GEPJournal of Geoscience and Environment Protection2327-4336Scientific Research Publishing10.4236/gep.2023.115004GEP-125070ArticlesEarth&Environmental Sciences Evaluation of Source Rock Potential for Hydrocarbon Generation in Shallow Offshore, Lamu Basin, Kenya DennisOmbati1GithiriJohn2MauriceK’Orowe2Department of Physics, Kisii University, Kisii, KenyaDepartment of Physics, Jomo Kenyatta University of Agriculture and Technology, Nairobi, Kenya190520231105608526, March 202321, May 2023 24, May 2023© Copyright 2014 by authors and Scientific Research Publishing Inc. 2014This work is licensed under the Creative Commons Attribution International License (CC BY). http://creativecommons.org/licenses/by/4.0/

The ever-increasing demand for oil and gas has driven its exploration in rather extreme conditions. In Lamu offshore, which is hitherto underexplored, most of the wells already drilled turned out dry save for a few wells with hydrocarbon shows despite the promising reservoir properties and related geological structures. This, therefore, necessitated a source rock evaluation study in the area to ascertain the presence and potential of the source rock by integrating the geochemical data analysis and petroleum system modeling. The shallow Lamu offshore source rock quantity, quality, and maturity have been estimated through the determination of the total organic carbon (TOC) average values, Kerogen typing, and Rock-Eval pyrolysis measurements respec tively. Geochemical data for Kubwa-1, Mbawa-1, Pomboo-1, and Simba-1 were evaluated for determining the source rock potential for hydrocarbon generation. Petroleum system modeling was applied in evaluating geological conditions necessary for a successful charge within a software that integrated geochemical and petrophysical characterization of the sedimentary formations in conjunction with boundary conditions that include basal heat flow, sediment-water interface temperature, and Paleo-water depth. The average TOC of 0.89 wt % in the study area suggests a fair organic richness which seems higher in the late cretaceous (0.98 wt %) than in the Paleocene (0.81 wt %). Vitrinite reflectance and T max values in the study area indicate the possible presence of both mature and immature source rocks. Type III Kerogen was the most dominant Kerogen type, and gas shows are the most frequent hydrocarbon encountered in the Lamu Basin with a few cases registering type II/III and type II. The charge properties (i.e. Temperature, transformation ratio, and Vitrinite reflectance) over geologic time at each of the wells have been estimated and their spatial variation mapped as seen from the burial history and depth curves overlaid with temperature, transformation ratio, and Vitrinite reflectance respectively. From the upper cretaceous maturity maps, the results seem to favor near coastal regions where average TOC is about 1.4 wt %, Vitrinite reflectance is more than 0.5%, transformation ratio is more than 10%, and temperatures range from 80 ° C to 160°C. The results postulate the absence of a definitive effective source rock with a likelihood of having cases of potential and possible source rocks. Moreover, greater uncertainty rests on the source rock ’ s presence and viability tending toward the deep offshore. Geochemical analysis and petroleum system modeling for hydrocarbon source rock evaluation improved the understanding of the occurrence of the possible and potential source rocks and processes necessary for hydrocarbon generation.

Geochemical Analysis Petroleum System Modeling Rock-Eval Pyrolysis Kerogen Typing Vitrinite Reflectance and Transformation Ratio1. Introduction

The ever-increasing demand for oil and gas has driven its exploration in rather extreme conditions. In Lamu offshore, which is hitherto underexplored, most of the wells already drilled turned out dry save for a few wells with hydrocarbon shows despite the promising reservoir properties and related geological structures. This, therefore, necessitated a source rock evaluation study in the area to ascertain the presence and potential of the source rock by integrating the geochemical data analysis and petroleum system modeling.

A source rock is rich in organic matter, which, if heated sufficiently, will generate oil or gas. Typical source rocks, usually shales or limestones, contain about 1% organic matter and at least 0.5% total organic carbon (TOC), although a rich source rock might have as much as 10% organic matter. The quantity of organic matter is commonly assessed by a measure of the total organic carbon (TOC) contained in a rock. Quality is measured by determining the types of Kerogen in the organic matter. Thermal maturity is most often estimated using Vitrinite reflectance measurements and data from pyrolysis analyses (Waples, 1994) .

