Pub Date : 2025-12-01DOI: 10.1016/j.petlm.2025.10.002
Na Wei , Chao Zhang , Li Zhou , Shenghui Zhang , Shouwei Zhou , Liehui Zhang , Jinzhou Zhao , Richard B.Coffin , Bjørn Kvamme
In the process of gas hydrate depressurization production, the reasonable depressurization rhythm and depressurization amplitude have significant impact on improving production and reducing engineering geological risks. Considering the basic stability of the reservoir, this study constructs mathematical models of gas hydrate decomposition kinetics, multiphase flow in the reservoir, and the disintegration and migration of rock matrix particles containing hydrates. Based on actual data from the first trial production in Japan's Nankai Trough, the validity of the model has been verified. The study analyzed changes in reservoir physical properties and productivity under multi-stage depressurization conditions. The influence of different pressure reduction rhythms on productivity changes and the evolution laws of porosity, permeability and saturation over time and space were discussed. The research disclosed the multi-stage depressurization mode can modulate the decomposition rate and sand production rate of natural gas hydrates through the progressive reduction of reservoir pressure, guaranteeing production capacity while attaining sand production control and minimizing the risk of blockage, thereby striking a balance between production efficiency and sustainability. This study provides a crucial theoretical basis for the design optimization of natural gas hydrate depressurization extraction schemes. The research outcomes not only guide the parameter configuration optimization during depressurization but also offer scientific support for establishing production prediction models.
{"title":"Evolution law of physical parameters and hydrate reservoir productivity under multi-stage depressurization","authors":"Na Wei , Chao Zhang , Li Zhou , Shenghui Zhang , Shouwei Zhou , Liehui Zhang , Jinzhou Zhao , Richard B.Coffin , Bjørn Kvamme","doi":"10.1016/j.petlm.2025.10.002","DOIUrl":"10.1016/j.petlm.2025.10.002","url":null,"abstract":"<div><div>In the process of gas hydrate depressurization production, the reasonable depressurization rhythm and depressurization amplitude have significant impact on improving production and reducing engineering geological risks. Considering the basic stability of the reservoir, this study constructs mathematical models of gas hydrate decomposition kinetics, multiphase flow in the reservoir, and the disintegration and migration of rock matrix particles containing hydrates. Based on actual data from the first trial production in Japan's Nankai Trough, the validity of the model has been verified. The study analyzed changes in reservoir physical properties and productivity under multi-stage depressurization conditions. The influence of different pressure reduction rhythms on productivity changes and the evolution laws of porosity, permeability and saturation over time and space were discussed. The research disclosed the multi-stage depressurization mode can modulate the decomposition rate and sand production rate of natural gas hydrates through the progressive reduction of reservoir pressure, guaranteeing production capacity while attaining sand production control and minimizing the risk of blockage, thereby striking a balance between production efficiency and sustainability. This study provides a crucial theoretical basis for the design optimization of natural gas hydrate depressurization extraction schemes. The research outcomes not only guide the parameter configuration optimization during depressurization but also offer scientific support for establishing production prediction models.</div></div>","PeriodicalId":37433,"journal":{"name":"Petroleum","volume":"11 6","pages":"Pages 757-769"},"PeriodicalIF":3.5,"publicationDate":"2025-12-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145847608","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Pub Date : 2025-12-01DOI: 10.1016/j.petlm.2025.10.001
Huifeng Liu , Yuri Osipov , Zebo Yuan , Siqing Xu , Jorge Costa Gomes , Zhangxin Chen
Well injectivity decline during waterflooding is primarily attributed to retention of injected particles within pores, subsequently blocking flow channels in near-wellbore regions. Developing a predictive model to describe this problem holds significant value as it can inform the development of strategies aimed at preventing or mitigating such damage. Previous research has typically assumed a linear suspension flow or a constant filtration coefficient, which does not represent the near-wellbore suspension flow very well. In this paper, an analytical model for the radial suspension transport in porous media is derived based on the Langmuirian blocking filtration mechanism. Considering the dimensionless distance from the wellbore as a small parameter, we attain the analytical solution through an asymptotic expansion. To provide a basis for comparison, we also obtain numerical solutions using Shampine's code, which is based on the explicit central finite difference method. Comparison of the analytical and numerical solutions shows that their difference errors remain below 5% under waterflooding conditions. Based on the analytical solution for retained particle concentration, expressions for injection pressure, damage factor and damaged zone radius are also derived and are also expressed explicitly. In the end, we discuss two practical applications of our model: evaluation of existing acidizing jobs and designing new acidizing jobs, based on real field data from Tarim Basin, western China. The results indicate our model is practical in field operations.
