Table of Content

25 August 2025, Volume 32 Issue 4

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Summary

Development status and key technologies of underground hydrogen storage

PAN Bin, YANG Yawen, CHEN Ting, YANG Yongfei, SONG Xianzhi, WAN Jifang, CHEN Hongkun, CUI Shaodong

2025, 32(4):  1-13.  DOI: 10.3969/j.issn.1006-6535.2025.04.001

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Hydrogen energy is a crucial supporting technology for promoting energy transition and achieving the "carbon peaking and carbon neutrality" goals. To achieve the rapid development of the hydrogen economy, the bottleneck of large-scale hydrogen storage technology must be broken. Salt caverns, depleted oil and gas reservoirs, and saline aquifers offer large storage space, good sealing, and enormous hydrogen storage potential, giving rise to the underground hydrogen storage (UHS) strategy. In recent years, scholars at home and abroad have conducted a certain degree of basic research and field testing on UHS. Based on previous research, this paper systematically reviews the domestic and international development status of UHS from the perspectives of necessity, feasibility, and key scientific and technological issues, clarifies the similarities and differences between underground hydrogen storage, carbon storage, and natural gas storage, sorts out the key scientific problems of UHS, and points out the focus areas for future research. This study identifies current limitations and future development directions, providing important guidance and impetus for the development of UHS technology.

Status and prospects of machine learning methods for predicting hydrocarbon production

XIE Kun, TIAN Xuanshuo, LIU Changlong, SHAO Ming, LIU Yanchun, GAO Mingxuan, YUAN Shiliang, ZHANG Baoyan

2025, 32(4):  14-24.  DOI: 10.3969/j.issn.1006-6535.2025.04.002

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Affected by the complex variability of reservoir physical properties, fluid characteristics, and technological measures during hydrocarbon development, the utilization of production data largely depends on the professional experience of petroleum scientists and engineers, resulting in high computational and time costs. This makes it difficult to meet the demands of efficient modern hydrocarbon reservoir development, necessitating the discovery of more efficient methods for hydrocarbon production prediction. In recent years, machine learning methods represented by deep neural networks, random forest algorithms, and transfer learning have achieved significant application results in hydrocarbon production prediction due to their unique advantages in handling high-dimensional data, capturing long-term dependencies in time-series data, and extracting development data features. This paper analyzes the principles, advantages, and disadvantages of commonly used machine learning methods for hydrocarbon production prediction, elaborates on the current application status of these methods in the field of hydrocarbon production prediction, summarizes potential issues during application, and prospects the development trends of hydrocarbon production prediction methods. In the future, on one hand, research on integrating physical constraints into machine learning models should be strengthened to enhance model interpretability and avoid overly idealized prediction results; on the other hand, algorithms and transfer learning techniques suitable for small-sample scenarios should be developed to fully utilize historical production data, providing better data analysis and technical support for hydrocarbon production prediction. This research has theoretical significance for improving intelligent hydrocarbon production prediction technology.

Geologic Exploration

Investigation on inversion methods for tracing the sources of shale nanopores via low-temperature ashing

SONG Dangyu, YANG Chunlin, LI Yunbo, QIAO Yu

2025, 32(4):  25-32.  DOI: 10.3969/j.issn.1006-6535.2025.04.003

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To address the limitations of traditional methods in studying shale nanopore sources,low-temperature ashing experiments were conducted.This study analyzed pore changes and transformation during ashing,established an inversion method for tracing organic and inorganic sources of shale micropores and mesopores,and applied such method to analyze the organic and inorganic sources of nanopores in marine-continental transitional shales at the eastern margin of the Ordos Basin.The study results show that organic matter contributes on average 45.77% to micropore volume and 44.62% to specific surface area,and 7.77% to mesopore volume and 12.85% to specific surface area.Organic micropores and mesopores are approximately 18.0 and 1.7 times larger than inorganic ones.Compared with the traditional correlation analysis method,the low-temperature ashing inversion method overcomes the influence of pore heterogeneity in organic matter on the analysis results,and is able to effectively quantify the true pore source of organic matter in each sample;the source of the shale′s micropores and mesopores is mainly controlled by the content of organic matter,with a more pronounced effect on micropores.This method enhances our understanding of shale gas storage mechanisms,free methane content,and release efficiency.

