Stage Of Hydrocarbon Generation Research Articles

Accumulation Conditions of Upper Palaeozoic Coal-Derived Gas in Eastern Linqing Depression

The hydrocarbon exploration is presently going on well in the Bohai Bay Basin, where several coal-derived gas fields have been found in the Upper Palaeozoic. However, no significant breakthrough has been made in the exploration of Eastern Linqing Depression, which is located in the southwest of the Bohai Bay Basin. To improve the gas exploration efficiency, this study employed the petroleum system theory to analyze the accumulation elements and processes of coal-derived gas of Upper Palaeozoic in this area, and further summarized the natural gas accumulation model. Results showed that the source rocks of Upper Palaeozoic in Eastern Linqing Depression mainly consist of coal-measure strata of Benxi-Taiyuan Formations of Carboniferous, as well as Shanxi Formation and the Lower Shihezi Formation of Permian. Reservoirs are widely distributed from the bottom to the top, mainly consisting of carbonate rocks and sandstones. The carbonate rock reservoirs include the weathering crust of Ordovician and the dolomite within Ordovician, while sandstone reservoirs include the distributary channel sand bodies of delta plain and the meandering river channel sand bodies in Upper Palaeozoic, as well as sandstones of river and lacustrine in Mesozoic and Cenozoic. The whole region is covered by the semideep-deep lacustrine mudstone of Sha 3 member (Es3) of Palaeogene, which constitutes the regional cap rock in presence of many other localized cap rocks. There are four source-reservoir-cap assemblages including Upper Palaeozoic-generating and Mesozoic-preserving assemblage, Upper Palaeozoic-generating and Cenozoic-preserving assemblage, Upper Palaeozoic-generating and Upper Palaeozoic-preserving assemblage and Upper Palaeozoic-generating and Lower Palaeozoic-preserving assemblage. The source rock, reservoir and cap rocks match well in time and space. Tectonic evolution controlled the thermal evolution of the Upper Palaeozoic coal-measure source rocks, which experienced five hydrocarbon generation stages. Hydrocarbon generated from the coal strata of Upper Palaeozoic migrated to the surrounding traps through migration pathways consisting primarily of faults, cracks and unconformities, among which faults and unconformities played a major role. Multiple types of traps, mainly structural traps, were formed by the intense tectonic movements that historically occurred in this area. The trap formation stages match well with the hydrocarbon generation stages. By analyzing the accumulation conditions of coal-derived gas of Upper Palaeozoic, we identified four accumulation models and further predicted the favorable hydrocarbon accumulation zone in the study area.

Research advances and direction of hydrocarbon accumulation in the superimposed basins, China: Take the Tarim Basin as an example

Abstract The superimposed basins in the Tarim Basin are characterized by multiple source-reservoir-caprock combinations, multiple stages of hydrocarbon generation and expulsion, and multi-cycle hydrocarbon accumulation. To develop and improve the reservoir forming theory of superimposed basins, this paper summarizes the progress in the study of superimposed basins and predicts its development direction. Four major progresses were made in the superimposed basin study: (1) widely-distributed of complex hydrocarbon reservoirs in superimposed basins were discovered; (2) the genesis models of complex hydrocarbon reservoirs were built; (3) the transformation mechanisms of complex hydrocarbon reservoirs were revealed; (4) the evaluation models for superimposed and transformed complex hydrocarbon reservoirs by tectonic events were proposed. Function elements jointly controlled the formation and distribution of hydrocarbon reservoirs, and the superimposition and overlapping of structures at later stage led to the adjustment, transformation and destruction of hydrocarbon reservoirs formed at early stage. The study direction of hydrocarbon accumulation in superimposed basins mainly includes three aspects: (1) the study on modes of controlling reservoir by multiple elements; (2) the study on composite hydrocarbon-accumulation mechanism; (3) the study on hydrocarbon reservoir adjustment and reconstruction mechanism and prediction models, which has more theoretical and practical significance for deep intervals in superimposed basins.

