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New Insight in Enhanced Oil Recovery Process Analysis and Application

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A special issue of Processes (ISSN 2227-9717). This special issue belongs to the section "Energy Systems".

Deadline for manuscript submissions: closed (31 August 2024) | Viewed by 12033

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Dr. Kang Zhou

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Guest Editor

College of Energy and Mining Engineering, Shandong University of Science and Technology, Qingdao 266590, China
Interests: enhanced oil recovery; chemical flooding; multiphase flow in porous media; intelligent oil production optimization

Dr. Qingjun Du

E-Mail Website
Guest Editor

School of Petroleum Engineering, China University of Petroleum (East China), Qingdao 266580, China
Interests: enhanced oil recovery; thermal oil recovery method; cold production method for heavy oil reservoir

Special Issue Information

Dear Colleagues,

Various enhanced oil recovery methods have been widely used to improve reservoir development performance worldwide. Chemical flooding methods effectively enhance the oil recovery of heterogeneous oil reservoirs. Thermal oil recovery methods have been successfully applied in heavy oil reservoirs. Considering the extensive depletion of easily accessible resources and the environmental concerns, researchers and engineers have to provide new insights into enhanced oil recovery methods for developing oil reservoirs operating in harsh conditions. In recent years, a promising chemical method introducing viscoelastic soft solid particles into polymer/surfactant solution was successfully used in a pilot test of the Shengli Oilfield in China. The new insight breaks the tradition of only using homogeneous liquid or gas phase as displacing fluid in petroleum engineering. Another example is the chemical cold production method for harsh heavy oil reservoirs, where the traditional thermal methods show poor performance because of the high humidity of steam, badly developed steam cavity, serious loss of heat and negative environmental impact. In fact, the revolution in enhanced oil recovery methods is just beginning, and more efforts are needed from researchers all over the world.

This Special Issue on “New Insight in Enhanced Oil Recovery Process Analysis and Application” aims to gather and promote new insights in the development and application of enhanced oil recovery methods to improve oil development performance in harsher reservoirs. Topics include, but are not limited to:

Chemical flooding methods;
Thermal oil recovery methods;
Cold production methods for heavy oil reservoirs;
Multiphase seepage flow in enhanced oil recovery;
Intelligent oil production optimization.

Dr. Kang Zhou
Dr. Qingjun Du
Guest Editors

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Keywords

enhanced oil recovery
chemical flooding
thermal oil recovery
cold production
multiphase seepage flow
intelligent oil production optimization

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Published Papers (12 papers)

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Research

12 pages, 5338 KiB

Open AccessArticle

Saturation Calculation for Low-Resistivity Reservoirs Caused by Pyrite Conductivity

by Meng Feng, Zhishang Zhang, Zhitong Song, Renzhong Gan, Guangwen Hu, Guoli Li, Haiquan Dou and Rui Deng

Processes 2024, 12(12), 2682; https://doi.org/10.3390/pr12122682 - 28 Nov 2024

Viewed by 215

Abstract

In the current petroleum industry, as oil and gas resources are continuously developed, easily accessible reservoirs are gradually diminishing, making complex reservoirs, especially low-resistivity reservoirs, key exploration targets. By analyzing the main geological factors contributing to the formation of low-resistivity reservoirs in the LN oilfield clastic rock formations and through the integrated use of logging and petrophysical data for property modeling, we considered the impact of pyrite content on low-resistivity reservoirs and reconstructed a low-resistivity reservoir density-volume model. Using a parallel conductivity model, a saturation calculation method was established to account for the conductivity induced by pyrite in low-resistivity reservoirs, which was able to accurately identify oil layers in practical applications. This pyrite-conductivity-based method for calculating saturation in low-resistivity reservoirs effectively addresses key issues in the identification of such reservoirs, significantly improving identification accuracy. It provides a new technical approach for the evaluation and development of complex reservoirs and holds important theoretical and practical significance for enhancing the efficiency of unconventional oil and gas resource development. Full article

