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Processes
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Advances in Heavy Oil Reservoir Development
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Advances in Heavy Oil Reservoir Development

A Special Issue of Processes (ISSN 2227-9717) belonging to the section "Petroleum and Low-Carbon Energy Process Engineering".

Deadline for manuscript submissions: 31 October 2026 | Viewed by 1885

Editors

Dr. Xiang Zhou

E-Mail Website
Guest Editor
School of Petroleum and Natural Gas Engineering, Southwest Petroleum University, Chengdu 610500, China
Interests: theory and technology of improving recovery rate of unconventional oil and gas reservoirs; theory and technology of CO2 utilization and storage; theory and technology of in-situ modification of heavy
Dr. Shanshan Yao

E-Mail Website
Guest Editor
Department of Civil and Environmental Engineering, School of Mining and Petroleum Engineering, Faculty of Engineering, University of Alberta, Edmonton, AB T6G 1H9, Canada
Interests: unconventional resources; hydraulic fracturing; reservoir characterization; reservoir engineering; pore-scale processes in porous media; pneumatic percussion drilling; pumped storage hydropower system
Dr. Binfei Li

E-Mail Website
Guest Editor
School of Petroleum Engineering, China University of Petroleum (East China), Qingdao, China
Interests: gas injection for EOR; heavy oil recovery; foam fluid
Special Issues, Collections and Topics in MDPI journals

Special Issue Information

Dear Colleagues,

Heavy oil resources, which are abundant worldwide, play a critical role in the global energy supply. Historically, heavy oil development has relied mainly on two approaches: thermal recovery, represented by steam-based methods, and cold production, such as expansion drive–dominated recovery. Thermal recovery faces challenges associated with high energy consumption, high cost and significant carbon emissions, while cold production is often constrained by low production rates and low ultimate recovery factors. The global energy transition toward green and sustainable development is driving heavy oil recovery technologies toward low-carbon, high-efficiency and digitalized solutions. To promote scientific innovation and technical exchange, this Special Issue invites original research and review papers from petroleum engineering, energy technology, environmental science and related disciplines. Topics of interest include, but are not limited to, the following areas:

  1. Low-Carbon Thermal Recovery Technologies
  • Theories and technologies for improving thermal recovery efficiency
  • Chemical-assisted thermal recovery and in situ upgrading of heavy oil
  • Electrical heating, electromagnetic heating, solar energy and other green-energy-assisted thermal recovery methods
  • Heavy oil recovery assisted by supercritical CO₂, nitrogen, flue gas and other green injectants
  • Utilization and coupling of geothermal energy in heavy oil development
  1. Chemical- and Bio-Assisted Cold Production
  • Chemicals-assisted cold production technologies and field applications
  • Microbial enhanced oil recovery and biosurfactant technologies
  • Advanced materials for viscosity reduction in heavy oil
  1. Intelligent and Digitalized Development of Heavy Oil Reservoirs
  • Artificial-intelligence-based optimization and management of production parameters
  • Applications of artificial intelligence in modeling heavy oil recovery processes
  • Digital twin technologies for energy efficiency optimization in heavy oil fields
  • Intelligent monitoring, forecasting and predictive analytics
  1. Clean Alternative Energy and Multi-Energy Integration
  • Applications of photovoltaic and wind energy in heavy oil recovery operations
  • Waste heat recovery and cascade utilization in thermal recovery systems
  • Source–grid–load–storage integrated systems and applications
  1. Low-Carbon Development Policies and Management
  • Carbon footprint accounting and life-cycle carbon-emission assessment
  • Carbon trading mechanisms and economic evaluation for heavy oil development
  • Low-carbon management strategies across the full development lifecycle of heavy oil reservoirs
  1. Novel Technologies for the Development of Medium- and Deep-Heavy Oil Reservoirs
  • Injectant-assisted energy pre-storage and development technologies
  • Solvent-assisted thermal and cold production
  • In situ solvent generation and dissolution-assisted SAGD
  • SAGD for medium- and deep-heavy oil reservoirs
  1. Advanced Technologies for Utilization of Heavy Oil Tailings and Residual Resources

