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5 pages, 147 KiB

Open AccessEditorial

Special Issue: Advances in Enhancing Unconventional Oil/Gas Recovery

by Tao Zhang, Zheng Sun, Dong Feng and Wen Zhao

Processes 2024, 12(7), 1386; https://doi.org/10.3390/pr12071386 - 3 Jul 2024

Cited by 1 | Viewed by 805

Abstract

In recent years, unconventional reservoirs such as tight gas/oil reservoirs [...] Full article

(This article belongs to the Special Issue Advances in Enhancing Unconventional Oil/Gas Recovery)

Research

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12 pages, 1507 KiB

Open AccessArticle

Research on Optimization of Sulfur Solubility Testing Method for High-Sulfur Natural Gas

by Ying Wan, Li Wang, Yan Yang, Zhao Ding, Daqing Tang, Dihong Zhang and Linling Zhang

Processes 2024, 12(6), 1210; https://doi.org/10.3390/pr12061210 - 13 Jun 2024

Viewed by 849

Abstract

At present, the methods for sulfur solubility testing of high-sulfur natural gas generally use laboratory proportioning gas samples and then connect equipment to test the sulfur solubility of the gas samples based on the adsorption deposition mechanism. However, these testing methods generally have [...] Read more.

At present, the methods for sulfur solubility testing of high-sulfur natural gas generally use laboratory proportioning gas samples and then connect equipment to test the sulfur solubility of the gas samples based on the adsorption deposition mechanism. However, these testing methods generally have the following problems: (1) The equipment used in these test methods has safety hazards such as leakage at pipe and valve connections. (2) The sulfur solubility of real gas samples cannot be measured directly. (3) The equipment is difficult to clean, and it is especially difficult to clean the sulfur deposited at pipe elbows and valve connections. This will lead to low sulfur solubility test results. (4) The thermal insulation performance during the test process is not good, and temperature changes have a great impact on gas volume measurement. In order to solve the above problems, a testing method and comprehensive experimental device for the solubility of elemental sulfur in high-sulfur natural gas were established. This test method wraps the entire experimental device with a metal shell, which has good safety and thermal insulation performance, and it uses customized pipeline connections, which have high flushing efficiency, less sulfur deposition, and more accurate experimental results. The upgraded filtration system can directly measure the sulfur dissolution of real gas samples, and a CS₂ solution recovery process is added to reduce the risk of leakage and environmental pollution. This method and equipment were used to test the elemental sulfur solubility determination of real gas samples from a high-sulfur gas well. The research results show that the solubility of elemental sulfur is related to temperature, pressure, and H₂S concentration and increases with the increase in temperature, pressure, and H₂S concentration. Compared with the previous method, this method has less residual sulfur during the test process, the measured sulfur solubility is 2.13% greater, and the test results are more accurate and reliable. This research result provides important basic data support for accurately measuring the elemental sulfur solubility of real gas samples in high-sulfur gas reservoirs and dealing with sulfur deposition problems. Full article

(This article belongs to the Special Issue Advances in Enhancing Unconventional Oil/Gas Recovery)

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13 pages, 3593 KiB

Open AccessArticle

Prediction of Single-Well Production Rate after Hydraulic Fracturing in Unconventional Gas Reservoirs Based on Ensemble Learning Model

by Fan Ye, Xiaobo Li, Nan Zhang and Feng Xu

Processes 2024, 12(6), 1194; https://doi.org/10.3390/pr12061194 - 11 Jun 2024

Cited by 3 | Viewed by 1095

Abstract

To address the significant challenges in determining the single-well production of tight gas and shale gas after hydraulic fracturing, artificial intelligence (AI) methods were implemented. Machine learning (ML) algorithms such as random forest (RF), extremely randomized trees (ET), lightweight gradient boosting machines (LightGBM), [...] Read more.

To address the significant challenges in determining the single-well production of tight gas and shale gas after hydraulic fracturing, artificial intelligence (AI) methods were implemented. Machine learning (ML) algorithms such as random forest (RF), extremely randomized trees (ET), lightweight gradient boosting machines (LightGBM), gradient boosting regression (GBR), and linear regression (LR) were utilized in conjunction with reservoir geology, engineering parameters, and production data to develop several foundational models for forecasting the production of unconventional gas wells. The accuracy of these models was evaluated. Based on this, improvements in the models’ predictive accuracy and generalizability were achieved through the ensemble of machine learning models. Furthermore, this paper selected two representative tight and shale gas reservoirs to demonstrate the application of the ensemble model for well production forecasting, and a comparative analysis with actual production data was conducted. For tight gas reservoir A, the blending model achieved an MAE of 0.8419 and an MSE of 1.0930, with an R² score of 0.8812. For shale gas reservoir B, the blending model achieved an MAE of 1.4841 and an MSE of 3.1629, with an R² score of 0.9524. The results of the case studies indicate that the ensemble model approach employed in this study has a higher predictive accuracy and reliability than a single machine learning algorithm, and is capable of handling high-dimensional, large-scale, and imbalanced data, offering scientific validation and technical support for the assessment of the well productivity in tight and shale gas wells. Full article

(This article belongs to the Special Issue Advances in Enhancing Unconventional Oil/Gas Recovery)

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24 pages, 7162 KiB

Open AccessArticle

Oil Removal Technology for Water Injection in Low-Permeability Reservoirs: A Micro-Vortex Flow Approach

by Dawei Zhao, Weihong Xie, Jingyi Zhu, Bing Li, Lirong Wang, Tao Chen, Yuxin Sheng and Xiujie Huang

Processes 2024, 12(6), 1092; https://doi.org/10.3390/pr12061092 - 27 May 2024

Viewed by 966

Abstract

Gravity settling is a widely employed technology that removes oil from produced water in oilfields. However, with the transition of reservoir development to low-permeability reservoirs, conventional produced water settling tanks face limitations in the treatment efficiency and coagulant dosage. This study presents an [...] Read more.

Gravity settling is a widely employed technology that removes oil from produced water in oilfields. However, with the transition of reservoir development to low-permeability reservoirs, conventional produced water settling tanks face limitations in the treatment efficiency and coagulant dosage. This study presents an innovative approach that optimizes sedimentation tank structures and integrates micro-vortex flow technology to enhance coagulation and flocculation. Through chemical dosage experiments, comparative experiments, and long-term observation, the micro-vortex flow reactor demonstrates a 9.4% increase in oil removal efficiency while reducing the coagulant dosage by 30.0%. The MOR equipment achieved a 20.5% higher oil removal efficiency than conventional methods while maintaining effluent oil and suspended solids below 20 mg/L. The long-term observation experiment of MOR equipment further highlights oil removal efficiency of 94.2% and the micro-vortex reactor’s excellent anti-pollution performance. The MOR equipment significantly reduces the land occupancy area by over 50% compared to conventional methods, thanks to the implementation of micro-vortex flow technology that effectively addresses the limitations associated with traditional settling tanks. This study contributes to advancing efficient and sustainable practices in waterflooding reservoirs, particularly for meeting stringent standards of water injection in low-permeability oilfields. Full article

(This article belongs to the Special Issue Advances in Enhancing Unconventional Oil/Gas Recovery)

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12 pages, 3994 KiB

Open AccessArticle

Study on the Flow Behavior of Gas and Water in Fractured Tight Gas Reservoirs Considering Matrix Imbibition Using the Digital Core Method

by Feifei Chen, Yonggang Duan and Kun Wang

Processes 2024, 12(4), 709; https://doi.org/10.3390/pr12040709 - 30 Mar 2024

Viewed by 915

Abstract

Tight gas reservoirs possess unique pore structures and fluid flow mechanisms. Delving into the flow and imbibition mechanisms of water in fractured tight gas reservoirs is crucial for understanding and enhancing the development efficiency of such reservoirs. The flow of water in fractured [...] Read more.