(This article belongs to the Special Issue New Insight in Enhanced Oil Recovery Process Analysis and Application)

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17 pages, 5029 KiB

Open AccessArticle

Research on the Calculation Method and Diffusion Pattern of VCE Injury Probability in Oil Tank Group Based on SLAB-TNO Method

by Xixiang Zhang, Yufeng Yang, Wanzhou Cheng, Guohua Chen, Qiming Xu and Tingyu Gao

Processes 2024, 12(11), 2459; https://doi.org/10.3390/pr12112459 - 6 Nov 2024

Viewed by 452

Abstract

Accidental leakage from oil–gas storage tanks can lead to the formation of liquid pools. These pools can result in vapor cloud explosions (VCEs) if combustible vapors encounter ignition energy. Conducting accurate and comprehensive consequence analyses of such explosions is crucial for quantitative risk assessments (QRAs) in industrial safety. In this study, a methodology based on the SLAB-TNO model to calculate the overpressure resulting from a VCE is presented. Based on this method, the consequences of the VCE accident considering the gas cloud concentration diffusion are studied. The probit model is employed to evaluate casualty probabilities under varying environmental and operational conditions. The effects of key parameters, including gas diffusion time, wind speed, lower flammability limit (LFL), and environment temperature, on casualty diffusion are systematically investigated. The results indicate that when the diffusion time is less than 100 s, the VCE consequences are significantly more severe due to the rapid spread of the gas cloud. Furthermore, increasing wind speed accelerates gas dispersion, reducing the spatial extent of casualty isopleths. The LFL is shown to have a direct impact on both the mass and diffusion of the flammable gas cloud, with higher LFL values shifting the explosion’s epicenter upward. The environmental temperature promotes gas diffusion in the core area and increases the mass of the combustible gas cloud. These findings provide critical insights for improving the safety protocols in oil and gas storage facilities and can serve as a valuable reference for consequence assessment and emergency response planning in similar industrial scenarios. Full article

(This article belongs to the Special Issue New Insight in Enhanced Oil Recovery Process Analysis and Application)

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12 pages, 5838 KiB

Open AccessArticle

A Novel Quantitative Water Channeling Identification Method of Offshore Oil Reservoirs

by Zhijie Wei, Yanchun Su, Wei Yong, Ben Liu, Jian Zhang, Wensheng Zhou and Yuyang Liu

Processes 2024, 12(11), 2363; https://doi.org/10.3390/pr12112363 - 28 Oct 2024

Viewed by 554

Abstract

Offshore oilfields are characterized by loose sandstone reservoirs, strong heterogeneity and high injection and production intensity. Water channeling gradually develops after entering the high water cut stage, which weakens production performance. Current identification methods usually have high computational costs and low efficiency. A quantitative identification model of water channeling based on inter-well connection units has been established by simplifying the complex reservoir system into a connection network between injectors and producers, which can quickly and accurately obtain strength characteristic parameters for waterflow channels. In addition, a comprehensive evaluation factor M and classification standard for water channeling suitable for offshore heterogeneous reservoirs have been proposed. It indicates a thief zone when M is larger than 0.65, a predominant waterflow channel when M is between 0.55 and 0.65, and no water channeling when M is smaller than 0.55. The application of (an) offshore S oilfield demonstrates that the new method successfully identifies 18 segments of the thief zone and 19 segments of the predominant waterflow channel and improves computational speed by 100 times compared with the conventional numerical modeling method. This novel method allows for rapid and accurate identification and prediction of water channeling, including location, directions, and strengths, thereby providing timely and practical guidance for inefficient water channel treatment. Full article

(This article belongs to the Special Issue New Insight in Enhanced Oil Recovery Process Analysis and Application)

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27 pages, 9710 KiB

Open AccessArticle

A Multi-Scale Numerical Simulation Method Considering Anisotropic Relative Permeability

by Li Wu, Junqiang Wang, Deli Jia, Ruichao Zhang, Jiqun Zhang, Yiqun Yan and Shuoliang Wang

