Xihu Sag Research Articles

Geochemical Characterization of the Eocene Coal-Bearing Source Rocks, Xihu Sag, East China Sea Shelf Basin, China: Implications for Origin and Depositional Environment of Organic Matter and Hydrocarbon Potential

Eocene coal-bearing source rocks of the Pinghu Formation from the W-3 well in the western margin of the Xihu Sag, East China Sea Shelf Basin were analyzed using Rock-Eval pyrolysis and gas chromatography–mass spectrometry to investigate the samples’ source of organic matter, depositional environment, thermal maturity, and hydrocarbon generative potential. The distribution patterns of n-alkanes, isoprenoids and steranes, high Pr/Ph ratios, abundant diterpanes, and the presence of non-hopanoid triterpanes indicate predominant source input from higher land plants. The contribution of aquatic organic matter was occasionally slightly elevated probably due to a raised water table. High hopane/sterane ratios and the occurrence of bicyclic sesquiterpanes and A-ring degraded triterpanes suggest microbial activity and the input of microbial organisms. Overwhelming predominance of gymnosperm-derived diterpanes over angiosperm-derived triterpanes suggest a domination of gymnosperms over angiosperms in local palaeovegetation during the period of deposition. The high Pr/Ph ratios, the plot of Pr/n-C17 versus Ph/n-C18, the almost complete absence of gammacerane, and the distribution pattern of hopanes suggest that the samples were deposited in a relatively oxic environment. Generally, fluctuation of redox potential is coupled with source input, i.e., less oxic conditions were associated with more aquatic organic matter, suggesting an occasionally raised water table. Comprehensive maturity evaluation based on Ro, Tmax, and biomarker parameters shows that the samples constitute a natural maturation profile ranging from marginally mature to a near peak oil window. Hydrogen index and atomic H/C and O/C ratios of kerogens suggest that the samples mainly contain type II/III organic matter and could generate mixed oil and gas.

2021–2025 is a period of great development of China's natural gas industry: Suggestions on the exploration and development of natural gas during the 14th five-year plan in China

Among the world's 10 major gas producing countries, only the United States (USA), Russia and Iran have annual gas production of 250 × 109 m3 or more. China is expected to have gas output of 250 × 109 m3 in 2025. There are three advantages for the great development of natural gas industry in China. Firstly, the natural gas resources are rich and the proved rate is low and only 8.6%, so it has the resource advantage for faster development; Secondly, over the past 35 years, natural gas production continues to grow, with the growth advantage for faster development; Finally, since 2006, the remaining recoverable reserves of natural gas have been increasing year by year, showing the reserve advantage for faster development. In recent 10 years, China's annual natural gas production growth rate, remaining recoverable reserves and reserve-production ratio of natural gas support that China's annual gas production in 2025 will reach 250 × 109 m3. Suggestions for accelerating natural gas exploration and development during the 14th Five-Year Plan Period: (1) Opening new exploration and development fields of Carboniferous-Permian shale gas in the Ordos Basin; (2) Exploring three potential large gas districts with hidden coal measures in the northern Tianshan Piedown Depression, Qaidam Depression, and Xihu Sag; (3) Accelerating the development of seven large gas fields with proved reserves over 100 × 109 m3, such as Lingshui 17–2 Gas Field; (4) Increasing the drilling of gas wells and ultra-deep exploration wells.

Studies on the Inversion Phenomenon of Physical Properties Observed in the Huagang Formation Reservoir in the Xihu Sag Based on the Water-Rock Reaction Experiments

Studies on the Inversion Phenomenon of Physical Properties Observed in the Huagang Formation Reservoir in the Xihu Sag Based on the Water-Rock Reaction Experiments

Origin and accumulation of natural gas in the Ningbo Tectonic Zone in the Xihu Sag

In this study, the geochemical characteristics of the oil and gas and the related source rocks in the Ningbo Tectonic Zone in the Xihu Sag are analysed to determine the source of the natural gas. The natural gas in the Ningbo Tectonic Zone is dry gas. It has a high content of methylcyclohexane and low contents of n-heptane and dimethylcyclopentane in the C7 light hydrocarbons and a heavy ethane-carbon isotope composition, indicating that the natural gas in the study area was derived from humic parent material, making it a coal-type gas. The ratios of the light hydrocarbon parameters of the NB-A and NB-B natural gas are significantly different from those of crude oil and the Pinghu Formation source rocks, indicating that there is no pronounced relationship between the natural gas and the Pinghu Formation source rocks, and the natural gas may be from the source rocks in the deeper horizons of the Pinghu Formation. The homogenization temperatures of the fluid inclusions in the upper member of the Huagang Formation (NB-A1) are mainly 140–150°C, which correspond to 3.5–0 Ma (Late Cenozoic) according to the paleogeothermal history, indicating that in this area, the natural gas in the upper member of the Huagang Formation has charged since the sedimentary period of the Santan Formation.

