Table of Content

25 April 2025, Volume 32 Issue 2

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Summary

Feasibility analysis and prospects of the application of interwell connection technology in the efficient development of dry hot rock

LI Shichang, LIU Gonghui, ZHAO Yunfei, LI Jun

2025, 32(2):  1-11.  DOI: 10.3969/j.issn.1006-6535.2025.02.001

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Dry hot rocks are rich in energy storage and represent a clean energy source. Interwell connection technology is one of the key technologies for the efficient development of dry hot rocks. To explore the applicability of interwell connection technology in dry hot rock development, the characteristics and challenges of drilling and completion technologies for dry hot rock interwell connections have been analyzed, and a summary analysis has been conducted on the drilling and completion technologies suitable for dry hot rock interwell connections. The study shows that steering tools and directional tools with a temperature tolerance of up to 175 ℃ have a certain practical foundation, while wellbore trajectory control technologies for higher temperatures are under development. Interwell connection technologies have been applied in coalbed methane and salt wells. Drilling fluids and circulation cooling technologies with temperature tolerance above 200 ℃ are widely used, and high-temperature, high-efficiency rock-breaking drill bits are relatively mature. However, the application of gas drilling and downhole acceleration tools is limited in dry hot rock formations. A complete set of completion technologies with a temperature tolerance of up to 200 ℃ is relatively mature. Future research directions include developing wellbore trajectory control technologies with higher temperature tolerance and control accuracy, researching precise interwell connection technologies suitable for high-temperature hard formations, investigating drilling fluid systems with higher temperature tolerance and stability, conducting research on drilling acceleration technologies for high-hardness, high-temperature dry hot rock formations, and further studying the compatibility of completion materials and accessories with dry hot rock formations. These research findings can provide references for the efficient application of interwell connection technology in dry hot rock development.

Geologic Exploration

Types of lithofacies combination and distribution characteristics of the Eocene series shale in the Jiyang Depression

WANG Yong, LIU Huimin, MENG Wei, WEI Xiaoliang, ZHANG Shun

2025, 32(2):  12-21.  DOI: 10.3969/j.issn.1006-6535.2025.02.002

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In response to the issues of numerous shale facies, rapid facies changes and high predictability in continental faulted basins, a comprehensive analysis was conducted on the combination types, sedimentary sequences and distribution patterns of shale facies by integrating data from cores, thin sections and geochemistry by taking the shale from the upper sub-member of the Member 4 to the lower sub-member of the Member 3 of the Shahejie Formation in Eocene series in the Jiyang Depression as an example.The results show that three major types of lithofacies combinations, namely endogenous, mixed-source and exogenous are predominantly developed in the study area. The endogenous lithofacies combination is primarily formed in a sedimentary environment of shallow to semi-deep lake settings with high salinity of water bodies and limited supply of external clastic material sources. The mixed-source lithofacies combination is mainly formed in a sedimentary environment of semi-deep to deep lake settings with relatively high salinity and relatively balanced internal and external material supply. The exogenous lithofacies combination is predominantly formed in a sedimentary environment of freshwater to brackish water with an ample supply of external material sources. Overall, the co-evolution of paleoclimate and paleowater medium controls the vertical evolution of shale lithofacies combinations, while the joint evolution of paleotopography and paleosource controls the zonal and regional distribution of shale lithofacies combinations. The annular co-evolution of the sedimentary environment controls the annular development of lithofacies combinations on the plane. As the basic unit of exploration deployment, the research findings on shale lithofacies combinations have significant guiding significance for shale oil exploration.

Microporous structure of the Longmaxi Formation shale reservoirs in southern Sichuan Basin and its effect on adsorption capacity