The Lamu Basin has potential source rocks ranging from type I to type III Kerogen (NOCK, 1995) . These include Jurassic Oolitic Limestone and Lacustrine shales, with an average TOC of 1.4%. Type III Kerogen is the most dominant Kerogen type, and gas occurrences are the most frequent hydrocarbon encountered in the Lamu Basin (Ngechu, 2012) . Jurassic to Cretaceous source rocks is widely distributed with good quality and is the primary source rocks on the east coast of Africa. Tertiary source rocks have a lower thermal evolution degree and are considered ineffective source rocks in all basins except Somali Basin (Nyaberi & Rop, 2014) .

Lamu Basin has bad source rock conditions, with an inference of a possible presence of two sets of source rocks and a lack of high-quality source rock (Zhou et al., 2013) . The Lamu basin source rock’s nature and maturity remain crucial (Osicki et al., 2015) . The charge, (primarily source presence), is the critical risk for deep offshore Lamu Basin, with no definitive evidence of deep-water marine source rock in the Basin. Since the source rock presence is unproven, great uncertainty in finding the source rock potential stratigraphic interval rests in deep offshore (Osukuku et al., 2022) .

The purpose of this study is to evaluate the source rock’s presence and potential using geochemical data analysis and applying petroleum system modeling in evaluating geological conditions necessary for a successful charge. Geochemical data for Kubwa-1, Mbawa-1, Pomboo-1, and Simba-1 were evaluated for determining the source rock potential for hydrocarbon generation. Petroleum system modeling was applied in evaluating geological conditions necessary for a successful charge within a software that integrated geochemical and petrophysical characterization of the sedimentary formations in conjunction with boundary conditions that include basal heat flow, sediment-water interface temperature, and Paleo-water depth.

2. Geological Setting and Study Area

The Lamu basin extends to an area of about 255,000 km2 covering both the onshore and offshore whereby the thickness of the sediments ranges from 3 km to 10 km onshore and 12 km near the coastline to less than 3 km offshore, thinning towards the deep Indian ocean. The geology of Lamu Basin is tectonically controlled (Kimburi et al., 2015) . These tectonic activities brought about the splitting of Gondwana during the Jurassic and the Anza Rift Cretaceous activity. The Lamu Basin belongs to a passive continental margin classification and is unusual in that it lies in a transitional position between a rifted margin to the North in Somalia and a transform margin to the south. Carbonates, shales, and marine sandstones constitute the sediments of the area (Figure 1) (NOCK, 1995) .

South-Eastern Kenya’s Lamu basin relates to the rifted continents like Australia, America, India, Antarctica, Africa, and Madagascar during the Jurassic rifting (Coffin & Rabinowitz, 1987) . East Africa’s potential for hydrocarbons is signified by the significant oil and gas discoveries in Mozambique and Tanzania and the heavy oil deposits in Madagascar’s conjugate margin (Osicki et al., 2015) . Following the worldwide scale for exploration status and success rate, computed according to the number of drilled exploration wells per 5000 km2, the exploration status and success rate in Kenya remain very low. However, the prospective offshore Lamu basin of Kenya, (Figure 2), has received much interest in hydrocarbon exploration, the exploration potential defined by the ratio of success rate to exploration status stands fair (51%) compared to other basins in Kenya (Nyagah et al., 1996) .

Despite the gas and oil shows evidenced by a few of the drilled twenty (20)

exploration wells, most of the drilled wells turned dry (Figure 3). The purpose of this paper, therefore, is to apply petroleum system modeling in evaluating geological conditions necessary for a successful charge. Petroleum Systems Modeling (PSM) is a vital component of exploration risk assessment and is applicable during all stages of exploration, from frontier basins with no well control to well-explored areas (Ruffo et al., 2006) . Petroleum system models require geochemical and petrophysical characterization of the sedimentary formations in

conjunction with boundary conditions (paleo-water depth, sediment-water interface temperature, and basal heat flow) (Al-Hajeri et al., 2009) .

3. Hydrocarbon Source Rocks Evaluation

Prediction of the presence of viable source rock is a vital prerequisite before exploration effort advancement in a new basin. Due to limited well control that could provide source rock interval direct evidence, the application of seismic geometries and petroleum system modeling are preferred in many cases (Liner & McGilvery, 2019) . To be a source rock, a rock must have a quantity of organic matter, quality capable of yielding moveable hydrocarbons, and thermal maturity features (Table 1). The first two components are products of the depositional setting. The third is a function of the structural and tectonic history of the province. Various criteria exist in source rock classification (Al-Areeq, 2018) . According to Waples (1994) , source rocks can be distinguished into potential, possible, and effective whereby potential source rocks are the immature sedimentary rocks capable of generating and expelling hydrocarbons if their level of maturity were higher. Possible source rocks are sedimentary rocks whose source potential has not yet been evaluated, but which may have generated and expelled hydrocarbons, and effective source rocks are sedimentary rocks, which have already generated and expelled hydrocarbons. Source rocks can also be classified as immature, mature, and post-mature regarding their oil generation

(Hunt et al., 2002) .

