Ultra-deep strike-slip fault-controlled hydrocarbon reservoirs have been discovered as a new frontier for exploration and development in the Tarim basin. However, the complexity of these reservoirs poses a significant challenge for profitable development, necessitating enhanced foundational geological research. The strike-slip fault-controlled hydrocarbon reservoirs are commonly characterized by strong heterogeneity, intricate reservoir and fluid distribution, significant variations in hydrocarbon production, and low recovery. The great differences in faulting, reservoir characteristics, hydrocarbon accumulation, and fluid dynamics of these reservoirs between different areas present a series of exploration and development challenges. A series of models for strike-slip fault zones of different genesis and their controls on reservoirs have been established, and the mechanisms of reservoir formation along strike-slip fault zones including combined reservoir control by microfacies, strike-slip fault and dissolution, and contiguous, differential and extensive development have been revealed. Furthermore, the strike-slip fault-controlled reservoir models with “source-fault-reservoir-caprock coupling” and “small reservoir but large field” are constructed, unveiling the mechanisms of the hydrocarbon accumulation and preservation of ultra-deep strike-slip fault-controlled reservoirs. This research breaks through the limitations in theory that weak strike-slip faults in cratonic basins are difficult to form large-scale strike-slip fault-controlled reservoirs and large oil/gas fields. Finally, the genesis of large-scale strike-slip fault systems, the differential reservoir formation mechanisms within strike-slip fault zones, and the hydrocarbon enrichment patterns in cratonic basins have been clarified.
In order to clarify the differences in hydrocarbon-generating precursor and mechanism of the shale oil between the upper and lower sweet spots of the Lucaogou formation, the source rocks of the Lucaogou formation in the Jimsar sag were characterized ultra-microbiologically using field emission scanning electron microscopy, electron probe, and Fourier transform infrared spectroscopy experiments. The results show that the main hydrocarbon-generating precursor of the shale oil in the upper sweet spot is lamalginite (Microcystis), with straight-chain aliphatic series in dominance, and the main hydrocarbon-generating precursor in the lower sweet spot is telalginite (Tasmanian algae), which is rich in branched-chain aliphatic, aromatic, and sulfoxide functional groups. Due to the significantly higher activation energy required for the cleavage of long straight-chain saturated hydrocarbons than that for branched-chain hydrocarbons, as well as the lower bond energies of carbon-sulfur and carbon-nitrogen bonds, the activation energy of the precursor of the shale oil in the lower sweet spot is lower than that in the upper sweet spot. Consequently, early-stage hydrocarbon generation occurs, leading to the formation of high-density crude oil rich in non-hydrocarbon bitumen at low maturity, which is the primary reason for the relatively heavy and viscous nature of the crude oil in the lower sweet spot.
The Da’anzhai member of the Lower Jurassic Ziliujing formation is the most favorable layer for the development of continental shale oil in the Sichuan basin, and has huge potential in shale oil exploration. However, there is a lack of systematic research on the thermal evolution history of this formation. Using the simulation system for petroliferous basins, the differences in the thermal evolution and hydrocarbon generation of the shales in Da’anzhai member between the northern part and the central part of the central Sichuan basin were comparatively analyzed, and their impacts on shale oil enrichment were discussed. The thermal evolution degree of the shale of Da’anzhai member in the study area gradually increases from southwest to northeast, and the shale can be divided into a highly matured zone and a matured zone on the plane. The highly matured zone is located in the northern part of the study area, with vitrinite reflectance ranging from 1.3% to 1.7%, mainly developing Type Ⅲ organic matter. The early oil generation occured in the early Late Jurassic, and the oil generation peaked at the end of Late Jurassic, experiencing two phases of hydrocarbon generation. The matured zone is located in the central to southern parts of the study area, with vitrinite reflectance ranging from 0.9% to 1.3%, mainly developing Type Ⅱ1-Ⅱ2 organic matter. The sedimentary thickness of the Jurassic is relatively small, the early oil generation occured at the end of the Late Jurassic and reached the peak in the Early Cretaceous, with only one period of hydrocarbon generation. Compared with the northern area, a large set of organic-rich shales deposited in the central area, which provieded a solid material basis for shale oil in the Da’anzhai member. However, the tectonic uplift and stratum erosion since the Paleogene posed a certain destructive effect on the preservation of oil and gas in this area.
