Geology and Petroleum Systems of the Offshore Benin Basin (Benin)
Oil & Gas Science and Technology - Rev. IFP Energies nouvelles, Vol.
Geology and Petroleum Systems of the Offshore Benin Basin (Benin)
C. Kaki 1
G.A.F. d'Almeida 1
N. Yalo 1
S. Amelina 0
0 Beninese Company of Hydrocarbon (CBH) 01 BP 8060 Cotonou , Benin
1 University of Abomey-Calavi , 01 BP 526 Cotonou , Benin
- Geology and Petroleum Systems of the Offshore Benin Basin (Benin) - This paper summarizes the tectonosedimentary development and petroleum system of the Offshore Benin Basin (OBB). In accordance with structural development, the stratigraphic succession of this basin was divided into 4 sequences: pre-rift (up to Late Jurassic); rift (Neocomian to Lower Cretaceous); transitional (Cenomanian to Santonian) and post-rift (Maastrichtian-Holocene) sequences. Only one Upper Cretaceous petroleum system is well known within this basin. Source rocks of this system contain Type II-III kerogens with a TOC (Total Organic Carbon) average of 2.9%. Oil is produced from sandstone facies within Abeokuta formation. Currently exploration data and geochemical characteristics of bituminous sands which outcrop in some onshore areas of the Dahomey Embayment point to the existence of another petroleum system of Lower Cretaceous age (Neocomian to Albian) in this basin.
With an area of some 40 000 km2, the Offshore Benin Basin
(OBB) belongs to the Benin Coastal Basin, one of the coastal
basins of the “Dahomey Embayment” (Fig. 1).
The Romanche transform fault and chain fractures zones
delimit the Dahomey Embayment which was formed during
the opening of Equatorial Atlantic starting in the Late
Jurassic and continuing into the Cretaceous
Black, 1967; Le Pichon and Hayes, 1971; Burke et al., 1971;
Mascle, 1976; Omatsola and Adegoke, 1981; Mascle et al.,
1988; Tucker, 1992; Chierici, 1996; Eagles and Konig, 2008;
Moulin et al., 2010)
. Seismic and bore hole data show that
sedimentary fill within the Basin is more than 3 500 m thick.
The stratigraphy of the OBB has been discussed by various
(Hessouh et al., 1994; Kaki et al., 2001; Brownfield
and Charpentier, 2006)
and several classification schemes
have been proposed. In the OBB, only one petroleum system
was presently clearly identified. This system is referred to
here as the Cretaceous petroleum system. The maximum
extent of this system coincides with the boundaries of the
Embayment and the minimum extent of the system is defined
by the area extent of fields of the eastern Dahomey
Embayment (Benin and western Nigeria). Currently, most of
this petroleum is in fields on the continental shelf or in waters
less than 2 000 meters deep.
According to the significant increased interest and
exploration activity in the northern Gulf of Guinea, this paper aims
to define the geology and the petroleum systems of the
Offshore Benin Basin (OBB). The results of this study can be
useful for companies in target to infer the hydrocarbon
potential of the basin and hence make an assessment of the basin
1 TECTONOSTRATIGRAPHIC DEVELOPMENT
The tectonic framework along the continental margin of the
Dahomey Embayment is controlled by Cretaceous fracture
zones expressed as trenches and ridges in the deep Atlantic.
The marginal basins of the Dahomey Embayment formed at
the culmination of Late Jurassic to Early Cretaceous tectonic
activity that was characterized by both block and transform
faulting superimposed across an extensive Paleozoic basin
during breakup of the African, North American and South
(Almeida and Black, 1967; Le
Pichon and Hayes, 1971; Mascle, 1976; Omatsola and
Adegoke, 1981; Mascle et al., 1988; Guiraud and Maurin,
1992; Bumby and Guiraud, 2005; Eagles and Konig, 2008;
Aslanian et al., 2009; Moulin et al., 2010)
1.1 Calibrated Seismic Sections of Seme Field
The tectono-sedimentary stages which have characterized the
development of the OBB were recognized using essentially
data from Seme oilfield (Fig. 2). The Seme oilfield
comprises two main oil-bearing structures named North Seme
and South Seme, separated approximately by 4 km.
Dahomey Embayment with localization of Seme oilfield and used seismic sections. (Red line: line 2 990; violet line: line BE 8 378-410;
blue line: line BE 8 262-315).
Petrographic analyses of cores samples confirm that rocks
within the embayment are almost exclusively clastics and in
a gross sense, mirror the increasing separation of the
continents representing a graduation from terrestrial at the base,
through shallow marine, deep marine (with restrictive bottom
circulation) to open deep marine. Stratigraphy and
tectonosedimentary stages of the OBB were acknowledged using
calibrated seismic sections. In this paper, two seismic sections
extracted respectively from lines 2 990 and BE 8 378-410
acquired (see Fig. 2) in that order within the northern and
southern structures of the Seme field and were used to show
facies geometry within the basin (Fig. 3, 4).
The calibration process gives possibility to identify on
various seismic sections the reflectors which represent the
main stratigraphy unconformities and some formations
boundaries. Calibration results are gathered in Table 1.
Consequently, it was possible to identify the sequences
types, the surfaces which draw up the boundaries of each of
them and understand the geometry of sedimentary bodies
within the Offshore Benin Basin. The proposed model of
geoseismic section for line BE 8 262-315 is shown in Figure 5.
