This hypothetical report attempts to evaluate, characterize and determine the maturity of multiple source rocks in the Lamu Basin, Kenya. The report uses a number of techniques and well data to come to a conclusion as what action should be taken with the basin.

1. 1.
Basin Evaluation of the Lamu Basin
Tom Adamson, Petroleum Geologist at Kongsberg
The Lamu Basin forms part of the continental passive margin of Kenya and covers the south-eastern
coastline with an area of 130,000 square kilometres, “extending offshore from a relatively narrow onshore
graben to cover most of the continental shelf and slope of Kenya.” (Nyaberi and Rop, 2014) The basin
formed during the separation of Madagascar from Africa and was rifted in the Carboniferous, but the
cretaceous section contains highly prospective source and reservoir units. Hydrocarbon traps in these units
are block faulted anticlines that have been affected by compaction faults. In 2014, a “14m gross oil column
was encountered by Subbird-1 in Miocene reefs,” (Osiki et at, 2015) and Kongsberg now view the Lamu
basin as an emerging hydrocarbon province. This report is an assessment of the basin to determine if it is
favourable for oil/gas generation and is therefore economically viable. The deposited sediments have been
interpreted based on rock eval data, and a source kitchen model has been constructed to analyse the maturity
and prospectively of the basin. The report is contained from the Upper Cretaceous to Upper Tertiary,
focusing on data between 0-4000m water depths where a total of 6 well analysis were used to tie the
interpretation.
A commercial discovery in the Lamu Basin has yet to be discovered, but most of the drilled wells have
yielded hydrocarbons shows of oil/gas. The “oil window is generally located at depths greater than 3000m,
due to the low geothermal gradient associated with thick sediments of the basin.” (Rop, 2003) From Figure
1a, vitrinite reflectance data from the Dodori well in block L-13 illustrates the Walu Shale, within the Sabaki
Group entering the oil window in the Miocene (15Ma), then growing in thermal maturity, entering the peak
oil and early gas windows when the fracture system opened. From the late cretaceous to tertiary, the oil in
this unit was immature, finally reaching the early stages of oil as the rocks were cooked further, arriving at
peak oil in the late Miocene. “The edges of the Davie Walu Fracture Rift have large-sharp negative
anomalies which indicates a large vertical displacement due to adjacent faults along the fracture zone.”
(Masinde, 2018) This fracture system has a north-south trend across the basin and was active roughly 5Ma,
which increase the potential for prospective reserves due to the poroperm assistance for the oil. As seen in
figure 1b, this trend continues in the Kipini well, found at the edge of Block L15. The key stage of oil
generation within this basin was during the mid to late Miocene, for the Campanian Walu Shales, which
were buried and cooked to greater extremes than the younger units. The Kipini well has phases of rifting
5Ma that line up with Dodori-1 in block L13. A tertiary dextral fault runs through Block L15, and the
sinistral fault through L13 of the Davie Walu Fracture zone. Data suggests that the Kipini formation in the
Tara group will also become more thermally mature and enter the oil window in the Miocene, migrating oil
generated at the peak stage, instead of early. A notable structure of the formation is the Miocene carbonate
fairway, which was faulted and is a suitable trap for the block.

