The Paleogene Shahejie Formation， Dongying Sag， develops typical carbonate-rich shales deposited in a saline lacustrine environment， with substantial shale oil resources. However， diverse types， multiple formation periods， and complex genetic processes of laminae and veins present a significant challenge to elucidating its shale oil enrichment mechanism. Therefore， this study focused on the calcite laminae and fracture veins developed in the upper Submember of the Fourth Member of the Eocene Shahejie Formation （Es4u） in Niuzhuang Subsag. By integrating fluid inclusion micro-petrography， fluorescence analysis， homogenization temperature， and freezing point measurements， the fluid activities and stages involved in the formation of different types of calcite laminae and fracture veins were analyzed. In combination with the simulation of the basin to restore the paleopressure evolution history of Es4u in Niuzhuang Subsag， the study revealed the key roles of fluid activities and paleopressure evolution in the process of shale oil enrichment. In Es4u of the study area， the shale mainly exhibits three types of calcite laminae： micritic calcite laminae， fibrous calcite laminae， and granular calcite laminae， along with fracture veins. Two periods of oil inclusions were identified within the fibrous calcite laminae and fracture veins. The yellowish-white fluorescent oil inclusions were captured 36.5-29.5 Ma ago， while the blue-white fluorescent oil inclusions were captured 10.5-6.3 Ma ago， documenting two periods of episodic hydrocarbon expulsion. The results of the paleopressure recovery analysis of fluid inclusions in Es4u shale indicate that the paleopressure during the first phase of episodic hydrocarbon expulsion was 33.13-64.69 MPa， and the formation pressure coefficient was 1.31-2.05， which was in a weak-to-strong overpressure environment. The paleopressure during the second phase of episodic hydrocarbon expulsion was 45.15-76.17 MPa， and the formation pressure coefficient was 1.39-2.09. The overpressure strength has increased. A comprehensive analysis suggests that the paleopressure evolution systematically documents the enrichment of Es4u shale oil. Temporally， the two overpressure peaks at the two phases correspond to the two key episodic hydrocarbon expulsion periods for shale oil enrichment. Spatially， the pressure distribution pattern， characterized by “being high in the subsag center and low at the margins”， is strongly coupled with the distribution of high-quality source rocks. This indicates the development area of the “sweet spots” of shale oil.
The deep part of the Ordos Basin is rich in coalbed methane resources. Understanding the characteristics of deep coalbed methane accumulation is of great geological significance for the geological evaluation and selection of deep coalbed methane. Combined with the burial and hydrocarbon generation evolution history of coal seams， the micropore characteristics of deep coal reservoirs were systematically investigated. The types of pores where free gas is present were identified， and the formation mechanism of free gas in coal seams was explored. Research results indicate that the mudstone， silty mudstone， and siltstone in the roof of the No. 8 coal seam in the Benxi Formation of the Ordos Basin all exhibit good sealing capacity. When micro-fractures are well-developed， and the coal seam is rich in free gas， effective trapping conditions can be formed. The microscopic pore structure of deep coal reservoirs shows a distinct bimodal distribution， with both micropores and macropores being well-developed. Macropores include maceral-type and bituminous-type pores. The formation of maceral-type pores is related to the hydrocarbon generation of unstable components during the coalification process， and bituminous-type pores are associated with the cracking gas of liquid hydrocarbons. These two types of pores have a relatively large size and can serve as the storage sites for free gas. The accumulation of deep coalbed methane is governed by the geological processes of pore development. Key geological factors include the coalification of coal measures， the burial and hydrocarbon generation history of the coalbed methane， and the rock’s mechanical properties of the macerals， which critically influence the occurrence of both deep free gas and adsorbed gas. Deep coal seams are characterized by extensive and blanket-like accumulation， with stable distribution， high gas content and saturation， and substantial free gas storage space. In production， these reservoirs demonstrate rapid gas breakthrough， strong reservoir energy， and high productivity. The free gas resources of coal seams in the burial depth range of 1 500-4 000 m are as high as 4.64 × 1012 m3. In particular， the areas of Yulin， Wushenqi， and Dingbian-Huachi-Zhidan have large resources and high gas contents in coal seams， which are worthy of accelerated exploration and deployment.
