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

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

Deadline for manuscript submissions: closed (10 March 2026) | Viewed by 6006

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Dr. Daoyi Zhu

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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

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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

New Advances in Oil, Gas and Geothermal Reservoirs in Energies (12 articles)
New Advances in Oil, Gas and Geothermal Reservoirs: 2nd Edition in Energies (9 articles)
New Advances in Oil, Gas and Geothermal Reservoirs—4th Edition in Energies

Published Papers (8 papers)

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Research

26 pages, 2709 KB

Open AccessArticle

Buckley–Leverett Solution for Two-Phase Displacement in a Composite Porous–Cavernous–Porous System

by Fang-Fang Chen, Xu-Jian Jiang, Ting Yan, Xiao-Ping Ma, Zhen-Yu Zhang, Ming-Jie Li and Zhao-Qin Huang

Energies 2026, 19(10), 2463; https://doi.org/10.3390/en19102463 - 20 May 2026

Viewed by 141

Abstract

Fluid flow in fractured-vuggy carbonate reservoirs is characterized by extreme multiscale heterogeneity, where the coexistence of tight matrix rock and macroscopic cave challenges traditional Darcy-based continuum models. This paper presents a semi-analytical solution for two-phase immiscible displacement in a one-dimensional composite porous–cavernous–porous (PCP) system. The main feature of the model is that the cave region is treated separately from the porous domains: classical Darcy flow is used in the surrounding matrix, whereas an idealized free-flow representation is introduced for open caves based on a simplified one-dimensional treatment of the cave momentum balance. To elucidate the impact of distinct flow regimes on displacement dynamics, three physical models are compared for the cave region: (1) an open-cave model represented by a simplified free-flow formulation; (2) a filled-cave non-Darcy model governed by the Forchheimer equation using the Ergun correlation; and (3) a creeping-flow model governed by Darcy’s law. A piecewise semi-analytical solution procedure is established to enforce flux continuity, characterize interfacial state remapping, and determine the downstream front under global water-balance closure. The results show that both cave geometry and internal cave-flow mechanism critically control water-front advancement. While the open-cave model exhibits piston-like displacement behavior with high local displacement efficiency but stronger preferential flow, the Forchheimer model shows that inertial resistance can modify the saturation profile and delay breakthrough relative to the Darcy prediction. The proposed framework provides an idealized theoretical reference for benchmarking numerical simulators and for interpreting waterflooding behavior in complex vuggy reservoirs under one-dimensional, incompressible, gravity-free, and capillarity-free conditions. Full article

(This article belongs to the Special Issue New Advances in Oil, Gas and Geothermal Reservoirs—3rd Edition)

13 pages, 1556 KB

Open AccessArticle

Water Coning Calculation and Application Analysis for Fault-Controlled Fractured–Vuggy Reservoirs Based on a Multi-Modal Flow Model

by Xujian Jiang, Xingdong Zhao, Zhaoqin Huang, Ting Yan, Chunyan Xiao, Guanglu Wei and Yufan He

Energies 2026, 19(7), 1780; https://doi.org/10.3390/en19071780 - 5 Apr 2026

Viewed by 582

Abstract

Fault-controlled reservoirs are characterized by strong heterogeneity and diverse flow types. Existing water-coning calculation methods cannot accurately describe the complex oil–water distribution within reservoirs exhibiting a distinct “core–damage zone” architecture. To address this limitation, the main goal of this study is to develop a zonal water-coning calculation framework tailored to these highly heterogeneous structures. Methodologically, the Forchheimer equation is utilized to describe the entire reservoir system, with region-specific simplifications applied based on dominant flow mechanisms: in the high-velocity core zone, the viscous term is ignored; in the low-velocity damage zone, the inertial term is neglected; and the transition zone employs the complete Forchheimer formulation. The results indicate that the water-coning curves in the core and transition zones are significantly steeper as the radial distance decreases compared to the damage zone. Specifically, in a field application at the Fuman Oilfield, the calculated theoretical critical production rate of the core zone (5.39 × 10⁻² m³/s) is three orders of magnitude higher than that of the damage zone (1.45 × 10⁻⁵ m³/s). In conclusion, this massive zonal disparity demonstrates the severe bottleneck effect of the high-permeability core under a unified wellbore pressure drawdown, theoretically validating the necessity of deploying segmented completions and targeted water-control strategies to prevent premature water breakthrough. Full article

(This article belongs to the Special Issue New Advances in Oil, Gas and Geothermal Reservoirs—3rd Edition)

