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New Advances in Oil, Gas and Geothermal Reservoirs—3rd Edition
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New Advances in Oil, Gas and Geothermal Reservoirs—3rd Edition

A special issue of Energies (ISSN 1996-1073). This special issue belongs to the section "H: Geo-Energy".

Deadline for manuscript submissions: 10 March 2026 | Viewed by 1667

Special Issue Editor

Dr. Daoyi Zhu

E-Mail Website
Guest Editor
Faculty of Petroleum, China University of Petroleum-Beijing at Karamay, Karamay 834000, China
Interests: oilfield chemistry; plugging theory and technology; low-energy processes for oil and gas recovery
Special Issues, Collections and Topics in MDPI journals

Special Issue Information

Dear Colleagues,

In recent years, oil, gas and geothermal reservoirs have become the most important geological energy sources in the world. In order to expand oil and gas reserves, experts in this field have adopted cutting-edge approaches, such as a new methods for evaluating the key parameters of continental shale oil reservoirs, and the theory of large-scale oil and gas accumulation in deep glutenite. In order to further expand the sweep coefficient of reservoir displacement agents, researchers have developed a multiscale, environmentally friendly profile control agent. Researchers have also used various methods, including nanomaterials and greenhouse gases such as CO2, to further exploit the remaining oil in formations. Geothermal energy is an environmentally friendly energy source, and improving its utilization rate has been a popular topic in recent years.

This Special Issue aims to disseminate the most recent advances in research on oil, gas and geothermal reservoirs.

Topics of interest include, but are not limited to, the following:

  • New technologies for drilling and production in tight oil and gas reservoirs;
  • New technologies for drilling and production in shale oil and gas reservoirs;
  • New technologies for drilling and production in carbonate reservoirs;
  • New technologies for drilling and production in fractured-cavity oil and gas reservoirs;
  • New technologies for natural gas hydrate drilling and production;
  • New technologies for drilling and production of geothermal resources;
  • New low-energy mining technology.

Dr. Daoyi Zhu
Guest Editor

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 250 words) can be sent to the Editorial Office for assessment.

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.

Keywords

  • tight oil and gas
  • shale oil and gas
  • carbonate reservoir
  • fractured-cavity oil and gas reservoir
  • gas hydrate
  • geothermal resources

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Related Special Issues

Published Papers (4 papers)