Accumulation Conditions of Hydrocarbon Generated by Marine Source Rock in Southern Depression of Southern Yellow Sea Basin

The energy situation of China has been very tough. Our country’s oil is heavily dependent on imports and lack of oil and gas reserve. The shortage of oil and gas resource has become an important factor which restricts our national economy health and sustainable development. Guided by the theory of petroleum system, we analyzed the Mesozoic-Palaeozoic marine strata hydrocarbon accumulation elements and conditions of the sourthern depression in Southern Yellow Sea Basin and concluded the hydrocarbon accumulation pattern in order to find the reserving oil and gas. There are seven source-reservoir-cap assemblages. Different tectonic units experienced different tectonic evolution history. The source rock of Lower Palaeozoic, Upper Palaeozoic and Lower Triassic have experienced four, three and two hydrocarbon generation stages separately in the depression. But the source rock of Lower Palaeozoic and Upper Palaeozoic in the salient have only experienced two and one hydrocarbon generation stages separately. Hydrocarbon generated by Mesozoic-Palaeozoic source rock migrated to the traps by fault, crack and unconformity. Lithologic trap, broad anticlinal trap and fault-lithologic trap are the main types in the study area. By the analysis of Mesozoic-Palaeozoic marine hydrocarbon accumulation in the sourthern depresssion, we concluded two accumulation patterns which are the original lithologic reservoir in the Mesozoic-Palaeozoic marine strata and fault-lithologic reservoir in the Mesozoic-Cenozoic terrestrial strata. These results will help to predict the oil and gas resources.

The Potentiality of Source Rocks in Hayat Oilfield Based on Well Data, North Western Desert, Egypt

A total of 51 ditch samples were collected from organic rich horizon including dark-grey shales and limestones of the two wells (Hayat Deep-20x: 32 samples; Hayat-1x: 19 samples) and analyzed by a Leco WR 12 apparatus and Rock Eval pyrolysis. These samples were used as evaluation in potential source rocks in the Hayat oilfield. The results showed the three significant source rock intervals, which were penetrated by the Hayat deep-20x and Hayat-1x: wells. (1) The Upper Cretaceous source interval does not have the capacity to generate significant quantities of hydrocarbons in Hayat Deep-20x well and have fair to good organic richness in Hayat-1x well. (2) The Lower Cretaceous source interval ranges from a poor to good source potential and enters to the early stage of hydrocarbon generation. (3) The Middle Jurassic source interval has good source potential and has the capacity to generate significant quantities of gas generation.

Organic geochemical characteristics and depositional environment of the Tertiary Tanjong Formation coals in the Pinangah area, onshore Sabah, Malaysia

The Tertiary Tanjong Formation coals exposed in the west middle block of the Pinangah Coalfield, central part of southern Sabah were analyzed, and their depositional environments were interpreted. The Tertiary Tanjong coals are humic and generally dominated by vitrinite, with significant amounts of liptinite and low amounts of inertinite macerals. Total organic carbon contents (TOC) of the coals range from 51.2 to 77.7wt.%, and yield of bitumen values ranging from 57,300 to 140,000ppm, which meet the standard as a source rock with good hydrocarbon-generative potential. In support, good liquid hydrocarbons generation potential can be expected from the Tanjong coals based on significant liptinitic content (>15%). This is supported by their high hydrogen index up to 300mg HC/g TOC, consistent with Type II and mixed Type II–III kerogens and Py–GC (S2) pyrograms with n-alkane/alkene doublets extending beyond C30. The coal samples have vitrinite reflectance values in the range of 0.42%–0.66 Ro%, indicating immature to early mature stage for hydrocarbon generation. These vitrinite reflectance values also indicated that the Tanjong coals are with sub-bituminous B–A and high volatile bituminous C rank. Tmax values ranging from 419 to 451°C are good agreement with the vitrinite reflectance data. This is supported by biomarker maturity parameters as suggested by the C32 homohopane. The saturated fraction of the Tanjong coals are characterized by dominant odd carbon numbered n-alkanes (n-C23 to n-C33), high Pr/Ph ratios (8–18), high Tm/Ts ratios (6–28), and predominant of regular sterane C29. All biomarker parameters clearly indicate that the organic matter was derived from terrestrial inputs and deposited under oxic condition.

