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Petroleum Potential of NW-Kenya Rift Basins:
A Synopsis of Evidence and Issues

Bernard Kipsang Rop, Ph.D. (Reg. Geol.)
Geofountain Synergy Consultancy
P.O. Box 7702 – 00200, Nairobi, Kenya.

posted online: August 4th, 2011



ABSTRACT: The petroleum synoptic research work gives an overview subsurface stratigraphy of northwestern Kenya rift basins. The basins 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. This movement was accompanied by a stupendous outpouring of the lava flows. The gravity anomaly maps and seismic profiles were most useful for the interpretations incorporated in this paper which revealed the presence of several horsts and grabens structural systems. It was also revealed that the basins attracted potential petroliferous sedimentary piles (~2000 – 5000 m thick) which were deposited on basement rocks of Precambrian age and later got covered by basaltic flows of mainly Miocene age. The drill core lithologs were available pertaining to wells: LT-1 and LT-2 in the Lokichar and North Kerio-Turkana basin systems (Tertiary) and C1, C2 and C3 in the Chalbi basin (Cretaceous). The northwestern Lotikipi basin (Cretaceous?) has not yet been drilled. Comparing the lithologs from these wells, the strata in which there was oil and/or gas indications was further characterised in the light of the organic matter and other sedimentological parameters in order to understand the source‐reservoir‐seal rocks which are favourable targets for future petroleum exploration.

Key Words: source rocks, hydrocarbons, petroleum, exploration, gravity, seismic.

Author:male; PhD;  main research fields: Hydrocarbons and Environmental Reduction and Risk Management; Department of Mining and Mineral Processing Engineering, Jomo Kenyatta University of Agriculture and Technology, Taita Taveta Campus, Private Bag, Voi, Kenya.

Introduction

The geology of Kenya is generally known for the coastal terrigenous clastic sediments of the Karroo system, the Kenya-Kilimanjaro volcanics belonging to the Tertiary volcanic activity and the Quaternary archaeological sites of the early man (Fig.1). It is also known for the spectacular landscape resulting out of the great East African Rift System and the chain of rift lakes from which some salt deposits are being exploited [1].

Fig.1: Geological map and location of study area

Fig.1: Geological map and location of study area

A large part of the Kenyan geology also consists of the Precambrian basement rocks and the Tertiary volcanics that have covered many of sedimentary basins, which are now considered to be potential basins for oil exploration. These basins are known to have evolved through extension tectonics (Figs. 2and3) 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 [2, 3, 4]. The region underwent uplift and subsidence, intermittently, along major boundary faults of these basins even in the Miocene period. This movement was accompanied by the stupendous outpouring of the lava flows.

The basins seem to have evolved consequent to a complex tectonic activity related to continental rifting and block faulting of the Lamu-Anza-Abu Gabra and Central African Rift Systems (Fig.3) .

Fig.2: Physiography, geology and drainage map

Fig.2: Physiography, geology and drainage map

The physiographical features such as the basement ranges and inliers, Tertiary volcanic plateaus, Lake Turkana and lowlands with alluvial plains as well as drainage systems are present in the study area (Fig.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 [5, 6]. 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. The small rivers flow perpendicular to the ranges and terminate to join the main rivers flowing north-south [7].

The existing information on the geology and stratigraphic succession of the four major sedimentary basins has been highlighted [8, 9]. It is suspected, and is the very basis and premise of this present synoptic work, that the sediments of the Anza Basin to the southeast and the sediments of the Abu Gabra and Sharaf Formations (Cretaceous) in Sudan to the northwest have counterparts in the intervening areas of northern Kenya (Fig.3). The Jurassic-Cretaceous sediments of the Anza Basin and those of the Sudanese Abu Gabra Basin [10] are said to have been deposited in rift basins, with possible encroachments of the sea from both directions, depositing sediments immediately overlying the basement rocks of these basins [7, 11, 12, 13].