Dr. Xiang Zhou
Dr. Shanshan Yao
Dr. Binfei Li
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 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-anonymized 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 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 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

  • oil recovery factor
  • machine learning
  • thermal recovery
  • unconventional resources
  • low-carbon technologies

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Published Papers (4 papers)

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Research

14 pages, 992 KB  
Article
Mechanistic Analysis of Stage-Dependent In Situ Hydrogen Production from Heavy Oil Under Nitrogen Atmosphere
by Junshi Tang, Ye Deng, Bolin Lv, Chunsheng Yu, Wenlong Guan and Youwei Jiang
Processes 2026, 14(18), 2962; https://doi.org/10.3390/pr14182962 - 17 Sep 2026
Abstract
In situ gasification-assisted hydrogen production from heavy oil has the potential to simultaneously achieve in-reservoir upgrading and hydrogen generation, offering a promising pathway for the clean and efficient development of heavy oil resources. To investigate stage-dependent hydrogen-formation pathways and the thermal conversion behavior [...] Read more.
In situ gasification-assisted hydrogen production from heavy oil has the potential to simultaneously achieve in-reservoir upgrading and hydrogen generation, offering a promising pathway for the clean and efficient development of heavy oil resources. To investigate stage-dependent hydrogen-formation pathways and the thermal conversion behavior of the heavy oil-water system, batch reactor experiments were conducted to simulate heavy oil gasification under reservoir-like conditions. Experiments were carried out under a nitrogen atmosphere at different temperatures and reaction times. Combined with gas chromatography and elemental analysis, the product distribution and reaction characteristics were investigated. The results show that, under an inert N2 atmosphere with an oil-to-water mass ratio of 1:1, in situ hydrogen production from heavy oil can be qualitatively divided into three approximate stages: a deoxygenation activation stage (300–400 °C), a water–gas shift hydrogen-production stage (400–500 °C), and a coke conversion hydrogen-production stage (500–550 °C). Temperature was identified as the key factor governing the reaction pathway, and the highest H2 mole fraction of 10.84% was obtained at 450 °C for 6 h. Reaction time mainly affected thermal conversion and gas distribution, while excessively long residence time at high temperatures promoted hydrogen-consuming reactions. Elemental analysis of the high-temperature residues further revealed enhanced dehydrogenation, aromatization, and coking, indicating that coke served as an important intermediate for sustained hydrogen generation. A stage-dependent mechanism of in situ hydrogen production from heavy oil at 300–550 °C was proposed, and the dominant reactions controlling H2 generation in different temperature intervals were clarified. These findings provide a basis for process optimization and numerical simulation of in situ hydrogen production from heavy oil. Full article
(This article belongs to the Special Issue Advances in Heavy Oil Reservoir Development)
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17 pages, 14472 KB  
Article
Study on the Viscosity Reduction Effects of Heat, Gas, and Viscosity Reducers in Multicomponent Thermal Fluids on Heavy Oil: Experiments and Molecular Dynamics Simulation
by Tao Lin, Rui Han, Qilin Gu, Na Fang, Xinru Zhao, Shanshan Lin, Binfei Li and Qian Cheng
Processes 2026, 14(17), 2705; https://doi.org/10.3390/pr14172705 - 24 Aug 2026
Viewed by 412
Abstract
The efficient development of heavy oil reservoirs is challenged by the high viscosity and poor mobility of heavy oil. Although multicomponent thermal fluid technologies involving heat, gas, and chemical agents have demonstrated potential advantages over conventional steam-based recovery methods, the microscopic synergistic mechanisms [...] Read more.