Geochemistry and geological significance of the Upper Paleozoic and Mesozoic source rocks in the Lower Yangtze region

The Lower Yangtze region is one of the important marine sedimentation areas of oil and gas distribution in southern China, for its favorable source rocks, reservoirs and covers. However, the intense tectonic movements and complex hydrocarbon generation process made it highly impossible to form large-sized oil and gas reservoirs. So it was divided to different hydrocarbon-bearing preservation units in oil-gas exploration. Recent study shows that the Permian and Lower Triassic source rocks in the Lower Yangtze region are complicated in lithology. The hydrocarbon generation potential of limestone there is low while argillaceous source rocks are overall of high abundance with excellent organic types, now in the process of hydrocarbon generation, so differences in high maturity influence the evaluation of organic matter abundance and type. Biomarker characteristics indicate a reductive environment. n-alkanes are marked by a single peak, with no odd-even predominance. The composition and distribution of the carbon numbers of n-alkanes, and the high abundance of long-chain tricyclic terpanes are indicative of marine sedimentation. The high contents of pregnane, homopregnane, rearranged hopane suggest that the source rocks are of high maturity. There is a good linear correlation between methylphenanthrene index and vitrinite reflectance. The correlation of oil-source rocks indicated that the oil of Well HT-3 may come from the Permian Longtan Formation in the Huangqiao area, the oil of Wells Rong-2 and Juping-1 came from the Lower Triassic Qinglong Formation in the Jurong area. The exploration here is promising in those different source rocks which all have great potential in hydrocarbon generating, and oil and gas were produced in the late stage of hydrocarbon generation.

Geochemical characterization of solid bitumen (migrabitumen) in the Jurassic sandstone reservoir of the Tut Field, Shushan Basin, northern Western Desert of Egypt

Abstract Asphaltene-rich solid bitumen was identified within the pore spaces of the Middle Jurassic Khatatba sandstone reservoir in the Tut Field, Shoushan Basin, Egypt. Despite good reservoir properties have been detected, the solid bitumen forms barriers in the reservoir, which prevents economic petroleum production. Petrographical and organic geochemical techniques were applied in order to characterize the source rock of the bitumen and its formation mechanisms. Organic geochemical results confirm the presence of actively migrating non-biodegraded hydrocarbons within the Khatatba sandstones. Biomarker data suggest that the solid bitumen originated from a marine shale source rock that was deposited in mildly anoxic to suboxic conditions. Biomarker oil-source rock correlation with the organic‐rich sediments of the Khatatba Formation indicates that the shale and coaly shale within the Khatatba Formation are an effective source rock in the area. The natural deasphalting is the predominant mechanism for the formation of the asphaltene rich solid bitumen in the Khatatba sandstones. Adsorption of asphaltenes onto authigenic kaolinite played a major role in the fixation of bitumen. Furthermore, gas deasphalting caused by gas injection may have contributed to a phase change in the reservoir fluid and deposition of solid bitumen. The injected gas is generated from Khatatba Type III kerogen or older source rocks in the Shoushan Basin during the mature stage of hydrocarbon generation.

Modeling of gas generation from the Alam El-Bueib formation in the Shoushan Basin, northern Western Desert of Egypt

The Shoushan Basin is an important hydrocarbon province in the northern Western Desert, Egypt, but the burial/thermal histories for most of the source rocks in the basin have not been assigned yet. In this study, subsurface samples from selected wells were collected to characterize the source rocks of Alam El-Bueib Formation and to study thermal history in the Shoushan Basin. The Lower Cretaceous Alam El-Bueib Formation is widespread in the Shoushan Basin, which is composed mainly of shales and sandstones with minor carbonate rocks deposited in a marine environment. The gas generative potential of the Lower Cretaceous Alam El-Bueib Formation in the Shoushan Basin was evaluated by Rock–Eval pyrolysis. Most samples contain sufficient type III organic matter to be considered gas prone. Vitrinite reflectance was measured at eight stratigraphic levels (Jurassic–Cretaceous). Vitrinite reflectance profiles show a general increase of vitrinite reflectance with depth. Vitrinite reflectance values of Alam El-Bueib Formation range between 0.70 and 0.87 VRr %, indicating a thermal maturity level sufficient for hydrocarbon generation. Thermal maturity and burial histories models predict that the Alam El-Bueib source rock entered the mid-mature stage for hydrocarbon generation in the Tertiary. These models indicate that the onset of gas generation from the Alam El-Bueib source rock began in the Paleocene (60 Ma), and the maximum volume of gas generation occurred during the Pliocene (3–2 Ma).

