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26 pages, 12228 KiB

Open AccessArticle

The Inversion Method of Shale Gas Effective Fracture Network Volume Based on Flow Back Data—A Case Study of Southern Sichuan Basin Shale

by Dengji Tang, Jianfa Wu, Jinzhou Zhao, Bo Zeng, Yi Song, Cheng Shen, Lan Ren, Yongzhi Huang and Zhenhua Wang

Processes 2024, 12(5), 1027; https://doi.org/10.3390/pr12051027 - 18 May 2024

Viewed by 1030

Abstract

Fracture network fracturing is pivotal for achieving the economical and efficient development of shale gas, with the connectivity among fracture networks playing a crucial role in reservoir stimulation effectiveness. However, flow back data that reflect fracture network connectivity information are often ignored, resulting [...] Read more.

Fracture network fracturing is pivotal for achieving the economical and efficient development of shale gas, with the connectivity among fracture networks playing a crucial role in reservoir stimulation effectiveness. However, flow back data that reflect fracture network connectivity information are often ignored, resulting in an inaccurate prediction of the effective fracture network volume (EFNV). The accurate calculation of the EFNV has become a key and difficult issue in the field of shale fracturing. For this reason, the accurate shale gas effective fracture network volume inversion method needs to be improved. Based on the flow back characteristics of fracturing fluids, a tree-shaped fractal fracture flow back mathematical model for inversion of EFNV was established and combined with fractal theory. A genetic algorithm workflow suitable for EFNV inversion of shale gas was constructed based on the flow back data after fracturing, and the fracture wells in southern Sichuan were used as an example to carry out the EFNV inversion. The reliability of the inversion model was verified by testing production, cumulative gas production, and microseismic results. The field application showed that the inversion method proposed in this paper can obtain tree-shaped fractal fracture network structure parameters, fracture system original pressure, matrix gas breakthrough pressure, fracture compressibility coefficient, reverse imbibition index, equivalent main fracture half length, and effective initial fracture volume (EIFV). The calculated results of the model belong to the same order of magnitude as those of the HD model and Alkouh model, and the model has stronger applicability. This research has important theoretical guiding significance and field application value for improving the accuracy of the EFNV calculation. Full article

(This article belongs to the Special Issue Advances in Technology for Enhancing Oil and Gas Recovery in Shale Reservoirs)

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21 pages, 10564 KiB

Open AccessArticle

Preparation and Application of CO₂-Resistant Latex in Shale Reservoir Cementing

by Chunyuan Jiang, Xuecheng Zheng, Yuanqiang Zhu, Lei Tang, Yuhao Liu, Zhijun Zhao and Hongyu Zhang

Processes 2024, 12(5), 945; https://doi.org/10.3390/pr12050945 - 7 May 2024

Viewed by 867

Abstract

With the application of CO₂ fracturing, CO₂ huff and puff, CO₂ flooding, and other stimulation technologies in shale reservoirs, a large amount of CO₂ remained in the formation, which also lead to the serious corrosion problem of CO₂ [...] Read more.

With the application of CO₂ fracturing, CO₂ huff and puff, CO₂ flooding, and other stimulation technologies in shale reservoirs, a large amount of CO₂ remained in the formation, which also lead to the serious corrosion problem of CO₂ in shale reservoirs. In order to solve the harm caused by CO₂ corrosion, it is necessary to curb CO₂ corrosion from the cementing cement ring to ensure the long-term stable exploitation of shale oil. Therefore, a new latex was created using liquid polybutadiene, styrene, 2-acrylamide-2-methylpropanesulfonic acid, and maleic anhydride to increase the cement ring’s resistance to CO₂ corrosion. The latex’s structure and characteristics were then confirmed using infrared, particle size analyzer, thermogravimetric analysis, and transmission electron microscopy. The major size distribution of latex is between 160 and 220 nm, with a solid content of 32.2% and an apparent viscosity of 36.8 mPa·s. And it had good physical properties and stability. Latex can effectively improve the properties of cement slurry and cement composite. When the amount of latex was 8%, the fluidity index of cement slurry was 0.76, the consistency index was 0.5363, the free liquid content was only 0.1%, and the water loss was reduced to 108 mL. At the same time, latex has a certain retarding ability. With 8% latex, the cement slurry has a specific retarding ability, is 0.76 and 0.5363, has a free liquid content of just 0.1%, and reduces water loss to 108 mL. Moreover, latex had certain retarding properties. The compressive strength and flexural strength of the latex cement composite were increased by 13.47% and 33.64% compared with the blank cement composite. A long-term CO₂ corrosion experiment also showed that latex significantly increased the cement composite’s resilience to corrosion, lowering the blank cement composite’s growth rate of permeability from 46.88% to 19.41% and its compressive strength drop rate from 27.39% to 11.74%. Through the use of XRD and SEM, the latex’s anti-corrosion mechanism, hydration products, and microstructure were examined. In addition to forming a continuous network structure with the hydrated calcium silicate and other gels, the latex can form a latex film to attach and fill the hydration products. This slows down the rate of CO₂ corrosion of the hydration products, enhancing the cement composite’s resistance to corrosion. CO₂-resistant toughened latex can effectively solve the CO₂ corrosion problem of the cementing cement ring in shale reservoirs. Full article

