Source Kitchen Research Articles

Quantitative evaluation of the transporting capacity of unconformities: A Case Study from the Zhongguai Area, Junggar Basin, NW China

Abstract Unconformities are special geologic bodies with a three-layer structure including the rock above the unconformity, a weathered clay layer, and a leached rock. The Upper Wuerhe (Upper Permian) bottom unconformity in Northwest Junggar Basin is the main pathway system linking the Zhongguai (ZG) lift with hydrocarbon source kitchens. Based on the log response characteristics of the unconformity's vertical structure and core calibration, a principal component analysis (PCA) was applied to extract and identify the evaluation parameters of the unconformity's vertical structure. On the basis of Darcy's Law, the quantitative characterization formula of the unconformity's transport capacity with an actual geological significance was established after taking several factors into consideration. The migration probability of the unconformity was used to evaluate the possibility that the unconformity acted as a migration pathway. Consequently, a relationship between the migration probability and the evaluation parameters was developed to analyze the effectiveness of these parameters in characterizing the transporting capacity of the unconformity. This study shows that the quotient of the two principal components extracted from the conventional logging curves (Pc1/Pc2) have different reference values in the leached and parent rocks. The distribution of thicknesses of the weathered clay layer and the leached rock is well matched with the distribution of paleogeomorphology. The parameters representing only a single geological factor are not enough to determine whether the unconformity acted as a migration pathway. The flow coefficient (Cf) containing multiple factors can effectively and clearly identify the transporting capacity of the unconformity, considering the positive correlation between the parameter Cf and the migration probability of the unconformity. The oil and gas shows of the area with a parameter Cf greater than 10 × 10−4 cm2/s are abundant, which is the superior transporting area of the unconformity, and there is a good matching relationship between the distribution of the superior transporting area of the unconformity and that of the hydrocarbon distribution.

Identifying multiple sources of petroleum fluids in Browse Basin accumulations using diamondoids and semi-volatile aromatic compounds

Abstract Hydrocarbon fluid correlation studies often rely on compounds that are source-specific, but only represent a minor fraction of the bulk fluid (e.g. steranes). The correlation in the present study utilises compounds that represent a significant proportion of the bulk fluid, namely semi-volatile aromatics (SVA), and diamondoids. Comprehensive two dimensional gas chromatography coupled to time-of-flight mass spectrometry (GC × GC-TOFMS) was used to analyse diamondoids and SVA in whole oil/condensate samples from the Browse Basin, North West Shelf, Australia. Together with aromatic maturity ratios and the stable carbon isotopic composition for selected diamondoids and alkylbenzenes, these analyses demonstrate that numerous accumulations within the Browse Basin contain hydrocarbons from mixed sources. The diamondoid and SVA data provides further information on the current hydrocarbon fluid discrimination, which is primarily based on saturated biomarker compositions. Results of this study reveal a complex fill history by identifying the presence of a high maturity fluid(s) in the biodegraded accumulations on the Yampi Shelf, i.e. in the greater Cornea field and at Gwydion-1. This high maturity fluid is most likely derived from the Lower–Middle Jurassic Plover Formation (J10–J20 supersequences) in the greater Cornea area and, in the case of Gwydion-1, additional hydrocarbons may also be derived from the Upper Jurassic Vulcan Formation (J30–K10 supersequences). Other accumulations that comprise mixtures include Mimia-1 and Concerto-1 ST1 Deep, located to the north of the Ichthys field, and could represent charge from several Jurassic source rocks. The most mature fluids analysed in this basin are family II Plover-sourced and reservoired condensates from Kronos-1, Dinichthys North-1 and Gorgonichthys-1, as demonstrated by their elevated concentrations of the methyladamantanes and methyldiamantanes. The Dinichthys North-1 and Gorgonichthys-1 condensates also show a significant enrichment in the δ13C compound-specific values of the di-, tri- and tetra-methylbenzenes, whereas the Kronos-1 condensate does not, suggesting derivation from different source kitchens.