Exploration breakthrough and enlightenment of the Yacheng Formation in the Yacheng 13-1 Low Uplift, Qiongdongnan Basin

REN Lijuan, HE Xiaohu, ZHANG Yazhen, XIE Chao, WANG Lifeng, CAI Quansheng

2025, 32(4):  33-40.  DOI: 10.3969/j.issn.1006-6535.2025.04.004

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In recent years, significant breakthroughs have been made in natural gas exploration of the Yacheng Formation in the Yacheng 13-1 Gasfield. To further summarize geological understanding of Yacheng Formation accumulation and promote field expansion and reserve growth, based on new drilling, seismic, and analytical test data, the geological conditions for accumulation in the Yacheng Formation of the Yacheng 13-1 Gasfield were systematically analyzed. The results indicate that the Yacheng Formation reservoirs in the Yacheng 13-1 Gasfield are mainly braided river delta channel sandstones and conglomerates, with large-scale sand body development and good physical properties. The structural top is covered by Meishan Formation mudstone, and the updip direction of the flank is segmented by mudstone barriers, forming a good reservoir-seal combination, representing a typical structural-stratigraphic trap. Since the trap is located at the structural high of the Yacheng Formation, it benefits from dual hydrocarbon supply from source rocks in the Yanan Sag and the Yinggehai Basin, providing excellent conditions for hydrocarbon migration and accumulation. The breakthrough of Yacheng Formation natural gas in Well YC13-10-C also confirms the characteristics of differential enrichment and three-dimensional accumulation of the Yacheng Formation in the Yacheng 13-1 Gasfield. Therefore, around existing gas-bearing structures or gas reservoirs, conducting three-dimensional exploration research on structural-stratigraphic traps from high to low positions will be an important direction for the next step of rolling natural gas exploration within this area and similar gas reservoirs. This understanding has certain guiding significance for the next step of exploration in the Yacheng 13-1 Gasfield.

Microscopic pore structure characteristics and multi-dimensional parameter classification evaluation of low-permeability reservoirs in the Shahejie Formation, Bozhong Oilfield

XIAO Dakun, FAN Tingen, YANG Erlong, FAN Hongjun, ZHANG Jingjun, ZHANG Lijun

2025, 32(4):  41-49.  DOI: 10.3969/j.issn.1006-6535.2025.04.005

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Research on the microscopic pore-throat characteristics and classification of the Shahejie Formation reservoirs in the Bozhong Oilfield is limited,failing to provide findings and insights with guiding significance for exploration and development.To address this issue,based on the analysis of high-pressure mercury injection (HPMI),oil-water relative permeability,and core NMR experimental results,the macroscopic physical properties,microscopic pore structure,and seepage capacity of low-permeability reservoirs in the Bozhong Oilfield were finely characterized and classified through single-factor discussion;reservoir comprehensive classification and evaluation were achieved using parameter optimization,comprehensive classification index calculation,K-means clustering,and other technical methods.The results indicate that the low-permeability reservoirs of the Shahejie Formation are a set of low-porosity, low-permeability reservoirs dominated by fine-grained feldspathic lithic sandstone with small pores and fine throats,with an average porosity of 11.40% and an average permeability of 1.90 mD;the reservoir space types are mainly secondary intergranular dissolved pores and intragranular dissolved pores,primarily developing sheet-like and curved sheet-like throat types.According to the comprehensive evaluation method and comprehensive classification index system, the low-permeability reservoirs are divided into three classes:Class Ⅰ are high-quality reservoirs with good reservoir quality and seepage capacity,Class Ⅱ are medium reservoirs,and Class Ⅲ are relatively poor reservoirs.This evaluation scheme is significant for predicting favorable reservoir areas and formulating development plans.

