SUPPRESSION AND RETARDATION OF VITRINITE REFLECTANCE, PART 1. FORMATION AND SIGNIFICANCE FOR HYDROCARBON GENERATION

Vitrinite consists of a number of macerals with varying morphology and reflectance. Although vitrinite reflectance (VR) generally increases with increasing depth of burial, a spread of values often occurs due to the presence of the different macerals. However, reports of suppressed and/or retarded VR values introduce a potential problem for the geologist attempting to assess the thermal maturity of a sedimentary basin. Suppression is defined as the reduction in reflectance resulting from:

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BURIAL,TEMPERATURE AND MATURATION HISTORY OF THE AUSTRAL AND WESTERN MALVINAS BASINS,SOUTHERN ARGENTINA,BASED ON 3D BASIN MODELLING

This paper presents a numerical petroleum systems model for the Jurassic‐Tertiary Austral (Magallanes) Basin, southern Argentina, incorporating the western part of the nearby Malvinas Basin. The modelling is based on a recently published seismo‐stratigraphic interpretation and resulting depth and thickness maps. Measured vitrinite reflectance data from 25 wells in the Austral and Malvinas Basins were used for thermal model calibration; eight calibration data sets are presented for the Austral Basin and four for the Malvinas Basin. Burial history reconstruction allowed eroded thicknesses to be estimated and palaeo heat‐flow values to be determined. Six modelled burial, temperature and maturation histories are shown for well locations in the onshore Austral Basin and the western Malvinas Basin. These modelled histories, combined with kinetic data measured for a sample from the Lower Cretaceous Springhill Formation, were used to model hydrocarbon generation in the study area. Maps of thermal maturity and transformation ratio for the three main source rocks (the Springhill, Inoceramus and Lower Margas Verdes Formations) were compiled. The modelling results suggest that deepest burial occurred during the Miocene followed by a phase of uplift and erosion. However, an Eocene phase of deep burial leading to maximum temperatures cannot be excluded based on vitrinite reflectance and numerical modelling results. Relatively little post‐Miocene uplift and erosion (approx. 50–100 m) occurred in the Malvinas Basin. Based on the burial‐ and thermal histories, initial hydrocarbon generation is interpreted to have taken place in the Early Cretaceous in the Austral Basin and to have continued until the Miocene. A similar pattern is predicted for the western Malvinas Basin, with an early phase of hydrocarbon generation during the Late Cretaceous and a later phase during the Miocene. However, source rock maturity (as well as the transformation ratio) remained low in the Malvinas Basin, only just reaching the oil window. Higher maturities are modelled for the deeper parts of the Austral Basin, where greater subsidence and deeper burial occurred.     

BURIAL AND THERMAL HISTORY MODELLING OF THE MURZUQ AND GHADAMES BASINS (LIBYA) USING THE GALO COMPUTER PROGRAMME

The GALO computer programme was used to model the thermal and burial histories of the Murzuq and Ghadames Basins, Libya. The model was based on recent drilling and seismic data from the basins, and used published deep temperature and vitrinite reflectance measurements. The model provides more accurate results than previous studies which were based on constant geothermal gradients during the basins' histories, and variations in heat flux at the base of the sedimentary cover were chosen so that calculated values of vitrinite reflectance coincide with those observed. The Murzuq Basin and Libyan part of the Ghadames Basin contain similar source rock units but have different burial histories. In the Murzuq Basin, maximum present‐day burial depths of Cambrian sediments range from 2200 to 2800 m and only locally reach 3000 – 3600 m; in the Ghadames Basin, however, burial depths can exceed 4–5 km. The burial history of the Murzuq Basin includes several periods of intense erosion and lithospheric heating which produced significant lateral variations in thermal maturity, leading in places to unexpected results. For example, relatively shallow‐buried Lower Silurian source rocks in the A‐76 area on the flank of the Murzuq Basin have a thermal maturity of R_o = 1.24% which is higher than the maturity of the same interval in more deeply buried areas (wells D1‐NC‐58 or J1‐NC101). In the central part of the Ghadames Basin, the modelling suggests a higher level of thermal maturity for organic matter in Silurian strata (R_o 0.8 to 1.3%), confirming the generation potential of Lower Silurian “hot shales”. Significant hydrocarbon generation began here in the Late Carboniferous and continues at the present day. Modelling of the Late Devonian (Frasnian) Aouinat Ouinine Formation “hot shales” suggests limited hydrocarbon generation depending strongly on burial depth, with the main phase of hydrocarbon generation taking place during the final episode of thermal activation in the Cenozoic. In the wells studied in the Ghadames Basin, the “oil window” extends over a considerable part of the present‐day sedimentary column.     

