Energies

Research

23 pages, 9737 KiB

Open AccessArticle

Integrated Study on Carbon Dioxide Geological Sequestration and Gas Injection Huff-n-Puff to Enhance Shale Oil Recovery

by Lei Wang, Shengyao Cai, Wenli Chen and Gang Lei

Energies 2024, 17(8), 1957; https://doi.org/10.3390/en17081957 - 19 Apr 2024

Viewed by 313

Multi-stage fractured horizontal well technology is an effective development method for unconventional reservoirs; however, shale oil reservoirs with ultra-low permeability and micro/nanopore sizes are still not ideal for production and development. Injecting CO₂ into the reservoir, after hydraulic fracturing, gas injection flooding [...] Read more.

Multi-stage fractured horizontal well technology is an effective development method for unconventional reservoirs; however, shale oil reservoirs with ultra-low permeability and micro/nanopore sizes are still not ideal for production and development. Injecting CO₂ into the reservoir, after hydraulic fracturing, gas injection flooding often produces a gas channeling phenomenon, which affects the production of shale oil. In comparison, CO₂ huff-n-puff development has become a superior method in the development of multi-stage fractured horizontal wells in shale reservoirs. CO₂ huff and injection can not only improve shale oil recovery but also store the CO₂ generated in industrial production in shale reservoirs, which can reduce greenhouse gas emissions to a certain extent and achieve carbon capture, utilization, and storage (CCUS). In this paper, the critical temperature and critical parameters of fluid in shale reservoirs are corrected by the critical point correction method in this paper, and the influence of reservoir pore radius on fluid phase behavior and shale oil production is analyzed. According to the shale reservoir applied in isolation to the actual state of the reservoir and under the condition of a complex network structure, we described the seepage characteristics of shale oil and gas and CO₂ in the reservoir by embedding a discrete fracture technology structure and fracture network, and we established the numerical model of the CO₂ huff-n-huff development of multi-stage fractured horizontal wells for shale oil. We used the actual production data of the field for historical fitting to verify the validity of the model. On this basis, CO₂ huff-n-puff development under different gas injection rates, huff-n-puff cycles, soaking times, and other factors was simulated; cumulative oil production and CO₂ storage were compared; and the influence of each factor on development and storage was analyzed, which provided theoretical basis and specific ideas for the optimization of oilfield development modes and the study of CO₂ storage. Full article

(This article belongs to the Special Issue Advances in the Development of Unconventional Oil and Gas Resources)

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21 pages, 7089 KiB

Open AccessArticle

Research on Fracturing Optimization of Coalbed Methane Wells Aiming at Economic Benefit—A Case Study of Liulin Block

by Jianzhong Liu, Yanchun Su, Lichun Sun, Chen Li, Lei Wang, Yanjun Meng and Yong Li

Energies 2024, 17(8), 1829; https://doi.org/10.3390/en17081829 - 11 Apr 2024

Viewed by 388

Abstract

Hydraulic fracturing is an essential technology in the development of coalbed methane reservoirs. Hydraulic fracturing can create a highly conductive fracture in the reservoir and increase its permeability. At present, the focus of coalbed methane reservoir fracturing optimization is gradually shifting to the [...] Read more.

Hydraulic fracturing is an essential technology in the development of coalbed methane reservoirs. Hydraulic fracturing can create a highly conductive fracture in the reservoir and increase its permeability. At present, the focus of coalbed methane reservoir fracturing optimization is gradually shifting to the fracturing scale. In the current development process, more and more coalbed methane blocks try to increase the fracturing scale to increase the gas production of coalbed methane wells. Field tests show that gas production of coalbed methane wells will increase to a certain extent with the increase of fracturing scale. However, the increase in the scale of fracturing also increases its cost. Therefore, the most economical fracturing scale is not necessarily the optimal fracturing scale for gas production. The field test usually pays more attention to the gas production effect, but the development of a coalbed methane field should pay more attention to the economic benefit, and the optimization of fracturing should take the economic benefit as the goal. Taking economic benefits as the starting point, this paper uses fracturing simulation to calculate the fracture extension under different geological conditions and different fracturing scales. It also uses numerical simulation to calculate the gas well productivity under different fracture extension conditions. The economic evaluation model was established to calculate the economic benefits under different fracturing scales, and the optimal fracturing scale was obtained. Finally, the typical maps of fracturing optimization under different geological conditions are formed. The optimization method of fracturing scale integrating economy, fracturing, and gas reservoir is realized. The research results have been successfully applied to the optimization scheme of Liulin block development, and very good results have been achieved. Because this method is targeted at different geological conditions, it can be used to guide the fracturing optimization of other coalbed methane blocks and has very important significance for the development and optimization of coalbed methane reservoirs. Full article

