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3 pages, 164 KiB

Open AccessEditorial

Special Issue “Petroleum Engineering: Reservoir Fracturing Technology and Numerical Simulation”

by Tiankui Guo and Ming Chen

Processes 2023, 11(1), 233; https://doi.org/10.3390/pr11010233 - 11 Jan 2023

Cited by 2 | Viewed by 1428

Abstract

Hydraulic fracturing is a technique that can provide space for oil and gas flow by pumping fracturing fluid into a reservoir to fracture rock and filling proppant to create fractures or fracture nets [...] Full article

(This article belongs to the Special Issue Petroleum Engineering: Reservoir Fracturing Technology and Numerical Simulation)

Research

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13 pages, 4036 KiB

Open AccessArticle

Numerical Simulations of Radial Well Assisted Deflagration Fracturing Based on the Smoothed Particle Hydrodynamics Method

by Diguang Gong, Junbin Chen, Weibo Wang, Guanzheng Qu, Jianhong Zhu, Xiaoming Wang and Haoyu Zhang

Processes 2022, 10(12), 2535; https://doi.org/10.3390/pr10122535 - 29 Nov 2022

Cited by 2 | Viewed by 1306

Abstract

The technology of radial-well-assisted hydraulic fracturing is applied in the stimulation of low-permeability hydrocarbon reservoirs where commercial production cannot be achieved by the conventional fracturing method. Here, a study on the reservoir stimulation effect and the fracture propagation pattern of radial-well-assisted deflagration fracturing [...] Read more.

The technology of radial-well-assisted hydraulic fracturing is applied in the stimulation of low-permeability hydrocarbon reservoirs where commercial production cannot be achieved by the conventional fracturing method. Here, a study on the reservoir stimulation effect and the fracture propagation pattern of radial-well-assisted deflagration fracturing was carried out. Based on smooth particle hydrodynamics (SPH), rock mechanics theory, and finite element theory, a numerical model of radial-well-assisted deflagration fracturing was established by integrating the JWL state equation. Research on the effects of the deflagration position, radial well azimuth and horizontal principal stress difference on the fracture propagation was carried out. The results show that the deflagration position, radial well azimuth and horizontal principal stress difference have significant effects on the fracture area in deflagration fracturing. The closer distance from the deflagration position is, the larger the radial well azimuth and the smaller the horizontal stress difference are, leading to a larger fracture area, which is conducive to reservoir stimulation. During fracturing, both shear fractures and tensile fractures are formed. The formation and conversion of shear fractures and tensile fractures are related to the deflagration position, radial well azimuth, horizontal principal stress difference, etc. Full article

(This article belongs to the Special Issue Petroleum Engineering: Reservoir Fracturing Technology and Numerical Simulation)

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17 pages, 7242 KiB

Open AccessArticle

Numerical Simulation of Multifracture Growth under Extremely Limited Entry Fracturing of Horizontal Well

by Tengfei Wang, Ming Chen, Yun Xu, Dingwei Weng, Zhanwei Yang, Zhaolong Liu, Zeyuan Ma and Hao Jiang

Processes 2022, 10(12), 2508; https://doi.org/10.3390/pr10122508 - 25 Nov 2022

Cited by 1 | Viewed by 1464

Abstract

The multifracture competitive growth from a horizontal well is an essential issue in multi-cluster fracturing design. In recent years, extremely limited entry (ELE) fracturing has been implemented to promote uniform multifracture growth. However, the mechanism of multifracture growth and ELE design remain unclear. [...] Read more.

