Lower Cretaceous Source Rocks Research Articles

Timing of hydrocarbon charge in the Axial Zone of the Eastern Cordillera, Colombia

The petroleum potential of onshore basins in Colombia has been partly controlled by the Andean Orogeny since the end of the Cretaceous. Its Axial Zone has at least one understudied active petroleum system with a rather low petroleum potential and few commercial medium to heavy oil accumulations, raising questions about how the Andean deformation influenced the petroleum system and the possible undiscovered accumulations. We examine the timing of this petroleum system in the Axial Zone through oil–source correlations and two 2D petroleum system models across the Boyacá and Soápaga faults based on cross-sections. Modelling reveals the direct control of deformation on generation–accumulation in the Axial Zone, where the Lower Cretaceous source rocks, due to high heat flows during the synrift phase, started generation so early (100 to 60 Ma) that no reservoirs or traps were yet available to allow hydrocarbon entrapment and accumulation. Equally, for the younger Upper Cretaceous source rocks, the tectonic inversion of the basin between 33 and 23 Ma along the Boyacá and Soápaga faults interrupted burial and the maturation in most parts of the basin, leaving only local pods of active source rocks where maturation continues today due to the tectonic overburden along the footwall of the Soápaga Fault. The latter is thus the major kitchen, contributing more than 50% of the liquid hydrocarbons trapped mainly in Upper Cretaceous and Paleocene sandstones. Hydrocarbons migrate upwards where biodegradation and water washing occurred in the near-surface, giving rise to the many tar sand occurrences in the Eocene sandstones.

Quality and composition of Lower Cretaceous carbonate source rocks and seepage oils in the Belize Basin, southern Belize, Central America

The Belize Basin in southern Belize, Central America, contains numerous seepage oils derived from marly and carbonate source rocks, but since no definitive source rocks have been identified the source remains uncertain. This study examines by pyrolysis and organic petrography the source rock quality and maturity of 66 samples collected from three newly exposed carbonate sections in the southeastern Belize Basin together with organic geochemical analysis of five new occurrences of seepage oils from the southern Belize Basin. Combined ammonite and aptychi biostratigraphy suggest a Berriasian to Hauterivian age of the source rock samples. Low Tmax values show the samples are thermally immature. Numerous samples are oil-prone and have Hydrogen Index values >300–400 mg HC/g TOC, reaching a maximum of 768 mg HC/g TOC. The samples with source rock potential contain from 32 to 64% pyrolysable organic carbon and contains liptinite-rich Type II kerogen consisting of alginite, bituminite, and liptodetrinite. The calculated Ultimate Expulsion Potential (UEP) of a 22.5 m thick section amounts to ∼2.5 mmboe/km2. This generation capacity is volumetrically relatively small, but it could be compensated for by a thicker source rock section. However, the identified source rocks could account for the seepage oils in the Belize Basin, and they are thus the first documentation of Lower Cretaceous source rocks in Belize. A plausible explanation for the widespread occurrence of seepage oils in the Belize Basin could be generation from organic-rich layers with bituminite and alginite. In line with this and previously examined seepage oils, the new variably degraded oils were sourced from carbonate source rock facies.

Structural styles of the Tierra del Fuego fold–thrust belt foothills, Argentina

Regional structural cross-sections based on seismic, borehole and surface data portray the foothills geometry of the Tierra del Fuego fold–thrust belt. Andean contraction was accommodated by two main deformation mechanisms: (1) a lower duplex thrust system that involves mainly Cretaceous deposits, with floor and roof thrusts at the base of the Cretaceous and close to the base of the Cenozoic, respectively; and (2) a series of detachment and faulted detachment anticlines in the Cenozoic, detached in mudstones above the roof thrust of the underlying duplex thrust system. Less common structures include fault-bend and fault-propagation folds. Basement fault reactivation is only locally important, with most Jurassic graben and half-graben preserved without inversion. Shortening along the foothills is modest, with values ranging from ∼8 to 4.6 km. This region of the fold–thrust belt has hydrocarbon exploration interest, but is still largely underexplored. Several large anticlines preserving Cenozoic clastic rocks have not yet been tested. The key risk for these structures is the charge because the thick mudstone package forming their detachment isolates potential Cenozoic reservoirs from the Lower Cretaceous source rocks. Duplex thrust systems at depth may constitute a potential exploration play if the brittle intervals are naturally fractured.

