The performances of numerical simulation and machine learning in production forecasting are severely dependent on precise geological modeling and high-quality history matching. To address these challenges, causal inference is an effective methodology since it can provide a causality for formalizing causality in history, not statistical dependence. In this paper, to dynamically predict oil production from causality existed in waterflooding oilfield, a dynamical counterfactual inference framework is built to predict oil production. The proposed framework can forecast the oil production under non-observation of engineering factors, i.e., counterfactual, and provide the causal effect of engineering factors impacting on oil production. Meanwhile, combining with the practice exploitation in engineering factor impacting on production, a counterfactual experiment is designed to execute counterfactual prediction. Compared with general machine learning and statistical models, our results not only show better performance in oil production flooding but also guide the specific optimization in improving production, which holds more practical application significance.
{"title":"Dynamical counterfactual inference under time-series model for waterflooding oilfield","authors":"Guoquan Wen , Chao Min , Qingxia Zhang , Guoyong Liao","doi":"10.1016/j.petlm.2024.11.001","DOIUrl":"10.1016/j.petlm.2024.11.001","url":null,"abstract":"<div><div>The performances of numerical simulation and machine learning in production forecasting are severely dependent on precise geological modeling and high-quality history matching. To address these challenges, causal inference is an effective methodology since it can provide a causality for formalizing causality in history, not statistical dependence. In this paper, to dynamically predict oil production from causality existed in waterflooding oilfield, a dynamical counterfactual inference framework is built to predict oil production. The proposed framework can forecast the oil production under non-observation of engineering factors, i.e., counterfactual, and provide the causal effect of engineering factors impacting on oil production. Meanwhile, combining with the practice exploitation in engineering factor impacting on production, a counterfactual experiment is designed to execute counterfactual prediction. Compared with general machine learning and statistical models, our results not only show better performance in oil production flooding but also guide the specific optimization in improving production, which holds more practical application significance.</div></div>","PeriodicalId":37433,"journal":{"name":"Petroleum","volume":"11 1","pages":"Pages 113-124"},"PeriodicalIF":4.2,"publicationDate":"2025-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"143534490","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"OA","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Pub Date : 2025-02-01DOI: 10.1016/j.petlm.2023.04.002
Weiji Liu , Hongxing Deng , Xiaohua Zhu , Yanxin Lv , Yunxu Luo
Many advanced rock breaking methods are emerged form improving the ROP in deep formation drilling in recent years, such as electric pulse rock breaking, ultrasonic rock breaking and hydraulic rock breaking. However, the traditional mechanical rock breaking is still the mainstream rock-breaking method. A detailed understanding of the rock cutting mechanism is essential to achieve high efficiency in rock breaking and to optimize the cutting parameters. This study establishes the simulation model of heterogeneous granite cut by polycrystalline diamond compact (PDC) cutter using FDEM, and the friction work factor is put forward to characterize the friction work proportion of PDC cutter in cutting process. Analysis is done on the variations in friction work factor, force, and failure mechanism of granite under different cutting depths. The results show that the three-dimensional force increase gradually with the increase of cutting depth. When the cutting depth is shallow, the tensile (Type I) failure is dominated, ductile failure mainly occurs to granite and the size of chips is small. When the cutting depth is deep, the proportion of tensile failure is low, the internal shear crack of granite gradually dominates, the failure mode of granite gradually changes to brittle failure, the chips gradually become larger. Friction work factor and failure factor can visualize the change of friction energy consumption of PDC cutter in rock cutting and the failure mode of rock. This study leads to an enhanced understanding of rock breaking mechanisms in rock cutting, and provides the basis to improve the PDC bit design.