Tight gas reservoirs possess unique pore structures and fluid flow mechanisms. Delving into the flow and imbibition mechanisms of water in fractured tight gas reservoirs is crucial for understanding and enhancing the development efficiency of such reservoirs. The flow of water in fractured tight gas reservoirs encompasses the flow within fractures and the imbibition flow within the matrix. However, conventional methods typically separate these two types of flow for study, failing to accurately reflect the true flow characteristics of water. In this study, micro-CT imaging techniques were utilized to evaluate the impact of matrix absorption and to examine water movement in fractured tight gas deposits. Water flooding experiments were conducted on tight sandstone cores with different fracture morphologies. Micro-CT scanning was performed on the cores after water injection and subsequent static conditions, simulating the process of water displacement gas in fractures and the displacement of gas in matrix pores by water through imbibition under reservoir conditions. Changes in gas–water distribution within fractures were observed, and the impact of fracture morphology on water displacement recovery was analyzed. Additionally, the recovery rates of fractures and matrix imbibition at different displacement stages were studied, along with the depth of water infiltration into the matrix along fracture walls. The insights gained from this investigation enhance our comprehension of the dynamics of fluid movement within tight gas deposits, laying a scientific foundation for crafting targeted development plans and boosting operational efficiency in such environments. Full article

(This article belongs to the Special Issue Advances in Enhancing Unconventional Oil/Gas Recovery)

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19 pages, 3715 KiB

Open AccessArticle

Research on the Scaling Mechanism and Countermeasures of Tight Sandstone Gas Reservoirs Based on Machine Learning

by Xu Su, Desheng Zhou, Haiyang Wang and Jinze Xu

Processes 2024, 12(3), 527; https://doi.org/10.3390/pr12030527 - 6 Mar 2024

Cited by 1 | Viewed by 1122

Abstract

The Sulige gas field is a typical “three lows” (low permeability, low pressure, and low abundance) tight sandstone gas reservoir, with formation pressures often characterized by abnormally high or low pressures. The complex geological features of the reservoir further deviate from conventional understanding, [...] Read more.

The Sulige gas field is a typical “three lows” (low permeability, low pressure, and low abundance) tight sandstone gas reservoir, with formation pressures often characterized by abnormally high or low pressures. The complex geological features of the reservoir further deviate from conventional understanding, impacting the effective implementation of wellbore blockage removal measures. Therefore, it is imperative to establish the wellbore blockage mechanism, prediction model, and effective prevention measures for the target area. In this study, based on field data, we first experimentally analyzed the water quality and types of blockage in the target area. Subsequently, utilizing a BP neural network model, we established a model for predicting the risk of wellbore blockage and analyzing mitigation measures in the target reservoir. The model’s prediction results, consistent with on-site actual results, demonstrate its reliability and accuracy. Experimental results show that the water quality in the target area is mainly a CaCl₂ type, and the predominant scales produced are CaCO₃ and BaSO₄. Model calculations reveal that temperature, pressure, and ion concentration all influence scaling, with BaSO₄ more influenced by pressure and CaCO₃ more influenced by temperature. Under the combined effect of temperature, pressure, and ion concentration, different types of scales exhibit distinct trends in scaling quantity. Combining scaling quantity calculations with wellbore contraction ratios, it was found that when the temperature, pressure, and ion concentration are within a certain range, the wellbore contraction rate can be controlled below 4%. At this point, the wellbore scaling risk is minimal, and preventive measures against wellbore scaling can be achieved by adjusting production systems, considering practical production conditions. This study investigates the mechanism of scaling in wellbores of tight sandstone gas reservoirs and proposes a cost-effective scaling prevention measure. This approach can guide the prediction of scaling risks and the implementation of scaling prevention measures for gas wells in tight sandstone reservoirs. Full article

(This article belongs to the Special Issue Advances in Enhancing Unconventional Oil/Gas Recovery)

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16 pages, 7634 KiB

Open AccessArticle

Research on Fluid–Solid Coupling Mechanism around Openhole Wellbore under Transient Seepage Conditions

by Erhu Liu, Desheng Zhou, Xu Su, Haiyang Wang, Xiong Liu and Jinze Xu

Processes 2024, 12(2), 412; https://doi.org/10.3390/pr12020412 - 18 Feb 2024

Viewed by 1028

Abstract

Hydraulic fracturing is one of the most important enhanced oil recovery technologies currently used to develop unconventional oil and gas reservoirs. During hydraulic fracture initiation, fluid seeps into the reservoir rocks surrounding the wellbore, inducing rock deformation and changes in the stress field. [...] Read more.

Hydraulic fracturing is one of the most important enhanced oil recovery technologies currently used to develop unconventional oil and gas reservoirs. During hydraulic fracture initiation, fluid seeps into the reservoir rocks surrounding the wellbore, inducing rock deformation and changes in the stress field. Analyzing the fluid–solid coupling mechanism around the wellbore is crucial to the construction design of fracturing technologies such as pulse fracturing and supercritical carbon dioxide fracturing. In this study, a new transient fluid–solid coupling model, capable of simulating the pore pressure field and effective stress field around the wellbore, was established based on the Biot consolidation theory combined with the finite difference method. The numerical results are in excellent agreement with the analytical solutions, indicating the reliability of the model and the stability of the computational approach. Using this model, the influence of seepage parameters and reservoir properties on the fluid–solid coupling around the open-hole wellbore was investigated. The simulation results demonstrate that, during wellbore pressurization, significant changes occur in the pore pressure field and effective stress field near the wellbore. The fluid–solid coupling effect around the wellbore returns to its initial state when the distance exceeds four times the radius away from the wellbore. As the fluid viscosity and wellbore pressurization rate decrease, the pore pressure field and effective circumferential stress (ECS) field around the wellbore become stronger. Adjusting the fluid viscosity and wellbore pressurization rate can control the effect of seepage forces on the rock skeleton during wellbore fluid injection. For the same injection conditions, rocks with q higher Young’s modulus and Poisson’s ratio exhibit stronger pore pressure fields and ECS fields near the wellbore. This model furnishes a dependable numerical framework for examining the fluid–solid coupling mechanism surrounding the open-hole wellbore in the initiation phase of hydraulic fractures. Full article

(This article belongs to the Special Issue Advances in Enhancing Unconventional Oil/Gas Recovery)

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20 pages, 3510 KiB

Open AccessArticle

New Method for Capacity Evaluation of Offshore Low-Permeability Reservoirs with Natural Fractures

by Kun Wang, Mingying Xie, Weixin Liu, Li Li, Siyu Liu, Ruijie Huang, Shasha Feng, Guotao Liu and Min Li

Processes 2024, 12(2), 347; https://doi.org/10.3390/pr12020347 - 6 Feb 2024

Cited by 1 | Viewed by 846

Abstract

In recent years, the development of two offshore low-permeability oil fields has revealed unexpected challenges. The actual productivity of these fields significantly deviates from the designed capacity. Some wells even outperform the expectations for low-permeability limestone fields. This discrepancy primarily stems from a [...] Read more.

In recent years, the development of two offshore low-permeability oil fields has revealed unexpected challenges. The actual productivity of these fields significantly deviates from the designed capacity. Some wells even outperform the expectations for low-permeability limestone fields. This discrepancy primarily stems from a lack of accurate understanding of natural fractures before and after drilling, resulting in substantial errors in capacity assessment. This paper addresses these challenges by proposing a new production capacity model and evaluation method for both vertical and horizontal wells in low-permeability limestone reservoirs. The method leverages logging curve data, incorporating vertical gradation and fractal analysis to effectively represent the fracture’s complexity and connectivity. It uniquely considers factors such as fracture fractal dimensions, threshold pressure, and stress sensitivity, significantly enhancing prediction accuracy. Furthermore, by analyzing the longitudinal gradient in logging curves, the method effectively identifies strong heterogeneity, leading to more accurate capacity evaluations in actual fields. The results demonstrate that our model reduces the average prediction error to less than 15%, markedly outperforming traditional methods. Calculation results of the newly developed capacity formula align closely with actual production data and tracer test results, showcasing its practical applicability and potential for widespread use. This study notably advances the evaluation of reasonable production capacity in similar offshore reservoirs. Full article

(This article belongs to the Special Issue Advances in Enhancing Unconventional Oil/Gas Recovery)

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17 pages, 6882 KiB

Open AccessArticle

Modeling of Quantitative Characterization Parameters and Identification of Fluid Properties in Tight Sandstone Reservoirs of the Ordos Basin

by Bo Xu, Zhenhua Wang, Ting Song, Shuxia Zhang, Jiao Peng, Tong Wang and Yatong Chen

Processes 2024, 12(2), 278; https://doi.org/10.3390/pr12020278 - 26 Jan 2024

Viewed by 980

Abstract

The Ordos Basin has abundant resources in its tight sandstone reservoirs, and the use of well logging technology stands out as a critical element in the exploration and development of these reservoirs. Unlike conventional reservoirs, the commonly used interpretation models are not ideal [...] Read more.

