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Oil and Gas Reservoirs: Phase Behavior, Seepage Mechanism, Productivity Prediction, and Novel Modelling Methods

A special issue of Energies (ISSN 1996-1073). This special issue belongs to the section "H: Geo-Energy".

Deadline for manuscript submissions: closed (11 October 2024) | Viewed by 11493

Special Issue Editors

Dr. Juntai Shi

E-Mail Website
Guest Editor
State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum, 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,

In order to reach the carbon reduction and carbon neutrality advocated for to achieve global ecology, improving oil/gas recovery to balance the daily increasing energy demands, rather than reinforcing the dependence on coal consumption, is urgent. Meanwhile, after the depletion of regular oil/gas reservoirs, we are forced to switch our attention to complex conventional and unconventional oil/gas reservoirs, such as condensate gas reservoirs, fractured oil/gas reservoirs, tight oil/gas reservoirs, shale gas/oil, coalbed methane, etc. However, it is required to reveal the phase behavior and seepage mechanism of the fluids in the mentioned complex and unconventional oil/gas reservoirs urgently, and the corresponding productivity prediction and novel modeling methods are still lacking. In order to address this issue, we are pleased to invite you to submit papers to this new Special Issue of Energies, entirely devoted to “Oil and Gas Reservoirs: Phase Behavior, Seepage Mechanism, Productivity Prediction, and Novel Modeling Methods”. This Special Issue puts emphasis on the current challenges faced in the description of phase behavior and multiphase flow in matrix pores of the mentioned oil and gas reservoirs. At the same time, studies focused on the productivity, prediction, and production modeling methods used for these reservoirs are also welcomed.

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

  • Characterization of nanopore morphology in shale/coal samples;
  • Fluid phase behavior in abnormal high-pressure and high-temperature reservoirs;
  • Fluid phase behavior in nanopores of shale condensate gas reservoirs;
  • Original multiphase fluid occurrence state in deep oil/gas reservoirs;
  • Pore network modeling towards fluid flow in porous media;
  • Novel numerical simulation method upon complex development modes;
  • Fracture propagation characterization and long-term conductivity calculation;
  • Advanced production data analysis methods based on multiphase flow.

Dr. Juntai Shi
Dr. Zheng Sun
Guest Editors

Manuscript Submission Information

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Keywords

  • phase behavior
  • multiphase seepage mechanism
  • tight oil/gas
  • shale oil/gas
  • gas condensate reservoirs
  • fractured oil/gas reservoirs
  • coalbed methane
  • production prediction
  • stimulation measures
  • data science

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Related Special Issue

Published Papers (13 papers)

