Melut Basin Research Articles

Geochemical characteristics and genetic types of crude oils from a variety of geological reservoir rocks (Cretaceous–Palaeogene) in the Melut Basin, southern Sudan based on biomarker and carbon isotope composition

This study uses physical and geochemical characteristics of crude oil samples representing the Cretaceous and Palaeogene reservoir sequence of the Melut Basin, southern Sudan to gain information about source rock properties, including organic matter characters, depositional environment and thermal maturity. The overall results show that the Melut Basin's oils have API values between 14.6° and 33.3° and indicate that most of oils are not biodegraded; except one heavy oil sample with low API gravity of 14.6°, which is likely biodegraded. The studied oils were generated from clay‐rich source rocks, containing a blend of organic matter derived primarily from a mixed organic matter of aquatic and terrestrial origin and deposited in a lacustrine setting under suboxic to relatively oxic conditions as demonstrated by their biomarker and carbon isotopic compositions (δ13C). The biomarker maturity indicators show that most of the Melut Basin's oils were generated in the main stage of oil generation, exhibiting a range of peak‐mature to late‐mature. The biomarker environmental indicators reveal that the shale source rocks of the Al‐Gayger and Galhak formations contributed to these oil samples.

Geochemical investigation and basin modelling of the Al renk shale formation in the Melut Basin, south Sudan: Implications for estimation of thermogenic gas generation potential

This study uses organic geochemical and basin modelling results to examine the potential for thermogenic gas generation from oil-to-gas conversion of the organic-rich Lower Cretaceous Al Renk shales in the Melut Basin, South Sudan. The overall geochemical results show that the Al Renk shales are considered good gas-source rocks with total organic carbon (TOC) content >1 wt % and a low hydrogen index (i.e., HI < 150 mg HC/g TOC; mainly Type III kerogen). This finding contrasts with the source of organic matter and biomarkers related to the depositional environment. Based on biomarker indicators, the Al Renk shales contains a mixture of aquatic organic matter with some terrigenous land plants and was deposited under suboxic to relatively oxic settings in a lacustrine environment. The presence of mixed aquatic and terrigenous organic matter in lacustrine shale sediments suggests a mix of Types II and III kerogen as the original organic matter input during deposition. The geochemical and optical maturity indicators represent late-mature oil to gas generation windows, implying that the Al Renk shale has substantial thermogenic gas generation potential. Therefore, high thermal maturation is a crucial factor in drastically altering the original organic matter (OM) and decreasing HI values (conversion of kerogen to hydrocarbons). The kerogen to oil conversion and the subsequent cracking of the retained oil into thermogenic gas have been simulated by the burial/thermal/generation models in the Agordeed-1 well. These models show that nearly 10–50% of kerogen was transformed into oil during the Late Cretaceous (78–68 Ma), correlating with the early to peak mature of oil generation window (0.62–0.85 %Ro). Moreover, oil was expelled from the Al Renk source rock system during the Late Cretaceous to Late Eocene. From the Late Eocene until the present, significant amounts of residual oil were cracked into gas due to the maturation of the gas generation window (>1.30 Easy % Ro), which is ideal for wet gas generation. Consequently, the findings of this study advocate for conventional gas exploration in the Melut Basin's deeper stratigraphic succession, where the Al Renk Shale Formation has reached a high maturity level of the gas generation window.

Investigation of the petroleum geology and sequence stratigraphy in Melut Basin, South Sudan: a case study using well logs and basin modeling

Investigation of the petroleum geology and sequence stratigraphy in Melut Basin, South Sudan: a case study using well logs and basin modeling

Geochemical characteristics of crude oils and hydrocarbon accumulation in the Palogue Oilfield, Melut Basin, South Sudan