3.1. Using Geochemical DATA

The quantity of organic matter is commonly assessed by a measure of the total organic carbon (TOC) contained in a rock. Quality is measured by determining the types of Kerogen contained in the organic matter and the prevalence of

Parameters for source rock evaluation (modified from JOGMEC)
maturityRo (%)0.51.3
immatureOil zoneGas zone
Tmax (˚C)430465
immatureOil zoneGas zone
Kerogen TypeHI mg HC/g TOC200300
III (gas-prone)II/III (oil/gas)II (oil-prone)
Organic richnessTOC (%)0.51
PoorFairGood
13
PoorFairGood

long-chain hydrocarbons. Thermal maturity is most often estimated by using Vitrinite reflectance measurements and data from pyrolysis analyses (Katz, 1983) . TOC and Rock-Eval pyrolysis is the handiest method to evaluate organic richness, Kerogen type, and maturity. It is often used as a routine screening tool to find a good source interval (Peters & Cassa, 1994) .

Rock-Eval is a standard routine analysis of source rocks, usually shales, to establish how much of the Kerogen has been transformed into petroleum and how much can be transformed at a higher temperature (Langford & Blanc-Valleron, 1990) (Figure 4). The sample of shale is crushed and heated to 300˚C, at which point one measure the amount of hydrocarbons that are already formed in the source rock but have not migrated out. The content of hydrocarbon with carbon numbers between C1 and C25 is called S1. It is measured as the area beneath the peak S1. On further heating from 300 to 550˚C - 600˚C, new petroleum is formed in the laboratory from the Kerogen by heating (pyrolysis), and this amount is called S2. This is a measure of how much oil and gas could have been generated if the source rock and been buried deeper. The reason it requires such high temperatures is that the heating in the laboratory lasts just a few minutes or hours, instead of some millions of years (Bjørlykke, 2010) .

Figure 4 shows how a rock sample, representing a possible source rock, is heated gradually to about 550◦C while the amount of hydrocarbons generated is measured. At about 300◦C oil and gas which has already been generated in the source rock is expelled and measured as the S1 peak. The peak at about 400˚C - 460˚C represents the amount of hydrocarbons generated from the Kerogen in the sample. The temperature of peak HC generation is called the Tmax. The Hydrogen Index (HI) is a measure of the potential of the source rock to generate petroleum (Equation (1)). The total amount of CO2 generated is measured as the S3 peak (Equation (2)). The Oxygen Index (OI) is the measure of the limitation of CO2 quantity. Production index (PI) is the ratio of the remnant hydrocarbon

to the total generated (Equation (3)). The higher the value of the production index the better the source rock. The temperature coinciding with maximum hydrocarbon generation is known as Tmax, which has a typical range 420˚C - 460˚C (Figure 4).

HI = S 2 TOC (1)

OI = S 3 TOC (2)

PI = S 1 S 1 + S 2 (3)

where HI is the hydrogen index, OI is the oxygen index, PI is the production index, TOC is the total organic carbon, S1 is the remnant hydrocarbon, S2 is the generated hydrocarbon, and S3 quantity of CO2 formed.

3.1.1. Amount of Organic Matter

The quantity, (amount of organic matter) is commonly assessed by a measure of the total organic carbon (TOC) contained in a rock (Langford & Blanc-Valleron, 1990) . Typical source rocks, usually shales or limestones, contain about 1% organic matter and at least 0.5% total organic carbon (TOC), although a rich source rock might have as much as 10% organic matter. The organic richness of rocks is customarily expressed in terms of the percentage by weight of organic carbon (TOC wt %) (Wang et al., 2021) . The minimum concentration of organic carbon sufficient enough to saturate the pore network for an adequate level of expulsion efficiency from a potential source rock is 1.0% TOC, although a threshold as low as 0.5% TOC are however considered possible in gas-prone systems which are largely driven by diffusion at an adequate level of the concentration gradient (Asadu et al., 2015) . Generally, the amount of TOC in shales (especially black shale) is always higher than five times that of carbonate or other beds of sediments but the potential to generate hydrocarbons from the organic matter is more in carbonate rocks than in shales (Rop & Patwardhan, 2013) .