2. 2.
The Kofia well “was drilled by Union Oil in 1985 and encountered good oil shows in the Palaeogene and
Upper Cretaceous intervals.” (Dominion Petroleum Ltd., 2019) A hypothetical geothermal gradient of 30o
C
was used for the Kofia well, and results showed that the Late Cretaceous units entered the early stage of oil
generation in the late Pliocene. Figure 1d shows that the Simba wells has a slower rate of oil generation
within block L9, and is less affected by the fracture zone. The oil is immature from the late cretaceous to
present day, where it enters the oil window. Seismic imaging suggests inversion structures formed by late
cretaceous/early tertiary faulting, later assisted the Miocene fracture system. The Neogene fracturing
migrated immature oil to a reservoir rock, implying the Kofia Sands (Sabaki Group) needed to be cooked
more before the hydrocarbons were transported. The general trend is that oil generation started in the Sabaki
Group in the mid to late Tertiary and migrated and accumulated into a reservoir rock. Episodes of basement
uplift from the late cretaceous formed complex patterns and structural highs, including the Davie-Walu
Ridge, which underwent recent fracturing. Seismic imaging form block L9 suggests potential stratigraphic
trapping in the western Simba graben, whereas blocks L15/13 are impacted by the fault blocks of the
Neogene Fracture Zone, which has rift grabens within the fault blocks, likely the source of kitchens. Most of
the wells terminate just as the sedimentary column enters the oil window, where deeper source rocks are
more thermally mature.
The parameters to determine optimal source kitchen conditions were HI values over 200, and vitrinite
reflectance over 0.8%. Contours were used to pain a 2D visualization of the source kitchen of the Walu and
Kipini Shales formation in the Lamu Basin. The Walu Shale is a marine facies and was drilled down to late
Cretaceous strata. The oil prone kitchen is located both on and offshore, specifically in blocks 8, 6, and 14.
The Maridadi well had extreme high HI values and is early in the oil window, but has only picked up
sparkly drill cuttings. North of Maridadi Well, the source rock lies predominantly in the gas window, which
may be caused by a gas rich terrigenous input and the extra cooking of the unit. From figure 2a, the main
kerogen type in the basin is “humic or gas prone kerogen Type III, [which] has been realized in the lower
Cretaceous.” (Nyaberi and Rop, 2014) This trend continues north of Lamu, up to the Hagarso well, where it
seems the further away from the oil prone kitchen, the further into the gas window the source rocks go. The
source rocks in the kitchen contain liquid hydrocarbons, whereas the rocks that contain migrated
hydrocarbons, are in a metagenesis stage, forming gaseous hydrocarbons and methane. Those areas have
gone past the oil window and have used up a lot of hydrogen and oxygen. Finally, the oil in these wells is
mature to over mature, but there has been oil linked to Tertiary basin subsidence, which may be “crucial in
limiting compaction and thermal conductivity which influenced the development of favourable thermal
regimes.” (Nyaberi and Rop, 2014) The Kipini shale source kitchen is located offshore in block 12 and 11
and covers a small area of 40km2
. It was likely a fluvial-delta shallow marine deposit and is poor to very
immature. The Pate-1 well barely reaches the porous sands of the formation, which “were the first deposits
with well-developed porosity to be encountered within the oil window.” (Nyagah, 1995) According to Osiki

3. 3.
et al (2015), the Kipini Shale is modelled as immature, but the petroleum system formed a good order for
hydrocarbon accumulation in offshore areas.

