The Weibei Sag in the Bohai Bay Basin currently contains proven hydrocarbon reserves of 20.07×106 t, but its hydrocarbon discovery rate is only 20%, indicating considerable exploration potential. The Kongdian Formation is the principal target interval for exploration and development, and hydrocarbon accumulations have been encountered in its 1st, 2nd, and 3rd members. To clarify the characteristics of structural units in the 2nd member of the Kongdian Formation and elucidate the mechanisms of fault-controlled hydrocarbon accumulation, this study was guided by the theory of fault-controlled hydrocarbon accumulation and employed seismic hydrocarbon accumulation analysis techniques. Drawing on a comprehensive integration of drilling-core, well-log, seismic, and other data, this study addressed the key issue of fault characteristics and their controls on hydrocarbon accumulation. The structural units were reclassified, the tectonic evolution history was reconstructed, and the fault characteristics, vertical and lateral hydrocarbon distribution patterns, and hydrocarbon reservoir types were investigated. These analyses further clarified the controls exerted by faults on the source-carrier-trap elements of representative hydrocarbon reservoirs with different degrees of enrichment, and summarized the differential enrichment characteristics and fault-controlled hydrocarbon accumulation models of different reservoir types. As indicated by the research results, the Weibei Sag was divided into four first-order structural units: the eastern sag-slope belt, central uplift-slope belt, western sag-slope belt, and southern overlap-denudation belt. Each slope belt was further subdivided into a deep-sag-low-slope zone, a middle-slope zone, and a high-slope zone, yielding a total of nine secondary structural units. The hydrocarbon accumulation conditions and characteristics differ significantly among these units. With faults F5, F7, and F6 as boundaries, three fault systems were identified: the Liutong-Yulibei transtensional fault system, central strike-slip fault system, and eastern strike-slip inversion fault system. These fault systems differ markedly in their controls on hydrocarbon migration and accumulation. The tectonic evolution of the study area was reconstructed and divided into four major stages: Cretaceous sinistral strike-slip rifting; dextral extensional rifting from the depositional period of the 3rd member of the Kongdian Formation to that of the 4th member of the Shahejie Formation; compressional inversion, uplift, and denudation at the end of the depositional period of the 4th member of the Shahejie Formation; and dextral transtensional subsidence since the Neogene. A hydrocarbon accumulation model characterized by spatially differentiated charging, coupled control of reservoirs by faults and sand bodies (fractures), preferential migration through source-connected faults and reservoir ridges, and differential and orderly accumulation in multiple hydrocarbon reservoir types was established. The high-slope zone of the intra-sag uplift in the western sag-slope belt, the middle- to high-slope structural ridge at the transition between the central and western parts, and the structural ridge belt of the intra-sag uplift in the eastern sag-slope belt are predicted to be favorable areas for future exploration.
Carbon isotope(δ13C)data of associated natural gas in oil and gas reservoirs have shown a strong cor-relation with source rock maturity.However,the rational application of this correlation is greatly constrained when only the traditional isotope-equivalent maturity template is used.On the basis of a systematic review of the main problems associated with traditional charts,this paper evaluates their limitations in isotope-maturity analy-sis across basins worldwide.A global dataset from oil and gas fields was compiled,including the carbon isotopic compositions of methane,ethane,and propane(δ13C1,δ13C2,δ13C3 or δ13C1-3),gas-oil ratio(GOR),gas wetness,and vitrinite reflectance(Ro).Particular emphasis was placed on in-source and near-source drilling results from shale source rocks over the past two decades,as well as updated charts proposed by many isotope researchers.The original isotope-maturity template was expanded,effectively resolving inconsistencies in the previous chart.Meanwhile,the wetness-δ13C2 chart was updated and extended by incorporating data from type Ⅰ,type Ⅱ,type Ⅲ,and saline-lacustrine type Ⅰ source rocks.Using the new isotope-equivalent maturity template and wetness-δ13C2 chart,together with case studies from several basins,source rocks were classified according to the variation trend of δ13C2 with gas wetness and its reversal characteristics at high maturity and in the dry-gas stage.Furthermore,after the source rock type is determined,the wetness-δ13C2 chart can be used to assess whether deviations from the wetness-813 C2 relationship are caused by oil-gas fractionation during PVT processes.For this purpose,Ro-GOR correlation templates were established for different source rocks,and PVT phase-diagram constraints were introduced.When used together with the wetness-δ13 C2 chart,these templates significantly broaden the application scope of isotope-maturity templates.This integrated approach can be used not only to determine whether produced oil and gas have undergone phase separation,but also to identify oil rims and gas caps by combining wetness data from isotope mud logging and conventional mud-gas logging,thereby optimizing production and facilitating the discovery of oil-rim and gas-cap reservoirs formed after phase separation.