Evaluation of the hydrocarbon source rock and the reservoir characterization of the Minagish Formation using wireline logs

We investigated the Mianagish Formation's potentiality as a Lower Cretaceous source rock and the included reservoir facies zone in the Umm Gudair oil field. The Middle Oolitic grainstone is the only producing zone in the formation. The wireline logs were used to trace the reservoir characteristics and calculate the total percentage of organic carbon (TOC) in the lithotype of the Minagish Formation. The commercial software, thin sections, and laboratory measurements are used to provide an integrated study. Integration of burial history, calculated TOC values, thermal maturity, depositional model, structural elements, and reservoir characterization were used to take a thoughtful look at the Minagish Formation's role in oil production in the field and as Lower Cretaceous source rock for the Cretaceous reservoirs. The reservoir facies are characterized by 16% average clay content, 16.7% average porosity, 420 millidarcys (mD) average permeability, and the average oil saturation is about 62%. The reservoir's quality reaches its maximum at the crest of the anticline in the west, south, and east, whereas the reservoir facies are deposited on the pre-existing structurally high shoal, while the quality decrease away from the shoal into the relatively deep water. The oil feeds the reservoir from the Lower Minagish Formation and maybe the Sulaiy Formation. According to the thermal model, the oil is heavy because of falling the TOC in the early maturation stage. The depositional environment and sequence stratigraphy are similar in the nearby Dharif and Abduliyah oil fields, and the study can be applied.

Structural reconstructions effect on oil and gas formation of the Yenisei-Khatanga trough eastern part

The article presents the results of research on the influence of structural reconstructions on the hydrocarbon systems evaluation in the eastern part of the Yenisei-Khatanga trough. Based on seismic data interpretation and paleoprofiles construction, several stages of structural reconstructions in the geological evolution of the basin are established: at the Middle and Late Triassic boundary, Late Triassic and Jurassic boundary, in the Bathonian-Callovian time, Tithonian-Valanginian time, in the Barremian-Aptian time, in the Aptian-Albian time, in the Cenomanian time, and powerful reconstructions in the Cenozoic era. Based on interpretation of geochemical information of the well-core and outcrops, the characterization of the type of organic matter, the amount of initial organic carbon, the oil and gas source potential for the Late Triassic, Lower Jurassic, Middle Jurassic, Upper Jurassic, Lower Cretaceous oil and gas source rocks is given. The results of exploration of the geological structure of the region, the geochemical features of oil and gas source rocks became the basis for building a 2D basin model, which made it possible not only to identify generation kitchen, migration routes and accumulation zones of hydrocarbon fluids, but also to estimate the start time of generation and emigration of hydrocarbons, as well as the moments of interruption of these processes during periods of uplifting of the territory. Changes of the structural plan transformed the configuration of the basin, which led, on the one hand, to the formation of areas where rich in organic matter interlayers accumulated, and, on the other hand, to the interruption of hydrocarbon systems evaluation, reconfiguration and even destruction of deposits.

Depositional environment and petroleum source rock potential of Mesozoic lacustrine sedimentary rocks in central Mongolia