(This article belongs to the Special Issue Advances in Technology for Enhancing Oil and Gas Recovery in Shale Reservoirs)

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16 pages, 8385 KiB

Open AccessArticle

Research on the Multifactor Synergistic Corrosion of N80 and P110 Steel Tubing in Shale Gas Wells in Sichuan Basin

by Yufei Li, Dajiang Zhu, Jian Yang, Qiang Liu, Lin Zhang, Linfeng Lu, Xiangkang Liu and Shuai Wang

Processes 2024, 12(5), 920; https://doi.org/10.3390/pr12050920 - 30 Apr 2024

Cited by 2 | Viewed by 896

Abstract

We aimed to investigate the corrosion patterns and the main controlling factors of N80 steel and P110 steel tubing under different sections. Conducting weight loss corrosion experiments for 168 h using high-temperature and high-pressure autoclaves to simulate the corrosion behavior of two types [...] Read more.

We aimed to investigate the corrosion patterns and the main controlling factors of N80 steel and P110 steel tubing under different sections. Conducting weight loss corrosion experiments for 168 h using high-temperature and high-pressure autoclaves to simulate the corrosion behavior of two types of casing materials, N80 steel and P110 steel, in different well sections under specific conditions of CO₂ content, chloride ion concentration, temperature, pressure, and sulfate-reducing bacteria population in highly mineralized formation water. X-ray diffraction (XRD), scanning electron microscopy (SEM), and energy-dispersive X-ray spectroscopy (EDS) were used to analyze the corrosion products, surface morphology, and elemental composition of the two steel pipes. Additionally, 3D microscopy was employed to observe the morphology and measure the dimensions of localized corrosion pits. Under different well sections, the corrosion products formed on N80 steel and P110 steel mainly consist of FeCO_3, and crystalline salts of chlorides present in the solution medium. Under low-water-cut conditions, narrow and deep corrosion defects were observed, while narrow and shallow corrosion defects were found under high-water-cut conditions. In the upper wellbore section, both steel pipes exhibited dispersed and thin corrosion product films that suffered from rupture and detachment, resulting in severe localized corrosion. In the middle wellbore section, the corrosion product film on N80 steel comprised irregularly arranged polygonal grains, some of which exhibited significant gaps, leading to extremely severe corrosion. For P110 steel, the corrosion product film was also dispersed and thin, with extensive detachment and extremely severe corrosion. In the lower wellbore section, both steel pipes were covered with a dense layer of grains, with smaller gaps between them, effectively protecting the metal matrix from corrosion. Consequently, the corrosion rate decreased compared to the middle section but still exhibited severe corrosion. In low-water-cut conditions, attention should be given to the risk of column safety due to corrosion from condensate water and CO₂, as well as the size of narrow and deep corrosion defects in the middle wellbore section. In high-water-cut conditions, it is recommended to use corrosion inhibitors in combination while focusing on SRB bacteria corrosion in the upper wellbore section, condensate water in the middle section, CO₂ content and chloride ion coupling in the lower section, and the size of narrow and shallow corrosion defects causing column safety risks. Full article

(This article belongs to the Special Issue Advances in Technology for Enhancing Oil and Gas Recovery in Shale Reservoirs)

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16 pages, 2901 KiB

Open AccessArticle

Simulation and Control Strategies for Longitudinal Propagation of Acid Fracture in a Low-Permeability Reservoir Containing Bottom Water

by Song Li, Yu Fan, Yujie Guo, Yang Wang, Tingting He, Hua Zhang, Jiexiao Ye, Weihua Chen and Xi Zhang

Processes 2024, 12(4), 792; https://doi.org/10.3390/pr12040792 - 15 Apr 2024

Cited by 10 | Viewed by 831

Abstract

The reservoir in the Anyue gas field, located in the Sichuan basin of China, belongs to the second member of the Dengying formation and has distinctive geological features. It is characterized by strong heterogeneity, low porosity, low permeability, and locally developed natural fractures. [...] Read more.

