Coal rock gas (CRG) in the Upper Carboniferous Benxi formation in the Ordos Basin is currently in the early stage of exploration and development, and knowledge regarding the coal rock’s microscopic composition, pore structure, and their controls on gas occurrence remains limited. By using techniques including petrographic microscopy, X-ray diffraction (XRD), micro-CT scanning, low-temperature CO₂ adsorption, low-temperature N₂ adsorption, high-pressure mercury intrusion, and high-pressure autoclave-gold tube pyrolysis simulation, etc., the maceral composition, industrial component, pore structure, and gas occurrence states in the No. 8 coal seam of the Benxi formation in the study area were investigated. The results show that the No. 8 coal seam is dominated by bright and semi-bright coals, with average vitrinite, inertinite, and exinite contents of 78.8%, 18.2%, and 1.0%, respectively. The coal rock exhibits an average fixed carbon content of 70.00% and an ash content of 13.90%, indicative of low-ash coal. The micropores, mesopores, and macropores contribute 75.7%, 14.4%, and 9.9% to the total pore volume, respectively, while their specific surface area proportions are 98.3%, 1.0%, and 0.7%, respectively. The micropores contribute the most to both total pore volume and specific surface area. The adsorbed gas and free gas account for 74.7% and 25.3% of the total gas content, respectively. The adsorbed gas content is positively correlated with micropore volume and micropore specific surface area, while the free gas content shows an approximately positive correlation with macropore volume.

To determine the factors influencing coal rock gas productivity in the Carboniferous Benxi formation in the eastern Ordos Basin and identify favorable target areas for production, based on the fundamental geological characteristics and test data of the study area, the No. 8 coal seam was taken as an example for detailed reservoir characterization and analysis of factors controlling gas accumulation. A high-precision 3D geological model was constructed, and sweet spot areas were identified. The study area is a gently west-dipping monocline as a whole. The No. 8 coal seam is well developed and stable, with a thickness ranging from 6.0 to 12.0 m. The reservoir-caprock assemblage primarily consists of coal and mudstone, and the coal structure is mainly classified as Type Ⅰ and Type Ⅱ. In plane, coal rocks are distributed in a banded pattern, with a high gas content averaging 23.17 m3/t. The key factors controlling gas content include burial depth, thermal maturity, positive structure, fracture development, and reservoir-caprock assemblage. Based on the analyses of lithofacies, gas content, rock mechanics, in-situ stress, and fracture characteristics, and considering resources, structural features, coal seam properties, and stress regimes at the roof/bottom, a scheme for sweet spot optimization was proposed. As a result, approximately 777 km2 Class Ⅰ sweet spots and 560 km2 Class Ⅱ sweet spots were delineated.

The Middle Ordovician Wulalike formation is the primary target for marine shale gas exploration in the Majiatan area of the Ordos Basin. The reservoir is dominated by siliceous shale and characterized by thin layers and strong horizontal heterogeneity, seriously challenging the seismic identification. By utilizing geological, logging, and core data from the Majiatan area, a petrophysical analysis was performed on the marine shale reservoir, a shear-wave prediction method was proposed, and the optimal petrophysical parameters for characterizing the sweet spots of the marine shale gas reservoir were identified. By integrating drilling and gas testing results, the evaluation criteria for geological and engineering sweet spots of the marine shale gas reservoir were established. By combining post-stack seismic waveform-indicated simulation with self-organizing neural network fusion techniques, the distribution of sweet spots in the shale gas reservoirs was predicted. The results show that the geological and engineering sweet spots are primarily distributed in a band-like pattern in the western and central parts of the study area. The drilling results confirm that the seismic prediction method for sweet spots of shale gas reservoirs is worthy of promotion.

