceous Composite Total Petroleum System (TPS) 

with its contained Coastal Plain and Offshore Assessment Unit 

(AU) was assessed in this study (fig. 2). Also owing to limited 

drilling and production data, the total petroleum system and 

assessment unit boundaries can only be approximately delineated and so are subject to future revisions.

This report documents and supplements the oil and gas 

assessment reported in USGS World Petroleum Assessment 

2000—Description and results (U.S. Geological Survey World 

Energy Assessment Team, 2000) by providing additional 

geologic detail concerning the total petroleum systems and 

assessment units and a more detailed rationale for the quantitative assessment input. Since the Gulf of Guinea assessment in 

1999, three major volumes (Cameron and others, 1999; Mello 

and Katz, 2000; Arthur and others, 2003) on the petroleum 

geology of west Africa have been published, signifying 

increased interest and exploration activity in the region.

Geology of the Gulf of Guinea Province

The Gulf of Guinea Province includes the Ivory Coast, 

Tano, Saltpond, Central, Keta, and Benin Basins and the 

Dahomey Embayment in the northwestern part of the Gulf of 

Guinea (figs. 3, 4). These basins share common structural and 

stratigraphic characteristics, in that they are wrench-modified 

basins (Clifford, 1986) and contain rocks ranging in age from 

Ordovician to Holocene (Kjemperud and others, 1992); they 

were therefore grouped together as one province. The eastern 

boundary is the Niger Delta Province (Klett and others, 1997), 

and the western boundary is the West African Coastal Province (fig. 4).

The Gulf of Guinea formed at the culmination of Late 

Jurassic to Early Cretaceous tectonism that was characterized 

by both block and transform faulting superimposed across an 

extensive Paleozoic basin during breakup of the African, North 

American, and South American paleocontinents (figs. 5, 6). 

Geology and Total Petroleum Systems of the

Gulf of Guinea Province of West Africa

By Michael E. Brownfield and Ronald R. Charpentier
LIBERIA

0°

5°W 0°

10°

5°

PORTONOVO

LAGOS

Ibadan

LOMÉ

ABIDJAN ACCRA

NIGERIA

BENIN

TOGO

GHANA

 CÔTE D'IVOIRE

GULF

OF

GUINEA

ATLANTIC

OCEAN

Projection: Robinson. Central meridian: 0

Gulf of Guinea Province 7183

EXPLANATION

Country boundary

Gas field centerpoint

Oil field centerpoint

0 250 500 KILOMETERS

Niger

Delta

Figure 1. Gulf of Guinea Province (7183) in west-central Africa and locations of oil and gas field 

centerpoints (Petroconsultants, 1996).

 Total Petroleum Systems, Gulf of Guinea Province, West Africa
LIBERIA

0°

5°W 0°

10°

5°

PORTONOVO

LAGOS

Ibadan

LOMÉ

ACCRA ABIDJAN

NIGERIA

BENIN

TOGO

GHANA

 CÔTE D'IVOIRE

GULF

OF

GUINEA

ATLANTIC

OCEAN

Projection: Robinson. Central meridian: 0

0 250 500 KILOMETERS

Niger

Delta

Coastal Plain and Offshore Assessment Unit 71830101

Cretaceous Composite Total Petroleum System 718301

Country boundary

EXPLANATION

Gas field centerpoint

Oil field centerpoint

Figure 2. Gulf of Guinea Province showing area of Cretaceous Composite Total Petroleum System and 

Coastal Plain and Offshore Assessment Unit, and oil and gas field centerpoints (Petroconsultants, 1996).

Geology of the Gulf of Guinea Province 
SOUTH

AMERICA

AFRICA

NIGERIA

BENIN

TOGO

GHANA

Volta

Basin

CÔTE D'IVOIRE

MALI

LIBERIA

Ivory Coast Basin

Espoir

Belier

Tano

Basin

Saltpond N. Tano

S. Tano

Saltpond and

Central Basins

Keta Basin

Lomé

Sémé

Benin Basin

GULF OF GUINEA

Chain Fracture Zone

Romanche Fracture Zone

St. Paul

FZ

0°

0 200 400 KILOMETERS

Fracture zone (FZ)

Sedimentary basin

Oil and gas discoveries and fields

Dahomey

Embayment

Cape

Three

Points

Epiya

Aje

W. Tano

Foxtrot

Exploration well mentioned in text

Attoutu-1

CTS-1 Dzita-1

Keta-1

ISE-2

10°W

5°

0°

5°W 5°E

EXPLANATION

Country boundary

Figure 3. Major features of the Gulf of Guinea Province, west Africa: Benin, Central, Ivory Coast, Keta, Saltpond, Tano, and Volta 

Basins, Cape Three Points, major fracture zones, and approximate locations of exploration wells and of the oil and gas discoveries and 

fields mentioned in the text. Mid-Atlantic Ridge and fracture zones shown in index map. Modified from Kjemperud and others (1992).

 Total Petroleum Systems, Gulf of Guinea Province, West Africa
Senegal

7013

West African

Shield

7021 Baffa

7105

West African

Coastal

7173

Gulf of Guinea

7183

Volta

7114

Taoudeni

Basin

7035

Niger

7192

West-Central

Coastal

7203

West Zaire

Precambrian

Belt

7211

Orange River

Coastal

7303

South African Coastal

7363

Damer Belt

7311

Kalahari

7325

Etosha

7285

Zaire

7225

Nigerian

Massive

7121

Benue

7136

Chad

7066

Karoo

7355

ATLANTIC

OCEAN

Precambrian rocks

Water

Quaternary rocks

Quaternary and Tertiary rocks

Cretaceous rocks

Tertiary rocks

Igneous rocks

Triassic and Jurassic rocks

Paleozoic rocks

EXPLANATION

Oil and gas province boundary

Subsurface salt diapir

28°S

0°

12°S

0°

4°N

8°N

0 500 1,000 KILOMETERS

WALVIS RIDGE

36°S

32°S

4°S

24°S

20°S

16°S

8°S

12°N

16°N

18°W 12°W 6°W 6°E 12°E 18°E 24°E

Iullemmeden

7055

Figure 4. Generalized geologic map of west Africa 

(from Persits and others, 2002), showing province 

boundaries and selected province names and codes 

as defined by Klett and others (1997).

Geology of the Gulf of Guinea Province 
ALBIAN

110 M.Y.

CENOMANIAN

95 M.Y.

TURONIAN

90 M.Y.

CAM

MAAS

7

EXPLANATION

Type of oceanic basins

Anoxic

Oxic

Areas of continental-margin sedimentation

WalvisRidge 

Walvis

Ridge Walvis Ridge

Gulf of

Guinea

Gulf of

Guinea Gulf of Guinea 

AFRICA AFRICA AFRICA

SOUTH

AMERICA

SOUTH

AMERICA

SOUTH

AMERICA SOUTH AMERICA

Tr

C

NORTH

AMERICA EUROPE 

NORTH AMERICA NORTH AMERICA NORTH AMERICA EUROPE EUROPE

Figure 5. Paleogeographic stages in the separation of Africa and South America during the Cretaceous. Modified from Tissot and others (1980).
15°W 10°W 5°W 0° 

5°

10°

15°W 10°W 5°W 0° 5°E

5°

10°

0 500 KILOMETERS

Ivory Coast

Basin

Ivory Coast

Basin

Benue

Trough

Benin and

Keta Basins

Senegal Basin

Senegal Basin

Volta

Basin

Volta

Basin

K

0 500 KILOMETERS

0 500 KILOMETERS

0 500 KILOMETERS

15°W 10°W 5°W 0° 

5°

10°

Ivory Coast

Basin

Senegal Basin

Volta

Basin

Bové Basin

B

K

15°W 10°W 5°W 0° 5°E

5°

10°

A

C

B

D

Ivory Coast

Basin

Benue

Trough

Senegal Basin

Volta

Basin

Benin and

Keta Basins

Bové Basin

Bové Basin

Bové Basin

Shear zones

Present-day 2,000-m isobath

EXPLANATION

West African and Brazilian shields

Onshore Mesozoic to Cenozoic

coastal basins

Areas of thick continental crust

and extension

Bové and Volta

Paleozoic basins

Divergent basins—Thinned

continental crust and thick clastics

Areas of oceanic crust—

Arrows show directionof crustal extension

Para-Maranhao

Basin

Para-Maranhao

Basin

Para-Maranhao

Basin

Para-Maranhao

Basin

Figure 6. Schematic Cretaceous stages in the Mesozoic breakup of Africa and South America and the tectonic evolution of the Equatorial Atlantic, and location of the Bové, Benin, Ivory Coast, Keta, Senegal, and Volta Basins and the Benue Trough of Africa and the Para-Maranhao Basin of Brazil. A, HautAlbian, 110 Ma; C, late Albian, 100 Ma; D, Santonian, 85 Ma. Modified from Mascle and others (1988).
Thus, the province has undergone a complex history, which we 

divide into pre-transform (late Proterozoic to Late Jurassic), 

syn-transform (Late Jurassic to Early Cretaceous), and posttransform (Late Cretaceous to Holocene) stages of basin 

development. These three stages are referred to as the pre-rift 

(or intracratonic), syn-rift (or rift), and post-rift (or drift) stages 

by Dumestre (1985), Kjemperud and others (1992), Tucker 

(1992), and Chierici (1996). The structural basins within the 

province are aligned generally east-west, with boundaries 

delimited by an east-west transform fault system (fig. 3) and 

north-south structural arches.

The initial phase of the post-Hercynian opening of the 

north Atlantic and the splitting of North America from Eurasia 

and Africa began during Late Permian–Early Triassic time 

(Lehner and De Ritter, 1977; Ziegler, 1988; Lambiase, 1989; 

Uchupi and others, 1976). The final breakup of Africa and 

South America began in the Late Jurassic in the southernmost 

part of the south Atlantic and prograded northward during 

Neocomian time (Binks and Fairhead, 1992; Guiraud and 

Maurin, 1992). The area now occupied by the Gulf of Guinea 

opened last, forming a continuous anoxic seaway in the late 

Albian to Turonian (Tissot and others, 1980). A continuous 

oxic Atlantic Ocean (fig. 5) existed by the end of the Santonian (Blarez and Mascle, 1988). The presence of Aptian 

evaporites and clastics in the West-Central Coastal Province to 

the south (fig. 4) provides evidence that rift-basin sedimentation occurred during the Early Cretaceous, associated with the 

breakup of Africa and South America.

