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Oil and Gas Reservoirs: Seepage Mechanism, Productivity Prediction and Development Technology

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

Deadline for manuscript submissions: closed (24 February 2023) | Viewed by 27118

Special Issue Editors

Dr. Juntai Shi

E-Mail Website
Guest Editor
State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum(Beijing), Beijing 102249, China
Interests: phase characteristics; percolation mechanism; productivity prediction and development technology of condensate gas reservoir; low permeability gas reservoir; coalbed methane gas reservoir; shale gas reservoir and other complex and unconventional gas reservoirs
Special Issues, Collections and Topics in MDPI journals
Dr. Zheng Sun

E-Mail Website
Guest Editor
State Key Laboratory of Coal Resources and Safe Mining, China University of Mining and Technology, Xuzhou 221116, China
Interests: nanoconfined hydrocarbon phase behavior; nanoconfined fluid flow mechanism; pore network modeling; numerical siumulation on coalbed methane reservoirs; production data analysis method; shale gas/oil development; CO2 storage and utilization; condensate gas reservoir
Special Issues, Collections and Topics in MDPI journals

Special Issue Information

Dear Colleagues,

Although carbon reduction is essential for the future of the world, the development of oil and gas reservoirs still acts an indispensable role in the energy supply nowadays. Meanwhile, after depletion of regular oil/gas reservoirs, tremendous attention is forced to switch to the unconventional oil/gas reservoirs, such as tight oil/gas reservoirs, shale gas/oil, and coalbed methane, or complex development mode. However, the seepage mechanism, productivity prediction method, as well as development technology of the mentioned complex and unconventional oil/gas reservoirs are still vague, and are required to be revealed urgently. In order to address the issue, we are pleased to invite you to submit papers to the journal Energies for a Special Issue that will be entirely devoted to “Oil and Gas Reservoirs: Seepage Mechanism, Productivity Prediction and Development Technology”.  The issue puts emphasis on current challenges in the development of oil and gas reservoirs, particularly for the tight reservoirs, shale oil/gas, and coalbed methane. At the same time, the utilization of advanced mathematic algorithm towards oil/gas development is also welcomed.

Potential topics of interest include, but are not limited to:

  • Characterization of nanopore morphology in shale/coal samples
  • Original multi-phase fluid occurrence state in oil/gas reservoirs
  • Pore network modeling towards fluid flow in porous media
  • Nanoconfined fluid phase behavior and fluid flow capacity
  • Novel numerical simulation method upon complex development modes
  • Fracture propagation characterization and long-term conductivity calculation
  • Advanced production data analysis methods based on multi-phase flow
  • Machine learning and data science applied for the oil/gas develpment

Dr. Juntai Shi
Dr. Zheng Sun
Guest Editors

Manuscript Submission Information

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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. Energies is an international peer-reviewed open access semimonthly 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 2600 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

  • multi-phase seepage mechanism
  • tight oil/gas
  • shale oil/gas
  • coalbed methane
  • production prediction
  • stimulation measures
  • data science

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Published Papers (15 papers)