Fig.3: Map of NW-trending Anza Basin rift extension

Fig.3: Map of NW-trending Anza Basin rift extension;
Inset – Gondwanaland breakup in Late Paleozoic time.
(modified after BEICP, 1984).

Materials and Methods

Status of Oil Exploration in Study Area

Efforts are now being made by National Oil Corporation of Kenya (NOCK) to explore for hydrocarbon reserves in the sedimentary basins belonging to the Jurassic/Cretaceous-Tertiary age; although most wells so far drilled in these basins did not prove any oil reserves. The present work is mainly a synoptic overview of the subsurface stratigraphy in the northwestern Kenya Rift basins with the help of geophysical and geochemical data.

The study is devoted to the collection and interpretation of all the data; structural, geomorphologic, seismic and gravity as well as gamma ray data, pertaining to drill core well profiles obtained from the three wells (C1, C2 and C3), drilled in Chalbi Cretaceous sequence and the two wells, LT-1 (Loperot-1) and LT-2 (Eliye Springs-1), drilled in Lokichar-Kerio/Turkana sub-basins which penetrated chiefly the Palaeocene or younger strata. Future drilling and fossil finds will also provide additional stratigraphic attributes to the seismically defined subsurface Formations in the Lotikipi basin [7].

From the palynological presence of flora and faunal assemblages found in these sedimentary sections the drilling companies (AMOCO and SEPK) have reported that the sediments were deposited in a fluvial-deltaic and marine-lacustrine environments. The sedimentation in these intracratonic rift basin was controlled by intrabasinal and marginal faults, some of them reaching also the basement. While examining the subsurface stratigraphy, it is intended also to assess the prognostic oil and/or gas potential of these basins and extrapolate the information to other parts of the northwest unexplored and yet to be drilled Lotikipi basin.

Sedimentation, Subsurface Structures and Tectonics

During the Cretaceous as well as Tertiary times the sedimentation in these rift-related basins, extending NW-SE, was mostly fluvial, gradually becoming brackish and marine in the peripheral regions towards the open seas (Fig.3). From the paleogeographic and dinosaurian fossil evidence, the Cenomanian period had paleoclimatic conditions (warm humid climate and heavy precipitation) predicted conducive for luxuriant thick vegetation [14], which accompanied the fluvial sedimentation of that period in the rift basins under study.

The detailed tectonic structures of the subsurface basins on the basis of basement depth and gravity anomalies (Bouguer anomalies) obtained from the regional contour map [15] covering the study area has been examined (Figs.4and5). The gravity surveys help in limiting the depths of the basins as well as the basement, scanning the lithosphere and the upper mantle mainly according to the relative densities (Table 1).

The positive gravity anomalies (Fig.4) define the limits of the horst structures where the basement is overlain mostly by the lava flows. The Bouguer gravity contours over the rift basins show distinct north-south strike, indicating that the Tertiary rift tectonics affected even the crust-mantle interface. In the present case, it has been found to be quite effective since the basement rocks as well as the upper cover of volcanics have distinctively higher densities than the infilled sedimentary sections within the basins (Table 1).

Rock Type or Mineral Density (g/cm3)
Sand 1.6 - 2
Sandstone (Mesozoic) 2.15 - 2.4
Sandstone (Paleozoic and older) 2.3 - 2.65
Quartzite 2.60 - 2.70
Limestone (Compact) 2.5 -  2.75
Shales  (younger) 2.1 - 2.6 (2.4)
Gneiss 2.6 - 2.9 (2.7
Basalt 2.7 - 3.3 (2.98)
Diabase 2.8 - 3.1 (2.96)
Granite 2.52 - 2.81 (2.67)
Granodiorite 2.6 - 2.79 (2.72)

Table 1: Characteristics of densities of rocks and minerals - limiting depths of rift basins. Table Adopted from Sharma, 1976 [16]

Fig. 4:  Bouguer gravity contour map with MOCO’s seismic  lines TVK 4 -7 in Lotikipi basin