{"title":"The rock cutting simulation of heterogeneous granite using FDEM method","authors":"Weiji Liu , Hongxing Deng , Xiaohua Zhu , Yanxin Lv , Yunxu Luo","doi":"10.1016/j.petlm.2023.04.002","DOIUrl":"10.1016/j.petlm.2023.04.002","url":null,"abstract":"<div><div>Many advanced rock breaking methods are emerged form improving the ROP in deep formation drilling in recent years, such as electric pulse rock breaking, ultrasonic rock breaking and hydraulic rock breaking. However, the traditional mechanical rock breaking is still the mainstream rock-breaking method. A detailed understanding of the rock cutting mechanism is essential to achieve high efficiency in rock breaking and to optimize the cutting parameters. This study establishes the simulation model of heterogeneous granite cut by polycrystalline diamond compact (PDC) cutter using FDEM, and the friction work factor is put forward to characterize the friction work proportion of PDC cutter in cutting process. Analysis is done on the variations in friction work factor, force, and failure mechanism of granite under different cutting depths. The results show that the three-dimensional force increase gradually with the increase of cutting depth. When the cutting depth is shallow, the tensile (Type I) failure is dominated, ductile failure mainly occurs to granite and the size of chips is small. When the cutting depth is deep, the proportion of tensile failure is low, the internal shear crack of granite gradually dominates, the failure mode of granite gradually changes to brittle failure, the chips gradually become larger. Friction work factor and failure factor can visualize the change of friction energy consumption of PDC cutter in rock cutting and the failure mode of rock. This study leads to an enhanced understanding of rock breaking mechanisms in rock cutting, and provides the basis to improve the PDC bit design.</div></div>","PeriodicalId":37433,"journal":{"name":"Petroleum","volume":"11 1","pages":"Pages 1-12"},"PeriodicalIF":4.2,"publicationDate":"2025-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86101089","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"OA","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Pub Date : 2025-02-01DOI: 10.1016/j.petlm.2024.10.001
Amr Gazem, Shanker Krishna
Enhanced oil recovery (EOR) methods are essential for optimizing oil extraction from modern reservoirs. This research delved into the synergistic impact of combining anionic and nonionic surfactant mixtures with silica (SiO2) nanoparticles (NPs) in sodium chloride (NaCl) solutions, alongside the added enhancement of polymers, to improve crude oil recovery. The study comprehensively evaluated stability, rheological characteristics, interfacial tension (IFT) behavior, wettability alterations, and EOR experiments using mixtures of sodium dodecyl sulfate (SDS) and triton X-100 (TX-100) surfactants. Scenarios both with and without SiO2 NPs in a base solution containing 3000 ppm NaCl and 2000 ppm xanthan gum (XG) polymer were examined. Core flooding tests were carried out on San-Saba sandstone core specimens with low permeability. The stability tests and dynamic light scattering (DLS) analysis were performed to assess the stability of NPs in low saline-surfactant-polymer solution. It was observed that NPs significantly reduced the IFT between the test solutions and crude oil, with nanofluids exhibiting satisfactory stability at a 0.4 wt% SiO2 NPs concentration. Core flooding studies demonstrated a synergistic interaction between NPs and the binary surfactant-polymer mixture, resulting in substantially greater incremental recovery of oil in comparison with the case of using binary surfactant-polymer combination alone. The mechanisms contributing to EOR with nanofluids, such as IFT reduction and wettability alteration, were explored. Incorporating NPs at concentrations of 0.1, 0.2, and 0.4 wt% led to incremental oil recoveries of 4.01%, 12.35%, and 12.73% of the original oil in place (OOIP), respectively, as opposed to the recovery achieved using only SDS + TX-100 + XG. Consequently, these findings advance the understanding of the potential application of SiO2 NPs in combination with the binary surfactant-polymer mixture as effective chemical EOR agents. Additionally, these insights aid in identifying suitable sandstone reservoirs for nanofluid application, contributing to the optimization of oil recovery strategies.