LI Shuaizhi, LIU Chenglin, LIU Wenping, HE Yubo, LIU Jia, XU Liang

2025, 32(2):  22-32.  DOI: 10.3969/j.issn.1006-6535.2025.02.003

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Shale gas primarily exists in an adsorbed state on the surfaces of organic matter and shale mineral particles. To enhance the understanding of the nanoscale micro-and meso-porous structures within the first sub-bed, first sub-member of the Longmaxi Formation and to compare the differences in the impact of two types of pore structures on shale gas adsorption capacity, this study employed argon ion polishing-field emission scanning electron microscopy, low-pressure N₂/CO₂ adsorption, and CH₄ isothermal adsorption experiments, analyzed the differences in micro porous structure and meso porous structure and pore size distributions among various shale lithofacies, established the relationship between micro porous structure and meso porous structure and shale gas adsorption capacity, and compared the contributions of the two types of pores to shale gas adsorption capacity. The study shows that: the Longmaxi Formation shale predominantly develops micropores, with dominant pore size ranging from 0.4 to 0.6 nm and 0.8 to 1.0 nm, and has a relatively underdeveloped meso porous structure. The argillaceous shale has the largest micropore specific surface area, while the calcareous shale has the largest meso pore specific surface area. The argillaceous shale has both the largest micro porous structure and meso pore volumes. Shales of argillaceous, siliceous, carbonate, and mixed lithofacies all exhibit fractal characteristics in their pore structures, with the siliceous shale having the largest micropore fractal dimension and the calcareous shale having the largest meso pore fractal dimension. As the Total Organic Carbon (TOC) content increases, the fractal dimension, specific surface area, pore volume, and meso pore volume of shale micropores correspondingly increase. The TOC content, micro pore and meso pore specific surface areas, fractal dimensions, and pore volumes all positively contribute to shale gas adsorption capacity, with micropores having a stronger influence. The argillaceous shale with high TOC content, maximum micropore specific surface area, and pore volume is the most favorable lithofacies for shale gas adsorption capacity. The findings of this study have significant implications for the exploration and development of shale gas in the Longmaxi Formation in southern Sichuan Basin.

Comprehensive characterization of pore structure and multi-scale fractal features of medium-rank coal in Panjiang Mining Area,southwestern Guizhou

HU Yongzhong, XU Zaigang, DENG Ende

2025, 32(2):  33-41.  DOI: 10.3969/j.issn.1006-6535.2025.02.004

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In order to explore the pore structure and pore size fractal characteristics of coal rank coal in Permian Longtan Formation of Panjiang Mining Area in southwestern Guizhou,the pore structure was characterized through high pressure mercury injection experiment and low temperature nitrogen adsorption experiment.Moreover,the multi-scale characteristics of the pore structure of medium-rank coal were compared and analyzed based on fractal theory.The findings indicate that the micropores and small pores of medium rank coal in the study area are rather developed,the pore connectivity is good,and the pore fractal characteristics are significant.The comprehensive fractal dimension of medium-rank coal is capable of reflecting more effectively the metamorphic degree of medium-rank coal,and has a certain positive correlation with Langmuir volume and Langmuir pressure.To a certain extent,it reflects the deposition feature and desorption difficulty of coalbed methane,that is,the larger the fractal dimension of medium-rank coal,the more conducive to the development and utilization of coalbed methane.The findings of this study can provide valuable data and theoretical basis for further exploration and development in the field of research.

Accumulation characteristics and "sweet spot" evaluation of shale oil in Fengcheng Formation, Urho District, Junggar Basin

SONG Tao

2025, 32(2):  42-50.  DOI: 10.3969/j.issn.1006-6535.2025.02.005

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To clarify the geological characteristics of shale oil in Fengcheng Formation, Urho District, Junggar Basin, this study analyzed the deposition and reservoir performance of the formation based on the core samples, thin sections observation, and geochemical characteristics data, and conducted a dual "sweet spots" evaluation integrating geological and engineering aspects in consideration of brittleness and oil content characteristics. The study results show that: the Fengcheng Formation was deposited in a hypersaline, anoxic, and reductive environment, with the main reservoir rock types being saline fine-grained mixed sedimentary rocks. These rocks exhibit complex longitudinal variations, strong heterogeneity, and significant vertical differences in organic matter content, have an average organic matter content of 1.22%, with type Ⅱ₁ kerogen being predominant, indicating a mature to over-mature stage with high hydrocarbon generation potential under saline conditions. The reservoir spaces in Fengcheng Formation are primarily dissolution pores and micro-fractures, accounting for 40.00% and 39.45% respectively, characterized by fine skewness, poor sorting, large variations in displacement pressure, and high median pressures, typical of low porosity and low permeability tight reservoirs. The main oil-bearing rock types are laminated dolomitic mudstones and argillaceous dolomites. The first class "sweet spots" are characterized by high brittleness, large oil-bearing area, good physical properties, and a high degree of fracture development, mainly distributed at the bottom of the second and third sub-members of Fengcheng Formation, and at the middle and upper parts of the second sub member, the second class "sweet spots" bed primarily develops. The findings of this study have guiding significance for the development of shale oil in Fengcheng Formation of Junggar Basin.