{"title":"A novel injectivity decline prediction model for waterflooding with analytical solutions and field applications","authors":"Huifeng Liu , Yuri Osipov , Zebo Yuan , Siqing Xu , Jorge Costa Gomes , Zhangxin Chen","doi":"10.1016/j.petlm.2025.10.001","DOIUrl":"10.1016/j.petlm.2025.10.001","url":null,"abstract":"<div><div>Well injectivity decline during waterflooding is primarily attributed to retention of injected particles within pores, subsequently blocking flow channels in near-wellbore regions. Developing a predictive model to describe this problem holds significant value as it can inform the development of strategies aimed at preventing or mitigating such damage. Previous research has typically assumed a linear suspension flow or a constant filtration coefficient, which does not represent the near-wellbore suspension flow very well. In this paper, an analytical model for the radial suspension transport in porous media is derived based on the Langmuirian blocking filtration mechanism. Considering the dimensionless distance from the wellbore as a small parameter, we attain the analytical solution through an asymptotic expansion. To provide a basis for comparison, we also obtain numerical solutions using Shampine's code, which is based on the explicit central finite difference method. Comparison of the analytical and numerical solutions shows that their difference errors remain below 5% under waterflooding conditions. Based on the analytical solution for retained particle concentration, expressions for injection pressure, damage factor and damaged zone radius are also derived and are also expressed explicitly. In the end, we discuss two practical applications of our model: evaluation of existing acidizing jobs and designing new acidizing jobs, based on real field data from Tarim Basin, western China. The results indicate our model is practical in field operations.</div></div>","PeriodicalId":37433,"journal":{"name":"Petroleum","volume":"11 6","pages":"Pages 784-799"},"PeriodicalIF":3.5,"publicationDate":"2025-12-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145847682","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Pub Date : 2025-12-01DOI: 10.1016/j.petlm.2025.11.001
Mohd. Shahnawaz Alam, Rishabh Tripathi, Sandeep D. Kulkarni
This study aims to mitigate CO2 leakage in high-temperature reservoirs using an organic cross-linked gel system. The engineered fluid system was evaluated by a quantified rheological methodology and pore-plugging analysis. A sulfonated hydrolyzed polyacrylamide polymer and organic crosslinkers, hydroquinone and hexamethylenetetramine, were utilized for forming the fluid gel systems. The pressure cell assembly has been employed for the gel analysis at an elevated temperature of 110 °C under a pressurized CO2 environment. The high-temperature viscosity vs. aging time data acquired under continuous shear conditions ( 50 s−1) was ingeniously categorized into three regimes: (1) an induction period characterized by a lower linear slope of dμ/dt = 15–50 mPa·s/h; (2) a ‘non-linear’ transition regime; (3) a rapid cross-linking period characterized by a higher linear slope, i.e. dμ/dt ≥ 350 mPa·s/h. The ‘gelation time’, defined as the point of initiation of the rapid-crosslinking period, was successfully modelled for variations in polymer concentration utilizing first-order kinetics. The new outcomes of the high-temperature rheological investigation under the pressurized CO2 environment were compared with the traditional bottle-testing approach and oscillatory rheological studies. The core flooding results showed excellent plugging efficiency (>99%) for both sub-critical and super-critical CO2 injections beyond the ‘gelation time’ at 110 °C.
