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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: 10 July 2024 | Viewed by 15518

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Prof. Dr. Wei Liu

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Guest Editor

College of Petroleum Engineering, China University of Petroleum (Beijing), Beijing 102249, China
Interests: rock mechanics; wellbore instability; sand production; hydraulic fracturing; cement sheath integrity

Prof. Dr. Tiankui Guo

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Guest Editor

School of Petroleum Engineering, China University of Petroleum, East China, Qingdao 266580, China
Interests: hydraulic fracturing; fracture propagation
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Dr. Ming Chen

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Guest Editor

State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum, Beijing 102249, China
Interests: hydraulic fracturing; rock mechanics
Special Issues, Collections and Topics in MDPI journals

Special Issue Information

Dear Colleagues,

The past decades have witnessed worldwide growth in the exploration and development of deep and ultra-deep oil and gas resources due to the increasing energy demand and evolving technologies. Despite considerable technological advancements, well drilling and completion in increasingly complex geological environment, i.e., high temperature, high pore pressure, high in situ stress, is still a non-trivial task. In particular, wellbore instability, sand production and insufficient hydraulic fracturing stimulation are still major obstacles for achieving cost-efficient oil and gas recovery from deep and ultra-deep reservoirs. Within this aspect, revealing the mechanical (deformation and failure) behavior of different reservoir rocks through experimental, analytical or numerical modeling, i.e., rock mechanics, plays an important role.

With this Special Issue on “Oil and Gas Drilling Rock Mechanics and Engineering”, we aim to attract original research articles and review papers that cover research on new experimental, analytical or numerical modeling methods and results in petroleum-related rock mechanics. Research topics may include (but are not limited to) the following:

Wellbore instability prediction and control;
Sand production prediction and control;
Hydraulic fracturing in various reservoir formations;
Cement sheath failure prediction and control.

We look forward to receiving your contributions.

Prof. Dr. Wei Liu
Prof. Dr. Tiankui Guo
Dr. Ming Chen
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. Processes is an international peer-reviewed open access monthly 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

rock mechanics
wellbore instability
sand production
hydraulic fracturing
cement sheath integrity

Published Papers (9 papers)

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Research

14 pages, 5133 KiB

Open AccessArticle

Research and Applications of New Fracturing Technology in Low-Abundance and Greater-Depth Well LN-1 Reservoirs

by Minghua Shi, Dechun Chen, Liangliang Wang, Tengfei Wang, Wei Song and Jiexiang Wang

Processes 2024, 12(3), 482; https://doi.org/10.3390/pr12030482 - 27 Feb 2024

Viewed by 609

Abstract

The upper Shasi reservoir in the LN block is characterized by low abundance and greater depth, low porosity, low permeability, and low pressure. Due to high water injection pressure, the LN block has been developed in an elastic way. The natural productivity of oil wells in this block is low, but the productivity can be improved after fracturing. However, the field development effects show that the oil well has high initial production, but rapid decline and rapid pressure drop. At present, the recovery factor of this block is only 0.38%, and it is difficult to realize the economic and effective development of a difficult-to-develop block by conventional fracturing technology. Based on the geological characteristics of the LN block and the fracturing experience of adjacent wells, the fracturing process is optimized and the key fracturing parameters are determined in combination with the sand body distribution and logging curve of well LN-1. Due to the low-pressure coefficient and medium water sensitivity of well LN-1, a new high-efficiency stimulation fracturing fluid system was selected and the formula of the fracturing fluid system was formed. The cluster perforating process is optimized according to reservoir differences, and the perforating “sweet spot” is optimized. Based on the sand body spread point of well LN-1, the high diversion channel technology and the temporary plugging and turning fracturing technology are selected to form a new fracturing and stimulation technology suitable for this kind of oil reservoir. A fracturing test was performed in layers 17# (electrical sequencing number) and 22# of well LN-1. The initial oil production was 12.5 t/d, and the stimulation effect was significantly higher than the 8.3 t/d (general fracturing) of adjacent wells. At present, the well LN-1 has been producing steadily for more than six months, and the results of this work can provide technical guidance for the efficient development of low-abundance and greater-depth oil reservoirs that are difficult to develop. Full article

(This article belongs to the Special Issue Oil and Gas Drilling Rock Mechanics and Engineering)

