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Applied Sciences
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Development and Production of Oil Reservoirs
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Development and Production of Oil Reservoirs

A special issue of Applied Sciences (ISSN 2076-3417). This special issue belongs to the section "Energy Science and Technology".

Deadline for manuscript submissions: closed (20 October 2024) | Viewed by 6312

Special Issue Editors

Dr. Qingbang Meng

E-Mail Website
Guest Editor
School of Earth Resources, China University of Geosciences, 388 Lumo Road, Wuhan 430074, China
Interests: imbibition and capillary action in ideal and natural materials; multiphase flow in porous/fractured media; enhanced oil recovery; CCUS; reservoirs numerical simulation
Special Issues, Collections and Topics in MDPI journals
Dr. Bin Liang

E-Mail Website
Guest Editor
State Key Lab Oil & Gas Reservoir Geol & Exploita, Southwest Petroleum University, Chengdu 610500, China
Interests: chemical EOR; machine learning; CO2-EOR; unconventional reservoirs
Special Issues, Collections and Topics in MDPI journals
Dr. Xiaocong Lyu

E-Mail Website
Guest Editor
School of Petroleum Engineering, China University of Petroleum, Beijing 102249, China
Interests: feological CO2 storage; chemical flooding enhanced oil recovery technology; reservoir numerical simulation
Special Issues, Collections and Topics in MDPI journals
Dr. Yingrui Bai

E-Mail Website
Guest Editor
School of Petroleum Engineering, China University of Petroleum (East China), Qingdao 257099, China
Interests: polymer gel; drilling fluid; lost circulation control; conformance control; water shutoff; enhanced oil recovery
Special Issues, Collections and Topics in MDPI journals

Special Issue Information

Dear Colleagues,

The demand for fossil fuels continues to grow, despite the emergence of alternative energy sources. Recently, new opportunities and challenges have occurred in the development and production of oil reservoirs. For conventional reservoirs, there are some intractable problems such as high water cut, low sweep efficiency, and the corresponding difficulties in enhancing oil recovery. For unconventional reservoirs, low permeability, high heterogeneity, and complex fracture systems are the current obstacles to improving oil and gas recovery. However, the burning of fossil fuels causes a large amount of CO2 emissions, a phenomenon which is not expected to continue in the following decades. In the context of the energy transition process, fossil fuel production must be performed in a more efficient and environmentally friendly manner. Confronted with these challenges, high-performance, cost-effective, and environmentally sustainable technologies and methods are drastically required to enhance oil production.

This Special Issue aims at advances in the novel technologies and methods for the development and production of oil and gas reservoirs with low-carbon emissions. These technologies should be capable of being deployed in both conventional and unconventional reservoirs. We invite a broad range of papers, including those on field practice, mathematical models, reservoir simulation methods, innovative methods of experiments, etc.

Topics for publication include, but are not limited to, as follows,

  •  Novel material and technology to improve oil recovery;
  •  Novel model and method to forecast reservoirs performance;
  •  Novel technology for well drilling and completion;
  •  Modeling and experiments of carbon storage in subsurface porous media.

Dr. Qingbang Meng
Dr. Bin Liang
Dr. Xiaocong Lyu
Dr. Yingrui 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. Applied Sciences 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/gas reservoirs
  • improve oil recovery
  • reservoir performance forecasting
  • well drilling and completion
  • multiphase flow in porous media
  • reservoir engineering
  • carbon storage

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Published Papers (6 papers)

