Petroleum that is related to the opening

Petroleum geology of the Niger Delta
Basin

Abstract:

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Nigeria was
ranked fifth among the largest crude oil suppliers to the United States in
1997, providing the US 689,000 barrels of crude per day. Known oil and gas
resources today rank the Niger Delta province as the twelfth largest in the
world depending on 34.5 billion barrels of oil and 93.8 trillion cubic feet of
gas that are recoverable (Petroconsultants, 1996a).. These are the amounts that
have been discovered till our day and there may be more discoveries in the
future as the exploration technologies develop.

The Tertiary
Niger Delta petroleum system (Akata-Agbada) is the only identified petroleum
system in the Niger Delta province. The delta lays at a rift triple junction
that is related to the opening of Southern Atlantic since Late Jurassic till
the Cretaceous time. The proper Delta began to develop in the Eocene,
depositing sediments that now have thickness of more than 10 kilometers. The
marine-shale facies of the Upper Akata formation are the main and primary
source rock of the region with some contribution from the interbedded marine
shales of the Lower Agbada Formation. We produce oil from the sandstone facies
within the Agbada formation but also the Upper Akata Formation turbidite sand
is an offshore deep-water potential target.

 

 

 

 

 

Introduction:

Location:

The Niger
Delta basin lays on the western edge of Africa and the Southern part of
Nigeria, with an area of 75,000 km2  and 9000-12000 meters of clastic sediments
accumulated (Ojo et al. 2012; Aminu and Oloruniwo 2012).

 

 

 

 

 

 

History
of the region:

The Delta
has prograded Southward from the Eocene till our day , forming the most active
portion of the delta represented by depobelts (Doust and Omatsola, 1990).

 

Geology,
tectonics and lithology overview:

The Niger
Delta Province is Geologically complicated. It contains an onshore part and an
offshore part. The onshore part is delineated by the geology of southern
Nigeria and southwestern Cameroon, it’s bounded from the north by the Benin
flank which is an east-northeast trending hinge line south of the West Africa basement
massif. While the offshore boundary is of the province is defined by the
Cameroon volcanic line to the east, the eastern boundary of the Dahomey basin
to the west, and the two-kilometer sediment thickness contour or the 4000-meter
bathymetric contour in areas where sediment thickness is greater than two
kilometers to the south and southwest. The province covers 300,000 km2
and includes the geologic extent of the Tertiary Niger Delta (Akata-Agbada)
Petroleum System.

The
sedimentary fill of the Niger Delta Basin is divided into three diachronous
formations, namely the Akata Formation, Agbada Formation and Benin Formation

 

 

 

 

 

 

 

 

Source
Rock and Thermal maturity:

Although
determining source rock of the Niger Delta Basin has been under discussions and
debates (e.g. Evamy and
others, 1978; Ekweozor and others, 1979; Ekweozor and Okoye, 1980;
Lambert-Aikhionbare and Ibe, 1984; Bustin, 1988; Doust and Omatsola, 1990), the
possibilities are that the main source rock are the Akata-Agbada Formations.

Akata-Agbada
Formations:

The Agbada
formation contains intervals that have sufficient organic-carbon contents to be
considered good source rocks Ekweozor and Okoye, 1980; Nwachukwu and Chukwura,
1986). However, their thickness rarely reaches a sufficient value to produce
such a valuable oil province and they are also immature in some parts of the
delta (Evamy and others, 1978; Stacher, 1995).

Below the
Agbada formation we have the Akata formation shales in large volumes and it is
volumetrically sufficient to produce such a valuable oil province as the Niger
Delta basin.

According to
content and type of the organic-matter, Evamy and others (1978) suggested that
both the shale with paralic sandstone interbeds (Lower Agbada formation) and
the marine shales (Akata formation) were the source rocks of the province.

using
ab-hopanes and oleananes, Ekweozor and others (1979) succeeded to fingerprint
the crudes to their source rocks. Ekweozor and Okoye (1980) also built this
hypothesis using geochemical maturity indicators. The indicators included
vitrinite reflectance data, which indicated that rocks which are younger than
the lower parts of the paralic sequence are immature. Lambert-Aikhionbare and
Ibe (1984) discussed that the over-pressured Akata shales would affect the migration
efficiency and that it will not exceed 12%, this indicates that little fluid has
been released from the formation. They also derived another thermal maturity
profile which showed that the Agbada formation shales are mature enough to
generate Hydrocarbons.

