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Petroleum Engineering in Oil and Gas Production: Advances in Theory and Operation

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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 (20 September 2023) | Viewed by 15540

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Dr. Xingguang Xu

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Hubei Key Laboratory of Oil and Gas Exploration and Development Theory and Technology, China University of Geosciences, Wuhan 430074, China
Interests: enhanced oil and gas recovery; CCUS; oilfield chemistry; interfacial behavior; molecular dynamics
Special Issues, Collections and Topics in MDPI journals

Dr. Kun Xie

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School of Petroleum Engineering, Northeast Petroleum University, Daqing 163318, China
Interests: enhanced oil recovery; oil and gas fields

Dr. Yang Yang

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Department of Petroleum Engineering, College of Energy, Chengdu University of Technology, Chengdu 610059, China
Interests: enhanced oil and gas recovery; reservoir stimulation; oilfield chemistry

Special Issue Information

Dear Colleagues,

Despite the increasing interest in renewable energy, oil and gas remain the predominant energy sources that spur economic growth. Along with escalating energy demand, the rapid decline in conventional oil and gas reservoirs introduces additional challenges to oil and gas supplies. Over the past decade, significant research progress has been made, with the intention of stimulating oil and its production from unconventional reservoirs that either have undesirable properties or harsh conditions.

Research papers in this Special Issue focus on recent advances in the basic theory and field practice of oil and gas production from (1) reservoirs that present unsatisfactory properties, such as tight rocks and extreme reservoir heterogeneity with fractures; (2) reservoirs that possess challenging conditions, including high temperature, high salinity, high oil viscosity and deep water. Review papers focusing on state-of-the-art prospectives that provide enlightening guidelines to the oil and gas production community will also be considered.

Dr. Xingguang Xu
Dr. Kun Xie
Dr. Yang Yang
Guest Editors

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Keywords

oil and gas production
unconventional reservoirs
reservoirs with harsh conditions
theory and operation

Published Papers (12 papers)

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Research

14 pages, 4641 KiB

Open AccessArticle

Numerical Modeling of Shale Oil Considering the Influence of Micro- and Nanoscale Pore Structures

by Qiquan Ran, Xin Zhou, Dianxing Ren, Jiaxin Dong, Mengya Xu and Ruibo Li

Energies 2023, 16(18), 6482; https://doi.org/10.3390/en16186482 - 8 Sep 2023

Cited by 1 | Viewed by 659

Abstract

A shale reservoir is a complex system with lots of nanoscale pore throat structures and variable permeability. Even though shale reservoirs contain both organic and inorganic matter, the slip effect and phase behavior complicate the two-phase flow mechanism. As a result, understanding how microscale effects occur is critical to effectively developing shale reservoirs. In order to explain the experimental phenomena that are difficult to describe using classical two-phase flow theory, this paper proposes a new simulation method for two-phase shale oil reservoirs that takes into account the microscale effects, including the phase change properties of oil and gas in shale micro- and nanopores, as well as the processes of dissolved gas escape, nucleation, growth and aggregation. The presented numerical simulation framework, aimed at comprehending the dynamics of the two-phase flow within fractured horizontal wells situated in macroscale shale reservoirs, is subjected to validation against real-world field data. This endeavor serves the purpose of enhancing the theoretical foundation for predicting the production capacity of fractured horizontal wells within shale reservoirs. The impact of capillary forces on the fluid dynamics of shale oil within micro- and nanoscale pores is investigated in this study. The investigation reveals that capillary action within these micro- and nanoscale pores of shale formations results in a reduction in the actual bubble point pressure within the oil and gas system. Consequently, the reservoir fluid persists in a liquid monophasic state, implying a constrained mobility and diminished flow efficiency of shale oil within the reservoir. This constrained mobility is further characterized by a limited spatial extent of pressure perturbation and a decelerated pressure decline rate, which are concurrently associated with a relatively elevated oil saturation level. Full article

(This article belongs to the Special Issue Petroleum Engineering in Oil and Gas Production: Advances in Theory and Operation)