The Fengcheng formation in the Mahu sag is a typical alkaline lacustrine deposit characterized by mixed provenance, complex lithology, overall oil possibility, and scattered sweet spots. To efficiently explore and develop the shale oil, it is necessary to optimize geological sweet spots for the shale oil. Based on the results of high-pressure mercury injection and rock pyrolysis experiments, the reservoir and shale oil mobility of the Fengcheng formation in Well Maye-1 were evaluated, a model for optimizing geological sweet spots for the shale oil was constructed, and the vertical distribution of geological sweet spots for the shale oil was assessed. The results show that porosity, total organic carbon content, brittle mineral content, and difference between free hydrocarbon content and 100 times of total organic carbon content are parameters for respectively evaluating the reservoir performance, oil-bearing property, brittleness, and shale oil mobility of the Fengcheng formation. A model for optimizing geological sweet spots for the shale oil was constructed by using these four parameters, with sweet spot factors for Class Ⅰ, Ⅱ, and Ⅲ shale oil geological sweet spots in Well Maye-1 being greater than 0.282 3, ranging from 0.011 1 to 0.282 3, and less than 0.011 1, respectively. Class Ⅰ shale oil geological sweet spots in the Fengcheng formation in Well Maye-1 are mainly distributed in the upper part of the second member of Fengcheng formation and in the third member of Fengcheng formation, with lithology dominated by mudstone and dolomitic mudstone.
The seismic data acquired from Kuqa foreland thrust belt is characterized by low signal-to-noise ratio and high interpretive ambiguity. By using high-resolution 3D seismic data, drilling and lab hydrocarbon analysis data, the stratigraphic assemblages of Kuqa foreland thrust belt were systematically described, the structural model was detailedly interpreted, and the hydrocarbon accumulation system was deeply analyzed. It is found that the Kuqa foreland thrust belt develops two sets of detachment layers: Paleogene and Neogene gypsum-salt rocks, and Triassic and Jurassic coal measures, all of which feature stratified detachment, vertical stacking, and multiphase deformation. Detachment folds in caprocks are found in the shallow structures, while basement-involved imbricate thrust structures are developed in deep strata. Detachment plastic deformation occured in the gypsum-salt and coal layers. Faulting occured in three phases including Caledonian, late Hercynian-Indosinian, and Yanshanian-Himalayan. The late Hercynian-Indosinian tectonics controlled the Mesozoic sedimentation, showing a north-to-south onlap thinning feature. Layered structural deformation in the Kuqa foreland thrust belt governs the stratified accumulation and migration of hydrocarbons. Hydrocarbons in the strata above the coal seam predominantly originated from the Jurassic source rocks, whereas oil and gas in the strata below the coal seam mainly came from the Triassic source rocks which contributs 60% of the hydrocarbons. A substantial quantity of hydrocarbon remains trapped in the formation below the coal layer.
The structural deformation in the foreland thrust belt of the Kuqa depression mainly occurred during the middle-late Himalayan orogeny. Previous studies primarily identified the initiation timing of shallow postsalt fold deformation, but had no absolute dating constraints on the subsalt thrust deformation and the timing of hydrocarbon accumulation. Taking the Awat area in the Kuqa depression as an example, using the data from petrographic observations, calcite U-Pb dating, and fluid inclusion analysis, the diagenesis, formation timing of calcite veins, and hydrocarbon accumulation process of the Lower Cretaceous Baxigai formation reservoirs were investigated, and the timing of structural deformation and hydrocarbon accumulation in the Awat area was determined. The research results show that two periods of calcite were developed in the Baxigai formation in the Awat area. The early calcite cement formed at (98.0±14.0) Ma, while the late calcite veins formed at (3.7±1.0) Ma, reflecting the time of subsalt thrust deformation. Oil inclusions and gas inclusions of different periods were identified in the calcite veins. Based on the homogenization temperatures of the fluid inclusions, burial history and thermal history, it is inferred that the oil charging occurred at 4.0-3.0 Ma, and gas charging at 3.0-1.0 Ma. The early oil reservoir underwent reworking of gas washing in the late Pliocene, forming the current condensate gas reservoir.