The efficient development of heavy oil reservoirs is challenged by the high viscosity and poor mobility of heavy oil. Although multicomponent thermal fluid technologies involving heat, gas, and chemical agents have demonstrated potential advantages over conventional steam-based recovery methods, the microscopic synergistic mechanisms responsible for viscosity reduction remain insufficiently understood. Therefore, this study investigates the synergistic mechanisms by which heat, an alkane solvent (C11H24), and CO2 reduce heavy-oil viscosity. Heavy oil from the Shengli Oilfield was selected as the research object, and rheological experiments were combined with molecular dynamics simulations to systematically analyze viscosity variations and their underlying microscopic mechanisms under different conditions. The experimental results demonstrate that increasing temperature significantly reduces heavy oil viscosity, and a characteristic transition in viscosity reduction behavior occurs at approximately 100 °C. At 90 °C, the addition 5 wt% oil-soluble viscosity reducer C11H24 decreases the heavy oil viscosity to 442.2 mPa·s, corresponding to a reduction rate of 83%. The solubility of CO2 increases markedly with pressure, and at 30 MPa, the viscosity reduction exceeds 99%. The combined effects of these three factors exhibit superior viscosity-reduction performance. Molecular dynamics simulation results indicate that CO2 and the viscosity reducer synergistically weaken the π-π stacking interactions of asphaltenes and resins in heavy oil, transforming heavy components from locally aggregated states into more uniformly dispersed configurations. Meanwhile, the intermolecular interaction energy and cohesive energy density decrease, indicating weakened molecular interactions and enhanced diffusion behavior. These results demonstrate that the synergistic viscosity-reduction mechanism of heat–gas–agent systems is mainly associated with structural disaggregation, interaction weakening, and diffusion enhancement. This study provides molecular-level insights into multicomponent thermal fluid-assisted heavy oil recovery and offers theoretical support for improving heavy oil development efficiency. Full article
(This article belongs to the Special Issue Advances in Heavy Oil Reservoir Development)
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31 pages, 39361 KB  
Article
Application of Microbial Cold Recovery Technology in Shallow Low-Temperature High-Viscosity In Situ Oil Sands: A Case Study of the Upper Cretaceous Oil Sands in the Central–Southern Part of the Western Slope of the Songliao Basin
by Lihua Tong, Yaohua Li, Jie Li, Yantong Liu, Lei Shi, Caiqin Bi, Wenjie Xia, Yinbo Xu, Yuan Yuan and Yue Tang
Processes 2026, 14(15), 2517; https://doi.org/10.3390/pr14152517 - 5 Aug 2026
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Abstract
The Cretaceous shallow oil sands in the Dagang area, located on the western slope of the Songliao Basin, are characterized by a burial depth of ≤182 m, an average reservoir temperature of 11.8 °C, an extremely high crude oil viscosity of 1,750,000 mPa·s [...] Read more.
The Cretaceous shallow oil sands in the Dagang area, located on the western slope of the Songliao Basin, are characterized by a burial depth of ≤182 m, an average reservoir temperature of 11.8 °C, an extremely high crude oil viscosity of 1,750,000 mPa·s at 15 °C, and water-bearing layers in both the roof and floor. Conventional thermal recovery methods such as SAGD and CSS are geologically unsuitable for this deposit and suffer from high energy consumption and carbon emissions. As microbial oil recovery is a technically advanced enhanced oil recovery technology that leverages microbial growth, reproduction and metabolism in the reservoir to alter the properties of oil, rock, gas and water through interaction with these components, and petroleum biotechnology research confirms that microorganisms can degrade high-molecular-weight petroleum hydrocarbons to reduce crude oil viscosity and improve its fluidity, this study explores the technical feasibility of microbial cold recovery for in situ extraction of such low-temperature, high-viscosity oil sands. The study adopts a five-well pilot pattern (one injector and four producers) with an integrated approach combining reservoir unblocking, microbial viscosity reduction, and vibration-assisted production. Systematic screening identified Pseudomonas, Chryseobacterium, and Citrobacter as the most efficient indigenous microbial strains. Pseudomonas exhibited a crude oil degradation rate of 32.17%, reducing asphaltene content from 7.47% to 3.56%, and achieved large-scale