Table of Content

25 August 2026, Volume 33 Issue 4

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Summary

Research progress and prospects of phase-field models for hydraulic fracturing simulation

Chen Weihua, Yang Zhaozhong, Wang Zhouyang, Guo Fufeng, Luo Zhilin, Li Xiaogang, Yi Liangping, Liu Jianping

2026, 33(4):  1-8.  DOI: 10.3969/j.issn.1006-6535.2026.04.001

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Hydraulic fracturing simulation of reservoirs is a complex fluid-solid-damage coupling process.Owing to the intrinsic advantages of the phase-field method in multiphysics simulation,it has been widely applied to hydraulic fracturing simulation.Over more than a decade of development,numerous phase-field models have been developed for hydraulic fracturing simulation,including brittle-fracture phase-field models based on linear elastic fracture mechanics,ductile-fracture phase-field models considering the post-peak plastic stage,phase-field models considering the viscoelastic behavior of rocks,and quasi-brittle-fracture phase-field models assuming the presence of a cohesive zone at the fracture tip.These models cover most types of rock fracture,including brittle fracture,ductile fracture,viscoelastic fracture,and quasi-brittle fracture.To further promote the development and advancement of the phase-field method in hydraulic fracturing simulation,especially technical progress in fracture-type identification,multiphysics coupling,and innovations in governing equations for fluid flow and rock deformation,this paper summarizes the progress of phase-field models in hydraulic fracturing and indicates future development directions for phase-field models in hydraulic fracturing simulation.This study can promote the wider application of phase-field models in hydraulic fracturing simulation and provide technical ideas for overcoming the limitations of existing models.

Geologic Exploration

Sedimentary-tectonic evolution and exploration prospects of the Mesozoic strata in the Hongde Area,Ordos Basin

Ye Qing, Zhang Zhongyi, Zhang Tao, Liu Baoxue, Zhang Xiaolei, Liang Zhiguo, Hou Yunchao, Cheng Junsheng

2026, 33(4):  9-15.  DOI: 10.3969/j.issn.1006-6535.2026.04.002

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The Mesozoic strata in the Hongde Area on the western margin of the Ordos Basin have experienced multiple tectonic movements,resulting in complex and diverse structures.To clarify the hydrocarbon accumulation patterns of the Mesozoic strata in this area and to guide subsequent exploration,an integrated workflow combining well-seismic integration,seismic horizon flattening,and tectonic evolution analysis was applied to investigate the sedimentary-tectonic evolution characteristics.The results show that the Mesozoic strata in the Hongde Area have experienced four tectonic evolution stages:a tectonic uplift stage(end of the Triassic),a stable subsidence stage(Jurassic),a rapid subsidence stage(Early Cretaceous),and a tectonic inversion stage(Late Cretaceous).Two fault systems were mainly developed,namely the Indosinian and Himalayan fault systems.During the Indosinian stage,faults were dominated by north-east-trending and north-west-trending orientations,controlling the formation of fault-block traps.During the Himalayan stage,affected by compressional stress, the north-east-east-trending strike-slip faults developed and divided the study area into multiple north-east-trending rhombic fault blocks.The Early Cretaceous was the main hydrocarbon charging period,with abundant hydrocarbon supply from high-quality source rocks of the Chang 7 in the central basin;large-scale accumulations formed on the western structural highs.Continuous subsidence of the Tianhuan Depression during the Early Cretaceous resulted in a structural configuration that is low in the west and high in the east,with early reservoirs damaged.Tectonic inversion occurred in the Late Cretaceous,and uplift of the western margin led to secondary adjustment of reservoirs,forming the present structural-lithologic reservoirs,which are characterized by low oil saturation,low oil-bearing amplitude,low-resistivity reservoirs,and complex oil-water relationships. Fault-block structural traps formed in the Indosinian stage are favorable zones for large-scale hydrocarbon accumulation,whereas low-amplitude structural traps formed in the Late Cretaceous are key domains for refined exploration.The results provide guidance for subsequent exploration of the Mesozoic strata in the Hongde Area.

Fault sealing evaluation method for gas storage based on combined subjective-objective weighting and the efficacy coefficient method

Xu Haitao, Liu Kang, Xiao Yong, Yu Yong, Liu Xiaofang, Chen Guoming, Wang Chengxin

2026, 33(4):  16-22.  DOI: 10.3969/j.issn.1006-6535.2026.04.003

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Faults are weak links in depleted oil-and-gas-reservoir underground gas storage facilities.The numerous factors affecting fault sealing,their complex interactions,and the ambiguity of indicator weights pose challenges to comprehensive evaluation of fault sealing in gas storage facilities.In view of this,a comprehensive evaluation method for fault sealing based on “combined subjective-objective weighting-the efficacy coefficient method” was proposed.A fault sealing evaluation index system was established from four aspects,namely fault lithologic characteristics,environmental conditions,mechanical characteristics,and injection-production system.The DEMATEL method and the anti-entropy weighting method were jointly used to determine indicator weights,thereby reducing the bias caused by weighting with a single method.By calculating the total efficacy coefficient of gas storage faults,the sealing performance grade of faults in gas storage facilities was quantitatively determined.This evaluation method was applied to a gas storage facility in the Bohai Bay Basin.The results show that the sealing grade of the gas storage facility is Grade Ⅲ(relatively good),and the calculated results are consistent with actual field conditions.This evaluation model is feasible and can provide a comprehensive assessment of the sealing performance of faults in underground gas storage facilities.These results can provide a theoretical reference for site selection and fault sealing evaluation of underground gas storage facilities.