The exploration of ultra-deep volcanic rock-type oil and gas reservoirs in the Junggar Basin faces a series of scientific problems， including unclear mechanisms of reservoir formation， hydrocarbon accumulation， and reservoir destruction. The reservoir minerals filled in the pores and fractures of volcanic reservoirs in different periods completely record the process of reservoir formation， hydrocarbon accumulation， and reservoir destruction. Through the study of the relative timing relationship of reservoir mineral formation and the chronological constraints of key reservoir minerals， the process of reservoir formation， hydrocarbon accumulation， and reservoir destruction of ultra-deep volcanic rocks can be reconstructed. The ultra-deep Carboniferous volcanic reservoir in the Fukang Sag was selected as the research object to clarify the genesis and reservoir formation mechanism of reservoir minerals， establish the relationship between reservoir formation and hydrocarbon accumulation， and restore the process of reservoir formation， hydrocarbon accumulation， and reservoir destruction， to provide a decision-making basis for the exploration of ultra-deep volcanic oil and gas reservoirs. The study shows that the ultra-deep volcanic rocks in the Fukang Sag have undergone complex processes of diagenesis and reservoir formation. The chlorite， quartz， and calcite filling in the reservoir pores and structural fractures are of post-magmatic hydrothermal fluid and oilfield brine origin. The reservoir spaces of ultra-deep volcanic rocks are mainly formed in the supergene karst period. The reservoir spaces of ultra-deep volcanic rocks were mainly formed during the epigenic karstification stage. During the subsequent deep to ultra-deep burial， multi-stage charging of post-magmatic hydrothermal fluids and oilfield brines resulted in varying degrees of damage to pre-existing vugs， pores and structural fractures； the deep dissolution in the process of ultra-deep burial is beneficial to the formation of secondary dissolution pores. Epigenic karstification， tectonic deformation and ultra-deep burial dissolution are vital mechanisms controlling the formation of ultra-deep volcanic rock reservoirs. The ultra-deep volcanic reservoirs in the Fukang Sag have experienced multiple stages of hydrocarbon accumulation and destruction， and the destruction of ancient oil and gas reservoirs is mainly controlled by post-magma hydrothermal filling. The destruction of the earliest ancient oil and gas reservoirs mainly occurred at 225.8 ± 2 Ma and may have experienced the superposition of two other stages of oil and gas accumulation and destruction. High-quality reservoir areas with weak post-magmatic hydrothermal activities are prospective targets for ultra-deep volcanic hydrocarbon accumulations in the Fukang Sag.
Since the “13th Five-Year Plan” period， 120 million tons of heavy oil reserves have been newly discovered and unproduced in Chunfeng Oilfield， which is an important strategic position for the construction of a base producing one million-ton crude oil in the western part of Shengli Oilfield. In view of the problems faced in the process of developing ultra-thin-shallow ultra-heavy oil reservoirs in Chunfeng Oilfield， including insufficient formation energy caused by ultra-shallow reservoir （burial depth of 180-300 m）， large heat loss caused by ultra-thin reservoir （overlapping effective thickness <6 m and single effective thickness of 1.5-3 m）， and high viscosity caused by ultra-heavy oil （10 × 104-75 × 104 mPa·s）， an innovative multi-effect coupled injection and production development technology of thermal permeable structure unit was proposed. The method revealed the synergistic mechanism of expanding thermal enthalpy field with multi-well coordination， multi-energy superposition， and multi-component enhancement as the core， and the integrated pattern of injection and production of combined huff and puff， combined displacement and drainage， multi-branch well coupling for field application was established to solve the problem of narrow effective flow and small volume. A functional diverting agent chemical system for expanding thermal enthalpy field was invented， achieving long-term plugging and thermal diversion. Eight sets of multi-well and multi-point full-system coupled injection and production processes and devices were innovatively developed， thus ensuring the balanced expansion of the thermal enthalpy field. The average annual production of ultra-thin-shallow ultra-heavy oil reservoirs in Chunfeng Oilfield has reached 20 × 104 t since the “14th Five-Year Plan” period， and the investment per million-ton has been reduced to 3.01 billion； the production capacity after 6-year construction has reached 120 × 104 t， ensuring that the annual oil production in Chunfeng Oilfield has increased by more than one million-ton for six consecutive years. The Chunfeng Oilfield produced 140 × 104 t of heavy oil in 2024， with significant economic and social benefits， and has built a new mode of high-efficiency development for ultra-thin-shallow ultra-heavy oil reservoirs.