(This article belongs to the Special Issue Advances in the Development of Unconventional Oil and Gas Resources)

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16 pages, 4045 KiB

Open AccessArticle

A Method for Evaluating Coalbed Methane Reservoir Productivity Considering Drilling Fluid Damage

by Chen Li, Lichun Sun, Zhigang Zhao, Jian Zhang, Yong Li, Yanjun Meng and Lei Wang

Energies 2024, 17(7), 1686; https://doi.org/10.3390/en17071686 - 01 Apr 2024

Viewed by 487

Abstract

In the process of coalbed methane development, drilling fluid and fracturing fluid cannot achieve absolute compatibility with formation. The incompatibility between the working fluid and reservoir will lead to the intrusion of working fluid into the reservoir and cause reservoir pollution. This is [...] Read more.

In the process of coalbed methane development, drilling fluid and fracturing fluid cannot achieve absolute compatibility with formation. The incompatibility between the working fluid and reservoir will lead to the intrusion of working fluid into the reservoir and cause reservoir pollution. This is a very common phenomenon. There is a large amount of pulverized coal in the coal seam, and the intrusion of working liquid will be combined with the pulverized coal to form cement to block the seepage space in the reservoir. Since pressure relief and fracturing fluid backflow will be performed at the first time after fracturing, the intrusion range of the working fluid is small, generally reaching 10 m to 50 m. Compared with a conventional gas reservoir or shale gas reservoir, the working fluid loss during CBM development will seriously affect the subsequent production project and even make the gas well lose production capacity. On the other hand, in order to avoid this phenomenon, measures such as acidification or volumetric fracturing are sometimes used to improve the seepage environment near the well and near the fracture. The purpose of this study is to quantitatively evaluate the impacts of working fluid filtration and reservoir reconstruction on production. In this study, a single well productivity evaluation model and sensitivity analysis method considering drilling fluid filtration loss, fracturing fluid filtration loss, reservoir reconstruction and other processes is proposed. The formation mechanism of fluid loss during drilling and fracturing is described, and the productivity evaluation model considering fluid loss is combined with the Langmuir isothermal adsorption equation, steady-state diffusion law, Darcy’s seepage law and Duhamel convolution formation. Combined with the distribution of actual gas reservoir flow characteristics, the sensitivity of single well productivity to gas reservoir porosity, gas reservoir permeability, coal seam adsorption coefficient, working fluid filtration loss and reservoir reconstruction measures are analyzed. Through the analysis and fitting of the actual production data on site, the relationship curve can better fit the field production data, and the evaluation results are in line with the drilling and fracturing conditions at that time and the subsequent production conditions, with small errors. The obtained method is suitable for predicting the productivity of fractured vertical wells in different working conditions and provides a basis for the development and productivity prediction of CBM reservoirs in China and in international cooperation. Full article

(This article belongs to the Special Issue Advances in the Development of Unconventional Oil and Gas Resources)

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22 pages, 8605 KiB

Open AccessArticle

Optimization Method of Production System for Coalbed Methane Wells throughout Life Cycle

by Chen Li, Lichun Sun, Zhigang Zhao, Jian Zhang, Cunwu Wang, Gang Lei, Yong Li and Yanjun Meng

Energies 2024, 17(4), 789; https://doi.org/10.3390/en17040789 - 06 Feb 2024

Viewed by 524

Abstract

Different from conventional gas reservoirs, the permeability of coalbeds is affected by stress sensitivity and matrix shrinkage during production. These two conditions lead to lower permeability in the reservoir and affect the production efficiency of the gas well. In addition, coalbed methane wells [...] Read more.