Fig. 4: Bouguer gravity contour map with AMOCO’s seismic lines TVK 4 -7 in Lotikipi basin

Fig. 5: Basement contour map showing basement depths

Fig. 5: Basement contour map showing basement depths

The basaltic cover has hidden under it a thick succession of Mesozoic and Tertiary sediments. These basins are bounded by major fault systems; the gravity profiles of the present terrain indicate that within the basins 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 (Figs.6and7). 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. The landscape and subsurface basin structures generally indicate that the tectonic activity, rifting and block faulting process, which was initiated in the Cretaceous time or prior, continued in pulses during the Tertiary and even during the Quaternary. It has been possible to demarcate within the basins the various horst and graben-like structures.

For example, in the case of Lake Turkana basin, the basement contours (Fig.5) indicate a deeper half-graben structure towards the northwestern 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 (Fig.7). The gravity picture of the Lake Turkana basin (Fig.4) 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 4oN, 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 downwarp of the mantle. In comparison, the mantle has been upwarped under the Lotikipi plains and has been sharply thrown upwards under the Koobi Fora (area under points R and S  in Figure7).

Fig. 6: S-N Cross-section of  Basement depth profiles  along L.Turkana basin between lats. 2o30’N  and  4o30’N; a)  From  South Is. to Lapurr Range; b) From Kerio Basin to NW corner of Lake Turkana.

Fig. 6: S-N Cross-section of Basement depth profiles along L.Turkana basin between lats. 2o30’N  and  4o30’N; a)  From South Is. to Lapurr Range; b) From Kerio Basin to NW corner of Lake Turkana.

Fig. 7: Cross-section of Bouguer gravity and Basement dept values along  lat. 4oN in the Lotikipi and Lake Turkana Basins showing half-grabens features

Fig. 7: Cross-section of Bouguer gravity and Basement dept values along  lat. 4oN in the Lotikipi and Lake Turkana Basins showing half-grabens features

Results and Discussions

Basin Configuration and Stratigraphy

The surface lithological characteristics give a clear indication that sedimentation, if at all has taken place during the Cretaceous or older times, should have been restricted to smaller sub-basins which can be demarcated only by geophysical data (Figs. 4-7). The three exploratory wells Sirius-1, Bellatrix-1 and Chalbi-3 (denoted as C1, C2 and C3) drilled in the Chalbi basin in 1988/89 by AMOCO, after the seismological work was completed, penetrated Cretaceous strata; while the two wells, LT-1 (Loperot) and LT-2 (Eliye Springs), drilled in 1992 by Shell Exploration and Production Kenya (SEPK) in Lokichar-Kerio sub-basins, penetrated chiefly the Palaeocene or younger strata (Fig.8).

The stratigraphic succession was ascertained by interpretation of the seismic data from these subsurface basins [7] which have also been correlated with the description of the stratigraphic lithologs obtained from the drilled wells (Figs.9and10). The lithologs have been examined in the light of gamma ray data in order to build up a clear understanding of the subsurface stratigraphic formations with respect to seismic profiles.

Among the geophysical methods, used commonly in exploration of oil and gas, the gravity and seismic methods are more common and effective. Seismic survey is a useful tool for exploration as it helps in covering large areas and in mapping the subsurface rock stratigraphic units bringing out also the physical characteristics like the degree of compactness, rigidity, porosity and permeability. From the seismic profiles, it was revealed that the frequency of the shaley rocks and compact sandstones increased with depths, for example those of the seismic lines TVK 4-7 in the unexplored Lotikipi basin (Fig.11).

These rocks were further distinguished by the gamma-ray logs to demarcate black shales with organic matter, coaly beds and sediments with radioactive elements. The analysis helped in determining the proportion and frequency of the shale horizons within the otherwise sandy sections, as well as the variations in grain size within the sandstone beds.

