Research

16 pages, 6529 KiB

Open AccessArticle

Numerical Simulation of Stress Disturbance Mechanism Caused by Hydraulic Fracturing of Shale Formation

by Yinghui Zhu, Heng Zheng, Yi Liao and Ruiquan Liao

Processes 2024, 12(5), 886; https://doi.org/10.3390/pr12050886 (registering DOI) - 27 Apr 2024

Viewed by 91

Characterizing changes in rock properties is essential for the hydraulic fracture and re-fracture parameter optimization of shale formations. This paper proposed a hydraulic fracturing model to investigate the changes in rock properties during hydraulic fracturing using SPH, and the changes in the stress [...] Read more.

Characterizing changes in rock properties is essential for the hydraulic fracture and re-fracture parameter optimization of shale formations. This paper proposed a hydraulic fracturing model to investigate the changes in rock properties during hydraulic fracturing using SPH, and the changes in the stress field and rock properties were quantitatively characterized. The simulation results indicated that the minimum horizontal principal stress increased by 10 MPa~15 MPa during fracture propagation, which is the main reason for the uneven propagation in multi-fracture propagation. Affected by the stress disturbance, the stimulated area was divided into four parts based on the changes in Young’s modulus and permeability; the more seriously the stress disturbance was affected, the higher the permeability of the stimulated zone was, and the smaller the stimulated zone was. Meanwhile, a zone with reduced permeability appeared due to the compression effect caused by the high injection pressure, and this increased with the increase in stress disturbance. The main reason for this was that strain formed because of the compression effect from the high injection pressure. The higher the stress disturbance, the higher the accumulated strain. This new model provides a new method for fracture parameter optimization, which also provides a foundation for the re-fracture parameter optimization of shale formations. Full article

(This article belongs to the Special Issue Advanced Fracturing Technology for Oil and Gas Reservoir Stimulation)

19 pages, 8388 KiB

Open AccessArticle

CFD−DEM Simulation of a Jamming Mechanism and Influencing Factors of a Fracture-Shrinking Model

by Jiabin Zhang, Cong Lu, Tao Zhang and Jianchun Guo

Processes 2024, 12(4), 822; https://doi.org/10.3390/pr12040822 - 18 Apr 2024

Viewed by 296

Abstract

Fractured-vuggy reservoirs are crucial for increasing unconventional oil storage and production, but the controlling mechanism of this dominant flow channel remains vague, and the jamming mechanism of modulator particles is unclear. This study explores the filling and jamming processes of particles in the [...] Read more.

Fractured-vuggy reservoirs are crucial for increasing unconventional oil storage and production, but the controlling mechanism of this dominant flow channel remains vague, and the jamming mechanism of modulator particles is unclear. This study explores the filling and jamming processes of particles in the fractures by conducting a computational fluid dynamics−discrete element method (CFD−DEM) coupled simulation, considering the variation of fracture width, fluid velocity, particle size, and concentration. Results suggest that four sealing modes are proposed: normal filling, local jamming, complete sealing, and sealing in the main fracture. The ratio of particle size to the main fracture width exerts the primary role, with the ratio having a range of 0.625 < D/W ≤ 0.77 revealing complete jamming. Furthermore, an optimal particle size for achieving stable sealing is observed when the particle size varies from 2 to 2.5 mm. A higher concentration of particles yields better results in the fracture-shrinking model. Conversely, a greater velocity worsens the sealing effect on fractures. This research can offer technical support for the large-scale dissemination of flow regulation technology. Full article

(This article belongs to the Special Issue Advanced Fracturing Technology for Oil and Gas Reservoir Stimulation)

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27 pages, 8773 KiB

Open AccessArticle

Study of Acid Fracturing Strategy with Integrated Modeling in Naturally Fractured Carbonate Reservoirs

by Xusheng Cao, Jichuan Ren, Shunyuan Xin, Chencheng Guan, Bing Zhao and Peixuan Xu

Processes 2024, 12(4), 808; https://doi.org/10.3390/pr12040808 - 17 Apr 2024

Viewed by 289

Abstract

Natural fractures and wormholes strongly influence the performance of acid fracturing in naturally fractured carbonate reservoirs. This work uses an integrated model to study the effects of treatment parameters in acid fracturing in different reservoir conditions. Hydraulic fracture propagation, wormhole propagation, complex fluid [...] Read more.