The multifracture competitive growth from a horizontal well is an essential issue in multi-cluster fracturing design. In recent years, extremely limited entry (ELE) fracturing has been implemented to promote uniform multifracture growth. However, the mechanism of multifracture growth and ELE design remain unclear. Based on the planar three-dimensional multifracture propagation model, a multi-cluster horizontal well fracturing model that considers ELE design has been developed. The model considers flow in the wellbore and fluid filtration loss in the fracture. The simulator enables the simulation and analysis of non-uniform in situ stress, filtration loss, and fracture properties. Using this program, we simulated the propagation process of multiple clusters of fractures in ELE fracturing of horizontal wells. The results show the following: The perforation friction in the ELE fracturing can counteract the difference in fluid allocation caused by stress interference, allowing all clusters of perforations to have even fluid allocation but to differ significantly in fracture geometry. The in situ stress profile and 3D fracture stress interference determine the fracture geometry, and the fracture of the middle cluster could cross through the layer with relatively higher in situ stress, resulting in a decrease in effective fracture area in the pay zone. Furthermore, an increase in perforation diameter causes the flow-limiting effect of the perforations to decrease. The fluid volumes entering different clusters of perforations become less uniform. The difference in fracture toughness within a perforated stage has a minor influence on the fluid allocation between different clusters, while the in situ stress distribution within a perforated stage has a significant impact on the fluid allocation between different perforation clusters in the stage. Fractures preferentially propagate at the perforation points with lower in situ stress and stress interference. This study can be helpful to understand multifracture competitive growth and the optimization of ELE fracturing design. Full article

(This article belongs to the Special Issue Petroleum Engineering: Reservoir Fracturing Technology and Numerical Simulation)

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18 pages, 4300 KiB

Open AccessArticle

Modeling the Transient Flow Behavior of Multi-Stage Fractured Horizontal Wells in the Inter-Salt Shale Oil Reservoir, Considering Stress Sensitivity

by Ting Huang, Xiao Guo, Kai Peng, Wenzhi Song and Changpeng Hu

Processes 2022, 10(10), 2085; https://doi.org/10.3390/pr10102085 - 14 Oct 2022

Cited by 1 | Viewed by 1399

Abstract

Oil flow in inter-salt shale oil reservoirs is different from that of other oil fields due to its high salt content. Dissolution and diffusion occur when the salt minerals meet the water-based working fluid, resulting in drastic changes in the shale’s permeability. In [...] Read more.

Oil flow in inter-salt shale oil reservoirs is different from that of other oil fields due to its high salt content. Dissolution and diffusion occur when the salt minerals meet the water-based working fluid, resulting in drastic changes in the shale’s permeability. In addition, ignoring the stress-sensitive effect will cause significant errors in naturally fractured reservoirs for a large number of the natural fractures developed in shales. This study presents a transient pressure behavior model for a multi-stage fractured horizontal well (MFHW) in inter-salt shale oil reservoirs, considering the dissolution of salt and the stress sensitivity mentioned above. The analytical solution of our model was obtained by applying the methods of Pedrosa’s linearization, the perturbation technique and Laplace transformation. The transient pressure of a multi-stage fractured horizontal well in an inter-salt shale oil reservoir was obtained in real space by using the method of Stehfest’s numerical inversion. The bi-logarithmic-type curves thus obtained reflected the characteristics of the transient pressure behavior of a MFHW for the inter-salt shale oil reservoirs, and eight flow periods were recognized in the type curves. The effects of salt dissolution, stress sensitivity, the storativity ratio and other parameters on the type curves were analyzed thoroughly, which is of great significance for understanding the transient flow behavior of inter-salt shale oil reservoirs. Full article

(This article belongs to the Special Issue Petroleum Engineering: Reservoir Fracturing Technology and Numerical Simulation)

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19 pages, 13912 KiB

Open AccessArticle

Analysis and Application of Horizontal Well Test in Low Permeability Porous Carbonate Reservoir

by Zeqi Zhao, Yong Li, Tongwen Jiang, Dandan Hu, Lixia Zhang and Ruicheng Ma

Processes 2022, 10(8), 1545; https://doi.org/10.3390/pr10081545 - 6 Aug 2022

Cited by 2 | Viewed by 2373

Abstract

Low permeability porous carbonate rocks occupy a certain proportion in the Middle East. Horizontal injection-production well pattern development is often adopted. Due to the influence of well type and wellbore, reservoir dynamic monitoring is mainly based on conventional daily measurement data, well test [...] Read more.