1.2 Tectono-Sedimentary Stages
Interpreted seismic sections as well as geoseismic model of a
section of line BE 8 262-315
(Hessouh et al., 1994)
Calibrated 3D seismic section extracted from line 2 990 showing seismic marker horizons (within Northern Structure).
possibility to understand that the Dahomey Embayment
region has undergone a complex history, which is generally
divided into four tectono-sedimentary stages: pre-rift (up to
Late Jurassic), syn-rift (Neocomian to Lower Cretaceous),
transitional (Cenomanian to Santonian) and post-rift
(Maastrichtian to Holocene). These 4 stages are referred to as
intracratonic, rift, transitional and drift stages by many
(Slansky, 1962; Billman, 1976; Tucker, 1992;
Hessouh et al., 1994; Chierici, 1996; Kaki et al., 2001;
Brownfield and Charpentier, 2006)
. Thus, the drift stage was
preceded by a Late Cretaceous transitional period which
extends from Cenomanian to Santonian.
Pre-Rift Stage (up to Late Jurassic)
The pre-rift rocks in the Dahomey Embayment are represented
by the lower part of the Ise formation
(Kogbe and Mehes,
1986; Jan Duchene, 1998; Kaki et al., 2001; Brownfield and
. In the Offshore Benin Basin drilling has
SEME 5 H2 H3 H4
Mid. Mioc UNC
Base Mioc UNC Eoc. UNC
Maastr UNC H6
Mid. Albian UNC
not reached the lower section of the Ise formation but seismic
data indicate that it directly overlies basement rocks and is
present on tilted basement blocks and in a series of grabens
and half grabens (Fig. 3).
On calibrated 3D seismic section extracted from line 2990
acquired in the northern structure of the Seme, the lower
boundary of Ise formation is the seismic marker named
horizon H10 and its upper boundary named “Deep marker”
represents the end of the pre-rift stage in the OBB. Indeed,
beneath the “Deep marker” Horizon (see Fig. 3), we can
observe other continuous subparallel seismic reflectors that
indicate the existence of pre-rift sediments below this seismic
frontier which form a sheet above the older basement rocks.
In a regional setting, the “Deep marker” Horizon (in
comparison with Keta Basin of Eastern Ghana), which is an
unconformity separating the pre-rift and the syn-rift sequences, is
interpreted as a sill of volcanic intrusives (basalt or dolerite)
which indicate in time the beginning of rifting process and
initial block faulting in the Dahomey Embayment. However,
the pre-rift stage is interpreted to be largely a period of
erosion and non deposition in the Dahomey Embayment. The
eroded sediments could be transported westward because
they are most likely preserved as the Jurassic pre-rift rocks
in the Tano and Ivory Coast Basins
. In Aje oilfield of Western Nigeria (Fig. 1)
seismic data indicate that the thickness of the entire Ise
formation is about 2 000 m. Since any drilled well doesn’t
reach the base of this formation, the datation of his lower part
Syn-Rift Stage: Neocomian – Lower Cretaceous
Although it was considered that the syn-rift stage began during
the Neocomian in the Dahomey Embayment
Hessouh et al., 1994; Kaki et al., 2001)
; data on the age of
volcanic intrusives associated with initial block faulting in
Eastern Ghana indicate that faulting started no later than the
Late Jurassic in the Dahomey Embayment
(MacGregor et al.,
2003; Brownfield and Charpentier, 2006)
. Orientation of the
intrusives indicates that the initial fracturing and graben
formation were subparallel to the present coastline
Konig, 2008; Moulin et al., 2010)
. Block faulting and graben
LEGEND HST TST LST
Oil production M.F.S.
Basement 1 km
filling characterized the initial tectonic stage, followed by
transform or extensional faulting.
In Seme field, the oldest syn-rift rocks are represented by
the Neocomian part of the Ise formation. The upper part of
this formation was encountered in the following wells DO-1,
DO-D2A, Seme 9 and Seme 10 (see Fig. 2) and only few
meters (less than 250 m) was drilled on geologist request.
The lithology consists of sandstone, shale and conglomerate
deposited in fluvial, lacustrine and deltaic environments
(Dumestre, 1985; Elvsborg and Dalode, 1985; MacGregor
et al., 2003)
. Sandstones are white to light grey, medium to
coarse, unsorted, conglomeratic, quartzic and well indurate
with abundant kaolinite, carbonate cement and high content
of feldspar, mica and chlorite. The shales are grey, brown,
fissile and hard
(Kaki et al., 2000; Brownfield and
. No fossils have been recovered. Datation
based on spore and pollen was provided but was unsuccessful
because this part of the formation is much damaged
. Owing to limited drilling data, we presently
consider that the part of Ise formation encounter in the Aje
field and defined as Neocomian age, represents the uppermost
part of this formation and may be equivalent to the Lower
Cretaceous Sekondi formation of Keta Basin. The upper part
of the Ise formation contains lacustrine algae
(Haack et al.,
2000; Brownfield and Charpentier, 2006)
unconformably overlain by the “Albian sandstone”. The “Albian
Sandstone” is interpreted as representing a transgressive
phase with the sea advancing in a tilted and eroded rift basin
after deposition of the Ise formation (see Fig. 5). The
lithology of this unit is predominantly sandstone with frequent
shaley and dolomitic thin beds, which distinguishes it from
the overlying unit. The sandstones are white to grey to dark
brown, fine to coarse grained, fair to poor sorting, feldspathic
and micaceous. A maximum of 455 m was penetrated in well
DO-D2A while 403 m was encountered in DO-1. In DO-C1
well, the “Albian Sandstone” overlain the crystalline
basement and its thickness reach 234 m.
