Search

Gas-bearing property evaluation and main controlling factor analysis have remained a concern in shale gas research. The application of principal component analysis, an important mathematical statistical method, in gas-bearing property evaluation and main controlling factor analysis of the Longmaxi shale in the Weirong area, Sichuan Basin, was examined. The Longmaxi shale exhibits high heterogeneity, manifested in the organic matter abundance, mineral composition, and pore structure. Seven geological factors, including the temperature, pressure, TOC content, clay content, brittle mineral content, pore volume, and specific surface area (SSA), were selected in principal component analysis. Four principal components with geological significance, such as mineral composition, formation condition, pore structure, and organic matter abundance, were extracted through principal component analysis, and further constituted a comprehensive factor. Shale gas-bearing properties were evaluated according to the score of the comprehensive factor. The Longmaxi shale could be identified as exhibiting good, medium, and poor gas-bearing properties based on the comprehensive factor scores of these samples. According to each geological factor's contribution to the comprehensive factor, combined with geological analysis, it could be considered that gas-bearing properties are primarily controlled by pore volume, SSA, and clay content, followed by TOC content, brittle mineral content, temperature and pressure., (© 2022. The Author(s).)

The north‐eastern Ordos Basin in Central China has become an exploration target in recent years due to the potential of natural gas resources in the Upper Palaeozoic strata. In this study, by analysing the geochemical characteristics of the source rocks and the natural gas, the genesis of the Upper Palaeozoic natural gas was identified. In addition, the accumulation process was discussed by combining studies of hydrocarbon generation and burial/thermal history. The results reveal three sets of source rocks developed in the study area—Carboniferous Benxi (C2b), Permian Taiyuan (P1t), and Shanxi (P1s) formations—consisting of mudstones, carbonaceous mudstones, and coals. The source rocks contain abundant Type III organic matter and have entered mature to high‐mature stage, while source rocks in the south‐eastern part of the study area have entered the overmature stage due to the activity of Zijinshan magmatic rocks. The natural gas has a high content of methane (average 93.99%). The stable carbon isotope of methane (δ13C1) value (average −37.05‰) and that of ethane (δ13C2) value (average −26.4‰) and the composition of the light hydrocarbons reflect the idea that the natural gas is organic in origin, thermogenic, and mainly terrigenous‐sourced. The evolution of a transitional to continental depositional environment of the source rocks results in the variation in the geochemical characteristics of the Upper Palaeozoic gas in the study area. Analysis of fluid inclusions indicates a long and continuous period of natural gas charging in the study area from 165 to 65 Ma. Sandstone bodies close to or interbedded with the source rocks made the gas charging from the source rocks to the reservoirs over a short distance with high efficiency, while faults and fractures provided paths for the gas migrating to reservoirs vertically far from the source rocks. The huge gas generation potential of the source rocks and continuous distribution pattern of sandstone bodies provides favourable conditions for the development of a large‐scale natural gas reservoir. [ABSTRACT FROM AUTHOR]

Abstract The Dongpu Depression, especially the northern part, is an important natural gas-rich area in the Bohai Bay Basin, China. The gases found in Es3M, Es3L and Es4 are mainly distributed in the western part of Qianliyuan, in Weicheng, and in the middle of the Wenliu area, respectively. However, few studies have been conducted on the relationship between the development of source rock and the enrichment of gas in different hydrocarbon-generating sags. In this paper, gas genetic types, distribution characteristics and gas-source correlations were analyzed using data from molecular and stable carbon isotope components of natural gas, biomarkers and thin sections. The results indicate that Es3M gas is predominantly oil-type gas and that Es3L gas is mainly mixed gases dominated by coal-type gas, with average dryness coefficients (C 1 /C 1–5) of 0.877 and 0.920, respectively. By contrast, Es4 gas is dry with an average dryness coefficient of 0.970 and displays the typical characteristics of coal-type gas from Carboniferous-Permian coal measures. Carbon isotope reversals are common in the gas samples, while their causes are different. The mixing of coal-type gas and oil-type gas is the main reason for the gas carbon isotope reversals in Es3M and Es3L. By contrast, the widely existing carbon isotope reversal in Es4 gas in the central part of Wenliu is related to the long-term migration and enrichment of coal-type gas from Carboniferous-Permian rocks. Gas-source correlations indicate that Es3M gas is predominantly from the in situ cracking of Es3M oil and that coal-type gas mixed within Es3L gas is from the Carboniferous-Permian coal measures. Highlights • Genetic types of natural gas in the northern Dongpu Depression were summarized. • Gas carbon isotope reversals in different target layers were analyzed. • Es3M gas is predominantly from in situ cracking of Es3M oil. • Coal-type gas mixed within Es3L gas is from the Carboniferous-Permian coal measures. [ABSTRACT FROM AUTHOR]