Lower Paleozoic Hydrocarbon Accumulation Conditions of Middle Uplift in Southern Yellow Sea Basin

Guided by the theory of petroleum system, we analyzed the Lower Palaeozoic hydrocarbon accumulation elements and conditions of the Middle uplift of Southern Yellow Sea Basin and concluded the hydrocarbon accumulation pattern. The results showed that: the source rock of lower Palaeozoic in the Middle uplift of Southern Yellow Sea Basin consists of the dark mudstone and carbonate rock; carbonate rock is the main favorable reservoir followed by clastic rock; there are three source-reservoir-cap assemblages; the source rock of Lower Palaeozoic has experienced two hydrocarbon generation stages which are late Silurian and late Middle Triassic; hydrocarbon generated by Lower Palaeozoic source rock can only migrate to the traps near the center of hydrocarbon generation by sandbody and cracks in a short distance; lithologic trap and broad anticlinal trap are the main types in the study area. Through the above analysis, we conclude two accumulation patterns of Lower Palaeozoic in the Middle uplift of Southern Yellow Sea Basin.

Oil and gas resource potential of the lower members of Eh3 in the lower Tertiary of the Biyang Depression, China

The lower Tertiary Eh3 is divided into two sections: the upper members of Eh3 and the lower members of Eh3 in the Biyang Depression. The first section is generally regarded as a key target of oil and gas exploration, but the resource potential of the lower members of Eh3 has been neglected. We have obtained new knowledge about Eh3 from comprehensive geological research. The lower members of Eh3 are high-quality and main source rocks, which have good oil and gas resource potential. This is a new direction for oil and gas exploration. The geochemistry characteristics of source rocks of the lower members of Eh3 in the lower Tertiary of the Biyang Depression were analyzed in detail. A basin modeling method was applied to hydrocarbon generation of the lower and upper members of Eh3 source rocks, the oil and gas resource potential was comparatively analyzed, and then favorable tectonic zones were pointed out. In the lower members of Eh3, a set of semi-deep lake to deep lake high-quality source rocks occurs rich in algae organisms, mainly of type II1, with a high abundance of organic matter. Most of the source rocks are just in the peak stage of hydrocarbon generation, which is a favorable foundation for forming abundant oil and gas resources in the Biyang Depression. The comparative analysis of the hydrocarbon-generation quantities between lower and upper members of the Eh3 source rocks shows that the lower members of Eh3 have good oil and gas resource potential, and the hydrocarbon-generation quantity accounts for 51% of the total in Eh3. Specifically, the oil-generating quantity accounts for 50% of the total and the gas-generating quantity accounts for two thirds of the total. Therefore, source rocks in the lower members of Eh3 of the Biyang Depression have good oil and gas resource potential, which is a key factor for future deep oil and gas exploration.

Maximum burial and unroofing of Mt. Judica recess area in Sicily: implication for the Apenninic–Maghrebian wedge dynamics

We integrated X-ray diffraction (XRD) data concerning the illite content in mixed-layer illite–smectite with data derived from Fourier Transform Infrared spectroscopy (FTIR) on H-rich organic matter to constrain the burial-exhumation path of the Mt. Judica sedimentary succession cropping out in tectonic window in Eastern Sicily.Thermal structural model constrained by organic and inorganic thermal parameters showed that the Mt. Judica succession experienced paleo-temperatures in the range of 100–130°C in deep diagenetic conditions and early mature stage of hydrocarbon generation. Specifically, the illite content in mixed-layer I–S ranges from 50 to 76% and FTIR-derived indexes suggest a thermal maturity equivalent to VRo values of at least 0.5–0.7%. As a whole, the Mt. Judica succession experienced maximum tectonic burial (ranging between 2.4 and 3.2km) during the Middle Miocene as a result of the emplacement of the allochthonous units atop it. The subsequent breaching phase characterized by up-thrust geometries, and erosion during Pliocene times ruled out the Mt. Judica exhumation. This last tectonic phase did not overprint thermal maturity because the extent of overthrusting was negligible when compared with the magnitude of vertical movements. Restoration of balanced cross sections revealed an increase of shortening from the salient to the Mt. Judica recess with values from 12.3 to 23.9km, consistent with the increase of tectonic thickening of the fold-and-thrust belt. Integration of maximum burial and shortening values along the curvature of the Sicilian fold-and-thrust belt allowed us to reconstruct the wedge paleo-geometry in the Mt. Judica recess area, to investigate the along-strike variations of the tectonic overburden, and to discuss the geodynamic causes of these changes. These results were compared with theoretical models of wedge dynamics.