Middle Jurassic (five samples from one location) and Lower Cretaceous (thirty-two samples from eight locations) lacustrine sedimentary rocks of central Mongolia were studied to determine their depositional environments and petroleum source rock potential. The Middle Jurassic shale contains sufficient organic matter (OM) with Type II/III kerogen to represent a mixed oil and gas potential source rock. Tmax and biomarker maturity indices suggest a thermally immature level. Pristane/phytane and the gammacerane index indicate that the shale accumulated in an oxic, freshwater environment. Terrigenous OM with input from algae and macrophytes was a major contributor as indicated by long-chain n-alkanes and the abundance of C29 regular steranes. The stable carbon and nitrogen isotope compositions and kerogen types agree with land plant derived OM. Lower Cretaceous shales are highly oil-prone but thermally immature, reflected by Rock-Eval data and biomarker parameters. Carbon preference index (CPI), n-alkane distributions, and C27/C29 ratios suggest that OM in Lower Cretaceous shales is a mixture of phytoplankton, macrophyte, and land plant. The contribution from algal OM is variable. Lower Cretaceous shales were deposited in stratified lakes with anoxic bottom waters and the salinity of paleolakes was variable, indicated by Pr/Ph and the gammacerane index, respectively. Organic geochemical characteristics and depositional environments of Middle Jurassic and Lower Cretaceous sedimentary rocks studied herein are similar to those of Jurassic source rocks in western Chinese basins and Lower Cretaceous source rocks in eastern Mongolian basins, respectively.

Jurassic-recent stratigraphy, structure, and hydrocarbon potential of the Mesozoic-Cenozoic rifted-passive margin of the Tarfaya-Dakhla basin of southern Morocco

We describe the structure, stratigraphy, and hydrocarbon potential of the 1000-km-long Tarfaya-Dakhla Basin (TDB) along the Atlantic rifted-passive margin of Morocco. Our dataset consists of a 4885-line km grid of depth-converted industry seismic data tied to three DSDP wells in the deepwater area and exploratory wells on the slope and shelf. Based on mapping of this seismic grid, the tectonostratigraphic events that have affected this margin include: 1) a Late Triassic-Early Jurassic rift phase that separated the Moroccan margin from its conjugate margin in eastern Canada began during the Late Triassic-Early Jurassic; 2) early passive margin sedimentation consists of Middle Jurassic-Early Cretaceous passive margin phase consisting of a massive, 14-km-thick, reefal-carbonate platform formed above the rifted margin during the Early Jurassic and was subsequently buried by the 6-km-thick, Early Cretaceous (Berriasian) Boujdour deltaic complex. During this period continued high rates of clastic sedimentation resulted in margin steepening and gravitational collapse during the Valanginian and formed a 480-km-long and 68-km-wide passive margin fold belt characterized by a zone of updip normal faults of 480 km in length and 30 km in width and a zone of downdip folds and thrusts of 117 km in length and 15 km in width. Geochemical data from DSDP 397 and 369 wells and two pseudo-wells were used to evaluate source rock potential and hydrocarbon prospectivity of the Jurassic to Recent section. Basin modeling reveals that the Jurassic source rocks known from DSDP drilling are presently overmature in the study area with hydrocarbon generation beginning in the Upper Jurassic-Lower Cretaceous. The Lower Cretaceous source rocks are immature except for localized areas, and the Upper Cretaceous is immature across the study area.

Organic geochemical signatures of source rocks and oil-source correlation in the Papuan Basin, Papua New Guinea

