©2015 Pearl Research Journals

Hydrocarbon Prospects under Lake Turkana Basin, NW-Kenya: Based on Geophysical and Geochemical Data

Investigations

Bernard Kipsang Rop

Accepted 8 August,2015

Department of Mining, Materials and Petroleum Engineering, JKUAT, P.O. Box 62000-00200, Nairobi, Kenya. E-mail: drropben@gmail.com.

ABSTRACT This study attempts to unravel subsurface structural features and further creates a better understanding of sedimentary rock sequences, believed to belong to Cretaceous-Tertiary age, which have been deposited under the vast Lake Turkana Basin (NW Kenya). The gravity anomaly maps and seismic profiles revealed the presence of several horst- and graben-like structural systems. It was also revealed that the basin could have attracted potential petroliferous sedimentary piles (? 2000 to 5200 m thick) which are deposited on basement rocks of Precambrian age. The stupendous outpouring of the lava flows has hidden under them a large terrain of older rocks comprising the Precambrian basement rocks and sediments filling the asymmetric rift basins. Thus direct observations on the possible Mesozoic and Tertiary sedimentary sequences are not possible, apart from few drilled Wells to the southwest and southeast of Lake Turkana basin (LT-1, LT-2 and C1, C2, C3, respectively). Some selective geochemical analysis of rock samples in Loperot-1 Well (denoted as LT-1 Well) for their total organic carbon (TOC) and other sedimentological parameters were useful in this research work. Understanding the subsurface structures and depositional environments conducive for hydrocarbon generation and trapping is essential as it forms the basis for exploration. The organic matter richness, facies type and degree of thermal alteration and/or maturation are factors useful in evaluating the potential source rocks. Rock-Eval pyrolysis was employed on selected rock samples with high TOC for quantification of data, and this would help in precise identification of phases of hydrocarbon generation.

Key words: Lake Turkana, Lokichar, Chalbi, sedimentary, hydrocarbon, petroliferous, basement, gravity, seismic and source rocks.

INTRODUCTION Lake Turkana Basin lies between longitudes 35

o45‟E and

36 o

48‟E and latitudes 2o25‟N and 4

o38‟N. The basin was

initiated as an asymmetric graben bounded by the N-S fault systems during the Tertiary time. At the centre of the basin lies Lake Turkana (formerly Lake Rudolf), one of the largest lakes in the eastern arm of the East African Rift system (Figure 1). The Lake Turkana Basin forms a north-south broad depressional Horst-graben feature with an alkaline lake water. It is bounded both to the east and to the west by the north-south trending fault systems of the Kenya Rift (Tertiary). These fault systems are the result of the rifting mechanism, which began in Late Oligocene to Early Miocene time and later gradually progressed eastwards with time to trend NNE-SSW (Barker et al., 1972; Rop, 2002, 2013; Wescott et al., 1993). Many of these major basinal faults have been

active and have also affected the Upper Oligocene-Lower Miocene to Pliocene volcanics, forming the highlands on both the eastern and western side of the Basin (Figure 2).

GEOLOGICAL SETTING

The geology of Lake Turkana Basin consists of the Precambrian basement rocks and the Tertiary volcanics that have covered subsurface sedimentary deposits, which are now considered to be a potential petroliferous block in Northern Kenya (Rop, 2003). The basin is known to have evolved through extension tectonics that brought out continental rifting as a part of the major Gondwanaland breakup in the Late Paleozoic time and continued in the Mesozoic and Tertiary (Figure 2). The

Research Journal of Engineering and Technology Vol. 1 (2), pp. 41-56, August, 2015 Research Paper http://pearlresearchjournals.org/journals/rjet/index.html

Rop 42

Figure 1. General Geological map showing present study area.

Figure 2. Physiographical and Geological map of the study area showing major fault system.

region underwent uplift and subsidence, intermittently, along major boundary faults even in the Miocene period. These movements were accompanied by the stupendous outpouring of the lava flows. The Mounts Kulal-Porr-Moiti and Loriu-Lothidok-Murua Rith volcanoes (Figure 2), which erupted during the Quaternary, form the eastern and western shoulders of the Lake Turkana basin, respectively. The Chalbi basin (Cretaceous), which forms a part of the Great North Anza Rift, is located some 40 km to the east of Lake Turkana. It is assumed that the Anza Graben discontinuously extends northwestwards across (under) the Lake Turkana and Lotikipi basins (Figure 3) into the Abu Gabra Rift of southern Sudan,

where oil discovery has been made (Schull, 1988). The basin and its sub-basins continued as sites of deposition and extension also during the Late Tertiary and even in Quaternary period. Sedimentary rock sequences belonging to (?) Cretaceous-Tertiary age may have been deposited under the vast and little known Lake Turkana Basin (Rop, 2003, 2013). PHYSIOGRAPHY OF LAKE TURKANA BASIN The physiographical features such as the basement ranges and inliers, Tertiary volcanic plateaus, Lake

Res. J. Eng. Technol. 43

Figure 3. Map Showing Drilled Wells in Northwestern Kenya Rifts Basins.