Distribution and hydrocarbon accumulation characteristics of Maokou Formation karst reservoirs in southwestern Sichuan Basin

LI Suhua, JIA Huofu, LU Qijun, LI Rong, SU Chengpeng, ZHU Lan

2025, 32(4):  50-57.  DOI: 10.3969/j.issn.1006-6535.2025.04.006

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To address the unclear understanding of the distribution and hydrocarbon accumulation characteristics of Maokou Formation karst reservoirs in southwestern Sichuan Basin,this study integrated geological, drilling, logging, and 3 D seismic data, classified the karst reservoirs, selected seismic attributes for distribution prediction, and analyzed the hydrocarbon accumulation relationships of different karst reservoir types. The study shows that the study area, located in a favorable paleogeomorphic unit, features four types of karst reservoirs developed: top karst, interbed karst, fault-associated karst, and karst collapse. Seismic texture entropy attributes effectively characterize interbed karst bodies and karst collapse. The hydrocarbon accumulation mode of the study area is "self-sourced and self-stored, sourced in lower part and stored in upper part, with efficient transport via faults and fractures." The distribution of Maokou Formation gas reservoirs is jointly controlled by paleogeomorphology, karst reservoir distribution, and fault and fracture systems. The research findings provide crucial support for further Maokou Formation exploration in the area.

Lithology logging identification method and application to carbonate reservoirs based on improved Stacking algorithm

LUO Shuiliang, QI Yingqiang, TANG Song, RUAN Jifu, GAO Da, LIU Qianqian, LI Sheng

2025, 32(4):  58-67.  DOI: 10.3969/j.issn.1006-6535.2025.04.007

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Conventional lithology identification methods for carbonate reservoirs in the Central Sichuan Area have low accuracy and weak model generalization. To address this, a lithology identification method in well logging based on an improved Stacking algorithm is proposed. This method integrates the advantages of multiple machine learning models, optimizes feature weighting strategies, and enhances the extraction of key information from logging curves, improving the accuracy and stability of complex lithology identification. Compared to traditional methods, it better captures the nonlinear relationships in logging data and reduces prediction confusion between lithology categories. The study results show that the accuracy of this method in identifying lithologies in central Sichuan carbonate reservoirs reaches 96%, an improvement of over 6 percentage point compared to traditional models. It also has lower average relative errors and better prediction performance. Combined with an efficient computing framework, the improved Stacking algorithm significantly enhances training and prediction efficiency, making lithology identification both efficient and reliable. This method effectively identifies complex lithologies and provides a valuable reference for carbonate reservoir lithology identification.

Accumulation conditions and main controlling factors of Triassic Chang 1+2 low-permeability sandstone reservoirs in the Mahuangshan-Buziwan Area, Ordos Basin

ZHANG Liang, QI Yuan, SUN Yuxi, HE Yiping

2025, 32(4):  68-76.  DOI: 10.3969/j.issn.1006-6535.2025.04.008

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Low-permeability sandstone reservoirs in the Triassic Chang 1+2 oil reservoirs are widely developed in the Mahuangshan-Buziwan area in the central and western Ordos Basin, with great potential for hydrocarbon exploration. However, the hydrocarbon accumulation conditions and main controlling factors remain unclear. To address this, an analysis of hydrocarbon accumulation conditions and the main controlling factors of oil reservoir enrichment was conducted based on core samples, cast thin sections, and logging data. The results show that The oil source for the Chang 1+2 reservoirs in the study area is the Chang 7 deep-lacustrine mud-shale. Hydrocarbons migrate through faults and multi-phase superimposed sand bodies. Unconformities, low-amplitude nose structures, dominant facies belts, and lithological properties are the key factors controlling the enrichment of the Chang 1+2 reservoirs. Under the blocking effect of unconformities and low-amplitude nose structures, the reservoirs continue to migrate towards the southeast, with the richest hydrocarbons in areas with dominant facies belt and lithological properties. The reservoirs have the characteristics of "unconformity blocking, sandbody-fault guidance, nose-controlled reservoirs, and lithological control of enrichment". The research provides a theoretical basis for predicting low-permeability reservoirs in the area.