The Ordos Basin has abundant resources in its tight sandstone reservoirs, and the use of well logging technology stands out as a critical element in the exploration and development of these reservoirs. Unlike conventional reservoirs, the commonly used interpretation models are not ideal for evaluating tight sandstone reservoirs through logging. In order to accurately evaluate parameters and identify fluid properties in the tight sandstone reservoirs of the Ordos Basin, we propose the adaption of conventional logging curves. This involves establishing an interpretation model that integrates the response characteristics of logging curves to tight sandstone reservoirs in accordance with the principles of logging. In this approach, we create interpretation models specifically for shale content, porosity, permeability, and saturation within the tight sandstone reservoir. Using the characteristics of the logging curves and their responses, we apply a mathematical relationship to link these parameters and create a template for identifying fluid properties within tight sandstone reservoirs. The average absolute errors of the new multi-parameter weighting method shale content interpretation model and porosity classification saturation interpretation model for quantitative evaluation of reservoir shale content and oil saturation are small, and the accuracy meets the production requirements. In this paper, the four-step method is used to identify the fluid properties of tight sandstone reservoirs step by step, which is to use the interrelationship between curves, eliminate the useless information, enhance the useful information, and finally solve the problem of identifying the fluid properties of tight sandstone reservoirs, which is difficult to identify, and realize the linear discrimination of the interpretation standard, which improves the accuracy of interpretation. The proven multi-information, four-step, step-by-step fluid property identification template has an accuracy of more than 90%. The interpretation model has been applied to 20 wells on the block with a compliance rate of 95.23%, providing the basis for accurately establishing the tight sandstone interpretation standard. The newly introduced log evaluation approach for tight sandstone reservoirs effectively overcomes the technical hurdles that have previously hindered the evaluation of such reservoirs in the Ordos Basin. This method is suitable for wide application and can be used for quantitative evaluation of tight sandstone reservoirs in different regions. Full article

(This article belongs to the Special Issue Advances in Enhancing Unconventional Oil/Gas Recovery)

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16 pages, 3941 KiB

Open AccessArticle

Bottomhole Pressure Prediction of Carbonate Reservoirs Using XGBoost

by Hao Sun, Qiang Luo, Zhaohui Xia, Yunbo Li and Yang Yu

Processes 2024, 12(1), 125; https://doi.org/10.3390/pr12010125 - 3 Jan 2024

Cited by 4 | Viewed by 1168

Abstract

The bottomhole pressure is one of the key parameters for oilfield development and decision-making. However, due to factors such as cost and equipment failure, bottomhole pressure data is often lacking. In this paper, we established a GA-XGBoost model to predict the bottomhole pressure [...] Read more.

The bottomhole pressure is one of the key parameters for oilfield development and decision-making. However, due to factors such as cost and equipment failure, bottomhole pressure data is often lacking. In this paper, we established a GA-XGBoost model to predict the bottomhole pressure in carbonate reservoirs. Firstly, a total of 413 datasets, including daily oil production, daily water production, daily gas production, daily liquid production, daily gas injection rate, gas–oil ratio, and bottomhole pressure, were collected from 14 wells through numerical simulation. The production data were then subjected to standardized preprocessing and dimensionality reduction using a principal component analysis. The data were then split into training, testing, and validation sets with a ratio of 7:2:1. A prediction model for the bottomhole pressure in carbonate reservoirs based on XGBoost was developed. The model parameters were optimized using a genetic algorithm, and the average adjusted R-squared score from the cross-validation was used as the optimization metric. The model achieved an adjusted R-squared score of 0.99 and a root-mean-square error of 0.0015 on the training set, an adjusted R-squared score of 0.84 and a root-mean-square error of 0.0564 on the testing set, and an adjusted R-squared score of 0.69 and a root-mean-square error of 0.0721 on the validation set. The results demonstrated that in the case of fewer data variables, the GA-XGBoost model had a high accuracy and good generalization performance, and its performance was superior to other models. Through this method, it is possible to quickly predict the bottomhole pressure data of carbonate rocks while saving measurement costs. Full article

(This article belongs to the Special Issue Advances in Enhancing Unconventional Oil/Gas Recovery)

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31 pages, 11750 KiB

Open AccessArticle

A Dynamic Permeability Model in Shale Matrix after Hydraulic Fracturing: Considering Mineral and Pore Size Distribution, Dynamic Gas Entrapment and Variation in Poromechanics

by Qihui Zhang, Haitao Li, Ying Li, Haiguang Wang and Kuan Lu

Processes 2024, 12(1), 117; https://doi.org/10.3390/pr12010117 - 2 Jan 2024

Cited by 1 | Viewed by 1804

Abstract

Traditional research on apparent permeability in shale reservoirs has mainly focussed on effects such as poromechanics and porosity-assisted adsorption layers. However, for a more realistic representation of field conditions, a comprehensive multi-scale and multi-flowing mechanism model, considering the fracturing process, has not been [...] Read more.

Traditional research on apparent permeability in shale reservoirs has mainly focussed on effects such as poromechanics and porosity-assisted adsorption layers. However, for a more realistic representation of field conditions, a comprehensive multi-scale and multi-flowing mechanism model, considering the fracturing process, has not been thoroughly explored. To address this research gap, this study introduces an innovative workflow for dynamic permeability assessment. Initially, an accurate description of the pore size distribution (PSD) within three major mineral types in shale is developed using focussed ion beam-scanning electron microscopy (FIB-SEM) and nuclear magnetic resonance (NMR) data. Subsequently, an apparent permeability model is established by combining the PSD data, leading to the derivation of dynamic permeability. Finally, the PSD-related dynamic permeability model is refined by incorporating the effects of imbibition resulting from the fracturing process preceding shale gas production. The developed dynamic permeability model varies with pore and fracture pressures in the shale reservoir. The fracturing process induces water blockage, water-film formation, and water-bridging phenomena in shale, requiring additional pressure inputs to counteract capillary effects in hydrophilic minerals in shale, But also increases the overall permeability from increasing permeability at larger scale pores. Unlike traditional reservoirs, the production process commences when the fracture is depleted to 1–2 MPa exceeds the pore pressure, facilitated by the high concentration of hydrophobic organic matter pores in shale, this phenomenon explains the gas production at the intial production stage. The reduction in adsorption-layer thickness resulting from fracturing impacts permeability on a nano-scale by diminishing surface diffusion and the corresponding slip flow of gas. this phenomenon increases viscous-flow permeability from enlarged flow spacing, but the increased viscous flow does not fully offset the reduction caused by adsorbed-gas diffusion and slip flow. In addition to the phenomena arising from various field conditions, PSD in shale emerges as a crucial factor in determining dynamic permeability. Furthermore, considering the same PSD in shale, under identical pore spacing, the shape factor of slit-like clay minerals significantly influences overall permeability characteristics, much more slit-shaped pores(higher shape factor) reduce the overall permeability. The dynamic permeability-assisted embedded discrete fracture model (EDFM) showed higher accuracy in predicting shale gas production compared to the original model. Full article

(This article belongs to the Special Issue Advances in Enhancing Unconventional Oil/Gas Recovery)

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13 pages, 9107 KiB

Open AccessArticle

A Study on the Production Simulation of Coal–Shale Interbedded Coal Measure Superimposed Gas Reservoirs under Different Drainage Methods

by Wenkai Wang, Shiqi Liu, Shuxun Sang, Ruibin Du and Yinghai Liu

Processes 2023, 11(12), 3424; https://doi.org/10.3390/pr11123424 - 13 Dec 2023

Cited by 1 | Viewed by 854

Abstract

To study the influence of different drainage methods on the production performance of coal measure gas wells, the interbedded reservoir composed of coal and shale in the Longtan Formation of the Dahebian block was used as the research object. Considering the influence of [...] Read more.

To study the influence of different drainage methods on the production performance of coal measure gas wells, the interbedded reservoir composed of coal and shale in the Longtan Formation of the Dahebian block was used as the research object. Considering the influence of coal and shale matrix shrinkage, effective stress, and interlayer fluid flow on reservoir properties such as fluid migration behavior and permeability, a fluid–solid coupling mathematical model of coal measure superimposed gas reservoirs was established. Numerical simulations of coal measure gas production under different drainage and production modes were conducted to analyze the evolution of reservoir pressure, gas content in the matrix, permeability, and other characteristic parameters of the superimposed reservoir, as well as differences in interlayer flow. The results showed that, compared to single-layer drainage, cumulative gas production increased by 33% under multi-layer drainage. Both drainage methods involve interlayer energy and substance transfer. Due to the influence of permeability, porosity, and mechanical properties, significant differences exist in reservoir pressure distribution, preferential flow direction, gas content in the matrix, and permeability ratio between coal and shale reservoirs under different drainage and production modes. Multi-layer drainage effectively alleviates the influence of vertical reservoir pressure differences between reservoir layers, facilitates reservoir pressure transmission in shale reservoirs, enhances methane desorption in shale matrices, promotes matrix shrinkage, and induces the rebound of shale reservoir permeability, thus improving overall gas production. Full article

(This article belongs to the Special Issue Advances in Enhancing Unconventional Oil/Gas Recovery)

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21 pages, 4178 KiB

Open AccessArticle

Effects of Pore Water Content on Stress Sensitivity of Tight Sandstone Oil Reservoirs: A Study of the Mahu Block (Xinjiang Province, China)

by Xiaoshan Li, Kaifang Gu, Wenxiu Xu, Junqiang Song, Hong Pan, Yan Dong, Xu Yang, Haoyu You, Li Wang, Zheng Fu, Lingqi Liu and Ke Wang

Processes 2023, 11(11), 3153; https://doi.org/10.3390/pr11113153 - 4 Nov 2023

Cited by 1 | Viewed by 1338

Abstract

Traditional stress sensitivity experiments are typically conducted under dry conditions, without considering the reservoir’s water content. In reality, the presence of water within pores significantly influences the extent of stress sensitivity damage in tight sandstone oil formations, subsequently affecting the determination of stress [...] Read more.