Turkana and lowlands with alluvial plains as well as drainage systems are present in the study area (Figure 2). The entire area is volcanically and seismically active, even throughout the Quaternary period, shown by the thick alluvial cover concealing the entire eroded surface of the older sedimentary sequences as well as the basement rocks (Johnston et al., 1987;Barker et al., 1972; Rop, 2002, 2013). The landscape consisting of flat alluvial plains and high plateaus and ranges intervening them indicates the control of block faulting. The drainage follows most recent strikes of faulting, north-south direction, but the tilts are asymmetric giving rise to rivers flowing in opposite directions. Lake Turkana, Alluvial Plains and Drainage Systems The Lake Turkana is the largest lake in the eastern arm of the East African Rift Valley. It is a tectonically controlled lake occurring centrally in the present study area. About 240 km long and 50 km wide, it has a maximum depth of 120 m (Johnson et al., 1987). The water level in the lake fluctuates with the variations in rainfall and the evaporation rates. The lake is fed by the Omo River (draining the Ethiopian highlands) in the north and the perennial Turkwell-Kerio river systems draining the western part of the present study area (Figure 2). These rivers, which predominantly flow southwards and northwards into the lake trace the north-south-trending major faults. The environment being very hot and arid, the lake has neither a surface outlet nor a subsurface drainage. The water is alkaline (pH 9.2), moderately saline, with total dissolved solids of about 2500 parts per million (Yuretich, 1986). The Lake Turkana is supposed

to have developed tectonically during the Early Miocene-Pliocene time, with major rifting of Pliocene age forming the north-south trending marginal faults on the northwestern and central parts of the lake (Ochieng et al., 1988; Wilkinson, 1988). It is bounded by the major N-S trending normal faults and the Kenyan and Ethiopian domes abutting against the northern end of the Gregory Rift Valley of Kenya, the entire depression between these two domes is rift-related; the rifting strongly influenced also the sedimentation history within this region. The Lake Turkana itself is said to be a part of the half-graben structure with intermittent structural highs, deepening progressively to the north because of tectonic subsidence (Johnson et al., 1987). Dunkelman (1986) suggested that the Lake Turkana is intersected obliquely also by some pre-rift structures of the North Anza Basin, which is a NW-SE striking basin filled with Cretaceous sediments, predicted to be 2500 m to 4000 m thick. The flat lowlands around the lake (for example, Koobi Fora to the northwest) contain Quaternary sediments of Plio-Pleistocene age (Brown and Feibel, 1986; Wilkinson, 1988; Ochieng et al., 1988). These areas are distinctly transected by the east-west flowing small rivulets. These rivers do not follow the main north-south drainage trend of this physiographic region. The low-lying alluvial areas with Plio-Pleistocene sediments occur intermittently amongst the Tertiary volcanic plateaus and the basement ranges. The rivers flowing through these lowlands have sudden major bends that are also tectonically controlled. The regional rifting and faulting systems have imposed restraint upon the courses of the rivers. The lowlands are more dominantly seen along sections drawn at 3

oN and

3o30‟N latitudes (Figure 2). Further south at 2

o30‟N

section line there are no mounts of very high altitudes like Mount Kulal.

The terrain is low but highly undulatory. On the whole, the steep escarpments are seen along the northernmost section and on both sides of Mount Kulal along the section at 3

oN latitude. The Turkwell and Kerio rivers,

draining the predominantly metamorphosed basement source area, subsequently converge and form a delta on the central southwestern shores of Lake Turkana. The Precambrian basement rocks are sparsely exposed as inliers and ranges, particularly at the Lapurr Ranges to the northwest, Kajong-Porr area to the southeast and at the north Loriu Plateau to the southwestern shores of Lake Turkana (Figure 2). These basement rocks are probably extension of the Precambrian rocks of Samburu gneissic groups to the south of the lake (Key et al., 1987). The Lapurr Range Sedimentary Sequences The basement rocks in the Lapurr Ranges (the „type‟ section for the surface geology in the present study) are seen to be unconformably overlain by sediments initially termed “Turkana Grits” by earlier workers. This term denotes a generally coarse-grained siliciclastic sediments between the basement and the Tertiary volanics. Thesesedimentary sequences have yielded wood and dinosaurian fossil remains (Savage and Williamson, 1986; McJGuire and Serra, 1985) in the Lapurr Ranges, to the immediate northwest of the Lake Turkana (Figure 2). These have been described as continental fluvial-lacustrine and fluvial-deltaic deposits (up to 600 m thick) consisting of fine- to coarse-grained sandstones, pebble- to cobble-conglomerates and siltstones or shales interbedded between the sandstones and conglomerates. They have been designated as the Lapurr Range Formation (Rop, 2003, 2013).

The sediments to the east of Lake Turkana Basin (around Kajong-Porr area) have been described as admixtures of both siliciclastic and volcaniclastic strata termed as Sera Iltomia and Kajong Formations, respectively (Savage and Williams, 1986; Rop, 1990, 2013; Wescott et al., 1993). The siliciclastic Sera Iltomia sediments are believed to be of Upper Cretaceous (?) to Miocene in age, while the Kajong sediments and volcanics are of Miocene age. The voluminous basalts (Upper Oligocene-Miocene to Pliocene) overlie the Lapurr Range and the Kajong-Porr sediments and, in turn, are overlain by the post-volcanic sediments of Plio-Pleistocene to Holocene age, particularly in the horst-graben like Koobi Fora sub-basin to the northwest of Lake Turkana Basin. The depositional environments within the margins of Lake Turkana basin provided suitable life conditions for a prolific vertebrate fauna during the Tertiary and Quaternary times resulting in high potential for preservation in the hominids fossil records (Brown and Feibel, 1986; Harris et. al., 1988).