Seismic prediction of fractures is the foundation of fractured reservoir evaluation. Metamorphic buried-hill reservoirs exhibit diverse fracture types, significant variations in fracture development at different reservoir parts, and difficulties in describing fracture heterogeneity. The Z4 metamorphic buried-hill reservoir was investigated for its fracture characteristics and seismic prediction. The development of fractures in the Z4 reservoir has layering characteristics and can be divided into four sections such as weathered-semi-filled fractures at the top, highly developed net-like fractures in the upper part, moderately developed low-angle fractures in the middle part, and poorly developed high-angle fractures at the bottom. A comprehensive fracture prediction technique was proposed, which integrates multi-scale general spectral decomposition, dip-oriented eigenvalue coherent processing, and iterative ant analysis. The fracture orientations and development revealed by cores were compared with the results of seismic prediction, suggesting a high consistency. It is believed that the multi-approach comprehensive fracture seismic prediction technology proposed in this study has high accuracy.
Compared to other low-resistivity oil layers, the low-resistivity oil layers in the Lower Jurassic Badaowan formation on the southern slope of the Zhongguai bulge in the Junggar basin are characterized by early hydrocarbon accumulation, deep burial, large grain size, and low mud content, showing a unique low-resistivity genesis. Based on a comprehensive analysis on the genetic mechanisms of typical low-resistivity oil layers globally, together with the data of drilling, logging, well testing, and core analysis in the study area, the main controlling factors of the low-resistivity oil layers in the Badaowan formation were investigated from various perspectives including tectonics, sedimentation, diagenesis, reservoir characteristics, and hydrocarbon accumulation conditions. It is found that low resistivity of the oil layers in the study area is jointly controlled by macroscopic and microscopic factors. In a macroscopic setting with low tectonic amplitude and weak hydrodynamic sedimentation, low oil-water differentiation degree, high formation water salinity, and low tuff debris content are the main controlling factors for low resistivity, while low saturation of bound water is a secondary controlling factor. Accordingly, a chart illustrating the relationship between formation resistivity and oil/gas indicator coefficient was established, which matches the formation/production testing data in the study area by 92.9%. The study results provide a basis for identifying low-resistivity oil layers in the Badaowan formation on the southern slope of the Zhongguai bulge.
In order to reveal and compare the microstructures of sandstone and shale reservoirs, and the fluid occurrences within different sizes of pores in the Fengcheng formation of the Mahu sag, the experiments including high-pressure mercury intrusion (HPMI), nuclear magnetic resonance (NMR), and large-view splicing SEM were conducted to quantitatively characterize the pore throat size and fluid occurrence characteristics of the two types of reservoirs. The NMR experimental results and the HPMI experimental results before and after extraction of the original samples and the pressurized oil-saturated sample were compared to reveal the distributions of bound and movable fluids within pores of different sizes. The results indicate that sandstone and shale do not differ significantly in the sizes of pores and throats, which are dominantly 0.01-10.00 μm in pore diameter and <10.00 nm in throat radius, respectively, indicative of mesopores and fine throats. Shale has slightly larger pore diameters but smaller throat radii than sandstone. Shale mainly develops tubular pores such as intercrystalline pores and honeycomb-like dissolution pores. Sandstone has an equal distribution of tubular and spherical pores, with the proportion of spherical pores such as intergranular pores and intergranular dissolution pores increasing as the pore size increases. Fluid occurrence and mobility are controlled by multiple factors such as mineral composition and pore size. The oil-wet properties of organic matter, dolomite and pyrite, and the strong capillary confinement of intergranular pores in clay minerals, reduce the mobility of shale oil, and the movable fluids are mainly distributed in mesopores-macropores with diameters greater than 300 nm. Combining the reservoir physical properties and movable fluid distribution, it is determined that the favorable shale oil block in the study area is the Ma 51X well block, both shale and sandstone in the well block are favorable targets for development.
In order to clarify sandbody distribution patterns and hydrocarbon accumulation model of the Baijiantan formation in the Mahu sag, Junggar basin, and evaluate its hydrocarbon exploration prospects, the drilling, logging, seismic and experimental data were comprehensively analyzed to understand the sedimentary patterns and hydrocarbon accumulation characteristics of the second member of the Baijiantan formation (Bai-2 member). It is found that the Bai-2 member represents a braided-river delta-beach bar-turbidite fan sedimentary sequence, with three types of sandbodies of underwater distributary channel, beach bar and turbidite fan. Channel sandbodies are dominant in braided-river delta front; beach bar sandbodies are developed in shore-shallow lake; controlled by slope breaks, multiple turbidite fans are developed in deep lake to semi-deep lake, with turbidite fan sandbodies distributed in a lobate pattern. Thus, a sedimentary pattern of underwater distributary channel-beach bar-turbidite fan was established. Nine major strike-slip fault systems are found in the study area. Among them, three types of fault combinations such as through-type, associated-type, and relay-type strike-slip faults effectively connect the Permian Fengcheng formation source rocks and serve as efficient vertical pathways for hydrocarbon migration. The Bai-2 member follows a hydrocarbon accumulation model characterized by strike-slip faults connecting source rocks, fault-sandbody configuration controlling reservoir, and hydrocarbon enrichment in high-quality reservoirs.