Low permeability porous carbonate rocks occupy a certain proportion in the Middle East. Horizontal injection-production well pattern development is often adopted. Due to the influence of well type and wellbore, reservoir dynamic monitoring is mainly based on conventional daily measurement data, well test and pressure monitoring. Therefore, it is particularly important to combine well test interpretation with production dynamic analysis to diagnose the main control factors and production characteristics of this type of reservoir. In this paper, the point source function is used to obtain the pressure variation function of a horizontal well in infinite formation with upper and lower closed boundary. The difference between the horizontal well test curve of A reservoir and the typical horizontal well test curve is compared and analyzed, and the abnormal well test curve of horizontal wells is characterized by a linear flow phase with a slope of 1/3 or 1/4. The abnormal well test curve accounted for 33.34%. The main influencing factors are the permeability around the well and the well trajectory. By combining well test interpretation with dynamic inversion method, the correlation between well test interpretation and dynamic characteristics of horizontal wells with different characteristics is classified and clarified. The main controlling factors that affect the difference in the water injection development effect of different horizontal wells are further clarified, and provide an important reference for the adjustment of injection-production parameters and the optimal deployment of schemes. Full article

(This article belongs to the Special Issue Petroleum Engineering: Reservoir Fracturing Technology and Numerical Simulation)

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27 pages, 2122 KiB

Open AccessArticle

Numerical Simulation on Hydraulic Fracture Height Growth across Layered Elastic–Plastic Shale Oil Reservoirs

by Hao Zeng, Yan Jin, Daobing Wang, Bo Yu and Wei Zhang

Processes 2022, 10(8), 1453; https://doi.org/10.3390/pr10081453 - 25 Jul 2022

Cited by 8 | Viewed by 1748

Abstract

Shale oil reservoirs are characterized by having various types of vertical sublayers, a large contrast in rock mechanical properties, well-developed bedding, and high clay content, which are likely to cause rock elastic–plastic deformation. In numerical simulations of hydraulic fracture (HF) propagation in the [...] Read more.

Shale oil reservoirs are characterized by having various types of vertical sublayers, a large contrast in rock mechanical properties, well-developed bedding, and high clay content, which are likely to cause rock elastic–plastic deformation. In numerical simulations of hydraulic fracture (HF) propagation in the shale oil reservoirs, the effects of rock elastic–plastic deformation and complex bedding structure on the layer-crossing behavior of HF are not considered. To understand the mechanism of HF height growth in shale oil reservoirs, we used the cohesive zone method to establish an elastic–plastic finite element model of HF propagation by considering the effects of shell limestone interlayers, the Mohr–Coulomb yield criterion for shear–plastic failure, the cross-mechanical interaction between bedding and shale oil reservoir, and the complex situations such as the HF height across high-electrical resistivity bedding and high-conductivity fractures. The effects of internal friction angle, cohesion, layer stress contrast, fracture toughness, bedding bond strength, injection rate, elastic modulus, and bedding shear strength on HF height growth in shale oil reservoirs are studied, and the characteristics of HF width profile, injection pressure, failure mode, and maximum HF width are compared. Compared with the layer stress contrast, cohesion, internal friction angle, and fracture toughness, the injection rate, elastic modulus, and bedding shear strength and bond strength have a larger effect on the vertical HF width. Increment of the injection rate, decrease of the elastic modulus, and increment of the bedding shear strength and bond strength are favorable for HF height growth in the shale oil reservoir. As rock cohesion and internal friction angle increase, the HF width decreases. At the initial stage of fracturing fluid injection, the maximum HF height and injection pressure fluctuate. Lower cohesion and internal friction angle promote rock shear failure in HF height growth. Our study provides guidance for the stimulation of fracture crossing layers in the shale oil reservoirs. Full article

(This article belongs to the Special Issue Petroleum Engineering: Reservoir Fracturing Technology and Numerical Simulation)

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12 pages, 4008 KiB

Open AccessArticle

Integrated Reservoir Model and Differential Stimulation Modes of Low Permeability Porous Carbonate Reservoir: A Case Study of S Reservoir in X Oilfield in Iraq

by Jing Yang, Guangya Zhu, Yichen An, Nan Li, Wei Xu, Li Wan and Rongrong Jin

Processes 2022, 10(6), 1179; https://doi.org/10.3390/pr10061179 - 12 Jun 2022

Cited by 3 | Viewed by 1703

Abstract

The S reservoir in the X Oilfield in Iraq has great development potential due to its rich geological reserves. However, the low permeability and strong heterogeneity of the reservoir lead to great differences in reservoir stimulation performance. In this study, an integrated reservoir [...] Read more.