Anomaly characterization of high heavy hydrocarbon fractions and rapid identification method of fluid properties in gas logging

HU Yitao, ZENG Tingxiang, CHEN Pei, ZHONG Peng, FU Qunchao, CHAI Hua, DU Kun

2025, 32(2):  51-58.  DOI: 10.3969/j.issn.1006-6535.2025.02.006

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In recent years, some exploratory wells in the western South China Sea oilfields have successively shown gas logging anomalies characterized by high heavy hydrocarbon fractions and low light hydrocarbon fractions. To address the issues of unclear understanding of the characteristics, unclear formation mechanisms, and difficulties in fluid property identification for such high heavy hydrocarbon fraction gas logging anomalies, statistical analysis was conducted on the gas logging fraction anomaly data in the study area to identify the causes of these anomalies, and research was also carried out on the identification of fluid properties using machine learning classification and prediction models. The analysis suggests that the main reason for these gas logging anomalies is the stimulation or destruction of oil reservoirs after their early formation, leading to secondary migration of oil and gas, during which light hydrocarbon fractions are lost in larger amounts, while heavy hydrocarbon fractions are lost less. The heavy hydrocarbon fraction gas logging anomalies are influenced by a combination of factors, including the degree of geological structural changes, the sealing properties of the cap rock and the properties of the crude oil. The random forest model demonstrates good training and predictive classification performance on the high heavy hydrocarbon fraction gas logging data set in the study area accurately and efficiently identifying fluid properties. This study provides a new approach from the perspective of gas logging technology for identifying reservoir stimulations and has significant guiding implications for oil and gas exploration and development.

Application of array acoustic wave SVP technology in fracture identification of horizontal shale gas wells in the southern Sichuan Basin

LIANG Xusheng

2025, 32(2):  59-65.  DOI: 10.3969/j.issn.1006-6535.2025.02.007

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Fracture serves as the important channel for the seepage of oil and gas, and their identification within shale reservoirs presents significant challenges. Considering the heterogeneity and propensity for natural fracture development in the Wufeng Formation and Longmaxi Formation shale reservoirs of the Southern Sichuan Basin, the SVP fracture processing technology has been utilized to identify information from array acoustic wave logging data, thereby assessing the degree of fracture development in the shale reservoirs. The study shows that: The array acoustic wave SVP processing results show a strong consistency with microseismic monitoring events. This technology is capable not only of evaluating the scale of fracture development in shale gas wells in the Southern Sichuan Basin but also, to some extent, assessing the correlation between fractures and the production capacity of shale gas wells. SVP analysis was conducted on four wells in the study area that had undergone production test, and the results indicated that wells with high reflection wave coefficients had higher gas production capabilities. This indicates that fractures can effectively communicate the reservoir modification volume, thereby enhancing the output of single wells. This study provides technical support for the evaluation of fractures in horizontal shale gas wells.

Reservoir Engineering

Dynamic characteristics of water breakthrough of fishbone multilateral well in bottom water reservoirs

CUI Chunxue, LIU Yuewu, DING Jiuge, ZHANG Guoqing, REN Yangqi, YANG Xiaofeng

2025, 32(2):  66-72.  DOI: 10.3969/j.issn.1006-6535.2025.02.008

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The efficient development of bottom-water oil reservoirs is significantly constrained by the bottom-water coning during the development process.To address this issue,the study focused on the fishbone multilateral wells in bottom-water oil reservoirs and established a dynamic prediction model for the bottom-water coning by applying theoretical methods from fluid mechanics in porous medium and reservoir engineering to investigate the distribution pattern of water breakthrough time and position along the wellbore trajectory,thus clarifying the dynamic characteristics of water breakthrough in fishbone multilateral wells and conducting a sensitivity analysis.The study results show that:the interflow interference and diversion effects between the main wellbore and multilateral wellbores result in lower flow rates in the angular region near the wellbore junction,where a larger vertical pressure gradient in the reservoir leads to earlier water breakthrough.Subsequently,the middle section of the main wellbore and the heel ends of the multilateral wellbores near the main wellbore experience water breakthrough,while the ends of the main wellbore and the toe ends of the multilateral wellbores have relatively later water breakthrough times.Increasing the water-shutoff height,oil-water density difference,main wellbore length,and branch angle can effectively mitigate the bottom-water coning/cresting.When the main wellbore length exceeds 400 m and the branch angle exceeds 30°,the increase in water breakthrough time slows down.It is more reasonable to position the wellbore height at 80% of the reservoir thickness.Heavy oil reservoirs are more prone to bottom-water cresting compared to light oil reservoirs.The research results provide significant practical guidance for oilfields to determine reasonable operating policies,delay water breakthrough time,and enhance water-free cumulative production and recovery efficiency.