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Research

18 pages, 2007 KiB  
Article
Single Well Production Prediction Model of Gas Reservoir Based on CNN-BILSTM-AM
by Daihong Gu, Rongchen Zheng, Peng Cheng, Shuaiqi Zhou, Gongjie Yan, Haitao Liu, Kexin Yang, Jianguo Wang, Yuan Zhu and Mingwei Liao
Energies 2024, 17(22), 5674; https://doi.org/10.3390/en17225674 - 13 Nov 2024
Viewed by 376
Abstract
In the prediction of single-well production in gas reservoirs, the traditional empirical formula of gas reservoirs generally shows poor accuracy. In the process of machine learning training and prediction, the problems of small data volume and dirty data are often encountered. In order [...] Read more.
In the prediction of single-well production in gas reservoirs, the traditional empirical formula of gas reservoirs generally shows poor accuracy. In the process of machine learning training and prediction, the problems of small data volume and dirty data are often encountered. In order to overcome the above problems, a single-well production prediction model of gas reservoirs based on CNN-BILSTM-AM is proposed. The model is built by long-term and short-term memory neural networks, convolutional neural networks and attention modules. The input of the model includes the production of the previous period and its influencing factors. At the same time, the fitting production and error value of the traditional gas reservoir empirical formula are introduced to predict the future production data. The loss function is used to evaluate the deviation between the predicted data and the real data, and the Bayesian hyperparameter optimization algorithm is used to optimize the model structure and comprehensively improve the generalization ability of the model. Three single wells in the Daniudi D28 well area were selected as the database, and the CNN-BILSTM-AM model was used to predict the single-well production. The results show that compared with the prediction results of the convolutional neural network (CNN) model, long short-term memory neural network (LSTM) model and bidirectional long short-term memory neural network (BILSTM) model, the error of the CNN-BILSTM-AM model on the test set of three experimental wells is reduced by 6.2425%, 4.9522% and 3.0750% on average. It shows that on the basis of coupling the empirical formula of traditional gas reservoirs, the CNN-BILSTM-AM model meets the high-precision requirements for the single-well production prediction of gas reservoirs, which is of great significance to guide the efficient development of oil fields and ensure the safety of China’s energy strategy. Full article
(This article belongs to the Special Issue Oil and Gas Reservoirs: Phase Behavior, Seepage Mechanism, Productivity Prediction, and Novel Modelling Methods)
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18 pages, 6197 KiB  
Article
Phase Behavior and Rational Development Mode of a Fractured Gas Condensate Reservoir with High Pressure and Temperature: A Case Study of the Bozi 3 Block
by Yongling Zhang, Yangang Tang, Juntai Shi, Haoxiang Dai, Xinfeng Jia, Ge Feng, Bo Yang and Wenbin Li
Energies 2024, 17(21), 5367; https://doi.org/10.3390/en17215367 - 28 Oct 2024
Viewed by 462
Abstract
The Bozi 3 reservoir is an ultra-deep condensate reservoir (−7800 m) with a high temperature (138.24 °C) and high pressure (104.78 MPa), leading to complex phase behaviors. Few PVT studies could be referred in the literature to meet such high temperature and pressure [...] Read more.
The Bozi 3 reservoir is an ultra-deep condensate reservoir (−7800 m) with a high temperature (138.24 °C) and high pressure (104.78 MPa), leading to complex phase behaviors. Few PVT studies could be referred in the literature to meet such high temperature and pressure conditions. Furthermore, it is questionable regarding the applicability of existing condensate production techniques to such a high temperature and pressure reservoir. This study first characterized the phase behavior via PVT experiments and EOS tuning. The operating conditions were then optimized through reservoir numerical simulation. Results showed that: (1) the critical condensate temperature and pressure of Bozi 3 condensate gas were 326.24 °C and 43.83 MPa, respectively; (2) four gases (methane, recycled dry gas, carbon dioxide, and nitrogen) were analyzed, and methane was identified as the optimal injection gas; (3) gas injection started when the production began to fall and achieved higher recovery than gas injection started when the pressure fell below the dew-point pressure; (4) simultaneous injection of methane at both the upper and lower parts of the reservoir can effectively produce condensate oil over the entire block. This scheme achieved 8690.43 m3 more oil production and 2.75% higher recovery factor in comparison with depletion production. Full article