Multi-scale differences in pore-fracture structures of coal reservoirs in the southern margin of the Junggar Basin and their influencing factors

Li Wenjie, Wu Jinbiao, Long Yu, Ma Nenghui, Tian Ruixing, Liao Zhengkai, Kong Fang, Su Jingyi

2026, 33(4):  23-31.  DOI: 10.3969/j.issn.1006-6535.2026.04.004

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Coalbed methane resources are abundant in the southern margin of the Junggar Basin(hereafter referred to as the southern Junggar Area),and are mainly hosted in the Jurassic Badaowan Formation and Xishanyao Formation.To clarify the differences in pore-fracture development characteristics and their influencing factors for coal reservoirs in the Badaowan Formation of the Fukang mining area and in the Xishanyao Formation of the Qigu fault-fold belt in the southern Junggar area,CT scanning,scanning electron microscopy (SEM),high-pressure mercury intrusion,low-temperature nitrogen adsorption and carbon dioxide adsorption experiments were conducted,and a full-aperture stitching technique was applied for analysis.The results show that the coals in the study area are all bituminous coals with similar reflectance and medium coal rank.The coal quality of the Fukang mining area(vitrinite content of 81%-88%)is slightly better than that of the Qigu fault-fold belt(vitrinite content of 70%-78%),while the coalification degree in the Qigu area is slightly higher.In the Fukang mining area,the coal reservoirs have few developed fractures;pores are dominated by tissue pores,with a small number of gas pores locally developed.The theoretical adsorption capacity is stronger with an average Langmuir volume of 18.75 cm³/g and an average specific surface area of 74.13 m²/g;however,affected by coal quality,the infilling effect of ash reduces the total pore volume pores are dominated by gas pores with higher proportions of mesopores and macropores.In the Qigu fault-fold belt, the average Langmuir volume is 10.83 cm³/g and the average specific surface area is 68.05 m²/g.Intensive tectonism provides conditions for fracture development;cleats and fractures are well developed overall,resulting in the advantageous reservoir physical properties of high porosity and permeability and low damage.Comprehensive analysis indicates that the Fukang mining area has better adsorption and high gas content,but fractures are not well developed,free gas is difficult to accumulate,and gas desorption is difficult;the Qigu Area has longer-term and more stable development potential.These results provide a theoretical basis for efficient exploration and development of coalbed methane in the study area.

Effect of sample crushing size on characterization of shale pore structure by small-angle X-ray scattering

Wang Jiang, Han Hui, Wen Ran, Nie Zunhao, Wu Wenjie, Wang Yixing, He Chunchen, He Jiang

2026, 33(4):  32-37.  DOI: 10.3969/j.issn.1006-6535.2026.04.005

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At present,the influence of sample crushing size on the characterization of shale pore structure by small-angle X-ray scattering remains unclear.To solve this problem,shale samples from the Longmaxi Formation in the Sichuan Basin were selected as the research objects.The samples were crushed into four commonly used particle sizes.Small-angle X-ray scattering(SAXS)experiments were then carried out to characterize closed pores,and low-pressure nitrogen adsorption experiments were performed to characterize open pores.The experimental results show that,with decreasing sample particle size,both pore volume and fractal dimension decrease correspondingly.This indicates that sample crushing damages pores,especially larger closed pores,thereby reducing the heterogeneity and surface complexity of the sample pore system.Therefore,in order to obtain true information on shale pore structure,20-mesh samples from the Longmaxi Formation in the Sichuan Basin are recommended for small-angle X-ray scattering experiments.The results of this study will promote the standardization of small-angle X-ray scattering for shale and the comparability of the results obtained.