The Papuan Basin is the largest petroliferous basin in Papua New Guinea (PNG), where developed several sets of potential source rocks (SRs). The Jurassic SRs are clay-rich shales, whose organic matter (OM, mainly type Ⅱ 2 -Ⅲ) is predominantly derived from terrestrial higher plants deposited in a more oxic environment with relatively high maturity (0.35% < Ro < 2.03%). The Cretaceous SRs contain mixed inputs of terrigenous and marine OM (type Ⅱ 2 -Ⅲ) formed in sub-oxidized to oxidized depositional conditions with moderate maturity (0.33% < Ro < 1.58%). Whereas the Paleocene-Miocene SRs are predominant marine calcareous shales with subsidiary terrigenous OM inputs. These SRs containing type Ⅲ kerogen are mostly immature (0.21% < Ro < 0.70%). The Papuan Basin oils were classified into three distinct genetic families based on biomarkers and stable carbon isotopes. Family A oils, with heavy carbon isotopes, low Pr/Ph ratios, C 29 /C 27 ααα 20 R sterane <1.0, are likely originated from autochthonic Paleogene-Neogene mature marine OM. Family B oils have the characteristics of high Pr/Ph, moderate carbon isotopes, the dominance of C 29 ααα 20 R sterane, and are predominantly derived from autochthonous Jurassic SRs. Family C oils in the Eastern Papuan Fold Belt (EPFB) can be further subdivided into three subtypes by more subtle differences in specific biomarkers. Type C 1 oils, most likely stemmed from the Lower Cretaceous SRs, are characterized by light stable carbon isotopes, Pr/Ph > 2, the mild dominance of C 29 ααα 20 R sterane and the absence of oleanane ± lupane. Type C 2 oils can be clearly distinguished from Type C 3 by C 19 /(C 19 + C 23 ) tricyclic terpane <0.5, while the latter ones have higher abundances of oleanane ± lupine and diahopanes as well as C 24 tetracyclic/C 23 tricyclic terpane ratios. Type C 2-3 oils are originated from calcareous SRs that deposited in Late Cretaceous or younger age. • The organic geochemical signatures of the Papuan Basin SRs were elaborated. • Biomarkers, stable carbon isotopes, n -alkanes and iso-alkanes were used. • The oil samples in the Papuan Basin can be classified into three genetic families. • The likely origin of diverse oil families in the Papuan Basin were discussed.

A Probable Connection between a Bitumen Sample from the Western Niger Delta and Isan Well Sample from the Lower Cretaceous (Neocomian) Shale

An earlier study of GC-MS analysis on bitumen samples from the Agbabu area in Western Niger Delta showed the significant presence of gammacerane and no Oleanane and is suggested to be generated from the Lower Cretaceous (Neocomian) source rock, however, twelve core samples were obtained from the geological survey of Nigeria for both optical geochemical and biomarker analysis, two of the samples from Isan-9 well indicated the presence of Botryococcus braunii a freshwater alga which is characteristic of a lacustrine lake type environment. The extracts from the same core showed m/z = 191 chromatogram with the significant presence of gammacerane which is diagnostic for stratified water columns and characterizes a typical lake environment. However, the m/z = 191 chromatogram also shows the presence of Oleanane which is diagnostic for vascular plant materials, this doesn’t corroborate with that of the Ise-2 well. The Isan-9 well source rock is suggested to have occurred due to the evolving structural geology of the continental shelf after the onset of the rifting, whereby the dominant lake-type environment in the Early Cretaceous was accompanied by a sediment fill of continental runoffs containing vascular plant materials. This implies that an ancient lacustrine lake system was gradually modified as a result of sedimentary infill. And that the bitumen is sourced from the lower Cretaceous Neocomian source rocks.

Tracing Lower Cretaceous Source Rocks Across the Sw Barents Shelf

Tracing Lower Cretaceous Source Rocks Across the Sw Barents Shelf

Yenisei–Khatanga Composite Tectono-Sedimentary Element, northern east Siberia

Abstract The Yenisei–Khatanga Composite Tectono-Sedimentary Element (CTSE) is located between the Siberian Craton and the Taimyr–Severnaya Zemlya Fold and Thrust Belt. The total thickness of the Mesoproterozoic–Cenozoic sediments of the Yenisei–Khatanga CTSE reaches 20–25 km, and they are divided into four tectono-sedimentary elements (TSEs): (i) Mesoproterozoic–early Carboniferous Siberian Craton continental margin; (ii) middle Carboniferous–Permian synorogenic Taimyr foreland basin; (iii) late Permian–Early Triassic synrift; and (iv) Triassic–Early Paleocene post-rift. The last one is the most important in terms of its petroleum potential and is the most drilled part of the CTSE. Its thickness accounts for half of the total thickness of the Yenisei–Khatanga CTSE. The margins of the post-rift TSE and the inner system of inversion swells and adjacent troughs and depressions were shaped by three tectonic events: (i) Middle Triassic uplift of South Taimyr; (ii) the Late Jurassic–Early Cretaceous Verkhoyansk Orogeny; and (iii) Late Cenozoic uplift. These processes led to more intense migration of hydrocarbons, the trap formation and their infill with hydrocarbons. Triassic, Jurassic and Lower Cretaceous source rocks are mostly gas-prone; and of the 20 discovered fields in Jurassic and Cretaceous plays, 17 are gas or mixed-type fields.