Natural fractures and wormholes strongly influence the performance of acid fracturing in naturally fractured carbonate reservoirs. This work uses an integrated model to study the effects of treatment parameters in acid fracturing in different reservoir conditions. Hydraulic fracture propagation, wormhole propagation, complex fluid leak-off mediums, and heat transfer are considered in the modeling. The model is validated in several steps by analytical solutions. The simulation results indicated that natural fractures and wormholes critically impact acid fracturing and can change the predicted outcomes dramatically. The high permeability reservoirs with conductive natural fractures or low permeability reservoirs with natural fracture networks showed the highest stimulation potential in applying acid fracturing technology. The optimal acid injection rate depends on natural fracture geometry and reservoir permeability. This study also observed that obtaining a high production index is difficult because natural fractures and wormholes reduce the acid efficiency during acid fracturing. Building an acid-etched fracture system consisting of acid-etched natural fractures and hydraulic fractures may help us better stimulate the naturally fractured carbonate reservoirs. The paper illustrates a better understanding of the effects of the treatment design parameters on productivity. It paves a path for the optimal design of acid fracturing treatment for heterogeneous carbonate reservoirs. Full article

(This article belongs to the Special Issue Advanced Fracturing Technology for Oil and Gas Reservoir Stimulation)

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16 pages, 5667 KiB

Open AccessArticle

A Novel Slickwater System with Strong-Polarity Fibers for High-Efficiency Proppant Flowback Mitigation

by Yang Xu, Ping Chen, Kun Wang, Suoliang Wang, Qingcong Meng, Mingqi Li, Yingxian Ma and Jie Zeng

Processes 2024, 12(4), 724; https://doi.org/10.3390/pr12040724 - 03 Apr 2024

Viewed by 417

Abstract

To avoid or mitigate proppant flowback after a massive hydraulic fracturing of tight formations and to reduce its impairment to well productivity, this study developed a new type of fiber material with strong polarity based on polyester fiber. This fiber material is modified [...] Read more.

To avoid or mitigate proppant flowback after a massive hydraulic fracturing of tight formations and to reduce its impairment to well productivity, this study developed a new type of fiber material with strong polarity based on polyester fiber. This fiber material is modified by introducing a strong-polar functional monomer into the molecular structure and adopting the means of surface grafting. On the basis of this fiber material, a fiber slip-water system with excellent dispersion performance can be established to prevent proppant backflow. Laboratory experiments were performed to analyze the specific function of the fibers with strong polarity and its working mechanisms. The results indicate that strong-polarity fibers have excellent dispersion performance. The fibers and resistance-reducing agents form an interwoven structure that can carry proppants, resulting in the enhancement of the sand-carrying capacity of the fracturing fluid system and the overall strength of the sand bank. In terms of the sand-carrying capacity and mitigation of proppant flowback, strong-polar fibers have significantly improved compared to unmodified fibers. In a 5 mm simulated crack, strong-polar fibers can increase the static settling time of 70/140 mesh quartz sand proppant by 26.5%. Meanwhile, the placement height of the sand embankment increased by 23.4% after the settlement of the proppant. In proppant transport experiments, strong-polar fibers with a mass fraction of 0.4% can increase the transport distance of proppants by more than 50%. Within the closed stress range of 2–10 MPa, the concentration of 0.5% strong-polar fibers increases the critical sand flow rate of the proppant by more than twice. The strong-polarity fiber system introduced in this study can be used to develop a fiber slickwater fracturing fluid system suitable for the massive hydraulic fracturing of tight reservoirs and has broad application prospects in the field of proppant flowback mitigation in tight reservoirs. Full article

(This article belongs to the Special Issue Advanced Fracturing Technology for Oil and Gas Reservoir Stimulation)

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16 pages, 40720 KiB

Open AccessArticle

Effect of Acid-Injection Mode on Conductivity for Acid-Fracturing Stimulation in Ultra-Deep Tight Carbonate Reservoirs

by Jiangyu Liu, Dengfeng Ren, Shaobo Feng, Ju Liu, Shiyong Qin, Xin Qiao and Bo Gou

Processes 2024, 12(4), 651; https://doi.org/10.3390/pr12040651 - 25 Mar 2024

Viewed by 586

Abstract

The conductivity of acid-etched fractures and the subsequent production response are influenced by the injection mode of the fracturing fluid and acid fluid during acid fracturing in a carbonate reservoir. However, there has been a lack of comprehensive and systematic experimental research on [...] Read more.

