Download Petroleum Prospects of Lamu Basin, South

JOURNAL
SOCIETY
OF INDIA
MOGAKA
D.GEOLOGICAL
NYABERI AND
BERNARD
K. ROP
Vol.83, April 2014, pp.414-422
414
Petroleum Prospects of Lamu Basin, South-Eastern Kenya
1
MOGAKA D. NYABERI1 and BERNARD K. ROP2
School of Earth Sciences, South Eastern University College (A Constituent College of
University of Nairobi), P.O. Box 170 – 90200, Kitui, Kenya
2
Department of Mining and Mineral Processing Engineering, Jomo Kenyatta University of
Agriculture and Technology, P.O. Box 635 – 30800, Voi, Kenya
Email: [email protected]; [email protected]
Abstract: The hydrocarbon potential of the sub-surface Lamu basin (SE Kenya) offshore sedimentary rock sequences of
Mesozoic age formed the premise of this study. Major similarities and some differences in structural styles can be seen
between the offshore Lamu and the Gondwana basins along the margins of Indian Ocean and Carnarvon basin along
Australia’s North West Shelf, where oil pools have been discovered. The existing well results and recent 2-D seismic
data have been interpreted to identify various structural styles and play fairway segments, which bolster the possibility
that the Karroo to late Tertiary sedimentary mega-sequences (~3000 – 13000 m thick), suitable for hydrocarbon exploration,
could be visualized in both the onshore and offshore Lamu basin areas. Similarly, major reservoir-seal and potential
source intervals have been identified in the present study. The hydrocarbon indicator from the well-log data shows that
oil potential in complex multiple petroleum systems, ranging in age from Triassic to Tertiary, have tested gas deposits.
Well control of only one exploratory well per 25,000 sq km in the offshore Lamu basin shows evidence of the existence
of at least two active petroleum systems. The Lamu basin has evolved consequent to a complex tectonic activity related
to continental rifting and block faulting of the Lamu-Anza and Central African rift systems. An attempt has been made
to recommend the probable prognostic structural leads, which are controlled by NW-SE trending faults sympathetic to
the Anza-Lamu rift systems, for future essential sub-surface features of source rocks, reservoir rocks and the cap rocks
in the Lamu basin.
Keywords: Sedimentary rock, Hydrocarbon, Geophysical and seismic data, Lamu Basin, Karoo, Kenya.
INTRODUCTION
o
The Lamu basin (bounded by the Equator and 4 30'S
latitude and by longitudes 39o00'E and 44o00'E) covers a
large area of southeastern coastal Kenya with an aerial extent
of 132,720 square kilometers, extending offshore from a
relatively narrow onshore graben to cover most of the
continental shelf and slope of Kenya (Fig. 1). The
hydrocarbon resource potential of the sub-surface offshore
segment of the Lamu basin (with sediment thickness ranging
from 3 km onshore to 13 km offshore) can be assessed by
comparing with other Gondwana basins on the margins of
the Indian Ocean. The formation of the Lamu basin
went through initial rifting during Carboniferous (Nyagah
and Cloeter, 1992). The sediments deposited during the rift
stage have been interpreted on the basis of geophysical data
and facies, and subsequently inferred from geotectonic
environment and their outcrop evidence (Rabinowitz and
Coffin, 1982). The Gondwana break-up history of East
Africa is reviewed to identify major reservoir-seal pairs and
potential source intervals within the basin. The stratigraphic
column of the offshore Lamu basin is compared with that of
the Carnarvon basin, along Australia’s Northwest shelf, in
order to identify analogue plays and potential resource
volumes (Rabinowitz, 1982).
Historical well results and recent 2-D seismic data have
been interpreted to identify various structural styles and play
fairway segments. Four ‘mega-sequences’ from the Karroo
to the late Tertiary are identified and all seem to have
potential reservoir-seal pairs. Major similarities and some
differences in structural styles are pragmatic between the
offshore Lamu and Carnarvon basins. Yet, the Carnarvon
basin has shown reserves in excess of three billion barrels
of oil from the drilling of about 50 wells per 25,000 square
kilometers of productive area of the basin. The results of
the comparison indicate a significant potential resource in a
number of trap types, within a core area of the offshore play
fairway in the Lamu basin. However, scant, a control of
only one well per 25,000 square kilometers in the offshore
0016-7622/2014-83-4-414/$ 1.00 © GEOL. SOC. INDIA
JOUR.GEOL.SOC.INDIA, VOL.83, APRIL 2014
PETROLEUM PROSPECTS OF LAMU BASIN, SOUTH-EASTERN KENYA
??