The early tectonic history of the Gulf of Guinea Province 

is different from that of the West-Central Coastal Province 

(fig. 3) or “Aptian salt basin” (Blarez and Mascle, 1988; 

Mascle and others, 1988; Basile and others, 1993; MacGregor 

and others, 2003; Brownfield and Charpentier, 2006). In the 

evolution of the “Aptian salt basin,” the rifting stage was 

dominated by extensional or block faulting, forming grabens 

that filled with lacustrine and fluvial sediments; this was followed by deposition of regional evaporates, and subsequent 

halokinesis (McHargue, 1990; Teisserenc and Villemin, 1990). 

The Gulf of Guinea Province shows two important geological 

differences compared to the passive-margin basins south of 

the Niger Delta: (1) the influence of transform tectonics, and 

(2) the absence of evaporites and halokinesis. Middle Jurassic 

volcanic rocks occur in the Gulf of Guinea Province, indicating that tectonism started no later than the Middle Jurassic 

(Dumestre, 1985; Kjemperud and others, 1992).

Transform faulting was initiated between the African and 

South American continental plates in Early Cretaceous time 

(Hauterivian, fig. 6A). The thick continental crust of the African and South American platform started to break up, forming 

divergent basins or pull-apart grabens separated by transform 

faults (Blarez and Mascle, 1988) in early Albian time (fig. 

6B). Thick continental clastics, consisting of fluvial and possibly lacustrine facies, were deposited in the divergent basins. 

In the Dahomey Embayment (figs. 3, 7), source-rock samples 

have chemical and geologic characteristics similar to Lower 

Cretaceous lacustrine source rocks in the Congo Basin (Haack 

and others, 2000). Such rocks may also be present in the 

Benue Trough and in the Keta and Ivory Coast Basins (figs. 3, 

6). Transform tectonism was active between the African and 

South American plates until middle to late Albian time, when 

the first oceanic crust was formed (fig. 6C) and the last connection between the two continents was breached (Blarez and 

Mascle, 1988). The end of syn-transform tectonism and sedimentation in the Gulf of Guinea Province coincides with this 

phase. A major Albian–lower Cenomanian unconformity was 

a direct consequence of the final separation of the continental 

margins (Blarez and Mascle, 1988; Chierici, 1996; MacGregor 

and others, 2003). By Santonian time (fig. 6D), continued 

crustal extension resulted in the formation of major oceanic 

crust, and the marginal basins and offshore platform of the 

province were subjected to an increase in clastic deposition 

and thermal subsidence, resulting in development of several 

Late Cretaceous and Tertiary unconformities.

The Gulf of Guinea Province is divided structurally by 

three major transform fault zones (figs. 3, 8): (1) the St. Paul 

fracture zone along the northwestern boundary, (2) the Romanche fracture zone that separates the Ivory Coast and the Central 

and Saltpond Basins from the Keta Basin, and (3) the Chain 

fracture zone along the eastern boundary. Sedimentary fill 

within the Ivory Coast Basin is more than 6,000 m thick (fig. 8) 

north of the Romanche fracture zone, which acted as a dam to 

the transport and accumulation of sediments to the south.

The three-stage tectonic evolution in the Gulf of Guinea 

Province allows the stratigraphic section to be divided into 

three main sequences (fig. 9): (1) Precambrian to Triassic 

intracratonic rocks and Jurassic to Lower Cretaceous continental to marginal marine rocks representing the pre-transform 

stage, (2) Lower Cretaceous to latest Albian rocks representing the syn-transform stage, and (3) Cenomanian to Holocene 

rocks representing the post-transform stage.

An understanding of the geology of both the African and 

South American margins of the Atlantic, and an appreciation 

of their resource potential, have increased greatly in the last 

decade. Some suggested references for general geology and 

structural evolution of the African Atlantic margin are Blarez 

and Mascle (1988), Uchupi (1989), Doust and Omatsola 

(1990), Teisserenc and Villemin (1990), Brown and others 

(1995), Cameron and others (1999), Mello and Katz (2000), 

and Arthur and others (2003).

Pre-Transform Stage

The pre-transform section consists of Precambrian to 

Triassic rocks that crop out in the Volta and Tano Basins 

of Ghana (Volta Province, figs. 3, 4). This section has been 

penetrated by drilling in the Saltpond, Tano, and Keta Basins 

(fig. 3) in the central and eastern parts of the Gulf of Guinea 

Province (Dumestre, 1985; Kesse, 1986; Kjemperud and others, 1992; Tucker, 1992). In the Volta Basin (figs. 3, 7), the 

pre-transform section consists of intracratonic Proterozoic to 

Cambrian rocks. The upper Precambrian Buem Formation 

overlies the Precambrian basement, and includes sandstone, 

 Total Petroleum Systems, Gulf of Guinea Province, West Africa
Niger Delta

7192

West-Centr

Coastal

7203

Gulf of Guinea

7183

West African

Coastal

7173

West African

Shield

7021

Volta

7114

Benue

7136

Nigerian

Massive

7121

Taoudeni

Basin

7035 Iullemmeden

7055

Dahomey Embayment

Quaternary rocksPleistocene rocks

Quaternary and Tertiary rocks

Igneous rocks

Precambrian rocks

Cretaceous rocks, undivided

Lower Cretaceous rocks

Paleozoic and Mesozoic rocks

Paleozoic rocks

Tertiary rocks

Salt structures

EXPLANATION

ATLANTIC OCEAN

GULF OF GUINEA

6°W 0° 6°E 

0°

4°

8°

Petroleum province boundary

0 500 K

Ivory Coast Basin

Volta Basin

Figure 7. Generalized geology of the Gulf of Gselected petroleum provinces and the Dahomey Ivory Coast and Volta Basins. Modified from Pe
shale, and volcanics (Kesse, 1986). The Voltaian Series 

overlies the Buem Formation, and includes sandstone, shale, 

mudstone, conglomerate, limestone, and tillites deposited in 

continental and shallow-marine environments (Kesse, 1986: 

Kulke, 1995).

In the Central, Keta, and Saltpond Basins (figs. 9, 10, 11) 

of central and eastern Ghana, the pre-transform rocks range in 

age from Ordovician to Triassic (Kjemperud and others, 1992; 

Tucker, 1992). The Ordovician to Silurian lacustrine Ajua 

Formation consists of laminated shales; it is overlain by the 

fluvial and lacustrine Elmina Formation, composed of feldspathic sandstone and minor conglomerate. Both formations are 

present only in the Central and Saltpond Basins (Kjemperud 

and others, 1992). The distribution of marine Silurian rocks 

(Clifford, 1986), which are known to contain oil-prone black 

graptolitic shales in northern Africa, is shown on the Silurian 

paleogeographic map in figure 12; as indicated, Silurian 

deposition possibly continued eastward to the Benue Trough, in 

Nigeria. Devonian marine sandstones and shales (fig. 11) were 

penetrated in the Dzita-1 well (Kjemperud and others, 1992) but 

drilling did not reach the basement. The Upper Devonian Takoradi Formation, consisting of sandstone, shale, and organic-rich 

shale, was deposited in a shallow to restricted marine environment. The Upper Devonian to Carboniferous Efia Nkvanta Formation is composed of nonmarine and marine sandstones and 

cherty shales with limestone deposited in continental to shallow 

marine environments. The Carboniferous to Triassic Sekondien 

Series includes red sandstones and red-brown shales deposited 

in a fluvial environment. Middle Devonian to Lower Cretaceous 

pre-transform rocks consisting of continental interbedded conglomerate, sandstone, and shale were observed in the onshore 

part of the Saltpond Basin (Kesse, 1986).

Pre-transform rocks have not been identified with certainty in the Ivory Coast Basin (fig. 3), but there are Lower 

Accra Abidjan

6

5 4

3

2

1

1

2

2

2

1

3 4

2

4 6

2

Four North FZ

St. Paul FZ

Romanche FZ

Chain FZ

AFRICA

15°W 10°W 5°W 0° 5°E

0°

8

Ivory Coast

Basin

Lagos

PortoNovo

Lomé

5°

0 100 500 KILOMETERS

Oceanic-continental crust boundary

Major fracture zones (FZ)

Sediment thickness, in kilometers

Gulf of Guinea Province

EXPLANATION

3

Figure 8. Sketch map showing major fracture zones (FZ), sediment thickness, and oceanic-continental crust boundary for the Gulf of 

Guinea Province. Modified from Emery and Uchupi (1984) and MacGregor and others (2003).

10 Total Petroleum Systems, Gulf of Guinea Province, West Africa
Ghana

Tano Saltpond Keta

Ivory

Coast Benin

?

? ?

? ?

?

?

? ?

?

?

?

System

Series/Stage

Tertiary

Pleistocene

Pliocene

Q

Miocene

Oligocene

Eocene

Paleocene

Cretaceous

Upper Lower

Maastrichtian

Campanian

Santonian

Turonian

Coniacian

Cenomanian

Albian

Barremian

Hauterivian

Aptian

Valanginian

Jurassic

Upper Middle Lower

Triassic Permian Carboniferous Devonian Silurian Ordovician

L

M

U

L

L

M

U

U

UUpper Lower Lower

L

M

U

Scale change

Block faulting

Syn-transform

Post-transform

Pre-transform

intracratonic

rocks

Tectonic

stage

Not penetrated by drilling

in western part of province Not penetrated by drilling

in the Tano Basin

Missing section,

major unconformity

Pre-transform

Volcanic flows

and intrusions,

marks the

initial breakup

?

Shale

Sandstone

Conglomerate

Calcareous shale

Limestone

Volcanic rocks

Not penetrated by drilling

EXPLANATION

Berriasian

?

? ? ? ?

Elmina Formation

Ajua Formation

Sekondi

Formation

Nauli Limestone

Imo

Shale

?

Efia Nkvanta

Formation

Takoradi Formation

Figure 9. Generalized stratigraphic 

column showing age, lithology, 

tectonic stage, and stratigraphic 

position of selected formations in 

major basins (see fig. 3) of the Gulf 

of Guinea Province. Modified from 

Kjemperud and others (1992).

Geology of the Gulf of Guinea Province 11
Tertiary

undivided

Maastrichtian

Campanian

Senonian

Cenomanian

Albian

Aptian

Jurassic

Permian

Carboniferous

Devonian

Ordovician

Precambrian

Volcanic rocks associated

with the beginning of block

faulting and continental

separation

Paleozoic sedimentation

in a stable intracratonic

setting

Marine brackish-water

facies, includes source

rocks of the Takoradi

Formation

Continental (fluvial and

lacustrine) facies

West African Shield

Continental facies

in Lower Cretaceous

associated with block faulting

Predominantly marine

sediments with minor

continental conditions

during the middle and

Late Cretaceous

Marine facies

Syn-transform Post-transform

Mid-Albian

unconformity

Age Lithology

Saltpond

Saltpond

Saltpond

North

Tano

South

Tano

Geologic setting and tectonic stage Field

discoveries

Stable

intracratonic

Block

faulting Extensional

faulting

Belier

Sandstone

Shale

Siltstone

Conglomerate

Limestone

Basement

EXPLANATION

Stratigraphic

horizon of

field

discovery

?