Different from conventional gas reservoirs, the permeability of coalbeds is affected by stress sensitivity and matrix shrinkage during production. These two conditions lead to lower permeability in the reservoir and affect the production efficiency of the gas well. In addition, coalbed methane wells have single-phase water flow in the initial stage of production. When the reservoir pressure is reduced to its critical desorption pressure, the adsorbed gas in the reservoir desorbs into the pore space and participates in the flow. The flow state in the reservoir changes from single-phase to two phase, and the permeability of the reservoir decreases. The occurrence of these three damage mechanisms is related to the flow rate of fluid in the reservoir. At present, there is a lack of research on the optimization of drainage and production systems considering the damage mechanism of coal reservoirs. This study comprehensively considers how to optimize the production rate of coal reservoirs under the influence of stress sensitivity, matrix shrinkage and two phase flow in the production process to achieve the purpose of production with the least damage to the reservoir. Full article

(This article belongs to the Special Issue Advances in the Development of Unconventional Oil and Gas Resources)

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16 pages, 6911 KiB

Open AccessArticle

Enhanced Gas Recovery for Tight Gas Reservoirs with Multiple-Fractured Horizontal Wells in the Late Stages of Exploitation: A Case Study in Changling Gas Field

by Bo Ning, Junjian Li, Taixian Zhong, Jianlin Guo, Yuyang Liu, Ninghai Fu, Kang Bie and Fankun Meng

Energies 2023, 16(24), 7918; https://doi.org/10.3390/en16247918 - 05 Dec 2023

Cited by 1 | Viewed by 652

Abstract

To initially improve the gas production rate and shorten the payback period for tight gas reservoirs, the multiple-fractured horizontal well (MFHW) model is always applied. However, in the late stages of exploitation, it is difficult to adopt reasonable measures for enhanced gas recovery [...] Read more.

To initially improve the gas production rate and shorten the payback period for tight gas reservoirs, the multiple-fractured horizontal well (MFHW) model is always applied. However, in the late stages of exploitation, it is difficult to adopt reasonable measures for enhanced gas recovery (EGR), particular for continental sedimentary formation with multiple layers, and efficient strategies for EGR in this type of gas field have not yet been presented. Therefore, in this paper, a typical tight gas reservoir in the late stages of exploitation, the Denglouku gas reservoir in Changling gas field, in which MFHWs were utilized and contributed to the communication of the higher Denglouku formation (0.34 mol% CO₂) and lower Yingcheng formation (27 mol% CO₂) during hydraulic fracturing, is studied comprehensively. Firstly, alongside the seismic, logging, drilling and experimental data, 3D geological and numerical simulation models are developed. According to the differences in CO₂ mole fractions for different formations, the gas production rate of MFHWs produced from Denglouku formation is accurately calculated. Then, the well gas production rate (WGPR) and the well bottom-hole pressure (WBHP) history are matched with the calculated values, and thus the types of remaining gas are provided through the fine reservoir description. Finally, in a combination of gas recovery and economics, the optimal infill well type and the adjustment scheme are determined. The results show that there are three main categories of remaining gas, which are areal distribution, abundant points, and marginal dispersion, and the ratios of reaming gas reserve for these three types are 80.3%, 4.2%, and 15.5%, respectively. For the tight gas reservoir developed by MFHWs with parallel and zipper patterns, the best infilling well type is the vertical well. The combination of patching holes, sidetracking, infilling and boosting can obtain the highest gas recovery, while the scheme with patching holes and sidetracking has the best economic benefits. To balance the gas recovery and economics, the measurement of patching holes, sidetracking and infilling with vertical wells is utilized. In the final production period, compared with the basic schemes, the gas recovery can increase by 5.5%. The primary novelty of this paper lies in the determination of the optimal infilling well types and its presentation of a comprehensive adjustment workflow for EGR in tight gas reservoirs. The conclusions in this paper can provide some guidance for other similar tight gas reservoirs developed with MFHWs in the later period. Full article