Analyzing the effects of multi-scale pore systems on reservoir Properties—A case study on Xihu Depression, East China Sea Shelf Basin, China

Determining the distribution and properties of multi-scale pores and the effect of these pores on reservoir properties is very significant for the analysis of the factors controlling pore structures and reservoirs quality. In this study, mercury injection porosimetry (MIP), field-emission scanning electron microscopy analysis (FE-SEM), and low-field nuclear magnetic resonance (NMR) experiments were conducted on the seven sandstone samples from Xihu Sag of the East China Sea Shelf Basin (ECSSB). The result shows that the MIP data were consistent with the other two methods so that MIP data can be used to classify pore sizes. By combining the experiment results with fractal theory, the pore size distribution can be divided into five groups: Ⅰ-micro-pores, Ⅱ-micro-pores, small pores, medium pores, and macro-pores. Considering the importance of pore throats size to the reservoir performance, the average throat based on the contribution of throats to permeability (D‾) was determined and taken as average pore throat size. Moreover, the proportions of these pores/pore throats were determined, and the effects of these pores/pore throats on reservoir parameters (porosity (ϕ), permeability (K), and irreducible/bond water saturation (Swi)) were analyzed. The results show that medium pores (2.5–25 μm) strongly influence ϕ and Swi, and D‾ is the major control on permeability. In addition, the relationships of types of pores, such as primary pores and mixed pores, to the medium pores and D‾ were analyzed in order to clarify the impact of pore textures. The results imply that the concentration and sizes of the primary pores appear to the most important factors controlling the development of medium pores and D‾.

Effects of evaporative fractionation on diamondoid hydrocarbons in condensates from the Xihu Sag, East China Sea Shelf Basin

Evaporative fractionation is a complex phenomenon associated with the separation of gas from oil in the subsurface, generally involving migration fractionation and gas invasion. The concentrations and distributions of diamondoid hydrocarbons in condensate samples with different type and extent of evaporative fractionation from the Xihu Sag, East China Sea Shelf Basin were investigated to determine the effects of evaporative fractionation on diamondoid hydrocarbons. The results suggest that both migration fractionation and gas invasion can affect the concentrations and distributions of diamondoid hydrocarbons. Residual oils after migration fractionation are generally characterized by relatively high concentrations of diamondoid hydrocarbons and low methyladamantanes/methyldiamantanes (MAs/MDs) ratios. However, maturity parameters based on diamondoid hydrocarbon isomers do not vary significantly from other typical maturity parameters, suggesting that they can still be used to assess maturity. Gas invasion causes the concentrations of diamondoid hydrocarbons in oil samples to rise generally, along with methyladamantanes/methyldiamantanes (MAs/MDs) and adamantane/diamantane (A/D) ratios, indicating that the effects of gas invasion on diamondoid hydrocarbons in oils are different from those of migration fractionation. In addition, gas invasion causes some changes in the diamondoid derived maturity parameters. Thus, the effects of gas invasion should be considered when using diamondoid hydrocarbons to evaluate the thermal maturity of crude oil. Diamondoid hydrocarbon concentrations and distributions in petroleum can be affected by evaporative fractionation, suggesting that it is possible to determine evaporative fractionation according to the diamondoid hydrocarbon composition. It can be proposed that the decreasing values of MAs/MDs ratios and increase of diamondoid concentration are indicators of migration fractionation, and increasing values of A/D, MAs/MDs and diamondoid concentration might suggest the introduction of additional gas.