Fig. 8: Map showing Wells drilled in the basins of the study area

Fig. 8: Map showing Wells drilled in the basins of the study area

Fig. 9: Comparative Lithologs of the Chalbi Basin C1, C2 and C3 Wells Based on Gamma ray and Sonic logs, p-wave velocities and Geological Time

Fig. 9: Comparative Lithologs of the Chalbi Basin C1, C2 and C3 Wells Based on Gamma ray and Sonic logs, p-wave velocities and Geological Time

Fig. 10: Comparative Lithologs of LT-1 and LT-2 Wells Based on Gamma ray and  p-wave velocities

Fig. 10: Comparative Lithologs of LT-1 and LT-2 Wells Based on Gamma ray and p-wave velocities

Marine sediments with higher gamma ray (uranium content) values are of course considered to be better source rocks than those deposited in lacustrine and freshwater conditions. Lacustrine sediments like the present ones have typically low gamma ray radioactivity. The radioactive heat [17] from organic matter (OM) rich sediments adds further to the temperature gradient which is otherwise also higher than the normal geothermal gradient in the intracratonic rift basins [18]. Black shales rich in carbon (2 percent weight TOC) as well as syngenetic uranium (up to 400 ppm) though more common to marine sediments, can also be deposited in other (lacustrine) environments which are biologically productive and anoxic. Speedy sedimentation along with basin subsidence prevents the oxidation of organic matter and preserves it for possible hydrocarbon generation. In India, there has been a recent discovery of a huge gas field in the near shore regions of the Godavari Basin which contains sufficient humic organic matter (shales and associated coals), deposited in intermediate environment [19].

The present intracratonic rift basins are separated from one another by ridges and horsts of igneous and metamorphic basement and tend to plunge northwestwards to Sudan. Towards the northwestern (Lotikipi) and southeastern (Chalbi) parts, they are expected to present a correlatable Cretaceous stratigraphy; the stratigraphic facies boundaries may be diachronic. In the central part (Lokichar - Kerio - Turkana basins), the Cretaceous stratigraphy is overlain by Tertiary and Quaternary sediments, many of these sequences being sandwiched between intermittent lava flows. These younger rift basins are a part of the N-S main East African Rift System (Figs. 1and3).

Examples of intracratonic basins are present throughout the northern Africa continent, including areas in Sudan and Libya, as well as Egypt. Their infilled sediments are predominantly non-marine but it is possible that there is some marine influence during the initial sediments filling of the Chalbi Basin (Anza Graben). The geothermal gradients of the Cretaceous and those of the Tertiary should have been different, consequent to the non-uniform mantle upwarping as revealed by the gravity anomaly profiles. Intracratonic basins of these types are poor prospects for the hydrocarbon exploration, but they contain adequate potential reservoir rocks, which can trap whatever hydrocarbons that were generated by the chiefly continental organic matter buried with the sediments. There are a few examples (1.5 percent of world’s proven reserves) of hydrocarbon generating intracratonic basins of this type [20].

Source Rocks Characteristics in the Rift Basins

The characteristics of identified subsurface strata showing oil and/or gas indications present conducive environments and implications for the generation of hydrocarbons [7]. Hydrocarbons are usually generated during burial and diagenesis of the organic matter (OM) they contain. In such intracontinental basins, like in the present case, the temperature gradient is often higher than the normal because of the process of formation of these basins. It may sometimes reach a gradient of 30–33oC/km. Higher temperatures are also reached by the co-precipitations of radioactive elements along the organic matter. Thus field of crude oil generation expands and reaches a maximum between 2 and 3 km depth. In many cases where there is less generation of crude oil, there is still a possibility of finding gas. The most promising depths for gas, however, are beyond 2.8 km depth [21].