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Research

15 pages, 14591 KiB  
Article
Characteristics of Fracturing Fluid Invasion Layer and Its Influence on Gas Production of Shale Gas Reservoirs
by Shijun Huang, Jiaojiao Zhang, Jin Shi, Fenglan Zhao and Xianggang Duan
Energies 2023, 16(9), 3924; https://doi.org/10.3390/en16093924 - 6 May 2023
Cited by 2 | Viewed by 1530
Abstract
With the increase of shale gas resource exploitation in our country during recent decades, the situations of low gas production, fast production decline rate, and low flowback rate have been appearing in field production. It is an urgent problem to be solved in [...] Read more.
With the increase of shale gas resource exploitation in our country during recent decades, the situations of low gas production, fast production decline rate, and low flowback rate have been appearing in field production. It is an urgent problem to be solved in shale gas production and it is therefore necessary to study the interaction of the shale gas reservoir and the detained fracturing fluid. In this paper, the Longmaxi Formation shale samples of Sichuan Basin were selected for a water invasion experiment. The fracture propagation law, the water invasion front location, and the water invasion thickness of deep and shallow shale reservoirs after water invasion were compared and analyzed by CT scanning technology. Based on the analysis of the experimental mechanism, a numerical simulation model was established. The dimensionless permeability and thickness of the fracturing fluid invasion layer were introduced to analyze the positive and negative effects of fracturing fluid retention on the reservoir. The results show that during the hydraulic fracturing of shale gas wells, fracturing fluid can quickly enter the complex fracture network, and then slowly enter the shale matrix under various mechanisms to form the fracturing fluid invasion layer. Compared with shallow shale reservoirs, deep shale reservoirs have lower porosity and permeability, which propagates microfractures in the matrix induced by fracturing fluid retention, and results in a smaller fracturing fluid invasion layer thickness. Both the negative effect of fracturing fluid retention on shale damage and the positive effect of microfracture formation and propagation exist simultaneously. The higher the dimensionless fracturing fluid invasion layer permeability, the more complex the fracture network formed in the fractured reservoir will be, resulting in a longer stable production period and a better development effect. When the dimensionless fracturing fluid invasion layer permeability is greater than 1, that is, when the positive effect of fracturing fluid retention is greater, and the thicker the dimensionless fracturing fluid invasion layer is, the better the development effect will be. Combining reservoir characteristics and fracture development, the key to obtaining high productivity of a shale gas well is to optimize the soaking time and the speed of flowback in order to extend the stable production period. In this paper, the characteristics of the fracturing fluid invasion layer and the influence of fracturing fluid retention on gas well productivity are deeply studied, which provides a certain theoretical basis for the optimization of shale gas extraction technology and the improvement of the gas–water two-phase productivity prediction method for fractured horizontal wells. Full article
(This article belongs to the Special Issue Oil and Gas Reservoirs: Seepage Mechanism, Productivity Prediction and Development Technology)
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18 pages, 3964 KiB  
Article
Study on the Effect of the Water Injection Rate on the Cavern Leaching Strings of Salt Cavern Gas Storages
by Shengwei Dong, Taian Fang, Jifang Wan, Xuhui Hu, Jingcui Li, Hangming Liu, Dongyang Li and Shaofeng Qiao
Energies 2023, 16(1), 344; https://doi.org/10.3390/en16010344 - 28 Dec 2022
Cited by 2 | Viewed by 1768
Abstract
In the early construction of cavern leaching in salt cavern gas storages, the inner leaching tubing is often blocked, frequently leading to the bending deformation phenomenon of the leaching strings, which can result in out-of-control cavity shapes. It is difficult to monitor the [...] Read more.
In the early construction of cavern leaching in salt cavern gas storages, the inner leaching tubing is often blocked, frequently leading to the bending deformation phenomenon of the leaching strings, which can result in out-of-control cavity shapes. It is difficult to monitor the stress, vibration, and morphological changes of the inner tube during the construction of a cavity. There are few research results in this field at home and abroad, and they are limited only to preliminary explorations of the mechanism or summaries and speculation of the field operation. In this paper, an experimental device for testing the dynamic characteristics of salt cavern leaching strings is developed based on the similarity principle. The device is used to simulate two types of operation processes, i.e., the direct and reverse circulation leaching processes. The experimental data are processed using the modal analysis method to obtain the vibration characteristic parameters of the inner leaching tubing in the circulation process with identical flow rates inside the tubing and the annular region. The following main conclusions can be drawn: The circulation mode has no significant effect on the vibration frequency of cavern leaching strings. The deformation characteristics of cavern leaching strings during direct and reverse circulation are identical, featuring maximum deformation at the bottom and minimum deformation in the middle. The maximum deformation of cavern leaching strings during reverse circulation is about 1.5 times that during direct circulation. Through an experimental investigation and analysis, the effects of the water injection rate and the cavern leaching method on the vibration frequency and bending deformation of cavern leaching strings was determined, providing a reference for further solving the bending problem of cavern leaching strings in combination with engineering practice. Full article