SUDAN
?
?
ETHIOPIA
SUGU
TA
IN
S
A
B
LOKICHAR
(LOPEROT) TROUGH
KENYA
200
Sedimentary Basins
Tertiary Rift Basin
Anza Basin
Mandera Basin
O
CE
AN
100
KILOMETERS
IN
DI
AN
0
NAIROBI
LAM
UE
MB
AYM
ENT
NYANZA TROUGH
MAGADI TROUGH
LAKE VICTORIA
SOUTH
KERIO
TROUGH
SOMALIA
ZA
N
A
UGANDA
M
AN
DE
RA
BA
SI
N
TURKANA BASIN
LOTIKIPI
BASIN
Lamu Basin
Fig.1. Map showing sedimentary basins in Kenya (Lamu basin
shaded yellow)
Lamu basin shows evidence of the existence of at least two
active petroleum systems.
Considering the Lamu basin, a total of 16 wells have
been drilled in the sub-surface as shown in Fig.2, many of
which were poorly located but some tested questionable
structures. The initial drilling focused primarily on
Mesozoic, marine Jurassic and Cretaceous rocks that are
visible in a few poorly exposed outcrops and large block
faulted structures on intra-basinal highs and platform areas.
Only in the later stages did the drilling activity move in the
Tertiary depocentres.
Petroleum exploration is an arduous job involving
interpretation and integration of geoscientific information
emanating from indirect sources (Rop, 2003). The surface
geologic information in both onshore and offshore of Lamu
basin is mainly gathered from exploratory wells, geophysical
surveys and wireline well logs. Meticulous data from these
sources are required. Projections for probability of sources,
reservoir and cap rock combinations over an area with
favorable entrapment conditions lead to the identification
of prospective structures and locales for exploration drilling.
Over the past five decades there have been spectacular
scientific advances in the quality and interpretation of
geophysical data for meeting geological goals. The National
Oil Corporation of Kenya (NOCK, 1995) is keeping pace
with the modern techniques and technology and has procured
matching computer-aided facilities (Rop, 2003).
JOUR.GEOL.SOC.INDIA, VOL.83, APRIL 2014
415
To date, about 33 wells have been drilled in the
sedimentary basins of Kenya but so far not a single viable
hydrocarbon field has been discovered. However, efforts
are still underway to demarcate drillable structures in the
sub-surface basins. Much of the present work depends upon
accomplishing extensive geophysical and geochemical data
and their logical interpretation, where the existing
information on drill cores from the onshore and offshore
Lamu basin have been studied and interpreted. The much
needed geophysical (gravity and seismic) data was made
available for the present work by NOCK (1995) in order to
interpret and understand the sub-surface geology and
structures.
Though, exploration in the offshore area of the Lamu
basin was dormant from 1954 until the 1980s, the Cities
Services Group, which included Marathon and Union Oil,
completed two dry holes: Maridadi-1 (4,196m deep) and
Kofia-1 (3,629 m deep ) in 1982 and 1985, respectively.
While the activities in the offshore area were disappointing,
they revealed the presence of a possible Jurassic salt basin
that had probably undergone significant halo kinetic
movement thus forming diapiric structures (NOCK, 1995).
The under-explored oil reserves and ample evidence of a
sizeable hydrocarbon deposit in the basin instigated
Woodside Petroleum Company, that started exploration of
the offshore Lamu basin in 2003, acquiring approximately
3600 km of 2-D seismic data, between the months of
November 2004 and January 2005; eventually drilling one
well by early 2006, although dry.
Fig.2. Location of wells drilled in the Lamu basin.
416
MOGAKA D. NYABERI AND BERNARD K. ROP
GEOLOGY, LITHOLOGY AND GEOPHYSICAL
SUBSURFACE STRUCTURES
The Lamu basin formed a failed arm of a major Paleozoic
tri-radial rift system with the southwestern arm extending
further south up to Malawi (Rabinowitz and Coffin, 1982).
The separation of Madagascar along a strike slip transverse
fault (Davie fracture zone) in late Mesozoic times created
an initial transform margin configuration. Passive margin
development accompanied progradational sediment
deposition on a continental margin that underwent periodic
rifting and subsidence until recent times (Karanja, 1982;
NOCK, 1995). Outcrop studies in the coastal onshore areas
of Lamu basin confirm the presence of potential reservoirs
in the Jurassic carbonate sequence (Nyagah, 1992). In
Triassic and early-mid Jurassic prospective Jurassic
reservoirs may be overlain by evaporitic units on the
regionally developed marine shale. Jurassic source rock
potential indicates hydrocarbon fluid inclusions found in
Jurassic oolitic limestone samples from the Lamu basin. In
the Cretaceous the reservoir comprises deltaic clastics of
the Ewaso, Kofia sands and the Frere town limestone which
has well developed vuggy porosity. Walu shale which is
related to a regional transgression and the pro-deltaic
sequences provide adequate sealing potential.