Characteristics of hydrocarbon transport systems and migration in slope areas of Qikou Sag, Bohai Bay Basin

The transport system plays an important role in hydrocarbon accumulation in slope area. The geochemical characteristics of the reservoir indicate that the oil and gas in this area generally have the tendency of migration and accumulation from the hydrocarbon generation center to the high part of slope. According to the relationship between source kitchens and traps, the hydrocarbon migration is divided into three types: inside source accumulation, near source vertical migration and outside source accumulation, controlled by the differential pressure between source rock and reservoir, dominant pathway-cap assembly and dominant migration phase respectively. The main types of migration pathway in the slope area are sand bodies, faults and unconformities, and the matching relationship between them controlled the direction and mode of oil and gas migration and accumulation in the slope area. The hydrocarbon migration and accumulation of middle-shallow layer in the low-middle slope are controlled by the dominant pathways and the matching relationship between faults and cap rocks, the hydrocarbon migration and accumulation in the middle slope are controlled by the favorable sedimentary facies, and the hydrocarbon migration and accumulation in the high slope are controlled by the distribution of sand bodies and favorable structures.

New concepts for deepening hydrocarbon exploration and their application effects in the Junggar Basin, NW China

The Junggar Basin is one of the major petroliferous basins with abundant oil and gas resources in onshore China. Around 2010 and thereafter, the hydrocarbon exploration for finding giant fields in the basin faced tough difficulties: in the northwestern margin area, no significant breakthrough has been made for long since seeking to “escape from the step-fault zone and extend to the slope area”; in the central part, the exploration for large lithologic-stratigraphic reservoirs stood still; since the discovery of the Kelameili gas field, no important achievement has been made in gas exploration. Under the guidance of “whole sag-oil-bearing” theory in the petroliferous basin, and based on the long-term study and thinking of the petroleum accumulation conditions and characteristics, the authors proposed several new concepts, i.e., a “thrust-induced second-order fault step” hiding under the northwestern slope area; six “hydrocarbon migrationward surfaces” favorable for hydrocarbon accumulation; promising natural gas resource. These concepts have played an important role in the discoveries of Wells Mahu1 and Yanbei1 as well as the confirmation and expansion of Permian-Triassic billion-ton-scale petroliferous areas in Mahu. The fairway of new discoveries has also appeared for natural gas exploration in Wells Fu26, Gaotan1 and Qianshao2, suggesting that the surrounding regions of the highly matured source kitchen are of high possibility to form gas accumulations.

One North Sea fairway analysis: revealing opportunities through data integration across scales

Abstract While the North Sea has many well-established prolific plays, the downwards trend of annual discovered resources has cast doubt on the continued ability of the stratigraphy to provide world-class future discoveries. However, despite this downwards trend, significant discoveries can still be made, such as Johan Sverdrup (Norwegian North Sea in 2010). Furthermore, new sub-plays within this petroleum system and new unproven plays with alternative source rocks are still being tested, although often with associated higher perceived pre-drill subsurface risk (Pg) and/or lower volume potential. There is room for new optimism, however, as new approaches and technologies are deployed, which could lead to future success. The analysis of regionally extensive integrated datasets allows for the interpretation of ‘One North Sea’ fairway maps that honour detailed observations from the prospect scale through to the play scale and beyond. By integrating source-rock maturity, hydrocarbon expulsion and migration, well shows, seismically defined gas chimneys, and direct hydrocarbon indications onto regional fairway maps, hydrocarbons can be traced from the source kitchens to the traps. By utilizing a zoom-in/zoom-out methodology, models can be developed, tested and applied across the basin, allowing new ideas to emerge, de-risk established prospects and reveal under-appreciated hydrocarbon volumetric upsides.

Major breakthrough of Well Gaotan 1 and exploration prospects of lower assemblage in southern margin of Junggar Basin, NW China

Abstract Well Gaotan 1 was tested a high yield oil and gas flow of more than 1 000 m3 a day in the Cretaceous Qingshuihe Formation, marking a major breakthrough in the lower assemblage of the southern margin of Junggar Basin. The lower assemblage in the southern margin of the Junggar Basin has favorable geological conditions for forming large Petroleum fields, including: (1) Multiple sets of source rocks, of which the Jurassic and Permian are the main source rocks, with a large source kitchen. (2) Multiple sets of effective reservoirs, namely Cretaceous Qingshuihe Formation, Jurassic Toutunhe Formation and the Khalza Formation etc. (3) Regional thick mudstone caprock of Cretaceous Tugulu Group, generally with abnormally high pressure and good sealing ability. (4) Giant structural traps and litho-stratigraphic traps are developed. The northern slope also has the conditions for large-scale litho-stratigraphic traps. (5) Static elements such as source rocks, reservoirs and caprocks are well matched, and the dynamic evolution is suitable for large oil and gas accumulation. The lower assemblage of the southern margin of the Junggar Basin has three favorable exploration directions, the Sikeshu Sag in the west part, the large structures in the middle and eastern part, and the northern slope.

