Muglad Basin Research Articles

The application of diamondoids indices for oils from Block 4 of the Muglad Basin in the middle of Africa

The abundances and distribution diamondoids were studied with a series of crude oil samples from Block 4 of the Mugald Basin in Sudan, to investigate the validity of various diamondoid parameters on the oil source, thermal maturity and biodegradation information. All crude oils of Block 4 were generated by lacustrine source in lower part of the Abu Gabra Formation as a whole, and can be further divided into two crude oil groups: oil group of the Neem-Azraq Uplift and oil group of K-3 well and B-1 well. They are all mature oils within oil window and four crude oils from the Neem-Azraq Uplift were slightly biodegraded. The concentrations of diamondoids in oils of K-3 well and B-1 well, especially the concentration of diamantanes, are higher than those of oils from the Neem-Azraq Uplift. The concentrations of diamondoids are mainly controlled by source of oil, while the influence of thermal maturity and biodegradation may be limited. The isomerization ratios as indicators of thermal maturity are inapplicable at the mature stage, but DMDI-2, 4,8/3,4-DMD and 1-EA/3-EA can clearly distinguish the two groups of crude oils. The concentration ratios of oils from K-3 and B-1 wells are significantly lower than these of oils from Neem-Azraq Uplift, and these concentration ratios including newly proposed parameters such as MAs/DMAs, DMAs/TMAs, D/MDs, MDs/DMDs and so on, are effective indicators on organofacies and oil group division within oil window.

Petroleum Potential Prospectivity of Muglad Basin, South Sudan: A Case of Source Rocks Characterisation in the Drilled Kaikang West-1 Well

This study focuses on Prospectivity of Petroleum Potential of Muglad basin, South Sudan, with the help of petroleum source rocks characterisation in the drilled Kaikang West-1 Well based on the organic matter quantity, quality, and the thermal maturation generation capability of the organic matter disseminated in the analysed rock samples. Muglad basin is a major petroliferous Western and Central African Rifts System (WCARS) member, with estimated reserves of 2,053 mm bbl. Muglad Basin comprises thick sandstones of Aradeiba and Bentiu Formations, considered to be the main petroleum prospectivity targets, with trapping mechanism being structural faults and lithological anticlines. The organic matter contents were determined directly from laboratory analyses of the source rock samples with the help of seismic and gamma ray profiles, total organic carbon (TOC wt %), maturity indices (OI, HI and PI), temperature maximum (Tmax °C), porosities and other sedimentological parameters. This study involved a series of analytical geochemistry and petro-physical studies to ascertain a number of effective source rock samples from the well cores which were then analysed in terms of TOC, OI, PI, HI, S2, S1 and Tmax to determine oil/gas prone samples (resource areas). These were then distinguished from strata with very high organic matter samples as well as very high TOC to help identify for possible source rock characterizations within the lithology pertaining to the well in terms of potential source-reservoir-seals combinations. The Rock-Eval pyrolysis data were useful in assessing and evaluating the type of organic matter, thermal maturity, and the generation capability of source rocks for hydrocarbon exploration rationale. The analyses revealed that some strata, within the sampled well data, have high hydrocarbon generation potential with the existence of commercial hydrocarbon production

The analysis of the fault system in the passive rift basin—an example from the Muglad Basin, central Africa

Introduction: The Muglad basin, located on the southern Central Africa Shear Zone, is an intracontinental passive rift basin. The Fula sag, situated in northeastern of the basin, is a hydrocarbon-rich depression. As exploration advanced, the Fula sag has entered the stage of fine exploration for complex fault blocks. Therefore, studying the characteristics and evolution of faults can aid in deepening the understanding of hydrocarbon accumulation rules in the area, and guide the next steps of oil and gas exploration. Previous studies have primarily focused on the division of fault level and their role in hydrocarbon accumulation, but have not delved into the geometric features and evolution of the fault system across the entire Fula sag.Methods: In this paper, we systematically studied the fault system and its hydrocarbon control within the sag using petroleum seismic reflection profiles, as well as logging data.Results and Discussion: And the conclusions are as followed: 1) tectonic features in diverse areas of the Fula sag vary significantly from a shovel-like half-graben to the asymmetric graben, and faults in the study area can be classified into five combination features. 2) Three complete rift-sag cycles have developed since the early Cretaceous, with continuously active faults controlling the formation of “inherited” sag. 3) The strong activity of faults in the first and second riftting period led to the development of mainly AG-Formation source rocks and middle reservoir-forming assemblages in the Fula sag. Additionally, the formation and distribution of oil and gas reservoirs in the sag were controlled by the faults in the central fault zone and the western steep slope zone. Furthermore, hydrocarbons migrated and formed reservoirs through the main faults in the central fault zone and the western main fault. Our research will provide a valuable insight for understanding the petroleum geological characteristics of basins with a similar genesis mechanism.