Deposition of the “Albian sandstone” occurred in an off
lapping siliciclastic sedimentation cycle that prograded
southwestward. During the earliest Cretaceous, the basin underwent
gradual subsidence, block faulting and graben filling followed
by extensional faulting. Syn-sedimentary faulting occurred in
response to variable rates of subsidence and sediment supply.
The interplay of subsidence and supply rates resulted in
deposition of discrete depobelts when further crustal
subsidence of the basin could no longer be accommodated, the
focus of sediment deposition shifted seaward, forming a new
depobelt. Each depobelt is a separate unit that corresponds to
a break in regional dip of the offshore basin and is bounded
landward by growth faults. Aptian and Albian rocks are
characterized by marine sandstone and shales with some
organicrich black shales, coarse sandstone and minor limestone
(Kjemperud et al., 1992; Kaki et al., 2001)
. The oldest
marginal marine strata are in the upper Albian and the lack
of evaporites in the Lower Cretaceous section indicates that
in the Dahomey Embayment the syn-rift sediments were
deposited in a humid equatorial climate. Graben filling
continued until the middle of the Cenomanian, when uplift of
the region brought about extensive erosion and
peneplanation. In OBB, shallow marine environment is predominant
for the upper part of the Unit and fluvial environment is
predominant for the lower part below H8 seismic horizon
(see Fig. 5).
The lower limit of transgressive “Albian Sandstone” is the
seismic marker named Horizon 9 (H9) and its upper
boundary (seismic marker H7) represents the end of the syn-rift
stage in the OBB. The end of the syn-rift stage is delineated
by a major unconformity, which separates it from the
transitional rocks of the uppermost Cenomanian to Santonian. 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
(Almeida and Black, 1967; Eagles, 2008;
Moulin et al., 2010)
Transitional Stage: Cenomanian to Santonian
The transitional Cenomanian to Santonian stage, in the
Offshore Benin Basin and Dahomey Embayment, was
influenced by transform and/or extensional faulting and also was
affected by deformation that took place during the Santonian
in the Benue Trough to the east
(Elvsborg and Dalode, 1985)
These episodes of tectonic activity resulted in the
development of the Senonian unconformity in the coastal Benin
basin (Fig. 5, 6). During this stage, Abeokuta and Awgu
formations were deposited. The Abeokuta formation which
includes two stratigraphic units is present over the entire
OBB and, in places, directly overly crystalline basement. The
“Abeokuta formation” is assigned to a Cenomanian-Turonian
age. Cenomanian shales unit gather the oldest deposits of the
transitional stage. The “Turonian sandstone” unit
unconformably overlies the Cenomanian unit. At this stage, a steep
shelf began to develop during the Cenomanian along the
continental margin of the Northern Gulf of Guinea. Scientists
speculated that several south-flowing ancient rivers (from
some basins like Oni, Ogun, Yema, Oueme, Mono and
Volta) supplied clastics to the continental margin of the
Dahomey Embayment prior to Santonian uplift in the
Northeast and their actual orientation. These rivers would
have drained extensive areas to the north during the early
post-rift period and deposited large amounts of clastics
sediment during the Cenomanian to Maastrichtian now represented
by the “Turonian sandstones” or the equivalent Abeokuta
(Elvsborg and Dalode, 1985; MacGregor et al.,
2003; SAPETRO, 2010)
. The lithology of “Turonian
sandstone” consists in 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
Maastrichtian Unconformity cuts into the formation in the
eastern most part of the shelf in the vicinity of the Seme field,
while the Mid Miocene Unconformity only affects the
formation beyond the shelf edge
(Elvsborg and Dalode, 1985)
depocenter is located in the eastern part of the basin, where
thicknesses are as much as 1 000 m and the unit thins to the
north and west. 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 clastics fans
(Fig. 5). The depositional conditions are from prograding fan
deltas with possible marine processes in the upper part.
Fluvial environment is predominant for lower part of the unit,
below H6.5 seismic horizon. The upper boundary of Abeokuta
sandstones is usually picked with the influx of immature,
medium and coarse predominantly non-calcareous sandstone.
It is materialized by the seismic marker H6. The lower limit
is the H7 (see Fig. 5).
The Coniacian Awgu formation which is present over
most of the Benin offshore unconformably overlies the
“Turonian sandstone” and its distribution is controlled by the
Senonian unconformity. The formation, consisting of dark-gray
calcareous shale interbedded with calcareous siltstone and
fine-grained sandstone which was deposited in an anoxic
marine environment below the Senonian unconformity (Fig. 5).
The age of the formation is Lower Senonian (Coniacian) to
Maastrichtian age and it is limited at the top by Senonian
Unconformity and at the base by the seismic marker H6.
Post-Rift Stage: Maastrichtian to Recent
The post-rift stage rocks in the Dahomey Embayment consist
predominantly of marine Cenomanian to Holocene sandstones,
shales and minor carbonate rocks deposited in alternating
regressions and transgressions
(Dumestre, 1985; Chierici,
1996; Kjemperud et al., 1992; MacGregor et al., 2003;
Hessouh et al., 1994; Kaki et al., 2001)
that resulted in
several Late Cretaceous and Tertiary unconformities (Fig. 5, 6). In
general, continental-margin tectonics of the region post-rift
stage was driven by thermal subsidence. Five Maastrichtian
to Holocene post-rift stratigraphic units, being separated by
unconformities, have been identified in the Benin Basin
– the Maastrichtian to Paleocene Araromi shale subdivided
into an upper and lower member. The boundary between
the upper Araromi and lower Araromi members is
announced by change in shale color. The upper Araromi
formation is of Paleocene age while the lower Araromi
formation is of Maastrichtian age. This formation
comprises black to dark laminated carbonaceous shales with
abundant pyrite and pyritised microfauna. Limestone
layers occur frequently. The Araromi formation was
deposited immediately above the Senonian unconformity.
