The Nalinhe area is a pilot area for deep coalbed methane （CBM） production in the Ordos Basin. Accurately assessing the area's resource development potential is significant for exploring high-rank CBM in the Benxi Formation. Currently， the geological characteristics of CBM reservoirs deeper than 3 000 meters in this area are unclear， as are the main factors controlling deep CBM productivity. Current evaluation methods are insufficient to effectively support sweet spot evaluation and development deployment for deep CBM reservoirs. This study comprehensively characterizes the CBM reservoir characteristics of the Benxi Formation No. 8 coal seam in the Nalinhe area of the Ordos Basin using coal testing and production and drainage data. Correlation analysis， gray relational analysis， and a machine learning random forest （RF） model were combined to identify the main geological and engineering factors that control high CBM production. Using the analytic hierarchy process， we established a sweet spot evaluation index system to clarify the distribution of deep CBM sweet spots in the Nalinhe area. The results show that： （1） The deep coal seams in the Nalinhe area of the Ordos Basin are characterized by deep burial， high thermal evolution， relatively large thickness， favorable storage conditions， good gas-bearing properties， and weak permeability. This indicates a sound basis for CBM enrichment and development potential. （2） The importance ranking of the geological parameters is as follows： initial permeability， coal thickness and gas content， vitrinite reflectance （R O）， porosity， gas logging peak， and burial depth. The importance ranking of engineering （development） parameters is as follows： sand injection volume， horizontal section length， injected fluid volume， unit pressure drop，and gas casing pressure. The controlling mechanism of CBM productivity has shifted from the commonly observed “resource abundance dominance” in medium-shallow reservoirs to “joint control of resource conditions， producibility， and fracability”. （3） Class I sweet spots are distributed in blocks in the western， eastern， and local areas in the southeastern of the study area and belong to high-resource or high-permeability zones. Class II sweet spots constitute transitional zones between Class I and Class III sweet spots， showing a ring-like distribution between Class I and Class III sweet spots. Class III sweet spots have an index of less than 0.2 and are mainly located along the southern and northern margins of the block. These areas have relatively poor resource conditions and reservoirs that are mostly characterized by relatively low porosity and permeability. This study provides a useful reference for sweet spot and development layer selection for deep CBM in the No. 8 coal seam of the Benxi Formation on the eastern margin of the Ordos Basin.
In the Hengshan-Wubu area on the eastern margin of the Ordos Basin， the Jinci Member of the Benxi Formation develops an interbedded sedimentary system of coal， shale， and tight sandstone. This region is a prime example of the co-enrichment of coal measure “three gases” （deep coalbed methane， shale gas， and tight sandstone gas）， and it has significant resource potential. This study uses systematic sampling， testing， and comprehensive geological analysis to thoroughly elucidate the material basis， differential patterns of reservoir characteristics， and coupled accumulation mechanisms of the coal-measure strata in this area. The results indicate that： （1） The coal measures exhibit high organic matter abundance （an average of 72.68% TOC in coal rock and 4.17% in shale） and have reached the high-to-over mature peak hydrocarbon generation stage （vitrinite reflectance ranging from 1.71% to 2.02%）， which provides a superior basis for generating the “three gases”. The organic matter in shale is predominantly Type II₂-III kerogen， ensuring sustained hydrocarbon generation capacity. （2） Coal， shale， and tight sandstone differ significantly in lithology， physical properties， and pore structure. Coal is dominated by micropores and is characterized by high gas saturation and a high proportion of free gas. Shale has well-developed mesopores and a large specific surface area， but it has the poorest physical properties. Its gas-bearing capacity is notably controlled by sub-member sedimentary facies. The Jin-1 and Jin-2 sub-members have better gas-bearing capacity than the Jin-3 sub-member. Tight sandstone is dominated by micron-scale pores. Although it has relatively higher porosity， its permeability is slightly lower than that of coal rock， and it is classified as a low-porosity， low-permeability reservoir. Vertically， these three layers form a complementary sequence of “high-gas-content coal rock—high-quality source shale—low-permeability tight sandstone”.（3）The enrichment of deep coalbed methane is controlled by the synergy of hydrocarbon generation intensity， positive structural backgrounds， and sealing conditions of the roof and floor. Shale gas enrichment primarily depends on sedimentary facies belts， organic matter maturity， and brittle mineral assemblages. Tight sandstone gas follows a mechanism of “widespread hydrocarbon generation and near-source accumulation within the source rock”， where hydrocarbon generation intensity determines the resource scale and local physical property “sweet spots” control high-yield distribution. （4） A co-occurrence accumulation model dominated by “intra-source combination accumulation” has been established for the Jinci Member in the Hengshan-Wubu area. Lagoon and shallow marine shelf facies belts are identified as optimal targets for the stereoscopic exploration of coal-measure gas due to their superior source-reservoir configuration. This study clarifies the differential enrichment laws of the “three gases” in coal measures， providing critical geological basis for the comprehensive， full-system evaluation and synergistic， stereoscopic development of coal-measure gas in the Ordos Basin and similar coal-bearing basins.