(This article belongs to the Special Issue Oil and Gas Reservoirs: Seepage Mechanism, Productivity Prediction and Development Technology)
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24 pages, 2683 KiB  
Article
Hierarchical Surrogate-Assisted Evolutionary Algorithm for Integrated Multi-Objective Optimization of Well Placement and Hydraulic Fracture Parameters in Unconventional Shale Gas Reservoir
by Jun Zhou, Haitao Wang, Cong Xiao and Shicheng Zhang
Energies 2023, 16(1), 303; https://doi.org/10.3390/en16010303 - 27 Dec 2022
Cited by 11 | Viewed by 2165
Abstract
Integrated optimization of well placement and hydraulic fracture parameters in naturally fractured shale gas reservoirs is of significance to enhance unconventional hydrocarbon energy resources in the oil and gas industry. However, the optimization task usually presents intensive computation-cost due to numerous high-fidelity model [...] Read more.
Integrated optimization of well placement and hydraulic fracture parameters in naturally fractured shale gas reservoirs is of significance to enhance unconventional hydrocarbon energy resources in the oil and gas industry. However, the optimization task usually presents intensive computation-cost due to numerous high-fidelity model simulations, particularly for field-scale application. We present an efficient multi-objective optimization framework supported by a novel hierarchical surrogate-assisted evolutionary algorithm and multi-fidelity modeling technology. In the proposed framework, both the net present value (NPV) and cumulative gas production (CGP) are regarded as the bi-objective functions that need to be optimized. The hierarchical surrogate-assisted evolutionary algorithm employs a novel multi-fidelity particle-swarm optimization of a global–local hybridization searching strategy where the low-fidelity surrogate model is capable of exploring the populations globally, while the high-fidelity models update the current populations and thus generate the next generations locally. The multi-layer perception is chosen as a surrogate model in this study. The performance of our proposed hierarchical surrogate-assisted global optimization approach is verified to optimize the well placement and hydraulic fracture parameters on a hydraulically fractured shale gas reservoir. The proposed surrogate model can obtain both the NPV and CPG with satisfactory accuracy with only 500 training samples. The surrogate model significantly contributes to the convergent performance of multi-objective optimization algorithm. Full article
(This article belongs to the Special Issue Oil and Gas Reservoirs: Seepage Mechanism, Productivity Prediction and Development Technology)
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15 pages, 3518 KiB  
Article
Numerical Simulation of the Proppant Settlement in SC-CO2 Sand-Carrying Fluid in Fracturing Fractures
by Dayong Chen and Zheng Sun
Energies 2023, 16(1), 11; https://doi.org/10.3390/en16010011 - 20 Dec 2022
Cited by 4 | Viewed by 1810
Abstract
Supercritical CO2 fracturing has unique advantages for improving unconventional reservoir recovery. Supercritical CO2 can penetrate deep into the reservoir and increase reservoir reform volume, and it is less damaging to reservoir and easy to flow back. However, when the supercritical CO [...] Read more.
Supercritical CO2 fracturing has unique advantages for improving unconventional reservoir recovery. Supercritical CO2 can penetrate deep into the reservoir and increase reservoir reform volume, and it is less damaging to reservoir and easy to flow back. However, when the supercritical CO2 flows as the sand-carrying fluid in the fracture, the settlement of the proppant is still worth studying. Based on the study of supercritical CO2 density and viscosity properties, assuming that the reservoir has been pressed out of the vertical crack by injecting prepad fluid, the proppant characteristics in sand-carrying fluid under different conditions were studied by numerical simulation. After the analysis, the proppant accumulation and backflow will occur at the end of the crack. Large sand diameters, high fluid flow rates, high sand concentrations, high reservoir temperatures, and low reservoir pressures can help to shorten deposition time, and the small particle size, high fluid flow rate, low sand concentration, low reservoir temperature, and high reservoir pressure can help increase the uniformity of sand deposition. Shortening the sand deposition time can help to complete the fracturing efficiently, and increasing the deposition uniformity can improve the fracture conductivity. This article has studied the proppant settling and crack formation characteristics. It is hoped that this study can provide theoretical support for field fracturing and provide theoretical assistance to relevant researchers. Full article