The S reservoir in the X Oilfield in Iraq has great development potential due to its rich geological reserves. However, the low permeability and strong heterogeneity of the reservoir lead to great differences in reservoir stimulation performance. In this study, an integrated reservoir model and differential stimulation mode are put forward to solve the above problems. First, the feasibility of fracturing is evaluated by laboratory experiments. Second, an integrated reservoir model is established, which mainly includes a rock mechanics model, fracturing simulation model, and numerical simulation model, and correct the integrated model by fracturing operation curves and production dynamic curves. Third, three types of stimulation areas are classified according to the combination of sweet spot types, and three different stimulation modes are proposed. In conclusion, a small-scale stimulation mode should be applied in the Type I area to maximize economic benefits. In the Type II area, the medium-scale stimulation mode should be performed to ensure certain productivity while achieving certain economic benefits. In the Type III area, the large-scale stimulation mode should be employed to obtain certain productivity while economic benefits must be above a limit. The differential stimulation model proposed in this paper has made a great reference for the efficient development of low-permeability carbonate rocks. Full article

(This article belongs to the Special Issue Petroleum Engineering: Reservoir Fracturing Technology and Numerical Simulation)

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16 pages, 4385 KiB

Open AccessArticle

Field-Scale Experimental Study on the Perforation Erosion in Horizontal Wellbore under Real Fracturing Conditions

by Baocheng Wu, Fujian Zhou, Mingxing Wang, Zhenhu Lv, Minghui Li, Bo Wang, Xiaodong Guo and Jingchen Zhang

Processes 2022, 10(6), 1058; https://doi.org/10.3390/pr10061058 - 25 May 2022

Cited by 6 | Viewed by 2264

Abstract

Limited-entry fracturing (LEF) technology is a widely used method to realize the simultaneous propagation of multiple fractures in horizontal wells. The key of this technology is to create high perforation friction to maintain the high treatment pressure in the wellbore and realize the [...] Read more.

Limited-entry fracturing (LEF) technology is a widely used method to realize the simultaneous propagation of multiple fractures in horizontal wells. The key of this technology is to create high perforation friction to maintain the high treatment pressure in the wellbore and realize the uniform fluid entry of multi-fractures; however, high perforation friction cannot be effectively maintained due to the serious perforation erosion effect. Considering that the current laboratory studies mostly used small fluid injection flowrate, low injection pressure, and small proppant dosage, this study has developed a field-scale flow system to investigate the effect of various factors on perforation erosion under real field conditions. The filed-scale flow system uses the real fracturing trucks, proppant, and perforated wellbore, the fluid flow rate through perforation could reach 200 m/s and the injection pressure could reach 105 MPa. The effects of different parameters, such as injection flow rates, proppant concentration, proppant type, proppant size, and carrying fluid viscosity, on the perforation erosion were investigated. The experimental results show that: (1) The perforation friction during erosion goes through two stages, i.e., the roundness erosion stage and the diameter erosion stage. The reduction of perforating friction mainly occurred in the first stage, which was completed after injecting 1 m3 proppant. (2) After erosion, the perforation changes from the original circular shape to a trumpet shape, the inner diameter is much larger than the outer diameter. (3) The more serious perforation erosion is caused by the conditions of high injection flow rate, large proppant size, using ceramic proppant, and low viscosity fluid. The findings of this study can help for a better understanding of perforation erosion during the limited-entry fracturing in the horizontal wells, and also could promote the establishment of a theoretical model of perforation erosion under the field-scale conditions. Full article

(This article belongs to the Special Issue Petroleum Engineering: Reservoir Fracturing Technology and Numerical Simulation)