Traditional stress sensitivity experiments are typically conducted under dry conditions, without considering the reservoir’s water content. In reality, the presence of water within pores significantly influences the extent of stress sensitivity damage in tight sandstone oil formations, subsequently affecting the determination of stress sensitivity coefficients during experimentation. By investigating sandstone samples from wells in the Mahu Block of China’s Xinjiang province, we observed that increasing water saturation reduces the stress sensitivity of tight sandstone. By conducting stress sensitivity experiments under varying water content conditions, we found that the stress sensitivity coefficient is not a constant value but decreases as water saturation increases. Based on experimental comparisons, an optimized power-law model for stress-sensitive damage assessment was refined. By conducting stress-sensitive damage assessment experiments under different water content conditions and integrating the concept of comprehensive compression coefficient, an improved stress-sensitive power-law model was established allowing for the influence of water content. The accuracy of this improved model was increased by 46.98% compared to the original power-law model through experimental validation. The research outcomes can enhance the accuracy of permeability and productivity evaluation, providing valuable guidance for unconventional oil and gas development. Full article

(This article belongs to the Special Issue Advances in Enhancing Unconventional Oil/Gas Recovery)

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21 pages, 4956 KiB

Open AccessArticle

A Semi-Analytical Model for Production Prediction of Deep CBM Wells Considering Gas-Water Two-Phase Flow

by Suran Wang, Dongjun Li and Wenlan Li

Processes 2023, 11(10), 3022; https://doi.org/10.3390/pr11103022 - 20 Oct 2023

Cited by 5 | Viewed by 1227

Abstract

The productivity prediction of deep coalbed methane (CBM) wells is significantly influenced by gas-water two-phase flow characteristics and seepage parameters of the fracture network. While numerical simulations offer a comprehensive approach, analytical models are favored for their faster and broader applicability. However, conventional [...] Read more.

The productivity prediction of deep coalbed methane (CBM) wells is significantly influenced by gas-water two-phase flow characteristics and seepage parameters of the fracture network. While numerical simulations offer a comprehensive approach, analytical models are favored for their faster and broader applicability. However, conventional analytical models often oversimplify the complex problem of two-phase seepage equations, leading to substantial errors in dynamic analysis outcomes. Addressing this shortcoming, we establish a gas-water two-phase productivity prediction model for deep CBM reservoirs. This model takes into account the two-phase flow characteristics within the reservoir and fracture network, as well as the stress sensitivity of the reservoir and fractures. Additionally, a modified trilinear flow model characterizes the fractured modification body. By integrating the flowing material balance equation with the Newton Iteration method, we gradually update the seepage model’s nonlinear parameters using the average formation pressure. We also linearize the gas-water two-phase model through successive iterations to derive a semi-analytical solution. The accuracy of the model was verified through comparison with commercial numerical simulation software results and field application. The model also enabled us to scrutinize the influence of reservoir and fracture network parameters on productivity. Our research findings suggest that the semi-analytical solution approach can efficiently address the nonlinear seepage problem of gas-water two-phase flow, enabling quick and accurate prediction of deep CBM well productivity. Moreover, appropriate fracture network parameters are paramount for enhancing the productivity of deep CBM wells. Lastly, during the development of deep CBM reservoirs, it is crucial to control the production pressure difference appropriately to minimize the stress sensitivity impact on production capacity. Full article

(This article belongs to the Special Issue Advances in Enhancing Unconventional Oil/Gas Recovery)

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14 pages, 3659 KiB

Open AccessArticle

Study on Connectivity Analysis and Injection–Production Optimization of Strong Heterogeneous Sandstone Reservoir Based on Connectivity Method

by Yuhui Zhou, Liang Pu, Sisi Dang, Jibo He and Shuang Pu

Processes 2023, 11(10), 2816; https://doi.org/10.3390/pr11102816 - 22 Sep 2023

Cited by 2 | Viewed by 1345

Abstract

The D reservoir in the Bongor Basin, southern Chad, is highly heterogeneous. In the stage of waterflood development, the injected water is seriously channeled along the dominant channel, and the water drive effect becomes worse. At the same time, due to the strong [...] Read more.

The D reservoir in the Bongor Basin, southern Chad, is highly heterogeneous. In the stage of waterflood development, the injected water is seriously channeled along the dominant channel, and the water drive effect becomes worse. At the same time, due to the strong edge and bottom water, the water flooding situation is aggravated, the water cut is increased, and the development efficiency is reduced. To accurately identify the inter-well connectivity relationship, we developed a reservoir inter-well connectivity model based on the principle of inter-well connectivity and dynamic production data and reservoir geological parameters. Thus, the plane water injection split coefficient and water injection efficiency of each reservoir layer were obtained. The results are in good agreement with the calculation results of inter-well connectivity through verification with field tracer interpretation. The practical application results show that the method can increase the annual output of oil by 1.3%, which has a good oil increase effect. In this study, a model of inter-well connectivity in multi-layer sandstone reservoirs was established for the first time. The production performance of the model injection–production well was optimized in real time by a historical fitting and production optimization algorithm and then applied to real reservoirs, so that it could effectively improve the oilfield development and optimize the injection–production structure. Full article

(This article belongs to the Special Issue Advances in Enhancing Unconventional Oil/Gas Recovery)

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16 pages, 4023 KiB

Open AccessArticle

Molecular Insight into the Occurrence Characteristics of Deep Oil with Associated Gas Methane and the Displacement Resistance in Water Flooding in Nano-Pore Throat

by Lixia Zhou, Weiming Wang, Youguo Yan, Chengen Zhao, Jiahao Zhong and Yuqi Liu

Processes 2023, 11(9), 2529; https://doi.org/10.3390/pr11092529 - 23 Aug 2023

Viewed by 1173

Abstract

In deep oil reservoirs, the existence of associated gas generally has a crucial impact on crude oil properties and flow performance. In this work, adopting molecular dynamic simulation, we studied the occurrence characteristics of oil with associate gas methane (the molar ratio of [...] Read more.

In deep oil reservoirs, the existence of associated gas generally has a crucial impact on crude oil properties and flow performance. In this work, adopting molecular dynamic simulation, we studied the occurrence characteristics of oil with associate gas methane (the molar ratio of methane to oil r_m/o were 1/4, 2/3, 3/2, and 4/1) in nano-pore throat and the displacement behavior of oil and methane in the water flooding process. Simulation results indicated: (1) an increasing replacement of the adsorption-status oil by methane as the methane content increased; (2) the oil and methane displacement efficiency was enhanced as the methane content increased in the water displacement oil and gas process; (3) the threshold displacement pressure gradually decreases as the methane content increases. The microscopic characteristics of the occurrence features and displacement performance of crude oil with associated methane in nano-pore throat were discussed in detail, and the underlying mechanism was discussed at the length concerning the interaction between different components. Our work provides an in-depth understanding of the occurrence characteristics and flow resistance of oil with associated gas in deep oil reservoirs. Full article

(This article belongs to the Special Issue Advances in Enhancing Unconventional Oil/Gas Recovery)

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16 pages, 6349 KiB

Open AccessArticle

Fast Assisted History Matching of Fractured Vertical Well in Coalbed Methane Reservoirs Using the Bayesian Adaptive Direct Searching Algorithm

by Zhijun Li

Processes 2023, 11(8), 2239; https://doi.org/10.3390/pr11082239 - 26 Jul 2023

Viewed by 1028

Abstract

The proper understanding of reservoir properties is an important step prior to forecasting fluid productions and deploying development strategies of a coalbed methane (CBM) reservoir. The assisted history matching (AHM) technique is a powerful technique that can derive reservoir properties based on production [...] Read more.