Conventional characterization of meandering river reservoirs typically relies on data from densely-spaced vertical wells, but insufficient inter-well data results in unreliable planar combinations of architectural elements. Taking the SSF-AH horizontal well + large well group targeting the Permian Shanxi formation in Sulige gas field as an example, and by integrating horizontal and vertical well data, the lithofacies of the meandering river reservoirs were identified, and the reservoir architecture was analyzed. The results demonstrate that the lithofacies in the study area can be classified into four types. Type Ⅰ to Ⅳ shows a gradually decreasing hydrodynamic force during deposition. Types Ⅰ and Ⅱ constitute the main gas-bearing lithofacies, while Types Ⅲ and Ⅳ are generally non-productive. Three combination patterns of architectural elements of the meandering river reservoir are identified: transverse-spanning, longitudinal-spanning, and intercrossing. The sand bodies of the meandering river channels are 900-1 100 m wide; the sand bodies of point bars are 650-800 m long (avg. 720 m) and 800-1 000 m wide (avg. 910 m); and the width of abandoned channels are generally less than 100 m. The point bars are typically composed of 4-5 stages of lateral accretion sand bodies, with the thickness ranging from 0.4 to 1.5 m individually and the planar width ranging from 120 to 220 m. The lateral acceretion mudstones are 0.2-0.4 m thick, with a vertical density of 0.5-0.8 beds per meter and a planar density of 0.011 beds per meter. The integration of horizontal wells with large well groups can improve the accuracy of architecture characterization.

To mitigate reservoir sensitivity damage and enhance oil recovery, the reservoir characteristics and sensitivity controlling factors of the 7th and 8th members of the Lower Jurassic Yan’an formation (Yan 7 and Yan 8 members) in the Yanwu oilfield, Ordos Basin were investigated. Using the data of petrophysical properties, cast thin sections, scanning electron microscopy (SEM), and mercury intrusion, and through various reservoir sensitivity experiments, the reservoir characteristics were identified, the reservoir sensitivities were evaluated, and the factors controlling reservoir sensitivities were analyzed. The results show that the Yan 7 and Yan 8 reservoirs are primarily composed of medium-grained feldspathic lithic quartz sandstones and medium- to fine-grained lithic quartz sandstones, respectively. The Yan 7 and Yan 8 reservoirs exhibit average porosities of 15.3% and 13.7%, average permeabilities of 498.9 mD and 343.0 mD, average plane porosities of 9.5% and 8.7%, and average pore diameters of 83.1 μm and 51.8 μm, respectively. The two reservoirs show weak-moderate velocity sensitivity, weak salinity sensitivity, weak-moderate acid sensitivity, strong alkali sensitivity, and negligible-to-weak stress sensitivity. The water sensitivities of the two reservoirs differs significantly: the Yan 7 reservoir shows a weak-moderate water sensitivity, while the Yan 8 reservoir has a moderate-strong water sensitivity. The sensitivities of the two reservoirs are primarily influenced by mineral composition, physical properties, and pore-throat structure, among which mineral composition plays a dominant role. The water sensitivity is closely related to the content and occurrence of illite; the acid sensitivity is influenced by the presence of chlorite and ferroan dolomite; and the strong alkali sensitivity results from high feldspar and quartz content. During reservoir stimulation, the pH values of injected fluids should be strictly controlled to minimize the reservoir damage induced by sensitivity.

The Permian Shan-1 member in the Qingyang gas field is characterized by large burial depth, complex diagenetic processes, and differential diagenesis-pore evolution, leading to unclear understanding of favorable reservoirs. By using the data from cast thin sections, scanning electron microscopy (SEM), physical properties, cathodoluminescence (CL), and X-ray diffraction (XRD) of authigenic clay minerals, and combining with previous research findings, the diagenesis of the Shan-1 member was investigated. The results indicate that the Shan-1 member exhibits a transition from meandering-river delta plain subfacies to delta front subfacies from southwest to northeast. Compared with delta plain reservoirs, the delta front reservoirs are featured with fewer interstitial materials, developed pores, better pore-throat structure, and favorable physical properties. Sedimentation controls the initial porosity, while differential diagenesis-pore evolution determines the degree of reservoir compaction. The delta front reservoirs are found with high initial porosity, which was then reduced by 36.34% due to compaction and cementation and enhanced by 4.28% due to dissolution, resulting in a present-day average porosity of 7.13%. In contrast, the delta plain reservoirs have low initial porosity, which was then reduced by 37.72% due to compaction and cementation and enhanced by 3.65% due to dissolution, resulting in a present-day average porosity of 4.43%. The delta front reservoirs are of good quality, as a result of a densification process from moderate compaction reducing porosity, to moderate cementation further decreasing porosity, and to moderate dissolution enhancing porosity. In contrast, the delta plain reservoirs show poor quality, after a densification process from strong compaction reducing porosity, to moderate cementation further decreasing porosity, and to weak dissolution enhancing porosity.