In recent years， major breakthroughs have been made in exploring Upper Paleozoic natural gas in the Qingyang Gas Field in the Longdong area of the southwestern Ordos Basin. The Shan1 Member and the He8 Member are the main gas-bearing intervals. However， due to strong reservoir heterogeneity， the natural gas is characterized by localized enrichment. Therefore， clarifying the reservoir characteristics and their controlling factors is significant for future natural gas exploration and development. Taking the tight sandstone reservoirs of the He8 Member in the Heshui-Zhengning area as the research object， this study integrates core observations， well-log data， cast thin-section analysis， scanning electron microscopy， high-pressure mercury intrusion， petrophysical measurements， and other analytical data. This approach is used to systematically investigate the sedimentary microfacies， pore structure， diagenetic characteristics， and their controlling factors. The results indicate that： （1） The He8 Member developed primarily as a shallow-water， braided-river delta plain subfacies， supplied by sediments from the southwest. This subfacies can be further subdivided into distributary-channel and floodplain microfacies. In the lower second sublayer of the He8 Member （He8 L2）， flood-dominated distributary channel sand bodies are relatively thick and exhibit good lateral continuity. （2） The He8 Member generally has ultra-low porosity and low permeability， and the reservoir quality progressively deteriorates from the lower second sublayer （He8 L2） to the upper first sublayer （He8 U1）. The main reservoir spaces consist of intercrystalline pores in clay minerals， intergranular dissolution pores， and lithic-fragment dissolution pores. The pore structure is primarily Type II. （3） Distributary-channel microfacies， sand-body thickness， and internal position within sand bodies significantly impact the macroscopic distribution of reservoirs. Compaction， pressure solution， ferroan calcite cementation， and quartz overgrowth significantly deteriorate reservoir quality. However， late-stage dissolution of carbonate minerals and kaolinite clay minerals， together with the development of microfractures， improves reservoir properties locally. （4） Thick distributary-channel sand bodies in the He8 L2 submember constitute the principal development zones of favorable reservoirs. Further statistical analysis of sample data indicates that among the macroscopic factors in the He8 L2 submember， the sand-to-formation ratio and sand-body thickness show significant positive correlations with porosity and LgK. At the microscopic scale， kaolinite exhibits the highest gray relational grades with porosity and LgK； however， the differences in weights among the microscopic factors are relatively small. Therefore， these results are used only to compare relative relational strength. Tuffaceous material is generally characterized by localized， high-value enrichment. However， its well-interval mean content shows no statistically significant correlation with porosity or LgK. This indicates that its influence on reservoir quality is localized and condition-dependent.