Recent exploration has revealed the great potential of gas resources, complicated gas distributions and geochemical characteristics of natural gases in tight sandstones of the West Sichuan Basin, China (WSBC). The chemical, stable carbon and light hydrocarbon compositions of natural gases from WSBC were investigated to assess the genesis, sources, and migration pattern leading to variations in the geochemical and stable carbon isotope compositions. The analysis shows that the natural gas in the Jurassic tight sandstones occurs as dry gas or wet gas in some places; however, most of the gas in the deep Triassic tight sandstones is apparently dry gas. Carbon isotope distributions increased in the order δ13C1 < δ13C2 < δ13C3 < δ13C4. The light hydrocarbon content increased in the order of chain (i.e. non-cyclic) alkanes, cycloalkanes, and aromatic hydrocarbons. Relatively high ethane carbon isotope values and methylcyclohexane contents indicated the presence of lacustrine coal-formed gases. The Jurassic natural gas is in a lower thermally mature stage and possibly originated from a mixture of T3X3 and T3X5 black mudstones. The deep Triassic natural gas was possibly originated in the deep source rocks because the gas has a relatively higher thermal maturity. Positive correlations between burial depth and methane content, dryness coefficient, δ13C1, and δ13C1-δ13C2 for the deep Triassic gas suggest that the migration distance was short and the source was nearby or the gas accumulated in situ. The chemical compositions and geological studies revealed that the fractionation of the Jurassic natural gases in a tight reservoir was predominantly caused by vertical migration rather than the maturity of the local source rocks. Copyright © 2016 John Wiley & Sons, Ltd. [ABSTRACT FROM AUTHOR]

Tight sandstone gas is regarded as a significant unconventional resource. One intriguing problem for tight sandstone gas accumulation is how gas was trapped in the tight-sandstone reservoirs. In this paper, we attempted to look for a reasonable explanation for this, which has attached great theoretical and practical significances. In this study, a dynamic equilibrium equation characterizing the critical buoyancy threshold (CBT) was established based on physical experiments, and the formation mechanism of tight gas and CBT were discussed. The explanations were further testified through the tight-gas reservoirs of the Upper Paleozoic Ordos Basin. A dynamical CBT occurs during the charge process in tight-gas reservoirs, and water- gas inversion with separating phases is dominated before natural gas reaches the CBT. At this stage, the driving force for gas movement is abnormal gas pressure, and almost no buoyancy exists. The pore throats, smaller than those corresponding to the CBT, enable the formation water to resist the gas to move upward. As a result, with no water-gas displacements, the gas migrates upward in a piston-like style forming continuous gas reservoir. The corresponding pore throat and depth of the CBT are geologically significant, which indicates a critical condition. However, the CBT condition is not constant and varies significantly according to the geologic setting. The case study of the tight-gas reservoirs of the Upper Paleozoic Ordos Basin indicates that the critical pore-throat radius was 1.77 µm by the end of the Early Cretaceous, with the corresponding critical permeability and porosity value of 0.686 mD and 10.6%, respectively. In contrast, its current counterparts are 1.33 µm, 0.39 mD, and 8.6%, respectively, which indicates that the original tight sandstone gas reservoir has shrunk during the geologic history. [ABSTRACT FROM AUTHOR]