The reservoir in the Anyue gas field, located in the Sichuan basin of China, belongs to the second member of the Dengying formation and has distinctive geological features. It is characterized by strong heterogeneity, low porosity, low permeability, and locally developed natural fractures. The reservoir space consists primarily of corrosion holes, natural fractures, and similar voids. Moreover, the lower reservoir exhibits high water saturation and a homogeneous bottom-water interface. Since it is a carbonate-based hydrocarbon reservoir with low porosity and permeability, deep acid fracturing has proven to be an efficient method for enhancing individual well production. However, the reconstruction of the second member of the Dengying formation reservoir poses significant challenges. The reservoir contains high-angle natural fractures, small vertical stress differences, and is located in close proximity to the gas–water interface. As a result, it becomes difficult to control the height of the acid break. Improper acid break treatment may easily result in water production affecting gas well production. To explore ways to control the longitudinal extension of acid fractures, 3D numerical models focusing on the initiation and expansion of acid fractures have been developed. This model takes into account geological and engineering factors such as stress differences, acid fracture displacements and scales, and their effects on the longitudinal extension of acid fractures. It was revealed that the pressure difference is the main controlling factor for the acid fracture height, followed by the reservoir thickness, the interlayer thickness, and the viscosity of the working fluid. Technical countermeasures for controlled fracture and high-acid fracturing tailored to different reservoir characteristics have been proposed, and design parameters for controlled fracture and high-acid fracturing can be optimized. By effectively controlling the vertical extension of the acid fracture, it is possible to maximize production from a single well while avoiding interference from the lower water layer. This study provides theoretical guidance for the application of deep-acid-fracturing techniques in low-permeability bottom-water gas reservoirs. Full article

(This article belongs to the Special Issue Advances in Technology for Enhancing Oil and Gas Recovery in Shale Reservoirs)

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16 pages, 2631 KiB

Open AccessArticle

Adsorption and Desorption Behavior of Partially Hydrolyzed Polyacrylamide on Longmaxi Shale

by Jun Li, Taotao Luo, Tingting Cheng, Ying Lei, Yameng Xing, Bin Pan and Xiao Fu

Processes 2024, 12(3), 606; https://doi.org/10.3390/pr12030606 - 18 Mar 2024

Viewed by 887

Abstract

Large-scale volumetric fracturing is generally used during shale gas development. The return rate of fracturing fluid is low, and a large amount of slickwater is retained in the reservoir. The adsorption and desorption of partially hydrolyzed polyacrylamide (HPAM), an additive commonly used in [...] Read more.

Large-scale volumetric fracturing is generally used during shale gas development. The return rate of fracturing fluid is low, and a large amount of slickwater is retained in the reservoir. The adsorption and desorption of partially hydrolyzed polyacrylamide (HPAM), an additive commonly used in slickwater, on the surface of shale was studied using Longmaxi shale from the Sichuan Basin. The experimental results showed that the mass ratio of the HPAM solution to shale reached saturation adsorption at 20:1 when the concentration of HPAM solution was 1000 mg/L and 25:1 when the concentration of HPAM solution was 500 mg/L. The mass ratio of the HPAM solution to shale was fixed at 25:1, and the adsorption equilibrium was reached at a HPAM concentration of 1000 mg/L when the aqueous solution temperature was 30 °C and 800 mg/L when the aqueous solution temperature was 60 °C. The Langmuir adsorption model yielded a better fit than the Freundlich adsorption model. The adsorption equilibrium time at 30 °C was at 60 min for a HPAM concentration of 500 mg/L, while for a concentration of 1000 mg/L, it was at 90 min. The adsorption equilibrium time at 60 °C was 40 min for a HPAM concentration of 500 mg/L, whereas it was 60 min for a HPAM concentration at 1000 mg/L. The pseudo-second order (PSO) kinetics model yielded better fits than the pseudo-first order (PFO) kinetics model. The adsorption of HPAM on shale was strong, and the adsorbed HPAM resembled cobwebs adhering to the shale surface. HPAM on the surface of shale after adsorption was able to resist the desorption capacity of water. However, when the amount of adsorbed HPAM on shale increased significantly, the amount of residual HPAM on the surface of the shale decreased rapidly during desorption in deionized water. The desorption of HPAM on the shale surface followed a modified desorption model. The higher the concentration of HPAM adsorbed on the shale surface was, the easier it was to desorb and the easier it was to be removed from the shale. Full article