Processes 2024, 12(9), 2058; https://doi.org/10.3390/pr12092058 - 23 Sep 2024

Viewed by 847

Abstract

Most of the oil reservoirs in China are fluvial deposits with firm reservoir heterogeneity, where differences in fluid flow capacity in individual directions should not be ignored; however, the available commercial reservoir simulation software cannot consider the anisotropy of the relative permeability. To handle this challenge, this paper takes full advantage of the parallelism of the multi-scale finite volume (MsFV) method and establishes a multi-scale numerical simulation approach that incorporates the effects of reservoir anisotropy. The methodology is initiated by constructing an oil–water black-oil model considering the anisotropic relative permeability. Subsequently, the base model undergoes decoupling through a sequential solution, formulating the pressure and transport equations. Following this, a multi-scale grid system is configured, within which the pressure and transport equations are progressively developed in the fine-scale grid domain. Ultimately, the improved multi-scale finite volume (IMsFV) method is applied to mitigate low-frequency error in the coarse-scale grid, thereby enhancing computational efficiency. This paper introduces two primary innovations. The first is the development of a multi-scale solution method for the pressure equation incorporating anisotropic relative permeability. Validated using the Egg model, a comparative analysis with traditional numerical simulations demonstrates a significant improvement in computational speed without sacrificing accuracy. The second innovation involves applying the multi-scale framework to investigate the impact of anisotropy relative permeability on waterflooding performance, uncovering distinct mechanisms by which absolute and relative permeability anisotropy influence waterflooding outcomes. Therefore, the IMsFV method can be used as an effective tool for high-resolution simulation and precise residual oil prediction in anisotropic reservoirs. Full article

(This article belongs to the Special Issue New Insight in Enhanced Oil Recovery Process Analysis and Application)

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21 pages, 9214 KiB

Open AccessArticle

Evaluation of Key Development Factors of a Buried Hill Reservoir in the Eastern South China Sea: Nonlinear Component Seepage Model Coupled with EDFM

by Jianwen Dai, Yangyue Xiang, Yanjie Zhu, Lei Wang, Siyu Chen, Feng Qin, Bowen Sun and Yonghui Deng

Processes 2024, 12(8), 1736; https://doi.org/10.3390/pr12081736 - 19 Aug 2024

Viewed by 575

Abstract

The HZ 26-B buried hill reservoir is located in the eastern part of the South China Sea. This reservoir is characterized by the development of natural fractures, a high density, and a complex geological structure, featuring an upper condensate gas layer and a lower volatile oil layer. These characteristics present significant challenges for oilfield exploration. To address these challenges, this study employed advanced embedded discrete fracture methods to conduct comprehensive numerical simulations of the fractured buried hill reservoirs. By meticulously characterizing the flow mechanisms within these reservoirs, the study not only reveals their unique characteristics but also establishes an embedded discrete fracture numerical model at the oilfield scale. Furthermore, a combination of single-factor sensitivity analysis and the Pearson correlation coefficient method was used to identify the primary controlling factors affecting the development of complex condensate reservoirs in ancient buried hills. The results indicate that the main factors influencing the production capacity are the matrix permeability, geomechanical effects, and natural fracture length. In contrast, the impact of the threshold pressure gradient and bottomhole flow pressure is relatively weak. This study’s findings provide a scientific basis for the efficient development of the HZ 26-B oilfield and offer valuable references and insights for the exploration and development of similar fractured buried hill reservoirs. Full article

(This article belongs to the Special Issue New Insight in Enhanced Oil Recovery Process Analysis and Application)

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21 pages, 11289 KiB

Open AccessArticle

Research on Numerical Simulation Methods for Reservoirs of Loose Sandstone Considering the Equilibrium Time of Vertical Seepage Flow

by Shuozhen Wang, Qing You, Ruichao Zhang, Chunlei Yu, Shuoliang Wang, Congcong Li and Xiao Zhuo