4. 4.
This trend continues north of Lamu, up to the Hagarso well, where it seems the further away from the oil prone
kitchen, the further into the gas window the source rocks go. The source rocks in the kitchen contain liquid
hydrocarbons, whereas the rocks that contain migrated hydrocarbons, are in a metagenesis stage, forming gaseous
hydrocarbons and methane. Those areas have gone past the oil window and have used up a lot of hydrogen and
oxygen. Finally, the oil in these wells is mature to over mature, but there has been oil linked to Tertiary basin
subsidence, which may be “crucial in limiting compaction and thermal conductivity which influenced the development
of favourable thermal regimes.” (Nyaberi and Rop, 2014) The Kipini shale source kitchen is located offshore in block
12 and 11 and covers a small area of 40km2
. It was likely a fluvial-delta shallow marine deposit and is poor to very
immature. The Pate-1 well barely reaches the porous sands of the formation, which “were the first deposits with well-
developed porosity to be encountered within the oil window.” (Nyagah, 1995) According to Osiki et al (2015), the
Kipini Shale is modelled as immature, but the petroleum system formed a good order for hydrocarbon accumulation in
offshore areas.
The source kitchen for the Walu shale in Sabaki group only recorded oil in the Mardidadi well, and based on seismic
data, the well was not drilled far enough to display the oil prone rocks. The burial curve for Maridadi places the Tana
group just over 4000m, meaning the Sabaki group is located close to 5000m by current estimates. The van krevlen
diagram shows there is Type 1 kerogen in the Maridadi and Kipini wells, but they’re not picking up any oil, which
likely has not undergone efficient migration and not been drilled deep enough. Regarding the Kipini shale in the Tana
group, the oil source kitchen covers a large area offshore, and figure 1b shows the oil has migrated west to Maridadi,
and was sourced from the Kofia well in block L-15. The only well with viable oil is the Maridadi, which is just
entering the oil window now as seen in figure 3b, but if it was drilled a little deeper, more oil would be discovered.
This well has been subjected to less heat and has the lowest geothermal gradient of 25.6, meaning the source rocks are
less likely to hold gaseous hydrocarbons. According to Stanca et al. (2016), the oil window in the south, surrounding
the Simba well is predicted to lie much deeper than expected. The risk associated with the faulting and migration
pathway of the oil is too high to set aside funds for licensing rounds. The wells in the current data base do not
economically support the extraction of oil in the basin. The lack of thermal maturity in late cretaceous sediments, and
the large area of the oil source kitchen leaves me to believe this is not the way forward for Kongsberg. I have been
unable to predict the best areas for oil migration pathways, and the van krevlen diagram suggests the basin is
prodimmently type III kerogen. In most of the cases, the wells picked up traces of oil, which has a window much
deeper than predicted.
Block L-15 sits atop of the Davy Fracture zone and has the best offshore oil show based on current data, but only
showed sparkly drill cuttings and lacked thermal maturity to enter the oil window. It’s a better option to search for gas
to the north west of Block-15, where the cretaceous sediments have been buried deeper. The Pate well has a high
geothermal gradient and shows the Kipini Shale entering the early stages of gas generation during the mid Miocene
fracture system. The van krevlen diagram for the Kipini formation show the Simba, Pate, and Dodori well as being gas
prone, and all those have higher vitrinite reflectance values and deeper formations than the Kofia-1 well. And yet, the
Pate-1 well “barely reached gas-saturated porous sands of the Kipini Foramtion at terminal depth.” (Nyagah, 1995)
However, there is evidence to suggest that the Kofia-1 wells was not drilled on an optimal location with respect to
structure. “The gas shows were under represented by ongoing problems with gas detector during drilling,” (Dominion,
2019), but I see more success of gas exploration in other areas along the coastline. There have been Tertiary episodes
of subsidence in the Lamu basin, halokinesis and faulting are important from the stand point of hydrocarbon formation
and migration.” (Rop and Nyaberi, 2014) The Mwaba complex in Block L-8 may extend into Block-15 and reveal
stratigraphic traps for gaseous hydrocarbons, but the associated with the theory is too high to warrant any action.
It is my professional opinion that
Each well just produced traces of oil or gas.

5. 5.
Graphs and Figures Figure 1b: Time against %Ro of the
Kipini Well in Block L6
Figure 1a: Time against %Ro of the Dodori Well in Block L13
Figure 1d: Time against %Ro of the Simba Well in Block 9
Figure 1c: Time against %Ro of the Kofia Well in Block L15

6. 6.
Figure 2a: Walu Shales Van Krevlen
Diagram
Figure 2b: Kipini Shales Van Krevlen Diagram
Well Depth GL (m)BHT (°C) Cor BHT (°C) Average Geothermal Gradient
Simba 1 -1204 41 52 30.07
-2204 69 84
-2607 79 99
Maridadi 1 -1687 63 72 25.9
-2507 84 91
-3052 104 111
-4089 146 161
Kipini 1 -1282 61 73 34.72
-2998 108 124
-3629 123 141
Pate 1 2 25 25 32.72
-1204 51 64
-2956 91 111
-3735 124 142
Dodori 1 0 25 25 29.98
-605 45 45
-2060 77 94
-2268 89 101
-2878 108 121
-3189 113 131
-3537 123 143
-3958 131 157

7. 7.