Provenance, clastic composition and their impact on diagenesis: A case study of the Oligocene sandstone in the Xihu sag, East China Sea Basin

Sandstone composition, heavy mineral analysis, and bulk rock geochemistry analyses were used to investigate the provenance lithotypes and sediment transport pathways of the third, fourth, and fifth (E3h3, E3h4 and E3h5) members of the E3h Formation at the gas–reservoir scale in the Xihu sag, East China Sea Basin. In addition, the diagenetic features and porosity of the metamorphic-sourced and volcanic-sourced sandstones were investigated. The provenance lithotypes of the E3h3, E3h4, and E3h5 were mainly medium–low grade metamorphic rocks and felsic to intermediate volcanic rocks. The sediment transport pathways were from northeast to southwest and from east to west, indicating that the E3h3, E3h4 and E3h5 members had two sediment provenance, namely, the metamorphic rocks of the northern Hupijiao Rise and the volcanic rocks of the eastern Diaoyudao Rise. Then the sedimentary microfacies distribution of the E3h3, E3h4, and E3h5 members and its relationship with the dual provenance sedimentary system were determined by using the heavy mineral assemblages, ZTR index, grain sizes, lithic fragments and quartz content. The initial porosity values of the metamorphic-sourced medium-grained and fine-grained sandstones were 35.35% and 35.22%, respectively; while the initial porosity values of the volcanic-sourced medium-grained and fine-grained sandstones were 34.09% and 34.97%, respectively. The average porosity compaction loss percentages were mainly 80.2% and 86.91% for the metamorphic-sourced medium–grained and fine–grained sandstones, and 86.95% and 87.23% for the volcanic-sourced medium–grained and fine–grained sandstones. The contact types of mineral grains in the metamorphic-sourced sandstones were mainly punctual, linear and concave-convex contacts; while the contact types of mineral grains in the volcanic-sourced sandstones were mainly linear, concave-convex, and sutured contacts. The metamorphic-sourced sandstone mainly developed chlorite coats; while the volcanic-sourced sandstones mainly contained pore-filling chlorite. The average quartz cement contents were 0.83% and 0.61% for the metamorphic-sourced medium–grained and fine–grained sandstones, and 0.67% and 0.43% for the volcanic-sourced medium–grained and fine–grained sandstones. The illite, mixed-layer illite/smectite and calcite cement reduced the sandstone porosity by filling pores. The metamorphic–sourced sandstones mainly developed primary intergranular pores and intergranular dissolved pores; while the volcanic–sourced sandstones mainly developed intergranular dissolved pores, intragranular dissolved pores, and moldic pores. The metamorphic-sourced sandstones had a higher porosity than the volcanic-sourced sandstones with the same grain size, which the difference in their porosities reached 1–3%.

Hydrocarbon Generation Potential and Depositional Setting of Eocene Oil-Prone Coaly Source Rocks in the Xihu Sag, East China Sea Shelf Basin.

The Xihu Sag in the East China Sea Shelf Basin is a focus for hydrocarbon exploration and development. Hydrocarbons in the Xihu Sag are believed to have mainly originated from coals in the Paleogene Pinghu Formation (shortened as Pinghu coal). In this study, the hydrocarbon generation potential, origin of organic matter, and depositional setting of the Pinghu coal were analyzed by means of optical microscopic analysis, bulk organic geochemistry, and molecular geochemistry analysis. The results reveal that the maceral compositions of the Pinghu coal are characterized by a predominance of vitrinite (73.91–96.13%) with relatively high contents of liptinite (1.47–23.02%) and only minor amounts of inertinite (0–5.18%). Type II–III kerogen and high values of TOC (total organic carbon) (8.24–56.77%), EOM (extractable organic matter) (14 601–112 259 ppm), and HI (hydrogen index) (178.76–291.18 mg·HC/g·TOC) indicate that the Pinghu coal is both gas- and oil-prone and could not only generate but also expel hydrocarbons. The results of vitrinite reflectance (0.54–0.90%), Tmax (421–453 °C), and biomarker-related parameters, including CPI (carbon preference index) (1.10–1.61), OEP (odd-to-even predominance) (1.09–1.49), 22S/(22S + 22R) for C31 homohopane (0.59–0.62), and 22S/(22S + 22R) for C32 homohopane (0.57–0.60), suggest that these coaly source rocks have entered the hydrocarbon generation threshold, most of which have entered the expulsion threshold. Biomarker-related parameters of ∑n-C21-/∑n-C22+ (0.38–3.62), Pr/Ph (3.33–9.23), Pr/n-C17 (1.91–14.88), Ph/n-C18 (0.35–1.83), 22S/(22S+22R) of C31 homohopane (0.59–0.62), 22S/(22S + 22R) of C32 homohopane (0.57–0.60), 1,2,7-TMN/1,3,7-TMN (0.74–14.39), and 1,2,5-TMN/1,3,6-TMN (2.22–21.07) suggest that organic matter in the Pinghu coal was deposited under relatively oxic peatland conditions characterized by a predominance of terrestrial higher plant input, especially the resin-rich Pinaceae and Taxodiaceae. The absence of combustion-derived PAHs indicates that neither vegetation fire nor peat fire occurred very frequently during the formation of peat. Areas in the Xihu sag with considerable thicknesses of coal should be paid particular attention for future hydrocarbon exploration. From a global perspective, Cenozoic coaly source rocks, which are characterized by a relatively high content of aliphatic components, should be paid special attention for their oil-prone properties related to the advent of conifer plants.