{"title":"Application of organic cross-linked gel system for mitigating CO2 leakage from high temperature reservoirs","authors":"Mohd. Shahnawaz Alam, Rishabh Tripathi, Sandeep D. Kulkarni","doi":"10.1016/j.petlm.2025.11.001","DOIUrl":"10.1016/j.petlm.2025.11.001","url":null,"abstract":"<div><div>This study aims to mitigate CO<sub>2</sub> leakage in high-temperature reservoirs using an organic cross-linked gel system. The engineered fluid system was evaluated by a quantified rheological methodology and pore-plugging analysis. A sulfonated hydrolyzed polyacrylamide polymer and organic crosslinkers, hydroquinone and hexamethylenetetramine, were utilized for forming the fluid gel systems. The pressure cell assembly has been employed for the gel analysis at an elevated temperature of 110 °C under a pressurized CO<sub>2</sub> environment. The high-temperature viscosity vs. aging time data acquired under continuous shear conditions (<span><math><mrow><mover><mi>γ</mi><mo>˙</mo></mover><mo>=</mo></mrow></math></span> 50 s<sup>−1</sup>) was ingeniously categorized into three regimes: (1) an induction period characterized by a lower linear slope of <em>dμ/dt</em> = 15–50 mPa·s/h; (2) a ‘non-linear’ transition regime; (3) a rapid cross-linking period characterized by a higher linear slope, i.e. <em>dμ/dt</em> ≥ 350 mPa·s/h. The ‘gelation time’, defined as the point of initiation of the rapid-crosslinking period, was successfully modelled for variations in polymer concentration utilizing first-order kinetics. The new outcomes of the high-temperature rheological investigation under the pressurized CO<sub>2</sub> environment were compared with the traditional bottle-testing approach and oscillatory rheological studies. The core flooding results showed excellent plugging efficiency (>99%) for both sub-critical and super-critical CO<sub>2</sub> injections beyond the ‘gelation time’ at 110 °C.</div></div>","PeriodicalId":37433,"journal":{"name":"Petroleum","volume":"11 6","pages":"Pages 800-812"},"PeriodicalIF":3.5,"publicationDate":"2025-12-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145847683","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Pub Date : 2025-12-01DOI: 10.1016/j.petlm.2025.10.004
Raafat Aborafia, Amir Hossein Saeedi Dehaghani
This study investigates the phase behavior of methane, ethane, and their binary mixture in both bulk and 5 nm slit-like pores with silica, anhydrite, calcite, dolomite, and montmorillonite walls using grand canonical Monte Carlo simulation (GCMC). The results show that vapor densities increase and, liquid densities decrease with the reduction of the pore width for both pure components and binary mixtures. The critical pressure and temperature decrease significantly in confined systems compared to bulk systems, with the rate of decrease varying depending on the type of surface. The response of critical density to surface type is distinct, and the critical density can be higher or lower than that in bulk systems. Furthermore, the dew point pressure of the confined binary mixture between two surfaces of silica, anhydrite, calcite, dolomite, and montmorillonite is higher than its value in bulk systems, while the bubble point pressure in confined systems can be lower, equal, or more than its value in bulk systems, depending on the pore surface and temperature.
{"title":"Investigating the phase behavior of methane, ethane and their binary mixture confined in a 5 nm slit-like-pore with different wall types: Monte Carlo simulation study","authors":"Raafat Aborafia, Amir Hossein Saeedi Dehaghani","doi":"10.1016/j.petlm.2025.10.004","DOIUrl":"10.1016/j.petlm.2025.10.004","url":null,"abstract":"<div><div>This study investigates the phase behavior of methane, ethane, and their binary mixture in both bulk and 5 nm slit-like pores with silica, anhydrite, calcite, dolomite, and montmorillonite walls using grand canonical Monte Carlo simulation (GCMC). The results show that vapor densities increase and, liquid densities decrease with the reduction of the pore width for both pure components and binary mixtures. The critical pressure and temperature decrease significantly in confined systems compared to bulk systems, with the rate of decrease varying depending on the type of surface. The response of critical density to surface type is distinct, and the critical density can be higher or lower than that in bulk systems. Furthermore, the dew point pressure of the confined binary mixture between two surfaces of silica, anhydrite, calcite, dolomite, and montmorillonite is higher than its value in bulk systems, while the bubble point pressure in confined systems can be lower, equal, or more than its value in bulk systems, depending on the pore surface and temperature.</div></div>","PeriodicalId":37433,"journal":{"name":"Petroleum","volume":"11 6","pages":"Pages 744-756"},"PeriodicalIF":3.5,"publicationDate":"2025-12-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145847607","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Pub Date : 2025-12-01DOI: 10.1016/j.petlm.2025.11.006
Okorie Ekwe Agwu , Saad Alatefi , Muhammad Aslam Md Yusof , Cosmas Brendan Orun
Equivalent circulating density (ECD) denotes the density of drilling mud during circulation within a well. It is determined by integrating the equivalent static density with the pressure loss attributable to friction between the flowing mud and the geological formation. The effective management of ECD is imperative during drilling operations, as it plays a critical role in preventing kicks and minimising mud losses. Mud ECD has undergone extensive investigation through laboratory experiments, field measurements, and predictive modelling. Nevertheless, a comprehensive review of the various predictive models associated with ECD remains absent. The objective of this study is to review and critique existing correlations for estimating ECD. To accomplish this, a thorough bibliometric analysis was performed, focusing on peer-reviewed journals, mud manuals, and oil and gas conference papers. For the sake of clarity, existing models were categorized into tables, with their principal features highlighted. A critique of each model was subsequently provided. In total, 45 models related to ECD were identified, reviewed, and critiqued. The findings reveal that over 44% of the models are based on machine learning (ML), 27% are analytical models, 16% are regression based models, and 13% are simulator-related. Although there is no universally accepted model for ECD, there is an observable trend towards the utilization of ML algorithms for ECD estimation due to their predictive capabilities. However, the interpretability of these ML-based models remains a significant concern. This review serves as a comprehensive source of information on ECD for both readers and industry practitioners. Additionally, it directs researchers towards areas requiring further exploration and aids drilling professionals in selecting appropriate ECD models.