{"title":"Synergistic enhancement of oil recovery: Integrating anionic-nonionic surfactant mixtures, SiO2 nanoparticles, and polymer solutions for optimized crude oil extraction","authors":"Amr Gazem, Shanker Krishna","doi":"10.1016/j.petlm.2024.10.001","DOIUrl":"10.1016/j.petlm.2024.10.001","url":null,"abstract":"<div><div>Enhanced oil recovery (EOR) methods are essential for optimizing oil extraction from modern reservoirs. This research delved into the synergistic impact of combining anionic and nonionic surfactant mixtures with silica (SiO<sub>2</sub>) nanoparticles (NPs) in sodium chloride (NaCl) solutions, alongside the added enhancement of polymers, to improve crude oil recovery. The study comprehensively evaluated stability, rheological characteristics, interfacial tension (IFT) behavior, wettability alterations, and EOR experiments using mixtures of sodium dodecyl sulfate (SDS) and triton X-100 (TX-100) surfactants. Scenarios both with and without SiO<sub>2</sub> NPs in a base solution containing 3000 ppm NaCl and 2000 ppm xanthan gum (XG) polymer were examined. Core flooding tests were carried out on San-Saba sandstone core specimens with low permeability. The stability tests and dynamic light scattering (DLS) analysis were performed to assess the stability of NPs in low saline-surfactant-polymer solution. It was observed that NPs significantly reduced the IFT between the test solutions and crude oil, with nanofluids exhibiting satisfactory stability at a 0.4 wt% SiO<sub>2</sub> NPs concentration. Core flooding studies demonstrated a synergistic interaction between NPs and the binary surfactant-polymer mixture, resulting in substantially greater incremental recovery of oil in comparison with the case of using binary surfactant-polymer combination alone. The mechanisms contributing to EOR with nanofluids, such as IFT reduction and wettability alteration, were explored. Incorporating NPs at concentrations of 0.1, 0.2, and 0.4 wt% led to incremental oil recoveries of 4.01%, 12.35%, and 12.73% of the original oil in place (OOIP), respectively, as opposed to the recovery achieved using only SDS + TX-100 + XG. Consequently, these findings advance the understanding of the potential application of SiO<sub>2</sub> NPs in combination with the binary surfactant-polymer mixture as effective chemical EOR agents. Additionally, these insights aid in identifying suitable sandstone reservoirs for nanofluid application, contributing to the optimization of oil recovery strategies.</div></div>","PeriodicalId":37433,"journal":{"name":"Petroleum","volume":"11 1","pages":"Pages 102-112"},"PeriodicalIF":4.2,"publicationDate":"2025-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"143534489","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"OA","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
In low salinity polymer flooding (LSPF), an advanced hybrid method for enhanced oil recovery (EOR), less attention has been given to the impacts of potential determining ions on polymer behavior in carbonate reservoirs. Therefore, seawaters spiked with divalent ions were used with sulfonated polyacrylamide (SPAM) polymer to investigate the effects of potential determining ions on SPAM performance in wettability alteration, polymer adsorption, carbonate surface charge, viscosity enhancement, emulsion type, and oil recovery. Among divalent anions and cations, only excess amounts of Mg2+ in a smart water-polymer solution could alter the wettability from oil-wet to neutral-wet and make the rock/brine zeta potential positive. Additionally, higher SPAM adsorption onto carbonate surfaces was observed as Mg2+ concentration was doubled, driven by interactions between sulfonate groups (–SO3−) and the positively charged rock surface. Conversely, excess SO42- impeded interactions between –SO3– and positively charged carbonate rock species, reducing SPAM adsorption. At 5000 ppm SPAM concentration, excess divalent ions increased solution viscosity due to the shielding effect, with the highest viscosity achieved by doubling Mg2+ concentration. However, at 10,000 ppm SPAM concentration, only SO42- improved viscosity, while Ca2+ and Mg2+ reduced the viscosity of smart water-polymer solutions. As for emulsions produced by smart water-polymer solutions, the presence of SPAM in smart water led to the production of water-in-oil (W/O) emulsions and increased the mean droplet size of water droplets due to the salt-out effect. According to the results obtained from calcite-coated micromodel flooding experiments, the ultimate oil recovery for SW + SPAM (5000 ppm) was 34.2%. Also, a two-fold increase in the Mg2+ concentration rose the oil recovery by 6.5%.
{"title":"Effect of potential determining ions on sulfonated polyacrylamide behavior during smart water-polymer injection into carbonate reservoirs","authors":"Seyed Masoud Ghalamizade Elyaderani, Amir Hossein Saeedi Dehaghani, Javad Razavinezhad, Rasoul Tanhay Choshali","doi":"10.1016/j.petlm.2024.12.002","DOIUrl":"10.1016/j.petlm.2024.12.002","url":null,"abstract":"<div><div>In low salinity polymer flooding (LSPF), an advanced hybrid method for enhanced oil recovery (EOR), less attention has been given to the impacts of potential determining ions on polymer behavior in carbonate reservoirs. Therefore, seawaters spiked with divalent ions were used with sulfonated polyacrylamide (SPAM) polymer to investigate the effects of potential determining ions on SPAM performance in wettability alteration, polymer adsorption, carbonate surface charge, viscosity enhancement, emulsion type, and oil recovery. Among divalent anions and cations, only excess amounts of Mg<sup>2+</sup> in a smart water-polymer solution could alter the wettability from oil-wet to neutral-wet and make the rock/brine zeta potential positive. Additionally, higher SPAM adsorption onto carbonate surfaces was observed as Mg<sup>2+</sup> concentration was doubled, driven by interactions