?

?

Volcanic rocks

Unconformity

Oligocene

unconformity

Figure 10. Generalized 

composite stratigraphic 

column showing age, 

lithology, approximate 

stratigraphic horizon of 

field discoveries, geologic 

setting, and tectonic 

stage for offshore and 

onshore parts of Saltpond 

and Tano Basins, Ghana, 

Gulf of Guinea Province. 

See figure 3 for location 

of field discoveries. The 

middle and upper parts 

of the Devonian section 

contain marine source 

rocks in the Takoradi 

Formation. See figure 9 for 

stratigraphic position of 

selected formation names. 

Modified from Tucker 

(1992). Cretaceous stage 

boundaries were not 

shown by Tucker (1992).

12  Total Petroleum Systems, Gulf of Guinea Province, West Africa
Miocene

Eocene

Sandstone

Shale

Siltstone

Conglomerate and sandstone

Limestone

EXPLANATION

Volcanic rocks

Sandstone and shale

TD-13,448 ft

PleistocenePliocene

Paleocene

Maastrichtian Cretaceous Aptian-Albian Barremian Hauterivian Ryazanian

Triassic?-

Jurassic

Carboniferous

Devonian

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

9,000

10,000

11,000

12,000

13,000

Lithology Depth

in feet Age Tectonic

stage Syn-transform, block faulting followed by extensional faulting Stable intracratonic Post-transform

Oligocene unconformity

Late Cretaceous unconformity

Unconformity

1

2

2

1

0°

5°

10°

5°W 0°

ACCRA ABIDJAN

TOGO

GHANA

CÔTE

D'IVOIRE

ATLANTIC

OCEAN

Index map

LAGOS

LOMÉ

NIGERIA

BENIN

GULF

OF

GUINEA

Dzita-1

Pretransform?

Figure 11. Generalized stratigraphic 

column showing age, depth, lithology, 

and tectonic stage of drill hole Dzita-1, 

Keta Basin, eastern Ghana. Jurassic 

volcanics represent the onset of 

block faulting in the province. Late 

Cretaceous unconformity at the base of 

the Maastrichtian represents a major 

period of erosion where it is estimated 

that more than 1,300 m of Upper 

Cretaceous (Albian to Campanian) rocks 

were removed. The middle Oligocene 

unconformity represents a period of 

erosion where as much as 390 m of 

Tertiary rocks was removed. Modified 

from Kjemperud and others (1992).

Geology of the Gulf of Guinea Province 13
and Middle Jurassic rocks (fig. 9), consisting of thick beds 

of conglomerate and sandstone deposited in a continental 

setting, which were interpreted to be older than syntransform-related volcanics (Kjemperud and others, 1992). 

Chierici (1996) also reported a sequence of rocks overlying 

the basement (figs. 13, 14) and below a thick section of syntransform rocks in the basin.

The only Paleozoic rocks observed in the Tano Basin of 

eastern Côte d’Ivoire and western Ghana are Lower Carboniferous siliciclastic rocks (Tucker, 1992) penetrated in the 

CTS-1 well (fig. 3). Seismic data indicate that this sequence is 

underlain by strata equivalent to the Ordovician and Devonian rocks in the onshore part of the Saltpond Basin and the 

offshore part of the Keta Basin. The CTS-1 well Lower Carboniferous and underlying rocks represent the western limit 

of Paleozoic rocks in the Gulf of Guinea Province. Similar 

Paleozoic rocks crop out at Cape Three Points (fig. 3) and are 

present offshore.

Upper Jurassic pre-transform sedimentary rocks have not 

been identified with certainty in the Keta Basin (fig. 9) in eastern Ghana (Kjemperud and others, 1992), although the lower 

part of the continental Upper Jurassic to Lower Cretaceous 

Sekondi Formation (fig. 9) may correlate to the Upper Jurassic 

to Lower Cretaceous Ise Formation in the offshore part of the 

Benin Basin (fig. 15; Elvsborg and Dalode, 1985), and may 

represent the uppermost part of this stage. The Ise Formation 

contains conglomerates, sandstones, and shales which were 

deposited in continental and deltaic environments. The dating 

of the lower part of the Sekondi Formation is uncertain because 

of the fluvial depositional environments where preservation of 

Africa

South

America

Gondwanaland

Antarctica

MID-EUROPEAN

OCEAN

HIMAL

SEA

India

Spain

Turkey

Silurian marine

deposition

Outline of present-day

continents, dashed

where uncertain

EXPLANATION

Outline of Silurian

 paleocontinents

20°S

30°S

40°S

50°S

60°S

70°S

Figure 12. Paleogeographic reconstruction of the Silurian Period showing relative positions of paleocontinents and areas of deposition 

for marine Silurian rocks, of which oil-prone graptolitic shales constitute a major part. Outline of present-day continents shown in relative 

position with areas of known Silurian rocks. Modified from Clifford (1986).

14  Total Petroleum Systems, Gulf of Guinea Province, West Africa
Sandstone

Shale

Siltstone

Conglomerate

Limestone with shale partings

Missing section

Pre-transform

Syn-transform,

block faulting

followed by

transform

faulting

Post-transform

Age Lithology Tectonic stage

Jurassic to

Neocomian

BarremianAlbian

Cenomanian

Early

Senonian,

Turonian (?)

CampanianMaastrichtian

Paleocenemiddle

Eocene

MiocenePliocene

Basement

Sandstone with shale

EXPLANATION

Precambrian

Unconformity

Oligocene unconformity

Senonian unconformity

Albian unconformity

1

2

3

1

2

3

Figure 13. Generalized stratigraphic 

column showing age, lithology, and 

tectonic stage for rocks in central and 

western parts of Ivory Coast Basin, 

Gulf of Guinea Province. Pre-transform 

rocks were deposited in continental 

environments, syn-transform rocks 

in continental to marginal marine 

environments, and post-transform rocks 

in marginal marine to open-marine 

environments. Exploration drilling has not 

reached rocks older than Jurassic in the 

central and western parts of the Ivory 

Coast Basin. Modified from Chierici (1996).

Geology of the Gulf of Guinea Province 15
Pre-transform

R

Senonian

Sea level

DEPTH, IN THOUSANDS OF FEET 5

10

Belier Espoir

Projected

 Albian

Middle

Syn-transform

Syn-transform

Albian

Albian

Aptian

Turonian

Senonian

Maastrichtian

Tertiary

unconformity

ATLANTIC OCEAN

NORTH

R unconformity

Post-transform

Post-transform

0 1 2 3 4 5 KILOMETERS

Vertical exaggeration 3:1

R

R

R

Sandstone

Shale

Carbonate rocks

Pre-transform rocks

R Proven and probable

reservoir rocks

EXPLANATION

R

R

R

0°

5°

10°

5°W 0°

L

ACCRA ABIDJAN

OGO

GHANA

 CÔTE

D'IVOIRE

ATLANTIC

OCEAN

Index map

Line ofsection

Figure 14. Schematic cross section across the Belier and Espoir fields in Ivory Coast Basin, Gulf of Guinea Province. The Senonian unconformity separates the continental and marginal marine syntransform rocks from the post-transform or passive margin rocks. Espoir and Belier field discovery wells are projected into the section (see fig. 3). Modified from Clifford (1986), Kulke (1995), and Chierici (1996). Heavy black line, fault.
Tertiary Cretaceous

Neogene Paleogene Late Early

Pliocene

Miocene

Oligocene

Eocene

Paleocene

Maastrichtian

Campanian

Santonian

Coniacian

Turonian

Cenomanian

Albian

Aptian

Barremian

Hauterivian

Valanginian

Berriasian

Senonian Neocomian

Benin

and

Ijebu

Afowo

Oshoshun

Imo

Shale

Araromi

Shale

Awgu

"Turonian

sandstone"

or Abeokuta

Formation

"Albian

sandstone"

Ise

? ?

Holocene to

Pleistocene

Syn-transform Post-transform

Pretransform

Formation Lithology Tectonic

stage

Quaternary

Age

Jurassic ?

Upper

Lower

1

2

3

Sandstone

Shale

Siltstone

Conglomerate

Sandstone with shale

EXPLANATION

Unconformity

Oligocene unconformity

Senonian unconformity

Albian unconformity

1

2

3

Figure 15. Generalized 

stratigraphic column for offshore 

part of Benin Basin, Gulf of Guinea 

Province. The lower part of the 

Ise Formation is considered to be 

Upper Jurassic and part of the 

pre-transform tectonic stage. The 

“Turonian sandstone” is also known 

as the Abeokuta Formation in Benin. 

Modified from Elvsborg and Dalode 

(1985) and MacGregor and others 

(2003).

Geology of the Gulf of Guinea Province 17
?

?

?

?

"Albian sandstone"

"Turonian sandstone"

Upper Afowo Formation

Benin and Ijebu Formations

Basement

Ise Formation

Lower Afowo Formation

ATLANTIC OCEAN

Imo Shale

NORTH SOU

Lower Afowo

Formation

Imo Shale

Imo Shale

Awgu Formation

Awgu

Formation

Araromi

sandstone Araromi Shale

DEPTH , IN METERS

Sea level

1,000

2,0003,000

4,000

5,000

6,000

7,0008,0009,000

0°

5°

10°

5°W 0°

ABIDJAN ACCRA

GHANA

TOGO CÔTE D'IVOIRE

ATLANTIC

OCEAN

Index map

LAGOS LOMÉ

NIGERIA

BENIN

GULF

OF

GUINEA

Line of section

Figure 16. Generalized geoseismic cross section of offshore part of Benin Basin, Gulf of Guinunconformity at base of the “Turonian sandstone” is the top of the syn-transform rocks. The Sbase of the Araromi Shale is related to tectonism in the Benue Trough; the Miocene unconformAfowo Formation is related to a depositional hiatus from the Eocene to the Miocene. The Oshowith the Imo Shale. Some unconformities are not shown. See figure 15 for stratigraphic positiounconformities. Modified from Elvsborg and Dalode (1985). Heavy line, fault. Basement extent 
fossils is low. However, the pre-transform stage is interpreted 

to be largely a period of erosion and nondeposition in the Keta 

Basin. The eroded sediments were transported westward, and 

are most likely preserved as the Jurassic pre-transform rocks in 

the Tano and Ivory Coast Basins.