Upper Jurassic to Lower Cretaceous source rocks in the Norwegian Barents Sea, part II: Insights from open- and closed-system pyrolysis experiments

The petroleum generation potential of Upper Jurassic to Lower Cretaceous organic rich shales from the southwestern Barents Sea was evaluated using bulk and quantitative pyrolysis analysis. Fifteen thermally-immature samples from the Hekkingen Formation with differing organic facies, as defined by maceral composition, were subjected to total organic carbon, Rock-Eval pyrolysis, pyrolysis gas chromatography, bulk kinetics, and micro-scale sealed vessel pyrolysis analyses. The results were employed to characterize differences in source rock kerogens, gross petroleum type, and the compositional evolution of the generated fluids as well as their physical properties (i.e. gas to oil ratio, saturation pressure, and formation volume factor) as a function of increasing maturity.The investigated samples contain varying proportions of kerogen type II and III. Heterogeneities in the kerogen composition result in different orders of thermal stability, with the onset of petroleum generation predicted to occur over a high and broad temperature range from 123 °C to 144 °C (at 3.3C⁰/Ma). Reduced kerogen stability associated with elevated sulfur contents is only documented in a few samples. Most of the analyzed samples have the potential to generate low GOR oils of an intermediate to aromatic, low wax paraffinic-naphthenic-aromatic (P–N-A) composition and variable amounts of wet gas. Petroleums of similar compositional and physical properties are predicted to have been generated from the natural maturation sequence of various organic facies in thermally mature areas of the Hammerfest Basin and the Ringvassøy-Loppa High and Bjørnøyrenna fault complexes. Vitrinite-rich sources in the Fingerdjupet Sub-basin and the Troms-Finnmark Fault Complex have potential for gas and condensate generation.

Upper Jurassic to Lower Cretaceous source rocks in the Norwegian Barents Sea, part I: Organic geochemical, petrographic, and paleogeographic investigations

This study provides a subregional to regional characterization of organofacies changes within the two members of the Upper Jurassic to Lower Cretaceous Hekkingen Formation (i.e. Alge and Krill) by integrating geochemical and petrographic analysis with paleogeographic models.The gross kerogen composition of the Hekkingen Formation is dominated by terrestrial macerals. This preponderance of land-derived particles is more pronounced in the Krill Member than in the underlying Alge Member. There is a greater proportion of marine macerals within distal areas of the Hammerfest Basin and well 7218/1-S in the southern Bjørnøyrenna Fault Complex. This shift in the relative proportion of marine and terrestrial macerals is ascribed to changes in the location of the depositional sites with respect to the sources of the terrestrial materials.The Alge Member features the highest levels of total organic carbon (TOC ≥7 wt %), but the more discrete and organically poorer beds of the Krill Member still remain sufficiently rich to be considered petroleum source rocks (TOC ≥2 wt %). Hydrogen indices (HI) between 50 and 400 mg HC/g TOC recorded throughout the entire formation indicate that the kerogen within both members has similar oil and gas generation capabilities. These low to moderate HI values are indicative of immature Type III to II-III kerogens and are generally consistent with the high proportions of terrestrial macerals. Prior to thermal maturation, marine type II kerogens (i.e. ≤ 400 mgHC/gTOC) probably existed in the marine liptinite-rich rocks in the distal Hammerfest Basin and Bjørnøyrenna Fault Complex. At least three factors controlled the detected variability in geochemical parameters: dilution rates of organic matter, varying inputs of terrestrial versus marine organic matter, and the degree of preservation. The documented variability in organic-rich facies assists in reducing source rock risk in the study area, but also helps explorationists understand source rock distribution across other shelfal areas.