The Ordovician ultra-deep strike-slip fault-controlled reservoirs in the Shunbei area of the Tarim Basin feature severe heterogeneity， and internal structural differences of fault zones dominate hydrocarbon accumulation and well productivity. Insufficient characterization of fracture-vug assemblages in fault segments with varying geometries， differences in reservoir connectivity， and their corresponding productivity response mechanisms restricts the fine evaluation of deep fault-controlled reservoirs and the optimization of favorable exploration targets， which restricts fine evaluation and favorable exploration target selection for deep fault-controlled reservoirs. Taking the No.1 Fault Zone in Shunbei as the research object， this study integrates high-precision 3D seismic data， drilling and mud logging records of circulation loss and drilling break， pressure buildup well test data， and production performance data. Through fine interpretation of seismic profiles and dynamic identification of log-log well test curves， the internal fractured-vuggy structural types of the fault zone are systematically classified， and differentiated development models for fault-controlled reservoirs are established. On this basis， the seismic responses， inter-well connectivity， and productivity characteristics of various reservoir types are compared. Three types of fault-controlled reservoirs are classified， namely the weakly fractured type， the through-fractured type， and the composite strongly connected type. Five fracture-vug architectures are identified， including linear main slip surfaces， isolated fracture-vugs， throughgoing fractured bodies， composite throughgoing fractured bodies， and laterally continuous throughgoing fractured bodies with strong strike extension. The intensity of segmented fault activities shows a differentiated pattern： strong activity in the middle segment and weak activity in the northern and southern segments. The No.3 intensely active segment hosts composite highly connected reservoirs with optimal inter-well connectivity and the highest single-well fluid production capacity. The weakly active segments （Segments 0-2） are dominated by isolated fracture-vugs， featuring poor reservoir connectivity and low productivity. The moderately active segments （Segments 4-5） develop throughgoing fractured reservoirs with intermediate connectivity and productivity. Geometric segmentation of strike-slip faults systematically restricts the fracture intensity， spatial assemblage of fracture-vugs， and reservoir connectivity of fault-controlled reservoirs by governing tectonic activity intensity. The internal architecture of reservoirs directly determines fluid supply capacity and well productivity. Composite highly connected reservoirs represent the favorable reservoir type for high and stable production in the study area. Accordingly， a complete evolutionary model of reservoir formation and hydrocarbon accumulation control is established， which links geometric segmentation， fault activity intensity， internal reservoir architecture， reservoir connectivity， and well productivity.
With the rapid development of artificial intelligence （AI） technology， its application in the field of oil and gas exploration and development has become increasingly extensive. To address the core challenges faced by the current oil and gas industry， including safeguarding energy security， maintaining stable production and improving efficiency in the late development stage of mature oilfields， and achieving cost reduction and efficiency enhancement， as well as to meet the urgent demand for deepening the industry’s digital transformation， this paper systematically discussed the theory and practice of the AI system for oil and gas exploration and development centered on large models. This paper first put forward four core concepts for the aforementioned AI system and completed the design scheme of its overall technical architecture. Then， combined with the practical application case of the “Shengxiaoli” large model from Sinopec Shengli Oilfield Company， it elaborated on the technical implementation， application effects， and follow-up development plan of this AI system in oil and gas exploration and development. The research shows that the large model-based AI system built on the four core concepts can deliver low-cost and highly agile responses to business demands and effectively solve the industry pain points in traditional intelligent applications， such as difficulty in knowledge reuse， high data barriers， and a long business adaptation cycle. Although oil and gas large model technologies in China and abroad are still in the exploration and trial stage， large model-centered technologies have demonstrated remarkable application value in field practice. They will bring revolutionary changes to the intelligent upgrading of the oil and gas industry and provide systematic theoretical support and replicable practical reference for the industry’s digital and intelligent transformation.
CO2 flooding and storage in tight sandstone reservoirs are one of the major demands for achieving China’s “carbon peaking and carbon neutrality” goal， and it is an important research direction for improving China’s oil and gas resource supply and reducing CO2 emissions. A comprehensive review was conducted on the current development status of CO2 flooding and storage in tight sandstone reservoirs， including the mechanisms of CO2 flooding and storage， micro molecular simulations， mesoscopic Lattice Boltzmann method （LBM） simulations， and macro experimental simulations of CO2， crude oil， formation water， and rock， as well as the integrated technology of CO2 flooding and storage. Based on the current research status， problems， challenges， and bottlenecks faced by tight sandstone reservoirs in CO2 flooding and storage， key issues that urgently need to be further studied were proposed， including the multi-objective dynamic synergistic integrated optimization model for CO2 flooding， storage， safety， and economic benefits， the CO2 flooding and storage collaborative optimization proxy model based on machine learning and data drive， the variation law of reservoir physical parameters under multiple factors， the time-varying law of reservoir physical parameters and the coupling mechanism between fluid transport， and the multi-scale coupling of microscale （molecular dynamics）， mesoscopic scale （LBM simulation）， and macroscopic scale （reservoir numerical simulation） transport. The synergistic integrated technology of CO2 flooding and storage provides a green and efficient new technology for the economic benefit development of tight sandstone reservoirs in China， achieving the safety， accuracy， and economy of CO2 flooding and storage projects and helping to achieve China’s strategic goals of “carbon peaking and carbon neutrality”.