proliferation (2.5 × 108 cfu/mL) at 15 °C. It also achieved a 40.8% reduction in crude oil viscosity and a desulfurization rate, alongside 56.6% denitrification. With the optimal activator No. 3, the viscosity reduction rate reached 45.18%, and the viable cell count exceeded 9.45 × 108 cfu/mL. The synergistic action of Pseudomonas and an A-type nano-microemulsion surfactant reduced the oil–water interfacial tension from 49.56 to 1.25 mN/m (a 97.48% reduction) and lowered the crude oil viscosity at 25 °C from 302,000 to 11,023 mPa·s (a 96.35% reduction). Core flooding tests demonstrated an incremental oil recovery of 7.38% compared with the water-flooded control, with interfacial tension dropping from 48.21 to 1.18 mN/m. In the field trial, composite perforation (32 shots/m, 1610 mm penetration) and two cycles of oil-based fermentation fluid huff-n-puff reduced injection pressure from 2.0 to 2.5 MPa to 1.0–1.8 MPa. A total of 1489 m3 of microbial agent was injected into five wells, followed by a 125-day shut-in period. Nano-microemulsion single-well huff-n-puff (579 m3 over 87 days) further decreased injection pressure to 0 MPa. A downhole harmonic vibration source (≤20 Hz) was also applied during the trial. During the production phase, Pseudomonas was found to dominate the produced fluid, with its peak relative abundance exceeding 70%. Cumulative fluid production reached 4114 m3, yielding 21 m3 of oil sand oil. Wells with vibration assistance showed significantly higher oil content and better emulsification performance than wells without vibration assistance. Full article
(This article belongs to the Special Issue Advances in Heavy Oil Reservoir Development)
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24 pages, 5289 KB  
Article
Pressure-Induced Viscoelastic Strengthening in Heavy Crude Oils: Experimental Quantification Under Reservoir-Relevant Conditions
by Esteban Alberto González-García, Rafael Herrera-Nájera, José Fernando Barragán-Aroche and Simón López-Ramírez
Processes 2026, 14(13), 2126; https://doi.org/10.3390/pr14132126 - 30 Jun 2026
Viewed by 657
Abstract
Heavy crude oils exhibit complex rheological behavior governed by the interplay between temperature, pressure, and colloidal microstructure. In this work, the coupled influence of pressure and temperature on the viscoelastic response of five Mexican heavy crude oils was experimentally investigated under reservoir-relevant conditions. [...] Read more.
Heavy crude oils exhibit complex rheological behavior governed by the interplay between temperature, pressure, and colloidal microstructure. In this work, the coupled influence of pressure and temperature on the viscoelastic response of five Mexican heavy crude oils was experimentally investigated under reservoir-relevant conditions. Steady and oscillatory shear measurements were performed at temperatures between 10 and 30 °C and at pressures ranging from atmospheric to 10.034 MPa. The results revealed pronounced shear-thinning behavior for all samples, with viscosity increasing systematically with pressure and decreasing strongly with temperature. Pressure effects were particularly significant at low temperatures, where enhanced elastic behavior and longer characteristic relaxation times were observed. Oscillatory measurements showed that pressurization shifted the viscoelastic crossover toward lower frequencies, indicating pressure-induced reinforcement of internal structures and reduced molecular mobility. The viscoelastic response was interpreted using a pressure-modified Arrhenius model, which successfully described the dependence of characteristic relaxation time on temperature and pressure. The fitted activation energies and activation volumes revealed systematic differences associated with crude oil composition and colloidal stability. Samples with lower resin-to-asphaltene ratios exhibited stronger pressure sensitivity and higher structural rigidity. The results demonstrate that pressure and temperature jointly control the relaxation dynamics and structural organization of heavy crude oils. These findings provide useful insights into flow assurance, transport, and production operations involving heavy crude systems under thermobaric conditions. Full article
(This article belongs to the Special Issue Advances in Heavy Oil Reservoir Development)
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