3.1.2. Kerogen Type

Kerogen is a collective name for organic material that is insoluble in organic solvents, water, or oxidizing acids. The portion of the organic material soluble in organic solvents is called bitumen, which is essentially oil in a solid state. With increasing temperature, the chemical bonds in these large molecules (Kerogen) are broken and Kerogen is transformed into smaller molecules that make up oil and gas. This requires that the temperature must be 80˚C - 150˚C over a long geological time (typically 1 - 100 million years). The conversion of Kerogen to oil and gas is thus a process that requires both higher temperatures than one finds at the surface of the earth and a long period of geological time (Pepper & Corvi, 1995) . Only when temperatures of about 80˚C - 90˚C are reached, i.e. at 2 - 3 km depth, does the conversion of organic plant and animal matter to hydrocarbons very slowly begin to take place. About 100˚C - 150˚C is the ideal temperature range for this conversion of Kerogen to oil, which is called maturation. This corresponds to a depth of 3 - 4 km with a normal geothermal gradient (about 30˚C - 40˚C/km) (Bjørlykke, 2010) . The three possible hydrocarbon source rock facies that may be identified from the seismic geometries include Type I (marine or lacustrine algal Kerogen, oil-prone), Type II (mixed marine and terrestrial organic material, oil and gas-prone), and Type III (terrestrial plant material, gas prone) (Liner & McGilvery, 2019; Tissot & Welte, 1984) .

3.1.3. Maturity

A theoretical maturity parameter (P) can be calculated by integrating temperature with respect to time:

P = ln ∫ 0 t 2 T / 10 ⋅ d T (4)

where t, is geological time (million years); T, is the temperature (˚C). We see that a doubling of the reaction rate for every 10˚C is built into this expression (Goff, 1983) . The maturity of source rocks can now be calculated with the help of basin modeling integrating temperature over time (Mani et al., 2015) . The source rock generative properties such as the Tmax and Vitrinite reflectance can then be determined. The subsidence curve for the source rock is determined from the stratigraphic age and thickness of the overlying sequence. When the subsidence curve is overlaid with the temperature, transformation ratio, and Vitrinite reflectance, information on the various hydrocarbon windows is obtained ranging from immature to Overmature (Makeen et al., 2016) .

3.2. Petroleum System Modeling

A network of mature source rocks, migration channels, reservoir rocks, and trapping and seal rocks in a geologic system constitute petroleum system elements (Ombati et al., 2022) . The combination of petroleum system elements and geologic processes such as hydrocarbon generation, migration, and accumulation defines a petroleum system and determines the existence of accumulated hydrocarbon in a given geologic environment (Hantschel & Kauerauf, 2009) . Petroleum system models require geochemical and petrophysical characterization of the sedimentary formations in conjunction with boundary conditions that include basal heat flow, sediment-water interface temperature, and Paleo-water depth (Magoon & Dow, 1994) (Figure 5). Petroleum systems modeling software is used to integrate all the information at hand to yield a range of scenarios in which the conditions of the petroleum system could have evolved in the past (Busanello et al., 2017) . In this study, petroleum system 1D modeling was focused on the play elements’ properties through geological time at a well location whereas the petroleum system quick look focused on the spatial distribution of play elements and properties represented as a map.

4. Results and Discussions

The geochemical characteristics: Total organic carbon content (TOC), Vitrinite reflectance (R0), Kerogen typing, and hydrocarbon content analysis of the sample petroleum source rocks were analyzed. Weatherford laboratories analyzed Kubwa-1 and Mbawa-1 samples, Geotech laboratories did for Pomboo-1, and Simba-1 samples were analyzed by Core laboratories. A total of 254 samples were taken through Rock–Eval pyrolysis consisting of 52 from Mbawa-1, 107 from Simba-1, 64 from Kubwa-1, and 31 from Pomboo-1. The results are presented in Tables 2-5.

Table 2 shows the average TOC values for four offshore wells. Kubwa-1 well gave an average TOC of 0.45 wt %, 1.04 wt % for Mbawa-1, 1.20 wt % for Pomboo-1, and 0.91 wt % for Simba-1 well. This gives an average of 0.89 wt % TOC value of the study area indicating a fair organic richness (refer to Table 1). When the samples from the late Cretaceous and the Paleogene are compared, the organic richness seems higher in the late Cretaceous (0.98 wt %) than in the Paleocene (0.81 wt %). The range of TOC values per well includes Kubwa-1 (0.09 wt % - 1.27 wt %), Mbawa-1 (0.1 wt % - 1.5 wt %), Pomboo-1 (0.82 wt % - 2.02 wt %), and Simba-1 (0.58 wt % - 2.23 wt %).