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19 pages, 2265 KiB

Open AccessArticle

Estimation of Free and Adsorbed Gas Volumes in Shale Gas Reservoirs under a Poro-Elastic Environment

by Reda Abdel Azim, Abdulrahman Aljehani and Saad Alatefi

Energies 2023, 16(15), 5798; https://doi.org/10.3390/en16155798 - 4 Aug 2023

Cited by 1 | Viewed by 803

Abstract

Unlike conventional gas reservoirs, fluid flow in shale gas reservoirs is characterized by complex interactions between various factors, such as stress sensitivity, matrix shrinkage, and critical desorption pressure. These factors play a crucial role in determining the behavior and productivity of shale gas reservoirs. Stress sensitivity refers to the stress changes caused by formation pressure decline during production, where the shale gas formation becomes more compressed and its porosity decreases. Matrix shrinkage, on the other hand, refers to the deformation of the shale matrix due to the gas desorption process once the reservoir pressure reaches the critical desorption pressure where absorbed gas molecules start to leave the matrix surface, causing an increase in shale matrix porosity. Therefore, the accurate estimation of gas reserves requires careful consideration of such unique and complex interactions of shale gas flow behavior when using a material balance equation (MBE). However, the existing MBEs either neglect some of these important parameters in shale gas reserve analysis or employ an iterative approach to incorporate them. Accordingly, this study introduces a straightforward modification to the material balance equation. This modification will enable more accurate estimation of shale gas reserves by considering stress sensitivity and variations in porosity during shale gas production and will also account for the effect of critical desorption pressure, water production, and water influx. By establishing a linear relationship between reservoir expansion and production terms, we eliminate the need for complex and iterative calculations. As a result, this approach offers a simpler yet effective means of estimating shale gas reserves without compromising accuracy. The proposed MBE was validated using an in-house finite element poro-elastic model which accounts for stress re-distribution and deformation effects during shale gas production. Moreover, the proposed MBE was tested using real-field data of a shale gas reservoir obtained from the literature. The results of this study demonstrate the reliability and usefulness of the modified MBE as a tool for accurately assessing free and adsorbed shale gas volumes. Full article

(This article belongs to the Special Issue Petroleum Engineering in Oil and Gas Production: Advances in Theory and Operation)

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12 pages, 4755 KiB

Open AccessArticle

Study of the Wellbore Instability Mechanism of Shale in the Jidong Oilfield under the Action of Fluid

by Xiaofeng Xu, Chunlai Chen, Yan Zhou, Junying Pan, Wei Song, Kuanliang Zhu, Changhao Wang and Shibin Li

Energies 2023, 16(7), 2989; https://doi.org/10.3390/en16072989 - 24 Mar 2023

Viewed by 1053

Abstract

Wellbore instability is the primary technical problem that restricts the low-cost drilling of long-interval horizontal wells in the shale formation of the Jidong Oilfield. Based on the evaluation of the mineral composition, structure and physicochemical properties of shale, this paper investigates the mechanical behavior and instability characteristics of shale under fluid action by combining theoretical analysis, experimental evaluation and numerical simulation. Due to the existence of shale bedding and microcracks, the strength of shale deteriorates after soaking in drilling fluid. The conductivity of the weak surface of shale is much higher than that of the rock matrix. The penetration of drilling fluid into the formation along the weak surface directly reduces the strength of the structural surface of shale, which is prone to wellbore collapse. The collapse pressure of the shale formation in the Nanpu block of the Jidong oilfield was calculated. The well inclination angle, azimuth angle and drilling fluid soaking time were substituted in the deterioration model of rock mechanics parameters, and the safe drilling fluid density of the target layer was given. This work has important guiding significance for realizing wellbore stability and safe drilling of hard brittle shale in the Jidong Oilfield. Full article

(This article belongs to the Special Issue Petroleum Engineering in Oil and Gas Production: Advances in Theory and Operation)

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13 pages, 3957 KiB

Open AccessArticle

Effect of Wire Design (Profile) on Sand Retention Parameters of Wire-Wrapped Screens for Conventional Production: Prepack Sand Retention Testing Results

by Dmitry Tananykhin, Maxim Grigorev, Elena Simonova, Maxim Korolev, Ilya Stecyuk and Linar Farrakhov