The geological composition of rifts in Sudan as related to oil and gas content

Gradual increase in hydrocarbon production by the Saudi Arabia, Russia and the USA has led to the fact that today their share in the global production volume is about 42%, according to British Petroleum. At the same time, the market volume for small players, focused primarily on domestic demand and meeting the needs of their nearest neighbors, is falling proportionally. A striking example of this trend is the Republic of Sudan, on whose territory a small number of oil and gas fields are being developed, characterized by a very complex structure associated with rift sedimentary basins, which began to be studied in detail only a few years ago. The first comprehensive regional geological work began only at the end of 1974. As of today, all discovered oil reservoirs are located within rift zones, and the most promising one is the Muglad Basin, which contains eleven discovered oil fields connected with the terrigenous deposits of Upper Cretaceous and Miocene. Based on the study of seismic and core data, sequence stratigraphic and sedimentological models were built of the main depositional structures of the Muglad Basin, the potential was evaluated of the discovery of new hydrocarbon deposits. Keywords: rift valley; fields sedimentary complexes; Muglad Basin; Sudan; sequence stratigraphy.

Lithofacies discrimination using seismic anisotropic attributes from logging data in Muglad Basin, South Sudan

Abstract The identification of formations in anisotropic reservoirs using seismic reflection data and logging data may lead to misrepresentations of the actual formations. Lithofacies discrimination intrinsically has ambiguity, and the depositional sequences of the study area comprise shales, fine-grained sands, and silts. So it needs to reduce the uncertainty of the lithofacies discrimination using anisotropic parameters. This study proposes an approach involving seismic anisotropic parameters to discriminate between different lithofacies. We calculate four anisotropic parameters (ε, δ, γ, η) from logging data (V p, V s, and density) and then employ these for lithofacies discrimination. We compared our results to lithofacies discrimination based on traditional parameters such as V p/V s ratio, clay volume, and water saturation. Using field data from Muglad Basin in South Sudan, we show how the suggested parameters could be used to identify eleven zones with distinct lithofacies. According to the anisotropic parameters, the lithofacies discrimination results are similar to other logging data, and it is easier to separate the lithofacies than petrophysical data. Furthermore, we introduce a new parameter, i.e., the difference between the normalized anisotropic δ parameter and clay volume, which can be used as a possible indicator for heavy oil reservoirs. The new parameter matches well with water saturation in the field data application.

Tectonic evolution and subsidence history of the Cretaceous basins in southern Egypt: The Komombo Basin

AbstractThe structure and tectonic evolution of the Cretaceous rift basins of southern Egypt are poorly understood. In this study, the tectonostratigraphy of the Komombo Basin has been determined using seismic, well and biostratigraphic data. The tectonostratigraphy of the basin is compared to the Kharit, Nuqra and Beni Suef basins in Egypt as well as Muglad Basin in Sudan. The Komombo Basin is a 58 km long, 28 km wide NW–SE trending half‐graben infilled with 2200 m of Berriasian‐Maastrichtian sediments and overlain by 400 m of Pliocene sediments. Four Berriasian to Maastrichtian syn‐rift and post‐rift sequences and three Pliocene channel systems of Nile sediments have been identified. Moreover, a series of normal faults, negative flower structures, reverse faults and folds are mapped in the basin. Backstripping reveals two rift phases during the Berriasian‐Barremian and Turonian‐Santonian, respectively. Additionally, the tectonic subsidence curves indicate that two major unconformities have occurred during the Aptian‐Albian and Maastrichtian‐Pliocene, which are correlated with a basement uplift during the Albian‐Cenomanian and the Oligocene‐Miocene flank uplift related to the opening of the Red Sea, respectively. The rift episodes are attributed to far‐field stress changes resulting from the initial opening of the South Atlantic and followed by the NW part of the African plate colliding and anticlockwise rotating into Europe. The highest β factors (1.20–1.11) for both rift phases are found at the centre of the basin. The rift phases thinned the crust from 32.5 to 28.2 km and 31.9 km in the depocenter and the western flank of the basin. The Komombo Basin has a similar rift history, stratigraphy and structural style to the Kharit, Nuqra and Mugland basins. All of these basins witnessed two major rift phases in the Early and Late Cretaceous, whereas the Beni Suef Basin encountered strike‐slip tectonic events in the Late Cretaceous.