His upper limit is the seismic marker named (H4).
Araromi shales are clearly deep sea (Upper bathyal) shales
deposited in an anaerobic restricted bottom circulation
– the Paleocene to Eocene Imo shale which is conformably
overlying the Araromi formation and over larger shelf
area conformably underlies the Oshoshun formation. The
formation consists of light greenish to bluish, grey to dark
grey, non calcareous, firm to moderately hard shales with
stringers of dark grey, microcrystalline limestone. The age
of the formation is restricted to Early Eocene
al., 1994; Kaki et al., 2001; Brownfield and Charpentier,
2006; Nton et al., 2009)
. The Imo formation is present on
the entire shelf offshore Benin and attains a thickness of
approximately 400 m in the Seme area. The formation has
a reduced thickness in a westward direction. In some areas
on the shelf, younger formations have eroded into Imo
formation. The upper limit of Imo formation is set where
the greenish shale become abundant and confirmed by GR
decrease at the same point. The Imo formation has been
deposited in an upper bathyal to outer sublittoral marine,
– the Eocene Oshoshun formation is assigned to offshore
sequence of marine shales and sandy shales of Middle
Eocene age containing abundant phosphatic material
. The formation consists of sandy, varied
colored and phosphatic claystone grading to siltstone. The
Oshoshun formation appears to be present all over the shelf
area, although eroded to the shelf break by the Mid Miocene
Unconformity (H2) and locally in the vicinity of seme
field. The depositional environment is interpreted as marine,
outer sublittoral and well oxygenated
– the Afowo formation of Early to Middle Miocene age
is subdivided into a lower and an upper
units being separated by an unconformity named Mid
Miocene Unconformity (H2) which is easily picked both
by seismic data and well logs. The basal limit of Afowo
formation is picked by seismic horizon (H3) and the lower
Afowo unit is described as a light grey siltstone grading
upwards to fine grained sandstone. The upper Afowo unit
is a sequence of grey brown soft, sticky and silty clay
interbedded with friable, coarse-grained sandstone with
glauconite, pyrite and shell debris. The interbedded sands
have resulted from turbidity currents. The depositional
environment is interpreted as marine, outer sublittoral to
upper bathyal well oxygenated environment;
– the Pliocene to Recent Benin-Ijebu formation is the
uppermost units of Offshore Benin Basin. The units consist of
marine shelf sands and become coarser grained toward the
top. They also include argillaceous sandstone and siltstone
and shale. The stratigraphic succession is capped with
very young marine shelf sediments that are prograding
southwards. Sediments transport was from the north and
rapid sedimentation rates initiated growth faults that sole
out in most cases in the Araromi shale
Thus, we can indicate that during the post-rift stage,
a depositional hiatus from the late Eocene through the
Oligocene led to a major unconformity between the Eocene
Imo, Oshoshun and Miocene Afowo formations (Fig. 5, 6).
A second Miocene unconformity came and separated the
lower and upper members of the Afowo Formation.
As a result, the generalized tectono stratigraphic chart of
the Offshore Benin Basin can be represented as follow in
During burial processes the lithological characteristics of the
formations encountered in the Benin offshore have changed
and rocks have acquired particulars petroleum specifities.
1.3 Petroleum Specificity of the Formations
Ise Formation (Neocomian section)
In the OBB, the entire Ise formation thickness and chemicals
analysis are needed to fully evaluate its petroleum specifities.
In Aje field of Western Nigeria, chemical analysis of shale
Generalized stratigraphy of the Offshore Benin Basin
(Brownfield and Charpentier, 2006 modified)
samples from the upper part of Ise formation (Ise-2 well)
show that they contain Type I kerogen, with Total Organic
Carbon (TOC) contents as much as 4%. The richest
sourcerock intervals have hydrogen index (HI, mg (milligrams)
hydrocarbon/g (grams) organic carbon) greater than 500
(Brownfield and Charpentier, 2006)
. Lower Cretaceous
lacustrine strata in oil window are identified as far west as the
Ivory Coast Basin and may include similar source rocks
(Elvsborg and Dalode, 1985; Abacan-Addax Consortium,
. In Seme field, sandstones units with favorable
reservoir characteristics have been encountered below the “Albian
sandstone” (wells DO-1; DO-D2A; Seme 9 and Seme 10)
and identified as from Ise formation. Average porosities of
these sandstones are in range of 11% to 13%.
Shales units are present and increase away from coast.
Geochemical analysis of 48 samples of Albian shales, gave
an average value of 2.91% TOC. In Seme10 TOC’s average
is around 1.6%, Hydrocarbon Indices (HI) average is 260 and
kerogen are generally 20-70% sapropelic
RockEval (RE) studies pointed out for the well Seme 11
(BeicipFranlab, 1994) gave the following results: TOC: fair to good
(0.5-3.4% with an average of 2.1%); S2: poor to good
(0.7-5.3 kg HC/t. rock, with an average of 2.8 kg HC/t. rock);
HI: weak to fair (90-155) and OI (Oil Indice): weak (5-25).