(This article belongs to the Special Issue Advances in the Development of Unconventional Oil and Gas Resources)

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24 pages, 5620 KiB

Open AccessArticle

A Powerful Prediction Framework of Fracture Parameters for Hydraulic Fracturing Incorporating eXtreme Gradient Boosting and Bayesian Optimization

by Zhe Liu, Qun Lei, Dingwei Weng, Lifeng Yang, Xin Wang, Zhen Wang, Meng Fan and Jiulong Wang

Energies 2023, 16(23), 7890; https://doi.org/10.3390/en16237890 - 03 Dec 2023

Viewed by 806

Abstract

In the last decade, low-quality unconventional oil and gas resources have become the primary source for domestic oil and gas storage and production, and hydraulic fracturing has become a crucial method for modifying unconventional reservoirs. This paper puts forward a framework for predicting [...] Read more.

In the last decade, low-quality unconventional oil and gas resources have become the primary source for domestic oil and gas storage and production, and hydraulic fracturing has become a crucial method for modifying unconventional reservoirs. This paper puts forward a framework for predicting hydraulic fracture parameters. It combines eXtreme Gradient Boosting and Bayesian optimization to explore data-driven machine learning techniques in fracture simulation models. Analyzing fracture propagation through mathematical models can be both time-consuming and costly under conventional conditions. In this study, we predicted the physical parameters and three-dimensional morphology of fractures across multiple time series. The physical parameters encompass fracture width, pressure, proppant concentration, and inflow capacity. Our results demonstrate that the fusion model applied can significantly improve fracture morphology prediction accuracy, exceeding 0.95, while simultaneously reducing computation time. This method enhances standard numerical calculation techniques used for predicting hydraulic fracturing while encouraging research on the extraction of unconventional oil and gas resources. Full article

(This article belongs to the Special Issue Advances in the Development of Unconventional Oil and Gas Resources)

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13 pages, 15033 KiB

Open AccessArticle

Research on Transformation of Connate Water to Movable Water in Water-Bearing Tight Gas Reservoirs

by Fuhu Chen, Zengding Wang, Shuaishi Fu, Aifen Li and Junjie Zhong

Energies 2023, 16(19), 6961; https://doi.org/10.3390/en16196961 - 05 Oct 2023

Viewed by 732

Abstract

The Dongsheng gas field is a water-bearing tight gas reservoir characterized by high connate water saturation. During gas production, the transformation of connate water into movable water introduces a unique water production mode, significantly impacting gas reservoir recovery. Current experimental and theoretical methods [...] Read more.

The Dongsheng gas field is a water-bearing tight gas reservoir characterized by high connate water saturation. During gas production, the transformation of connate water into movable water introduces a unique water production mode, significantly impacting gas reservoir recovery. Current experimental and theoretical methods for assessing formation water mobility are static and do not address the transformation mechanism from connate into movable water. In this study, we considered dynamic changes in formation stress and proposed the mechanism for the transformation of connate water into movable water during depressurization, involving the expansion of connate water films and the reduction of pore volume. We developed a novel methodology to calculate the dynamic changes in movable and connate water saturation in tight reservoirs due to reservoir pressure reduction. Furthermore, we quantitatively evaluated the transformation of connate water into movable water in the Dongsheng gas field through laboratory experiments (including formation water expansion tests, connate water tests, and porosity stress sensitivity tests) and theoretical calculations. Results show that under original stress, the initial connate water saturation in the Dongsheng gas field ranges from 50.09% to 58.5%. As reservoir pressure decreases, the maximum increase in movable water saturation ranges from 6.1% to 8.4% due to the transformation of connate water into movable water. This explains why formation water is produced in large quantities during gas production. Therefore, considering the transition of connate water to movable water is crucial when evaluating water production risk. These findings offer valuable guidance for selecting optimal well locations and development layers to reduce reservoir water production risks. Full article