Transitional marine-continental depositional systems are developed in the Eocene Pinghu Formation in the Xihu Sag, East China Sea Shelf Basin. Previous studies have mostly used drilling and seismic data to investigate individual sedimentary facies types. However, systematic studies on the identification of fluvial-tidal co-controlled areas and the characterization of fluvial-dominated to tide-dominated deltas remain relatively limited. To clarify the planar distribution characteristics and spatiotemporal evolution of different depositional systems in the Pinghu Formation in the western slope belt of the Xihu Sag, this study comprehensively identified the variation in the relative intensity of fluvial and tidal processes in both planar and vertical directions. The identification was based on indicators including core facies characteristics, the serration degree of logging curves, the wavelength-to-amplitude ratio of seismic events, and the roundness of detrital zircons. Identification criteria for the "fluvial-tidal co-controlled" depositional system suitable for the Pinghu Formation in the study area were established. Vertically, the Pinghu Formation gradually evolved from tidal flat-tide-dominated delta deposits during the E2pSQI stage to a depositional system dominated by fluvial-dominated deltas during the E2pSQⅢ stage. In planar distribution, the slope belt shows obvious south-north differences. The southern part is characterized by strong tidal influence, whereas the northern part is dominated by fluvial processes. From south to north, the depositional system changes from tidal flat-tide-dominated delta to fluvial-dominated delta. Overall, it is characterized by a distribution pattern of "sea in the south and land in the north".
Research on hydrocarbon-bearing fluids is one of the key and difficult aspects of hydrocarbon accumulation studies, and fracture fillings record important information about hydrocarbon-bearing fluids. Petrological characteristics of cores, thin sections, and cathodoluminescence images from the Ordovician Majiagou Formation in the Daniudi Gas Field, Ordos Basin, were analyzed to determine the formation stages of fractures and the types of fillings. Laser Raman spectroscopy and microthermometry of inclusions in fracture-vug calcite veins were performed. Carbon and oxygen isotopes and rare earth elements (REEs) were also analyzed to identify the types, properties, and sources of hydrocarbon-bearing fluids. As indicated by the research results, multistage tectonic fractures are developed in the Majiagou Formation, and these fractures cut and offset each other. Fracture fillings differ among different intervals. In the weathering crust interval, fractures are filled with calcite, dolomite, mudstone, limestone breccia, and other materials. Fractures in the inter-salt and subsalt intervals are mainly filled with calcite, and minor quartz filling occurs in the subsalt interval. Three stages of oil-gas inclusions were trapped in the calcite veins, and their carbon isotopic compositions show a marked negative shift due to the influence of hydrocarbon-bearing fluids. This indicates that fractures served as important pathways for hydrocarbon migration and reveals a favorable coupling between tectonic activity and source rock hydrocarbon generation. The calcite veins in the Majiagou Formation exhibit negative oxygen isotopic shifts and positive δCe anomalies. The contents of trace elements such as Mn and Sr are comparable to those of the host rocks, and the REE distribution patterns are generally consistent with those of the host rocks, characterized by enrichment in light rare earth elements and depletion in heavy rare earth elements. These features suggest that the calcite veins formed during the burial stage, with diagenetic fluids characterized by high temperatures and reducing conditions. Calcite veins in the study area generally show negative δEu anomalies and lack typical magmatic hydrothermal minerals, indicating that the diagenetic fluids in fractures were dominated by formation water. However, minor local input of magmatic hydrothermal fluids occurred, as indicated by positive δEu anomalies in some samples and minor quartz filling in the subsalt interval.
The use of abandoned salt caverns for compressed air energy storage (CAES) can reduce storage construction costs and shorten the construction period. However, owing to the effects of mining history, cavern morphology evolution, complex geological conditions, and differences in operating conditions, the evaluation of their long-term stability involves significant uncertainty. To address the problem that existing studies have difficulty systematically quantifying the stability uncertainty of abandoned salt caverns under the coupled effects of multiple factors, this study proposes a comprehensive evaluation method integrating scenario design and numerical simulation of salt cavern creep. The method identifies the main controlling factors of stability from three dimensions: geological conditions, cavern structure, and operating conditions. Representative multi-scenario combinations were constructed using orthogonal design, and a long-term creep numerical model was established based on FLAC3D. Using creep displacement around the cavern and the 30-year volume shrinkage rate as the main indicators, cavern stability under the coupled effects of different factors was evaluated. A typical legacy salt cavern in the Hongze Salt Basin, northern Jiangsu, was selected for application analysis. The results show that mudstone interlayers can constrain creep deformation of salt rock. When the interlayer thickness increases from 2 m to 4 m or the number of interlayers increases from 1 to 3, the 30-year volume shrinkage rate decreases by 1.89%-2.08%. When the burial depth increases from 1 600 m to 2 000 m, the difference between in-situ stress and working pressure inside the cavern increases, and the 30-year volume shrinkage rate increases by 4.91%. Compared with horizontal butted wells, caverns formed by single-well convection mining show a more uniform deformation distribution and better overall stability. When the working pressure range increases from 16-19 MPa to 22-25 MPa, the 30-year volume shrinkage rate decreases by 4.02%; however, sealing risk and operating economy should also be considered. On this basis, a quantitative stability rating standard was established with the 30-year volume shrinkage rate as the core indicator. The research results show that the multi-scenario numerical simulation method based on orthogonal design can quantitatively characterize the influence of multi-factor uncertainty on the stability of CAES in abandoned salt caverns. This method can provide low-cost technical support for the preliminary selection of regional legacy salt cavern resources and subsequent engineering evaluation.