超压和富氢背景下镜质组反射率计算模型——以渤海湾盆地渤中西次凹东三段烃源岩为例

在考虑富氢和超压对镜质组反射率的抑制作用下,对传统仅考虑了温度和时间的镜质组反射率计算模型——Easy%R_o模型进行了重新校正。通过引进富氢校正系数和超压抑制系数,建立起适合双重抑制背景下镜质组反射率计算模型,并利用渤海湾盆地渤中西次凹受双重抑制作用和未受双重抑制作用影响的镜质组反射率R_o实测资料,确定了相关参数。模拟结果表明,在双重抑制作用影响的地层中,镜质组反射率R_o的模拟值与实测值吻合较好,但与Easy%R_o模型的计算结果相差悬殊,双重抑制作用对R_o的影响可达0.2%~0.4%。超压抑制了有机质热演化,导致生烃门限下移和生烃时间延迟,这非常有利于油气晚期成藏。      

THERMAL MATURITY AND HYDROCARBON GENERATION IN ROCKS FROM THE SEDIMENTARY BASINS OF MADAGASCAR

Oil exploration in Madagascar has been concentrated on the Morondava Basin in the SW of the island, which is well-known for its large deposits of tar sand and heavy oil at Bemolanga and Tsimiroro. Petroleum shows have frequently been encountered in exploration wells, but source-rock identification has remained inconclusive. Thus, the present study of a wildcat was originally related mostly to geochemical prospect appraisal. Due to the inform oraganic matter type and wide range of thermal evolution stages sampled, the case history has more general implications, however, as regards relationships between thermal maturation and hydrocarbon generation. Evaluation of eleven rock samples taken at depths of between 1,100 and 2,500m by Rock-Eval, solvent extraction and vitrinite reflectance (Rr) methods revealed only poor source rocks for oil with marginal through to post-mature Type III kerogens (Rr between 0.5% and 1.4%) Discrepancies in yield profiles of total C15+ -hydorcarbons peaking at higher R_r in the Morondava and Dauala Basin (Cameroon) wells than in a Deep Basin (West Canada) well are tentatively attributed to their different geothermal histories. However, yield trends of specific saturated and aromatic hydrocarbon families, as determined by capillary gas chromatography, did not testify to the suspected effect of geothermal rate variations on generation curves, which hence remain unproven. Based on systematic changes with depth in the distribution of methylated di- and tri-aromatics, the interpretration of maturation levels with respect to hydrocarbon generation was refined. When converted to vitrinite reflectance equivlents (Rc), molecular parameters such as the Trimithylnaphthalene Ration (TNR 1) and the Methylphenanthrene Index (MPI I) were able to disclose gradual marurity changes. In contrast to the large Morondava Basin, the smaller Majunga Basin in NW Madagascare has been the site of little explortion activity until recently. Based on organic-geochemical analysis of seven rock samples from two exploration wells by the above-mentioned methods, it was found that good source rocks for oil are absent. Some of the samples may have a considerable gas generation potential, which at best has been partially reasised. Certainly, maturities inadequate for substantial gas generation are indicated by aromatic parameters.     

