Table of Content

25 August 2024, Volume 31 Issue 4

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Summary

Comparison and Implications of Typical Normal Pressure Shale Gas Development between China and the United States

Wang Jiwei, Song Liyang, Kang Yuzhu, Wei Haipeng, Chen Gang, Li Donghui

2024, 31(4):  1-9.  DOI: 10.3969/j.issn.1006-6535.2024.04.001

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To address the issues of low single-well production capacity,immature engineering technology,and difficulty in development profitability of China's normal pressure shale gas,and to explore reasonable development approaches,taking Fayetteville Shale Gas Field in the United States and Dongsheng Shale Gas Block in China as examples,based on the geological characteristics of the two gas fields,the evaluation and comparison are conducted in terms of favorable area evaluation,single well productivity and engineering costs.The study shows that the evaluation of favorable areas for shale gas in Dongsheng Block is comparable to Fayetteville,but Dongsheng Block is still in the early stages of development,with greater burial depth and more complex geological conditions.It is necessary to combine the characteristics of later development,learn from the experience of Fayetteville,and further refine and deepen the zoning classification evaluation.The modes of Fayetteville and Dongsheng Shale Gas Field are partition compound development.The supporting engineering technology is gradually improved.For all that,the intensity of block fracturing fluid and sanding in Dongsheng are lower than those in Fayetteville,resulting in a lower average single well EUR.Continuous studied is needed.Both Fayetteville Gas Field and Dongsheng Block adhere to the goal of continuous cost reduction.The comprehensive cost per well keeps decreasing,but further efforts are required in Dongsheng Block,aiming to lower the comprehensive cost per well to within 3 000×10⁴ to 3 500×10⁴ yuan.The geological resources of normal pressure shale gas in China are abundant,which is the main source for enhancing reserves and production.By further clarifying favorable areas,tackling supporting engineering technologies,reducing overall costs,the comprehensive benefit development will be realized,which is of great strategic significance for the long-term stable production of shale gas in China.

Research Progress on the Impact of Tight Reservoir Pore Structure on Spontaneous Imbibition

Yang Chen, Yang Erlong, An Yanming, Li Zhongjun, Zhao Xuewei

2024, 31(4):  10-18.  DOI: 10.3969/j.issn.1006-6535.2024.04.002

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Against the backdrop of the gradual depletion of conventional oil and gas resources, unconventional oil and gas resources, represented by tight oil resources, are increasingly gaining importance in energy development and utilization. However, compared to conventional reservoirs, the pore structure of tight oil reservoirs is highly complex, featuring with wide distribution of pore sizes, diverse pore types, and well-developed pore throats. All these factors pose significant challenges to the exploitation of tight oil reservoirs. Therefore, a thorough research on the pore structure and spontaneous imbibition mechanism in tight oil reservoirs is crucial for improving tight oil recovery rates. Based on this, through literature review, this paper provides an overview of the research on the pore structure and imbibition mechanism of tight oil reservoirs, introducing characterization methods for pore structure, research progress on tight oil pore structure, the impact mechanism of pore structure on tight oil imbibition mechanism, and summarizing and prospecting the research progress in this field. This study can provide reference for the development of crude oil production in tight oil reservoir and promote the development of tight oil recovery technology.

Research Progress and Development Tendency of Transient Well Testing Technology

Wang Weiqi, Guan Yingzhu, Zhang Jinfa, Wang Huliang, Ji Guofa

2024, 31(4):  19-26.  DOI: 10.3969/j.issn.1006-6535.2024.04.003

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In order to better monitor the production performance of oil and gas reservoirs and improve the production capacity of oil and gas fields, this paper reviews the principles, interpretation methods, and application effects of four commonly used transient well testing technologies. It analyzes the problems existing in transient well testing technology and proposes future key research directions. The results show that the currently commonly used transient well testing technologies mainly suffer from serious inter-well interference, complex characteristics of testing curves, low accuracy of testing interpretation, and low efficiency and high losses in conventional testing of complex fault block reservoirs. While new types of testing technologies such as numerical well testing, vertical interference testing, and low-frequency pulse testing can address these issues. The future development trends of transient well testing technology lie in deep and ultra-deep testing processes, evaluation of low-permeability tight reservoir testing data, assessment of fracturing effects, and integrated application of data. Emphasis can be placed on technical breakthroughs in numerical well testing and multi-layer testing. Through a comprehensive analysis of transient well testing technology, this study can provide technical references for on-site testing and offer new perspectives for subsequent technological developments.