The Carboniferous Kalashayi Formation in the southwestern Tarim Basin is a key target for Paleozoic hydrocarbon exploration in the Tarim Basin. Exploration results currently show marked spatial differences. Several sizable hydrocarbon reservoirs have been discovered in the Bachu Uplift, demonstrating favorable exploration results, whereas only limited exploration breakthroughs have been achieved on the Maigaiti Slope, where exploration has reached a bottleneck. To clarify the mechanisms responsible for the differences in hydrocarbon accumulation conditions between the two areas and identify directions for future exploration, a systematic study of the accumulation conditions and play evaluation of the Kalashayi Formation was conducted. Source-rock analytical data from 12 wells, drilling, well-log, and mud-logging data from more than 30 wells, 3D seismic interpretation results, and geochemical test data were integrated. The main factors controlling hydrocarbon accumulation were analyzed in terms of five aspects: source rocks, reservoirs, carrier systems, traps, and tectonic movements. Differentiated hydrocarbon accumulation models were established, and a multi-index evaluation system with block-specific weights was constructed to delineate favorable zones. Detailed seismic interpretation was also used to delineate traps and select favorable exploration targets. As indicated by the research results, hydrocarbon accumulation in the Kalashayi Formation is jointly controlled by source-rock supply, reservoir development, carrier systems, trap matching, and tectonic movements, and shows distinct spatial differences. Against the background of inherited paleo-uplift development, the Bachu Uplift is characterized by a structural-trap accumulation model involving a single phase of hydrocarbon generation and multistage tectonic adjustment. The Maigaiti Slope is controlled by secondary hydrocarbon generation and source-reservoir coexistence and is characterized by a near-source accumulation model in low-relief lithologic or structural-lithologic traps. The differentiated evaluation indicates that the area where the Yubei Fault Zone overlaps tidal-channel sand bodies in the eastern Maigaiti Slope is a Class Ⅰ favorable zone. Its overall score is 0.84 and decreases to 0.80 after barrel-effect correction. The eastern Bachu Uplift is a Class Ⅱ favorable zone, with an overall score of 0.76. A total of 13 favorable traps, covering an area of 147.85 km2, were delineated in the Yubei 3D seismic survey area, and three Class Ⅰ targets were selected.
The sandy interbeds in the Chang 71 sub-member of the Upper Triassic Yanchang Formation, Wuqi area, Ordos Basin, are characterized by strong heterogeneity of pore-throatstructure, ambiguous relationship between pore development and seepage capacity, and insufficient understanding of whether dissolution pores can be transformed into effective seepage spaces. To address these issues, this paper takes sandstone samples collected from shale-reservoir sandy interbeds of the Chang 71 sub-member, Yanchang Formation, at well A within the study area as the research object. Comprehensive methods including bulk-rock X-ray diffraction, porosity and permeability testing, scanning electron microscopy observation, rate-controlled high-pressure mercury intrusion experiments, and nano-CT three-dimensional pore network reconstruction are adopted to analyze the mineral composition, pore-throat structure characteristics, and their controlling effects on seepage capacity. The results show that the sandy interbeds of the Chang 71 sub-member generally present low porosity and ultra-low permeability features. The porosity ranges from 0.60% to 7.92%, with an average of 2.01%, and permeability ranges from 0.004 84×10-3 μm2 to 0.131×10-3 μm2, with an average of 0.018 4×10-3 μm2. Porosity shows a significant positive correlation with permeability. The reservoir spaces are mainly residual intergranular pores, feldspar dissolution pores, and clay intercrystalline micropores. Carbonate cements and clay minerals are widely developed with obvious heterogeneity. The displacement pressure of representative samples is 0.119-0.306 MPa, and there are remarkable discrepancies in the main throat interval and fine throat tailing characteristics. High-permeability samples have a high proportion of connected pores, large average coordination number, and well-connected pore networks, while low-permeability samples feature a low proportion of connected pores and sparse pore network branches, and are prone to connectivity interruption. The seepage capacity of sandy interbeds in the Chang 71 sub-member is mainly controlled by the development degree of dominant throats, throat threshold, and three-dimensional connected framework. Carbonate cementation-dissolution and clay filling exert remarkable coupled controlling effects over pore-throat structure. Early carbonate cementation and late re-precipitation can narrow and partition pore throats, and clay filling further aggravates throat refinement and weakens connectivity. The pore increment formed by feldspar dissolution can only be converted into seepage advantages under the condition of preserving an effective connected framework. The research results can provide a basis for sweet spot identification of shale oil sandy interbeds and the optimization of fracturing intervals in the Chang 7 Member.
Shale wettability refers to the tendency of one fluid in a two-phase fluid system to preferentially wet the shale surface, and is a key property affecting the occurrence and mobility of shale oil and gas. Current research is limited by the complexity of influencing factors and the insufficient general applicability of multiphase experimental results, which restricts the development of related evaluation technologies. By systematically reviewing the factors influencing shale wettability in gas-water-rock and oil-water-rock systems, this study clarifies that, in the gas-water-rock system, the main controlling factors of water wettability include surface roughness, inorganic mineral composition, organic matter type and abundance, and pore structure. In the oil-water-rock system, in addition to the above factors, temperature and pressure conditions, crude oil composition, and ion concentration in formation water have significant effects on oil wettability. Future research should construct multiphase and multicomponent experimental systems under near-formation conditions, deepen understanding of the microscopic wetting mechanisms at organic-inorganic interfaces, and promote the integration of in-situ wetting characterization at the micro- to nanoscale with digital core modeling, thereby providing theoretical and technical support for the efficient exploration and development of shale oil and gas.