Quantitative prediction of oil and gas prospects of the Sinian-Lower Paleozoic in the Sichuan Basin in central China

Abstract Reliably and conveniently predicting oil and gas prospects and avoiding costly drilling mistakes are the goals pursued by oil explorers and companies. In 2013, the Anyue gas field was discovered in Sichuan Basin, and it was the first discovery of a giant natural gas field in Precambrian strata attracting extensive attention since then. However, the complexity of geology in the Sinian-Lower Paleozoic makes prediction of oil and gas prospects very challenging. Based on the comprehensive review of the Anyue gas field, we identify four functional elements, i.e., a source kitchen (S), paleo-uplift (U), reservoir depositional facies (D), and regional cap rock (C). The combination of these four functional elements in time and space (T- CDUS) controls the Sinian-Lower Paleozoic hydrocarbon accumulation. The probability for hydrocarbon accumulation is determined by a proposed index, Tcdus. As a tectonic movement can damage oil and gas reservoirs formed prior to the movement, a model for calculating the hydrocarbon reservoir preservation probability is also established. The oil and gas prospects in Sinian-Lower Paleozoic are predicted with the combination of the hydrocarbon accumulation and preservation model. 137 wells drilled in the Sichuan Basin show that 88.9% of the successful wells are distributed in the predicted zones.

“Exploring petroleum inside source kitchen”: Connotation and prospects of source rock oil and gas

Abstract Based on the transitional background of the global energy structure, exploration and development of unconventional oil and gas, and investigation of key basins, the unconventional oil and gas resources are divided into three types: source rock oil and gas, tight oil and gas, and retention and accumulated oil and gas. Source rock oil and gas resources are the global strategic supplies of oil and gas, the key resource components in the second 150-year life cycle of the future petroleum industry, and the primary targets for “exploring petroleum inside source kitchen”. The geological connotation of source rock oil and gas was proposed, and the models of source rock oil and gas generation, expulsion and accumulation were built, and five source rock oil and gas generation sections were identified, which may determine the actual resource potential under available technical conditions. The formation mechanism of the “sweet sections” was investigated, that is, shale oil is mainly accumulated in the shale section that is close to the oil generation section and has higher porosity and permeability, while the “sweet sections” of coal-bed methane (CBM) and shale gas have self-contained source and reservoir and they are absorbed in coal seams or retained in the organic-rich black shale section, so evaluation and selection of good “sweet areas (sections)” is the key to “exploring petroleum inside source kitchen”. Source rock oil and gas resources have a great potential and will experience a substantial growth for over ten world-class large “coexistence basins” of conventional-unconventional oil and gas in the future following North America, and also will be the primary contributor to oil stable development and the growth point of natural gas production in China, with expected contribution of 15% and 30% to oil and gas, respectively, in 2030. Challenges in source rock oil and gas development should be paid more attention to, theoretical innovation is strongly recommended, and a development pilot zone can be established to strengthen technology and promote national support. The source rock oil and gas geology is the latest progress of the “source control theory” at the stage of unconventional oil and gas. It will provide a new theoretical basis for the new journey of the upstream business in the post-industry age.

Hydrocarbon prospectivity of the Cooper Basin, Australia

The Pennsylvanian-Middle Triassic Cooper Basin is Australia's premier conventional onshore hydrocarbon-producing province. The basin also hosts a range of unconventional gas play types, including basin-centered gas and tight gas accumulations, deep dry coal gas associated with the Patchawarra and Toolachee Formations, and the Murteree and Roseneath shale gas plays. This study used petroleum systems analysis to investigate the maturity and generation potential of 10 Permian source rocks in the Cooper Basin. A deterministic petroleum systems model was used to quantify the volume of expelled and retained hydrocarbons, estimated at 1272 billion BOE (512 billion bbl and 760 billion BOE) and 977 billion BOE (362 billion bbl and 615 billion BOE), respectively. Monte Carlo simulations were used to quantify the uncertainty in volumes generated and to demonstrate the sensitivity of these results to variations in source-rock characteristics. The large total generation potential of the Cooper Basin and the broad distribution of the Permian source kitchen highlight the basin's significance as a world-class hydrocarbon province. The large disparity between the calculated volume of hydrocarbons generated and the volume so far found in reservoirs indicates the potential for large volumes to remain within the basin, despite significant losses from leakage and water washing. The hydrocarbons expelled have provided abundant charge to both conventional accumulations and to the tight and basin-centered gas plays, and the broad spatial distribution of hydrocarbons remaining within the source rocks, especially those within the Toolachee and Patchawarra Formations, suggests the potential for widespread shale and deep dry coal plays.