Characterization and recognition of well test curves of multi-stage fractured horizontal wells in tight sandstone gas reservoirs

WANG Huiqiang, LI Mingqiu, CAO Zhenglin, DENG Qingyuan, YU Peng, SHI Erhan

2025, 32(2):  73-81.  DOI: 10.3969/j.issn.1006-6535.2025.02.009

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In response to the issue that there are certain differences in flow regime characteristics and curve morphology between the actual well test curves and theoretical curves of multi-stage fractured horizontal wells in tight sandstone gas reservoirs,a seepage model for multi-stage fractured horizontal wells was established.Theoretical well test curve charts were drawn to analyze the impact of fracture parameters on well test curves.Based on mine field examples, the characteristics of well test curves of multi-stage fractured horizontal wells in the tight gas reservoir of the Shaximiao Formation in the Tianfu Gasfield were analyzed.The study shows that Compared with the well test curves of traditional fractured horizontal wells,the early fracture bilinear or linear flow stage of multi-stage fractured horizontal wells is masked by the wellbore storage effect and skin effect.In the middle stage, only the characteristics of the radial flow stage are exhibited,and in the later stage,it transitions into the formation linear flow stage.The larger the fracture half-length and the more complex the fracture network,the more obvious the difference between the middle radial flow stage and the formation linear flow stage.The multi-stage fractured horizontal wells in the tight gas reservoir of the Shaximiao Formation in the Tianfu Gasfield are affected by the complex fracture network near the wellbore and the river channel boundaries.The flow regime can be divided into four stages:wellbore storage and skin reflection,radial flow,formation linear flow, and boundary reflection. This study provides a new approach for precise well test analysis of multi-stage fractured horizontal wells in tight sandstone gas reservoirs.

Productivity prediction method of tight reservoir based on data-driven approach

WANG Hongliang, LI Ning, LI Xin, WANG Zhiping, WU Xianghong, YAN Lin

2025, 32(2):  82-88.  DOI: 10.3969/j.issn.1006-6535.2025.02.010

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In view of the unclear main controlling factors of tight oil reservoir productivity and the large difference of single well production,the dynamic time warping algorithm and LightGBM algorithm are used to establish the main controlling factors analysis and production prediction method of tight oil productivity.This method can comprehensively take into account geological,engineering and development factors,rapidly identify the main controlling factors of tight oil well productivity and the production change mode,and then predict oil well productivity,which possesses strong universality.The research results are applied to the tight oil block in Qian′an Area.The results show that there are four kinds of oil well production change modes in this block,which are slow decline type,sharp decline type,fluctuation decline type and stable production type.The main controlling factors are the effective length of horizontal section,the thickness of producing oil layer,the control reserve multiplied by permeability divided by viscosity,oil protential,the density of fracturing section,fracture density,fracturing fluid intensity,sand to liquid ratio,sand strength,dynamic liquid interface and shut-in time.By using this method to predict the productivity of tight oil wells,the average accuracy is over 90%,and the boundaries of geological and engineering main control factors required for the cumulative oil production of single wells within 4 a to reach 0.5×10⁴ t and 1.0×10⁴ t respectively can be calculated.The research results have certain guiding significance for the optimization of tight oil development plan.

Molecular simulation of wettability of water-methane-carbon dioxide-carbon system

YONG Wei, WEI Zhijie, LIU Yuyang, WANG Deqiang, CUI Yongzheng, ZHANG Jian, ZHOU Wensheng

2025, 32(2):  89-94.  DOI: 10.3969/j.issn.1006-6535.2025.02.011

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To address the difficulty in conducting wettability studies at the molecular scale,molecular simulation methods were employed to investigate the wettability behavior of droplets in shale nanopores after interaction with the methane-carbon dioxide-carbon system (wettability was characterized by surface tension and contact angle).The results show that the proportion of CO₂ molecules, X_CO2,significantly affects the surface tension γ of the CH₄-CO₂-H₂O system.The surface tension γ decreases with increasing temperature and X_CO2,with a maximum reduction of approximately 40%.Further analysis revealed the variation of droplet contact angle with changes in CH₄ and CO₂ pressure.It was found that in a CH₄ environment,when the pressure exceeds 78 MPa,the droplet detaches from the solid surface,forming a contact angle of 180°,indicating that the shale pore surface reaches a completely hydrophobic state. In a CO₂ environment,the corresponding pressure for the shale surface to become completely hydrophobic is 12 MPa.The simulation results are consistent with relevant experimental data. Compared to CH₄, CO₂ exhibits stronger interaction with the shale surface, thereby displacing CH₄ attached to the solid surface and enhancing gas recovery.For CH₄-CO₂ mixtures, the contact angle shows a linear positive correlation with the proportion of CO₂ molecules.The research findings provide theoretical guidance on the relationship between wettability and enhanced recovery in shale.