(This article belongs to the Special Issue Advances in Technology for Enhancing Oil and Gas Recovery in Shale Reservoirs)

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11 pages, 3200 KiB

Open AccessArticle

A New Fracturing Method to Improve Stimulation Effect of Marl Tight Oil Reservoir in Sichuan Basin

by Yang Wang, Yu Fan, Song Li, Zefei Lv, Rui He and Liang Wang

Processes 2023, 11(11), 3234; https://doi.org/10.3390/pr11113234 - 16 Nov 2023

Cited by 1 | Viewed by 916

Abstract

China’s argillaceous limestone reservoir has a lot of oil and gas resources, and hydraulic fracturing of the argillaceous limestone reservoir faces many difficulties. The first problem is that the heterogeneity of the argillaceous limestone reservoir is strong, and it is difficult to optimize [...] Read more.

China’s argillaceous limestone reservoir has a lot of oil and gas resources, and hydraulic fracturing of the argillaceous limestone reservoir faces many difficulties. The first problem is that the heterogeneity of the argillaceous limestone reservoir is strong, and it is difficult to optimize fracturing parameters. The second problem is that there are a lot of natural fractures in the argillaceous limestone reservoir, which leads to a lot of fracturing fluid loss. The third problem is that the closure pressure of the argillaceous limestone reservoir is high, and the conductivity of fractures decreases rapidly under high closure pressure. The last problem is that the fracture shape of the argillaceous limestone reservoir is complex, and the law of proppant migration is unclear. The main research methods in this paper include reservoir numerical simulation, fluid-loss-reducer performance evaluation, flow conductivity tests and proppant migration visualization. To solve the above problems, this paper establishes the fracturing productivity prediction model of complex lithology reservoirs and defines the optimal hydraulic fracturing parameters of the argillous limestone reservoir in the Sichuan Basin. The 70/140 mesh ceramide was selected as the fluid loss additive after an evaluation of the sealing properties of different mesh ceramides. At the same time, the hydraulic fracture conductivity test is carried out in this paper, and it is confirmed that the fracture conductivity of 70/140 mesh and 40/70 mesh composite particle-size ceramics mixed according to the mass ratio of 5:5 is the highest. When the closure pressure is 40 MPa, the conductivity of a mixture of 70/140 mesh ceramic and 40/70 mesh ceramic is 35.6% higher than that of a mixture of 70/140 mesh ceramic and 30/50 mesh ceramic. The proppant migration visualization device is used to evaluate the morphology of the sand dike formed by the ceramsite, and it is clear that the shape of the sand dike is the best when the mass ratio of 70/140 mesh ceramsite and 40/70 mesh ceramsite is 6:4. The research results achieved a good stimulation effect in the SC1 well. The daily oil production of the SC1 well is 20 t, and the monitoring results of the wide-area electromagnetic method show that the fracturing fracture length of the SC1 well is up to 129 m. Full article

(This article belongs to the Special Issue Advances in Technology for Enhancing Oil and Gas Recovery in Shale Reservoirs)

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22 pages, 9033 KiB

Open AccessArticle

Hydrocarbon Generation and Residue Features of Ediacaran High-Maturity Source Rocks and Their Significance in Gas Exploration in Sichuan Basin

by Wenyang Wang, Xiongqi Pang, Yaping Wang, Mingjun Chen, Ying Chen, Changrong Li and Zhangxin Chen

Processes 2023, 11(11), 3193; https://doi.org/10.3390/pr11113193 - 8 Nov 2023

Cited by 1 | Viewed by 1122

Abstract

Evaluating residual hydrocarbons is crucial for assessing shale oil and gas reservoirs, significantly impacting resource evaluation and exploration prospects. Previously regarded as lacking hydrocarbon generation potential, the Ediacaran Dengying Formation (Fm) microbial dolomite in the Sichuan Basin has been re-evaluated for its hydrocarbon [...] Read more.