The conductivity of acid-etched fractures and the subsequent production response are influenced by the injection mode of the fracturing fluid and acid fluid during acid fracturing in a carbonate reservoir. However, there has been a lack of comprehensive and systematic experimental research on the impact of commonly used injection modes in oilfields on conductivity, which directly affects the optimal selection of acid-fracturing injection modes. To address this gap, the present study focuses on underground rock samples, acid systems, and fracturing fluid obtained from ultra-deep carbonate reservoirs in the Fuman Oilfield. Experimental investigations were conducted to examine the conductivity of hydraulic fractures etched by various types of acid fluids under five different injection modes: fracturing fluid + self-generating acid or cross-linked acid; fracturing fluid + self-generating acid + cross-linked acid. The findings demonstrate that the implementation of multi-stage alternating acid injection results in the formation of communication channels, vugular pore space, and natural micro-cracks, as well as grooves and fish-scales due to enhanced etching effects. The elevation change, amount of dissolved rock, and conductivity exhibited by rock plates are significantly higher in comparison to those achieved through the single-acid injection mode while maintaining superior conductivity. It is recommended for optimal conductivity and retention rate in the Fuman Oilfield to adopt two stages of alternating acid-fracturing injection mode. Field application demonstrated that two-stages of alternating acid-fracturing generate more pronounced production response than the adjacent wells. Full article

(This article belongs to the Special Issue Advanced Fracturing Technology for Oil and Gas Reservoir Stimulation)

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15 pages, 3244 KiB

Open AccessArticle

A Comprehensive Evaluation of Shale Oil Reservoir Quality

by Fuchun Tian, Yongqiang Fu, Xuewei Liu, Dongping Li, Yunpeng Jia, Lifei Shao, Liyong Yang, Yudong Zhao, Tao Zhao, Qiwu Yin and Xiaoting Gou

Processes 2024, 12(3), 472; https://doi.org/10.3390/pr12030472 - 26 Feb 2024

Cited by 1 | Viewed by 553

Abstract

To enhance the accuracy of the comprehensive evaluation of reservoir quality in shale oil fractured horizontal wells, the Pearson correlation analysis method was employed to study the correlations between geological parameters and their relationship with production. Through principal component analysis, the original factors [...] Read more.

To enhance the accuracy of the comprehensive evaluation of reservoir quality in shale oil fractured horizontal wells, the Pearson correlation analysis method was employed to study the correlations between geological parameters and their relationship with production. Through principal component analysis, the original factors were linearly combined into principal components with clear and specific physical meanings, aiming to eliminate correlations among factors. Furthermore, Gaussian membership functions were applied to delineate fuzzy levels, and the entropy weight method was used to determine the weights of principal components, establishing a fuzzy comprehensive evaluation model for reservoir quality. Without using principal component analysis, the correlation coefficient between production and evaluation results for the 40 wells in the Cangdong shale oil field was only 0.7609. However, after applying principal component analysis, the correlation coefficient increased to 0.9132. Field application demonstrated that the average prediction accuracy for the cumulative oil production per kilometer of fractured length over 12 months for the 10 applied wells was 91.8%. The proposed comprehensive evaluation method for reservoir quality can guide the assessment of reservoir quality in shale oil horizontal wells. Full article

(This article belongs to the Special Issue Advanced Fracturing Technology for Oil and Gas Reservoir Stimulation)

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13 pages, 4701 KiB

Open AccessArticle

An Optimal Model for Determination Shut-In Time Post-Hydraulic Fracturing of Shale Gas Wells: Model, Validation, and Application

by Jianmin Li, Gang Tian, Xi Chen, Bobo Xie, Xin Zhang, Jinchi Teng, Zhihong Zhao and Haozeng Jin

Processes 2024, 12(2), 399; https://doi.org/10.3390/pr12020399 - 17 Feb 2024

Viewed by 456

Abstract

The global shale gas resources are huge and have good development prospects, but shale is mainly composed of nanoscale pores, which have the characteristics of low porosity and low permeability. Horizontal drilling and volume fracturing techniques have become the effective means for developing [...] Read more.