The shales of the Upper Permian Dalong Formation in the Lower Yangtze region, South China, constitute important hydrocarbon source rocks. However, the dynamic evolution of the mechanisms and controlling factors governing organic matter enrichment remains insufficiently understood. Using the continuously exposed Dalong Formation section in Hanshan, Ma'anshan, Anhui Province, as the study object, the paleoenvironmental evolution sequence of the study area was reconstructed through geochemical analyses of 25 shale samples. As indicated by the research results, the paleoceanographic environment during deposition of the Dalong Formation exhibited a three-stage evolutionary pattern: Stage Ⅰ was characterized by anoxic conditions, Stage Ⅱ evolved into a strongly euxinic environment, and Stage Ⅲ transitioned into a suboxic environment. Water reduction degree showed a significant positive correlation with Total Organic Carbon (TOC) content, indicating that favorable preservation conditions constituted a key prerequisite for organic matter enrichment. Primary productivity during Stage Ⅱ was significantly higher than that during the other stages and was strongly coupled with records of volcanic activity, including Hg anomalies and tuff interlayers. This suggests that the nutrient fertilization effect associated with volcanic activity was an important factor promoting enhanced productivity. Terrigenous input was relatively strong during Stages Ⅰ and Ⅲ, exerting a pronounced dilution effect on organic matter, whereas terrigenous input reached its minimum during Stage Ⅱ, when the dilution effect was weakest. The study indicates that organic matter enrichment in the Lower Yangtze region during the Upper Permian exhibited distinct stage-dependent evolutionary characteristics. Stage Ⅰ was characterized by preservation-dominated enrichment; Stage Ⅱ represented the most organic- rich interval and was characterized by the synergistic effects of high productivity, strongly euxinic conditions, and weak dilution effect; whereas Stage Ⅲ corresponded to a suppression stage unfavorable for organic matter enrichment. Sea-level fluctuations were an important controlling factor governing paleoenvironmental evolution and the transformation of organic matter enrichment patterns.
To investigate efficient and low-cost approaches for enhancing fracture conductivity, the impacts of discontinuous (cluster-type) proppant placement on fracture conductivity were systematically studied, and its main controlling factors and applicable conditions were clarified to provide an experimental basis for field application. Comparative experiments on continuous and discontinuous proppant placement were conducted under closure stresses ranging from 10 to 90 MPa using a fracture conductivity testing apparatus (Core-Lab FCES-100). Experimental variables included cluster area ratio (12%, 20%, and 52%), proppant type (quartz sand, resin-coated sand, and ceramic proppant), lithology (shale and sandstone), and fiber additive concentration (0.0%-0.8%). Fracture conductivity was evaluated through real-time conductivity data acquisition combined with post-experimental morphological analysis. As indicated by the research results, cluster structure is the key factor controlling fracture conductivity performance, and a moderate cluster area ratio (approximately 20%) achieves the optimal balance between flow channel connectivity and cluster stability. Under low closure stress conditions (≤40 MPa), discontinuous placement effectively reduces the conductivity differences among proppant types, enabling low-cost quartz sand to achieve conductivity comparable to that of ceramic proppants. Under high closure stress conditions (≥80 MPa), however, fracture conductivity decreases sharply to a near-failure level. Lithological influence is insignificant under low stress conditions, whereas shale exhibits better conductivity retention performance than sandstone within the medium-stress range of 40-70 MPa. Fibers improve fracture conductivity by enhancing the aggregation effect of proppant clusters, and the optimal additive concentration is 0.6%. Therefore, discontinuous placement is suitable for reservoirs with relatively low closure stress and can achieve both cost reduction and improved stimulation efficiency. For reservoirs under high closure stress, continuous placement combined with high-strength proppants is recommended. The results of this study provide important experimental support for the optimization and field application of discontinuous proppant placement technology.
The Ordovician reservoirs in the Lunnan Oilfield have undergone multiple episodes of secondary alteration and hydrocarbon charging, resulting in highly complex crude oil compositions and molecular geochemical characteristics. Heteroatom-containing polar compounds are highly sensitive to secondary alteration and are therefore key targets for revealing the evolutionary history of reservoirs. Using gas chromatography-mass spectrometry (GC-MS) and electrospray ionization Fourier transform ion cyclotron resonance mass spectrometry (ESI FT-ICR MS), this study systematically analyzed differences in the molecular compositions of nonpolar hydrocarbons and heteroatom-containing polar compounds in Ordovician crude oils from different blocks of the Lunnan Oilfield, aiming to clarify their intrinsic relationships with secondary alteration types, late-stage hydrocarbon charging, and maturity evolution. As indicated by the research results, both conventional biomarker parameters and heteroatom-containing polar compound parameters demonstrate east-to-west migration and charging of crude oils. The average molecular weight and double bond equivalent (DBE) values of heteroatom-containing polar compounds in crude oils from the western Lungu area are significantly higher than those in crude oils from the eastern Lungu area, reflecting a genetic difference between crude oils dominated by biodegraded heavy oils in the western Lungu area and those dominated by light oil in the eastern Lungu area. From west to east, the relative abundances of sulfur-containing polar compounds with lower thermal stability, including O2S2, O1S2, N1S1, and N1S2 compounds, gradually decrease, whereas the proportions of the thermally more stable O1S1 and O2S1 compounds gradually increase. The carbon number distribution of n-alkanes in crude oils from the western Lungu area is highly similar to that of n-fatty acids, indicating that these n-alkanes may have mainly originated from the decarboxylation of fatty acids in early biodegraded heavy oil. The late-stage charged high-maturity hydrocarbons in the eastern Lungu area are dominated by nonpolar compounds, but their heteroatom-containing polar compounds still retain the molecular characteristics of early crude oils. The maturity parameter of heteroatom-containing polar compounds (IMAU) shows that the maturities of crude oils from both the eastern and western Lungu areas are close to 1.0, with only minor differences. In contrast, the aromatic hydrocarbon-based maturity parameter (Rc) indicates that the maturity of crude oils from the eastern Lungu area (1.24-1.29) is significantly higher than that of crude oils from the western Lungu area (0.86-1.04). This suggests that heteroatom-containing polar compounds mainly record the maturity information of early-charged crude oils rich in such compounds, whereas aromatic hydrocarbons primarily reflect the maturity characteristics of late-stage high-maturity hydrocarbon charging. In summary, heteroatom-containing polar compounds can effectively trace secondary alteration processes and the multi-stage charging history of deep reservoirs in superimposed basins, providing critical molecular geochemical evidence for deciphering complex hydrocarbon accumulation and evolution.