BURIAL,TEMPERATURE AND MATURATION HISTORY OF CRETACEOUS SOURCE ROCKS IN THE NW PERSIAN GULF,OFFSHORE SW IRAN: 3D BASIN MODELLING

This study presents a 3D numerical model of a study area in the NW part of the Persian Gulf, offshore SW Iran. The purpose is to investigate the burial and thermal history of the region from the Cretaceous to the present day, and to investigate the location of hydrocarbon generating kitchens and the relative timing of hydrocarbon generation/migration versus trap formation. The study area covers about 20,000 km² and incorporates part of the intra‐shelf Garau‐Gotnia Basin and the adjacent Surmeh‐Hith carbonate platform. A conceptual model was developed based on the interpretation of 2700 km of 2D seismic lines, and depth and thickness maps were created tied to data from 20 wells. The thermal model was calibrated using bottom‐hole temperature and vitrinite reflectance data from ten wells, taking into account the main phases of erosion/non‐deposition and the variable temporal and spatial heat flow histories. Estimates of eroded thicknesses and the determination of heat‐flow values were performed by burial and thermal history reconstruction at various well and pseudo‐well locations. Burial, temperature and maturation histories are presented for four of these locations. Detailed modelling results for Neocomian and Albian source rock successions are provided for six locations in the intra‐shelf basin and the adjacent carbonate platform. Changes in sediment supply and depocentre migration through time were analyzed based on isopach maps representing four stratigraphic intervals between the Tithonian and the Recent. Backstripping at various locations indicates variable tectonic subsidence and emergence at different time periods. The modelling results suggest that the convergence between the Eurasian and Arabian Plates which resulted in the Zagros orogeny has significantly influenced the burial and thermal evolution of the region. Burial depths are greatest in the study area in the Binak Trough and Northern Depression. These depocentres host the main kitchen areas for hydrocarbon generation, and the organic‐rich Neocomian and Albian source rock successions have been buried sufficiently deeply to be thermally mature. Early oil window maturities for these successions were reached between the Late Cretaceous (90 Ma) and the early Miocene (18 Ma) at different locations, and hydrocarbon generation may continue at the present‐day.     

ORGANIC FACIES VARIATIONS AND HYDROCARBON GENERATION POTENTIAL OF PERMIAN GONDWANA GROUP COALS AND ASSOCIATED SEDIMENTS,BARAPUKURIA AND DIGHIPARA BASINS,NW BANGLADESH

In the Barapukuria and Dighipara coal basins, NW Bangladesh, the Basement Complex is overlain by the coal‐bearing Permian Gondwana Group. In the present study, 36 core samples collected from five boreholes in these two basins were analysed using organic geochemical and organic petrological methods. Based on the results of biomarker analyses (TIC, m/z 191 and m/z 217 fragmentograms) and maceral composition (proportions of vitrinite, liptinite, inertinite), three organic facies were identified: coals, carbargillites and mudstones. Together with other evidence, cross‐plots of HI versus T_max and Pr/nC₁₇ versus Ph/nC₁₈ indicate that the coals, as expected, were dominated by terrestrial organic matter (OM). The carbargillites contained a mixture of terrestrial and probable Type II aquatic OM, and the mudstones contained mostly terrestrial OM. Accordingly the coals, carbargillites and mudstones are interpreted to have been deposited in swamp‐dominated environments in a delta‐plain setting which was subject, in the case of carbargillites, to periodic flooding. Suboxic conditions were indicated by very high Pr/Ph ratios and a high content of inertinite macerals. All the samples analysed were immature or early mature for hydrocarbon generation, as indicated by mean vitrinite reflectance (%R_o) of 0.60–0.81%, Rock‐Eval T_max of 430–439°C, and biomarker ratios (hopane C₃₂ 22S/(22S+22R)) of 0.57–0.60. Carbargillites showed potential for both liquid and gaseous hydrocarbon generation; coals were mainly gas‐prone with minor liquid hydrocarbon potential; and mudstones were dominantly gas‐prone. The oil‐prone nature of the samples was attributed to the presence of resinite, cutinite, bituminite and fluorescent vitrinite. The presence of exsudatinite within crack networks, solid bitumen and oil droplets as well as bituminite at early oil‐window maturities suggests that the organic matter may have expelled some hydrocarbons.     