{"title":"Predicting drilling mud equivalent circulating density with precision: A critical review of modern approaches","authors":"Okorie Ekwe Agwu , Saad Alatefi , Muhammad Aslam Md Yusof , Cosmas Brendan Orun","doi":"10.1016/j.petlm.2025.11.006","DOIUrl":"10.1016/j.petlm.2025.11.006","url":null,"abstract":"<div><div>Equivalent circulating density (ECD) denotes the density of drilling mud during circulation within a well. It is determined by integrating the equivalent static density with the pressure loss attributable to friction between the flowing mud and the geological formation. The effective management of ECD is imperative during drilling operations, as it plays a critical role in preventing kicks and minimising mud losses. Mud ECD has undergone extensive investigation through laboratory experiments, field measurements, and predictive modelling. Nevertheless, a comprehensive review of the various predictive models associated with ECD remains absent. The objective of this study is to review and critique existing correlations for estimating ECD. To accomplish this, a thorough bibliometric analysis was performed, focusing on peer-reviewed journals, mud manuals, and oil and gas conference papers. For the sake of clarity, existing models were categorized into tables, with their principal features highlighted. A critique of each model was subsequently provided. In total, 45 models related to ECD were identified, reviewed, and critiqued. The findings reveal that over 44% of the models are based on machine learning (ML), 27% are analytical models, 16% are regression based models, and 13% are simulator-related. Although there is no universally accepted model for ECD, there is an observable trend towards the utilization of ML algorithms for ECD estimation due to their predictive capabilities. However, the interpretability of these ML-based models remains a significant concern. This review serves as a comprehensive source of information on ECD for both readers and industry practitioners. Additionally, it directs researchers towards areas requiring further exploration and aids drilling professionals in selecting appropriate ECD models.</div></div>","PeriodicalId":37433,"journal":{"name":"Petroleum","volume":"11 6","pages":"Pages 699-716"},"PeriodicalIF":3.5,"publicationDate":"2025-12-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145847605","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
This research investigates the role of dispersion of nanoparticles in gas during gas recycling process to improve the gas condensate recovery via altering the carbonate reservoirs wettability. The nanoparticles were synthesized and analyzed using dynamic light scattering (DLS), energy-dispersive X-ray (EDX), and transmission electron microscopy (TEM). After that, the dispersion of nanoparticles in methane was investigated by cloud point pressures measurement. Also, the effectiveness of methane/nanoparticles solutions was assessed through the contact angle experiments and gas recycling process. Based on the cloud point pressures results, the nanoparticles can be dispersed in methane at pressures commensurate with hydrocarbon reservoirs. Gas/nanoparticles single-phase solutions increased the contact angles of gas condensate and n-decane from 12° to 121° and 135.5°, respectively, for fluorinated silica, and to 100.5° and 108° for fluorinated titania. The shift from oil-wet to gas-wet conditions enhanced the recovery factor from 55% to 76%, marking a 21% improvement in gas condensate recovery during gas recycling. Furthermore, the pressure drop ratio decreased by 60%, due to better surface wettability and reduced condensate blockage. Comparative results indicated that the dispersion of fluorinated silica nanoparticles in gas outperformed fluorinated titania in altering wettability. These results emphasize the potential of current new approach, through dispersion of fluorinated nanoparticles in gas; to improve gas condensate recovery during gas recycling, especially in low-permeability carbonate reservoirs.