The pre-transform rocks in the Benin Basin and Dahomey 

Embayment are represented by the lower part of the Ise 

Formation (Dumestre, 1985; Elvsborg and Dalode, 1985; 

MacGregor and others, 2003). The Upper Jurassic to Neocomian Ise Formation (fig. 15), as much as 2,000 m thick, is 

composed of sandstone, shales, and conglomerate deposited in 

fluvial and deltaic environments. Drilling has not reached the 

base of the formation, but seismic data indicate that it directly 

overlies basement rocks (fig. 16) in the offshore part of the 

Benin Basin.

Syn-Transform Stage

Data on the age of volcanic intrusives associated with 

initial block faulting in Liberia, southern Sierra-Leone, and 

Ghana (fig. 3) indicate that faulting started no later than 

the Middle Jurassic and may be as old as Early Jurassic 

(Dumestre, 1985; Kjemperud and others, 1992). Continental 

syn-transform rocks in the Ivory Coast Basin (figs. 3, 9, 13) 

also show evidence that volcanic and fault activity may have 

started in the Early Jurassic. Orientation of the intrusives 

indicates that the initial fracturing and graben formation were 

subparallel to the present coastline. Block faulting and graben 

filling characterized the initial stage of tectonism, followed by 

transform or extensional faulting in the Gulf of Guinea.

The oldest Mesozoic syn-transform sedimentary rocks 

are extensive, continental Jurassic conglomerate and sandstone 

(Dumestre, 1985), with thicknesses as much as 2,000 m in the 

Ivory Coast Basin (location, fig. 3). A comparable sequence 

has not been penetrated by drilling in Ghana, indicating a 

period of nondeposition and (or) erosion in that area (Kjemperud and others, 1992). Drilling has not encountered rocks older 

than Jurassic in the Ivory Coast Basin.

During Neocomian, Aptian, and probably early and 

middle Albian time, more than 5,000 m (Chierici, 1996) of 

syn-transform sediments were deposited in continental to 

marginal marine environments in the Ivory Coast Basin (figs. 

9, 13, 14). The oldest marginal marine strata are in the upper 

Albian, and the lack of evaporites in the Lower Cretaceous 

section indicates that in the Gulf of Guinea Province the syntransform sediments were deposited in a humid equatorial 

climate.

Lowermost Cretaceous syn-transform sediments in the 

Tano and Saltpond Basins (figs. 3, 10) were deposited under 

mostly continental conditions (Kjemperud and others, 1992; 

Tucker, 1992), resulting in interbedded sandstone, shale, 

and limestone (figs. 9, 10). The environment became mostly 

marine during the late Aptian to early Albian, resulting in a 

syn-transform sequence of alternating sandstone and shale 

with some black shale, coarse sandstone, conglomerate, and 

minor limestone.

The Keta Basin of eastern Ghana (figs. 9, 11) contains 

syn-transform rocks of Early Cretaceous age (Kjemperud and 

others, 1992), including the Sekondi Formation (fig. 9), in both 

offshore and onshore areas. The Sekondi Formation consists 

of alternating red-brown to red sandstone, siltstone, and shale 

deposited in a continental environment. During the earliest 

Cretaceous, the basin underwent gradual subsidence, block 

faulting, and graben filling followed by extensional faulting. 

The Aptian to Albian rocks (fig. 9) are characterized by marine 

sandstone and shales with some organic-rich black shales, 

coarse sandstone and conglomerates, and minor limestone 

(Kjemperud and others, 1992). Graben filling continued until 

the middle of the Cenomanian, when uplift of the basin brought 

about extensive erosion and the peneplanation of the Gulf of 

Guinea Province. The Campanian is represented by marine 

sandstone, shale, and minor limestone and conglomerate (fig. 

9). The unconformity at the base of the Maastrichtian in the 

Dzita-1 well (fig. 11) represents a major period of erosion, 

during which it is estimated that more than 1,300 m of Upper 

Cretaceous rocks were removed (Kjemperud and others, 1992).

In the Benin Basin (location, fig. 3), syn-transform rocks 

are represented by the Neocomian part of the Ise Formation 

(figs. 15, 16); they are composed of sandstone, shale, and conglomerate deposited in fluvial, lacustrine, and deltaic environments (Dumestre, 1985; Elvsborg and Dalode, 1985; MacGregor and others, 2003). The base of the formation has not 

been reached by drilling, but seismic data indicate that deposition was in a series of grabens and half grabens in the basin 

(fig. 16) and that the strata may be equivalent to the Lower 

Cretaceous rocks in the Keta Basin. The upper part of the Ise 

Formation contains lacustrine algae similar to those present 

in the lacustrine Bucomazi Formation of the Lower Congo 

Basin (Haack and others, 2000; Brownfield and Charpentier, 

2006) in the West-Central Coastal Province of west Africa 

(fig. 4). The Ise Formation is unconformably overlain by the 

transgressive “Albian sandstone,” which consists of sandstone 

with some interbedded shale (figs. 15, 16) and forms the upper 

boundary of the syn-transform stage in the Benin Basin (Elvsborg and Dalode, 1985).

The end of the syn-transform stage is delineated by 

a major unconformity, which separates it from the marine 

post-transform rocks of the uppermost Albian and Cenomanian (Dumestre, 1985; Kjemperud and others, 1992; Chierici, 

1996; MacGregor and others, 2003). This major unconformity 

is also readily recognized in the Brazilian marginal basins, 

which supports the interpretation that the two continents were 

close to one another during the Early Cretaceous and that their 

geologic histories were similar during that time.

Post-Transform Stage

The post-transform stage rocks in the Gulf of Guinea 

Province consist predominantly of marine Cenomanian to 

Holocene sandstones, shales, and minor carbonate rocks (fig. 

9) deposited in alternating regressions and transgressions 

(Dumestre, 1985; Chierici, 1996; Kjemperud and others, 1992; 

Geology of the Gulf of Guinea Province 19
MacGregor and others, 2003) that resulted in several Late 

Cretaceous and Tertiary unconformities (figs. 9–11, 13, 15). In 

general, continental-margin tectonics of the province’s posttransform stage were driven by thermal subsidence (Kjemperud and others, 1992).

A marine transgression in the Ivory Coast Basin in the 

early Cenomanian (fig. 13) signaled the beginning of the 

post-transform stage, resulting in the deposition of limestone 

on fault-block crests and of organic-rich black shale and 

turbidites in the grabens (Dumestre, 1985; Chierici, 1996). 

Paleontological evidence indicates restricted water circulation and low oxygen content. Following this transgression, a 

middle Cenomanian regression and uplift resulted in erosion 

of the upper Albian to lower Cenomanian sequence in the 

eastern part of the Ivory Coast Basin (figs. 13, 14). During the 

regression more than 3,000 m of middle and upper Cenomanian sediments were deposited in the central and western 

parts of the basin, as evidenced by strata encountered in the 

Attoutu-1 well (fig. 3) in the northwestern part of the basin 

(Chierici, 1996). In the Turonian, a major transgression took 

place that established the first communication between Atlantic and Tethyan waters. Paleontological analysis indicates that 

restricted water circulation and a low oxygen content continued through the Turonian. Mainly marine shale with some 

sandstone characterizes the overlying Coniacian to Santonian 

interval (figs. 13, 14).

An episode of intense deformation occurred in the Benue 

Trough (fig. 6) at the end of the Santonian that was reflected by 

erosion and the development of a major unconformity (labeled 

“Senonian unconformity” in figs. 13, 14) in the east half of the 

Ivory Coast Basin (Dumestre, 1985; Chierici, 1996). Campanian rocks, predominantly shale with minor sandstone deposited 

during a transgression, lie unconformably on the older Cretaceous rocks. Paleontological evidence indicates improved 

bottom-water circulation, but the waters were still anoxic. The 

Maastrichtian is the interval best represented throughout the 

onshore part of the Ivory Coast, where it includes sandstone 

and shale deposited in fluvial and near-shore environments; on 

the continental shelf, it includes more marine facies.

The Paleocene sequence represents a major transgression 

in the Ivory Coast Basin, where it consists of glauconitic shale 

with sandy shale and minor limestone. These strata are overlain 

by lower and middle Eocene shales and marls with thin beds 

of limestone (Chierici, 1996), which, in turn, are overlain by a 

major unconformity (figs. 13, 14) that apparently developed in 

Oligocene time. Marine Miocene rocks lie above this unconformity in the offshore part of the Ivory Coast Basin, and no Oligocene rocks have been identified in offshore exploration wells.

The Tano Basin is located in the easternmost part of the 

Ivory Coast Basin (fig. 3), and the post-transform period in the 

Tano Basin generally has the same tectonic and stratigraphic 

history as the rest of the Ivory Coast Basin. Post-transform 

continental margin tectonism was driven by thermal subsidence, 

beginning in the Cenomanian (figs. 9, 10) with the first marine 

transgression into the Gulf of Guinea Province. The marine 

waters most likely inundated the remaining syn-transform block 

faulted terrain. The Cenomanian rocks include sandstone, shale, 

siltstone, mudstone, and limestone (Kjemperud and others, 

1992; Tucker, 1992); black shale and limestone were deposited 

on the crests of the horsts, whereas turbidites accumulated in the 

grabens. Turonian to Maastrichtian rocks (fig. 9) include marine 

sandstone, shale, limestone, and minor conglomerates (Kjemperud and others, 1992). Major unconformities bound the Cenomanian to Maastrichtian rocks in the Tano Basin as in the Ivory 

Coast Basin. The unconformably overlying Tertiary rocks are 

marine sandstone, shale, and limestone. The regional Oligocene 

unconformity is present in the Tano Basin (figs. 9, 10) separating Miocene from the underlying Eocene rocks.

Post-transform rocks range in age from Campanian to 

Holocene in the Keta Basin (figs. 9, 11, 17). Campanian strata, 

including marine and continental conglomerate, sandstone, 

shale, and limestone (fig. 9), unconformably overlie Albian 

syn-transform rocks, and are unconformably overlain by 

Maastrichtian rocks. The Maastrichtian includes limestone 

and shale with sandstone and claystone deposited in a marine 

environment; these strata grade into continental clastics eastward toward the Benin Basin. Tertiary post-transform rocks 

unconformably overlie the Maastrichtian rocks, and include 

Paleocene to Eocene marine shale interbedded with sandstone, 

siltstone, and limestone. These rocks are separated from the 

upper Miocene marine sandstone, conglomerate, shale, and 

limestone (fig. 9) by a major Oligocene to Miocene unconformity. During the erosional period represented by this unconformity, as much as 365 m of Tertiary rocks (Kjemperud and 

others, 1992) was removed, as evidenced by the stratigraphic 

sequence penetrated in the Dzita-1 and Keta-1 wells (figs. 3, 

11, 17). An unconformity separates the upper Miocene and 

lower Pliocene in parts of the onshore and shallow shelf (fig. 

