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New Progress in Unconventional Oil and Gas Development

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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: 31 October 2024 | Viewed by 9028

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Dr. Shan Wu

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Guest Editor

School of Resources and Environmental Engineering, Hefei University of Technology, Hefei, China
Interests: hydraulic fracturing models and experiments; microseismic and acoustic emission; low-frequency distributed acoustic sensing

Dr. Xiaoqiong Wang

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Guest Editor

Unconventional Natural Gas Institute, China University of Petroleum, Beijing, China
Interests: rock physics; rock failure mechanism; hydraulic fracturing; microseismic

Prof. Dr. Mianmo Meng

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Guest Editor

1. Hubei Key Laboratory of Marine Geological Resources, China University of Geosciences, Wuhan 430074, China 2. College of Marine Science and Technology, China University of Geosciences, Wuhan 430074, China
Interests: pore structure characterization; fluid occurrence; water–rock interaction; nuclear magnetic resonance; unconventional oil/gas
Special Issues, Collections and Topics in MDPI journals

Dr. Junrong Liu

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Guest Editor

School of Petroleum Engineering, China University of Petroleum, Qingdao, China
Interests: CO₂-enhanced oil recovery; CO₂ hydraulic fracturing; CCUS

Special Issue Information

Dear Colleagues,

Unconventional oil and gas, i.e., shale oil/gas, tight oil/gas, coalbed methane, natural gas hydrates, and geothermal energy play a key role in the energy future, as the non-renewable conventional energy decrease. In recent years, the rapid implementation of advanced theories and techniques promote the development of unconventional oil and gas. The new technologies contain horizontal drilling, hydraulic fracturing, and new enhanced oil recovery methods.

However, compared to conventional reservoirs, these unconventional systems have unique properties, i.e., low permeability (including a large number of nanopores), consist of inter-particle pore networks with very poor connectivity, strong anisotropy of rock mechanics properties, and so on, which complicate the application of all the technologies. In the past decade, new digital core and numerical methods, multiscale-multiphysics experimental methods, models, and theoretical methods are being continuously constructed to optimize all techniques from the perspective of a new mechanism.

This Special Issue aims to bring together original research articles and review articles highlighting recent advances in various subjects addressing new numerical, experimental, and theoretical approaches to developing unconventional oil and gas. We sincerely invite prospective authors to submit high-quality original articles or reviews regarding new progress in unconventional oil and gas development.

Potential topics include but are not limited to the following:

Experimental study of hydraulic fracturing;
Numerical study of hydraulic fracturing;
Optimization of fracturing technology;
Monitoring method of the fracture propagation process;
Characterization of multi-scale fractures;
Multiscale and multiphase flow in unconventional reservoirs;
Petrophysical models and experimental methods for unconventional reservoir;
Rock mechanical properties characterization for unconventional reservoir;
CCUS (Carbon capture, utilization, and storage) related to unconventional oil and gas development;
New enhanced oil/gas recovery methods and mechanism;
Drilling, completion, and related reservoir damage and stimulation;
Induced-risk assessment of reservoir development.

Dr. Shan Wu
Dr. Xiaoqiong Wang
Prof. Dr. Mianmo Meng
Dr. Junrong Liu
Guest Editors

Manuscript Submission Information

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Keywords

shale gas and oil
tight sandstone
hydraulic fracturing
EOR
rock physics

Published Papers (10 papers)

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Research

21 pages, 5763 KiB

Open AccessArticle

Preliminary Insight into Ice Melting, Surface Subsidence, and Wellhead Instability during Oil and Gas Extraction in Permafrost Region

