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Enhanced Oil Recovery for Unconventional Oil and Gas Reservoirs

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A special issue of Energies (ISSN 1996-1073). This special issue belongs to the section "H1: Petroleum Engineering".

Deadline for manuscript submissions: closed (25 November 2022) | Viewed by 16946

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Prof. Dr. Chuanjin Yao

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Guest Editor

School of Petroleum Engineering, China University of Petroleum (East China), Qingdao 266580, China
Interests: multi-field coupled multi-phase flow mechanism and simulation; reaction dynamics of complex oil and gas reservoirs; in situ conversion of shale reservoir underground; enhanced oil recovery and simulation of unconventional oil and gas reservoirs; CCUS green, low-carbon, and efficient development; big data analysis and application

Dr. Lei Li

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Guest Editor

School of Petroleum Engineering, China University of Petroleum (East China), Qingdao 266580, China
Interests: gas flooding; CCUS; chemical flooding; shale oil/tight oil recovery
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Special Issue Information

Dear Colleagues,

With the massive consumption of conventional oil and gas resources, research on unconventional oil and gas resources of tight oil and gas, shale oil and gas, etc., has become of primary interest in the last decade. Development and production of these reservoirs is a capital and labor-intensive enterprise due to their low porosity and permeability, which prompts oil suppliers to seek advanced theories, methods, and technologies for increasing oil recovery. This Special Issue aims to present the latest progresses in this interesting area, in particular, fundamental theory and technology in enhancing recovery of tight and shale reservoirs, frontier fields of shale oil in situ conversion, natural gas hydrate, etc., including reservoir evaluation, fracturing and reconstruction, reservoir engineering and numerical simulation, CO₂ enhanced oil recovery, oilfield chemical engineering, big data analysis and application, etc. We invite investigators to submit original research articles and review papers for publication in this Special Issue.

Prof. Dr. Chuanjin Yao
Dr. Lei Li
Guest Editors

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Keywords

tight/shale reservoir characterization
phase behavior considering nanopore confinement
multiphase flow in nanoporous media
CO₂ enhanced oil recovery and sequestration
advanced hydraulic fracturing for shale reservoirs
tight/shale reservoir damage and remediation
in situ conversion of shale reservoir underground
natural gas hydrate development and optimization
big data application in unconventional reservoirs

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Published Papers (10 papers)

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Research

22 pages, 5094 KiB

Open AccessArticle

A Fully Coupled Gas–Water–Solids Mathematical Model for Vertical Well Drainage of Coalbed Methane

by Chengwang Wang, Haifeng Zhao, Zhan Liu, Tengfei Wang and Gaojie Chen

Energies 2024, 17(6), 1497; https://doi.org/10.3390/en17061497 - 21 Mar 2024

Viewed by 1003

Abstract

The coupling relationship between the deformation field, the diffusion field, and the seepage field is an important factor in fluid transport mechanisms in the long-term coalbed methane (CBM) exploitation process. A mathematical model of gas–water two-phase fluid–structure coupling in a double-porosity medium in coal reservoirs is established in this paper. Taking Hancheng Block, a typical production block in Qinshui Basin, as the geological background critical desorption pressure, reservoir permeability anisotropy is considered in the model. COMSOL Multiphysics (COMSOL_6.0) was used to create the model. The accuracy and rationality of the model were verified by comparing field production data with the results of the simulation. Using the simulation, the influence law of various reservoir geological characteristics parameters (Langmuir strain constant, ratio of critical desorption pressure to reservoir pressure of coal seam (CDPRP), elastic modulus, initial water saturation, Langmuir pressure, etc.) on CBM productivity, reservoir pressure, and permeability ratio was discussed, and a thorough analysis of the factors affecting productivity was obtained using the orthogonal test method. The findings of this study indicate that the change in permeability is the result of the superposition effect of many factors. Different stages of drainage have different primary regulating factors. Rock skeleton stress has a consequence on coal matrix permeability in the early drainage stage, and coal matrix shrinkage is primarily impacted in the later drainage stage. Besides the initial water saturation, other reservoir geological parameters (e.g., CDPRP, Langmuir volume, Langmuir strain constant, elastic modulus) have a strong relationship with productivity. When the value of coal geological parameters increases, the degree of productivity release is higher (as the initial water saturation increases, the production decreases correspondingly). Different coal and rock parameters have varying levels of impact on the drainage stage of CBM wells. The influences of the CDPRP, Langmuir volume, Langmuir strain constant, and elastic modulus on gas production are mainly concentrated in the initial and intermediate drainage stages and begin to fall off during the last drainage stage. Per the multi-factor analysis, the main coal–rock parameters affecting the productivity release are the Langmuir strain constant, followed by the CDPRP and other parameters. The analysis findings can offer theoretical guidance for CBM well selection and layer selection and enhance the block’s overall CBM development level. The improved productivity prediction model for CBM, which is based on fluid–structure coupling theory, can offer a new technical benchmark for CBM well productivity prediction. Full article

