管道输氢是实现氢气大规模、长距离运输的有效方式,然而受高投资和运行成本影响,实现管道输送氢气并非易事.现阶段,技术经济模型可对管道的各个阶段进行预可行性和可行性评估,并描述管道的技术内容和特点,而对于氢气管道,已有国内外氢气管道研究通常将氢气管道视为氢供应链流程中运输环节的一种运输方式进行宏观供应链系统优化,而无法反映管道的详细技术特征和市场变化,导致氢气管道成本的大幅度变化.为此,本文结合现有管道的技术特征与成本分析法,建立了氢气管道的预算型技术经济模型,分析了氢气管道的主要构成成本、氢气管道平准化成本与运输规模之间的关系,并采用氢气平准化成本为分析指标进行氢气管道运输与长管拖车、天然气掺氢管道和液氢槽车运输方式的对比,最终获取国内纯氢管道的投资建设成本范围和平准化成本范围.此外,本文提出降低氢气管道运输成本的主要方式为提高氢气输送规模、改造现有油气管道与优化包含氢气管道的运输方式布局.研究结果显示:①当设计输量为2040年的需求量时,氢气管道运行结果为选取管径为DN500的氢气管道进行运输,沿线站场压力满足要求且管线流速均在安全范围内.②对于给定的150～550 km管道,当设计输量为2040年的需求量时,总建设投资范围为9.66×108～35.43×108 CNY.③氢气管道运输平准化成本随运输距离增加而增加,当运输规模一定时,平准化成本最高不超过10.12 CNY/kg.④在给定运输规模和不同的运输距离下,氢气管道运输成本较长管拖车和液氢槽车具有价格优势,价格范围在2.76～10.12 CNY/kg.研究成果可为纯氢管道的成本估算提供依据,对合理选择氢气管道工程投资和经济效益评价对比分析具有重要意义,为管道建设提供参考.

China is rich in shale oil resources.By the end of 2022,the predicted reserves of continental shale oil in China have reached 3 billion tonnes,but only recoverable shale oil has economic value under such reserves.The shale oil reservoirs of the Lucaogou For-mation in the Jimusar Sag can be divided into three types:interlayer type,lamina type and block type according to mineral composition and source-reservoir ratio.However,due to the large difference in pore structure characteristics and fluid occurrence state of the three types of reservoirs,the productivity difference is high using the same fracturing method.In order to clarify the pore structure character-istics of the Lucaogou interlayer and laminated reservoirs in the Jimusar sag and the difference of fluid mobility under their constraints,this paper studies the pore structure characteristics by means of XRD,casting thin sections,scanning electron microscopy and nitrogen adsorption.Nuclear magnetic resonance centrifugation technology was used to quantitatively evaluate the mobility of shale oil in laminated and laminated reservoir samples.The T1-T2 spectrum method was used to clarify the occurrence state of shale oil in different reservoir types.Finally,the main controlling factors of fluid mobility in shale oil reservoirs were analyzed by combining characteristic pore structure parameters.The results show that the carbonate content of laminated reservoirs is high,and the reservoir space is domi-nated by carbonate intergranular pores,clay mineral interlayer fractures and organic matter pores.The fluid component is dominated by kerogen,and the free oil component content is extremely low.The average value of movable fluid saturation is only 7.97%.The felsic content of the interlayer type is higher,the reservoir space is mainly composed of intercrystalline pores and dissolved pores in feldspar grains,the fluid composition is mainly movable oil,followed by bound oil and kerogen,and there is no movable water.The average saturation of movable fluid is 29.3%.The pore throat radius in the characteristic pore structure parameters is the main factor controlling the movable fluid saturation of shale oil reservoirs.The two are exponentially correlated,and the correlation coefficient can reach 0.95.Through the study,the main reservoir space types of the intergranular pores and intra-granular pores in the Lucaogou Formation and the laminar shale oil reservoirs in the Jimsal Depression are determined.The mobile fluid saturation decreases gradually from unimodal interlayer reservoirs to bimodal laminated reservoirs,but increases exponentially with the increase of the maximum pore throat radius.The results show that the maximum pore throat radius has a great influence on the mobile fluid saturation of shale oil reservoir.

Multi-stage alternating injection acid fracturing is commonly employed in the stimulation of tight carbonate reservoirs to enhance differential etching along the fracture surfaces and improve the conductivity of acid-etched fractures. The numerical simulation technique serves as an effective tool for optimizing the operational parameters of such treatments, significantly contributing to the enhancement of post-fracturing productivity and long-term production stability. However, existing numerical simulation approaches for multi-stage alternating injection acid fracturing often neglect acid-rock reactions or adopt simplified equivalent viscosity methods, which result in considerable deviations between simulation results and actual field observations. To address this issue, this study developed a mathematical model for multi-stage alternating injection acid fracturing based on the Volume of Fluid (VOF) method. This model incorporated both the interface tracking between reactive and non-reactive fluids, and also the acid-rock reaction. The governing equations of the mathematical model were discretized using the finite difference method, and the resulting numerical model was solved through computer programming. The accuracy of the model in capturing viscous fingering behavior and acid-etching profiles was verified by comparing the simulation results with the experimental data and analytical solutions. Based on this validated model, simulations were conducted to investigate the flow and reaction behavior of acid under different numbers of alternating injection stages, as well as the evolution of viscous fingering patterns and changes in etched fracture width. To comprehensively evaluate the effectiveness of differential etching, a viscous fingering index was introduced, which was accounted for acid penetration distance, the number of fingering branches, and the area covered by the viscous fingering. Simulation results demonstrate that under typical fracture widths and alternating injection conditions, low-viscosity acid gradually forms preferential flow channels in the fracture due to the viscosity contrast, which is the manifestation of the fingering phenomenon. As the number of alternating stages increases, the competitive development and mergence between the adjacent fingers happens. The effective acid penetration distance continues to increase with the number of alternating injection stages. However, when it is beyond a certain critical stage number, the growth rate of acid penetration distance slows, and further increasing of the alternating injection stages primarily only enhances the acid-etched width within the existing viscous fingering regions. Therefore, for a given fracture geometry and acid system, there is an optimal range of alternating stages, which simultaneously maximizes differential etching and the acid penetration distance. This model provides an effective simulation tool for the optimization of multi-stage alternating injection acid fracturing and offers theoretical guidance for the design of field treatment.

The Jurassic Lianggaoshan Formation shale is a key exploration interval in the Sichuan Basin,but its pore structure and shale oil mobility are still unclear.In order to reveal the reservoir space characteristics and the mobility of shale oil in the Lianggaoshan Formation,this paper divided lithofacies types according to sedimentary structure and mineral composition.Basic geochemical characteristics were obtained by total organic carbon determination,rock pyrolysis and vitrinite reflectance experiments.The porosity and pore structure were characterized and evaluated by means of field emission scanning electron microscopy,nuclear magnetic resonance,low temperature nitrogen adsorption and high pressure mercury injection.The difference in reservoir space characteristics between different rock phases was also compared.With a centrifugation time of 3 h and centrifugation speed of 11 000 r/min,quantitative evaluation of the mobility of shale oil with different lithofacies was carried out by NMR centrifugation and the influential factors are clearly defined.The evaluation model of movable oil quantity logging was established and.the favorable rock facies was selected.The results show that:(1)The TOC of Lianggaoshan Formation shale is mainly between 0.15%～2.95%,the Ro is between 1.06%～1.68%,and the shale is in the mature-high mature stage.After the recovery of light hydrocarbons,the change range of S1 was 0.03 mg/g～3.32 mg/g.The mineral types are mainly clay minerals and quartz.The developed lithofacies are lamellar clay shale facies,lamellar felsic shale facies,lamellar mixed shale facies and massive silty mudstone facies.(2)Shale reservoir space types are mainly clay mineral intergranular pores,organic matter pores,in addition to quartz dissolution pores,interparticle pores,pyrite intergranular pores and microfractures.The porosity is between 1.15%and 4.71%.The shale has a wide pore size distribution.The pore volume is mainly contributed by mesopores and macrop-ores smaller than 200 nm.Laminated clay shale has the best physical properties(3)the movable oil content of the Lianggaoshan Formation shale ranges from 0.25 mg/g to 3.26 mg/g,and the movable oil rate ranges from 5.13%to 44.8%.Lamellar clay shale has the best mobility,and massive silty mudstone has the worst mobility.TOC,clay mineral content and porosity are the key factors controlling movable oil content in the Lianggaoshan Formation.Based on these three factors,a mobile oil quantity pre-diction model is established and verified.Laminated clayey shale is preferred as the key exploration object of the Lianggaoshan Formation,which is indicative of the exploration and development of shale oil in the Sichuan Basin.

The Lower Cambrian Qiongzhusi Formation in the Sichuan Basin exhibits significant shale gas resource potential, with major exploration breakthroughs achieved in the Deyang-Anyue rift sag. However, the complex hydrocarbon accumulation processes under multi-phase tectonic activities have constrained the optimization of shale gas enrichment zones and efficient exploration and development. This study focuses on typical Qiongzhusi Formation shale gas reservoirs in the Zizhong-Weiyuan area of the Deyang-Anyue Rift Sag. Through petrographic observations of fracture veins, fluid inclusion thermometry, laser Raman analysis, and basin modeling, the evolutionary processes and differences in shale gas accumulation in the Zizhong-Weiyuan area were elucidated. Results reveal three distinct stages of fracture vein development in the Cambrian Qiongzhusi shale: Stage I veins formed during the late Caledonian movement (ca.420~405 Ma), containing abundant primary bitumen inclusions indicative of peak oil generation; Stage II veins developed during the Indosinian movement (ca.235~215 Ma), characterized by both primary bitumen and methane inclusions reflecting high-to-over mature shale conditions; Stage III veins formed during the Yanshanian-Himalayan reservoir preservation and adjustment stage, predominantly hosting primary methane inclusions. The Weiyuan and Zizhong areas exhibit vein formation during the Late Cretaceous (ca.75~60 Ma) and Eocene (ca.45~35 Ma), respectively. This may due to that the Weiyuan area is situated in the aulacogen margin, whereas the Zizhong area is located in the inner zone of aulacogen. Therefore, the Weiyuan area began to uplift ~10 Ma before the Zizhong area during the Yanshannian orogeny. Additionally, the Zizhong area benefits from superior basal sealing by the Maidiping Formation, forming an effective gas containment system. Its location on the intra-sag slope belt features less developed faults and fractures compared to the Weiyuan anticlinal region. These combined factors contribute to the overall superior gas-bearing characteristics of the Qiongzhusi Formation in the intra-sag Zizhong area relative to the sag-margin Weiyuan area.