The Miocene Meishan Formation is the main hydrocarbon-bearing interval in the Lingshui Sag, Qiongdongnan Basin. Its overall exploration degree is relatively low, and its hydrocarbon exploration potential is significant. Previous studies have confirmed that high-quality gas-bearing reservoirs in the Meishan Formation commonly show strong-amplitude "bright spot" reflections on seismic profiles. However, two major difficulties remain in practical exploration. First, non-reservoir lithologies such as tuff, low-velocity mudstone, and calcareous sandstone can produce similar "bright spot" seismic responses, severely interfering with effective reservoir identification. Second, gas-bearing and water-bearing layers have similar seismic response characteristics, making it difficult to effectively distinguish fluid properties using post-stack seismic data alone. Based on drilled wells, well-log data, and 3D seismic data, and combined with well-seismic response analysis, seismic forward modeling, and pre-stack and post-stack seismic inversion techniques, sandstone reservoir identification and gas-bearing prediction are carried out for the Meishan Formation. As indicated by the research results, post-stack seismic amplitude is mainly controlled by sand-body thickness and porosity, and has relatively low sensitivity to gas saturation. Pre-stack AVO intercept and gradient parameters can effectively respond to variations in gas saturation. The P-wave impedance of sandstone reservoirs is higher than that of tuff and lower than that of calcareous sandstone; the P-/S-wave velocity ratio is lower than that of low-velocity mudstone and background mudstone. Sandstone reservoirs in the study area are mainly characterized by Class Ⅲ AVO responses, which are clearly distinguished from Class Ⅰ AVO responses of calcareous sandstone and Class Ⅳ AVO responses of tuff and low-velocity mudstone. On this basis, a multi-parameter collaborative technical workflow for reservoir gas-bearing prediction is established. The "bright spot" anomaly range is delineated using seismic wave-group energy. Tuff and calcareous sandstone are excluded using P-wave impedance. Low-velocity mudstone and background mudstone are distinguished using the P-/S-wave velocity ratio. Reservoir identification is then verified jointly with AVO classes. A gas-bearing indicator factor is constructed from the AVO intercept and gradient parameters to achieve quantitative evaluation of reservoir gas-bearing properties. Verification by drilled-well data shows that this integrated prediction method has a high degree of consistency. It can effectively reduce prediction non-uniqueness caused by multi-lithology interference and improve the accuracy of high-quality reservoir identification and gas-bearing prediction in the Meishan Formation, Qiongdongnan Basin.
The Upper Triassic Xujiahe Formation in the Sichuan Basin hosts one of China's most important tight sandstone gas reservoirs. To clarify the reservoir development mechanism under a multi-provenance framework, reservoir characteristics and the principal controlling factors associated with four major provenance systems—the Jiangnan Old Land, the Micangshan-Dabashan Fold Belt, the Kangdian Old Land, and the Longmenshan Thrust Belt—were systematically compared across the entire basin using core observations, thin-section petrography, X-ray diffraction (XRD), and high-pressure mercury intrusion (HPMI) analyses. Based on these results, the development pattern of high-quality reservoirs was established. Reservoirs sourced from different provenance systems exhibit significant differences in lithic composition and compositional maturity. The 2nd member of the Xujiahe Formation (Xu 2 Member) is dominated by lithic sandstone, whereas carbonate lithic fragments become more abundant in the 3rd member (Xu 3 Member). The 4th member (Xu 4 Member) exhibits the most favorable reservoir properties. The reservoirs are generally characterized by ultra-low porosity (average 6.0%-10.8%) and ultra-low to extremely low permeability (average (0.005-2.238) × 10-3 μm2). Reservoir space is dominated by secondary dissolution pores, with primary pores occurring as a subordinate component. Specifically, the Xu 4 Member exhibits the optimal pore-throat structure, whereas the southeastern Sichuan provenance area displays the highest mercury withdrawal efficiency (average 38.57%) and the best pore-throat connectivity. Compaction is the primary destructive diagenetic process, followed by cementation (characterized by siliceous and calcareous cements); conversely, dissolution (specifically of feldspar and lithics) effectively improves the pore space. Compaction is strongest in the northwestern Sichuan provenance area, while dissolution is most developed in the southeastern Sichuan provenance area. The development of high-quality reservoirs is synergistically controlled by four factors: provenance systems providing the geological foundation, sedimentary microfacies determining reservoir quality, differential diagenesis controlling pore evolution, and fractures enhancing reservoir connectivity. Distributary channel sand bodies within braided river deltas exhibit the best physical properties, and fractures development significantly enhances the reservoir permeability in the study area. This study provides a theoretical foundation for sweet-spot optimization and the efficient exploration and development of tight sandstone gas reservoirs within the Xujiahe Formation in the Sichuan Basin.