Upper Jurassic–Lower Cretaceous Source Rocks in the North of Western Siberia: Comprehensive Geochemical Characterization and Reconstruction of Paleo-Sedimentation Conditions

The present work is devoted to geochemical studies of the Bazhenov Formation in the north of the West Siberian Petroleum Basin. The object is the Upper Jurassic–Lower Cretaceous section, characterized by significant variations in total organic carbon content and petroleum generation potential of organic matter at the beginning of the oil window. The manuscript presents the integration of isotopic and geochemical analyses aimed at the evaluation of the genesis of the rocks in the peripheral part of the Bazhenov Sea and reconstruction of paleoenvironments that controlled the accumulation of organic matter in sediments, its composition and diagenetic alterations. According to the obtained data, the sediments were accumulated under marine conditions with a generally moderate and periodically increasing terrigenous influx. The variations in organic matter composition are determined by redox conditions and terrigenous input which correlate with the eustatic sea level changes during transgressive/regressive cycles and activation of currents. Transgression is associated with an intensive accumulation of organic matter under anoxic to euxinic conditions and insignificant influence of terrigenous sources, resulting in the formation of rocks with oil-generating properties. During the regression periods, the terrigenous sedimentation increased along with the dissolved oxygen concentration, and deposits with low organic matter content and gas-generating properties were formed.

Source rock maturity evaluation and its implications for regional petroleum charge, Sirt Basin, Libya: Insights from regional geochemical assessments and modelling study

Six marine and lacustrine source rocks were studied to define their thermal maturation levels in the largest, youngest, and most productive petroliferous sedimentary basin in Libya (Sirt Basin). From the oldest to the youngest, the studied source rock formations were: 1) Middle Nubian; 2) Etel; 3) Rachmat; 4) Sirte; 5) Kalash; and 6) Hagfa. The calibrated basin modelling studies (1D, 2D, and 3D) were used to generate regional maturation maps for each source rock in the basin. Thermal maturity calibration was carried out at different levels utilising measured and simulated vitrinite reflectance (VRo), pyrolysis Tmax data, and 39 typical wells for burial history modelling and geochemical screening. Corrected bottom hole temperature data were used to obtain the geothermal gradient and heat flow throughout the basin. The thermal gradient and heat flow analyses results indicated that the Sirt Basin has an average geothermal gradient of approximately 1.58 °F/100 ft and an average heat flow of 72 m.W.m−2 with a systematic heat flow increase toward the basin platforms and a decrease toward the basin troughs. The conducted assessments in the Sirt Basin presented different levels of source rocks thermal maturity due to variable burial depths, with an average VRo range of 0.35%–2%. The lower Cretaceous source rocks were subjected to higher degrees of diagenesis of organic matter (i.e. mid-to over-mature rocks), with an average VRo of 0.9%–2%. In contrast, the Upper Cretaceous source rocks demonstrated a wide range of thermal maturity (from marginally to late mature) in the deepest part of the Sirt Basin (Ajdabiya trough), whereas the late Palaeocene source rocks entered the mid-to late-maturity levels in the Wadayet trough (North Ajdabiya trough).

Organic geochemical characteristics of Lower Cretaceous source rocks and crude oils in Doseo Depression of central African rift system