Source rocks are likely to be mature in narrow kitchen sub-parallel
to the coast. Organic matter is of Type III. However, in
consideration of high maturity level of samples, one can’t exclude the
presence of organic matter of type II before maturation.
For the most important unit, the Albian sandstones unit,
average of porosity values is in the range of 13-14%.
In this formation, dark Cenomanian shales units reach 10-20%
of sandstones thickness which is over 600 m. Chemical
analysis of two samples of Cenomanian shales gave
respectively 4.2 and 7.1% of TOC with HI values of 324 and
531 mg HC/g TOC. The Turonian sandstones unit has porosity
20% and permeability 150 millidarcys (mD)
Chemical characteristics of the formation are following:
TOC of 2.4%; S2 of 13 kg HC/t; Tmax 440°C and HI of
476 mg HC/g TOC. The kerogen is of Type II with equivalent
PRV of 0.7%.
fca 3 000
tep 5 000
10 Abeokuta shale
5 BarreUmninaan mtoeAdptian
Burial history of Offshore Benin Basin with indication of time-depth maturity level of source rocks intervals
Rock-Eval analysis of samples catched from depth 1630-1810 m
, point out an average
S2 of 20 kg HC/t rock and an average TOC of 4.4%.
The organic matter is essentially of Type II. South Atlantic
concerning samples of
S-1 well indicate that the TOC reaches 5% and HI is about
476 mg HC/g TOC. The kerogen is of Type II and Type II-III.
The Paleocene to Eocene Imo shale (Fig. 6) contains Type II
and Type II-III kerogen with TOC contents ranging from 2 to
more than 5 w%. The formation is immature in the Dahomey
Some geochemical characteristics concerning samples of
S-1 well and related to the shale formations of Maastrichtian
to Miocene age (Araromi, Imo, Oshoshun and Afowo), are
pointed out in Figure 7. Arising from Rock-Eval pyrolysis,
similar geochemical results were obtained with Maastrichtian
to Eocene sediments of the eastern Dahomey basin (Aje-1
well – southwestern Nigeria). In this region, the Total
Organic Carbon (TOC) shows a range from 0.01-3.55 wt%.
This indicates that the organic matter is low to adequate,
particularly within the dark shaly interval of Araromi and
Afowo formations in Aje-1 well. Tmax ranges from 359°C to
465°C and indicate thermally immature to marginally mature
sediments, while calculated vitrinite reflectance is 0.27% to
(Nton et al., 2009)
2 PETROLEUM SYSTEMS OF THE OFFSHORE
The Offshore Benin Basin includes several potential source
rocks, many reservoir rocks and a variety of potential trapping
mechanisms, some of which have a significant potential. Oil
and gas occurrences are concentrated in Cretaceous reservoirs.
At least two Petroleum Systems (PS), with unlike concepts
plays, exist in the OBB:
– the Upper Cretaceous PS consisting of Albian to Coniacian
marine and terrestrial source rocks and Cretaceous
– the Lower Cretaceous PS, consisting of Lower Cretaceous
lacustrine source rocks and Lower Cretaceous reservoir
2.1 Hydrocarbons Source Rocks and Maturation
Maturation model utilizing Lopatin Time Temperature Index
(denoted TTI) was used to calculate the theoretical thermal
maturity of source rocks in Seme field
model which describes quantitavely the relationship between
thermal history and organic maturity, accounts only for the
burial history and assumes a background constant geothermal
gradient. The model therefore neglects the feedback effect of
the sedimentary process itself on the local thermal gradient,
where cool sediments are laid down upon a background
geothermal gradient in the basement rocks. This model assumes
that the maturation rate is exponential in temperature and
linear in time for a particular interval of temperature and
time-both are reasonable assumptions
Palumbo et al., 1999)
Empirically, the model is defined by:
with Dtn, time interval (in Ma) that the rock spent in the nth
temperature interval, usually split into 10°C independent
geothermal gradient bands; nmin and nmax, minimum and
maximum values of the index n; r, arbitrary number
describing the exponential dependence. After empirical calibration
tests, the optimum value for the factor r is found to be equal
Typically, hydrocarbons are produced for 15 < TTI < 160.
After calibration, this Time-Temperature Indexes (TTI) interval
corresponds to a range 0.65 < Ro < 1.35 for the oil generative
window determined by the vitrinite reflectance technique
(Tissot et al., 1980; Perrodon, 1980; Sokolov and Foursov,
1983; Abrikossov and Goutman, 1986; Palumbo et al., 1999)
In the Offshore Benin Basin, proven potential source
rocks which have produce oil are shales sequences of Ise,
Albian, Abeokuta and Awgu formations. Oil seeps in
outcrops of Upper Cretaceous tar sands in the onshore area of
the Dahomey Embayment (tar sands of Sakete-Benin and
western Nigeria) are interpreted to be sourced by Neocomian
lacustrine strata of Ise formation, such as were drilled into
Ise-2 well situated eastwards of the Seme oilfield in western
(Brownfield and Charpentier, 2006)
. Owing to limited
drilling data and samples studies, we cannot actually point out
the thickness of shales units of this formation. However, data
from Aje field allow us to deduce that Ise formation contains
potential source rocks in the deep Benin offshore.