Energies 2023, 16(5), 2438; https://doi.org/10.3390/en16052438 - 3 Mar 2023

Cited by 5 | Viewed by 1544

Abstract

There are many technologies to implement sand control in sand-prone wells, drilled in either weakly or nonconsolidated sandstones. Technologies that are used to prevent sanding can be divided into the following groups: screens (wire-wrapped screens, slotted liners, premium screens, and mesh screens), gravel packs, chemical consolidation, and technological ways (oriented perforation and bottomhole pressure limitation) of sanding prevention. Each particular technology in these groups has their own design and construction features. Today, slotted liners are the most well-studied technology in terms of design, however, this type of sand control screen is not always accessible, and some companies tend towards using wire-wrapped screens over slotted liners. This paper aims to study the design criteria of wire-wrapped screens and provides new data regarding the way in which wire design affects the sanding process. Wires with triangular (wedge), trapezoidal, and drop-shaped profiles were tested using prepack sand retention test methodology to measure the possible impact of wire profile on sand retention capabilities and other parameters of the sand control screen. It was concluded that a trapezoidal profile of wire has shown the best result both in terms of sand production (small amount of suspended particles in the effluent) and in particle size distribution in the effluent, that is, they are the smallest compared to other wire profiles. As for retained permeability, in the current series of experiments, high sand retention did not affect retained permeability, although it can be speculated that this is mostly due to the relatively high particle size distribution of the reservoir. Full article

(This article belongs to the Special Issue Petroleum Engineering in Oil and Gas Production: Advances in Theory and Operation)

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13 pages, 16530 KiB

Open AccessArticle

Multi-Well Pressure Interference and Gas Channeling Control in W Shale Gas Reservoir Based on Numerical Simulation

by Jianliang Xu, Yingjie Xu, Yong Wang and Yong Tang

Energies 2023, 16(1), 261; https://doi.org/10.3390/en16010261 - 26 Dec 2022

Cited by 1 | Viewed by 1089

Abstract

Well interference has drawn great attention in the development of shale gas reservoirs. In the W shale gas reservoir, well interference increased from 27% to 63% between 2016 and 2019, but the gas production recovery of parent wells was only about 40% between 2018 and 2019. Therefore, the mechanism and influencing factor of well interference degree were analyzed in this study. A numerical model of the W shale gas reservoir was developed for history matching, and the mechanisms of well interference and production recovery were analyzed. Sensitivity analysis about the effect of different parameters on well interference was carried out. Furthermore, the feasibility and effectiveness of gas injection pressure boosting to prevent interference were demonstrated. The results show that the main causes of inter-well interference are: the reservoir energy of the parent well before hydraulic fractures of the child well, well spacing, the fracture connection, etc. The fracture could open under high pressure causing fracturing fluid to flow in, while fracture closure happens under low pressure and the influence on the two-phase seepage in the fracture becomes more serious. The combination of liquid phase retention and fracture closure comprehensively affects the gas phase flow capacity in fractures. Gas injection pressure boosting can effectively prevent fracturing fluids flowing through connected fractures. Before the child well hydraulic fracturing, gas injection and pressurization in the parent well could reduce the stress difference and decrease the degree of well interference. The field case indicates that gas channeling could be effectively prevented through parent well gas injection pressurization. Full article

(This article belongs to the Special Issue Petroleum Engineering in Oil and Gas Production: Advances in Theory and Operation)