Based on the development background of the strike-slip fault zone in the Shunbei area of the Tarim Basin, the in-situ stress states, the fracture systems around faults, and the well productivity characteristics in different segments of the Shunbei No.4 strike-slip fault zone were analyzed by using geomechanical theories. According to the reservoir mechanical properties obtained through P-wave and S-wave logging and rock mechanics experiments, a 3D geomechanical model was constructed. Based on the elastoplastic theory, and by using the finite element numerical simulation method, the fracture development characteristics of the target layer controlled by the strike-slip faults were predicted. The research results show that the in-situ stress patterns vary across segments in the fault zone. The differences in structures of geological units control the in-situ stress distribution, and regions with high fracture density typically exhibit a strip-like distribution on both sides of the fault or between faults. High fracture density combined with Anderson-type Ⅰa and Ⅲ stress states is associated with wells exhibiting high yields. The in-situ stress conditions, fracture development characteristics, and key factors controlling high well productivity in different segments in the Shunbei strike-slip fault zone were clarified.
To determine the genesis of dolomite in the lower Yingshan formation-Penglaiba formation of the Middle-Lower Ordovician in northern Tarim basin, this paper investigates the dolomitization in the target interval through the observations of core samples and thin sections and the analysis of cathodoluminescence, X-ray diffraction order degree, stable carbon and oxygen isotopes, strontium isotopes, and rare earth element compositions and partition patterns, and by combining petrological characteristics with geochemical characteristics. The results show that silty to microcrystalline dolomites and silty to fine-grained anhedral dolomites were formed from syndepositional dolomitization in high-salinity seawater which was primarily originated from the seawater under low-temperature surface evaporation; silty to fine-grained euhedral dolomites were formed from shallow-burial dolomitization in early diagenetic period, with fluids sourced from Ordovician seawater and an increasing temperature with the increase of burial depth; and saddle-like dolomites were formed from hydrothermal dolomitization in early diagenetic period, with fluids sourced from Ordovician seawater as well as later deep-seated magmatic hydrothermal fluid. Reservoir spaces can’t generate from syndepositional high-salinity seawater dolomitization, but may be formed after the dissolution of the precipitated gypsum due to regional constraints and intense evaporation. Eeuhedral dolomite can form under early diagenetic shallow-burial dolomitization, which promotes the development of intercrystalline pores where dissolution fluid may easily enter in late diagenetic stage, forming intercrystalline dissolution pores and dissolved pores. Early diagenetic hydrothermal dolomitization is unfavorable for the formation of reservoir spaces.
In the Tarim basin, transpressional strike-slip faults are developed under oblique compression in the Ordovician carbonate rocks, but a series of transtensional strike-slip faults have been discovered in the Tazhong uplift, significantly controlling the hydrocarbon accumulation. Using the 3D seismic data from the western Tazhong uplift, as well as the attributes such as coherence and curvature, the kinematic parameters of the strike-slip faults were statistically analyzed. Through structural analysis of the strike-slip faults, the FⅡ21 strike-slip fault zone in the Tazhong uplift was optimally selected for segmented modeling, and its growth mechanism was investigated. The results show that the FⅡ21 strike-slip fault zone is segmented horizontally and stratified vertically. Various structural forms such as linear, en echelon, horsetail, wingtip, braided, and overlapping structures are found at the top of the Ordovician carbonates. The characteristics of altitude differences of the fault zone reveal segmentation and tail-end expansion as the growth mechanisms, elucidating its role as a transform fault that regulates the reverse contraction deformation on either side of the strike-slip fault zone, and clarifying its evolution process including stages of en echelon fracturing, growth and linkage, and reactivation.