The Palogue Oilfield is the largest oilfield in the Melut Basin, an important petroliferous rift basin in Africa. Geochemical analyses, including gas chromatography and gas-mass chromatography were adopted to analyze the biomarker composition and geochemical characteristics of oils from the Palogue Oilfield and the neighboring Moleeta and Jamous lows. Oil-oil correlations were performed for the Palogue Oilfield and the Moleeta/Jamous lows, and the hydrocarbon accumulations of the Palogue Oilfield were studied based on the oil maturities, thermal evolution modelling of the Moleeta/Jamous lows and the petroleum system analysis of the Melut Basin. Geochemical analysis indicates that the oils of the Moleeta/Jamous lows are derived from terrestrial higher plants, with the low ratios (<1) of light n-alkanes to heavy n-alkanes (∑nC21-/∑nC22+) and the predominance of C29 regular sterane, but there still are some geochemical differences in distribution shape of n-alkanes, paleoenvironments and maturities in these two lows. The oils of the Palogue Oilfield have mixed-source features and their geochemical characteristics are more like those of the Jamous low, and a few oils are like the oils in the Moleeta low. The Jamous low has a larger area and higher thermal maturity than the Moleeta low, and the abundant oils generated by the Al Renk source rocks (upper part of early Cretaceous) in the Jamous low are the primary contributors to the formation of the giant Palogue Oilfield. The vitrinite reflectance equivalent (Rc) converted by the methyl phenanthrene ratio indicates that the oil maturities of the Palogue Oilfield range from 0.65% to 1.07%. Thermal evolution modelling of the Moleeta/Jamous lows indicates that the Jamous low generated and expelled hydrocarbons earlier than the Moleeta low. The maturity of Al Renk source rocks reached 0.65% at 70Ma (Late Cretaceous) and 1.07% at 38Ma (Eocene) in the Jamous low, and reached 0.65% at 59Ma (Paleocene) and 1.07% at present in the Moleeta low. Thus, the high-maturity oils (Ro> 1.07%) generated by the source rocks in the Jamous low since 38 Ma have not been discovered in the primary production layers of the Paleogene Samma and Yabus Formations in the higher part of the Palogue structure, a drape-anticline developing on a paleo-high between the Jamous and Moleeta lows. The maturity parameter of Ts/(Ts + Tm) shows that the oil maturities from late Cretaceous Formation in the well PS-7 and PS-8 are close to the oils in the Jamous Low and are significantly higher than the oils from the Paleogene Formation in the higher part of the Palogue structure. So, the Cretaceous Formation under the Paleogene pay zones and the Paleogene Formation in the lower part of the Palogue structure likely accumulated high-maturity oils from the Jamous low, which will enhance the exploration potential of the Palogue Oilfield. The petroleum system study indicates that the end of Oligocene (late Paleogene) is the critical moment for the Paleogene hydrocarbon accumulations in the Melut Basin. Whereas, the high-maturity oil accumulations (Ro> 1.07%) in Cretaceous formations in the Palogue Oilfield occurred after 38Ma (late Eocene), when the Al Renk source rocks in the Jamous low started to enter the high thermal evolution stage with the Ro> 1.07%.

3D Seismic Data Interpretation in Gumry Field, Melut Basin

This work describes interpretation of 3D seismic data of Gumry area which is located in Blocks 3 & 7 in Melut Basin the South of Sudan. The data used in this study was acquired by Blue Nile Geophysical Company (BGC) in 2004. The 3D data was interpreted by the author at the SUDAPET CO. LTD in Khartoum – Sudan, Vertical Seismic Profiling data (VSP) and Check-Shot data of the Gumry-1 well were used. The data quality is good and adequate for the objectives. Geoframe software has been used which enables to display inline, cross line and time slice and also enables checking of the consistency of the interpretation from line to line. Synthetic seismogram has been generated for Gumry _1 well for seismic data tie. Time and depth maps have been generated for the top of Yabus Formation. The 3D data interpretation clarifies that there are many oil structures found in study area such as normal faults, faulted trap, graben, half graben, and faulted anticline. Faults system in Gumry area consists of normal faults, trending NW-SE, with some of them dipping SW and others dipping NE. Gumry oil field prospects are mainly fault block structure, located at the block up thrown side of the normal Fault block.