(This article belongs to the Special Issue Oil and Gas Reservoirs: Seepage Mechanism, Productivity Prediction and Development Technology)
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12 pages, 2173 KiB  
Article
A Method for Evaluating the Dominant Seepage Channel of Water Flooding in Layered Sandstone Reservoir
by Changlin Liao, Xinwei Liao, Ruifeng Wang, Jing Chen, Jiaqi Wu and Min Feng
Energies 2022, 15(23), 8833; https://doi.org/10.3390/en15238833 - 23 Nov 2022
Viewed by 1305
Abstract
A method for evaluating the dominant seepage channel (DSC) water flooding in a layered sandstone reservoir is proposed and applied in an oilfield based on the water-cut derivative. The water-cut derivative curve of the reservoir with DSC shows double peaks. Therefore, based on [...] Read more.
A method for evaluating the dominant seepage channel (DSC) water flooding in a layered sandstone reservoir is proposed and applied in an oilfield based on the water-cut derivative. The water-cut derivative curve of the reservoir with DSC shows double peaks. Therefore, based on the analysis of geology and production characteristics, the evaluation method of DSC is established. The evaluation index is proposed to quantitatively characterize the development degree of DSC and determine its distribution in a water-flooding reservoir. The test data validate that the proposed method can not only accurately determine the DSC and quantitatively evaluate its development degree, but also show its dynamic change. This method will be a powerful guide for water controlling and oil stabilizing in the adjustment stage of sandstone reservoirs. Full article
(This article belongs to the Special Issue Oil and Gas Reservoirs: Seepage Mechanism, Productivity Prediction and Development Technology)
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14 pages, 5924 KiB  
Article
A Novel Equivalent Numerical Simulation Method for Non-Darcy Seepage Flow in Low-Permeability Reservoirs
by Hui Xu, Nannan Liu, Yan Chen, Yapeng Tian, Zhenghuai Guo, Wanjun Jiang and Yanfeng He
Energies 2022, 15(22), 8505; https://doi.org/10.3390/en15228505 - 14 Nov 2022
Cited by 2 | Viewed by 1590
Abstract
The low permeability and submicron throats in most shale or tight sandstone reservoirs have a significant impact on microscale flow. The flow characteristics can be described with difficultly by the conventional Darcy flow in low-permeability reservoirs. In particular, the thickness of the boundary [...] Read more.
The low permeability and submicron throats in most shale or tight sandstone reservoirs have a significant impact on microscale flow. The flow characteristics can be described with difficultly by the conventional Darcy flow in low-permeability reservoirs. In particular, the thickness of the boundary layer is an important factor affecting the formation permeability, and the relative permeability curve obtained under conventional conditions cannot accurately express the seepage characteristics of porous media. In this work, the apparent permeability and relative permeability were calculated by using non-Darcy-flow mathematical modeling. The results revealed that the newly calculated oil–water relative permeability was slightly higher than that calculated by the Darcy seepage model. The results of the non-Darcy flow based on the conceptual model showed that the area swept by water in non-Darcy was smaller than that in Darcy seepage. The fingering phenomenon and the high bottom hole pressure in the non-Darcy seepage model resulted from the larger amount of injected water. There was a large pressure difference between the injection and production wells where the permeability changed greatly. A small pressure difference between wells resulted in lower variation of permeability. Consequently, the non-Darcy simulation results were consistent with actual production data. Full article
(This article belongs to the Special Issue Oil and Gas Reservoirs: Seepage Mechanism, Productivity Prediction and Development Technology)
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16 pages, 2285 KiB  
Article
A Prediction Method for Development Indexes of Waterflooding Reservoirs Based on Modified Capacitance–Resistance Models
by Libing Fu, Lun Zhao, Song Chen, Anzhu Xu, Jun Ni and Xuanran Li
Energies 2022, 15(18), 6768; https://doi.org/10.3390/en15186768 - 16 Sep 2022
Cited by 2 | Viewed by 1342
Abstract
Capacitance–resistance models (CRMs) are semi-analytical methods to estimate the production rate of either an individual producer or a group of producers based on historical observed production and injection rates using material balance and signal correlations between injectors and producers. Waterflood performance methods are [...] Read more.