Fault evolution and hydrocarbon significance in the Changling Fault-Depression

LIU Jiayu, LI Tao, YANG Guang, HU Jia, ZHANG Jiachang, CAI Yuxun

2025, 32(4):  77-86.  DOI: 10.3969/j.issn.1006-6535.2025.04.009

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To clarify the tectonic features of the major control faults of the Changling Fault-Depression and the influence of their activity on hydrocarbon accumulation, this article analyzed the activity characteristics of the major control faults of each depression using growth index, paleo-displacement, and activity rate through the fine interpretation of the key seismic profiles of the Changling Fault-Depression and the restoration analysis of the balanced profile, and discussed the influence of the fault activity on the evolution of each depression in the Changling Area, the formation of the trap, and the formation of the oil and gas reservoirs. The study shows that the major control faults of the Changling Fault-Depression have experienced multi-phase activity with inheritance, connecting multiple series of strata and providing favorable conduits for hydrocarbon migration and accumulation. At the syn-rift stage, active faulting enabled large-scale oil generation from Shahezi Formation source rocks, with lateral and vertical migration along the major faults. At the rift attenuation stage, most faults became syn-sedimentary due to tensional stress, forming local syn-sedimentary antic, reverse drag structures, and nosing structures. At the post-rift stage, fault activity declined or ceased, with most faults acting as seals. At the inversion stage, faults were compressed into inverted faults, causing hydrocarbon reservoir adjustment andremigration. The Changling Depression has an east-west-trending "three grabens interspersed with two horsts" zonation. Structural evolution differences among depressions affect the accumulation mode of depressions in the Changling Fault-Depression. This study enhances understanding of the tectonic features of the major control faults of the Changling Fault-Depression and offers insights into evaluating the impact of such faults on accumulation modes.

Reservoir Engineering

Effect of thermochemical fluids on fracturing pressure in tight reservoirs

LAI Fengpeng, ZHANG Haonan, CAO Longtao, LIU Kaiyuan, ZHAO Qianhui, MIAO Lili

2025, 32(4):  87-93.  DOI: 10.3969/j.issn.1006-6535.2025.04.010

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Aiming at the challenges in reducing fracturing pressure to enhance fracturing efficiency in the field of efficient unconventional hydrocarbon development,this study employs mechanism analysis,numerical simulation,and comprehensive comparison to investigate the selected exothermic reaction system of ammonium chloride and sodium nitrite (NH₄Cl-NaNO₂). It clarifies the temperature and pressure variation patterns generated by this exothermic system in tight sandstone cores and its impact on rock mechanical parameters,and compares this system with conventional hydraulic fracturing regarding fracturing pressure and fracture initiation. The results indicate that the NH₄Cl-NaNO₂ exothermic system can generate a maximum temperature of 133 ℃ and a high pressure of 11 MPa in the core.Simulation results align with laboratory experiments,showing that this system can effectively increase the Young′s modulus and reduces the Poisson′s ratio of tight sandstone.Compared with conventional hydraulic fracturing, the rock fracturing pressure is reduced by 23.76%.This research is significant for promoting the efficient development of unconventional hydrocarbons and advancing the application level of thermochemical fluid fracturing technology.