Unconventional oil and gas resources serve as vital replacement energy in China's hydrocarbon portfolio,and their efficient development is of great significance for safeguarding national energy security.The implementation of staged multi-clus-ter hydraulic fracturing in horizontal wells,along with the optimization of intra-stage cluster design parameters,is critical to maximizing the production potential of unconventional reservoirs.Clarifying fracture propagation mechanisms and quantifying the relationship between fracture geometry and well productivity is key to optimize intra-stage multi-cluster fracturing strategies.In this study,a phase-field method is employed to simulate the competitive propagation morphology of multiple fractures within a fracturing stage.A fracture morphology identification technique is integrated to construct a two-dimensional equivalent fracture model,which can characterize the stimulated flow pathways.Equivalent physical parameters after stimulation are extracted and transferred-together with geometric descriptors-as input for a discrete fracture flow model.This enables automatic coupling and data transfer between the geometric and flow models,thereby facilitating quantitative evaluation of production performance under different fracturing scenarios and ultimately achieving fully coupled fracture propagation-fluid flow simulation.The accuracy and feasibility of the dual-model coupling method are verified through comparison with laboratory-scale physical simulation experiments and field fracturing data.On this basis,the effects of intra-stage cluster number and cluster spacing on fracture morphology and production response are further investigated.The results show that,as the cluster spacing increases from 15 m to 25 m,the fracture deflection point shifts farther from the wellbore,and the tip deflection angle decreases from 30° to 24°.Meanwhile,the pressure gradient around the fracture tip is reduced,weakening the fluid driving force and significantly diminishing inter-fracture fluid interference.This change leads to a decline in peak daily oil production and stabilized production rate,with daily and cumulative oil output decreasing by 35.88%and 35.89%,respectively.In contrast,when the number of clusters per stage increases from 3 to 5,the deflection angle at the tip of the outer fractures increases from 30° to 34°,while the coverage of the induced stress field expands from 36.74%to 42.46%.This results in a higher pressure gradient surrounding the fractures,enhancing the fluid driving force and significantly improving oil mobilization.Consequently,peak daily and cumulative oil production increased by 40.49%and 45.467%,respectively.Therefore,optimizing the intra-stage cluster spacing and cluster number can effectively balance the degree of fracture interference and enhance single-well productivity,thereby improving the overall effectiveness of staged multi-cluster hydraulic fracturing in horizontal wells.

In the process of fracturing in tight reservoirs,the imbibition and displacement of crude oil in reservoir pores by fracturing fluids has gradually become a key research field of enhanced oil recovery technology.However,the production characteristics and mechanism of pore crude oil at different scales in the process of imbibition are still unclear,which seriously restricts the optimal design of fracturing fluid system and the reasonable selection of mining technology.Taking the Chang 7 member tight reservoir in the Ordos Basin as the research object,the amphoteric surfactant(EAB-40)was used as the main agent of the clean fracturing fluid system,combined with T1-T2 two-dimensional nuclear magnetic resonance and wettability test,the influence of surfactant concentration on reservoir interface properties and fracturing fluid imbibition and displacement efficiency was systematically studied,and its microscopic mechanism was revealed.The experimental results show that EAB-40 signifi-cantly enhances the capillary driving force and crude oil desorption efficiency by synergistically reducing the oil-water interfacial tension(up to the order of 10-2 mN/m)and inducing the wettability reversal(the contact angle is reduced from 147° to 57.34°).The comprehensive oil displacement effect of the fracturing fluid system is optimal when the concentration of surfactant is 0.1 wt%.During the imbibibibition process,the wettability inversion is caused by the concentration of water-wet minerals in the small pores,and the diffusion of surfactants causes the wetting inversion,which drives the crude oil to migrate efficiently from the small pores T2<1 ms to the middle(T2 is between 1 and 100 ms)and large pores T2>100 ms.Polymer molecules improve the rheological properties of the fracturing fluid system and promote the deep utilization of residual oil in bound oil and blind end pores.Realize the triple synergistic imbibibibibition mechanism of"IFT reduction-wetting inversion-viscoelastic flow control".

The shale revolution has weaned the US from its dependence on imported oil and gas to become a net exporter.This paper reviews the history of the shale revolution in the United States,summarizes the characteristics of shale oil and tight oil and gas,analyzes the development status of the shale oil and gas revolution in China,and puts forward the basic geological theory of shale oil and tight oil and gas.The research shows that:(A)The United States has advantages such as good resource endowment,strong scientific and technological innovation ability,huge investment capacity,and strong engineering construction capacity,and has already realized the shale revolution.China's shale revolution is now under way.(B)Compared with conventional oil and gas,shale oil and tight oil and gas have different accumulation modes and development methods.They have the characteristics of continuous large-area distribution,self-sealing oil and gas accumulations,huge development and production engineering,and the"distributed"characteristics of oil and gas field production can flexibly cope with the characteristics of production reduction and low recovery.(C)Seven conditions need to be met for the further production of shale oil and gas in China:These are(1)Clear resources;(2)Mature horizontal well and fracturing technology;(3)The cost is controllable;(4)The engineering space of enhanced oil recovery in the late stage is large;(5)Meet environmental requirements;(6)Adequate capital investment;(7)Strong engineering construction ability.(D)The whole oil and gas system has a sequence of conventional oil and gas,tight oil and gas and shale oil and gas.Shale oil and gas and tight oil and gas reservoirs have the basic characteristics of tight reservoirs,complex fluid composition and phase state,and diverse reservoir driving modes,and we are faced with the problem of unclear reservoir geological and flow models.It is necessary to carry out further theoretical research of the whole oil and gas system,and vigorously develop sweet spot evaluation technology and fracturing technology.

Low-frequency distributed acoustic sensing in adjacent wells, a recently emerged fracturing monitoring technology, enables detailed diagnosis of hydraulic fractures. To promote industry understanding of recent advances in low-frequency distributed acoustic sensing technology for hydraulic fracture monitoring and facilitate its large-scale field application, this paper begins with the principles of distributed acoustic sensing. It briefly explains the sensing mechanism and well deployment methods, systematically summarizes research progress in numerical simulation, physical modeling, and field applications during hydraulic fracturing, and concludes by outlining future development directions for low-frequency distributed acoustic sensing technology. Research findings indicate that: ①Low-frequency fiber-optic acoustic sensing technology for hydraulic fracturing delivers high precision and real-time monitoring capabilities. This technology is increasingly being deployed for field fracture monitoring and has garnered significant attention from researchers worldwide. Disposable fiber optic systems offer distinct advantages including simplified deployment, low cost, compact footprint, and excellent value proposition. They represent a promising primary solution for future offset-well fracturing monitoring. Mitigating fiber slippage artifacts’ impact on strain response is therefore paramount for enhancing strain data fidelity in fiber optic sensing applications. ②Forward modeling primarily involves comparative analysis of simulated fiber optic strain fields with actual monitoring data to qualitatively characterize strain patterns. This establishes correlations between distinct fracture propagation types and their corresponding strain signatures, enabling interpretation of hydraulic fracture geometry and growth modes in offset wells. Current strain interpretation models predominantly consider two monitoring configurations: horizontal and vertical offset wells. However, these models fail to characterize fracture deflection induced by stress shadowing, resulting in discrepancies with field monitoring observations. Future work urgently requires developing sophisticated multi-fracture forward models that incorporate stress interference effects and fluid partitioning mechanisms to provide reliable guidance for field data interpretation. ③Inversion modeling primarily utilizes the Displacement Discontinuity Method(DDM) to construct fracture propagation models and solve for fracture dimensions. Current solution approaches include Least Squares, Picard iteration, Levenberg-Marquardt (L-M) method, and the Delayed Rejection Adaptive Metropolis (DRAM) algorithm. However, none can simultaneously invert fracture geometric parameters in all three spatial dimensions. Future inversion research must focus on optimizing solution algorithms, where effectively mitigating the impact of solution non-uniqueness will be the primary research focus for subsequent algorithmic enhancements. ④Physical simulation experiments primarily integrate distributed optical fiber interrogators based on Optical Frequency Domain Reflectometry (OFDR) technology with True Triaxial fracturing apparatuses to monitor fracture propagation. However, current experimental parameter configurations still fall short of fully replicating field conditions. Optimizing fiber deployment methodologies across diverse rock specimens and advancing the interpretation of laboratory-derived fiber optic data represent critical research priorities for future physical simulation studies. The study concludes that offset-well fiber optic monitoring demonstrates significant potential for interpreting hydraulic fracture dimensions. This technology holds considerable promise as a key enabling technology for addressing critical bottlenecks in unconventional resource development.