Geologic Exploration

Oil-bearing Characteristics and "Sweet Spots" Evaluation of Medium-low Maturity Shale Oil Reservoirs in Ludong Sag

Zhou Liguo

2024, 31(4):  27-35.  DOI: 10.3969/j.issn.1006-6535.2024.04.004

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To address the issues of unclear distribution characteristics and enrichment control factors of medium-low maturity shale oil reservoirs in the Jiaolige Sag,Ludong Depression,a study on the oil-bearing characteristics of shale oil reservoirs was conducted through methods such as 2D NMR analysis,nano-CT scanning,and identification of kerogen microscopic components.A comprehensive evaluation standard for identifying shale oil sweet spots was established based on factors such as shale lithofacies,reservoircapabilities,oil-bearing characteristics,andmobility.The results show that the degree of development,density,lithology,and other structural characteristics of shale lamination and bedding are the primary influencing factors on the oil-bearing characteristics and distribution.The layered siltstone,composed of coarse grained clastics and laminated felsic shale,exhibits excellent pore microstructure and connectivity.The specific surface area is less than 15 m²/g,and the average pore size of nitrogen adsorption is greater than 8 nm,which is a highly favorable reservoir.The total organic carbon (TOC)content of class Ⅰ+Ⅱ "sweet spot" exceeds 1%,with the reservoir exhibiting medium and large pores accounting for over 25%.The pore size within the reservoir space is greater than 8 nm,indicating a medium to good oil bearing potential and mobility,leading to relatively enriched oil and gas.These findings offer valuable technical support for identifying favorable targets for shale oil development in the study area,as well as for deploying and evaluating test areas.

Application of Seismic Forward Modeling in the Study of Deep-water Sedimentary Formation

Shen Xiangcun, Fan Weifeng, Jiang Zhongzheng, Luo Shaohui, Guo Wei, Wan Li

2024, 31(4):  36-43.  DOI: 10.3969/j.issn.1006-6535.2024.04.005

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To improve the seismic interpretation accuracy and seismic data information extraction capacity of deep-water sedimentary formation, seismic forward modeling was conducted on the slope deposits with canyons. The seismic reflection characteristics of cleuch, channels and canyons dominated by turbidity flow and block transposition are analyzed. The fine forward modeling of the natural levee complex of channels is carried out. The comprehensive analysis suggests that the width-depth ratio of the cleuch dominated by block transport is low and symmetrically filled, and the interior is mainly chaotic weak amplitude reflections. While the canyons dominated by turbidity flow has a large width and depth, the interior of which is an undulating high amplitude reflections; the smaller the angle between the top and bottom interfaces of the formation, the greater the error between the true pinch-out point and the seismic reflection pinch-out point; the decrease in thickness of the natural levee complex of channels results in a lower seismic reflection frequency and enhanced amplitude; the amplitude of the channel when it is saturated with water is stronger than that when it is saturated with gas. Hence the seismic response characteristics of multi-type deep-water sedimentary bodies with different morphological attributes are further clarified, which can effectively improve the accuracy of comprehensive interpretation of seismic data in deep-water sedimentary formations.

Distribution Characteristics and Main Controlling Factors of Movable Fluid in Tight Sandstone Reservoir

Li Yating, Tong Changbing, Han Jin, Shi Liang, Zhong Gaorun, Zhao Bangsheng

2024, 31(4):  44-53.  DOI: 10.3969/j.issn.1006-6535.2024.04.006

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Due to the significant variation in fluid distribution,complex pore structure,and relatively low percolation capacity of the Chang 8 reservoir in the Fuxian Area of the Ordos Basin,five representative rock samples from the study area were selected for testing and analysis.The primary controlling factors affecting fluid mobility were analyzed using thin section casting, scanning electron microscopy (SEM),X-ray diffraction clay mineral analysis (XRD),and constant velocity mercury injection experiments.The results indicate that the movable fluid saturation in tight sandstone reservoirs ranges from 26.31% to 50.61%,with an average of 35.15%.The pore throat radius for movable fluid is between 0.10 μm and 0.50 μm;the T₂ cutoff value falls within the range of 6.69 ms to 49.90 ms,and the minimum pore throat radius for movable fluid is between 0.16 μm and 0.36 μm.The permeability of a reservoir exerts greater control over the mobility of fluids than porosity.The median radius,maximum pore throat radius,and average pore throat radius exhibit a positive correlation with movable fluid,with the median radius exerting a greater influence.Higher feldspar content facilitates the formation of feldspar dissolution pores,resulting in greater movable fluid saturation.Type Ⅰ and Type Ⅱ reservoirs exhibit high kaolinite content,with pores filled with dispersed particles.Type Ⅲ reservoirs exhibit high illite and mixed-layer illite content,with pores bridged and segmented,leading to pore throat plugging.These research findings provide valuable insights for enhancing the recovery of tight oil reservoirs.