Capacitance–resistance models (CRMs) are semi-analytical methods to estimate the production rate of either an individual producer or a group of producers based on historical observed production and injection rates using material balance and signal correlations between injectors and producers. Waterflood performance methods are applied to evaluate the waterflooding performance effect and to forecast the development index on the basis of Buckley–Leverett displacement theory and oil–water permeability curve. In this case study, we propose an approach that combines a capacitance–resistance model (CRM) modified by increasing the influence radius on the constraints and a waterflood performance equation between oil cut and oil accumulative production to improve liquid and oil production prediction ability. By applying the method, we can understand the waterflood performance, inter-well connectivities between injectors and producer, and production rate fluctuation better, in order to re-just the water injection and optimize the producers’ working parameters to maximize gain from the reservoir. The new approach provides an effective way to estimate the conductivities between wells and production rates of a single well or well groups in CRMs. The application results in Kalamkas oilfield show that the estimated data can be in good agreement with the actual observation data with small fitting errors, indicating a good development index forecasting capability. Full article
(This article belongs to the Special Issue Oil and Gas Reservoirs: Seepage Mechanism, Productivity Prediction and Development Technology)
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15 pages, 3376 KiB  
Article
A Novel Model of Counter-Current Imbibition in Interacting Capillaries with Different Size Distribution
by Zhenjie Zhang, Tianyi Zhao and Qingbang Meng
Energies 2022, 15(17), 6309; https://doi.org/10.3390/en15176309 - 29 Aug 2022
Cited by 1 | Viewed by 1552
Abstract
The imbibition phenomenon widely exists in nature and industrial applications. It is of great significance to study the mechanism of imbibition and the influence laws of related factors. In this paper, based on the assumption of interacting capillaries, a capillary bundle model of [...] Read more.
The imbibition phenomenon widely exists in nature and industrial applications. It is of great significance to study the mechanism of imbibition and the influence laws of related factors. In this paper, based on the assumption of interacting capillaries, a capillary bundle model of counter-current imbibition is established. In addition, the characteristics of imbibition and the influences of capillary size and fluid viscosity are analyzed. The results show that water is imbibed into the smaller capillaries and expelled from the larger capillaries. The rate of the meniscus in water-imbibition capillaries is proportional to the square root of time. In the interacting capillaries, oil production by counter-current imbibition decreases and then increases gradually with the increase of the capillary diameter difference. When the total cross-sectional area of the capillary remains unchanged, the cross-sectional area of the total water-imbibition capillaries is affected by the size distribution of the capillaries. The larger the viscosity of the non-wetting phase, the more uneven the imbibition front, the lower the imbibition efficiency. The higher the viscosity of the wetting phase, the more uniform the imbibition front, and the higher the imbibition efficiency. Full article
(This article belongs to the Special Issue Oil and Gas Reservoirs: Seepage Mechanism, Productivity Prediction and Development Technology)
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20 pages, 2685 KiB  
Article
3D Fracture Propagation Simulation and Pressure Decline Analysis Research for I-Shaped Fracture of Coalbed
by Chengwang Wang, Zixi Guo, Lifeng Zhang, Yunwei Kang, Zhenjiang You, Shuguang Li, Yubin Wang and Huaibin Zhen
Energies 2022, 15(16), 5811; https://doi.org/10.3390/en15165811 - 10 Aug 2022
Cited by 1 | Viewed by 1467
Abstract
After hydraulic fracturing, some treatments intended for production enhancement fail to yield predetermined effects. The main reason is the insufficient research about the fracture propagation mechanism. There is compelling evidence that I-shaped fracture, two horizontal fractures at the junction of coalbed and cover/bottom [...] Read more.
After hydraulic fracturing, some treatments intended for production enhancement fail to yield predetermined effects. The main reason is the insufficient research about the fracture propagation mechanism. There is compelling evidence that I-shaped fracture, two horizontal fractures at the junction of coalbed and cover/bottom layer, and one vertical fracture in the coalbed have formed in part of the coalbed after hydraulic fracturing. Therefore, this paper aims at I-shaped fracture propagation simulation. A novel propagation model is derived on the basis of a three-dimensional (3D) model, and the coupling conditions of vertical fracture and horizontal fractures are established based on the flow rate distribution and the bottom-hole pressure equality, respectively. Moreover, an associated PDA (pressure decline analysis of post-fracturing) model is established. Both models complement with each other and work together to guide fracturing treatment. Finally, a field case is studied to show that the proposed models can effectively investigate and simulate fracture initiation/propagation and pressure decline. Full article
(This article belongs to the Special Issue Oil and Gas Reservoirs: Seepage Mechanism, Productivity Prediction and Development Technology)
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17 pages, 7337 KiB  
Article
Numerical Investigation of Interaction Mechanism between Hydraulic Fracture and Natural Karst Cave Based on Seepage-Stress-Damage Coupled Model
by Yue Li, Jianye Mou, Shicheng Zhang, Xinfang Ma, Cong Xiao and Haoqing Fang
Energies 2022, 15(15), 5425; https://doi.org/10.3390/en15155425 - 27 Jul 2022
Cited by 3 | Viewed by 1516
Abstract