Total organic carbon(TOC)content is a crucial geochemical parameter for assessing reservoir quality and hydro-carbon generation potential of source rocks.The accurate prediction of TOC content is important for optimizing the exploration and development processes of shale oil and gas.With the rapid development of artificial intelligence technologies,individual machine learning algorithms have been increasingly applied to evaluate TOC content in shale.Despite the promising results of the individual machine learning algorithms,they are often subject to several challenges including overfitting,underfitting,and getting trapped in local optima of objective function.To address these limitations,the ensemble learning models are developed.Ensemble learning models leverage the strengths of multiple individual intelligent algorithms to enhance prediction accuracy and stability.Among them,combination strategy is one of the key factors in optimizing the ensemble learning models.Arithmetic average method as the simplest combination strategy fails to fully use prediction performance of the best individual intelligent model,and it can be severely affected by the individual intelligent model with a large prediction error,which can interfere with prediction outcome of overall model.In comparison,weighted summation method as a common combination strategy assigns the weights to different individual intelligent models according to their performance on training data.This method will perform excellently on training set,but it tends to have a poor performance when applied to test set.This paper develops an ensemble model based on an intelligent matching technology(IMTEM).The proposed method utilizes a set of robust intelligent algorithms including extreme gradient boosting,random forest,support vector machine,and extreme learning machine as algorithm modules to initially process input data.Then,the processed feature information combined with original log responses is fed to feedforward neural network layer for nonlinear transformation and feature learning,thereby enabling accurate and continuous estimation of TOC content in shale.To validate effectiveness of the IMTEM,the proposed method is applied to the prediction of TOC content in the Longmaxi Formation shale in the Sichuan Basin.Test results indicate that,compared to two ensemble models,five baseline models,and the ΔlogR method,predictions of the IMTEM exhibit higher consistency with measured TOC content.This demonstrates that the IMTEM is more suitable for predicting TOC content in shale.

As a critical technical approach for shale reservoir development,dynamic imbibition displacement during the fractur-ing stage has emerged as a focal point in reservoir engineering research over recent years.In light of global energy demands and ongoing exploration of unconventional oil and gas resources,the significance of this technology in enhancing the exploitation of shale oil reservoirs cannot be overstated.However,the specific mechanisms of dynamic imbibition process in shale oil reservoirs influenced by various factors still aren't unclear,and it's difficult to accurately quantify their impact on imbibition oil production efficiency.These uncertainties significantly hinder further improvement in the development efficiency of shale oil reservoirs,lead to higher development costs and bring huge challenges to sustainable resource development. Aiming at the unclear dynamic imbibition mechanisms and action laws of shale oil reservoir,a core-scale numerical simulation model was established,and the control variable method was adopted to set up 15 simulation schemes.By these methods,the mechanisms of displacement pressure difference,capillary radius,wetting angle and oil-water viscosity of dynamic imbibition displacement effect,and the change laws of fluid seepage were revealed.The effects of displacement pressure difference,capillary radius,wetting angle,and oil-water viscosity on the effectiveness of dynamic imbibition oil recovery,and the laws of fluid seepage changes were clarified in this study.The results show that:During dynamic imbibition,as the capillary radius increase from 0.1 μm to 10 μm,capillary force decrease and fluid seepage rate accelerates,leading to 8.0%increase in imbibition recovery.Along with the displacing pressure difference increases from 0 MPa to 3 MPa,the imbibition upgrades from static to dynamic,and the imbibition recovery degree increases by 7.9%.It is considered that the displacing pressure difference and the recovery degree are in accordance with the power function relationship,and there is an optimal displacing pressure difference.With changes in rock wettability from hydrophilic to neutral or oleophilic,extraction degree decreases from 48.9%for water-wet conditions to 33.9%for oil-wet conditions.As crude oil viscosity decreases from 53.3 mPa·s to 13.99 mPa·s,imbibition recovery rate increases by 9.1%;the higher the viscosity of water phase,the smaller the initial imbibition velocity,but the better the imbibition displacement effect.In oil field operation,by optimizing injection pressure,selecting suitable fracturing fluid and surfactant,the hydrophilic degree and displacement phase viscosity can be improved,and the dynamic imbibition process can be improved to increase the oil displacement efficiency.In the future,the complexity of multiphase flows and the heterogeneity of reservoirs should be further considered to study the influence of various factors on the dynamic imbibition process of shale from different scales.

To address the challenges of conventional temporary plugging agents in oilfield development, such as inefficient gel breaking at later stages, prolonged degradation time, low gel strength, and significant permeability damage caused by residues, this study developed a self-degrading nano-composite gel temporary plugging agent (PAE) based on a physicochemical cross-linking strategy. The PAE was synthesized via free radical polymerization in aqueous solution using acrylamide (AM), acrylic acid (AA), polyethylene glycol diacrylate (AE), and hydrophobic monomer stearyl methacrylate (SMA), with nano-silica (SiO₂) incorporated to reinforce the cross-linked network. The effects of cross-linker (MBA) dosage, hydrophobic monomer content, initiator (APS) concentration, and temperature on gelation time and strength were systematically investigated. The degradation behavior of PAE under varying temperatures (70-120 ℃), pH (3-12), and salinity (20-50 g/L) was elucidated. Characterization techniques including Scanning Electron Microscopy (SEM), Fourier-Transform Infrared Spectroscopy (FTIR), and Thermogravimetric Analysis (TGA) were employed to analyze the microstructure, chemical composition, and thermal stability of PAE. Experimental results demonstrated that under the optimized conditions (monomer concentration 8%, APS 0.2%, SMA 0.4%, and temperature 70 ℃), PAE exhibited controllable gelation time (30-120 min) and formed a dense three-dimensional network with a gel strength of grade 9 (no deformation upon inversion). The degradation time of PAE ranged from 3 to 10 h at 70-120 ℃, with post-degradation viscosity below 10 mPa·s, significantly outperforming conventional agents (>96 h). Sand-packed tube tests revealed a breakthrough pressure gradient of 1.870 MPa/m and a plugging efficiency exceeding 90%. Core flooding experiments confirmed a permeability recovery rate above 90% after gel breaking, indicating minimal formation damage. Mechanistic studies revealed that the high plugging strength of PAE originated from the synergistic enhancement of physicochemical dual-crosslinking networks and nano-SiO₂, while self-degradation was achieved through ester bond saponification under alkaline conditions and dissociation of hydrophobic association networks. This research provides a theoretical foundation and technical solution for developing high-performance, environmentally friendly temporary plugging agents in oilfield applications.

Deep and ultra-deep oil and gas resources, characterized by vast potential but low proven rates, become a key target of exploration and development in China presently. However, evaluating their resource potential still faces a series of scientific and technological challenges, such as high thermal evolution degree of source rocks, strong diagenetic modification of reservoirs, multi-stage adjustment, transformation and effective preservation of oil and gas reservoirs. Recently, new breakthroughs have been made in ultra-deep exploration in the Yuanba Area, with the discovery of natural gas reservoirs in the fourth section of the Dengying Formation at a depth of nearly 9000 meters, revealing promising exploration prospects for ultra-deep layers in the northern Sichuan Basin. Based primarily on the latest drilling data of YS1 well, combined with peripheral drilling, outcrop and analysis testing data, this study systematically investigates the key control elements of source rocks, reservoirs and oil and gas accumulation processes in the Dengying gas reservoir in the study area, aiming to provide reference for the exploration and evaluation of ultra-deep oil and gas reservoirs. The results show that: (1) The YS1 gas reservoirs of the fourth member of the Dengying Formation were derived from the Cambrian Qiongzhusi Formation source rocks. These source rocks entered a low maturity stage during the Silurian, then reached a medium high maturity stage for the main oil generation and early cracking during the Late Permian-Triassic, and reached a high over maturity stage for main cracking gas generation during the Middle Jurassic-Early Cretaceous. (2) The YS1 gas reservoirs are consist of the microbial dolomites deposited on the platform margin, which have undergone long-term compaction, pressure solution, and deep burial cementation, resulting in currently low porosity and low permeability characteristics. (3) In northern Sichuan Basin, the platform marginal mound-shoal reservoirs are adjacent to the high-quality deep-water facies source rocks of the Qiongzhusi Formation, and has favorable source and reservoir configuration conditions of “source generation in slope facies with reservoir accumulation in margin facies” and “upper source feeding lower reservoir", which provides the material basis for paleo-oil reservoir formation. (4) The gas reservoir in Member 4 of the Dengying Formation underwent multistage modifications. During the paleo-oil stage, located on the central Sichuan paleo-uplift slope, it formed large-scale lithologic paleo-oil reservoirs sealed by tight inter-shoal layers. During oil-gas conversion and gas reservoir stages, influenced by the Micang Mountain uplift, subtle structural highs developed on the Micang uplift slope, forming structure-lithology composite paleo-gas reservoirs. In the late stage, the Himalayan compression caused basin-margin uplift, adjusting the paleo-gas reservoir to form current reservoirs, with YS1 well in the favorable overlap zone. Exploration should target large paleo-oil reservoirs, identify key-period paleo-structures, and focus on areas combining effective preservation with paleo-present structural overlap as preferential enrichment zones.