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18 pages, 4539 KiB

Open AccessFeature PaperArticle

Study on the Temporal and Spatial Multiscale Coupling Flow of Shale Oil

by Binglin Li, Yuliang Su and Mingjing Lu

Processes 2022, 10(5), 939; https://doi.org/10.3390/pr10050939 - 9 May 2022

Cited by 3 | Viewed by 1488

Abstract

Shale oil is one of the world’s most important strategic energy reserves. The microscopic kerogen and matrix structure plays an important role in fluid flow and diffusion processes. The oil flow time in the shale reservoir is determined by the pore spatial scale. [...] Read more.

Shale oil is one of the world’s most important strategic energy reserves. The microscopic kerogen and matrix structure plays an important role in fluid flow and diffusion processes. The oil flow time in the shale reservoir is determined by the pore spatial scale. An accurate shale reservoir flow model must consider these factors. In this research, fluid flow, Fick’s diffusion in consideration of the time delay effect, desorption, as well as the absorption are considered using the molecular momentum correlation and the partial pressure law of the components. The effect of the above-mentioned factors on the time scale contribution of the well rate is discussed. The spatial distribution diagram of the time scale is constructed and analyzed. The results show that the production process is composed of five periods. The time delay effect is reflected by fluctuations in the production at periods 1–3. The time scale corresponds to different mediums. The oil mainly flows through the outer boundary of the stimulated region through surface diffusion. The time scale spatial distribution diagram also shows that the oil flows into the endpoint of the hydraulic fracture at an early stage. Moreover, the outer boundary needs a longer time to be exploited. The proposed model improves the simulation of shale oil flow, and therefore, would be favorable in designing a more suitable working system. Full article

(This article belongs to the Special Issue Petroleum Engineering: Reservoir Fracturing Technology and Numerical Simulation)

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18 pages, 4018 KiB

Open AccessArticle

Simulation of Fracture Morphology during Sequential Fracturing

by Peng Zheng, Tuan Gu, Erhu Liu, Ming Zhao and Desheng Zhou

Processes 2022, 10(5), 937; https://doi.org/10.3390/pr10050937 - 9 May 2022

Cited by 4 | Viewed by 1689

Abstract

During hydraulic fracturing, the aperture of hydraulic fractures will shrink by the in-situ stress, but will not fully close because of the existence of proppant inside the fracture. In previous studies, few people noticed the existence of proppant, which has resulted in the [...] Read more.

During hydraulic fracturing, the aperture of hydraulic fractures will shrink by the in-situ stress, but will not fully close because of the existence of proppant inside the fracture. In previous studies, few people noticed the existence of proppant, which has resulted in the inaccuracy of simulation results. In this study, based on the boundary element method, a numerical simulation model for sequential fracturing was established, which respectively considered the influence of proppant in staged fracturing and zipper fracturing. In addition, the influence mechanism of proppant on fracture morphology is then revealed. Simulation results show that the residual aperture of the previous hydraulic fracture, which was produced by proppant, may increase with the increase of proppant stiffness and fracture spacing and may also be shrunk by the dynamic propagation of subsequent hydraulic fracture. However, the residual aperture will rebound after hydraulic fracturing construction is finished. The shrinkage and rebound values of residual aperture of hydraulic fracture are usually less than 1 mm. In addition, at the same time, the residual aperture of previous hydraulic fracture may also influence the propagation of subsequent hydraulic fracture. These influences are represented by the bend of fractures in multistage fracturing and the intersection in zipper fracturing. With the increase of well spacing, the influence degree of residual aperture on subsequent fracture propagation is reduced. The previous hydraulic fracture cannot have a significant effect on the deflection of subsequent hydraulic fracture when fracture spacing is between 10 and 30 m. The above research has important guiding significance for controlling fracture morphology in hydraulic fracturing. Full article

(This article belongs to the Special Issue Petroleum Engineering: Reservoir Fracturing Technology and Numerical Simulation)

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17 pages, 7072 KiB

Open AccessArticle

Fracture Interference and Refracturing of Horizontal Wells

by Hai Lin, Yakai Tian, Zhenwei Sun and Fujian Zhou

Processes 2022, 10(5), 899; https://doi.org/10.3390/pr10050899 - 2 May 2022

Cited by 4 | Viewed by 2032

Abstract

Due to fracture interference, not all perforations can be fractured, resulting in 20% of fractures contributing to 80% of the total production. The extraction of oil and gas also reduces production, necessitating refracturing. In this study, the finite element method was used to [...] Read more.