Seven hydrocarbon reservoirs have been discovered to date in the Upper Ordovician of the Tazhong Area, a region in which hydrocarbon phase distribution is complex. In the present study, the genesis and controlling factors of the hydrocarbons with complex phase in the Tazhong Area were investigated on the basis of the geological and geochemical conditions required for the formation and distribution of hydrocarbon reservoirs, integrated with the source rock geochemistry, natural gas and oil properties, and oil and gas reservoir fluid tests PVT (i.e., pressure, volume, and temperature tests). The results indicate that hydrocarbon reservoir types in the Upper Ordovician of the Tazhong Area transition from unsaturated to saturated condensate-gas reservoirs from west to east and from condensate-gas reservoirs to unsaturated-oil reservoirs from north to south. The crude oil in the region originated primarily from the mixing of Lower-Middle Cambrian and Middle-Upper Ordovician source rocks, while the natural gas was sourced primarily from the cracking gas of Lower-Middle Cambrian crude oil. This hydrocarbon-phase distribution was controlled primarily by temperature and pressure and has been affected by multiple periods of hydrocarbon accumulation and alteration. The high-quality Lower-Middle Cambrian reservoir-cap assemblage may be an important target for future exploration of natural gas in the Tazhong Area. [ABSTRACT FROM AUTHOR]

Tight-sand gas in the Jurassic and shale gas within the fifth member of Xujiahe Formation (T3×5) in the Western Sichuan Basin (WSD) are currentiy regarded as the most proiific emerging unconventional gas plays in China. This study conducted a conventional evaluation of T3×5 source rocks in the WSD, and investigated their hydrocarbon generation and e×pulsion characteristics, including intensity, efficiency and amount. The results show that, the T3×5 source rocks are thick (generally >200 m), and have a high total organic content (TOC), ranging from 2.5 to 4.5 wt%. It is thus indivative of a great hydrocarbon generation potential when they underwent high thermal evolution (Ro>1.2%) in the area. In addition, an improved method of hydrocarbon generation potentiai is applied, indicating that the source rocks reached a hydrocarbon e×pulsion threshold with vitrinite reflectance (Ro) reaching 1.06%, and that the comprehensive hydrocarbon e×pulsion efficiency is about 60%. The amount of hydrocarbon generation and e×pulsion from T3×5 source rocks is 3.14×10 t and 1.86×10 t, respectiveiy, with a residual amount of 1.28×10 t within them. Continuous-type tight-sand gas is predicted to have developed in the Jurassic in the Chengdu Sag of the WSD because of the good source-reservoir configuration; the Jurassic sandstone reservoirs are tight, and the gas e×pelied from the T3x5 source rocks migrates for very short distances verticaliy and horizontaily. The amount of gas accumulation in the Jurassic reservoirs derived from T3x5 source rocks is up to 9.3×10 t. Geological resources of shale gas are up to 1.05×10 t. Small differences between the amounts calculated by the volumetric method and those obtained by hydrocarbon generation potential method may be due to other gas accumulations present within interbedded sands associated with gas shales. [ABSTRACT FROM AUTHOR]

Systematic analyses of the formation water and natural gas geochemistry in the Central Uplift of the Tarim Basin (CUTB) show that gas invasion at the late stage is accompanied by an increase of the contents of H2S and CO2 in natural gas, by the forming of the high total dissolved solids formation water, by an increase of the content of HCO−3, relative to Cl−, by an increase of the 2nd family ions (Ca2+, Mg2+, Sr2+ and Ba2+) and by a decrease of the content of SO2−4, relative to Cl−. The above phenomena can be explained only by way of thermochemical sulfate reduction (TSR). TSR often occurs in the transition zone of oil and water and is often described in the following reaction formula: σCH+CaSO4+H-2O→H2S+CO2+CaCO3. (1) Dissolved SO2−4 in the formation water is consumed in the above reaction, when H2S and CO2 are generated, resulting in a decrease of SO2−4 in the formation water and an increase of both H2S and CO2 in the natural gas. If formation water exists, the generated CO2 will go on reacting with the carbonate to form bicarbonate, which can be dissolved in the formation water, thus resulting in the enrichment of Ca2+ and HCO−3. The above reaction can be described by the following equation: CO2+H2O+CaCO3→Ca2++2HCO−3. The stratigraphic temperatures of the Cambrian and lower Ordovician in CUTB exceeded 120°C, which is the minimum for TSR to occur. At the same time, dolomitization, which might be a direct result of TSR, has been found in both the Cambrian and the lower Ordovician. The above evidence indicates that TSR is in an active reaction, providing a novel way to reevaluate the exploration potentials of natural gas in this district. [ABSTRACT FROM AUTHOR]