{"title":"Improving the gas condensate recovery through wettability alteration to gas-wet during gas recycling via dispersion of nanoparticles in gas","authors":"Naser Namdari Garaghani , Asghar Gandomkar , Amin Azdarpour","doi":"10.1016/j.petlm.2025.10.003","DOIUrl":"10.1016/j.petlm.2025.10.003","url":null,"abstract":"<div><div>This research investigates the role of dispersion of nanoparticles in gas during gas recycling process to improve the gas condensate recovery via altering the carbonate reservoirs wettability. The nanoparticles were synthesized and analyzed using dynamic light scattering (DLS), energy-dispersive X-ray (EDX), and transmission electron microscopy (TEM). After that, the dispersion of nanoparticles in methane was investigated by cloud point pressures measurement. Also, the effectiveness of methane/nanoparticles solutions was assessed through the contact angle experiments and gas recycling process. Based on the cloud point pressures results, the nanoparticles can be dispersed in methane at pressures commensurate with hydrocarbon reservoirs. Gas/nanoparticles single-phase solutions increased the contact angles of gas condensate and n-decane from 12° to 121° and 135.5°, respectively, for fluorinated silica, and to 100.5° and 108° for fluorinated titania. The shift from oil-wet to gas-wet conditions enhanced the recovery factor from 55% to 76%, marking a 21% improvement in gas condensate recovery during gas recycling. Furthermore, the pressure drop ratio decreased by 60%, due to better surface wettability and reduced condensate blockage. Comparative results indicated that the dispersion of fluorinated silica nanoparticles in gas outperformed fluorinated titania in altering wettability. These results emphasize the potential of current new approach, through dispersion of fluorinated nanoparticles in gas; to improve gas condensate recovery during gas recycling, especially in low-permeability carbonate reservoirs.</div></div>","PeriodicalId":37433,"journal":{"name":"Petroleum","volume":"11 6","pages":"Pages 770-783"},"PeriodicalIF":3.5,"publicationDate":"2025-12-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145847609","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
This study investigates the torsional stick-slip behavior of steel and aluminum drill strings under varying levels of aggressiveness, which refers to the intensity with which the drill bit interacts with the rock formation. Aggressiveness is primarily influenced by critical factors such as torque on bit (TOB), weight on bit (WOB), and rotational speed (RPM). It is quantitatively expressed as the ratio of TOB to WOB, a key determinant in the drilling process that influences how effectively the bit penetrates the formation. A small-scale drill string model was developed and tested under varying aggressiveness and RPMs using a numerical simulator. The objective was to assess how the different materials respond to torsional stick-slip vibrations across a range of operational parameters. The simulations were conducted over 30 s intervals with both stable and varying RPMs, allowing for a detailed comparison of the material's dynamic behaviors. The RPM limits, which indicate the maximum RPM beyond which severe stick-slip occurs, were calculated for both materials. Results revealed that steel drill strings exhibited superior stability, with fewer torsional oscillations and shorter sticking periods, particularly at higher aggressiveness ratios. While aluminum drill strings, being lightweight, showed greater susceptibility to torsional oscillations, especially at lower rotational speeds, leading to longer periods of stick-slips. Also, as the aggressiveness reduces, the RPM limits for both materials increases. This emphasizes the importance of identifying optimal RPM limits and material selection to minimize vibrations and improve drilling efficiency.