The petroleum system: a new classification scheme based on reservoir qualities

A new classification of petroleum systems (PSs) based on reservoir qualities is proposed. We classify PSs into the following three basic types: (1) source-rock petroleum system (SPS); (2) tight-reservoir or tight petroleum system (TPS); and (3) conventional-reservoir or conventional petroleum system (CPS). The CPS is a PS in which hydrocarbons accumulate in conventional reservoirs, and all the essential elements and processes are significant and indispensable. Oil and gas accumulations are geographically discrete and therefore exist as discontinuous accumulations. The TPS is a PS where hydrocarbons accumulate in tight reservoirs and the source rock, reservoir, seal, migration, and trap are also indispensable, but the traps are mostly non-anticlinal and the accumulations are primarily quasi-continuous and secondarily discontinuous. The SPS is a PS where both hydrocarbon generation and accumulation occurred in source rocks and traps and migration are unnecessary or inconsequential; the hydrocarbon distribution is extensive and continuous and has no distinct boundaries. The aforementioned three PSs can be derived from a common hydrocarbon source kitchen and are closely linked in terms of their formation and distribution. Therefore, to maximize the exploration efficiency, a comprehensive study and different strategies are needed by considering the SPS, TPS, and CPS as parts of a greater whole.

Petroleum geochemical characterization of Albian-Oligocene sequences in the Campos Basin: “Case study: Eastern Marlim oilfield, offshore, Brazil”

The current research was performed in the eastern portion of the Marlim oilfield to identify the hydrocarbon-generating potential of the Albian-Oligocene sequences (Macaé Group, Ubatuba and Carapebus formations) in the Campos Basin, Brazil. On the basis of petroleum geochemical proxies, an integrated approach was developed using source rock characterizations to establish the distribution of source rock properties, such as organic matter content, hydrocarbon-generating potential, thermal maturity and stratigraphic thickness. The outcomes of a comprehensive petroleum geochemical characterization were integrated with cuttings and core sample descriptions, biostratigraphic controls, well log analyses and 2-D/3-D seismic interpretations. Our results reveal that for the Albian-Oligocene deposits, the key geochemical properties required to develop hydrocarbon source kitchens converge in specific locations, demonstrating a variable hydrocarbon potential ranging from poor to excellent and suggesting the existence of local generation pods in the central and principally northern portions of the research area. The accumulation and preservation of the organic matter were influenced by the paleo-topography and tectonic controls, and the lowest concentrations of organic carbon were attributed to significant siliciclastic dilution taking place mostly toward the middle and southern portions of the Eastern Marlim oilfield. Lateral variations in both the lithofacies and organic facies are the main conditions controlling the behavior of the petroleum potential in the investigated sediments. Our results indicate that the Macaé Group has sufficient source-rock potential, maturation patterns, and hydrocarbon-generating potential to be considered as an active source rock in the Eastern Marlim oilfield, where the petroleum geochemical properties converge and are adequate to generate hydrocarbon compounds. In addition, the Ubatuba and Carapebus formations are also likely to generate oil and/or gas, but due to their relatively low maturity, it is difficult to establish that these rocks can be active source rocks in the study area.

Geochemistry and possible origins of biodegraded oils in the Cretaceous reservoir of the Muglad Basin and their application in hydrocarbon exploration

The Muglad Basin is one of the largest petroliferous basins within the Central and Western African Rift System (WCARS). A total of 42 oil samples including light, normal and heavy crude oils from the Cretaceous reservoirs of the Muglad Basin were systematically analyzed to fully understand their geochemical characteristics and possible origins. The results of oil–oil correlation show that these Cretaceous crude oils are genetically identical and derive from the same source kitchen. Differences in physical properties and geochemical compositions may be attributed to secondary alteration, such as biodegradation. Lightly, moderately and severely biodegraded oils can be divided on the basis of the relative abundance of n–alkanes and acyclic isoprenoids in the oils and the presence of “humps” on gas chromatogram baselines, as well as of the relative abundance of 25–norhopanes. The biodegradation degree of Cretaceous oils in the Muglad Basin is closely related to the burial depth of oil reservoirs and the distance between the locations of oil reservoirs and adjacent faults. This study may have practical application for further petroleum exploration and development in the Muglad Basin.