Characteristics,genesis,and development significance of calcareous baffle interlayers in the Hanjiang Formation,Enping Sag,Pearl River Mouth Basin

Li Qi, Wen Xin, Yang Jiao, Song Jianhu, Tu Yi, Gong Zheng, Yang Zhipeng

2026, 33(4):  38-48.  DOI: 10.3969/j.issn.1006-6535.2026.04.006

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To solve the problem that the development of calcareous baffle interlayers constrains the fine-scale development of marine sandstone oilfields,core,well logging and resistivity boundary-detection inversion data were integrated.Using microscopic identification,facies analysis,mechanism investigation and distribution prediction,this study investigates the development characteristics,genetic mechanisms,distribution patterns and development significance of calcareous baffle interlayers within the Hanjiang Formation reservoir of the F Oilfield in the Enping Sag,Pearl River Mouth Basin.Results show that calcareous baffle interlayers in the study area are mainly calcareous fine-and silt-sized sandstones,with calcite as the dominant calcareous component.Conventional logs are characterized by low gamma ray,high density,low neutron porosity,and high resistivity;the resistivity boundary-detection response presents a red high-resistivity feature.Combined with isotopic evidence,three genetic mechanisms are identified:dissolution-reprecipitation of bioclasts,evaporation,and sandstone-mudstone coupled diagenesis.The distribution of calcareous baffle interlayers is jointly controlled by "sequence-sedimentation-diagenesis".Vertically,calcareous baffle interlayers are continuously bedded near stable mudstone intervals,whereas those within sandstone reservoirs are discontinuously bedded and occur as massive patches.Laterally,calcareous baffle interlayers are more developed along the provenance direction.These results improve the accuracy of geological reserves estimation,guide the design and optimization of development well types,and provide an important basis for reservoir heterogeneity characterization and fine residual-oil tapping under offshore sparse-well conditions.

Sequence-constrained characterization of delta-front single sand bodies

Zuo Gaoming, Zhao Yonggang, Wu Zemin, Deng Haichao, Li Zhihong, Cai Shen'ao, Chai Xun, Lin Xi

2026, 33(4):  49-58.  DOI: 10.3969/j.issn.1006-6535.2026.04.007

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To address the problem that single-sand-body characterization in Block Z,southwestern Ordos Basin,cannot meet the needs of efficient reservoir development,a systematic method for single-sand-body study constrained by ultra-short-term base-level cycles was proposed by taking the Chang 8₁ sand-layer group in this area as an example and using core,outcrop,mud-logging,well-logging,and production-performance data.The results show that seven ultra-short-term base-level cycles are developed in the Chang 8₁ sand-layer group in the study area,corresponding to seven sets of sequence single sand bodies.Single-sand-body interfaces were identified using electrical-log characteristics,and seven stable reservoir single sand bodies were identified through lateral correlation of sequence single sand bodies.The strength of lateral connectivity between single sand bodies mainly depends on the lateral contact relationships of sand bodies.Under the influence of the distribution and scale of underwater distributary channels,individual branches of single sand bodies are generally narrow in plan view,and channel width-to-thickness ratio exhibits a good positive correlation.Oil layers with injection-production relationship types such as injection without production,production without injection,and neither injection nor production have low producing degrees,which is closely related to the low degree of single-sand-body study.In single sand body 2-1 of the study area,targeted supplementary perforation adjustment increased the well-pattern connectivity rate to as high as 66%,effectively improving the producing degree of oil layers.This study expands the characterization of reservoir single sand bodies and provides technical support for optimizing injection-production adjustment measures.

Reservoir Engineering

Safety impact analysis of dynamic evolution of gas compositions on heavy-oil thermal recovery wells with nitrogen injection

Zhang Ruyun, Zhang Laibin, Dong Shaohua

2026, 33(4):  59-65.  DOI: 10.3969/j.issn.1006-6535.2026.04.008

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During heavy-oil development operations with nitrogen injection,downhole explosion hazards may still exist during field operations even when the purity of injected nitrogen meets industry standards.With a typical field downhole explosion accident as the research object,this study systematically analyzed the dynamic evolution mechanism of explosion-inducing factors in nitrogen-injection thermal-recovery wellbores from four dimensions:crude-oil properties,combustible formation,oxidant conditions,and ignition sources.The results show that hydrocarbon components in formation crude oil undergo cracking and volatilization reactions in high-temperature,high-pressure wellbore environments,continuously generating combustible hydrocarbon gases such as methane.Dissolution and dissipation of nitrogen in the wellbore lead to imbalance in gas composition,causing the oxygen volume fraction in the system to gradually increase.The mixed-gas parameters enter the methane explosion-limit range,ultimately forming a highly hazardous explosive gas mixture.During steam-injection operations,mechanical collision of the tubing string,string friction,and fluid electrostatic accumulation can all generate energetic ignition sources,satisfying all conditions required for an explosion.Field measured data and comparative tests from adjacent wells in the same horizon verified the dynamic evolution pattern of gas compositions in the wellbore and the formation mechanism of explosive gas mixtures,clarifying the root cause of downhole explosion accidents.Based on the explosion-triangle theory,a risk prevention and control system for heavy-oil development with nitrogen injection was constructed,providing theoretical support for safety-risk identification and hazard prevention and control in heavy-oil nitrogen-injection thermal recovery.Targeted technical recommendations were also proposed for key links,including optimization of the nitrogen-injection process,real-time monitoring of wellbore gas,and source control of ignition sources,providing a scientific reference for field safety management.