Pattern of nanoemulsion imbibition and its applications in tight oil reservoirs

LIANG Xingyuan, HAN Guoqing, ZHOU Fujian, LIANG Tianbo, YUE Zhenduo, YANG Kai

2025, 32(2):  95-102.  DOI: 10.3969/j.issn.1006-6535.2025.02.012

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To address the unclear understanding of the imbibition patterns of nanoemulsions in tight reservoirs at the field scale, a numerical simulation method was employed to analyze the factors influencing the imbibition recovery rate from both laboratory and field scales. The results show that at the laboratory scale, as permeability increases, the imbibition recovery rate rises to 47% and then stabilizes; with increasing capillary pressure, the recovery rate gradually increases to 61%; and as the critical adsorption amount increases, the recovery rate initially stabilizes at 28% before decreasing to 2%. At the field scale, the imbibition recovery rate increases to 38%, 35%, and 11% with the rise in permeability, capillary pressure, and diffusion coefficient, respectively; and it decreases to 5% as the critical adsorption amount gradually increases. The variation patterns of factors influencing the imbibition recovery rate at the field scale differ from those at the laboratory scale, primarily because the smaller matrix volume and larger contact area between the core and fracturing fluid at the laboratory scale allow the fracturing fluid to enter all pores of the core, which does not reflect the actual field conditions. This study provides guidance for the design of fracturing fluid parameters in tight oil reservoirs.

Experiments on the effect of methanol and polyvinylpyrrolidone compound system to inhibit hydrate generation

YAO Ziyi, LIU Huaizhu, HE Shuiliang, ZHAO Kangning, LI Ling, LI Fangfang, MA Pan, WANG Jie

2025, 32(2):  103-109.  DOI: 10.3969/j.issn.1006-6535.2025.02.013

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The commonly used thermodynamic inhibitors in industry have issues such as large usage amounts,high costs,and severe pollution.To address such issues,based on the principle of synergistic inhibition by the combination of thermodynamic and kinetic inhibitors,the effectiveness and variation patterns of the methanol and polyvinylpyrrolidone (PVP) compound system in inhibiting hydrate formation were studied.The study shows that Methanol molecules inhibit hydrate formation through their hydrophilic hydroxyl groups and lipophilic methyl groups.The amount of hydrate formed decreases and may even disappear with increasing methanol usage,with the optimal inhibitory effect of methanol on hydrate formation achieved at a mass fraction of 10.00%.PVP inhibits hydrate nucleation and growth through internal dissolution and surface adsorption.The effectiveness of PVP in inhibiting hydrate formation is determined jointly by its relative molecular mass and mole fraction,and there exists an optimal mass fraction for the best inhibitory effect.Within a certain range,in inhibitor solutions with the same mole fraction,the inhibitory performance of PVP against hydrate formation increases with increasing relative molecular mass.The compound system of PVP and methanol is more effective in inhibiting hydrate formation than using methanol alone at the same mass fraction,demonstrating good synergistic inhibitory performance.The combined use of different types of inhibitors can both reduce costs and enhance the effectiveness of inhibiting hydrate formation,ensuring the safe production of gas wells.

Development and performance evaluation of CO₂-responsive preformed particle gel

DENG Jia′nan, ZHENG Hao, GAO Yuanxian, BI Wenliang, ZHAO Honghao, HE Jiayuan, LU Guiwu, ZHANG Xiao

2025, 32(2):  110-116.  DOI: 10.3969/j.issn.1006-6535.2025.02.014

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In response to the issue of preformed particle gel (PPG) degradation and dehydration caused by the acidic environment formed during CO₂ flooding,a CO₂-responsive preformed particle gel (CR-PPG) with a triple crosslinked network was prepared using N,N-dimethylacrylamide (DMAA),vinylimidazole (VIZ),and N-vinylpyrrolidone (NVP) as the main raw materials,along with the organic crosslinking agent N,N′-methylenebisacrylamide (MBA) and the nano-crosslinking agent vinyl silica nanoparticles (VSNPs),through aqueous solution polymerization.System optimization,CO₂ responsiveness testing,conductivity testing,rheological testing,and core displacement experiments were conducted.The study shows that the optimal ratio of the monomers DMAA,VIZ,and NVP was found to be 2∶2∶1.The CR-PPG exhibited excellent CO₂ responsiveness and mechanical strength,demonstrating efficient plugging and profile control capabilities during CO₂ flooding.The CO₂ responsiveness mechanism of CR-PPG is attributed to the protonation effect of the tertiary amine groups in its structure under CO₂ acidic conditions.This study provides an important basis for plugging and profile control operations during CO₂ flooding.