Compared with ordinary polymers， emulsion polymers used for oil displacement in Daqing Oilfield exhibit performance characteristics such as emulsifying thickening and low interfacial tension， leading to better oil displacement efficiency than conventional polymer flooding. However， the numerical model of conventional polymer flooding fails to accurately characterize the oil displacement mechanism of emulsion polymers， affecting the optimization of injection parameters and the effect prediction. In view of the performance characteristics of emulsion polymers， the mathematical models in the CHEMEOR numerical simulation software were used to equivalently characterize the oil displacement mechanisms of emulsion polymer flooding systems， including emulsifying thickening， shear resistance， and interfacial tension reduction. Through numerical simulation studies， parameters such as injection concentration， polymer dosage， and slug combination modes of emulsion polymers were optimized， and their influences on oil displacement efficiency were analyzed. The optimization results show that the amplitude of enhanced oil recovery increases with the increase in emulsion polymer injection concentration and dosage， but the growth rate slows down. The optimal oil displacement effect is achieved when the injection concentration is 1 200 mg/L， the polymer dosage is 1 200 （mg/L）·PV， and the slug combination mode of pre-high concentration + gradient concentration reduction is adopted. Based on the parameter optimization results， a field test of emulsion polymer flooding has been carried out. After implementation， the stage effect meets the expectation， and the variation law of field water cut is in good agreement with the numerical simulation prediction results， predicting that the ultimate oil recovery can be increased by more than 14 percentage points.
Continental shale oil reservoirs in the Jiyang Depression are characterized by large burial depth， strong heterogeneity， high crude oil viscosity， and low-to-moderate thermal maturity. Their development is confronted with severe challenges， including rapid production decline and pronounced stress sensitivity， and the development experiences of marine shale oil in North America cannot be directly applied. To establish a full-life-cycle regulation method of production system suitable for continental shale oil， typical shale oil reservoirs in the Jiyang Depression were taken as the research targets. Three core flow mechanisms， namely imbibition displacement， stress sensitivity， and nonlinear flow， were clarified. Based on production performance and flow regime characteristics， the full-life-cycle of fractured horizontal wells was divided into five stages： shut-in， early flowback， linear flow， transitional flow， and boundary flow. A quantitative staged regulation index system was constructed with pressure diffusion rate， production drawdown pressure， elastic liquid productivity， and daily pressure drop rate as core parameters， and field application verification was implemented. The results demonstrate that the pressure diffusion rate should be controlled in grades according to the fracture development degree during the shut-in stage. In the early flowback stage， the choke size is increased stepwise to 4-6 mm with a controlled production drawdown pressure of 8-10 MPa. For the linear flow stage， the elastic liquid productivity ranging from 1 500 to 2 000 m3/MPa is set as the regulation threshold. The optimal daily pressure drop rate of 0.06-0.07 MPa/d is determined for the transitional flow stage， while a reasonable production drawdown pressure of 3-5 MPa is maintained in the boundary flow stage. After adopting the full-life-cycle production system regulation strategy in Well FYX1， the water cut rapidly droped to 27% in the early flowback stage； the cumulative oil production reachesd 32 189 t in the linear flow stage， and the daily oil output stabilized at 30 t/d during the transitional flow stage. The estimated ultimate recovery （EUR） of the natural flow period was increased to 10.9 × 104 t.