Rop 44 SUBSURFACE STRUCTURES AND TECTONICS UNDER LAKE TURKANA The Lake Turkana Basin lies along the Kenya Rif Valley, which forms the eastern arm of the East African Rift system (Figure 1). The rifting period in the Turkana basin occurred between the Late Mesozoic to Early Tertiary during which the sub-basins that formed extended in the north-south directions; the rifting being mostly in the east-west direction. During this rifting, there was stupendous outpouring of basaltic lavas which extensively covered the entire northern Kenya (Figure 3). These lavas have hidden under them a large terrain of older rocks comprising the Precambrian basement rocks and sediments filled in the rift basins (Rop, 2002; 2003). Thus direct observations on the possible Mesozoic and Tertiary sedimentary sequences are not possible apart from few drilled wells (Figure 3) to the southwest and southeast of Lake Turkana basin (LT-1, LT-2 and C1, C2, C3, respectively). The Lake Turkana basin forms a part of the Early Oligocene-Miocene rifting. The Chalbi basin to the east of Lake Turkana and the Lotikipi basin to the west of the lake are not a part of this Tertiary rifting. They belong to the Late Paleozoic rifting (Key et al., 1989; Winn et al., 1993) and are supposed to extend subsurface in the NW direction towards Sudan, where oil discoveries have been reported (Schull, 1988). The study of intracontinental rifting and its associated subsurface structural features caused by extensional tectonic stresses is critical for effective hydrocarbon exploration province (Rop, 2013; Harding, 1984). It is proposed therefore to examine in this paper the tectonic structure of the Lake Turkana subsurface basin in the light of basement depth contours and gravity anomalies from BEICIP, 1987 regional structural contour maps (Figures 4 and 5). The gravity anomaly maps and seismic profiles were most useful for the interpretations of subsurface structural features, thus unravelling the depositional province of the (? 2000 to 5200 m thick) sedimentary rock sequences, believed to belong to (?) Cretaceous-Tertiary age, which have been deposited in the vast Lake Turkana. The gravity values both to the east and west of Lake Turkana basin are mainly positive, to the order of 20 to 40 mgals (Figure 4). Over the Koobi Fora and Moiti areas, to the east of the basin, the gravity are positive (+40 and +20 mgals, respectively). Some negative gravity anomalies are seen in areas around the North Island (-90 mgal) within the lake, Eliye Springs (-70 mgal) to the southwest of the lake, and South Island (-70 mgal) within the south part of the lake. Gravity Cross-Section along 4

oN Latitude

The strike of the Bouguer gravity anomaly contours is mostly north-south. A cross-section along latitude 4

oN

(Figures 2, 4 and 6) through Lake Turkana basin reveals

Res. J. Eng. Technol. 45

Figure 4. Bouguer gravity contour map over the Lake Turkana basin (Adopted from BEICIP-Ministry of Energy Geological Map, 1987).

Figure 5. Basement contour map showing basement depths in Lake Turkana (Adopted from BEICIP-Ministry of Energy Geological Map, 1987).

a couple of sharp anomaly variations, which indicate subsurface features such as the thickness of sediments, basement depth, and direction of shallowing and deepening (Rop, 2002, 2003). To the east of longitude

35o30‟E the gravity anomalies become steeply negative

(ranging from -60 to -90 mgal). This is the area extending from the western margins of the N-S trending Murua Rith–Lokitaung volcanic Hills (point X) towards east up to

Fig. 4: Bouguer gravity contour map over the Lake Turkana basin (Adopted from BEICIP-

Ministry of Energy Geological Map, 1987)

E T H I O P I A

Map, 1987)

Fig. 5: Basement contour map showing basement depths in Lake Turkana (Adopted from BEICIP-Ministry of

Energy Geological Map, 1987)

E T H I O P I A

Rop 46

Figure 7. W-E Section of Bouguer Gravity and Basement Depth Values profile along Latitude 3

o30‟N. Between Longitudes 31

o15‟E and 37

o30‟E through Lake

Turkana north Chalbi Basin.