The Distribution and Main Controlling Factors of High-quality Shale in Longmaxi Formation in Southern Sichuan-Eastern Sichuan Region

Chen Yuchuan, Lin Wei, Li Mingtao, Han Denglin, Guo Wei

2024, 31(4):  54-63.  DOI: 10.3969/j.issn.1006-6535.2024.04.007

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Sichuan Basin is rich in marine shale gas resources. From Paleozoic to Cenozoic, the basin has experienced multiple tectonic movements, forming complex structural styles and variable sedimentary environments, featuring with uneven distribution of shale gas resources. In order to clarify the distribution law of high-quality shale, taking the Longmaxi Formation shale in southern Sichuan-eastern Sichuan Region as an example, comprehensive analyses including whole-rock X-ray diffraction, geochemical testing, basin simulation, and drilling and logging data analysis were conducted. The distribution law and main controlling factors of high-quality shale were discussed from the perspectives of sedimentation, reservoir formation, and structure, and favorable areas for shale gas exploration and development were delineated. The results show that high-quality shale in the southern Sichuan-eastern Sichuan Region is mainly distributed in the semi-deepwater to deepwater continental shelf facies; an R_o value of 2.5% to 3.5% is conducive to the development of high-quality shale; and fold structures play a significant controlling role in the enrichment and distribution of shale gas. The research results can provide theoretical basis for shale exploration and development in southern Sichuan-eastern Sichuan Region.

Control of Effective Normal Stress on Fault Lateral Sealing Capacity

Yan Nianbin, Wang Haixue, Hou Jiayi, Jiang Mingming, Song Xianqiang

2024, 31(4):  64-70.  DOI: 10.3969/j.issn.1006-6535.2024.04.008

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The lateral sealing of small displacement faults determines the capacity of fault traps to accumulate oil and gas. With the development of oil and gas exploration technology theories, the role of small displacement faults, which were once overlooked, is becoming increasingly prominent in the process of oil and gas exploration and development. To clarify the internal structural characteristics of small displacement faults and the influence on the lateral sealing of faults, a self-developed high-pressure and low-speed circular shear device was applied. Taking the effective normal stress of the cross-section as a variable, it conducts circular shear physical simulation experiments on high porosity pure sandstone to analyze effective normal stress on the lateral sealing of faults. The results show that the fracture mechanism is mainly characterized by fragmentation in high porosity and pure sandstone, forming typical fragmented fault rocks. The significant decrease in permeability is the fundamental reason for the lateral sealing of the joint section of sandstone in the same formation. Under the condition that other factors remain unchanged, the larger the effective normal stress of the cross-section, the greater the degree of fragmentation of the fault rock, and the smaller the particle diameter and porosity; the fracture of rock particles and the filling of detrital matrix lead to a significant decrease in porosity and permeability of the fracture zone. The effective normal stress of the fault section is the main controlling factor of the lateral sealing capacity of the small displacement fault. Small displacement faults have the potential of oil and gas accumulating. The study results have guiding significance for the exploration and development of fault-block oil and gas reservoirs in rift basins.

Full Pore Size Characterization of Coal Pore Structure Based on CT Scanning

Zhu Wentao, Li Xiaogang, Ren Yong, Shi Binbin, Dai Ruirui, Hong Xing, Yang Xiao, Chen Guohui