Diagenetic evolution of the Oligocene Huagang Formation in Xihu sag, the East China Sea Shelf Basin

The deep and ultra deep clastic reservoir is characterized by strong reservoir heterogeneity and complicated reservoir-forming characteristics for its high degree of diagenetic stage and the complexity of diagenesis. In order to better study the diagenetic evolution of deep and ultra deep reservoir in the burial process, a fine subsection scheme of 36 diagenetic micro-stage (DS) in diageneitic process was proposed based on paleotemperature (T), vitrinite reflectance (Ro%) and proportion of smectite in illite/smectite interstratified minerals (I/S-S%). Taking the Oligocene Huagang Formation in the Xihu sag of the East China Sea Basin as an example, the diagentic stage IIA1–IIA2–IIB was identified mainly by means of formation temperature data (T), homogenization temperature of fluid inclusion (Th), vitrinite analysis and clay mineral X-ray diffraction method. On this basis, diagenetic evolution using the fine subsection scheme in geological time were conducted. This fine division of diagenetic stage could bring accurate insight into porosity evolution history, hydrocarbon charging periods, diagenetic and reservoir-forming characteristics of low-permeability and tight sandstone.

HIGHER LANDPLANT –DERIVED BIOMARKERS IN LIGHT OILS AND CONDENSATES FROM THE COAL‐BEARING EOCENE PINGHU FORMATION, XIHU SAG, EAST CHINA SEA SHELF BASIN

The Cenozoic Xihu Sag in the East China Sea Shelf Basin contains large reserves of coals together with liquid petroleum derived from coal‐associated sediments. However, the origin of the petroleum is not well understood. In this study, biomarker assemblages in a suite of recently discovered light oils and condensates from the Paleogene succession in the western margin of in the Xihu Sag were investigated using gas chromatography – mass spectrometry. The objectives were to investigate the samples' thermal maturity and the depositional environment of the precursor source rocks which generated the oils. The light oils are believed to have been derived from coaly source rocks in the Eocene Pinghu Formation.Assessment of thermal maturity based on CPI, pristane/n‐C17 ratio and isomerisation ratios of C29 steranes and C31 homohopanes suggest that the hydrocarbons have a relatively low maturity in the early to mid oil generation window. The distribution of isoprenoids relative to n‐alkanes, the high pristane/phytane ratios (5.1–10.7), the almost complete absence of gammacerane and C33+ homohopanes, and the low dibenzothiophene/phenanthrene ratios indicate that the source rocks of the hydrocarbons were deposited in a relatively oxic and sulphate‐poor fluvio‐deltaic environment which was favourable for coal measure development.Abnormally abundant gymnosperm‐derived diterpanes including labdane, 19‐norisopimarane, fichtelite, rimuane, pimarane, isopimarane, 17‐nortetracyclic diterpene, phyllocladanes and abietane were detected in the samples analysed. 16a(H)‐Phyllocladane was identified unambiguously and kauranes were confirmed to be absent. In addition, three 19‐norisopimarane isomers, 13β(H)‐atisane, and 20‐normethylatisane were tentatively identified in the studied samples. The distributions of n‐alkanes, isoprenoids and regular steranes, the presence of 4β(H)‐eudesmane and oleanane, high Pr/Ph ratios and the abundant diterpanes together suggest that the hydrocarbons were derived from a coaly source rock. Gymnosperms of the conifer families Cupressaceae (especially the former Taxodiaceae) and Pinaceae are interpreted to be the major source of the diterpanes and to have made a significant contribution to the coaly source rock. However, the low abundance of oleanane relative to diterpanes may underestimate the contribution from angiosperms relative to gymnosperms. This could be due to differential preservation and alteration of the di‐ and triterpenoid precursors during diagenesis and the occurrence of non‐specific precursors in higher land plants.