The seismic reflection mapping is concerned with
delineation of sub-surface sedimentary structures and
lithologic variations in the upper 5 km of the crust (BEICIP,
1984). Located in the northern part of the basin is a NW-SE
trending structural basement high (the Garissa High), while
in the southern part is an N-S trending basement uplift (the
Walu and Tana synclines), which is believed to be an onshore
continuation of the Davie Fracture Zone and the Cap Saint
Andre Axis (NOCK, 1995). This basement high separates
the Morondava and Majunga basins of Madagascar. The
western boundary of the basin is marked by N-S trending
fault that separates the Karroo rocks from the outcropping
Precambrian basement, which shows a distinct tectonic
direction, exhibited by structural elements in the basin. An
example of a structural element is the Hargaso anticline
(section of 181 km running NW–SE), which includes
Hargaso well in Dodori area in the basin. In the southeast
of the faulted Hargaso anticline, all horizons undergo
progressive but irregular deepening in the direction of the
coast (Fig. 3). There are few unconformities in this
southeasterly dipping and deepening sedimentary basin. The
on lap of Paleocene and late Eocene on the Cretaceous
period is very clear. The assortment of deep horizons (the
top and the base Cretaceous limestone’s, possible tops of
Jurassic and Triassic periods) is more difficult as one
proceeds towards the southeast.
Hagarso is a structure related to basement tectonics but,
R–94 line movements relate to deep intrusions apparently
rooted below the bottom of the section (below 4.5 second
t.w.t that is, 8.5 – 9 km). The intrusions are either crystalline,
which originated within the basement or salt diapirs. The
Fig.3. Burial history curve of Hagarso-1 well
JOUR.GEOL.SOC.INDIA, VOL.83, APRIL 2014
PETROLEUM PROSPECTS OF LAMU BASIN, SOUTH-EASTERN KENYA
Jurassic salts resulted from the opening of the sea between
Madagascar and Africa, forming the base of Jurassic at
around 9 km (Nyagah and Cloeter, 1992). The Karroo
sediments are moderately thick. The total offshore line 140
begins at about 25 km SE of Malindi and extends offshore
for 140 km with water depth increasing from 300 – 2,400 m
(BEICIP, 1984). In the southeast a lenticular sequence poor
in reflection and possibly identified as Jurassic salt rests on
about 2,000 m of flat energetic series, considered as
belonging to the Karroo group. The thickness of the possible
salt may vary towards the southeast from 4,000 to few
hundreds meters. Above this the Cretaceous and Tertiary
sediments are rather constant in thickness and the bottom
itself is approximately parallel to the top salt. In the
northeast, the Cretaceous, the Eocene and the Miocene are
heavily faulted and may be very thick in a syncline centered
in shot point 2300. This tectonism may be related to salt
diapirism but deep reflections are too poor and too
discontinuous to allow thorough interpretation. Here the
Karroo and the basement are probably very deep. The profile
ends in the northwest on the flank of a probably diapiric,
anticline culminating 15 km southeast of Malindi.
The transition between these two parts of profile
corresponds to strike-slip fault which are related to Davie
ridge, along which Madagascar is known to have shifted
towards the south during the Jurassic and early Cretaceous,
where the related horizons on both sides of the fault exhibit
clear change of facies (Simiyu,1989; NOCK, 1995). In
shallow horizons, for instance, at the top of Cretaceous, the
fault corresponds to the Tembo anticline and at depth it
appears to be down to the northwest. The roughly northsouth line of culmination, which extends from the Tembo
anticline to the Kipini structure, through the Kifaru diapir,
is considered as shallow expression of the strike-slip fault.
Four major groups of stratigraphic mega-sequences
(Nyagah, 1992; NOCK, 1995) have been distinguished for
the strata of Lamu basin sub-surface. The local lithological
and sedimentological assemblages are delimited by major
unconformities and grouped into mega-sequences (Fig. 4).
The mega-sequence boundaries were seismically defined.
Mega-sequence 1 belongs to the Karroo Group of rocks
(Permo-Carboniferous to early Jurassic). The sequence
comprises in ascending order, the Taru Grifts, Maji ya
Chumvi, Mariakani sandstones and the Mazeras sandstone.