Total organic carbon (TOC) is a measure of carbon present in a rock in the form of kerogen and bitumen. The organic matter is usually converted into kerogen and the type of kerogen depends upon the kind of organic matter that gets buried. Not all the organic matter in the sedimentary rocks are convertible into petroleum hydrocarbons. For example, intracratonic basins like the ones under study do not attract marine organic matter. These basins have had fluvial and lacustrine environments of deposition. Therefore, the organic matter brought from the vegetation on the higher lands of the time (?Jurassic-Cretaceous and Early Tertiary) was buried along with the sediments in the mostly lacustrine and fluvial environments [7].

Chalbi Basin

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. Based on Bouguer gravity anomalies [7] it was possible to visualise the structural configuration of the part of Chalbi basin in which the three wells were drilled (Figs.8and9). The location of C1 well has been taken such that it reached the deepest part of the sedimentary section, immediately to the west of the Kargi fault. The sections with source rocks identified in C1 are represented by 1500 – 1800 m and 2300 – 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 – 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 [7].

The section with reported oil and 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 (Fig.12), 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 percent weight TOC content. This section has been characterised by high gamma peaks ranging from 75 to 90 API units and p-wave velocities of 3.8 – 4.1 km/s. Some good to fair porosity reservoir rocks are also present within this source rock section at depths 2730 m 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 (Fig.12). 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 [7]. 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 well C3 was drilled near the Chalbi fault towards the western part of the basin [7]. 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 visualise that this criss-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 LT-1 well showed good seals provided by lacustrine shales at depths where the oil shows have been found.  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 850–900 m, 980–1057 m and 1360–1420 m depths [7]. The sections of source rocks in LT-1 extending to the deeper regions towards west,  could have achieved the temperature realms of 60–150oC. 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. 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 reservoir rocks at C3 well are at shallow depths (1660 – 1700 m and 1860 – 1960 m), and are characterised by low gamma ray (36 – 40 API units) and p-wave values 2.9 to 3.2 km/s. 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 (Fig.12).

Lokichar-Kerio Basins

The source rocks of well LT-1 identified above belonged to Oligocene to Lower Miocene age. These source rocks range from depths 800–1797 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 1650–1800 m (considering the normal temperatures gradients). The porosity at shallow depths (800 -1760 m) is high (12 - 40%) but decreases with depth (5 – 10%) at 1760 -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 oldest strata of Paleocene or younger age in LT-1 has a thickness of 360 m (2600–2960 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 belong to the Upper Oligocene-Lower Miocene and to the lower part of the Lower-Middle Miocene [7].

The other potential area for future exploration would be to the east of Lodwar fault  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.

Lake Turkana Basin

The nature of the Lake Turkana subsurface basin (Figs.2-7) is like half-graben, which deepens and becomes more complex from south to north [7]. There seems to be variations in the depth of the basement from lats. 2o30’N to 4o30’N. It can be seen that between lat. 2o50’N and 3oN the basement shallows and is exposed to the surface. This is a horst-like structure which seems to be controlled by E-W faults. This region coincides with the Kajong/Porr area, east of Lake Turkana. The basement gradually deepens towards the east under the Moiti area, which also shows the presence of E-W trending minor faults which have controlled the river courses also. Beyond latitude 3o30’N, the basement deepens suddenly; it becomes deepest (-3 to -5.2km) between lats. 4oN to 4o15’N.

The nature of the Lake Turkana subsurface basin (Figs.2-7) is like half-graben, which deepens and becomes more complex from south to north [7]. There seems to be variations in the depth of the basement from lats. 2o30’N to 4o30’N. It can be seen that between lat. 2o50’N and 3oN the basement shallows and is exposed to the surface. This is a horst-like structure which seems to be controlled by E-W faults. This region coincides with the Kajong/Porr area, east of Lake Turkana. The basement gradually deepens towards the east under the Moiti area, which also shows the presence of E-W trending minor faults which have controlled the river courses also. Beyond latitude 3o30’N, the basement deepens suddenly; it becomes deepest (-3 to -5.2km) between lats. 4oN to 4o15’N.