Evaluating residual hydrocarbons is crucial for assessing shale oil and gas reservoirs, significantly impacting resource evaluation and exploration prospects. Previously regarded as lacking hydrocarbon generation potential, the Ediacaran Dengying Formation (Fm) microbial dolomite in the Sichuan Basin has been re-evaluated for its hydrocarbon generation capabilities. While understanding source rock characteristics is vital for petroleum resource assessment, a comprehensive analysis of the dolomite’s source rocks, encompassing hydrocarbon generation and residual features, remains undocumented. In this study, we thoroughly analyze the total organic carbon and vitrinite reflectance and extensively utilize pyrolysis analysis, gas chromatography and isotopic analysis of the organic kerogen from the Ediacaran Dengying Fm dolomite samples. The findings affirm that the Ediacaran Dengying Fm dolomite indeed serves as a source rock with moderate hydrocarbon generation and residue capabilities. This microbial dolomite was formed in a reducing marine environment with high salinity. Characterized by an averaging TOC of 0.82%, the kerogen is primarily identified as type I, with a minor presence of type II, and underwent thermal maturation up to the post-maturity stage. Throughout its geological history, the maximum intensities for hydrocarbon generation and residues were 4.5 × 10⁷ t/km² and 3.2 × 10⁷ t/km², respectively. Additionally, cumulatively generated and residual hydrocarbon quantities amounted to 2.7 × 10¹² t and 1.67 × 10¹² t, respectively. This study indicates significant exploration potential for the Ediacaran Dengying Fm microbial dolomite. Consequently, the central region in the Sichuan Basin has been identified as a promising area for future exploration endeavors. Our study provides valuable insights for the understanding of shale gas exploration in high-maturity source rock areas. Full article

(This article belongs to the Special Issue Advances in Technology for Enhancing Oil and Gas Recovery in Shale Reservoirs)

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16 pages, 10162 KiB

Open AccessArticle

A Design Method for Improving the Effect of Shale Interlaced with Limestone Reservoir Reconstruction

by Zefei Lv, Weihua Chen, Yang Wang, Rui He, Fei Liu and Song Li

Processes 2023, 11(11), 3190; https://doi.org/10.3390/pr11113190 - 8 Nov 2023

Viewed by 942

Abstract

Sichuan Basin, located in southwestern China, is renowned for its abundant oil and gas resources. Among these valuable reserves, Da’anzhai seashell limestone stands out as a significant contributor to the region’s energy industry. Da’anzhai seashell limestone is a type of sedimentary rock that [...] Read more.

Sichuan Basin, located in southwestern China, is renowned for its abundant oil and gas resources. Among these valuable reserves, Da’anzhai seashell limestone stands out as a significant contributor to the region’s energy industry. Da’anzhai seashell limestone is a type of sedimentary rock that contains substantial amounts of organic matter. Over millions of years, the accumulation and transformation of this organic material have resulted in the formation of vast reservoirs rich in oil and natural gas. These reservoirs are found within the layers of Da’anzhai seashell limestone. The geological conditions in Sichuan Basin have played a crucial role in the development and preservation of these resources. The basin’s unique tectonic history has created favorable conditions for the generation and accumulation of hydrocarbon. Additionally, the presence of faults and fractures within the rock formations has facilitated fluid migration and trapping, further enhancing the resource potential. The exploitation of Da’anzhai seashell limestone resources has significantly contributed to China’s energy security and economic growth. Oil extracted from these reserves not only meets domestic demand, but also supports various industries such as transportation, manufacturing, and power generation. Natural gas derived from this source plays an essential role in heating homes, fueling industrial processes, and reducing greenhouse gas emissions by replacing coal as a cleaner-burning alternative. Efforts to explore and exploit Da’anzhai seashell limestone continue through advanced technologies such as seismic imaging techniques, horizontal drilling methods, and hydraulic fracturing (fracking), among others. These technological advancements enable more efficient extraction while minimizing the environmental impact. It is worth noting that sustainable management practices should be implemented to ensure the responsible utilization of these resources without compromising the ecological balance or endangering local communities. Environmental protection measures must be prioritized throughout all stages—exploration, production, transportation—to mitigate any potential negative impacts on ecosystems or water sources. In conclusion, the Sichuan Basin boasts abundant oil and gas resources, with Da’anzhai seashell limestone playing a vital role in supporting China’s energy needs. Through responsible exploration, extraction, and utilization practices, these valuable reserves can contribute positively towards national development while ensuring environmental sustainability. Full article

(This article belongs to the Special Issue Advances in Technology for Enhancing Oil and Gas Recovery in Shale Reservoirs)

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12 pages, 2463 KiB

Open AccessArticle

Experimental Evaluation of Authigenic Acid Suitable for Acidification of Deep Oil and Gas Reservoirs at High Temperatures

by Yongwei Duan, Boru Chen and Yanpeng Li

Processes 2023, 11(10), 3002; https://doi.org/10.3390/pr11103002 - 18 Oct 2023

Cited by 2 | Viewed by 1089

Abstract

During the acid pressure conversion process in high-temperature, deep oil and gas reservoirs, a number of challenges are encountered that hinder the effectiveness of acid fracturing. These obstacles include significant corrosion of acidized pipe strings, rapid reaction rates of acid with rock, limited [...] Read more.