the immediate southwest of the North Island (point R). From point R eastwards the gravity anomalies become only gently positive from -90 to -80 mgal up to point T. The anomalies show a jump and become positive (-75 mgal to +75 mgal), representing horst structure covered by volcanic under point U on the section. From the basement depth contour map (Figures 5 and 6), the basement is also seen to be deepening (from -1 km to -4 km) towards the centre of the lake, west of North Island. This deepening is seen to have been accomplished in two stages. From point X the basement rises from -2 km to -1 km up to point P and then steeply deepens to -2 km at point Q. The basement deepens further eastwards, first gently up to point R and then steeply to -4.2 km at point S. From point S the basement also steeply rises first from -4.2 km to -3 km at point T and then gently to about -2 km at point U. From the above variations in the basement depth and the steep negativity of the gravity anomalies, one can conclude that (1) the area has undergone vertical active tectonic and (2) the upper mantle in this region has steeply down warped. There are a series of faults, some of them are deep and have affected the basement also. The sense of movement between point P and point S is that of a down throw. It can thus be concluded that the basin here represents a graben structure bounded by faults underneath points X and U. Other intrabasinal faults underneath points P, Q. R and S can also be marked. The magnitude of the deepening, west of the North Island, is far less than towards the east. The region to the east of the shoulders of the basin beyond point U represents an up thrown horst structure, while the Turkana Basin itself seems to be half-graben. The basement contours (Figure 5) also indicate a deeper half-graben structure towards the north western edge of

the lake (depth contours increasing from -3 km to -5 km). It implies that the sediment fill progressively deepens not only eastwards under points R and S but also northwards. The gravity picture of the Lake Turkana basin is in sharp contrast with that towards the immediate eastern and western region. In the Lotikipi plains to the west, the gravity anomalies showed hardly any variations along this latitude, while to the east under the Koobi Fora region, highly positive anomalies are seen. Thus the faults in the Turkana basin seem to be even mantle-reaching, bringing about a down warp of the mantle. In comparison, the mantle has been up warped under the Lotikipi plains and has been sharply thrown upwards under the Koobi Fora area. Between points X and P, faulting has up thrown the basement but has affected the mantle also. Gravity Cross-Section along 3

o30’N Latitude

The cross-section along latitude 3

o30‟N (Figures 2, 4 and

7) through the central part of the Lake Turkana Basin, at the Central Island area (long. 36

o05‟E) reveals, more or

less, similar subsurface features as those to the north (cross-section 4

oN latitude). The positive gravity

anomalies (+50 to +70 mgals) between longs. 35o40‟E

and 35o45‟E over the Lothidok volcanic hills (points C and

O) mark the western margin of the basin. From point O eastwards the anomaly suddenly dips to -75 mgal at point E. Further eastwards the negativity varies gently towards the central part of the lake up to longitude 36

oE (-85

mgal) at point F, which is to the immediate west of the Central Island. It becomes gently positive from point F to point G (-85 to -75 mgal), where it suddenly (point H) becomes highly positive (from -70 to +70 mgal) in the

Res. J. Eng. Technol. 47

Figure 8. W-E Section of Bouguer Gravity and Basement Depth Values profile along Latitude 3

o00‟N. Between Longitudes 35

o25.5‟E and 37

o30‟E through Lokichar/Kerio,

Lake Turkana and Chalbi Basins.

Moiti area forming the eastern margin of the basin (Figure 4). From the basement depth contours map (Figures 5 and 7), the basement is also seen to be gently deepening (from -1.5 km to -4 km) from the western margin (point C) of the basin to the eastern margin (point H). It is seen that the basement deepens nearer the eastern margin of the basin from -1 km to -4 km (points C and H). From the above it can be concluded that the basin is bounded by faults that have affected the basement, and have even down warped the upper mantle also. One can also demarcate a series of faults striking north-south. Among these, the faults under point C and point H form the western and eastern margin, respectively. Within these two major marginal faults lie intra-basinal faults under points O, E, F and G. The western margin faults (under points O, E and F) gently dip eastwards while the eastern margin faults (under points G, H and I) steeply dip westwards. Both marginal and intra-basinal faults have subsequently contributed to the formation of half-graben structure at the centre of the basin. From the basement depth contours map (Figures 5 and 7) a half-graben structure can be interpreted, which is deeper to the immediate east of the Central Island (-4 km). The graben structure strikes in the N-S direction and appears to deepen towards the north. Similar to the earlier section the magnitude of deepening, east of the Central Island, is far more than towards the west. The regions both to the western and eastern shoulders of the basin beyond points O and H represent horst structures while the Lake Turkana Basin is a half-graben.

Gravity Cross-Section along 3oN Latitude

The cross-section along latitude 3oN (Figures 2, 4 and 8)

cuts across the two subsurface basins: North Kerio and

Turkana basins. The North Kerio basin joins the Lake Turkana basin at around longitude 36

oE and extends

southwards. The section reveals an N-S striking Bouguer anomaly contours and similar subsurface features as those of the latitude 3

o30‟N cross-section. To the

immediate east of longitude 36oE (Figure 4) the gravity

anomaly dips at the Lokichar River from a low of -70 mgal to -80 mgal toward east, forming the western margin of the Turkana basin (points C/B to point J in Figure 8). The gravity anomaly then becomes gently positive eastwards (from -80 mgal to -75 mgal) up to point K then suddenly varies steeply to become positive (-75 to +75 mgal) under points M and A on the section. From point A to point E, which is the eastern margin of the basin, the positive gravity anomalies gently decrease from +75 mgal to +45 mgal. From the basement depth contours map (Figure 5) and Figure 8, the basement is also seen to be gently deepening from -1.8 km at point H, at the eastern margin of the Lokichar basin towards the east up to point K (-3.2 km)) and gently rises to -2 km at point L. From point L it takes another gently dip through point M (-2 km) to point N (-2.2 km) where it suddenly becomes steep and positive up to point B (+0.5 km) on longitude 36

o30‟E; in

the Kajong/Porr area, forming the south eastern shore of the Lake Turkana Basin (Figures 2 and 4). The rifting and faulting in this area has been active in the Tertiary up to Quaternary time thus controlling also the river drainage system in this part of the basin. Comparing the sections across latitudes 4

oN and 3

o30‟N, it can be

concluded that the basemen depth shallows towards the south and deepens northwards (Figures 5, 6 and 7). It can be said that the sedimentary sequence in the Lake Turkana basin becomes thicker from south to north. The region to the west of the shoulders of the lake (point H) represents another graben structure (Lokichar/Kerio sub-

Rop 48

Figure 9. W-E Section of Bouguer Gravity anomaly values profile along Latitude 2

o30‟N.