THERMAL MATURITY AND HYDROCARBON GENERATION IN ROCKS FROM THE SEDIMENTARY BASINS OF MADAGASCAR

Oil exploration in Madagascar has been concentrated on the Morondava Basin in the SW of the island, which is well-known for its large deposits of tar sand and heavy oil at Bemolanga and Tsimiroro. Petroleum shows have frequently been encountered in exploration wells, but source-rock identification has remained inconclusive. Thus, the present study of a wildcat was originally related mostly to geochemical prospect appraisal. Due to the uniform organic matter type and wide range of thermal evolution stages sampled, the case history has more general implications, however, as regards relationships between thermal maturation and hydrocarbon generation. Evaluation of eleven rock samples taken at depths of between 1,100 and 2,500m by Rock-Eval, solvent extraction and vitrinite reflectance (R_r) methods revealed only poor source rocks for oil with marginal through to post-mature Type III kerogens (R_r between 0.5% and 1.4%). Discrepancies in yield profiles of total C₁₅₊ -hydrocarbons peaking at higher R_r in the Morondava and Douala Basin (Cameroon) wells than in a Deep Basin (West Canada) well are tentatively attributed to their different geothermal histories. However, yield trends of specific saturated and aromatic hydrocarbon families, as determined by capillary gas chromatography, did not testify to the suspected effect of geothermal rate variations on generation curves, which hence remain unproven. Based on systematic changes with depth in the distribution of methylated di- and tri-aromatics, the interpretation of maturation levels with respect to hydrocarbon generation was refined. When converted to vitrinite reflectance equivalents (R_r), molecular parameters such as the Trimethylnaphthalene Ratio (TNR 1) and the Methylphenanthrene Index (MPI 1) were able to disclose gradual maturity changes. In contrast to the large Morondava Basin, the smaller Majunga Basin in NW Madagascar has been the site of little exploration activity until recently. Based on organic-geochemical analysis of seven rock samples from two exploration wells by the above-mentioned methods, it was found that good source rocks for oil are absent. Some of the samples may have a considerable gas generation potential, which at best has been partially realised. Certainly, maturities inadequate for substantial gas generation are indicated by aromatic parameters.     

油气生成的化学动力学模型和煤成气的数值模拟

建立了一个半开放系统的生烃化学动力学模型及其煤成气的简化模型.在该模型中煤或干酪根首先降解为油和气,随以后成熟度的增加,源岩中未排出的石油裂解为气,在油气的形成过程中,伴随着油气的初次运移.该模型可用于任何沉积盆地中油气形成过程的数值模拟.实际应用时,可根据给定的化学动力学参数,选择模型和其中参数.     

THERMAL HISTORY RECONSTRUCTION IN THE SOROOSH AND NOWROOZ FIELDS, PERSIAN GULF, BASED ON APATITE FISSION TRACK ANALYSIS AND VITRINITE REFLECTANCE DATA

The thermal history of the sedimentary successions at the Soroosh-17, Soroosh-02 and Nowrooz-16 wells in the northern Persian Gulf have been studied using apatite fission track analysis and vitrinite reflectance data. These data were used to identify and quantify episodes of heating and cooling which have affected the sections penetrated by these wells. This information was synthesised to provide a thermal history framework for the wells, within which the history of hydrocarbon generation, as well as regional structural development, can be understood. Preliminary hydrocarbon generation histories are presented for the Soroosh and Nowrooz oilfields and nearby areas.
Modelling of hydrocarbon generation histories based on the AFTA- and VR-derived thermal histories, assuming a dominant Type III kerogen for possible Albian Kazhdumi Formation source rocks and a dominant Type II kerogen for possible Neocomian Fahliyan (Lower Ratawi) Formation source rock, suggest that local sourcing of oil from the Kazhdumi Formation is unlikely. The most likely source rock for oil in the Burgan Formation reservoir at Soroosh-17 and Nowrooz-16 is interpreted to be the Fahliyan Formation based on the available data. On the other hand, speculative modelling of the Hendijan-I well down-dip from the Nowrooz field does allow some oil to be generated from the Kazhdumi sequence at that location, and this might be available for migration to the Nowrooz field.     