Abstract: The hydrocarbon migration and entrapment mechanism in the lower overlapped basins, occurring in the complex carbonate pore-fissure-fracture reservoirs, is one of the key problems that have to be solved for effective hydrocarbon exploration. The production, gas/oil ratio, and the composition of crude oils and natural gas in the TZ83 Well block are high at the intersection point of the NE and NW-strike faults and decrease gradually along the ridge of the structure. A basic model of the pore-fissure-fracture system is built according to the achievements in the research on carbonate karstification. Processes of hydrocarbon migration and entrapment in this system are analyzed, which indicate that an understanding of the complexness of differential hydrocarbon migration is the key to interpreting this phenomenon. The hydrocarbon must charge the nearest compartment before migrating further away to charge other compartments in its pathway in the complex pore-fissure-fracture system. As a result, the following two phenomena appear: (1) Gas is enriched near the hydrocarbon injection point and drives away the oil, which is enriched in the compartments farther from the injection point. (2) The complex gas–oil–water relationship is controlled by the lateral connecting networks. Based on this, this article shows that the fault intersection point is the injection point of the oil and gas, and the main pathway system is distributed along the ridge of the structure. The theory of deferential hydrocarbon migration in the pore-fissure-fracture system can be presented from two aspects: (1) In hydrocarbon exploration, the structure of the fissure-fracture system should be described first, and then the special distribution of gas–oil–water can be predicted according to the main charging point and the main pathway system. (2) Exploration should be confined to the hydrocarbon charging point and the main pathway systems. An explored area should not be abandoned merely due to failures in some wells. [Copyright &y& Elsevier]

In recent years, significant progress and breakthroughs have been made in the exploration of conventional and unconventional natural gas in the Lower Cambrian petroleum system in the Sichuan Basin in Central China, showing excellent exploration prospects. However, detailed evaluation of the Qiongzhusi shale, the main source rocks in the Lower Cambrian petroleum system, including their hydrocarbon generation and expulsion characteristics, is lacking, even though such evaluation is critical for understanding conventional and unconventional natural gas resource potential. To investigate the geological and geochemical characteristics of the Qiongzhusi shale, experiments including pyrolysis, total organic carbon (TOC), vitrinite reflectance (Ro), gas chromatography (GC) and gas chromatography–mass spectrometry (GC–MS) were conducted. Based on modeling work and fluid inclusion analysis, the hydrocarbon generation and expulsion characteristics of the Qiongzhusi shale and their control on hydrocarbon accumulation was analyzed, and the conventional and unconventional natural gas resource potential of the Lower Cambrian petroleum system was systematically evaluated. The results indicate that the organic matter of the Qiongzhusi shale is mainly derived from bacteria and algae deposited in a saline, reducing marine environment. The shale is predominantly composed of type I kerogen with an average TOC value of 1.85 wt%, and is widely distributed in the basin with an average thickness of 212.7 m. The Qiongzhusi shale is primarily post-mature with an average vitrinite reflectance (Ro) of 2.53%. Modeling work suggests the Qiongzhusi shale reached the hydrocarbon expulsion threshold (HET) at Ro = 0.9%, and the main hydrocarbon expulsion stages are Triassic, Jurassic, and Cretaceous. The maximum hydrocarbon generation and expulsion intensities at present day are 32 × 106 t/km2 and 18 × 106 t/km2, respectively. The conventional natural gas resource potential of the Longwangmiao Formation derived from the Qiongzhusi shale is estimated to be between 9.51 × 1012 m3 and 19.03 × 1012 m3. The unconventional shale gas resource potential of the Qiongzhusi shale is predicted to be 1.4 × 1012 m3, showing significant prospects for natural gas exploration. • Geochemistry characteristics of the Qiongzhusi Formation were systemically evaluated. • Hydrocarbon generation and expulsion characteristics of the Qiongzhusi Formation were first analyzed. • Conventional and unconventional natural gas resource potentials of ancient Lower-Cambrian petroleum system were calculated. [ABSTRACT FROM AUTHOR]