Large-scale sedimentary clinoform systems are developed in the Yanchang Formation in the Qingcheng area along the southwestern margin of the Ordos Basin. However， extant studies have primarily relied on 2D seismic data for static and qualitative descriptions， which hinders effective characterization of their evolutionary processes. This study utilizes 1 500 km² of high-resolution 3D seismic data to conduct a comprehensive investigation of the growth and evolution of clinoforms in the Yanchang Formation of the Qingcheng area， Ordos Basin. The objective is realized through the qualitative characterization of three-dimensional seismic geomorphology and the quantitative calculation of key geometric parameters of the clinoform systems. The study identifies eight clinoform stages （C1-C8） in the Yanchang Formation， Qingcheng area， predominantly comprising sigmoidal and oblique types. These clinoforms grow progressively from the southwestern source areas towards the basin center， exhibiting variable dominant growth directions and an evolution shift from thicker topsets to thicker bottomsets. This pattern reveals the migration of the lake-basin depocenter from southwest to northeast. Foresets of clinoforms in the study area predominantly exhibit the geometric morphological characteristics of an upper section that is “short and steep” and a lower section that is “long and gentle”. The research， in response to this unique feature， innovatively proposes the geometric parameters foreset shape ratio （Fsr） and foreset steepness variation index （Fsvi） to quantitatively characterize morphology and evolution processes of clinoforms. C2， C6 and C7 exhibit Fsr≥0.6， corresponding to oblique clinoforms characterized by underdeveloped topsets. C3-C5 exhibit Fsr<0.4， reflecting sigmoidal clinoforms with a well-developed “topset-foreset-bottomset” architecture； C1 and C8， representing early and late evolutionary stages respectively， display Fsvi≈1， indicating a transitional type. Based on morphological characteristics， C1 and C8 are judged to be more inclined towards the oblique type. Parameter studies indicate that multi-phase superimposed clinoforms undergo a three-stage filling evolution： oblique type - sigmoidal type - oblique type. This process is primarily controlled by tectonics and sediment supply， with relative lake-level changes playing a secondary role. The research reveals the variable characteristics of clinoform morphology and evolution， and establishes the relationships between quantitative parameters， morphological types and sedimentary processes. The research provides novel perspectives for the quantitative study of clinoforms in the Ordos Basin， as well as a solid geological foundation for the study of the evolution of clinoforms in other lacustrine basins.
The Qingshimao Gas Field， which is newly discovered by Changqing Oilfield Company， PetroChina， is the eighth to be classified as a 100-billion-cubic-meter-scale gas field. It is a new frontier for tight gas exploration and development in the Ordos Basin， and a replacement area for increasing reserves and production. However， the current natural gas accumulation process and its key controlling factors in the Qingshimao tight sandstone gas reservoirs are unclear. Through analyzing sedimentary facies， sand body distribution， fault activity， later tectonic movements and reworking processes， thermal evolution， and hydrocarbon generation histories in the Qingshimao Gas Field， this study systematically analyzes how sedimentary-tectonic evolution and post-depositional modification control tight sandstone gas accumulation in this field. Our results show that the thickness and planar distribution of Early Permian unidirectional sand bodies trending NW-SE controlled the range of tight sandstone gas reservoirs within the He 8 section and the Shanxi Formation in the Qingshimao Gas Field. Hercynian faulting controlled the lithological-structural trap in the Qingshimao gas field. The tectono-thermal evolutionary history， the differential pressure between the source and the reservoir， and the Indosinian-Early Yanshanian faulting activities jointly controlled the processes of natural gas enrichment and accumulation. This was crucial for natural gas to undergo long-term continuous migration， filling and accumulation during the Jurassic-Early Cretaceous period. Since the Late Cretaceous， the Qingshimao gas field has undergone large-scale uplift， erosion， cooling， and weakened hydrocarbon generation. These processes have reduced the pressure differential between the source and the reservoir， and have also reduced the dynamics of migration， charging， and accumulation. During the Late Yanshanian and Himalayan periods， fault movement destroyed the preservation conditions of the Qingshimao gas reservoir， constituting the primary cause of its adjustment， destruction， and leakage.