(This article belongs to the Special Issue Enhanced Oil Recovery for Unconventional Oil and Gas Reservoirs)

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14 pages, 5982 KiB

Open AccessArticle

Characteristics and Controlling Factors of Tight Marl Reservoirs with an Eyelid-Shaped Structure of the First Member of the Deep Maokou Formation in Eastern Sichuan

by Qingchun Jiang, Weiming Wang and Qixia Lyu

Energies 2023, 16(5), 2353; https://doi.org/10.3390/en16052353 - 1 Mar 2023

Cited by 2 | Viewed by 1605

Abstract

Tight marl is a special type of unconventional oil and gas resource, and the study on its reservoir characteristics and controlling factors is of immense scientific significance. In this paper, 113 core samples of marl from Gouxi Area, Eastern Sichuan were selected. Based on organic carbon, pyrolysis, X-ray diffraction of whole rock, and X-ray diffraction of clay analysis, the reservoir evaluation of eyelid-shaped limestone in the first member of Maokou Formation was carried out. The results show that there are obvious differences between eyelid-shaped limestone reservoirs and eyeball-shaped limestone reservoirs in the target stratum. Eyelid-shaped limestone is mainly distributed in the lower members a and c of the first member of Maokou Formation. It could be the main reservoir of low porosity and permeability tight marl, as its developed apertures, micro-fractures, and pore throat structure are obviously better than that of the eyeball-shaped limestone. As eyelid-shaped limestone features obvious self-generation and self-storage characteristics, the deep-water and low-energy sedimentary environment provides it with a large amount of highly brittle minerals and clay minerals as well as a favorable reservoir-forming background for diagenetic evolution and organic matter adsorption of clay minerals in the later period. The transformation of sepiolite into talc through diagenesis provides a large number of shrinkage joints for the reservoir, which are an effective space for tight gas accumulation. Full article

(This article belongs to the Special Issue Enhanced Oil Recovery for Unconventional Oil and Gas Reservoirs)

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13 pages, 2412 KiB

Open AccessArticle

Model for Predicting Horizontal Well Transient Productivity in the Bottom-Water Reservoir with Finite Water Bodies

by Xiaofei Jia, Zhaobo Sun, Guanglun Lei and Chuanjin Yao

Energies 2023, 16(4), 1952; https://doi.org/10.3390/en16041952 - 16 Feb 2023

Cited by 2 | Viewed by 1258

Abstract

To better understand the horizontal well transient productivity in the bottom-water reservoir with finite water bodies, the horizontal well transient productivity model for the bottom-water reservoir with finite water-body multiple was developed using Green’s function and potential superposition method. Laplace transforms, Fourier transforms, superposition of point source, and Duhamel principle were used to obtain the transient productivity of the horizontal well, and the transient productivity of the horizontal well in real space was obtained by the Stehfest numerical inversion method. The typical pressure response curve and dimensionless productivity curves were plotted. The effects of the water-body multiple, the distance between the horizontal well and oil–water contact, and the skin factor, were analyzed. Six main flowing stages were divided for horizontal wells in the bottom-water reservoir with finite water bodies. When the water body multiples are zero or tend to infinity, the results obtained from the model are consistent with the calculations by the conventional top-bottom closed reservoir model or infinite rigid bottom-water reservoir model, respectively, and the pressure dynamic for the finite water body falls in between both. With the increase in the water body multiples and the decrease in distance between the horizontal well and the oil–water contact, and the horizontal well productivity decreases slowly. With the increase in the skin factor, the initial productivity decreases; moreover, the skin factor has a great influence on the initial productivity of the horizontal well, while the later influence gradually decreases. Accurate horizontal well productivity prediction in the bottom-water reservoir with finite water bodies provides a strong basis for horizontal well deployment, design optimization, and formulation of development policy. Full article

(This article belongs to the Special Issue Enhanced Oil Recovery for Unconventional Oil and Gas Reservoirs)