Vitrinite reflectance and Tmax values in the study area range from 0.5% to 0.7% and 304˚C to 444˚C respectively. Simba-1 well shows the highest Tmax range value compared to the other three wells. The highest Vitrinite reflectance value was obtained in Kubwa-1 well. The results suggest the possible presence of both immature and mature source rocks. Values between 0% to 0.5% Vitrinite reflectance and 300˚C to 430˚C Tmax correspond to immature source rocks. The oil window will be indicated by Vitrinite reflectance (0.6% - 1.3%) and Tmax (430˚C - 465˚C) while the gas zone is shown with values of above 1.3% Vitrinite reflectance and above 465˚C Tmax value. Kubwa-1 and Mbawa-1 Tmax values suggest a

Average source rock TOC values for four offshore wells
AgeKubwa-1Mbawa-1Pomboo-1Simba-1Average
Paleogene0.510.941.010.780.81
Late Cretaceous0.381.131.381.040.98
Early Cretaceous0.43
Average0.451.041.200.910.89
 Geochemical and Rock-Eval pyrolysis data parameters for Kubwa-1 well
Depth (m)FormationTmax (˚C)S1S2S3S1 + S2S2/S3PITOCHIOIRo
3330Miocene3960.261.012.41.270.40.200.71403330.5
3340Miocene3890.120.711.740.830.40.140.8922260.5
3770Paleocene3750.180.770.640.951.20.19181670.5
4000Paleocene3310.560.720.471.281.50.44176490.6
4020Paleocene0.510.540.411.051.30.490.959450.6
4300Maastrichtian0.440.590.371.031.60.430.873460.6
4350Maastrichtian4190.540.951.011.490.90.361.187930.7
4354Maastrichtian4370.130.740.330.872.20.151.166290.7
4400Maastrichtian4180.290.660.770.950.90.311.352610.7
4790Maastrichtian4280.170.680.350.851.90.200.888450.7

lack of a mature source rock or limited mature source rock whereas in Pomboo-1 and Simba-1 there is a likelihood of having a mature source rock given the Tmax values obtained.

In measuring the quality of the organic matter in the various formation samples within the study area, Kerogen typing was performed using TOC and Rock-Eval pyrolysis ( Figure A1) (Steiner et al., 2016) . Type III Kerogen was found to be the most dominant Kerogen type, and gas shows are the most frequent hydrocarbon encountered in the Lamu Basin ( Figure 3). The hydrogen index (HI) range for the studied wells is 52 to 140 mg HC/g TOC (Kubwa-1), 3 to 141 mg HC/g TOC (Mbawa-1), 244 to 608 mg HC/g TOC (Pomboo-1), and 4 to 274 mg HC/g TOC (Simba-1). HI values below 200 mg HC/g TOC suggest type III Kerogen which is gas-prone. Type II/III Kerogen (Oil/gas-prone) is suggested by the HI values between 200 mg HC/g TOC to 300 mg HC/g TOC. Oil-prone type II Kerogen is suggested by the HI values above 300 mg HC/g TOC. The oxygen index (OI) ranges from 21 mg HC/g TOC to 1241 mg HC/g TOC in the four wells. This negatively correlates with TOC (Arab et al., 2015) . The higher the value of the production index (PI), the better the source rock (Ratnayake et al., 2018) . The PI range in the four wells is from 0.1 to 0.93, the