Some minor faults have also been interpreted based on the changes in the slope of the basement profile. The subsurface structure between latitudes 2o50’N to 3o45’N, based on gravity profiles and basement depth, showed that the basin also deepens towards the east. Thus the Lake Turkana Basin seems to have been initiated prior to the N-S faulting; deepest towards the north between latitudes 3o30’N to 4o30’N (Fig.6 a). It is in this region one ought to expect the subsurface continuation of the Lapurr Range outcrops.

A cross-section of the basement depth from North Kerio basin to the northern Lake Turkana basin, between lats. 2o30’N to 4o30’N and longs. 35o45’E and 36o15’E, shows that though the basement gradually deepens towards north, there is no distinct deep trough existing between lats. 3o30’N to 4o30’N (Fig.6 b). The horst structure seen under the Moiti area is also not distinctly demarcated in this profile. Thus the subsurface structure is therefore very complicated, characterised by irregular downthrows and upthrows related first to the E-W faulting and later to the N-S faulting in the basin. From the above gravity and basement depth cross-sections, it can be concluded that the entire Lake Turkana subsurface basin is bounded by N-S-striking faults and there exists intrabasinal  faults also [7]. 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.

Lotikipi Basin

From the seismic profiles along Lines TVK-4, TVK-5, TVK-6 and TVK-7 (Figs.4,11and12), in the Lotikipi basin, it was possible to identify two sub-basins, between longitudes 34o30’E and 35o00’E and latitudes 4o15’N and 4o45’N, which have been named after the nearest river systems as a) the Anam-Natira Formation and b) the Tarach-Nakalale Formation [7].

The anticipated best-developed subsurface sedimentary section, identified on the basis of seismic and gravity studies, under the channels of the Anam and Natira rivers (Figs.2,4and11), has been named as the Anam-Natira Formation. The 1050 m thick sequence (between long 34o30’E and 35o00 N), showing P-wave velocity (Vp) between 3.0 and 4.0 km/s on TVK-4 line profile, is interpreted to consist chiefly of sandstones and shales [7]. The lower 350 m section, between 1900 m to 2250 m depth, should contain compact sandstones with frequent thick clay/shale layers, for which the Vp range is between 3.5 to 4.0 km/s.

The upper 700 m section, between 1200 m - 1900 m depths, should be mainly fine-grained sandstones with minor clay/shale layers, followed upward by mainly coarse-grained sandstones. The upper section is characterised by a lower Vp range between 3.0 and 3.5 km/s, but the intercalated clay/shale or less porous, more compact sandstones layers are marked by higher Vp (3.5 km/s).

Fig. 11: General stratigraphic columns variations of  probable type  sections of Lotikipi Formations based on seismic profiles

Fig. 11: General stratigraphic columns variations of  probable type  sections of Lotikipi Formations based on seismic profiles

The best-developed (Tertiary ?) section (1420 m thick) located beneath the Tarach and Nakalale river systems, characterized by Vp between 2.0 and 3.0 km/s, has been named as the Tarach-Nakalale Formation [7]. Deduced along TVK-6 the area covered under Longs. 34o45’E and 35o03’E and Lats. 4o24’ N and 4o42’ N shows a better development of this formation, which seems to be constituted of less consolidated sands, gravels, silts and clays which increasingly become more compact towards the basal part of the section (1560-2060m depth). The sub-basin on the TVK-6 line bounded by lats. 4o24’N and 4o42’ N and longs. 34o45’E and 35o03’E can be considered as representing the ‘type’ section of the Tarach-Nakalale Formation. The ‘type’ Tarach-Nakalale Formation sequence shows well-developed representation of both the members, which range to about 800 m thick each.

Future drilling and fossil finds will provide additional stratigraphic attributes to these seismically defined Formations in the Lotikipi basin. However, at this juncture, the section cannot be assigned a definite stratigraphic age, but occurring in similar tectonic and stratigraphic setup, it is suspected that the Anam-Natira Formation might be homotaxial to the Sharaf and Abu Gabra Formations (Neocomian or Albian-Aptian in age, [10] of southern Sudan. Although future drilling alone would enable assigning additional lithological attributes to these two subdivisions, in the absence of any other criteria to assign a stratigraphic age, it might help to consider Tarach-Nakalale Formation as coeval to the Kordofan Group of southern Sudan (early Tertiary in age, [10].

