Table of Content

25 August 2023, Volume 30 Issue 4

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Summary

Research Progress on Calculation Methods and Influencing Factors of Tight Reservoir Irreducible Water Film Thickness

Liu Zhinan, Zhang Guicai, Wang Zenglin, Ge Jijiang, Du Yong

2023, 30(4):  1-9.  DOI: 10.3969/j.issn.1006-6535.2023.04.001

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To address the problem that there are many kinds of calculation methods for the thickness of irreducible water film in tight reservoirs, and the method cannot be accurately selected in the actual research, the calculation methods and influencing factors of irreducible water film thickness in tight reservoirs are summarized in recent years. The study shows that the calculation methods for irreducible water film thickness in tight reservoirs are divided into macroscopic calculation methods based on the ratio of irreducible water film volume to pore throat surface area and microscopic derivation methods that simplify the matrix into capillary model or from the perspective of microelements; the irreducible water film is divided into initial water film, post-displacement water film and post-imbibition water film, and the thickness of the initial water film is influenced by the relative humidity, reservoir depth and permeability of the reservoir, and the thickness of the post-displacement water film is influenced by the displacement pressure, permeability and porosity, and the post-imbibition water film thickness is influenced by the water saturation, ion mass concentration and matrix composition. This study has implications for the selection of calculation methods for the irreducible water film thickness in tight reservoirs and the study of recovery enhancement.

Geologic Exploration

Heterogeneity of Chang 7 Shale Oil Reservoir and Its Oil Control Law in Ganquan Area, Ordos Basin

Zhong Hongli, Zhuo Zimin, Zhang Fengqi, Zhang Pei, Chen Lingling

2023, 30(4):  10-18.  DOI: 10.3969/j.issn.1006-6535.2023.04.002

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To reveal the macro heterogeneity of shale oil reservoirs in the Chang 7 oil reservoir formation, Ganquan area in the southeastern part of the Yishan Slope, Ordos Basin and its control on oil distribution, the macro heterogeneity of the Chang 7₁ and Chang 7₂ oil reservoir sub-formations was quantitatively characterized and compared by means of barrier bed and interbed identification statistics, permeability statistics and Lorenz curve construction, and the influence of macro heterogeneity on oil distribution was analyzed by the method of correlation analysis and multifactor overlay. The results of the study show that the average number of interbeds developed in the Chang 7₁ and Chang 7₂ shale oil reservoirs in the study area is 3.8 and 5.1 respectively, and the permeability of the sand body is dominated by composite rhyme and is strongly heterogeneous; the average number of barrier beds developed is 3.4 and 2.8 respectively, and the average thickness of single barrier bed is 6.0 and 4.9 m respectively; Chang 7₁ exhibits slightly weaker intra-layer heterogeneity and stronger inter-layer heterogeneity than Chang 7₂. The rhythmicity of the shale oil sandstone reservoir has obvious influence on the oil saturation, and the barrier bed with thickness greater than 10.0 m have obvious capping effect on oil and gas, while the "physical" barrier beds and interbeds constitute lateral shielding for oil and gas accumulation. The barrier bed is more developed in Chang 7₁ than Chang 7₂, and the oil and gas are more abundant in Chang 7₂. In the plane, the distribution of oil-gas accumulation area is strip-like, mostly located in the area with large sand thickness, good continuity and permeability of greater than 0.2 mD.The thickness of oil layer varies slightly in the direction of sand body extension along the river, but varies more in the direction of vertical river extension. The conclusion of the study can provide theoretical reference for the evaluation of the favorable area and the selection of development parameters for the Chang 7 sandwich type shale oil in the southeastern part of the Yishan slope of Ordos Basin.

Study on Hydrocarbon Generation Characteristics of Carboniferous-Permian Coal-measure Source Rocks in Huanghua Depression, Bohai Bay Basin