CO2泡沫驱可以有效地控制CO2相的流度从而提高波及效率,同时它还能够进行CO2地质封存,减少碳排放以应对全球气候变暖的挑战.表面活性剂能降低CO2泡和水相液膜之间的界面张力(IFT),从而增加因拉普拉斯毛细管自吸效应导致的泡沫液膜中液体析出的阻力.聚合物可以提高泡沫液膜黏度,也可以减缓液膜中的液体析出并缓解气泡聚并现象.二者同时被用作提高泡沫稳定性的化学试剂,然而表面活性剂分子根据亲水头基电荷正负属性不同会具有不同的界面行为,在微观尺度下不同类型表面活性剂和聚合物分子之间的协同作用还不明确.本研究采用分子动力学模拟的方法,研究了油藏条件下阴离子型(SDS)和阳离子型(CTAB)表面活性剂分别与水解聚丙烯酰胺(HPAM,水解度25％)在CO2与水相界面处的相互作用.研究结果表明,CTAB比SDS具有更强的降低CO2与水之间IFT的能力,IFT的大小与界面宽度和界面覆盖率呈正相关性.具有相同电性的HPAM与平衡离子Br–在CTAB界面膜上形成竞争吸附关系;而带有相反电性的HPAM与平衡离子Na+在SDS界面膜附近形成盐桥结构.前者更有利于降低气—液界面处IFT和增大液膜厚度,两种模式对泡沫液膜剪切黏度的提高程度差别不大.本研究揭示了阴/阳离子型表面活性剂分别与水解聚合物分子协同作用稳定CO2泡沫的微观机制.

Low salinity water flooding is a new technology for enhancing oil recovery by adjusting the ion composition or con-centration of injected water.However,the applicable reservoir conditions and enhanced oil recovery mechanism of low salinity water flooding have not yet reached a consensus.In this paper,a series of laboratory experiments of wettability control-based low salinity flooding are carried out with plunger rock samples from marine carbonate reservoirs in the Middle East as the research object.Based on the theory of Derjaguin-Landau-Verwey-Overbeek theory(DLVO),an interfacial reaction model of a typical crude oil/brine/rock system is established,and the contact angle and total separation pressure are calculated simultaneously with the augmented Young-Laplace formula.The reliability of the model is verified by the literature experimental data,and the effects of ion concentration and ion type on the separation pressure curve and contact angle are clarified.The results show that in low salinity environments,the pore surface of carbonate rock is more water-wet under the action of fluid flushing,the oil displacement efficiency is higher,and the low salinity water improves the crude oil recovery by 3.2%;under the assumption of constant charge,the mathematical model established based on the DLVO theory for the crude oil/brine/rock system can accurately predict the change of contact angle;compared with the ion concentration,ion type has a greater impact on separation pressure and contact angle.Among divalent ions,Mg2+ions exhibit a more pronounced influence on wettability control compared to Ca2+ions.When the water film thickness is minimal,van der Waals force is the main force affecting the separation pressure.As the thickness of water film increases,the electric double layer force gradually becomes the main force.This study contributes to a deeper understanding of the wettability control mechanism of low salinity water flooding for enhanced oil recovery.

Unconventional oil and gas,represented by shale oil and gas and low-permeability tight oil and gas,are important replace-ment resources in China.Due to their poor reservoir properties,effective exploitation is difficult.Currently,reservoir transformation is mainly carried out through horizontal well volume fracturing technology.However,there are still problems such as water resource waste,reservoir damage,and poor increasing production.Because of the the low viscosity,high density,and high diffusivity,super-critical/liquid CO2 can quickly enter reservoir micropores and microfracture.CO2 fracturing can effectively reduce fracture pressure,form complex fracture networks,increase formation energy,improve backflow rate,reduce reservoir damage,and achieve single well production increase.It is suitable for efficient and green exploitation of unconventional oil and gas resources.This paper introduces the basic research progress of CO2 fracturing from the aspects of the mechanism of rock breaking and fracture making by CO2 fracturing,the mechanism of influence of CO2 on rock properties,the flow characteristics of CO2 fracturing wellbore,CO2 fracturing stimulation and geological storage,and briefly describes the development and application of several main fracturing technologies,including CO2 foam fracturing,CO2 dry fracturing,CO2 acid fracturing,and CO2 mixed fracturing.Against the background of China's current"dual carbon"goals and increased exploration and development efforts for unconventional oil and gas resources such as shale oil and gas,CO2 fracturing technology is one of the key core technologies for building a clean,environmentally friendly,low-carbon,and efficient energy security and development technology system,with great potential for development and promotion.

With the exploration and development of oil and gas into the ultra-deep reservoir,hydraulic fracture propagation under the condition of high stress difference is prone to occur large curvature deflection,leading to wellhead overpressure,sand plugging and other problems occur frequently.It is of great significance to clarify the mechanism and main control factors of hydraulic fracture propagation and deflection near wellbore in ultra-deep and high stress difference reservoir for safe and efficient develop-ment.Under the constraint of the continuity framework of classical thermodynamics,the sharp fracture on the discrete interface is smoothly described as a continuous damage dispersion fracture,and the Lagrange Energy Functional is constructed based on Griffith energy balance relation and fracture variational principle,and then the phase field hydraulic fracturing model of perforated well in anisotropic reservoir is established based on the principle of energy minimization.The validity of the phase-field model presented in this paper is verified by comparing with the classical Griffith crack opening profile equation.It is found that the hydraulic fracture starts to crack along an approximate straight line between perforation and maximum horizontal principal stress,and then deflects to the maximum horizontal principal stress direction.The specific direction of crack initiation is affected by in-situ stress difference,displacement and perforation angle.The increase of the in-situ stress difference will promote the hydraulic fracture deflection propagation near the wellbore,make the deflection angle increase and the deflection radius decrease;increasing the displacement can weaken the hydraulic fracture deflection,and making the deflection angle decrease and the deflection radius increase;with the increase of perforation angle,the angle between perforation and the maximum horizontal principal stress increases,which will aggravate the deflection degree of crack propagation so that the flow friction of fracturing fluid increases and the risk of sand plugging increases;the anisotropy characteristics of the reservoir can also significantly affect the deflection and propagation process of hydraulic fractures.In the model,the critical energy release rate in different directions is taken as the anisotropic parameter of fracture resistance.The results show that fractures tend to propagate in the direction of low resistance.The stronger the anisotropy of fracture resistance,the greater the deflection degree of hydraulic fractures.The anisotropic characteristics of reservoir fractures significantly affect the turning behavior of fractures.The phase-field hydraulic fracturing model in this paper provides a convenient method to study the propagation and steering behavior of hydraulic fractures without any fracture criteria,which is helpful to improve the understanding of near-well fracture steering in ultra-deep and high stress difference reservoirs,help to understand the fracture mechanism and fracture deflection behavior under different geological environments and fracturing conditions,and provide reference and suggestions for fracturing technology design and perforation scheme optimization.

The submarine fan is an important reservoir for oil and gas in deep water areas. The differences in reservoir quality have a significant impact on the differential accumulation and exploitation of oil and gas. Previous studies have conducted extensive research on the differences in reservoir quality of submarine fans. However, the characteristics and distribution patterns of reservoir quality differences within submarine fans under a steep continental slope background are still unclear. This paper takes the Oligocene submarine fan reservoir in the X gas field of the Rovuma Basin in East Africa as the research object. By integrating core, well logging and seismic data, an in-depth study has been carried out on the control of reservoir quality differences and distribution patterns of submarine fan sedimentary microfacies and lithofacies under the steep continental slope background. The results show that the changes in reservoir quality within the submarine fan are mainly controlled by rock texture, lithofacies (association) and sedimentary microfacies under the circumstance of weak diagenesis. Grain sorting and clay content mainly control the porosity and permeability of the reservoir, respectively, but the relationship between grain size and reservoir properties is very complex. In sand-rich lithofacies, fine sandstones have the highest porosity due to their good sorting, and massive gravel-bearing coarse sandstones have the highest permeability due to their low clay content. Under the steep continental slope background, the submarine fan sedimentary microfacies are arranged in the order of muddy channel-sandy channel-lobe main body-lobe edge along the source direction, resulting in the source-directional differences in reservoir quality in the order of “poor, good, and poor”. The proximal muddy channel consists of fine-grained and clay-rich lithofacies, with overall poor physical properties. In the middle position, the sandy channel and lobe main body change to massive gravel-bearing coarse sandstone lithofacies and medium-coarse sandstone lithofacies, with low clay content and improved to good physical properties. Among them, the reservoir quality of the sandy channel is better than that of the lobe main body. The internal high porosity and high permeability zones of the sandy channel are in the form of elongated lenses, while the relatively high porosity and high permeability areas of the lobe main body are in the shape of lobes. The distal lobe edge changes to fine-grained lithofacies (fine-medium sandstone, fine sandstone) with increased clay content and gradually deteriorated physical properties.

The uncertainty of geological composition,the invisibility of the under-well real-time working conditions,and the complexity of the engineering simulation in the oil and gas field drilling and production process have hindered its scientific and efficient design and construction.The digital twin technology can bring up real-time,intelligent,and visualized project design and decision-making but has yet to lack a systematic method for modeling oil and gas field drilling and production.In this regard,the article first explored the current levels of investigation and implementation both domestically and abroad,based on that the level of development by applying the maturity index was quantified.It then proposed the digital twin modeling approach for drill-ing and production in the oil and gas field,which encompassed the modeling workflow,model division strategies,architecture for model assembly and integration,and modeling tools for constructing the digital twin.Also,two case were studied for drilling and production,using wellbore stability while drilling and offshore gas well production system as two examples,respectively.Finally,the difficulties and challenges related to the digital twin deployment in the field were analyzed,based on which the suggestions for its future development are proposed.It is found that the digital twin for drilling and production has stayed at the visualization level and at a relatively low degree of maturity compared to the manufacturing field on digital twin.The complex demand for oil and gas drilling and production systems can be divided into several clear and easy realized sub-demands.Based on requirement analysis,the modeled object can be separated to be various sub-models based on the granularity,dimension,and lifecycle.The sub-models are then assembled layer by layer across the model,function,and demand layers so that the multi-dimension and multi-field models can be integrated.Meanwhile,an improvement of their methods and an increase in efficiency for the model administration,data management,and engineering simulation ae desired.Moreover,the digital twin faces the problems such as difficulty in selection and fusion of multi-source heterogeneous data,vagueness in the sub-model definition,and ambiguity in the model validation,as well as the challenges such as the complicated kinetics processes,multi-division and multi-task collaboration,and development of domestic software tools.In summary,the digital twin modeling approach and the case studies in this article can provide a methodological guidance and practical reference for oil and gas drilling and production practices.