The Doseo depression in the Central African Rift System is characterized by weak inversion, strong strike-slip and rifting, which is an important onshore frontier area for oil and gas exploration in Africa. Based on the data of new wells drilled in recent years, the Lower Cretaceous source rocks in the Doseo depression were investigated comprehensively in respect of organic matter type, abundance, maturity and formation environment, through the analysis of TOC, pyrolysis, vitrinite reflectance (Ro), carbon isotope and gas chromatography-mass spectrometry (GC-MS) of source rock samples, together with the GC-MS experiment of discovered crude oil samples. Furthermore, the main hydrocarbon generation and expulsion periods were inferred through burial history simulation. The study results reveal the findings in three aspects. First, there are three sets of source rocks in the Lower Cretaceous of the Doseo depression, i.e. Doba Formation, Kedeni Formation and Mangara Formation, of which the latter two are the main source rocks in the area. The Kedeni Formation source rocks, with the average TOC of 3.96% and the organic matters of type I–II1, are at low-mature to mature stage. The Mangara Formation source rocks, with the average TOC of 3.52% and the organic matters of type II1, are at mature to high-mature stage. Second, all the three sets of source rocks are lacustrine facies developed in low-reducing and low-oxidizing environment. They are typically characterized by low sterane/hopane ratio and low terpane/hopane ratio, and contain organic matters derived from mixed origins, including aquatic lower organisms and terrestrial higher plants. From the Mangara Formation to the Kedeni Formation, the carbon isotope value of source rocks becomes lighter; the organic matters derived from higher plants exhibit a reducing proportion, while the organic matters derived from lower organisms (e.g. algae) are more abundant. The discovered crude oils are found with similar characteristics of organic matters, and they are mainly sourced from the Kedeni Formation and Mangara Formation source rocks with relatively high maturity in the center of the Doseo depression. Third, the Kedeni Formation source rocks are mature for oil generation within the depression, while the Mangara Formation source rocks are high mature for gas generation in the center of the depression and mature for oil generation at the margin of the depression. The source rocks within the Doseo depression became mature for hydrocarbon generation since 110 Ma, and have demonstrated two hydrocarbon generation and expulsion peaks in the early Late Cretaceous (105–95 Ma) and the Early Paleogene (66–40 Ma).

Petroleum System Modelling of the Akri-Bijeel Oil Field, Northern Iraq: Insights From 1-Dimensional Basin Modelling

The petroleum system of the Akri-Bijeel oil field shows that the Palaeogene formations such as the Kolosh Formation seem to be immature. However, the Jurassic–Lower Cretaceous source rocks such as those from the Chia Gara, Naokelekan, and Sargelu formations are thermally mature and within the main oil window because their vitrinite reflectance (Ro%) values are &gt;0.55%. The Triassic Kurra Chine and Geli Khana formations are thought to be in the high maturity stage with Ro values ≥1.3% and within the wet and dry gas windows, whereas the older formations are either within the dry gas zone or completely generated hydrocarbon stage and depleted after the hydrocarbons were expelled with subsequent migration to the reservoir rock of the structural traps.

E&amp;P Notes (December 2020)

E&amp;P Notes (December 2020)

PETROLEUM SYSTEMS OF THE BONGOR BASIN AND THE GREAT BAOBAB OILFIELD, SOUTHERN CHAD

The Bongor Basin in southern Chad is an inverted rift basin located on Precambrian crystalline basement which is linked regionally to the Mesozoic – Cenozoic Western and Central African Rift System. Pay zones present in nearby rift basins (e.g. Upper Cretaceous and Paleogene reservoirs overlying Lower Cretaceous source rocks) are absent from the Bongor Basin, having been removed during latest Cretaceous – Paleogene inversion‐related uplift and erosion. This study characterizes the petroleum system of the Bongor Basin through systematic analyses of source rocks, reservoirs and cap rocks.Geochemical analyses of core plug samples of dark mudstones indicate that source rock intervals are present in Lower Cretaceous lacustrine shales of the Mimosa and upper Prosopis Formations. In addition, these mudstones are confirmed as a regional seal. Reservoir units include both Lower Cretaceous sandstones and Precambrian basement rocks, and mature source rocks may also act as a potential reservoir for shale oil. Dominant structural styles are large‐scale inversion anticlines in the Lower Cretaceous succession whilst underlying “buried hill” ‐type basement plays may also be important. Accumulations of heavy to light oils and gas have been discovered in Lower Cretaceous sandstones and basement reservoirs.The Great Baobab field, the largest discovery in the Bongor Basin with about 1.5 billion barrels of oil in‐place, is located in the Northern Slope, a structural unit near the northern margin of the basin. Reservoirs are Lower Cretaceous syn‐rift sandstones and weathered and fractured zones in the crystalline basement. The field currently produces about 32,000 barrels of oil per day.

塔木察格盆地南贝尔凹陷东部次凹下白垩统烃源岩和储集层的主要特征

塔木察格盆地南贝尔凹陷东部次凹下白垩统烃源岩和储集层的主要特征