Discovery of Early Mesozoic Magmatism in the Northern Muglad Basin (Sudan): Assessment of Its Impacts on Basement Reservoir

The crystalline basement in the Central African Rift System (CARS) has been confirmed as a good unconventional reservoir in the surrounding basins of the Muglad area, Sudan. This study has recognized at least five Early Mesozoic intrusions for the first time at the northern margin of the Muglad Basin. Field and petrographic investigations show that they are mainly granite, syenite, diorite, and monzonite, with dominant alkali feldspar, plagioclase, quartz, and minor hornblende, biotite, and magnetite. Zircon internal structures, Th/U ratios, and rare earth element (REE) patterns indicate their magmatic origin. A total of 210 zircons from five samples were analyzed using LA-ICP-MS and they yielded U-Pb ages from 195.0 ± 6 to 225.0 ± 3 Ma, belonging to the Late Triassic-Early Jurassic. These results suggest that the Muglad Basin basement is not universally Precambrian as previously considered. The older basement was intruded and modified by Early Mesozoic magmas as evidenced by field contacts and our dating results. These magmatic events produced diverse Mesozoic igneous rocks prior to the formation of the Muglad Basin (Early Cretaceous), becoming new members of the crystalline basement. This composite basement then experienced prolonged weathering and fracturing for 65–95 Ma, resulting in porous and permeable weathered layers or fractured zones, making the basement a good unconventional reservoir for oil and gas.

Integrated study between Sedimentology and Conventional core analysis for some core samples, Bentiu Formation, Muglad Basin, Sudan,

Integrated study between Sedimentology and Conventional core analysis for some core samples, Bentiu Formation, Muglad Basin, Sudan,

Integrated study between Sedimentology and Conventional core analysis for some core samples, Bentiu Formation, Lower Cretaceous, Muglad Basin, Sudan

Integrated study between Sedimentology and Conventional core analysis for some core samples, Bentiu Formation, Lower Cretaceous, Muglad Basin, Sudan

Reservoir quality and its controlling diagenetic factors in the Bentiu Formation, Northeastern Muglad Basin, Sudan

The Abu Gabra and Bentiu formations are widely distributed within the interior Muglad Basin. Recently, much attention has been paid to study, evaluate and characterize the Abu Gabra Formation as a proven reservoir in Muglad Basin. However, few studies have been documented on the Bentiu Formation which is the main oil/gas reservoir within the basin. Therefore, 33 core samples of the Great Moga and Keyi oilfields (NE Muglad Basin) were selected to characterize the Bentiu Formation reservoir using sedimentological and petrophysical analyses. The aim of the study is to de-risk exploration activities and improve success rate. Compositional and textural analyses revealed two main facies groups: coarse to-medium grained sandstone (braided channel deposits) and fine grained sandstone (floodplain and crevasse splay channel deposits). The coarse to-medium grained sandstone has porosity and permeability values within the range of 19.6% to 32.0% and 1825.6 mD to 8358.0 mD respectively. On the other hand, the fine grained clay-rich facies displays poor reservoir quality as indicated by porosity and permeability ranging from 1.0 to 6.0% and 2.5 to 10.0 mD respectively. A number of varied processes were identified controlling the reservoir quality of the studies samples. Porosity and permeability were enhanced by the dissolution of feldspars and micas, while presence of detrital clays, kaolinite precipitation, iron oxides precipitation, siderite, quartz overgrowths and pyrite cement played negative role on the reservoir quality. Intensity of the observed quartz overgrowth increases with burial depth. At great depths, a variability in grain contact types are recorded suggesting conditions of moderate to-high compactions. Furthermore, scanning electron microscopy revealed presence of micropores which have the tendency of affecting the fluid flow properties in the Bentiu Formation sandstone. These evidences indicate that the Bentiu Formation petroleum reservoir quality is primarily inhibited by grain size, total clay content, compaction and cementation. Thus, special attention should be paid to these inhibiting factors to reduce risk in petroleum exploration within the area.