between sulfonate groups (–SO<sub>3</sub><sup>−</sup>) and the positively charged rock surface. Conversely, excess SO<sub>4</sub><sup>2</sup><sup>-</sup> impeded interactions between –SO<sub>3</sub><sup>–</sup> and positively charged carbonate rock species, reducing SPAM adsorption. At 5000 ppm SPAM concentration, excess divalent ions increased solution viscosity due to the shielding effect, with the highest viscosity achieved by doubling Mg<sup>2+</sup> concentration. However, at 10,000 ppm SPAM concentration, only SO<sub>4</sub><sup>2-</sup> improved viscosity, while Ca<sup>2+</sup> and Mg<sup>2+</sup> reduced the viscosity of smart water-polymer solutions. As for emulsions produced by smart water-polymer solutions, the presence of SPAM in smart water led to the production of water-in-oil (W/O) emulsions and increased the mean droplet size of water droplets due to the salt-out effect. According to the results obtained from calcite-coated micromodel flooding experiments, the ultimate oil recovery for SW + SPAM (5000 ppm) was 34.2%. Also, a two-fold increase in the Mg<sup>2+</sup> concentration rose the oil recovery by 6.5%.</div></div>","PeriodicalId":37433,"journal":{"name":"Petroleum","volume":"11 1","pages":"Pages 41-55"},"PeriodicalIF":4.2,"publicationDate":"2025-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"143534631","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"OA","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Pub Date : 2025-02-01DOI: 10.1016/j.petlm.2024.09.001
Gui Wang , Jiaqing Wang , Kai Tan
The solid weighting material in a high-density workover fluid is prone to static sag. Existing experimental methods cannot predict the parameters of the settling stability of workover fluids at high temperature and high pressure (HTHP). Therefore, in this study, static settlement experiments were carried out using a novel experimental setup. The experimental setup enables the measurement of the density profile of heavy workover fluids at HTHP. A multi-parameter correlation equation between the sag factor and particle diameter, particle density, base fluid density, workover fluid density and rheological parameters, aging time, temperature, and pressure was obtained using dimensional analysis and multivariate nonlinear regression methods. The results reveal that the settlement stability of the workover fluid decreases with the increase in temperature and pressure. Based on the multi-parameter correlation, the predicted and the measured values were compared and verified. The error between the predicted value and the measured value was within 5%. The average prediction error was 1.68%, and the maximum prediction error was 3.8%. These results reveal that the model proposed in this study can effectively predict the static sedimentation stability of the solid weighted Polysulfonate workover fluids. Furthermore, the proposed correlation can guide the properties adjustment of the workover fluids to achieve the required sag stability. This work provides a new approach to predict and control the sag stability of the solid weighted workover fluids.
{"title":"Experimental and modelling studies on static sag of solid weighting powders in Polysulfonate workover fluids at high temperature and high pressure","authors":"Gui Wang , Jiaqing Wang , Kai Tan","doi":"10.1016/j.petlm.2024.09.001","DOIUrl":"10.1016/j.petlm.2024.09.001","url":null,"abstract":"<div><div>The solid weighting material in a high-density workover fluid is prone to static sag. Existing experimental methods cannot predict the parameters of the settling stability of workover fluids at high temperature and high pressure (HTHP). Therefore, in this study, static settlement experiments were carried out using a novel experimental setup. The experimental setup enables the measurement of the density profile of heavy workover fluids at HTHP. A multi-parameter correlation equation between the sag factor and particle diameter, particle density, base fluid density, workover fluid density and rheological parameters, aging time, temperature, and pressure was obtained using dimensional analysis and multivariate nonlinear regression methods. The results reveal that the settlement stability of the workover fluid decreases with the increase in temperature and pressure. Based on the multi-parameter correlation, the predicted and the measured values were compared and verified. The error between the predicted value and the measured value was within 5%. The average prediction error was 1.68%, and the maximum prediction error was 3.8%. These results reveal that the model proposed in this study can effectively predict the static sedimentation stability of the solid weighted Polysulfonate workover fluids. Furthermore, the proposed correlation can guide the properties adjustment of the workover fluids to achieve the required sag stability. This work provides a new approach to predict and control the sag stability of the solid weighted workover fluids.</div></div>","PeriodicalId":37433,"journal":{"name":"Petroleum","volume":"11 1","pages":"Pages 13-22"},"PeriodicalIF":4.2,"publicationDate":"2025-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"143534628","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"OA","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Pub Date : 2025-02-01DOI: 10.1016/j.petlm.2024.12.003
Yan Liang , Sukai Wang , Guiyi Zhang , Yonglong Li , Wei Liu , Songlin Pu , Lipeng Zhang , Tianxiang Wang , Lianghui Wan , Xionghui Liu