Defining stratigraphic oil and gas plays by modifying structural plays: A case study from the Xihu Sag, east China Sea Shelf Basin

The study focuses on an area of relatively mature oil and gas exploration located in the western slope of the Xihu Sag, East China Sea Shelf Basin. Three stratigraphic oil and gas plays are introduced to replenish the shrinking prospect inventory in the area. The reservoirs of these plays are traditional pay intervals of the Eocene Pinghu Formation and Baoshi Formation composed of tide-dominated delta front, tidal flat and delta front sand bar facies. By investigating conventional seismic data, seismic inversion volumes, and well log data, multiple tidal-influenced delta front channels, beach sand packages have been mapped out in different reservoir sand intervals of the Pinghu Formation and Baoshi Formation. We recognize four types of stratigraphic terminations: channel flank pinch-outs, axial pinch-outs of sand-fills, channel mouth sand bar pinch-outs, and onlap pinch-outs for the Baoshi Formation. Both the depositional facies and relatively low sand-shale ratio of the reservoir formations favor the occurrence of stratigraphic terminations. The closure mechanism of all these plays are similar to the traditional structure plays in the area: fault blocks or fault-bounded rollover anticlines, except that one or more closing faults are replaced by these stratigraphic terminations. Several small-sized closures should exist but the relatively large ones are centered around a major intra-slope rise, raising the exploration potential in this maturely explored area. The new exploration drilling campaign has so far tested the play of delta front channel facies, with three out of four wells commercially successful. These play concepts open up a novel approach to identify new traps in the study area and many other rift basins with similar settings in eastern China.

Hyperpycnal flow depositional characteristics and model in an ancient continental basin: a record from the Oligocene Lower Huagang Formation in the Xihu Sag, East China Sea Shelf Basin

Modern observations have determined the presence of hyperpycnal flows; however, their presence in ancient rocks is scarcely reported in the literature, particularly with respect to continental strata. The present study is the first to use core and thin-section analyses and examination of physical reservoir properties to identify hyperpycnal flow sediment from the lower section of the Oligocene Huagang Formation in the central Xihu Sag, East China Sea Shelf Basin. The multiple fine sandy layers are characterized by lower reverse-graded and upper normal-graded bedding with horizontal bedding, climbing-ripple lamination, wavy bedding, and small foreset laminae. Microerosion surfaces are occasionally present between the reverse-graded and normal-graded bedding, and plant fragments are sometimes visible in the deposits. The same grain size sequence changes are observed in the thin sections. This lithologic combination is considered to be related to hyperpycnal flow sedimentation caused by flood events. The lower reverse-graded and upper normal-graded bedding sequences indicate that the flood energy first increased then decreased and the microerosion surfaces were formed through erosion of lower sediments by the flood. Hyperpycnal flows can directly transport deposits from an estuary to a deep-water basin, which distinguishes them from typical turbidity currents. This study also establishes a sedimentary model of the hyperpycnal flow in lacustrine basin, which can be used as a reference for future hyperpycnal deposit studies.

Fracture development and hydrocarbon accumulation in tight sandstone reservoirs of the Paleogene Huagang Formation in the central reversal tectonic belt of the Xihu Sag, East China Sea