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Research

20 pages, 6407 KiB  
Article
Prediction of Breakdown Pressure Using a Multi-Layer Neural Network Based on Supercritical CO2 Fracturing Data
by Xiufeng Zhang, Min Zhang, Shuyuan Liu and Heyang Liu
Appl. Sci. 2024, 14(22), 10545; https://doi.org/10.3390/app142210545 - 15 Nov 2024
Viewed by 361
Abstract
Hydraulic fracturing is a widely employed technique for stimulating unconventional shale gas reservoirs. Supercritical CO2 (SC-CO2) has emerged as a promising fracturing fluid due to its unique physicochemical properties. Existing theoretical models for calculating breakdown pressure often fail to accurately [...] Read more.
Hydraulic fracturing is a widely employed technique for stimulating unconventional shale gas reservoirs. Supercritical CO2 (SC-CO2) has emerged as a promising fracturing fluid due to its unique physicochemical properties. Existing theoretical models for calculating breakdown pressure often fail to accurately predict the outcomes of SC-CO2 fracturing due to the complex, nonlinear interactions among multiple influencing factors. In this study, we conducted fracturing experiments considering parameters such as fluid type, flow rate, temperature, and confining pressure. A fully connected neural network was then employed to predict breakdown pressure, integrating both our experimental data and published datasets. This approach facilitated the identification of key influencing factors and allowed us to quantify their relative importance. The results demonstrate that SC-CO2 significantly reduces breakdown pressure compared to traditional water-based fluids. Additionally, breakdown pressure increases with higher confining pressures and elevated flow rates, while it decreases with increasing temperatures. The multi-layer neural network achieved high predictive accuracy, with R, RMSE, and MAE values of 0.9482 (0.9123), 3.424 (4.421), and 2.283 (3.188) for training (testing) sets, respectively. Sensitivity analysis identified fracturing fluid type and tensile strength as the most influential factors, contributing 28.31% and 21.39%, respectively, followed by flow rate at 12.34%. Our findings provide valuable insights into the optimization of fracturing parameters, offering a promising approach to better predict breakdown pressure in SC-CO2 fracturing operations. Full article
(This article belongs to the Special Issue Development and Production of Oil Reservoirs)
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24 pages, 7663 KiB  
Article
Experimental Analysis of Shale Cuttings Migration in Horizontal Wells
by Qiang Fang, Mingyu Ma, Dong Xiao, Ming Wang and Xiaoqi Ning
Appl. Sci. 2024, 14(20), 9559; https://doi.org/10.3390/app14209559 - 19 Oct 2024
Viewed by 650
Abstract
The extraction of shale gas via horizontal drilling presents considerable challenges, primarily due to the accumulation of cuttings within the annular space, resulting in increased friction, torque, and potential drilling complications. To address this issue, the study proposes an experimental setup aimed at [...] Read more.
The extraction of shale gas via horizontal drilling presents considerable challenges, primarily due to the accumulation of cuttings within the annular space, resulting in increased friction, torque, and potential drilling complications. To address this issue, the study proposes an experimental setup aimed at simulating cuttings transport under various operational conditions, with a particular emphasis on gas wells. The methodology encompasses the modulation of the drilling fluid flow rate and the drill’s rotational speed to examine the transport velocity of cuttings. Furthermore, the study analyzes the impact of annular eccentricity on return volume, transport time, and cuttings bed height. Critical initiation velocities for cuttings across different motion modes were also determined, and theoretical calculations were compared with empirical data. The findings indicate that an increased flow rate of drilling fluid and higher rotation speed substantially improve the transport of cuttings, thereby minimizing bed formation, whereas increased eccentricity hinders this process. The results revealed that the theoretical model showed a greater overestimation of the start-up velocity for spherical particles, with average errors ranging from 15.50% to 17.56%. In contrast, the model exhibited better accuracy for non-spherical (flaky) particles, with errors between 8.63% and 9.61%. Under non-rotating conditions, the average error of the model was approximately 8.32%, while the introduction of drill tool rotation increased the average error to 11.94%. These results have the potential to optimize operational parameters in shale gas well drilling and may contribute to the development of specialized borehole purification tools. Full article
(This article belongs to the Special Issue Development and Production of Oil Reservoirs)
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15 pages, 3656 KiB  
Article
Borehole Condition and Limit Pressure Differential Analysis in Carbonate Reservoirs
by Long Wang, Peng Su, Qiang Tan, Ke Li and Naikun Hu
Appl. Sci. 2024, 14(13), 5676; https://doi.org/10.3390/app14135676 - 28 Jun 2024
Viewed by 539
Abstract
In deep carbonate reservoirs, testing and production with open-hole completion can help release the maximum production capacity. However, because the reservoir is subjected to high in situ stress, if the test pressure differential is too large, the wellbore collapse and instability will occur [...] Read more.
In deep carbonate reservoirs, testing and production with open-hole completion can help release the maximum production capacity. However, because the reservoir is subjected to high in situ stress, if the test pressure differential is too large, the wellbore collapse and instability will occur easily, causing downhole accidents. Therefore, it is necessary to determine the state of the borehole during the open-hole test in the carbonate reservoir and analyze the ultimate test pressure differential accordingly to ensure test safety. Considering the characteristics of open-hole completion, based on the mechanical properties of the carbonate reservoir and the stress distribution around the borehole during testing, a calculation method of the elastic zone, plastic zone, and residual failure zone around the open-hole wellbore was proposed. Regarding actual engineering data, a criterion for the overall stability of the open-hole section had been established from three aspects: the volume ratio of the plastic zone; the failure zone around the wellbore; and the failure angle on the borehole wall. According to this criterion, it is possible to determine the ultimate pressure differential during the open-hole test process and provide theoretical support for designing the open-hole completion test and production parameters for deep carbonate reservoirs. Full article
(This article belongs to the Special Issue Development and Production of Oil Reservoirs)