These rocks were deposited in graben and half graben
structures. The axes of these grabens are mainly oriented in
north-south direction. These grabens are a result of regional
extension that was the precursor to the break-up of
Gondwanaland (Miller, 1852; NOCK, 1995).
The Taru Member consists of primary sedimentary
JOUR.GEOL.SOC.INDIA, VOL.83, APRIL 2014
417
structures such as rare water escape and slump structure
(Odada E.O, 1995). The Maji Ya Chumvi Formation
comprises lacustrine regime that was sustained by renewed
faulting during late Permian times (Cannon et al., 1981). A
faulted contact exists between the Mazeras and Mariakani
formations. Movements (middle Triassic) gently folded the
Mariakani sandstone producing broad and shallow synclines
and anticlines (Caswell, P.V, 1953, p.35). The beds have a
regional dip to the northeast throughout the greater part of
the area. Upper Jurassic to Cretaceous had a Tertiary passive
margin of developing Indian Ocean Complex and sediment
evolution (BEICIP 1984; NOCK, 1995).
The major structural elements in the Lamu basin include;
the ENE-WSW structural high trending from Garissa to Wal
Merer High, with N-S strike (Precambrian basement
direction with block faulting tectonics but also strike slip
faulting which originated during the formation of protoIndian Ocean) and NE-SW structural low (Simiyu, 1989;
Nyagah, 1992). In Triassic, characteristic traps are mainly
block faulted anticlinal structures with associated antithetic
faults. Various large intra-basinal anomalies have been
mapped, seismically and by aeromagnetic, along the near
shore areas of the coast. The largest of these structures covers
400 sq km. In Cretaceous, structural-stratigraphic traps
associated with the Ewaso sand and Kofia sands are present
within the sequence. In the Paleogene, there is a large
structure with 1000 m of vertical closure, in well positioned
in delta lobe and down the southwest plunge of the WaluKipini High (NOCK, 1995). Another large structural
complex located on the delta fair way has been informally
termed the “Hackberry play” (Fig. 5). It is a direct geologic
analogue to the productive trend in the Texas Gulf Coast.
Back-reef and shoal-water oolitic carbonate facies overlying
basement horsts or pinching out on the Walu–Kipini
basement ridge, provide favorable trap geometries. Several
small reefs that are just above the oil window have been
mapped, seismically, on the southwest flank of the Walu
High. A very large Miocene reefal build-up, extending for
40 km in water (900 m to 1000 m depth), is seismically
identified. Although the reef trend may be above the top of
the oil window that starved ocean basin conditions, following
basin subsidence may have been critical in limiting
compaction and thermal conductivity which influenced the
development of favorable thermal regimes.
PROGNOSTIC EVALUATION OF HYDROCARBON
POTENTIAL
Exploratory drilling in Tertiary depocentres has shown
encouraging wet gas shows in the basin. Recent time
418
MOGAKA D. NYABERI AND BERNARD K. ROP
Fig.4. Stratigraphy of Lamu basin.
JOUR.GEOL.SOC.INDIA, VOL.83, APRIL 2014
PETROLEUM PROSPECTS OF LAMU BASIN, SOUTH-EASTERN KENYA
419
Fig.5. Seismic profile showing the “Hackberry Play”.
temperature index determinations for coastal wells indicate
that the oil window is generally located at depths greater
than 3000 m, due to the low geothermal gradient associated
with the great sediment thickness in this part of the Lamu
basin (Rop, 2003; NOCK, 1995). The present day
knowledge indicates that hydrocarbon discoveries in the
world have been made in basins located within or at the
edge of cratons (BEICIP, 1984), not overlooking the
continental margin where the Lamu basin is located. The
rates of sedimentation in the basin average 30 to 50 meters
per million years, during rifting and post rifting with
Neogene period yielding a higher value (around 100m / 105y)
for Lamu embayment.