The deposition of Albian shales units coincides in time
with the anoxic conditions and black shale deposition that
took place in Southern Atlantic basins during Mid-Cretaceous
(Brownfield and Charpentier, 2006)
. Shales in such
settings tend to be organic rich and oil prone
(Tissot et al., 1980)
Seismic data indicate that Albian and Aptian source rocks
may be more present in deep water but are mainly sandstones
on the basin shelf. Shale content of Abeokuta formation
increases away from coast (SAPETRO, 2010). Although the
shale beds are relatively thin within the predominantly sandy
succession of Abeokuta formation, the whole thick of the
formation give possibility to indicate that its shales sequences
are potential source rocks in the OBB. Rock-Eval analysis of
samples from core in Seme-9 well
indicate that the Awgu formation is a good potential source
rocks within the OBB. Currently, the formation continues to
The Araromi formation unit covers most of the Beninian
shelf. Unfortunately, the thickness of the formation generally
did not exceed 100 m, except in three depocenters in the eastern
part of the basin where it exceeds 600 m. Arising from
available data and previous studies, it can be deduce that Araromi
formation is very a good source rock but immature to slightly
mature, with prospect to generate oil rather than gas at
appropriate maturation. Araromi oil which should be lighter than
Albian and Abeokuta oil wasn’t encountered in wells. The
Paleocene to Eocene Imo shale (Fig. 8) is a good source rock
but it completely immature within the OBB.
Araromi shale average 5% TOC 80% oil prone kerogen 12.5 kg/tonne S2 hydrogen index 325.
Excellent non to marginally mature oil source
Imo shale modest light O/W et gas potential-immature"
Geochemical summary of Maastrichtian-Miocene sequence
(Beicip-Franlab, 1994, modified)
A global source rocks maturity model basing on Petrel
Software was presented by a research team of SAPETRO.
On this model, Time Temperature Index (TTI) and vitrinite
reflectance values are matched to indicate, on a burial history
plot of the basin, the progressive maturity level of containing
source rocks intervals (Fig. 7). The vitrinite reflectance
technique, a quantitative optical measure of the degree of
maturation, was widely used to estimate the source rocks maturation
and hydrocarbon generative windows within the OBB. The
results, expressed by definition of equal-reflectance lines,
point out that the Ise formation has past the oil generation
window in Senonian and is now over-mature (Ro > 3%). The
Albian (unnamed Albian) and Abeokuta (Abeokuta shale 10)
shales reach the maturity level of oil generation Eocene and
hydrocarbon (gas for Albian source rocks and oil for
Abeokuta one) generation may be active to the present. Oil
generation started in Pliocene for the Awgu formation.
2.2 Reservoir Rocks
At least proven (Ise, Albian and Turonian) reservoirs
horizons were highlighted in this offshore basin. Reservoir rocks
are mostly Cretaceous turbidites sandstones with minor
potential limestone units. Stratigraphic units that contain
proven reservoirs in the shallow-water discoveries are mainly
late syn-rift Albian sandstones and transitional Cenomanian
to Turonian marginal marine and turbidites clastics rocks.
In Seme field terminology, the upper part of the Albian
reservoir rocks is defined as Zone 3 that tested oil in DO-1
well and the lower part named Zone 4 has proved to be gas
and oil bearing. Cenomanian to Turonian reservoir rocks are
generally simple anticline structures delineate by faults.
South of the Seme field, the Turonian sandstones to
Cenomanian may be eroded by the Araromi formation
erosive channels (Fig. 4). The downslope projections of deltas
that were formed at that time would be prospective for
turbidite channel and ponded turbidite sandstone reservoirs. In
general, reservoirs in the transitional habitat are likely to be
of better quality than those in the syn-rift habitat. Oils
extracted from “Albian sandstones” and “Turonian
sandstones” are not the same. Albian Oil tested from Fifa-1 well
(Block 4) has 42° API while Turonian oil tested in 5 wells of
Seme field has 22° API and is little charged in sulfurs
Seismic data indicate that a thick Lower Cretaceous syn-rift
section in the offshore part of the Benin Coastal Basin
contains sandstone reservoir units deposited in fluvial to deltaic
(Elvsborg and Dalode, 1985; SAPETRO,
. Lithological changes are large both in time and space.
Similar reservoir rocks should also be present in the Keta
Basin below the mid-Albian unconformity (Kjemperud et al.,
1992). These possible reservoir rocks could be more present
in the deep-water part of the basin in the form of detached
sandstone units resulting from ponded turbidite sands behind
transpressional structures (see Fig. 5). Recent seismic data
indicate that Tertiary section has fewer reservoirs than the
Cretaceous section in the Dahomey Embayment. Some slope
fans have been identified in the Araromi shale in the overlying
section above the regional Maastrichtian unconformity (Fig. 5).
The Araromi sandstone unit (Fig. 5, 6) has been interpreted
as a slope fan in the offshore Benin Basin.
2.3 Hydrocarbon Generation and Migration
In the Offshore Benin Basin hydrocarbon generation began
in late Cretaceous time and may be active to the present
. The most important hydrocarbon
generation within the Dahomey Embayment is from the upper
Albian, Cenomanian and Awgu source rocks, which are
distributed throughout the entire offshore part of the region.
These strata are expected to increase in thickness and source
rock quality into deep water. The main area of hydrocarbon
generation is interpreted to exist eastward to the Niger Delta.
This possible oil kitchen is only present in the deep-water
parts of Dahomey Embayment where the source rocks have
reached a temperature of at least 100°C and a vitrinite
reflectance (Ro) more than 0.6%
(MacGregor et al., 2003)
Hydrocarbon generation started in the Late Cretaceous for
the Albian to Cenomanian source rocks and continues to the
The hydrocarbon generation history graph obtained after
analysis of Albian sample (Seme-1 well; source rocks No. 7;
organic matter No. 2), shows the gap time, amount of
generated hydrocarbons and residue (mg HC/g TOC) (Fig. 9).
