Kenya´s world class lacustrine source rock: A geochemical analysis and proven petroleum system

Abstract

Until Cepsa drilled Tarach-1 (2016) in Block 11A, Lotikipi Basin NW Kenya, the presence of a proven Tertiary source rock was restricted to the Tullow operated Lokichar Basin blocks some 200 kms southeast of Cepsa's area of interest (figure 1). The prolific lacustrine petroleum system of the Lokichar Basin has now yielded around 1 BBO recoverable resources. Block 11A is located at the junction of the N-S Tertiary East Africa Rift System (EARS) and the NW-SE trending Cretaceous Rift System (CARS) (figure 1). The existence of both Tertiary and Cretaceous rift basins should not be ruled out, the lack of stratigraphic control in the immediate area should not exclude the possibility of more than one rifting event. The EARS is composed of two rift trends called the Eastern and the Western branches. The Eastern branch is located North and East of the Lake Victoria and corresponds to the volcanic system that forms the Kenya and the Ethiopian Rifts. In some places there are outcrops of Plio-Pleistocene deposits, dominantly fluvio-lacustrine sediments. However outcrops of older sedimentary sequences are rare, in the area of interest, Block 11A no sedimentary formations have been identified. The main surface feature of the Block 11A is the Lotikipi Plain. This broad depression measures approximately 110 km from East to West. The Lotikipi Basin has been interpreted as either a thermal sag basin or a rift basin by Wescott et al. in 1999. Gravity data, acquired in the area by Cepsa in 2013, identified a sedimentary basin within the Block 11A area below the Lotikipi Plain. Using neighbouring basin evolution as an analogue the sedimentary fill was inferred to be a series of Miocene-age, stacked fluvial deltaic sandstones and lacustrine deposits, forming a sedimentary package of more than 3000m thickness. The likelihood of a deeper Cretaceous sequence should not be discounted. The Tarach-1 well was a frontier exploration wildcat and was located in the deepest part of the basin (based on initial gravity modelling), in a location best considered to test the presence of a working petroleum system and to provide stratigraphic control of the area. The well spudded on the 14th April 2016 and reached the prognosed 3010m TD on 11th June 2016 (59 days). The well penetrated an intercalation of thick layers of volcanic rocks (dominant volcanic/volcaniclastic sequence composed of basaltic, andesites and trachytes) interbedded with shales and siltstones. The sequence drilled by the well is Late Oligocene to Middle Miocene based on biostratigraphy. The well did not encounter reservoir facies, however it did encounter two excellent organic-rich shale intervals. Gas Shows The most important gas show was reported by gas-while-drilling in a shale interval from 1270 to 1325m MD with up to 0.16% total gas (TG) and the methane (C1) concentration exceeded 1000 ppm. Even ethane (C2) to pentane (C5) presence was registered. Wellsite geology also reported the presence of very dull hydrocarbons shows in this interval. A second shale interval contained less prominent gas shows, but again with the presence of C1 to C5. Isotope analyses of these gases indicated a thermogenic and oil associated gas type. Source Rock Rock Eval analyses revealed the presence of at least two organic-rich shale units (1270-1325 m MD and 1475-1505 m MD) with excellent source rock potential and kerogen quality (table 1). The depositional environment is lacustrine and indicative for a Type I source rock, which is strongly supported by biomarker analyses. Organic petrography supported these analyses. The lacustrine depositional setting of the source rocks is demonstrated by abundant occurrence of Botryococcus (b) and Pediastrum (figure 2a). Botryococcus is a colonial algae typical of freshwater-to-brackish environments with intense yellow fluorescence in the samples. Even oil inclusions have been observed in the lower source layer (figure 2b). The maturity of the two presented source layers ranges from immature for the upper to oil-mature for the lower unit. This is supported by vitrinite reflectance (VR), homohopane (H) biomarkers and the analysed gas isotopes. Tmax data indicate a higher maturity, which seems to be less likely. 3D petroleum systems modelling calibrated with VR, H, gas isotopes and well temperatures shows that the oil kitchen very likely sits in a deeper setting further to the southwest of the well location. Conclusions The Tarach-1 well has provided the first and only stratigraphic control in Block 11A; and has confirmed the existence of a sedimentary fill in the basin (organic rich shales). This sedimentary section is interbedded with a dominant volcanic/volcaniclastic sequence composed of basaltic, andesites and trachytes. Most of the sequence drilled by the well is Late Oligocene to Middle Miocene, in age and suggests that lakes were developed at several levels and were subjected to a number of strong volcanic episodes. Reservoir facies have not been drilled. However, two excellent organic-rich shale intervals at 1270-1325 m MD and 1475-1505 m MD have been discovered. The upper unit had the most important gas shows. The lower unit contained oil inclusions. These intervals are world-class lacustrine source rocks (Type I) and are believed to be equivalent in age to the Lokhone Shale found in the Lokichar Basin to the southeast. These units are immature to oil mature at the well location. The presence of these source rocks and the resulting analyses indicate a working petroleum system in the Lotikipi Basin with certain exploration potential. and the resulting analyses indicate a working petroleum system in the Lotikipi Basin with certain exploration potential.

AAPG Datapages/Search and Discovery Article #90330©2018 AAPG Hedberg: Geology of Middle America – the Gulf of Mexico, Yucatan, Caribbean, Grenada and Tobago Basins and Their Margins “Integration of the geology of the area from the southern onshore of North America to the northern onshore of South America”, Siguenza, Guadalajara, Spain, July 2-5, 2018