Geochemical and rock-eval pyrolysis data parameters for Mbawa-1
Depth (m)FormationTmaxLecoRE(S1/TOC) *100S2/S3HIOIPIRo, %
TopBottom(˚C)TOCS1S2S3
15191520Lower Eocene−10.20.020.010.46100.052320.67
15201530Lower Eocene−10.30.010.010.4130.031360.50
15301550Lower Eocene3530.70.060.321.9490.2492980.16
15501580Upper Paleocene−10.40.020.040.4950.1101240.33
15801610Middle Paleocene−10.20.020.060.5790.1282630.25
16101640Middle Paleocene−11.20.010.040.5910.13510.20
16401670Lower Paleocene4220.80.020.040.5420.15680.33
16701700Upper Maastrichtian3340.60.010.030.5820.151010.25
17001730Upper Maastrichtian4220.70.020.070.4930.110700.22
17301760Lower Maastrichtian3590.80.040.080.4750.29550.33
17601790Lower Maastrichtian−10.60.030.050.4750.18760.38
17901820Upper Campanian3160.90.040.130.3640.414400.23
18201850Upper Campanian3640.70.100.110.67140.215910.48
18501880Upper Campanian3270.90.040.170.2750.620310.19
18801910Upper Campanian4281.10.050.260.5150.524470.16
19101940Upper Campanian4351.50.050.420.5230.828340.11
19401970Upper Campanian4261.50.060.450.540.930330.12
19702000Upper Campanian4311.50.050.440.3431.329230.10
20002006Upper Campanian4271.20.040.30.2531.225210.12
20062030Upper Campanian4261.00.050.330.3451.033340.14
20302060Upper Campanian4250.80.040.180.3650.522440.18
20602083Upper Campanian3610.30.020.070.3860.2201110.22
20832086Upper Campanian−10.30.040.070.48120.1221480.37
20862089Upper Campanian4290.80.100.330.7120.539830.23
20892092Upper Campanian3180.30.070.070.32210.221940.51
20922095Upper Campanian3040.40.060.160.22140.736500.27
20952098Upper Campanian−10.20.000.010.11−10.1661−1.00
20982101Upper Campanian3380.20.050.030.47300.1182810.63
21012104Upper Campanian3610.40.140.291.07370.3752780.33
21042107Upper Campanian4230.50.240.711.05490.71412090.26
21072110Upper Campanian3240.50.060.160.3110.531580.27
21102113Upper Campanian−10.30.060.050.33240.2201290.55
21132116Upper Campanian4220.20.040.070.57190.1322630.37
21162119Upper Campanian−10.30.040.040.62140.1142190.50
21192122Upper Campanian4230.30.060.130.72210.2472590.31
21222125Upper Campanian3660.40.090.150.74210.2351720.37
21252128Upper Campanian3460.40.060.120.76150.2301900.34
21282131Middle Campanian−10.20.100.040.75540.1224100.71
21312134Middle Campanian−10.10.060.040.56790.1537470.60
21342137Middle Campanian−10.10.020.010.41290.0145770.67
21372140Middle Campanian−10.00.020.010.36690.03412410.67
21402143Middle Campanian−10.10.010.010.26160.0164130.51
21432146Middle Campanian−10.30.020.020.4280.081670.51
21462149Middle Campanian−10.00.020.010.38490.0249270.67
21492152Middle Campanian−10.10.000.010.68−10.07493−1.00
21522155Lower Campanian3660.20.180.061.121110.1366750.75
21552158Lower Campanian−10.10.100.040.84990.0408480.71
21582161Lower Campanian3380.40.130.10.89370.1292540.56
21612164Lower Campanian4280.60.100.240.63180.4421090.30
21642167Lower Campanian4220.70.170.51.23250.4741820.25
21672173Lower Campanian4220.30.100.150.74400.2582870.41
21732179Lower Campanian3200.30.090.10.73300.1322350.48
21792185Lower Campanian−10.20.070.050.84320.1233780.59
21852191Lower Campanian4260.60.090.180.58160.3321040.33
21912197Lower Campanian3140.10.070.040.671000.1579570.64
21972203Lower Campanian3530.30.130.130.83430.2422690.50
22032227Upper Santonian−10.10.000.020.46−10.019434−1.00
22272260Upper Santonian−10.20.040.040.56230.1233160.50
22602290Middle Santonian4070.10.050.040.68350.1284760.56
22902323Lower Santonian−10.20.050.040.64310.1253980.56
23232353Lower Santonian−10.20.060.050.79310.1264090.54
23532383Upper Turonian−10.20.070.110.64400.2623640.39
23832413Middle Turonian3180.10.050.040.55410.1324440.56
24132443Middle Turonian3150.20.050.040.58330.1263790.56
24432475Middle Turonian4220.20.070.070.68420.1414000.51
24752505Middle Turonian3450.20.080.060.68330.1252820.57
25052535Lower Turonian−10.20.070.040.78330.1183580.64
25352553Lower Turonian−10.30.060.070.58200.1221840.47
25532580Lower Turonian−10.40.090.070.58210.1171370.56
25802610Lower Turonian−10.50.120.070.54250.1151130.63
26102640Upper Cenomanian−10.50.180.120.59370.2241180.61
26402670Upper Cenomanian−10.30.070.070.52280.1272020.50
26702700Middle Cenomanian−10.40.100.070.67260.1181710.59
27002730Middle Cenomanian−10.20.040.020.57250.0123410.67
27302760Middle Cenomanian−10.20.130.190.66640.3933240.41
27602790Middle Cenomanian−10.20.090.140.72520.2814190.39
27902820Middle Cenomanian4230.20.080.160.66440.2863570.34
28202850Middle Cenomanian3110.30.110.210.72420.3802740.34
28502880Upper Albian4220.30.090.131.03260.1382990.41
28802910Upper Albian3510.40.120.161.27270.1362860.43
29102940Upper Albian4130.30.120.240.95400.3803170.34
29402970Upper Albian−10.30.100.150.76310.2462310.41
29703000Upper Albian−10.20.110.160.72480.2703170.41
30003030Upper Albian3550.30.310.360.46950.81121430.46
30303060Upper Albian−10.20.130.150.68530.2622800.46
30603090Middle Albian−10.30.130.110.7450.2382410.54
30903120Middle Albian−10.20.100.110.67410.2452720.48
31203150Middle Albian−10.20.050.060.86290.1344940.45

