Assessment of the Undiscovered Oil and 

Gas of the Senegal Province, Mauritania, 

Senegal, The Gambia, and Guinea-Bissau, 

Northwest Africa

By Michael E. Brownfield and Ronald R. Charpentier

U.S. Geological Survey Bulletin 2207–A

U.S. Department of the Interior

U.S. Geological Survey
Posted online October 2003, version 1.0

Any use of trade, product, or firm names in this publication

is for descriptive purposes only and does not imply 

endorsement by the U.S. Government.

Published in the Central Region, Denver, Colorado

Manuscript approved for publication June 5, 2003

U.S. Department of the Interior

Gale A. Norton, Secretary

U.S. Geological Survey

Charles G. Groat, Director
 iii

Contents

Foreword. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1

Abstract. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2

Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2

Senegal Basin Geology. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3

Pre-rift Section. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4

Syn-rift Section. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7

Post-rift Section . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12

Petroleum Occurrence in the Senegal Basin. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12

Hydrocarbon Source Rocks in the Senegal Basin . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12

Hydrocarbon Generation and Migration in the Senegal Province . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14

Hydrocarbon Reservoirs, Traps, and Seals in the Senegal Basin . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19

Total Petroleum Systems of the Senegal Province. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19

Lower Paleozoic and Sub-salt Total Petroleum Systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19

Cretaceous-Tertiary Composite Total Petroleum System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23

Coastal Plain and Offshore Assessment Unit. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23

Summary. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24

References Cited. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24

Figures

1. Location map showing the Senegal Province boundary. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3

2. Generalized geologic map of northwest Africa. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .4

3. Generalized map of the central and southern parts of the Senegal Basin. . . . . . . . . . . . . . . . . . . . . . . . . . . .5

4. Generalized stratigraphic column for the Casamance region of the Senegal Basin. . . . . . . . . . . . . . . . . .6

5. Location map for Guinea-Bissau, southern Senegal Basin. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7

6. Schematic cross section, Guinea-Bissau, southern Senegal Basin . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .8

7. Generalized stratigraphic column, Casamance offshore . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .9

8. Generalized stratigraphic column for northern and southern Mauritania. . . . . . . . . . . . . . . . . . . . . . . . . . . .9

9. Schematic east-to-west cross section through The Gambia. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10

10. Schematic cross section through Cape Verde. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11

11. Organic facies distribution of the Cenomanian to Turonian source rocks. . . . . . . . . . . . . . . . . . . . . . . . . . 13

12. Paleogeographic reconstruction of the Silurian Period. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15

13. Examples of maturation evolution involving the Silurian, Jurassic, basal Neocomian, 

and the Cenomanian to Turonian source rocks . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16

14. Examples of maturation evolution involving the Albian, Turonian, Senonian, 

Campanian, Maastrichtian, and Paleocene source rocks. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16

15. Isogeneration map of the Upper Cretaceous and Paleocene. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17

16. Schematic cross sections showing the position of the zone of oil generation, 

Senegal Basin. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18

17. Schematic cross section of Guinea-Bissau offshore. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20

18. Schematic cross section of the Mauritania offshore. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21

19. Events chart for the Lower Paleozoic Total Petroleum System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22

20. Events chart for the Sub-salt Total Petroleum System. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22

21. Events chart for the Cretaceous-Tertiary Composite Total Petroleum System . . . . . . . . . . . . . . . . . . . . . 23

Tables

(Tables follow References Cited)

1. Estimated sizes, numbers, and coproduct ratios of undiscovered oil and gas fields

2. Estimated undiscovered conventional oil, gas, and natural gas liquids volumes
1

Assessment of the Undiscovered Oil and Gas of the 

Senegal Province, Mauritania, Senegal, The Gambia, 

and Guinea-Bissau, Northwest Africa

By Michael E. Brownfield and Ronald R. Charpentier

Foreword

This report was prepared as part of the World Petroleum 

Assessment 2000 of the U.S. Geological Survey’s Energy 

Resources Program. The purpose of the World Petroleum 

Assessment 2000 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 minimum-field-size cutoff value of at least 1 million barrels of oil equivalent, or occur 

as reserve growth of fields already discovered.

In order to organize, evaluate, and delineate areas to 

assess, a hierarchical scheme of geographic and geologic units 

was developed. This scheme consists of regions, geologic provinces, petroleum systems, and assessment units. In the World 

Petroleum Assessment 2000, regions serve as organizational 

units and geologic provinces are used as prioritization tools.

The project divided the world into 8 regions and 937 geologic provinces. Provinces were ranked according to the discovered oil and gas volumes within each (Klett and others, 1997; 

Klett and others, 2000a). Seventy-six “priority” provinces 

(exclusive of the United States and chosen for their high ranking) and 26 “boutique” provinces (exclusive of the United 

States and chosen for their anticipated petroleum richness 

or special regional economic or strategic importance) were 

selected for appraisal of oil and gas resources.

A geologic province is an area 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 

places their location is based on other factors such as a specific 

bathymetric depth in open oceans.

Total petroleum systems and assessment units are delineated within each of the geologic provinces assessed for undiscovered oil and gas. Although the boundaries of total petroleum 

systems and assessment units are usually contained within a 

geologic province, it is not required. The petroleum system concept emphasizes the similarities in oil composition (Magoon 

and Dow, 1994), unlike geologic provinces and plays that 

emphasize similarities in the rocks. The mapped area of the total 

petroleum system, as defined for this study, includes all genetically related petroleum that occurs in seeps, shows, and accumulations (discovered and undiscovered) generated by a pod or 

by closely related pods of mature source rock (Klett and others, 

2000b). The area also includes the essential geologic elements 

(that is, reservoirs, seals, traps, and overburden rocks) that control the fundamental processes of petroleum generation, expulsion, migration, entrapment, and preservation. The “minimum” 

petroleum system is that part of a total petroleum system 

encompassing discovered shows, seeps, and accumulations 

together with the geologic space in which the various essential 

elements have been proved by these discoveries.

An assessment unit is a mappable portion of a total petroleum system in which discovered and undiscovered fields constitute a single, relatively homogeneous population. The methodology of our resource assessment is based on the probability 

of number and size of undiscovered fields and, therefore, is sensitive to the homogeneity of each population being assessed.

A total petroleum system might equate to a single assessment unit or, if necessary, may be subdivided into two or more 

assessment units such that each assessment unit is sufficiently 

homogeneous in terms of geology, exploration considerations, 

and risk to assess individually. Heterogeneity cannot be alleviated in all assessment units. In such cases, accumulation density 

and exploration concepts are not extrapolated across the entire 

assessment unit.

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:

The codes for the regions and provinces are listed in Klett and 

others (1997, 2000a).

Unit Name Code

Region Sub-Saharan Africa 7

Province Senegal Basin 7013

Total petroleum system Cretaceous-Tertiary Composite 701301

Assessment unit Coastal Plain and Offshore 70130101
2 Assessment of the Undiscovered Oil and Gas of Northwest Africa

Known 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. Increases in reported estimated total recoverable volumes are commonly observed from year to year. To address this 

phenomenon, the U.S. Geological Survey created a “reservegrowth” model. When applicable, this model is applied to the 

reported data, and the resulting “grown” data rather than the 

“known” data are used in the assessment process.

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 the Environmental Systems Research Institute 

ArcWorld 1:3 million digital coverage (Environmental Systems 

Research Institute, 1992). These boundaries are not politically 

definitive and are displayed for general reference only. Oil and 

gas field center points, shown in these figures, are reproduced, 

with permission, from Petroconsultants (1996).

Abstract

Undiscovered, conventional oil and gas resources were 

assessed in the Senegal Province as part of the U.S. Geological 

Survey World Petroleum Assessment 2000 (U.S. Geological 

Survey World Energy Assessment Team, 2000). Although 

several total petroleum systems may exist in the province, 

only one composite total petroleum system, the CretaceousTertiary Composite Total Petroleum System, was defined 

with one assessment unit, the Coastal Plain and Offshore 

Assessment Unit, having sufficient data to allow quantitative 

assessment.

The primary source rocks for the Cretaceous-Tertiary 

Composite Total Petroleum System are the CenomanianTuronian marine shales. The Turonian shales can be as much 

as 150 meters thick and contain Type II organic carbon ranging 

from 3 to 10 weight percent. In the Senegal Province, source 

rocks are mature even when situated at depths relatively shallow for continental passive margin basins. Reservoir rocks consist of Upper Cretaceous sandstones and lower Tertiary clastic 

and carbonate rocks. The Lower Cretaceous platform carbonate 

rocks (sealed by Cenomanian shales) have porosities ranging 

from 10 to 23 percent. Oligocene carbonate rock reservoirs 

exist, such as the Dome Flore field, which contains as much 

as 1 billion barrels of heavy oil (10° API, 1.6 percent sulfur) 

in place. The traps are a combination of structural closures 

and stratigraphic pinch-outs.