by Xiaohui Zhou, Yinao Su, Yuanfang Cheng and Qingchao Li

Energies 2024, 17(6), 1292; https://doi.org/10.3390/en17061292 - 7 Mar 2024

Viewed by 544

Abstract

Oil and gas production in permafrost can effectively alleviate energy tensions. However, ice melting around wellbores and the accompanying wellhead instability affect the efficiency and safety of oil and gas development in permafrost. Moreover, the potential oil and gas leakage will damage the environment and the ecology of permafrost. Unfortunately, ice melting, formation subsidence, and wellhead behavior during this process have rarely been investigated in previous studies. In the present work, mechanical properties of permafrost were first experimentally investigated, which provided the basic parameter for subsequent numerical simulation. It was found that the ultimate strength gradually increased with the decreasing temperature, as well as the increasing confining pressure. Meanwhile, although the elastic modulus increased with decreasing temperature, it was less affected by confining pressure. Unlike other parameters, the Poisson’s ratio was hardly affected by temperature and confining pressure. Moreover, both the internal friction angle and the cohesion increased with decreasing temperature, but the influence degree varied within different temperature ranges. Then, ice melting, formation subsidence, and the instability behavior of the wellhead caused by the disturbance of the development operation were numerically explored. The investigation results show that the ice melting range in the reservoir section reached 8.06 m, which is much wider than that in other well sections. Moreover, failure of the cement–permafrost interface, caused by ice melting, resulted in a wellhead sinking of up to 1.350 m. Finally, the insulation effect of the vacuum-insulated casing showed that the temperature drop of the designed vacuum-insulated casing was much lower than that of the ordinary casing. When the fluid temperature within the wellbore was 70 °C, the temperature drop of the designed vacuum-insulated casing was 3.54 °C lower than that of the ordinary casing. This study provides support for maintaining wellhead stability during oil and gas extraction in permafrost for avoiding some environmental disasters (such as oil and gas leakage). Full article

(This article belongs to the Special Issue New Progress in Unconventional Oil and Gas Development)

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17 pages, 7143 KiB

Open AccessArticle

Research on Wellbore Stability in Deepwater Hydrate-Bearing Formations during Drilling

by Ting Sun, Zhiliang Wen and Jin Yang

Energies 2024, 17(4), 823; https://doi.org/10.3390/en17040823 - 9 Feb 2024

Viewed by 732

Abstract

Marine gas hydrate formations are characterized by considerable water depth, shallow subsea burial, loose strata, and low formation temperatures. Drilling in such formations is highly susceptible to hydrate dissociation, leading to gas invasion, wellbore instability, reservoir subsidence, and sand production, posing significant safety challenges. While previous studies have extensively explored multiphase flow dynamics between the formation and the wellbore during conventional oil and gas drilling, a clear understanding of wellbore stability under the unique conditions of gas hydrate formation drilling remains elusive. Considering the effect of gas hydrate decomposition on formation and reservoir frame deformation, a multi-field coupled mathematical model of seepage, heat transfer, phase transformation, and deformation of near-wellbore gas hydrate formation during drilling is established in this paper. Based on the well logging data of gas hydrate formation at SH2 station in the Shenhu Sea area, the finite element method is used to simulate the drilling conditions of 0.1 MPa differential pressure underbalance drilling with a borehole opening for 36 h. The study results demonstrate a significant tendency for wellbore instability during the drilling process in natural gas hydrate formations, largely due to the decomposition of hydrates. Failure along the minimum principal stress direction in the wellbore wall begins to manifest at around 24.55 h. This is accompanied by an increased displacement velocity of the wellbore wall towards the well axis in the maximum principal stress direction. By 28.07 h, plastic failure is observed around the entire circumference of the well, leading to wellbore collapse at 34.57 h. Throughout this process, the hydrate decomposition extends approximately 0.55 m, predominantly driven by temperature propagation. When hydrate decomposition is taken into account, the maximum equivalent plastic strain in the wellbore wall is found to increase by a factor of 2.1 compared to scenarios where it is not considered. These findings provide crucial insights for enhancing the safety of drilling operations in hydrate-bearing formations. Full article

(This article belongs to the Special Issue New Progress in Unconventional Oil and Gas Development)

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13 pages, 8084 KiB

Open AccessArticle

Lithofacies Characteristics of Gulong Shale and Its Influence on Reservoir Physical Properties

by Zongyan Han, Guiwen Wang, Hongliang Wu, Zhou Feng, Han Tian, Yingyi Xie and Hao Wu

Energies 2024, 17(4), 779; https://doi.org/10.3390/en17040779 - 6 Feb 2024

Viewed by 519

Abstract

The lithofacies characteristics of the Qingshankou Formation (K₂qn) shale in the Gulong Depression are crucial for oil exploration and development. This study investigates the K₂qn shale lithofacies characteristics and their impact on reservoir physical properties using scanning electron microscopy (SEM), high-pressure mercury injection (HPMI), and logging quantification. The results indicate that the main minerals in K₂qn shale are quartz, plagioclase, and clay. The sedimentary structures are classified into three types: laminated, layered, and massive. The K₂qn shale lithofacies can be categorized into 12 types based on a combination of lithology and sedimentary structure. The main types are laminated clayey shale, layered clayey shale, and layered felsic shale. The larger the average pore size of the K₂qn lithofacies, the stronger the heterogeneity of pore size distribution in space and the better the pore-to-throat connectivity. The impact of K₂qn shale lithofacies on reservoir physical properties is mainly due to differences in lithology, complemented by variations in the sedimentary structural model. Under certain diagenetic or tectonic conditions, a layered sedimentary structural model of lithofacies may not increase reservoir permeability. Generally, felsic and carbonate rocks in tidal flat environments promote the development of shale with high permeability and porosity, while lithofacies deposited in static water environments below the wave base in lake basins typically exhibit low permeability and porosity. The physical properties of a reservoir are primarily influenced by the differences in pore throat characteristics resulting from variations in lithology. Full article