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20 pages, 3278 KiB  
Article
Mitigation of Gravity Segregation by Foam to Enhance Sweep Efficiency
by Meijie Wang, Rigu Su, Yaowei Huang, Dengya Chen, Yiyang Li, Hong Xiang, Wenxuan Guo and Long Chen
Appl. Sci. 2023, 13(15), 8622; https://doi.org/10.3390/app13158622 - 26 Jul 2023
Cited by 2 | Viewed by 1108
Abstract
Foam-assisted gas injection exhibits promising potential for enhancing sweep efficiency through the amelioration of gravity segregation, particularly within reservoirs characterized by heterogeneity. In this work, the implicit-texture (IT) model featuring two flow regimes is employed to examine the impact of heterogeneity on gravity [...] Read more.
Foam-assisted gas injection exhibits promising potential for enhancing sweep efficiency through the amelioration of gravity segregation, particularly within reservoirs characterized by heterogeneity. In this work, the implicit-texture (IT) model featuring two flow regimes is employed to examine the impact of heterogeneity on gravity segregation. The validation of the numerical results for water–gas coinjection and pre-generated foam injection is accomplished through a comparative analysis with analytical solutions. A hypothetical two-layer model with varying permeabilities and thickness ratios is used to examine the impact of foam on gravity segregation. The numerical findings demonstrate satisfactory conformity with analytical solutions in homogeneous reservoirs. A high-permeability top layer in a layered model with a fixed injection rate results in sweep efficiency similar to that of a homogeneous reservoir with each individual permeability. A low-permeability top layer could increase the sweep efficiency, but with severe permeability contrast, the bottom high-permeability layer could impact the displacement process, even with a thin thickness. The sweep efficiency increases with the thickness of the high-permeability top layer and decreases with a thicker low-permeability top layer under fixed injection pressure. The predicted segregation length through a single-layer approximation cannot match the results of the layered models where the permeability contrast is too great or the thickness of two layers is comparable. Full article
(This article belongs to the Special Issue Development and Production of Oil Reservoirs)
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18 pages, 6451 KiB  
Article
A New Approach for Predicting the Rheological Properties of Oil-Based Drilling Fluids under High Temperature and High Pressure Based on a Parameter-Free Method
by Yuguang Ye, Honghai Fan and Yuhan Liu
Appl. Sci. 2023, 13(15), 8592; https://doi.org/10.3390/app13158592 - 26 Jul 2023
Cited by 5 | Viewed by 1352
Abstract
Under different temperatures and pressures, the physical parameters of drilling fluid will change, resulting in inaccurate drilling hydraulic calculations. Aiming to address the problem of the traditional rheological prediction method needing to first determine the rheological model, this paper proposed a method for [...] Read more.
Under different temperatures and pressures, the physical parameters of drilling fluid will change, resulting in inaccurate drilling hydraulic calculations. Aiming to address the problem of the traditional rheological prediction method needing to first determine the rheological model, this paper proposed a method for first predicting the readings of the rheometer and then determining the rheological model. The model established in this paper adopted a parameter-free method, which expands the application range of the model. Rheology experiments were carried out on the three types of oil-based drilling fluids collected at the well site. The model in this paper was verified based on the experimental data. The results showed that, compared with the traditional drilling fluid rheological prediction method, the model established in this paper had a better prediction effect, with an average error of 4.85%, and the average error reduction ranges from 3.8% to 8.3%. The model established in this paper is able to provide theoretical support for accurate hydraulic calculation. Full article
(This article belongs to the Special Issue Development and Production of Oil Reservoirs)
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19 pages, 21287 KiB  
Article
Experimental Study of Pore-Scale Water Flooding with Phase Change Based on a Microfluidic Model in Volatile Carbonate Reservoirs
by Pin Jia, Yang Li, Hongxin Guo, Haoran Feng and Linsong Cheng
Appl. Sci. 2023, 13(11), 6642; https://doi.org/10.3390/app13116642 - 30 May 2023
Viewed by 1326
Abstract
Carbonate reservoirs usually have strong heterogeneity, with complex pore structure and well-developed natural fractures. During reservoir development, when the formation pressure is lower than the bubble point pressure of crude oil, the fluid undergoes phase change and degassing. This leads to the subsequent [...] Read more.
Carbonate reservoirs usually have strong heterogeneity, with complex pore structure and well-developed natural fractures. During reservoir development, when the formation pressure is lower than the bubble point pressure of crude oil, the fluid undergoes phase change and degassing. This leads to the subsequent waterflooding displacement under the oil–gas two-phase condition, also followed by a secondary phase change of oil and gas caused by the increase in formation pressure. In this paper, the glass etching model is used to carry out microfluidic experiments. The porous carbonate model and the fractured porous carbonate model are designed to simulate the process of depletion development and waterflooding development. In the process of depletion development, it can be observed that the crude oil degassing and gas phase occurrence areas of the porous model are in the order of the large pore throat area first, followed by the small pore throat area. And the crude oil degassing and gas phase occurrence order in the fractured porous model is as follows: fractures, large pore throat area and, finally, small pore throat area. In the process of converting to the waterflooding development, the early stage of the replacement reflects the obvious characteristic of “displace oil but not gas”; with the replenishment of formation energy, the gas redissolution area expands from the mainstream to other areas, and the waterflooding mobilization increases. The characteristics of oil, gas and water flow in different stages of carbonate reservoirs with different pore-fracture characteristics that are clarified, and the characteristics of fluid migration and the distribution under the condition of oil and gas coexisting and water flooding after crude oil degassing are explored, and the water displacement mechanism of volatile carbonate reservoirs with different pressure levels is revealed. Full article
(This article belongs to the Special Issue Development and Production of Oil Reservoirs)
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