The rifting stage affected the Lamu basin during late
Jurassic and was responsible for the generation and
maturation of source rocks. High geothermal gradients and
early migration into paleostructures or pinch are associated
with rifting system. The failed rift and the post rift stages
were characterized by low geothermal gradients. The second
phase of subsidence which resulted in the generation of
hydrocarbons, applies to Karroo sediments of the basin of
Jurassic, for example oil shows that were encountered in
Kipini and Dodori wells (upper Cretaceous and lower
Tertiary beds) are related to Tertiary subsidence which
triggered a late phase of oil generation from Jurassic source
rocks. The Tertiary period rocks have low degree of
maturation while the upper Cretaceous rocks prove
immature except in the deepest parts of studied basins. The
JOUR.GEOL.SOC.INDIA, VOL.83, APRIL 2014
maturity levels in lower Cretaceous are variable with
Garissa High (Wal Merer–1 well) probably being overmature, whereas, the Garissa flanks (Bahat –Anza graben,
Kipini–Dodori) show mature to over-mature. Those of the
Jurassic period (from the present day geothermal gradient
3OC/100 m) whose Cretaceous sections are very thick (4,000
m), the maturation is likely to be over-mature. The
occurrence of oil window in most of these wells did not
coincide with strata possessing well developed porosities.
Saturated porous sands of the Kipini sands at terminal depth
of the oil window were seen to be deeper than previously
determined. It is possible that some well-developed source
rock sequences from Carboniferous to mid-Jurassic are
likely to exist in Lamu embayment.
CHARACTERISTICS OF THE SOURCE ROCKS
The assessment of the hydrocarbon potential of the basin
hinges on the establishment of time–stratigraphic framework
interpretation of deposition conditions of different facies,
and regional paleogeographic reconstruction. The eastern
onshore of Lamu east (forming extension of Davie Fracture
Zone) is characterized by reduced rift sequence continuation
of Bur ridge in rift stage. The Tertiary sandstones in this
area has 5 – 20 percent porosity which is comparable to
structural high areas of lower Oligocene deposits of Maragh
Trough, southeastern Sirt basin, Lybia (Reeveset al,
1986). Middle Cretaceous carbonates between Wal Merer
420
MOGAKA D. NYABERI AND BERNARD K. ROP
and Walu have porosity of 4 – 7 percent with depths of 2000
meters; late Cretaceous sandstone and quartzite have a
porosity of 4–14 percent at depths of 3000 – 3500 meters
between Hargaso and Walu. The late Tertiary beds are
evidently containing rich potential source rock. Hydrocarbon trapping areas in this formation are in anticlines of
block faulting type which are associated with compaction
of faults. The clastic fans of Eocene–Paleocene sequence
are up to 10 meters with porosity of 20 percent, while those
of upper Cretaceous (1–2 meters thick), have 10–14 percent
porosity.
The reefal limestone in the Tertiary sequence is 5000 –
6000 meters thick, and the Cretaceous–Tertiary section
presents fair to good source rock. Source rock might well
be down in the oil window of the basin and hydrocarbon
migration from hypothetical section, or the infra evaporatic
sequence might also have filled Tertiary reservoirs. The
Tembo–Walu culmination, situated in the Tembo–Kipini
Walu trend, has better possibilities of hydrocarbon migration
from deep source rock as well as in potential structural area
in the Malindi high, with limited closure. The other good
prospects of hydrocarbon potential are in Eocene to
Oligocene deltaic clastics and shelf carbonate facies
underlying the present coastal area which also constitute
good prospective reservoirs (Karanja, 1982). Shelf edge
patch reefs, commonly associated with these shelf facies,
could also be the targets in the shallow offshore area of the
Pate embayment. The pattern of alternating periods of
subsidence and sedimentation should have brought about
the source and reservoirs facies into spatial and temporal
coincidence (Miller, 1952; NOCK, 1995).
There is a frequent occurrence of the Karroo euxinic
sediments (BEICIP, 1984) with a possible existence of rich
and well-developed lacustrine and/or marine source rocks.
The organic matter present in the sediments is coaly, humic
Type III, algae-sapropelic Type II and there may be the
enriched Type I under favorable conditions of deposition.
The Karroo source rocks sequences, in the present study,
have similarities to Gondwanaland depocentres in other parts
of the world, such as the Carnarvon basin where oil reserves
in excess of three billion barrels of oil have been discovered.
The sedimentation, in the initial rifting stage, took place
from late Triassic to mid-Jurassic under the anoxic marine
environmental conditions. These sedimentary sequences,
deposited under the same geotectonic conditions, have
shown well-developed and matured source beds, due to the
high geothermal fluxes and rapid sediments deposition in
the rift environment. The evaporate beds observed in the
Lamu basin act as excellent cap rocks for hydrocarbons
generated during the syn-rift or initial rifting tectonics.
The Lamu embayment underwent a typical evolution in
the post-rift stage (mid-Jurassic to Quaternary) causing
continental passive marine depositions with good source
rocks in the passive marginal sediments. The organic matter
in these formations may contain Type II kind of kerogen,
but more complex type (maybe Type II) may be predominant
if sporadic and/or deltaic facies were present during sediment
deposition. Maturation in the post-rift stage may not have
been rapid owing to the low geothermal gradients of passive
margin. Deep burial is, therefore, required in order to attain
the oil window.