Comparison experiment of heat transfer effect between CO₂-plume geothermal system and water-based enhanced geothermal system

FAN Yangjie, FU Meilong, LIU Yiwen, LI Guojun, SU Zhihao

2025, 32(2):  117-122.  DOI: 10.3969/j.issn.1006-6535.2025.02.015

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To address the issues of flow loss and resource waste during geothermal extraction in water-based enhanced geothermal systems,CO₂ was selected as the heat transfer fluid for the CO₂-plume geothermal system. Through methods such as heat transfer experiments,dissolution experiments,and post-CO₂ flooding gas-water relative permeability curve evaluation experiments,the heat transfer performance of supercritical CO₂ under different conditions and the dissolution effect of CO₂ aqueous solution on rocks were quantitatively assessed. Additionally,the heat-carrying capacity and heat extraction rate of CO₂ and water were evaluated. The study shows that under the condition of the same mass flow rate of the heat transfer fluid,when the injection temperature is 24 ℃,the heat transfer efficiency of CO₂ is over 27% higher than that of water;when the injection temperature is 35 ℃,the heat transfer efficiency of CO₂ is over 8% higher than that of water,indicating that CO₂ has higher heat transfer efficiency and heat-carrying capacity than water. When the formation pressure of the gas reservoir rises to 25 MPa,the heat capacity value of CO₂ is 0.45 times that of water,and its mobility is 2.5 times that of water,making CO₂′s heat extraction advantage more pronounced. The dissolution reaction of CO₂ with chlorite is strong,leading to an increase in the pore space and permeation channels of the core,effectively enhancing the reservoir permeability,strengthening the convection of fluids in the pores,and improving the heat transfer efficiency. This study provides a fundamental theoretical basis for the application and promotion of CO₂-plume geothermal resource extraction technology.

Drilling & Production Engineering

Predictive model for sulfur precipitation in high-sulfur gas wells considering phase change

LI Peng, DENG Hucheng, ZHANG Chuyue, LU Jie, ZHANG Xiaoju, HUANG Liang

2025, 32(2):  123-130.  DOI: 10.3969/j.issn.1006-6535.2025.02.016

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To accurately predict the wellbore pressure,temperature,and sulfur precipitation patterns in high-sulfur gas reservoirs,based on the law of conservation of mass,momentum and energy,a predictive model for wellbore pressure,temperature,and sulfur precipitation in high-sulfur gas reservoirs was established with the comprehensive considerations of the influence of well deviation angle and gas-liquid-solid phase characteristics of sulfur;the finite difference method and iterative techniques model were used to solve the model;the compressibility factor algorithm was optimize based on field data;predictions of wellbore pressure,temperature,and sulfur precipitation trends were made after validating the accuracy of the model;and the influencing factors of wellbore pressure and sulfur precipitation patterns were studied.The results show that using the DPR algorithm for calculating the compressibility factor yields the smallest average relative errors in predicting wellbore pressure and temperature,at 0.93% and 1.06%,respectively.The fluid flow inside the wellbore is characterized as either single-phase gas or gas-solid two-phase flow,with no gas-liquid two-phase flow present.With the increase of gas production rates,H₂S content,initial solubility of sulfur particles,and the decrease of well inclination,the variation range of wellbore pressure changes mounts gradually.Higher gas production rates result in sulfur precipitation closer to the wellhead with larger volumes of precipitated sulfur;higher H₂S content leads to sulfur precipitation closer to the wellhead with smaller volumes of precipitated sulfur;larger initial solubilities of sulfur particles and greater well inclinations push the precipitation location further from the wellhead,resulting in larger volumes of precipitated sulfur.This research provides technical support for the efficient development of high-sulfur gas reservoirs.