Additionally, one might also point out that the sub-basins in which the thicker Anam-Natira Formation sequences (Upper Cretaceous?) are suspected are different than the sub-basins in which a greater thickness of Tarach-Nakalale Formation (Lower Tertiary?) is anticipated [7]. Since there has been no exploratory wells drilled in the Lotikipi basin, most of the prognostic evaluation of the basin  (Fig. 12) would depend upon the evaluation done on rocks of equivalent age belonging to the other basins (along the NW-SE-trending Anza and Abu Gabra Rifts – Fig.3).

Fig. 12: Map showing probable petroleum prospective areas (shaded black or grey) in the NW Kenya rifts basins

Fig. 12: Map showing probable petroleum prospective areas (shaded black or grey) in the NW Kenya rifts basins

 

 

Paleogeographic Position

As earlier discussed, the paleogeographic position of this region (what is presently northern Kenya) was much to the south of the Equator during the Triassic-Jurassic up to Cretaceous time. Therefore luxuriant vegetation on land, swampy grounds, humid climate and good rainfall were some of the then prevailing environmental conditions. With such a source, the organic matter that got buried could only generate the Type I or Type III kerogen whose initial product could be waxy crude or gas  [21, 22].

Conclusion

From the palynological presence of flora and faunal assemblages found in these sedimentary sections, the drilling companies (AMOCO and SEPK) have reported that the sediments were deposited in marine and deltaic and/or fluvial-lacustrine environments. The sedimentation in these intracratonic rift basins was controlled by intrabasinal and marginal faults, some of them reaching also the basement. While examining the subsurface stratigraphy and the drilled well cores, it is intended also to assess the prognostic oil and gas potential of these sedimentary basins and extrapolate the information to other parts of these basins, as well as to the northwestern unexplored areas of the Lotikipi basin. Their infilled sediments are predominantly non-marine but it is possible that there is some marine influence during the initial sediments filling of the Chalbi Basin (Cretaceous) in the north Anza graben. The geothermal gradients of the Cretaceous basins and those of the Tertiary should have been different, consequent to the non-uniform mantle upwarping as revealed by the gravity anomaly profiles.

Intracratonic basins of these types are poor prospects for the hydrocarbon exploration, but they contain adequate potential reservoir rocks, which can trap whatever hydrocarbons that were generated by the chiefly continental organic matter buried with the sediments. There are a few examples of hydrocarbon generating intracratonic basins of this type. Speedy sedimentation along with basins subsidence prevent the oxidation of organic matter and preserves it for possible hydrocarbons generation. Thus, the examined salient structural features of source‐reservoir‐seal associations revealed favourable prognostic targets for future petroleum exploration in the northwest Kenya rift basins.

Acknowledgements

This paper is published with the permission of the Managing Director, National Oil Corporation of Kenya (NOCK). The fieldwork, data analyses and interpretation formed part of the PhD research-related thesis work submitted to  the University of Pune. I am grateful to Prof. Patwardhan for his invaluable comments and discussions during my research period.

 