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13 pages, 4047 KiB

Open AccessArticle

Study on Shear Velocity Profile Inversion Using an Improved High Frequency Constrained Algorithm

by Qing Ye, Huafeng Sun, Zhiqiang Jin and Bing Wang

Energies 2023, 16(1), 59; https://doi.org/10.3390/en16010059 - 21 Dec 2022

Viewed by 1012

Abstract

The formation shear-wave (S-wave)’s velocity information around a borehole is of great importance in evaluating borehole stability, reflecting fluid invasion, and selecting perforation positions. Dipole acoustic logging is an effective method for determining a formation S-wave’s velocity radial profile around the borehole. Currently, the formation S-wave’s radial-profile inversion methods are mainly based on the impacts of radial velocity changes of formations outside the borehole on the dispersion characteristics of dipole waveforms, without considering the impacts of an acoustic tool on the dispersion curves in the inversion methods. Accordingly, the inversion accuracy is greatly impacted in practical data-processing applications. In this paper, a novel inversion algorithm, which introduces equivalent-tool theory into the shear-velocity radial profile constrained-inversion method, is proposed to obtain the S-wave’s slowness radial profile. Based on the equivalent-tool theory, the acoustic tool can be modeled using two parameters, radius and elastic modulus. The tool’s impact on the dipole waveform’s dispersion is eliminated first by using the equivalent-tool theory. Then, the corrected dispersion curve is used to carry out the constrained inversion processing. The results of this processing on the simulation data and the real logging data show the validity of the proposed algorithm. Full article

(This article belongs to the Special Issue Petroleum Engineering in Oil and Gas Production: Advances in Theory and Operation)

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11 pages, 9674 KiB

Open AccessArticle

Numerical Simulation of Multiarea Seepage in Deep Condensate Gas Reservoirs with Natural Fractures

by Lijun Zhang, Wengang Bu, Nan Li, Xianhong Tan and Yuwei Liu

Energies 2023, 16(1), 10; https://doi.org/10.3390/en16010010 - 20 Dec 2022

Viewed by 1112

Abstract

Research into condensate gas reservoirs in the oil and gas industry has been paid much attention and has great research value. There are also many deep condensate gas reservoirs, which is of great significance for exploitation. In this paper, the seepage performance of deep condensate gas reservoirs with natural fractures was studied. Considering that the composition of condensate gas changes during the production process, the component model was used to describe the condensate gas seepage in the fractured reservoir, modeled using the discrete fracture method, and the finite element method was used to conduct numerical simulation to analyze the seepage dynamic. The results show that the advancing speed of the moving pressure boundary can be reduced by 55% due to the existence of threshold pressure gradient. Due to the high-speed flow effect in the near wellbore area, as well as the high mobility of oil, the condensate oil saturation near the wellbore can be reduced by 42.8%. The existence of discrete natural fractures is conducive to improving the degree of formation utilization and producing condensate oil. Full article

(This article belongs to the Special Issue Petroleum Engineering in Oil and Gas Production: Advances in Theory and Operation)

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26 pages, 15762 KiB

Open AccessArticle

The Control of Sea Level Change over the Development of Favorable Sand Bodies in the Pinghu Formation, Xihu Sag, East China Sea Shelf Basin

by Zhong Chen, Wei Wei, Yongchao Lu, Jingyu Zhang, Shihui Zhang and Si Chen

Energies 2022, 15(19), 7214; https://doi.org/10.3390/en15197214 - 30 Sep 2022

Cited by 2 | Viewed by 1462

Abstract

The Pinghu Formation consists primarily of marine-continental transitional deposits. The widely distributed fluvial and tidal transgressive sand bodies comprise the main reservoirs of the Baochu slope zone in the Xihu Sag in the East China Sea Shelf Basin. These sand bodies are deeply buried, laterally discontinuous, and are frequently interrupted by coal-bearing intervals, thereby making it extremely difficult for us to characterize their hydrocarbon potential quantitatively via seismic inversion techniques, such as multi-attribute seismic analysis and post-stack seismic inversion, hindering further hydrocarbon exploration in the Xihu Sag. Here, a prestack seismic inversion approach is applied to the regional seismic data to decipher the spatiotemporal distribution pattern of the sand bodies across the four sequences, i.e., SQ1, SQ2, SQ3, and SQ4, from bottom up, within the Pinghu Formation. In combination with detailed petrology, well log, and seismic facies analysis, the secular evolution of the sedimentary facies distribution pattern during the accumulation of the Pinghu Formation is derived from the sand body prediction results. It is concluded that the sedimentary facies and sand body distribution pattern rely on the interplay between the hydrodynamics of fluvial and tidal driving forces from the continent and open ocean, respectively. Drops in the sea level led to the gradual weakening of tidal driving forces and relative increases in riverine driving forces. The direction of the sand body distribution pattern evolves from NE–SW oriented to NW–SE oriented, and the dominant sand body changes from tidal facies to fluvial facies. In addition, the sea level drop led to the decrease in the water column salinity, redox condition, organic matter composition, and the development of coal seams, all of which directly influenced the quality of reservoir and source rocks. The sand bodies in SQ2 and SQ3 are favorable reservoirs in the Pinghu Formation due to their good reservoir properties and great thickness. The high-quality source rock in SQ1 could provide significant hydrocarbons and get preserved in the sand body within SQ2 and SQ3. This contribution provides an insight into the control of the sea level change over the development of hydrocarbon reservoirs in the petroleum system from marginal-marine environments such as the Xihu Sag. Full article