9). The Pliocene to Holocene offshore units consist of unconsolidated sands and muds.

The Cenomanian to Santonian part of the post-transform stage in the Benin Basin and Dahomey Embayment 

was influenced by transform or extensional faulting, and 

also was affected by deformation that took place during the 

Santonian in the Benue Trough to the east (fig. 6; Elvsborg 

and Dalode, 1985); these episodes of tectonic activity resulted 

in the development of the Senonian unconformity in the 

Benin Basin (figs. 15, 16). The “Turonian sandstone” (fig. 

15) consists of a gray to white coarse-grained, poorly sorted 

sandstone interbedded with thin shale beds overlying a shale 

and siltstone sequence deposited as a reworked fan delta in a 

marginal marine to inner shelf environment. The “Turonian 

sandstone” unconformably overlies the syn-transform “Albian 

sandstone” and is the oldest post-transform unit in the Benin 

Basin. It is present over the entire Benin Basin, and, in places, 

directly overlies crystalline basement. The depocenter is 

located in the eastern part of the basin, where thicknesses are 

as much as 1,000 m; the unit thins to the north and west. The 

Miocene unconformity cuts out the “Turonian sandstone” 

beyond the shelf edge, whereas the Senonian unconformity 

cuts into the unit in the eastern part of the shelf and along the 

shelf edge (Elvsborg and Dalode, 1985).

20 Total Petroleum Systems, Gulf of Guinea Province, West Africa
0 5 KILOMETERS

Miocene unc

TWO WAY TIME, IN SECONDS

0

1

2

3

4

5

6

ATLANTIC OCEAN

Pliocene-Holoc

Pliocene

Miocene

Paleocene-Eocene

Maastrichtian

ConiacianCampanian

Pre-CretaceousAptian

Pre-CretaceousAptian

Projected

well

Keta-1

0°

5°

10°

5°W 

ABIDJAN

G

 CÔTE D'IVOIRE

ATLANTIC

OCEAN

Inde

NORTH

Sealevel

Miocene unconformity

Upper Cretaceous unconformity

Pliocene to Quaternary

sediments

Pliocene rocks

Miocene rocks

Oligocene rocks

Paleocene to

Eocene rocks

Maastrichtian rocks

Coniacian to

Campanian rocks

Pre-Cretaceous

to Aptian rocks

EXPLANATION

Exploration wellSeismic reflector

Fault

Figure 17. Generalized geoseismic cross section of offshore part of Keta Basin, eastern Ghana. See figure 11 for stratigraphic positions of major unconformities. Modified from Kjemperud and others (1992).
The Coniacian Awgu Formation (fig. 15), which is present over most of the Benin Basin, unconformably overlies the 

“Turonian sandstone.” The formation, consisting of dark-gray 

calcareous shale interbedded with calcareous siltstone and 

fine-grained sandstone, was deposited in an anoxic marine 

environment; below the Senonian unconformity (fig. 15), it is 

preserved in grabens. Six Maastrichtian to Holocene post-transform stratigraphic units have been identified in the Benin Basin 

(fig. 15): (1) the Maastrichtian to Paleocene Araromi Shale; (2) 

the Paleocene to Eocene Imo Shale; (3) the Eocene Oshoshun 

Formation; (4) the Miocene Afowo Formation; (5) the Pliocene 

Benin Formation; and (6) the Pliocene(?) to Holocene Ijebu 

Formation. The units become coarser grained toward the top 

and include argillaceous sandstone and siltstone, and shale. 

Sediment transport was from the north, and rapid sedimentation rates initiated growth faults (Elvsborg and Dalode, 1985) 

that sole out in most cases in the Araromi Shale. A depositional 

hiatus from the late Eocene through the Oligocene resulted in 

a major unconformity between the Eocene Imo and Oshoshun 

Formations and Miocene Afowo Formation (figs. 15, 16). A 

second Miocene unconformity separates the lower and upper 

members of the Afowo Formation.

Petroleum Occurrences in the Gulf of 

Guinea Province

Oil and gas occurrences in the Gulf of Guinea Province are 

concentrated in Cretaceous reservoirs on the continental shelf 

and adjacent onshore extensions in two basin areas (fig. 3): (1) 

the Ivory Coast to Tano Basins (Espoir field) of Côte d’Ivoire 

and Ghana, and (2) the Keta Basin (Lomé discovery) to the 

Benin Basin (Aje field) of westernmost Nigeria. These areas 

are associated with oil seeps and tar sand accumulations along 

Upper Cretaceous outcrops west of Cape Three Points (fig. 3) 

in the onshore parts of the Ivory Coast and Tano Basins, and in 

the Dahomey Embayment from Togo to western Nigeria. Most 

discoveries in the province to 1995 have been located in water 

depths less than 500 m. Oil has also been produced from Devonian to Carboniferous Takoradi Formation sandstones sourced 

from Devonian shales in the Saltpond field (figs. 3, 10).

Hydrocarbon Source Rocks

The oldest hydrocarbon source rocks in the Gulf of 

Guinea Province are postulated to be shales in the Middle 

to Upper Devonian Takoradi Formation (figs. 9, 10) in the 

Saltpond Basin and field (fig. 3) of western Ghana (Kjemperud and others, 1992). These source rocks were deposited in 

a brackish marine environment. Oils from the Lomé field in 

Keta Basin (fig. 3) are interpreted to be sourced from correlative Devonian shales (MacGregor and others, 2003), and 

seismic data indicate that similar source rocks are preserved 

in the Tano Basin (Tucker, 1992). Upper Albian reservoirs in 

Sémé and Aje fields (fig. 3) may also have been sourced from 

Devonian shales (MacGregor and others, 2003), as the alternative of an Upper Cretaceous source (see paragraph on anoxic 

conditions) seems unlikely.

Oil seeps in outcrops of the Upper Cretaceous tar sands 

in the northern Dahomey Embayment are interpreted to be 

sourced by Neocomian lacustrine strata (fig. 15), such as were 

drilled into in the Ise-2 well (Haack and others, 2000). These 

source rocks contain Type I kerogen, with total organic carbon 

(TOC) contents as much as 4 percent and the richest sourcerock intervals having hydrogen indices (HI, mg (milligrams) 

hydrocarbon/g (grams) organic carbon) greater than 500. The 

geochemical characteristics are similar to those of the lacustrine source rocks in the Neocomian Bucomazi Formation of 

the Lower Congo Basin in the West-Central Coastal Province 

(fig. 4). Lower Cretaceous lacustrine strata are identified as 

far west as the Ivory Coast Basin (fig. 13) and may include 

similar source rocks (Elvsborg and Dalode, 1985).

Lower to middle Albian gas-prone source rocks have 

been identified in the Ivory Coast and Tano Basins (MacGregor and others, 2003) (figs. 9, 10, 13). These source rocks 

are part of a sequence consisting of as much as 5,000 m of 

Lower Cretaceous continental to marginal marine rocks deposited in grabens in the Ivory Coast and Tano Basins (Chierici, 

1996). Similar source rocks are likely present in the Keta and 

Benin Basins (figs. 9, 11, 17).

Anoxic oceanic conditions that characterized the middle 

Cretaceous worldwide also affected the Gulf of Guinea during the Cenomanian (fig. 5), resulting in the deposition of 

the sediments forming the Albian and Cenomanian black 

shale source rocks in the Ivory Coast and Tano Basins. This 

depositional event marks the first marine transgression in the 

Gulf of Guinea and was accompanied by a decrease in rate of 

subsidence in the province. Anoxic conditions continued into 

the Turonian. Samples analyzed from deep sea drilling sites 

both north and south of the Gulf of Guinea indicate that these 

source rocks (fig. 13) contain more than 10 weight percent 

organic matter consisting of Type II kerogen. In contrast, the 

Dahomey Embayment and Benin Basin are characterized by 

nonmarine to marginal marine conditions with the deposition of coarse sandstone and interbedded shale and carbonaceous shale (fig. 9) representing the last “land bridge” during 

the opening of the Atlantic Ocean (Chierici, 1996). Middle 

Cretaceous source rocks in this area are expected to contain 

gas-prone Type III kerogen.

The Coniacian Awgu Formation, the Maastrichtian 

Araromi Shale, and the Paleocene to Eocene Imo Shale (fig. 

15) contain marine source rocks in the offshore part of the 

Benin Basin. These source rocks contain Type II and Type 

II-III kerogen with TOC contents ranging from 2 to more than 

5 weight percent; they were deposited from the northwestern 

part of the Niger Delta westward to the Keta Basin (Haack and 

others, 2000). The richest source rock intervals have hydrogen 

indices greater than 500. Coniacian to Paleocene rocks are 

present in the offshore part of the Keta Basin (fig. 17) and may 

contain Type II and Type II-III source rocks similar to those in 

the Benin Basin.

22  Total Petroleum Systems, Gulf of Guinea Province, West Africa
TIME (m.a.b.p.)

350.0 300.0 250.0 200.0 150.0 100.0 50.0 Present

Sea level

1,500

4,500

6,000

7,500

9,000

10,500

12,000

13,500

15,000

16,500

DEPTH, IN FEET

Miocene 2

Eocene 1

Maastrichtian

Aptian 1

Barremian 1

Efia Nkvanta Formation

Lower Takora Formation

EXPLANATION

VITRINITE REFLECTANCE (Ro)

3,000

DEPTH, IN FEET

0

0.0 1.0 2.0

1,500

3,000

4,500

6,000

7,500

9,000

10,500

12,000

13,500

Control

point

DEPTH, IN FEET

0

0.0 100.0 200.0

1,500

3,000

4,500

6,000

7,500

9,000

10,500

12,000

13,500

Control

point

TEMPERATURE, IN DEGREES FAHRENHEIT

Figure 18. Modeled burial history curves and vitrinite reflectance and temperature plots of Dzita-1 well (figs. 

3, 11) in Keta Basin, Ghana (fig. 3). Factoring in major erosion in the Cretaceous and minor erosion in the Tertiary 

produces a good fit with measured Ro values. Total amount of erosion was 1,800 m. Modified from Kjemperud and 

others (1992); (m.a.b.p.), millions of years before present.

Petroleum Occurrences in the Gulf of Guinea Province  23
Hydrocarbon Generation and Migration

The most important hydrocarbon generation within 

the Gulf of Guinea Province is from the upper Albian and 

Cenomanian source rocks, which are distributed throughout 

the offshore part of the province; these strata are expected to 

increase in thickness and source rock quality into deep water. 