To clarify the types and distribution of grain shoals in the Middle Ordovician Yijianfang formation in the Fuman area of the Tarim basin, the sedimentary facies and distribution were studied using the core, rock thin section, carbon isotope, logging, and seismic data. The sedimentary facies of the Yijianfang formation in the study area can be categorized into slope-basin, platform margin, and open platform, with the latter two being the principal zones for grain shoal development. The grain shoals which include psammitic shoal, oolitic shoal, bioclastic shoal, and transitional types, generally account for over 80% of the formation thickness, or even over 90% in some well blocks. The distribution of these shallow grain shoals are primarily under the control of sedimentation processes represented by lateral migration in the setting of rapid marine transgression and gradual marine regression. The psammitic shoals and bioclastic-psammitic shoals extensively distributed in the open platform indicates excellent reservoir quality, and they will be significant targets for future petroleum exploration.
Well S3 drilled in the gentle slope zone of the eastern Shiqiantan sag in the east uplift of the Junggar basin, has produced a high-yield industrial gas flow from the Carboniferous Shiqiantan formation. This significant breakthrough in natural gas exploration in the Shiqiantan formation further confirms the presence of a marine clastic-rock sag rich in natural gas in the eastern Junggar basin. To better understand the geological characteristics and petroleum exploration potential of the Shiqiantan formation in the Shiqiantan sag, a comprehensive study of source rocks, reservoirs, and hydrocarbon accumulation was conducted using seismic, drilling, logging, core, and testing data. The Shiqiantan formation in the study area contains two sets of source rocks, which are generally thick and of high quality, providing a solid material basis for large-scale gas reservoir development. The reservoirs in the Shiqiantan formation are typically composed of tight sandy conglomerate in which a fan delta system with bidirectional provenances in the south and north is found. Large scale delta-front sand bodies are mainly distributed in the slope zone around the sag. The Shiqiantan formation hosts near-source tight lithological sandstone gas reservoirs, making it the key target for gas exploration in the Carboniferous of the Shiqiantan sag. It has favorable source-reservoir assemblages jointly controlled by proximity to the source and sand body size.
In recent years, with the progress of oil and gas exploration in the Tarim basin, large-scale strike-slip fault systems have been discovered in the Paleozoic strata of the platform area in the basin and a new type of fault-karst reservoir has been identified. Due to multiple tectonic movements in the basin, these strike-slip faults exhibit multilayer structures featured with multiple phase superimposition. Based on high-quality 3D seismic data, drilling data, and petroleum geological data, the multilayer superimposition of large-scale strike-slip faults in the basin and its controls over hydrocarbon accumulation were investigated. The research results show that the strike-slip fault zones in the platform area of the Tarim basin primarily develop five structural layers in the Paleozoic: Lower Cambrian pre-salt structural layer, Middle Cambrian salt structural layer, Upper Cambrian-Middle Ordovician carbonate structural layer, Upper Ordovician-Carboniferous clastic structural layer, and Permian magmatite structural layer. Affected by multiple tectonic movements and strike-slip fault activities, these layers exhibit characteristics of banded spatial distribution, vertical superposition, and differential superimposition. The superimposition patterns can be broadly categorized into four types: connection, overlapping, inverse superimposition, and inverse reformation. These superimposition patterns have significant impacts on hydrocarbon accumulation, and three types of reservoirs such as TypeⅠ (Ordovician carbonate reservoirs), Type Ⅱ (Ordovician carbonate, Silurian clastic, and Permian magmatite reservoirs), and Type Ⅲ (Cambrian pre-salt dolomite reservoirs) are formed.
The Jurassic strata in the areas around the Yakela fault-bulge in the northern Tarim basin are critical targets for hydrocarbon exploration, where a near-source alluvial fan-fan delta system with the fault-bulge as a provenance is developed. This cannot explain the extensive development of the sandbodies in Jurassic in the southern Yakela fault-bulge. Based on the analysis of the tectonic evolution of the Yakela fault-bulge, together with the seismic and core data and the reservoir characteristics, a comprehensive analysis was conducted on the sedimentary facies to determine the spatial distribution patterns of the sedimentary facies in the Jurassic Yangxia formation around the Yakela fault-bulge. It is found that during the Jurassic deposition the Yakela fault-bulge as a whole was higher in the west than in the east, with erosion occurring in the west and a peneplain state in the east at the late stage of Yangxia formation deposition. The sedimentary system primarily comprises two parts: one sourced from the western Yakela fault-bulge, forming an apron-like distribution of the near-source fan delta deposits along the fault-bulge; the other sourced from the southern Tianshan Mountains, forming a braided river delta system extending from north to south in the eastern Yakela fault-bulge. From the perspective of reservoir characteristics, the fan delta system is characterized by coarse lithology, mainly including conglomerates and gravel-bearing medium-coarse sandstones, with low textural and compositional maturities and poor physical properties. In contrast, the braided river delta system predominantly consists of gravel-bearing medium-fine sandstones, and records a long transport distance, with high textural and compositional maturities and good physical properties. The Yangxia formation in the eastern Yangxia sag may be a potential favorable exploration target.