The proper understanding of reservoir properties is an important step prior to forecasting fluid productions and deploying development strategies of a coalbed methane (CBM) reservoir. The assisted history matching (AHM) technique is a powerful technique that can derive reservoir properties based on production data, which however is usually rather time-consuming because hundreds or even thousands of numerical simulation runs are required before reasonable results can be obtained. This paper proposed the use of a newly developed algorithm, namely the Bayesian adaptive direct searching (BADS) algorithm, for assisting history matching of fractured vertical CBM wells to derive reservoir property values. The proposed method was applied on representative fractured vertical wells in the low-permeable CBM reservoirs in the Qinshui Basin, China. Results showed that the proposed method is capable of deriving reasonable estimates of key reservoir properties within a number of 50 numerical simulation runs, which is far more efficient than existing methods. The superiority of the BADS algorithm in terms of matching accuracy and robustness was highlighted by comparing with two commonly used algorithms, namely particle swarm optimization (PSO) and CMA-ES. The proposed method is a perspective in laboring manual efforts and accelerating the matching process while ensuring reasonable interpretation results. Full article

(This article belongs to the Special Issue Advances in Enhancing Unconventional Oil/Gas Recovery)

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21 pages, 16730 KiB

Open AccessArticle

Intelligent Optimization of Gas Flooding Based on Multi-Objective Approach for Efficient Reservoir Management

by Meng Gao, Chenji Wei, Xiangguo Zhao, Ruijie Huang, Baozhu Li, Jian Yang, Yan Gao, Shuangshuang Liu and Lihui Xiong

Processes 2023, 11(7), 2226; https://doi.org/10.3390/pr11072226 - 24 Jul 2023

Cited by 2 | Viewed by 1487

Abstract

The efficient development of oil reservoirs mainly depends on the comprehensive optimization of the subsurface fluid flow process. As an intelligent analysis technique, artificial intelligence provides a novel solution to multi-objective optimization (MOO) problems. In this study, an intelligent agent model based on [...] Read more.

The efficient development of oil reservoirs mainly depends on the comprehensive optimization of the subsurface fluid flow process. As an intelligent analysis technique, artificial intelligence provides a novel solution to multi-objective optimization (MOO) problems. In this study, an intelligent agent model based on the Transformer framework with the assistance of the multi-objective particle swarm optimization (MOPSO) algorithm has been utilized to optimize the gas flooding injection–production parameters in a well pattern in the Middle East. Firstly, 10 types of surveillance data covering 12 years from the target reservoir were gathered to provide a data foundation for model training and analysis. The prediction performance of the Transformer model reflected its higher accuracy compared to traditional reservoir numerical simulation (RNS) and other intelligent methods. The production prediction results based on the Transformer model were 21, 12, and 4 percentage points higher than those of RNS, bagging, and the bi-directional gated recurrent unit (Bi-GRU) in terms of accuracy, and it showed similar trends in the gas–oil ratio (GOR) prediction results. Secondly, the Pareto-based MOPSO algorithm was utilized to fulfil the two contradictory objectives of maximizing oil production and minimizing GOR simultaneously. After 10,000 iterations, the optimal injection–production parameters were proposed based on the generated Pareto frontier. To validate the feasibility and superiority of the developed approach, the development effects of three injection–production schemes were predicted in the intelligent agent model. In the next 400 days of production, the cumulative oil production increased by 25.3% compared to the average distribution method and 12.7% compared to the reservoir engineering method, while GOR was reduced by 27.1% and 15.3%, respectively. The results show that MOPSO results in a strategy that more appropriately optimizes oil production and GOR compared to some previous efforts published in the literature. The injection–production parameter optimization method based on the intelligent agent model and MOPSO algorithm can help decision makers to update the conservative development strategy and improve the development effect. Full article

(This article belongs to the Special Issue Advances in Enhancing Unconventional Oil/Gas Recovery)

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15 pages, 2122 KiB

Open AccessArticle

CO₂ Injection for Enhanced Gas Recovery and Geo-Storage in Complex Tight Sandstone Gas Reservoirs

by Linqiang Zhang, Tongzhou Bai, Qibin Zhao, Xinghua Zhang, Hanlie Cheng and Zhao Li

Processes 2023, 11(7), 2059; https://doi.org/10.3390/pr11072059 - 10 Jul 2023

Viewed by 2980

Abstract

With the popularization of natural gas and the requirements for environmental protection, the development and utilization of natural gas is particularly important. The status of natural gas in China’s oil and gas exploration and development is constantly improving, and the country is paying [...] Read more.

With the popularization of natural gas and the requirements for environmental protection, the development and utilization of natural gas is particularly important. The status of natural gas in China’s oil and gas exploration and development is constantly improving, and the country is paying more and more attention to the exploitation and utilization of natural gas. The Upper Paleozoic tight sandstone in the Ordos Basin is characterized by low porosity, low permeability and a large area of concealed gas reservoirs. By injecting carbon dioxide into the formation, the recovery rate of natural gas can be improved, and carbon neutrality can be realized by carbon sequestration. Injecting greenhouse gases into gas reservoirs for storage and improving recovery has also become a hot research issue. In order to improve the recovery efficiency of tight sandstone gas reservoirs, this paper takes the complex tight sandstone of the Upper Paleozoic in the Ordos Basin as the research object; through indoor physical simulation experiments, carried out the influence of displacement rate, fracture dip angle, core permeability, core dryness and wetness on CO₂ gas displacement efficiency and storage efficiency; and analyzed the influence of different factors on gas displacement efficiency and storage efficiency to improve the recovery and storage efficiency. The research results show that under different conditions, when the injection pore volume is less than 1 PV, the relationship between the CH₄ recovery rate and the CO₂ injection pore volume is linear, and the tilt angle is 45°. When the injection pore volume exceeds 1 PV, the CH₄ recovery rate increases slightly with the increase in displacement speed, the recovery rate of CO₂ displacement CH₄ is between 87–97% and the CO₂ breakthrough time is 0.7 PV–0.9 PV. In low-permeability and low-speed displacement cores, the diffusion of carbon dioxide molecules is more significant. The lower the displacement speed is, the earlier the breakthrough time is, and the final recovery of CH₄ slightly decreases. Gravity has a great impact on carbon sequestration and enhanced recovery. The breakthrough of high injection and low recovery is earlier, and the recovery of CH₄ is about 3.3% lower than that of low injection and high recovery. The bound water causes the displacement phase CO₂ to be partially dissolved in the formation water, and the breakthrough lags about 0.1 PV. Ultimately, the CH₄ recovery factor and CO₂ storage rate are higher than those of dry-core displacement. The research results provide theoretical data support for CO₂ injection to improve recovery and storage efficiency in complex tight sandstone gas reservoirs. Full article

(This article belongs to the Special Issue Advances in Enhancing Unconventional Oil/Gas Recovery)

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14 pages, 3165 KiB

Open AccessArticle

Adsorption Behavior and Adsorption Dynamics of Micrometer-Sized Polymer Microspheres on the Surface of Quartz Sand

by Jun Li, Taotao Luo, Wende Yan, Tingting Cheng, Keyang Cheng, Lu Yu, Jiannan Cao and Zhongquan Yang

Processes 2023, 11(5), 1432; https://doi.org/10.3390/pr11051432 - 8 May 2023

Cited by 2 | Viewed by 1442

Abstract

The adsorption of polymer microspheres in a stratum can directly affect its action mode and performance in the actual application process. Understanding the adsorption pattern of polymer microspheres and their adsorption mechanism can facilitate optimization of the application mode and enhance the use [...] Read more.

The adsorption of polymer microspheres in a stratum can directly affect its action mode and performance in the actual application process. Understanding the adsorption pattern of polymer microspheres and their adsorption mechanism can facilitate optimization of the application mode and enhance the use efficiency. Ultraviolet spectrophotometry was employed to measure the static adsorption characteristics of polymer microspheres (PMS) on the surface of quartz sand. The PMS adsorption capacity on the surface of quartz sand increased with increasing concentration. When the concentration was 1000 mg/L, the static equilibrium adsorption capacity was 402 μg/g, and monolayer adsorption was dominant. The effect of the contact time on the adsorption was investigated, and the fitting was performed using the isothermal adsorption thermodynamic equilibrium model and the adsorption kinetic model. The adsorption of 800 mg/L PMS tended to equilibrate after 0.8 h of adsorption on the surface of quartz sand, and the adsorption of 1400 mg/L PMS tended to equilibrate after 1 h of adsorption on the surface of quartz sand. Good fitting results of the kinetic adsorption process were obtained using the pseudo-first-order (PFO) model, pseudo-second-order (PSO) model, Elovich model, and mixed-order (MO) model. The effects of the temperature, particle size of the quartz sand, solid–liquid ratio, and salinity on the adsorption of PMS on the surface of quartz sand were examined. The PMS adsorption capacity on the surface of quartz sand decreased with increasing environmental temperature. The adsorption of PMS at the solid–liquid interface was an exothermic process, and the enthalpy of adsorption was negative. As the mass of the quartz sand in the solid–liquid ratio increased, the adsorption capacity decreased; a low salinity and neutral pH were conducive to the adsorption of PMS on the surface of quartz sand. Full article

(This article belongs to the Special Issue Advances in Enhancing Unconventional Oil/Gas Recovery)

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10 pages, 229 KiB

Open AccessArticle

The Development and Application of Novel Water-Based Drilling Fluid for Complex Pressure System Formation in the South China Sea

by Hexing Liu, Yi Huang, Zhiqin Liu, Lifei Dong and Miao Wang

Processes 2023, 11(5), 1323; https://doi.org/10.3390/pr11051323 - 25 Apr 2023

Cited by 1 | Viewed by 1728

Abstract

The Y oilfield reservoir is characterized by ultra-depleted reservoir and multiple pressure systems in each well section. If conventional PLUS/KCL drilling fluid is used in directional drilling, the following problems are found: the rheological stability of drilling fluid is not sufficient, resulting in [...] Read more.