Oil/gas is mainly distributed in caves for fractured-vuggy carbonate reservoirs, it is therefore of significance to effectively connect caves for successful carbonate reservoir development. However, the mechanism and controlling factors that influence the connection between fractures and caves still remain unknown. To investigate [...] Read more.
Oil/gas is mainly distributed in caves for fractured-vuggy carbonate reservoirs, it is therefore of significance to effectively connect caves for successful carbonate reservoir development. However, the mechanism and controlling factors that influence the connection between fractures and caves still remain unknown. To investigate how hydraulic fracture interacts with natural karst cave, a coupled seepage-stress-damage model for a vuggy carbonate reservoir is established based on statistical damage mechanics theory and finite element method. The accuracy of the proposed model is validated in comparison with experimental results. Some influencing factors, including fluid pressure in the cave, formation parameters, and construction parameters, are fully taken into account. The study results show that, when the fracture deflection degree is small, a hydraulic fracture can indirectly connect with the cave through high permeable damage units. The matrix heterogeneity that influences hydraulic fracture morphology almost does not affect the interactions between fracture and cave. The higher permeability can lead to insufficient net pressure in the fracture, which is detrimental to the connection between fracture and cave. The ability of the cave to repel fracture is proportional to the in-situ stress magnitude. The higher in-situ stress difference can cause hydraulic fracture extends along with its original path, hindering hydraulic fracture deflection. The compressive stress concentration effect around the cave weakens as the fluid pressure in the cave rises, causing the cave wall to gradually transform from a compressed to a tensioned state. The hydraulic fracture can propagate along its initial trajectory because of the high injection rate’s ability to lessen the impact of the cave. These findings achieve deep insights into interaction patterns between fracture and cave, as well as provide useful guidance for hydraulic fracturing treatment design in fractured-vuggy carbonate reservoirs. Full article
(This article belongs to the Special Issue Oil and Gas Reservoirs: Seepage Mechanism, Productivity Prediction and Development Technology)
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20 pages, 2529 KiB  
Article
Research Methods of Main Parameter Sensitivity Differences in China’s Dynamic Oil and Gas Reserve Estimation under SEC Standards
by Qirong Qin, Lin Liu and Xuefeng Pan
Energies 2022, 15(15), 5358; https://doi.org/10.3390/en15155358 - 24 Jul 2022
Cited by 1 | Viewed by 1232
Abstract
International oil and gas companies listed in New York must publish the information of oil and gas reserves under the SEC (United States Securities and Exchange Commission) standards every year. For greatly improving the SEC reserve, the SEC reserve value and the SEC [...] Read more.
International oil and gas companies listed in New York must publish the information of oil and gas reserves under the SEC (United States Securities and Exchange Commission) standards every year. For greatly improving the SEC reserve, the SEC reserve value and the SEC reserve substitution rate, in this article not only the SEC reserve equations have been determined but also the SEC reserve value models have been established. The SEC reserve value models have been verified as correct. Based on these models, the multivariate function calculus method, the multivariate function limit method and the function recurrence method have been adopted to research parameter sensitivity differences rules, parameter adjustment directions, parameter adjustment degrees and SEC reserve parameter linkage adjustment rules. The research is significant, because there are great differences between SEC standards and China’s in reserve management mode, reserve estimation method system and financial management system. It is just these differences that cause the frequent adjustment of SEC reserve parameters during the process of SEC reserve submissions each year. As a result, this article reaches some conclusions. Above all, the article has clarified the parameter quantitative conditions that lead to the sensitivity between the SEC reserve and the initial production to begin stronger and weaker than the sensitivity between the SEC reserve and the price in production exponential, hyperbolic and harmonic decline types. Furthermore, the article has clarified the parameter quantitative conditions that lead to the sensitivity between the SEC reserve value and the initial production to begin stronger and weaker than the sensitivity between the SEC reserve value and the price in common production exponential decline types. Moreover, the article has clarified reserve parameter linkage adjustment rules and found the most significant parameter whose least adjustment will cause the largest reserve increase. In addition, the function calculus method adopted to disclose reserve parameter sensitivity rules will expand the parameter sensitivity analysis method that took the previous statistical mapping method as the main analysis method. Full article
(This article belongs to the Special Issue Oil and Gas Reservoirs: Seepage Mechanism, Productivity Prediction and Development Technology)
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24 pages, 8005 KiB  
Article