Conclusions
by Ejedawe and others (1984) using the maturation models indicated that in the
central part of the delta, the shales of the Abgada formation are the source of
oil while the shales of the Akata formation are the source of gas. They also
believe that both shales are the source of oil in other parts of the delta.

Another
hypothesis from Doust and Omatsola (1990) indicates that the source organic
matter lays in the deltaic off-lap sequences and in the lower coastal plain
sediments. The Agbada and the Akata formations, according to their hypothesis,
have dispersed source rock levels, but Agbada formation will contain the most.
They also favor the deep turbidite fans and the delta slope of the Akata
formation in the deep water as source rocks. There is an indication of the
existence of terrestrial input in these environments, although it may contain
amorphous, hydrogen-rich matter from bacterial degradation in high amounts.
According to stacher(1995), the only source rock which is volumetrically
significant and has depth of burial consistent with the depth of the oil window
is the Akata formation.

Frost (1997)
suggested that there is a fertile source rock beneath the Niger Delta which is
the marine shales of the cretaceous age. Unfortunately, no data exists on this
section because it is very deep. The Akata shale formation is nearly 6,000 ft.
thick so it would have required a network of faults and fractures for
immigration to take place from the cretaceous shales to the reservoirs in the
Agbada formation.

 

Chemical
characteristics of the source rocks:

According to
Bustin’s study in 1988, there is no rich source rock in the delta in the
uppermost Akata Formation or the transition area between Akata and Agbada
formation. However, the lack of rich source rock was compensated by some
factors such as migration pathways, excellent drainage and the volume of the
sediments. Another enhancement factor for the oil potential in the permeability
of the interbedded sandstone and the rapid hydrocarbon generation due to high
rates of sedimentation. The study indicated the TOC% content in the sand,
siltstone and shale ranges from 1.4 to 1.6 TOC%. An important observation in
his study is that the TOC content seems to change with time of the
sedimentation. For example, the average TOC% in the late Eocene was 2.2% while
in the Pliocene it decreased to 0.9%.

Others
reported different TOC% values, values ranging from 0.4% to 14.4% were reported
by Ekeweozor and Okoye in 1980 in the onshore and offshore paralic sediments.
Nwachukwu and Chukwura (1986) reported 5.2% in paralic shales in the western
delta parts. Doust and Omatsola (1990) indicated the thin beds contain the
higher TOC% values.

In addition
to Bustin’s conclusions he also added that the organic matter is mainly
composed of mixed maceral components, the percentage of sulfur in shales is
very low, Hydrogen indices are also low (160-50mg HC/g TOC )

However,
Ekweozor and Daukoru (1994) had another opinion. They suggest that Bustin’s 90
mg HC/g TOC average is not true and it underestimates the true potential of the
source rock because of the matrix effect on the rock pyrolysis of deltaic
rocks. Values as high as 232 were reported by Udo and others (1988) for the
immature kerogen isolates from the shales of Akata-Agbada formations.

Bustin
(1998) had also included pristane/phytane values in his study which ranged
between 2 and 4. He found that pristine/phytane values and HI values vary with
stratigraphic position.

The average
source rock potential index (SPI) was estimated by Demaison and Huizinga (1994)
for the Niger Delta at 14 t HC/m2 as the Niger delta has small
drainage area in its vertical drainage system.

 

Another
study was conducted
to determine the maturity levels and attributes of the source rock of the Eocene
intervals (Akata). Three wells were drilled, and 40 samples were examined, a
well was drilled on the eastern part (Alpha), another was drilled in the
central part (Beta) and the third was drilled in the western flank (Zeta).
Vitrinite reflectance of the samples was measured and they were examined using
Rock-Eval pyrolysis.
To determine the Thermal maturity of sediments we always use the
Vitrinite Reflectance method. The shale samples from the 3 wells resulted in
values of Ro% ranging between 0.42–0.70 VRo % for the
first well (Alpha), 0.43–1.17 VRo % for the second well
(Beta) and 0.58 VRo–0.63 VRo % for the
third well (Zeta). These results indicate that they range from immature source
rocks to thermally mature. This table shows exactly the results of the 40
samples

 

 

Well name

Depth(m)

Measured VR%

Alpha

2764

0.42

Alpha

2798

0.7

Beta

2495

0.43

Beta

3912

1.17

Zeta

2743

0.58

Zeta

2773

0.59

Zeta

2926

0.62

Zeta

3081

0.63

Zeta

3231

0.63

 

The total
organic carbon (TOC) values of the three wells : Alpha ,Beta and Zeta were high
enough to indicate that the hydrocarbon generation potential was good to
excellent (Peters and Cassa 1994). Values ranged from
1.21–3.1 wt% in Alpha , 1.04–3.62 wt% in Beta and 1.33–2.12 wt%
in Zeta. When samples were subjected to pyrolysis, S2
yielded values that indicated good to very good source rock with poor to
fair generation potential. Hydrogen Index of the kerogen suggested type 3 and
type 4 kerogens.