Wang Xin, Li Zheng, Zhu Rifang, Li Ping, Wang Ru, Niu Zicheng, Lou Da

2023, 30(4):  19-27.  DOI: 10.3969/j.issn.1006-6535.2023.04.003

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In recent years, several condensate reservoirs supplied with hydrocarbons from Carboniferous-Permian coal-measure source rocks have been identified in the Bohai Bay Basin, showing considerable exploration potential. To address the problems of poorly understood hydrocarbon generation characteristics and unclear exploration directions in the study area, it is urgent to reconceptualize the hydrocarbon supply capacity of coal-measure source rocks. To this end, the Huanghua Depression in the Bohai Bay Basin was taken as the research object, and the spatial distribution, hydrocarbon generation potential and hydrocarbon generation characteristics of different lithologies of coal-measure source rocks in the Huanghua Depression were comprehensively analyzed through multivariate data statistics such as cores, well logging, mud logging and oil production testing, based on the analysis of the difference of sedimentary filling characteristics of tectonic units in the basin, and the evaluation model of sedimentary units established by using the numerical simulation technology for the basin.The hydrocarbon generation pattern of Carboniferous-Permian coal-measure source rocks in the Bohai Bay Basin was clarified, and a favorable hydrocarbon accumulation zone in the study area was predicted. The result shows that for the Carboniferous-Permian coal-measure source rocks in the Huanghua Depression, the coal rock is the marker bed, and three types of hydrocarbon generation lithologies are developed: mudstone, carbonaceous mudstone and coal rocks, among which the mudstone is thick and continuous with high hydrocarbon generation potential; the hydrocarbon generation simulation shows that the primary hydrocarbon generation is dominated by oil production from mudstone, and the secondary hydrocarbon generation is dominated by mixed oil and gas production from various hydrocarbon source rocks; three types of hydrocarbon generation patterns are developed: early subsidence type, late subsidence type and continuous subsidence type, and the hydrocarbon generation areas of continuous subsidence and late subsidence types are the most favorable for in-situ oil and gas accumulation in the buried hill. The results of the study can provide technical support and data for theoretical research and exploration deployment of oil and gas accumulation by hydrocarbon supply from coal-measure source rocks in the study area.

Main Controlling Factors and Reservoir Formation Mode of Oil and Gas in the Putaohua Reservoir in Sanzhao Sag, Songliao Basin

Qin Yingfeng

2023, 30(4):  28-34.  DOI: 10.3969/j.issn.1006-6535.2023.04.004

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To address the problem that the main controlling factors of hydrocarbon enrichment in the Putaohua reservoir in the Sanzhao Sag of the Songliao Basin are unclear, the main controlling factors of hydrocarbon accumulation are comprehensively analyzed by using test data and seismic data, and a hydrocarbon enrichment model is established to provide a theoretical basis for hydrocarbon exploration. The results of the study show that the sedimentary microfacies controls the distribution of favorable reservoirs; the oil source faults and sand bodies form the dominant transportation channels; two major types of tectonic-lithologic traps and lithologic traps have been developed in the Sanzhao Sag, which are subdivided into four subcategories: nose-like tectonic-lithologic traps, fault-lithologic traps, low-amplitude anticline-lithologic traps, and single sand body up-dip thin-out traps, and these facilitated traps control the distribution of oil and water in the study area, forming a hydrocarbon accumulation model of reservoir control by sedimentary microfacies, transport control by oil source faults and sand bodies, and enrichment control by traps. This study can provide effective theoretical guidance for the exploration of the Putaohua reservoir in the Sanzhao Sag of the Songliao Basin.

Response of Well Logging and "Sweet Spot" Rapid Evaluation Technology for Shale Oil in the Lucaogou Formation of Jimsar Sag

Xiong Xiong, Xiao Dianshi, Lei Xianghui, Li Yingyan, Lu Shuangfang, Wang Meng, Peng Yue, Guo Xueyi

2023, 30(4):  35-43.  DOI: 10.3969/j.issn.1006-6535.2023.04.005

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The hybrid sedimentary shale oil is complex in lithology, with many mineral types and rapid lateral changes in the "sweet spot".The conventional logging is not sensitive to the lithology, physical properties and oil-bearing properties response, while the NMR logging requires petro-physical experimental calibration and long interpretation period, so there is a lack of effective on-site "sweet spot" rapid evaluation technology. To address the above problems, the shale oil reser-voir in the Lucaogou Formation of the Jimsar Sag of the Junggar Basin is taken as an example to study the response characteristics of gas logging, carbonate minerals, drilling time and other logs to the lithology, physical properties and oil-bearing properties of hybrid sedimentary shale oil based on the interpretation of NMR logging, so that the internal connection is clarified and sensi-tive parameters are selected to achieve the rapid evaluation of parameters and "sweet spots" of shale oil reservoir. The study shows that the lithology, physical properties and oil saturation of the hybrid sedimentary shale oil all have obvious responses on the logging data, among which, carbo-nate content and dolomite percentage can effectively reflect the main lithologies such as siltstone, dolomitic siltstone, psammitic dolomite, dolomicrite and dolomitic limestone, the carbonate con-tent and total hydrocarbon/drilling time are sensitive to the porosity, and the carbonate content, humidity ratio and total hydrocarbon are sensitive to the oil saturation. Based on the interpretation model of logging sensitive parameters such as porosity and oil saturation, the accuracy can reach 71.0%.Compared with the NMR logging, the identification rate of "sweet spot" of Class I oil formation is over 90%, thus achieving rapid and accurate evaluation of "sweet spot" of shale oil in the process of drilling. The results of the study are useful for improving the drilling catching rate of the "sweet spot" in horizontal wells of hybrid sedimentary shale oil and for reducing costs and increasing efficiency.