(This article belongs to the Special Issue New Progress in Unconventional Oil and Gas Development)

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18 pages, 6199 KiB

Open AccessArticle

Experimental Study on Water-in-Heavy-Oil Droplets Stability and Viscosity Variations in the Dilution Process of Water-in-Heavy-Oil Emulsions by Light Crude Oil

by Yigang Liu, Jianhua Bai, Peipei Guo, Wei Zhang, Liguo Zhong, Chaohui Lyu, Yi Hao, Mengqi Zhang, Xiaodong Han and Peidong Bi

Energies 2024, 17(2), 332; https://doi.org/10.3390/en17020332 - 9 Jan 2024

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Abstract

The main objective of this study is to put forward effective schemes for alleviating reservoir choke caused by emulsification or Jamin’s effect using the dilution method by light crude oil, as well as sharply increased viscosity. In this study, water-in-heavy-oil (W/O) emulsions with varying water fractions were prepared with heavy oil from Bohai Bay, China. Mixtures of W/O emulsions and light crude oil samples (light oil and light heavy oil) with varied dilution ratio (1:9, 2:8, 3:7) are tested, respectively by the electron microscope and by the rheometer. W/O droplets’ distribution and viscosity variations are obtained to evaluate the emulsion stability and viscosity reduction effects by dilution. Results show that W/O droplets^, size distribution range increases with the increase of water fractions. W/O droplets with larger size tend to be broken first in the dilution process. Light oil could reduce emulsions’ viscosity more effectively than light heavy oil. Viscosity reduction mechanisms by dilution could be concluded as the synergistic effects of dissolving heavy components and weakening oil–water film stability. Therefore, light oil is suggested as the optimal one for solving formation plugging. The poor performance of Richardson model is related to the re-emulsification between free water and crude oil favored by light heavy oil, and demulsification favored by light oil. The modified model shows a significant improvement in prediction accuracy, especially for W/O emulsions with large water fractions. This study demonstrates a promising and practical strategy of solving heavy oil well shutdown problems and viscosity increasing by injecting light crude oil in the thermal stimulation. Full article

(This article belongs to the Special Issue New Progress in Unconventional Oil and Gas Development)

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20 pages, 5896 KiB

Open AccessArticle

An Analytical–Numerical Model for Determining “Drill String–Wellbore” Frictional Interaction Forces

by Michał Bembenek, Yaroslav Grydzhuk, Bożena Gajdzik, Liubomyr Ropyak, Mykhaylo Pashechko, Orest Slabyi, Ahmed Al-Tanakchi and Tetiana Pryhorovska

Energies 2024, 17(2), 301; https://doi.org/10.3390/en17020301 - 7 Jan 2024

Cited by 1 | Viewed by 926

Abstract

Currently, drilling of directional oil and gas wells under complex technical-technological and mining-geological conditions requires the use of drill pipes made of various materials. In turn, to choose rational modes of strengthening drill pipes and drill string layouts, information on the contact forces and friction forces of the drill string pipes on boreholes is necessary. Drill pipe curved sections friction with boreholes and drill bit resistance moment changes are the main causes of uneven rotation of a drill string during rotary or combined drilling methods and the occurrence of parametric oscillations. To reduce the cost of mechanical energy for well wiring, it is necessary to take into account the “drill string–borehole rocks” force interaction to estimate the magnitude of the frictional forces and their influence on the technological parameters of the drilling process. To solve this problem, mathematical models of “conventionally vertical and inclined drill string sections–borehole” were built. Based on the industrial data, an analysis of the force interaction of a deformed drill string composed of pipes made of different materials (aluminum, titanium, steel) was carried out. Analytical dependences were obtained for determining the contact forces and friction of the pipes on boreholes. A numerical study of the change of these power factors depending on the depth of the well under conditions of intensive vibration loading was carried out. The amplitude values of these forces, the frequency of their change for good sections, as well as the places for the most rational installation of drill pipes in the layout of the drill string were estimated. It was established that the intensity of contact and friction forces for steel drill pipes is greater than for titanium or aluminum ones. It is shown that the greater impact of a solid steel string on contact forces and frictional forces compared to a layout with sections of titanium or aluminum pipes in the range of vibration frequencies of 8–22 Hz corresponds to a bit rotation frequency of 70–80 rpm. The practical application of the obtained research results will contribute to the improvement of technical and economic indicators of the well drilling process. Full article