The Yanwu area of the Ordos Basin has a unique tectonic position， and its complex， multi-stage fault system strongly controls hydrocarbon accumulation. However， the difficulty of seismically identifying faults and the limited understanding of the reservoir-controlling mechanism severely constrain exploration deployment. To address these issues， this study first uses the latest seismic data to perform seismic forward modeling and determine the detection limit of low-grade faults. This improves the detection accuracy of concealed strike-slip faults and clarifies the intrinsic differences in the effectiveness of multiple seismic attributes for fault characterization. Next， we investigate fault evolution in this area. The fault system can be divided vertically into three-layer architecture： Caledonian normal faults， Hercynian mixed normal-reverse faults， and Indosinian-Yanshanian strike-slip faults. In plan view， the faults display multi-scale and multi-directional characteristics. Finally， the reservoir-controlling mechanism is analyzed. Hercynian fault activity controlled the development of Permian reservoirs and trap formation. Yanshanian fracture systems improved the physical properties of reservoirs. Himalayan tectonic adjustments promoted gas redistribution， ultimately leading to the formation of structural-lithologic composite gas reservoirs. These findings reveal the origin and evolution of the faults in the Yanwu area， as well as their reservoir-controlling mechanisms. This information provides important support for the deployment of future exploration efforts.
This study clarifies the controlling effect of fault structures on natural gas enrichment in bauxite gas reservoirs of the Taiyuan Formation in the Qingcheng-Heshui area of the southwestern Ordos Basin， providing a scientific basis for their exploration and evaluation. A comprehensive analysis of stratigraphy and fault structures was carried out based on high-precision 3D seismic data. The layer flattening method and the seismic structural trend method were applied to restore the paleogeomorphology and the microgeomorphic units. Geostatistical inversion technology was also used to predict the distribution of bauxite. The results reveal the development of four fault systems （the Lvliang-Caledonian， Hercynian， Indosinian， and Yanshan-Himalayan） in the study area， which experienced four evolutionary stages： basement formation， synsedimentary activity， structural adjustment， and closure/transformation. Third-order geomorphic units， such as buried pits （depressions） and grooves in karst highlands and slopes， are favorable for the development of porous bauxite reservoirs. Geostatistical inversion enables the quantitative prediction of gas-bearing bauxite reservoirs with a coincidence rate of over 85% verified by 7 wells. The fault system controls gas reservoirs in three ways： provenance channels， pore construction， and migration and accumulation. The Hercynian synthetic fault-step zone formed by fault reactivation controls the dynamics and direction of the allochthonous transport of aluminum-bearing clastics， forming vertical seepage channels for pore construction. Indosinian faults further dissolutionally modify the reservoirs， and Yanshan–Himalayan faults have the dual function of destruction and adjustment， as well as local sealing. Statistics show a negative correlation between gas layer thickness and distance from main faults， confirming faults' positive controlling effect on gas enrichment. The spatiotemporal coupling between the Hercynian synthetic fault-step zone and the microgeomorphic units is concluded to be the key mechanism controlling the development of bauxite reservoirs and natural gas enrichment. This understanding surpasses traditional thinking， which focuses on only one paleogeomorphology or fault element. It provides important support for identifying "sweet spots" in bauxite reservoirs and optimizing well placement.