暂堵转向压裂是非常规油气资源开发过程中的重要增产改造手段之一.通过对国内外暂堵转向压裂技术文献的整理,从暂堵转向压裂机理、材料和工艺3个方面对暂堵转向压裂技术的发展进行了总结.首先,暂堵转向压裂过程包括3个关键步骤:暂堵剂运移、封堵、裂缝转向.不同暂堵剂颗粒的运移分异行为影响了其后续的封堵过程,进而影响新缝的开启,三者紧密相连.其次,在现场应用的暂堵剂种类繁多,包括固体颗粒、纤维、凝胶、泡沫等类型,需要根据储层特征优选适合的暂堵剂,特别是考虑其耐温性、降解性以及承压能力.目前,可降解颗粒和纤维暂堵剂是主流的发展趋势.最后,暂堵转向压裂技术具有广泛的应用场景,其效果得到多种监测手段的证实.在作业过程中需要根据暂堵剂类型的差异采用不同的加注方式,暂堵剂用量和加入时机可根据管外光纤、高频压力监测等多种先进技术手段进行优化设计.随着这些先进技术的应用与推广,暂堵转向压裂作业终将实现实时调控与优化.

The Tarim Basin, functioning as China's strategic hydrocarbon resource succession zone, encounters globally recognized technical bottlenecks in the exploitation of deep/ultra-deep reservoirs. A comprehensive chronological analysis is conducted on the development trajectory of stimulation technologies for ultra-deep hydrocarbon reservoirs in the Tarim Oilfield, particularly highlighting stimulation technology breakthroughs implemented in the field’s dual primary production zones: For complex carbonate reservoirs in ultra-deep intracratonic basins, an innovative integrated design approach for fracture-cavity-system identification and stimulation was proposed; for ultra-deep fractured classic reservoirs in the Kuqa piedmont zone, a series of high-efficiency stimulation technologies were developed. The research has achieved three major technological breakthroughs: First, the successful development of high-temperature resistant acid systems has significantly enhanced stimulation effectiveness in ultra-deep reservoirs; second, the breakthrough in high-density weighted-fracturing fluid technology provides critical support for ultra-deep well stimulation; third, continuous innovations in supporting process technologies have established a solid foundation for efficient development of ultra-deep oil and gas reservoirs. Integrating exploration trends with development challenges of ultra-deep oil and gas reservoir in the Tarim Basin, the paper addresses the production demands and existing technical deficiencies in reservoir stimulation, including: the fundamental laboratory research on deep/ultra-deep reservoir stimulation, artificial fracture propagation mechanisms, development gaps in novel stimulation fluids, zonal isolation tools, temporary plugging materials and supporting application techniques, limitations in real-time monitoring and interpretation technologies for stimulation operations. Six key technical recommendations are proposed: (1) Establishment of an ultra-high temperature/pressure experimental platform to conduct fundamental research on rock mechanics, fluid flow, and conductivity testing; (2) Investigation fracture propagation mechanisms in high-stress complex reservoirs and develop a multi-physics coupled fracture growth model; (3) Development of high-performance acid systems resistant to 200 °C, with breakthroughs in weighted, low-friction, thermal-stable, and controlled-acid-generation technologies; (4) Development of engineer stratified stimulation tools (including diverting agents and supporting techniques) to optimize treatment in interbedded formations; (5) Enhancement of “multi-cluster limited-entry” fracturing for ultra-deep horizontal wells to improve fracture-controlled reserves; (6) Implemention of real-time fracture diagnostics using fiber-optic monitoring and develop high-temperature downhole monitoring tools. This study not only systematically synthesizes the stimulation technology framework for “triple-ultra” (ultra-deep, ultra-high temperature, ultra-high pressure) reservoirs in the Tarim Oilfield, but also establishes critical technological foundations for China’s 10 000-meter-depth reservoir stimulation endeavors. The research outcomes provide significant theoretical value and engineering guidance for promoting efficient development of deep hydrocarbon resources in China, while the innovative technological approaches may also serve as valuable references for global oilfield development under analogous geological conditions.

Seismic petrophysical inversion is an effective method for reservoir physical property evaluation. Direct prediction of reservoir parameters from seismic data has lower uncertainty and higher accuracy than estimation of reservoir parameters from seismic elastic parameters. However, at present, there is little discussion on the establishment of initial model in direct reservoir parameter inversion. A reasonable initial model can not only improve the accuracy of inversion results but also reduce the calculation cost of inversion process. To solve this problem, this paper proposes a seismic reservoir characterization method based on pre-stack and post-stack joint inversion, which combines post-stack impedance inversion and statistical rock physical model to provide a reliable initial model for pre-stack seismic rock physical inversion, and makes full use of the high signal-to-noise ratio of post-stack seismic data and the high resolution of pre-stack seismic data to improve the stability and accuracy of reservoir parameter inversion. Firstly, the critical porosity model is calibrated based on the existing logging data, and the reservoir parametric reflection coefficient formula is constructed based on Zoeppritz reflection coefficient equation, which establishes the direct relationship between seismic data and reservoir physical properties. Then the P-wave impedance is obtained by post-stack inversion, and the initial model of reservoir physical parameter inversion is obtained by using the statistical petrophysical model obtained from logging data. Finally, based on Bayesian framework and Cauchy prior constraints, the inversion of physical property parameters such as porosity, shale content and water saturation from pre-stack seismic data is realized. The synthetic tests show that the superior anti-noise performance of post-stack impedance can provide a reliable initial model for reservoir parameter prediction, and can significantly improve the accuracy of physical property inversion. The field data test verifies the advantages of this method in improving inversion accuracy and enhancing lateral continuity in direct estimation of reservoir physical properties.

The Linxing gas field was selected as the research object, where weak bedding planes represent typical features and significantly influence hydraulic fracture propagation. This study provides valuable insights on hydraulic fracture propagation in bedded shale formations and offers guidance for optimizing fracturing techniques. The characteristics of shale featuring bedding planes were examined by utilizing rock mechanics experiments and direct shear tests. Considering the cementation strength and friction properties of bedding planes, a computational subroutine was developed to characterize the contact behavior for bedding planes. A 3D Finite Element Method-Cohesive Zone Model (FEM-CZM) has been established for multi-field coupling analysis of stress-damage-fluid flow, specifically incorporating bedding planes. This model incorporates a contact constitutive relationship that accounts for both friction and cementation strength of the bedding. A comprehensive and systematic quantitative analysis is conducted to investigate the influence of various factors on bedding shear slip and the propagation of hydraulic fractures. These factors include the initial opening of bedding fractures, friction coefficient, cementation strength, number of bedding planes surrounding the wellbore, and fracturing operation parameters. The results indicate that the presence of weakly bonded bedding planes leads to complex fracture propagation patterns involving both tensile and shear fractures. Bedding plane apertures serve as preferential flow pathways for fracturing fluid, significantly inhibiting fracture propagation. When the bedding aperture increases to 300 μm, the fractures are unable to cross bedding planes, which limits the fracture scale. Compared to the bonding strength, the bedding friction coefficient plays a more dominant role in determining whether fractures penetrate. Higher friction coefficients facilitate the penetration, regardless of whether the bedding planes are bonded or not. The penetration probability increases exponentially as the friction coefficient rises. In contrast, with lower friction coefficients and weakly bonded bedding planes, fractures are intercepted, while higher cementation strength allows for effective penetration. Furthermore, with a rise in the number of bedding planes, the shear fractures along these beddings expands considerably, which results in a more intricate fracture pattern. The shear failure of multiple bedding planes restricts the development of tensile-dominated fractures, which reduces the efficiency of reservoir stimulation. Optimizing fracturing fluid injection, increasing high-viscosity fracturing fluid volumes, and raising injection rates can enhance vertical fracture propagation and improve the stimulated reservoir area. Further validation of the influence of bedding planes on fracture propagation is provided by analyzing distributed temperature sensing (DTS) profiles, as well as the post-fracturing performance in Linxing.

Lost circulation is one of the most frequent and hazardous complications in drilling operations, and its accurate prediction plays a vital role in ensuring the safe and efficient exploration and development of hydrocarbon resources. However, conventional prediction methods largely rely on historical drilling and logging data combined with empirical analyses, while often neglecting critical geological risk elements such as structural features. These methods suffer from delayed predictions and limited spatial applicability, making them insufficient for pre-drilling risk assessment in complex geological environments. To address these challenges, this study proposes a seismic-guided prediction method for geological lost circulation risks based on a “four-element hazard” (FEH) model. Utilizing multi-scale data from representative offshore drilling blocks, the method integrates well-logging data, drilling parameters, and 3D seismic information. Through geological statistics and analysis of typical well sections, four major geological factors are identified as the primary triggers for lost circulation: fault zones, volcanic conduits, lithologic discontinuities, and abnormally overpressured formations. These factors form the foundation of the FEH model framework. Guided primarily by seismic data and constrained by well and drilling information, the method extracts multi-source sensitive seismic attributes to establish identification workflows for each of the four risk types. Specifically, a multi-attribute Bayesian fusion model is used to estimate fault-related risk probabilities; joint amplitude-variance analysis delineates the boundaries of volcanic conduits; lithologic interface indicators are optimized based on response features; and abnormal overpressure zones are predicted by integrating seismic velocity and pore pressure inversion. Field applications in the Bohai A Block and South China Sea B Block demonstrate strong consistency between predicted risk zones and actual lost circulation events. In particular, the model successfully forecasted 80% of the loss intervals in the Bohai H1 well, including several composite-origin zones, with a maximum instantaneous loss rate of 90 m³/h. These results validate the model’s capability for forward-looking and effective risk prediction in structurally complex formations. In summary, this research develops a three-dimensional, seismic-guided, pre-drilling risk identification workflow targeting structurally complex zones. The method provides essential technical support for well placement optimization, trajectory design, and proactive drilling risk management.