Reutilizing flowback fluid and produced water to prepare fracturing fluid is still an urgent problem that needs to be solved and is not well solved. In this work, an anti-salt associative thickener (AAT) was synthesized by free radical copolymerization, and the molecular structure of AAT was demonstrated by FTIR and 1H-NMR. Furthermore, compared with a common anti-salt thickener (HAT), the comprehensive performances of AAT were systematically investigated under the conditions of fresh water, flowback fluid and produced water in Sulige Gasfield. The results show that under the conditions of an average salinity of 34,428 mg/L and an average high-valent ion content of 4967 mg/L, AAT can present good thickening capacity, temperature and shear resistance, drag reduction efficiency, sand-carrying ability, gel-breaking property and high-effective crosslinking capacity with organic zirconium crosslinker at high salinity, which implicates the great potential and feasibility to prepare fracturing fluid by reutilizing high-salinity flowback fluid and produced water without further treatment. Moreover, the possible mechanisms of the associative thickener to achieve high-effective drag reduction and sand-carrying might be the existence of reversible supramolecular structures and the significant increase of viscoelasticity by shear stretching in turbulent state. At the same time, both physical and chemical interaction can make a significant contribution to high-effective crosslinking capacity of associative thickener. All results and findings can provide an important reference for the design of novel fracturing fluid and the reutilization of high-salinity water in stimulation applications.
{"title":"Untreatment reutilization of high-salinity flowback fluid and produced water to prepare fracturing fluid by using associative thickener","authors":"Yan Liang , Sukai Wang , Guiyi Zhang , Yonglong Li , Wei Liu , Songlin Pu , Lipeng Zhang , Tianxiang Wang , Lianghui Wan , Xionghui Liu","doi":"10.1016/j.petlm.2024.12.003","DOIUrl":"10.1016/j.petlm.2024.12.003","url":null,"abstract":"<div><div>Reutilizing flowback fluid and produced water to prepare fracturing fluid is still an urgent problem that needs to be solved and is not well solved. In this work, an anti-salt associative thickener (AAT) was synthesized by free radical copolymerization, and the molecular structure of AAT was demonstrated by FTIR and <sup>1</sup>H-NMR. Furthermore, compared with a common anti-salt thickener (HAT), the comprehensive performances of AAT were systematically investigated under the conditions of fresh water, flowback fluid and produced water in Sulige Gasfield. The results show that under the conditions of an average salinity of 34,428 mg/L and an average high-valent ion content of 4967 mg/L, AAT can present good thickening capacity, temperature and shear resistance, drag reduction efficiency, sand-carrying ability, gel-breaking property and high-effective crosslinking capacity with organic zirconium crosslinker at high salinity, which implicates the great potential and feasibility to prepare fracturing fluid by reutilizing high-salinity flowback fluid and produced water without further treatment. Moreover, the possible mechanisms of the associative thickener to achieve high-effective drag reduction and sand-carrying might be the existence of reversible supramolecular structures and the significant increase of viscoelasticity by shear stretching in turbulent state. At the same time, both physical and chemical interaction can make a significant contribution to high-effective crosslinking capacity of associative thickener. All results and findings can provide an important reference for the design of novel fracturing fluid and the reutilization of high-salinity water in stimulation applications.</div></div>","PeriodicalId":37433,"journal":{"name":"Petroleum","volume":"11 1","pages":"Pages 23-40"},"PeriodicalIF":4.2,"publicationDate":"2025-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"143534630","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"OA","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Pub Date : 2025-02-01DOI: 10.1016/j.petlm.2023.12.005
Shuai Zhao , Wanfen Pu , Yibo Li , Qi Jiang
The investigation of low-temperature oxidation (LTO) of crude oil within tight shale holds significant importance due to its implications for subsequent oxidation reactions and enhanced oil recovery in the process of air injection. In this study, the tight shale sample underwent oxidation at various LTO temperatures, followed by an analysis of the resulting gas composition. Furthermore, the oxidized oil was separated from the tight shale and subjected to characterization using electron paramagnetic resonance, nuclear magnetic resonance, and negative ion electrospray Fourier transform-ion cyclotron resonance mass spectrometry techniques. The primary focus was on examining the distinct LTO reaction pathways observable across different temperature ranges. The findings demonstrated a correlation between LTO temperature and the concentration of free radicals, which predominantly resided on aromatic hydrocarbons, alkanes, and oxygen atoms. Additionally, the proton count of polycyclic aromatic hydrocarbons exhibited a continuous increase from 83 to 350°C, suggesting intensified aromatization and condensation reactions involving aliphatic and aromatic compounds. With rising LTO temperature, the molecular structure of O2 compounds underwent significant transformations, characterized by increased condensation degree and a decrease in low carbon number molecular structures, while higher equivalent double bonds and carbon number molecular structures became more prevalent. The LTO reaction pathways of shale oil included cycle paths 1, 2, and 3. The influence of cycle path 1 diminished at temperatures ranging from 83 to 150°C and 250 to 350°C, whereas the significance of cycle paths 2 and 3 increased, resulting in an overall escalation of the oxidation rate with temperature elevation. It was observed that the shale oil LTO process exhibited a negative temperature coefficient within the temperature range of 150 to 250°C, emphasizing the criticality of overcoming the energy barrier in this region to achieve stable combustion. This comprehensive investigation provides valuable insights into the mechanisms underlying LTO in crude oil confined within tight shale.