Due to fracture interference, not all perforations can be fractured, resulting in 20% of fractures contributing to 80% of the total production. The extraction of oil and gas also reduces production, necessitating refracturing. In this study, the finite element method was used to simulate multiple fractures fracturing simultaneously and the stress field distribution was then extracted and applied to a new geological model. This paper explains the effect of stress around the horizontal wellbore on new fractures during the refracturing of old wells using a temporary plugging technique. The results show that initial breaking pressures are the same, but as fractures extend, inter-fracture interference increases, resulting in different fracture extension pressures and widths. The fracturing fluid is filtered into the reservoir matrix after fracturing, reducing formation stress. Compared with fracturing at the initial fracture site, reperforating fracturing has a lower fracture extension pressure and a longer fracture length. According to this study, hydraulic fractures have a 15 m effective influence radius on the external formation. Stress relief is beneficial for fracture initiation prior to refracturing. Reperforating and fracturing, in combination with temporary plugging technology, can assist in increasing the effective stimulated reservoir volume and achieving high and stable production. Full article

(This article belongs to the Special Issue Petroleum Engineering: Reservoir Fracturing Technology and Numerical Simulation)

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18 pages, 4050 KiB

Open AccessArticle

An Unsupervised Clustering Method for Selection of the Fracturing Stage Design Based on the Gaussian Mixture Model

by Xin Wang, Lifeng Yang, Meng Fan, Yushi Zou and Wenchao Wang

Processes 2022, 10(5), 894; https://doi.org/10.3390/pr10050894 - 1 May 2022

Cited by 2 | Viewed by 1542

Abstract

In order to further improve the efficiency and economic benefits of multi-stage fracturing of unconventional oil and gas horizontal wells, it is urgently needed to conduct comprehensive reservoir quality evaluation research on the whole horizontal well section. Firstly, based on logging data, focusing [...] Read more.

In order to further improve the efficiency and economic benefits of multi-stage fracturing of unconventional oil and gas horizontal wells, it is urgently needed to conduct comprehensive reservoir quality evaluation research on the whole horizontal well section. Firstly, based on logging data, focusing on reservoir quality and completion quality, and comprehensively considering key factors such as reservoir physical property indexes and fracability indexes, a subjective and objective coupled evaluation model of the entropy weight method (EWM) and the analytic hierarchy process (AHP) without bias is established to obtain the composite reservoir quality index. Then, unsupervised gaussian mixture model (GMM) clustering algorithms are used to classify the reservoir comprehensive quality index and finally four grades of fracturing stages are established. Taking shale oil well A and B of the Permian Lucaogou Formation in Jimsar Sag, Junggar Basin, as examples, the comprehensive reservoir quality evaluation and clustering model training, testing, and prediction were carried out. By comparing the clustering results with the actual fracturing stages and oil production, it is found that the evaluation results obtained by the GMM clustering algorithms based on the coupled evaluation model of EWM and AHP can identify the good fracturing grades. The algorithm can also predict the fracturing grades of other wells in the same block. It proves the accuracy of the method proposed in this paper and provides a favorable technical basis for determining the placement of multi-cluster fracturing perforation. Full article

(This article belongs to the Special Issue Petroleum Engineering: Reservoir Fracturing Technology and Numerical Simulation)

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16 pages, 4214 KiB

Open AccessArticle

Shale Gas Productivity Prediction Model Considering Time-Dependent Fracture Conductivity

by Yuan Pan, Yiwen Xu, Ze Yang, Chunli Wang and Ruiquan Liao

Processes 2022, 10(5), 801; https://doi.org/10.3390/pr10050801 - 19 Apr 2022

Cited by 2 | Viewed by 1459

Abstract

Conventional shale gas productivity prediction techniques consider fracture conductivity to be a fixed value, but in actual production processes, conductivity changes with time. Therefore, this paper proposed a capacity prediction method that considers time-dependent conductivity and validates its accuracy using commercial simulators. First, [...] Read more.