Bearing Capacity Parameters for Pipe Piles in Stiff to Hard Highly Plastic Clays

The design of steel pipe piles in clay soils is faced with insufficient information regarding the parameters used forestimation of their static ultimate load capacity, namely the adhesion factor and plug length.This paper gives guides forthe selection of the mentioned parameters. Direct shear and adhesion tests were performed. The soil tested is highly plasticsilty clay statically compacted in the shear box at constant dry density and varying water content covering dry and wet ofoptimum water content. The adhesion factorwas computed for each test condition. An average value of 0.48 was foundfor the interface resistance when the water content is lower than the plastic limit. The factor was found to increase withincrease in water content for water content higher than the plastic limit.The Plug length data was generated from a construction site in Melut Basin in Southern Sudanwhere steel pipe piles of differentsizes were driven in very stiff to hard silty clay to about the same length and driving records were recorded with extra dataregarding plug lengths. Geotechnical investigation preceded the construction activities. The plug data was analyzed for theeffects of pile diameter and soil conditions on the plug length. Plug length to diameter ratio ranged between 3.8 and 8.0. Pluglength increased linearly with increasing pile diameter and an excellent linear relationship was obtained between the averageplug length for each diameter and pile diameter. Piles with small diameter gave lower resistance to penetration compared withthose with larger diameters.

Formation of the stratigraphic hydrocarbon accumulations of the Upper Yabus Formation in the Northern Sub-basin of the Melut Basin, South Sudan

The Melut Basin is an important petroliferous rift basin in Africa, and a large number of structural hydrocarbon accumulations of the Paleogene Yabus and Samma Formations have been discovered in it. However, there are few published research results and exploration discoveries on stratigraphic hydrocarbon accumulations in the Melut Basin. Based on information from the evaluation of the lithology assemblage, oil-source, migration pathway, preservation condition and the detailed analysis of typical exploration cases, the favorable exploratory interval, formation conditions and accumulation characteristics of the stratigraphic hydrocarbon accumulations have been studied in the northern Melut sub-basin. The sedimentary facies study indicated that the Upper Yabus Formation developed widespread delta front deposits with the lithology assemblage of “sand wrapped by mud”, which was conducive to forming depositional stratigraphic traps dominated by facies change or depositional pinchout. The Adar Formation is a set of mudstone deposition with a thickness of 200–600 m above the Yabus Formation and well sealed the Yabus and Samma hydrocarbon accumulations as the regional top seal. The parameters of organic matter, and the thickness and distribution of source rocks showed that the Al Renk Formation has good source rock quality with an average TOC value of 2.08% wt. and type II kerogen prone to oil generation. The thermal modelling revealed that the Al Renk source rocks continuously generated and expelled hydrocarbon since the Late Cretaceous to the present and provided sufficient oil source for the Upper Yabus stratigraphic traps. The tectonic evolution research showed that the multi-stage rifting cycles made the Melut Basin develop numerous normal faults, which provided essential vertical migration pathways for the hydrocarbon charging of the Paleogene stratigraphic traps. Among these faults, the basinal border faults and the intra-basinal late-rifting faults are the primary hydrocarbon conduit faults. The details of exploration cases showed that the hydrocarbon conduit faults are the key controlling factors for the formation of the Upper Yabus stratigraphic hydrocarbon accumulations, and the stratigraphic traps jointly dominated by lithology change (depositional pinchout) and hydrocarbon conduit faults have low hydrocarbon filling risk. The sandstones of the Upper Yabus Formation are shallow (700–2500 m) and have high porosity with a value of greater than 20% and high oil production of a few hundred to more than 1000 barrels per day. Therefore, the Upper Yabus Formation develops favorable petroleum geology conditions for the formation of stratigraphic hydrocarbon accumulations, and exploring such stratigraphic traps is of great significance to the increasing exploration in the mature northern Melut sub-basin.

Bulk pyrolysis and biomarker fingerprints of Late Cretaceous Galhak Shale Formation in the northern Melut Basin, Sudan: implications on lacustrine oil-source rock

Organic-rich shale samples from the Late Cretaceous Galhak Formation were collected from one well location in the northern Melut Basin, Sudan, and analyzed by integrated organic geochemical and microscopic techniques. The study investigates the nature and preservation conditions of the organic facies and their relevance to petroleum resource potential. Judging from the high total organic contents (total organic carbon (TOC) > 2%), the analyzed Galhak shales are organically rich and include favorable source rocks. The organic richness in these shale sediments may be attributed to enhance the preservation of organic matter under suboxic conditions as implied from the n-alkanes and isoprenoid biomarkers. Biological markers, including of n-alkanes, isoprenoids, terpanes, and steranes, further suggest that the Galhak shale sediments were deposited in a relatively fresh lacustrine environment and received largely aquatic organic matter of plankton and bacteria with little terrestrial plant input. An abundance of aquatic-derived organic matter is consistent with types I and II kerogen as indicated by high Rock-Eval HI values of more than 400 mg HC/g TOC. The hydrogen-rich kerogen types I and II in the analyzed samples suggests an oil-prone source. According to the optical and geochemical maturity indicators, the organic matter in the Galhak oil shale is thermally immature; thus, they have not reached sufficient oil-window maturity for commercial oil generation. Therefore, the deeper parts of the Melut Basin, where the Galhak Formation reached high mature of peak-oil generation window, are recommended for further petroleum exploration and production.