Exploration data indicates that the Kipini-1 well has
400 m plus of porous and permeable sands while the Pate-1
is known to have flowed wet gas, water and mud from sand
unit of lower Eocene age. Shale deposited during the
intermittent sea level cycles of the Paleogene are effective
caps. Shale sections associated with the Kipini Formation
and the Pate limestone demonstrate fair to good source
potential. Similar formation, for example oil-prone shales
of the Eocene age with good source richness, has been
identified in the Pemba-5 well on Pemba Island in Tanzania
just to the south of the Kenya–Tanzania border. Drilling of
Nyuni-1 well has confirmed an active petroleum system in
the area as evidenced by gas and oil shows in Tanzania.
They posses oil and gas prone Type II to Type III Kerogen
similar to source rocks of Niger grabens (Suggate, 1998).
In the late Tertiary (Neogene), bioclastic debris associated
with traps generated from salt diapirsm, also provide viable
prospects. The Simba shales provide good seals for the deep
water prospects with possible source rocks being shale
sections in the Kipini sands and Kipini Formation (NOCK,
1995).
GEOCHEMICAL STUDIES OF SOURCE ROCKS
Based on geochemical analysis from the Simba-1Well
(NOCK, 1995), the late Cretaceous and Paleocene sections
have fair to good source richness with an average Total
organic content of 1.4 % and Type III Kerogen, which is
comparable to the source rocks of Cretaceous sequence at
the Abu Gharadig oil and gas field, northwestern desert,
Egypt (Kent, 1982; Khaleb 1999). The late Cretaceous rocks
carry source rock characteristics similar to those of Tertiary
sections, with rich marginal organic matter (Type IV) and a
fair (4kg Hc/t. rock) mature source rock interval at 3450 m
depth in Kipini-1 well, which may be conducive for gas
production. Some local marginal source rock sequences
whose organic matter could be detrital residual Type IV,
often associated with humic or gas-prone kerogen Type III,
have been realized in the lower Cretaceous. Those of the
JOUR.GEOL.SOC.INDIA, VOL.83, APRIL 2014
PETROLEUM PROSPECTS OF LAMU BASIN, SOUTH-EASTERN KENYA
Jurassic sequences contain Type IV kerogen and poor
source rock petroleum potential (1kg.Hct/rock) with fair
reservoir capabilities.
In the Tertiary sequence, immature source intervals were
identified in the Kipini–1 and Dodori–1 wells which
contained one fair (3kg. Hc/t. rock, 20 – 30 m) interval in
the Kipini (1,900 m) upper Eocene and a good interval
(15kg.Hc/t. rock) with intercalated coal seams of mainly
sandy section (20 – 30 m) in middle Eocene (2160 m).
Those of the Dodori–1 well have a good interval (48kg.Hc/
t rock) in middle Eocene (1450 m depth) with also
intercalations of several thin coal or lignite streaks in the
sandy sequence.
In 1983 BEICIP Labs analyzed 42 surface samples,
which included 10 silty-shaley samples from Cretaceous
period, 3 silty samples from Permian period, and 29 samples;
all from Jurassic lithologies (sandstones, siltstones and
shale). No significant petroleum show was recorded from
these zones.
KARROO SOURCE ROCK POTENTIAL
The sediments of Karroo were laid down during the
initial rifting of Lamu embayment under continental
lacustrine to restricted marine conditions during the late
Paleozoic to early Triassic. Such conditions (anoxic
environment) are often favorable to the preservation of
organic matter, with rich and well developed source rocks
containing either Type III or Type II, or even Type I under
favorable conditions and depth. Such source beds are likely
to be associated with excellent carrier beds. The source
characteristics of the Karoo sediments in the depocenters
of Gondwanaland basins contain specks of bitumen in cores,
as well as carbonaceous intercalations in the Ria-Kalui well,
rich in lenticular black shale of Duruma outcrops. Those to
the south of Taru Formation contain fair amount of organic
carbon (0.5 – 1 percent) and fair to rich Total Organic
Content (0.7 – 2.4 percent).