Formation mechanism of CO₂ channeling fracture network in ultra-low permeability reservoirs based on diversion critical energy

LIU Zhiyuan, ZHAO Haifeng, GAN Guipeng, ZHANG Wang

2025, 32(4):  94-103.  DOI: 10.3969/j.issn.1006-6535.2025.04.011

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Aiming at the serious channeling during CO₂ flooding and the lack of a mechanical mechanism explanation for channeling formation,by analyzing the energy evolution law of CO₂ channeling fracture network formation in tight sandstone during CO₂ flooding in ultra-low permeability reservoirs,the critical energy law for the simultaneous diversion of both ends of natural fracture-type channeling pathways with accumulated injection energy was studied.Furthermore, an energy criterion for the formation of channeling fracture networks was established.The applicability and accuracy of this criterion were verified by tracer dynamic monitoring results of field CO₂ channeling.The study results show that critical energy is positively correlated with natural fracture size,stress intensity factor,etc.,negatively correlated with elastic modulus, and exhibits a trigonometric function relationship with its own dip angle and wellbore angle;the energy required for channeling fracture network connectivity increases with increasing injection pressure and injection rate;by comparing with tracer monitoring of channeling in two well groups,it was found that this energy criterion is applicable to inter-well distances of about 300 m.This energy criterion can avoid complex fluid-solid coupling calculations at the front of the channeling pathway and compensate for the defect of classical stress criteria in reflecting the effect of action time,providing mechanical mechanism support for CO₂ channeling in ultra-low permeability reservoirs.

Evaluation and application of an air-assisted microbial flooding thickening nutrient activation system for heavy oil reservoirs

LIU Xiaoli, LI Yang, BAI Lei, MA Yanqing, MA Ting, JIANG Zhenxue, WAN Yunyang

2025, 32(4):  104-111.  DOI: 10.3969/j.issn.1006-6535.2025.04.012

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The L-9 Reservoir in Xinjiang is a thin-layer sandstone ordinary heavy oil reservoir with edge and bottom water. Due to the influence of edge/bottom water and CaCl₂ water type, conventional chemical flooding systems are not applicable. To address this, a field test of air-assisted microbial flooding was carried out for enhanced oil recovery. During the test, to curb bottom-water coning and water channeling in high-permeability channels, and to expand the sweep volume of microbial flooding, reservoir fine geological modeling, and tracer monitoring numerical simulation techniques were used to identify preferential migration pathways. It was found that the remaining oil saturation was high on both sides of these pathways. Then, the compatibility of the thickening nutrient activation system (mainly bio-polysaccharides) with the reinjected wastewater on site and formation water was assessed. Also, the activation effect of the system on major oil-producing bacteria and the rule of changes in microbial community structure during activation were studied. The results show that The thickening nutrient activation system without additives shows high viscosity and stability, with a core plugging rate of 93.1% and an enhanced oil recovery of 15.5 percentage points. After adding the activator, the concentration of oil-producing function genes and total bacteria increased by 1-2 orders of magnitude, promoting the degradation of the thickening system. After injecting the thickening nutrient activation system, high-permeability channels were effectively blocked, achieving good oil-increase and water-reduction effects. This research offers useful guidance for the regulation of microbial flooding in heavy-oil reservoirs during the high-water-cut period.

Evaluation method and control countermeasures for inter-well steam channeling in multi-cycle steam huff and puff

WANG Bo, LI Deru, TANG Lei, LI Changhong, ZHAO Changxi, HAO Lina, QU Han, DENG Haokun