(This article belongs to the Special Issue Petroleum Engineering in Oil and Gas Production: Advances in Theory and Operation)

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20 pages, 7779 KiB

Open AccessArticle

Depositional and Diagenetic Controls on Reservoir Quality of Callovian-Oxfordian Stage on the Right Bank of Amu Darya

by Yuzhong Xing, Hongjun Wang, Liangjie Zhang, Muwei Cheng, Haidong Shi, Chunqiu Guo, Pengyu Chen and Wei Yu

Energies 2022, 15(19), 6923; https://doi.org/10.3390/en15196923 - 21 Sep 2022

Cited by 1 | Viewed by 1377

Abstract

Based on the detailed analysis of sedimentology, diagenesis, and petrophysics, this study characterized the Middle-Lower Jurassic Callovian-Oxfordian carbonate reservoirs of 68 key wells in the Amu Darya Basin and assessed the controlling factors on the quality of the target intervals. We identified 15 types of sedimentary facies developed in seven sedimentary environments using sedimentary facies analysis, such as evaporative platform, restricted platform, open platform, platform margin, platform fore-edge upslope, platform fore-edge downslope, and basin facies. The target intervals went through multiple diagenetic stages, including the syndiagenetic stage, early diagenetic stage, and middle diagenetic stage, all of which had a significant impact on the reservoir quality. Main diagenetic processes include dissolution and fracturing which improve the reservoir quality as well as cementation, compaction, and pressure solution that reduce the reservoir quality. By analyzing the reservoir quality, we identified nine fluid flow units and five types of reservoir facies. Among them, the dissolved grain-dominated reservoir facies is of the highest quality and is the best storage and flow body, while the microporous mud-dominated reservoir facies of platform fore-edge downslope and open marine facies is of the lowest quality and could not become the flow unit unless it was developed by fracturing. Full article

(This article belongs to the Special Issue Petroleum Engineering in Oil and Gas Production: Advances in Theory and Operation)

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24 pages, 6598 KiB

Open AccessArticle

Laboratory Evaluation and Field Application of a Gas-Soluble Plugging Agent: Development of Bottom Water Plugging Fracturing Technology

by Aiguo Hu, Kezhi Li, Yunhui Feng, Hucheng Fu and Ying Zhong

Energies 2022, 15(18), 6761; https://doi.org/10.3390/en15186761 - 15 Sep 2022

Cited by 2 | Viewed by 1087

Abstract

The currently reported bottom water sealing materials and fracturing technologies can hardly simultaneously achieve the high production and low water cut of gas reservoirs due to the complexity of various formation conditions. Therefore, without controlling the fracturing scale and injection volume, a kind of polylactide polymer water plugging material with a density of 1.15–2.0 g/cm³ is developed, which can be used to seal the bottom water of a gas–water differential layer by contact solidification with water and automatic degradation with natural gas. This technology can not only fully release the production capacity of the gas reservoir but also effectively control water production and realize the efficient fracturing development of the target gas reservoir. Laboratory test results show that the smart plugging agent has a bottom water plugging rate of 100%, and the low-density plugging agent has a dissolution rate of 96.7% in methane gas at 90 °C for 4 h and a dissolution rate of 97.6% in methane gas at 60 °C for 6 h, showing remarkable gas degradation performance. In addition, settlement experiments show that the presence of a proppant can increase the settlement rate of a plugging agent up to many times (up to 21 times) in both water and guanidine gum solution. According to the actual conditions of well J66-8-3, a single-well water plugging fracturing scheme was prepared by optimizing the length of fracture, plugging agent dosage, and plugging agent sinking time, and a post-evaluation method was proposed. It has guiding significance to the development of similar gas reservoirs. Full article