2024, 31(4):  71-80.  DOI: 10.3969/j.issn.1006-6535.2024.04.009

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12 samples of X coal from the Benxi Formation were collected in the DJ Block at the eastern edge of Ordos Basin,in order to explore the pore structure of deep and ultra-deep coal formations.The full pore size distribution characteristics of X coal were characterized by multi-experiment splicing method,based onthe three-dimensional reconstruction technology of digital core CT scanning and tests of high-pressure mercury intrusion,liquid nitrogen adsorption,and carbon dioxide adsorption.The study also compared and analyzed the distribution differences between the micropores,mesopores,and macropores in deep,medium,and shallow coal formations and their effects on adsorption and permeability.The results show that the reserving space of coal reservoirs is dominated by micropores and macropores,with fewer mesopores.In deep X coal formation,micropores and macropores on average account for 44.1% and 53.9%,respectively.While in shallow-to-medium X coal,micropores and macropores on average account for 34.8%,64.1%,respectively.The adsorption nanopores in deep coal are more developed.However,the development of micron-scale fractures in shallow-to-medium coal is better than that in deep coal.Through the analysis of the full pore size distribution characteristics,it is concluded that the proportion of macropore volume in shallow-to-medium X coal is higher,and the permeability is an order of magnitude higher than that of deep X coal,while the proportion of micropore volume in deep X coal is higher,indicating stronger adsorption capacity.Through quantitative characterization of the full aperture,the pore distribution characteristics of the reservoir at all levels are clarified,which provides data and theoretical support for the occurrence state and production mechanism of coalbed methane.

Method of Determining the Upper Limit Pressure of Gas Storage Operation and Its Application in the Banzhongbei Gas Storage

Yan Ping, Jin Yejun, Yuan Xuehua, Su Hesong, Chang Jinyu, Zeng Jingbo, Zhang Fengsheng, Cai Hongbo

2024, 31(4):  81-88.  DOI: 10.3969/j.issn.1006-6535.2024.04.010

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The Banzhongbei Gas Storage in the Dagang Oilfield is located on the upcast side of the Banqiao Fault, which is a fault block gas storages and a semi-anticlinal structure cut by faults. The loading capacity of faults and capping formation determines the high limit pressure for the gas storage operation. To address the lack of consideration of mechanical integrity in determining the upper limit pressure of gas storage operation, this study evaluates the hydraulic sealing ability of the cap rock and the stability of faults in the study area from the perspective of geomechanics. This evaluation is based on comprehensive data including 3D seismic interpretation results, XMAC logging stress interpretation results, and rock mechanics tests. It utilizes the theory of rock brittle fracture to determine the upper limit pressure for the safe operation of gas storage considering mechanical integrity. The results show that the upper limit pressure of the hydraulic sealing capacity of the cap rock in the Banzhongbei Gas Storage is 39.30 MPa, and the weak point of fault stability is at the intersection of two faults with a minimum activation pressure of 30.57 MPa. By considering the upper limit of cap rock hydraulic sealing capacity and fault stability, the upper limit pressure for the operation of the Banzhongbei Gas Storage is determined to be 30.57 MPa, which is reasonably close to the design operating upper limit pressure of 30.50 MPa. The research findings have significant guiding for the design of upper limit pressure for gas storage operation.

The Advanced SGR Method for Fracture Closure Evaluation in Arenaceous Shale Formation and Its Application

Zhu Huanlai, Wang Weixue, Fu Guang, Sun Yue

2024, 31(4):  89-95.  DOI: 10.3969/j.issn.1006-6535.2024.04.011

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When evaluating the lateral closure performance of fractures in arenaceous shale formation,The SGR uses a constant derived from statistics as the lower limit,which leads to a significant deviation between the evaluation results and exploration practice.In view of the aforementioned issue,the minimum shale content of fault rock required for lateral closure of faults in arenaceous shale formation is determined by using fault dip angle,diagenetic time of fault rock compaction,shale content of target reservoir and diagenesistime of compaction.The results show that the minimum shale content of fault rock is a variable value based on the closure mechanism,which addresses the issue of insufficient constant value in SGR method and effectively improves the accuracy of lateral closure evaluation.This method has been applied to the evaluation of the lateral closure of the arenaceous shale reservoir in the southern section-2 of the F3 fault in the Huhenuoer tectonic zone of the western Beier Depression in the Hailar Basin,and the finds are as follows:at measuring points 5,7,8 and 12-15,the F3 fault closes laterally towards the inner side of the sandstone reservoir in the southern section-2,while at the remaining measuring points,it does not close laterally,which is consistent with the main distribution of oil and gas observed at measurement points 7,8,12 and 14.The research results are of great reference significance for the distribution characteristics of fault-type oil and gas reservoirs in arenaceous shale formation of oil and gas bearing basins,and indicate the direction of oil and gas exploration.