The Y oilfield reservoir is characterized by ultra-depleted reservoir and multiple pressure systems in each well section. If conventional PLUS/KCL drilling fluid is used in directional drilling, the following problems are found: the rheological stability of drilling fluid is not sufficient, resulting in increased viscosity and thickening after aging, and the single plugging material may cause loss-circulation when the drilling differential pressure is more than 26 MPa, resulting in poor reservoir protection effects. To solve the above problems, based on the conventional PLUS/KCL drilling fluid formula, a PLUS/KCL drilling fluid system suitable for directional drilling in multi-pressure systems was formed by optimizing the addition of a treating agent to improve the rheological stability of the drilling fluid, optimizing the plugging agent and compound combination to improve plugging ability, and optimizing the particle size distribution of a temporary plugging agent to improve the reservoir protection effect. The laboratory test evaluation showed that the optimized PLUS/KCL drilling fluid had fine plugging pressure capacity, and the intrusion depth was only 4.1 cm on the natural core at 120 °C/35 MPa/12 h, effectively reducing the risk of loss-circulation. The permeability recovery rate of the core after cutting off the polluted end was more than 90%, indicating that the reservoir protection effect was good. The drilling fluid performance was stable, and the cuttings rolling recovery rate was over 90%. Field application showed that the optimized PLUS/KCL drilling fluid was used without any loss-circulation or wellbore instability, and the production of all wells was over-matched, effectively solving the problem of ensuring drilling safety and reducing reservoir damage under the differential pressure of multiple pressure systems. Full article

(This article belongs to the Special Issue Advances in Enhancing Unconventional Oil/Gas Recovery)

15 pages, 3644 KiB

Open AccessArticle

Unusual Water Flow in Ultra-Tight Porous Media: Integration of Profession and Innovation

by Yanglu Wan, Na Niu, Wei Lu, Yushuang Zhou, Bin Wang and Shan Lu

Processes 2023, 11(4), 1245; https://doi.org/10.3390/pr11041245 - 18 Apr 2023

Cited by 1 | Viewed by 1191

Abstract

Hydraulic fracturing is an effective method for stimulating reservoirs, making the economic development of ultra-tight shale gas and coalbed methane reservoirs possible. These formations are rich in nanopores, in which the fracturing fluid, such as fresh water, the flow, and the behavior of [...] Read more.

Hydraulic fracturing is an effective method for stimulating reservoirs, making the economic development of ultra-tight shale gas and coalbed methane reservoirs possible. These formations are rich in nanopores, in which the fracturing fluid, such as fresh water, the flow, and the behavior of this flow differ significantly from those described in the classic Navier-Stokes formula. In bulk space, the interaction force exerted by the solid phase can be ignored, but the solid–fluid interaction plays a dominant role in nanoconfinement spaces in which the pore size is comparable to the molecular diameter. Nanoconfined water molecules tend to approach the water-wet pore surface, enhancing the water viscosity, which is a key parameter affecting the water flow capacity. Conversely, water molecules tend to stay in the middle of nanopores when subjected to a hydrophobic surface, leading to a decrease in viscosity. Thus, nanoconfined water viscosity is a function of the strength of the surface–fluid interaction, rather than a constant parameter, in classic theory. However, the influence of varying the viscosity on the nanoscale water flow behavior is still not fully understood. In this research, we incorporate wettability-dependent viscosity into a pore network modeling framework for stable flow for the first time. Our results show that: (a) the increase in viscosity under hydrophilic nanoconfinement could reduce the water flow capacity by as much as 11.3%; (b) the boundary slip is the primary mechanism for boosting the water flow in hydrophobic nanopores, as opposed to the slight enhancement contributed by a viscosity decline; and (c) water flow characterization in nanoscale porous media must consider both the pore size and surface wettability. Revealing the varying viscosity of water flow confined in nanopores can advance our microscopic understanding of water behavior and lay a solid theoretical foundation for fracturing-water invasion or flowback simulation. Full article

(This article belongs to the Special Issue Advances in Enhancing Unconventional Oil/Gas Recovery)

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21 pages, 12977 KiB

Open AccessArticle

Digital-Rock Construction of Shale Oil Reservoir and Microscopic Flow Behavior Characterization

by Jianguang Wei, Jiangtao Li, Ying Yang, Ao Zhang, Anlun Wang, Xiaofeng Zhou, Quanshu Zeng and Demiao Shang

Processes 2023, 11(3), 697; https://doi.org/10.3390/pr11030697 - 25 Feb 2023

Cited by 2 | Viewed by 1961

Abstract

In shale oil reservoirs, nano-scale pores and micro-scale fractures serve as the primary fluid storage and migration space, while the associated flow mechanism remains vague and is hard to understand. In this research, a three-dimensional (3D) reconstruction of the shale core and micro-pore [...] Read more.

In shale oil reservoirs, nano-scale pores and micro-scale fractures serve as the primary fluid storage and migration space, while the associated flow mechanism remains vague and is hard to understand. In this research, a three-dimensional (3D) reconstruction of the shale core and micro-pore structure description technique is established; digital core technology for shale reservoirs was developed using X-ray computed tomography (X-CT), scanning electron microscope (SEM) and a focused ion beam scanning electron microscope (FIB-SEM). Microscopic oil–water two-phase flow is mimicked using the lattice Boltzmann method (LBM), a well-acknowledged approach to exploring nanoconfined fluid dynamics. In addition, coupled with digital cores, the flow characteristics of shale reservoirs are characterized. The total porosities of bedding fractures in shale and lamellar shale are 2.042% and 1.085%, respectively. The single-phase oil flow inside bedding fractures follows Darcy’s linear flow principle. This work can deepen the understanding of the microscopic flow characteristics of continental shale reservoirs and provide a reference for similar problems that may be encountered. Full article

(This article belongs to the Special Issue Advances in Enhancing Unconventional Oil/Gas Recovery)

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12 pages, 6463 KiB

Open AccessArticle

Prediction of Longitudinal Superimposed “Sweet Spot” of Tight Gas Reservoir: A Case Study of Block G, Canada

by Yuepeng Jia, Wensong Huang, Ping Wang, Penghui Su, Xiangwen Kong, Li Liu and Yunpeng Shan

Processes 2023, 11(3), 666; https://doi.org/10.3390/pr11030666 - 22 Feb 2023

Viewed by 1422

Abstract

In this paper, taking Block G in Canada as an example, combined with the data of the working area, the Pearson–MIC comprehensive evaluation method was adopted to optimize the key parameters of productivity. Based on the analytic hierarchy process, the weight of each [...] Read more.

In this paper, taking Block G in Canada as an example, combined with the data of the working area, the Pearson–MIC comprehensive evaluation method was adopted to optimize the key parameters of productivity. Based on the analytic hierarchy process, the weight of each parameter was calculated, the grade of evaluation index of the “sweet spot” was divided, the standard of the sweet spot was established, and the distribution of the superimposed sweet spot was finally depicted. The results show that lateral length, number of stages, volume of fluid, and amount of proppant are the key engineering parameters of horizontal well, and lateral length is an independent key engineering parameter. The cumulative gas production in the first two years was normalized on the lateral length to eliminate the engineering influence, and the total organic carbon (TOC) was finally determined as the key geological parameter, whereas porosity and water saturation were the secondary key parameters. The area of Type I sweet spots accounts for 24.2% in the Series Upper and 23.1% in the Series Lower. This study proposed a new sweet spot prediction idea based on the influence of geological factors on productivity, and its results also laid a foundation for the subsequent placement of horizontal wells in Block G. Full article

(This article belongs to the Special Issue Advances in Enhancing Unconventional Oil/Gas Recovery)

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17 pages, 1748 KiB

Open AccessArticle

Optimization and Performance Evaluation of Foam Acid Systems for Plugging Removal in Low Pressure Oil and Gas Reservoirs

by Xiangwei Kong, Bing Liu, Hongxing Xu, Jianwen Shen and Song Li

Processes 2023, 11(3), 649; https://doi.org/10.3390/pr11030649 - 21 Feb 2023

Cited by 5 | Viewed by 2227

Abstract

Foam acidization has unique advantages such as low damage, low filtration, low friction, high efficiency, excellent retardation, and fast liquid discharge rate, which is suitable for stimulation and reconstruction of low-pressure oil and gas reservoirs that have been developed over many years. It [...] Read more.