Study and application of super mass transfer technology for accelerated polymer dissolution

ZHAO Wensen, ZHANG Jian, SHU Zheng, ZHU Shijie

2025, 32(2):  131-136.  DOI: 10.3969/j.issn.1006-6535.2025.02.017

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Due to the limited space on offshore platforms, the large-scale application of polymer flooding technology in offshore oilfields is restricted. Accelerated polymer dissolution is one of the key technologies to support the scaled implementation of polymer flooding in offshore oilfields. To this end, optimization studies have been conducted on factors such as the packing pore size of the enhanced super mass transfer rapid dissolution device, the mass transfer factor, the structure of the mass transfer ring, and the feed rate, in order to obtain the optimal application parameters. The study shows that smaller packing pore sizes and higher mass transfer factors lead to faster polymer dissolution. However, excessively small pore sizes and high mass transfer factors can cause significant viscosity loss. Different combinations of mass transfer rings result in varying degrees of reduction in polymer dissolution time and viscosity loss of the polymer solution. The best mass transfer effect is achieved with a mass transfer ring structure of 300 μm × 1 038 (outer ring) + 200 μm × 1 307 (inner ring). The feed rate has a relatively minor impact on the dissolution time and viscosity of the polymer. The site application results show that after the introduction of the enhanced super mass transfer rapid dissolution device, the dissolution time of polymer mother liquor with a mass concentration of 2 500 mg/L is reduced from 41 minutes to 19 minutes. The footprint of the polymer preparation and injection system is decreased by 50.23%, and the operational mass is reduced by 53.6%. The system has successfully achieved miniaturization and high efficiency, effectively saving platform space. This technology provides a technical guarantee for the efficient application of polymer flooding in offshore oilfields.

Development of new variable viscosity copolymer fracturing fluid and its application

MA Shou, DI Shiying, WEI Yuhua, CHENG Shiqing, LIU Mingming, MIAO Li′nan

2025, 32(2):  137-144.  DOI: 10.3969/j.issn.1006-6535.2025.02.018

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A new copolymer solution was developed and its indoor performance evaluation and field application were conducted.Deep shale gas development often saw technical challenges such as poor sand-carrying capacity,low width generation capasity,and complex variable viscosity processes of conventional fracturing fluids.To address these challenges,new mononers S1 and T1 were developed based on the characteristics of deep shale reservoirs in the Dingshan Block of southern Sichuan and according to the requirements of construction.A certain amount of acrylamide,sodium 2-acrylamido-14-alkyl sulfonate,and monomers S1 and T1 were copolymerized to form new copolymer solution.The copolymer solution underwent indoor performance evaluation and field application.The results show that the copolymer solution has a strong viscosifying effect;at a low mass fraction(0.005%),the molecules exhibit monodispersity and low viscosity,while at a high mass fraction(0.500%),the molecules form a spatial network structure through intermolecular forces,demonstrating strong elasticity.The copolymer solution with medium and high mass fractions exhibits good sand-carrying capacity,with a sedimentation velosity of 0.17 cm/min in a 1.500% mineralized water solution at 60 ℃;additionally,it also has good gel-breaking ability and salt resistance.Field applications show that the new real-time variable viscosity copolymer fracturing fluid can effectively switch between low,medium,and high viscosity in real-time,enhancing fracturing and sand-carrying capabilities.This research provides theoretical guidance and technical support for improving deep shale gas fracturing effects.

Optimized design method and application of nitrogen drilling for horizontal wells in coalbed methane reservoirs

TAN Zhanglong, ZHANG Linqiang, SHAO Mingren, WANG Chunpeng, LI Xiaolong, ZHOU Lu, YANG Hao

2025, 32(2):  145-153.  DOI: 10.3969/j.issn.1006-6535.2025.02.019

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In response to issues such as wellbore leakage, coalbead water sensitivity, and pulverized coal plugging in the Yuwang coalbed methane reservoir, a nitrogen drilling software was independently developed. Suitable gas injection parameter calculation models and friction torque calculation models for coalbed methane nitrogen drilling were established. The calculation methods for construction parameters such as gas injection volume, injection pressure, friction torque under different working conditions, and erosion wear of the drill string were clarified. The drilling tools for horizontal well nitrogen drilling technology were analyzed and selected, and one directional test well and one horizontal production test well were drilled in the Yuwang Block in Yunnan. During the actual construction process, the calculated injection pressure values were within 10% error range of the actual values. No accidents occurred due to friction torque and erosion wear of the drilling tools. The mechanical drilling speed reached 11.64 m/h, which is three times the drilling speed of the adjacent wells, verifying the high accuracy of the software. This study provides a reference for nitrogen drilling in coalbed methane reservoirs.