Methods and Applications for Characterizing Pore Structure and Determining Physical Property Lower Limit in Shale Reservoirs

Zhou Zhijun, Zhang Guoqing, Cui Chunxue, Bao He, Ren Shuai, Wang Jingyi

2024, 31(4):  96-102.  DOI: 10.3969/j.issn.1006-6535.2024.04.012

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Inadequate comprehension of the pore structure and physical properties of shale reservoirs impedes precise calculation of shale oil reserves and efficient development seriously. This study focuses on the core holes of Xinyishen-9, Liye-1, and wells Fanye-1 in the Paleogene Shahejie Formation within the Jiyang Depression. The pore structure of shale reservoirs is comprehensively characterized using N₂ adsorption, high-pressure mercury injection,physical properties measurement, and other experimental methods. Additionally, we determined the physical property cutoffs through a comprehensive approach involving irreducible water saturation method, pressed mercury displacement method, minimum flow pore-throat radius method, and oil testing method. The findings indicate that the nitrogen adsorption experiment primarily characterizes the small pores of shale samples. The pore morphology in the study area predominantly comprises ink bottle, transition, and flat types, mainly featuring nano-scale pores with a radius ranging from 1.50 to 40.00 nm and an average pore radius of 16.00 nm. Moreover, the high-pressure mercury injection experiment focuses on characterizing mesopores and macropores of shale, revealing a pore throat radius range of 0.03 ~ 66.13 μm. The lower limit of shale reservoir porosity falls within the range of 1.30% to 3.82%, while permeability's cutoff is between 0.03 ~ 0.12 mD, the minimum flow pore-throat radius is 14.60~23.50 nm and average value is 17.76 nm. The research outcomes offer valuable parameter indexes and technical support for reserve calculation and reservoir evaluation in Jiyang Depression's shale oil exploration.

Reservoir Engineering

Calculation Method of Maximum Imbibition Distance of Countercurrent Imbibition in Shale Reservoirs

Wu Zhongwei, Qin Lei, Cui Chuanzhi, Wang Yidan, Qian Yin, Huang Yingsong, Yu Gaoming

2024, 31(4):  103-108.  DOI: 10.3969/j.issn.1006-6535.2024.04.013

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Imbibition is an important mechanism for fracturing development in shale reservoirs,and the maximum imbibition distance is a direct indicator for evaluating the scope of imbibition,which is of great significance for the development of shale reservoirs.In order to determine the maximum imbibition distance of shale reservoirs,a calculation method of imbibition distance of countercurrent imbibition in shale reservoirs was developed according to the principles of filtration theory and numerical methods and based on the characterization of the capillary curve of shale reservoirs.The results were compared to the results of laboratory experiments so as to verify the reliability of the calculation method and analyze the influencing factors of the maximum imbibition distance.The research shows that the maximum imbibition distance increases linearly with the increase of permeability,but the time required to reach the maximum imbibition distance decreases exponentially;the ratio of oil/water viscosity has no effect on the maximum imbibition distance,however,the greater the viscosity of crude oil,the longer the time required to reach the maximum imbibition distance;when the reservoir permeability is 0.05 mD,with the contact angle of 45 ° and the interfacial tension of 50 mN/m,the maximum imbibition distance is 2.2 m,taking 170 d,which takes longer time.This study provides reference for evaluating the range of imbibition distance in shale reservoirs.

Oxidation Characteristics and Oil Displacement Effect Evaluation of Air Flooding in Low Permeability Reservoirs

Luo Chen, Liu Huiqing, Bai Zongxian, Wang Zhuanzhuan, Wang Liangliang, Zhang Yaqian

2024, 31(4):  109-117.  DOI: 10.3969/j.issn.1006-6535.2024.04.014

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In the process of high-pressure air injection development in low-permeability reservoirs,the mechanism of crude oil oxidation is unclear,and there is difficulty in predicting enhanced oil recovery potential.In order to solve these problems,low-temperature oxidation experiments and physical simulation experiments of air injection in long core were conducted to analyze the differences in oil and gas composition before and after oxidation reactions under different reservoir conditions,reveal the characteristics and laws of crude oil low-temperature oxidation,investigate the development transition potential from water flooding to air flooding in low-permeability reservoirs,and evaluate the oil displacement effect of air injection.The results show that with the increase in oxidation temperature,the oxygen consumption of crude oil rises;while after the oxidation,the light components of the oil sample decrease and the medium and heavy components increase.Excessive water saturation reduces the heat effect of crude oil oxidation.The sensitivity factors of crude oil oxidation in terms of sensibility from large to small are pressure,temperature,and water saturation.So,air flooding has a better oil displacement effect,with an oil displacement efficiency of up to 41.20%.However,excessively high gas injection pressure can cause gas channeling.After reaching the economic limit by water flooding,development mode switched to air flooding can improve oil displacement efficiency,but the increment of oil displacement efficiency during the air flooding is relatively small,with an ultimate oil displacement efficiency of 50.92%.Therefore,in actual development process,oxygen-reduced air flooding should be adopted,and gas injection parameters should be optimized so as to control gas channeling and enhance oil recovery rate.The research results can provide a theoretical basis and technical support for the development of low-permeability reservoir by air flooding.