During the acid pressure conversion process in high-temperature, deep oil and gas reservoirs, a number of challenges are encountered that hinder the effectiveness of acid fracturing. These obstacles include significant corrosion of acidized pipe strings, rapid reaction rates of acid with rock, limited reach of acid liquids, and shallow penetration depth of active acids. Additionally, the transportation of highly corrosive acids presents safety risks, necessitating surface conditions that are free of acidity. However, underground conditions require strongly acidic liquids to meet enhanced ecological and environmental protection requirements. To address these limitations, experimental investigations have been conducted to examine the reaction rates of low-corrosive and low-acid rocks in alkaline systems involving halides and carbonyl compounds. Through meticulous assessments of reaction rates and dissociation effects in acid rocks, parameters have been successfully optimized to incorporate erythropoiesis and other compounding agents into acid-pressing designs. The experimental findings indicate that the concentration of released H⁺ ions after 60 min exceeded that of the conventional acid solution processed for 15 min. Enhanced dissolution was observed when erythropoietin content was increased to 20%. Furthermore, combining 10% acetic acid with 20% caustic acid resulted in a significant increase of 6.08% in the dissolution rate from 10 to 120 min, while exhibiting lower dissolution values compared with other types of acids. The development of naturally occurring acids with reduced rates of dissolution and acid–rock reaction holds significant potential for enhancing the efficacy of high-temperature, deep oil and gas reservoirs through acid fracturing stimulation. Full article

(This article belongs to the Special Issue Advances in Technology for Enhancing Oil and Gas Recovery in Shale Reservoirs)

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20 pages, 11909 KiB

Open AccessArticle

Effect of Lateral Trajectory on Two-Phase Flow in Horizontal Shale Gas Wells

by Jian Yang, Jiaxiao Chen, Yang Peng and Bochun Li

Processes 2023, 11(10), 2844; https://doi.org/10.3390/pr11102844 - 27 Sep 2023

Viewed by 964

Abstract

Horizontal gas wells are one of the key technologies for the production of shale gas reservoirs. Compared with conventional gas reservoirs, horizontal shale gas wells have ultra-long and complex lateral sections. Overall, toe-up, toe-down, and horizontal trajectories will be exhibited in the lateral [...] Read more.

Horizontal gas wells are one of the key technologies for the production of shale gas reservoirs. Compared with conventional gas reservoirs, horizontal shale gas wells have ultra-long and complex lateral sections. Overall, toe-up, toe-down, and horizontal trajectories will be exhibited in the lateral section. The statistical results of field production data indicate that the lateral trajectory has a significant impact on the estimated ultimate recovery. However, the mechanism has not yet been fully revealed owing to the complicated two-phase flow in lateral pipes. Therefore, taking horizontal shale gas wells’ lateral section as the research object, we designed our experimental parameter ranges based on horizontal shale gas wells in the Changning shale gas field. Simulation experimental tests were conducted on the pipe with an inclined angle from −15° to 15° to analyze the effects of different gas velocities, liquid velocities, and pipe inclinations on flow patterns and liquid holdup. Based on our observations and measurements, we evaluated the flow pattern prediction methods and drew a new flow pattern map for pipes with an inclined angle from −15° to 15°. Based on the momentum conservations between the gas and liquid phases and measured liquid holdup data, a new liquid holdup model was established in the pipes with inclined angle from −15° to 15°. Experimental and field-measured data were collected to verify the new method’s accuracy. Full article

(This article belongs to the Special Issue Advances in Technology for Enhancing Oil and Gas Recovery in Shale Reservoirs)

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19 pages, 8824 KiB

Open AccessArticle

Quantitative Characterization of Shale Pores and Microfractures Based on NMR T₂ Analysis: A Case Study of the Lower Silurian Longmaxi Formation in Southeast Sichuan Basin, China

by Chuxiong Li, Baojian Shen, Longfei Lu, Anyang Pan, Zhiming Li, Qingmin Zhu and Zhongliang Sun

Processes 2023, 11(10), 2823; https://doi.org/10.3390/pr11102823 - 25 Sep 2023

Cited by 2 | Viewed by 1150

Abstract

In order to quantitatively characterize shale pores and microfractures, twelve marine shale samples from the Longmaxi Formation in the southeastern Sichuan Basin were selected and their NMR T₂ spectra were analyzed under the conditions of full brine saturation, cyclic centrifugal treatment and [...] Read more.