(This article belongs to the Special Issue Advances in the Development of Unconventional Oil and Gas Resources)

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18 pages, 6955 KiB

Open AccessArticle

Diagnostic Fracture Injection Tests Analysis and Numerical Simulation in Montney Shale Formation

by Lulu Liao, Gensheng Li, Yu Liang and Yijin Zeng

Energies 2022, 15(23), 9094; https://doi.org/10.3390/en15239094 - 30 Nov 2022

Cited by 2 | Viewed by 1536

Abstract

Unconventional oil and gas formations are abundant, have become an increasingly important part of the global energy supply, and are attracting increasing attention from the industry. Predicting key reservoir properties plays a significant role in both geological science and subsurface engineering workflows. With [...] Read more.

Unconventional oil and gas formations are abundant, have become an increasingly important part of the global energy supply, and are attracting increasing attention from the industry. Predicting key reservoir properties plays a significant role in both geological science and subsurface engineering workflows. With the advent of horizontal well drilling and multiple-stage hydraulic fracturing, the Montney Shale formation is one of the most promising and productive shale plays in Canada. However, very few academic papers discuss its in situ stress, reservoir pressure, and permeability, which are essential for the development of the Montney Shale. The objective of this study is to analyze the geo-stress, the pore pressure, and several key reservoir properties by using diagnostic fracture injection test (DFIT) data from the Montney Shale. One horizontal well from the Wapiti field has been analyzed with a set of DFIT data, and its results show that the general pressure and Gdp/dG responses from Well-A indicate a signature of height recession/transverse storage. In the study, the Tangent Line method, the Compliance method, and the Variable Compliance method have been applied to estimate the key reservoir properties. As a result, the Well-A DFIT analysis estimates that the closure pressure is ranging from 34.367 to 39.344 MPa, contributing to the stress gradient from 14.09 to 16.13 KPa/m for the formation. The pore pressure is ranging from 20.82 to 24.58 MPa, contributing to the pore pressure gradient from 8.54 to 10.07 KPa/m for the formation. The porosity is ranging from 3% to 6%. These reservoir properties are contoured cross the Montney Shale formation. Using the DFIT’s numerical simulation and history matching, the reservoir permeability is 0.024 md, fracture length is 13.44 m, and fracture geometries are analyzed by different models. Moreover, the physics behind the DFIT are analyzed and discussed in detail. For the first time, three different analysis methods have been applied to estimate a series of key reservoir properties for the case wells in the Montney Shale formation. This approach can not only reduce the potential prediction error caused by a single method application but also increase the persuasiveness of the assessment and save time, ensuring the efficient implementation of engineering operations. Given the significance of quantifying in situ stress and reservoir pore pressure in unconventional hydrocarbon exploration and development, this study could help the operator to quickly understand the stress regimes, the fracture geometry, and the formation properties of the Montney Shale formation in the Wapiti field. Furthermore, the interpreted results demonstrated in this paper are adding substantial business value to the asset, especially in terms of improving the hydraulic fracturing design and, thus, accelerating the cashflow from production. Full article

(This article belongs to the Special Issue Advances in the Development of Unconventional Oil and Gas Resources)

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17 pages, 5982 KiB

Open AccessArticle

Effect of Wettability Heterogeneity on Water-Gas Two-Phase Displacement Behavior in a Complex Pore Structure by Phase-Field Model

by Wenbo Gong and Jinhui Liu

Energies 2022, 15(20), 7658; https://doi.org/10.3390/en15207658 - 17 Oct 2022

Viewed by 1323

Abstract

Understanding the immiscible displacement mechanism in porous media is vital to enhancing the hydrocarbon resources in the oil and gas reservoir. Improving resource recovery requires quantitatively characterizing the effect of wettability heterogeneity on the immiscible displacement behaviors at the pore scale, which can [...] Read more.