(This article belongs to the Special Issue Oil and Gas Reservoirs: Phase Behavior, Seepage Mechanism, Productivity Prediction, and Novel Modelling Methods)
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17 pages, 13288 KiB  
Article
Multi-Scale Visualization Study of Water and Polymer Microsphere Flooding through Horizontal Wells in Low-Permeability Oil Reservoir
by Liang Cheng, Yang Xie, Jie Chen, Xiao Wang, Zhongming Luo and Guo Chen
Energies 2024, 17(18), 4597; https://doi.org/10.3390/en17184597 - 13 Sep 2024
Viewed by 692
Abstract
Our target USH reservoir in the D oilfield is characterized by “inverse rhythm” deposition with the noticeable features of “high porosity and low permeability”. The reservoir has been developed with waterflooding using horizontal wells. Due to the strong heterogeneity of the reservoir, water [...] Read more.
Our target USH reservoir in the D oilfield is characterized by “inverse rhythm” deposition with the noticeable features of “high porosity and low permeability”. The reservoir has been developed with waterflooding using horizontal wells. Due to the strong heterogeneity of the reservoir, water channeling is severe, and the water cut has reached 79%. Considering the high temperature and high salinity reservoir conditions, polymer microspheres (PMs) were selected to realize conformance control. In this study, characterization of the polymer microsphere suspension was achieved via morphology, size distribution, and viscosity measurement. Furthermore, a multi-scale visualization study of the reservoir development process, including waterflooding, polymer microsphere flooding, and subsequent waterflooding, was conducted using macro-scale coreflooding and calcite-etched micromodels. It was revealed that the polymer microspheres could swell in the high salinity brine (170,000 ppm) by 2.7 times if aged for 7 days, accompanied by a viscosity increase. This feature is beneficial for the injection at the wellbore while swelled to work as a profile control agent in the deep formation. The macro-scale coreflood with a 30 cm × 30 cm × 4.5 cm layer model with 108 electrodes installed enabled the oil distribution visualization from different perpendicular cross sections. In this way, the in situ conformance control ability of the polymer microsphere was revealed both qualitatively and quantitatively. Furthermore, building on the calcite-etched visible micro-model, the pore-scale variation of the residual oil when subjected to waterflooding, polymer microsphere waterflooding, and subsequent waterflooding was collected, which revealed the oil displacement efficiency increase by polymer microspheres directly. The pilot test in the field also proves the feasibility of conformance control by the polymer microspheres, i.e., more than 40,000 bbls of oil increase was observed in the produces, accompanied by an obvious water reduction. Full article
(This article belongs to the Special Issue Oil and Gas Reservoirs: Phase Behavior, Seepage Mechanism, Productivity Prediction, and Novel Modelling Methods)
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14 pages, 2577 KiB  
Article
The Time-Varying Characteristics of Relative Permeability in Oil Reservoirs with Gas Injection
by Hengjie Liao, Xinzhe Liu, Xianke He, Yuansheng Li, Zhehao Jiang, Kaifen Li and Keliu Wu
Energies 2024, 17(17), 4512; https://doi.org/10.3390/en17174512 - 9 Sep 2024
Viewed by 644
Abstract
Relative permeability is a critical parameter in reservoir numerical simulation and production prediction, intimately associated with reservoir architecture and fluid property. During gas injection development, substantial alterations in reservoir properties and fluid phase behavior induce dynamic changes in relative permeability. Clearly characterizing the [...] Read more.
Relative permeability is a critical parameter in reservoir numerical simulation and production prediction, intimately associated with reservoir architecture and fluid property. During gas injection development, substantial alterations in reservoir properties and fluid phase behavior induce dynamic changes in relative permeability. Clearly characterizing the time-varying features of relative permeability is very useful for an understanding of how gas injection influences fluid mobility within the reservoir and enhances recovery rates. In this paper, core displacement experiments are firstly conducted to obtain the characteristics of the relative permeability of oil and gas under various development stages and displacement conditions, further delineating the comprehensive shifts in reservoir properties at different gas injection stages. Subsequently, a novel reservoir numerical simulation method is proposed that considers the spatial and temporal segmentation of relative permeability curves in the reservoir simulation. Finally, a practical application is presented to clarify the effects of injection and production parameters on the development performance