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Research

16 pages, 6944 KB  
Article
Water Shutoff with Polymer Gels in a High-Temperature Gas Reservoir in China: A Success Story
by Tao Song, Hongjun Wu, Pingde Liu, Junyi Wu, Chunlei Wang, Hualing Zhang, Song Zhang, Mantian Li, Junlei Wang, Bin Ding, Weidong Liu, Jianyun Peng, Yingting Zhu and Falin Wei
Energies 2025, 18(24), 6554; https://doi.org/10.3390/en18246554 - 15 Dec 2025
Viewed by 193
Abstract
Gel treatments have been widely applied to control water production in oil and gas reservoirs. However, for water shutoff in dense gas reservoirs, most gel-based treatments focus on individual wells rather than the entire reservoir, exhibiting limited treatment depth, poor durability, and inadequate [...] Read more.
Gel treatments have been widely applied to control water production in oil and gas reservoirs. However, for water shutoff in dense gas reservoirs, most gel-based treatments focus on individual wells rather than the entire reservoir, exhibiting limited treatment depth, poor durability, and inadequate repeatability Notably, formation damage is a primary consideration in treatment design—most dense gas reservoirs have a permeability of less than 1 mD, making them highly susceptible to damage by formation water, let alone viscous polymer gels. Constrained by well completion methods, gelant can only be bullheaded into deep gas wells in most scenarios. Due to the poor gas/water selective plugging capability of conventional gels, the injected gelant tends to enter both gas and water zones, simultaneously plugging fluid flow in both. Although several techniques have been developed to re-establish gas flow paths post-treatment, treating gas-producing zones remains risky when no effective barrier exists between water and gas strata. Additionally, most water/gas selective plugging materials lack sufficient thermal stability under high-temperature and high-salinity (HTHS) gas reservoir conditions, and their injectivity and field feasibility still require further optimization. To address these challenges, treatment design should be optimized using non-selective gel materials, shifting the focus from directly preventing formation water invasion into individual wells to mitigating or slowing water invasion across the entire gas reservoir. This approach can be achieved by placing large-volume gels along major water flow paths via fully watered-out wells located at structurally lower positions. Furthermore, the drainage capacity of these wells can be preserved by displacing the gel slug to the far-wellbore region, thereby dissipating water-driven energy. This study evaluates the viability of placing gels in fully watered-out wells at structurally lower positions in an edge-water drive gas reservoir to slow water invasion into structurally higher production wells interconnected via numerous microfractures and high-permeability streaks. The gel system primarily comprises polyethyleneimine (PEI), a terpolymer, and nanofibers. Key properties of the gel system are as follows: Static gelation time: 6 h; Elastic modulus of fully crosslinked gel: 8.6 Pa; Thermal stability: Stable in formation water at 130 °C for over 3 months; Injectivity: Easily placed in a 219 mD rock matrix with an injection pressure gradient of 0.8 MPa/m at an injection rate of 1 mL/min; and Plugging performance: Excellent sealing effect on microfractures, with a water breakthrough pressure gradient of 2.25 MPa/m in 0.1 mm fractures. During field implementation, cyclic gelant injections combined with over-displacement techniques were employed to push the gel slug deep into the reservoir while maintaining well drainage capacity. The total volumes of injected fluid and gelant were 2865 m3 and 1400 m3, respectively. Production data and tracer test results from adjacent wells confirmed that the water invasion rate was successfully reduced from 59 m/d to 35 m/d. The pilot test results validate that placing gels in fully watered-out wells at structurally lower positions is a viable strategy to protect the production of gas wells at structurally higher positions. Full article
(This article belongs to the Special Issue New Advances in Oil, Gas and Geothermal Reservoirs—3rd Edition)
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14 pages, 5394 KB  
Article
Study on Time-Varying Mechanism of Reservoir Properties During Long-Term Water Flooding
by Xiaoping An, Yufen Zhu, Xiqun Tan, Jingyi Bi and Chengqian Tan
Energies 2025, 18(24), 6488; https://doi.org/10.3390/en18246488 - 11 Dec 2025
Viewed by 187
Abstract
Long-term water flooding is a primary development method for oilfields, yet the heterogeneous evolution mechanism of reservoir properties during prolonged water injection remains poorly understood—particularly in the medium-high water cut stage, where the impact of pore-throat network changes on seepage capacity remains controversial. [...] Read more.
Long-term water flooding is a primary development method for oilfields, yet the heterogeneous evolution mechanism of reservoir properties during prolonged water injection remains poorly understood—particularly in the medium-high water cut stage, where the impact of pore-throat network changes on seepage capacity remains controversial. Its reservoir property evolution is highly representative of and provides a valuable reference for similar oilfields. Focusing on the 16-year developed WU Oilfield (long-term water flooding, middle-high water cut stage), its reservoir property evolution exhibits typical reference value for similar oilfields. To reveal the time-varying laws and microscopic mechanism of reservoir properties during long-term water flooding, this study systematically investigated the changes in porosity, permeability, pore throat characteristics, clay content, and oil recovery of high-permeability and low-permeability cores under different injected water volumes (up to 500 pore volumes) through laboratory core displacement experiments. The experimental results showed that with increasing injected water volume, the permeability of high-permeability cores increased by 27.3%, with an overall 21.6% porosity increase in both high and low-permeability cores, and the oil recovery rate of high-permeability cores increased to 15%. In contrast, the permeability of low-permeability cores decreased by 22.2%, with porosity showing a synchronous overall increasing trend, and the oil recovery rate decreased by 10%. Microscopic analysis revealed an overall 7.34% decrease in clay content, and this property difference mainly resulted from the polarization of pore throat network connectivity: large pores in high-permeability cores further expanded due to clay migration and particle transport, while small pores in low-permeability cores gradually became occluded due to clay plugging and authigenic mineral precipitation. This study clarifies the evolution mechanism of reservoir heterogeneity during long-term water flooding and provides a theoretical basis for optimizing water flooding development plans and improving oil and gas recovery. Full article
(This article belongs to the Special Issue New Advances in Oil, Gas and Geothermal Reservoirs—3rd Edition)