The Permian sandstones tested in the Calul well of
Southern Ethiopia (the extension of Mandera Basin in
northeastern Kenya) have produced gas of 1 million at m3/
d from 2742 – 2815 m depth. The Madagascar Isalo–I
sandstones’ hydrocarbons, contained in tar sands, seem to
have similar stratigraphic equivalents to those of the Taru
Grits of Maji Chumvi Karroo beds in Kenya. The impressive
thicknesses of coal seams (several meters thick) have been
reported in lower Permian coal measures (Rabinowitz, 1982)
of India. The prolific source rocks deposited during initial
rifting, which led to the separation of Southern Africa from
South America, have also been encountered in Neocemican
JOUR.GEOL.SOC.INDIA, VOL.83, APRIL 2014
421
lacustrine prodeltaic shales of the coastal Brazilian fields;
the abundant source rocks of early Cretaceous shale and
lacustrine clays in the Gabo–Congo coastal basin (Mayanga
Marls, Melanie formation, and Black shale) also form
potential source rocks (BEICIP, 1984).
The Karroo sediments (4,000 m thick) could have
undergone a rapid maturation during the late Paleozoicmiddle Jurassic rifting stage, resulting in high geothermal
fluxes (gradients 3oC/100 m). Thus in such geotectonic
environments, the maturation may have occurred in greater
depths during the post-rift or failed-rift stages, with burial
becoming considerably deeper during late Triassic
Cretaceous and Tertiary sedimentation. This has given rise
to the top of the Karroo at 5,000–10,000 m depth in Lamu
embayment. The Karroo sediments increasingly become
over-mature or super-mature as evidenced in the thermal
and burial history (Fig. 3). The hydrocarbons generated
before the present burial may have been preserved in traps
which were not subjected to burial at destructive depths.
The syn–rift sequences of the Jurassic sedimentation in
other parts of the world, with similar geotectonic conditions
and facies characteristics, are apparently similar to those
belonging to the Jurassic outcrops in Kenya. The central
Lamu embayment deposits constitute good reservoirs that
are devoid of source potential, comprising shaley
interbedded limestones and anhydrites intercalations which
gradually become more calcareous and subsequently
terminate as evaporitic sequences. They have a well
developed shaley or carbonate source rocks containing Type
II kerogen. The argillaceous shale or evaporate form good
cap rocks in the Karroo, although they are poor quality
reservoirs. Under favorable structural conditions the
underlying sandstone sections of the late Triassic to early
Jurassic may be excellent carrier beds. Evidence of source
rocks in syn–rift sequences include the Miocene Globigerina
marls of Egyptian fields and Gulf of Suez forming prolific
source rocks. However, some transitional euxinic shale
associations of Aptian age are considered to be good source
rocks; for example, those in the Brazilian coastal fields and
Jurassic limestone of Ganale Doria river in Ethiopia.
The geothermal gradients of 3°C/100 m are far less in
the post-rift sequences, hence slowing down the sediment
maturation. The maturity level is likely to be high (overmature to super mature) in the Jurassic. The oil generation
window obtained by use of computer-aided modeling
indicate a burial depth ranging from 3,300 m to 3,400 m at
the top of the oil zone and 4,700 m in the top of gas zone.
The paleogeographic position of this region (what is
presently Lamu embayment in eastern Kenya) was much to
the south of the Equator during the Triassic-Jurassic/
422
MOGAKA D. NYABERI AND BERNARD K. ROP
Cretaceous time (Bloom, 2002). Luxuriant vegetation on
land, swampy grounds, humid climate and good rainfall were
some of the prevailing environmental conditions. The
organic matter that got buried could only generate the Type
I, Type II or Type III kerogen whose initial product could
be waxy crude or gas. The sub-surface strati-graphical and
sedimentological studies indicate that the Cretaceous
sediments of Lamu embayment show the tendency to become
more pelagic in the direction of Deep Ocean, with the
presence of source rocks dwindling at depths.
Computer-aided model indicates the presence of mature
upper Cretaceous sediments in the Walu–Kipini–Pate–
Dodori wells, whose top of oil window vary in depths from
2,400 – 3,600 m with the maturity levels gradually
diminishing offshore (where they are probably immature).
The lower Cretaceous sediments in the present study area
are mostly over-mature, except in the proximity of the
offshore areas (along Kenya coastal shores), where they may
be mature at depths ranging between 3,300 – 4,700 m.
DISCUSSIONS, PROGNOSTIC EVALUATION
AND CONCLUSION
The prognostic evaluation of potential hydrocarbons in
Lamu basin have been examined and recommended,
although they are not of any commercial quantities. It is
also evident that there is poor well siting in the area under
study. Literature shows that Tertiary episodes of subsidence
in the Lamu basin (cyclic – reciprocal – sedimentation),
halokinesis and faulting are important from the stand point
of hydrocarbon formation and migration. Basinwards, at
greater depths, the immature intervals of Kipini and Dodori
wells might be in the oil zone window.