of gas flooding oil reservoirs. The results show the following: (i) Significant time-varying characteristics of relative permeability occur throughout gas injection development, in the early stages of gas injection, where most of the reservoir is at the gas injection front, and a rightward shift in relative oil and gas permeability indicates that gas injection promotes oil mobility. Conversely, in the later stages of gas injection, as the reservoir reaches the trailing edge of gas injection, the change trend in relative oil and gas permeability reverses, shifting leftward, thereby exacerbating the gas breakout phenomena. (ii) Increasing the rate of gas injection causes relative oil and gas permeability to move leftward, effectively enhancing the gas volume sweep coefficient and microscopic oil displacement efficiency at lower injection speeds while reducing development performance at higher injection speeds. (iii) An increase in gas injection pressure causes relative oil and gas permeability to shift rightward, and although it reduces residual oil saturation and enhances microscopic oil displacement efficiency, it also intensifies gas breakout phenomena and lowers the gas volume sweep coefficient. This paper provides theoretical guidance and technical support for the design of gas injection strategies, optimization of injection and production parameters, and production forecasting. Full article
(This article belongs to the Special Issue Oil and Gas Reservoirs: Phase Behavior, Seepage Mechanism, Productivity Prediction, and Novel Modelling Methods)
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14 pages, 3871 KiB  
Article
Effects and Mechanisms of Dilute-Foam Dispersion System on Enhanced Oil Recovery from Pore-Scale to Core-Scale
by Xiuyu Wang, Rui Shen, Yuanyuan Gao, Shengchun Xiong and Chuanfeng Zhao
Energies 2024, 17(16), 4050; https://doi.org/10.3390/en17164050 - 15 Aug 2024
Viewed by 707
Abstract
The dilute-foam dispersion system improves oil recovery by reducing interfacial tension between oil and water, altering wettability, and diverting displaced fluids by plugging larger pores. An optimized foaming system is obtained by formability evaluation experiments, in which the half-life for drainage and foaming [...] Read more.
The dilute-foam dispersion system improves oil recovery by reducing interfacial tension between oil and water, altering wettability, and diverting displaced fluids by plugging larger pores. An optimized foaming system is obtained by formability evaluation experiments, in which the half-life for drainage and foaming volume by different types and concentrations of surfactants are analyzed, followed by the addition of partially hydrolyzed polyacrylamide (HPAM) with varied concentrations to enhance the foam stability. Using COMSOL Multiphysics 5.6 software, the Jamin effect and plugging mechanism of the water–gas dispersion system in narrow pore throats were simulated. This dispersion system is applied to assist CO2 huff-n-puff in a low-permeability core, combined with the online NMR method, to investigate its effects on enhanced oil recovery from the pore scale. Core-flooding experiments with double-pipe parallel cores are then performed to check the effect and mechanism of this dilute-foam dispersion system (DFDS) on enhanced oil recovery from the core scale. Results show that foam generated by combining 0.6% alpha-olefin sulfonate (AOS) foaming agent with 0.3% HPAM foam stabilizer exhibits the strongest foamability and the best foam stability. The recovery factor of the DFDS-assisted CO2 huff-n-puff method is improved by 6.13% over CO2 huff-n-puff, with smaller pores increased by 30.48%. After applying DFDS, the minimum pore radius for oil utilization is changed from 0.04 µm to 0.029 µm. The calculation method for the effective working distance of CO2 huff-n-puff for core samples is proposed in this study, and it is increased from 1.7 cm to 2.05 cm for the 5 cm long core by applying DFDS. Double-pipe parallel core-flooding experiments show that this dispersion system can increase the total recovery factor by 17.4%. The DFDS effectively blocks high-permeability layers, adjusts the liquid intake profile, and improves recovery efficiency in heterogeneous reservoirs. Full article
(This article belongs to the Special Issue Oil and Gas Reservoirs: Phase Behavior, Seepage Mechanism, Productivity Prediction, and Novel Modelling Methods)
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22 pages, 4857 KiB  
Article
Numerical Calculation and Application for Crushing Rate and Fracture Conductivity of Combined Proppants
by Zixi Guo, Dong Chen and Yiyu Chen
Energies 2024, 17(16), 3868; https://doi.org/10.3390/en17163868 - 6 Aug 2024
Viewed by 585
Abstract
Proppant is one of the key materials for hydraulic fracturing. For special situations, such as middle-deep reservoirs and closure pressures ranging from 40 MPa to 60 MPa, using a single proppant cannot solve the contradiction between performance, which means crushing rate and fracture [...] Read more.