{"title":"Optimizing drilling efficiency: Comparative study of stick-slip vibration of steel and aluminum drill strings","authors":"Chinedu Ejike , Khizar Abid , Chinedu J. Okere , Catalin Teodoriu","doi":"10.1016/j.petlm.2025.09.005","DOIUrl":"10.1016/j.petlm.2025.09.005","url":null,"abstract":"<div><div>This study investigates the torsional stick-slip behavior of steel and aluminum drill strings under varying levels of aggressiveness, which refers to the intensity with which the drill bit interacts with the rock formation. Aggressiveness is primarily influenced by critical factors such as torque on bit (TOB), weight on bit (WOB), and rotational speed (RPM). It is quantitatively expressed as the ratio of TOB to WOB, a key determinant in the drilling process that influences how effectively the bit penetrates the formation. A small-scale drill string model was developed and tested under varying aggressiveness and RPMs using a numerical simulator. The objective was to assess how the different materials respond to torsional stick-slip vibrations across a range of operational parameters. The simulations were conducted over 30 s intervals with both stable and varying RPMs, allowing for a detailed comparison of the material's dynamic behaviors. The RPM limits, which indicate the maximum RPM beyond which severe stick-slip occurs, were calculated for both materials. Results revealed that steel drill strings exhibited superior stability, with fewer torsional oscillations and shorter sticking periods, particularly at higher aggressiveness ratios. While aluminum drill strings, being lightweight, showed greater susceptibility to torsional oscillations, especially at lower rotational speeds, leading to longer periods of stick-slips. Also, as the aggressiveness reduces, the RPM limits for both materials increases. This emphasizes the importance of identifying optimal RPM limits and material selection to minimize vibrations and improve drilling efficiency.</div></div>","PeriodicalId":37433,"journal":{"name":"Petroleum","volume":"11 6","pages":"Pages 732-743"},"PeriodicalIF":3.5,"publicationDate":"2025-12-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145847604","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Pub Date : 2025-12-01DOI: 10.1016/j.petlm.2025.11.004
Junyu You , Xingxin Jiang , Xiaoliang Huang , Qiqi Wanyan , Ziang He , Songze Li , Hongcheng Xu
The construction and operation of gas reservoir-type underground gas storage (UGS) facilities play a pivotal role in ensuring the safety and stability of natural gas supply. For gas reservoirs with edge or bottom water, the subsurface gas-water two-phase flow dynamics and high-speed injection/withdrawal (I/W) processes result in complex distributions of gas and water within the reservoir layers. Additionally, the boundaries of multiphase flow zones are often poorly defined, and the pore volume utilization efficiency (PVUE), which directly impacts effective storage capacity, remains difficult to quantify. These challenges hinder the accurate evaluation of gas storage capacity and complicate the design of optimal construction and operational parameters for UGS facilities. To address these issues, this study proposes an integrated approach combining multi-cycle I/W experiments, numerical reservoir simulations, and the mass balance method to accurately assess UGS storage capacity. The methodology was applied to an active UGS facility constructed in a water-bearing gas reservoir in northwestern China. The gas-bearing reservoir was categorized into four distinct flow zones: the gas zone, the gas-displacing-water zone, the transition zone, and the water zone. Key factors influencing immobile gas-bearing pore volume—such as water invasion and stress sensitivity—were identified for each zone. A mathematical model was developed to predict immobile gas-bearing pore volume, and a quantitative model was established to estimate effective gas storage space (underground) by incorporating PVUE variations across different flow zones. These models provided theoretical foundations for designing UGS construction and operational strategies. The results demonstrated: (1) After six I/W cycles, the measured PVUE in the gas zone was 99.3% and 94.9% for blocks B1 and B2, respectively. In the gas-displacing-water zone, the PVUE was 80.9% and 73.8%, while in the transition zone, it was 47.9% and 40.3%. (2) The total gas-bearing pore volume of the UGS was 9.65 million rm3 (subsurface conditions), with an effective gas storage space of 5.39 million rm3 after accounting for PVUE variations across flow zones. (3) Numerical simulations confirmed that the proposed UGS operational design would achieve a total inventory of 8.24 × 108 sm3 (surface conditions) and an effective storage capacity of 6.67 × 108 sm3. This study provided a robust framework for evaluating and optimizing UGS storage capacity in water-bearing gas reservoirs, offering valuable insights for the design and operation of such facilities.