Conventional shale gas productivity prediction techniques consider fracture conductivity to be a fixed value, but in actual production processes, conductivity changes with time. Therefore, this paper proposed a capacity prediction method that considers time-dependent conductivity and validates its accuracy using commercial simulators. First, relevant parameters were obtained by fitting the improved long-term conductivity test, and then the shale gas seepage model was established using the EDFM method. The laboratory test results showed that the order of significance affecting the conductivity retention rate was fracturing fluid viscosity > sand concentration > fracturing fluid retention time; the calculation results of the production prediction model show that the flow and the pressure curves that corresponded to constant conductivity and variable conductivity were to some extent different. In the presence of complex fractures and natural fractures, the increase in the variable conductivity production curve was smaller than that of the constant conductivity production curve. This study provides some guidance for field production. Full article

(This article belongs to the Special Issue Petroleum Engineering: Reservoir Fracturing Technology and Numerical Simulation)

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13 pages, 4830 KiB

Open AccessArticle

Investigation into Hydraulic Fracture Propagation Behavior during Temporary Plugging and Diverting Fracturing in Coal Seam

by Yushi Zou, Budong Gao and Qimiao Ma

Processes 2022, 10(4), 731; https://doi.org/10.3390/pr10040731 - 10 Apr 2022

Cited by 4 | Viewed by 1837

Abstract

Temporary plugging and diverting fracturing (TPDF) is widely used to improve the stimulation effectiveness in coal seam. To study the fracture propagation behavior during TPDF in coal formation, a series of laboratory hydraulic fracturing experiments were performed on natural coal samples. Based on [...] Read more.

Temporary plugging and diverting fracturing (TPDF) is widely used to improve the stimulation effectiveness in coal seam. To study the fracture propagation behavior during TPDF in coal formation, a series of laboratory hydraulic fracturing experiments were performed on natural coal samples. Based on the results of sample splitting and fracture reconstruction, the influences of horizontal stress difference and the size of temporary plugging agent (TPA) as well as the concentration of TPA on hydraulic fracture growth were analyzed. Experimental results show that TPDF is beneficial for improving the fracture complexity even under high stress difference of 8 MPa. When the TPA of small particle size (70/100 mesh) was applied, the primary fracture could not be fully blocked whereas increasing the particle size of TPA to 20/40 mesh tended to cause accumulation and bridging in the wellbore, resulting in an abnormally high fracturing pressure. TPA with particle size of 40/70 mesh tended to be a reasonable choice for the target formation, as it could form effective plugging in primary fractures and promote the generation of new fractures. Meanwhile, optimizing the concentration of TPA was also conducive to improving the plugging effectiveness. Effective temporary plugging can be achieved by using appropriate TPA of proper size and concentration, which varies with different treatment parameters and formations. Laboratory experiments are expected to provide guidance for the parameter optimization for TPDF in coal seam. Full article

(This article belongs to the Special Issue Petroleum Engineering: Reservoir Fracturing Technology and Numerical Simulation)

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18 pages, 6588 KiB

Open AccessArticle

Experimental Investigation of the Growth Law of Multi-Fracture during Temporary Plugging Fracturing within a Stage of Multi-Cluster in a Horizontal Well

by Yanchao Li, Qing Zhang and Yushi Zou

Processes 2022, 10(4), 637; https://doi.org/10.3390/pr10040637 - 24 Mar 2022

Cited by 5 | Viewed by 1809

Abstract

Temporary plugging fracturing in a horizontal well with multi-stages and multi-clusters is usually used to improve stimulation efficiency and increase the gas production from shale gas reservoirs. However, the fracture propagation geometry and the mechanism of temporary plugging are still unclear, which restricts [...] Read more.