Proppant is one of the key materials for hydraulic fracturing. For special situations, such as middle-deep reservoirs and closure pressures ranging from 40 MPa to 60 MPa, using a single proppant cannot solve the contradiction between performance, which means crushing rate and fracture conductivity, and cost. However, using combined proppants is an economically effective method for hydraulic fracturing of such special reservoirs. Firstly, for different types, particle sizes, and proportions of combined proppants, various contact relationships between proppant particles are considered. The random phenomenon of proppant particle arrangement is described using the Monte Carlo method, and the deterministic phenomenon of proppant particles is processed using an optimization model, achieving computer simulation of the microscopic arrangement of proppant particles. Secondly, a mathematical model for the force analysis of combined proppant particles is established, and an improved singular value decomposition method is used for numerical solution. A computational model for the crushing rate and fracture conductivity of combined proppants is proposed. Thirdly, the numerical calculation results are compared and discussed with the test values, verifying the accuracy of the computational model. Finally, the application of combined proppants is discussed, and a model for optimizing the proportion of combined proppants is proposed. The onsite construction technology is introduced, and the cost and economic benefits of combined proppants are compared with those of all ceramic particles and excessive all-quartz sand. It is proved that combined proppants can balance performance and price, and are an economically effective method for hydraulic fracturing of special reservoirs. The research results can select the optimal proppant material and optimize the combination of different proppant types, which can help achieve cost reduction and efficiency increase in oil and gas development. Full article
(This article belongs to the Special Issue Oil and Gas Reservoirs: Phase Behavior, Seepage Mechanism, Productivity Prediction, and Novel Modelling Methods)
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24 pages, 11113 KiB  
Article
Numerical Investigation of Hydraulic Fractures Vertical Propagation Mechanism for Enhanced Tight Gas Recovery
by Jianshu Wu, Baitao Fan, Guangai Wu, Chengyong Peng, Zhengrong Chen, Wei Yan, Cong Xiao, Wei Liu, Mingliang Wu and Lei Zou
Energies 2024, 17(15), 3785; https://doi.org/10.3390/en17153785 - 31 Jul 2024
Viewed by 865
Abstract
Hydraulic fracturing stands as a pivotal technological approach for enhanced tight gas recovery. This paper investigates the influences of geological and engineering parameters on the vertical extension mechanism of hydraulic fractures. In addition, the feasibility and effectiveness of fracture height prediction method and [...] Read more.
Hydraulic fracturing stands as a pivotal technological approach for enhanced tight gas recovery. This paper investigates the influences of geological and engineering parameters on the vertical extension mechanism of hydraulic fractures. In addition, the feasibility and effectiveness of fracture height prediction method and various fracture height control techniques have been examined. The results indicate that the height of hydraulic fractures decreases with an increase in the thickness of the barrier layers, the stress difference between the barrier and reservoir layers, the difference in tensile strength, and the difference in fracture toughness, whereas it increases with the increasing of difference in elastic modulus between the barrier and reservoir layers. Compred with the difference in Poisson’s ratio, the volume of fracturing fluid, discharge rate, and fluid viscosity have little impactd. The influence of these factors on fracture height, in descending order, is stress difference between barrier and reservoir layers, fracturing fluid viscosity, fracturing discharge, fracturing fluid volume, barrier layer thickness, tensile strength difference between barrier and reservoir layers, elastic modulus difference between barrier and reservoir layers, Poisson’s ratio difference between barrier and reservoir layers. Furthermore, based on typical geomechanic and reservoir parameters of the target area, a fracture height prediction workflow has been developed. Engineering practice has proven the reliability of fracture height prediction method. The results of this study provide theoretical support and guidance for predicting fracture morphology, controlling fracture height in the hydraulic fracturing development of the tight gas reservoir, and optimizing fracturing process design. Full article