The Sinian Dengying Formation is a key target for deep oil and gas exploration in the Sichuan Basin, China. Natural gas was mainly distributed in the Ziyang–Weiyuan area (ZWA) and the Gaoshiti–Moxi area (GMA). At present, the genetic types and sources of natural gas are still unclear and controversial. The chemical composition, stable carbon isotopes, and biomarkers were used to analyze geochemical characteristics, genetic types, and gas–source relations. The results showed that the composition and content of hydrocarbon gas in the ZWA and GMA were similar. Natural gas was a typical dry gas with an average dry coefficient (C 1 /C 1 +) of 0.9991, which reflected higher methane (CH 4) content and lower heavy hydrocarbon gas (C 2 +) content. For nonhydrocarbon gas, CO 2 (0.01%–26.34%), N 2 (0.03%–24.95%), H 2 S (0.10%–3.19%), and He (0.01%–0.37%) were mainly distributed. Compared with the GMA, the ZWA was characterized by higher N 2 content and lower CO 2 content. Although the carbon isotopes had not been reversed, the values of δ13C 2 –δ13C 1 were different between the ZWA and GMA, with the GMA having the higher value. The assemblage relation between the natural gas composition and carbon isotopes indicated that the natural gas type was dominated by oil-cracking gas. Mud-shale in the high maturity stage of thermal evolution greatly influenced on the content of N 2 and He. H 2 S mainly belonged to thermochemical sulfate reduction (TSR), and most of CO 2 was formed by deep carbonate metamorphism and TSR. The gas–source relation showed that natural gas in the ZWA was derived from the Cambrian Qiongzhusi Formation and that the gas in the GMA mainly originated from the Sinian Dengying Formation and the Cambrian Qiongzhusi Formation. The established hydrocarbon generation model indicated that the Sinian Dengying Formation is potentially gas-rich. • The Sinian Dengying Formation natural gas was a typical dry gas, dominated by oil-cracking gas. • Source rocks of the Qiongzhusi Formation and Dengying Formation were the mainly gas source for gas reservoirs. • The resource potential was qualitatively evaluated by the established hydrocarbon generation model. [ABSTRACT FROM AUTHOR]

Natural gases in the Carboniferous Donghe Sandstone reservoir within the Block HD4 of the Hadexun Oilfield, Tarim Basin are characterized by abnormally low total hydrocarbon gas contents (<65%), low methane contents (<10%) and low dryness coefficients (<0.5), and a reversal of the normal trend of carbon isotope ratios, showing δ 13 C methane (C 1 ) > δ 13 C ethane (C 2 ) < δ 13 C propane (C 3 ) < δ 13 C butane (C 4 ). Specifically, methane is enriched in 13 C with the variations in δ 13 C 1 values between gases from Block HD4 and gases from its neighboring blocks reaching 10‰. This type of abnormal gas has never been reported previously in the Tarim Basin and such large variations in δ 13 C have rarely been observed in other basins globally. Based on a comprehensive analysis of gas geochemical data and the geological setting of the Carboniferous reservoirs in the Hadexun Oilfield, we reveal that the anomalies of the gas compositions and carbon isotope ratios in the Donghe Sandstone reservoir are caused by gas diffusion through the poorly-sealed caprock rather than by pathways such as gas mixing, microorganism degradation, different kerogen types or thermal maturity degrees of source rocks. The documentation of an in-reservoir gas diffusion during the post entrapment process as a major cause for gas geochemical anomalies may offer important insight into exploring natural gas resources in deeply buried sedimentary basins. [ABSTRACT FROM AUTHOR]