Understanding the immiscible displacement mechanism in porous media is vital to enhancing the hydrocarbon resources in the oil and gas reservoir. Improving resource recovery requires quantitatively characterizing the effect of wettability heterogeneity on the immiscible displacement behaviors at the pore scale, which can be used to predict the displacement distribution of multiphase fluids and evaluate the optimal wettability strategy in porous media. The heterogeneity of fluid wettability in a natural rock makes it extremely hard to directly observe the fluid displacement behaviors in the reservoir rocks and quantify the sensitivity of preferential displacement path and displacement efficiency to wettability distribution. In this study, the phase-field model coupling wettability heterogeneity was established. The gas-water two-phase displacement process was simulated under various wettability distributions and injecting flux rates in a complex pore structure. The effect of wettability heterogeneity on immiscible displacement behavior was analyzed. The results indicated that wettability heterogeneity significantly affects the fluid displacement path and invasion patterns, while the injecting flux rate negatively influences the capillary–viscous crossover flow regime. The continuous wetting patches enhanced the preferential flow and hindered displacement, whereas the dalmatian wetting patches promoted a higher displacement efficiency. The results of the fractal dimensions and specific surface area also quantitatively show the effects of wettability distribution and heterogeneity on the complexity of the two-phase fluid distribution. The research provides the theoretical foundation and analysis approach for designing an optimal wettability strategy for injecting fluid into unconventional oil and gas reservoirs. Full article

(This article belongs to the Special Issue Advances in the Development of Unconventional Oil and Gas Resources)

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15 pages, 12720 KiB

Open AccessArticle

Investigation of the Evolution of Stratum Fracture during the Cavity Expansion of Underground Coal Gasification

by Zhen Dong, Haiyang Yi, Yufeng Zhao, Xinggang Wang, Tingxiang Chu, Junjie Xue, Hanqi Wu, Shanshan Chen, Mengyuan Zhang and Hao Chen

Energies 2022, 15(19), 7373; https://doi.org/10.3390/en15197373 - 07 Oct 2022

Cited by 3 | Viewed by 1166

Abstract

The evolution of fracture zone controls the safety of underground coal gasification (UCG) in terms of gas emission and water leakage. In order to understand the fracture propagation in the confining rock of a UCG cavity with various influence factors, this paper implemented [...] Read more.

The evolution of fracture zone controls the safety of underground coal gasification (UCG) in terms of gas emission and water leakage. In order to understand the fracture propagation in the confining rock of a UCG cavity with various influence factors, this paper implemented a set of numerical models based on different geological and operating conditions. Analysis was implemented on the mechanism of fracture propagation and its evolution characteristics, suggesting that (a) continuum expansion of the cavity leads a near-field fracture circle in confining rock initially, followed by the roof caving and successive propagation of shear band. (b) The key observed influence factors of fracture propagation are the grade of confining rock, overburden pressure, dimension of the cavity and gasifying pressure, the linear relationships between them, and the fracture height. Additionally, the fracture depth in the base board was mainly caused by tensile fracture. (c) A model was proposed based on the evolution of fracture height and depth in roof and base board, respectively. Validation of this model associated with orthogonal tests suggests a good capacity for predicting fracture distribution. This paper has significance in guiding the design of the gasifying operation and safety assessment of UCG cavities. Full article

(This article belongs to the Special Issue Advances in the Development of Unconventional Oil and Gas Resources)

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10 pages, 5507 KiB

Open AccessArticle

NMR-Based Shale Core Imbibition Performance Study

by Yuping Sun, Qiaojing Li, Cheng Chang, Xuewu Wang and Xuefeng Yang

Energies 2022, 15(17), 6319; https://doi.org/10.3390/en15176319 - 30 Aug 2022

Cited by 4 | Viewed by 1066

Abstract

Shale gas reservoirs are unconventional resources with great potential to help meet energy demands. Horizontal drilling and hydraulic fracturing have been extensively used for the exploitation of these unconventional resources. According to engineering practice, some shale gas wells with low flowback rate of [...] Read more.