8. 8.

9. 9.
In this research project an assessment of source rock maturity in the Lamu Basin based on well distribution, hydrocarbon shows, total organic carbon (T.O.C) levels,
kerogen type using hydrogen-oxygen indices and Vitrinite Reflectance (Ro) has facilitated modeling of the hydrocarbon prospectivity in the Lamu Basin. The Lamu
Basin, also known as the Lamu Embayment, is the largest sedimentary basin in Kenya and covers an area of approximately 259,782 square kilometers. The Lamu
Basin covers both onshore and offshore geologic settings. The Basin contains sediments thickness of up to thirteen thousand (13,000) meters of sediments in the
offshore parts of the Basin. Over eighteen (18) exploratory wells have been sunk in Lamu Basin. Seven (7) wells had with gas shows, two (2) had oil shows and two
(2) had both oil and gas shows. Most of the wells drilled on the onshore portion of the Lamu Basin so far have targeted trapping mechanisms identified on a north-
south axial trend thought to be an extension of the Davie Fracture Zone (DFZ). There has not been any commercial discovery so far in the Lamu Basin but most of
the wells drilled in this basin have yielded hydrocarbon shows of oil and or gas. Average (TOC) for horizons ~ 0.5% within the Lamu Basin sediments measured
1.17% in Simba-I Well, 0.59% in Maridadi-1 Well, 1.53% in Kipini-I Well and 0.56% in Walu-1 Well. Highest TOC level of up to 11.36% in the Kipini Formation of
Middle Eocene age which is enough to yield commercial accumulations of hydrocarbons on maturation. Type III kerogen is the most dominant Kerogen Type and
gas occurrences are the most frequent type of hydrocarbon encountered in the Lamu Basin. In Simba-I Well, gas shows were encountered at 1389m-3080m.
In Maridadi-1 Well, gas shows were encountered at the depth of 3320m-3600m, and oil shows at the depth of 3660m, while in Kipini-l Welt gas shows were
encountered at 1110m- 3360m. Vitrinite Reflectance values indicate deeper source rocks to have attained thresh hold values of more than 0.6%. These sediments
are therefore mature with a threshold maturity depth of 3183m in Simba-I Well, 3583m in Maridadi-l Well, 2609m in Kipini-1 Well and 2000m in Walu-l Well. These
observations are consistent with the interpretations arrived at in this research. This research has indicated that the wells drilled so far are terminated just as the
sedimentary column is entering oil window therefore deeper drilling is required to intercept hydrocarbon bearing sediments.

10. 10.
The sabaki group has entered the peak oil window.
“The edges of the DWFR have large-sharp negative anomalies which indicates a large vertical
displacement due to adjacent faults along the fracture zone.” Masinde
The zone is highly faulted (figure 3) with some faults
structurally binding sedimentation to the west. The eastern side is
dominated by the DWFZ-half graben uplift leading to sediment
removal. The thinning of this early Tertiary into late Cretaceous
suggests that the DWFZ marked the eastern limit of this Tertiary
basin. Campanian unconformityJurassic half grabenMid Maastrichtian onlapping on
CampanianCampanian unconformityHigh amplitude Jurassic reflectorsUplifted basement
fault blocks
Two major petroliferous systems in the Lamu basin havebeen recognized, one is the Cretaceous-Jurassic/Cretaceouspetroliferous system and the other is the Tertiary sys-tem
(Maende and Danson 1994; M’Mukindia 2004,2005).For the Cretaceous-Jurassic/Cretaceous petroliferous sys-tem, the Cretaceous-Lower Paleocene shale is the hydrocar-
bon source rock. As the source rock, the Cretaceous Walushale is overmature and/or reaches the threshold of the oilwindow. In the region experiencing tectonic activities,
theTuronian-Paleocene Kofia shale shows immature to maturecharacteristics and entered the oil window in the MiddleEocene (Maende and Danson 1994). The reservoir
strata aremainly Jurassic and Lower Cretaceous Ewaso sandstone andUpper Cretaceous–Lower Palaeocene Kofia clastic rocks aswell as Upper Cretaceous Freretown and
Hagarso limestone: about block 2