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14 pages, 3085 KiB

Open AccessArticle

Three-Dimensional Physical Simulation of Horizontal Well Pumping Production and Water Injection Disturbance Assisted CO₂ Huff and Puff in Shale Oil Reservoir

by Zemin Ji, Jia Zhao, Xinglong Chen, Yang Gao, Liang Xu, Chang He, Yuanbo Ma and Chuanjin Yao

Energies 2022, 15(19), 7220; https://doi.org/10.3390/en15197220 - 1 Oct 2022

Cited by 2 | Viewed by 1600

Abstract

In view of the problems of low matrix permeability and low oil recovery in shale reservoirs, CO₂ huff and puff technology is considered as an effective method to develop shale oil reservoirs. However, the production behaviors of actual shale reservoirs cannot be reproduced and the EOR potentials cannot be evaluated directly by scaled models in the laboratory. Conventional CO₂ huff and puff has problems such as early gas breakthrough and gas channeling leading to inefficient development. In this article, with the help of a three-dimensional experimental simulation apparatus, a new method of CO₂ huff and puff with a horizontal well assisted by pumping production and water injection disturbance is developed. The dynamic characteristic, pressure field distribution of soaking and the enhanced oil recovery effect are comprehensively evaluated. The results show that the soaking stage of CO₂ huff and puff can be divided into three stages: differential pressure driving, diffusion driving and dissolution driving. According to the pressure field distribution, after water injection disturbance, the fluctuation boundary and distribution of pressure becomes more stable and uniform and the sweep rate is greatly improved. Water injection disturbance realizes the combination of CO₂ injection energy enhancement and water injection energy enhancement and the CO₂ injection utilization rate is improved. It has the dual effect of stratum energy increase and economic benefit. The new huff and puff method can increase the oil recovery rate by 7.18% and increase the oil–gas replacement rate to 1.2728, which confirms the potential of horizontal well pumping production and water injection disturbance-assisted CO₂ huff and puff technology to improve oil recovery. Full article

(This article belongs to the Special Issue Enhanced Oil Recovery for Unconventional Oil and Gas Reservoirs)

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17 pages, 8708 KiB

Open AccessArticle

Influence of Temperature on the Adsorption and Diffusion of Heavy Oil in Quartz Nanopore: A Molecular Dynamics Study

by Dongsheng Chen, Wei Zheng, Taichao Wang, Fan Liu, Tong Cheng, Hengyuan Chen and Tingting Miao

Energies 2022, 15(16), 5870; https://doi.org/10.3390/en15165870 - 12 Aug 2022

Cited by 4 | Viewed by 1770

Abstract

The desorption of heavy oil is one of the important indicators affecting the development efficiency of the remaining oil in nanopores. However, the study of the adsorption and diffusion mechanisms of heavy oil molecules in nanopores remains scarce. In this work, the influences of temperature on the adsorption and diffusion properties of the heavy oil four-fractions in quartz nanopore have been investigated via molecular dynamics simulations. Our results show that the heavy oil molecules will form a denser multilayer adsorption oil layer on the nanopore surface, and high temperature can alter the adsorption behaviors of the heavy oil four-fractions. As the temperature increases, the saturate molecules are desorbed from the nanopore surfaces, but the aromatic, resin, and asphaltene molecules maintain a tendency to aggregate towards the nanopore surface. In particular, the agglomeration behaviors of most saturate, aromatic and asphaltene molecules in nanopore can be suppressed by the confined space compared with the heavy oil molecules in oil droplet. In addition, the influence of temperature on the movement of heavy oil molecules in nanopore decreases compared with the oil molecules in a heavy oil droplet due to the confined space and adsorption effect. Interestingly, there is a competition phenomenon between the adsorption and diffusion of aromatic, resin, and asphaltene molecules in the nanopore, resulting in different adsorption behaviors with the increase in temperature. The results obtained in this paper will provide molecular-level theoretical guidance for understanding the adsorption and desorption mechanisms of heavy oil in nanopores. Full article

(This article belongs to the Special Issue Enhanced Oil Recovery for Unconventional Oil and Gas Reservoirs)

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15 pages, 3914 KiB

Open AccessArticle

Quantitative Evaluation of Imbibition Damage Characteristics of Foaming Agent Solutions in Shale Reservoir

by Liangbin Dou, Jingyang Chen, Nan Li, Jing Bai, Yong Fang, Rui Wang and Kai Zhao

