Feasibility of gas displacement application between horizontal wells in shale oil

doi:10.3969/j.issn.2096-1693.2026.02.005

Abstract

Abstract:

The Lucaogou formation of the Permian System in the Jimsar Sag, Junggar Basin, represents a typical example of mixed siliciclastic-carbonate continental shale oil in China. After more than a decade of exploration and pilot development, remarkable technological and production breakthroughs have been achieved, confirming its substantial resource potential. Nevertheless, the current depletion-based development mode continues to face critical challenges such as rapid formation energy loss, sharp production decline rates, and persistently low recovery factors. The key technical direction for improving oil recovery at the later stage of development therefore remains unclear and urgently requires systematic investigation. To address these issues, a coupled numerical model of hydraulic fractures and the shale matrix was established based on the actual geological model of a well platform located in the lower sweet-spot interval of the Jimsar Sag. The model was validated through history matching by optimizing key reservoir and fracture parameters. On this basis, an inter-well gas injection displacement scheme involving three horizontal wells was designed, in which gas is injected through the central well and oil is produced from the two adjacent wells following an initial depletion phase. Simulation results show that, for Jimsar shale oil characterized by an ultra-tight matrix and poorly developed natural fractures, the degree of communication between horizontal wells through hydraulic fractures is the key factor determining the effectiveness of gas injection development. Comparative analyses of different injected gases (CO₂ and CH₄), injection timing, and injection pressure were performed to clarify their influence on the displacement process. Based on these results, an optimized operation strategy was proposed, involving cyclic reinjection of produced gas after the initial breakthrough of the injected gas at the production wells. Compared with depletion development, the designed inter-well gas injection scheme increases the cumulative oil production by approximately 45%, while the oil utilization ratio-an indicator of carbon and energy efficiency-nearly doubles. The proposed cyclic reinjection of produced gas further enhances carbon utilization efficiency and reduces the external CO₂ supply demand, thereby achieving a dual objective of improving oil recovery and promoting effective carbon recycling. Overall, the developed coupled model and the derived optimization strategy provide a technically feasible and scientifically grounded approach for enhancing oil recovery in continental shale oil reservoirs. The findings clarify the mechanisms and governing parameters of inter-well gas displacement under ultra-tight conditions, and the proposed cyclic reinjection mode offers a practical pathway for synergistic oil production enhancement and CO₂ geological utilization. This study provides important theoretical support and engineering reference for large-scale application of gas injection displacement and CO₂ sequestration in the late-stage development of continental shale oil fields in China.

Key words: shale oil, gas displacement, numerical simulation, enhanced oil recovery, carbon sequestration

摘要：

准噶尔盆地吉木萨尔凹陷二叠系芦草沟组是中国混积型陆相页岩油的典型代表。经过十余年的勘探与开发，虽然已取得重大突破，但现行衰竭式开发仍面临地层能量衰减快、产量递减快、采收率低等问题，后期提高采收率的关键技术方向尚不明确。为此，基于吉木萨尔凹陷下甜点某平台井实际地质模型，建立了水力裂缝—页岩基质耦合数值模拟模型，通过优化关键参数完成生产动态历史拟合，设计了衰竭开发后中间井注气、两侧井采油的3口水平井间注气驱替工程方法。结果表明，针对吉木萨尔页岩油基质致密、天然裂缝不发育特征，水平井间水力裂缝沟通程度决定了注气驱替开发效果，通过对比注入气体种类、注气时机、注气压力影响，提出了注入气突破后产出气循环回注方式，与衰竭开发相比，注气驱替累计增油量提高约45%，换油率提升近一倍。进一步提出的产出气循环回注方式，可在保证提高原油采出程度的同时有效利用注入的CO₂，实现驱油增产与高效碳利用。本研究结果对陆相页岩油后期注气驱替开发及CO₂地质封存具有重要参考意义。

关键词: 页岩油, 气驱, 数值模拟, 提高采收率, 碳埋存

CLC Number:

TE319
TE341

GE Chenqi, LEI Zhengdong, JI Dongqi, ZHANG Yuan, LIU Yishan, YAN Yiqun, HUI Gang, CHEN Zhangxing. Feasibility of gas displacement application between horizontal wells in shale oil[J]. Petroleum Science Bulletin, 2026, 11(1): 239-256.

葛琛琦, 雷征东, 纪东奇, 张原, 刘一杉, 阎逸群, 惠钢, 陈掌星. 页岩油水平井间注气驱替开发可行性研究[J]. 石油科学通报, 2026, 11(1): 239-256.