Rock spontaneous imbibiton is the process of wetting phase fluid within the pore space spontaneously exhausting and driving the non-wetting phase,which is one of the important mechanisms for tight reservoirs to improve recovery.Due to the complexity of porous media characteristics and fracture morphology and other factors,the researches on imbibiton and mass transfer laws between fractures and pores have not yet been fully elucidated.In this paper,based on the phase field method and fluid motion equations,a pore-scale dynamic imbibiton and suction numerical model was established to analyze the mass transfer mechanism between fractures and pores within complex pore structures and the relationship with the recovery rate.The results show that:(1)the imbibiton process mainly covers three key stages inside the pore space:rapid penetration of the fracture,interaction between the fracture and the pore space,and gradual advancement in the pore space(i.e.,repulsion process).A faster injection rate will hinder the imbibiton process,and result in more residual oil retention.(2)There is a specific critical fracture width,and when the fracture width is about 40 times the average pore size,the recovery rate will fluctuate up and down in a certain range.As the critical fracture width decreases,the positive correlation between the fracture dimensionless number and the recovery rate is shown.(3)Fracture systems of different complexity have different effects on fluid transport.As the critical fracture width decreases,the impact of different fracture complexity on fluid mobilization is different.Specifically,with the increase of fracture complexity,the wave range of imbibiton effect become larger.The decrease of crack width will exacerbate the phenomenon of oil droplet aggregation,which will significantly slow down the recovery rate and cause clogging problems in the small pore area.(4)The number increase of the system open boundaries can effectively enhance the contact area of the wetting phase,which can maximize the dynamic utilization of the pore space,and form a synergistic seepage drive mechanism.The optimal imbibiton recovery was achieved under the four-sided open(AFO)condition,while the worst recovery was achieved under the one-sided open(OEO)condition.At the same dimensionless time,TEO and OEO show higher normalized recovery rates due to the strong non-homogeneous effect of the open number of end faces and spatial distribution model,while the recovery change curves of the remaining three boundary conditions show relatively concentrated trends.

Distributed fiber optic monitoring in adjacent wells has increasingly become an essential technique for fracture surveillance during hydraulic fracturing of unconventional oil and gas reservoirs. Developing forward models for distributed fiber optic strain response in adjacent wells is of significant importance for understanding the mechanism of fiber response and for the inversion of fracture geometries. However, existing forward interpretation models face limitations from insufficient flexibility in the selection of fracture propagation models, and by computational inefficiency caused by grid-based discretization, especially when high precision is required. To address these limitations, this study presents a semi-analytical stress-displacement field model for simulating fracture propagation with arbitrary aperture and geometric shape. Based on this, a forward modeling framework for adjacent well distributed fiber optic strain response is established. Using a penny-shaped fracture as a representative example, the stress field around the fracture is calculated and benchmarked against the classical Sneddon analytical solution. A forward simulation of fiber optic strain response for a scenario where a horizontal adjacent well monitors a vertically oriented elliptical fracture is conducted. The results are compared with the forward-modeled strain response from the Displacement Discontinuity Method(DDM). The results reveal strong consistency between the semi-analytical model and both the analytical and DDM solutions in classical benchmark cases, confirming the model’s validity and applicability. The model is further coupled with various fracture propagation models and applied to the interpretation of real field data. In particular, distributed fiber optic monitoring results from Stage 19 of Well B1H and Stage 20 of Well B2H in the Hydraulic Fracturing Test Site 2 (HFTS-2) project in the United States are analyzed. The modeling results show that the proposed approach accurately reproduces the characteristic patterns observed in field fiber data. For Stage 20 of Well B2H, which exhibits higher-complexity response characteristics, the model provides a closer match to observed details and temporal evolution compared with the DDM-based approach. In conclusion, this study establishes a semi-analytical forward modeling approach for fiber optic strain in adjacent wells under arbitrary fracture aperture and geometry, significantly reducing computational cost and improving efficiency. The model’s flexibility enables seamless integration with a variety of fracture propagation models, enhancing its capacity to accurately capture complex fracture behaviors observed in field monitoring. This provides a powerful tool for detailed interpretation and analysis of distributed fiber optic data in adjacent well applications.

Fractured-vuggy carbonate reservoirs differ from conventional reservoirs by exhibiting characteristics such as discontinuous spatial distribution of reservoir bodies, significant variations in effective storage space scale, complex internal structures and fracture-cavity connectivity, heterogeneous oil-water distribution relationships among different reservoir units, and complicated hydrocarbon flow mechanisms. Water flooding and gas injection serve as important methods for efficient development of fractured-vuggy carbonate reservoirs. However, the unclear timing for switching between water flooding and gas injection in fractured-vuggy carbonate reservoirs leads to difficulties in determining the optimal gas injection timing during field gas injection operations. Meanwhile, existing physical simulation models for fractured-vuggy carbonate reservoirs worldwide can only achieve either visualization or high-temperature-high-pressure conditions, resulting in insufficiently comprehensive research perspectives. To address these issues, this study independently developed a high-temperature-high-pressure two-dimensional visual physical model of fractured-vuggy reservoirs based on similarity principles. Using this model, we conducted water flooding and gas displacement experiments to investigate oil-gas-water flow mechanisms during the displacement process in fracture-cavity systems, evaluate the effects of different water-gas switching timings and various water injection positions on displacement efficiency, clarify the relationship between water and gas injection, and determine the optimal gas injection timing and spatial distribution characteristics of remaining oil. The experimental results show that: 1) Through water flooding followed by nitrogen injection experiments in the visual fractured-vuggy model, we confirmed that this method represents an effective development approach for fractured-vuggy reservoirs. Under the synergistic effects of water flooding characteristics and nitrogen gas-cap drive mechanisms, a high displacement efficiency of 67.67% was achieved. 2) Comparative experiments on different injection-production methods demonstrated that during water flooding development of fractured-vuggy reservoirs, the low-injection-high-production method provided larger water flooding sweep area and more effective water flooding performance compared with the high-injection-low-production method, resulting in 2%~4% higher overall displacement efficiency. 3) By comparing oil displacement effects under different nitrogen injection timings, the optimal development method was determined to be low-injection-high-production with nitrogen injection initiated after 1 PV of water flooding, which yielded the highest displacement efficiency. 4) After water flooding development in fractured-vuggy reservoirs, remaining oil primarily distributed as “oil films,” “attic oil,” and “bypassed oil.” Following gas flooding, the main remaining oil distribution patterns were “interfacial oil,” “bypassed oil,” and “oil films.” These research findings contribute to understanding the enhanced oil recovery mechanisms of water and gas injection in fractured-vuggy carbonate reservoirs, clarifying the optimal switching timing and remaining oil distribution patterns, and providing theoretical guidance for optimizing gas flooding development plans and remaining oil potential exploitation in fractured-vuggy reservoirs.

In order to investigate the deformation characteristic and transport behavior of oil-water micro-interface and its evolution law under different wettability conditions in water flooding,a Hele-Shaw cylindrical model has been constructed based on the N-S equation.Phase field method has been employed to track the topological deformation characteristics of oil-water micro-interface in water flooding.The effect of wettability,oil-water viscosity ratio,and capillary number on the deformation characteristic and evolution process of oil-water micro-interfaces has been studied.The simulation results show that the dynamic evolution process of oil-water micro-interfaces observed from the model surface in water flooding can be divided into four stag-es,including breakthrough,fracture,three-phase contact line intersection,and micro-interface merging.The breakthrough and fracture phenomenon of oil-water micro-interfaces can be observed repeatedly in the displacement process,and is not affected by wettability and rock particle distribution.Three-phase contact line intersection and micro-interface merging phenomenon have the similar deformation characteristics and evolution law in the vertical profile of the model,which are mainly influenced by wet-tability and rock particle distribution.Three-phase contact line intersection phenomenon occurs more frequently under water-wet condition,while the micro-interface merging phenomenon occurs more frequently under oil-wet condition.The change amplitude of displacement front decreases and then increases in water flooding as wettability changes from strong water-wet to strong oil-wet,which exhibits the piston-like displacement under weak water-wet condition.The simulation results show that the highest oil displacement efficiency is observed under weak water-wet condition,while the lowest oil displacement efficiency(61.06%)is observed under strong oil-wet condition.Moreover,as the oil-water viscosity ratio increases from 20 to 100,the occurrence rate of three-phase contact line intersection phenomenon decreases,the micro oil displacement efficiency decreases by 8.56%,and the initial displacement pressure also increases under weak water-wet and the same injected pore volume multiple condition.As the capillary number increases from 0.66×10-3 to 2.0×10-3,the occurrence rate of three-phase contact line intersection phenomenon increases,the volumes of residual oil decreases,the micro oil displacement efficiency increases by 9.36%,and the displacement pressure also decreases under weak water-wet and the same injected pore volume multiple condition.This reveals that the micro oil displacement efficiency can be significantly improved by increasing the occurrence rate of three-phase contact line intersection phenomenon under water-wet condition.The research results can enrich the micro flow mechanism in water flooding,and provide a theoretical basis for further explore and utilize the residual oil.