Affected by source input and sedimentary cycles, continental mud-shale systems are lithologically complex and diverse. To elucidate the lithological differences of these systems and their controls on shale oil content, the mud-shale system in the 7th member of the Yanchang formation (Chang 7 member) in the Ansai area of Ordos Basin was selected for detailed analysis. By comparing petrological and geochemical characteristics, the development features of mudstone, shale, sandstone, and sand-laminated shale in the study area were identified. Through quantitative evaluation of shale oil content and analysis of geological parameters, the differences in shale oil content between different lithologies and the controlling factors were revealed. The results indicate that shale has the highest content of shale oil, with a poor mobility; sandstone and sand-laminated shale contain moderate content of shale oil, with a good mobility; and mudstone has the lowest content of shale oil, with the poorest mobility. For shale, mudstone, and sand-laminated shale, the higher the total organic carbon content and pyrolysis peak temperature, the higher the shale oil content; the better the organic matter types, the higher the shale oil content. For sandstone, the higher the porosity and permeability, the higher the shale oil content.

To determine the oil source and hydrocarbon accumulation mechanism for the eighth member of the Yanchang formation (Chang 8 member) in the northern Pingliang area of the Ordos Basin, chromatography and chromatography-mass spectrometry of saturated hydrocarbon, and carbon isotope composition were combined to analyze organic geochemical properties and sources of the crude oil in the Chang 8 member. It is found that the crude oil in the Chang 8 member varies greatly in density and viscosity. Due to biodegradation, the crude oil in the Chang 8 member is characterized by high density, high viscosity, elevated Pr/nC₁₇ and Ph/nC₁₈ ratios, and relatively low abundance of rearranged hopanes. The ααα-20R steranes display an asymmetric V-shaped distribution, and the crude oil contains a high proportion of C₂₇ regular steranes, indicating that its organic precursor is primarily derived from aquatic organisms deposited in a freshwater to brackish water, weakly oxic to weakly reducing environment. The crude oil in the Chang 8 member in the Pingliang-Guoyuan area is classified as low mature to mature oil, with lower Ts/Tm, tricyclic terpane/17α(H), and 21β(H) hopane values compared to the crude oil in the Change 8 member in the Yinjiacheng area. The Chang 7 source rock in the study area has lower organic matter abundance, maturity, and development scale than those in the Qingyang area, with differences in tricyclic terpane/17α(H), and 21β(H) hopane values. By comparing the biomarkers of crude oil and source rocks, and considering the development and maturity of the source rocks, it is inferred that the crude oil in the Chang 8 member in the Pingliang-Guoyuan area is well correlated with the Chang 7 source rock in the northern Pingliang area, and it is mainly accumulated after vertical migration. In contrast, the crude oil in the Chang 8 member in the Yinjiacheng area is correlated with the Chang 7 source rock in the Qingyang area, and it is mainly accumulated after lateral transportation and migration.

A number of Jurassic reservoir groups have been discovered in the southern part of the Tianhuan depression in the Ordos Basin, highlighting significant oil and gas exploration potential. Taking the Yanwu area as an example, by integrating the data of 3D seismic, drilling, core, and production performance, the fault characteristics were investigated, and the controls of these faults on the Jurassic Yan’an formation reservoir were analyzed. The results indicate that the Mesozoic in the Yanwu area develops three groups of major faults trending in NW-SE, NEE-SWW, and nearly E-W, which are primarily sub-vertical strike-slip faults featured with lateral zonation and vertical stratification. The NW-SE faults in the Triassic Yanchang formation were formed during the Indosinian Movement. The NEE-SWW and nearly E-W faults in the Jurassic Yan’an formation were mainly formed during the Yanshanian Movement, with the highest fault density in the Jurassic, and some discontinuous minor faults connected and extended through the Late Yanshanian to Himalayan to create the main fault belt. The NEE-SWW strike-slip faults vertically communicate source rocks and reservoir rocks, facilitating hydrocarbon migration and accumulation in the Jurassic. The trap-controlling faults near the main displacement zone, which exhibit large fault throws, resulted in hydrocarbon escape during multiple phases of activity, compromising reservoir preservation. Fractures are developed at fault ends or in overlapping zones. These fault-related fractured reservoir may suffer water front advancing, significantly impacting waterflooding effect in the reservoirs.