Identification Method and Application of Marine-Continental Transitional Shale Laminae Based on Rock Thin Section Image

Li Jiahang, Li Wei, Liu Xiangjun, Li Xingtao, Li Yongzhou, Xiong Jian, Liang Lixi

2023, 30(4):  44-53.  DOI: 10.3969/j.issn.1006-6535.2023.04.006

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Rock thin section image is one of the most direct and effective means to identify shale laminae. Using image color segmentation to identify shale laminae is a conventional method.When it is applied to the marine-continental transitional shale with complex and diverse laminae morphology, the identification effect depends on the local features of the image and is greatly affected by the laminae morphology. To address the above problems, we propose a method to identify marine-continental transitional shale laminae structure by converting rock slice thin images into frequency domain images using two-dimensional discrete Fourier transform, extracting frequency domain image features with principal component analysis technology, and establishing characterization parameters of shale laminae structure development degree. The method was applied to the analysis of rock thin section images of the target reservoir in the study area, and the application results showed that: The method is more applicable to the complex and diverse marine-continental transitional shale shale strata than the conventional method, and the conformation rate of laminae identification reaches more than 90%. The method can provide strong support for shale structure analysis and anisotropy evaluation.

A Comparative Study Of the Pore Structure of Deep-Medium Shale in the Longmaxi Formation of the Southern Sichuan Basin

Bai Lixun, Gao Zhiye, Wei Weihang, Yang Biding

2023, 30(4):  54-62.  DOI: 10.3969/j.issn.1006-6535.2023.04.007

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The direction of shale gas exploration has gradually changed from medium-deep shale to deep shale, but the unclear differences in the pore structure characteristics of medium-deep to deep shales and the unknown controlling factors have restricted the understanding of the reservoir formation and accumulation mechanism of deep shale gas. To this end, a comparative study of geological characteristics, rock characteristics and pore structure of the medium-deep to deep shales of the Longmaxi Formation in the Changning and Dingshan areas of southern Sichuan Basin was conducted on the basis of field emission scanning electron microscopy (SEM), high-pressure mercury injection, nitrogen adsorption experiments and organic geochemical parameters. The study shows that: The differences in carbonate minerals and quartz content between the medium-deep and deep shale samples in the southern Sichuan Basin are relatively large, and the medium-deep and deep shale samples both have higher clay mineral contents; the organic matter of the medium-deep shale in Changning area is uniformly developed but with small pores, and the dissolution pores and intergranular pores are more developed, whereas the primary intergranular pores and organic matter pores of the deep shale in Dingshan area are more developed, and the organic matter pores are larger; the pore volume and specific surface area of the medium-deep shale in Changning area are mainly contributed by micropores, whereas the pore volume and specific surface area of the deep shale in Dingshan area are mainly contributed by mesopores and macropores; the differences in mineral components caused by different depositional environments are one of the main factors resulting in the differences in the pore structure of the 2 sets of shales. The research results are of great significance for further understanding of the reservoir formation mechanism of deep shales.

Shale Reservoir Characteristics and Shale Oil Mobility in Member 2 of Kongdian Formation of Cangdong Sag, Bohai Bay Basin

Wen Jiacheng, Hu Qinhong, Yang Shengyu, Ma Binyu, Wang Xuyang, Pu Xiugang, Han Wenzhong, Zhang Wei