Mechanism of Methane Adsorption/Desorption in Low-Rank Vitrain and Durain Coal Affected by Pore Structure and Wettability: A Case Study in Dafosi Area, South Ordos Basin, China
by Tao Peng, Yue Chen, Liya Wang, Dongmin Ma, Guofu Li, Weibo Li, Chao Zheng, Yusong Ji, Zhuoyuan Ma, Peng Hui and Xin Wang
Energies 2022, 15(14), 5094; https://doi.org/10.3390/en15145094 - 12 Jul 2022
Cited by 5 | Viewed by 1842
Abstract
Water content and water–coal interface wettability are always the difficult issues of coalbed methane adsorption/desorption. In order to study the effects of the pore structure and wettability of different macro coal components on methane adsorption and desorption, we compared and analyzed the wettability [...] Read more.
Water content and water–coal interface wettability are always the difficult issues of coalbed methane adsorption/desorption. In order to study the effects of the pore structure and wettability of different macro coal components on methane adsorption and desorption, we compared and analyzed the wettability difference between vitrain and durain, and revealed the influence of wettability on methane adsorption and desorption through a pore structure analysis, wettability measurements, an adsorption–desorption experiment and adsorption heat calculations under different conditions, taking the No. 4 coal in Dafosi Coal Mine of the Huanglong coalfield as the research object. The results show that both vitrain and durain are relatively hydrophilic substances. However, vitrain has a low ash content, high volatility, and less oxygen, and the pores are mainly semi-closed pores compared with dark coal. Vitrain also has poor connectivity, poor sorting, a small pore diameter, and a coarser surface, resulting in poor surface wettability. The large specific surface area (SSA) and relatively poor wettability of vitrain leads to more adsorption sites in methane, which makes the adsorption capacity of vitrain greater than that of durain, but the good pore connectivity of durain causes the strong desorption capacity of durain. The isosteric adsorption heat of the adsorption process is greater than that of the desorption process, indicating that there is a desorption hysteresis phenomenon which is essentially due to the lack of energy in desorption. Surfactants change the wettability of the coal surface, and different surfactants have different effects on methane adsorption and desorption. Relatively speaking, the methane desorption of coal samples treated with G502 and 6501 are better. The research results provide scientific reference for the study of gas–water transport in the desorption process of low-rank CBM, and provide evidence for the methane desorption model of vitrain and durain. Full article
(This article belongs to the Special Issue Oil and Gas Reservoirs: Seepage Mechanism, Productivity Prediction and Development Technology)
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15 pages, 14121 KiB  
Article
Stability Analysis of a Typical Salt Cavern Gas Storage in the Jintan Area of China
by Jingcui Li, Jifang Wan, Hangming Liu, Maria Jose Jurado, Yuxian He, Guangjie Yuan and Yan Xia
Energies 2022, 15(11), 4167; https://doi.org/10.3390/en15114167 - 6 Jun 2022
Cited by 21 | Viewed by 3001
Abstract
Using underground space to store natural gas resources is an important means by which to solve emergency peak shaving of natural gas. Rock salt gas storage is widely recognized due to its high-efficiency peak shaving and environmental protection. Damage and stress concentrations inside [...] Read more.
Using underground space to store natural gas resources is an important means by which to solve emergency peak shaving of natural gas. Rock salt gas storage is widely recognized due to its high-efficiency peak shaving and environmental protection. Damage and stress concentrations inside the cavern injection during withdrawal operations and throughout the storage facility life have always been among the most important safety issues. Therefore, accurate evaluation of the stability of rock salt gas storage during operation is of paramount significance to field management and safety control. In this study, we used the finite element numerical analysis software Flac3D to numerically simulate large displacement deformations of the cavern wall during gas storage—in addition to the distribution of the plastic zone of the rock around the cavern and the surface settlement—under different working conditions. We found that the maximum surface settlement value occurred near the upper part of the cavern. The surface settlement value increased as a function of creep time, but this increase leveled off, that is, a convergence trend was observed. The value was relatively small and, therefore, had little impact on the surface. The application of gas pressure inhibited the growth of the plastic zone, but on the whole, the plastic zone’s range increased proportionally to creep time. For the 20-year creep condition, the deformation value of the cavern’s surrounding rock was large. Combined with the distribution of the plastic zone, we believe that the cavern’s surrounding rock is unstable; thus, corresponding reinforcement measures must be taken. Full article
(This article belongs to the Special Issue Oil and Gas Reservoirs: Seepage Mechanism, Productivity Prediction and Development Technology)
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17 pages, 1292 KiB  
Article
Production Simulation of Oil Reservoirs with Complex Fracture Network Using Numerical Simulation