The global shale gas resources are huge and have good development prospects, but shale is mainly composed of nanoscale pores, which have the characteristics of low porosity and low permeability. Horizontal drilling and volume fracturing techniques have become the effective means for developing the shale reservoirs. However, a large amount of mining data indicate that the fracturing fluid trapped in the reservoir will inevitably cause hydration interaction between water and rock. On the one hand, the intrusion of fracturing fluid into the formation causes cracks to expand, which is conducive to the formation of complex fracture networks; on the other hand, the intrusion of fracturing fluid into the formation causes the volume expansion of clay minerals, resulting in liquid-phase trap damage. At present, the determination of well closure time is mainly based on experience without theoretical guidance. Therefore, how to effectively play the positive role of shale hydration while minimizing its negative effects is the key to optimizing the well closure time after fracturing. This paper first analyzes the shale pore characteristics of organic pores, clay pores, and brittle mineral pores, and the multi-pore self-absorption model of shale is established. Then, combined with the distribution characteristics of shale hydraulic fracturing fluid in the reservoir, the calculation model of backflow rate and shut-in time is established. Finally, the model is validated and applied with an experiment and example well. The research results show that the self-imbibition rate increases with the increase in self-imbibition time, and the flowback rate decreases with the increase in self-imbibition time. The self-imbibition of slick water is the maximum, the self-imbibition of breaking fluid is the minimum, and the self-imbibition of mixed fluid is the middle, and the backflow rates of these three liquids are in reverse order. It is recommended the shut-in time of Longmaxi Formation shale is 17 days according to the hydration and infiltration model. Full article

(This article belongs to the Special Issue Advanced Fracturing Technology for Oil and Gas Reservoir Stimulation)

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11 pages, 4436 KiB

Open AccessArticle

Pore Fluid Movability in Fractured Shale Oil Reservoir Based on Nuclear Magnetic Resonance

by Yishan Liu, Zhewei Chen, Dongqi Ji, Yingfeng Peng, Yanan Hou and Zhengdong Lei

Processes 2023, 11(12), 3365; https://doi.org/10.3390/pr11123365 - 04 Dec 2023

Cited by 3 | Viewed by 661

Abstract

Gulong shale oil is found in a typical continental shale oil reservoir, which is different from marine shale oil reservoirs. The Gulong shale oil reservoir is a pure shale-type oil reservoir with abundantly developed nanoscale pores, making it extremely difficult to unlock fluids. [...] Read more.

Gulong shale oil is found in a typical continental shale oil reservoir, which is different from marine shale oil reservoirs. The Gulong shale oil reservoir is a pure shale-type oil reservoir with abundantly developed nanoscale pores, making it extremely difficult to unlock fluids. Pressure drive does not easily achieve fluid unlock conditions; thus, it is necessary to utilize imbibition to unlock nanoscale pore fluids. In this study, experiments were conducted on oil displacement by high-speed centrifugal pressure and imbibition under different conditions, respectively, and simulations were used to evaluate the effects of pressure differential drive and imbibition efficiency on the utilization of crude oil following fracturing. Combined with the mixed wettability of the reservoir, the imbibition efficiency was analyzed, and the imbibition efficiency at different soaking stages was evaluated. When the fracturing pressure was higher than the matrix pore pressure, the imbibition efficiency was the most obvious, which was 27.9%. Spontaneous imbibition depending solely on capillary force had poor efficiency, at 16.8%. When the fracturing pressure was lower than the matrix pore pressure, the imbibition efficiency was the lowest, at only 1.3%. It is proposed that strengthening fracture pressure and promoting pressurized imbibition are the keys to improving shale oil development. Full article

(This article belongs to the Special Issue Advanced Fracturing Technology for Oil and Gas Reservoir Stimulation)

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