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23 pages, 10385 KiB

Open AccessArticle

An Integrated Model for Acid Fracturing without Prepad Considering Wormhole Growth

by Yuxin Chen, Haibo Wang, Fengxia Li, Tong Zhou, Ning Li and Yu Bai

Processes 2024, 12(3), 429; https://doi.org/10.3390/pr12030429 - 20 Feb 2024

Viewed by 588

Abstract

Acid fracturing is an effective stimulation technology that is widely applied in carbonate reservoirs. An integrated model for acid fracturing without prepad treatment has been established. Compared with the previous models which use prepad for generating hydraulic fractures, this model can simultaneously simulate the fracture propagation and the acid etching of fracture surfaces, as well as the wormhole growth during acid fracturing. The influences of some essential factors have been studied through a series of numerical simulations, and the main conclusions are as follows. First, increasing the injected acid volume can expand the size of the formed hydraulic fractures and extend the propagation distance of the wormhole. Increasing the injected acid volume can also expand the etched width and extend the effective distance of the injected acid. Second, a high injection rate impels more acid to flow into the depth of a fracture before infiltration and reaction, resulting in the augmentation of a hydraulic fracture’s geometric size and the extension of the effective distance. But the maximum etched width decreases as the injection rate rises. A high injection rate can also enable wormholes to grow in the natural fracture area farther away from the hydraulic fracture inlet, but shorten the length of the original wormhole near the hydraulic fracture inlet. Third, an increase in acid viscosity can enlarge the geometric size of the hydraulic fracture and reduce the propagation distance of wormholes. In addition, an increase in the acid viscosity blocks the acid flow from fracture inlet to tip, reducing the effective distance of acid fracturing. Fourth, the natural fracture is the vital inducement of wormhole growth, and wormholes are apt to grow in the natural fracture area. Moreover, the geometric size of the hydraulic fracture and the effective distance of acid fracturing decrease with an increasing number of natural fractures. This research can provide a reference for field applications of acid fracturing without prepad. Full article

(This article belongs to the Special Issue Oil and Gas Drilling Rock Mechanics and Engineering)

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13 pages, 3449 KiB

Open AccessArticle

Diagnostics of Secondary Fracture Properties Using Pressure Decline Data during the Post-Fracturing Soaking Process for Shale Gas Wells

by Jianfa Wu, Liming Ren, Cheng Chang, Shuyao Sheng, Jian Zhu, Sha Liu, Weiyang Xie and Fei Wang

Processes 2024, 12(2), 239; https://doi.org/10.3390/pr12020239 - 23 Jan 2024

Viewed by 7831

Abstract

In addition to main fractures, a large number of secondary fractures are formed after the volumetric fracturing of shale gas wells. The secondary fracture properties are so complex, that it is difficult to identify and diagnose by direct monitoring methods. In this study, a new approach to model and diagnose secondary fracture properties is presented. First, a new pressure decline model, which is composed of four interconnected domains, i.e., wellbore, main fractures, secondary fractures, and reservoir matrix pores, is built. Then, the fracturing fluid pumping and post-fracturing soaking processes are simulated. The simulated pressure derivatives reflect five fracture-dominated flow regimes, which correspond to multiple alternating positive and negative slopes of the pressure decline derivative. The results of sensitivity simulation show that the density, permeability, and width of secondary fractures are the main controlling factors affecting the size ratio. Finally, based on the simulated pressure decline characteristics, a diagnostic method for the identification and analysis of secondary fracture properties is formed. This method is then applied to three platform wells in the Changning shale gas field in China. This study builds the correlation between the secondary fracture properties and the shut-in pressure decline characteristics, and also provides a theoretical method for comprehensive post-fracturing evaluation of shale gas horizontal wells. Full article

(This article belongs to the Special Issue Oil and Gas Drilling Rock Mechanics and Engineering)

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17 pages, 9856 KiB

Open AccessArticle

Simulation Study on the Prediction of Macroscale Young’s Modulus Based on the Mesoscale Characteristics of Tight Glutenite Reservoirs

by Fengchao Xiao, Shicheng Zhang, Xiaolun Yan, Xuechen Li, Xinfang Ma and Cong Xiao