Two main areas of hydrocarbon generation were interpreted by 

MacGregor and others (2003) to exist in the province: (1) the 

offshore parts of the Ivory Coast and Tano Basins and (2) the 

offshore parts of the Keta and Benin Basins and the Dahomey 

Embayment (fig. 3) eastward to the Niger Delta (fig. 7) just 

east of the Gulf of Guinea Province. These two probable 

oil kitchens are only present in the deep-water parts of the 

province, where the source rocks have reached a temperature 

of at least 100°C and a vitrinite reflectance (Ro) of 0.6 percent 

(MacGregor and others, 2003), which are values equivalent to 

having source rocks subjected to about 2,700 m of overburden. 

The source of hydrocarbon generation in the Saltpond Basin, 

which lies between the two areas of generation just listed, is 

more problematic, and may involve deeper source rocks, such 

as the Devonian Takoradi Formation and Lower Cretaceous 

lacustrine rocks. Hydrocarbon generation started in the Late 

Cretaceous and continues to the present in the Ivory Coast 

and Tano Basins, whereas hydrocarbon generation started in 

the late Miocene and continues to the present in the Keta and 

Benin Basins and Dahomey Embayment (fig. 3) eastward to 

the Niger Delta (fig. 7).

Examples of a burial-history curve and Ro and temperature plots of the Dzita-1 well in the Keta Basin are shown in 

figure 18. This well was drilled in 1973 to test the hydrocarbon potential of Devonian and Cretaceous sandstones; figure 

11 shows the stratigraphic sequence recorded in the drilling, as 

interpreted by Kjemperud and others (1992). A model of the 

burial history that factors in both a major Cretaceous (middle 

Albian) unconformity and a minor Tertiary (Oligocene) 

unconformity, marking time intervals during which 1,300 m 

and 360 m of material, respectively, are estimated to have been 

removed by erosion, indicates a good fit with the measured Ro

values (fig. 18). This model is in agreement with the maturity 

mapping of the Cretaceous unconformity by MacGregor and 

others (2003), who placed the top of the oil-generation window (Ro

 about 0.6) at about 2,700 m below the sea bed.

At least two areas of hydrocarbon generation related to 

Lower Cretaceous lacustrine source rocks are present in the 

Gulf of Guinea Province (Haack and others, 2000; MacGregor 

and others, 2003). These areas are associated with oil seeps 

and tar sand accumulations along Upper Cretaceous outcrops 

west of Cape Three Points in the onshore parts of the Ivory 

Coast and Tano Basins as well as in the Dahomey Embayment (fig. 3); in particular, there are large in-place volumes of 

hydrocarbons in the eastern tar belt of the Dahomey Embayment. The total tar-belt volumes likely exceed the published 

reserves of any field in the Gulf of Guinea Province including 

the largest, which is Espoir field in the Ivory Coast Basin, 

whose reported field size is 400 million barrels (MacGregor 

and others, 2003). Hydrocarbon generation began in the Late 

Cretaceous and may be active to the present.

 Hydrocarbon Reservoirs, Traps, and Seals

The oldest proven reservoir rocks in the Gulf of Guinea 

Province are Devonian to Carboniferous sandstone beds in 

the Saltpond field in Ghana (fig. 3). The sands forming the 

Devonian reservoirs were deposited in shallow to restricted 

marine environments, whereas those forming the Carboniferous reservoirs were deposited in a fluvial environment.

Seismic data indicate that a thick Lower Cretaceous 

syn-transform section in the offshore part of the Benin Basin 

contains probable sandstone reservoir units (Elvsborg and 

Dalode, 1985) deposited in fluvial to deltaic environments. 

Sandstone units with favorable reservoir characteristics have 

been encountered below the “Albian sandstone” (fig. 15) in 

drilling in the Sémé field (fig. 3). Similar reservoir rocks may 

exist westward across the province; for example, as much as 

5,000 m of Lower Cretaceous continental to marginal marine 

sandstone and shales (fig. 9) was deposited in the Ivory Coast 

Basin (Chierici, 1996). Similar reservoir rocks should also be 

present in the Keta and Tano Basins (fig. 9).

Stratigraphic units that contain proven reservoirs in the 

shallow-water discoveries in the Gulf of Guinea Province are 

mainly late syn-transform Albian sandstones and Cenomanian 

to Maastrichtian post-transform marginal marine and turbidite 

clastic rocks. Clastic Albian rocks are the dominant reservoir 

type in the Espoir and Belier fields (fig. 3) in the Ivory Coast 

Basin and are also known in the Tano and Keta Basins. These 

rocks are interpreted to have been deposited in several different depositional settings, including lacustrine, fluvial through 

fluviodeltaic, and marginal marine to marine and submarine 

fans. Marginal marine to marine upper Albian sandstone reservoirs in the Ivory Coast Basin (fig. 13) contain the best petrophysical qualities, with porosities as much as 25 percent and 

permeabilities in the hundreds of millidarcies (MacGregor and 

others, 2003). Many of the sandstone reservoirs are characterized as being laterally discontinuous and exhibiting variable 

petrophysical properties across short distances. Similar Albian 

reservoirs have been penetrated in the Tano and Keta Basins 

(figs. 10, 11) below the mid-Albian unconformity (Kjemperud and others, 1992; MacGregor and others, 2003). Only 

the transgressive “Albian sandstone” represents the marine 

Albian interval in the offshore part of the Benin Basin (fig. 

15), and the upper Albian section is missing (Tucker, 1992). 

The potential middle Albian reservoir rocks in the Ivory Coast 

Basin were deposited in a fluvial continental environment and 

are characterized by poorer petrophysical qualities.

A steep shelf began to develop during the Cenomanian 

along the continental margin of the Gulf of Guinea Province. 

MacGregor and others (2003) speculated that several southflowing rivers supplied clastics to the continental margin prior 

to their capture by the ancestral Niger River. These rivers—for 

example, a large ancestral Tano River in western Ghana and 

24  Total Petroleum Systems, Gulf of Guinea Province, West Africa
a major south-flowing river in the Benin Basin—would have 

drained extensive areas to the north during the early posttransform period in the province and deposited large amounts 

of clastic sediment during the Cenomanian to Maastrichtian 

(Elvsborg and Dalode, 1985; Tucker, 1992; MacGregor and 

others, 2003) now represented by the “Turonian sandstone” 

(figs. 15, 16) or the equivalent Abeokuta Formation (fig. 15). 

The downslope projections of deltas that were formed at that 

time would be prospective for probable turbidite channel and 

ponded turbidite sandstone reservoirs (fig. 14). Because the 

continental shelf is steep and was subjected to several low 

stands along the continental margin, conditions favored the 

deposition of detached, deep-water sandstone units, ponded 

turbidite sands, and clastic fans (fig. 14). Recent seismic data 

indicate that large turbidite channels developed in the Ivory 

Coast Basin during the Maastrichtian (MacGregor and others, 

2003). The presence of large turbidite channels supports the 

interpretation that large fans or detached sandstone bodies may 

lie in the deeper parts of the basin. In general, reservoirs in the 

early post-transform section are likely to be of better quality 

than those in the syn-transform section.

Seismic data indicate that the Tertiary section has fewer 

reservoirs than the Cretaceous section in the Gulf of Guinea 

Province. Some slope fans have been identified in the Araromi 

Shale (fig. 15; Elvsborg and Dalode, 1985) in the overlying section above the regional Maastrichtian unconformity 

(MacGregor and others, 2003). The Araromi sandstone unit 

(fig. 16) has been interpreted as a slope fan in the Benin Basin. 

Other probable reservoir rocks could be present in the deepwater part of the continental margins in the form of detached 

sandstone units resulting from ponded turbidite sands (fig. 14).

Proven hydrocarbon accumulations associated with faultblock traps (fig. 19) are in the upper part of the syn-transform 

section throughout the Gulf of Guinea Province in shallow to 

moderate water depths (MacGregor and others, 2003). This 

trap type characterizes both the Espoir field (Grillot and others, 1991) and the Tano field (fig. 3; MacGregor and others, 

2003), and extends offshore onto the continental slope. Faultblock traps are also along the Romanche fracture zone (fig. 3) 

and in the western part of the Ivory Coast Basin, including the 

2001 Baobab deep-water discovery.

Syn-transform anticlinal traps (fig. 19), detected only 

from seismic data and as yet untested, are associated with the 

terminations of regional fracture zones in two areas: (1) the 

offshore parts of the Dahomey Embayment and Keta Basin, 

and (2) the western offshore part of the Ivory Coast Basin 

(MacGregor and others, 2003). Proven hydrocarbon accumulations associated with post-transitional anticlinal traps are in 

the Tano Basin and the eastern part of the Ivory Coast Basin 

(fig. 3) in the Belier field.

Known hydrocarbon accumulations are associated with 

erosional channel-fill traps (fig. 19) in the post-transform 

section of the Gulf of Guinea Province in both shallow- and 

deep-water areas (MacGregor and others, 2003). This type of 

trap characterizes the Aje field of westernmost Nigeria (fig. 3), 

where the west end of the reservoir is sealed by a shale-filled 

channel. Seismic data indicate that undrilled channel-erosion 

traps are commonly associated with the regional Oligocene 

unconformity from Benin westward, in the deep-water part of 

the province.

Seismic data indicate that syn-transform ponded turbidites 

lying directly above the upper Albian unconformity in the 

western part of the Ivory Coast Basin (MacGregor and others, 

2003) could be trapped against existing faults (fig. 19). Ponded 

turbidite traps are also observed as detached sandstone bodies in the post-transform section in the Ivory Coast, Keta, and 

Benin Basins, where stratigraphic trapping and updip seals are 

the critical factors in defining potential targets. Some of the 

high-amplitude traps associated with the late Albian unconformity may be limestone units located on syn-transform highs 

(Kjemperud and others, 1992; MacGregor and others, 2003).

Untested stratigraphic traps consisting of mounded sandstones and channels interbedded with the Cenomanian source 

rocks are interpreted from seismic data in the post-transform 

section in the Gulf of Guinea Province (fig. 19). Thick and 

extensive sandstone units were observed by MacGregor and 

others (2003) above the late Albian unconformity, covering 

areas of more than 80 km2 in the deep-water parts of the province, where the shelf is steeper and a greater probability exists 

for detached sandstone units and up-dip seals. An example of 

a stratigraphically sealed channel is Dana’s (British Independent) Maastrichtian West Tano oil discovery (figs. 3 and 19).

Seals associated with syn-transform reservoirs are formed 

by both shales and faults (fig. 19), whereas the seals associated 

with post-transform reservoirs are generally shales.