smallest value obtained from Mbawa-1 well and the highest from Simba-1 well.

Petroleum system modeling was applied in evaluating geological conditions necessary for a successful charge. The three major stages involved in petroleum system modeling include the making model stage, the numerical simulation stage, and the calibration/inferences stage (Figure 5). Schlumberger’s Petrel 2017 software was used in petroleum system modeling.

Figure 6(a), Figure 7(a), and Figure 8(a) show the highest temperature (246.56˚C), transformation ratio (99.19%), and Vitrinite reflectance (3.0) in Kubwa-1 respectively. This is achieved at the Cretaceous (Maastrichtian) time at a depth of about 4500 m. The transformation ratio curve indicates both mature and immature source rocks where generation with/without expulsion has occurred in the cretaceous and no generation in the rest of the time. The Vitrinite reflectance curve indicates Overmature Cretaceous (Maastrichtian), gas generation in Paleocene, and oil window during the Miocene.

Geochemical and Rock-Eval pyrolysis data parameters for Pomboo-1
Depth (m)FormationTmax (˚C)S1S2S3S1 + S2S2/S3PITOCHIOIRo
2950Middle Eocene4411.473.932.915.41.350.270.82479356
3040Middle-Early Eocene4191.063.172.234.231.420.250.89356252
3140Middle-Early Eocene3672.393.472.165.861.610.410.94369230
3170Early Eocene3603.923.641.937.561.890.521.07340180
3270Late Paleocene4263.164.422.227.581.990.421.3340171
3340Late Maastrichtian4279.168.082.1617.243.740.532.02400107
3420Late Maastrichtian3883.872.761.766.631.570.581.13244156
3480Late Maastrichtian4285.294.881.6210.173.010.521.47332110
3530Late Maastrichtian4303.235.221.48.453.730.381.32395106
3650Late Maastrichtian4261.44.841.666.242.920.221.13428147
3790Late Maastrichtian4262.754.971.597.723.130.361.15432138
3830Late Maastrichtian4282.85.441.378.243.970.341.3418105
3900Early Maastrichtian4256.286.161.9512.443.160.51.88328104
3990Early Maastrichtian4294.657.021.8211.673.860.41.6439114
4040Early Maastrichtian4301.522.721.74.241.60.360.92296185
4140Early Maastrichtian4313.696.082.049.672.980.371.44422142
4190Early Maastrichtian4266.045.321.5911.363.350.531.533481040.58
4210Early Maastrichtian4291.984.441.66.422.780.311.23361130
4230Early Maastrichtian4285.586.781.9411.363.50.491.54375107
4270Early Maastrichtian4257.646.161.613.83.850.551.6936495
4300Early Maastrichtian4244.444.231.928.672.20.511.33318144
4320Early Maastrichtian4285.164.721.779.882.670.521.43330124
4390Early Maastrichtian4295.76.081.9511.783.120.481.643711190.6
4420Early Maastrichtian4304.97.222.1812.123.310.41.74415125
4430Early Maastrichtian4196.6251.8511.622.70.571.65303112
4470Early Maastrichtian4265.86.262.0512.063.050.481.66377123
4490Early Maastrichtian4241.314.041.955.352.070.240.994081970.61
4520Late Campanian42614.221.915.222.210.191.02414187
4540Late Campanian4221.724.281.862.380.290.84510214
4590Late Campanian4271.175.161.956.332.650.181.025061910.68
4610Late Campanian4331.216.322.646.532.390.191.045122140.62

Figure 6(b) shows the highest temperature of 109.81˚C achieved between the bases Campanian and base Paleocene at a depth of between 1800 m and 2300 m for the Mbawa-1 well. The maximum transformation ratio value in Figure 7(b) is 47.94% which signifies a possible oil generation at the base Campanian but without an expulsion. Figure 8(b) is the Vitrinite reflectance curve with a reading of 0.7 implying an early oil window at the base Paleocene and base Campanian.