2025, 32(4):  112-121.  DOI: 10.3969/j.issn.1006-6535.2025.04.013

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Steam channeling occurs during steam injection development of heavy oil reservoirs, severely impacting the effectiveness of steam injection development. However, there are currently no quantitative indicators for describing inter-well steam channeling pathways after multi-cycle steam huff and puff or for evaluating the degree of channeling, resulting in non-targeted and non-adaptive designs for on-site steam channeling control measures. To address this problem, physical simulation methods were used to study the causes and mechanisms of steam channeling pathway formation during heavy oil steam huff and puff development. The macro and micro morphology of steam channeling pathways were obtained through visualization experiments. A set of quantitative calculation theoretical models for inter-well channeling pathways in steam huff and puff and a method for evaluating the degree of steam channeling were established. Based on this, parameter calculations for steam channeling pathways were performed considering the reservoir properties and current steam channeling status in the Lou 1917 well block, northern area of Jinglou Block 1, Henan Oilfield. Further optimization of steam channeling control measures was conducted. The study results show that the channeling pathways dominate the main flow paths after inter-well steam channeling occurs. The areal sweep coverage overall exhibits a "wedge-shaped" distribution, with an areal sweep efficiency of approximately 43.16%. The steam channeling pathways show a tortuosity of about 1.2, with a total number of approximately 4-5. The permeability increase averages 3-5 times, the average diameter is about 368 μm, and the volume of steam channeling pathways accounts for about 8.5% of the swept volume. Since 2020, On-site implementation of steam channeling control technology reached 220 well-times. Cumulative oil production was 3.14×10⁴ t, with a cumulative incremental oil of 5 327 t. The stage oil-steam ratio was 0.27, the recovery factor increased by 3.5 percentage points, and the output-input ratio reached 1.9∶1.0. this technology has been scaled up for application, achieving good development results and economic benefits, providing theoretical and technical support for the profitable development of heavy oil reservoirs.

Data-driven bottomhole pressure prediction for gas storage reservoirs

JIANG Huaquan, ZENG Juan, LI Limin, WEN Tingjun, ZHOU Junchi, CHEN Xiaofan, WANG Jian

2025, 32(4):  122-129.  DOI: 10.3969/j.issn.1006-6535.2025.04.014

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For the difficulty in accurately and swiftly obtaining bottomhole pressure in gas storage reservoirs,in this study,Xiangguosi Gas Storage was taken as the research object to analyze 12 characteristic parameters from 14 datasets across 10 wells based on the data-driven principles and supervised learning methods.Three bottomhole pressure prediction models:Gaussian Process Regression (GPR),Support Vector Regression (SVR),and Artificial Neural Network (ANN),were developed and evaluated for prediction accuracy.The study shows that the main factors influencing bottomhole pressure are daily injection-production volume,wellhead pressure,formation pressure,and wellhead temperature,and the prediction accuracy of SVR,GPR,and ANN models are 99.2%,97.4%,and 95.1%,respectively.This indicates that data-driven methods can effectively predict bottomhole pressure,with the SVR model offering a more reliable prediction for gas storage injection-production control.This research is of great practical significance for enhancing the safety and economy of gas storage operations.

Drilling & Production Engineering

Research and experiment on electric thermal molten salt energy storage steam injection technology

LIU Jianfeng, ZHANG Xin, WANG Yantao, ZHAO Xinggang, LIU Bing

2025, 32(4):  130-135.  DOI: 10.3969/j.issn.1006-6535.2025.04.015

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To address the problems of high energy consumption and high carbon emissions in heavy oil steam injection systems, research on electric thermal molten salt energy storage steam injection technology suitable for heavy oil steam injection was carried out to achieve green development of heavy oil. Using Abaqus software simulation methods and system comprehensive thermal efficiency evaluation methods, the system operating conditions were optimized and designed, and field tests were conducted. The study shows that the technology of using electric thermal molten salt energy storage steam injection, which utilizes green electricity/off-peak electricity to replace fossil fuel combustion for producing wet saturated steam for heavy oil steam injection, is technically feasible; the steam flow rate of the steam preheating system fluctuates within a small range with changes in steam pressure, which is conducive to stable system operation and is the preferred preheating process for electric thermal molten salt energy storage steam injection systems; when the load rate of the electric thermal molten salt energy storage steam injection system is 60%~100%, the system comprehensive thermal efficiency is 92.61%~94.34%, and it increases with increasing system operating load; the average experimental value of system comprehensive thermal efficiency is 0.44 percentage points lower than the average theoretical calculation value, indicating a small deviation; compared with existing gas-fired steam injection boilers, the test station produces 4.8×10⁴ t annually, replacing 313×10⁴ m³/a of natural gas, and reducing CO₂ emissions by 6 768 t/a. The research on this technology can provide technical support and practical guidance for the green transformation of heavy oil steam injection systems, and the system comprehensive thermal efficiency evaluation method can be used to guide engineering design.