BURIAL HISTORY AND THERMAL MATURITY EVOLUTION OF THE TERMIT BASIN,NIGER

Reconstruction of the burial history and thermal evolution of the Cretaceous – Tertiary Termit Basin, a sub‐basin within the larger Eastern Niger Basin of Niger, indicates spatially and temporally variable conditions for organic matter maturation during the basin's multi‐phased evolution. Three episodes of tectonic subsidence which correspond to the observed fault mechanical stratigraphy within the Termit Basin are identified: Late Cretaceous, Maastrichtian to early Paleocene, and Oligocene. These episodes fall within the regional tectonic phases of the West African Rift System delineated by previous studies. The basin exhibits substantial heterogeneity in the magnitude of the tectonic episodes and in consequent thermal maturities. For this paper, 1D burial and thermal histories of eight widely dispersed wells in the Agadem permit area in the SW of the Termit Graben were modelled to investigate the maturation of organic matter in source rocks ranging from Santonian to Oligocene in age. The kinetic modelled maturities match with maturities based on Rock‐Eval T_max values for four wells if present‐day heat flows are elevated. Future exploration strategies in the Termit Basin should take into consideration these heterogeneities in thermal histories and tectonic pulses, which may lead to the development of hydrocarbon accumulations with different oil‐gas compositions in different reservoir compartments.     

REFLECTANCE RETARDATION (SUPPRESSION) AND SOURCE ROCK PROPERTIES RELATED TO HYDROGEN-ENRICHED VITRINITE IN MIDDLE JURASSIC COALS, DANISH NORTH SEA

Middle Jurassic high volatile bituminous A coals from the Danish North Sea may yield vitrinite reflectance values retarded by 0.10–0.14 %R_r The coals are low in liptinite content, and the reflectance retardation is related to the vitrinite composition. Vitrain (assumed to be pure vitrinite) was hand-picked from eight samples and characterised by means of element analysis, Fourier Transform infrared spectroscopy and Rock-Eval pyrolysis. In contrast to the vitrinite from samples yielding "true" reflectance values, the vitrinite from three of the samples yielding retarded reflectances is perhydrous in nature (5.57–5.79 wt-% (d.a.f.) H) and has H/C atomic ratios of 0.80–0.83. Vitrinite from another reflectance-retarded sample is enriched in sulphur. The hydrogen enrichment is inherited from oxygen-deficient, waterlogged and marine-influenced conditions in the precursor mires. FTIR spectra demonstrate that the perhydrous vitrinites have a lower aromaticity as measured by aromatic hydrogen vibrations in the region 900–700 cm^-1 compared to the "normal" vitrinites. This suggests a reduced maturation rate of the hydrogen-enriched vitrinite. S_1(Vitr), S_2(vitr) and HI_vitr values from the vitrinite concentrates indicate that the vitrinite is a significant contributor to the overall generative potential; this is particularly the case for the perhydrous vitrinite. Activation energies for the vitrinites are centred at 260 and 268 kJ/mole. It is not possible to detect a measurable difference in E_a between the perhydrous and "normal" vitrinites. This may suggest more-or-less similar generation characteristics, or it may indicate that Rock-Eval kinetics do not replicate Nature in this regard.     