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URL: https://sykxtb.cup.edu.cn/EN/10.3969/j.issn.2096-1693.2026.02.005

https://sykxtb.cup.edu.cn/EN/Y2026/V11/I1/239

Figures/Tables 25

Table 1 Model parameters of a well platform in Jimsar shale oil lower sweet-spot

模型参数	数值
基质平均孔隙度	0.096
基质平均水平渗透率/md	0.066
基质平均垂向渗透率/md	0.013
基质岩石压缩系数/kPa^-1	2.5×10^-6
参考深度/m	3155
参考压力/MPa	54.6
储层温度/℃	102.29
平均含油饱和度	0.67

Fig. 1 Simulation model of fractured formation in Jimsar shale oil lower sweet-spot

Table 2 Oil properties by experiments and regressions of Jimsar lower sweet-spot shale oil

参数	实验结果	拟合结果
储层原油密度/(kg/m³)	883	875
储层原油粘度/cp	18.61	18.60
地面原油密度/(kg/m³)	903	899
地面原油粘度(50 ℃)/cp	99.62	103.1
气油比(m³/m³)	13.7	13.61
体积系数	1.035	0.99

Table 3 Jimsar shale oil pseudo-components

组分	临界压力/MPa	临界温度/K	摩尔质量/(g/mol)	偏心因子	临界体积/(L/mol)	摩尔分数/%
CO₂	7.28	304.20	44.01	0.22	0.09	0.12
CH₄	4.54	190.60	16.04	0.01	0.12	14.68
C₂-C₃	4.48	341.05	37.45	0.13	0.31	6.25
C₄-C₆	3.33	480.19	77.01	0.25	1.20	10.25
C₇-C₁₃	2.53	616.70	131.89	0.43	1.57	23.65
C₁₄-C₂₄	1.60	754.78	243.29	0.74	3.47	20.03
C₂₅-C₃₅	1.03	869.39	388.63	1.07	2.60	10.58
C₃₆₊	0.64	1073.2	785.00	1.42	4.06	14.44

Fig. 2 Fitting results of GOR-viscosity by CO₂-crude oil and CH₄-crude oil interactions(41 MPa，89 ℃)

Fig. 3 Relative permeability curves of platform well model: (a) oil-water phase curve of shale matrix; (b) oil and gas of shale matrix; (c) shale matrix oil-water capillary force relation^[41]

Fig. 4 Simulation flowchart of each process in depletion development

Fig. 5 Dynamic history match results of the three wells in the platform

Fig. 6 Schematic diagram of the gas injection displacement mode after the depletion development of three wells in the platform

Fig. 7 Planar pressure (a) and planar oil saturation distribution (b) after the depletion development of the three wells in the platform

Fig. 8 Comparison of the cumulative oil production and the total volume of injected gas after CO₂ and CH₄ displacement in well 2 of the platform

Fig. 9 Comparison of the planar pressure distribution after injecting the equivalent volume of CO₂ and CH₄into well 2 of the platform well

Fig. 10 Comparison of planer oil saturation distribution after injection of the equivalent volume of CO₂ and CH₄ in well 2 of the platform well

Fig. 11 Comparison of the planer molar fraction distribution of the injected gas in the oil phase after injecting the equivalent volume of CO₂ and CH₄ into well 2 of the platform

Fig. 12 Comparison of the planer viscosity distribution of crude oil after injection of the equivalent volume of CO₂ and CH₄ into well 2 of the platform

Fig. 13 Simulation comparison of cumulative oil production at different gas injection timing

Fig. 14 Comparison of cumulative gas injection volumes of three well on the platform at different gas injection timing

Fig. 15 Comparison of different gas injection displacement timing in Well 2: a. pressure; b. oil saturation; c. CO₂ molar fraction in the oil phase; d. oil viscosity

Fig. 16 After the depletion of the three wells on the platform, oil and gas production rates of the two side wells by gas displacement by injection in Well 2

Fig. 17 Cumulative oil production and cumulative gas injection volume after platform well depletion under varying gas injection pressure

Fig. 18 Comparison of CO₂ utilization ratio (cubic meter produced oil by per 10,000 cubic meter injected gas) under varying gas injection pressure (5,475 days, 14 years)

Fig. 19 Schematic diagram of the gas production and reinjection mode of the three wells on the platform (gas produced from wells 1 and 3 is reinjected to Well 2)

Fig. 20 Gas production rate and the molar fraction of CO₂ in the produced gas of two production wells after the platform depletion

Fig. 21 Cumulative oil production and cumulative gas injection volume changes of the cyclic gas injection application

Fig. 22 Comparisons of cyclic gas injection and CO₂ utilization ratio (cubic meter produced oil by per 10,000 cubic meter injected gas) (5,475 days, 14 years)

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