Processes 2024, 12(4), 733; https://doi.org/10.3390/pr12040733 - 4 Apr 2024

Viewed by 1060

Abstract

Due to their high porosity and permeability characteristics, reservoirs of loose sandstone have great development potential. Under weak dynamic conditions, the vertical migration and mass exchange of oil–water two-phase fluids in loose sandstone reservoirs occur very easily. The phenomenon of vertical seepage flow equilibrium has a significant impact on the distribution of oil–water two-phase fluids in the reservoir. However, existing mainstream numerical simulators cannot accurately describe the phenomenon of vertical migration of oil–water two-phase fluids under weak dynamic conditions. In this study, using 3D printing technology, multiple transparent rock core holders were constructed to conduct experiments on the vertical seepage flow equilibrium time of different viscosities and contents of crude oil under different permeabilities of rock cores. Through the analysis and regression of experimental results, a predictive formula for the vertical seepage flow equilibrium time of loose sandstone reservoirs was established. Based on the time-prediction discriminant formula, a multi-scale numerical simulation method for vertical seepage flow equilibrium was constructed. A comparison between the new method and experimental results showed that the numerical simulation method, considering vertical seepage flow equilibrium, is closer to experimental phenomena than traditional numerical simulation methods. This indicates that the method can more accurately reveal the characteristics and distribution laws of the vertical seepage flow of oil–water two-phase fluids in loose sandstone reservoirs. Full article

(This article belongs to the Special Issue New Insight in Enhanced Oil Recovery Process Analysis and Application)

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16 pages, 8070 KiB

Open AccessArticle

Effect of Displacement Pressure Gradient on Oil–Water Relative Permeability: Experiment, Correction Method, and Numerical Simulation

by Jintao Wu, Lei Zhang, Yingxian Liu, Kuiqian Ma and Xianbo Luo

Processes 2024, 12(2), 330; https://doi.org/10.3390/pr12020330 - 3 Feb 2024

Viewed by 1204

Abstract

Relative permeability is a fundamental parameter affecting reservoir development performance analysis. During the development of oil and gas fields, the displacement pressure gradient changes with time and space. This paper studies the effect of displacement pressure gradient on relative permeability. The oil–water relative permeability curves of a Bohai Oilfield under different displacement pressure gradients are obtained through experimental analysis. Based on the experimental data, a correction model of the permeability curve is established by regression of the Willhite model parameters. The correction model is introduced into the black oil numerical simulation, and the production performance and remaining oil are compared and analyzed. The results show that the displacement pressure gradient can have an obvious impact on the relative permeability curve. As the displacement pressure gradient increases, the two-phase span of the relative permeability curve increases, the oil displacement efficiency increases, and the water relative permeability increases. The relative permeability curves under different displacement pressure gradients can be accurately characterized by the Willhite model. The consideration of the displacement pressure gradient has an obvious impact on numerical simulation results. The conventional method of using a fixed relative permeability curve cannot truly reflect the production performance and the remaining oil distribution. This paper proposes a set of realization methods including obtaining laws from experiments, utilizing the empirical model to correct, and simulating to characterize reservoir changes. Full article

(This article belongs to the Special Issue New Insight in Enhanced Oil Recovery Process Analysis and Application)

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13 pages, 6626 KiB

Open AccessArticle

Study on Main Factors Controlling Development Performance of Heterogeneous Composite Flooding in Post-Polymer Flooding Reservoir