To address the key challenges of low thermal efficiency, poor displacement performance, and the unclear enhancement mechanism of single-gas-assisted steam flooding in heavy oil reservoirs, a comprehensive study integrating high-temperature and high-pressure PVT experiments, one-dimensional tubular displacement tests, and three-dimensional physical simulations was conducted. The objective was to reveal the synergistic enhancement mechanism between multi-component composite gas (20% CO2 + 80% N2) and steam, thereby promoting the efficient and environmentally sustainable development of heavy oil resources. First, a PVT apparatus was used to determine the dissolution behavior of the multi-component composite gas in crude oil under different temperature and pressure conditions, as well as its effects on heavy oil physical properties, such as viscosity and expansion coefficient. Second, one-dimensional displacement experiments were conducted to compare the oil displacement efficiencies of pure steam flooding and composite gas-assisted steam flooding, and to optimize injection parameters including temperature and total gas injection volume. Finally, three-dimensional physical simulation experiments were employed to investigate the production performance and steam chamber expansion behavior during composite gas-assisted steam flooding, and to quantitatively evaluate its contribution to enhanced oil recovery. As indicated by the research results, under reservoir conditions of 50 ℃ and 4 MPa, the solubility of the multi-component composite gas reached 15.5 m3/m3, reducing heavy oil viscosity by 72.76% and exhibiting a pronounced synergistic effect of viscosity reduction through gas dissolution and volumetric expansion. The one-dimensional displacement experiments determined an optimal injection temperature of 250 ℃ and an optimal total injection volume of 0.6 PV, under which the oil displacement efficiency of multi-component composite gas-assisted steam flooding was 12%-18% higher than that of pure steam flooding. The three-dimensional physical simulation experiments confirmed that co-injection of the multi-component composite gas increased the steam chamber expansion rate by 25%, expanded the heating area (100 ℃ isotherm) from 68.98% under pure steam flooding to 82.21%, and raised the final oil recovery to 49.49%, representing an improvement of 7.95% over pure steam flooding. Multi-component composite gas-assisted steam flooding significantly enhances heavy oil mobility and sweep efficiency through multiple synergistic mechanisms, including viscosity reduction by CO2 dissolution, pressure maintenance by N2, gas phase displacement of residual oil in small pores, and steam chamber expansion.
With continued exploration in the Nanpu Sag, Bohai Bay Basin, hydrocarbon exploration is facing problems such as unclear hydrocarbon distribution patterns and great difficulty in making discoveries. Exploration has confirmed that faults play an important role in controlling hydrocarbon accumulation in this area, but the related mechanisms remain unclear. Based on detailed interpretation of 3D seismic data, this study systematically summarizes the characteristics of fault assemblages in the Nanpu Sag. The hydrocarbon accumulation theory of "convergence ridges" was introduced to study the characteristics of deep fault-assemblage convergence ridges in the Paleogene Shahejie Formation and their reservoir-controlling effects on shallow hydrocarbon reservoirs in the Neogene Minghuazhen and Guantao formations. Combined with exploration practice in the Liunan area, a shallow hydrocarbon accumulation model was established for this area, and favorable exploration directions were defined. As indicated by the research results, the profile assemblage types of deep faults in the Nanpu Sag can be divided into four types: synthetic adjustment type, antithetic adjustment type, synthetic/antithetic fault-step type, and graben-horst type. The plane assemblage types can be divided into four types: synthetic parallel/branching type, antithetic parallel/branching type, synthetic parallel/en echelon type, and alternating synthetic-antithetic parallel/ en echelon type. Deep fault-assemblage convergence ridges can be classified into three types: fault-sand type in the steep slope belt, intra-sag uplift type in the sag area, and low-uplift type in the slope belt. Deep fault-assemblage convergence ridges have important controlling effects on shallow hydrocarbon reservoirs. These effects are reflected in three aspects: the dual "conduit-guidance" control on hydrocarbon migration, the synergistic "trap-enrichment" effect on hydrocarbon accumulation, and the "barrier-stability" protection of hydrocarbon reservoir preservation. This study suggests that the Gaoliu fault plays an important role in controlling shallow hydrocarbon accumulation in the Liunan area. A shallow hydrocarbon accumulation model of "fault-sand type convergence ridge controlling reservoirs in the steep slope belt" was established for the Liunan area. This model can scientifically explain the complex hydrocarbon distribution patterns in this area. It is inferred that the Liuxi structure, the eastern side of block L25, and shallow channel sands on the western-wing slope setting of Liu 102, which are located in the favorable hydrocarbon migration zone of the convergence ridge, are favorable exploration areas for the next stage in the study area.