Reservoir characteristics and hydrocarbon accumulation of the glauconitic sandstone in the Tarapoa Block, Oriente Basin, Ecuador

Although Oriente basin has explored throughout the past fifty years, little is known about the reservoir quality and hydrocarbon accumulation of the Cretaceous Upper T glauconitic sandstones. Until recently, the Upper T has drawn attention due to the commercial oil discovery. Howerer, exploration of glauconitic sandstones is complicated and reservoir quality is difficult to evaluate based on logging and seismic data.The glauconitic sandstones developed in open marine environments, characterized by a framework of glauconite and quartz grains. Diagenesis includes compation, silica overgrowth, feldspars dissolution, iron carbonate cementation. Its porosity ranges 5–20% and less than 500 md permeability. The dominant pore type is intergranular, especially residual intergranular. Glauconitic sandstones have bimodal pore throat size distributions and complex pore geometries.The Upper T glauconitic sandstones are capped by a thin veneer of fossiliferous limestones and laminated to burrowed shales. These large-area matured source rocks close to the glauconitic sandstones are probably the source kitchen in the slope of Oriente Basin. The oil pools are very little relation to structure. A large area of continuous developed glauconitic sandstone reservoirs and adjacent source rocks form an excellent source–reservoir–cap assemblage. Differ from previous views of long-distance migration from the southwest Oriente Basin, we propose that volume flow and diffusive flow are the primary migration and accumulation mechanism for the Upper T reservoir in Tarapoa Block.

Reconstruction of hydrocarbon generation and accumulation on the Gydan Peninsula and adjacent offshore areas using basin modeling approach

Based on structural and lithological grid models, a three-dimensional numerical dynamic model of the Mesozoic-Cenozoic sedimentary cover of the Gydan source kitchen and adjacent territories was built. The thermal history of sediments was reconstructed. A map of effective deep heat flow was compiled. A good agreement was found between the measured and calculated degrees of catagenetic transformation for Upper Jurassic rocks. The possible types of kerogens from the main Jurassic and Cretaceous source rock sequences were justified. The study also provides assessments of the volumes of hydrocarbon generation from the main source rock sequences, timing of formation of regional seals and possible extent of hydrocarbon accumulation in structural traps.

Oil and gas reservoirs of weathering crusts and Paleozoic basement in the southeast of Western Siberia (forecasting of hard-to-recover reserves)

The study and development of hard-to-recover reserves in the pre-Jurassic petroleum of Western Siberia is a new focus for development of the resource base and oil production in Russia, identified the necessity of assessing a special strategy, a conceptual scheme for forecasting and exploration. The aim of the study is to identify and assess the primary research areas of hydrocarbon reservoirs in pre-Jurassic basement by the example of underexplored areas of the Ust-Tym mega-depression and structures of the Nurol’ka mega-depression which are located on the well-developed oilfield infrastructure areas of Tomsk region. Object of study is the potential pre-Jurassic reservoirs of Permo-Triassic weathering crust and Paleozoic basement. The accumulations of weathering crust are associated with reservoirs formed on clay and siliceous, carbonate and acid volcanic rocks, and, under certain conditions, by ultrabasites. The reservoirs of bedrock are associated with secondary reservoirs formed by limestones, granites, rhyolites. The main oil source formation is the Lower-Jurassic Togur sediments. The study is carried out based on the concept of mainly vertical hydrocarbon migration. The research area is located in boundaries of the oil source formation. Thermal history reconstruction of oil source formation, cumulatively taking into account the temperatures of the localized source kitchen, is carried out by solving the direct and inverse problems of geothermy. The studies are based on a special technology that includes an integrated analysis of mapping results of the Togur oil source kitchen by the geotemperature criterion and predicting mapping of the weathering crust and the Paleozoic basement reservoirs according to the data of deep drilling, oil geological zoning and perspective areas ranking. In the territory of the Ust-Tym megadepression as the primary research area for the weathering crust reservoir the zone of the northeastern side of the megadepression has been selected. As the priority area for exploration of Paleozoic basement reservoirs the zone uniting the north-eastern slope of North-Parabel megamonocline and the adjacent southern part of Pyzhinsk mesodepression has been selected. As the perspective research area for the weathering crust reservoir the land of the south beads of Kulan-Igay and Tamrad basins and its adjacent areas for the territory of Nurol’ka megadepression have been identified. As the priority areas for research and development of Paleozoic basement reservoirs the south beads of Kulan-Igay basin and adjacent zone of Tamrad basin have been identified, as well as the lands of the south-eastern beads of Nurol’ka megadepression and the adjacent lands of Chuzik-Chizhap mesosaddle. The reliability of the forecast for perspective areas of the pre-Jurassic petroleum play is identified by comparison with the results of well testing and is about 70—80 %. It argues the previously formulated resource-efficient strategy and technology of exploration for oil deposits in the pre-Jurassic basement of Western Siberia.