Field practice of low free-water activity water-based drilling fluid technology for lacustrine shale gas horizontal wells in Yan′an Area

WANG Bo, LIN Jin, WU Jinqiao, WU Huimin, MA Zhenfeng, YANG Xianlun, WANG Jintang

2025, 32(2):  154-161.  DOI: 10.3969/j.issn.1006-6535.2025.02.020

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To address the challenge of wellbore instability in lacustrineshale gas horizontal wells, a low free-water activity water-based drilling fluid system PSW-2 for shale gas horizontal wells was developed based on the principles of reducing liquid activity, inhibiting hydration, and enhancing shale sealing. Rheological, sealing, and inhibition tests were conducted, along with evaluations of practical application effectiveness. The study shows that the API filtration loss of PSW-2 drilling fluids with different densities is below 3.2 mL, with a sealing efficiency greater than 86%, a rolling recovery rate higher than 95%, and a linear expansion rate below 1.38%. The fluid exhibits good rheological properties, sealing capability, and inhibition performance. Field practice indicates that the PSW-2 drilling fluid maintains stable performance during application, with the API filtration loss kept below 3.0 mL. It provides effective wellbore stability for long sections of mudstone, carbonaceous mudstone and shale, which has achieved an 87.5% success rate in 8 shale gas horizontal wells. Future development trends include enhancing the sealing capability for nano-scale and micro-scale fractures and improving the sealing and collapse prevention ability of drilling fluids through composite weighting methods, while further reducing drilling fluid costs. This technological achievement provides technical support for low-cost and efficient drilling in shale gas horizontal wells.

Development and application of a new type of insulated tubing centralizer for offshore heavy oil thermal production wells

GU Qilin, SONG Hongzhi, LIN Tao, ZHANG Baoling, JI Zhengxin, JIANG Qun, AN Hongxin, FANG Qingchao

2025, 32(2):  162-167.  DOI: 10.3969/j.issn.1006-6535.2025.02.021

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Offshore heavy oil thermal production wells are often directional or horizontal wells with large inclination angles. Under the influence of gravity, the steam injection string may contact the inner wall of the casing, leading to a decrease in the thermal insulation effect, especially at the thermal insulation coupling positions, and resulting in significant heat loss. To address this issue, a new type of insulated tubing centralizer was developed, and its thermal insulation and temperature-pressure resistance performance were tested. The centralizer mainly consists of a thermal insulation mechanism, a centralizing mechanism, and a fixing mechanism. The thermal insulation mechanism is provided with a composite thermal insulation structure designed to ensure thermal insulation functionality. The centralizing mechanism is designed with multiple centralizing blocks and combined cylindrical springs evenly distributed circumferentially, ensuring elastic centralizing functionality and guaranteeing the centralization effect of the string. Indoor performance tests indicate that the centralizer can withstand temperatures of 350 ℃ and pressures of 21 MPa, with a thermal insulation rating of Class D, and it also has good resistance to contraction when encountering obstacles. The site application results show that the new insulated centralizer ensures the seating and sealing effect of the packer, solves the problem of the steam injection string "lying against the wall" in offshore thermal production horizontal wells, effectively reduces the heat loss in the wellbore, and protects the casing and cement sheath. This technology can provide strong technical support and assurance for the safe and efficient thermal production development of offshore heavy oil oilfields.

Analysis of formation pressure evolution patterns and influencing factors for CO₂ storage

WANG Dian, LI Jun, LIAN Wei, LIU Xianbo, ZHANG Juncheng, GUO Shaokun

2025, 32(2):  168-174.  DOI: 10.3969/j.issn.1006-6535.2025.02.022

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To investigate the evolution of reservoir pressure during CO₂ storage and to prevent wellbore leakage during the well drilling and completion within the storage site, this study established a numerical model of the CO₂ reservoir-caprock system based on the theory of multiphase flow through porous media to clarify the characteristics of the pressure difference evolution during the storage process and to analyze the influence patterns of key engineering geological factors.The study shows that: the injection of CO₂ leads to an increase in pressure within both the reservoir and caprock.After injection ceases,the reservoir pressure gradually dissipates,with the pressure change range significantly exceeding the radius of CO₂ diffusion.The caprock pressure response is delayed,causing dynamic evolution of interbed pressure differences,and there is a peak in pressure difference during the early stages of injection,which can easily lead to wellbore leakage.The peak pressure difference is negatively correlated with the distance from the injection well,reservoir temperature and pressure, reservoir pore permeability,and reservoir thickness,and positively correlated with the injection rate in a linear relationship.For large-scale CO₂ geological storage,controlling the distance between CO₂ injection wells and completion wells,and selecting injection points in deep-buried,thick,high-permeability,and high-porosity beds can help reduce the risk of wellbore leakage.The results of this study can provide a reference for CO₂ geological storage.