Low-permeability fractured reservoirs are commonly challenged by non-Darcy flow， complex reservoir architecture， multi-stage channel shielding， time-varying fracture effects， and stress sensitivity， while existing numerical simulation methods still lack sufficient accuracy and systematic theory and technology. Taking the M Block of the Chaoyanggou Oilfield in Daqing as an example， the matrix non-Darcy flow behavior is accurately characterized through equivalent start-up pressure gradient simulation to improve the description of displacement systems. A multi-stage channel contact simulation was adopted to revise sandbody connectivity and enhance the fitting accuracy of water-cut at channel boundaries. Considering time-varying fracture behavior， a dynamic evolution model for natural fractures was established； the activation timing of implicit fractures was optimized， and a dynamic modeling scheme for hydraulic fractures was incorporated， so as to improve oil-water migration simulation. Meanwhile， a pressure-sensitive effect of reservoirs and an effective water injection volume simulation method were employed to refine the calculation of effective water injection volume and the allocation of injected water. Results show that under the threshold pressure characterization， residual oil in low-permeability zones without an effective displacement system accounts for 9.25%. After connectivity correction， the boundary water-cut error decreases， and the single-well fitting accuracy exceeds 80%. The incorporation of time-varying effects of natural fractures improves the single-well water-cut fitting accuracy by 18.56 percentage points. Through simulation using a hydraulic fracture conductivity decline model， the relative error of liquid production rate decreases from 11.6% to 1.8%， and the proportion of inter-well trapped residual oil increases by 4.36 percentage points. After simulating the pressure-sensitive effect， the relative error in the flowing pressure fitting for existing wells can be controlled within 3%， and the relative error in predicted daily liquid production for new wells can be controlled within 4%. After calibrating the water storage capacity of the surrounding rock， the pressure fitting accuracy reaches 98.14%， representing an improvement of 1.32 percentage points. Ultimately， the calculation accuracy of cumulative oil production improves by 0.66 percentage points； the field-wide composite water-cut calculation accuracy improves by 0.52 percentage points， and 86.2% of oil wells have water-cut errors less than 4%.
Deep exploration in the Ordos Basin in recent years has revealed that tight sandstone gas reservoirs possess considerable potential for helium resources. Helium and natural gas are derived from distinct source rocks. Clarifying the enrichment mechanism and evolutionary patterns of the two gases within the same reservoir system can further guide the exploration of helium-rich gas accumulations. This study focused on the Longdong area in the southwestern margin of the Ordos Basin. Geochemical and petroleum geological approaches were adopted to analyze the carbon isotopic compositions of natural gas and the distribution characteristics of radioactive elements in potential helium source rocks. The genetic mechanisms of helium， main controlling factors and model governing the accumulation of helium and natural gas in this area were systematically investigated. The results indicate that the methane and ethane carbon isotopes in this area are inverted， suggesting that the natural gas originated from deep mixed sources with reversed carbon isotopes， with source rocks being carbonaceous mudstones and marine source rocks from the Carboniferous to Permian coal measures. The helium isotope ratio （R/Ra） ranges from 0.021 to 0.046， suggesting a typical crustal radiogenic origin， with the helium sourced from uranium- and thorium-rich granitic rocks of the Archaean basement. The average helium content of natural gas in the study area is 0.157%， classified as medium helium abundance. Helium migrates via mechanisms including deep thermally driven diffusion， advective release and vertical hydrothermal degassing. Under the extraction effect of migrating natural gas， helium mixes with high-pressure-driven natural gas and migrates upward to accumulate in overlying traps. Deep and large faults connecting the basement helium source rocks and overlying tight sandstone reservoirs act as efficient pathways for vertical helium migration. The reservoir-forming model of different sources but identical reservoirs for helium and natural gas demonstrates that the activity and connectivity of deep faults control the pulsed release and enrichment of helium.
The velocity of deep-buried sandstone is similar to that of sandy mudstone and limy mudstone， and their seismic reflection characteristics are similar. The reservoir prediction is indefinite only by using seismic data. In view of this key problem of reservoir prediction， an intelligent curve reconstruction inversion technology was proposed. By making full use of natural potential， natural gamma， and other logging curves that can distinguish the reservoir and non-reservoir， the medium- and low-frequency components of the acoustic travel time log reflecting the formation’s velocity， the medium- and high-frequency components of the sensitive curve reflecting the lithology changes， and the seismic waveforms reflecting different lithological combinations were intelligently learned to construct a reconstructed acoustic travel time log can reflect both the formation changes and highlight the reservoir information. The intelligently reconstructed acoustic travel time log is used to participate in logging constraint-based seismic inversion， which eliminates the interference of sandy mudstone and limy mudstone to a large extent and improves the reliability of turbidite sandbody prediction in calcareous-rich areas. The technology has been applied in the prediction of turbidite sandbodies in the calcareous-rich area of the middle Submember of the third Member of the Eocene Shahejie Formation （Es3M） in the Minfeng area along the eastern belt of the northern Dongying Sag. The prediction results conform to the law of geological distribution and are highly consistent with the drilling results， which effectively guide the exploration well position deployment in this area.