Due to the low accuracy of conventional well logging methods for porosity measurements in highly heterogeneous， tight sandstone reservoirs and the need to improve the prediction performance and geological interpretability of existing machine learning methods， this study uses Chang 6 Member of the Yanchang Formation in the Wujqi area of the Ordos Basin as an example. Six training wells and two blind wells were selected， along with conventional logging data and porosity data from the target layer. Pearson， Spearman， and Kendall correlation analyses were used to evaluate the correlation between logging parameters and porosity. The average of the absolute values of these three coefficiants is used as the overall correlation degree to rank and select input features for the model. A porosity prediction model is built using the LightGBM algorithm， and the Bayesian optimization algorithm is employed to globally optimize key hyperparameters. This results in a prediction model with higher accuracy and stronger generalization ability for unknown wells. Finally， the SHAP algorithm is introduced to quantitatively analyze the degree to which the above factors influence the model. The results indicate that the six parameters most closely related to the porosity of tight sandstone are acoustic transit time （AC）， density （DEN）， compensated neutron log （CNL）， deep laterolog resistivity （RT）， natural gamma （GR）， and deep induction resistivity （CILD）. The BO-LightGBM model used in these calculations achieved a coefficient of determination， R²， of 98% based on data from two independent blind well tests. The root mean square error （RMSE） and the mean absolute error （MAE） are 0.248 and 0.148， respectively. Compared to traditional linear regression and supervised machine learning models （RF， SVM， XGBoost， LightGBM， and GAPSO-LightGBM）， R² values improved by 14.9%， 14.1%， 47.7%， 11.3%， 7.8%， and 4.5%， respectively. Additionally， RMSE and MAE are relatively low. Acoustic transit time （AC） and density well logging （DEN） were identified as the primary factors affecting porosity prediction in tight sandstone reservoirs. This method provides an efficient， highly interpretable approach to predicting porosity in tight sandstone reservoirs.
comprehensive characterization of shale reservoirs， specifically the multi-scale cascade characterization spanning meter， millimeter， micrometer， and nanometer scales， is paramount for "sweet spot" prediction. This methodology relies heavily on multi-scale digital core technology， which integrates various core imaging techniques to comprehensively evaluate reservoir properties from micro to macro scales. This technology plays a crucial role in shale oil exploration and development. This study investigated shale oil reservoir rocks from the Chang 73 sub-member in the Jiyuan area of the Ordos Basin. Multi-scale digital core scanning experiments were performed to establish digital core models across various scales and types. Subsequently， numerical simulations were performed to characterize key parameters， including rock mineralogy， storage space， and fluid flow capability. This provided an in-depth analysis of the practical application of multi-scale digital core technology in evaluating shale oil reservoirs. Results show that the Chang 73 shale oil reservoir in the Jiyuan area has well-developed texture with significant vertical variations in mineral composition and high clay mineral content. The storage space is highly complex and features dual-medium characteristics composed of fractures and matrix pores. The matrix pores are predominantly submicron- to micron-scale intergranular dissolution pores and clay pores. Type I reservoirs （siliceous shale） are the dominant lithofacies reservoirs and are characterized by high matrix porosity， superior pore connectivity， and relatively favorable fluid flow capability. Type II reservoirs （organic-rich， clay-bearing siliceous shale） have relatively well-developed millimeter-scale fractures and moderate matrix pore development. However， their matrix transport properties are poor. Fine pore throats and restricted pore connectivity are the primary limiting factors. Type III reservoirs （organic-rich， clay-rich mud shale） have high organic matter content， but they have low porosity， poor pore structure， and minimal matrix flow capability. They predominantly act as source rocks. The integrated application of multi-scale digital core technology provides a robust theoretical foundation and technical support for the comprehensive characterization of shale reservoirs and efficient shale oil development.
Deep coal seams are prevalent in the Ordos Basin's deep area. Controlled by the superposition of multi-stage coal-forming processes， these coal seams are characterized by great burial depth， well-developed partings， and widespread thin coal seams. Coal seams exhibit strong， continuous peak reflections in seismic responses. However， the limited seismic bandwidth in relation to the demand for fine characterization of thin coal seams has become a key technical bottleneck that restricts deep coalbed methane exploration in this area. To overcome the difficulty of identifying thin beds below seismic resolution， this study establishes a progressive technical system for the fine characterization of thin coal seams based on petrophysical analysis. First， a high-resolution inversion method constrained by paleogeomorphology and multi-level facies control is used to accurately clarify the spatial distribution of multiple thin coal seams and partings. Second， we combine logging and core data to construct characteristic curves of macroscopic coal lithotypes and quantitatively characterize them. Finally， the coupling transformation between wave impedance and the characteristic curves is completed using cloud transformation technology based on the high-resolution inversion results. This clearly depicts the spatial distribution of high-quality coal seams dominated by bright and semi-bright coal. The prediction results align well with actual drilling data. The proposed technical system has been verified to effectively improve the seismic characterization accuracy of coal seams， overcome the prediction problem of thin coal seams， and provide important technical support for the efficient exploration and development of deep coalbed methane in the eastern Ordos Basin.