by Kang Zhou, Fangjian Zhao and Xilong Zhou

Processes 2024, 12(2), 269; https://doi.org/10.3390/pr12020269 - 26 Jan 2024

Viewed by 906

Abstract

Heterogeneous composite flooding has performed well with regard to enhanced oil recovery after polymer flooding in recent years. In order to significantly increase oil recovery, the development parameters should be designed differently for each well. However, it is difficult to rapidly allocate development parameters through the lowering of computational costs. Therefore, the authors of this paper carried out research to clarify the main controlling factors of parameter allocation. Firstly, the numerical simulation domain was separated into several regions, with injection wells and production wells at the center of each region. The statistical parameters of each region were calculated. Then, the water injection rate, liquid production rate, and chemical agent concentration were allocated based on the proportion of statistical parameters in each region. A large number of development schemes were designed by combining different injection and production allocations that were calculated based on each statistical parameter. Finally, the development performance of each scheme was simulated and analyzed. The statistical parameters corresponding to the best performance scheme were regarded as the main controlling factors of heterogeneous composite flooding after polymer flooding. These results showed that the main controlling factors for the allocation of the water injection rate were pore volume and permeability variation coefficient. The main controlling factors for liquid production rate were the remaining oil saturation, formation coefficient, and reservoir pressure. The main controlling factors for chemical agent concentration were pressure and permeability variation coefficient. These findings concerning the main factors controlling development parameter allocation were validated by practical application in several well groups of an actual reservoir model. This study provides references for improving heterogeneous composite flooding performance for post-polymer flooding reservoirs in the future. Full article

(This article belongs to the Special Issue New Insight in Enhanced Oil Recovery Process Analysis and Application)

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36 pages, 39359 KiB

Open AccessArticle

Modeling Microscale Foam Propagation in a Heterogeneous Grain-Based Pore Network with the Pore-Filling Event Network Method

by Jun Yang, Nu Lu, Zeyu Lin, Bo Zhang, Yizhong Zhang, Yanfeng He and Jing Zhao

Processes 2023, 11(12), 3322; https://doi.org/10.3390/pr11123322 - 29 Nov 2023

Cited by 1 | Viewed by 1025

Abstract

Foam flooding is an efficient and promising technology of enhanced oil recovery that significantly improves sweep efficiency of immiscible displacement processes by providing favorable mobility control on displacing fluids. Although the advantages in flexibility and efficiency are apparent, accurate prediction and effective control of foam flooding in field applications are still difficult to achieve due to the complexity in multiphase interactions. Also, conventional field-scale or mesoscale foam models are inadequate to simulate recent experimental findings in feasibility of foam injection in tight reservoirs. Microscale modeling of foam behavior has been applied to further connect those pore-scale interactions and mesoscale multiphase properties such as foam texture and the relative permeability of foam banks. Modification on a microscale foam model based on a pore-filling event network method is proposed to simulate its propagation in grain-based pore networks with varying degrees of heterogeneity. The impacts of foam injection strategy and oil-weakening phenomena are successfully incorporated. Corresponding microfluidic experiments are performed to validate the simulation results in dynamic displacement pattern as well as interfacial configuration. The proposed modeling method of foam propagation in grain-based networks successfully captures the effects of lamellae configurations corresponding to various foaming processes. The results of the simulation suggest that the wettability of rock has an impact on the relevance between reservoir heterogeneity and the formation of immobile foam banks, which supports the core idea of the recently proposed foam injection strategy in tight oil reservoirs with severe heterogeneity, that of focusing more on the IFT adjustment ability of foam, instead of arbitrarily pursuing high-quality strong foam restricted by permeability constraints. Full article

(This article belongs to the Special Issue New Insight in Enhanced Oil Recovery Process Analysis and Application)

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16 pages, 2956 KiB

Open AccessArticle

Characterization of Extra Low-Permeability Conglomerate Reservoir and Analysis of Three-Phase Seepage Law