Distribution Characteristics of Residual Oil in Block III of District Ⅰ to District Ⅲ by Polymer Flooding and Its Comprehensive Management Strategies in Xingshugang Oilfield

Liang Peng

2024, 31(4):  118-125.  DOI: 10.3969/j.issn.1006-6535.2024.04.015

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The reservoirs with low permeability in the western part of Block Ⅲ of District Ⅰ to District Ⅲ in Xingshugang Oilfield in Daqing Oilfield experienced various development stages,such as natural energy,water flooding,and polymer flooding,leaving a complex distribution of residual oil and a pressing need to improve development efficiency.Therefore,Block Ⅲ was divided into three regions featured by:normal polymer flooding,casing-damaged polymer flooding,and polymer follow-up water flooding based on the study of residual oil and analysis results of development effectiveness,so as to develop proper technical strategies for improving development effectiveness with artificial core displacement and numerical simulation techniques.After years of chemical flooding,residual oil in the normal polymer flooding region is sporadically distributed at the edges of sand bodies and areas with low permeability.In the casing-damaged polymer flooding region,the producing performance of oil layers is poor due to casing damage,and the remaining oil reserves there is high.Based on the conditions described above,optimization is carried out in three aspects:development method,oil displacement system,and well pattern design with the full consideration of different regional characteristics.For normal polymer flooding regions and polymer subsequent water flooding regions,a five-spot well pattern dilution of regular polymer flooding was adopted with a well spacing of 175 meters and a plug size of 0.40 times of the pore volume.While for casing-damaged polymer flooding region,a local infilled five-spot well pattern of regular polymer flooding is applied with a well spacing of 140 meters and a plug size of 0.70 times of the pore volume.An increase of 3.53 percentage points is predicted in recovery rate.After the implementation of these measures,the cumulative injection of polymer pre-plugs in Block Ⅲ is estimated to be 0.10 times the pore volume,an expected oil increase of 9 780 tons.This study can provide reference for improving development efficiency in polymer flooding blocks.

A Method for Calculating the Permeability of Inorganic and Organic Pores in Shale

Li Yajun, Li Jinghong, Sang Qian, Dong Mingzhe, Cui Chuanzhi

2024, 31(4):  126-132.  DOI: 10.3969/j.issn.1006-6535.2024.04.016

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In order to address the coexistence of inorganic and organic pores in shale reservoirs, a dual-continuum approach was developed to establish a percolation mathematical model for the flow of oil and water phases in shale. This model takes into consideration the wetting and flow characteristics of oil and water phases within both inorganic and organic pores in shale. By employing the proposed model, we obtained matching results from oil-water spontaneous imbibition experiments conducted on shale and determined both the inorganic and organic pore permeability, facilitating accurate calculation of oil content within shale reservoirs. Furthermore, a comprehensive study was carried out to investigate the dynamic characteristics and influential laws of the permeation process in shale. The study results indicate that the permeability of inorganic pores ranges from 10^-8 to 10^-5 D, while that of organic pores ranges from 10^-10 to 10^-7 D. As the permeability through inorganic pores increases, the rate of spontaneous imbibition in shale also increases. However, when the ratio of organic pore permeability to inorganic pore permeability is less than 10^-3, the impact of organic pore permeability on self-imbibition rate is insignificant. These findings have significant implications for a thorough assessment of permeability and reserves in shale reservoirs.