{"title":"Low-temperature oxidation characteristics and reaction pathways of crude oil within tight shale during air injection","authors":"Shuai Zhao , Wanfen Pu , Yibo Li , Qi Jiang","doi":"10.1016/j.petlm.2023.12.005","DOIUrl":"10.1016/j.petlm.2023.12.005","url":null,"abstract":"<div><div>The investigation of low-temperature oxidation (LTO) of crude oil within tight shale holds significant importance due to its implications for subsequent oxidation reactions and enhanced oil recovery in the process of air injection. In this study, the tight shale sample underwent oxidation at various LTO temperatures, followed by an analysis of the resulting gas composition. Furthermore, the oxidized oil was separated from the tight shale and subjected to characterization using electron paramagnetic resonance, nuclear magnetic resonance, and negative ion electrospray Fourier transform-ion cyclotron resonance mass spectrometry techniques. The primary focus was on examining the distinct LTO reaction pathways observable across different temperature ranges. The findings demonstrated a correlation between LTO temperature and the concentration of free radicals, which predominantly resided on aromatic hydrocarbons, alkanes, and oxygen atoms. Additionally, the proton count of polycyclic aromatic hydrocarbons exhibited a continuous increase from 83 to 350°C, suggesting intensified aromatization and condensation reactions involving aliphatic and aromatic compounds. With rising LTO temperature, the molecular structure of O<sub>2</sub> compounds underwent significant transformations, characterized by increased condensation degree and a decrease in low carbon number molecular structures, while higher equivalent double bonds and carbon number molecular structures became more prevalent. The LTO reaction pathways of shale oil included cycle paths 1, 2, and 3. The influence of cycle path 1 diminished at temperatures ranging from 83 to 150°C and 250 to 350°C, whereas the significance of cycle paths 2 and 3 increased, resulting in an overall escalation of the oxidation rate with temperature elevation. It was observed that the shale oil LTO process exhibited a negative temperature coefficient within the temperature range of 150 to 250°C, emphasizing the criticality of overcoming the energy barrier in this region to achieve stable combustion. This comprehensive investigation provides valuable insights into the mechanisms underlying LTO in crude oil confined within tight shale.</div></div>","PeriodicalId":37433,"journal":{"name":"Petroleum","volume":"11 1","pages":"Pages 84-93"},"PeriodicalIF":4.2,"publicationDate":"2025-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"143534488","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"OA","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Pub Date : 2025-02-01DOI: 10.1016/j.petlm.2024.04.001
Qiang Wang , Yufeng Wang , Rong Wang , Jinzhou Zhao , Yongquan Hu , Jin Zhao
Stress changes associated with reservoir depletion have been frequently observed. Stress evolution within and around the drainage areas can affect the completion of infill wells and refracturing considerably. To accurately predict the stress distribution in shale gas reservoirs, a coupled fluid-flow/geomechanics model considering the microscopic seepage mechanism of shale gas and the distribution of complex natural fractures (NFs) was derived based on Biot's theory, the embedded discrete fracture model, and the finite volume method. Based on this model, stress can be predicted by considering the mechanisms of adsorption, desorption, diffusion, and slippage of shale gas and the random distribution of NFs. The results show that in the process of stress evolution, there will be extremes of σxx, σyy, σxy, Δσ, α, and stress reversal area at a certain point, and the time of occurrence of extremes differs at different positions. The key to determining this law is the pore pressure gradient, with a spatiotemporal evolution effect. Different microscopic seepage mechanisms significantly influence the storage and transmission of shale gas, leading to significant differences in the distributions of reservoir pressure and stress. The larger the initial stress difference, the more difficult the stress reversal. When the initial stress difference exceeds a certain limit, stress reversal does not occur in the reservoir. Under the influence of the distribution difference of the NFs, the shape of the pressure-depletion area and magnitude of the pressure gradient differed significantly. As the approaching angle of NFs increased, the range of stress reversal in the top and bottom parts of the domain gradually decreases; At the same time, the orientation of maximum horizontal stress (MHS) near the fractures also gradually decreases. When the approaching angles of the NFs are the same, the number of natural fractures has little effect on the stress. Owing to the effect of NFs and hydraulic fracture, the anisotropy of stress is enhanced, the occurrence time of extreme value of local stress and stress reversal area differ significantly, and selecting the timing of infill well fracturing and refracturing becomes difficult. This research is essential to understanding the stress evolution law of shale gas reservoirs and guiding the completion of infill wells and refracturing design.