Thickness Variations, Lithofacies Changes, and Time of Hydrocarbons Generation in the Khalda West Area, North Western Desert, Egypt

The lithostratigraphic cross-sections, thickness variations, and lithofacies changes of the Jurassic (Khatatba) and Cretaceous (Alam El Bueib and Bahariya) Formations, as well as time of hydrocarbon generation were discussed in the study area. The results showed that the thickness of the Jurassic and Cretaceous rock units increases from east to west. Results also showed shallow marine environment for the Khatatba Formation, a fluvio-deltaic environment for the Alam El Bueib Formation, and a fluvial to shallow marine environment for the Bahariya Formation. Also, the Khatatba Formation entered the early stage of hydrocarbon generation during the Late Cretaceous-Eocene and Alam El Bueib Formation during the Late Cretaceous-Oligocene. Bahariya Formation is still immature and do not reach the onset of hydrocarbon generation.

Geochemical characteristics and hydrocarbon generation modeling of the Jurassic source rocks in the Shoushan Basin, north Western Desert, Egypt

The Shoushan Basin is an important hydrocarbon province in the Western Desert, Egypt, but the origin of the hydrocarbons is not fully understood. In this study, organic matter content, type and maturity of the Jurassic source rocks exposed in the Shoushan Basin have been evaluated and integrated with the results of basin modeling to improve our understanding of burial history and timing of hydrocarbon generation. The Jurassic source rock succession comprises the Ras Qattara and Khatatba Formations, which are composed mainly of shales and sandstones with coal seams. The TOC contents are high and reached a maximum up to 50%. The TOC values of the Ras Qattara Formation range from 2 to 54 wt.%, while Khatatba Formation has TOC values in the range 1–47 wt.%. The Ras Qattara and Khatatba Formations have HI values ranging from 90 to 261 mgHC/gTOC, suggesting Types II-III and III kerogen. Vitrinite reflectance values range between 0.79 and 1.12 VRr %. Rock−Eval T max values in the range 438–458 °C indicate a thermal maturity level sufficient for hydrocarbon generation. Thermal and burial history models indicate that the Jurassic source rocks entered the mature to late mature stage for hydrocarbon generation in the Late Cretaceous to Tertiary. Hydrocarbon generation began in the Late Cretaceous and maximum rates of oil with significant gas have been generated during the early Tertiary (Paleogene). The peak gas generation occurred during the late Tertiary (Neogene).

Composition, porosity, and reservoir potential of the Middle Jurassic Kashafrud Formation, northeast Iran

In the Kopet-Dagh Basin of Iran, deep-sea sandstones and shales of the Middle Jurassic Kashafrud Formation are disconformably overlain by hydrocarbon-bearing carbonates of Upper Jurassic and Cretaceous age. To explore the reservoir potential of the sandstones, we studied their burial history using more than 500 thin sections, supplemented by heavy mineral analysis, microprobe analysis, porosity and permeability determination, and vitrinite reflectance. The sandstones are arkosic and lithic arenites, rich in sedimentary and volcanic rock fragments. Quartz overgrowths and pore-filling carbonate cements (calcite, dolomite, siderite and ankerite) occluded most of the porosity during early to deep burial, assisted by early compaction that improved packing and fractured quartz grains. Iron oxides are prominent as alteration products of framework grains, probably reflecting source-area weathering prior to deposition, and locally as pore fills. Minor cements include pore-filling clays, pyrite, authigenic albite and K-feldspar, and barite. Existing porosity is secondary, resulting largely from dissolution of feldspars, micas, and rock fragments, with some fracture porosity. Porosity and permeability of six samples averages 3.2% and 0.0023 mD, respectively, and 150 thin-section point counts averaged 2.7% porosity. Reflectance of vitrinite in eight sandstone samples yielded values of 0.64–0.83%, in the early mature to mature stage of hydrocarbon generation, within the oil window. Kashafrud Formation petrographic trends were compared with trends from first-cycle basins elsewhere in the world. Inferred burial conditions accord with the maturation data, suggesting only a moderate thermal regime during burial. Some fractures, iron oxide cements, and dissolution may reflect Cenozoic tectonism and uplift that created the Kopet-Dagh Mountains. The low porosity and permeability levels of Kashafrud Formation sandstones suggest only a modest reservoir potential. For such tight sandstones, fractures may enhance the reservoir potential.