Characteristics of source rock controlling hydrocarbon distribution in Huizhou Depression of Pearl River Mouth Basin, South China Sea

In a petroleum accumulation system, the source rock plays a significant geological role in controlling hydrocarbon distribution, because it provides the material basis for hydrocarbon accumulation. Thus, quantitative evaluations of source rock control on hydrocarbon distribution are useful for predicting future hydrocarbon discoveries. Using the Huizhou Depression in the Pearl River Mouth Basin, China, as a case study, geostatistical methods and probability calculation were employed to analyze the controlling effect of source rocks. The Huizhou Depression can be divided into five petroleum accumulation systems of which the Huixi contains the largest known amount of hydrocarbons. A probability model of hydrocarbon accumulations is established for quantitative evaluation of potentially favourable hydrocarbon distribution. In each petroleum accumulation system, the larger the hydrocarbon expulsion intensity, the larger the amount of hydrocarbons that accumulates; the longer the distance from the hydrocarbon expulsion centre, the lower the amount of hydrocarbon accumulates. The hydrocarbon distribution limit controlled by the source rock is 3.5 times the radius of the source kitchen in the Huizhou Depression. In the current state of exploration, oil fields in the Huizhou Depression are mainly observed in the areas 1.5 to 2 times the source kitchen radius. Based on the prediction model, structural highs around hydrocarbon source kitchens are potentially favourable zones for structural hydrocarbon reservoirs, and the interiors of source kitchens are potentially targets for subtle hydrocarbon reservoirs and unconventional resources.

The characteristics of source rock and hydrocarbon charging time of Precambrian granite reservoirs in the Bongor Basin, Chad

The success of hydrocarbon drilling in Precambrian granite reservoirs expands the petroleum exploration boundary in the Bongor Basin which belongs to the Central and western Africa Rift System. This study integrated the analyses of geochemistry, fluid inclusion and 1D basin models to characterize and identify the source rock of the granite reservoirs, reconstruct the burial history and investigate the time of the hydrocarbon charging in the granite reservoirs. The results indicate all the 5 synrift intervals are organic rich deposition and the kerogen is dominated by type Ⅱ1 and type Ⅰ. However, the Lower Cretaceous P, M and K Formations are regarded as potential hydrocarbon source rock intervals with a high richness of organic matters and thermal – evolution degrees. The close relationship in biomarkers between the crude oil in granite reservoirs and the source rocks in the P and M Formations indicates the P and M Formations are the most potential source kitchens for the granite reservoirs. Core samples obtained from 3 representative burial hills were used to conduct the fluid inclusion analysis. Constrained by the uplift history which was reconstructed based on the apatite fission track analysis obtained from the inner reports and the Ro-calibrated thermal history, four 1D basin models were carried out, and the model of the Well Baobab NE-1 indicates that the hydrocarbon generation began at the time of approximately 89 Ma. By projecting the homogenization temperature to the burial history of the corresponding wells, the hydrocarbon charging time was revealed: twice hydrocarbon charging in the granite reservoirs occurred simultaneously during 87 to 82 Ma and 76 to 72 Ma, corresponding to the uplifting episode in the Later Cretaceous.