Organic matter No. 2
110 100 90 80 70 60 50 40 30 20 10
Time (m.y.) 0
Hydrocarbon generation history for Albian shales
This maturation model indicates that the “Albian sandstone”
maturation levels adequate for petroleum generation were
reached in Eocene. Currently, in the Offshore Benin Basin,
Albian source rocks are expected to contain gas-prone Type III
kerogen similar to the one identified in Tano and Ivoirian
(MacGregor et al., 2003)
A single Seme-1 well model of hydrocarbons and residue
generation ratio based on depth and geochemical characteristics
of Albian to Benin-Ijebu formations is shown in Figure 10.
For the Turonian and Coniacian source rocks, hydrocarbon
generation possibly started in the early Tertiary and also
continues to the present. Araromi oil which should be lighter
than Albian and Abeokuta oils wasn’t encountered in Benin
offshore. Some areas of hydrocarbon generation related to
Lower Cretaceous lacustrine source rocks are present in the
(Haack et al., 2000; MacGregor et al.,
. Taking into account the maximum depth of drilled Ise
formation within the OBB, a model indicates that the upper
part of the Ise passed the main oil generation window in
Paleocene. For the deeper part, the main oil generation window
occurred probably at Late Cretaceous time.
The hydrocarbon migration from late Cretaceous and
Early Tertiary source rocks should occur during Late Tertiary
times. Oils extracted from various field within the basin were
generated in late Cretaceous to Miocene time and migrated in
tertiary time from south and south west after the structures
were already established. Migration was either directly from
adjacent source rocks or upward along faults from deeper
sources. The lower parts of the Araromi shales have reached
the mature stage but generation and migration still take place.
The Araromi formation is partially mature and is presently at
the beginning of the oil generation window (~0.7 eq. PRV).
2.4 Hydrocarbon Traps and Seals
Both structural and stratigraphic traps are present in the
OBB. Structural traps are associated with each main tectonic
stage. Syn-rift anticlinal traps (Fig. 5), detected only from
seismic data and as yet untested, are associated with the
terminations of regional fracture zones in the offshore parts of
the Dahomey Embayment
stratigraphic traps (unconformity with shale) forming seal on
the top of reservoir rocks were shaped before the end of the
Cretaceous. The sratigraphic traps envisaged for the
Maastrictian-Daanian sequence enveloped in shales that may
provide seal as well as source rocks. Moreover, trap
adjustment occurred as a result of basin ward tilting in both Late
Cretaceous and Tertiary times following continental break-up.
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
Dahomey Embayment. Ponded turbidite traps are observed
as detached sandstone bodies in the Benin Basin, where
stratigraphic trapping and updip seals are the critical factors
in defining potential targets.
Seals are marine shales and shale-filled channels with
minor fault-related ones. Seals associated with rift-valley
habitat are formed by both shales and faults, whereas seals
associated with transitional habitat are generally shales (Fig. 5,
6). Seals of Turonian reservoirs are generally assume by shales
of Awgu formation and also by interbedded shales layers
within Abeokuta formation. The Awgu formation is limited
at the top by Senonian unconformity and at the base by
the seismic marker H6. The Awgu formation is present on
the entire shelf except for localized areas in the vicinity of the
100 200 300 400
Hydrocarbon generation ratio (mg HC/g TOC) 500
Graph of a single model of hydrocarbon generation
Seme field. The present distribution of the Awgu formation
is controlled by the Senonian unconformity, a regional low
sea level sand feature of Santonian to Lower Campanian age,
which in places has eroded through the entire Turonian
section. Seaward, the Araromi and Imo formations cut the
Turonian reservoir. That means that the Maastrichtian and
Paleocene regional unconformities also clearly play the role
of seal on the slope and may be in deepwater.
The Lower Cretaceous Ise formation traps may have been
source from lacustrine shales of the same formation. Its
thickness leaves the possibility of the long interval with oil
and gas expulsion. However, early generated hydrocarbons
may have been lost before the formation of a seal on the top
of the unconformity traps.
In summary, we can specify that several potential source
rocks, many reservoir rocks and a variety of trapping
mechanisms, some of which have a significant potential are present
in the Offshore Benin Basin. Data related to recognize
elements (source rocks and reservoir rocks) and processes
(hydrocarbon generation, migration and traps formation) can
be chart in petroleum systems. Thus, two Petroleum Systems
(PS), with unlike concepts plays, exist in the Offshore Benin
– the Upper Cretaceous PS consisting of Albian to
Cenomanian marine and terrestrial source rocks and
Cretaceous reservoir rocks;
– the Lower Cretaceous PS, consisting of Lower Cretaceous
lacustrine source rocks and Cretaceous reservoir rocks.
Upper Cretaceous Petroleum System
The Upper Cretaceous PS was defined in the entire Dahomey
Embayment (see Fig. 1). Only this well-known PS was
considered for assessment, because:
– it is the most extensive;
– current exploration and production are mostly limited to
The principal source rocks for the Cretaceous PS are
Albian, Cenomanian and Turonian marine shales with Type II;
Type II-III oil-prone kerogen and Type III terrestrial kerogen.