by Xijun Ke, Yunxiang Zhao, Jiaqi Li, Zixi Guo and Yunwei Kang
Energies 2022, 15(11), 4050; https://doi.org/10.3390/en15114050 - 31 May 2022
Cited by 4 | Viewed by 1554
Abstract
This paper established a numerical simulation model to analyze the pressure transient and rate transient behaviors in reservoir with complex fracture network. Firstly, the fractures are introduced into the coordinate system through the position, angle, and length. Secondly, a mathematical model is established [...] Read more.
This paper established a numerical simulation model to analyze the pressure transient and rate transient behaviors in reservoir with complex fracture network. Firstly, the fractures are introduced into the coordinate system through the position, angle, and length. Secondly, a mathematical model is established by using unstable seepage model. Thirdly, the central difference method was used to solve the model and local grid refinement method is introduced to describe the network fractures. Finally, we compared the results obtained from this paper’s model with the production data. The results show acceptable and reasonable matches for typical well. Meanwhile, the sensitivity of two properties is discussed. The model solution is verified with an analytical method thoroughly. The novelty of this paper is to introduce each fracture in fracture network into the coordinate system. Then, the grid refinement is achieved according to the fracture information. The presented new model simplifies the analysis of the pressure transient and rate transient of the reservoir with complex fracture network, and it is more efficient than the conventional numerical method. Compared with the analytical methods, the new model describes the fractures system in more detail. However, the new model treats fractures as reservoirs with higher permeability in the central difference method, which is simpler and rougher than traditional numerical methods. Full article
(This article belongs to the Special Issue Oil and Gas Reservoirs: Seepage Mechanism, Productivity Prediction and Development Technology)
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29 pages, 15594 KiB  
Article
Simulation of Water Influx and Gasified Gas Transport during Underground Coal Gasification with Controlled Retracting Injection Point Technology
by Yanpeng Chen, Tianduoyi Wang, Jinhua Zhang, Mengyuan Zhang, Junjie Xue, Juntai Shi, Yongshang Kang and Shengjie Li
Energies 2022, 15(11), 3997; https://doi.org/10.3390/en15113997 - 29 May 2022
Cited by 8 | Viewed by 2071
Abstract
Underground coal gasification (UCG) may change the energy consumption structure from coal-dominated to gas-dominated in the years to come. Before that, three important problems need to be solved, including failure of gasification due to large amounts of water pouring into the gasifier, environmental [...] Read more.
Underground coal gasification (UCG) may change the energy consumption structure from coal-dominated to gas-dominated in the years to come. Before that, three important problems need to be solved, including failure of gasification due to large amounts of water pouring into the gasifier, environmental pollution caused by gas migration to the surface, and low calorific value caused by poor control of the degree of gasification. In this study, a geological model is first established using the computer modeling group (CMG), a commercial software package for reservoir simulation. Then, the inflow of coal seam water into the gasifier during the controlled retracting injection point (CRIP) gasification process is simulated based on the geological model, and the maximum instantaneous water inflow is simulated too. Meanwhile, the migration of gasified gas is also simulated, and the migration discipline of different gases is shown. Finally, the pressure distributions in two stages are presented, pointing out the dynamic pressure characteristics during the UCG process. The results show that (a) the cavity width, production pressure, and gasifier pressure are negatively correlated with the maximum instantaneous water inflow, while the initial formation pressure, injection pressure, coal seam floor aquifer energy, and temperature are positively correlated; (b) CO2 is mainly concentrated near the production well and largely does not migrate upward, O2 migrates upward slowly, while CH4, CO and H2 migrate relatively quickly. When the injection–production pressure difference is 2 MPa, it takes 33.5 years, 40 years, and 44.6 years for CH4, CO, and H2 to migrate from a depth of 1000 m to 200 m, respectively. When the pressure difference increases to 4 MPa, the gas migration rate increases about two-fold. The aquifer (3 MPa) above a coal outcrop can slow down the upward migration rate of gas by 0.03 m/day; (c) the pressure near the production well changes more significantly than the pressure near the injection well. The overall gasifier pressure rises with gasifier width increases, and the pressure distribution always presents an asymmetric unimodal distribution during the receding process of the gas injection point. The simulation work can provide a theoretical basis for the operation parameters design and monitoring of the well deployment, ensuring the safety and reliability of on-site gasification. Full article
(This article belongs to the Special Issue Oil and Gas Reservoirs: Seepage Mechanism, Productivity Prediction and Development Technology)
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