SOME THOUGHTS ON THE INFLUENCE OF PRESSURE AND THERMAL HISTORY ASSUMPTIONS ON PETROLEUM SYSTEMS MODELLING

The use of petroleum systems modelling (PSM) requires the integration of the geological sciences with petroleum engineering, physics and chemistry. In a recent paper in JPG (October 2014, vo. 37, pp 329–348), Mahanjane et al. (2014) applied a 1‐D petroleum systems model to the study of maturation and petroleum generation in northern Mozambique. However, PSM cannot divorce itself from the fundamental laws of mechanics and thermodynamics when attempting to derive a thermal history to be used for the modelling of maturation and petroleum generation. As will be shown in this brief Comment, the application of mechanics and thermodynamics to the derivation of the thermal history may require some radical changes to the methods currently used in PSM. Mechanics and thermodynamics require a reducing heat flow during subsidence, but require an increased heat flow during inversion. The failure to apply mechanics and thermodynamics during thermal history derivation in PSM arises from a failure to incorporate the effects of pressure into the kinetic models used for predicting maturation and petroleum generation. Pressure increases the activation energy of endothermic reactions including maturation and petroleum generation in the kinetic model used to predict the reaction rate, and results in higher temperatures being required to produce the same transformation ratio as would be required for the current temperature – time kinetic models. Incorporating pressure should enable the same thermal history obtained from tectonic history‐mechanic‐thermodynamic models to be used as those used to calibrate the thermal history using maturity parameters such as vitrinite reflectance.     

ORGANIC GEOCHEMISTRY AND PETROLOGY OF A LOWER JURASSIC (PLIENSBACHIAN) PETROLEUM SOURCE ROCK FROM AÏT MOUSSA,MIDDLE ATLAS,MOROCCO

Organic‐rich silty marls and limestones (Pliensbachian to earliest Toarcian) exposed at Aït Moussa in Boulemane Province are the only known example of an effective petroleum source rock in the Middle Atlas of Morocco. In this study, petrological and organic‐geochemical analyses (vitrinite reflectance measurements, Rock‐Eval pyrolysis, GC‐MS) were carried out in order to evaluate the maturity, quality and quantity of the organic matter (OM) and to investigate the depositional environment of these source rocks. Results indicate the presence of Type I/II kerogen which was deposited under marine conditions with an input of predominantly algal‐derived organic matter. The presence of woody particles indicates minor input of terrestrial material. Organic‐geochemical and biomarker analyses are consistent with deposition of carbonate‐rich sediments under oxygen‐depleted but not anoxic conditions. In terms of thermal maturity, the sediments have reached the oil window (0.5–0.6 %VR_t) but not peak oil generation, although petroleum generation and migration are indicated by organic geochemical and microscopic evidence. Kinetic parameters derived from an investigation of petroleum generation characteristics show that the kerogen decomposes within a narrow temperature interval due to the fairly homogenous structure of the algal‐derived organic matter. The kinetic parameters together with vitrinite reflectance data were used to construct a ID model of the burial, thermal and maturation history of the Aït Moussa locality. The model suggested that deepest burial (approx. 3200 m) for the Pliensbachian succession took place in the Eocene (approx. 40 Ma). Two phases of hydrocarbon generation occurred, the first in the Late Jurassic/Early Cretaceous (approx. 150 Ma), and the second at the time of deepest burial (Eocene).     

TEMPERATURE AND BURIAL HISTORY MODELLING OF THE DRMNO AND MARKOVAC DEPRESSIONS, SE PANNONIAN BASIN, SERBIA

We have modelled the subsidence, thermal and maturation history of the Drmno and Markovac depressions in the SE Pannonian Basin (Serbia) in order to calculate quantities of generated, expelled and migrated hydrocarbons. Stratigraphic, lithofacies, structural, thermal and geochemical data were used to create a conceptual model of the basin's evolution to depths of 5,000m. The models were calibrated using present-day temperature and vitrinite reflectance data from representative wells. The results show that in the centres of these depressions, possible Badenian and pre-Badenian (i.e. Middle and Lower Miocene) source rocks are sufficiently mature to have generated oil and gas.
Maturity data reveal significant differences in heat flow during times when maximum palaeotemperatures were reached. From these data high heat flows can only be deduced for some of the wells, whereas similar high heat flows are deduced from present-day temperature data. Future research is necessary to resolve in detail the geologic evolution of the study area which resulted in the significant differences between the Mio/Pliocene and Recent heat flows.
Petroleum generation is taking place at depths below 2,000m in both depressions, mainly from Pre-Badenian source rocks which contain Type II-III kerogen and which appear to have a high petroleum generation potential.     