Integrated petrophysical and petrographical studies for characterization of reservoirs: a case study of Muglad Basin, North Sudan

Petrography, scanning electron microscopy, X-ray diffraction, and both conventional and special core analyses are applied to precisely reservoir characterize the Lower Cretaceous Bentiu and Abu Gabra Formations of the Muglad Basin, which is among the largest hydrocarbon reservoirs in South Kordofan, SW North Sudan. Based on this integrated study, the Abu Gabra–Bentiu sequence comprises four petrographical microfacies, which consist of two reservoir rock types (RRTs). RRT1 is composed of quartz arenites and RRT2 is composed of quartz wackes. The greatest storage, flow capacities, and reservoir quality are assigned for RRT1 due to its good-to-excellent porosity (average ∅ = 26.7%), permeability (average k = 1365 md), reservoir quality index (RQI, average = 1.43 μm), flow zone indicator (FZI, average = 3.66 μm) and discrete rock type (DRT, average = 13). The relatively low-to-fair reservoir quality of the Abu Gabra Formation (average ∅ = 13.2%, average k = 14.7 md, average RQI = 0.17 μm, average FZI = 1.05 μm, and average DRT = 10) is due to authigenic kaolinite and siderite content, compaction and cementation by silica and clay patches.

Sedimentary characteristics of the shallow water delta in rifted lacustrine basin: A case study in the Aradeiba Formation, Unity Sag, Muglad Basin

Sedimentary characteristics of the shallow water delta in rifted lacustrine basin: A case study in the Aradeiba Formation, Unity Sag, Muglad Basin

Sedimentology, petrography, and reservoir quality of the Zarga and Ghazal formations in the Keyi oilfield, Muglad Basin, Sudan

The Zarga and Ghazal formations constitute important reservoirs across the Muglad Basin, Sudan. Nevertheless, the sedimentology and diagenesis of these reservoir intervals have hitherto received insignificant research attention. Detailed understanding of sedimentary facies and diagenesis could enhance geological and geophysical data for better exploration and production and minimize risks. In this study, subsurface reservoir cores representing the Zarga formation (1114.70–1118.50 m and 1118.50–1125.30 m), and the Ghazal formation (91,403.30–1406.83 m) were subjected to sedimentological (lithofacies and grain size), petrographic/mineralogic (thin section, XRD, SEM), and petrophysical (porosity and permeability) analyses to describe their reservoir quality, provenance, and depositional environments. Eight (8) different lithofacies, texturally characterized as moderately to well-sorted, and medium to coarse-grained, sub-feldspathic to feldspathic arenite were distinguished in the cored intervals. Mono-crystalline quartz (19.3–26.2%) predominated over polycrystalline quartz (2.6–13.8%), feldspar (6.6–10.3%), and mica (1.4–7.6%) being the most prominent constituent of the reservoir rocks. Provenance plot indicated the sediments were from a transitional continental provenance setting. The overall vertical sequence, composition, and internal sedimentary structures of the lithofacies suggest a fluvial-to-deltaic depositional environment for the Ghazal formation, while the Zarga formation indicated a dominant deltaic setting. Kaolinite occurs mainly as authigenic mineral, while carbonates quantitatively fluctuate with an insignificant amount of quartz overgrowths in most of the analyzed cores. Integration of XRD, SEM, and thin section analysis highlights that kaolinite, chlorite, illite, and smectite are present as authigenic minerals. Pore-destroying diagenetic processes (e.g. precipitation, cementation, and compaction etc.) generally prevailed over pore-enhancing processes (e.g. dissolution). Point-counted datasets indicate a better reservoir quality for the Ghazal formation (ɸ = 27.7% to 30.7%; K = 9.65 mD to 1196.71 mD) than the Zarga formation (17.9% to 24.5%; K = 1051.09 mD to 1090.45 mD).

Reply to the discussion on “Influence of structures on drainage patterns in the Tushka region, SW Egypt. Journal of African Earth Sciences 136, 262–271 by C.A. Robinson, H. El-Kaliouby, E. Ghoneimˮ by B.S. Nabawy