Hydrocarbon production in the Senegal Province to date 

has been limited to several small oil and gas fields around 

Cape Verde (also known as the Dakar Peninsula) from Upper 

Cretaceous sandstone reservoirs bounded by normal faults, of 

which three fields (two gas and one oil) exceed the minimum 

size assessed in this study (1 MMBO; 6 BCFG). Discovered 

known oil resources in the Senegal Province are 10 MMBO, 

with known gas resources of 49 BCFG (Petroconsultants, 

1996).

This study estimates that 10 percent of the total number of 

potential oil and gas fields (both discovered and undiscovered) 

of at least the minimum size have been discovered. The estimated mean size and number of assessed, undiscovered oil 

fields are 13 MMBO and 13 fields, respectively, whereas the 

mean size and number of undiscovered gas fields are estimated 

to be 50 BCFG and 11 fields.

The mean estimates for undiscovered conventional petroleum resources are 157 MMBO, 856 BCFG, and 43 MMBNGL 

(table 2). The mean sizes of the largest anticipated undiscovered 

oil and gas fields are 66 MMBO and 208 BCFG, respectively.

The Senegal Province is underexplored considering its 

large size. The province has hydrocarbon potential in both the 

offshore and onshore, and undiscovered gas resources may be 

significant and accessible in areas where the zone of oil generation is relatively shallow.

Introduction

The Senegal Province (fig. 1), which includes the onshore 

and offshore (to a water depth of 2,000 m) parts of the Senegal 

Basin, is situated along the northwestern African coast and 

includes parts of Western Sahara, Mauritania, Senegal, The 

Gambia, Guinea-Bissau, and Guinea. The Senegal Basin is 

classified as an Atlantic-type passive margin or marginal sag 

basin of Middle Jurassic to Holocene age overlying a Paleozoic 

basin (Wissmann, 1982). Figure 2 is a generalized geologic 

map of northwest Africa showing the location of Senegal 

and adjoining provinces. The northern limit of the Senegal 

Basin is the Precambrian Reguibate Shield in Morocco, and 

the southern limit is the Bove Basin of Guinea (fig. 3). The eastern edge of the basin is separated from the Taoudeni Basin by 

Precambrian rocks of the Mauritanide Mountains that were 

uplifted during the Late Paleozoic Hercynian Orogeny (figs. 2 

and 3).

The Senegal Basin is the largest of the northwest African 

Atlantic margin basins (De Klasz, 1978), with a total land area 

of about 340,000 km2

 and an offshore portion in excess of 

100,000 km2. The offshore portion of the basin was limited 

for this study to water depths of 2,000 m or less. Three major 

subbasins (fig. 3) have been recognized in the Senegal Basin: 

(1) the Mauritania offshore subbasin, which extends north 

from the Senegal River to the southern part of Western Sahara; 

(2) the Northern subbasin, which is located north of the Gambia 

River to the Senegal River; and (3) the Casamance subbasin, 

which extends south from the Gambia River through the 

Casamance region into Guinea-Bissau.
Senegal Basin Geology 3

There are both offshore and onshore hydrocarbon occurrences in several formations in the Senegal Basin. The best 

understood hydrocarbon occurrences in the Senegal Basin 

are in Cretaceous and Tertiary reservoirs. The lower Paleozoic 

rocks contain oil-prone organic matter, and recent seismic data 

have delineated a Permian-Triassic pre-salt clastic section that 

may contain hydrocarbon source rocks. The Jurassic and Lower 

Cretaceous rocks have been explored only nearshore where 

they contain Type III organic matter (terrestrial plant material) 

and might be potential sources of gas.

At least three total petroleum systems may exist in the 

Senegal Province: (1) the hypothetical Lower Paleozoic Total 

Petroleum System, (2) the hypothetical Sub-salt total petroleum 

system, and (3) the Cretaceous-Tertiary Composite Total 

Petroleum System. Drilling and production data available for 

this study are mostly limited to the Cretaceous and Tertiary 

rocks in the basin. Therefore, only the Cretaceous-Tertiary 

Composite Total Petroleum System with its contained Coastal 

Plain and Offshore Assessment Unit was assessed in this study. 

Due to limited drilling and production data, total petroleum system and assessment unit boundaries can only be approximately 

delineated and are subject to future revisions.

Senegal Basin Geology

The Senegal Basin formed at the culmination of a 

Permian to Triassic rift system that developed over an extensive 

Paleozoic basin during the breakup of North America, Africa, 

and South America. The Senegal Basin has undergone a complex history that can be divided into pre-rift (Upper Proterozoic 

to Paleozoic), syn-rift (Permian to Triassic), and post-rift 

(Middle Jurassic to Holocene) stages of basin development. 

The basin can be divided into a number of subbasins aligned in 

a north-south direction and delimited by an east-west fault system and other structural dislocations related to syn-rift tectonics.

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 Ruitter, 1977; Ziegler, 1988; Lambiase, 1989; 

Uchupi and others, 1976; Uchupi, 1989) and is represented by 

syn-rift rocks in the Senegal Basin. 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

0°

0°

30°

30°

30°

0 500 1,000 KILOMETERS

BURKINA

FASO

MAURITANIA

IVORY 

LIBERIA

COAST SIERRA LEONE

GUINEA

GUINEABISSAU

THE GAMBIA

GHANA

MALI

NIGER

SENEGAL

WESTERN SAHARA

TOGO

BENIN

Atlantic

Ocean



Province boundary

Coastal Plain and Offshore

 Assessment Unit boundary

 and Cretaceous Composite

 Total Petroleum System

Center of oil

 or gas field 

EXPLANATION

MOROCCO

ALGERIA AFRICA

30°

0°

0°

l



Figure 1. Location map showing the Senegal Province (7013) boundary, the Cretaceous-Tertiary Composite Total Petroleum 

System (701301), the Coastal Plain and Offshore Assessment Unit (70130101), and the center points for oil and gas fields.
4 Assessment of the Undiscovered Oil and Gas of Northwest Africa

Maurin, 1992). The opening of the Atlantic was not completed 

until Albian time. The presence of Triassic evaporites and clastics in the Senegal Basin provides evidence that rift-basin sedimentation occurred during this time, associated with the 

breakup of northwest Africa and North America. The basal 

Jurassic and lowermost Cretaceous limestones of the MesozoicTertiary platform (figs. 3 and 4) are most likely related to the 

Tethys Sea rather than the South Atlantic because the final 

opening of the Atlantic did not take place before Albian time.

Pre-rift Section

The pre-rift section consists of Precambrian- to Devonianage rocks that outcrop in the Bove Basin of southern Senegal 

and Guinea, which is an extension of the Taoudeni Basin 

(figs. 2 and 3). The most complete pre-rift section was recognized in the Diana-Malari (DM–1) and Kolda (KO–1) wells 

(fig. 3), which penetrated Ordovician, Silurian, and Devonian 

rocks in southernmost Senegal, also known as the Casamance

Taoudeni Basin

7035

Senegal

7013

12°

8°

4°

16°

20°

24°

28°

18° 12° 6° 0°

West African

 Shield

7021

Baffa 7105

Reguibate Shield

Aaiun-Tarfaya Basin

2066

West African Coastal

7173

Gulf of Guinea

7183

Reguibate

Uplift

2068

Volta

7114

0 500 1,000 KILOMETERS

Quaternary rocks

Tertiary rocks

Cretaceous rocks

Paleozoic rocks

Precambrian rocks

Igneous rocks

Water

Oil and Gas

 Province boundary

Assessment Unit

 boundary

EXPLANATION

Figure 2. Generalized geologic map of northwest Africa (Persits and others, 1997) showing the Reguibate Shield, province boundaries, selected province names and codes as defined in Klett and others (1997, 2000a) and the boundary of the Coastal Plain and

Offshore Assessment Unit for the Senegal Province. The Baffa Province includes the Paleozoic Bove Basin.
Senegal Basin Geology 5

?

?