The Coniacian Awgu Formation and the Maastrichtian
Araromi Shale (Fig. 6) contain marine source rocks in Benin
offshore. These source rocks contain Type II and Type II-III
kerogen with TOC contents ranging from 2 to more than
5 wt%. The area of the original deposition was from the
northwestern extension of the Niger Delta westward to the
(Haack et al., 2000)
. 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.
Reservoir rocks are mostly Cretaceous turbidite sandstones
with minor potential limestone units. In Seme field nine (09)
wells have produced each an average of 3 000 BOPD
(Barrels of Oil Per Day). In the nearby Aje field, this average
is about 8 000 BOPD. Migration was either directly from
adjacent source rocks or upward along faults from deeper
sources. The traps include pre-rift traps related to fault
blocks, syn-rift structural and stratigraphic traps and post-rift
stratigraphic traps. Seals are marine shales and shale-filled
channels with minor fault-related seals.
An events chart 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 is shown in Figure 11. The critical moment is
defined as the beginning of hydrocarbon generation and
Lower Cretaceous Petroleum System
Only limited exploration information is available for the
Lower Cretaceous PS. Lower Cretaceous PS oils have only
been identified in Upper Cretaceous tar sands and oil seeps at
Cape Three Points (western Ghana) and in the Dahomey
Embayment (Benin and western Nigeria).
Currently, it is assumed that upper Albian reservoirs in
Seme and Aje fields are sourced from Ise formation shales,
because downward migration from Upper
Cretaceoussourced oils seems unlikely. Hydrocarbon generation most
likely began in the Early Cretaceous and may have continued
into the early Tertiary. The Lower Cretaceous PS was
defined because lacustrine source rocks and sandstones
reservoirs deposited in early grabens have been recognized in the
entire Dahomey Embayment (from Aje oilfield westwards),
as evidenced in wells test and by the presence of lacustrine
oils from Upper Cretaceous tar sands and seeps in areas west
of Cape Three Points in western Ghana, as well as in Sakete
region of Benin Republic. Oil from Ise formation has been
tested in the OBB (Ouidah-1 well in Block 3; Porto-Novo
well in Block 2) and in Lome field (Lome-1 well) (Fig. 2, 6).
In Lome Field, Ise sandstones units have produced in test 500
BOPD. Although Ise formation is not yet productive in the
OBB, Pendencia sands (Ise equivalent) in Potiguar Basin
(Eastern Brazil) are productive. Similar productive reservoir
rocks are also present in the Keta Basin below the
(Kjemperud et al., 1992)
the Albian reservoirs, oil tests from five wells of Seme field
were positive. In two of them, the test gives over 1 000 BOPD
along with 90 m of potential oil pay in DO-C1 well.
Events charts for potential Lower Cretaceous PS
graphically portray the ages of source rocks, reservoir rocks and
seal, as well as the timing of generation, migration, trap
development, preservation of hydrocarbons and the critical
moment (Fig. 12). The critical moment is defined as the
beginning of hydrocarbon generation and migration. This
petroleum system is few documented in reports and not
assessed in the OBB because of data lack.
Haq et al., 1987
and Ross & Raoss,
et al., 1998)
Harland et al., 1990
Well-known Upper Cretaceous Petroleum System of Seme oilfield
Nomenclature for source rocks and reservoirs: (!) known; (.) hypothetical.
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C. Kaki et al. / Geology and Petroleum Systems of the Offshore Benin Basin (Benin)
et al., 1998)
Haq et al., 1987
and Ross & Raoss,
Harland et al., 1990
l d ck
a n lo
t in a b
ifr ss s lt
- e m u
n r r a
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S s f- d
an it e
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t a ta
Lower Cretaceous Petroleum System of Seme oilfield. Nomenclature for source rocks and reservoirs: (!) known; (.) hypothetical.
The tectonostratigraphy development and the history of the
formation of the total Petroleum Systems of the Offshore
Benin Basin are summarized in events charts (Fig. 11, 12).
Rocks within the petroleum system are from
Cretaceous to Paleocene in age. Most of the petroleum is
sourced from the Awgu Formation, with smaller amounts
generated from the mature shale beds of Ise, Albian and
Abeokuta Formations. Hydrocarbon generation within the
Offshore Benin Basin began in Late Cretaceous and
continues to the present. Two Petroleum Systems exist in the
Offshore Benin Basin:
– the proven Upper Cretaceous Petroleum System which
consists of middle Albian to Coniacian Type II, II-III
and III oil-prone kerogen and Type III gas-prone kerogen
and Cretaceous reservoirs. Cretaceous marine mudstones
and shales are the primary seals. Reservoirs are sandstones
throughout the Abeokuta Formation;
– the Lower Cretaceous Petroleum System, consisting of
proven Lower Cretaceous lacustrine source rocks (Type I
kerogen) and reservoir rocks. Reservoirs are below
currently producing Turonian reservoirs and, in the distal
portions of the basin, may include sands as well as turbidite
sands within Albian Formations. Although this Petroleum
System is considered to have hydrocarbon potential, it is
not yet assessed. It is why this Petroleum System is still
considered as hypothetical within Benin offshore.
Exploration works are now expanding especially in deeper
water. The deep-water part of the Offshore Benin Basin is
underexplored and contains many potential prospects
emphasized by 3D seismic of Petroleum Geo-Services (PGS).
Structural traps have been the most favourable exploration
target; however, stratigraphic traps are likely to become more
important targets in distal and deeper portions of the OBB.
The authors thank the authorities of the Ministry in charge of
Petroleum and Mining Research of Benin Republic for their
collaboration which were very useful for the redaction of this
paper and greatly improved the text.
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