Between Longitudes 35o30‟E and 37

o00‟E through Lokichar-Kerio, and Lake Turkana Basins.

basins) while that to the east of the fault under point N represents a horst (Kajong/Porr area). The Lake Turkana Basin itself is a half-graben. Gravity Cross-Section along 2

o30’N Latitude

The cross-section along latitude 2

o30‟N (Figure 9), further

to the south resembles those drawn on the northern latitudes (Figure 2, 6 and 8). Both the Bouguer gravity anomalies and the basement depth dip eastwards from point A to point E. East of point E both the basement and gravity anomalies gently rise; the basement rises from -2.2 km to the surface at the southern margin of Mount Kulal (Figure 2) and the gravity anomaly rises from -80 mgal to -65 mgal. At the eastern margin of the basin the gravity anomaly rises to +65 mgal (point M). It can be concluded that the basin represents a simple graben bounded by faults at points A and M. Some intra-basinal faults can also be interpreted between points H and C. The central part of this graben is the deepest region but the basement depth is the shallowest when compared to sections along the northern latitudes. It seems the Lake Turkana deepens from south towards the north. The faults interpreted have certainly affected the sediments, basement and perhaps also the upper mantle.

On both the eastern and western sides of this basin, horst structures can be interpreted on which the surface outcrops of basaltic flows are located. This study of the intracontinental Lake Turkana rifting and its associated subsurface structural features caused by extensional tectonic stresses is critical for effective probable petroleum prospective target areas (Figure 10) identified from the gravity profiles of the cross sections above. The Turkana basin revealed the presence of several horst- and graben-like structural systems. It was also revealed that the basin could have attracted potential petroliferous sedimentary piles (? 2000 to 5200 m thick) which are deposited on basement rocks of Precambrian age and later covered by Tertiary/Quaternary volcanics. Concluding Remarks on the Cross-sections From the above four cross-sections, it can be concluded that the entire Lake Turkana subsurface basin is bounded by N-S striking faults and the thickness of the sediments seems to be maximum to the north and less to the south, since the basin seems to be deepening northwards. The nature of the subsurface basin is like half-graben, which deepens and becomes more complex from south to north. There seems to be variations in the depth of the

side by a major fault and on the other side by a set of faults. The major faults define

the boundaries with either a horst of basement rocks without volcanic cover or with a huge

volcanic cover. The asymmetric rifts or half-grabens are intracontinental and the gravity

profiles reveal that they characteristically occur over the crests of regional arches of the

basement and the mantle, or, only on the continental crust with a trough-like mantle profile.

Fig. 9: W-E Section of Bouguer Gravity anomaly values profile along Latitude 2o30’N.

Between Longitudes 35o30’E and 37o00’E through Lokichar-Kerio, and Lake Turkana Basins

Res. J. Eng. Technol. 49

Figure 10. Map showing probable petroleum prospective areas (shaded black) in the Lake Turkana rift- related asymmetric and half-graben sub-basins.

basement in this part of the basin from lats. 2

o30‟N to

4o30‟N. It can be seen that between lat. 2

o30‟N and 3

oN

the basement shallows and is exposed to the surface. This is a horst-like structure which seems to be controlled by E-W faults. Beyond latitude 3

o30‟N, the basement

deepens suddenly as has been interpreted earlier; it becomes deepest between latitudes 4

oN to 4

o15‟N. The

subsurface structure between latitudes 2o50‟N to 3

o45‟N,

based on gravity profiles and basement depth, showed that the basin also deepens towards the east; deepest towards the north between latitudes 3

o30‟N to 4

o30‟N.

Thus the subsurface structure is therefore very

complicated, characterised by irregular downthrows and up throws related first to the E-W faulting and later to the N-S faulting in the basin. The gravity profiles of the Lake Turkana Basin present terrain have indicated that within the basin are sub-basins, which are asymmetric half-grabens bounded only on one side by a major fault and on the other side by a set of faults. The major faults define the boundaries with either a horst of basement rocks without volcanic cover or with a huge volcanic cover. The asymmetric rifts or half-grabens are intra continental and the gravity profiles reveal that they characteristically occur over the crests of

Rop 50

Figure 11. Laboratory rock pyrolysis showing effect of heating an organic-rich

sample at 1098 m of LT-1 Well (Tmax 435.3oC).