During water flooding in ultra-low permeability reservoirs, crude oil within the swept area is preferentially produced, leaving a high residual oil saturation with the potential for further recovery. Microbially activated water flooding is an effective reservoir development technology; however, its mechanism in ultra-low permeability reservoirs remains unclear. By integrating geophysics, microbiology, and reservoir engineering, the group components and microbial diversity of crude oil were tracked and analyzed. Then, using production performance data, the mechanism of microbially activated water flooding was investigated. The results indicate that in relatively homogeneous reservoir regions, surface tension of produced fluids remains stable, biomarkers in crude oil show no significant degradation, and oil viscosity exhibits no substantial changes. MEOR in the study area is mainly realized with the mechanism of microscopic profile control, supplemented by displacement efficiency enhancement and viscosity reduction. During field applications, this finding was validated by using reservoir microbial variations and production data.

Shale oil is primarily developed through horizontal well volume fracturing, where substantial fluid is injected into and produced from the matrix. However, the contributions of imbibition and displacement remain controversial. To clarify their mechanisms and contributions in shale oil reservoirs, the shale core samples from the Chang 7 member of the Qingcheng oilfield were used for analysis. The imbibition + displacement and displacement experiments under formation pressure, as well as imbibition experiments under varying pressures, were performed to obtain the nuclear magnetic resonance (NMR) T₂ spectra at different stages, and the impact of well soaking on production were analyzed. Furthermore, by integrating fractal theory and oil-water two-phase flow theory, a mathematical model of flow mechanics which considered displacement pressure and capillary pressure was established, and a chart illustrating imbibition and displacement under different pressure differences was plotted. The results show that displacement primarily mobilizes oil in medium-to-large pores, while imbibition recovers oil from pores and throats of all sizes. Compared to pure water flooding, post-imbibition water flooding demonstrates superior oil displacement efficiency, because imbibition can not only mobilizes oil directly but also facilitates subsequent water flooding performance.

To understand the sweep efficiency and water washing behaviors during waterflooding of extra-low permeability reservoirs in the Chang 6 member of the Ansai oilfield, 9 sealed coring inspection wells were systematically deployed at different orientations around Well W16-15 in the WY block. Using logging and scanning electron microscopy (SEM) data, the water washing behaviors, sweep efficiency, and microstructural changes in the reservoir were examined. The results show that the Chang 61-21 sublayer with good physical properties is strongly water washed, whereas the Chang 61-31 sublayer with poor physical properties is weakly or not water washed. The smaller the angle between the producer orientation and the principal stress direction or the closer to the injector, the greater the water washing degree and the water-washed reservoir thickness. The vertical sweep efficiency of the inspection well group in Chang 6₁ is 0.51, closely matching the calculated sweep efficiency (0.55) of the original well group. In the medium water-washed and strongly water-washed intervals of Chang 6 reservoir, long-term washing by injected water leads to the migration and swelling of clay minerals, enhancing the reservoir heterogeneity.

CO₂ solubility is a critical parameter impacting the effects of CO₂ injection for enhanced oil recovery (EOR) in low-permeability/tight reservoirs and CO₂ storage in deep saline aquifers. By using a high-temperature, high-pressure visualized phase reactor, CO₂ dissolution experiments were conducted to investigate the influences of formation temperature/pressure, formation water salinity, and multiphase fluid saturation on solubility of CO₂ in crude oil-formation water systems. A prediction model for CO₂ solubility in crude oil-formation water systems under formation temperature and formation pressure was developed by fitting experimental data. The results show that in crude oil-formation water systems, CO₂ solubility is strongly influenced by pressure and fluid type, and higher pressure and oil saturation can promote CO₂ dissolution. Both formation water salinity and temperature have minor impacts on solubility of CO₂ in formation water. CO₂ dissolution in crude oil exhibits multistage behaviors, and the CO₂ solubility increases significantly with the increase of oil saturation. Moreover, CO₂ solubility declines rapidly with increasing water saturation in oil-water systems and decreases slightly with increasing temperature. The solubility prediction model, derived from the fitting of experimental data, calculates CO₂ solubility in two-phase systems via saturation-weighted contributions of the solubility in oil and water phases and the results show high consistency with the experimental results.