In order to quantitatively characterize shale pores and microfractures, twelve marine shale samples from the Longmaxi Formation in the southeastern Sichuan Basin were selected and their NMR T₂ spectra were analyzed under the conditions of full brine saturation, cyclic centrifugal treatment and cyclic heat treatment. Then, movable, capillary bound and unrecoverable fluid of shale samples were distinguished and the NMR porosity and full-scale PSD were calculated. Based on NMR spectral peak identification, the relative content of pores and microfractures was determined and their influence factors were analyzed. The results show that the PSD of shale samples is bimodal, with pores distributed in the range of 1 nm to 200 nm and microfractures distributed in the range of 200 nm to 5000 nm, with relative contents in the ranges of 3.44–6.79% and 0.22–1.43%, respectively. Nanoscale organic pores are the dominant type of pores, while inorganic pores and microfractures contribute much less to the shale reservoir space than organic pores. The T₂ cutoff values range from 0.55 ms to 6.73 ms, and the surface relaxivities range from 0.0032 µm/ms to 0.0391 µm/ms. Their strong correlation with TOC suggests that organic matter is the main factor controlling the pore type and structure. In addition, the main difference between NMR porosity and He porosity is that gas logging porosity is used to detect connected pores, while NMR porosity also includes closed pores and microfractures. Combined with NMR and high-temperature pressure displacement experimental facilities, this will be a further step towards studying the pore structure of shale under simulated formation conditions. Full article

(This article belongs to the Special Issue Advances in Technology for Enhancing Oil and Gas Recovery in Shale Reservoirs)

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11 pages, 2172 KiB

Open AccessArticle

Temporary Plugging Agent Evaluation Technology and Its Applications in Shale Reservoirs in the Sichuan Basin

by Liang Wang, Jian Yang, Junliang Peng, Huifen Han, Yang Wang and Zefei Lv

Processes 2023, 11(9), 2799; https://doi.org/10.3390/pr11092799 - 20 Sep 2023

Cited by 1 | Viewed by 1045

Abstract

Shale oil reservoirs in the Daanzhai section of central Sichuan are mainly developed in the Daer subsection, with a rich resource base and great exploration and development potential. However, the shale oil reservoir is characterized by shale and limestone interactions, poor physical properties, [...] Read more.

Shale oil reservoirs in the Daanzhai section of central Sichuan are mainly developed in the Daer subsection, with a rich resource base and great exploration and development potential. However, the shale oil reservoir is characterized by shale and limestone interactions, poor physical properties, undeveloped fractures, and large differences in the fracture pressure of interactive reservoirs. Therefore, it is necessary to use temporary plugging and diverting fracturing technology to improve the complexity of fractures in reservoir reconstruction. To this end, an experimental device was innovatively established that takes into account the morphology of fractures and the permeability of reservoirs, and it can evaluate the temporary blocks and turns within third-level fractures in a reservoir. It can simulate third-level turning fractures under conditions involving 3–15 mm crack openings and different roughness values. Using this device and method, the combination and particle-size optimization experiments involving the temporary plugging agents used in the field were carried out, and the field tests were carried out in Well Long’an 1 and Well Ren’an 1 in the Sichuan Basin. The test results show that the pressure response after temporary plugging is obvious, which can significantly improve microseismic event points and increase the reservoir’s reconstruction volume. Compared with Well Nanchong 2H, the length in kilometers of the SRV after tackling key problems increases from 3918 × 10⁴ m³ to 4578 × 10⁴ m³, an increase of 17%. The average crack length increased from 265 m to 321 m, an increase of 21%, achieving a significant breakthrough in the “oil production gap”. Full article

(This article belongs to the Special Issue Advances in Technology for Enhancing Oil and Gas Recovery in Shale Reservoirs)

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17 pages, 1861 KiB

Open AccessArticle

Mechanism and Main Control Factors of CO₂ Huff and Puff to Enhance Oil Recovery in Chang 7 Shale Oil Reservoir of Ordos Basin

by Tong Wang, Bo Xu, Yatong Chen and Jian Wang

Processes 2023, 11(9), 2726; https://doi.org/10.3390/pr11092726 - 12 Sep 2023

Cited by 4 | Viewed by 1216

Abstract

The Chang 7 shale oil reservoir has low natural energy and is both tight and highly heterogeneous, resulting in significant remaining oil after depletion development. CO₂ huff and puff (huff-n-puff) is an effective way to take over from depletion development. Numerous scholars [...] Read more.