{"title":"A multi-zone characterization-based framework for effective storage capacity evaluation in water-bearing reservoirs","authors":"Junyu You , Xingxin Jiang , Xiaoliang Huang , Qiqi Wanyan , Ziang He , Songze Li , Hongcheng Xu","doi":"10.1016/j.petlm.2025.11.004","DOIUrl":"10.1016/j.petlm.2025.11.004","url":null,"abstract":"<div><div>The construction and operation of gas reservoir-type underground gas storage (UGS) facilities play a pivotal role in ensuring the safety and stability of natural gas supply. For gas reservoirs with edge or bottom water, the subsurface gas-water two-phase flow dynamics and high-speed injection/withdrawal (I/W) processes result in complex distributions of gas and water within the reservoir layers. Additionally, the boundaries of multiphase flow zones are often poorly defined, and the pore volume utilization efficiency (PVUE), which directly impacts effective storage capacity, remains difficult to quantify. These challenges hinder the accurate evaluation of gas storage capacity and complicate the design of optimal construction and operational parameters for UGS facilities. To address these issues, this study proposes an integrated approach combining multi-cycle I/W experiments, numerical reservoir simulations, and the mass balance method to accurately assess UGS storage capacity. The methodology was applied to an active UGS facility constructed in a water-bearing gas reservoir in northwestern China. The gas-bearing reservoir was categorized into four distinct flow zones: the gas zone, the gas-displacing-water zone, the transition zone, and the water zone. Key factors influencing immobile gas-bearing pore volume—such as water invasion and stress sensitivity—were identified for each zone. A mathematical model was developed to predict immobile gas-bearing pore volume, and a quantitative model was established to estimate effective gas storage space (underground) by incorporating PVUE variations across different flow zones. These models provided theoretical foundations for designing UGS construction and operational strategies. The results demonstrated: (1) After six I/W cycles, the measured PVUE in the gas zone was 99.3% and 94.9% for blocks B1 and B2, respectively. In the gas-displacing-water zone, the PVUE was 80.9% and 73.8%, while in the transition zone, it was 47.9% and 40.3%. (2) The total gas-bearing pore volume of the UGS was 9.65 million rm<sup>3</sup> (subsurface conditions), with an effective gas storage space of 5.39 million rm<sup>3</sup> after accounting for PVUE variations across flow zones. (3) Numerical simulations confirmed that the proposed UGS operational design would achieve a total inventory of 8.24 × 10<sup>8</sup> sm<sup>3</sup> (surface conditions) and an effective storage capacity of 6.67 × 10<sup>8</sup> sm<sup>3</sup>. This study provided a robust framework for evaluating and optimizing UGS storage capacity in water-bearing gas reservoirs, offering valuable insights for the design and operation of such facilities.</div></div>","PeriodicalId":37433,"journal":{"name":"Petroleum","volume":"11 6","pages":"Pages 717-731"},"PeriodicalIF":3.5,"publicationDate":"2025-12-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145847606","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Pub Date : 2025-12-01DOI: 10.1016/j.petlm.2025.09.004
Malik Muhammad Ali Awan , Farzain Ud Din Kirmani
CO2 storage is a potential strategy for decarbonizing the fossil-based power and industrial sectors while also serving as a bridge technology for a long-term transition to a zero-emission future. CO2 storage has been identified as the most effective technique for reducing CO2 emissions. While numerous reviews exist, this study offers a critical synthesis focused on the integrated role of petrophysical properties across the entire lifecycle of carbon storage projects—from reservoir characterization and seal integrity assessment to real-time monitoring. Unlike reviews that treat these aspects independently, this paper emphasizes their interdependencies and practical implications for project safety and efficiency. It examines how porosity, permeability, wettability, and other petrophysical parameters influence storage capacity, injectivity, trapping mechanisms, and caprock stability. This review also addresses how uncertainty in petrophysical measurements can propagate through modeling and risk assessments and evaluates tools and simulators in terms of their sensitivity to such inputs. A novel contribution is linking petrophysical data quality with seal failure risks and monitoring reliability, an area underexplored in the existing literature. The study concludes by identifying critical research gaps and proposing a roadmap to enhance the reliability of future CO2 storage projects. These insights aim to support both researchers and project developers in designing more robust, data-informed storage strategies.