Energies 2022, 15(16), 5768; https://doi.org/10.3390/en15165768 - 9 Aug 2022

Cited by 4 | Viewed by 1611

Abstract

Shale reservoirs are characterized by extremely low porosity and permeability, poor connectivity, and high content of clay minerals. This leads to the reservoir being vulnerable to imbibition damage caused by foaming agent solutions during foam drainage gas recovery. It results in the decrease of reservoir permeability and the reduction of gas well production and ultimate recovery. Therefore, as the most commonly used foam drainage gas production, it is particularly important. This study is structured as follows. First, we analyze and evaluate the characteristics of shale reservoirs within the target area, and that of mineral composition and microscopic pore throat structures. Second, we study foaming agent types and two types are selected to be applied in subsequent sensitivity tests. Simultaneously, the nuclear magnetic resonance (NMR) method was used to study the microscopic characteristics of reservoir damage and imbibition damage of shale, caused by the impact of foaming agent solutions during the foam drainage and gas recovery processes. Finally, it is concluded that the degree of damage to the core permeability is minimized when the concentration of foaming agents is 0.4–0.6%. A trend has been established for increased damage to the cores with increasing exposure time. Additionally, this study provides technical guidance for damage evaluation and reservoir protection in shale reservoir exploitation. Full article

(This article belongs to the Special Issue Enhanced Oil Recovery for Unconventional Oil and Gas Reservoirs)

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15 pages, 6914 KiB

Open AccessFeature PaperArticle

Prediction of Oil Saturation during Water and Gas Injection Using Controllable Convolutional Long Short-Term Memory

by Yukun Dong, Fubin Liu, Yu Zhang and Qiong Wu

Energies 2022, 15(14), 5063; https://doi.org/10.3390/en15145063 - 11 Jul 2022

Cited by 1 | Viewed by 1436

Abstract

Oil saturation is a kind of spatiotemporal sequence that changes dynamically with time, and it is affected not only by the reservoir properties, but also by the injection–production parameters. When predicting oil saturation during water and gas injection, the influence of time, space and injection–production parameters should be considered. Aiming at this issue, a prediction method based on a controllable convolutional long short-term memory network (Ctrl-CLSTM) is proposed in this paper. The Ctrl-CLSTM is an unsupervised learning model whose input is the previous spatiotemporal sequence together with the controllable factors of corresponding moments, and the output is the sequence to be predicted. In this way, future oil saturation can be generated from the historical context. Concretely, the convolution operation is embedded into each unit to describe the interaction between temporal features and spatial structures of oil saturation, thus the Ctrl-CLSTM realizes the unified modeling of the spatiotemporal features of oil saturation. In addition, a novel control gate structure is introduced in each Ctrl-CLSTM unit to take the injection–production parameters as controllable influencing factors and establish the nonlinear relationship between oil saturation and injection–production parameters according to the coordinates of each well location. Therefore, different oil saturation prediction results can be obtained by changing the injection–production parameters. Finally, experiments on real oilfields show that the Ctrl-CLSTM comprehensively considers the influence of artificial controllable factors such as injection–production parameters, accomplishes accurate prediction of oil saturation with a structure similarity of more than 98% and is more time efficient than reservoir numerical simulation. Full article

(This article belongs to the Special Issue Enhanced Oil Recovery for Unconventional Oil and Gas Reservoirs)

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15 pages, 2543 KiB

Open AccessArticle

Steam Cavity Expansion Model for Steam Flooding in Deep Heavy Oil Reservoirs

by Lina Zhang, Dianfa Du, Yaozu Zhang, Xin Liu, Jingang Fu, Yuan Li and Jianhua Ren

Energies 2022, 15(13), 4816; https://doi.org/10.3390/en15134816 - 30 Jun 2022

Cited by 4 | Viewed by 1665

Abstract

Steam flooding is crucial for the development of heavy oil reservoirs, and the development of the steam cavity significantly determines the efficiency of steam flooding. Previous studies have elucidated the concept of steam overburden and pseudomobility ratio; however, the thermal energy loss in deep heavy oil reservoirs during steam injection needs further investigation. Therefore, in this study, the vapour–liquid interface theory and mathematical integration were used to establish a steam cavity expansion model. The wellbore heat loss rate coefficient, steam overlay, and pseudomobility ratio were used to accurately describe the development of the steam cavity in deep heavy oil reservoirs. The proposed model was experimentally validated, and it was observed that the model could accurately reflect the actual mine conditions. In addition, the pressure gradient distribution of the steam belt and the heat dissipation areas of the top and bottom layers of the steam cavity were evaluated. The results showed that the influence of the wellbore heat loss rate coefficient on the pressure gradient of the oil layer was primarily in the range of 5–20 m away from the steam injection well. Furthermore, it was observed that the pseudomobility ratio is inversely proportional to the development of the steam cavity. As the wellbore heat loss rate coefficient increased, the wellbore heat loss increased. The larger the area ratio, the more pronounced the steam overlay phenomenon, and the large area ratio does not meet the development requirements of the steam chamber. The research closely combines theory with production, and the results of this study can help actual mines by providing theoretical support for the development of deep heavy oil reservoirs. Full article