Establishment of a novel characteristic equation and dynamic prediction chart for CO₂ flooding

Cui Chuanzhi, Chen Wenteng, Zheng Jiapeng, Ma Xiaoli, Li Dan, Gu Xiao, Wang Junkang

2026, 33(4):  66-73.  DOI: 10.3969/j.issn.1006-6535.2026.04.009

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Dynamic evaluation of CO₂ flooding performance still lacks a sound theoretical basis,which relies heavily on numerical simulation,and is difficult to apply in real time.To solve these problems,a novel characteristic-curve equation and a theoretical dynamic prediction chart for CO₂ flooding were established on the basis of material balance principles and mathematical derivation.The results show that the proposed prediction chart overcomes the limitations of traditional methods that rely on fitting field data and lack physical-mechanism support.It can quantitatively characterize the mathematical functional relationships among key parameters and,together with the theoretical chart,realize real-time dynamic evaluation and prediction of CO₂ flooding performance.Validation against numerical simulation results and actual production data indicates that,during the medium-to-high pseudo water-cut gas-rate stage,the prediction accuracy of the chart exceeds 90%.When the pseudo water-cut gas rate is greater than 90%,the prediction accuracy is further improved.In an application to a block of a certain oilfield,the chart predicts an ultimate recovery factor of 42%;the theoretical curve is in good agreement with the actual production performance,showing relatively high accuracy and satisfactory predictive capability.This study realizes real-time dynamic evaluation of CO₂ flooding performance and provides a new approach for development scheme optimization and recovery prediction.

Preparation of a biomass-based micro-nano combustion agent and its feasibility of chemical ignition in fireflooding

Yang Ying, Zhao Renbao, Ren Haitao, Zhou Guanghui, Liao Bin, Liu Bin, Liu Yushen

2026, 33(4):  74-80.  DOI: 10.3969/j.issn.1006-6535.2026.04.010

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In chemical ignition for heavy oil fireflooding,chemical combustion agents are required.To address the high storage-transport risk and high cost of existing chemical agents,a biomass pulp was used as raw material to prepare a biomass-based micro-nano chemical combustion agent(DES-US-BIO)via a deep eutectic solvent-ultrasonic method.The structure of DES-US-BIO was characterized in terms of average particle size and crystallinity.Combustion cell experiments were carried out,including measurement of activation energy and analysis of combustion characteristics,and the combustion-promoting performance of DES-US-BIO was evaluated.The results show that the prepared material has an average particle size of about 628 nm and an ignition temperature of 240.0-260.0 ℃.The activation energy in the combustion stage ranges between 69×10³ and 160×10³ J/mol.DES-US-BIO can accelerate crude oil ignition and promote temperature increase at the combustion front,thereby improving the oil recovery efficiency.The micro-nano size and low ignition temperature of DES-US-BIO meet injection requirements and can provide initial ignition energy as well as increase fuel concentration,endowing it with great application potential for chemical ignition in fireflooding development.

Unsteady pressure transient analysis of a volume-fractured vertical well in a tight reservoir based on fractal theory

Guo Jingjing, Wang Chengjie, Chen Xingguan, Wang Tao, Zheng Hailiang, Shi Keyan, Wang Haitao

2026, 33(4):  81-89.  DOI: 10.3969/j.issn.1006-6535.2026.04.011

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To address the limitation of existing models that cannot simultaneously characterize the fractal features of hydraulic fracture networks in tight reservoirs,the fractal characteristics of the matrix system and the effects of stress sensitivity,fractal theory was employed to characterize the complex morphology of fracture networks within the hydraulically stimulated region and the heterogeneity of the matrix system in the unstimulated region.An analytical well test model for a stress-sensitive tight reservoir subjected to volumetric fracturing in a vertical well was established.Dimensionless pressure and pressure-derivative type curves were generated,characteristic flow regimes were identified and sensitivity analyses of relevant parameters were conducted.The results indicate that fluid flow in a volumetrically fractured vertical well completed in a fractal tight reservoir can be classified,into six typical flow regimes,according to well test curve characteristics:wellbore storage,early transition flow,linear flow,early pseudo-radial flow,inter-region transition flow between inner and outer zones,and second radial flow.The fractal parameters of the stimulated region exert a pronounced influence on the well test curves during the linear flow regime and subsequent stages.The fractal parameters of the unstimulated region primarily affect the characteristics of the well test curves during the inter-region transition flow and the second radial flow stages.The stress sensitivity effect mainly influences the mid-to late-time bottom-hole pressure response.These findings provide important guidance for evaluating hydraulic fracturing performance in vertical wells in heterogeneous tight gas reservoirs and for determining dynamic reservoir parameters.