0 100 KILOMETERS

21° 19° 17° 

13°

15°

17°

DSPD 368

Senghor

Seamount

Cape Verde

Seamount

DSDP 367

DSDP 367

Salt

basin

Mesozoic

Carbonate

Shelf Edge

MAURITANIA

ATLANTIC

 OCEAN

Dakar

LIMIT OF PROSPECTIVE AREA

2-SECOND SEDIMENT ISOPACH

Dome Flore

Salt basin

THE GAMBIA

Bove Basin

(Paleozoic)

Basement at 4,000 meters

Basement at 1,000 meters

SENEGAL

CAPE VERDE

Gambia River

Casamancesubbasin

Northernsubbasin

SENEGAL-CASAMANCE

DM-1 KO-1

Bissau

15°

Mauritaniasubbasin

Approximate2,000-meterbathymetriccontour

Approximate200-meterbathymetriccontour

GUINEA-BISSAU

Mesozoic shelf edge— approximate 200-meter bathymetric contourProvince boundary— approximately locatedGrabenCountry boundary

Onshore part of the Senegal Basin

Salt dome

DM-1 Oil and gas exploration

 drill hole and number 

Subbasin boundary— approximately located

Deep sea drilling project drill hole and number

EXPLANATION

Senegal 

Casa

m

an

ce

R

River 

Figure 3. A generalized map of the central and southern parts of the Senegal Basin showing part of the Senegal Province, the Mauritania, Nortbasins, the Mesozoic shelf edge, the northern and southern salt basins, the Mauritanide Mountains, the Bove Basin, the Deep Sea Drilling Proje2-second sediment isopach, and the onshore depth to basement isopachs. Also shown are the appropriate locations of the Diana-Malari (DM–1that penetrated the Silurian source rocks (Buba Shale). Brick pattern delineates the Mesozoic carbonate rock platform. Modified from Bungene
6 Assessment of the Undiscovered Oil and Gas of Northwest Africa

Stratigraphy Lithology Description Thickness (meters)

Cretaceous

Lower Upper

Mesozoic Paleozoic

Precambrian undifferentiated Metamorphic rocks

Cambrian

Ordovician

Silurian

Devonian

Triassic

Jurassic

Limestone -claystone-sandstone

Limestone-marls, shales*

Sandstone

Shale/sandstone

Bituminous shales*

Shales/siltstone/sandstone

Limestone/shales/sandstone

Limestone/siltstone/sandstone

Limestone/shales/evaporites

Anhydrite

Massive salt

Gabu Sandstone

Pirada Shale

Cantari Shale

Caium Sandstone

Buba Shale*

Bafata Shale

Cusselinta Sandstone

Clastics and lacustrine shales?*

Neocomian

Aptian

Albian

Cenomanian

Turonian

Senonian

Maastrichtian

Shales/sandy shales*

Cenozoic

Tertiary

Oliogocene

Eocene

Miocene

Paleocene

600

300

150

150

300

200

900

600

650

1,100

500

2,000

2,000

300

150

400

1,400

400

500

350

Total

petroleum

systemCretaceous-Tertiary Composite Sub-salt (hypothetical) Lower Paleozoic (hypothetical)

Figure 4. Generalized stratigraphic column showing the three total petroleum systems in the Senegal Basin 

and the rocks found in the Casamance region of southern Senegal and Guinea-Bissau, includes the Bove 

Paleozoic Basin, which is an extension of the Taoudeni Basin of Mauritania and Mali. * denotes potential source 

rocks. Modified from Dumestre and Carvalho (1985).
Senegal Basin Geology 7

subbasin. The Cambrian rocks are known only from outcrops 

in the Bove Basin. The pre-rift section might be as much as 

3,500 m thick in the Bove Basin, whereas over 5,000 m of preMesozoic rocks are interpreted from seismic data in the deeper 

offshore part of the Senegal Basin (Hinz and Martin, 1995). 

The Precambrian basement consists of metamorphic rocks 

of unknown thickness (fig. 4). The Cambrian sedimentary section is as much as 1,250 m thick and contains three units: the 

Pirada Shale, the Cantari Shale, and the Caium Sandstone. The 

Ordovician Gabu Sandstone attains a maximum thickness of 

1,400 m. The Silurian section contains the graptolitic Buba 

Shale source rocks, which are as much as 400 m thick. The 

Devonian rocks are widespread and are the youngest Paleozoic 

rocks known in the basin. The Lower Devonian consists of the 

Cusselinta Sandstone, a 150-m-thick unit, and the Middle and 

Upper Devonian are represented by the 300-m-thick Bafata 

Shale. The section is known to occur under much of the southern one-half part of the basin (south of the Mauritanian border).

Two main tectonic regimes have been recognized in 

the Paleozoic pre-rift part of the Senegal Basin. An extensional 

system is defined south and east of the Casamance subbasin and 

south of Cape Verde (fig. 3) in which a pre-Hercynian structural 

style of horsts and grabens and tilted blocks was preserved, 

and a compressional regime has been defined in the central and 

northern parts of the basin resulting from the combined effect 

of Caledonian and Hercynian orogenies (figs. 5 and 6).

Syn-rift Section

The syn-rift section of the southern Senegal Basin 

consists principally of thick Triassic to Early Jurassic evaporites (Uchupi and others, 1976) overlying inferred Triassic 

clastic rocks, which may include organic-rich lacustrine rocks 

(fig. 4). The syn-rift evaporite section in the Casamance subbasin may be as much as 2,000 m thick and consists mostly 

of salt with an anhydrite cap, whereas the underlying clastic 

section may be as thick as 1,500 m (fig. 7). In the Northern 

and Mauritania subbasins, the evaporite section might be as 

thick as 2,000 m (fig. 8), whereas the thickness of the underlying Triassic clastic section is unknown but may have a thickness similar to the Casamance subbasin (fig. 7). Except for 

a few salt structures (Ayme, 1965; Wissmann, 1982) in the 

Casamance and Mauritania subbasins, the Northern subbasin,

GUINEA-BISSAU

GUINEA

0 50 100 KILOMETERS

Atlantic Ocean

SENEGAL

SD-1

CG-1

CO-1

SF-1

PGO-1

PGO-4

PGO-6

PGO-3

PGO-2

GBO-1

PGO-1

?

?

? ?

Bijagos Archipelago

Geba River

Bissau

100

1,000

2,000

A

A'

Dry hole

Oil show

City

Bathymetric

 contour (meters)

100

EXPLANATION

Figure 5. Location map for Guinea-Bissau showing line of section and oil and gas exploration holes, southern Senegal 

Basin, northwest Africa. Cross section A to A’ is shown in figure 6. Modified from Dumestre and Carvalho (1985).
8 Assessment of the Undiscovered Oil and Gas of Northwest Africa

? ? EXPLANATIO

Sea 

level

Deep outer

continental shelf

Shallow inner

continental shelf

Onshore wells projected

Mouth of Geba Ri

SW 

2,0004,0006,0008,000

10,00012,000

Atlantic

Ocean

Tertiary

Triassic salt

Triassic

salt

?

Permo - Triassic

clastics?

Oligocene-Miocene

Paleocene-Eocene

Senonian

Cenomanian-Turonian

Aptian-Albian

Neocomian Neocomian

Neocomian

Jurassic

Jurassic

Jurassic

Unconformity-Paleozoic surface

Cambrian

Infra-Cambrian and Precambrian

Bijagos archipelago

PETROLEUM GEOLO

Potential source rock

Clastic reservoir faciesCarbonate reservoir facies 

Zo gOi m p

Paleozoic clastics

PGO-6 PGO-2 PGO-3 CG-1 CO-1 

A 

METERS

Figure 6. Schematic stratigraphic northeast to southwest cross section, Guinea-Bissau, southern Senegal Province, showing potential reserv

with the zone of oil generation and possible oil migration pathways. Modified from Dumestre and Carvalho (1985).
Senegal Basin Geology 9

and offshore Guinea-Bissau, drilling has not yet penetrated 

these rocks, but new and reprocessed seismic data have delineated this section in some parts of the Senegal Basin. In the 

southern Senegal Basin, the evaporite section has undergone 

extensive halokinesis evidenced by salt diapirs intruding 

the overlying Cretaceous and Tertiary rocks (fig. 6). Seismic 

studies have shown salt diapirs in offshore Mauritania, confirming that this section also is present in the northernmost part of 

the basin (fig. 3). Salt diapirs have not been recognized in the 

Northern subbasin (fig. 3). Figure 9 is a schematic east-to-west 

cross section through The Gambia where the syn-rift section

Lithology Thickness

(meters)

400-650

90-300

150-450

50-150

300-900

500-1,050

700

300-1,200

500-2,000?

100

100

500-2000?

?-1500?

150-250

100-350

30-110

Stratigraphy

Cretaceous-Tertiary Composite

Total Petroleum System

Sub-salt Total

Petroleum System

West East

Cenozoic

20-350

Cenomanian

Albian

Aptian

Neocomian

Jurassic

Triassic

Mesozoic

Cretaceous

Lower Upper

Tertiary

Senonian

Campanian

Maastrichtian

Turonian

Paleocene

Eocene

Miocene

Oligocene

Figure 7. Generalized stratigraphic column of the Casamance 

offshore subbasin, south of Cape Verde, Senegal Basin, northwest Africa. In the Casamance subbasin, the best source rocks 

are in the Cenomanian and Turonian units. Possible source 

rocks may exist in the clastic section below the evaporites. 

Modified from Dumestre (1985).