The flow mechanism for the elastic development of shale oil is complex， and the fluid distribution and mobilization mechanism during hydraulic fracturing， shut-in， and development stages are unclear. It is difficult to evaluate the contribution of different energy sources to oil production， and the influence of pore structure and imbibition is unclear. Therefore， the online nuclear magnetic resonance-assisted core experimental method for the entire elastic development process of shale oil was improved， revealing the flow mechanism for elastic development of cores， imbibition mechanisms， and the influence of pore structure. Moreover， an evaluation method for the contribution rate to oil production was established to quantify the contribution rate of different energy sources to oil production. Research has shown that ① fracturing fluid is mainly distributed in large pores， after hydraulic fracturing injection volumes are large， and the artificial energy replenishment is sufficient in fractured and laminated cores. ② During the shut-in stage， the synergistic effect of residual pressure difference and capillary force promotes the fracturing fluid in large pores to replace shale oil in small pores， increasing the degree of shale oil mobilization， and the imbibition efficiency is positively correlated with the development of laminae and fractures. ③ During the development stage， multi-scale pores and fractures are gradually activated， with the fracturing fluid in the bedding fractures and large pores first produced， resulting in high water cut； as small pores gradually supply liquid， the water cut decreases and tends to stabilize. In addition， the contribution rate of submicron-micron pores in laminated cores to oil production exceeds 60%， and the characteristic of a high contribution rate of large pores to oil production is obvious. ④ The final recovery of different lithofacies cores is 8.7%-14.7%， and the contribution rates of rocks and fracturing fluids to oil production are 43.7%-54.9% and 23.0%-30.0%， respectively. The fractures and laminated structures improve the recovery and contribution rate of fracturing fluid to oil production.
SiO2 nanoparticles （SiO2 NPs） have been proven to be an effective means for enhanced oil recovery （EOR） and have been extensively studied and applied. However， in the high-temperature and high-salinity environments of oil reservoirs， they are prone to instability and aggregation due to surface charge shielding and compression of the electrical double layer， which greatly limits their practical application effectiveness. To enhance the dispersion stability and resistance to harsh environments of NPs， surface modification of the NPs can be carried out. At present， there is limited understanding of the EOR properties of modified SiO2 NPs. To this end， this article reviewed the modification methods of SiO2 NPs and their advantages and disadvantages， as well as the EOR mechanisms and applications of modified SiO2 NPs. First， it elaborated on the physical and chemical modification methods： Physical modification involves using electrostatic forces to encapsulate the modifier around the NP surface or employing heating methods to dehydrate the hydroxyl groups on the NP surface. Chemical modification involves reacting the hydroxyl groups on the NP surface with the modifier to introduce new functional groups and alter the properties of the hydroxyl groups. Among these， chemical modification can form stable chemical bonds to achieve long-term modification and is more suitable for demanding EOR scenarios. Then， it summarized that modified SiO2 NPs could enhance oil recovery by altering rock wettability， reducing oil-water interfacial tension， generating structural disjoining pressure， and conducting profile modification for oil displacement. Compared with unmodified NPs， modified SiO2 NPs exhibited better EOR performance. Meanwhile， modified SiO2 NPs could also be combined with chemical flooding （polymer flooding and surfactant flooding） to improve the oil recovery efficiency of chemical flooding. In addition， modified SiO2 NPs could enhance the stability of foams and emulsions， showing significant effects in enhanced foam flooding and emulsion flooding. Finally， based on the current research status of modified SiO2 NPs for EOR， the existing shortcomings were pointed out， and the future development directions of modified SiO2 NPs were further envisioned. This provides new ideas for subsequent research， with the hope that the modification methods of SiO2 NPs will become more mature， and that modified SiO2 NPs can be more widely applied in the field of EOR.
Asphaltene deposition has become an urgent technical challenge in the petroleum industry. In the processes of oil production， transportation， and processing， the aggregation and deposition of asphaltene have a negative impact on fluidity and production equipment performance， posing a serious challenge to industrial operation and economic benefits. Therefore， understanding asphaltene deposition behavior and its control mechanisms， especially at the molecular level， is key to improving petroleum industry efficiency and reducing costs. In recent years， molecular dynamics （MD） simulation has become an important tool for studying asphaltene deposition. With its precise characterization of molecular behavior， it provides a new perspective for revealing the basic properties， molecular structure， deposition behavior， and influencing factors of asphaltene. This article reviewed the latest research progress of MD simulation in the field of asphaltene deposition and deeply analyzed the key processes of asphaltene molecular association， precipitation， aggregation， and adsorption. It explored the effects and control mechanisms of variables such as temperatures， pressures， main driving factors， and surface characteristics on deposition behavior. Research has shown that asphaltene deposition is a complex process coupled with multiple factors， and MD simulation can reveal the molecular level interactions and dynamic evolution of its interfaces， promoting breakthroughs and development in prevention and control technologies. New methods such as chemical additives， nanomaterials， and external electric fields provide practical and effective solutions for preventing and controlling asphaltene deposition. With the advancement of MD simulation technology， especially the combination of MD simulation and experimental data， future research is expected to achieve precise control of the entire process of asphaltene deposition at the molecular， mesoscopic， and macroscopic scales. However， current research still faces challenges such as molecular model construction， quantification of factor coupling effects， and experimental verification. The strengths and weaknesses of existing research have been evaluated， and future research directions have been discussed. We hope to continuously optimize MD simulation methods and prevention strategies to promote breakthroughs and innovations in asphaltene deposition in the petroleum industry， providing a solid theoretical foundation and technical support for efficient development and utilization of petroleum resources.