2023, 30(4):  63-70.  DOI: 10.3969/j.issn.1006-6535.2023.04.008

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The shale oil resources in Member 2 of Kongdian Formation of Cangdong Sag, Bohai Bay Basin are abundant, but there are few studies on the reservoir characteristics, occurrence, mobility and its correlation. To this end, the argon ion polishing field emission scanning electron microscopy, neutron scattering, high pressure mercury injection and low-temperature nitrogen adsorption experiments are adopted to describe the microscopic pore structure of the shale oil reservoir in Member 2 of Kongdian Formation, to compare the difference in pore volume before and after extraction with the saturation-centrifugal NMR results, and to reveal the characteristics of shale oil occurrence and mobility. The results of the study show that in the shale oil in Member 2 of Kongdian Formation, the nanometer-sized intra-granular pores, dissolution pores, organic pores and micron-sized micro-fracture and other reservoir spaces are mainly developed; the shale oil is mainly occurred in the pores with diameters ranging from 20-40 nm and 80-200 nm; the high saturation of movable oil in the felsic shale indicates that it has better pore connectivity and seepage capacity, which is conducive to the transportation of shale oil. The mineral content and pore structure in shale reservoirs jointly control the mobility of shale oil. Pores with a pore size less than 50 nm have a larger specific surface area and have a stronger adsorption capacity for shale oil, which is not conducive to the flow of shale oil. The study results have important guidance for the exploration and development of shale oil.

Microscopic Pore Structure Characteristics of Tight Sandstone Reservoirs and Its Classification Evaluation

Meng Jing, Zhang Liying, Li Rui, Zhao Aifang, Zhu Biwei, Huang Pei, Shen Shibo

2023, 30(4):  71-78.  DOI: 10.3969/j.issn.1006-6535.2023.04.009

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To address the problem of unclear microscopic pore structure characteristics of tight sandstone in Block XAB, by using the experiments such as high-pressure mercury injection (HPMI), nuclear magnetic resonance (NMR), cast thin section (CTS) and scanning electron microscopy (SEM), the microscopic pore distribution and connectivity characteristics of tight sandstone reservoirs in Block XAB was studied; the relationship between parameters such as effective pore throat radius, effective porosity and effective movable porosity and macroscopic physical properties was clarified, and the microscopic and macroscopic characteristics of typical pore structure reservoirs was identified and evaluated. The results of the study show that the target reservoir had many pore types and a wide range of pore sizes, but the overall pore size was less than 2 μm, and the pore throat was dominated by large pore-fine throat ink bottle type connectivity; the pore throat with pore size larger than the effective pore throat radius had a small proportion of the total pore volume, but it contributed more than 90% to the permeability; the pore size distribution range measured by NMR was wider than that of HPMI, and the effective movable porosity excluded the existence of unmovable water in the isolated large pores; there was a strong positive correlation with the effective porosity obtained by HPMI, and a high index relationship with the permeability; the pore throat radius had an important role in controlling the microscopic pore structure and macroscopic reservoir quality; the target reservoir pore structure can be classified into three types, i.e., type Ⅰ, Ⅱ and Ⅲ, and the average effective movable porosity was 2.93%, 0.78% and 0.15%, respectively, as the reservoir pore structure parameters became worse. The study results are of great significance for the effective evaluation of the target reservoir and its efficient development.

Study on the Sedimentary Environment and Main Controlling Factors of Organic Matter Enrichment of Marine Shale in Zigong Area of the Southern Sichuan Basin

Yao Tianxing, Li Zhongcheng, Guo Shichao, Song Peng, Wang Hailong, Tang Xiaodan

2023, 30(4):  79-86.  DOI: 10.3969/j.issn.1006-6535.2023.04.010

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To deepen the understanding of the sedimentary environmental characteristics and organic matter enrichment mechanism of the marine shale of the Wufeng Formation-Longmaxi Formation in the Zigong area of the southern Sichuan Basin, a comprehensive study was carried out on the sedimentary environmental characteristics of the Well Z303 by conducting experiments on organic geochemistry and elemental geochemistry. The results of the study show that: The organic matter abundance of marine shales in the target area is high, with an average TOC content of 2.15%; the mineral composition is dominated by quartz and clay minerals, and the redox environment is the main controlling factor for organic matter enrichment in the Zigong Area; the organic matter enrichment conditions during the deposition period of the Wufeng Formation and Lower Longmaxi Formation are more superior than those during the deposition period of the Middle and Upper Longmaxi Formations, forming favorable shales rich in organic matter and high in brittle minerals.It is the preferred target for shale gas exploration and development in the study area.