Jurassic

Neocomian

Aptian

Albian

Cenomanian

Turonian

Senonian

Campanian

Maastrichtian

Paleocene

Eocene

Miocene

Cretaceous

Upper Lower

Mesozoic

Tertiary

Cenozoic

Stratigraphy

? - >2000

100?

Triassic

? - 2,000?

? - 1,500?

Cretaceous-Tertiary Composite

Total Petroleum System

Sub-salt Total

Petroleum System

Lithology Thickness

(meters)

30-200

100-600

100-200

650-1,250

100-450

300-1,000

50-120

150-950

200-1,200

150-1,450

400-1,200

West East

Figure 8. Generalized stratigraphic column for the Northern 

subbasin and the southern part of the Mauritania subbasins (see 

fig. 3). Type II and III source rocks are found in the Cenomanian 

and Turonian units. Modified from Dumestre (1985).

is present but the evaporites exhibit little halokinesis. The 

onshore part of central Senegal Basin has a thinner syn-rift section consisting of probable Triassic age continental clastics and 

organic-rich lacustrine shales (fig. 10). The northwest Africa 

basins have been virtually undisturbed by extension since the 

Jurassic (Lambiase, 1989).
10 Assessment of the Undiscovered Oil and Gas of Northwest Africa Cenomanian-Turonian Aptian Albian Offshore Onshore Senonian- Tertiary ? Atlantic Ocean Slope 

Paleozoic Paleozoic Neocomian-Jurassic B B B C D D Sea level 1,000 2,000 3,000 4,000 5,000 6,000 7,000 8,000 9,000 A 

Triassic

UnconformPaleozoic 

A?

ert ry

E E Senonian-Maastrichtian

WEST

EXPLANATION

Total petroleum systems with potential oil prospects

Lower Paleozoic Total Petroleum System - Unassessed Prospect A - Ordovician-Devonian reservoirs, Silurian source?Sub-salt Total Petroleum System - Unassessed Prospect B - Lower Paleozoic? and Triassic reservoirs, Triassic and (or) Silurian source?Cretaceous-Tertiary Composite Total Petroleum System - Assessed Prospect C - Albian/Aptian reservoirs, Turonian/Cenomanian source Prospect D - Albian carbonate and sandstone reservoirs, Turonian/Cenomanian source Prospect E - Tertiary/Upper Cretaceous reservoirs, Turonian/Cenomanian source

14°

15°

100 m50 m 1,000 m 200 m

A

A

Jammah 1 Sarakunda 1 Brikama 1 projected

ShaleClasticsSandstone

CarbonateSalt

Anhydrite

Unconformity

Fault

Well location

METERS

Figure 9. Schematic east-to-west cross section through The Gambia showing locations of potential oil prospects with their associated total pe

source rocks. Modified from Bungener (1995).
Senegal Basin Geology 11

AtlanticOcean

EXPLANATION

3

3

4

4

5

6

6

7

?

?

?

?

?

? ? 7

1 2

3

4

5

3,403.3m

CV-1

3,855m.

1,623m

DN-4 Do-1 DS-1 PI-2 Tl-1 

EocenePaleocene

Upper CretaceousTuronian to CenomanianLower Cretaceous

Lower Cretaceous-JurassicTriassicFolded Precambrian

Basement, age unknownExtrusive and intrusive rocks

12

345

67

1,036m.

2,104m.

6 

CV-1

DN-4

P1-2

T1-1 Do-1

CAPEVERDE

DS-1 D1-1

Sene

Index 

A A'

THE GAMBIA Oil and (or) gas

Sea level

1,000

3,000

5,000

7,000

9,000

WEST 

A 

4,010m.

METERS

Figure 10. Schematic stratigraphic east-to-west cross section through Cape Verde showing producing zones, Senegal Basin, northwest Africa. 

Petroconsultants (1979).
12 Assessment of the Undiscovered Oil and Gas of Northwest Africa

Post-rift Section

Marine deposition began during the Early Jurassic in 

Morocco with transgressing seas reaching the southern end 

of the Senegal Basin by the Late Jurassic (Uchupi and others, 

1976). The post-rift section in the Senegal Basin consists of 

Middle Jurassic to Holocene rocks. The section increases in 

thickness from east to west across the Senegal Basin. The basal 

unit of the post-rift sequence is a thick, carbonate-rock shelf of 

Middle to Late Jurassic to Neocomian age that is genetically 

related to the Tethys Sea. The carbonate-rock unit ranges in 

thickness from 2,300 m to 3,200 m in the Mauritania, Northern, 

and Casamance subbasins (figs. 7 and 8). During the Aptian 

and Albian this carbonate-rock unit continued to be deposited 

in the central offshore part of the basin, whereas in the northern 

part of the Mauritania subbasin and southernmost part of the 

Casamance subbasin it was replaced by deeper water sediments. 

The Cenomanian rocks of the post-rift section are represented 

by thick marine shales interbedded with marginal marine sandstones, deposited after the opening of the Atlantic Ocean. Minor 

carbonate-rock banks and reefs are present. The Turonian marks 

the time of maximum Cretaceous transgression and is represented by widespread black, and commonly bituminous, shale 

that is an important hydrocarbon source rock in the basin. 

The Turonian shales range in thickness from 50 to 150 m. The 

Senonian stage was a time of major marine regression that culminated with the deposition of widespread and thick sandstone 

units in the Maastrichtian. Tertiary sediments are unconformable 

with the Upper Cretaceous and consist primarily of marine 

shales and carbonates. The thickness of the post-rift section is 

about 12,000 m in the depocenter near the GBO–1 well (fig. 5) 

in the Guinea-Bissau part of the basin (Dumestre and Carvalho, 

1985).

Two major stratigraphic domains delimited by the present 

shelf edge are recognized within the Senegal Basin. The shelf of 

northwest Africa is characterized by a 35- to 100-km-wide plain 

cut by sparse, shallow channels, especially north of Cape Verde 

(Egloff, 1972), while south of Cape Verde the shelf is more 

incised by canyons and affected by recent deltaic deposits. The 

shelf and western edge of the Jurassic to Lower Cretaceous 

carbonate-rock platform (fig. 3) roughly parallels the 200-m 

bathymetric contour.

East of the present shelf edge is a gently westward dipping 

Mesozoic and Cenozoic platform characterized by prograding 

deposits separated by regressive episodes and regional unconformities. The section thins eastward so that the Paleozoic sequence 

is accessible to drilling over a large area. The Mesozoic section 

has not undergone any orogenic or compressional stress. Normal 

faults generally strike north-south and are typically downthrown 

to the west, reflecting the predominant tensional structural style 

during the Mesozoic and Cenozoic. Salt diapirs in the offshore 

Casamance and Mauritania subbasins have pierced the Mesozoic 

section and are prominent structural targets for exploration.

West of the shelf edge (greater than 200-m water depth) 

where the sedimentary thickness can exceed 12,000 m, the 

regional structural style is dominated by gravitational features 

such as listric faulting and slumping, reflecting a slope environment and the influence of the opening of the Atlantic. The current sedimentary depocenter is located west of the shelf edge in 

water depths of 1,000–2,000 m.

Petroleum Occurrence in the Senegal Basin

There are both offshore and onshore hydrocarbon occurrences in several formations in the Senegal Basin. The best 

understood hydrocarbon occurrences in the Senegal Basin are in 

Cretaceous and Tertiary reservoirs in the Casamance, Northern, 

and Mauritania subbasins. The lower Paleozoic rocks contain 

oil-prone organic matter, and recent seismic data have delineated 

a pre-salt clastic section in the Lower Triassic. The Jurassic and 

Lower Cretaceous rocks have only been explored nearshore and 

contain continental-derived organic matter, which may be gasprone.

Hydrocarbon production in the Senegal Basin has 

been limited to several small oil and gas fields (fig. 10) east 

of Cape Verde (Brown, 1981; Woodside, 1983). Discovered 

oil resources in the Senegal Basin are 10 MMBO, with gas 

resources of 49 BCFG (U.S. Geological Survey World Energy 

Assessment Team, 2000, disc 4, data file provvol.tab).

Hydrocarbon Source Rocks in the Senegal Basin

The most effective Cretaceous source rocks related to 

hydrocarbon discoveries and production in the Senegal Basin 

are the Cenomanian-Turonian marine shale units (figs. 7 and 8). 