The following figure shows the kerogen quantity of the
samples. It is called van krevelen Diagram and it is plotted between HI and Tmax
.

 

 

 

 

 

 

 

Tmax
values in the three wells range from 412 to 459 °C which are agree with the
vitrinite reflectance values, concluding that the samples have entered the oil
window stage.

Therefore,
the conclusion of the study is that the three source rocks in the three wells
are gas-prone source rocks with good generating potential in the Agbada
formation. Results are based on thermal maturity, TOC content and widespread
distribution.

 

Migration
pathways:

Short and
Stäuble (1967); Reed (1969) studied the wax content, oil chemistry and the API
gravity of the oils to conclude that the migration pathways were short

Migration occurred
from the mature, over pressured shales of the Akata formation in the more
distal portion of the delta. According to Hunt’s(1990) opinion, the expulsion
of hydrocarbon was related to releasing and fracturing of the over-pressured
interval’s top seal.
A prejudice towards gas and condensate ( light hydrocarbons) was predicted by
Beka and Oti in 1995 from the over-pressured shale, this is due to the mitigation
of the organic matter and also due to the differentiation related to expulsion
from sources that are over pressured.

Reservoir:

The Agbada formation unconsolidated sands and sandstones are
major reservoir in the Nige delta province. Depth of burial and depositional
environments in Agbada formation control the reservoir rock properties.
According to Evamy and others (1978) range in thickness from 15 meters to 45 meters, stacked and their
age range from Eocene to Pliocene.
Doust and Omatsola (1990) suggest that thick reservoirs represent complex
bodies of stacked channels.

Depending on reservoir quality and geometry, coastal barrier
bars intermittently cut by sand-filled channels and point bars of distributary
channels are the most important types of reservoirs (Kulke ,1990).

According to Edwards and Santogrossi (1990), the Niger Delta
primary reservoirs are Miocene paralic sandstones that are 100 meters thick ,
40% porous and 2 Darcys permeable. Growth faults mainly control the later
variations in reservoir thickness, the reservoir thick part is always towards
the down-thrown block of the fault (Weber and Daukoru, 1975).

Kulke (1990) said that fluvial sandstones have coarser grain
sized sandstones than the delta front sandstones, as point bars are always
fining upward and barrier bars have good sorting.

Beka and otti (1995), realized other potential reservoirs in
the Niger Delta region, they included the outer parts of delta complex,
proximal turbidities, low-stand sand bodies and deep-sea channels. In 1972
Burke described three active fans in the deep water that have been active for
the most time of the delta’s history. He also added that the fans were very
small compared to those related to other large deltas because much of the sand
is deposited on the delta’s top or buried at the position of successive
depobelts that moves seawards.
Their petrophysical characteristics are not well understood (Kulke, 1995).

Traps and Seals:

Structural traps form the vast majority of the traps in the
Niger Delta basin. However, stratigraphic traps also exist.

(Evamy and others, 1978; Stacher, 1995) declared that these
structural traps were developed due to the agbada paralic sequence
syn-sedimentary deformation.

The complexity of structure increases from the early formed
depobelts in the North to the later formed depobelts in the South due to
instability increment of the over-pressured under-compacted shales.

Doust and Omatsola (1990) declared different structural
trapping elements such as rollover structures, channels filled with clay,
growth faults, collapsed crest structures and antithetic faults.

On the delta flanks there are sandstone pockets that exist
between diapiric structures, towards the toe of the delta the shale/sandstone
alternating sequences tend to be only sandstone.

According to Doust and Omatsola (1990),the Agbada formation
interbedded shale is considered the main seal in the Niger Delta province. This
shale seals in three ways, the first one is clay smearing along faults , the
second is interbedded units on which the sand reservoir juxtapose due to faults
and the third is vertical seals. They also added that the clay filled canyons
on the delta flanks form the top seal of some important offshore fields.

Timing:

According to Evamy and others (1978)
opinions, expulsion and migration in the Niger Delta basin took place
consequently among depobelts after the depobelt is structurally deformed,
therefore the deformation in the norther belt is believed to have been
completed in the Late Eocene. The lower part of the Agbada formation is
believed to have entered the oil window in the Late Oligocene.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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