Abstract By using thin section identification, cathodoluminescence, major and trace elements and fluid inclusion tests and authigenic illite dating, based on observation of core cracks, combined with the microscopic characteristics and imaging logging characteristics of fractures, the stages of the fractures in the Huagang Formation of the central reversal tectonic belt of the Xihu Sag in the East China Sea, and the matching relationship between the fracture development stages and the oil and gas charging stages are clarified. There are diagenetic fractures and tectonic fractures in the reservoirs of the Huagang Formation in the study area. The diagenetic fractures developed during the diagenetic stage of the reservoirs and have less effect on oil and gas migration and transport. The tectonic fractures are divided into three stages based on tectonic movements controlling the fractures and their relationships with hydrocarbon charging: The first stage of fractures was generated in the early stage of the Himalayan Movement–Longjing Movement (12–13 Ma ago), when the tectonic stress caused the sutures and shale strips to twist, deform, and break. Tectonic microfractures generated in this period had short extension, narrow width, and poor effectiveness, and had little effect on oil and gas migration and transport. The second stage of fractures came up during the middle-late period of Himalayan Movement–Longjing Movement (9–12 Ma ago), when tectonic movements caused the development of tectonic fractures in the central reversal tectonic belt, these fractures are of large scale, long extension, and good effectiveness, and matched with the first stage of large scale oil and gas charging (9–12 Ma ago), so they play an important role in oil and gas migration, transportation, and accumulation. The third stage of fractures were created from Himalayan Movement–Okinawa Trough movement to the present day (0–3 Ma ago), the fractures are tectonic ones developing successively; matching with the second stage (0–3 Ma ago) of large-scale oil and gas charging, they created conditions for continuous natural gas migration and transportation. All these prove that the development of reservoir fractures in the Huagang Formation of Xihu Sag can provide seepage space and continuous and effective channels for efficient migration and accumulation of oil and gas.

Organic geochemistry and kinetics for natural gas generation from mudstone and coal in the Xihu Sag, East China Sea Shelf Basin, China

Abstract A comparative study on organic geochemistry and kinetics was performed on two representative coal measure mudstone and coal samples of the Eocene Pinghu Formation in the Xihu Sag, East China Sea Shelf Basin, China. Gas chromatography–mass spectrometry analysis of the aliphatic fractions of the source rock extracts was performed to characterize the maturity, depositional conditions, and source materials in the samples. The kerogens isolated from the mudstone and coal were pyrolyzed in a closed-system at two heating rates to determine the kinetics for natural gas generation, and the results were extrapolated to geological conditions. Biomarker assemblages show that the mudstone (type III kerogen) and coal (type II/III kerogen) contain predominantly terrigenous source materials with the effect of microbial reworking, and were deposited under oxic conditions within an unstratified water column. The mudstone has slightly more algal material input and less oxic conditions during deposition than the coal. The rocks are at the early-mature stage but the coal is slightly more mature than the mudstone. The activation energies for natural gas generation from the mudstone and coal distribute mainly in the range of 47–62 kcal/mol and 50–69 kcal/mol with a frequency factor of 2.0 × 1011 s−1 and 1.0 × 1013 s−1, respectively. The lower activation energies for the mudstone than the coal suggests an earlier onset of natural generation. Assuming a constant burial heating rate of 3 °C/Ma for the calculated activation energy distributions, the calculated temperature for a given transformation ratio can differ by > 60 °C, indicating varying kinetic stability due to different kerogen composition and structure. This significant and unexpected difference suggests that more attentions should be paid to the kinetic heterogeneity of coal bearing source rocks, and we must be particularly cautious about selecting appropriate kinetic models in petroleum system modeling.

Organic Geochemical and Petrographic Characteristics of the Coal Measure Source Rocks of Pinghu Formation in the Xihu Sag of the East China Sea Shelf Basin: Implications for Coal Measure Gas Potential

AbstractCoal measure source rocks, located in the Xihu Sag of the East China Sea Shelf Basin, were analyzed to define the hydrocarbon generation potential, organic geochemistry/petrology characteristics, and coal preservation conditions. The Pinghu source rocks in the Xihu Sag are mainly gas‐prone accompany with condensate oil generation. The coals and shales of the Pinghu Formation are classified from “fair” to “excellent” source rocks with total organic carbon (TOC) contents ranging from 25.2% to 77.2% and 1.29% to 20.9%, respectively. The coals are richer in TOC and S1+S2 than the shales, indicating that the coals have more generation potential per unit mass. Moreover, the kerogen type of the organic matter consists of types II‐III and III, which the maturity Ro ranges from 0.59% to 0.83%. Petrographically, the coals and shales are dominated by vitrinite macerals (69.1%–96.8%) with minor proportions of liptinite (2.5%–17.55%) and inertinite (0.2%–6.2%). The correlation between maceral composition and S1+S2 indicates that the main contributor to the generation potential is vitrinite. Therefore, the coals and shales of the Pinghu Formation has good hydrocarbon generation potential, which provided a good foundation for coal measure gas accumulation. Furthermore, coal facies models indicates that the Pinghu coal was deposited in limno‐telmatic environment under high water levels, with low tree density (mainly herbaceous) and with low‐moderate nutrient supply. Fluctuating water levels and intermittent flooding during the deposition of peat resulted in the inter‐layering of coal, shale and sandstone, which potentially providing favorable preservation conditions for coal measure gas.