Cenomanian to Turonian source rock units developed in two 

different subbasins (fig. 11). The first area is located north of 

Cape Verde and includes the Mauritania and Northern subbasins 

(fig. 3) where samples from wells located along the shelf boundary have exhibited good source rocks, up to 380 m thick, containing Type II and Type III organic matter (fig. 11) with hydrocarbon source potentials between 3 and 21 kg/ton (Reymond and 

Negroni, 1989). The second area is located south of Dakar in 

the Casamance subbasin. Reymond and Negroni (1989) state 

that the richest source rocks here contain Type II organic matter 

surrounded by a large area containing Type III organic matter 

(fig. 11). These source rocks display source potentials ranging 

between 5 and 75 kg/ton and range from 330 to 490 m thick. The 

Turonian interval contains bituminous shales that were probably 

deposited under anoxic conditions (Kuhnt and Wiedmann, 1995) 

with thickness up to 150 m (fig. 4). Samples analyzed from the 

Casamance Maritime 10 well (fig. 11) contain Type II kerogen 

with total organic carbon (TOC) values ranging from about 7 

to more than 10 percent. Geochemical data obtained from Deep 

Sea Drilling Project well samples (DSDP 367 and 368, fig. 3) 

identified potential Neocomian to Cenomanian source rocks 

beyond the 2-second sediment isopach in the Senegal Basin 

(Tissot and others, 1980; Rullkötter and others, 1982). The 

source rocks contain mostly Type II kerogen with TOC values 

ranging from about 3 to more than 10 percent. Minor source
Petroleum Occurrence in the Senegal Basin 13

0°

0°

30°

30°

30°

High

geothermal

gradient due

to salt diapirism

(>30° C/km)

High geothermal

gradient due

to volcanism

MAURITANIA

SENEGAL

MALI

GUINEA-BISSAU

GUINEA

SIERRA

LEONE

THE GAMBIA

Type II organic matter

Type II–III organic matter

Type IV organic matter

Control well

35 Geothermal gradient

(in oC/km)

35

35

35

30

30

30

25

30

40

0 100 KILOMETERS

25

40

Dome Flore

heavy oil

accumulation

Diam Niadio

field

DM-1

KO-1

Exploration well

penetrating Silurian rocks

CM-1

Cap Vert Marine-1

Dakar Marine-2

PGO-3

35

EXPLANATION

Figure 11. Distribution of organic matter in the Cenomanian to Turonian source rock. Also shown are the approximate 

locations of the Diana-Malari (DM–1) and Kolda (KO–1) wells that penetrated the Silurian Buba Shale source rocks (TOC 

as much as 5.5 percent) and the Casamance Maritime 1 (CM–1) well that penetrated the Turonian bituminous shales 

(TOC from 7 to more than 10 percent). Modified from Reymond and Negroni (1989).
14 Assessment of the Undiscovered Oil and Gas of Northwest Africa

rocks within the post-rift section have been identified (Dumestre 

and Carvalho, 1985; Reymond and Negroni, 1989) including the 

Senonian and Maastrichtian (2–5 kg/ton, Type II and III), the 

Paleogene (greater than 5 kg/ton, Type II with detrital Type IV), 

and the Miocene to Pliocene (2–5 kg/ton, Type II).

A second important source rock has been recognized 

recently and consists of graptolitic Silurian shale up to 400 m 

thick (fig. 4) in the southern one-half of the Senegal Basin. The 

Buba Shale may be equivalent to the oil-rich Silurian Tanezzuft 

Formation of North Africa (fig. 4), which is an important source 

rock in North Africa and the Middle East. The distribution 

of marine Silurian rocks, which contain oil-prone black graptolitic shales, is shown in the Silurian paleogeographic map in 

figure 12. Measurements conducted on samples from the DianaMalari (DM–1) and Kolda (KO–1) wells (figs. 3 and 11) and 

outcrop studies in the Bove Basin and the Guinea Paleozoic 

Basin (Baffa Province, fig. 2) show these source rocks contain 

black amorphous organic matter and have TOC’s ranging from 

1 to 5.5 percent (Reymond and Negroni, 1989).

A third regional source rock may be related to the synrift section in the Senegal Basin. The source rocks are inferred 

Upper Permian-Lower Triassic lacustrine rocks that underlie 

the thick Triassic salt unit. Recent seismic studies have delineated this clastic section in the Casamance region of southern 

Senegal (figs. 6 and 9). The syn-rift section does not crop out 

in the Senegal Basin, and drilling has not penetrated it. Several 

analog Upper Permian? to Triassic rift basins have been recognized in Morocco, northwest Africa, and North America and 

contain clastic, lacustrine, and evaporite rocks (Van Houten, 

1977; Evans, 1978; Manspeizer, 1981). The Newark Basin of 

North America is one of these rift basins that contain lacustrine 

beds with Type I and Type II organic matter ranging from more 

than 2 to 35 percent TOC (Ziegler, 1983). These beds are highly 

variable in organic content and thickness. A younger but similar 

syn-rift section related to the opening of the South Atlantic 

is located along the west-central African coast in the CongoCabinda basin off the coast of Congo. There, the section 

consists of Neocomian to Barremian lacustrine rocks of the 

Melania Formation overlain by Aptian evaporite rocks of the 

Loeme Formation. The lacustrine rocks contain both Type I 

and Type II organic matter averaging 6.1 percent and reaching 

as high as 20 percent (Schoellkopf and Patterson, 2000).

Burial history profiles and maturation studies have been 

carried out on several wells within the Senegal Basin. Maturation studies were determined from geothermal gradient data and 

samples analyzed from wells that penetrated the Mesozoic and 

Paleozoic units, and data extrapolated from outcrops in the Bove 

Basin for the Paleozoic part of the section. Two periods of oil 

generation have been determined for the Silurian source rocks 

(fig. 13); the first period began in the Carboniferous (300 Ma) 

and continued into the Hercynian orogeny (about 250 Ma). Generation paused during the Permian and Triassic, resumed during 

the Cretaceous, and continues to the present. The zone of oil generation ranges in depth from 1,850 to 4,000 m in the southern 

part of basin (fig. 6). In the eastern part of the Bove Basin, the 

zone of oil generation is elevated, probably in response to higher 

heat flow that may be due to intrusions or a local hot spot.

Hydrocarbon Generation and Migration in the Senegal 

Basin

The most significant hydrocarbon production within the 

Senegal Basin is from the Mesozoic section underlying the 

Cape Verde Peninsula onshore and the Casamance subbasin 

offshore. The Cretaceous source rocks display a highly variable 

maturation history. The Albian source rocks in the Mauritania 

subbasin started to generate oil in the late Eocene, whereas the 

Turonian and Senonian source rocks began to generate oil in the 

Miocene (fig. 14, drill hole V–1). The Upper Cretaceous source 

rocks began generating oil in the Miocene (fig. 14, drill hole 

COP–1). The Paleocene source rocks were found to be immature in the Mauritania offshore (fig. 14, drill hole COP–1). Two 

main areas of hydrocarbon generation have been delineated in 

the Senegal Province (fig. 15). The first area is located in the 

offshore Mauritania and northernmost Northern subbasins 

(figs. 3 and 15), whereas the second area is located in the 

Casamance subbasin and Guinea-Bissau offshore. North of 

Cape Verde, the amount of generated hydrocarbons increases 

seaward due to the combined effect of the thickening and deepening of the Cenomanian to Paleocene source rocks. The quality 

of source rocks onshore north of Cape Verde is not favorable 

for the generation of oil. In the Casamance and Mauritania subbasins, the Triassic diapiric salt (fig. 3) has induced a modification of maturation gradients because of the good thermal conductivity of the salt. Within the Casamance subbasin at least 

2,500 tons of hydrocarbons per square kilometer have been 

generated (fig. 15) mainly from the Cenomanian and Turonian 

sources (Reymond and Negroni, 1989).

Present depth of the zone of oil generation ranges from less 

than 1,000 to more than 3,000 m depending upon the local geological and thermal parameters in the Senegal Basin (figs. 6 and 

16). The zone of oil generation in parts of the Casamance and 

Mauritania subbasins is relatively shallow due to elevated geothermal gradients related to salt diapirism. A shallow zone of oil 

generation in the vicinity of Cape Verde is related to volcanism 

and ranges in depth from 900 m (Dakar Marine-2) to 1,200 m 

(Cap Vert Marine-1). Reymond and Negroni (1989) measured 

geothermal gradient values of nearly 45 °C/km in these wells 

(fig. 11). In areas where the average geothermal gradient is 

about 30 °C/km (fig. 11), the top of the zone of oil generation 

ranges from 2,285 to 2,680 m. The top of the zone of oil generation is at 2,800 m in the PGO–3 well, where Cenomanian 

source rocks are immature (figs. 5 and 6). Gas resources may 

be very significant and accessible in areas where the zone of oil 

generation is relatively shallow. Migration of hydrocarbons 

most likely began in the late Miocene and continues to the 

Holocene.