The practice of oil and gas exploration and development shows that the transformation from “outside source” to “inside source” is an inevitable choice for the sustainable development of petroleum industry. Recently, the breakthrough of unconventional oil and gas in semi-deep lacustrine facies shale in the Qingshankou Formation (K₂qn) in the northern Songliao Basin has proved that it has broad resource prospects. The sedimentary paleoenvironment controls the accumulation of organic matter and the distribution of lithofacies, which is the basis for the prediction of shale oil desserts. In this paper, by means of experimental methods of biomarkers and element geochemistry, parameters such as paleoproductivity, paleoreoxidation, and paleosalinity of the lake basin in the northern Songliao Basin were recovered to clarify the paleoclimate evolution characteristics during the formation of Qingshankou Formation, and to compare the paleoenvironment with that of other major shale oil and gas resource enrichment basins in China. The biomarker compounds in the Qingshankou Formation samples predominantly exhibit a unimodal distribution of n-alkanes, with major peaks at nC₁₈, nC₁₉, nC₂₀, and nC₂₁. The Pr/Ph ratio ranges from 0.44 to 1.31, with an average value of 0.87, indicating a general dominance of phytane. Among the major elements, CaO, Na₂O, and P₂O₅ are relatively enriched, while among trace elements, Sr shows the highest enrichment, with Ba, V, Cr, Ni, Cu, Rb, and Y being relatively depleted. The research results indicate that the Songliao Basin developed under warm and humid paleoclimate conditions. Among the sub-basins, the Gulong Sag was relatively more humid compared to the Sanzhao Sag. The lower section of the Qingshankou Formation exhibited warmer and more humid characteristics compared to the middle and upper sections. Influenced by the transgression of the Paleo-Pacific Ocean from the east, the salinity of the lake basin water was relatively high, with a higher degree of salinization observed in the eastern Sanzhao Sag. During the depositional period of the Qingshankou Formation in the northern Songliao Basin, overall paleoproductivity levels were high. The basin predominantly exhibited a dysoxic to anoxic reducing environment, which provided favorable conditions for the accumulation and preservation of organic matter.

Volcanic reservoirs are important fields for oil and gas exploration in China. Affected by multiple volcanic activities and complex diagenesis and tectonic processes, these reservoirs exhibit diverse lithology, well-developed fractures, and strong micro-heterogeneity, which restrict the understanding of such reservoirs. Clearly defining the reservoir characteristics under dual-media conditions is of great guiding significance for the evaluation of storage capacity, optimization of development strategies, and identification of sweet spots in volcanic rock oil reservoirs. To address these challenges, this paper proposes a quantitative classification and evaluation approach for dual-media reservoirs constrained by productivity. Firstly, based on the pore structure characteristic parameters obtained from mercury injection tests (mean pore radius, sorting coefficient, skewness, kurtosis, and coefficient of variation), the K-means clustering method is employed to establish the classification criteria for the matrix, then the Shapley value is incorporated to improve the interpretability of the classification results. Secondly, fracture classification criteria are established using the K-means clustering method based on fracture density derived from electrical micro-imaging (EMI) logs. Finally, by integrating the fracture and matrix classification results, we employ the particle swarm optimization algorithm to optimize the dual-media reservoir classification criteria. The optimization objective is to minimize the total sum of squared deviations of maximum monthly production among different reservoir types within the study area. The classification results are further validated through production characteristic analysis of different reservoir types based on Arps production decline model. The results show that four types of reservoirs with gradually deteriorating physical properties, namely, micro-fracture type, condensed tuff type/tuffaceous sandstone type, tuff type, and tight matrix type, are mainly developed in the study area. The factors influencing the matrix reservoir classification results are, in descending order of significance: permeability, mean pore radius, skewness, and porosity. The fractured reservoirs are classified into four categories based on fracture density thresholds of 11.35, 6.14, and 3.03 fractures/m. Comprehensive classification results reveal that both seepage capacity and storage capacity significantly impact reservoir performance. The Pearson correlation coefficient between the fracture category and comprehensive category is 0.63, while that between the matrix category and comprehensive category is 0.69. Production analysis demonstrates that all wells follow Arps’ exponential decline model, showing a positive correlation between initial production and decline rates. As reservoir quality declines, oil wells exhibit both lower initial production and slower decline rates. This paper not only provides a quantitative understanding of the classification of volcanic rock reservoirs but also offers a methodological reference for characterizing other dual- and triple-media reservoirs requiring multi-dimensional evaluation approaches.

The real-time and accurate monitoring of the production well fluid profile is crucial for guiding dynamic adjustments in oilfield development. It plays a critical role in evaluating the proportion of fluid produced from different production layers, optimizing parameters for horizontal well fracturing, and adjusting production dynamics. In recent years, fluid profile testing based on distributed acoustic sensing (DAS) technology has emerged as a new method with high accuracy and strong real-time capabilities. This technique is particularly suitable for the high-temperature, high-pressure, and narrow-complex downhole environments commonly found in oil and gas fields. However, most current research on distributed fiber-optic profile monitoring is focused on theoretical studies and laboratory experiments, with limited application to actual production conditions of the mining field operations. In actual production, downhole fiber-optic signals are often subject to interference from complex noise, and their response characteristics can be highly variable. Furthermore, there is a lack of mature analysis processes and models for using DAS technology to analyze downhole fluid events and calculate production profiles. This paper proposes a model and calculation process for fluid profile analysis that can be applied to mining field production scenarios. The method involves deploying distributed fiber-optic acoustic sensing to collect fiber-optic data under various operational conditions. Frequency analysis is then performed to identify effective frequency bands, and the fluid profile is calculated from the perspective of acoustic energy. This approach addresses the challenge of limited analysis methods for calculating production profiles from distributed acoustic fiber-optic data. To validate the proposed model and process, the paper analyzes data from three wells in a mining field. The results indicate that in the 400-800 Hz frequency range, the maximum difference in Fiber-Based Energy (FBE) energy occurs during well switching. This allows the system to filter out most background and environmental noise while retaining important flow-related information. After opening the wells, all three wells showed a delay in energy response. During the production phase, the production layers did not extend to all depths, and a dominant influx region was observed. However, after the second well opening, the overall fluid profile distribution became more uniform. Additionally, the intensity of the FBE energy varied between the first and second well openings, with stronger absolute FBE energy observed during the first production phase. These findings provide valuable insights into optimizing oilfield operations and improving the accuracy of fluid profile monitoring through distributed acoustic sensing technology.

Shale pores serve as the primary reservoir space for shale gas,whose structural characteristics directly determine the gas occurrence state,enrichment degree,and flow mechanisms.However,the complex structure and strong heterogeneity of organic pores in shale gas reservoirs significantly constrain precise reservoir evaluation and dynamic development.To clarify the three-dimensional structural characteristics of organic pores in the Lower Paleozoic shale reservoirs in South China,this study focuses on two organic-rich shale successions in the northern Guizhou:The Lower Cambrian Niutitang Formation and the Lower Silurian Longmaxi Formation shales,which exhibit significantly different thermal maturities.An integrated approach was employed,combining organic matter extraction,low-temperature nitrogen adsorption,and focused ion beam-scanning electron microscopy(FIB-SEM)three-dimensional reconstruction techniques to systematically characterize the microstructure of organic pores in these two shale successions.Based on nitrogen adsorption and FIB data,the Frenkel-Halsey-Hill(FHH)and box-counting models were respectively applied to evaluate the complexity of organic matter pore structures across different scales.The results show that the moderately mature Longmaxi Formation shale(equivalent vitrinite reflectance Ro=2.1%～2.8%)contains well-developed organic pores,predominantly exhibiting bubble-like and sponge-like cluster morphologies with pore sizes(r)mainly ranging from 200 nm to 450 nm,along with high specific surface area(133.9～159.5 m2/g)and substantial pore volume.In contrast,the overmature Niutitang Formation shale(Ro=3.0%～3.8%)contains smaller organic pores(r=10～140?nm)with irregular or slit-shaped geometries,showing lower specific surface area(30.9～31.4 m2/g)and reduced pore volume.Three-dimensional pore network modeling further reveals distinct connectivity patterns between these two shale successions.In the Longmaxi Formation shale,organic pores are primarily isolated with poor connectivity,and large pores(r>140 nm)contribute approximately 70%of the total pore volume.The Niutitang Formation shale,however,shows enhanced connectivity among large pores(r>150 nm)through thermal-induced microfractures formed during organic matter condensation,while small pores(r<150 nm)remain largely isolated yet account for 64%of the total pore volume.Fractal dimension analysis highlights additional structural differences.The Niutitang Formation shale exhibits higher fractal dimensions for large organic matter pores(D2=2.37～2.78),indicating greater structural complexity,whereas the organic pores of the Longmaxi Formation shale display relatively regular geometries with lower fractal dimensions.These variations are mainly controlled by differences in thermal maturity.Our study provides systematic understanding of three-dimensional pore structure evolution in shales with different thermal maturities,and offers theoretical foundations for shale gas reservoir evaluation and development strategies in northern Guizhou.

针对碳酸盐岩缝洞型含油储层,电成像测井方法可以探测得到高分辨率井壁缝洞分布图像,但由于岩性变化、井孔介质非均质性等的干扰以及裂缝间的互相缠绕、黏连使得对裂缝和溶蚀孔洞信息的有效提取仍存在较大阻碍.不完备路径开算法和容忍路径算子对直线或者轻微弯曲结构有良好的适应性,该适应性与结构元素形状的选取无关,而正弦函数族对弯曲结构的匹配度较好.文中将多尺度不完备路径形态学方法和正弦函数族、二阶矩椭圆拟合算法应用于电成像测井电导率图像的处理,提出采用不完备路径形态学算法和正弦函数族智能匹配的裂缝和溶蚀孔洞自动识别和分离方法.首先采用数学形态学中的开闭变换,消除电成像测井图像的干扰;其次,进行不完备路径形态学、密度聚类算法的公式推导和分析,并融合多方向的形态学路径算子、容忍路径算子、含噪的基于密度聚类方法追踪并提取连续或间断的弯曲线状结构;再次,对提取的弯曲线状结构进行改进的Hough变换和正弦函数族匹配,发现Hough变换仅对低角度裂缝的匹配效果较好,而正弦函数族对高角度裂缝及完整度较低的残缝有更高的精确度;还有,使用正弦函数族计算裂缝的相位、振幅和井壁的深度位置信息;最后,对于剩下的溶蚀孔洞,采用二阶矩等效椭圆函数方法进行拟合,获得了孔洞的纵横比.为验证文中提出的算法,对几个数值模型和某油田的碳酸盐岩井的电成像资料进行了处理,成功完成对缠绕的裂缝和孔洞的分离过程,验证了所提出算法的有效性和适应性,为碳酸盐岩缝洞型含油储层的精细评价提供了实用方法,有助于提高对储层缝洞分布特点的认识水平.

