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Advances in Technology for Enhancing Oil and Gas Recovery in Shale Reservoirs

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A special issue of Processes (ISSN 2227-9717). This special issue belongs to the section "Energy Systems".

Deadline for manuscript submissions: 4 July 2025 | Viewed by 7106

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Prof. Dr. Mingjun Chen

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Petroleum Engineering School, Southwest Petroleum University, Chengdu 610500, China
Interests: shale; unconventional reservoir petrophysics; unconventional oil and gas development; CCUS; HDR geothermal development

Prof. Dr. Keliu Wu

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Guest Editor

College of Petroleum Engineering, China University of Petroleum-Beljing, Beijing 102249, China
Interests: shale; nanopores; fluid transport; phase behavior; CCUS
Special Issues, Collections and Topics in MDPI journals

Dr. Jiajia Bai

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School of Petroleum and Natural Gas Engineering, Changzhou University, Changzhou 213164, China
Interests: shale gas/oil; EOR; water–rock interaction; multiscale transport of methane; CCUS

Special Issue Information

Dear Colleagues,

From a geological point of view, shale oil and gas reservoirs are different from conventional oil and gas reservoirs. The specific petrophysical and geochemical properties of a shale reservoir endow it with special fluid characteristics and stimulation technologies. Shale oil and gas are abundant, but the recovery rate is low. Therefore, with the growing demand for enhancing the performance of shale oil and gas development, the technology for enhancing oil and gas recovery in shale reservoirs is gaining great interest throughout the petroleum engineering community.

This Special Issue, entitled “Advances in Technology for Enhancing Oil and Gas Recovery in Shale Reservoirs,” aims to cover the latest advances in the technology and application of enhancing shale oil and gas production, as well as the latest research on the fluid in shale reservoirs. In this Special Issue, original research articles and reviews are welcome. Topics include, but are not limited to, mechanisms, methods, and/ or applications in the following areas:

Fluid properties and flow mechanisms in shale reservoirs;
Drilling, cementing, and perforating in shale reservoirs;
Hydraulic fracturing in shale reservoirs;
Formation damage control in shale oil and gas development;
Production strategy optimization of shale oil and gas wells;
Innovative methods for enhancing shale oil and gas recovery;
Carbon capture, storage, and utilization in shale reservoirs.

Thank you for your time, and we hope that you will consider contributing to this Special Issue.

Dr. Mingjun Chen
Prof. Dr. Keliu Wu
Dr. Jiajia Bai
Guest Editors

Manuscript Submission Information

Manuscripts should be submitted online at www.mdpi.com by registering and logging in to this website. Once you are registered, click here to go to the submission form. Manuscripts can be submitted until the deadline. All submissions that pass pre-check are peer-reviewed. Accepted papers will be published continuously in the journal (as soon as accepted) and will be listed together on the special issue website. Research articles, review articles as well as short communications are invited. For planned papers, a title and short abstract (about 100 words) can be sent to the Editorial Office for announcement on this website.

Submitted manuscripts should not have been published previously, nor be under consideration for publication elsewhere (except conference proceedings papers). All manuscripts are thoroughly refereed through a single-blind peer-review process. A guide for authors and other relevant information for submission of manuscripts is available on the Instructions for Authors page. Processes is an international peer-reviewed open access monthly journal published by MDPI.

Please visit the Instructions for Authors page before submitting a manuscript. The Article Processing Charge (APC) for publication in this open access journal is 2400 CHF (Swiss Francs). Submitted papers should be well formatted and use good English. Authors may use MDPI's English editing service prior to publication or during author revisions.

Keywords

shale gas
shale oil
enhanced recovery
drilling
reservoir stimulation
fracturing fluid
multiscale heat and mass transport
pore structure
fracture network
CCUS

Published Papers (10 papers)

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Research

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

Viewed by 334

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. 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 433

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 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

Viewed by 539

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 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 - 08 Nov 2023

Viewed by 726

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 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 - 08 Nov 2023

Viewed by 619

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 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

Viewed by 731

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 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 627

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 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

Viewed by 713

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 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

Viewed by 631

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, 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 2 | Viewed by 785

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 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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