(This article belongs to the Special Issue New Progress in Unconventional Oil and Gas Development)

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19 pages, 2104 KiB

Open AccessArticle

Seismic Anisotropy Estimation Using a Downhole Microseismic Data Set in a Shale Gas Reservoir

by Changpeng Yu, Yaling Zhu and Serge Shapiro

Energies 2023, 16(23), 7857; https://doi.org/10.3390/en16237857 - 30 Nov 2023

Viewed by 669

Abstract

Shale anisotropy has a significant impact on the data processing and interpretation of microseismic monitoring in shale gas reservoirs. A geology- and rock-physics-constrained approach to estimating shale anisotropy using down-hole microseismic data sets is proposed in this study and is applied to the case of Horn River shale. A priori knowledge of shale anisotropy is obtained by integrating geological analyses and rock physics studies. This knowledge serves as an important constraint when building the initial model, minimizing the uncertainties and evaluating the results. The application to Horn River shale shows that the optimized anisotropic velocity model reduces the time misfit by about 65% compared to the originally provided velocity model. As the relocated perforation shot indicates, the event locations are significantly improved. The results also show that a high fraction of clay mineral results in strong fabric anisotropy in the Fort Simpson formation, whereas the quartz-rich shale gas reservoirs (Muskwa and Otter Park formations) show weaker fabric anisotropy. The percentage of velocity anisotropy in Horn River shale can be up to 40%. The fabric anisotropy of shale derived from the downhole microseismic data set is comparable with that of laboratory experiments. This demonstrates that downhole microseismic monitoring, as a quasi in situ experiment, has the potential to contribute to a better understanding of subsurface anisotropy beyond the laboratory. In addition, microseismic measurements of shale anisotropy are conducted in the seismic frequency band and are thus more applicable for further seismic applications. Full article

(This article belongs to the Special Issue New Progress in Unconventional Oil and Gas Development)

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14 pages, 3851 KiB

Open AccessArticle

Iso-Permeability Point Trail Method to Determine the Relative Permeability Curve for a New Amphiphilic Polymer Flooding

by Xudong Wang, Binshan Ju, Yi Jin and Yapeng Tian

Energies 2023, 16(21), 7362; https://doi.org/10.3390/en16217362 - 31 Oct 2023

Viewed by 586

Abstract

Amphiphilic-polymer flooding, which can increase water viscosity, decrease oil viscosity, and improve oil displacement efficiency, is a promising oil exploitation method for heavy oil. Due to oil–water emulsification, shear-thinning, and changes in oil viscosity when determining the relative permeability data of new amphiphilic polymers, the conventional J.B.N. method is not accurate. This paper presents a new method called the iso-permeability point trial method to determine the relative permeability curve by combining the J.B.N. method, the Corey model, and the relationship between water saturation and the relative permeability ratio. To avoid using polymer viscosity, a mathematical equation was derived based on the characteristics of the relative permeability curve. The results indicate that the new method is feasible and the obtained curve is more reasonable and smooth. The influence of concentration, permeability, and oil viscosity on amphiphilic-polymer displacement relative permeability was also analyzed, demonstrating that under the same water saturation, the water relative permeability is lower than that of water flooding but the oil relative permeability is bigger, which manifests as the iso-permeability point moves to the right and results in a lower residual oil saturation. In addition, the aforementioned trends are more obvious when the amphiphilic-polymer concentration is high, formation permeability is low, and oil viscosity is low. Full article

(This article belongs to the Special Issue New Progress in Unconventional Oil and Gas Development)

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11 pages, 3529 KiB

Open AccessArticle

Characterization of Asphaltene Deposition Behavior in Diluted Heavy Oil under High-Pressure Conditions

by Zuguo Yang, Xinpeng Wu, Jixiang Guo, Jianjun Zhang, Ruiying Xiong, Lei Liu and Wyclif Kiyingi