From the interpretation of seismic data, the reservoirs
along which many wells in the area have been drilled appear
to be compartmentalized by a combination of structural lead
features (faults) and sub-surface stratigraphic elements
(geothermal highs). Faulting at favorable locations may have
trapped the generated oil and gas although high heat may
lead to over-maturation of hydrocarbons. Thus, on analysis
and interpretation of the data from the basin, the potential
effects of sub-seismic faults in the area should be of critical
significance. For improved reservoir characterization, a
model should be developed which integrates seismic,
petrophysical and transient pressure data yields. This will
prognostically direct the drilling of the wells at proper points
of the reservoir, away from the major fault zones and zones
of high thermal gradients.
References
BEICIP (1984) Petroleum potential of Kenya 1984 follow-up,
Ministry of Energy and Regional Development, 100 p.
BLOOM, A.L. (2002) Geomorphology, Third Edition, Prentice-Hall
India Pvt. Ltd., New Delhi, 482 p.
CANNON, R.T.; SIAMBI, W.M.N. and KARANJA, F.M. (1981) The
proto Indian Ocean and probable Paleozoic Mesozoic Triradial
rift system in east Africa. Earth Planet. Sci. Lett., v.52, pp.419426.
KARANJA, F.M. (1982) Report on the geology of the Kilifi, Gede
and Sokoke area. Geol. Surv. Kenya, Nairobi, 32p.
KENT, P.E. (1982) The Somali ocean basin and the continental
margin of east Africa. In: A.E.M. Nairn and F.G. Stehli (Eds.),
The Ocean Basins and Margins, The Indian Ocean, Plenum
Press, New York, v.6, pp.185-204.
KHALEB, K.A. (1999) Cretaceous source rocks at the Abu Gharadig
oil and gas field, Northern western desert, Egypt. Jour. Petrol.
Geol., v.22. pp.623-629.
MILLER, J.M. (1952) Geology of the Mariakani MacKinnon road
area, Report No. 20, Geol. Surv. Kenya, 45p.
NATIONAL OIL CORPORATION OF KENYA (NOCK, 1995) Hydrocarbon
potential of the coastal onshore and offshore Lamu Basin of
southeast Kenya, Integrated Report, 97 p.
NYAGAH, K. (1992) Hydrocarbon exploration in the sedimentary
basins of Kenya. In: P.S. Plummer, Ed., Proceedings of the
Indian Ocean-First Regional Seminar on Petroleum
Exploration, United Nations Department of Technical Co-
operation for Development, Seychelles, pp.53–66.
NYAGAH, K. and CLOETER, J.J. (1992) International exploration opportunities in Kenya. Bull. Houston Geol. Soc., v.35, pp.16-18.
ODADA, E.O. (1995) Geological evolution of coast Kenya as
Inferred from sedimentary sequences and marine terraces,
Geol. Surv. Kenya, Nairobi, 24 p.
RABINOWITZ, P.D. and COFFIN, M.F. (1982) Salt diapirs bordering
the continental margin of northern Kenya and southern
Somalia. Science, v.215, pp.663-665.
RABINOWITZ, P.D. COFFIN M.F. and FALVEY, D. (1983) The separation of Madagascar and Africa. Science., v.220, pp.67-69.
R AIS-ASSA , R. (1988) Stratigraphy and geodynamics of the
Mombasa basin (Kenya) in relation to the genesis of the protoIndian Ocean, Geol. Mag., v.125, pp.141-147.
REEVES, C.V. KARANJA, F.M. and MACLEOD, I.N. (1986) Geophysical
evidence for a Jurassic triple-junction in Kenya, Earth Planet.
Sci. Lett., v.81, pp.299-311.
ROP, B.K. (2003) Subsurface stratigraphical studies of CretaceousTertiary basins of northwest Kenya, (Unpublished Ph.D.
Thesis, University of Pune), 174p.
SIMIYU, S.M. (1989) Geophysical studies in Lamu Embayment to
determine its structures and stratigraphy, (Unpublished M.Sc.
Thesis, University of Nairobi), 126p.
SUGGATE, R.P. (1998) Relationships between depth of burial,
vitrinite reflectance and geothermal gradient. Jour. Petrol.
Geol., v.21, pp.5–32.
(Received: 29 May 2011; Revised form accepted: 6 March 2013)
JOUR.GEOL.SOC.INDIA, VOL.83, APRIL 2014