The study focuses on the Chang 7 Member of the Dongrengou Block in the Ordos Basin to address the strong dependence on empirical judgment in interval selection and the uncertainty in treatment-parameter design for refracturing mature wells. We established a K-means clustering-fuzzy comprehensive evaluation （KM-FCE） evaluation method for interval selection by integrating K-means clustering with fuzzy comprehensive evaluation. We then optimized refracturing parameters through fracture-propagation simulation of typical wells. Oil saturation and the poroelastic stress-reorientation coefficient were identified as key indicators of refracturing potential. The absolute values of their respective correlation coefficients with one-year cumulative oil production after refracturing were 0.78 and 0.82. Intervals with an oil saturation of approximately 40% and a Class I membership degree of about 0.36 exhibited relatively high refracturing potential. Numerical simulations of typical vertical wells revealed that increasing the volumes of the treatment fluid and proppant promoted new fracture propagation. However， the incremental gain in fracture length gradually diminished as the treatment scale increased. A per-stage treatment fluid volume of 70-90 m³ and a proppant volume of 14-18 m³ are recommended. 80 m³ of fluid and 16 m³ of proppant were selected as representative parameter combinations. These results provide a basis for selecting intervals and designing parameters for refracturing mature wells in the Chang 7 Member of the Dongrengou Block.
Most current methods of evaluating reservoir fracturability rely primarily on the rock brittleness index. However， existing studies have shown that these approaches lack sufficient stress-strain mechanistic support and often exhibit significant discrepancies with actual fracturing performance under complex stress fields and heterogeneous conditions. Under similar burial depth and lithology backgrounds， intervals with high brittleness indices do not necessarily have higher post-frac productivity. Fracturability is essentially a comprehensive characterization of rock fracture tendency and fracture propagation capacity under the constraints of in-situ stress and natural defects. Of these factors， the in-situ stress differential plays a particularly significant role in controlling fracture initiation modes， propagation paths， and fracture network morphology. This factor more accurately reflects fracturing behavior under real geomechanical conditions. Compared to the well-established evaluation systems for shale and tight sandstone reservoirs， due to its strong heterogeneity， confining-pressure sensitivity， and complex fracture-vug structures， research on fracturability in tight limestone reservoirs is considerably lacking， with no unified indicator system and quantitative standards. This paper proposes a multi-parameter， coupled fracturability evaluation model for the tight limestone of the Taiyuan Formation that considers key factors such as the brittleness index， fracture toughness， in situ stress differential， and natural fracture index. Using a weighted product form to reflect the synergy and “short-board effect” of key factors， the model outputs a comprehensive fracturability index （FI）. Comparative validation against traditional brittleness index models shows stronger capability in fracturability grading and sweet-spot identification under varying lithologies and stress field conditions. It achieves significantly higher agreement with field fracturing responses and production data， with post-frac productivity increases of 37%-46% in optimized intervals of typical wells. When applied to the tight limestone reservoirs of the Taiyuan Formation in the Ordos Basin， the model effectively identifies fracturing “sweet spots”， selects optimal intervals， and optimizes parameters. This markedly enhances the stimulated reservoir volume and fracture network complexity， providing a reusable evaluation method and engineering basis.