regional arches of the basement and the mantle, or, only on the continental crust with a trough-like mantle profile. METHODOLOGY Selection of Samples for TOC Analysis Total organic carbon (TOC) is a measure of carbon present in a rock (not pecent) in the form of kerogen and bitumen. The Loperot-1 well (LT–1), drilled in Lokichar basin, penetrated a total depth of 2960 m. The lithology established through drill core samples showed no substantial presence of carbonaceous strata beyond 2000 m depths. Rock samples selected from 800 to 1800 m depths, showing some indications of the presence of organic matter, were analyzed using Rock-Eval technique. The section between 800 and 1800 m depths was selected because of the reported oil indications and abundance of rocks with high gamma ray values. The aim was to measure the total amount of organic carbon (TOC) and identify the possible source rocks. Methodology of TOC Analysis The rock samples (about 1 gram) are first treated with hydrochloric acid - HCL (20% v/v) to remove inorganic

carbonates. The remaining acid is drained using a vacuum pump. The sample is washed with distilled water and dried in the oven at a constant temperature of about 40

oC. The difference in weight before and after HCl

treatment or reaction is recorded. Once the system is started, it is left to run for one hour and calibrated for TOC/CO2. The dried sample is then analyzed in a carbon determinator (IR–212) with an induction furnace and a control console or computer. Oxygen gas (for burning the sample) and nitrogen gas (for pneutomatics-lifting of pedestal) are pressure-controlled at 35 pounds per square inch (psi). The combustion chamber pressure is also set between 11 and 12 psi. The CO2 produced is passed through a carbon IR cell and its volume is recorded. The machine automatically records the corresponding TOC weight percent. Generally, TOC in shales, especially black shales, always exceed five times that from carbonates or other beds of sediments (Selly, 1985). The organic matter in carbonates has more potential to generate hydrocarbons than those in shales. In the present case the LT–1 well does not show presence of carbonates. The lithology is mostly clastics dominated by sandstones with shaley horizons. Rock-Eval Pyrolysis of LT–1 Samples The selected samples are first treated with organic

solvents (Chloroform, Dichloromethane, Menthol Acetone, etc) to remove bitumen. Bitumen content TOC also represents the oil content that can be dissolved from a rock. Subsequently, they are subjected to pyrolysis (Rock-Eval) after drying. The tried sample (~100 mg) is put inside a flame ionization detector (FID) and is heated in a stream of helium at relatively low temperature (up to 300

oC) for the first five minutes, in order to remove free or

absorbed hydrocarbons (bitumen) that were present in the rock sample before pyrolysis (Figure 11). The analysis records two peaks, representing the volumes of two components of the organic matter (the volumes being proportional to the areas below the peaks). The expelled hydrocarbons, which usually volatilize below 300

oC are

represented by S1, which provides a measure of already generated hydrocarbons bitumen (North, 1985; Barker, 1999; Tissot and Welte, 19844). There are not many samples, which give higher S1 values. Most of the samples showed S2 values only up to 20 kg/g and low S1 values (<0.3). The low S1 values show the paucity of hydrocarbons (bitumen) generated below 300

oC. S2

values >10 kg/g are supposed to be more potential for hydrocarbons (kerogen) generation. On further heating the sample at the rate of 25

oC per

minute up to 600oC, the main pyrolytic thermal

breakdown of kerogen occurs, and is represented by peak S2 (Figure 11). The measure of the S2 area, produced at higher temperatures (550–600

oC), decides

the actual potential for generation of hydrocarbons by the sample (Rop, 2003). The area S2 is a measure of the remaining hydrocarbon generating ability of the organic matter. Oxygen bearing volatile compounds (CO2 and H2O) are usually passed to a separate (thermal conductivity) detector, which produces S3 response. However, this procedure was not done in the case of LT–1 Well sample. The two areas of S1 and S2 are used to determine the maturation level of kerogen in the source rock. They are expressed in milligrams per gram of original rock (mg/g), or kilograms per tonne (kg/ton). Rocks with S1 + S2 values < 2 kg/ton are not considered potential source rocks for hydrocarbon generation. Between 2 and 5 kg/ton a significant amount of petroleum may be generated but it would be too small to result in expulsion (Rop, 2013). Source rocks with S1 + S2 values between 5 and 10 kg/ton have the potential to expel some portion of the generated oil. Only source rocks with values >10 kg/ton are considered rich for sufficient oil expulsion (Allen and Allen, 1990). Thus, these rocks had the potential of oil generation as well as expulsion. The actual oil and gas generation can take place only when the threshold temperature (60

oC) is reached. It also

depends on the maturity level of kerogen, given by the temperature maximum (Tmax). The Tmax at which the S2 generation peak occurs is also recorded in degree Celsius and is an indicator of source maturity (a function of the degree of maturation). Perhaps the temperature did not reach the threshold of 60