The present study aims at conducting a detailed reservoir characterization of the Early Cretaceous Bentiu and Abu Gabra formations in Muglad basin which is one of the most prospective hydrocarbon basins in South Kordofan, SW Sudan. This can be achieved through integration between well logging (conventional), petrography (thin sections, and scanning electron microscopy SEM), and core data.Based on this integrated study, the Abu Gabra-Bentiu sequence is composed of two reservoir rock types (RRTs). RRT1 is composed of quartz arenite, whereas RRT2 is composed of quartz wacke. The best storage and flow capacities and the best reservoir quality are assigned for RRT1 due to its good to excellent porosity (20.0 ≤ ∅ ≤ 34.1%), permeability (138 ≤ k ≤ 4140 md), reservoir quality index (0.61 ≤ RQI ≤ 2.91 μm), and flow zone indicator (2.37 ≤ FZI ≤ 6.12 μm) values. This rock type is mostly assigned to two hydraulic flow units (HFU-1, and HFU-2) of Bentiu Formation which comprises 95% of the flow capacity of the sequence. The average reservoir parameters of the studied sequence, including shale volume, effective porosity and hydrocarbon saturation, equal to 31.6, 16.2 and 39.5%, respectively with 29.5 m as a total net-pay thickness.Petrographically, the relatively low contribution of the Abu Gabra Formation is due to its authigenic mineral content, compaction, and cementation.

Rock typing and hydraulic flow units as a successful tool for reservoir characterization of Bentiu-Abu Gabra sequence, Muglad basin, southwest Sudan

The present study aims at conducting a detailed reservoir characterization of the Early Cretaceous Bentiu and Abu Gabra formations in Muglad basin which is one of the most prospective hydrocarbon basins in South Kordofan, SW Sudan. This can be achieved through integration between well logging (conventional), petrography (thin sections, and scanning electron microscopy SEM), and core data.Based on this integrated study, the Abu Gabra-Bentiu sequence is composed of two reservoir rock types (RRTs). RRT1 is composed of quartz arenite, whereas RRT2 is composed of quartz wacke. The best storage and flow capacities and the best reservoir quality are assigned for RRT1 due to its good to excellent porosity (20.0 ≤ ∅ ≤ 34.1%), permeability (138 ≤ k ≤ 4140 md), reservoir quality index (0.61 ≤ RQI ≤ 2.91 μm), and flow zone indicator (2.37 ≤ FZI ≤ 6.12 μm) values. This rock type is mostly assigned to two hydraulic flow units (HFU-1, and HFU-2) of Bentiu Formation which comprises 95% of the flow capacity of the sequence. The average reservoir parameters of the studied sequence, including shale volume, effective porosity and hydrocarbon saturation, equal to 31.6, 16.2 and 39.5%, respectively with 29.5 m as a total net-pay thickness.Petrographically, the relatively low contribution of the Abu Gabra Formation is due to its authigenic mineral content, compaction, and cementation.

Development characteristics and exploration significance of basement reservoirs in block-6 of the Muglad Basin, Sudan

Development characteristics and exploration significance of basement reservoirs in block-6 of the Muglad Basin, Sudan

Characteristics of transfer structure and hydrocarbon accumulation control of Fula western steep slope belt in the Fula sag, Muglad Basin, Sudan

Characteristics of transfer structure and hydrocarbon accumulation control of Fula western steep slope belt in the Fula sag, Muglad Basin, Sudan

The hydrocarbon accumulation potential of Upper Cretaceous to Paleogene in the northern Kaikang trough, Muglad Basin

This paper investigates the characteristics of sedimentary faces, source rocks, and hydrocarbon accumulation in detail within the Paleogene and Upper Cretaceous in the northern Kaikang trough, Muglad Basin. Analysis shows that the fluvial floodplain, delta, and shore-shallow lake facies are well developed in the main formations and several reservoir-cap assemblages are formed. Research on geochemical indicators, hydrocarbon generation, and expulsion potential of source rocks indicated that the thickness of good source rocks in Paleogene ranges from 50 to 200 m and TOC value can reach 0.5–1.3%, but it is immature and has no hydrocarbon generation potential. Nevertheless, the Upper Cretaceous source rocks are mostly matured, but its hydrocarbon generation is limited because of lower TOC (only 0.5–0.8%) and thinner thickness (only 10 m). The main effective source rock is the AG Group in the Lower Cretaceous, which is distributed throughout the area. The evolutionary history shows that most of structures in the central troughs lack hydrocarbon potential, because they were formed since the Paleogene, which are later than the main accumulation period of the AG source rock. The fault terrace zones on both sides of the Kaikang trough have obtained petroleum discovery, but the distribution of oil layers is much complicated. Hydrocarbon accumulation is controlled by formation dips, fault activity intensity, and fault lateral docking characteristics. The weaker active fault block in late period and more effective trap are the key factors to hydrocarbon enrichment at the fault terrace zones. There are two typical reservoir-forming modes; one is the small fault distance reservoir-forming mode of the lower primary reservoir, and the other is the secondary reservoir-forming mode of the upper and middle combination.