Re-evaluation of Medium-low Permeability Sandstone Reservoirs in the Later Stage of Water Flooding and Strategies to Improve Recovery Efficiency

Chen Hongcai, Wang Zhaokai, Jin Zhongkang, Wang Teng, Sun Yongpeng, Zhao Guang

2024, 31(4):  133-141.  DOI: 10.3969/j.issn.1006-6535.2024.04.017

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In order to explore effective approaches to enhance oil recovery in the late stage of water-flooded development in reservoirs with medium-low permeability and high-ultra-high water content,this study,taking Nanhu Oilfield as an example,deepens the understanding of reservoir microscopic characteristics through mineral analysis and SEM methods,and investigates the feasibility and application effects of dispersed particle gel in improving oil recovery using the combination of nuclear magnetic resonance and mercury injection methods.The results show that Nanhu Oilfield is featured with well-developed large pore channels, obvious speed sensitivity and water sensitivity.Severe water breakthrough is the main reason for inefficient development,while key factors for improving development effectiveness include low-rate water injection,maintaining reservoir energy,and controlling water channeling.The dispersed particle gel can effectively inhibit water breakthrough and improve the mobilization ability of residual oil in medium and small pores. The oil recovery ratio in small pores of the core samples, in medium pores increased by 52.83 percentage points by 34.60 percentage points,respectively,after dispersed particle gel flooding,and the oil recovery increased,and the overall recovery ratio increased by 33.14 percentage points,indicating a significant improvement in development effectiveness.The findings of this study can provide references for improving the development effectiveness of reservoirs with high water content.

Drilling & Production Engineering

Research on Low-Cost,Low Oil-Water Ratio,Low Soil Content Oil-based Drilling Fluid Technology

Gao Wenlong

2024, 31(4):  142-148.  DOI: 10.3969/j.issn.1006-6535.2024.04.018

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The application range of oil-based drilling fluids is extensive.To reduce the cost of oil-based drilling fluids,a new low-cost formulation with a low oil-water ratio and low soil content was developed.This was achieved by selecting affordable oil-based base fluids,developing new single-dose high-efficiency emulsifiers,reducing the oil-water ratio,and decreasing the addition of organic soil.The performance of the new formulation was evaluated in the laboratory.According to experimental results,the oil-water ratio of the drilling fluid can be adjusted within the range of 65:35 to 85:15.The organic matter content is limited to 2.0% or lower,with a density of 1.4 to 2.2 g/cm³ and temperature resistance up to 200 ℃.The demulsification voltage is greater than 800 v,high temperature and high pressure fluid loss is less than 3 mL,and the unit cost of oil-based drilling fluid is reduced by over 15% compared to the fluid prepared with No.3 white oil.This fluid is suitable for -25 ℃ conditions and can meet construction needs during winter in the Liaohe Oilfield.The low-cost,low oil-water ratio,low-soil oil-based drilling fluid has been successfully applied in shale oil and tight oil formations in Liaohe Oilfield.Field application results demonstrate its stable performance,good plugging and anti-collapse capabilities,excellent emulsification stability,good low-temperature resistance,and significantly reduced unilateral cost.These research findings contribute to the expansion of the application scale of oil-based drilling fluid and can meet the technical requirements for the low-cost,safe,and efficient development of unconventional oil and gas reservoirs.

Improvement and Application of Mechanical Specific Energy Model in Buried Hill Reservoir Evaluation

Li Hongru, Tan Zhongjian, Cheng Weihong, Deng Jinhui, Zhang Ligang, Zhang Zhihu, Liu Zhiwei

2024, 31(4):  149-155.  DOI: 10.3969/j.issn.1006-6535.2024.04.019

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The buried hill reservoirs in the Bohai oilfield exhibit diverse lithology,complex geological conditions,and strong heterogeneity,making traditional mechanical specific energy models less sensitive to the reservoir's performance and hard to provide efficient guide exploration strategy.Therefore,based on micro-bit drilling tests and the moving window theory,this study analyzed the response patterns of mechanical specific energy to engineering parameters,constructed standardized mechanical specific energy models and modified mechanical specific energy models,also formulated interpretation standards for reservoir performance in buried hill reservoirs.The results indicate that the drilling pressure coefficient of buried hill reservoirs in Bohai oilfield ranges from 0.309 to 0.605.When the specific energy of the modified mechanical model is less than 0.80,it corresponds to Type Ⅰ and Type Ⅱ reservoir; when the specific energy ranges from 0.80 to 1.15,it corresponds to Type Ⅲ reservoir,while when it exceeds 1.15,it is tight reservoir.The research findings have been applied in 36 buried exploration wells in Bohai oilfield,with anaverage interpretation coincidence rate of reservoir performance of 80.2%.This study can provide technical support for exploration decisions such as midterm testing and completion drilling, and has significant reference value.

