Geochemical Evaluation for the Hydrocarbon Potential of Source Rocks in the Anza Basin

Anza basin is located in the extensional arm of the central African rift system in the North-Eastern part of Kenya. Cretaceous sedimentary rocks were sampled from the four wells namely, Chalbi-3, Sirius-1, Ndovu-1 and Kaisut-1. Anza basin occurs on a fault block within a Paleocene-Cretaceous rift basin. The methodological approach used for the evaluation of source rocks included petrophysical and geochemical methods to ascertain their potential. Well sections with a higher shale-volume ratio were sampled for geochemical screen-ing to determine the organic richness and thermal maturity of potential source rocks, respectively. Source rock with organic richness ≥ 0.5% were evaluated further for their petroleum potential using Rock-Eval pyrolysis to determine their thermal maturity, organo-facies and in-situ generated hydrocarbons present in sedimentary facies. The geochemical evaluation of rock samples from the drilled wells’ sections of Chalbi-3 and Sirius-1 confirmed both oil and gas potential. Gas Chromatography and Mass Spectrometry (GCMS) were used to characterize the biomarker signatures and oil-oil correlation of Sirius-1 samples. A predictive model was developed to integrate the petrophysical and geochemical data to reveal hydrocarbons’ potential in the Anza basin.


Introduction
Anza basin is a sedimentary basin located in the northeastern part of Kenya (Figure 1(a)). Anza basin has been referred to as the termination of the Central African Rift System in Chalbi sub-basin and an extension of the Melut and Muglad rift basins in South Sudan ( Figure 2) where working petroleum systems [1] exist. Anza basin evolved through extension tectonics that brought out continental rifting during the Gondwanaland break-up in the Late Paleozoic time and continued in the Mesozoic and Tertiary [2] [3] [4]. The stratigraphic layout of the Anza basin included Precambrian basement rocks overlain by Upper Jurassic-Cretaceous clastic [4] rock with minor outcrops of limestone within the Anza rift system. However, due to post-rifting occurrences, volcanic and sedimentary units [3] were deposited including sandstone, mudstone and siltstone. Anza basin has dominantly continental, fluvial and lacustrine [2] [3] [4] sediment provenance with sandstone beds. Marine facies occasionally occurred in some sections which explain the paleoenvironmental conditions in the region. This research aimed to determine the hydrocarbon potential of the Anza basin using data from four drilled wells (Figure 1(b)) namely: Chalbi-3, Sirius-1, Ndovu-1 and Kaisut-1. The target depth interval has Cretaceous-Tertiary rocks which were assessed using petrophysical and geochemical analysis of source rocks. Geochemical study is imperative science for unravelling the properties of source rock [5] and reduces the uncertainty inherent in petroleum exploration regarding project viability [6]. Therefore, it revolved around resource origin and producibility [7] [8] that included describing organic facies associated with paleo-parameters [9], burial history and post-depositional geologic processes that occurred in the basin.  Anza region is generally a product of post-rifting [10] depositional sequences that occurred in the Kaisut and Ndovu sag sub-basins. To assess the source rocks parameters, geochemical analyses were applied to determine total organic carbon (TOC), generating source potential (S2), Production Index (PI), Oxygen Index (OI), Hydrogen Index (HI) and T max [9]. According to Rop [2], the Cretaceous sedimentary sequences of the Anza Basin, those of the Abu Gabra ( Figure   2) (South Sudan) and Sharaf Formations (Sudan) share a common tectonic setting and lithological composition which triggered this study to assess their potential.

Methods
Petrophysical study involved evaluation of subsurface rock physical features in order to portray source rock properties associated with petroleum accumulation that included porosity, fluid inclusions, resistivity and shalyness. Gamma-ray log illustrated shale volume ratios [11], neutron-density log [12] [13] gave rock data for porosity calculation and the deep resistivity log was then used to compute for water saturation [14] [15]. The objective of formation evaluation was to quantitatively locate and determine the shale volume, effective porosity and water saturation of the source rocks using Technlog software. The depth intervals with high shale content were sampled for geochemical analysis. Total Organic Carbon (TOC) analysis investigated the organic richness and spatial distribution [8] of organic components in the samples, which is an initial step for evaluating petroleum characterization [6] [16]. 1 mg sample was pulve-International Journal of Geosciences rized and treated with hot 10% HCl to remove carbonate [17] contaminants. Then heated at 1200˚C in an inducing furnace. TOC is expressed as a percentage of the dry weight of the organic content in the sample, denoted as wt% TOC [18] [19]. Rock-Eval Pyrolysis was subsequently undertaken for over 0.5% TOC [20] to assess their kerogen type and thermal maturity. The pyrolysis process is the programmed heating [21] of source rock in order to break its complex composition [22] to mimic subsurface natural phenomena. The resultant parameters were expressed in mg/g of rock as S1, S2, S3 and T max . Gas Chromatography-Mass Spectrometry (GC-MS) was used to investigate mass spectra and mass to charge (m/z) ratios for associated compounds in order to characterize the biomarker compositions.