Deep sour gases are found in the Ordovician carbonate reservoir of the Tazhong Uplift in the Tarim Basin, northwest China. All sour gases in this field are dominated by gas hydrocarbons (C 1 –C 4 ) with varying amounts of H 2 S. Most of the gases in the eastern Tazhong are characterized by high gas dryness coefficients (>0.95), 13 C-enriched methane (δ 13 C 1 ranging from −44.6‰ to −35.8‰), and small difference between values of the δ 13 C 2 and δ 13 C 1 (δ 13 C 2 - 1 ). In contrast, the gases in the western Tazhong are characterized by relatively low gas dryness coefficients (mostly < 0.90), 13 C-depleted methane (δ 13 C 1 ranging from −54.9‰ to −35.7‰), and high values of δ 13 C 2 - 1 , indicating relatively lower maturity. Gas compositions, carbon isotope ratios, and diamantane data together with thermal pyrolysis experiments using sealed gold tubes suggest that the Ordovician gases in the Tazhong Uplift belong to oil cracking gases mixed with high-maturity 13 C-enriched dry gases, which originated from the deeper paleo-reservoirs cracking. The H 2 S (0.0008%–23.1000%) is attributed to thermochemical sulfate reduction (TSR); in contrast to typical TSR-altered gases, the natural gases in the western Tazhong are characterized by low dryness coefficients, relatively 13 C-depleted methane, and high δ 13 C 2 - 1 , suggesting a low degree of TSR alteration. Observations suggest that the H 2 S contents are generally high in the western Tazhong, with positive correlation to Mg 2+ concentrations and total dissolved solids (TDS) in the Ordovician formation water, indicating that TSR has entered early period of SO 4 2− contact ion pairs (CIPs) oxidation. Compared with the eastern Tazhong, the Mg 2+ concentrations and TDS in the western Tazhong are higher and form more CIPs that accelerate TSR and produce H 2 S. In addition, based on the analysis of the Cambrian formation water and the Cambrian gypsiferous salt, TSR might have also exist in the deeper Cambrian reservoirs, and the TSR-altered gases with high content of H 2 S migrated along faults to Ordovician reservoirs. [ABSTRACT FROM AUTHOR]

[Display omitted] • A new hydrocarbon generation and expulsion model was established. • Mudstones and Upper-Middle Eocene source rocks contributed most to petroleum system. • The new model provides an efficient method for identifying oil-gas sources. The widely developed Tertiary coal-bearing intervals in the Xihu Sag, East China Sea Shelf Basin in offshore eastern China, are hosted in the Middle-Upper Eocene Pinghu Formation (PHF) and Oligocene Huagang Formation (HGF). Based on field data and geochemical features, a new model for the hydrocarbon generation and expulsion is developed using Rock-Eval pyrolysis that was applied to quantify the potentials of coaly source rocks of the PHF and HGF throughout the Xihu Sag. The results suggest the coaly source rocks of the HGF and PHF are primarily composed of type II/III kerogen, and begin to expel hydrocarbon at 0.68 %R o and 0.71 %R o , respectively. Several hydrocarbon expulsion centers are located in the western slope zone for coals and the central anticline zone for mudstones, with the highest intensity of 3.5 × 106 and 24 × 106 t/km2 for coals and mudstones, respectively. Among all source rocks, the coals and mudstones contribute 2.5% and 97.5%, respectively, of the total expelled hydrocarbon, whereas the source rocks of the HGF and PHF provide 19% and 81%, respectively, of the total hydrocarbon. The study also shows that the natural gas discovered in the north of the central anticline zone and the north of the western subsag have mixed sources from the HGF and PHF while the light oil and condensate accumulated in other zones are primarily derived from the source rocks of the PHF. The model used in the Xihu Sag provides an efficient method for evaluating source rocks and identifying oil-gas sources. [ABSTRACT FROM AUTHOR]

Abstract: In the prolific Zhanhua Depression of the Bohai Bay Basin, eastern China, over 76% of the proven petroleum reserves occur in the Neogene Guantao and Minhuazhen formations. Detailed geological and geochemical mapping of the Phanerozoic strata in this area reveals that oil shales and dark mudstones in the Es4, Es3 and Es1 members of the Eocene–Oligocene Shahejie Formation have excellent potential as petroleum source rocks. Regional distributions of total organic carbon content, kerogen type and thermal maturation indicate that abundant mature source rocks are present in several discrete sag areas bounded by extensive basement-related fault networks. In contrast, source rocks along the paleo-topographic highs are currently immature with respect to the generation of conventional oils. This study examined the key molecular characteristics for the common isoprenoid, hopanoid and steroid biomarkers, in relation to source facies variations in lacustrine sediments. The hydrocarbon source potential and expulsion efficiency for each of the source rock units were evaluated, which integrated the source rock characteristics with regional thermal subsidence and sediment burial. An important observation made during this study is the striking contrast between the source potential and proven oil reserves within each stratigraphic section, illustrating how significant the migration of hydrocarbon fluids derived from deep mature source kitchens through over 2000 m of fine-grained formations must have been to form several giant oil accumulations in the shallow strata. These results support the concept of the “Neogene fault-fracture mesh petroleum plays” proposed by Zhang et al. (2004) [Marine & Petroleum Geology, 21, 651–668] and the vital role that the faults and fracture systems have in controlling hydrocarbon migration conduits and accumulation habitat in this rift basin. [Copyright &y& Elsevier]