Processes 2024, 12(1), 185; https://doi.org/10.3390/pr12010185 - 14 Jan 2024

Viewed by 843

Abstract

To obtain the macroscale Young’s modulus of glutenite under gravel inclusions, a numerical simulation of macroscale Young’s modulus prediction based on the mesoscale characteristics of glutenite was carried out. Firstly, the micron indentation test was used to obtain the meso-mechanical parameters of gravel and matrix in glutenite to ensure the reasonableness of the numerical simulation parameter settings; secondly, a two-dimensional glutenite physical model generation method based on the secondary development of Python was put forward; and then, the macroscale Young’s modulus variation rule of glutenite under different gravel sizes, particle size ratios, and content characteristics were analyzed using the finite element method (FEM). The results show that Young’s modulus of gravel is larger than Young’s modulus of the matrix, and Young’s modulus of different gravel and matrix has some differences. The gravel content is the main controlling factor affecting the macroscale Young’s modulus of glutenite; the gravel content and Young’s modulus of glutenite show a strong positive correlation, and the gravel size and particle size ratio have less influence on the macroscale Young’s modulus of glutenite. The difference in Young’s modulus between gravel and matrix causes the formation of local stress concentrations during loading and compression of glutenite. The smaller the gravel grain size, the higher the degree of non-uniformity of the grain size, the more likely it is to form higher local stresses. The results of the study provide a new prediction method for the prediction of the macroscale Young’s modulus of a glutenite reservoir. Full article

(This article belongs to the Special Issue Oil and Gas Drilling Rock Mechanics and Engineering)

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13 pages, 5338 KiB

Open AccessArticle

Model and Analysis of Pump-Stopping Pressure Drop with Consideration of Hydraulic Fracture Network in Tight Oil Reservoirs

by Mingxing Wang, Jian Zhu, Junchao Wang, Ziyang Wei, Yicheng Sun, Yuqi Li, Jiayi Wu and Fei Wang

Processes 2023, 11(11), 3145; https://doi.org/10.3390/pr11113145 - 3 Nov 2023

Viewed by 502

Abstract

The existing pump-stopping pressure drop models for the hydraulic fracturing operation of tight oil reservoirs only consider the main hydraulic fracture and the single-phase flow of fracturing fluid. In this paper, a new pump-stopping pressure drop model for fracturing operation based on coupling calculation of the secondary fracture and oil-water two-phase flow is proposed. The physical model includes the horizontal wellbore, the fracture network and the tight oil reservoir. Through the numerical simulation and calculation, the wellbore afterflow performance, the crossflow performance between the main hydraulic fracture and the secondary fracture, the fracturing fluid leakoff and the oil-water replacement after termination of pumping are obtained. The pressure drop characteristic curve is drawn out by the bottom-hole flow pressure calculated through the numerical simulation, and a series of analyses are carried out on the calculated pressure drop curve, which is helpful to diagnose the -oil-water two-phase flow state and the fracture closure performance under the control of the fracture network after hydraulic fracturing pumping. Finally, taking a multi-stage fractured horizontal well in a tight oil reservoir in the Junggar basin, China as an example, the pump-stopping pressure drop data of each stage after hydraulic fracturing are analyzed. Through the history fitting of the pressure drop characteristic curve, the key parameters such as fracture network parameters, which include the half-length of main hydraulic fracture, the conductivity of main hydraulic fracture and the density of secondary fracture, the fracture closure pressure are obtained by inversion, thus, the hydraulic fracturing effect of fractured horizontal well in tight oil reservoirs is further quantified. Full article

(This article belongs to the Special Issue Oil and Gas Drilling Rock Mechanics and Engineering)

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26 pages, 18734 KiB

Open AccessArticle

Thermo-Mechanical Numerical Analysis of Stress and Damage Distribution within the Surrounding Rock of Underground Coal Gasification Panels

by Pengfei Wang, Jingen Deng, Wei Liu, Qiangzhong Xiao, Qian Lv, Yan Zhang and Youlin Hou

Processes 2023, 11(9), 2521; https://doi.org/10.3390/pr11092521 - 22 Aug 2023

Viewed by 1100

Abstract

Underground coal gasification (UCG) is a promising technology for extracting synthesis gas from coal seams through in situ gasification. This study aims to investigate the thermo-mechanical behavior and integrity of the surrounding rock in the gasification vicinity to facilitate safe and efficient UCG operations. Rock property testing experiments are conducted under varying temperature conditions, revealing significant temperature dependencies for the thermal and mechanical parameters. A thermo-mechanical coupling model is developed to analyze the stress and damage distribution near the gasification chamber. The influence of the temperature dependency of stress states and failure risks during the gasification process is evaluated. In addition, the effects of panel orientation, chamber width, maintaining duration, operating temperature and operating pressure on the failure behavior of the gasification surrounding rocks are illustrated through parametric analysis. The findings have practical implications for the design and assessment of UCG processes, enhancing the safety and efficiency of coal gasification operations. Full article

(This article belongs to the Special Issue Oil and Gas Drilling Rock Mechanics and Engineering)