Foam acidization has unique advantages such as low damage, low filtration, low friction, high efficiency, excellent retardation, and fast liquid discharge rate, which is suitable for stimulation and reconstruction of low-pressure oil and gas reservoirs that have been developed over many years. It is obtained that the main chemical components of downhole plugging materials include vegetable oil, fatty acids and their esters, silicone oil, amide polymers, and additional organic components, as well as non-organic components, elemental sulfur, ferrous sulfide, iron disulfide, silicon dioxide, mineral salts, etc. The performance of foam acid was investigated by experiments, including the effective range of action of active acids, reducing filtration, increasing temperature resistance and high-temperature stability of foam acid deep wells. The new foam acid system is developed and optimized to suitable for low-pressure deep well acidification operations. Experimental evaluation optimized the acid foaming agent and foam stabilizer and developed a new foam acid formulation with foam stability, filter loss reduction, temperature resistance, and easy backflow performance. The experimental condition is that the temperature is 90 °C, the foam quality can reach more than 70% when mixed for more than 30 s, the average half-life is 38.75 min, and the liquid separation rate is 19.90 s/mL. Its suspension is better than that of conventional hydrochloric acid, its corrosion rate is 1.872 g/m²·h, and the flowback rate of foam acid residue reaches 97%. Experimental evaluation has shown that the developed foam acid features high surface activity, stable foam, strong temperature resistance, significant speed and corrosion suppression, and excellent drainage assist performance. Dynamical simulation evaluation of reservoir core foam acidification demonstrated that the foam features long-life, strong suspension capacity, excellent rheology, low filtration, and significant acidization and plug removal effects, and can be used in stimulating the medium-deep, high-temperature, and low-pressure oil and gas reservoirs. Full article

(This article belongs to the Special Issue Advances in Enhancing Unconventional Oil/Gas Recovery)

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16 pages, 2564 KiB

Open AccessArticle

A Semi-Analytical Model for Gas–Water Two-Phase Productivity Prediction of Carbonate Gas Reservoirs

by Dayong Chen and Zheng Sun

Processes 2023, 11(2), 591; https://doi.org/10.3390/pr11020591 - 15 Feb 2023

Cited by 1 | Viewed by 1490

Abstract

The productivity prediction of gas wells in carbonate gas reservoirs is greatly affected by the characteristics of gas–water two-phase flow and fracture seepage parameters. Compared with numerical simulation, the productivity prediction based on the analytical model is fast and widely used, but the [...] Read more.

The productivity prediction of gas wells in carbonate gas reservoirs is greatly affected by the characteristics of gas–water two-phase flow and fracture seepage parameters. Compared with numerical simulation, the productivity prediction based on the analytical model is fast and widely used, but the traditional analytical model is fairly simplified while dealing with the nonlinear problem of the two-phase seepage equation, leading to a large discrepancy in the results of dynamic analysis. To solve this problem, this paper considers the characteristics of gas–water two-phase flow in the reservoir and fracture, uses the dual-medium model to characterize the stress sensitivity of the fracture and reservoir, and establishes a gas–water two-phase productivity prediction model for carbonate gas reservoirs. Combining the flowing material balance equation with the Newton iteration method, the nonlinear parameters of the percolation model are updated step by step with the use of average formation pressure, and the gas–water two-phase model is linearized through successive iterations to obtain the semi-analytical solution of the model. The accuracy of the model was verified using a comparison with the results of commercial numerical simulation software and field application, the gas–water two-phase productivity prediction curve was obtained, and the influence of sensitive parameters on productivity was analyzed. The results show that: (1) the semi-analytical solution method can efficiently deal with the gas–water two-phase nonlinear seepage problem and obtain the productivity prediction curve of carbonate gas wells rapidly and (2) the water production of the carbonate gas reservoir seriously affects the productivity of gas wells. During the development process, the production pressure difference should be reasonably controlled to reduce the negative impact of stress sensitivity on productivity performance. Full article

(This article belongs to the Special Issue Advances in Enhancing Unconventional Oil/Gas Recovery)

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25 pages, 6911 KiB

Open AccessArticle

Quantitative Characterization of Shallow Marine Sediments in Tight Gas Fields of Middle Indus Basin: A Rational Approach of Multiple Rock Physics Diagnostic Models

by Muhammad Ali, Umar Ashraf, Peimin Zhu, Huolin Ma, Ren Jiang, Guo Lei, Jar Ullah, Jawad Ali, Hung Vo Thanh and Aqsa Anees

Processes 2023, 11(2), 323; https://doi.org/10.3390/pr11020323 - 18 Jan 2023

Cited by 14 | Viewed by 2804

Abstract

For the successful discovery and development of tight sand gas reserves, it is necessary to locate sand with certain features. These features must largely include a significant accumulation of hydrocarbons, rock physics models, and mechanical properties. However, the effective representation of such reservoir [...] Read more.

For the successful discovery and development of tight sand gas reserves, it is necessary to locate sand with certain features. These features must largely include a significant accumulation of hydrocarbons, rock physics models, and mechanical properties. However, the effective representation of such reservoir properties using applicable parameters is challenging due to the complicated heterogeneous structural characteristics of hydrocarbon sand. Rock physics modeling of sandstone reservoirs from the Lower Goru Basin gas fields represents the link between reservoir parameters and seismic properties. Rock physics diagnostic models have been utilized to describe the reservoir sands of two wells inside this Middle Indus Basin, including contact cement, constant cement, and friable sand. The results showed that sorting the grain and coating cement on the grain’s surface both affected the cementation process. According to the models, the cementation levels in the reservoir sands of the two wells ranged from 2% to more than 6%. The rock physics models established in the study would improve the understanding of characteristics for the relatively high V_p/V_s unconsolidated reservoir sands under study. Integrating rock physics models would improve the prediction of reservoir properties from the elastic properties estimated from seismic data. The velocity–porosity and elastic moduli-porosity patterns for the reservoir zones of the two wells are distinct. To generate a rock physics template (RPT) for the Lower Goru sand from the Early Cretaceous period, an approach based on fluid replacement modeling has been chosen. The ratio of P-wave velocity to S-wave velocity (V_p/V_s) and the P-impedance template can detect cap shale, brine sand, and gas-saturated sand with varying water saturation and porosity from wells in the Rehmat and Miano gas fields, both of which have the same shallow marine depositional characteristics. Conventional neutron-density cross-plot analysis matches up quite well with this RPT’s expected detection of water and gas sands. Full article

(This article belongs to the Special Issue Advances in Enhancing Unconventional Oil/Gas Recovery)

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17 pages, 8989 KiB

Open AccessArticle

Research on Gas Control Technology of “U+ Omni-Directional Roof to Large-Diameter High-Level Drilling Hole” at the End Mining Face of Multi-Source Goaf

by Hong Gao and Yun Lei

Processes 2023, 11(2), 320; https://doi.org/10.3390/pr11020320 - 18 Jan 2023

Cited by 3 | Viewed by 1384

Abstract

Aiming at the gas over-run problem in the upper corner of the “U-type ventilation” end-mining working face in the multi-source goaf of the #15 coal seam in the Phoenix Mountain Mine, site survey and numerical simulation methods were adopted, which showed that the [...] Read more.

Aiming at the gas over-run problem in the upper corner of the “U-type ventilation” end-mining working face in the multi-source goaf of the #15 coal seam in the Phoenix Mountain Mine, site survey and numerical simulation methods were adopted, which showed that the maximum caving zone height of the #15 coal seam is 14.87 m, and the maximum height of the fissure zone is 51.63 m. On this basis, the gas control scheme of the “U+ omni-directional large-diameter high-level borehole along roof strike” in the end-mining working face was formulated. After adopting this scheme, the extracted gas concentration of each borehole will reach 5–20%, the gas extraction flow rate will reach 1 m³/min–2.5 m³/min, the gas concentration at the upper corner of the working face will be controlled below 0.54%, and the gas concentration in the return airway will be controlled below 0.35%, achieving the expected effect of gas control. Full article

(This article belongs to the Special Issue Advances in Enhancing Unconventional Oil/Gas Recovery)

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18 pages, 10577 KiB

Open AccessArticle

Fracture Parameters Optimization and Field Application in Low-Permeability Sandstone Reservoirs under Fracturing Flooding Conditions

by Cong Lu, Li Ma, Jianchun Guo, Lin Zhao, Shiqian Xu, Bugao Chen, Yulong Zhou, Haoren Yuan and Zhibin Tang

Processes 2023, 11(1), 285; https://doi.org/10.3390/pr11010285 - 16 Jan 2023

Cited by 7 | Viewed by 2385

Abstract

To solve engineering problems in the production process after fracturing and flooding of low-permeability sandstone reservoirs, such as rapid water-cut rise and low water flooding efficiency, a method for optimizing the fracture parameters of low-permeability sandstone reservoirs under fracturing flooding conditions was proposed. [...] Read more.