Total Organic Carbon
Kaisut-1 well samples have siliciclastic sediments with poor shale content. It had the lowest margin of organogenic sedimentary rocks below 0.5% TOC threshold [8]     ) illustrated that both samples occur within the gas window [24].

Rock-Eval Pyrolysis
Further analyses show samples were kerogen types III and IV [9], respectively. HI range between 155 and 1010 mg HC/g TOC ( Figure 5(a)) reflect oil-bearing zone enriched with OM [29]. HI extend from 765 -1010 mg HC/g TOC in the depth section from 1497 -1521 m suggested organic-rich oil-prone type 1 [26] [30] [31] while the rest of the samples are of oil-prone Type II ( Figure 5(b)).
The low PI indices (0.01 -0.05) indicated the origin of extractable OM (S1) to be inherent source rocks and have not migrated [24] from other places. S2 versus TOC ( Figure 5(c)) illustrated various kerogen types from type I-III of the source rocks. All the samples except 1520 m depth had mature Cretaceous shale deposits. Accordingly, Kerogen type I -II (oil) and, type II -III (oil-gas condensate) and III (early gas) [21] [22] occurred.

Gas Chromatography-Mass Spectrometry
Sirius  The high abundance of C 30 αβ hopanes relative to C 29 norhopane, 17α (H)trisnorhopane (Tm) suggests derivation from clastic source rocks. Isomerisation ratios of the C 31 and C 32 αβ-hopanes [36] flanged from 0.50 -0.56 indicating that they were mature. This corresponded to T max and other maturity biomarkers such as the low C 30 moretane/hopane ratios.
All samples contain C 21 to C 29 steranes. However, few in elemental numbers relative to pentacyclic terpanes as shown by the low sterane/hopane ratio The samples display high C 28 /C 29 sterane ratio (Figures 7(a)-(d)) in the range 0.4 -1.25 indicating moderate heterogeneity of phytoplankton assemblages [39] in the OM. The extracts generally show dominance of C 28

Discussion
Organic richness and maturity of source rocks have increasingly been used to ascertain the occurrence of HC during the exploration stage. In this study, source rocks were visually examined for shale content and sampled for geochemical analysis. The geochemical signatures associated with source rock types provided information about the depositional environment and their organic origin, burial history and maturity. The four wells namely Kaisut-1, Ndovu-1, Chalbi-3 and Sirius-1 were case studied to assess the HC parameters occurring in the Anza Basin.
Kaisut-1 well was primarily a shallow well with a total depth of 1450 m. It encountered quartz sandstones with minimal shale content of Tertiary origin that resulted in very poor source rocks. Ndovu-1 well samples were from the Paleocene-Cretaceous age with sandstone-mudstone bearing shale deposited sediments.
However, evaluation provided very poor ratios of wt% TOC. For probable depths, well sections for up to Mesozoic should be analyzed.
Chalbi-3 had a confirmable volume of kerogen type III and mature source rocks but with very low HI compared to OI. Both samples were gas prone but had little extractable ratios of HC. Sirius-1 well has deep well intervals with good shale volume, high wt% TOC, and producible mature oil content. Sirius-1 well was the most productive as per both the petrophysical characterization and geochemical evaluation of the Cretaceous shaly rocks. Therefore, the correlation model portrayed good source rock depositions and enrichment of mature extractable HC content.

Conclusions
This study was geared towards unravelling the hydrocarbon potentiality of Anza well profile revealed varied but increasing volumes of shale content which suggested potential source rock sections occurred. Sirius-1 well has potentially extractable oil at depth intervals from 2540 -2597 m. The sections act as reservoir depth with over 30% porosity that allowed for the accumulation of HC. The accumulation of good source rocks within the sampled depths indicates the presence of an active petroleum system. However, storage and handling of the drill or core cuttings required good storage conditions in order to preserve samples for future assessment. Anza basin stratigraphic layout trend southwards in sediment deposition which implies a deeper burial history sequence for potential source rocks. Petrophysical study for Sirius-1 well revealed higher shale ratio content extending to deeper depths which could be further studied to map the source rock enrichment. In addition, future study is encouraged to explore suitable trapping mechanisms that were present and/or absent at the time of petroleum generation, migration, accumulation, and preservation.