Water blocking limits gas-well productivity and development efficiency in tight gas reservoirs. To clarify its mechanisms and spatial distribution patterns， long-core displacement experiments and high-temperature， high-pressure visualized displacement tests were conducted together with nuclear magnetic resonance （NMR） measurements. The characteristics of water blocking damage under different displacement pressure differentials were systematically investigated. Results show that water blocking damage increases along the gas flow direction， indicating strong spatial heterogeneity. Formation water retention varies significantly with pore scale. Small pores are the main sites of water retention； even at a pressure differential of 20 MPa， the average retention reaches 74.70%， showing low sensitivity to pressure changes. In contrast， water in medium and large pores is more readily mobilized， with retention decreasing to 57.11% and 22.45%， respectively， as the pressure differential increases. Correspondingly， the morphology of water blocking evolves from patchy to film-like and eventually to sheet-like distributions with decreasing displacement pressure differential. Furthermore， the application of an anti-water-blocking agent enhances gas-phase permeability by reducing interfacial tension and altering rock wettability. These findings provide a theoretical basis and technical support for optimizing displacement pressure control and designing effective water-blocking removal measures in tight gas reservoirs.
As development of high-water-content gas reservoirs in tight sandstones in the northern Ordos Basin intensifies， well network density continues to increase. This leads to a growing number of inter-well interference incidents. These interference wells exhibit “rapid response and difficult production recovery” characteristics， which significantly impact the continuous， stable production of gas wells and the achievement of expected recovery factor targets. This study focuses on the geological and engineering parameters， as well as the production characteristics of the interfered wells in the A block of the Dongsheng gas field's high-water-content gas reservoir in tight sandstones. The study systematically analyzes the factors influencing the fracturing interference of tight sandstone gas wells. It employs methods such as generalized grey relational analysis， CRITIC weighting method， the entropy method， and the information weight assessment method to evaluate the influence weights. The results of the research indicate that the main controlling factors affecting inter-well interference are well spacing， average proppant volume relevant stage， the absolute open flow potential of the interfered wells， and the time of production commencement. Additionally， parameters such as pumping rate and average fluid volume per stage also influence inter-well interference to some extent. Based on the analysis of degree of fracturing interference and its main controlling factors， a comprehensive evaluation model for inter-well interference factors has been established. Based on the parameter boundaries of the main controlling factors， targeted preventive measures are proposed to optimize well spacing and treatment parameters. According to the minor， moderate， and severe interference， corresponding recovery measures are implemented： enhanced dynamic monitoring with spontaneous recovery for minor cases， gas lift for general cases， and regular chloride monitoring with well-specific strategies for severe cases. This achieves a 94.4% recovery success rate. These measures provide a favorable basis for preventing inter-well interference and restoring production capacity in horizontal well fracturing operations in gas fields. This approach strongly supports the efficient development of tight sandstone gas reservoirs.
To address the challenges of severe formation energy depletion and rapid production decline after fracturing fluid flowback in shallow （burial depth ~500 m） ultra-low permeability tight oil reservoirs of the Yanchang Oilfield， Ordos Basin， a low-damage and high-efficiency imbibition slickwater fracturing fluid system suitable for non-flowback operations was developed， coupled with an "energy storage and enhancement" technology for horizontal well volume fracturing. Through laboratory experiments， APFR-6 was selected as the friction reducer， ammonium persulfate as the gel breaker， and ZSD-SX-1 nano-microemulsion as the permeability enhancer， establishing a base fluid formulation of fresh water + 0.2%–0.3% APFR-6 + 0.02%–0.03% ammonium persulfate + 0.1% ZSD-SX-1. Performance evaluations indicated that the imbibition oil recovery reached 16.8%–17.2% under atmospheric conditions and 21.1%–23.5% under high pressure （9 MPa）， while the matrix permeability damage rate was reduced to 10%–12% and the fracture conductivity damage rate ranged from 9% to 19%. Shut-in imbibition experiments determined an optimal imbibition pressure of 9 MPa. Based on this， a numerical simulation model was established and validated through history matching， leading to the optimization of a process chain characterized by "high-pressure shut-in， gradient pressure depletion， and controlled flowback rate". Field tests on two horizontal wells demonstrated that， compared to offset wells in the same region， the average daily oil production increased by 35.7% and the decline rate decreased by approximately 7.4% within the first three months of production. This technology provides an economically effective approach for energy storage and enhancement of shallow low-pressure ultra-low permeability tight oil reservoirs， with broad application prospects.