Energy transfer laws and thermo-economic performance during coalbed methane production from a bituminous-coal reservoir by microwave heating

Su Chang, Jian Farun, Yang Xinle, Liu Jie, Cui Shengran, Tao Shimin, He Liuquan

2026, 33(4):  90-97.  DOI: 10.3969/j.issn.1006-6535.2026.04.012

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Microwave heating for coalbed methane(CBM)production features fast heat injection and high thermal efficiency;however,energy dissipation and loss are inevitable in field operations.To further improve energy-utilization efficiency in microwave-heating production,a systematic study was conducted on energy-transfer laws and thermo-economic performance during the production process.Based on triaxial adsorption-desorption experiments for CBM under microwave heating,the dynamic relationship between temperature and desorbed gas volume with heating time was obtained,and a mathematical model of energy transfer was established.Numerical simulation was used to reveal heat-transfer laws during microwave-heating production,and a thermo-economic evaluation model was constructed with thermal efficiency and energy extraction efficiency as the core indices;the impacts of different microwave power levels and port layouts on thermo-economic performance were analyzed.Results show that under different microwave power levels,the coal seam accounts for the largest proportion of absorbed heat,whereas the adsorbed gas accounts for the smallest proportion.The heat absorbed by water changes relatively steadily;the heat absorbed by desorbed gas increases with time;and boundary dissipated heat increases significantly under high microwave power.With two microwave ports and 500 d of heating,thermal efficiency reaches a peak of 14.7% at 1 330 W;energy extraction efficiency can reach 660% at 1 330 W.Under constant power,the use of a four-port layout increases thermal efficiency by 2.51 percentage points and increases energy extraction efficiency by 71.00 percentage points.This study provides a theoretical basis for accelerating commercialization of CBM production and for optimizing construction schemes and process parameters for microwave-heating production.

Experiments of formulation parameters optimization for an in-situ microemulsion flooding system

Chen Wenlin, Cao Ruibo, Yan Wei, Jiang Guoqing, Liu Haibo, Han Peihui

2026, 33(4):  98-104.  DOI: 10.3969/j.issn.1006-6535.2026.04.013

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To solve the problems of low residual oil saturation and high dispersion after polymer flooding,based on surfactant structure-property relationships,phase-behavior experiments,instrumental tests and physical simulation were conducted.An oil-displacement system capable of forming a middle-phase microemulsion in situ was developed,and formulation parameters optimization research was conducted,including the hydrophobic-chain lengths of the extended surfactant,the type of hydrophilic group,the numbers of propylene oxide(PO)/ethylene oxide(EO)units,and the blending ratio of mixed surfactants.Results show that the primary surfactant is a double-tailed C₂₄ extended carboxylate surfactant(APEC)containing 10 EO units and 25 PO units,which provides both favorable hydrophobic performance and cost effectiveness.The most suitable auxiliary surfactant is an alkylbenzene sulfonate surfactant(ABS).When combined with APEC,it generates ultralow interfacial tension at extremely low salinity,exhibits Winsor-type phase behavior,and provides a middle-phase microemulsion salinity window of 0.20%;the optimal mass ratio of APEC to ABS is 4∶6.The system can form a middle-phase microemulsion in situ under reservoir conditions.After waterflooding,in situ microemulsion flooding can improve recovery by 45.9%,which is 8.7 percentage points higher than weak-alkali alkaline-surfactant-polymer(ASP)flooding.This study provides an important basis for developing new post-polymer-flooding EOR technologies in Daqing Oilfield.

Development performance and practice of energized imbibition in an ultra-low permeability and tight oil reservoir

Cao Bao, Xie Kun, Lu Xiangguo, Wen Guofeng, Chen Qi

2026, 33(4):  105-113.  DOI: 10.3969/j.issn.1006-6535.2026.04.014

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To address the large variability in effectiveness of water-injection energized imbibition in an ultra-low permeability and tight oil reservoir and the unclear development-technology strategies,a discrete fracture model was used,and pseudo threshold pressure-gradient and stress-sensitivity effects were considered.The technical boundaries for water-injection energized imbibition in different reservoir types and the development performance of an ultra-low permeability and tight oil reservoir under different fracture-network forms and injection parameters were investigated.Results indicate that ultra-low permeability and tight reservoirs can be classified into three types(Type Ⅲ,Type IV,and Type V),with reservoir properties progressively deteriorating.Type Ⅲ reservoirs are suitable for volume fracturing+energized displacement;Type IV reservoirs are suitable for volume fracturing+energized displacement or volume fracturing+energized huff-and-puff;reservoirs with poor connectivity or Type V reservoirs are suitable for volume fracturing+energized huff-and-puff.Recommended parameters for energized imbibition in an ultra-low permeability and tight oil reservoir include multi-stage volume fracturing,an injection volume of 15 000 m³,a shut-in time of 8-14 days,and 3 huff-and-puff cycles.Field tests of volume fracturing+energized displacement and volume fracturing+energized huff-and-puff are conducted in ultra-low permeability and tight reservoirs in Dagang Oilfield,the cumulative incremental oil production of injection-production well groups exceeds 6000.00 t within 2 years, and the cumulative oil production of huff-and-puff wells exceeds 3800.00 t over 300 days, showing significant stimulation effects.These results can provide technical support and field-practice guidance for development of analogous reservoirs.