Reservoir Engineering

Establishment and Application of Pressure Drive Dynamic Fracture Model for Tight Oil Reservoirs

Cui Chuanzhi, Wang Junkang, Wu Zhongwei, Sui Yingfei, Li Jing, Lu Shuiqingshan

2023, 30(4):  87-95.  DOI: 10.3969/j.issn.1006-6535.2023.04.011

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To address the problem that conventional reservoir numerical simulation software cannot accurately simulate the fracture propagation during the development of pressure drive water injection of tight oil; based on the dynamic fracture propagation law during the development of pressure drive, the fracture propagation model is organically coupled with the oil-water two-phase seepage model of tight oil reservoir, a pressure drive water injection model was established, and the problem was solved by the finite difference method. The model was applied to the five-point injection and recovery well network of Well Cluster X8 in an oilfield to study the production dynamic characteristics of pressure drive development under high-speed constant displacement and step increasing displacement. The result shows that the injection displacement is positively correlated with the fracture propagation velocity; under the same injection displacement, the fracture propagation speed in the near-wellbore zone of the water injection well is faster; dynamic fracture made the pressure and injected water propagate along the fracture propagation direction; in a five-spot pattern well network with a cumulative injection volume of 3×10⁴m³, compared with the step increasing displacement with high-speed constant displacement method, the fracture propagation length is increased by 11.9 m, and the oil-water front edge migration lags by 4.2 m; corresponding to corner wells, the effective time was 5 days later, the water breakthrough time was 31 days later, and the staged recovery degree was 0.45 percentage points higher; the step increasing displacement pressure drive method improved the affecting area of the injected water, delayed the water breakthrough time of the production well, and improved the development effects of the reservoir. The research results can provide technical support for pressure drive development water injection design of tight reservoirs.

Non-grid Numerical Simulation of Two-Phase Fluid-Solid Coupling for Shale Gas Reservoir

Wu Jianfa, Zhu Weiyao, Zhang Deliang, Chen Zhen, Wu Tianpeng

2023, 30(4):  96-103.  DOI: 10.3969/j.issn.1006-6535.2023.04.012

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Aiming at the difficulty of productivity prediction in shale gas reservoirs due to the influence of two-phase complex flow and fluid-solid coupling, the seepage field is divided into the primary modified zone, the secondary modified zone and the unmodified zone, and a multi-scale gas-water two-phase flow-fluid-solid coupling mathematical model is established by combining the multi-fluid unified transport model and the equivalent continuous non-uniform medium physical model, and the mathematical model is programmed and solved by gridless generalized finite difference. The results of the study show that the gridless generalized finite difference method can adapt to different computational domains and avoid the arithmetic instability caused by the coupling of traditional difference grids with unstructured grids; the propagation of the pressure drop leading edge in the unmodified zone is only about 20 m, and the solid displacement mainly occurs in the junction area between the secondary modified and unmodified zones; neglecting the influence of the stress field, the gas production is significantly overestimated at the early stage of gas well production, and this influence gradually decreases at the later stage of production; the shale gas reservoirs with low initial water saturation are more beneficial for development, focusing on water saturation during reservoir selection. The study results have important guidance for future numerical simulations of fluid-solid coupling and unconventional oil and gas reservoir capacity prediction.

Tight Oil Horizontal Well Production Profile Interpretation Method Based on Distributed Temperature Sensing

Luo Hongwen, Zhang Qin, Li Haitao, Zhu Hanbin, Liu Wenqiang, Xiang Yuxing, Ma Hansong, Li Ying

2023, 30(4):  104-112.  DOI: 10.3969/j.issn.1006-6535.2023.04.013

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To address the problem of difficult quantitative diagnostic techniques for tight oil horizontal well production profiles, the tight oil horizontal well temperature profile predicting model is used as the forward model, and a tight oil horizontal well distributed temperature sensing (DTS) data inversion model is established based on the simulated annealing (SA) algorithm, forming a DTS-based tight oil horizontal well production profile interpretation method, to achieve the quantitative inversion interpretation of the tight oil horizontal well production profile and fracture parameters. The result shows that the tight oil horizontal well temperature profile is sensitive to the following factors in descending order: fluid production, fracture half-length, permeability, integrated heat transfer coefficient of wellbore, porosity, fracture conductivity, and thermal conductivity of reservoir rocks, and the main controlling factors affecting the temperature profile of tight oil horizontal wells are fracture half-length and formation permeability distribution. The inversion model was used to invert the measured DTS data from three different production stages of one field well, and the average compliance rate between the production profile interpretation results and the commercial software interpretation results was 87.39%, which verified the reliability of the production profile interpretation method for tight oil horizontal wells. The study results have important guidance for the quantitative interpretation of the tight oil horizontal well production profile.