Shale gas reservoirs are unconventional resources with great potential to help meet energy demands. Horizontal drilling and hydraulic fracturing have been extensively used for the exploitation of these unconventional resources. According to engineering practice, some shale gas wells with low flowback rate of fracturing fluids may obtain high yield which is different from the case of conventional sandstone reservoirs, and fracturing fluid absorbed into formation by spontaneous imbibition is an important mechanism of gas production. This paper integrates NMR into imbibition experiment to examine the effects of fractures, fluid salinity, and surfactant concentration on imbibition recovery and performance of shale core samples with different pore-throat sizes acquired from the Longmaxi Formation in Luzhou area, the Sichuan Basin. The research shows that the right peak of T₂ spectrum increases rapidly during the process of shale imbibition, the left peak increases rapidly at the initial stage and changes gently at the later stage, with the peak of the left peak shifting to the right. The result indicates that water first enters the fracture system quickly, then enters the small pores near the fracture wall due to the effect of the capillary force, and later gradually sucks into the deep and large pores. Both imbibition rate and capacity increase with increased fracture density, decreased solution salinity, and decreased surfactant concentration. After imbibition flowback, shale permeability generally increases by 8.70–17.88 times with the average of 13.83 times. There are also many microcracks occurring on the end face and surface of the core sample after water absorption, which may function as new flowing channels to further improve reservoir properties. This research demonstrates the imbibition characteristics of shale and several relevant affecting factors, providing crucial theory foundations for the development of shale gas reservoirs. Full article

(This article belongs to the Special Issue Advances in the Development of Unconventional Oil and Gas Resources)

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18 pages, 4572 KiB

Open AccessArticle

Research and Successful Application of the Diverted Fracturing Technology of Spontaneously Selecting Geologic Sweet Spots in Thin Interbedded Formation in Baikouquan Field

by Chuanyi Tang, Wenxi Xu, Baiyang Li, Huazhi Xin, Xiaoshuan Zhang, Hui Tian and Jianye Mou

Energies 2022, 15(14), 5208; https://doi.org/10.3390/en15145208 - 18 Jul 2022

Cited by 1 | Viewed by 1065

Abstract

Baikouquan oil field is composed of multiple interbedded, thin, low-permeability layers, which are required to vertically fracture multiple layers and to create complex fractures for economic development. However, conventional fracture technologies create a single, simple fracture, having poor feasibility for this field. Therefore, [...] Read more.

Baikouquan oil field is composed of multiple interbedded, thin, low-permeability layers, which are required to vertically fracture multiple layers and to create complex fractures for economic development. However, conventional fracture technologies create a single, simple fracture, having poor feasibility for this field. Therefore, we conducted research on fracturing technology by spontaneously selecting geologic sweet spots based on diversion. This technology can vertically fracture the thin layers one by one and horizontally divert the fracture to non-depleted areas. Firstly, a triaxial diverted fracturing experiment approach was setup, and then diverted fracturing experiments were carried out to verify the feasibility of diverted fracturing and to study the fracture geometry and the law of diversion. Next, experiments were carried out to evaluate the performance of the diversion agents. The valuated properties comprise the diversion pressure, stability time, and degradation based on which to optimize the selection of the diversion agents. Finally, the fracturing technology was applied to well b21004 of Baikouquan oil field, and post-frac performance was evaluated. The experimental results show that multiple and complex fractures are realized through temporary plugging. Diversion performance evaluation tests show that a 4 wt% concentration of 1–5 mm granules + 20/60 mesh powder and a 3 wt% concentration of 1–7 mm granules + 20/60 mesh powder + fiber can hold up enough pressure to force the fracture to divert. The field treating pressure curve shows that there is a 3–10 MPa pressure increase when there are pump diversion agents, which is a clear sign of fracture diversion. Plugging the fracture mouth gives a faster and a higher incremental pressure. Before this fracturing, the well had almost stopped oil production. After the stimulation, the initial oil production rate became 20 + t/d, which shows the effectiveness of this fracturing technology for Baikouquan oil field. Full article

(This article belongs to the Special Issue Advances in the Development of Unconventional Oil and Gas Resources)

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