Total Petroleum Systems of the Gulf of 

Guinea Province

At least five total petroleum systems (TPS) exist in the 

Gulf of Guinea Province (7183): (1) the Lower Paleozoic TPS, 

consisting of Devonian source rocks and Devonian to Lower 

Cretaceous reservoir rocks; (2) the Lower Cretaceous TPS, 

consisting of Lower Cretaceous lacustrine source rocks and 

Cretaceous reservoir rocks; (3) the middle Albian Terrestrial 

TPS, consisting of gas-prone source rocks and Albian reservoir 

rocks; (4) the upper Albian TPS, consisting of marine transgressive oil-prone source rocks and Albian reservoir rocks; and 

(5) the Cenomanian-Turonian TPS, consisting of open marine 

oil-prone source rocks and Albian to Upper Cretaceous reservoir rocks. The three youngest systems were combined into the 

Cretaceous Composite TPS consisting of Albian to Turonian 

marine and terrestrial source rocks and Cretaceous reservoir 

rocks. Only limited exploration and production information is 

available for the Lower Paleozoic TPS and Lower Cretaceous 

TPS. Oil production from the Lower Paleozoic TPS is limited 

to the Saltpond and Lomé fields (fig. 3), whereas Lower Cretaceous TPS oils have only been identified in Upper Cretaceous 

tar sands and oil seeps at Cape Three Points and the Dahomey 

Embayment. Only the Cretaceous Composite TPS was 

Total Petroleum Systems of the Gulf of Guinea Province  25
considered for assessment, because (1) it is the most extensive, 

and (2) current exploration and production are mostly limited 

to this system. One assessment unit (AU) was defined within 

the Cretaceous Composite TPS—the Coastal Plain and Offshore AU. Input data describing the assessment unit are given 

in the U.S. Geological Survey World Petroleum Assessment 

2000—Description and results, Disk 3 (U.S. Geological Survey 

World Energy Assessment Team, 2000).

Lower Paleozoic and Lower Cretaceous Total 

Petroleum Systems

Events charts (figs. 20, 21) for the Lower Paleozoic TPS 

and Lower Cretaceous TPS graphically portray the ages of 

source, seal, and reservoir rocks, as well as the timing of trap 

development, and generation, migration, and preservation of 

hydrocarbons, and the critical moment. The critical moment 

is defined as the beginning of hydrocarbon generation and 

migration. These total petroleum systems were not assessed 

but are documented in the Gulf of Guinea Province report.

The likely source rocks for the Lower Paleozoic TPS are 

organic-rich brackish marine shales in the Middle to Upper 

Devonian Takoradi Formation in the Saltpond field. Lomé field 

(fig. 3) oils are sourced from these shales (MacGregor and 

others, 2003), and seismic data indicate that they are preserved 

in the Tano Basin (Tucker, 1992), although potential targets 

are presently untested. Reservoir rocks consist of Devonian 

and Carboniferous to Permian sandstone beds (fig. 10) in the 

Saltpond area (fig. 3). Currently it is assumed that upper Albian 

reservoirs in Sémé and Aje fields are sourced from Devonian 

shales (MacGregor and others, 2003), because downward 

migration from Upper Cretaceous-sourced oils seems unlikely. 

Hydrocarbon generation most likely began in the Late Carboniferous and may have continued into the early Tertiary.

The Lower Cretaceous TPS was defined because lacustrine source rocks deposited in early rift grabens have been 

recognized in the central and eastern parts of the province, 

as evidenced by the presence of lacustrine oils from Upper 

Syn-transform

anticline

Fault block,

Espoir

Post-transform

anticline, Belier

Channel, West Tano

Ponded

turbidites

Stratigraphic

updip pinchout

Stratigraphic Erosional

channel, Aje

Conglomerate

Sandstone

Shale

Siltstone

Unconformity

Fault

EXPLANATION

Middle Albian unconformity

Figure 19. Schematic cross section showing common trap types and oil- and gas-field analogs (see fig. 3) in Gulf of Guinea Province. 

Many of the traps are present only in the deep-water parts of the province and have not been tested. Barbs on fault (heavy line) show 

relative movement. Modified from MacGregor and others (2003). No scale.

26  Total Petroleum Systems, Gulf of Guinea Province, West Africa
0

100

200

300

400

500

600

50

150

250

350

450

550

Paleogene

Cretaceous

Jurassic

Triassic

Permian

65

146

208

245

363

570

510

439

408

Precambrian

Cambrian

Ordovician

Silurian

Devonian

290

323

Mississippian

Pennsylvanian

Neogene

24

E

M

L

E

E

E

E

E

E

E

E

M

M

M

M

M

L

L

L

L

L

L

L

L

L

Pal

Eoc

Olig

Mio

Plio

ROCK UNIT

SOURCE ROCK

RESERVOIR ROCK

SEAL ROCK

OVERBURDEN ROCK

TRAP FORMATION

GENERATIONPRESERVATION

CRITICAL MOMENT

PETROLEUM

SYSTEM EVENTS

GEOLOGIC

TIME

SCALE

ACCUMULATION MIGRATIONX

?

?

E

Figure 20. Events chart for the Lower Paleozoic Total 

Petroleum System in the Saltpond, Keta, and Tano Basins, 

Gulf of Guinea Province. Light-gray shading indicates rock 

units present (fig. 9); wavy line, unconformity. Age ranges of 

source, seal, reservoir, and overburden rocks and the timing of 

trap formation and generation, migration, and preservation of 

hydrocarbons are shown in green and yellow. Queried where 

uncertain. Critical moment is defined as the beginning of 

hydrocarbon generation and migration.

ROCK UNIT

SOURCE ROCK

RESERVOIR ROCK

SEAL ROCK

OVERBURDEN ROCK

TRAP FORMATION

PRESERVATION

CRITICAL MOMENT

PETROLEUM

SYSTEM EVENTS

GEOLOGIC

TIME

SCALE

0

100

200

50

150

250

Paleogene

Cretaceous

Jurassic

Triassic

Permian

245 E

E

E

E

M

M

L

L

L

L

Neogene

Pal

Eoc

Olig

Mio

Plio

X

?

GENERATIONACCUMULATION MIGRATION24

65

146

208

Figure 21. Events chart for the Lower Cretaceous Total 

Petroleum System in the Ivory Coast, Tano, Keta, and Benin 

Basins, and the Dahomey Embayment, Gulf of Guinea Province. 

Light-gray shading indicates rock units present (fig. 9); wavy 

line, unconformity. Age ranges of source, seal, reservoir, and 

overburden rocks and the timing of trap formation and generation, 

migration, and preservation of hydrocarbons are shown in green 

and yellow. Queried where uncertain. Critical moment is defined 

as the beginning of hydrocarbon generation and migration.

Total Petroleum Systems of the Gulf of Guinea Province  27
Cretaceous tar sands and oil seeps in areas west of Cape 

Three Points in western Ghana, as well as in the Dahomey 

Embayment (fig. 3). Neocomian Ise Formation source rocks 

encountered in the Ise-2 well (fig. 3) have been correlated 

to Upper Cretaceous oil seeps and tar sands in the northern 

Dahomey Embayment (Haack and others, 2000). The Ise 

Formation source rocks (fig. 15) contain Type I kerogen with 

TOC contents as much as 4 percent and hydrogen index (HI, 

mg hydrocarbon/g organic carbon) values greater than 500 in 

the organically richest intervals. These Neocomian lacustrine 

shales have similar geochemical characteristics to the Lower 

Cretaceous lacustrine source rocks of the Bucomazi Formation 

in the Congo Delta (MacGregor and others, 2003; Brownfield 

and Charpentier, 2006). Lower Cretaceous lacustrine rocks 

are identified as far west as the Ivory Coast Basin (fig. 13) and 

may contain source rocks (Elvsborg and Dalode, 1985).

Cretaceous Composite Total Petroleum System 

(718301)

The Cretaceous Composite TPS was defined in the Gulf of 

Guinea Province (fig. 1). An events chart (fig. 22) for this total 

petroleum system graphically portrays the ages of the source, 

seal, and reservoir rocks, as well as the timing of trap development, and generation, migration, and preservation of hydrocarbons, and the critical moment. The critical moment is defined 

as the beginning of hydrocarbon generation and migration.

The principal source rocks for the Cretaceous Composite 

TPS are Albian, Cenomanian, and Turonian marine shales 

with Type II and II-III oil-prone kerogen and Type III terrestrial kerogen. Lower to middle Albian Type III source rocks 

were identified in the Ivory Coast and Tano Basins (figs. 9, 

10, 13) by MacGregor and others (2003). These organic-rich 

sediments were deposited in fluvial and deltaic environments; 

in the Ivory Coast Basin as much as 5,000 m of Lower Cretaceous continental to marginal marine sediment was deposited 

in grabens (Chierici, 1996). Similar source rocks should be 

present in the Keta (Kjemperud and others, 1992) and Benin 

Basins (figs. 9, 11, 17). Worldwide anoxic ocean conditions 

during the Cenomanian (fig. 5) resulted in the deposition of 

the Cenomanian to Turonian black shale source rocks in the 

Ivory Coast and Tano Basins. These source rocks (fig. 13) 

contain more than 10 weight percent TOC consisting of Type 

II kerogen. In contrast, the Dahomey Embayment and Benin 

Basin are characterized by nonmarine to marginal marine 

conditions resulting in the deposition of middle Cretaceous 

gas-prone source rocks containing Type III kerogen (Chierici, 

1996). The Coniacian Awgu Formation and the Maastrichtian 

Araromi Shale (fig. 15) contain marine source rocks in the 

offshore part of the Benin Basin. These source rocks contain 

Type II and Type II-III kerogen with TOC contents ranging 

from 2 to more than 5 weight percent; area of original deposition was from the northwestern extension of the Niger Delta 

westward to the Keta Basin (Haack and others, 2000). The 

richest source rock intervals have HI values greater than 500. 

ROCK UNIT

SOURCE ROCK

RESERVOIR ROCK

SEAL ROCK

OVERBURDEN ROCK

TRAP FORMATION

CRITICAL MOMENT

PETROLEUM

SYSTEM EVENTS

GEOLOGIC

TIME

SCALE

0

100

200

50

150

250

Paleogene

Cretaceous

Jurassic

Triassic

Permian

65

146

208

245 E

E

E

E

M

M

L

L

L

L

Neogene

24

Pal

Eoc

Olig

Mio

Plio

X

GENERATIONPRESERVATION

ACCUMULATION MIGRATIONFigure 22. Events chart for the Cretaceous Composite Total 

Petroleum System (718301) in the Ivory Coast Basin, Gulf of 

Guinea Province. Light-gray shading indicates rock units 

present (fig. 9); wavy line, unconformity. Age ranges of source, 

seal, reservoir, and overburden rocks and the timing of trap 

formation and generation, migration, and preservation of 

hydrocarbons are shown in green and yellow. Queried where 

uncertain. Critical moment is defined as the beginning of 

hydrocarbon generation and migration.