The successful development of shale oil and gas formations mainly depends on engineering measures such as extended-reach horizontal drilling and high-volume fracturing, which enable high-quality geological sweet spots in long horizontal shale oil and gas formations to extract more industrial production capacity. Among them, drilling is the most effective and direct technical means to communicate engineering and geology. The drilling geological environment is a significant factor influencing the drilling engineering process, including both geological factors of the formation and the mutual influence factors between drilling environment and geological environment. In order to improve the high-quality sweet spot sweet-spot encounter rate, facilitate fracturing, and reduce engineering risks, this paper proposes wellbore trajectory optimization control technology for shale oil and gas formation production increase, safety, and efficiency. By analyzing the geological environmental factors of shale oil and gas formations, the models of geological sweet spot evaluation, geological risk identification, and geological engineering integration application have been formed. Based on these models, three drilling wellbore trajectory optimization control technologies have been proposed: ① Control the horizontal drilling position according to the changes of geological sweet spots in the formation space, and form trajectory control technologies that optimize drilling encountering sweet spot layers and enhance initial production (IP) rates; ② optimize the drilling direction based on the fracturing properties of engineering sweet spots, and trajectory direction optimization technology to improve the fracturing response characteristics of shale oil and gas formations; ③ To mitigate drilling risks, trajectory control techniques are developed to ensure the safety of drilling in shale oil and gas formations and reduce drilling engineering risks. Wellbore trajectory optimization control technology is one of the key technologies for achieving geo-engineering integration, which improves the efficiency of fast drilling and completion of long horizontal wells and high-volume fracturing, as well as increase the sweet-spot encounter rate rate and development efficiency of geological sweet spots.

Under high operational costs and selective applicability constraints, time-lapse (4D) seismic monitoring requires a rigorous feasibility assessment before implementation. The critical aspect of this analysis involves predicting post-production changes in formation elastic parameters, which are influenced by complex factors including reservoir temperature variations, pore pressure changes, and alterations in rock frame properties during hydrocarbon production. To achieve a quantitative evaluation of time-lapse seismic feasibility, a methodological framework based on rock physics modeling has been established, using several shallow, unconsolidated sandstone reservoirs in the Bohai Bay Basin as representative examples. The targeted sandstones exhibit high porosity and weak cementation, requiring specialized modeling approaches. Based on the geological background of the target areas, sedimentary environment analysis and burial history reconstruction are integrated with rock physics techniques to build geologically constrained models. These models facilitate the quantitative description of petrophysical characteristics under varying burial and diagenetic conditions. Based on the constructed rock physics models, evaluations of rock frame stiffness and pore fluid properties are conducted, and elastic parameter variations caused by reservoir production are predicted. Forward seismic modeling is then applied to assess the detectability of time-lapse seismic signals under different acquisition scenarios. Given the limited thickness of the target reservoirs, wedge-shaped model simulations are employed to analyze the sensitivity of time-lapse seismic responses to changes in formation thickness. The overall feasibility of time-lapse seismic application is assessed from three dimensions: geological conditions, rock physical properties, and seismic detectability. Results indicate that most studied reservoirs exhibit favorable geological frameworks and competent rock skeletons. However, the nature of the pore fluids, especially hydrocarbon composition and phase behavior, emerges as the critical factor influencing the effectiveness of time-lapse seismic monitoring. Light oil reservoirs show greater potential for successful monitoring due to more significant impedance contrasts. Among the studied cases, the reservoir exhibiting the highest suitability for time-lapse seismic monitoring is selected for further analysis using existing seismic datasets. Time-lapse seismic data matching processing and 4D response evaluation are performed to validate the reliability of the feasibility assessment framework. The findings demonstrate that the proposed approach can provide robust support for evaluating the feasibility of time-lapse seismic monitoring in shallow, unconsolidated sandstone reservoirs in the Bohai Bay Basin. These insights contribute valuable guidance for future applications of 4D seismic in similar geological settings, offering meaningful implications for both petroleum geology and reservoir engineering disciplines.

Shale oil is one of the most potential and strategic alternative oil resource in China.It's of great significance to clarify the fluid distribution and evolution laws in porous media for enhancing the recovery of shale oil during the fracturing-soak-ing-producing process.In this work,a multi-component multiphase lattice Boltzmann model was adopted to study the shale oil flow mechanism during fracturing-soaking-producing process.Firstly,the accuracy of the model was verified using Laplace's law,contact angle,and stratified flow.Then,based on the scanning electron microscope(SEM)image of Jiyang shale,the struc-ture of the shale porous medium was constructed including the distribution of fracture and matrix pores.Subsequently,the lattice Boltzmann model was used to simulate the fracturing-soaking-producing process of shale porous media,and the fluid distribution characteristics at different stages were analyzed.Then the effects of different soaking time,reservoir wettability and drainage rate were explored further.The results show that the fracturing fluid will seep into the matrix pore and replace the oil phase under the action of capillary force during the soaking stage,and with the increase of soaking time,the backflow rate of fracturing fluid return tends to decrease;the water-wet core has a better development effect than the neutral and oil-wet cores,and the utilization rate of fracturing fluid and the degree of crude oil utilization in the matrix are higher;the higher drainage rate will make the pore pressure drop rapidly,which is not conducive to the development and production of the shale oil.The fluid flow mechanisms during the shale oil fracturing-soaking-producing process are investigated from a pore-scale perspective,which provides support for the formulation of a reasonable production schedule for shale oil wells.

油气勘探开发领域从常规油气向非常规油气跨越,是石油工业发展的必然趋势.全球"页岩气革命"推动页岩气勘探开发技术得到了迅速发展,水力压裂成为页岩气高效开发的关键技术之一.为了实现致密页岩储层的商业开采,必须通过大规模全井段储层缝网体积改造才能获取经济产能.目前复杂裂缝网络的形态和扩展规律仍是压裂施工中面临的关键难题,严重制约了页岩气资源的合理开发.本文归纳总结了目前常见的裂缝扩展规律研究方法并分析了不同方法在研究裂缝扩展规律问题时存在的优缺点.此外,在页岩水力压裂裂缝扩展的已有实验和数模的研究基础上,从地质和工程因素两个角度分析了对水力裂缝扩展规律的影响,系统总结了各因素影响下的裂缝扩展规律,取得了如下认识:(1)页岩物理及力学性质影响裂缝的扩展,高脆性,非均质性强的地层容易形成复杂裂缝网络;(2)地应力是影响裂缝扩展的最主要因素,决定了裂缝扩展的方向与裂缝形态;(3)页岩储层中的天然弱面(层理与天然裂缝等)是产生复杂裂缝的重要原因,其弱面性质、产状以及地应力共同决定了裂缝能否穿过弱面扩展;(4)高施工排量和高黏度可以有效增加储层的压裂改造范围,但是裂缝复杂程度低;(5)射孔方式能影响裂缝复杂程度,螺旋射孔得到的裂缝形态最复杂,平面射孔的裂缝形态最简单.通过实验和数模可以研究特定地层和施工条件下的裂缝扩展规律,但是无法满足现场真实情况下的复杂裂缝网络的裂缝扩展规律的研究.未来对于页岩储层裂缝扩展规律的研究仍然以实验和数值模拟方法为主,不断改进和完善复杂裂缝网络的模拟,同时大力发展裂缝形态监测技术,更加准确的描述实验和现场压裂裂缝的形态.此外积极探索研究裂缝扩展规律的新方法,为我国非常规页岩油气资源的勘探开发提供强有力的储层改造理论保障.

超临界二氧化碳(SC-CO2)压裂改造非常规储层具有提高油气产量、储层无污染、节约水资源、埋存CO2等优点,受到了工业界和学术界的广泛关注.本文综述了目前室内SC-CO2压裂实验方法、裂缝起裂扩展特征与机理,以及存在的问题并给出建议.SC-CO2与岩石的"热(T)—流(H)—力(M)—化(C)"多场耦合作用机理为诱导应力和弱化断裂性质两方面.诱导应力方面包括:SC-CO2低黏度和高扩散性导致的孔隙压力场和热应力场,共同降低有效应力并诱发天然裂缝的剪切破坏(TH-M);SC-CO2相变释放的能量以冲击载荷和热应力的形式促进裂缝动态扩展(TH-M).弱化断裂性质方面包括:零表面张力的SC-CO2可进入微裂纹尖端,降低裂缝扩展所需的缝内净压力(H-M);SC-CO2吸附在微裂纹表面,降低裂缝失稳扩展所需的临界应力(C-M).因此,SC-CO2压裂易于形成以I-II混合型破坏为主的多裂缝,适合改造裂缝性致密储层.未来应积极开展SC-CO2三维裂缝扩展实验模拟,进行裂缝特征重构和定量评价,利用理论模型和数值模拟研究方法,实现研究尺度的升级,加快SC-CO2压裂工业应用进程.