The application of CO2 flooding has garnered significant attention due its ability to significantly enhance oil recovery. However， low-permeability reservoirs frequently exhibit substantial heterogeneity， both within individual layers and across multiple layers. This heterogeneity can manifest especially the development of local high-permeability channels， which can lead to preferential flow patterns and subsequent alterations in sweep efficiency， residual oil distribution， and gas channeling. The present study focuses on a low-permeability reservoir in Block X of the Yanchang Formation within the Ordos Basin. To this end， three large-scale physical core models were constructed， including a homogeneous single-layer model， a heterogeneous single-layer model， and a heterogeneous dual-layer model with both intra-layer and inter-layer heterogeneity. These models were constructed to investigate CO2 flooding following water flooding. The electrical resistivity responses were monitored using the potential electrode method， while pressure evolution was measured using piezoresistive pressure sensors， all under reservoir temperature and pressure conditions. During the water-flooding stage， oil saturation was quantitatively interpreted based on calibrated rock-electrical relationships. Conversely， during the CO2 flooding stage， resistivity responses were used solely to characterize the apparent gas–oil phase distribution and the evolution of preferential flow pathways. The results demonstrated that， during the process of CO2 flooding in the homogeneous model， fluids migrated along the main streamlines， thereby progressively establishing dominant channels. In the heterogeneous model， planar high-permeability strips reduced local flow resistance and promoted preferential CO2 migration； however， they also intensified sweep heterogeneity and the development of dominant flow channels. The phenomenon of asynchronous mobilization of the upper and lower layers is further exacerbated by interlayer permeability contrasts. The final recovery factors of the three models were 56.21%， 70.36%， and 69.54%， respectively. These differences reflect the combined control of different heterogeneous structures on sweep efficiency and channeling risk. The present study offers experimental evidence for understanding fluid migration in dominant-channel reservoirs under interlayer and intralayer heterogeneity. It also provides a foundation for well-pattern optimization and displacement-scheme design.
The study systematically investigates the types and distribution of formation water， characteristics of water-rock interactions， and their geological implications for hydrocarbon accumulation in the 6th member of the Yanchang Formation （Chang 6 Member） in the Yanchi area of the Ordos Basin， in order to elucidate its hydrochemical characteristics and petroleum geological significance. The analysis is based on 132 high-quality formation water samples and employs methods including major ion composition analysis， Piper diagram classification， ion-ratio analysis， and evaluation of the relationships between hydrochemical parameters and reservoirs. The results indicate that the formation water in the Yanchi area is generally characterized by high salinity， with total dissolved solids （TDS） ranging from 70.03 to 153.40 g/L. It is dominated by Cl- and K++Na+ and belongs mainly to the CaCl2-type formation water. Vertically， salinity shows a regular decreasing trend with increasing burial depth. Stratigraphically， salinity follows the order of Chang 61 > Chang 62 > Chang 63 . Laterally， salinity is relatively higher in the southwestern part of the study area and lower in the northeastern part. Water-rock interactions directly influence the geochemical characteristics of local fluids in different sub-members. The type and intensity of diagenetic processes， including feldspar dissolution， chloritization of biotite， carbonate cementation， and chlorite cementation， are the main factors controlling Mg2+ and SO4 2- enrichment and locally high HCO3 - anomalies in the Chang 62 formation water. In the Chang 6 Member of the Yanchi area， the average Na+/Cl- ratio of formation water is 0.51， the average Mg2+/Ca2+ ratio is 0.27， and the average metamorphism coefficient is 40.63， collectively indicating good formation sealing capacity and favorable hydrocarbon preservation conditions. The sealing capacity of formation water in the northern part of the study area is better than that in the southern part， with higher oil-test production in the north than in the south. Overall， the hydrochemical composition and evolutionary characteristics of formation water in the study area provide important indicators for evaluating the quality of tight sandstone reservoirs， hydrocarbon preservation conditions and the optimization of exploration targets.
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