Thermal evolution characteristics of source rocks in the Northern depression of the Melut Basin, South Sudan, and their petroleum geological significance

Thermal evolution characteristics of source rocks in the Northern depression of the Melut Basin, South Sudan, and their petroleum geological significance

Petroleum geological characteristics and hydrocarbon accumulation patterns in the Melut Basin, South Sudan

The Melut Basin is a passive rift basin controlled by the Central African Shear Zone (CASZ), which contains numerous oil-rich rift sub-basins. After 20 years of large-scale hydrocarbon exploration, it has become increasingly difficult to find new discoveries, and it is necessary to deepen the understanding of petroleum geology, identifying new hydrocarbon accumulation patterns and establishing typical oil reservoir models to promote the future exploration in the Melut Basin. In the north Melut Basin, the far-source migration and accumulation pattern has been identified for the Paleogene main producing layer, which provided more than 95% oil reserves in the past years. For the Paleogene far-source accumulation pattern, the capability of hydrocarbon charge from the Al Renk source rocks and the development of oil-source faults connecting Al Renk source rocks and Paleogene reservoir rocks determine if the Paleogene traps can accumulate hydrocarbon. Using the model of the far-source accumulation pattern, numerous oil reservoirs have been discovered in the north Melut Basin, including the world-class Palogue oilfield. In addition to the Paleogene far-source accumulation pattern, three new near-source accumulation patterns have been identified in the Cretaceous, including the accumulation pattern of Galhak Formation, the accumulation pattern of Al Gayger Formation, and the accumulation patter of Al Renk Formation. Meanwhile, the typical oil reservoir models have been established for each near-source accumulation pattern. These new accumulation patterns and corresponding typical oil reservoir models should promote the exploration of the Cretaceous sequence in the Melut Basin. Compared to the north Melut Basin, the sub-basins in the south Melut Basin have smaller areas and coarser siliciclastic sediment infillings, which make the quality of Adar caprocks worse. Consequently, the Paleogene reservoir (Yabus and Samma Formations)-caprock (Adar Formation) pair is not an effective petroleum system combination in the south Melut Basin, and the near-source Cretaceous has better exploration potential. Affected by the movement of the East African Rift System in Paleogene, the Melut Basin widely developed inversion structures with numerous uplifts and faulted blocks, which provide good trap conditions for hydrocarbon accumulation. Three types of inversion structures have been identified, including the inner-basin inversion structures, the basin-margin inversion structures, and the inversion structures between sub-basins. The inner-basin inversion structures and the inversion structures between sub-basins have better oil-source and trap conditions and are important oil-bearing structures. However, the basin-margin inversion structure has big oil-source risk due to the long-distance migration from the basin center. The inversion movement makes the Cretaceous and basement shallower and therefore greatly increases the exploration potential of deep formations.

Sedimentary characteristics of Paleogene Yabus Formation in shallow-water delta in the northern sag of the Melut Basin, South Sudan

Sedimentary characteristics of Paleogene Yabus Formation in shallow-water delta in the northern sag of the Melut Basin, South Sudan

The Environmental and Social Impacts of Oil Exploration and Production on Melut basin of South Sudan

The Environmental and Social Impacts of Oil Exploration and Production on Melut basin of South Sudan

Accumulation conditions of far-source lithologic reservoirs and exploration strategy in Melut Basin, Central Africa

Accumulation conditions of far-source lithologic reservoirs and exploration strategy in Melut Basin, Central Africa

Seismic inversion as a predictive tool for porosity and facies delineation in Paleocene fluvial/lacustrine reservoirs, Melut Basin, Sudan