(This article belongs to the Special Issue Oil and Gas Reservoirs: Phase Behavior, Seepage Mechanism, Productivity Prediction, and Novel Modelling Methods)
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13 pages, 3386 KiB  
Article
Study on Compatibility Evaluation of Multilayer Co-Production to Enhance Recovery of Water Flooding in Oil Reservoir
by Leng Tian, Xiaolong Chai, Lei Zhang, Wenbo Zhang, Yuan Zhu, Jiaxin Wang and Jianguo Wang
Energies 2024, 17(15), 3667; https://doi.org/10.3390/en17153667 - 25 Jul 2024
Viewed by 509
Abstract
Increasing oil production is crucial for multilayer co-production. When there are significant differences in the permeability of each layer, an interlayer contradiction arises that can impact the recovery efficiency. After a number of tests and the establishment of a mathematical model, the effects [...] Read more.
Increasing oil production is crucial for multilayer co-production. When there are significant differences in the permeability of each layer, an interlayer contradiction arises that can impact the recovery efficiency. After a number of tests and the establishment of a mathematical model, the effects of permeability contrast on oil production for water flooding were revealed. In the meantime, the developed mathematical model was solved using the Buckley–Lever seepage equation. Ultimately, the accuracy of the established model was confirmed by comparing the simulated outcomes of the mathematical model with the experimental results. The findings indicate that when permeability contrast increases, the production ratio of the high-permeability layer will improve. This is primarily due to the low-permeability layer’s production contribution rate decreasing. The accuracy of the established model is ensured by an error of less than 5% between the results of the experiment and the simulation. When the permeability contrast is less than three, the low-permeability layer can be effectively used for three-layer commingled production. However, when the permeability contrast exceeds six, the production coefficient of the low-permeability layer will be less than 5%, which has a significant impact on the layer’s development. Full article
(This article belongs to the Special Issue Oil and Gas Reservoirs: Phase Behavior, Seepage Mechanism, Productivity Prediction, and Novel Modelling Methods)
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18 pages, 14510 KiB  
Article
Research on Geological-Engineering Integration Numerical Simulation Based on EUR Maximization Objective
by Haoqi Chen, Hualin Liu, Cheng Shen, Weiyang Xie, Taixin Liu, Junfu Zhang, Jiangnuo Lu, Zhenglan Li and Yu Peng
Energies 2024, 17(15), 3644; https://doi.org/10.3390/en17153644 - 24 Jul 2024
Viewed by 620
Abstract
Shale gas reservoirs, as representative reservoirs in the Sichuan Basin, have attracted widespread attention regarding development. Using gas reservoir numerical simulation to assist development has greatly improved the work efficiency of workers. However, traditional gas reservoir numerical simulation is widely criticized for its [...] Read more.
Shale gas reservoirs, as representative reservoirs in the Sichuan Basin, have attracted widespread attention regarding development. Using gas reservoir numerical simulation to assist development has greatly improved the work efficiency of workers. However, traditional gas reservoir numerical simulation is widely criticized for its inability to effectively integrate with geological and engineering factors. In this study, we proposed a geological engineering integration method that considers pre-fracturing parameters. We further applied it to a typical well (N03) in a certain block of the Sichuan Basin. The reliability of the method was determined through historical fitting. Based on the N03 geological model, the optimization range of fracturing construction parameters in adjacent areas was determined with the goal of maximizing EUR. Recommended values for widely distributed construction parameter combinations of Class II reservoirs were provided through orthogonal analysis. The influence order of fracturing construction parameters is (1) sand addition strength, (2) cluster spacing, (3) construction displacement, (4) fracture fluid strength, and (5) horizontal segment length. Finally, we compared the simulated data with the actual case. The results showed that an integrated numerical simulation method including geological and engineering factors can comprehensively and accurately assist in reservoir development. Full article
(This article belongs to the Special Issue Oil and Gas Reservoirs: Phase Behavior, Seepage Mechanism, Productivity Prediction, and Novel Modelling Methods)
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18 pages, 6712 KiB  
Article
Investigation of Removing Asphaltene-Resin-Paraffin Deposits by Chemical Method for Azerbaijan High-Paraffin Oil Production Process
by Xiuyu Wang, Huseyn Gurbanov, Mehpara Adygezalova and Elnur Alizade