{"title":"Evolution law of stress induced by pressure depletion in fractured shale reservoirs: Implications for subsequent refracturing and infill well development","authors":"Qiang Wang , Yufeng Wang , Rong Wang , Jinzhou Zhao , Yongquan Hu , Jin Zhao","doi":"10.1016/j.petlm.2024.04.001","DOIUrl":"10.1016/j.petlm.2024.04.001","url":null,"abstract":"<div><div>Stress changes associated with reservoir depletion have been frequently observed. Stress evolution within and around the drainage areas can affect the completion of infill wells and refracturing considerably. To accurately predict the stress distribution in shale gas reservoirs, a coupled fluid-flow/geomechanics model considering the microscopic seepage mechanism of shale gas and the distribution of complex natural fractures (NFs) was derived based on Biot's theory, the embedded discrete fracture model, and the finite volume method. Based on this model, stress can be predicted by considering the mechanisms of adsorption, desorption, diffusion, and slippage of shale gas and the random distribution of NFs. The results show that in the process of stress evolution, there will be extremes of <em>σ</em><sub><em>xx</em></sub>, <em>σ</em><sub><em>yy</em></sub>, <em>σ</em><sub><em>xy</em></sub>, <em>Δσ</em>, <em>α</em>, and stress reversal area at a certain point, and the time of occurrence of extremes differs at different positions. The key to determining this law is the pore pressure gradient, with a spatiotemporal evolution effect. Different microscopic seepage mechanisms significantly influence the storage and transmission of shale gas, leading to significant differences in the distributions of reservoir pressure and stress. The larger the initial stress difference, the more difficult the stress reversal. When the initial stress difference exceeds a certain limit, stress reversal does not occur in the reservoir. Under the influence of the distribution difference of the NFs, the shape of the pressure-depletion area and magnitude of the pressure gradient differed significantly. As the approaching angle of NFs increased, the range of stress reversal in the top and bottom parts of the domain gradually decreases; At the same time, the orientation of maximum horizontal stress (MHS) near the fractures also gradually decreases. When the approaching angles of the NFs are the same, the number of natural fractures has little effect on the stress. Owing to the effect of NFs and hydraulic fracture, the anisotropy of stress is enhanced, the occurrence time of extreme value of local stress and stress reversal area differ significantly, and selecting the timing of infill well fracturing and refracturing becomes difficult. This research is essential to understanding the stress evolution law of shale gas reservoirs and guiding the completion of infill wells and refracturing design.</div></div>","PeriodicalId":37433,"journal":{"name":"Petroleum","volume":"11 1","pages":"Pages 71-83"},"PeriodicalIF":4.2,"publicationDate":"2025-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140785914","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"OA","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Because of the nature of low permeability of shale and tight reservoirs, a gas injection method has the advantage of enhancing oil recovery. Among gases, air has its vast and free resources. And one extra benefit is its thermal effect resulting from combustion. However, issues of feasibility of spontaneous ignition, oil requirement, and air requirement for the continuation of combustion in shale and tight reservoirs need to be addressed. This paper is to address these issues with the aid of numerical simulation. The relevant literature information is reviewed when discussing these issues. It is found that failure of spontaneous ignition may be caused by more factors such as vaporization, fuel displacement by air, etc., in addition to lack of oil exothermicity and heat loss that are commonly believed; the oil saturation difference between the initial oil saturation and the remaining oil saturation after air flooding and low-temperature oxidation is proposed to define the oil content; air requirement may not be satisfied in typical shale or tight reservoirs because of the low injectivity. More factors can complicate the issues of feasibility of spontaneous ignition, oil requirement, and air requirement. Therefore, a simulation approach is more appropriate to address those issues.