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23 pages, 10340 KB

Open AccessArticle

A Method for Predicting the Waterflood Sweep Efficiency in Deepwater Turbidite Channel Oil Reservoirs

by Zhiwang Yuan, Li Yang, Xiaoqi Liu and Yibo Li

Energies 2026, 19(7), 1605; https://doi.org/10.3390/en19071605 - 25 Mar 2026

Viewed by 427

Abstract

The complex architecture and stacking patterns of deepwater turbidite channel sandbodies introduce significant uncertainty in injector–producer connectivity. This uncertainty affects both the mechanisms and the quantitative evaluation of the waterflood sweep. In this study, a representative reservoir in the Niger Delta Basin is selected as a case study. Injector–producer well groups are first classified into three connectivity patterns—coeval, cross-stage, and hybrid based on geological and seismic constraints. Time-lapse seismic data are then interpreted to delineate sweep morphology and to infer the controlling mechanisms associated with each pattern. Coeval connectivity exhibits a relatively uniform and continuous front advance with minimal barriers. Cross-stage connectivity shows fragmented swept regions with pronounced bypassing, and localized preferential breakthrough caused by discontinuous sandbodies and pervasive barriers. Hybrid connectivity is characterized by intermediate behavior, combining features of both patterns. To translate these mechanistic differences into quantitative metrics for development evaluation, an oil–water relative permeability ratio correlation for low viscosity oil is established that remains valid across the full water cut range, thereby overcoming the limitations of conventional semi-log linear correlations at both low and ultra-high water cut stages. Based on this framework, a production data-driven predictive model for waterflood sweep efficiency is derived using production data and steady state flow theory. The model is validated across well groups representing different connectivity patterns. Field application yields a consistent ranking of sweep efficiency: coeval > hybrid > cross-stage, with group average values of 0.86, 0.80, and 0.70, respectively. These results agree with the mechanistic interpretation derived from time-lapse seismic analysis. The proposed methodology provides a practical quantitative framework for evaluating injector–producer connectivity and comparing development strategies in deepwater turbidite channel reservoirs. Full article

(This article belongs to the Special Issue New Advances in Oil, Gas and Geothermal Reservoirs—3rd Edition)

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13 pages, 2269 KB

Open AccessArticle

Low-Temperature Oxidation Behavior and Non-Isothermal Heat Release of Heavy Oil During Oxygen-Reduced Air Injection

by Wuchao Wang, Defei Chen, Zhaocai Pan, Jianfeng He, Jianxin Shen, Min Liu, Yanzhao Li, Meili Lan and Shuai Zhao

Energies 2026, 19(1), 225; https://doi.org/10.3390/en19010225 - 31 Dec 2025

Cited by 1 | Viewed by 526

Abstract

Oxygen-reduced air injection technology has demonstrated considerable potential for developing heavy oil reservoirs. However, the low-temperature oxidation (LTO) behavior and non-isothermal heat release of heavy oil under oxygen-reduced conditions remain poorly understood. Accordingly, this study systematically investigated the oxygen consumption characteristics of heavy crude oil under two oxygen concentrations (8% and 10%) through isothermal static oxidation experiments. Additionally, scanning electron microscopy (SEM) and differential scanning calorimetry (DSC) were employed to analyze the microstructural evolution of rock cuttings and the exothermic characteristics of heavy oil before and after oxidation. The results indicated that as the oxygen concentration increased from 8% to 10%, the pressure drop during the LTO process rose from 1.73 to 2.04 MPa, and the oxygen consumption rate increased from 1.47 × 10⁻⁵ to 2.06 × 10⁻⁵ mol/(h·mL). This demonstrated that higher oxygen partial pressure promoted LTO reactions, thereby generating more abundant coke precursors for the subsequent high-temperature oxidation (HTO) stage. SEM analysis revealed that the microstructure of the rock cuttings after oxidation transitioned from an originally smooth, “acicular” morphology to a “flaky” structure characterized by extensive crack development, which significantly improved the connectivity of the pore-fracture system. DSC analysis further demonstrated that the mineral components in the rock cuttings played a dual role during the oxidation process: at the LTO stage, their heat capacity effect suppressed the exothermic behavior during oxidation; whereas at the HTO stage, their larger specific surface area and the catalytic effect of clay minerals enhanced the heat release from coke combustion. This study thus provided a theoretical foundation for developing heavy oil reservoirs through oxygen-reduced air injection. Full article

(This article belongs to the Special Issue New Advances in Oil, Gas and Geothermal Reservoirs—3rd Edition)

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16 pages, 6944 KB

Open AccessArticle

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

Cited by 1 | Viewed by 897

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 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

Open AccessArticle

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

Cited by 1 | Viewed by 516

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. 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

Open AccessArticle

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 746

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 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

Open AccessArticle

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

Cited by 1 | Viewed by 1434

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, 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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