(This article belongs to the Special Issue Enhanced Oil Recovery for Unconventional Oil and Gas Reservoirs)

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17 pages, 4579 KiB

Open AccessArticle

Optimizing Composition of Fracturing Fluids for Energy Storage Hydraulic Fracturing Operations in Tight Oil Reservoirs

by Guanzheng Qu, Jian Su, Ming Zhao, Xingjia Bai, Chuanjin Yao and Jiao Peng

Energies 2022, 15(12), 4292; https://doi.org/10.3390/en15124292 - 11 Jun 2022

Cited by 5 | Viewed by 1874

Abstract

Energy storage fracturing technology is a technical means by which oil displacement fluid is injected into the reservoir before the traditional hydraulic fracturing and subsequent implement fracturing. It provides a good solution for developing tight oil reservoirs. The efficiency of this technology significantly depends on the injection performance of the fracturing fluid, and the ability of its liquid phase to penetrate the formation. According to the needs of energy storage fracturing, four surfactants were selected. Then, based on the performance evaluation of the four surfactants, the compositions of two surfactant systems were determined. The performance of slickwater fracturing fluids for energy storage hydraulic fracturing was evaluated. The mechanism of tight oil displacement in energy storage hydraulic fracturing was analyzed. The results showed that the compositions of oil–displacement agents 1 and 2 for energy storage fracturing were successfully acquired. The performance of oil–displacement agent 2 was slightly better than that of oil–displacement agent 1 at a concentration of 0.25 wt%. The defined composition of the fracturing fluid met requirements for energy storage hydraulic fracturing. It was demonstrated that the tight oil in small pores was effectively substituted by the fracturing fluid, and subsequently aggregated in the large pores. The tight oil displacement ratio increased with an increase in temperature, and the difference among the tight oil displacement ratios of tight sandstone cores increased with increases in their permeability differences. Full article

(This article belongs to the Special Issue Enhanced Oil Recovery for Unconventional Oil and Gas Reservoirs)

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19 pages, 8441 KiB

Open AccessArticle

Lattice Boltzmann Modeling of Spontaneous Imbibition in Variable-Diameter Capillaries

by Rundong Gong, Xiukun Wang, Lei Li, Kaikai Li, Ran An and Chenggang Xian

Energies 2022, 15(12), 4254; https://doi.org/10.3390/en15124254 - 9 Jun 2022

Cited by 6 | Viewed by 1798

Abstract

Previous micro-scale studies of the effect of pore structure on spontaneous imbibition are mainly limited to invariable-diameter capillaries. However, in real oil and gas reservoir formations, the capillary diameters are changing and interconnected. Applying the lattice Boltzmann color gradient two-phase flow model and the parallel computation of CPUs, we simulated the spontaneous imbibition in variable-diameter capillaries. We explored the reasons for the nonwetting phase snap-off and systematically studied the critical conditions for the snap-off in spontaneous imbibition. The effects of pore-throat aspect ratio, throat diameter, and the pore-throat tortuosity of the capillary on spontaneous imbibition were studied. Through analyzing the simulated results, we found that the variation in the capillary diameter produces an additional resistance, which increases with the increase in the pore-throat ratio and the pore-throat tortuosity of a capillary. Under the action of this additional resistance, the snap-off phenomenon sometimes occurs in the spontaneous imbibition, which makes the recovery efficiency of the non-wetting phase extremely low. In addition, the main factors affecting this phenomenon are the pore-throat ratio and the pore-throat tortuosity, which is different from the conventional concept of tortuosity. When the snap-off does not occur, the spontaneous imbibition velocity increases when the throat diameter increases and the pore-throat aspect ratio is fixed, and when the period increases, i.e., the diameter changing rate decreases, the spontaneous imbibition velocity also increases. In addition, when the capillary throat diameter is fixed, a bigger pore diameter and a smaller period of sine function both inhibit the speed of spontaneous imbibition. Full article

(This article belongs to the Special Issue Enhanced Oil Recovery for Unconventional Oil and Gas Reservoirs)

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