Numerical Simulation Study on Parameters Optimization of CO₂ Huff-n-puffin Tight Reservoir

Song Baojian, Li Jingquan, Sun Yili, Zhang Wei, Liu Peng

2023, 30(4):  113-121.  DOI: 10.3969/j.issn.1006-6535.2023.04.014

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To improve the development effect of oil wells after fracturing in tight reservoirs, based on the Block ZD of Henan Oilfield, the permeability-stress sensitivity relationship of matrix and fracture was determined by fracture-variable-conductivity physical experiments, and the numerical simulation was applied, to determine the optimal values of CO₂ huff-n-puff parameters in different reservoirs of tight oil reservoirs. The result shows that in the injection and shut-in stages, the affected area of CO₂ is getting wider and wider, the crude oil viscosity in the affected area decreases significantly, and the CO₂ is produced with the crude oil in the production stage, and the range of production is larger; the oil exchange rate increases and then decreases with the increase of CO₂ injection volume or shut-in time, which is positively correlated with the CO₂ injection rate and negatively correlated with the huff-n-puff period; the better the reservoir physical properties, the lower the optimal CO₂ injection volume and injection rate, and the shorter the optimal shut-in time and the longer huff-n-puff cycles. The CO₂ huff-n-puff test was carried out in Well ZA4121 in four types of reservoirs, and the accumulated oil increment was 303.4 t, which achieved a good development effect with an oil exchange rate of 0.16 t/t. The research results can provide reference for the study and application related to CO₂ huff-n-puff after fracturing in tight reservoirs.

Productivity Assessment of Tight Gas Wells after Fracturing based on Unstable Pressure Well Test Analysis

Wang Tao, Yu Haiyang, Zhao Pengfei, Li Jingsong, Liu Rumin, Kou Shuangyan, Wang Jing, Liao Shuang

2023, 30(4):  122-130.  DOI: 10.3969/j.issn.1006-6535.2023.04.015

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To solve the problem of difficultly predicting the productivity for tight gas reservoirs after fracturing, based on the seepage mechanism and considering the stress sensitivity of the formation and the effect of formation improvement after fracturing, a linear heterogeneous composite zone fractured well model applicable to the inversion of fracture pump-stop is established, the fracture parameters and formation parameters are determined by using the established model and numerical well tests, and the relationship between productivity and fracture scale before and after fracturing is established by applying SPSS regression method, to obtain the The relationship between productivity and fracture scale before and after fracturing was established by applying SPSS regression method, to obtain the productivity prediction method for tight gas reservoirs after fracturing. The study shows that the double logarithmic characteristic curves of shut-in pressure change after hydraulic fracture pump-stop can be divided into fracture linear flow stage, transition stage, interfacial flow stage, outer zone linear flow stage and boundary effect stage; the newly established productivity prediction method is applied to Well Block X in Yulin Gas Field, with the average error of productivity prediction of 16.1% and good applicability; the effects of different fracturing parameters on productivity are, in descending order, discharge volume, sand addition volume, and fracturing fluid volume, with the optimal fracturing discharge volume of 3.36-4.83 m³/min, the optimal sand addition volume of 56.95-77.66 m³, and the optimal fracturing fluid volume of 167.09-259.91 m³.The study results have certain guidance for optimizing the fracturing design and post-fracturing productivity prediction of tight gas reservoirs.

Pore Structure and Oil-Water Two-Phase Seepage Characteristics of Tight Oil Reservoirs Based on Stress Sensitivity

Wang Changquan, Tian Zhongjing, Wang Chenchen, Chen Liang, Wang Guoqing

2023, 30(4):  131-138.  DOI: 10.3969/j.issn.1006-6535.2023.04.016

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To address the problem of poor fluid permeability and reduced production capacity caused by strong stress sensitivity in tight reservoirs, a core from a tight reservoir in the Jidong Oilfield was selected for full-diameter core displacement experiments and in situ CT scanning experiments to study the pore structure and oil-water two-phase permeability characteristics of tight reservoirs under the stress sensitivity. The study shows that with the increase of net stress, the stress sensitivity increased, the throat and larger pores in the core were compressed and deformed, some of the ultra-fine pores were even closed, the falling speed of the relative permeability of the oil phase and the rising speed of the relative permeability of the water phase increased, and the two-phase permeability curve gradually shifted down; the saturation of irreducible water and residual oil increased, the co-permeability point shifted to the right, the two-phase permeability zone gradually became smaller, and the efficiency of water-oil displacement decreased; it indicated that after water breakthrough in the oil well, the water cut increased significantly, the oil-water production period was shorter, the breakthrough of water displacement was rapid, and the efficiency of water-oil displacement decreased.The impact of stress sensitivity on oil-water two-phase seepage law and recovery factor was mainly reduced by supplementing formation energy. The study results have important guidance significance for the development of technical solutions for tight reservoir development.