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32 pages, 18674 KB  
Article
An Experimental Study on Oil–Water Emulsification Mechanism During Steam Injection Process in Heavy Oil Thermal Recovery
by Hui Cai, Zhilin Qi, Yingxian Liu, Dong Liu, Chunxiao Du, Jie Tian, Wende Yan and Taotao Luo
Energies 2025, 18(23), 6250; https://doi.org/10.3390/en18236250 - 28 Nov 2025
Viewed by 242
Abstract
This article focuses on the oil–water emulsification problem during steam injection in heavy oil thermal recovery. Emulsions were prepared through one-dimensional flow experiments, and key parameters including the inversion point water cut and micro-morphological characteristics (particle size and distribution range) of the emulsions [...] Read more.
This article focuses on the oil–water emulsification problem during steam injection in heavy oil thermal recovery. Emulsions were prepared through one-dimensional flow experiments, and key parameters including the inversion point water cut and micro-morphological characteristics (particle size and distribution range) of the emulsions were systematically measured under varied conditions (temperature: 150–360 °C; salinity: 0–7500 mg/L; water cut: 10.07–72.22%). By analyzing the experimental data, the emulsification mechanism and influencing rules were revealed: under the combined conditions of high temperature (150–360 °C), high salinity (up to 7500 mg/L), and low water cut (10.07–19.35%), crude oil and formation water form oil-in-water emulsions under the shear action of porous media. During this process, active substances in crude oil react with inorganic salts in formation water to generate natural surfactants, which reduce the oil–water interfacial tension and enhance emulsion stability, enabling the emulsion to maintain stability even at a high water cut of up to 72.22%, with particle sizes ranging from 1 μm to 350 μm and distribution spans varying from 4 μm to 50 μm. The formation of such emulsions leads to a significant increase in viscosity, adversely affecting oil recovery. In production practice, it is recommended to add chemical agents during the early stage of steam huff and puff development (water cut: 10.07–37.50%). This measure aims to destroy the oil–water liquid film, promote water droplet coalescence (narrowing the particle size distribution span), and facilitate emulsion breaking and phase inversion, thereby effectively mitigating the adverse impacts of oil–water emulsions and improving heavy oil recovery efficiency. Full article
(This article belongs to the Special Issue New Advances in Oil, Gas and Geothermal Reservoirs—3rd Edition)
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19 pages, 1977 KB  
Article
Research on the Evaluation Model for Natural Gas Pipeline Capacity Allocation Under Fair and Open Access Mode
by Xinze Li, Dezhong Wang, Yixun Shi, Jiaojiao Jia and Zixu Wang
Energies 2025, 18(20), 5544; https://doi.org/10.3390/en18205544 - 21 Oct 2025
Viewed by 690
Abstract
Compared with other fossil energy sources, natural gas is characterized by compressibility, low energy density, high storage costs, and imbalanced usage. Natural gas pipeline supply systems possess unique attributes such as closed transportation and a highly integrated upstream, midstream, and downstream structure. Moreover, [...] Read more.
Compared with other fossil energy sources, natural gas is characterized by compressibility, low energy density, high storage costs, and imbalanced usage. Natural gas pipeline supply systems possess unique attributes such as closed transportation and a highly integrated upstream, midstream, and downstream structure. Moreover, pipelines are almost the only economical means of onshore natural gas transportation. Given that the upstream of the pipeline features multi-entity and multi-channel supply including natural gas, coal-to-gas, and LNG vaporized gas, while the downstream presents a competitive landscape with multi-market and multi-user segments (e.g., urban residents, factories, power plants, and vehicles), there is an urgent social demand for non-discriminatory and fair opening of natural gas pipeline network infrastructure to third-party entities. However, after the fair opening of natural gas pipeline networks, the original “point-to-point” transaction model will be replaced by market-driven behaviors, making the verification and allocation of gas transmission capacity a key operational issue. Currently, neither pipeline operators nor government regulatory authorities have issued corresponding rules, regulations, or evaluation plans. To address this, this paper proposes a multi-dimensional quantitative evaluation model based on the Analytic Hierarchy Process (AHP), integrating both commercial and technical indicators. The model comprehensively considers six indicators: pipeline transportation fees, pipeline gas line pack, maximum gas storage capacity, pipeline pressure drop, energy consumption, and user satisfaction and constructs a quantitative evaluation system. Through the consistency check of the judgment matrix (CR = 0.06213 < 0.1), the weights of the respective indicators are determined as follows: 0.2584, 0.2054, 0.1419, 0.1166, 0.1419, and 0.1357. The specific score of each indicator is determined based on the deviation between each evaluation indicator and the theoretical optimal value under different gas volume allocation schemes. Combined with the weight proportion, the total score of each gas volume allocation scheme is finally calculated, thereby obtaining the recommended gas volume allocation scheme. The evaluation model was applied to a practical pipeline project. The evaluation results show that the AHP-based evaluation model can effectively quantify the advantages and disadvantages of different gas volume allocation schemes. Notably, the gas volume allocation scheme under normal operating conditions is not the optimal one; instead, it ranks last according to the scores, with a score 0.7 points lower than that of the optimal scheme. In addition, to facilitate rapid decision-making for gas volume allocation schemes, this paper designs a program using HTML and develops a gas volume allocation evaluation program with JavaScript based on the established model. This self-developed program has the function of automatically generating scheme scores once the proposed gas volume allocation for each station is input, providing a decision support tool for pipeline operators, shippers, and regulatory authorities. The evaluation model provides a theoretical and methodological basis for the dynamic optimization of natural gas pipeline gas volume allocation schemes under the fair opening model. It is expected to, on the one hand, provide a reference for transactions between pipeline network companies and shippers, and on the other hand, offer insights for regulatory authorities to further formulate detailed and fair gas transmission capacity transaction methods. Full article
(This article belongs to the Special Issue New Advances in Oil, Gas and Geothermal Reservoirs—3rd Edition)
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