The development patterns and coal accumulation models of thin coal seams are significant topics in sedimentology and energy geology. In recent years, scholars have typically discussed the sedimentary environment of coal seams and combined this with sequence stratigraphic analysis to study their distribution patterns. With the increasing abundance of geological data and deeper geological understanding, the coal seams of the Paleogene Pinghu Formation in the Xihu Sag, the main oil and gas exploration area in the East China Sea Basin, have seen growing attention on their research value. Previous studies have conducted relatively in-depth discussions on the hydrocarbon generation potential of the coal-bearing strata in the Pinghu Formation of the Xihu Sag. However, descriptions of the sedimentary characteristics of coal seams have mostly focused on a single perspective, such as sedimentary environment or systems tract facies. A comprehensive and clear understanding of coal seam development patterns and coal accumulation models is still lacking. Thin coal seams of the Pinghu Formation in the Baochu slope belt were systematically identified through the comprehensive utilization of core observations, well-logging curves, and 3D seismic interpretation. Based on this, the lateral and vertical distribution characteristics of the coal seams were analyzed. Meanwhile, the controlling factors of coal seam development were explored considering multiple factors, including palaeogeomorphology, sedimentary environment, palaeoclimate, and palaeovegetation, and coal accumulation patterns were summarized, aiming to provide a comprehensive model for coal seam genesis in the study area. Core observations and well-logging analysis indicated that coal seams in the slope belt of the Xihu Sag were widely developed across all intervals of the Pinghu Formation, exhibiting vertical characteristics of thin individual layers, numerous stacked layers, and large cumulative thickness. Horizontally, coal seams were widely developed in the northern part of the slope belt and had a relatively larger average thickness. Comprehensive research analyses suggested that the coal seams of the Pinghu Formation in the Xihu Sag primarily developed in an intertidal environment and were controlled by a combination of factors such as topography, sedimentary environment, palaeoclimate, and organic facies belts. The coal accumulation model was characterized by "geomorphology controlling slope, slope break controlling belts, and belts controlling coal seams".
To clarify the differential evolution of porosity in tight sandstone reservoirs, the Chang 6 Member of the Triassic Yanchang Formation in the X255 area, Ordos Basin, was selected as a case study. Cast thin sections, scanning electron microscopy, X-ray diffraction (XRD) analysis of clay minerals, and cathodoluminescence data were integrated to classify the diagenetic facies of the tight sandstone reservoirs and establish the diagenetic evolution sequence of each facies. Burial and thermal histories were reconstructed, and the porosity of reservoirs with different diagenetic facies at key stages of geological history was quantitatively calculated to determine their differential evolution patterns. As indicated by the research results, four diagenetic facies are mainly developed in the Chang 6 member reservoirs in the study area: moderate-compaction feldspar-dissolution facies, moderate-compaction chlorite-cementation facies, strong-compaction tight facies, and moderate-compaction carbonate-cementation facies. Their porosity evolution processes differ markedly. In the moderate-compaction feldspar-dissolution facies, compaction and cementation caused a combined porosity loss of 20.21% during early diagenetic stage A. Dissolution increased porosity by 6.06% during early diagenesis, whereas a further porosity loss of 11.38% occurred during early diagenetic stage B and the mesodiagenetic stage. The final porosity is 11.85%, making this a favorable diagenetic facies. In the moderate-compaction chlorite-cementation facies, compaction and cementation caused porosity losses of 16.45% and 14.0%, respectively, whereas dissolution increased porosity by 3.15%. Chlorite coatings provided some protection for primary pores, making this the second most favorable diagenetic facies. In the strong-compaction tight facies, compaction and cementation caused porosity losses of 27.61% and 2.70%, respectively, making this an unfavorable diagenetic facies. In the moderate-compaction carbonate-cementation facies, dolomite precipitation occupied approximately 10.0% of the pore space. Subsequent compaction and calcite-dominated cementation rendered the reservoir tight during early diagenesis, making this the least favorable diagenetic facies.