Sedimentation, organic maturity, and petroleum potential of the Oligocene–Miocene oil shale deposits, Yayu Basin, southwestern Ethiopia

Studies initiated in the search for domestic energy supplies for Ethiopia have confirmed the presence of oil shales in the Yayu Basin. This article presents some of the characteristics of these shales. The basin is located in the southwest of Ethiopia and consists of Precambrian basement and Cenozoic volcanic and sedimentary rocks. Three sedimentary successions reach a cumulative maximum thickness of 165 m (541 ft). Two oil shale horizons have been identified in the upper and lower sedimentary successions and reach a maximum thickness of 35 and 20 m (115 and 65 ft), respectively. Sedimentation in the basin occurred in fluvial and lacustrine depositional environments. The sandstone facies was deposited in a fluvial environment, whereas the oil-shale-bearing sediments were deposited in a lacustrine environment. Algal amorphous materials and minor amounts of woody materials characterize the studied oil shales with Botryococcus and Pediastrum, indicating a lacustrine environment. The studied oil shales are characterized by high total organic carbon values up to 61.2% and S2 (hydrocarbon-generating potential) values ranging from 10.78 to 119.07 HC g/kg, indicating excellent source rocks. Most of the oil shales are at the immature to early mature stage for hydrocarbon generation. Vitrinite reflectance measurements on the oil shale samples are less reliable because of the presence of abundant algal materials. Gas chromatogram results also indicate source rocks. The Yayu Basin is estimated to have up to 1 billion metric tons of oil shale reserves.

Petroleum potential of campano-maastrichtian shales of Anambra Basin, south astern Nigeria

Over 6,000 meters thick terrigeneous sediment (mainly shale/ siltstones/lithologies) of campano – Maastrichtian age has been recorded in the Anambra basin. These shale/siltstones lithologies have been reported to be rich in organic matter and had fulfilled other relevant condition for hydrocarbon source rock potential. However, only few patches of hydrocarbon shows have been documented elsewhere in the basin. This work attempts to critically evaluate the hydrocarbon source potential of the organic rich shale sediments in the basin. A sample set of 40 ditch cuttings of manly shale lithologies retrieved at different depths intervals from 2 well were subjected to standard geo-chemical and organic petrography investigations. The samples were analyzed for the total carbon content (TOC), extract yield, organic matter types and organic maturity level. As screening criteria, all the sample set were subjected to TOC measurement (LECO). The TOC values range from 0.81-1.40% (AKU2) and from 0.82-1.81% (AMA.1) most of the samples meet up with minimum required TOC value ().5%) for a siliciclastic sediments to be hydrocarbon prone. Extract yield range from 30.0 to 180.5 ppm (AKU2) and 30.0 to 128ppm (AMA 1). The Rock-Eval Pyrolysis data HI vs OI revealed that the samples fall within types II & III kerogen. This corroborates with the results of the maceral analysis. The maceral composition is mainly vitrinitic and liptinitic of terrestrial origin, which are over 65 volume percent. The shales are moderately rich in organic matter. Extract yields and the bitumen ratio (mg HC/g TOC) revealed that these samples are at immature stage of Hydrocarbon generation. This is also supported by Tmax values of between 430-4900C.KEY WORDS:- Terrigeneous, Campano – Maastrichtian, Vitrinit, Liptinite, Rock-Eval.

Hydrocarbon Generation Evolution of Permo‐Carboniferous Rocks of the Bohai Bay Basin in China

Abstract:The Bohai Bay Basin is a Mesozoic subsidence and Cenozoic rift basin in the North China Craton. Since the deposition of the Permo‐Carboniferous hydrocarbon source rock, the basin has undergone many tectonic events. The source rocks have undergone non‐uniform uplift, twisting, deep burying, and magmatism and that led to an interrupted or stepwise during the evolution of hydrocarbon source rocks. We have investigated the Permo‐Carboniferous hydrocarbon source rocks history of burying, heating, and hydrocarbon generation, not only on the basis of tectonic disturbance and deeply buried but also with new studies on apatite fission track analysis, fluid inclusion measurements, and the application of the numerical simulation of EASY %Ro. The heating temperature of the source rocks continued to rise from the Indosinian to Himalayan stage and reached a maximum at the Late Himalayan. This led to the stepwise increases during organic maturation and multiple stages of hydrocarbon generation. The study delineated the tectonic stages, the intensity of hydrocarbon generation and spatial and temporal distribution of hydrocarbon generations. The hydrocarbon generation occurred during the Indosinian, Yanshanian, and particularly Late Himalayan. The hydrocarbon generation during the late Himalayan stage is the most important one for the Permo‐Carboniferous source rocks of the Bohai Bay Basin in China.