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14 pages, 6455 KiB

Open AccessArticle

Numerical Simulation of Hydraulic Fracture Propagation in Conglomerate Reservoirs: A Case Study of Mahu Oilfield

by Yuting Pan, Xinfang Ma, Jianmin Li, Bobo Xie and Dong Xiong

Processes 2023, 11(7), 2073; https://doi.org/10.3390/pr11072073 - 12 Jul 2023

Viewed by 799

Abstract

Mahu conglomerate oilfield has strong heterogeneity. Currently, large-scale hydraulic fracturing is commonly used for reservoir reconstruction. The geometry of hydraulic fractures is influenced by gravel. By referring to the scanning and logging results of a conglomerate reservoir, and considering the characteristics of gravel development in the Mahu Oilfield reservoir, python programming is used to establish a finite element model containing a matrix, bonding interface, and gravel, which considers the random distribution of gravel position and size. The model uses cohesive element global embedding to study the geometry of a hydraulic fracture. The results show that the hydraulic fracture in the gravel reservoir mainly spreads around the gravel, and the propagation path of the hydraulic fracture is affected by the horizontal stress difference. When the interfacial bonding strength is greater than 2 MPa, the conglomerate is more likely to be penetrated by hydraulic fractures, or the hydraulic fractures stop expanding after entering the conglomerate. The strength of the conglomerate largely determines whether hydraulic fractures can pass through it. When the strength of gravel is greater than 7 MPa, hydraulic fractures will stop expanding after entering the gravel. During the hydraulic fracturing process of conglomerate reservoirs, using a large injection rate can result in longer hydraulic fractures and larger fracture volumes. Full article

(This article belongs to the Special Issue Oil and Gas Drilling Rock Mechanics and Engineering)

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16 pages, 7276 KiB

Open AccessArticle

Coupled Thermal-Hydraulic-Mechanical Modeling of Near-Well Stress Evolution in Naturally Fractured Formations during Drilling

by Yong Song, Zhenlin Wang, Wei Wang, Peirong Yu, Gang Chen, Jiaying Lin, Bolong Zhu and Xuyang Guo

Processes 2023, 11(6), 1744; https://doi.org/10.3390/pr11061744 - 7 Jun 2023

Cited by 2 | Viewed by 908

Abstract

Naturally fractured formations usually have strong heterogeneities. Drilling and production operations in such formations can involve unwanted formation failure risks such as wellbore collapse and wellbore fracturing. This study presents a coupled thermal-hydraulic-mechanical numerical model for near-well stress evolutions during drilling in naturally fractured formations. The evolution of pressure, temperature, and geo-mechanical responses on the wellbore wall and in the near-well region is simulated. The effects of wellbore pressure, internal friction angle, and natural fracture length on formation rock risks are discussed. A failure index is used to quantify the formation rock failure risks. The existence of natural fractures magnifies the heterogeneous system response induced by drilling. Increasing the wellbore pressure from a relatively low value can improve the support for the wellbore wall, which reduces the failure risks caused by shearing. In mechanically weak formations, the effect of natural fractures on formation rock failure becomes more significant. When the natural fracture length is large, the near-well region tends to have greater failure risks as the formations become more mechanically weak. This study provides a quantitative understanding of the effects of drilling and formation parameters on failure risks. Full article

(This article belongs to the Special Issue Oil and Gas Drilling Rock Mechanics and Engineering)

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11 pages, 4696 KiB

Open AccessArticle

Expanding Measuring Range of LWD Resistivity Instrument in High Permittivity Layers

by Chengquan Gao, Dong Wu, Jichun Liu, Quan He and Rui Deng

Processes 2023, 11(4), 1175; https://doi.org/10.3390/pr11041175 - 11 Apr 2023

Cited by 1 | Viewed by 1222

Abstract

The effective measuring range of an electromagnetic wave resistivity instrument used in logging while drilling (LWD) is small, and the resistivity measurement is greatly influenced by the dielectric constant, especially in high-dielectric-constant formations. In this paper, the response characteristics of the instrument under a high dielectric constant are investigated by a numerical simulation algorithm, and the resistivity conversion method is determined. The results show that the higher the working frequency of the electromagnetic wave resistivity instrument while drilling, and the greater the formation of background resistivity, the greater the influence of the dielectric constant on the logging response. The existence of the dielectric constant will cause the phase shift and amplitude attenuation of the measured signal to migrate, and this migration is proportional to the formation resistivity and the dielectric constant. According to this rule, the resistivity–permittivity response library is established, and the formation permittivity is calculated by the inversion of the library. On the basis of obtaining the formation permittivity, the migration of the logging signal permittivity is corrected, the influence of the dielectric constant is eliminated, and the measuring precision and measuring range of the instrument in the high-dielectric-constant formation are enlarged. Full article

(This article belongs to the Special Issue Oil and Gas Drilling Rock Mechanics and Engineering)

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