The gas reservoirs of the Changxing Formation in the L Block in the northeast of the Sichuan Basin are typical complex reef gas reservoirs. Their strong heterogeneity and complex gas-water relationships significantly constrain actual production and development， making efficient development and deployment challenging. Therefore， this paper proposed a dynamic-static integrated three-dimensional characterization technique for gas-water distribution in gas reservoirs with multi-gas-water systems. First， three-dimensional models of sedimentary facies， reservoirs， and water saturation were collected to analyze the distribution characteristics of the reef reservoirs. Then， based on gas- and water-layer interpretations from well logs， a logging facies-controlled model was built using sequential Gaussian simulation. A neural network-genetic algorithm was employed to establish a three-dimensional seismic inversion model for gas and water layers， and co-Kriging was used to integrate well and seismic data into a combined three-dimensional gas-water layer model. By analyzing the relationship between water saturation from well logs and elevation， a regression equation for water saturation was developed， providing data for analyzing the gas-water transition zone and establishing a mapping relationship for the gas-water contact. A deterministic modeling approach was then applied to construct a gas-water contact model for the multi-gas-water system. Finally， numerical simulation was used to optimize and adjust the model， resulting in a gas-water layer and water saturation distribution model consistent with both dynamic and static data. This technique effectively bridged geological modeling and numerical simulation， accurately reflecting the gas-water distribution characteristics of gas-water systems A， B， and C in the study area. The water saturation values of each gas-water system were assigned to the water saturation distribution model. The error between the calculated geological reserves of natural gas and the volumetric method-based geological reserves of natural gas was only 2.8%， resolving discrepancies between static and dynamic reserves and inconsistencies between actual water production and prior understanding.
In response to the significant plastic characteristics of deep shale rocks， a fluid-structure interaction model for deep shale gas wells was constructed based on the elastoplastic distribution of rocks formed around horizontal wells during the fracturing process. This model comprehensively incorporates the multiple gas transport mechanisms in shale （including Knudsen diffusion， surface diffusion， adsorption/desorption， and gas slippage） as well as the interaction between rock mechanics and fluid flow during depressurization exploitation. The model also characterized the complex reservoir structure and the main hydraulic fractures were explicitly represented using a discrete fracture model. The extensively developed natural fracture system was described using a dual media model （matrix-fracture system）. A refined simulation of the complete gas transport pathway from desorption and diffusion in the matrix into natural fractures and then into the main fractures was thus achieved. To solve this complex multi-physics problem involving the mechanical field， seepage field， and their dynamic coupling， the finite element method was employed for numerical solution. The accuracy of the fluid-structure interaction model was verified using the classical Mandel’s problem. An analysis of production variation trends and key influencing factors in both elastic and elastoplastic shale reservoirs was conducted. According to the results， cumulative gas production over 1 500 days in shale gas wells in elastic reservoirs rises monotonically with the production pressure differential， while that in elastoplastic reservoirs increases and then decreases， with an optimal and reasonable production pressure differential. Further analysis of cumulative production under various influencing factors reveals that the reasonable production pressure differential is approximately 0.4-0.5 times the original formation pressure. The primary influencing factors are original formation pressure， Poisson’s ratio， and natural fracture aperture in order.