28  Total Petroleum Systems, Gulf of Guinea Province, West Africa
Coniacian rocks are present in the offshore part of the Keta 

Basin (fig. 17); some of these may be source rocks.

Hydrocarbon generation started in the Late Cretaceous 

for the Albian to Cenomanian source rocks and continues to 

the present. For the Turonian and Coniacian source rocks, 

hydrocarbon generation possibly started in the early Tertiary and also continues to the present. Migration was either 

directly from adjacent source rocks or upward along faults 

from deeper sources.

Reservoir rocks are mostly Cretaceous turbidite sandstones with minor potential limestone units. The traps include 

pre-transform traps related to fault blocks, syn-transform 

structural and stratigraphic traps, and post-transform stratigraphic traps. Seals are marine shales and shale-filled channels 

with minor fault-related seals.

Assessment Units of the Gulf of Guinea 

Province

The Coastal Plain and Offshore Assessment Unit (AU; 

71830101) (fig. 2) includes Cretaceous reservoirs associated 

with pre-transform fault blocks and syn- and post-transform 

ponded turbidites, turbidite channels, and slope fans in basins 

between the major fracture zones (fig. 3). This assessment 

unit was defined to be co-located geographically with the 

Gulf of Guinea Province boundary, with the northern boundary of the assessment unit defined as the northern limit of 

the Cretaceous rocks and the southern boundary drawn at a 

water depth of 2,000 m. Although potential reservoirs in this 

assessment unit could exist in the shallow-water part, most of 

the prospectivity is expected to be in the deep-water part of 

the province.

Coastal Plain and Offshore Assessment Unit 

(71830101)

Exploration in the 1970s and 1980s resulted in the discovery of several moderate-sized oil fields, including Espoir 

(1980; 400 million barrels) and the large Foxtrot gas field 

(1982; about 1 trillion cubic feet) in the assessment unit (fig. 

3). Exploration through 1995 was considered to be relatively 

immature with the discovery of only 33 fields (Petroconsultants, 1996), only 4 of which are in deep-water areas. The 

presence of one large gas field coupled with the relative lack 

of exploration for stratigraphic traps indicates a promising 

potential for future discoveries. Since the 2000 assessment 

(U.S. Geological Survey World Energy Assessment Team, 

2000), eight discoveries have been made, with four of them in 

deep water (IHS Energy Group, 2003).

The USGS assessed mean undiscovered volumes in the 

Coastal Plain and Offshore AU of 1,004 MMBO, 10,071 BCFG, 

and 282 MMBNGL (table 1). The estimated sizes of the largest undiscovered oil and gas fields are 201 MMBO and 1,138 

BCFG, respectively. Most of the undiscovered resources are 

expected to be in the deep-water parts of the assessment unit. 

Compared to other provinces along the Atlantic coast of Africa, 

the Gulf of Guinea Province has only modest potential for undiscovered resources (table 2) and ranks as the third province in 

Sub-Saharan Africa (table 2) in terms of mean undiscovered oil.

Summary

The Cretaceous Composite Total Petroleum System 

(TPS; 718301) consists of middle Albian to Maastrichtian 

Type II, II-III, and III oil-prone kerogen and Type III gasprone kerogen and Cretaceous reservoirs. Worldwide middle 

Cretaceous anoxic ocean conditions resulted in the formation 

of the Cenomanian to Turonian Type II oil-prone kerogen 

source rocks containing more than 10 weight percent TOC. 

Cretaceous marine mudstones and shales are the primary seals. 

Hydrocarbon generation began in the Late Cretaceous and 

continues to the present.

Two other total petroleum systems were recognized 

in the Gulf of Guinea Province: (1) the Lower Paleozoic 

TPS, consisting of Devonian source rocks and Devonian 

to Lower Cretaceous reservoir rocks, and (2) the Lower 

Cretaceous TPS, consisting of Lower Cretaceous lacustrine 

source rocks and Cretaceous reservoir rocks. Although 

these total petroleum systems are considered to have 

hydrocarbon potential, they were not assessed: current 

exploration and production data are limited to the overlying 

Cretaceous Composite TPS.

Two important geologic differences contrast the Gulf of 

Guinea Province with the passive-margin basins south of the 

Niger Delta: (1) the influence of transform tectonics in the 

Gulf of Guinea Province, and (2) the absence of evaporites 

and salt deformation. The province also lacks long-lived delta 

systems that provide depositional conditions for rapid source 

rock burial and abundant high-quality reservoirs.

The Gulf of Guinea Province is estimated to have mean 

undiscovered resources of 1,004 MMBO and 10,071 BCFG 

in undiscovered fields. Compared to other provinces in SubSaharan Africa, the province has a moderate potential for 

undiscovered resources. All of the undiscovered resources are 

offshore and mostly in deep water.

Critical factors controlling oil and gas accumulations in 

the Gulf of Guinea Province are the presence of good reservoirs, quality and preservation of hydrocarbons, and the ability 

to produce hydrocarbons at a rate that would be economic in 

a deep-water setting. Offshore core samples and seismic data 

indicate that erosion on the structural highs and on the province 

shelf and slope is extensive, exposing the Albian rocks on the 

sea bed and removing potential reservoir and source rocks.

Although the deep-water parts of the Gulf of Guinea 

Province are underexplored, they are considered to contain 

many potential prospects. Gas resources may be substantial, 

and may also be accessible in areas where the zone of hydrocarbon generation is relatively shallow.

Summary  29
Table 1. Summary of estimated undiscovered volumes of conventional oil, gas, and natural gas liquids for undiscovered oil and gas 

fields for the Coastal Plain and Offshore Assessment Unit in the Cretaceous Composite Total Petroleum System of the Gulf of Guinea 

Province, west Africa, showing allocations of undiscovered volumes to the onshore.

[MMBO, million barrels of oil. BCFG, billion cubic feet of gas. MMBNGL, million barrels of natural gas liquids. MFS, minimum field size assessed (MMBO or 

BCFG). Prob., probability (including both geologic and accessibility probabilities) of at least one field equal to or greater than the MFS. Results shown are fully 

risked estimates. For gas fields, all liquids are included under the NGL (natural gas liquids) category. F95 represents a 95 percent chance of at least the amount 

tabulated. Other fractiles are defined similarly. Fractiles are additive under the assumption of perfect positive correlation. Shading indicates not applicable]

Undiscovered Resources

Field

Type MFS Prob. Oil (MMBO)

(0-1) F95 F50 F5 Mean F95 F50 F5 Mean F95 F50 F5 Mean

Gas (BCFG) NGL (MMBNGL)

Cretaceous Composite Total Petroleum System

Oil Fields 2 225 901 2,117 1,004 918 3,846 9,845 4,420 29 124 339 146

Gas Fields 12 1,256 5,064 12,000 5,650 28 118 303 136

Total 1.00 225 901 2,117 1,004 2,174 8,910 21,846 10,071 57 242 642 282

Coastal Plain and Offshore Assessment Unit Offshore (100% of undiscovered oil fields and 100% of undiscovered gas fields allocated to offshore)

1.00

Code Undiscovered Resources

and Field Prob. Oil (MMBO)

Type (0-1) F95 F50 F5 Mean F95 F50 F5 Mean F95 F50 F5 Mean

Gas (BCFG) NGL (MMBNGL)

7013

Oil Fields 15 120 430 157 33 255 968 345 2 15 59 21

Gas Fields 83 414 1,276 510 3 18 58 22

Total 1.00 15 120 430 157 116 669 2,244 856 5 33 118 43

7183

Oil Fields 225 901 2,117 1,004 918 3,846 9,845 4,420 29 124 339 146

Gas Fields 1,256 5,064 12,000 5,650 28 118 303 136

Total 1.00 225 901 2,117 1,004 2,174 8,910 21,846 10,071 57 242 642 282

7192

Oil Fields 17,487 39,975 65,123 40,487 28,703 70,120 133,579 74,056 903 2,292 4,608 2,459

Gas Fields 28,845 57,910 90,585 58,660 1,741 3,517 5,594 3,574

Total 1.00 17,487 39,975 65,123 40,487 57,548 128,030 224,165 132,716 2,643 5,808 10,202 6,034

7203

Oil Fields 9,033 27,917 56,465 29,747 17,693 56,368 123,798 61,608 827 2,739 6,483 3,080

Gas Fields 5,268 23,152 58,794 26,436 217 989 2,715 1,164

Total 1.00 9,033 27,917 56,465 29,747 22,961 79,520 182,592 88,044 1,044 3,727 9,198 4,244

1.00

1.00

Senegal Province

Gulf of Guinea Province

Niger Delta Province

West-Central Coastal Province

1.00

1.00

Table 2. Summary of estimated undiscovered volumes of conventional oil, gas, and natural gas liquids for undiscovered oil and 

gas fields for Sub-Saharan Africa, showing allocations by oil and gas province.

[MMBO, million barrels of oil. BCFG, billion cubic feet of gas. MMBNGL, million barrels of natural gas liquids. MFS, minimum field size assessed 

(MMBO or BCFG). Prob., probability (including both geologic and accessibility probabilities) of at least one field equal to or greater than the MFS. Results 

shown are fully risked estimates. For gas fields, all liquids are included under the NGL (natural gas liquids) category. F95 represents a 95 percent chance of at 

least the amount tabulated. Other fractiles are defined similarly. Fractiles are additive under the assumption of perfect positive correlation. Shading indicates 

not applicable]

7 Total: Sub-Saharan Africa

Oil Fields 26,783 68,999 124,447 71,512 47,393 130,775 268,891 140,685 1,763 5,180 11,533 5,722

Gas Fields 36,081 89,369 170,545 94,604 2,015 4,762 9,031 5,044

Total 1.00 26,783 68,999 124,447 71,512 83,474 220,144 439,436 235,290 3,778 9,942 20,564 10,766

1.00

7303

Oil Fields 23 87 312 116 46 186 701 256 3 11 43 15

Gas Fields 629 2,829 7,889 3,348 26 121 361 147

Total 1.00 23 87 312 116 675 3,015 8,590 3,603 28 132 404 163

Orange River Coastal Province

1.00

30 Total Petroleum Systems, Gulf of Guinea Province, West Africa
Acknowledgments

The authors thank Lorna Carter, Mitchell Henry, Douglas 

Nichols, and Christopher Schenk for their suggestions, comments, and editorial reviews, which greatly improved the text.

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