BURIAL AND THERMAL HISTORY MODELLING OF THE MANNAR BASIN,OFFSHORE SRI LANKA

The Mannar Basin is a Late Jurassic – Neogene rift basin located in the Gulf of Mannar between India and Sri Lanka which developed during the break‐up of Gondwana. Water depths in the Gulf of Mannar are up to about 3000 m. The stratigraphy is about 4 km thick in the north of the Mannar Basin and more than 6 km thick in the south. The occurrence of an active petroleum system in the basin was confirmed in 2011 by two natural gas discoveries following the drilling of the Dorado and Barracuda wells, located in the Sri Lankan part of the Gulf. However potential hydrocarbon source rocks have not been recorded by any of the wells so far drilled, and the petroleum system is poorly known. In this study, basin modelling techniques and measured vitrinite reflectance data were used to reconstruct the thermal and burial history of the northern part of the Mannar Basin along a 2D profile. Bottom‐hole temperature measurements indicate that the present‐day geothermal gradient in the northern Mannar Basin is around 24.4 ^oC/km. Optimised present‐day heat flows in the northern part of the Mannar Basin are 30–40 mW/m². The heat flow histories at the Pearl‐1 and Dorado‐North well locations were modelled using SIGMA‐2D software, assuming similar patterns of heat flow history. Maximum heat flows at the end of rifting (Maastrichtian) were estimated to be about 68–71 mW/m². Maturity modelling places the Jurassic and/or Lower Cretaceous interval in the oil and gas generation windows, and source rocks of this age therefore probably generated the thermogenic gas found at the Dorado and Barracuda wells. If the source rocks are organic‐rich and oil‐ and gas‐prone, they may have generated economic volumes of hydrocarbons.     

BURIAL AND MATURATION HISTORY OF THE HEGLIG FIELD AREA, MUGLAD BASIN, SUDAN

The NW‐SE trending Muglad Basin (SW Sudan) is one of a number of Mesozoic basins which together make up the Central African Rift System. Three phases of rifting occurred during the Cretaceous and Tertiary, resulting in the deposition of at least 13 km of sediments in this basin. Commercial hydrocarbons are sourced from the Barremian‐Neocomian Sharaf Formation and the Aptian‐Albian Abu Gabra Formation. The Heglig field is located on a NW‐SE oriented structural high in the SE of the Muglad Basin, and is the second‐largest commercial oil discovery in Sudan. The high is characterised by the presence of rotated fault blocks, and is surrounded by sub‐basinal structural lows. We modelled the geohistories of three wells on different fault blocks in the Heglig field (Heglig‐2, Barki‐1 and Kanga‐1) and one well in the Kaikang Trough (May25–1). The models were calibrated to measured porosity‐depth data, temperature and vitrinite reflectance measurements. Predicted present‐day heat flow over this part of the Muglad Basin is about 55 mW/m². However, a constant heat‐flow model with this value did not result in a good fit between calculated vitrinite Ro and measured Ro at the wells studied. Therefore a variable heat‐flow model was used; heat flow peaks of 75, 70 and 70 mW/m² were modelled, these maxima corresponding to the three synrift phases. This model resulted in a better fit between calculated and measured Ro. The source rock section in the Sharaf and Abu Gabra Formations was modelled for hydrocarbon generation in the four wells. Model results indicate that the present‐day oil generation window in the Hegligfield area lies at depths of between 2 and 4 km, and that oil and gas generation from the basal unit of the Abu Gabra Formation occurred between about 90 and 55 Ma and from the Sharaf Formation between 120 and 50 Ma. The results suggest that the oils discovered in the Heglig area have been generated from a deep, mature as‐yet unpenetrated source‐rock section, and/or from source rocks in nearby sub‐ basinal areas.     