Energies 2024, 17(15), 3622; https://doi.org/10.3390/en17153622 - 24 Jul 2024
Viewed by 1963
Abstract
Asphaltene-resin-paraffin deposition (ARPD) is a complicated and prevalent issue in the oil and gas industry, impacting the efficiency and integrity of petroleum extraction, production, transportation and processing systems. Considering all witnessed ARPD problems in Azerbaijan oil fields, this paper proposed a chemical method [...] Read more.
Asphaltene-resin-paraffin deposition (ARPD) is a complicated and prevalent issue in the oil and gas industry, impacting the efficiency and integrity of petroleum extraction, production, transportation and processing systems. Considering all witnessed ARPD problems in Azerbaijan oil fields, this paper proposed a chemical method and optimized the type and concentration of chemical inhibitors. Then, the effect of selected chemical reagents on inhibiting the ARPD amount and thus enhancing oil recovery was detected by reservoir simulation during both waterflooding and CO2 flooding production. Three new chemical compounds (namely, Chemical-A, Chemical-B and Chemical-C) were examined in laboratory conditions, and their impact on rheological properties of high-paraffin oilfield samples of Azerbaijan (X, Y and Z) were investigated. Experimental results show that Chemical-C with a concentration of 600 g/t has the best efficiency for alleviating the problems. After adding Chemical-C to the crude oil, the freezing point of oil was decreased from 12 °C to (−4) °C, the ARPD amount declined from 0.185 to 0.016 g, and oil effective viscosity was reduced from 16.2 mPa·s to 3.1 mPa·s. It was determined that for water and CO2 flooding, higher injection pressure resulted in reduced asphaltene precipitation. Adding the selected ARPD inhibitor, the oil recovery for waterflooding can increase from 52% to 62%, while it can rise from 55% to 68% for CO2 flooding. Full article
(This article belongs to the Special Issue Oil and Gas Reservoirs: Phase Behavior, Seepage Mechanism, Productivity Prediction, and Novel Modelling Methods)
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17 pages, 10952 KiB  
Article
Density-Driven CO2 Dissolution in Depleted Gas Reservoirs with Bottom Aquifers
by Xiaocong Lyu, Fang Cen, Rui Wang, Huiqing Liu, Jing Wang, Junxi Xiao and Xudong Shen
Energies 2024, 17(14), 3491; https://doi.org/10.3390/en17143491 - 16 Jul 2024
Cited by 1 | Viewed by 798
Abstract
Depleted gas reservoirs with bottom water show significant potential for long-term CO2 storage. The residual gas influences mass-transfer dynamics, further affecting CO2 dissolution and convection in porous media. In this study, we conducted a series of numerical simulations to explore how [...] Read more.
Depleted gas reservoirs with bottom water show significant potential for long-term CO2 storage. The residual gas influences mass-transfer dynamics, further affecting CO2 dissolution and convection in porous media. In this study, we conducted a series of numerical simulations to explore how residual-gas mixtures impact CO2 dissolution trapping. Moreover, we analyzed the CO2 dissolution rate at various stages and delineated the initiation and decline of convection in relation to gas composition, thereby quantifying the influence of residual-gas mixtures. The findings elucidate that the temporal evolution of the Sherwood number observed in the synthetic model incorporating CTZ closely parallels that of the single-phase model, but the order of magnitude is markedly higher. The introduction of CTZ serves to augment gravity-induced convection and expedites the dissolution of CO2, whereas the presence of residual-gas mixtures exerts a deleterious impact on mass transfer. The escalation of residual gas content concomitantly diminishes the partial pressure and solubility of CO2. Consequently, there is an alleviation of the concentration and density differentials between saturated water and fresh water, resulting in the attenuation of the driving force governing CO2 diffusion and convection. This leads to a substantial reduction in the rate of CO2 dissolution, primarily governed by gravity-induced fingering, thereby manifesting as a delay in the onset and decay time of convection, accompanied by a pronounced decrement in the maximum Sherwood number. In the field-scale simulation, the injected CO2 improves the reservoir pressure, further pushing more gas to the producers. However, due to the presence of CH4 in the post-injection process, the capacity for CO2 dissolution is reduced. Full article
(This article belongs to the Special Issue Oil and Gas Reservoirs: Phase Behavior, Seepage Mechanism, Productivity Prediction, and Novel Modelling Methods)
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26 pages, 7567 KiB  
Article
An Artificial Neural Network Model for a Comprehensive Assessment of the Production Performance of Multiple Fractured Unconventional Tight Gas Wells