Drilling & Production Engineering

Study on Numerical Simulation of Cementing Displacement Efficiency of Horizontal Expansion Well Sections in Shale Reservoir

Sun Xiaofeng, Tao Liang, Zhu Zhiyong, Yu Furui, Sun Minghao, Zhao Yuanzhe, Qu Jingyu

2023, 30(4):  139-145.  DOI: 10.3969/j.issn.1006-6535.2023.04.017

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Improving the displacement efficiency of horizontal expansion well section is one of the ways to improve the quality of horizontal well cementing, but the relevant study assumptions are too ideal and do not match the actual situation in the field. For this reason, a three-dimensional displacement simulation study of cementing slurry in elliptical horizontal expansion well section was carried out by using CFD numerical simulation method and taking Gulong Shale Reservoir as an example. The result shows that the higher the eccentricity, the more significant the flow velocity difference at the wide and narrow gap of the expansion well section, and when the eccentricity was 0.7, the flow velocity difference reached 2.00 m/s, which made it difficult for drilling fluid to be completely displaced.When the maximum expansion well section was located in the middle of the expansion section, the cement slurry displacement efficiency was the highest, and when the expansion section was close to one side of maximum expansion section, the cement slurry displacement efficiency became poor, and it was easy to form a drilling fluid stagnation zone.Under the condition of high casing eccentricity, the displacement efficiency improved significantly with the increase of casing speed, and when the eccentricity was 0.7, the casing speed increased from 30 r/min to 40 r/min, and the displacement efficiency increased by 1.17 percentage points; the spindle rotation changed the geometry of the expansion well section, and the displacement efficiency changed significantly when the spindle azimuth was 60-120 °, and decreased by 0.81 percentage points when the spindle azimuth increased from 60 ° to 90 °. The study results can help to improve the cementing quality of elliptical horizontal expansion well sections in shale reservoirs.

Characteristics of Proppant Placement in Fractures Dynamically Coupled between Fracture Propagation and Sand Transport

Li Xiaogang, He Jiangang, Huang Yanhong, Yi Liangping, Zhang Jingqiang, Du Bodi, Huang Liuke

2023, 30(4):  146-155.  DOI: 10.3969/j.issn.1006-6535.2023.04.018

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The dynamic coupling of fracture propagation and proppant migration is one of the challenges in terms of hydraulic fracturing numerical simulation technology. In order to investigate the characteristics of proppant placement in shale dynamic fractures, based on the three-dimensional discrete element method, a dynamic coupling numerical model of fracture propagation and proppant migration in shale reservoirs considering bedding was established, and the laws of fracture propagation and proppant placement under different proppant particle sizes, proppant density, fracturing fluid viscosity and proppant injection methods were analyzed. The study shows that: The smaller the particle size, the wider the proppant placement range and the more uniform placement.The placement area and placement efficiency of the proppant with a particle size of 150 μm are 1.8 times that of the proppant with a particle size of 600 μm; the proppant density was not the main factor affecting fracture propagation and proppant migration; the higher the viscosity of fracturing fluid, the smaller the fracture area and placement area, and the higher placement efficiency, the viscosity increased from 1 mPa·s to 15 mPa·s, and the fracture area decreased by 45%, and the placement area reduced by 34%, and the placement efficiency increased by 12%.When the proppant injection method is step injection, the fracturing fluid has the best effect on fracture creation and sand carrying. The study results can provide theoretical guidance for effective modification of shale reservoirs.