References

[1] Barker, B.H.,1986, “Tectonics and volcanics of southern Kenya Rift Valley and its influence on rift sedimentation,” In: Frostick, L.E. et al (Ed), Sedimentation in the African Rifts, Geological Society Special Publication No. 25, pp.45-57.
[2] Girdler, R.W.,1983, “Processing of planetary rifting as seen in the rifting and breaking up of Africa,” Tectonophysics, Vol. 94, pp. 241-252.
[3] Green, L.C.; Richards, D.R. and Johnson, R.A., 1991, “Crustal structure and tectonic evolution of the Anza rift, northern Kenya, “Tectonophysics, Vol. 197, pp. 203-211.
[4] Davidson, A. and Rex, D.C., 1980, “Age of volcanism and rifting in southwestern Ethiopia,”  Nature, Vol. 283, pp. 657-658.
[5] Barker, B.H., Morh, P.A. and Williams, L.A.J., 1972, “Geology of the Eastern Rift systems of Africa,” Geological Society of American Special Paper 136, 67p.
[6] Rop, B.K., 2002, “Subsurface geology of Kenyan Rift Basins adjacent to Lake Turkana based on gravity anomalies,” In the abstracts of International Seminar on Sedimentation and Tectonics in Space and Time, Dept. of Civil Engineering, S.D.M. College of Eng. and Tech., Dharward – 580 003, India, 16th – 18th April, 2002; pp 83-85.
[7] Rop, B.K., 2003, “Subsurface stratigraphical studies of Cretaceous-Tertiary basins of northwest Kenya,” Ph.D. thesis, University of Pune, India.
[8] Walsh, J. and Dodson, R.G., 1969, “Geology of Northern Turkana. Geological Survey of Kenya,” In: Bishop, W.W. (Eds.), Scottish Academic Press, Edinbergh, pp. 395-414.
[9] Rop, B.K., 1990, “Stratigraphic and sedimentological study of Mesozoic-Tertiary strata in Loiyangalani area, Lake Turkana district, NW Kenya,” M.Sc. Thesis, University of Windsor, Canada.
[10] Schull, T.T., 1988, “Rift Basins of interior Sudan: Petroleum Exploration and Discovery,” The AAPG Bulletin, Vol. 72, pp. 1128-1142.

 

[11] Morley, C.K., Wescott, W.A., Stone, D.M., Harper, R.M., Wigger, S.T. and Karanja, F.M., 1992, “Tectonic evolution of the northern Kenya Rift,” Journal of the Geol. Soc., London, Vol. 149, pp. 333-348.
[12] Key, R.M., Rop, B.P. and Rundle, C.C., 1987, “The development of the Late Cenozoic alkali basaltic Marsabit Shield Volcano, northern Kenya,” Journal of African Earth Sciences, Vol. 6, pp. 475-491.
[13] Winn, R.D., Steinmetz, J.C. and Kerekgyarto, W.L., 1993, “Stratigraphy and Rift History of Mesozoic-Cenozoic Anza Rift, Kenya,” The AAPG Bulletin, Vol. 77, pp. 1989-2005.
[14] Bloom, A.L.,2002, “Geomorphology, Third Edition,”  Prentice-Hall India Pvt. Ltd., New Delhi.
[15] BEICIP, 1984, “Petroleum potential of Kenya 1984 follow-up, Ministry of Energy and Regional Development.”
[16] Sharma, P.V., 1976, “Geophysical Methods in Geology,” W.H. Freeman and Company, New York.
[17] Durrance, E.M., 1986, “Radioactivity in Geology: Principles and Applications,” Ellis Horwood Limited Publishers, Chichester.
[18] Patwardhan, A.M., 1999, “The Dynamic Earth System,” Prentice-Hall of India.
[19] Minax Pal, Venkatesh, V., Balyan, A.K. and Sarkar, A., 1992, “Hydrocarbon Prospects of Gondwana Basins in India; Source Rock Studies of Kamthi Sub-Basins of Pranhita-Godavari Graben,” Journal of Geological Society of India, Vol. 40, pp. 207-215.
[20] Selly, C.R., 1985, “Elements of Petroleum Geology,” W.H. Freeman and Co. New York.
[21] Tissot, B.P. and Welte, D.H., 1984, “Petroleum Formation and Occurrence,” Second Revised and Enlarged Edition, Springer-Verlag Berlin Heidelberg New York Tokyo.
[22] North, F.K., 1985, “Petroleum Geology,” Boston Unwin Hyman Publishers.



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