Synthesis and performance evaluation of a temperature-responsive self-defoaming intelligent gas drainage foaming agent for gas wells

DU Jing, CHEN Jun, MAO Yukun, XU Zhiyu, LIAO Li, YE Kejie, LI Gang, HOU Baofeng

2025, 32(4):  136-142.  DOI: 10.3969/j.issn.1006-6535.2025.04.016

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To solve the problems of excessive consumption of foaming agents and defoaming agents, incomplete defoaming, and complex processes in liquid drainage gas production technology, a gas well temperature-responsive self-defoaming intelligent gas drainage foaming agent TS-1 was developed, and its performance was evaluated. The study shows that the foaming agent has good foaming performance and stability at a temperature of 80 ℃ and a salinity of 20×10⁴ mg/L; a 0.2% foaming agent solution can undergo a phase transition by itself around 20 ℃, changing from foamability to defoamability, with a foam volume reaching 420 mL and a foam half-life reaching 13 minutes; formation sand has little effect on the foaming ability of the foaming agent solution, with a liquid-carrying rate of 84.8%. After 20 minutes, the self-defoaming rate reached 84.3%; after adding the synergistic agent ESAB, the self-defoaming rate approached 100%, and the self-defoaming ability was enhanced; at the wellhead position and in surface pipelines, the self-defoaming intelligent foaming agent for gas wells can rapidly self-defoam under the influence of ambient temperature, avoiding the step of adding defoaming agents, simplifying the operation process, and effectively improving the efficiency of foam drainage operations. After the successful application of the self-defoaming intelligent foaming agent, the average daily gas production increase was 4 000 m³, and the average daily liquid discharge increase was 2.8 m³, showing significant gas increase and liquid discharge effects. This achievement provides a new technical approach for gas well liquid drainage gas production and has important field application value.

Oil-based high filtration loss pressure-bearing plugging technology for shale formations

ZHANG Jing, HENG De, XU Xinghai, LI Bo, WEN Qianbin, HUANG Xudong, WEN Jie

2025, 32(4):  143-148.  DOI: 10.3969/j.issn.1006-6535.2025.04.017

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For the issue of frequent and severe oil-based drilling fluid losses in shale formations and the ineffectiveness of conventional plugging methods, an oil-based high filtration loss pressure-bearing plugging agent has been developed. Tests on its suspension stability, filtration time, initial strength, pressure-bearing capacity, and compatibility with drilling fluids were conducted. The properties and plugging mechanism of the agent were analyzed, along with its application process and field performance. The study shows that the oil-based high filtration loss plugging agent is a uniform mixture of fibers, porous inert materials, infiltrating materials, and filter-aids in specific proportions. The formulated slurry has good suspension stability, a total filtration time of less than 50 seconds, high initial strength of the solidified body, stable rapid filtration properties at 150 ℃, a pressure-bearing range of 10.0 to 19.0 MPa, and good compatibility with drilling fluids. Field application results show that this technology is simple and safe in operation, with strong adaptability of the oil-based drilling fluid and high pressure-bearing capacity. It is suitable for plugging small, medium, and large-scale losses in oil-based drilling fluids, as well as for addressing leakage in water-sensitive shale formations using water-based drilling fluids. This study offers a new solution for plugging the oil-based drilling fluid loss in shale formations.

Numerical simulation of acidizing in fractured carbonate rocks considering temperature effects

YANG Junchao, CHENG Yuanfang, HAN Zhongying, HAN Songcai, YAN Chuanliang, ZHAO Zhuyu, SUN Bo