(This article belongs to the Special Issue Petroleum Engineering in Oil and Gas Production: Advances in Theory and Operation)

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16 pages, 4988 KiB

Open AccessArticle

Characterization of Microstructures in Lacustrine Organic-Rich Shale Using Micro-CT Images: Qingshankou Formation in Songliao Basin

by Yan Cao, Qi Wu, Zhijun Jin and Rukai Zhu

Energies 2022, 15(18), 6712; https://doi.org/10.3390/en15186712 - 14 Sep 2022

Cited by 1 | Viewed by 1196

Abstract

In order to explore the development characteristics and influencing factors of microscale pores in lacustrine organic-rich muddy shale, this study selected five shale samples with different mineral compositions from the Qingshankou Formation in the Songliao Basin. The oil content and mineralogy of the shale samples were obtained by pyrolysis and X-ray diffraction analysis, respectively, while the porosity of the samples was computed by micro-CT imaging. Next, based on the CT images, the permeability of each sample was calculated by the Avizo software. Results showed that the continuous porosity of Qingshankou shale in the Songliao Basin was found between 0.84 and 7.79% (average 4.76%), the total porosity between 1.87 and 12.03% (average 8.28%), and the absolute permeability was calculated between 0.061 and 2.284 × 10⁻³ μm². The total porosity of the samples has a good positive correlation with the continuous porosity and permeability. This means higher values of total porosity suggested better continuous porosity and permeability. Both total porosity and continuous porosity are positively correlated with the content of clay minerals. Moreover, the oil content of the samples (the S₁ peak from programmed pyrolysis) exhibits a good positive correlation with the total porosity, continuous porosity, permeability, and clay mineral content. Therefore, pores that are developed by clay minerals are the main storage space for oil and flow conduits as well. Clay minerals were found to be the main controlling factor in the porosity, permeability, and the amount of oil content in the pores in the study area. Full article

(This article belongs to the Special Issue Petroleum Engineering in Oil and Gas Production: Advances in Theory and Operation)

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19 pages, 3864 KiB

Open AccessArticle

FTCN: A Reservoir Parameter Prediction Method Based on a Fusional Temporal Convolutional Network

by Hongxia Zhang, Kaijie Fu, Zhihao Lv, Zhe Wang, Jiqiang Shi, Huawei Yu and Xinmin Ge

Energies 2022, 15(15), 5680; https://doi.org/10.3390/en15155680 - 5 Aug 2022

Cited by 1 | Viewed by 1388

Abstract

Predicting reservoir parameters accurately is of great significance in petroleum exploration and development. In this paper, we propose a reservoir parameter prediction method named a fusional temporal convolutional network (FTCN). Specifically, we first analyze the relationship between logging curves and reservoir parameters. Then, we build a temporal convolutional network and design a fusion module to improve the prediction results in curve inflection points, which integrates characteristics of the shallow convolution layer and the deep temporal convolution network. Finally, we conduct experiments on real logging datasets. The results indicate that compared with the baseline method, the mean square errors of FTCN are reduced by 0.23, 0.24 and 0.25 in predicting porosity, permeability, and water saturation, respectively, which shows that our method is more consistent with the actual reservoir geological conditions. Our innovation is that we propose a new reservoir parameter prediction method and introduce the fusion module in the model innovatively. Our main contribution is that this method can well predict reservoir parameters even when there are great changes in formation properties. Our research work can provide a reference for reservoir analysis, which is conducive to logging interpreters’ efforts to analyze rock strata and identify oil and gas resources. Full article

(This article belongs to the Special Issue Petroleum Engineering in Oil and Gas Production: Advances in Theory and Operation)

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