Maturity of the source rocks in the basin increases 

southward. This may be somewhat misleading because of the 

lack of data north of Cape Verde. A zone of salt diapirs off 

the Mauritania coast may be more widespread than previously 

thought and may have caused increased maturation of 

Cretaceous source rocks.
Petroleum Occurrence in the Senegal Basin 15 Silu

 de

AFRICA

SOUTH

AMERICA

GONDWANALAND

ANTARC

Mid-European

Ocean

Out da

20°30°40°50°60°70°

EXPLAN

Figure 12. Paleogeographic reconstruction of the Silurian Period showing relative positions of continents and areas of deposition for graptolit

Modified from Clifford (1986).
16 Assessment of the Undiscovered Oil and Gas of Northwest Africa PERCENTAGE OF POTENTIAL

HYDROCARBONS GENERATED

PERCENTAGE OF POTENTIAL

HYDROCARBONS GENERATED

AGE, IN MILLIONS OF YEARS AGE, IN MILLIONS OF YEARS

600 400 300 200 100 0 500

Top Silurian

2,205 meters

Base Silurian

2,330 meters

Oil generation

zone

Beginning of oil

generation

Stratigraphic test drill hole

Diana-Malari (DM–1)

200 150 125 100 75 50 25 0 175

Beginning of 

 oil generation

Oil generation zone

Jurassic

4,200 meters Base

Neocomian

2,200 meters

CenomanianTuronian

1,140 meters

Drill hole DS–1 

90

80

70

60

50

40

30

20

10

0

80

70

60

50

40

30

20

10

0

PERCENTAGE OF POTENTIAL

HYDROCARBONS GENERATED

PERCENTAGE OF POTENTIAL

HYDROCARBONS GENERATED

AGE, IN MILLIONS OF YEARS AGE, IN MILLIONS OF YEARS

100 75 50 25 0

Oil generation zone Oil generation zone

Beginning of

oil generation

Albian

Turonian

Senonian

Drill hole V–1

(Mauritania offshore)

Drill hole COP–1

(Mauritania offshore)

50

40

30

20

10

0

100 75 50 25 0

Beginning of 

oil generation

50

40

30

20

10

0

Campanian

CampanianMaastrichtian

Paleocene

Figure 13. Examples of hydrocarbon maturation evolution in the Senegal Basin involving the Silurian, Jurassic, basal 

Neocomian, and the Cenomanian to Turonian source rocks. Maturity levels are expressed in percentage of potential 

hydrocarbons generated. Modified from Reymond and Negroni (1989).

Figure 14. Examples of hydrocarbon maturation evolution on the shelf edge in the Senegal Basin involving the Albian, 

Turonian, Senonian, Campanian, Maastrichtian, and Paleocene source rocks. Maturity levels are expressed in percentage 

of potential hydrocarbons generated. Modified from Reymond and Negroni (1989).
Petroleum Occurrence in the Senegal Basin 17

SIERRA

LEONE

GUINEA

MALI

GUINEA-BISSAU

SENEGAL

SENEGAL

MAURITANIA

THE GAMBIA

0 100 KILOMETERS

Atlantic

Ocean

1,000 Isogeneration contours in

 1,000 tons of hydrocarbon

 per square kilometer

Exploration well

Diam Niadio

field

Dome

Flore

heavy oil

accumulation

25

100

25

25

500

500

?

?

?

?

?

?

?

?

?

2,500

1,500

1,500

1,000

1,000

100

500

0°

0°

30°

30°

30°

CAPE VERDE

V-1

COP-1

CM-10

Casamance

subbasin—

area 2

Mauritania

subbasin—

area 1

Northern subbasin

Subbasin boundary—

 approximately located 

EXPLANATION

Figure 15. Isogeneration map of the Cenomanian to Paleocene source rocks in the Senegal Province. Two main 

source/generation areas, the Casamance subbasin and a large offshore area in the Mauritania subbasin, were delineated using Rock-Eval; maturity levels expressed in percentage of potential hydrocarbons generated (fig. 14) and net thickness of the source rocks. Modified from Reymond and Negroni (1989).
18 Assessment of the Undiscovered Oil and Gas of Northwest Africa

EXPLANATION

EXPLANATION

Offshore

Offshore

Offshore

Onshore

Onshore

Onshore

Mature zone

+

KILOMETERS KILOMETERS KILOMETERS

1

2

3

4

5

6

7

1

2

3

4

5

6

7

1

2

3

4

5

6

7

8

+

+

+ +

+

+ +

+

+ +

Paleocene

Jurassic

Upper Cretaceous

Lower Cretaceous

Mature zone

Northern part

Cenomanian-Turonian

Oligocene

Eocene

+ +

+

+

+

+ + +

+

+

+

+

lower Senonian

Lower

Cretaceous

Jurassic

Central part

Oligocene-Miocene

lower Eocene

Maastrichtian

Upper

Cretaceous

Sea

level upper Senonian

Paleocene

PermianTriassic

Triassic

Triassic ?

Turonian

+ +

+

+ +

+

+

+ +

+

+

+ +

+ +

+

+

+

+

+

+

+

+

+

+

+

+

+

+

+

+

+

+

+

+ +

+ +

+ +

+

+ +

Southern part Sea

level

Sea

level

lower-upper Miocene

Paleocene to lower Miocene

Senonian

Aptian-Albian

Neocomian

Devonian

Carboniferous-Permian

Silurian

Ordovician

Cambro-Ordovician

Basement

Basement

Basement

Mature zone

Miocene-Pliocene

EXPLANATION

Figure 16. Schematic cross sections showing the approximate position of the zone of oil generation in the northern, central, 

and southern Senegal Province, northwest Africa. Zone of gas generation was not determined because gas data were not 

available. Modified from Reymond and Negroni (1989).
Total Petroleum Systems of the Senegal Province 19

Hydrocarbon Reservoirs, Traps, and Seals in the 

Senegal Basin

The Mesozoic-Cenozoic section of the Senegal Basin 

can exceed 10,000 m in thickness and contains several primary 

reservoirs and seals: (1) Jurassic-Lower Cretaceous carbonate 

section sealed by Cenomanian or other Lower Cretaceous 

shales; (2) Upper Cretaceous sandstone units and overlying 

shale units; and (3) lower Tertiary clastic and carbonate-rock 

units and overlying and intercalated shale units (figs. 6, 9, and 

10). Cretaceous deltaic sandstone (Clifford, 1986) with porosities ranging from 17 to 25 percent are present in the Mauritania 

offshore (fig. 17). The Jurassic-Lower Cretaceous carbonaterock platform has never been fully penetrated by drilling but 

does show good porosities ranging from 10 to 23 percent 

(figs. 17 and 18). Reef prospects on the shelf edge remain to 

be explored. Upper Cretaceous sandstone sequences in the eastern part of the basin become interbedded with shale to the western offshore part of the basin. Maastrichtian sandstones up to 

30 m thick occur at Dome Flore, with porosities ranging from 

20 to 30 percent, and contain light oil (33.6° API). In the Dome 

Flore area, an excellent Oligocene carbonate-rock reservoir 

exists and contains up to 1 billion barrels of heavy oil (10° API, 

1.6 percent sulfur) in place. About 40 km east of Dakar, several 

shallow oil and gas discoveries were made in the 1950’s. Following a geologic reinterpretation of the area in 1984 (Dumestre, 

1985), these wells and two new wells were found to be productive, with rates up to 300 barrels of oil per day (BO/D) and 

2.4 million cubic feet of gas per day (MMCFG/D). Currently, 

only a small amount of gas is being produced from the Diam 

Niadio field (fig. 11).

The Mesozoic-Cenozoic section in the Senegal Basin contains diverse oil and gas trapping configurations. These include 

salt-related structures, structures related to volcanic intrusion, 

growth-fault-related traps, slope truncation traps along the 

present shelf edge, sandstone pinch-outs along the eastern margin of the Senegal Basin, Jurassic-Lower Cretaceous carbonate 

bank deposits, and possible turbidite-related stratigraphic traps. 

Seals consist of Mesozoic and Cenozoic marine shales and 

faults.

Sandstone reservoirs associated with syn-rift rocks 

might be present and interbedded with the inferred PermianTriassic source rocks underlying the Triassic salt (fig. 9). The 

thick Triassic salt is the major seal in the syn-rift section in the 

Senegal Basin.

Potential sandstone reservoirs are abundant in lower 

Paleozoic rocks based on measured sections in the Bove Basin 

and analyzed samples from the DM–1 and KO–1 stratigraphic 

test wells (fig. 3). The Ordovician sandstones are intensely fractured and could constitute good secondary reservoirs, whereas 

the Devonian fine- to coarse-grained sandstone beds have 

porosities ranging from 15 to 20 percent. In the onshore portion 

of the Paleozoic basin, regional seismic data have shown that 

the Paleozoic section has been faulted and could form traps in 

conjunction with the Paleozoic unconformity (fig. 6). Interpretation of seismic data shows that the Paleozoic unconformity is 

at a depth of about 10,000 m at the PGO–3 (fig. 6) exploration 

hole in the Guinea-Bissau offshore. The Paleozoic reservoirs 

were not assessed in this study.