Figure 6(c), Figure 7(c), and Figure 8(c) show 158.13˚C as the highest temperature achieved during the base Campanian at a depth of over 2600 m, more than 50% transformation ratio at a depth of between 2500 m to 4000 m, and Vitrinite reflectance value of between 0.5% and more than 2.0% for Pomboo-1 well respectively. The Vitrinite reflectance curve suggests a possible gas generation window during the base Campanian and an oil window between the base Eocene and the base Campanian.

Figure 6(d), Figure 7(d), and Figure 8(d) are the standard interpretation scales for temperature, transformation ratio, and Vitrinite reflectance respectively. The temperature scale shows diagenesis happening below 50˚C whereby only biogenic gas may be generated. The hydrocarbon is said to be immature since this corresponds to a Tmax value below 430˚C. Catagenesis follows at a temperature between 50˚C - 200˚C corresponding to Tmax (430˚C - 550˚C)

showing oil and wet gas. Beyond 200˚C temperature (Tmax > 550˚C) metagenesis sets in showing dry gas. The transformation scale indicates three levels: less than 10% value signifying immature source rock which has not been generated yet, between 10% to 50% the oil generation without expulsion level, and more than 50% value being the oil generation and expulsion level. The Vitrinite reflectance scale shows the immature window (0.2% - 0.5%), early oil window (0.5% - 0.7%), peak oil window (0.7% - 1.0%), late oil window (1.0% - 1.3%), gas generation window (1.3% - 2.0%), and Overmature window (>2.0%).

Figure 9 and Figure 10 are the petroleum system quick-look upper cretaceous surface maps showing the spatial distribution of temperature and Vitrinite reflectance. The maps indicate the region that is favorable for source maturation and maturity status. The region toward the coastline shows higher temperatures compared to regions towards the deep offshore. Since temperature is a factor in source rock maturation, the vitrine reflectance is equally higher near the coastline than the rest of the other regions, especially towards deep offshore. Towards the coastline, there is the early oil window to the Overmature window, whereas towards deep offshore there is the majorly immature window. These results may explain why Pomboo-1, Kubwa-1, and Simba-1 wells were dry, although the Mbawa-1 well had gas shows in the upper cretaceous sandstones.

5. Conclusion

The shallow Lamu offshore source rock quantity, quality, and maturity have been estimated through the determination of the TOC average values, Kerogen typing, and Rock-Eval pyrolysis measurements respectively. The results postulate the absence of a definitive effective source rock with a likelihood of having cases of potential and possible source rocks. The average TOC of 0.89 wt % in the study area suggests a fair organic richness which seems higher in the late cretaceous (0.98 wt %) than in the Paleocene (0.81 wt %). Vitrinite reflectance and Tmax values in the study area indicate the possible presence of both mature and immature source rocks. For instance, the result implies that Mbawa-1 formation may have not reached the required levels of maturity to begin generating despite the non-commercial gas shown in the upper cretaceous. Type III Kerogen was the most dominant Kerogen type, and gas shows are the most frequent hydrocarbon encountered in the Lamu Basin with a few cases registering type II/III and type II. The charge properties (i.e. Temperature, transformation ratio, and Vitrinite reflectance) over geologic time at each of the three wells have been estimated and their spatial variation mapped as seen from the burial history and depth curves overlaid with temperature, transformation ratio, and Vitrinite reflectance respectively. From the upper cretaceous maturity maps, the results seem to favor near coastal regions where average TOC is about 1.4 wt %, Vitrinite reflectance is more than 0.5%, transformation ratio is more than 10%, and temperatures range from 80˚C to 160˚C. However, greater uncertainty rests on the source rock’s presence and viability tending toward the deep offshore. Geochemical analysis and petroleum system modeling for hydrocarbon source rock evaluation improved the understanding of the occurrence of the possible and potential source rocks and processes necessary for hydrocarbon generation.

Acknowledgements

Special thanks to the National Oil Corporation of Kenya (NOCK) for providing the necessary data and allowing me to access the required software in their workstations.

Conflicts of Interest

The authors declare no conflicts of interest regarding the publication of this paper.

Cite this paper

Ombati, D., John, G., & K’Orowe, M. (2023). Evaluation of Source Rock Potential for Hydrocarbon Generation in Shallow Offshore, Lamu Basin, Kenya. Journal of Geoscience and Environment Protection, 11, 60-85. https://doi.org/10.4236/gep.2023.115004

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