2025, 32(4):  149-157.  DOI: 10.3969/j.issn.1006-6535.2025.04.018

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To address the unclear mechanism of wormhole propagation during acidizing in deep fractured carbonate rocks,an MFCAC mathematical model coupling seepage field,chemical field,and temperature field for multi-mineral component acidizing was established based on a dual-scale continuum model and discrete fracture treatment method.The mechanism of wormhole propagation and acid-etching characteristics in fractured reservoirs considering temperature effects were analyzed,and the influences of the initial content ratio of CaMg(CO₃)₂ to CaCO₃,acid temperature,and reaction exotherm on wormhole propagation were studied.The study shows that the propagation direction of the main wormhole is mainly dominated by the control domain of nearby fractures;temperature effects increase the acid-rock reaction rate but decrease the H⁺ mass transfer rate,resulting in fewer natural fractures connected by the main wormhole;the increased H⁺ diffusion rate caused by temperature effects makes acid easier to diffuse into pores in all directions,leading to more complex wormhole morphology;the pore volume to breakthrough (PVBT) first decreases and then increases with increasing initial CaMg(CO₃)₂ content;when the initial content ratio of CaMg(CO₃)₂ to CaCO₃ is 1.5,the corresponding PVBT is the smallest;PVBT increases with increasing acid temperature;compared to ignoring reaction exotherm,considering reaction exotherm results in a smaller PVBT.This research provides a theoretical basis for the precise control of dynamic wormhole propagation and optimization of operational parameters during acidizing operations in deep fractured carbonate reservoirs.

Establishment and effect analysis of critical liquid-carrying flow rate models for new types of production tubing strings in gas wells

LIU Shichun, JIA Youliang, BAI Xiaohong, YANG Xudong, WEI Yaming, ZHAO Binbin, XIAO Shuqin

2025, 32(4):  158-166.  DOI: 10.3969/j.issn.1006-6535.2025.04.019

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As the development cycle of gas wells extends, wellbore liquid loading intensifies, leading to reduced field production and recovery. To address this issue, based on the minimum pressure drop theory, critical liquid-carrying flow rate calculation models with wellhead tubing pressure and water-gas ratio as variables were established for vertical wells with depths of 2 400-4 000 m, using two types of tubing strings: Φ50.8 mm coiled tubing and Φ60.3 mm tubing. The study shows that Φ50.8 mm coiled tubing has stronger autonomous liquid-carrying capacity, less severe liquid loading, lower bottom-hole flowing pressure, and higher daily gas production; the critical liquid-carrying flow rate increases with water-gas ratio, wellhead tubing pressure, and well depth, among which the influence of water-gas ratio and wellhead tubing pressure on the critical flow rate is significantly higher than that of well depth; when the wellbore flow pattern transitions to slug flow, the gas flow rate for Φ50.8 mm coiled tubing (7 000 m³/d) is lower than that for Φ60.3 mm tubing (16 000 m³/d), and the production time of the latter is reduced by more than 70% compared to the former. Field tests show that compared to Φ60.3 mm tubing, Φ50.8 mm coiled tubing brings higher completion efficiency, extending the natural continuous production period by 1.5 years, further verifying the accuracy of the model. This research provides a theoretical basis for analyzing gas well liquid-carrying laws and optimizing liquid drainage gas production measures, and offers important guiding significance for improving the development efficiency of low-productivity gas wells.

New Energy

Research on cross-seasonal thermal storage performance of W-type buried pipe systems

ZHANG Jie, NIU Chen, YU Chunyu

2025, 32(4):  167-174.  DOI: 10.3969/j.issn.1006-6535.2025.04.020

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To explore the impact of buried pipe design parameters on thermal storage, a numerical simulation model for W-type buried pipe cross-seasonal thermal storage systems was developed, and the effects of inlet temperature, velocity, well spacing, and burial depth on thermal storage performance were analyzed. The study shows that the underground temperature field changes most significantly along the radial direction during cross-seasonal thermal storage. A velocity of 0.6 m/s is optimal for the circulating fluid in the buried pipe as it balances thermal storage efficiency and energy consumption. Increasing the inlet fluid temperature of the system widens the temperature fluctuation range within the pipe but also increases heat loss. Under a hexagonal tube cluster layout, the optimal well spacing increases with the depth of the buried pipe. The research findings provide a theoretical basis for the design and optimization of cross-seasonal thermal storage systems of buried pipes.