Laboratory experiments and application-effect evaluation of polymer microsphere flooding in the Chang 6 ultra-low-permeability reservoir,Jing'an Oilfield

Mo Lei, Guo Hongxia, Li Pingdong, QI Huaiyan, Yang Xuewu, Yang Yong, Zhang Jinbo, Zhao Kailiang

2026, 33(4):  114-121.  DOI: 10.3969/j.issn.1006-6535.2026.04.015

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To address the severe areal and interlayer contradictions, rapid water cut increase, complex remaining oil distribution, and difficult oil stabilization and water control in the high-water-cut development stage of Chang 6 ultra-low permeability reservoirs in Jing'an Oilfield, polymer microsphere flooding experiments with macroscopic and microscopic visualization were conducted via laboratory and field tests. The flooding mechanism was analyzed, and the field application performance was evaluated.Results show that after polymer microsphere flooding,permeability decreases by 39.5%~68.7%,and the residual resistance factor reaches 1.65~3.19.The crossover point of relative-permeability curves shifts significantly to the right,residual-oil saturation decreases,water-phase relative permeability decreases,and oil-phase relative permeability increases.Under uniform polymer microsphere displacement,residual oil shows spotty or locally scattered distribution patterns;under non-uniform displacement,residual oil shows locally contiguous enrichment or enrichment along the flanks of preferential flow channels. After polymer microsphere flooding in the target blocks,the water injectivity of injection wells decreases,water-injection utilization and reservoir displacement conditions improve,the waterflood swept volume expands,and the reservoir recovery factor increases by 2.0~2.9 percentage points.These results provide important guidance and reference value for stabilizing oil production,controlling water,enhancing residual-oil tapping,and improving recovery in ultra-low-permeability reservoirs during middle-to-high water-cut stages.

Drilling & Production Engineering

Flow in porous media-stress coupled finite-element simulation of gas production in the fractured zone of horizontal wells based on a refined geological model

Liu Houbin, Du Shuang, Zhang Lishuang, Wang Shuai, Cui Shuai

2026, 33(4):  122-131.  DOI: 10.3969/j.issn.1006-6535.2026.04.016

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To investigate the flow in porous media-stress coupling mechanism during gas production from the fractured zone of shale-gas horizontal wells and the spatiotemporal evolution of pore pressure and in-situ stress,a finite-element coupled simulation method based on a refined geological model was established.By embedding fracture surfaces into geological grids and using a three-dimensional property interpolation function,this method accurately maps multiscale fractures onto finite-element grids.On this basis,a fluid-solid coupling model considering non-Darcy flow and the dynamic evolution of porosity and permeability was constructed.According to the model,a production-history matching method was established using gradient descent of the error between simulated and actual pressures of production wells.With the Well X platform in the Luzhou Block,Sichuan,as an example,the coupled responses of pore pressure and stress under gas-production drive and the influence of the fracture system were analyzed on the basis of dynamic calibration of initial pore pressure and permeability and production-history matching.The results show that the average relative error of history matching was 4.6%,indicating that the model accurately reflects actual production performance.During short-term gas production over 82 d,the near-wellbore pore pressure decreased by approximately 1.5 MPa,and the effective stress increased correspondingly by approximately 0.9 MPa.The near-wellbore pressure-depletion funnel and stress-concentration zone expanded outward synchronously,with the affected range mainly confined within 50 m of the well.The decrease in pore pressure and the volumetric strain of the rock led to slow reductions in porosity and permeability,with decreases of less than 0.5%,indicating that short-term production had limited effects on reservoir physical properties.As preferential seepage pathways,the fracture system accelerated pressure propagation and simultaneously formed stress concentration in the mechanical response,causing fluid-solid coupling to exhibit pronounced anisotropy and heterogeneity.The results provide a quantitative research tool for engineering issues such as productivity evaluation,interwell interference analysis,and casing-integrity assessment in shale-gas development.

Alternating mechanics during fracturing and failure characteristics of the second cementing interface in shale oil horizontal wells in the Longdong Area,Ordos Basin