In the Ordovician carbonate rocks in the Tarim basin, there are extra-large oil and gas oilfields controlled by strike-slip faults. However, the distributions of carbonate reservoirs and hydrocarbons along the fault zones is extraordinarily complex, posing challenges for well deployment and efficient petroleum development. Taking the FⅠ17 hydrocarbon-rich strike-slip fault zone as an example, a fine structural analysis was conducted by using high-resolution seismic data. Coupling with core, logging and production data, the reservoir distribution and its controls on hydrocarbon accumulation were investigated. The results show that the FⅠ17 strike-slip fault zone can be divided into five segments from south to north: parallel en echelon segment, linear segment, superimposed segment, oblique superimposed segment, and horse-tail segment. The distribution, scale, and type of strike-slip faults govern the reservoir distribution and development. From the parallel en echelon segment to the oblique superimposed segment, the fault development intensifies, resulting in larger and more interconnected reservoirs. Conversely, the horse-tail segment in the north features reservoirs distributed along branch faults with poor connectivity. The fault-controlled hydrocarbon reservoirs in the FⅠ17 strike-slip fault zone can be classified into four types: linear fixed-volume, connected superimposed, superimposed fault-block, and tail-end dispersed. The type and scale of strike-slip faults control the reservoir types and hydrocarbon enrichment levels, necessitating targeted drilling strategies for different fault-controlled reservoir types.
To understand the styles and structures of the maze karst cave system in the Upper Ordovician Lianglitage formation in the Tahe oilfield, Tarim basin, the palaeohydrological and geomorphological restoration, karst framework construction, karst cave identification, and genetic model analysis were performed for Block 11 of the oilfield by using the methods such as paleolandform restoration, paleo-water system characterization, log-based stratigraphic correlation, structural fracture analysis, and seismic attribute characterization. The results show that during the Episode Ⅱ of the Middle Caledonian, the southern Tahe oilfield was higher in the northwest than in the southeast geomorphically, with developed NNW-SSE dendritic incised valleys. A subhorizontal maze karst cave system with closed conduit structures and high intensity of erosion are found in the Lianglitage formation, which is a typical maze karst cave system formed by epigenetic karst diffusion and infiltration and shares similarities in genesis with the Bullita karst cave system in the Judbarra region of Australia. The mudstone interval in the Upper Ordovician Qiaerbake formation serves as an aquiclude, which controls the lateral erosion of the karst cave system in the Lianglitage formation. The faults connecting surface water systems provide primary channels for karst water infiltration and erosion. As the regional base level drops, karst water infiltrates downwards along the fractures into the Middle Ordovician strata, forming fault-karst reservoirs in the Yijianfang formation. Understanding the “double-layer” maze epigenetic karst cave system of the Episode Ⅱof the Middle Caledonian in the Tahe oilfield is crucial for the development of Upper Ordovician reservoirs.
The Permian Fengcheng formation in the Maxi slope area of the Junggar basin is characterized by highly saline tight reservoirs deposited in alkaline lakes, and the relationship between oil and water in these reservoirs is complicated, which leads to difficulties in fluid identification. A thermal neutron macroscopic capture cross-section of the highly saline formation was constructed by using lithoscanner logging data, and an oil-sensitive factor was constructed by using the difference between the thermal neutron macroscopic capture cross-section from logging and the thermal neutron macroscopic capture cross-section of the brine-saturated formation. Furthermore, a salinity-sensitive factor was constructed by using the ratio of chlorine element relative yield to total porosity. Then, a fluid identification chart was established by intersecting the oil-sensitive factor with the salinity-sensitive factor. The actual application shows that this fluid identification chart can accurately assess reservoir fluid properties and provide a basis for selecting formation test layers.