Study on Mathematical Model and Influencing Factors of Composite Temporary Plugging Pump Pressure in Shale Gas Wells

Kong Xiangwei, E Xuanji, Qi Tianjun, Chen Qing, Ren Yong, Wang Subing, Li Ting, Liu Yu

2023, 30(4):  156-162.  DOI: 10.3969/j.issn.1006-6535.2023.04.019

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At present, the pump pressure prediction of shale gas well fracturing mainly relies on commercial software fitting, and there are few mathematical models for predicting the amount of temporary plugging agent and pump pressure. To this end, a mathematical model for pump pressure prediction of composite temporary plugging was proposed by taking into account the final speed of temporary plugging agent migration, fracture width, temporary plugging agent resistance and other factors, and the effect of composite temporary plugging parameters on pump pressure was analyzed. The result shows that with the dosage increase of composite temporary plugging agent dosage, the pump pressure increases; compared with the single temporary plugging agent, the dosage of composite temporary plugging agent dosage is more sensitive to the pump pressure; with the increase of temporary plugging particle size, the peak pump pressure shows an increasing trend; the pressure starting and boosting time of composite temporary plugging agent is significantly reduced compared with the single temporary plugging agent, and the temporary plugging effect is better; when the dosage of composite temporary plugging agent is 180 g, the pressure boosting time is 31 s, and the peak pump pressure can reach 17.5 MPa, compared with the temporary plugging agent with the particle size of 0.8 mm, the boosting time is shortened by 51 s, the peak pump pressure is increased by 2.7 MPa, and the boosting speed is increased by 63.09%. Indoor experiments and field applications show that the maximum errors between the calculated and measured pump pressure values are 6.76% and 6.27% respectively. It has guidance significance of the mathematical model of composite temporary plugging pump pressure prediction to the dosage of temporary plugging agent and the evaluation of temporary plugging effect.

Technology of Strong Plugging Constant Rheology Oil-Based Drilling Fluid for Shale Oil Reservoir in Damintun Sag of Liaohe Basin

Yin Jiafeng, Wang Xiaojun, Lu Zhengquan, Bu Wenyang, Sun Lei, Jing Yeqi, Sun Yunchao, Wen Li

2023, 30(4):  163-168.  DOI: 10.3969/j.issn.1006-6535.2023.04.020

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In response to the technical problems such as frequent occurrence of complicated accidents due to insufficient plugging performance of oil-based drilling fluid and long cycle processing time and difficulty in transfer due to strong sensitivity to low temperature in the development of shale oil reservoir in Liaohe Oilfield, an oil-based cross-linked plugging agent and low temperature rheology improving agent were developed to form a set of strong plugging and constant rheology oil-based drilling fluid system, and the performance evaluation and practical application of this drilling fluid system were carried out. The study shows that: The density of strong plugging constant rheology oil-based drilling fluid is 1.80-2.40 g/cm³, and the low temperature resistance reaches -25 ℃ and high temperature resistance reaches over 220 ℃; the drilling fluid has good rheology and settlement stability, the primary recovery rate of shale is 100.0%, the secondary recovery rate is 97.5%, and the plugging rate for shale reaches 60%, which can efficiently slow down the pressure transfer inside the shale. The field application shows that, Strong plugging constant rheology oil-based drilling fluid system has stable rheology and is easy to adjust, with good wellbore stability and high rate of penetrate. This technology can provide a technical reference for efficient drilling of deep and ultra-deep wells in shale and other complex formations.

Experimental on Distribution of Fracturing Proppant between Perforating Clusters in Horizontal Wellbore

Zhao Jiale, Li Ting, Wang Gang, Yang Qi, He Meiqi, Wu Qingmiao, Li Shaoming

2023, 30(4):  169-174.  DOI: 10.3969/j.issn.1006-6535.2023.04.021

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In order to study the distribution of proppant in the perforation cluster and analyze the principle of proppant settlement along the horizontal wellbore, an indoor experimental simulation device was established to analyze the influence of the factors above on the distribution of proppant in the perforation cluster by changing the parameters of proppant pumping displacement, particle size, sand ratio, etc. The results of the study show that under the low pumping displacement, with the increase of sand ratio, the distribution of 20/40-mesh quartz sand mainly changed from the 2ndand 3rd perforation clusters to the 1st and 2nd perforation clusters, and 40/70-mesh quartz sand mainly concentrated in the 1st perforation cluster; under the high pumping displacement, the distribution of 20/40-mesh quartz sand was similar to the low pumping displacement, and 40/70-mesh quartz sand was influenced by the high speed fluid and migrated at a speed far beyond the critical deposition rate, and mainly deposited at the 3rd perforation cluster.Under the same sand ratio, the impact of fluid on small-sized quartz sand is weaker, so the proppant was easily deposited nearby, while the impact on large-sized quartz sand is stronger and more easily deposited far away; with the increase of sand ratio, the mass proportion of proppant in the 1st perforation cluster gradually increases, and significantly decreased in the 3rd perforation cluster. This study provides a strong support for the optimization of perforation clusters for horizontal well staged fracturing and improvement of the stimulation effect.