11. 11.
In Cretaceous, structural-stratigraphic trapsassociated with the Ewaso sand and Kofia sands are presentwithin the sequence.
The rifting stage affected the Lamu basin during lateJurassic and was responsible for the generation andmaturation of source rocks. High
geothermal gradients andearly migration into paleostructures or pinch are associatedwith rifting system. The failed rift and the post rift stageswere
characterized by low geothermal gradients. The secondphase of subsidence which resulted in the generation ofhydrocarbons, applies to Karroo
sediments of the basin ofJurassic, for example oil shows that were encountered inKipini and Dodori wells (upper Cretaceous and lowerTertiary
beds) are related to Tertiary subsidence whichtriggered a late phase of oil generation from Jurassic sourcerocks. (Nyaberi and Rop, 2014)
Oil discovered in the Kipini and Dodori wells relate to the Tertiary subsisdence which triggered a phase of oil generation from the Mitomkuu Shales and
Kambe Formation. The tertiary formations are immature, whilst the crecaerous rocks are more mature. The Kipini and Dodori wells show mature to over
mature maturity levels.
The extensional domain ischaracterized by basinward dipping normal growth faults and the compressional domain by a series of imbri-cate,
basinward verging thrusts, forming a narrow critical taper (about 3°), and characterized by kink-shapedfolds. The interpreted age of the
synkinematic strata indicates that thrusts were active approximately duringthe Late Miocene and Early Pliocene.
The Lamu Basin deepwater fold-and-thrust belt:An example of a margin-scale, gravity-driventhrust belt along the continental passivemargin
of East Africa

12. 12.
Wells onshore in the Juba-Lamu Basin in the south display much lower geothermal gradients
consistent with being underlain by, or close to, Jurassic oceanic crust. The oil window in the
south is therefore predicted to lie much deeper. The Juba-Lamu Basinhas the thickest post-rift stra-
tigraphy over the shelf and slope, up to 12 km. It comprises siliciclastic deltaic sediments, sourced by the
Shabeelle/Jubba/Tana River Deltas, and is thought to consist of organic rich pro-delta shales and turbidite
deposits. Source rock intervals are inferred from décollement surfaces in the Cenomanian and
Eocene. As both of these intervals are shallower than the syn-rift source rock, assisted by low
geothermal gradients we model these horizons to be in the oil window present day, as is the
Jurassic syn-rift source in the outboard setting (Figure 9): Stanca, R., Kearns, H., Paton, D., Hodgson, N., Rodriguez, K. & Hussein, A.A.2016.
Offshore Somalia: crustal structure and implications on thermalmaturity.First Break,34, December, 61–67.
arbonates and sandstones of Mid–LateCretaceous age are present on the shelf and thin out at the Simba-1well. These are separated from the Tertiary clastics by
an importantunconformity. Another unconformity separates the Oligocene clasticsfrom the Miocene limestones.
The Lamu Basin has good reservoir potential with a large amount ofclastic sediment deposited onto a delta-fed from the Anza Graben.There is a high risk of
gas in the mid and outer shelf, due to the thickTertiary fill. The deep-water gravity fold belt contains largeanticlines which probably host Late Tertiary turbidite
sandstoneplays, but hydrocarbons will need to migrate from a deep sourcethrough the overpressured detachment.: Davison, I. and Steel, I. (2017). Geology and
hydrocarbon potential of the East African continental margin: a review. Petroleum Geoscience, 24(1), pp.57-91.