Continental shale oil reservoirs in China are generally characterized by complex pore structures, strong heterogeneity, and poor crude oil mobility. During post-fracturing depletion development, production declines rapidly, and oil mobilization from the matrix remains limited. To clarify the mechanisms by which CO2+H2O mixed-fluid huff-n-puff enhances shale oil recovery, cores from a shale reservoir in Upper Es4 member of the Boxing subsag of Shengli Oilfield were used to investigate shale oil mobilization under different huff-n-puff fluids and fracture conditions. Scanning electron microscopy (SEM), nuclear magnetic resonance (NMR), and high-pressure mercury intrusion (HPMI) porosimetry calibration were used to characterize shale mineral composition, pore structure, and oil occurrence in different pore-size ranges. CO2-water-shale interaction experiments were conducted to analyze changes in porosity, permeability, and pore-size distribution before and after interaction. Under identical pressure-replenishment conditions, H2O, CO2, and CO2+H2O were separately used as the huff-n-puff fluids in multicycle physical simulation experiments on matrix and fractured cores. NMR T2 spectra were used to evaluate the degree of oil mobilization in pores of different sizes. As indicated by the research results, the weakly acidic fluid formed by the dissolution of CO2 in water can react with soluble minerals such as calcite and feldspar in shale, weaken intergranular cementation, generate dissolution pores, and improve pore-throat connectivity. After 10 d of interaction, core porosity and permeability increased by 21.48% and 16.9%, respectively. Pore volumes in the micropore, small-pore, and larger-pore ranges all increased to varying degrees. The huff-n-puff experiments showed that the final recovery factor of water huff-n-puff in the matrix core was 14.15%. Oil in micro- and small pores was progressively mobilized, mainly through capillary imbibition. The final recovery factor of CO2 huff-n- puff was 21.29%, indicating effective oil mobilization in pores of multiple scales. The final recovery factor of CO2+ H2O mixed-fluid huff-n-puff was 25.93%, showing a more pronounced recovery enhancement than water huff-n-puff. For fractured cores, water huff-n-puff provided only limited recovery enhancement, whereas the final recovery factors of CO2 and CO2+H2O mixed-fluid huff-n-puff reached 54.54% and 48.63%, respectively. These results indicate that fractures shorten the mass-transfer distance from the huff-n-puff fluid to the matrix, enlarge the drainage area, and enhance oil mobilization. The CO2+H2O mixed fluid can improve the shale pore structure through water-rock interactions and enhance shale oil recovery through CO2 diffusion, dissolution, swelling, and viscosity reduction. Fracture development and huff-n-puff fluid type jointly control the extent of shale oil mobilization and the recovery enhancement. CO2+H2O mixed-fluid huff-n-puff has the potential for the synergistic application of post-fracturing pressure replenishment, enhanced oil recovery, and subsurface CO2 retention.
With the continuous deepening and improvement of China's mining right management system, petroleum enterprises face multiple challenges: heavy pressure to surrender existing mining rights, obstacles in potential assessment of newly awarded blocks, stringent requirements for accurate asset valuation, and high efficiency demands for evaluation procedures. It is urgent to develop systematic quantitative classification and prioritization approaches alongside asset valuation technologies for exploration blocks. Adopting a tiered evaluation framework of "basin-play-block", this paper has elaborated key technologies and application outcomes from four dimensions: strategic area screening, block prioritization, asset valuation, and system development. In strategic area screening, we have established an evaluation methodology based on dynamic basin hydrocarbon accumulation processes, identified priority key expansion targets, including peripheral zones of major basins in central and western China, and built a superposition evaluation system covering critical hydrocarbon accumulation factors for various play types. In block prioritization, we have proposed an integrated estimation method for geological success probability and resource volume that integrates both conventional and unconventional resources. We have also proposed a two-factor classification and prioritization model defined by the dual indicators of "geological success probability-resource strategic value". In asset valuation, we have developed valuation methodologies applicable to blocks with varying exploration maturity levels. In terms of system development, we have constructed the Block Evaluation and Decision Support System, which has strongly supported SINOPEC's mining rights assessment and expansion initiatives following the rollout of the new mining right regulatory policies. The research outcomes provide technical underpinnings for systematic, standardized, and refined evaluation of mining rights, and can serve as a valuable reference for other domestic oil and gas operators conducting mining right assessment.
Against the backdrop of global energy transition, deep coalbed methane (CBM) at burial depths greater than 1 500 m has emerged as a highly promising unconventional natural gas resource. Multiple coal seams are developed in the Permian Longtan Formation in the Qijiang area, southeastern Sichuan. However, their reservoir characteristics remain poorly understood, and future exploration targets have yet to be clearly defined. To address these issues, reservoir characteristics, gas enrichment conditions and exploration targets of deep coal seams in the Longtan Formation were systemically investigated based on core observations, laboratory analyses and experimental data from multiple wells. As indicated by the research results, the Longtan Formation contains coal seams with large cumulative thickness and wide lateral distribution in research area. The coal rank is high-rank anthracite, with an average vitrinite reflectance of 2.93%. Measured gas contents range from 4 to 46.7 m3/t, with free gas accounting for approximately 18%-36%, indicating high gas contents and a relatively high proportion of free gas. The reservoirs are characterized by a dual pore-cleat system comprising micron- to nano-scale pores and cleats. Macropores account for 64.1% of the pore system, and pore-fracture connectivity is favorable. Clay minerals are dominated by illite/smectite mixed-layer minerals (averaging 68%). The reservoir exhibits low Young's modulus and high Poisson's ratio, indicating that stress-related risks should be carefully considered during hydraulic fracturing. Based on lithological assemblages, coal quality and preservation conditions, a three-category, twelve-parameter evaluation system was established, within which three favorable coal assemblage types were identified: thick coal seams, medium-thick coal seams interbedded with mudstone, and medium-thick coal seams interbedded with mudstone and sandstone. Accordingly, favorable areas covering approximately 5 243 km2 were delineated, with estimated geological resources of 1.38 × 1012 m3. The C4-C5-C6 coal-bearing assemblages in the 2nd member of the Longtan Formation (Longtan 2 Member) within the Guanshengchang Synclinorium, the plunging end of the Dingshan-Dongxi Structure, and the Lizi Gentle Fold Belt exhibit the most favorable geological conditions. These areas cover approximately 1 204.6 km2 and contain estimated geological resources of 316.2×108 m3, making them priority targets for future exploration.