Ouyang Yong, Zhang Pengxin, Wang Tingting, Zeng Xuyang, Li Teng

2026, 33(4):  132-138.  DOI: 10.3969/j.issn.1006-6535.2026.04.017

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During staged fracturing of shale oil horizontal wells in the Longdong area of the Ordos Basin,the second cementing interface is prone to cracking because of its low bonding strength,which may further induce interlayer channeling.To solve this problem,the mechanical response of the cement sheath system under alternating loads and the evolution of interface failure were investigated.Based on the principles of elasticity and fracture mechanics,a mechanical model covering the entire loading and unloading process during fracturing was established.Triaxial mechanical experiments revealed a stepwise decrease in the elastic modulus of cement stone with increasing cycle number,and field data from production wells were used to validate the accuracy of the mechanical model.The results show that the weakening effect of alternating stress on the contact pressure of the second cementing interface is significantly stronger than that on the first cementing interface.The energy dissipation mechanism of crack propagation at the second cementing interface was clarified,and it was demonstrated that a physical equilibrium boundary exists for crack growth under specific operating conditions.The maximum propagation length of the second cementing interface under typical conditions was calculated to be 12.7 m.Further analysis indicates that the failure length of the second cementing interface increases with increasing wellhead pump pressure and in-situ stress.The greater the difference in elastic modulus between the formation and the cement sheath,the more slowly the interfacial energy release rate decays,the more significantly the risk of interlayer sealing failure increases.These findings can provide scientific and effective technical guidance for hydraulic fracturing of horizontal wells and field cementing operations in this area,and are of important academic value and engineering significance for optimizing fracturing parameters and determining their limits.

Optimization method and practice of annular nitrogen thermal-insulation technology for steam-injection wells

Guo Binjian

2026, 33(4):  139-145.  DOI: 10.3969/j.issn.1006-6535.2026.04.018

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During heavy-oil thermal recovery,improper application of annular thermal-insulation measures in steam-injection wells can readily induce technical problems in thermal injection,such as large steam-injection heat loss,wellhead uplift,casing damage,and wellbore corrosion.Therefore,based on the completion structure of thermal-injection wells and by comprehensively applying the basic principles of heat transfer and fluid mechanics,a model for the critical annular nitrogen injection rate was constructed.The factors influencing the critical annular nitrogen injection rate were analyzed,and an optimization method for annular nitrogen-injection thermal-insulation technology in thermal-injection wells was proposed.The results show that under different well-type conditions,horizontal wells have greater annular thermal resistance than directional wells and require higher critical nitrogen injection rates.The required critical nitrogen injection rate increases with increasing pressure,steam injection rate,and steam quality.With increases in the length and thermal conductivity of insulated tubing,the required critical nitrogen injection rate decreases rapidly.In addition,increasing interval pack-off in the annulus causes the required critical nitrogen injection rate to decrease linearly.Through integrated optimization design measures,such as simplifying the model for critical annular nitrogen injection rate,designing pack-off devices,optimizing the completion string,and reducing injection pressure,the nitrogen injection rate of the annular nitrogen-injection thermal-insulation technology was reduced by more than 75%.This study provides key theoretical guidance for improving steam heat-utilization efficiency and reducing the casing-damage rate in thermal-injection wells.

Establishment of a prediction model for drilling-fluid contamination in low-permeability tight reservoirs and evaluation of reservoir damage

Ji Hui, Li Jun, Ju Yafeng, Yan Changhao, Zhang Hui, An Jintao, Lian Wei, Liu Gonghui

2026, 33(4):  146-153.  DOI: 10.3969/j.issn.1006-6535.2026.04.019

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To clarify the degree of damage caused by drilling fluid to low permeability tight reservoirs and to quantify the depth of drilling fluid contamination,a prediction model for drilling fluid contamination based on dual-size solid particles was established on the basis of long core injection displacement experiments.The effects of seepage time,wellbore pressure drop,solid particle mass concentration,and filter cake porosity on drilling fluid contamination damage were analyzed,and Well Y88-32 in the Y88 Block of the Changqing Oilfield was taken as an example for calculation and analysis.The results show that when the injection rate is 0.2 mL/min and the pressure limit is 30 MPa,distilled water can penetrate the long core of the Y88 interval,whereas the maximum displacement depth of the drilling fluid does not exceed 150 mm.The predictions of the dual-size solid particle drilling fluid contamination model are highly consistent with the experimental results,indicating that the model can simulate the damage process induced by solid particles and can satisfy the prediction requirements for the radius of drilling fluid contamination in the target block.Controlling the bottomhole pressure differential and reducing the invasion of drilling fluid solid particles by lowering their mass concentration can effectively reduce the contamination radius.Under field drilling parameters,the optimal evaluated contamination radius of drilling fluid for the reservoir in Well Y88-32 is 131.1 mm.The results provide a reasonable method and theoretical guidance for damage evaluation in tight reservoirs and are helpful for efficient reservoir development.