The Chang 7 shale oil reservoir has low natural energy and is both tight and highly heterogeneous, resulting in significant remaining oil after depletion development. CO₂ huff and puff (huff-n-puff) is an effective way to take over from depletion development. Numerous scholars have studied and analyzed the CO₂ huff-n-puff mechanism and parameters based on laboratory core sample huff-n-puff experiments. However, experimental procedures are not comprehensive, leading to more general studies of some mechanisms, and existing CO₂ huff-n-puff experiments struggle to reflect the effect of actual reservoir heterogeneity due to the limited length of the experimental core samples. In this paper, CO₂ huff-n-puff laboratory experiments were performed on short (about 5 cm) and long (about 100 cm) core samples from the Chang 7 shale oil reservoir, and the microscopic pore fluid utilization in the short samples was investigated using a nuclear magnetic resonance (NMR) technique. We then analyzed and discussed the seven controlling factors of CO₂ huff-n-puff and their recovery-enhancing mechanisms. The experimental results show that the cumulative recovery increased with the number of huff-n-puff cycles, but the degree of cycle recovery decreased due to the limitation of the differential pressure of the production. The significant increase in recovery after the CO₂ mixed-phase drive was achieved by increasing the minimum depletion pressure as well as the gas injection amount. The soaking time was adjusted appropriately to ensure that the injected energy was thoroughly utilized; too short or too long a soaking time was detrimental. The pressure depletion rate was the main factor in the CO₂ huff-n-puff effect in shale. If the pressure depletion rate was very high, the effective permeability loss was larger. In the CO₂ huff-n-puff process of the Chang 7 shale oil reservoir, the improvement in oil recovery was mainly contributed to by mesopores and small pores. The huff-n-puff experiments using long cores could better characterize the effect of heterogeneity on the huff-n-puff effect than short cores. Full article

(This article belongs to the Special Issue Advances in Technology for Enhancing Oil and Gas Recovery in Shale Reservoirs)

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Induced Casing Deformation in Hydraulically Fractured Shale Gas Wells: Risk Assessment, Early Warning, and Mitigation

by Xiaojin Zhou, Yonggang Duan, Yu Sang, Lang Zhou, Bo Zeng, Yi Song, Yan Dong and Junjie Hu

Processes 2024, 12(9), 2057; https://doi.org/10.3390/pr12092057 - 23 Sep 2024

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Abstract

In recent years, casing deformation has become a key factor affecting the scale and efficiency of shale gas development. Consequently, a fast and efficient integrated prevention, control, and treatment technology for casing deformation is of great significance in terms of both theory and [...] Read more.

In recent years, casing deformation has become a key factor affecting the scale and efficiency of shale gas development. Consequently, a fast and efficient integrated prevention, control, and treatment technology for casing deformation is of great significance in terms of both theory and application. This paper combines a geological mechanics analysis and multi-cluster fracture propagation to investigate the risk evaluation, early warning and identification, and warning and identification technology relating to casing deformation and its application. It proposes a method for the dynamic and static evaluation of casing deformation risk levels and types, and establishes an index system incorporating stress, fracture, time, and space factors. This four-factor evaluation method is in greater alignment with field conditions. It also proposes a method for the early warning and identification of casing deformation based on fracture monitoring and an operation curve, and clarifies the dominant engineering factors around casing deformation. According to the findings, the total fluid volume per stage has a greater impact on casing deformation than a high pump rate. The prevention and control of casing deformation should preferably be realized by optimizing the fracturing parameters. Moreover, the paper reviews existing technologies for treating casing deformation, several of which are defined as major technologies: small-diameter bridge plug staged fracturing and small-size gun perforation, and long-stage multi-cluster asynchronous fracture initiation and composite temporary plugging and diversion. The study results provide support for a significant reduction in the casing deformation rate during fracturing, improving the effective stimulation degree in the casing deformation section in shale gas wells in the southern Sichuan Basin. These results could serve as references for subsequent research. Full article

(This article belongs to the Special Issue Advances in Technology for Enhancing Oil and Gas Recovery in Shale Reservoirs)

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