Energies 2023, 16(19), 6780; https://doi.org/10.3390/en16196780 - 23 Sep 2023

Cited by 2 | Viewed by 786

Abstract

Some oil wells in the Tahe oilfield have been reported to produce extremely heavy oil due to asphaltene deposition. To enhance the flow of crude oil through the wellbore, engineers adopted the use of light oil from nearby wells to dissolve the heavy crude in the wells’ sections to maximize recovery from the Tahe oilfield. However, this mixing has led to the problem of accelerated asphaltene deposition, which often blocks the wellbore in the process. In this research, the factors that influence the stability of diluted heavy oil, temperature, and mixing ratio on asphaltene deposition characteristics under high pressure are studied using a high-temperature and high-pressure crude oil flow property experimental device based on the differential pressure method. The results under high pressure show that the initial deposition pressure of asphaltene decreases as the experimental temperature increases. With an increase in the mixing light oil ratio, the initial deposition pressure of diluted heavy oil increases, and the deposition trend of asphaltene strengthens. The asphaltene accumulation and deposition will be aggravated by filling quartz sand and pipe diameter changes. The research here is helpful to understand the deposition characteristics of asphaltene during the production of diluted heavy oil. It offers significant guidance in the prevention and control of asphaltene precipitation in heavy oil wells. Full article

(This article belongs to the Special Issue New Progress in Unconventional Oil and Gas Development)

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11 pages, 4604 KiB

Open AccessArticle

Effects of Mineral Composition on Movable Fluid Porosity in Micro-Nanoscale Porous Media

by Quanqi Dai, Yangwen Zhu, Yingfu He, Rui Wang, Da Zheng, Yinbang Zhou, Yunfeng Liu, Guiwen Wang and Hao Wu

Energies 2023, 16(13), 5166; https://doi.org/10.3390/en16135166 - 5 Jul 2023

Viewed by 846

Abstract

In natural micro-nanoscale porous media, the movable fluid porosity can effectively represent storage and permeable properties, but various mineral compositions have complicated effects on it. Taking saline lacustrine shale as an example, this study researched the effects of mineral composition on movable fluid porosity, based on nuclear magnetic resonance (NMR), focused ion beam (FIB), and x-ray diffraction (XRD) experiments. The results show that movable fluid porosity exhibits a stronger dependence on porosity than movable fluid saturation does. Micropores (<100 nm) and macropores (>1000 nm) are mostly developed in silicate and gypsum minerals, and have a highly heterogeneous distribution. In contrast, carbonate intercrystalline pores are dominated by mesopores (100−1000 nm), and behave strongly heterogeneously. Many mesopores play a positive role in generating highly movable fluid porosity, but the development of micropores and macropores is not conducive to an increase in movable fluid porosity. Overall, a significant negative effect is observed between silicate mineral content and movable fluid porosity, and carbonate mineral content has a strong positive effect on movable fluid porosity, whereas movable fluid porosity exhibits a relatively small reduction with an increase in the gypsum. Full article

(This article belongs to the Special Issue New Progress in Unconventional Oil and Gas Development)

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11 pages, 7488 KiB

Open AccessArticle

Experimental Study on Hydraulic Fracture Initiation and Propagation in Hydrated Shale

by Guifu Duan, Jianye Mou, Yushi Zou, Budong Gao, Lin Yang and Yufei He

Energies 2022, 15(19), 7110; https://doi.org/10.3390/en15197110 - 27 Sep 2022

Cited by 1 | Viewed by 1167

Abstract

Shale reservoirs contain a certain amount of clay minerals, which can hydrate through imbibition when in contact with various water-based fluids during drilling and completion. Shale hydration can lead to structural changes in the shale such as the expansion of bedding planes and propagation of microfractures, consequently affecting the initiation and propagation of hydraulic fractures. However, the effect of shale hydration under confining pressure on hydraulic fracture propagation and stimulation effect is still unclear. To this end, a novel experimental method integrating shale hydration and hydraulic fracturing was proposed based on the laboratory triaxial hydraulic fracturing simulation system. This method enables a more realistic simulation of shale hydration and hydraulic fracturing process happening in downhole conditions. The experimental results show that under simulated reservoir conditions, water imbibition increases over time with the imbibition rate reaching its peak within 24 h. The breakdown pressure, number of fractures, and complexity of fractures are positively correlated with imbibition time. The increase in fracture complexity could be attributed to the increase in the number of fractures. In contrast, imbibition pressure (injection pressure for imbibition) has little influence on water imbibition. For specimens under different imbibition pressure, the breakdown pressure and the number of fractures are close, and the complexity of fractures does not change prominently; all are T-shaped fractures. It is believed that the closure of microfractures under confining pressure caused by hydration is the main reason for the increase in breakdown pressure. Higher breakdown pressure means higher net pressure in the wellbore, which facilitates fracture initiation where the breakdown pressure is higher. Therefore, shale hydration is conducive to the initiation of multiple fractures, thus increasing the number and complexity of fractures. Full article

(This article belongs to the Special Issue New Progress in Unconventional Oil and Gas Development)

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