The Melut Basin is a rift basin in the interior Sudan linked to the Mesozoic-Cenozoic Central and Western African Rift System. The Paleocene Yabus Formation is the main reservoir deposited in heterogeneous fluvial/lacustrine environment. Delineation of channel sandstone from shale is a challenge in reservoir exploration and development. We demonstrate a detailed 3D quantitative seismic interpretation approach that integrates petrophysical properties derived from well logs analysis. A porosity transform of acoustic impedance inversion provided a link between elastic and rock properties. Thus, we used seismic porosity to discriminate between different facies with appropriate validation by well logs. At the basin scale, the results revealed lateral and vertical facies heterogeneity in the Melut Basin. Good reservoir quality is observed in the Paleocene Yabus Formation. The sand facies indicated high porosity (20%) corresponding to low acoustic impedance (20000–24000 g ft/(cm3.s)). However, lower quality reservoir is observed in the Cretaceous Melut Formation. The porosity of sand/shale facies is low (5%), corresponding to high acoustic impedance (29000–34000 g ft/(cm3.s)). This suggests that the Yabus Sandstone is potentially forming a better reservoir quality than Melut Formation. At the reservoir scale, we evaluated the facies quality of Yabus Formation subsequences using petrophysical analysis. The subsequences YB1 to YB3, YB4 to YB7 and YB8 to YB10 showed relatively similar linear regressions, respectively. The subsequence of YB4 to YB7 is considered the best reservoir with higher porosity (25%). However, subsequence YB1 to YB3 showed lower reservoir quality with higher shale volume (30%). This attributed to floodplain shale deposits in this subsequence. Similarly, the high porosity (20%) recognized in deeper subsequences YB6 to YB9 is due to clean sand facies. We learnt a lesson that appropriate seismic preconditioning, exhaustive petrophysical analysis and well log validation are important keys for improved reservoir quality prediction results in fluvial/lacustrine basins.

Sedimentological reservoir characteristics of the Paleocene fluvial/lacustrine Yabus Sandstone, Melut Basin, Sudan

Melut Basin in Sudan is regionally linked to the Mesozoic-Cenozoic Central and Western African Rift System (CWARS). The Paleocene Yabus Formation is the main oil producing reservoir in the basin. It is dominated by channel sandstone and shales deposited in fluvial/lacustrine environment during the third phase of rifting in the basin. Different scales of sedimentological heterogeneities influenced reservoir quality and architecture. The cores and well logs analyses revealed seven lithofacies representing fluvial, deltaic and lacustrine depositional environments. The sandstone is medium to coarse-grained, poorly to moderately-sorted and sub-angular to sub-rounded, arkosic-subarkosic to sublitharenite. On the basin scale, the Yabus Formation showed variation in sandstone bodies, thickness, geometry and architecture. On macro-scale, reservoir quality varies vertically and laterally within Yabus Sandstone where it shows progressive fining upward tendencies with different degrees of connectivity. The lower part of the reservoir showed well-connected and amalgamated sandstone bodies, the middle to the upper parts, however, have moderate to low sandstone bodies’ connectivity and amalgamation. On micro-scale, sandstone reservoir quality is directly affected by textures and diagenetic changes such as compaction, cementation, alteration, dissolution and kaolinite clays pore fill and coat all have significantly reduced the reservoir porosity and permeability. The estimated porosity in Yabus Formation ranges from 2 to 20% with an average of 12%; while permeability varies from 200 to 500 mD and up to 1 Darcy. The understanding of different scales of sedimentological reservoir heterogeneities might contribute to better reservoir quality prediction, architecture, consequently enhancing development and productivity.

Thermal modelling of the Melut basin Sudan and South Sudan: Implications for hydrocarbon generation and migration