Split-type chemical power ball technology for dewatering and gas production in horizontal gas wells

Liu Shubing, Zhang Kun, Liu Lei, Zhang Hexing, Wang Luyao, Guo Haihai, Liu Yonghui

2026, 33(4):  154-159.  DOI: 10.3969/j.issn.1006-6535.2026.04.020

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Due to curved wellbore design and tubing-casing isolation by packers in horizontal gas wells,foamers are difficult to be delivered to the bottom of the wells,and large volumes of accumulated liquid in horizontal sections cannot be effectively removed.Therefore,based on the principle of synergistic foam drainage with sodium nitrite-ammonium chloride self-generated nitrogen,a split-type spherical chemical power ball was developed by mixing ammonium chloride,sodium nitrite,and a slow-release acid catalyst separately with a foamer,and fabricating them into split-type spherical balls via high-pressure stamping.A split-type chemical power ball dewatering and gas production technology for horizontal gas wells was formed;the formulation and performance of the foaming system were optimized and evaluated,construction parameters were optimized,and field tests were conducted.The results show that the basic formulation of the split-type chemical power ball foaming system(mass fraction)is 45% ammonium chloride+35% sodium nitrite+10% foamer (including foam stabilizer)+5% slow-release acid catalyst+5% high-density filler.The split-type and spherical design solves the problem of foamer placement and avoids the risk of premature reaction triggering.Each gram of reactants(45% ammonium chloride+35% sodium nitrite)can generate 108~147 mL of foam and 4.9~5.9 mL of liquid-carrying capacity.The test well exhibits pronounced slug-flow liquid unloading characteristics,the liquid production increases significantly,and the average daily gas production increases by 6.66 times.These results provide a new solution for liquid loading control in horizontal gas wells.

Development and application of a superamphiphobic strong-plugging water-based drilling fluid in the Linxing-Shenfu tight gas field

Wang Peng, Li Bin, Zhang Hongjie, Wang Kunjian, Huang Shengming, Dong Tengfei

2026, 33(4):  160-167.  DOI: 10.3969/j.issn.1006-6535.2026.04.021

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In view of problems such as wellbore instability,lost circulation,and reservoir damage in the Linxing-Shenfu Block tight gas reservoirs,which are caused by strong water sensitivity of mud shale,well-developed microfractures,low porosity and low permeability,and poor pore-throat connectivity,the concept of "dual hydrophobic-oleophobic inhibition plus film-forming plugging" was proposed.A weakly crosslinked superamphiphobic polymer inhibitor for drilling fluids and an amphiphilic polymer film-forming plugging agent were developed,and together with a fluid-loss reducer,flow-pattern regulator,and lubricant,a superamphiphobic strong-plugging water-based drilling fluid system was constructed.The results show that this system can effectively regulate the surface electrical properties of bentonite,inhibit clay hydration and dispersion,and enhance the stability of particle aggregation.After aging at 200 ℃,it still exhibits good rheological stability and fluid-loss control capability,with both API fluid loss and high-temperature high-pressure fluid loss below 5.0 mL.It also shows excellent plugging,lubrication,and reservoir-protection performance,with primary and secondary rolling recovery rates of 98.6% and 94.5% respectively,and a permeability recovery rate of 92.5%.Field application demonstrates that,compared with a conventional polymer drilling fluid,the superamphiphobic strong-plugging water-based drilling fluid increases the average rate of penetration by 23.9%,shortens the drilling cycle by 9.6 days,and reduces the average hole enlargement rate by 46.4%,with smooth drilling-fluid operations throughout.This system can effectively solve the problems of wellbore instability,difficulty in plugging microfractures,and reservoir protection in the Linxing-Shenfu Block,and can provide a reference for safe and efficient drilling in similar tight reservoirs.

Preparation and evaluation of an oil-soluble mixed-resin temporary plugging agent for high-temperature and high-salinity carbonate reservoirs

Dong Xiumin, Fang Jing, Feng Xin'gen

2026, 33(4):  168-174.  DOI: 10.3969/j.issn.1006-6535.2026.04.022

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Carbonate reservoirs in the Tahe Oilfield are characterized by high temperature,high salinity and high acidity.Conventional temporary plugging agents show poor stability and insufficient strength,and that are difficult to meet the requirements of such reservoirs.In response to this,an oil-soluble mixed-resin temporary plugging agent was prepared using maleic anhydride modified petroleum resin as the main raw material,and compounding rosin-modified phenolic resin,terpene resin,and epoxy resin.The formulation was optimized and its performance was evaluated.The results show that the optimal formulation is 81.67% modified C₉ petroleum resin+6.77% rosin-modified phenolic resin+8.72% terpene resin+2.84% epoxy resin.Under extreme conditions of 140 ℃,salinity of 21×10⁴ mg/L,and 5.00% hydrochloric acid,the temporary plugging agent still maintains excellent stability,with a breakthrough pressure exceeding 10 MPa.Meanwhile,it exhibits oil-water selectivity of plugging upon water contact and unplugging upon oil contact;after plugging,the reservoir permeability recovery exceeds 93.0%.A pilot field test in Well X in the Tahe Oilfield shows that after application of this temporary plugging agent,the water-free oil production period is extended by 20% compared with nearby wells,water cut decreases from 82% to 18%,and daily oil production increases from 3.5 t to 12.8 t,indicating significant water control and oil increase effects.This study successfully addresses the bottleneck of temporary plugging technology for high-temperature and high-salinity carbonate reservoirs,and can provide technical support for efficient water-control development of fractured-vuggy carbonate reservoirs.