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Special Issue "Advances in the Development of Unconventional Oil and Gas Resources"

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A special issue of Energies (ISSN 1996-1073). This special issue belongs to the section "H1: Petroleum Engineering".

Deadline for manuscript submissions: 5 April 2024 | Viewed by 5654

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Prof. Dr. Gang Lei

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Guest Editor

Faculty of Engineering, China University of Geosciences, Wuhan, China
Interests: unconventional oil and gas resources; single-phase/multi-phase fluid flow; mechanical properties of natural gas hydrate; Reservoirs

Dr. Weiwei Zhu

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Guest Editor

Department of Engineering Mechanics, Tsinghua University, Beijing 100084, China
Interests: discrete fracture networks; engineering geology; solid–fluid coupling
Special Issues, Collections and Topics in MDPI journals

Dr. Zhenhua Wei

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Guest Editor

Department of Ocean Science and Engineering, Southern University of Science and Technology, Shenzhen 518055, China
Interests: composite materials; polymer encapsulation; polymer-reinforced concrete; thermal regulation
Special Issues, Collections and Topics in MDPI journals

Dr. Liangliang Zhang
E-Mail Website
Guest Editor

College of Science, China Agricultural University, Beijing, China
Interests: multiphase multifield particle composites; solar energy

Special Issue Information

Dear Colleagues,

The use of unconventional oil and gas resources has increased in natural gas and oil production worldwide in recent decades. The science and technology involved in the development of unconventional oil and gas resources not only play indispensable roles in petroleum engineering but are also crucial for various areas such as geological carbon dioxide capture, utilization and storage (CCUS), hydrology, geothermal energy production, and so on.

Potential topics include, but are not limited to, the following:

New methods to test and characterize properties of unconventional oil and gas reservoirs;
Rock mechanics and hydraulic fracturing of unconventional oil and gas reservoirs;
Effective techniques to enhance recovery of unconventional oil and gas reservoirs;
Artificial intelligence in unconventional oil and gas development;
New science and technology involve in unconventional oil and gas development;
Developmental technologies for new energy resources (e.g., hydrogen energy and gas hydrate);
Carbon-reducing technologies (e.g., CCUS) in unconventional oil and gas development.

Prof. Dr. Gang Lei
Dr. Weiwei Zhu
Dr. Zhenhua Wei
Dr. Liangliang Zhang
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. Energies is an international peer-reviewed open access semimonthly 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 2600 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.

Published Papers (6 papers)

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Research

13 pages, 15033 KiB

Open AccessArticle

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

and

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

Viewed by 378

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 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

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

Cited by 1 | Viewed by 1022

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 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

Wenbo Gong

and

Jinhui Liu

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

Viewed by 993

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 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

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

Cited by 2 | Viewed by 828

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 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

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

Cited by 1 | Viewed by 763

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 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

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

Cited by 1 | Viewed by 726

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, 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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