The thermal history of the Melut rift Basin was studied in a number of wells and along a northeast-southwest cross sectionacross the basin using 1-D and 2-D basin models. Modelling was conducted using PetroMod software to test subsidence, thermal history and their implications for hydrocarbon generation, migration and accumulations. Geotherms were found ranging between 24 and 44 °C/km and average 32 °C/km and present day heat flow was found to vary between 53 and 65 averaging 59 mW/m2. A geologicaly realistic paleoheat flow model with higher heat flow peaks of 75, 70 and 65 mW/m2 during the first, second and third rifting phases respectively, calibrated against vitrinite reflectance data was employed. The model was found sensitive to Cenozoic erosions and a 600 m of exhumation did support the vitrinite data in providing a reasonable fit in most locations. Using the Easy %Ro vitrinite kinetic model for maturity the average present day oil window was found between 1565 and 4050 m in the wells studied and between 1705 and 4200 m along the cross section. Using type-II kerogen for the Aptian-Albian source rocks, the hydrocarbon generation and expulsion were modelled and revealed that the generation started as early as 95 Ma in some areas but significant generation rates were during the second rifting phase and expulsion started at around 85 Ma. Calculations of the probable expelled amounts of hydrocarbon from the northern sub basin are high and up to 2.2 × 1011 bbls of oil and 2.3 × 1014 ft3of gas. Migration of oils from Cretaceous source rocks kitchen to the Cenozoic traps was probably through faults, porous carrier beds and breaching of traps cap rocks. The filling of these traps might be periodic during the rifting episodes and hydrocarbons remigrated from deeper traps to shallow ones. It is possible that thinner and siltier cap rocks along the hydrocarbon migration path, may have allowed gas to scape but holded the oil back. It is most probable that part of the hydrocarbons might have been generated from shallower source rocks areas and a 2-D hybrid Darcy-Flow path model have demonstrated this and predicted a number of accumulations which are similar to the known large discoveries such as Palogue-Fal and Adar-Yale oil fields.

Upper Cretaceous to Neogene palynology of the Melut Basin, Southeast Sudan

The palynology of the Upper Cretaceous to Neogene non‐marine succession in the Melut Basin, southeast Sudan was investigated. The palynomorphs are overwhelmingly of terrestrial origin, but rare brackish water dinoflagellate cysts and scolecodonts were encountered from the Lower Miocene and Oligocene‐Miocene. Mangrove pollen, which is common in coeval West African coastal basins, is rare and inconsistent. Examples are Spinizonocolpites (Nypa) from the Campanian‐Maastrichtian to Eocene and Rhizophoraceae (Zonocostites ramonae) from the Neogene. Based on the stratigraphic distribution of selected pollen and spores from four exploration wells, eight informal palynozones from the Campanian to the Neogene are proposed. The zones, in stratigraphically ascending order, are as follows: Assemblage Zone I, Campanian (lower Melut Formation); Assemblage Zone II, Campanian‐Maastrichtian (middle Melut Formation); Assemblage Zone III, Maastrichtian (upper Melut Formation); Assemblage Zone IV, Paleocene (Yale Formation); Assemblage Zone V, Eocene (upper Yale and Adar formations); Assemblage Zone VI, Oligocene‐Early Miocene (Jimidi and lower Miadol formations); Assemblage Zone VII, Early Miocene (uppermost Miadol and lowermost Daga formations); and Assemblage Zone VIII, Late Miocene‐Pliocene (Daga Formation). The ages are based on stratigraphic positions and a series of first downhole appearances of key species such as Foveotricolpites cf. giganteus (Zone I), Auriculiidites reticulatus (Zone II), Ariadnaesporites spinosus (Zone III), Periretisyncolpites giganteus (Zone IV), Retistephanocolpites williamsii (Zone V), Cricotriporites camerounensis (Zone VI), Perfotricolpites digitatus (Zone VII), and Peregrinipollis nigericus (Zone VIII). Palynofacies investigations indicated differences between the Late Cretaceous and Paleogene‐Neogene paleoenvironments of the sections studied. The coexistence of structured organic palynodebris with pteridophyte spores, including those of water ferns (Ariadnaesporites), in the Upper Cretaceous strata suggests swampy conditions within a predominantly fluvial setting. The frequent occurrence of Palmae pollen indicates warm, humid conditions during the Late Cretaceous, although seasonal or hinterland aridity is suggested because of the occurrence of ephedroid pollen. Late Paleogene and Neogene assemblages are characterized by amorphous organic matter, fern spores, freshwater algae, and Gramineae pollen. Deposition in lacustrine habitats under warm, humid conditions is inferred. The occurrence of Gramineae pollen, mainly in the Neogene, indicates the development of grassy areas in a seasonally dry climate. A short marine incursion may have taken place during the Oligocene‐Miocene, due to the rare occurrence of brackish water dinoflagellate cysts and scolecodonts.