oC considering the depth

Res. J. Eng. Technol. 51 range of these samples. Or whatever hydrocarbon that was generated has been expelled and/or migrated. For expulsion to occur the source rocks must get saturated first, a condition which is reached only on maturity of kerogen and temperature. RESULTS AND DISCUSSION Some evaluation of the Eliye Springs-1 and Loperot-1 Wells (denoted as LT-1 and LT-2 Wells, respectively) drilled in the southwestern part of Lake Turkana (Figure 3) in terms of lithology, comprised mainly sand-shale sequence with some volcanic intercalations which have been interpreted. The section of LT-2 Well from 2900 m up to the total depth (2964 m) apparently contains mainly shales of lacustrine origin and volcanics; possibly related to extensional episodes. The sands comprised poorly to well sorted, sub-angular to rounded, very fine to coarse quartz grains with some feldspars (8 to 20%). The wire logs from this well (LT-2) which were of reasonable quality were helpful in this study. Porosities were derived from the sonic log but the density logs were not easily available for this study. Whereas two potential reservoir intervals were identified in the Loperot-1 (LT-2) Well which comprised the oil sandstones of Lower/Middle Miocene and the main reservoir sandstones of Oligocene/Lower Miocene age, from which high TOC were geochemically analyzed in the section above. The deltaic and fluvial-lacustrine sedimentation in these intracratonic rift basins was controlled by intrabasinal and marginal faults, some of them reaching also the basement (Figure 12). The source rocks of well LT-1 identified above belonged to Oligocene to Lower Miocene age. These source rocks range from depths 800 to 1797 m. However, the interval section which proved to have effective source rocks with sufficient organic matter (OM) that could generate potential oil and gas, is considered to be at depths 1650 to 1800 m (considering the normal temperatures gradients). The stratigraphic column is shown in Figure 12. The porosity at shallow depths (800 to 1760 m) is high (12 to 40%) but decreases with depth (5 to 10%) at 1760 to 1800 m. No wells have so far been drilled in the North Lokichar and South Kerio basins. Future drilling in the deeper parts of both the Lokichar and Kerio-Turkana basins could indicate potential areas for hydrocarbons (presuming that the source rocks could have reached the natural temperatures gradient in these parts). The thickness of different lithologies (Figure 12) according to age and time is seen distinctly in well LT-1. The oldest strata of Paleocene or younger age in LT-1 has a thickness of 360 m (2600 to 2960 m), indicating a thicker sedimentary sequence with the exception only seen in the section of Lower Miocene age, which anyway has neither the source rocks nor the oil shows. The sections in which oil and gas indications in LT-1 occur

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Figure 12. LT-1 Well cross-section showing probable prognostic site to the east.

belong to the Upper Oligocene-Lower Miocene and to the lower part of the Lower-Middle Miocene. The LT-1 well showed good seals provided by lacustrine shales at depths where the oil shows have been found (Figure 12). The black shales have high gamma ray log values (120 API units) and low porosity (< 5%). They intermittently were encountered in LT-1 well at 850 to 900 m, 980 to 1057 m and 1360 to 1420 m depths (Rop, 2003, 2013). However, the numerous interpreted and intrabasinal N-S trending faults in Lokichar basin could have caused the escape of whatever hydrocarbons generated. Thus, even if the good sandstones were of good reservoirs and quality, as intermittently seen between depths 800 to 1760 m, no oil accumulation took place perhaps due to lack of fault closures. The maturation of the organic matter in these source rocks (fluvio-lacustrine) was consequent to high heat flow associated with mantle upwelling and rifting. The proximity of volcanic dykes locally also enhanced the maturation temperature. The well LT-1 was close to the eastern margin of South Lokichar basin, perhaps on a tilted fault block (Figure 12). Further east of LT-1 location is a small horst-like structure represented by the basement ridge. To the west of LT-1 numerous north-south intrabasinal faults have been interpreted, which extend to the basement. The South Lokichar basin is deeper in this part along the marginal major N-S trending fault (Lokichar). The sections of source rocks in LT-1 extending to the deeper regions towards west, could have achieved the temperature realms of 60 to 150

oC.

Their maturity and cooking at that depth would make these OM-rich sediments more potential for hydrocarbon generation. The extension of the section with hydrocarbon-shows in the well LT-1 would also provide

better reservoir rocks. Thus, the areas in the basin west of LT-1 could be projected as the prognostic areas for future exploration targets (Figures 12 and 10). It can be visualized to some extent also from the seismic profiles. Northwards also, the Lokichar basin deepens with intermediate horst-like structures separating the North Lokichar (Lodwar) from the South Lokichar. The other potential area for future exploration would be to the east of Lodwar fault (Figure 10) in the North Lokichar basin. These two areas could also be decided after giving due consideration to the east-west lineaments and/or faults controlling the drainage (Turkwell River). It must be recalled that the well LT-2 (in the North Kerio basin) to the east of the basement ridge went dry with no location of either the potential source rocks or the reservoir rocks at depth. There is however a chance also to get some rocks with potential hydrocarbons at a deeper level in the area to the east of LT-2. The gravity and seismic data (gamma and sonic ray logs) further give clue to the porosity of the rocks. The studies by the drilling company (AMOCO) in the Chalbi Basin did reveal the presence of good reservoirs and source rocks mainly in the Upper Cretaceous. The sections with source rocks identified in C1 well are represented by 1500 to 1800 m and 2300 to 2390 m depths. These rocks have a high gamma ray values (up to 75 API units) and p-wave velocity values of 3.3 to 3.9 km/s. The porosity of the upper source rock interval is good (27%) while the lower one is relatively low (10 to 15%). The depth at which they occur would make the organic matter in these sediments (with TOC >5%) undergo changes to produce hydrocarbons since the temperature gradient would be a contribution by the igneous intrusive activity of a later date. The section with reported oil and