The Chang 7 Member in the Ordos Basin is a typical heterogeneous shale reservoir， which is mainly composed of thick shale and multi-stage thin sandstone. It is a complex reservoir system with self-generation and self-storage. In the process of fracturing construction and shut-in development， compared with conventional reservoirs， heterogeneous reservoirs are more likely to cause reservoir damage， resulting in a decrease in permeability and a decrease in recovery. In order to study the microscopic pore damage characteristics of heterogeneous reservoir under hydration， the cores of the Chang 7 reservoir in the Ordos Basin were taken as the research object， and the hydration damage mechanisms were studied by means of high temperature expansion experiment， nuclear magnetic resonance experiment， and micron CT scanning. The experimental results show that the expansion heights of shale are higher than those of tight sandstone. After adding 0.7% clay stabilizer， the expansion rates of shale and tight sandstone are reduced by 1.33% and 0.53%， respectively. After hydration， the pore volume of tight sandstone decreases by 11.62%； the proportion of newly increased pore volume reaches 7.34%， and the permeability continues to decrease. The pore volume of the shale decreases by 54.8%， and the proportion of newly increased pore volume reaches 23.9%. The primary pores in the early stage of shale hydration are closed， but the micro-fractures expand to form a new fracture network. The new pores connect the isolated reservoir space， and the local permeability is improved， showing the characteristics of hydration damage and damage regulation. For tight sandstone reservoirs， the intrusion of fracturing fluid into micropores can be reduced by rapid flowback. For shale reservoirs， measures such as delayed gel breaker and imbibition agent can be added to the fracturing fluid to reduce hydration damage and increase reservoir productivity.
The application of CO2 pre-fracturing in shale oil development demonstrates promising prospects. However， current research predominantly focuses on single-phase CO2 injection optimization， neglecting the synergistic interactions between CO2 and water-based fluids during actual field production for the enhancement of energy and shale oil recovery. This study utilized shale core samples from Member 1 of the Qingshankou Formation in the Songliao Basin. A high-temperature and high-pressure oil recovery simulation system combined with two-dimensional nuclear magnetic resonance （2D NMR） technology was employed to conduct synergistic enhancement of energy and shale oil recovery experiments of CO2 and water-based fluids. The impacts of injection fluid type， injection sequence， injection ratio， injection volume， and shut-in time on shale oil recovery were systematically investigated. Furthermore， the contribution of multi-scale pores to the recovery process was quantitatively analyzed from a microscopic perspective. The results show that the mobilization efficiency of different media differs markedly across pore sizes. Water-based fluids exhibit superior mobilization of clay interlayer pore oil （pore size： 3-111 nm）， while CO2 dominates in medium-large pores （>201 nm）. The combination of CO2 and slickwater breaker fluid achieves optimal enhanced oil recovery performance， significantly improving clay interlayer pore oil mobilization by 8.2%. Compared with injecting water-based fluid first， pre-injecting CO2 yields an average 3.2% higher recovery. Increasing the CO2 injection proportion enhances recovery， with the optimized ratio at 1∶1. Recovery increases with energy-enhancing injection volume but exhibits diminishing returns. The optimal injection volume corresponds to elevating the formation pressure coefficient to approximately 1.7. Recovery rises with shut-in time， particularly within the first 20 days， suggesting an optimal shut-in duration of 10-20 days. Applying these optimized parameters to a shale oil test well resulted in a 18% increase in daily oil production compared to conventional fracturing wells in the same formation， demonstrating significant recovery enhancement.
It is difficult to establish an effective displacement system for the conventional water injection development of horizontal wells in tight oil reservoirs. The method of depletion development after refracturing faces the problems of insufficient energy in the later stage and excessive production decline. Multi-cycle water huff and puff technology is an effective means to supplement formation energy in the later stage of horizontal well development in tight oil reservoirs. After initial fracturing， the stress field， fracture morphology， and flow field need to be studied urgently in the whole process of water injection development， depletion development after refracturing， and multi-cycle water huff and puff. In this paper， an iterative coupling simulation method of stress field， fracture propagation， and flow field was established， which accurately captured the changes of the artificial fracture morphology during multi-cycle water huff and puff and reduced the complexity of data conversion between models. By taking the typical horizontal well group in Changqing Oilfield of Ordos Basin as an example， the variation law of stress field， fracture propagation law， and flow field characteristics at different stages were studied， and the improvement effect of multi-cycle water huff and puff on the flow field was clarified. The results show that the principal stress difference near the well increases in water injection development after the initial fracturing， and the horizontal principal stress is deflected by about 13° compared with the initial direction. The horizontal two-way stress difference of the formation decreases after water injection for replenishment of energy. The old fractures are more likely to expand， and new fractures are generated after refracturing. After one round of water huff and puff for replenishment of energy， the stress difference near the well decreases. The horizontal principal stress’s deflection angle reaches approximately 38°， which promotes the formation of branch fractures and makes the fracture morphology more complex. Subsequently， the near-well stress difference gradually increases. Among them， after the third round of water huff and puff， the performance significantly deteriorates， while the horizontal principal stress difference increases， and the fracture morphology remains basically unchanged. After five rounds of water huff and puff， the recovery can be increased by 1.9 percentage points compared to the depletion development method.