Total Petroleum Systems of the Senegal 

Province

At least three total petroleum systems (TPS) may be 

present in the Senegal Province: (1) the hypothetical Lower 

Paleozoic Total Petroleum System consisting of Silurian source 

rocks and Ordovician to Devonian and Triassic reservoir rocks; 

(2) the hypothetical Sub-salt Total Petroleum System consisting 

of Triassic (?) lacustrine source rocks and clastic reservoirs 

capped by Triassic salt; and (3) the Cretaceous-Tertiary 

Composite Total Petroleum System consisting of CenomanianTuronian source rocks and Cretaceous and Tertiary reservoirs. 

Only limited drilling and seismic information is available for 

the Lower Paleozoic TSP, whereas there is no drilling and only 

limited seismic information on the Sub-salt TSP. Only the 

Cretaceous-Tertiary Composite Total Petroleum System was 

considered for this assessment because current production and 

exploration data were almost entirely limited to the Cretaceous. 

We defined one assessment unit within the TSP—the Coastal 

Plain and Offshore Assessment Unit.

Lower Paleozoic and Sub-salt Total Petroleum 

Systems

Events charts (figs. 19 and 20) for the Lower Paleozoic 

and Sub-salt Total Petroleum Systems summarize the age 

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

development and generation and migration of hydrocarbons.

The likely source rocks for the Lower Paleozoic Total 

Petroleum System are oil-prone graptolite-bearing Silurian 

shale that may be as much as 400 m thick (fig. 4) in the southern 

one-half of the Senegal Province. Measurements carried out in 

the Diana-Malari (DM–1) and Kolda (KO–1) wells and outcrop 

studies in the Bove Basin and the Guinea Paleozoic Basin show 

these source rocks to contain moderate organic matter and have 

TOC contents ranging from 1 to 5.5 percent (Reymond and 

Negroni, 1989). Two periods of oil generation have been determined for the Silurian source rocks and the first period began in 

the Carboniferous (300 Ma) and continued into the Hercynian 

orogeny (fig. 13). Generation paused during the Permian and 

Triassic, resumed during the Cretaceous, and continues to the 

present. Sandstone reservoirs have been shown to be abundant 

in the lower Paleozoic section based on measured sections in the 

Bove Basin and analyzed samples from stratigraphic test wells 

(fig. 3). The Ordovician sandstones could be good secondary 

reservoirs, whereas the Devonian fine- to coarse-grained sandstone beds have porosities ranging from 15 to 20 percent and 

could comprise a third type of potential reservoirs.
20 Assessment of the Undiscovered Oil and Gas of Northwest Africa Pliocene Pliocene Miocene Miocene 

Eocene Paleocene Paleocene

Low

Upper Cretaceous

WEST 

Upper Cretaceous

Atlantic Ocean

Lower Cretaceous

5

10

15

DEPTH (X1,000 FEET)

0 10 KILOMETERS

ShaleSandstone

Carbonate

Carbonate reef or bank

EXPLANATION

Sea

 level

Figure 17. Schematic cross section of the Mauritania offshore, northern Senegal Basin, northwest Africa. Several potential hydrocarbon areas 

Mauritania offshore, but commercial hydrocarbon accumulations have not been found to date. Oil-prone source rocks (TOC as much as 5 percen

and potential Upper Cretaceous deltaic reservoir sands with porosities of 17–25 percent have been identified. Lower Cretaceous carbonate rock

of the basin. Miocene turbidite fans also are prospective. Modified from Clifford (1986).
Total Petroleum Systems of the Senegal Province 21

ShaleClasticsSandstoneCarbonateSalt

Liassic

? Dogger

Malm

Neocom

Lower Cretaceous

undifferentiated

Aptian

Cenomanian-Turonian

Senonian

Tertiary

undifferentiated

Maastrichtian

Triassic

25201510

5

WEST 

DEPTH (X1,000 FEET)

Bank

Atlantic Ocean

Sea

 level

0 

Figure 18. Schematic cross section of offshore Guinea-Bissau, Senegal Basin, northwest Africa. The Albian-Cenomanian Geba delta prograded ate platform providing reservoir-potential sands and source rocks. The carbonate and deltaic rocks subcrop the Senonian paleoslope, offering sModified from Clifford (1986).
22 Assessment of the Undiscovered Oil and Gas of Northwest Africa

The Sub-salt Total Petroleum System is related to the 

syn-rift section and has not been tested in the Senegal Province, 

but seismic data suggest that this TSP may be present and it 

may be an important future hydrocarbon objective. The potential source rocks are lacustrine rocks below the thick Triassic 

salt unit. Recent seismic studies have delineated this clastic 

section in the Casamance region of southern Senegal (figs. 6 

and 9). The Newark (New Jersey, USA) and Congo-Cabinda 

(Congo and southern Gabon, Africa) analog rift basins contain 

lacustrine source rocks with Type I and Type II organic matter. 

Hydrocarbon generation is inferred to have started in the early 

Cretaceous to middle Cretaceous. Reservoir rocks are inferred 

to be Triassic clastic units along the margins of the rift valleys 

and clastic rocks along the landward margins of Jurassic to 

Neocomian limestones (figs. 6 and 9).

0

100

200

300

400

500

600

50

150

250

350

450

550

Paleogene

Cretaceous

Jurassic

Triassic

Permian

Precambrian

Cambrian

Ordovician

Silurian

Devonian

E

M

L

E

E

E

E

E

E

E

E

E

M

M

M

M

M

L

L

L

L

L

L

L

L

L

Mississippian

Pennsylvanian

Neogene

Pal

Eoc

Olig

Mio Plio

ROCK UNIT

SOURCE ROCK

RESERVOIR ROCK

SEAL ROCK

OVERBURDEN ROCK

TRAP FORMATION

PRESERVATIONCRITICAL MOMENT

PETROLEUM

SYSTEM EVENTS

GEOLOGIC TIME

SCALE

TPS Name: Lower Paleozoic (701302) Province Name: Senegal (7013)

Author(s): Michael E. Brownfield and Ronald R. Charpentier Date: 09-22-99

X

24

65

146

208

245

363

570

510

439

408

290

323

GENERATION-MIGRATIONACCUMULATION

Figure 19. Events chart for the hypothetical Lower Paleozoic 

Total Petroleum System, Senegal Province, northwest Africa. Light 

gray shading indicates rock units present. Light blue indicates secondary or possible occurrences of source rocks depending on 

quality and maturity of the unit. 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.

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

E

M

L

E

E

E

E

E

E

E

E

E

M

M

M

M

M

L

L

L

L

L

L

L

L

L

Mississippian

Pennsylvanian

Neogene

24

Pal

Eoc

Olig

Mio Plio

ROCK UNIT

SOURCE ROCK

RESERVOIR ROCK

SEAL ROCK

OVERBURDEN ROCK

TRAP FORMATION

CRITICAL MOMENT

PETROLEUM

SYSTEM EVENTS

GEOLOGIC TIMESCALE

TPS Name: Sub-salt (701303) Province Name: Senegal (7013)

Author(s): Michael E. Brownfield and Ronald R. Charpentier Date: 09-22-99

X

?

?

? ? GENERATION-MIGRATION- ACCUMULATION PRESERVATION

Figure 20. Events chart for the hypothetical Sub-salt Total 

Petroleum System in the Senegal Basin, northwest Africa. Light 

gray shading indicates rock units present. 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.
Total Petroleum Systems of the Senegal Province 23

The hypothetical Lower Paleozoic and Sub-salt Total 

Petroleum Systems were not assessed in this study because current production and exploration data in the Senegal Province 

was almost entirely limited to the Cretaceous and Tertiary units. 

These two total petroleum systems may have the potential to be 

significant hydrocarbon objectives in the future.

Cretaceous-Tertiary Composite Total Petroleum 

System

The Cretaceous-Tertiary Composite Total Petroleum 

System (TSP) was defined in the Senegal Province. An events 

chart (fig. 21) summarizes the age of the source, seal, and reservoir rocks and the timing of trap development and generation 

and migration of hydrocarbons for this TSP.

The principal source rocks in the Cretaceous-Tertiary 

Composite Total Petroleum System are the Cenomanian and 

Turonian shales (fig. 21). The Turonian can be as much as 

150 m thick with TOC contents ranging from 3 to 10 percent; 

it contains Type I, II, and III organic matter. Petroleum generation is presumed to have begun during the Miocene and continues to the present. Migration and charge most likely occurred 

shortly after generation along faults and porous Cretaceous and 

Tertiary reservoirs.