UPPER CRETACEOUS TO NEOGENE PALYNOLOGY OF THE MELUT BASIN, SOUTHEAST SUDAN

Abstract The palynology of the Upper Cretaceous to Neogene non-marine succession in the Melut Basin, southeast Sudan was investigated. The palynomorphs are overwhelmingly of terrestrial origin, but rare brackish water dinoflagellate cysts and scolecodonts were encountered from the Lower Miocene and Oligocene-Miocene. Mangrove pollen, which is common in coeval West African coastal basins, is rare and inconsistent. Examples are Spinizonocolpites (Nypa) from the Campanian-Maastrichtian to Eocene and Rhizophoraceae (Zonocostites ramonae) from the Neogene. Based on the stratigraphic distribution of selected pollen and spores from four exploration wells, eight informal palynozones from the Campanian to the Neogene are proposed. The zones, in stratigraphically ascending order, are as follows: Assemblage Zone I, Campanian (lower Melut Formation); Assemblage Zone II, Campanian-Maastrichtian (middle Melut Formation); Assemblage Zone III, Maastrichtian (upper Melut Formation); Assemblage Zone IV, Paleocene (Yale For...

Unusual high acidity oils from the Great Palogue Field, Melut Basin, Sudan

Crude oils produced from the Great Palogue Field in the Melut Basin, Sudan display unusually high total acid number values (TAN, up to 10.4 mg KOH/g oil). This field was discovered in 2002 and produces oils of highly variable (15–31°) API gravity. The main production comes from the Paleogene Samma and Yabus Formations, with the Upper Cretaceous Melut Formation being a minor contributor. The effective hydrocarbon source rocks are most likely within Lower Cretaceous lacustrine shales deposited during the syn-rift stages of the basin’s evolution. This study addressed 20 crude oil samples from five exploration and appraisal wells in the Great Palogue Field and four oil samples from other oil fields in the basin to represent the various production fluids from the Upper Cretaceous and Paleogene pay zones. These oil samples were characterized using routine molecular geochemical techniques to determine the primary geological and geochemical controls on oil acidity. Based on source and maturity constraints, two genetic types of high acidity oils have been recognized from the Melut Basin. The first group of high acidity oils is likely primary high TAN oils with a TAN value of 0.5–0.99 mg KOH/g oil. They are buried deeper than 2000 m where the temperature is higher than 80 °C. These include the oils only in the Upper Cretaceous Melut Formation of the Anbar-1 and Palogue South-2 blocks. The second group of high acidity oils show higher TAN values (>1.0 mg KOH/g oil) and various levels of biodegradation. These oils represent the dominant oil type in the Melut Basin, occurring mainly in the Paleogene Yabus and Samma Formations. A multiple phase oil charging model is proposed to explain the horizontal and vertical variation in the oil TAN values across the Great Palogue Field.

Petroleum geology of the Melut Basin and the Great Palogue Field, Sudan

This paper overviews the framework, structural and petroleum geology aspects of the Melut rift Basin in Sudan. The data base is from mainly proprietary exploration work consisting of more than 20,000 km of seismic profiles, 2000 km 2 of 3D seismic, and more than 50 exploration wells. There have been more than 15 oil and oil and gas discoveries. The Melut Basin is a Meso-Cenozoic rift basin accompanied by the formation and development of the Central African Shear Zone (CASZ) on the pre-Cambrian crystalline and metomorphic basement of lower relief. Three stages of rift development and fracturing have been identified, stronger in the Early Cretaceous and Paleogene and weaker in the Late Cretaceous. Source rocks are the Lower Cretaceous lacustrine shales, whereas reservoirs and seals are both Paleogene and Upper Cretaceous. Dominant structural styles are large-scale anticlines in the Paleogene sequences and antithetic normal fault-blocks in the Upper Cretaceous and Paleogene. Heavy to light oils (8.87–61.5° API) and gas have been discovered in the Paleogene and only light oils and gas in the Upper Cretaceous pay zones. The primary pay zone in the Melut Basin is the Paleogene. The Great Palogue Field, with ultimate recoverable oil reserves of more than 900 million barrels, was discovered in the northern Melut Basin. The gentle slopes of each subbasin are favorable areas for petroleum accumulation and enrichment. The faulted anticlines within the Paleogene syn-rift sequences are the main trap types, whereas the antithetic fault-blocks of the Upper Cretaceous sequences are secondary.