Seismic interpretation and tectonic regime of Sudanese Rift System: Implications for hydrocarbon exploration in Neem field (Muglad Basin)

The Muglad Basin is located in the hinterland of the Africa Continent. The weakness zones on the rigid basement of Sudanese Rift System and the relative movement occurring under the united action of regional stress field played controlling roles in the structural framework and its evolution in the overlying sedimentary covers. It is interesting that the present geological locations of the Central Africa rift system including the Muglad Basin are well coincident with the inhomogeneity of the Africa Continent. This further proved the controlling roles of the basement on the development of the basin. The alternately arranged high-and-low structural framework on the basement, reflected by seismic data, not only proved the large thickness variation of the sediment infills within the depression from south to north but also reflected the critical action of pull-apart movement on the structural evolution of the basin. The Cretaceous NNW structural belts were formed earlier and thus controlled the development of the early paleostructures. The exploration achievements of the Muglad Basin have proven good oil potential in this kind of structural belts. The NW structural belts in the Kaikang Trough were strongly active predominantly during the Paleogene, resulting in many new structures, whose oil potential is relatively poorer than the former ones, with only secondary oil accumulations being the key targets of exploration. Through tectonic and structural analysis, a complete overview of the structuration of the basin was displayed, from which we can observe the important roles of the tectonic and structural activities on the forming of the petroleum geological conditions of the Muglad Basin. This understanding favors prediction of the source rock, reservoir and seal, and also favors analysis and assessment of the forming history and oil bearing conditions of the structural belts.

New insights on Muglad’s Cretaceous source rocks: a paleo-geographic review & organic geochemical characterization, Muglad basin, Sudan

Pyrolysis, chromatographic, and isotopic techniques were applied to study a suite of (174) rock cuttings from Muglad’s block 2 & 4, aiming at identifying and fully characterizing the potential source rock/s in the basin. Two source rock units were recognized and described as good-very good for hydrocarbon generation in the study area. These include the middle Early Cretaceous Abu Gabra and the top Late Cretaceous Baraka formations. The former consists of a good-very good organic rich shales (TOC = 1.0-4.0 %, S2 >20 mg HC/g TOC), of mixed kerogens dominated primarily by the oil prone type-I (HI = 600 mg/g) in association with few type-III, and is currently thermally mature for hydrocarbon generation in the basin peripheries and over mature in the centre. The Baraka displays a wide hydrocarbon generative potential ranging from fair to very good (TOC = (0.5-4.0%) and S2 yield of (2.0-20 mg HC/g TOC), of mainly type-II oil and gas prone kerogen (HI = 450 mg/g), and thermally mature for hydrocarbon generation in the basin centre only.Biomarker characteristics of the analyzed samples reveal three main organofacies units; a (I) freshwater oxic to sub-oxic clay-rich Early Cretaceous distal lacustrine, (II) a highly anoxic, and clay-poor Late Cretaceousdistal marine, and a (III) proximal lacustrine and/marine of both E. and L. Cretaceous. Organofacies-I shows relatively high ratios of: [Pr/Ph (1.2-3.02), C26/C25 tricyclic terpanes (1.11-3.12), Ts/Tm (0.95-1.33), gammacerane indices (0.14-0.50), and diasterane/regular steranes] with low: [tri- and tetracyclic terpanes, C17/C25 n-alkanes (1.0-1.5), C29/C30 hopanes (0.55-1.14), and pregnanes & homopregnanes]. Organofacies-II inversely, is characterized by very low [Pr/Ph ratios (0.37-1.0) suggesting extreme anoxic conditions, C26/C25 tricyclic terpanes between (0.50-1.0), Ts/Tm (0.21-0.50), Gammacerane indices (0.05-0.22), and low diasterane/regular steranes (0.34-0.66)] with high: [tricyclic terpanes content dominated by the C23 variety, C24 tetracyclic terpanes, C17/C25 n-alkanes ratios (3.7-5.12), C29/C30 hopanes (0.4-1.11), and abundant pregnanes and homopregnanes]. Organofacies-III is amerely proximal sub-facies of the former two differentiated basically on the basis of the redox conditions of their corresponding depositional environments and amount of terrigenous organic matter supply. The isotopic data is fairly consistent with the biomarkers in delineating the same three organofacies units. We relate the marine input into Muglad basin during the L. Cretaceous to the global L. Cretaceous sea transgressions in Africa and thus foresee a booming new exploration opportunity in the basin.