PETROLEUM POTENTIAL, THERMAL MATURITY AND THE OIL WINDOW OF OIL SHALES AND COALS IN CENOZOIC RIFT BASINS, CENTRAL AND NORTHERN THAILAND

Oil shales and coals occur in Cenozoic rift basins in central and northern Thailand. Thermally immature outcrops of these rocks may constitute analogues for source rocks which have generated oil in several of these rift basins. A total of 56 oil shale and coal samples were collected from eight different basins and analysed in detail in this study. The samples were analysed for their content of total organic carbon (TOC) and elemental composition. Source rock quality was determined by Rock‐Eval pyrolysis. Reflected light microscopy was used to analyse the organic matter (maceral) composition of the rocks, and the thermal maturity was determined by vitrinite reflectance (VR) measurements. In addition to the 56 samples, VR measurements were carried out in three wells from two oil‐producing basins and VR gradients were constructed. Rock‐Eval screening data from one of the wells is also presented. The oil shales were deposited in freshwater (to brackish) lakes with a high preservation potential (TOC contents up to 44.18 wt%). They contain abundant lamalginite and principally algal‐derived fluorescing amorphous organic matter followed by liptodetrinite and telalginite (Botryococcus‐type). Huminite may be present in subordinate amounts. The coals are completely dominated by huminite and were formed in freshwater mires. VR values from 0.38 to 0.47%R_o show that the exposed coals are thermally immature. VR values from the associated oil shales are suppressed by 0.11 to 0.28%R_o. The oil shales have H/C ratios >1.43, and Hydrogen Index (HI) values are generally >400 mg HC/g TOC and may reach 704 mg HC/ gTOC. In general, the coals have H/C ratios between about 0.80 and 0.90, and the HI values vary considerably from approximately 50 to 300 mg HC/gTOC. The HI_max of the coals, which represent the true source rock potential, range from ～160 to 310 mg HC/g TOC indicating a potential for oil/gas and oil generation. The steep VR curves from the oil‐producing basins reflect high geothermal gradients of ～62°C/km and ～92°C/km. The depth to the top oil window for the oil shales at a VR of ～0.70%R_o is determined to be between ～1100 m and 1800 m depending on the geothermal gradient. The kerogen composition of the oil shales and the high geothermal gradients result in narrow oil windows, possibly spanning only ～300 to 400 m in the warmest basins. The effective oil window of the coals is estimated to start from ～0.82 to 0.98%R_o and burial depths of ～1300 to 1400 m (～92°C/km) and ～2100 to 2300 m (～62°C/km) are necessary for efficient oil expulsion to occur.     

超压环境有机质热演化和生烃作用机理

通过对多个盆地大量样品的多参数对比分析,建立了超压抑制有机质热演化的多参数识别标志,揭示了不同成熟度指标对超压的差异响应.识别出超压抑制有机质热演化和生烃作用的4个层次:①超压抑制了有机质热演化的各个方面,包括不同干酪根组分的热降解(生烃作用)和烃类的热演化;②超压仅抑制了烃类的热演化和富氢干酪根组分的热降解,而对贫氢干酪根组分的热演化不产生重要影响,因此镜质体反射率未受到抑制;③超压抑制了烃类的热裂解,而对干酪根的热降解未产生明显影响;④超压对有机质热演化的各个方面均未产生可识别的影响.超压对有机质热演化的抑制作用层次取决于超压发育后有机质热演化反应的体积膨胀效应、产物浓度变化速率及超压的发育特征.早期强超压和长期保持封闭流体系统是产生第一层次超压抑制作用的必要条件.超压发育过晚、超压强度低、超压流体频繁释放等都可能导致超压对有机质热演化的各个方面均不产生可识别的影响.     

西湖凹陷中央背斜带两种热体制下烃源岩的热演化

通过对东海盆地西湖凹陷中央背斜带不同区带的单井流体包裹体、镜质体反射率以及盆地模拟结果的分析 ,认为该区烃源岩的热演化存在 2种热体制 ,即正常热传导下的热体制和叠加了异常岩浆热作用的热体制。在正常热传导背景下 ,西湖凹陷中央背斜带沉积速率、升温速率、成熟速率以及生烃速率等四者之间相辅相成 ,依次控制 ;局部岩浆热作用会产生古地温的浅部高温现象 ,它对加速该区烃源岩层的生烃过程以及提高生烃量和生烃速率具有促进作用