{"title":"Reservoir characterization, seal integrity assessment, and monitoring to ensure safe and effective implementation of carbon storage: A critical review","authors":"Malik Muhammad Ali Awan , Farzain Ud Din Kirmani","doi":"10.1016/j.petlm.2025.09.004","DOIUrl":"10.1016/j.petlm.2025.09.004","url":null,"abstract":"<div><div>CO<sub>2</sub> storage is a potential strategy for decarbonizing the fossil-based power and industrial sectors while also serving as a bridge technology for a long-term transition to a zero-emission future. CO<sub>2</sub> storage has been identified as the most effective technique for reducing CO<sub>2</sub> emissions. While numerous reviews exist, this study offers a critical synthesis focused on the integrated role of petrophysical properties across the entire lifecycle of carbon storage projects—from reservoir characterization and seal integrity assessment to real-time monitoring. Unlike reviews that treat these aspects independently, this paper emphasizes their interdependencies and practical implications for project safety and efficiency. It examines how porosity, permeability, wettability, and other petrophysical parameters influence storage capacity, injectivity, trapping mechanisms, and caprock stability. This review also addresses how uncertainty in petrophysical measurements can propagate through modeling and risk assessments and evaluates tools and simulators in terms of their sensitivity to such inputs. A novel contribution is linking petrophysical data quality with seal failure risks and monitoring reliability, an area underexplored in the existing literature. The study concludes by identifying critical research gaps and proposing a roadmap to enhance the reliability of future CO<sub>2</sub> storage projects. These insights aim to support both researchers and project developers in designing more robust, data-informed storage strategies.</div></div>","PeriodicalId":37433,"journal":{"name":"Petroleum","volume":"11 6","pages":"Pages 675-698"},"PeriodicalIF":3.5,"publicationDate":"2025-12-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145847603","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Pub Date : 2025-12-01DOI: 10.1016/j.petlm.2025.11.005
Grigoriy Shutov , Viktor Duplyakov , Shadfar Davoodi , Anton Morozov , Dmitriy Popkov , Kirill Pavlenko , Albert Vainshtein , Viktor Kotezhekov , Sergey Kaygorodov , Boris Belozerov , Mars M. Khasanov , Vladimir Vanovskiy , Andrei Osiptsov , Evgeny Burnaev
Obtaining reliable permeability maps of oil reservoirs is crucial for building a robust and accurate reservoir simulation model and, therefore, designing effective recovery strategies. This problem, however, remains challenging, as it requires the integration of various data sources by experts from different disciplines. Moreover, there are no sources to provide direct information about the inter-well space. In this work, a new method based on the data-fusion approach is proposed for predicting two-dimensional permeability maps on the whole reservoir area. This method utilizes non-parametric regression with a custom kernel shape accounting for different data sources: well logs, well tests, and seismics. A convolutional neural network is developed to process seismic data and then incorporate it with other sources. A multi-stage data fusion procedure helps to artificially increase the training dataset for the seismic interpretation model and finally to construct an adequate permeability map. The proposed methodology of permeability map construction from different sources was tested on a real oil reservoir located in Western Siberia. The results demonstrate that the developed map perfectly corresponds to the permeability estimations in the wells, and the inter-well space permeability predictions are considerably improved through the incorporation of the seismic data.
{"title":"A deep learning-aided approach for estimating field permeability map by fusing well logs, well tests, and seismic data","authors":"Grigoriy Shutov , Viktor Duplyakov , Shadfar Davoodi , Anton Morozov , Dmitriy Popkov , Kirill Pavlenko , Albert Vainshtein , Viktor Kotezhekov , Sergey Kaygorodov , Boris Belozerov , Mars M. Khasanov , Vladimir Vanovskiy , Andrei Osiptsov , Evgeny Burnaev","doi":"10.1016/j.petlm.2025.11.005","DOIUrl":"10.1016/j.petlm.2025.11.005","url":null,"abstract":"<div><div>Obtaining reliable permeability maps of oil reservoirs is crucial for building a robust and accurate reservoir simulation model and, therefore, designing effective recovery strategies. This problem, however, remains challenging, as it requires the integration of various data sources by experts from different disciplines. Moreover, there are no sources to provide direct information about the inter-well space. In this work, a new method based on the data-fusion approach is proposed for predicting two-dimensional permeability maps on the whole reservoir area. This method utilizes non-parametric regression with a custom kernel shape accounting for different data sources: well logs, well tests, and seismics. A convolutional neural network is developed to process seismic data and then incorporate it with other sources. A multi-stage data fusion procedure helps to artificially increase the training dataset for the seismic interpretation model and finally to construct an adequate permeability map. The proposed methodology of permeability map construction from different sources was tested on a real oil reservoir located in Western Siberia. The results demonstrate that the developed map perfectly corresponds to the permeability estimations in the wells, and the inter-well space permeability predictions are considerably improved through the incorporation of the seismic data.</div></div>","PeriodicalId":37433,"journal":{"name":"Petroleum","volume":"11 6","pages":"Pages 813-824"},"PeriodicalIF":3.5,"publicationDate":"2025-12-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145847684","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
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