To solve engineering problems in the production process after fracturing and flooding of low-permeability sandstone reservoirs, such as rapid water-cut rise and low water flooding efficiency, a method for optimizing the fracture parameters of low-permeability sandstone reservoirs under fracturing flooding conditions was proposed. A rock property test experiment was first carried out, the fracturing coefficient was defined, and an evaluation method for the brittleness index of low-permeability sandstone was established to optimize the perforation location of the fracturing reservoir. A productivity numerical model for the two-phase flow of oil–water in matrix–fracture media was established to optimize the fracture morphology under fracturing flooding conditions. The results showed that the quartz content, Young’s modulus, and peak stress mainly affected the fracturing coefficient of rock and are the key indicators for evaluating the brittleness of low-permeability sandstone reservoirs. For production wells in the direction of minimum horizontal principal stress, the swept area of water flooding should be expanded, fracture length should be optimized to 90 m, and fracture conductivity should be 20 D·cm. For fracturing production wells in the direction of maximum horizontal principal stress, the advancing speed of the water injection front should be slowed down to reduce the risk of water channeling in injection-production wells. The optimized fracture length was 80 m, and the fracture conductivity was 25 D·cm. The application of these findings can markedly improve oil production and provide a reference for optimizing the fracture parameters of low-permeability sandstone reservoirs under fracturing flooding conditions. Full article

(This article belongs to the Special Issue Advances in Enhancing Unconventional Oil/Gas Recovery)

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13 pages, 2603 KiB

Open AccessArticle

Transport Behavior of Methane Confined in Nanoscale Porous Media: Impact of Pore Evolution Characteristics

by Shan Wu, Sidong Fang, Liang Ji, Feng Wen, Zheng Sun, Shuhui Yan and Yaohui Li

Processes 2022, 10(12), 2746; https://doi.org/10.3390/pr10122746 - 19 Dec 2022

Cited by 3 | Viewed by 1629

Abstract

As a key technical aspect contributing to shale gas development, nanoconfined methane flow behavior has received tremendous research interest, which remains challenging to understand clearly. The majority of previous contributions put emphasis on the mechanism model for methane confined in a single nanopore; [...] Read more.

As a key technical aspect contributing to shale gas development, nanoconfined methane flow behavior has received tremendous research interest, which remains challenging to understand clearly. The majority of previous contributions put emphasis on the mechanism model for methane confined in a single nanopore; at the same time, the other part focusing on an upscaling approach fails to capture the spatial pore-network characteristics as well as the way to assign pressure conditions to methane flow behavior. In light of the current knowledge gap, pore-network modeling is performed, in which a pore coordination number, indicating the maximum pores a specified pore can connect, gas flow regimes classified by Knudsen numbers, as well as different assigned pressure conditions, are incorporated. Notably, the pore-network modeling is completely self-coded, which is more flexible in adjusting the spatial features of a constructed pore network than a traditional one. In this paper, the nanoconfined methane flow behavior is elaborated first, then the pore network modeling method based on the mass conservation principle is introduced for upscaling, and in-depth analysis is implemented after that. Results show that (a) as for porous media with pore sizes ranging from 5~80 nm, dramatic advancement on apparent gas permeability takes place while pressure is less than 1 MPa; (b) apparent gas permeability evaluated at a specified pressure shall be underestimated by as much as 31.1% on average compared with that under the pressure-difference condition; (c) both a large pore size and a high coordination number are beneficial for strong gas flow capacity through nanoscale porous media, and the rising ratio can reach about 6 times by altering the coordination number from 3 to 7, which is quantified and presented for the first time. Full article

(This article belongs to the Special Issue Advances in Enhancing Unconventional Oil/Gas Recovery)

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16 pages, 6392 KiB

Open AccessArticle

Study on Gas Invasion Behavior of Gas–Liquid Displacement in Fractured Reservoirs

by Cheng Ye, Jiaqin Gong, Kecheng Liu, Jingjing Pei, Shengjiang Xu and Peng Xu

Processes 2022, 10(12), 2533; https://doi.org/10.3390/pr10122533 - 29 Nov 2022

Cited by 1 | Viewed by 1553

Abstract

When drilling or exploiting fractured formations, gas fluid displacement and invasion often occur, and gas invasion is very subtle and difficult to find. The gas in the fracture enters the wellbore and arrives near the wellhead with the drilling fluid. Improper treatment may [...] Read more.

When drilling or exploiting fractured formations, gas fluid displacement and invasion often occur, and gas invasion is very subtle and difficult to find. The gas in the fracture enters the wellbore and arrives near the wellhead with the drilling fluid. Improper treatment may lead to serious accidents such as lost circulation and blowout. In this study, using computational fluid dynamics (CFD) simulation software for modeling and grid generation, based on the volume of fluid (VOF) method, the gas invasion behavior under different conditions was simulated to explore the flow process and characteristics of gas invasion, and the effects of different drilling fluid properties and fracture morphology on gas invasion were analyzed. The experimental results show that the drilling fluid enters the fracture to compress the gas, making the pressure in the fracture greater than that in the wellbore, thus leading to the occurrence of gas invasion. The viscosity and density of the drilling fluid have different effects on the gas invasion process. The higher the viscosity, the smaller the possibility of gas invasion. However, when the viscosity of the drilling fluid gradually increases from 10–50 MPa·s, the change of gas invasion rate is small, all within 1.0–1.2 m/s. The higher the density, the more conducive to the occurrence of gas invasion. The inlet pressure has no obvious effect on the occurrence of gas invasion, and the occurrence time of the gas invasion fluctuates in 0.35 s at 0.5–2.5 MPa. With the increase in the fracture width and length, the possibility of gas invasion decreases, but there is an extreme value for the fracture height. The time of gas invasion does not change beyond this extreme value. When the fracture height is 100–700 mm, the time of gas invasion increases with the increase in the height; when the height is 700–900 mm, the gas invasion time does not change. These results provide a practical and effective method for enhancing oil recovery, preventing and treating gas invasion in gas–liquid flooding. Full article

(This article belongs to the Special Issue Advances in Enhancing Unconventional Oil/Gas Recovery)

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Open AccessReview

Development of Microbial Consortium and Its Influencing Factors for Enhanced Oil Recovery after Polymer Flooding: A Review

by Hui Xiao, Zulhelmi Amir and Mohd Usman Mohd Junaidi

Processes 2023, 11(10), 2853; https://doi.org/10.3390/pr11102853 - 27 Sep 2023

Cited by 5 | Viewed by 4687

Abstract

After polymer flooding, substantial oil and residual polymers remain in reservoirs, leading to plugging and reduced recovery. MEOR (Microbial Enhanced Oil Recovery) aims to release trapped oil by utilizing microorganisms and their byproducts. The microorganisms can use residual HPAM (hydrolyzed polyacrylamide) as an [...] Read more.

After polymer flooding, substantial oil and residual polymers remain in reservoirs, leading to plugging and reduced recovery. MEOR (Microbial Enhanced Oil Recovery) aims to release trapped oil by utilizing microorganisms and their byproducts. The microorganisms can use residual HPAM (hydrolyzed polyacrylamide) as an energy source for polymer degradation, addressing reservoir plugging issues and improving oil recovery. However, microorganisms are sensitive to environmental conditions. This paper presents a detailed update of MEOR, including microbial products, mechanisms, and merits and demerits. The effect of the displacement fluid and conditions on microorganisms is thoroughly demonstrated to elucidate their influencing mechanism. Among these factors, HPAM and crosslinkers, which have significant biological toxicity, affect microorganisms and the efficiency of MEOR. Limited research exists on the effect of chemicals on microorganisms’ properties, metabolism, and oil displacement mechanisms. The development of microbial consortium, their metabolic interaction, and oil displacement microprocesses are also discussed. In addition, prior studies lack insights into microorganisms’ interaction and mechanisms using chemicals. Finally, field trials exist to examine the microbial consortium’s efficiency and introduce new technologies. This review mainly explores the influencing factors on microorganisms, and confirms the credibility of MEOR after polymer flooding, providing a scientific basis for improving the theory of MEOR. Full article

(This article belongs to the Special Issue Advances in Enhancing Unconventional Oil/Gas Recovery)

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