Abstract: The chemical compositions of crude oils from over 20 oilfields in the Zhanhua Depression, Bohai Bay Basin, were studied in order to understand their genetic relationships, thermal maturity and biodegradation ranking. Molecular geochemical parameters indicate the presence of three possible oil families in reservoirs ranging from Paleozoic (basement) to Neogene. A number of biomarker features support deposition of the source rocks for these oils under a wide range of depositional environments. The majority of the oils discovered in the depression belong to the FL family, and display characteristics consistent with a dominantly freshwater (to slightly brackish water) lacustrine source rock in the Es3 member of the Shahejie Formation. The somewhat geographically restricted SL family oils are apparently linked to saline lacustrine, carbonate-evaporite source rocks distributed mostly in the upper Es4 member of the Shahejie Formation from the Bonan-Gubei sag areas. The thermally less mature BL family oils occur mostly within the Es1, Es2 or Dongying Formation reservoirs near the central sag areas, and show close affinities to the interbedded or intercalating Es1 calcareous mudstones and oil shales deposited in a slightly saline to dominantly brackish water lacustrine setting. The SL and FL family oils are generally mature, whereas most of the BL family oils usually show low maturity. Oil-source correlation demonstrates strong genetic relationships between the mature Es4 and Es3 source rocks of the Eocene–Oligocene Shahejie formation in the sag areas and the oils accumulated in the shallow Neogene petroleum plays. The geochemical data provide strong support for two sharply contrasting hydrocarbon migration scenarios: (1) short distance lateral migration is dominant in the central sag areas; and (2) the fault-fracture mesh facilitated vertical migration, and coupled with the regional porous Guantao Formation sand sheets, makes the structural, stratigraphic and lithological features over basement high blocks the focal points for petroleum accumulation. Therefore, further exploration in this highly mature petroleum province should focus on heavy oils in the shallow Neogene strata and light oils in the tight sandstones of the deep sag areas. [Copyright &y& Elsevier]

The study on the secondary migration of hydrocarbons in Ordovician carbonate reservoirs in the Lunnan area has been a challenge caused by limited geologic records as direct physical evidence, and physical simulations are difficult to conduct since the parameters of realistic geologic conditions are rare. Based on the analysis of the regional structure, and by integrating the study on the fluid properties and benzocarbazole nitrogen compounds parameters, the secondary hydrocarbon migration in Ordovician carbonate reservoirs in the Lunnan area, Tarim Basin, were investigated. The results indicated oil density show gradually increasing trends from Lungudong Fault to the Middle Slope in eastern Lunnan Uplift; while the trend is converse from southwest of Lunxi and Sangtamu Faults to the Middle Slope in western area. The benzocarbazole nitrogen compounds contents of Ordovician reservoir oil exhibit gradually increasing trends from southwest of Lunxi and Sangtamu Faults and southeast of Lungudong and Sangtamu Faults to the Middle Slope. The wax contents, gas dryness coefficients and gas/oil ratios show decreasing trends from east to west and away from the Lungudong Fault and Sangtamu Fault. The crude oil generated at the late Hercynian stage (about 290 Ma ago) in the Lunnan area migrated along the directions from southwest of Lunxi and Sangtamu Faults and southeast of Lungudong and Sangtamu Faults to the Middle Slope; the gas formed at the late Himalayan stage (about 208 Ma ago) migrated from the east to west laterally, and along the natural gas invasion faults Lungudong Fault and Sangtamu Fault upwards vertically. • The Ordovician oil and gas properties were analysed in the Lunnan area. • Carbazole nitrogen compound distribution was studied. • Secondary migration direction of Ordovician oil and gas was identified. [ABSTRACT FROM AUTHOR]