Petrology and hydrocarbon significance of the coaly source rocks from the Pinghu Formation in the Xihu Sag, East China Sea Shelf Basin

The Xihu Sag in the East China Sea Shelf Basin contains abundant oil and gas reserves and is a focus for hydrocarbon exploration and development. Source rocks are mainly coals and coal-measures mudstones in the Paleogene Pinghu and Huagang formations. Samples from the Pinghu Formation in the Xihu Sag were collected for petrology, total organic carbon, and Rock-Eval analysis for the purpose of investigating macerals component and their contributions to hydrocarbon generation potential. The coaly source rocks from the Pinghu Formation are dominated by vitrinite (average 86.18%) but have an obviously elevated content of liptinite (average 12.59%) and a much lower amount of inertinite (average 1.23%). Liptinite of the samples is mainly composed of resinite, with a small amount of cutinite, sporinite and alginate in descending order. TOC values are 37.55%–65.58% (average 49.16%). Effective HI values are 167–281 mg HC/g TOC (average 223.5 mg HC/g TOC), suggesting the organic matter is type II kerogen. Relatively high HI values and macerals components suggest that the coaly source rocks can generate both oil and gas. Although the liptinite in the coaly source rocks has a content lower than vitrinite values, it makes a significant contribution to both total hydrocarbon and liquid hydrocarbon generation. The contributions of vitrinite, liptinite and inertinite to the total hydrocarbon generation approximately are 63.21%, 36.46% and 0.33%, respectively. The contributions of vitrinite and liptinite to the liquid hydrocarbon generation are approximately 40.95% and 59.05%, respectively. These results demonstrate that the coaly source rocks are dominated by vitrinite macerals with a relatively higher content of liptinite macerals, especially resinite, and these source rocks are more prone to both total hydrocarbon and liquid hydrocarbon generation. Paleogene coaly source rocks from other parts of the world should be considered for their oil-prone nature.

Factors controlling the development of tight sandstone reservoirs in the Huagang Formation of the central inverted structural belt in Xihu sag, East China Sea Basin

By means of thin section analysis, zircon U-Pb dating, scanning electron microscopy, electron probe, laser micro carbon and oxygen isotope analysis, the lithologic features, diagenetic environment evolution and controlling factors of the tight sandstone reservoirs in the Huagang Formation of Xihu sag, East China Sea Basin were comprehensively studied. The results show that: the sandstones of the Huagang Formation in the central inverted structural belt are poor in physical properties, dominated by feldspathic lithic quartz sandstone, high in quartz content, low in matrix, kaolinite and cement contents, and coarse in clastic grains; the acidic diagenetic environment formed by organic acids and meteoric water is vital for the formation of secondary pores in the reservoirs; and the development and distribution of the higher quality reservoirs in the tight sandstones of the Huagang Formation are controlled by sediment source, sedimentary facies belt, abnormal overpressure and diagenetic environment evolution. Sediment provenance and dominant sedimentary facies led to favorable initial physical properties of the sandstones in the Huagang Formation, which is the prerequisite for development of reservoirs with better quality later. Abnormal high pressure protected the primary pores, thus improving physical properties of the reservoirs in the Huagang Formation. Longitudinally, due to the difference in diagenetic environment evolution, the high-quality reservoirs in the Huagang Formation are concentrated in the sections formed in acidic diagenetic environment. Laterally, the high-quality reservoirs are concentrated in the lower section of the Huagang Formation with abnormal high pressure in the middle-northern part; but concentrated in the upper section of Huagang Formation shallower in burial depth in the middle-southern part.