by Zhibin Jiang, Hongming Tang, Jie Wang, Lin Zhang and Xiaoguang Wang

Processes 2023, 11(7), 2054; https://doi.org/10.3390/pr11072054 - 10 Jul 2023

Cited by 1 | Viewed by 1201

Abstract

The micro distribution of residual oil in low-permeability sandstone reservoirs is closely related to pore structure, and the differences in pore structure often determine the reservoir’s productivity and development effectiveness from a macro perspective. On the basis of in-depth research, this paper analyzes the distribution law of the remaining microscopic oil, establishes the digital core multi-stage pore network modeling of the strongly sorted heterogeneous conglomerate reservoir in the Lower Wuerhe Formation of Block 8 of the Karamay Oilfield, the three-phase seepage simulation method considering the release of dissolved gas, and the three-phase permeability curve test. The research results are as follows: (1) Conventional physical property analysis shows that the permeability of core samples exhibits an inverse rhythmic distribution with layer depth. (2) CT core analysis and mercury injection experiments indicate that the area with porosity ranging from 9% to 21% accounts for 79% and is the main seepage channel area. Larger pores play an important role in seepage. (3) Through comparative experiments on cores with different permeability, it was found that the degassing phenomenon of low-permeability rock samples is more severe. In the actual process of reservoir development, it is necessary to reasonably handle the impact of water injection on development effectiveness, select appropriate water injection methods and cycles, and avoid premature water breakthrough in ultra low-permeability reservoirs. Full article

(This article belongs to the Special Issue New Insight in Enhanced Oil Recovery Process Analysis and Application)

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20 pages, 6605 KiB

Open AccessArticle

A Three-Phase Relative Permeability Model for Heavy Oil Emulsion System

by Zezheng Sun, Kang Zhou and Yuan Di

Processes 2023, 11(4), 1247; https://doi.org/10.3390/pr11041247 - 18 Apr 2023

Cited by 2 | Viewed by 1259

Abstract

Chemical flooding is important and effective enhanced oil recovery processes are applied to improve the recovery of heavy oil reservoirs. Emulsification occurs during chemical flooding processes, forming an oil-in-water (O/W) emulsion system. In this work, the heavy oil emulsion system is characterized as a three-phase (continuous oil phase, dispersed oil phase, and continuous water phase) system. Based on a capillary tube model, a new relative permeability model is proposed to describe the flow of the emulsion system in porous media quantitatively, considering the physicochemical properties of emulsions and the properties of porous media. A resistance factor is derived in this model to describe the additional resistance to the emulsion flow caused by the interaction between dispersed oil droplets and the pore system. Three dimensionless numbers related to the emulsion porous flow process were proposed and their different effects on the three-phase relative permeability are investigated. To validate the reliability of the proposed model, a one-dimensional O/W emulsion–oil displacement experiment is simulated. The maximum absolute error between the simulated results and experimental data is no more than 10%, and the new model can be used to describe the flow behavior of heavy oil emulsions in porous media. Full article

(This article belongs to the Special Issue New Insight in Enhanced Oil Recovery Process Analysis and Application)

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15 pages, 4591 KiB

Open AccessArticle

Intelligent Diagnosis Model of Working Conditions in Variable Torque Pumping Unit Wells Based on an Electric Power Diagram

by Ruichao Zhang, Dechun Chen, Nu Lu, Bo Zhang and Yanjie Yang

Processes 2023, 11(4), 1166; https://doi.org/10.3390/pr11041166 - 11 Apr 2023

Cited by 1 | Viewed by 1570

Abstract

Because of the problems, such as the lack of an electric power diagram atlas under different working conditions and the difficulty in intelligent diagnosis of variable torqued pumping unit wells, this paper proposes a diagnosis model of working conditions based on feature recognition. The mathematical relationship model between the polished rod load and motor output power is derived based on the analysis of geometric structure, motion law, and process of energy transformation and transfer of the variable torque pumping unit. It can calculate the electric power diagram based on a dynamometer card. On this basis, the electric power diagram atlas is created, and the feature analysis and eigenvalue extraction of the electric power diagrams under different working conditions are carried out to realize the direct diagnosis of the working conditions in the variable torque pumping unit wells. The application and analysis of examples show that the electric power diagram atlas created in this paper has good practicability, and the working condition diagnosis model accuracy is high. It can provide a theoretical basis and technical support for the intelligent diagnosis of oil production working conditions and improve the intellectual management level of the oilfield, which is conducive to reducing production management costs and improving the oilfield’s production efficiency and benefits. Full article

(This article belongs to the Special Issue New Insight in Enhanced Oil Recovery Process Analysis and Application)

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