The shale reservoirs of the Chang 7 member in the Qingcheng oilfield are characterized by the combination of mud shale and multi-stage thin layers of fine to silty sandstone, posing significant challenges for optimizing and adjusting long horizontal well trajectories, which in turn affects the overall oilfield development effect. Four mature trajectory adjustment techniques, i.e. logging-seismic combined frequency-division attribute fusion, fine 3D geological modeling constrained by seismic structure, trajectory-stratigraphy matching, and curve shifting, were described with the adjustment success rates of 87.9%, 88.3%, 89.8% and 92.5%, respectively. Furthermore, the 3 techniques were evaluated regarding application scope, advantage, and limitation. Based on the evaluation results, a comprehensive analysis method was proposed for complex and challenging wells. The performances of these techniques were evaluated with respect to 11 parameters for 268 horizontal wells in the central Huachi area of Qingcheng oilfield. It is found that the application of the conventional mud-logging geosteering technique in conjunction with one trajectory adjustment technique increases the reservoir encountered rate to 79.4%, while the comprehensive analysis method improves the reservoir encountered rate to 84.2%.

The Jurassic bottom-water reservoirs in the Ordos Basin suffer from insufficient natural energy, low pressure coefficient, low permeability, and strong reservoir heterogeneity, and they exhibit a rapid rise in water cut and low recovery when developed by conventional water injection process. To improve the development effects of such reservoirs, the concept of bottom water injection was proposed. In respect of five key factors influencing the development effects of bottom-water reservoirs, i.e. bottom-water energy, permeability anisotropy, barrier permeability, interlayer frequency, and sedimentary rhythm, oil-layer water injection and bottom water injection were compared for recovery by using reservoir numerical simulation. The results indicate that bottom water injection effectively enhances bottom water energy, facilitates uniform elevation of the oil-water contact, and significantly extends oil production period with medium-low water-cut. Compared with oil-layer water injection, bottom water injection improves ultimate oil recovery by more than 10%.

Well pattern optimization for tight gas reservoirs is generally implemented at the overall deployment stage. In the central Sulige gas field, which is now in mid-to-late development stage, the productivity construction enters the well infilling stage. To ensure the performance of infill wells, it is essential to evaluate the reasonable well pattern density under varying reservoir conditions, infill timing, and natural gas prices. In this study, typical well blocks with different reserves abundances in the central Sulige gas field were selected for numerical simulation. By analyzing development indicators of gas wells and gas reservoirs under different well pattern densities, the degree of gas well interference and formation pressure distribution of existing wells at different production stages were assessed. Based on these findings, the ultimate cumulative gas production of infill wells was predicted. By integrating economic parameters such as natural gas prices, the reasonable well pattern density for different infill timings was determined, enabling economically well infilling. The application in the Sulige gas field demonstrates that, at a natural gas price of 1.119 yuan/m3, a reasonable well pattern density of 4.5 well/km2 can be deployed in non-producing areas; for infill drilling near existing wells within 3 years of production, the well density can be increased to 3.5 well/km2; if the gas price rises to 1.550 yuan/m3, infill drilling near wells within 5 years of production can reach 5.0 well/km2.

Ultra-low permeability reservoirs are typically developed by waterflooding, which yet is highly complex in the factors influencing displacement limits. To establish a waterflood displacement limit characterization method for ultra-low permeability reservoirs, 12 parameters were considered, including porosity, permeability, pore-throat radius, and heterogeneity coefficient. These parameters are classified into three categories：porosity-permeability, heterogeneity, and pore-throat radius. By using the Pearson correlation coefficient method, the optimal characterization parameters were identified from each category, and a characteristic displacement index was then constructed based on the selected parameters. Waterflooding experiments were conducted to determine displacement limits for different core samples, and a characterization model was established by fitting the displacement limits with the characteristic index. The results indicate that, among the influencing parameters, permeability, variation coefficient, and weighted average pore-throat radius can effectively characterize the displacement limits of ultra-low permeability reservoirs. By fitting the displacement limits with the selected characterization parameters, a reliable waterflood displacement limit characterization model for ultra-low permeability reservoirs can be developed.