Temporary plugging fracturing in a horizontal well with multi-stages and multi-clusters is usually used to improve stimulation efficiency and increase the gas production from shale gas reservoirs. However, the fracture propagation geometry and the mechanism of temporary plugging are still unclear, which restricts the further optimization of temporary plugging fracturing scheme. In this study, taking the Longmaxi shale as the research object and considering the intrafracture and intrastage temporary plugging, the true tri-axial hydraulic fracturing system was used to put forward an experimental method for simulating the temporary plugging fracturing in a horizontal well with multi-stages and multi-clusters. Afterward, the effects of the size combination and concentration of temporary plugging agents and the cluster number in a stage on the fracture geometry created in the secondary fracturing were investigated in detail. The results show that an optimal fracture propagation geometry tends to be obtained by using the combinations of 100 to 20/70 mesh, and 20/70 to 10~18 mesh temporary plugging agents for the intrafracture and intrastage temporary plugging, respectively. Increasing the proportion of the temporary plugging agent of a larger particle size can improve the effectiveness of intrafracture and intrastage temporary plugging fracturing, and tends to open new fractures. With the increase in temporary plugging agent concentration and the cluster number within a stage, both the number of diverting fractures formed and the overall complexity of fractures tend to increase. After fracturing, the rock specimen with a high peak in the temporary plugging pressure curve has more transverse fractures, indicating a desirable diversion effect. By contrast, the fractured rock specimen with a low peak pressure has no transverse fracture, generally with fewer fractures and poor diversion effect. Full article

(This article belongs to the Special Issue Petroleum Engineering: Reservoir Fracturing Technology and Numerical Simulation)

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13 pages, 3108 KiB

Open AccessArticle

Characteristics Description of Shale Fracture Surface Morphology: A Case Study of Shale Samples from Barnett Shale

by Guanzheng Qu, Tao Shi, Zheng Zhang, Jian Su, Haitao Wei, Rui Guo, Jiao Peng and Kairui Zhao

Processes 2022, 10(2), 401; https://doi.org/10.3390/pr10020401 - 18 Feb 2022

Cited by 4 | Viewed by 1674

Abstract

Shale reservoirs are the hot issue in unconventional resources. The key to the development of shale reservoirs lies in the complex fractures, which are the only path for fluid to migrate from the matrix to the wellbore in shale reservoirs. Therefore, the characteristics [...] Read more.

Shale reservoirs are the hot issue in unconventional resources. The key to the development of shale reservoirs lies in the complex fractures, which are the only path for fluid to migrate from the matrix to the wellbore in shale reservoirs. Therefore, the characteristics of shale fracture surface morphology directly affect fluid migration in shale reservoirs. However, there are few reports about the characteristics of shale fracture surface morphology as the parallel plate model was commonly used to characterize the fracture, neglecting its surface morphology characteristics and leading to great deviation. Thus, description methods were introduced to characterize shale fracture surface morphology with the aim to provide a foundation for the development of shale resources. Three shale samples were fractured by the Brazilian test, and the height distribution of the fracture surface was captured by a three-dimensional profilometer. Then, three-dimensional fracture surface morphology was regarded as a set of two-dimensional profiles, which converted three-dimensional information into two-dimensional data. Roughness, joint roughness coefficient, fractal dimension, tortuosity, and dip angle were employed to characterize shale fracture surface morphology, and their calculation methods were also, respectively, proposed. It was found that roughness, joint roughness coefficient, fractal dimension, tortuosity, and dip angle were all directional, and they varied greatly along with different directions. Roughness, joint roughness coefficient, fractal dimension, tortuosity, absolute dip angle, and overall trend dip angle were among 0.0834–0.2427 mm, 2.5715–10.9368, 2.1000–2.1364, 1.0732–1.1879, 17.7498°–24.5941°, and −3.7223°–13.3042°, respectively. Joint roughness coefficient, fractal dimension, tortuosity, and dip angle were all positively correlated with roughness. Full article

(This article belongs to the Special Issue Petroleum Engineering: Reservoir Fracturing Technology and Numerical Simulation)

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