Good reservoir rocks are known throughout the section 

and include Upper Cretaceous sandstones and Tertiary clastics 

and carbonates, whereas the Lower Cretaceous carbonate-rock 

platform and Cretaceous reef units have not been explored 

(figs. 6, 9, 10, 16, 17, and 18). Oligocene carbonate-rock reservoirs exist such as the reservoir at the Dome Flore discovery (up 

to 1 billion barrels of heavy oil) that was charged with Turoniansourced oil and underwent degradation due to an insufficient seal 

allowing water washing and(or) biodegradation.

The Upper Cretaceous and Tertiary marine mudstone 

and shale rocks are the primary seals for the reservoirs in 

the Cretaceous-Tertiary Composite Total Petroleum System. 

The Mesozoic-Cenozoic part of the Senegal Province contains 

diverse trapping mechanisms (figs. 6, 9, 10, 16, 17, and 18) 

including salt-related structures, structures related to volcanic 

intrusions, growth-fault-related traps, slope truncations along 

the present day and paleoshelf edge (Senonian unconformity), 

Mesozoic and Tertiary pinch-outs along the eastern basin margin, and reef buildups along the shelf edge.

The lack of hydrocarbon production possibly is due to 

poor timing of hydrocarbon migration and the lack of effective 

seals. However, many of the early exploration wells were 

drilled on structures based on interpretations of poor seismic 

data. Currently, many of the seismic lines are being reinterpreted and new lines have been run. The Senegal Province is 

underexplored considering its large size, and that it has hydrocarbon potential in both the offshore and onshore in all three 

total petroleum systems.

Coastal Plain and Offshore Assessment Unit

One assessment unit (AU) was defined for the CretaceousTertiary Composite Total Petroleum System, designated the 

Coastal Plain and Offshore Assessment Unit (fig. 1). The eastern boundary of the AU was defined as the eastern limit of the 

Cretaceous rocks within the basin, whereas the western boundary was set at a 2,000-m water depth (figs. 2 and 3). The AU is 

X

TPS Name: Cretaceous-Tertiary Composite (701301) Province Name: Senegal (7013)

Author(s): Michael E. Brownfield and Ronald R. Charpentier Date: 09-22-99

ROCK UNIT

SOURCE ROCK

RESERVOIR ROCK

SEAL ROCK

OVERBURDEN ROCK

TRAP FORMATION

PRESERVATIONCRITICAL 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

M

M

L

L

L

L

Neogene

24

Pal

Eoc

Olig

Mio

Plio

?

E

GENERATION-MIGRATIONACCUMULATION

Figure 21. Events chart for the Cretaceous-Tertiary Composite 

Total Petroleum System (701301) and the Coastal Plain and 

Offshore Assessment Unit (70130101). Light gray shading indicates 

rock units present. Light blue indicates secondary or possible 

occurrences of source rocks depending on quality and maturity 

of the unit. 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.
24 Assessment of the Undiscovered Oil and Gas of Northwest Africa

considered a frontier area with only two gas fields and one minor 

oil field producing east of Dakar and Cape Verde that meet the 

minimum size criteria for this study. Minimum field sizes of 

1 MMBO and 6 BCFG were chosen for this assessment unit. 

Discovered oil resources in the Coastal Plain and Offshore 

Assessment Unit are 10 MMBO, with discovered gas resources 

at 49 BCFG (Petroconsultants, 1996). Within the past 47 years, 

fewer than 150 exploration wells have been drilled in the 

Province, of which 52 are offshore. Most of the wells are concentrated in two areas, in the vicinity of Cape Verde and in the 

offshore Casamance subbasin (fig. 3). Most of the Senegal 

Province remains relatively unexplored.

This study estimates that 10 percent (three fields) of the 

total number of fields (discovered and undiscovered) of at least 

the minimum size has been discovered. The estimated mean 

size and number of undiscovered oil fields are 12 MMBO 

and 13 fields, and the mean size and number of undiscovered 

gas fields are 44 BCFG and 11 fields. The estimated ranges 

in size and number and estimated coproduct ratio for these 

undiscovered fields are given in the U.S. Geological Survey 

World Petroleum Assessment 2000—Description and Results 

CD–ROM (U.S. Geological Survey World Energy Assessment 

Team, 2000) and are summarized in table 1.

The estimated means of the undiscovered conventional 

petroleum volumes contained in these fields are 157 MMBO, 

856 BCFG, and 43 MMBNGL (table 2). The mean expected 

sizes of the largest anticipated undiscovered oil and gas fields 

are 66 MMBO and 208 BCFG, respectively.

Summary

The Cretaceous-Tertiary Composite Total Petroleum 

System consists of Cenomanian-Turonian marine source rocks 

containing Type I, II, and III organic matter and Cretaceous 

and Tertiary carbonate-rock and sandstone reservoirs. Upper 

Cretaceous and Tertiary marine mudstone and shale rocks are 

the primary seals. Petroleum generation began in the Miocene 

and continues to the present. Migration and charge most likely 

occurred shortly after generation and continues to the present. 

The Coastal Plain and Offshore Assessment Unit was defined 

and assessed for the Cretaceous-Tertiary Composite Total 

Petroleum System.

Two other total petroleum systems were recognized in 

the Senegal Province: (1) the Lower Paleozoic Total Petroleum 

System consisting of Silurian source rocks and Ordovician to 

Devonian and Triassic reservoir rocks; and (2) the Pre-salt Total 

Petroleum System consisting of Permian-Triassic (?) lacustrine 

source rocks and clastic reservoirs capped by Triassic salt. 

Although they have the potential to be significant hydrocarbon 

objectives in the future, these total petroleum systems were not 

assessed because current production and exploration data were 

almost entirely limited to the overlying Cretaceous-Tertiary 

Composite Total Petroleum System.

Current hydrocarbon production is limited to gas and 

minor amounts of oil in several small fields east of Dakar. Production is from Upper Cretaceous sandstone reservoirs bounded 

by normal faults. The traps are a combination of structural closures and stratigraphic pinch-outs. No other commercial accumulations have been found to date.

Many of the early exploration wells were drilled on structures based on interpretations of older, two-dimensional seismic 

data. Currently, many of the seismic lines are being reprocessed 

and reinterpreted, and many new three-dimensional lines have 

been run. Recent exploration drilling by Woodside Petroleum in 

the Mauritania offshore has delineated a light oil (47° API) 

accumulation. The Senegal Province is underexplored for its 

large size and does have possibilities in both the offshore and 

onshore potential prospects in all three total petroleum systems. 

Gas resources may be very significant and accessible in areas 

where the zone of oil generation is relatively shallow.

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Table 1. Estimated sizes, number, and coproduct ratios of undiscovered oil and gas fields for the Coastal Plain and Offshore Assessment Unit in the Cretaceou

Petroleum System of the Senegal Province, northwest Africa

[MMBO, million barrels of oil; BCFG, billion cubic feet of gas; CFG/BO, cubic feet of gas per barrel oil, not calculated for gas fields; BNGL/MMCFG or BL/MMCFG, bar

cubic feet of gas or barrels of total liquids per million cubic feet of gas. BNGL/MMCF was calculated for USGS-defined oil fields, whereas BL/MMCFG was calculated for 

size of the accumulation are within a lognormal distribution of field sizes for which the origin is the selected minimum field size. Shading indicates not applicable]

Size of fields Number of fields Gas–to–oil ratio (CFG/BO) 

(BNG

Field type Minimum Median Maximum Mean Minimum Median Maximum Mean Mode Minimum Median Maximum Mean Mode Minimum MOil fields 1 4 500 13 1 12 35 13 4 1,100 2,200 3,300 2,198 2,200 30 Gas Fields 6 20 1,500 50 1 10 25 11 6 22 

Table 2. Estimated undiscovered volumes of conventional oil, gas, and natural gas liquids for oil and gas fields for the Coastal Plain and Offshore Assessment 

Composite Total Petroleum System of the Senegal Province, northwest Africa

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

for gas fields). Volumes of undiscovered NGL were calculated for oil fields, whereas volumes of total liquids (oil plus NGL) were calculated for USGS-defined gas fields. L

is in units of MMBO for oil fields and BCFG for gas fields. Results shown are estimates that are fully risked with respect to geology and accessability. Undiscovered volume

minimum field size are excluded from the assessment. Means can be summed, but fractiles (F95, F50, and F5) can be summed only if a correlation coefficient of +1.0 is assu

ble]

Field type MFS Probability (0–1) Oil (MMBO) Undiscovered conventional resources Gas (BCFG) NGL (MMBNGL) 

F95 F50 F5 Mean F95 F50 F5 Mean F95 F50 F5 Mean F9

Oil fields 1 1.00 15 120 430 157 33 255 968 345 2 15 59 21 Gas fields 6 1.00 83 414 1,276 510 3 18 58 22 3Total 15 120 430 157 116 669 2,244 856 5 33 118 43