A hydrocarbon enrichment model and prediction of favorable accumulation areas in complicated superimposed basins in China

The geologic conditions of superimposed basins in China are very complicated. This is mainly shown by multi-phase structural evolution, multiple sets of source-reservoir-cap rock combinations, multiple stages of hydrocarbon generation and expulsion from source rocks, multi-cycle hydrocarbon enrichment and accumulation, and multi-phase reservoir adjustment and reconstruction. The enrichment, accumulation and distribution of hydrocarbon is mainly controlled by the source rock kitchen, paleoanticline, regional cap rock and intensity of tectonic movement. In this paper, the T-BCMS model has been developed to predict favorable areas of hydrocarbon accumulation in complicated superimposed basins according to time and spatial relationships among five key factors. The five factors include unconformity surface representing tectonic balancing (B), regional cap rock representing hydrocarbon protection (C), paleo-anticline representing hydrocarbon migration and accumulation (M), source rock kitchen representing hydrocarbon generation and expulsion (S) and geological time (T). There are three necessary conditions to form favorable areas of hydrocarbon accumulation. First, four key factors BCMS should be strictly in the order of BCMS from top to bottom. Second, superimposition of four key factors BCMS in the same area is the most favorable for hydrocarbon accumulation. Third, vertically ordered combination and superimposition in the same area of BCMS should occur at the same geological time. The model has been used to predict the most favorable exploration areas in Ordovician in the Tarim Basin in the main hydrocarbon accumulation periods. The result shows that 95% of the discovered Ordovician hydrocarbon reservoirs are located in the predicted areas, which indicates the feasibility and reliability of the key factor matching T-BCMS model for hydrocarbon accumulation and enrichment.

Hydrocarbon generation evaluation of Permo-Carboniferous source rocks in Qinggu-2 well in Dongpu depression, China

The Dongpu (东濮) depression is a Mesozoic subsidence and Cenozoic fault basin developed within the North China craton. Since the deposition of Permo-Carboniferous hydrocarbon source rock, the depression has undergone many tectonic disturbances and uplifts. The source rocks have undergone nonuniform uplift, deformation, deep burying, and magmatism, and those led to an interrupted or stepwise evolution of the hydrocarbon source rocks in Qinggu (庆古)-2 well. We have investigated the history of burying, heating, and hydrocarbon generation of the Permo-Carboniferous hydrocarbon source rocks not just on the basis of tectonic disturbance and deep burying, but also with new studies in apatite fission track analysis, fluid inclusion measurements, and the application of the numerical simulation of EASY%R o. The heating temperature of the source rocks pulsated upward from Indosinian to Himalayan stages and reached a maximum during early Himalayan. This led to the stepwise increases of organic maturation and multiple stages of hydrocarbon generation. This study delineated the tectonic stages, maturity evolved ranges, and the intensity of hydrocarbon generation of Permo-Carboniferous source rocks in Qinggu-2 well. The hydrocarbon generation mainly occurred during Indosinian and early Himalayan. The early Himalayan stage hydrocarbon generation is the larger one, but the Dongying (东营) movement, which happened at the end of early Himalayan, may destroy the trapped oil and gas. Thereby, future exploration will need to pay more attention to the Dongying movement effect in Qinggu-2 well area, and it may get new breakthrough in Permo-Carboniferous oil and gas.

Thermal Evolution of Organic Matter and Secondary Hydrocarbon Generation from Upper Paleozoic Coal Deposits in Northern China

Abstract The metamorphism and hydrocarbon generation from the Upper Paleozoic coal-bearing strata in Northern China have been widely studied by Chinese geologists since the 1990s. Based on a large amount of data of R o values, combined with geological background, we have systematically analyzed the thermal evolutionary characteristics of organic matter and the stages of hydrocarbon generation from the Permo-Carboniferous coal deposits and discussed the condition of secondary hydrocarbon generation. The distribution range of secondary hydrocarbon generation in Northern China is thus determined. It is shown that the coal ranks of the Upper Paleozoic coal deposits are higher in the southern and western belts than those in the northern and eastern belts. Really significant secondary hydrocarbon generation is mainly related to the thermal evolution of organic matter during the Himalayan Period. Profitable areas for secondary hydrocarbon generation should be buried at 3000–4000 m up to the present. Maturity of the Permo-Carboniferous source rocks is not very high. It is suggested that the Bohai Bay depression is favourable for secondary hydrocarbon generation and has good oil and gas prospects.