Res. J. Eng. Technol. 53

Figure 13. Cross-section of C1 Well showing basement depth and Bouguer gravity curves.

gas shows in well C1 would similarly constituted of good reservoir rocks with good to fair porosity (30%). Since the source and reservoir rocks are not much separated vertically, there is a possibility that the oil and gas have not migrated much in this well section. Both the source rocks as well as the reservoir rocks occur only within the Upper Cretaceous stratigraphic section. The Lower Cretaceous sequence, the entire younger section of the Upper Cretaceous as well as the Tertiary sections, have no potential rocks. However, in the areas west and east of this well C1 (Figure 13), there could be a migrated oil show, taking into consideration the various intrabasinal faults. The potential rocks towards the north could be judged by the section of C2 drilled immediately to the north of C1. This well has also revealed depths of the order of 3500 m. The source rocks have been represented in the interval depth 2230 m to 3400 m. They are rich in organic matter with up to 2% weight TOC content. This section has been characterized by high gamma peaks ranging from 75 to 90 API units and p-wave velocities of 3.8 to 4.1 km/s. Some good to fair porosity reservoir rocks are also present within this source rock section at depths2730 to 3370 m. The reservoirs have same gamma ray and p-wave velocity characteristics as source rocks. The source rock section, if extended further into the eastern deeper areas of C2, would probably have better oil and gas potential (Figure 14). The entire section containing source rocks is mostly confined to the Upper

Cretaceous stratigraphic part. The higher gamma ray peaks indicate the presence of radioactive elements with organic matter which enhance the possibility of reaching temperatures conducive for hydrocarbon generation. The areas to the east of C2 have experienced faster subsidence as they are near the Kargi fault. In the western section there is less possibility of potential source rocks but migration of oil from east to west along tilted faults cannot be ruled out. It will depend upon the channels, on the porosity, and on the intercalations of shales with sandstones. Unlike the C1 and C2, the C3 well was drilled near the Chalbi fault towards the western part of the basin (Figures 7 and 3). It can be seen that it was again drilled in the deeper part of the Chalbi basin but much to the north. Between locations C1, C2 to the south and C3 to the north, a few faults have been interpreted striking WNW – ESE to the north of Mount Kulal. The deepening of the basin towards the west in this section is a departure from what is shown in C1 and C2 wells. Therefore it seems logical to visualize that this crisis-cutting faults should have also contributed to the subsidence of the basin. The source rocks in the depth range 2300 m to 3100 m is comparable with the depths reached in C1 and C2. The source rocks show high gamma ray (60 API units) and p-wave values of 3.6 to 4.5 km/s. The reservoir rocks at C3 well are at shallow depths (1660 to 1700 m and 1860 to 1960 m), and are characterized by low gamma ray (36 to 40 API units) and p-wave values 2.9 to 3.2 km/s.

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Figure 14. Cross-section of C2 Well showing basement depth and Bouguer gravity curves.

Gas shows encountered in C3 are within a section which is younger (Upper Cretaceous). However, both the source rocks as well as the reservoir rocks in which gas shows are found are within the Upper and Lower Cretaceous stratigraphic section. This is a departure from the wells C1 and C2 where the source rocks as well as the reservoir rocks are within the Upper Cretaceous section only. Immediately to the east of well C3, there is a possibility that the Lower Cretaceous section containing these potential rocks reaches deeper parts of the basin, which will have higher temperatures and possible radioactive elements. CONCLUSION The examined subsurface stratigraphy was intended also to assess the prognostic oil and gas potential of this basin and extrapolate the information to other parts of the northwestern unexplored areas of the Lotikipi basin to the northwest of Lake Turkana. Their infilled sediments are predominantly non-marine but it is possible that there was some marine influence during the initial sediments filling of the Chalbi Basin (Cretaceous), in the north Anza

Extension Basin. The geothermal gradients of the Cretaceous and those of the Tertiary basins should have been different, consequent to the non-uniform mantle up warping as revealed by the gravity anomaly profiles. Intracratonic basins of these types are poor prospects for the hydrocarbon exploration, but they may contain adequate potential reservoir rocks, which can trap whatever hydrocarbons that were generated by the chiefly continental organic matter buried with the sediments. The examined salient structural features containing source-reservoir-seal rocks in the oil/gas-bearing strata based on gravity, seismic and gamma ray profiles, TOC and other sedimentological parameters helped in characterizing possible future prognostic targets and their implications for hydrocarbons prospecting and exploration in the Lokichar-Turkana-Chalbi rift basinal systems. ACKNOWLEDGEMENTS This paper is published with the permission of the Managing Director, National Oil Corporation of Kenya. The fieldwork, data analyses and interpretation formed

part of the Ph.D. research-related thesis work submitted to University of Pune, under the guidance of Prof. A.M. Patwardhan, whom I deeply thank for the valuable comments and discussions during my research period in India. REFERENCES

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APPENDIX: EXPLANATION FOR GEOLOGICAL COLOURED MAPS IN FIGURES 4 AND 5 (Adopted from BEICIP-Ministry of Energy Geological Map, 1987).