Connotation and strategic role of in-situ conversion processing of shale oil underground in the onshore China

Abstract In-situ conversion processing (ICP) of shale oil underground at the depth ranging from 300 m to 3 000 m is a physical and chemical process caused by using horizontal drilling and electric heating technology, which converts heavy oil, bitumen and various organic matter into light oil and gas in a large scale, which can be called “underground refinery”. ICP has several advantages as in CO2 capture, recoverable resource potential and the quality of hydrocarbon output. Based on the geothermal evolution mechanism of organic materials established by Tissot et al., this study reveals that in the nonmarine organic-rich shale sequence, the amount of liquid hydrocarbon maintaining in the shale is as high as 25% in the liquid hydrocarbon window stage (Ro less than 1.0%), and the unconverted organic materials (low mature-immature organic materials) in the shale interval can reach 40% to 100%. The conditions of organic-rich shale suitable for underground in-situ conversion of shale oil should be satisfied in the following aspects, TOC higher than 6%, Ro ranging between 0.5% and 1%, concentrated thickness of organic-rich shale greater than 15 meters, burial depth less than 3 000 m, covering area bigger than 50 km2, good sealing condition in both up- and down-contacting sequences and water content smaller than 5%, etc. The shale oil resource in China's onshore region is huge. It is estimated with this paper that the technical recoverable resource reaches 70−90 billion tons of oil and 60−65 trillion cubic meters of gas. The ICP of shale oil underground is believed to be a fairway to find big oil in the source kitchen in the near future. And it is also believed to be a milestone to keep China long-term stability of oil and gas sufficient supply by putting ICP of shale oil underground into real practice in the future.

Origin and distribution of natural gas and oil in the Baiyun Depression, Pearl River Mouth Basin, South China Sea

The Baiyun Depression is the main hydrocarbon-rich province in the deep-water area of the Pearl River Mouth Basin, South China Sea. Several petroleum samples, well data and 3D-seismic data from the Baiyun Depression were collected, the geochemical features and origins were determined using various methods, and finally, their distribution pattern was analysed. The results are as follows: (1) the natural gases are the thermogenic gases of organic matter belonging to terrestrial organic gas. They are mainly kerogen-cracking gases with high maturities, and their kerogen is the mixed sapropelic-humic type. The carbon isotope of the oil indicates that its source rock may be a continental deposit. Most of the oil in the Baiyun Depression has suffered from gas washing, which substantially affected its light hydrocarbon content. The biomarker features of the oil contain high Pr/Ph (pristane/phytane), high oleanane and medium bicadinane, reflecting that its source rock contains a large amount of terrestrial organic matter. The steranes indicate that the oil is mature and is derived from both higher plant and algae. It can be concluded that natural gas and oil in the Baiyun Depression mainly originated from source rocks of Enping Formation. (2) The distribution pattern of natural gas and oil is mainly controlled by the characteristics of the hydrocarbon source kitchens and the hydrocarbon migration pathways. These results can provide some information for future petroleum exploration in the Baiyun Depression, as well as in other petroliferous basins with similar geological settings.

PETROLEUM CHARGE AND MIGRATION IN THE BLACK SEA: INSIGHTS FROM OIL AND SOURCE ROCK GEOCHEMISTRY

Although a number of significant oil and gas discoveries have been made within the Western Black Sea and the surrounding area, only sparse data about migration mechanisms are available. In this paper, biomarker and isotope data from five oilfields and one oil show located offshore Bulgaria and Romania (in the western Black Sea), and from one field onshore Georgia (at the margin of the eastern Black Sea), were compared with geochemical data from potential source rock intervals from borehole samples. The source rock data came from offshore Bulgaria and outcrop samples from onshore Georgia. The biomarker data indicates that all the oils analysed were generated by source rocks of Late Cretaceous or Cenozoic age. In the Western Black Sea sub‐basin, the most likely source rocks are Oligocene to Lower Miocene shales of the Maikop Group. Compound‐specific isotope data indicate that Lower Oligocene source rocks are the most significant although a contribution by Lower Miocene diatom‐rich source rocks cannot be excluded. For an oil sample from the Shromisubani field onshore Georgia, isotope data from individual n‐alkanes together with biomarker data indicates that the oil contains a mixture of hydrocarbons generated from the Middle Eocene Kuma Formation and the Oligocene part of the Maikop Group.Oligocene and Miocene source rocks are immature at the shelfal locations where the oil samples were recovered. Charge for these hydrocarbon accumulations is interpreted to have been provided by long‐distance lateral migration from source kitchens in more central parts of the Black Sea basin, where Oligocene and (some) Miocene source rocks are within the oil and gas window. The results of this study highlight the prospectivity of recently‐discovered deep‐water plays, and significantly de‐risk future deep‐water projects within the Black Sea area.