东海西湖凹陷P油田古近系始新统沉积模式及油气地质意义

东海西湖凹陷P油田古近系始新统沉积模式及油气地质意义

Fluvial morphology and reservoir sand-body architecture in lacustrine rift basins with axial and lateral sediment supplies: Oligocene fluvial–lacustrine succession in the Xihu sag, East China Sea Shelf Basin

The Xihu sag, which is the largest petroliferous sub-basin of the East China Sea Shelf Basin, formed in a continental back-arc setting. The Oligocene Huagang Formation consisting of a fluvial–lacustrine succession deposited during the compressional stage is the prime hydrocarbon-bearing interval in the Xihu sag. A third-order sequence-stratigraphic framework has been built, and component sand-body characteristics were investigated based on seismic attribute analysis and well-log correlation. Two overall upward-fining sequences, and an internal low-accommodation systems tract (LAST) (fluvial successions characterised by amalgamated fluvial channel sand bodies interlayered with rare overbank deposits) and high-accommodation systems tract (HAST) (intervals dominated by overbank or lacustrine deposits) have been identified. The thick, multi-storied channel-fill sandstone bodies deposited along the central depression belt, capped by extensive overbank or lacustrine mud deposits, characterise each sequence and form favourable reservoir–seal associations. Proximal-to-distal changes in lithofacies associations were also analysed. The sequence-stratigraphic and lithofacies analysis suggest the existence of an axial, large-scale river channel system in the Oligocene Xihu sag. On the basis of the restoration of basin geomorphology and seismic facies analysis, the depositional architectures of the axial paleodrainage system have been reconstructed. Overall, the Huagang sequences represent the sedimentary evolution of a large-scale fluvial system sourced from axial and lateral supply areas, to form river deltas into an interior-draining basin-centre lake. Two major fluvio-lacustrine transgression–regression cycles have been recorded. During the transgression cycle, the fluvial morphology was dominated by braided fluvial style; whereas during the regression cycle, the fluvial morphology was characterised by a combination of multiple fluvial channel styles in the LAST, from upstream to downstream low-sinuosity braided, high-sinuosity braided and anastomosing fluvial channel patterns were distributed and then replaced by large-scale lake flooding in the HAST. The braided channel centre, paleobathymetric lows of channel networks and delta-front bodies are sand-prone units. The fluvial sedimentation was governed by multiple parameters: tectonics, paleogeomorphology and climate fluctuations. This integrated study on fluvial sedimentation and evolution of the Oligocene drainage system enable us to propose a conceptual model depicting fluvial channel styles and component sand-body architecture in lacustrine rift basins with axial plus transverse sediment supplies. This model can serve as a reference to illustrate channel-sand-body and associated reservoir architecture in similar types of drainage systems in terrestrial basins.

Effect of burial history on diagenetic and reservoir-forming process of the Oligocene sandstone in Xihu sag, East China Sea Basin

Abstract Porosity evolution history, hydrocarbon charging periods, diagenetic and reservoir-forming characteristics of low-permeability and tight sandstone are presented in this study. The interpretation is based on information including thin section, scanning electron microscope, homogenization temperature of fluid inclusion, bulk rock X-ray diffraction analysis, clay X-ray diffraction analysis and stable isotopic composition. These sandstones are located in the Oligocene E3h Formation in the Xihu sag, East China Sea Basin, East China. Five diagenetic events in the H3, H4 and H5 members were determined, including connate alkaline pore water of the Oligocene sandstone, meteoric water leaching in late Miocene, organic acids and CO2 acidic fluids in early-middle Miocene, reservoir temperature decrease induced by tectonic uplift, and alkaline diagenetic environment from late Miocene to present day. Porosity evolution history of different grain-size lithology were evaluated by basin modelling and test data. The medium sandstone and coarse sandstone of the H3 member and medium sandstone of the H4 member not reached the tight state in the geologic time. The fine sandstone of the H4 member entered the tight state at 12 Ma, suffered acidic fluids to improve the tight state in late stage, and entered the tight state again since 6.5 Ma. The medium sandstone, fine sandstone and siltstone in the H5 member entered the tight state at 13.5Ma, 16Ma and 19Ma, respectively. Three hydrocarbon charging periods were determined, including 15.5 Ma-10.4 Ma in the middle Miocene, 9.6 Ma-7.0 Ma in the late Miocene and 6.2 Ma-0.0 Ma from the late Miocene to present day. Three diagenetic and reservoir-forming patterns were proposed, including accumulation without tightness, accumulation after tightness-improving reservoir quality with acidic fluid-accumulation while tightness, accumulation after tightness. The burial history cannot be ignored in the diagenetic events, porosity evolution history and hydrocarbon charging periods of similar low-permeability and tight sandstone in sedimentary basins.