by Łukasz Klimkowski 
Energies 2024, 17(13), 3091; https://doi.org/10.3390/en17133091 - 22 Jun 2024
Viewed by 1499
Abstract
The potential of unconventional hydrocarbon resources has been unlocked since the hydraulic fracturing technique in combination with long horizontal wells was applied to develop this type of reservoir economically. The design and optimization of the fracturing treatment and the stimulated reservoir volume and [...] Read more.
The potential of unconventional hydrocarbon resources has been unlocked since the hydraulic fracturing technique in combination with long horizontal wells was applied to develop this type of reservoir economically. The design and optimization of the fracturing treatment and the stimulated reservoir volume and the forecasting of production performance are crucial for the development and management of such resources. However, the production performance of tight gas reservoirs is a complicated nonlinear problem, described by many parameters loaded with uncertainty. The complexity of the problem influences and inspires the sophistication of the solution to be used. This paper proposed an artificial network model that allows for fast, extended, and accurate analyses of the production performance of multiple fractured unconventional tight gas wells. In the comprehensive approach developed, the reservoir rock parameters, the drainage area, and the hydraulic fracture parameters are treated as a variable input to the model. The analysis is no longer constrained by fixed “shoes box” geometry, and the values of the parameters defining the reservoir and stimulated volume are not limited to a few discrete values. The numerical experiment used to construct a database for model development was designed using a genetically optimized Latin hypercube sampling technique. A special approach was used in the preparation of “blind data”, which are crucial for truly reliable model verification. In the result, a developed tool offers an extended rock-fluid description, flexible model, and stimulated reservoir volume dimensioning and parameterization, as well as a high degree of applicability in sensitivity analysis and/or optimization. Full article
(This article belongs to the Special Issue Oil and Gas Reservoirs: Phase Behavior, Seepage Mechanism, Productivity Prediction, and Novel Modelling Methods)
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10 pages, 1478 KiB  
Article
Effect Evaluation of Staged Fracturing and Productivity Prediction of Horizontal Wells in Tight Reservoirs
by Yuan Zhang, Jianyang Chen, Zhongbao Wu, Yuxiang Xiao, Ziyi Xu, Hanlie Cheng and Bin Zhang
Energies 2024, 17(12), 2894; https://doi.org/10.3390/en17122894 - 13 Jun 2024
Cited by 1 | Viewed by 743
Abstract
In this paper, the effect evaluation and production prediction of staged fracturing for horizontal wells in tight reservoirs are studied. Firstly, the basic characteristics and value of horizontal wells in tight reservoirs are introduced, their geological characteristics, flow mechanism and permeability model are [...] Read more.
In this paper, the effect evaluation and production prediction of staged fracturing for horizontal wells in tight reservoirs are studied. Firstly, the basic characteristics and value of horizontal wells in tight reservoirs are introduced, their geological characteristics, flow mechanism and permeability model are analyzed and the application of grey theory in effect analysis is discussed. Considering the problems of staged fracturing effect evaluation and the production prediction of horizontal wells in tight reservoirs, a BP neural network model based on deep learning is proposed. Due to the interference of multiple physical parameters and the complex functional relationship in the development of tight reservoir fracturing, the traditional prediction method has low accuracy and it is difficult to establish an accurate mapping relationship. In this paper, a BP neural network is used to simulate multivariable nonlinear mapping by modifying the model, and its advantages in solving the coupling relationship of complex functions are brought into play. A neural network model with fracturing parameters as input and oil and gas production as output is designed. Through the training and testing of data sets, the accuracy and applicability of the proposed model for effect evaluation and yield prediction are verified. The research results show that the model can fit the complex mapping relationship between fracturing information and production and provide an effective evaluation and prediction tool for the development of the staged fracturing of horizontal wells in tight reservoirs. Full article
(This article belongs to the Special Issue Oil and Gas Reservoirs: Phase Behavior, Seepage Mechanism, Productivity Prediction, and Novel Modelling Methods)
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