Experiment and Prediction Method of Liquid Holdup of Gas-liquid Two-phase Slug Flow with Different Viscosity in Inclined Tube

Liu Zilong, Qian Xiao, Liu Chao, Guan Tong, Wang Wei, Liao Ruiquan

2024, 31(4):  156-162.  DOI: 10.3969/j.issn.1006-6535.2024.04.020

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Accurate prediction of liquid holdup provides important basis for flow pattern identification and pressure drop calculation in wellbores. Slug flow is the most common flow pattern in heavy oil wellbores. High-viscosity fluids in the wellbore will exacerbate gas-liquid two-phase slippage, resulting in poor prediction accuracy of existing holdup models applied to high-viscosity fluids. Therefore, a new model for liquid holdup in gas-liquid two-phase slug flow in inclined pipes with different viscosities is proposed. This proposal is based on experimental observations and theoretical derivations. The holdup experiments of slug flow are conducted in a multiple phase pipe flow experimental platform, in a test string with an inner diameter of 60 mm. The influence of viscosity on liquid holdup and flow pattern transitions is studied based on the data of slug flow patterns and liquid holdup obtained with different viscosities and different inclinations in the experiments. The study shows that an increase in liquid viscosity will intensify the viscous resistance between the liquid phase and the pipe wall, resulting in a rise in liquid holdup. While the effect of viscosity on liquid holdup will change the transition boundaries between slug flow and other flow patterns. A new model for liquid holdup in gas-liquid two-phase slug flow in inclined pipes is established. This model is based on the Kora liquid holdup relationship formula and uses mixed-phase viscosity instead of liquid-phase viscosity. The model is validated by experimental and literature data, with confirmed higher accuracy. This research can provide technical support for predicting pressure drop in heavy oil wellbores.

Damage Analysis of Bedding Shale under Ultrasonic Vibration Based on Discrete Element Simulation

Yang Zhenwei, Liu Xiangjun, Xiong Jian

2024, 31(4):  163-168.  DOI: 10.3969/j.issn.1006-6535.2024.04.021

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This study is to simulate the damage of layered shale under ultrasonic vibration with different bedding dip angles by establishing a discrete element model of layered shale with numerical simulation methods so as to explore the feasibility of ultrasonic vibration-assisted shale reservoir stimulation. The results show that the angle between the vibration direction and the bedding surface has a significant influence on the propagation of ultrasonic vibration.The smaller the angle, the more microcracks generated.The racks are mainly concentrated near the vibration stress, and fewer microcracks are generated in areas further away from the vibration source.Ultrasonic vibration has an obvious impact on the strength of layered shale, inducing a large number of microcracks inside the shale, and the change of microstructure and physical properties of the shale, also the uniaxial compressive strength and elastic modulus are significantly reduced. This study provides a theoretical basis for reservoir stimulation of layered shale using ultrasonic vibration.

Synthesis and Performance Evaluation of Clay-free Water-based Drilling Fluid with Hyperbranched Polymer Filtrate Reducer

Ding Weijun, Zhang Ying, Yu Weichu, Ding Fei, Yang Shichu, Pu Hongbing, Duan Wenbo

2024, 31(4):  169-174.  DOI: 10.3969/j.issn.1006-6535.2024.04.022

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Under high temperature conditions,the degradation of polyacrylamide filtrate reducer molecules leads to a significant decrease in filtrate reduction efficiency.To address this issue,a high temperature resistant hyperbranched polymer filtrate reducer(JHPAS)was synthesized through copolymerization of hyperbranched monomer allyl pentaerythritol(APE)with 2-acrylamido-2-methylpropane sulfonic acid(AMPS),acrylamide(AM),and sodium styrene sulfonate(SSS).A novel clay-free water-based drilling fluid was formulated using JHPAS,and its filtrate reduction mechanism was analyzed.The rheological properties and filtrate performance under high temperature and high salt conditions were evaluated.The results demonstrate that JHPAS exhibits excellent thermal stability and has the ability to create a network structure in an aqueous solution. It adsorbs onto the surface of superfine CaCO₃,forming a compact filter cake in clay-free water-based drilling fluid,effectively plugging the pores on the filter cake and consequently reducing the filtrate loss of drilling fluid.The developed clay-free water-based drilling fluid maintains consistent rheological properties and demonstrates effective filtrate loss reduction even after exposure to 200 ℃ aging for 16 hours and saturated sodium chloride brine.The API filtrate loss and high-temperature,high-pressure filtrate loss are measured at 5.5 mL and 7.6 mL,respectively.These research findings contribute to advancing the exploration and utilization of hyperbranched polymers in drilling fluids for in deep and ultra-deep reservoirs.