{"title":"Discussion of the feasibility of spontaneous ignition, oil requirement, and air requirement for air injection in shale and tight reservoirs","authors":"Jiaping Sheng , Erlong Yang , Siyuan Huang , Chaofan Zhu , Weiyu Tang","doi":"10.1016/j.petlm.2024.12.001","DOIUrl":"10.1016/j.petlm.2024.12.001","url":null,"abstract":"<div><div>Because of the nature of low permeability of shale and tight reservoirs, a gas injection method has the advantage of enhancing oil recovery. Among gases, air has its vast and free resources. And one extra benefit is its thermal effect resulting from combustion. However, issues of feasibility of spontaneous ignition, oil requirement, and air requirement for the continuation of combustion in shale and tight reservoirs need to be addressed. This paper is to address these issues with the aid of numerical simulation. The relevant literature information is reviewed when discussing these issues. It is found that failure of spontaneous ignition may be caused by more factors such as vaporization, fuel displacement by air, etc., in addition to lack of oil exothermicity and heat loss that are commonly believed; the oil saturation difference between the initial oil saturation and the remaining oil saturation after air flooding and low-temperature oxidation is proposed to define the oil content; air requirement may not be satisfied in typical shale or tight reservoirs because of the low injectivity. More factors can complicate the issues of feasibility of spontaneous ignition, oil requirement, and air requirement. Therefore, a simulation approach is more appropriate to address those issues.</div></div>","PeriodicalId":37433,"journal":{"name":"Petroleum","volume":"11 1","pages":"Pages 94-101"},"PeriodicalIF":4.2,"publicationDate":"2025-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"143534629","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"OA","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Pub Date : 2025-02-01DOI: 10.1016/j.petlm.2024.11.002
Huiying Tang , Qi Ruan , Liehui Zhang , Dandan Hu , Jianhua Qin , Yulong Zhao , Yiping Ye
The Mahu oilfield in the Junggar Basin of Xinjiang has the characteristics of poor reservoir quality, large horizontal stress difference, and strong heterogeneity, which poses challenges in oil production due to the unclear hydraulic fracture geometry, large fracturing effectiveness difference among wells/stages, and the lack of automation in stage and cluster designs. To address the above issues, this study proposes systematically intelligent designs for stage and cluster parameters in the tight conglomerate oil reservoir in the Ma131 well area. First, through sensitivity analysis, the key parameters for stage division (storage coefficient, brittleness index, and minimum horizontal principal stress) are identified, and a stage division algorithm is developed based on the similarity of these key parameters. In order to quickly calculate the productivity of different cluster designs, a single cluster production prediction dataset was established by using the fracturing-production integrated numerical simulation method. Based on the results of fracturing stage division, cluster spacing and injection volume are quickly optimized using the above dataset, and the cluster locations are optimized with the objective of balanced fracture initiation and propagation. Finally, the automatic designs of fracturing stage and cluster starting from the well logging data is realized. Then, the proposed optimization method is applied to a practical well and both the production and profit are increased with the optimized designs. The proposed method can efficiently and intelligently optimize the stage and cluster designs for horizontal wells with the consideration of fracture propagation, productivity, and economic benefits, which helps provide theoretical and methodological support for fracturing designs in unconventional reservoirs such as the tight conglomerate oil reservoirs in this work.
{"title":"Intelligent optimization of fracturing stage and cluster parameters for tight oil reservoir","authors":"Huiying Tang , Qi Ruan , Liehui Zhang , Dandan Hu , Jianhua Qin , Yulong Zhao , Yiping Ye","doi":"10.1016/j.petlm.2024.11.002","DOIUrl":"10.1016/j.petlm.2024.11.002","url":null,"abstract":"<div><div>The Mahu oilfield in the Junggar Basin of Xinjiang has the characteristics of poor reservoir quality, large horizontal stress difference, and strong heterogeneity, which poses challenges in oil production due to the unclear hydraulic fracture geometry, large fracturing effectiveness difference among wells/stages, and the lack of automation in stage and cluster designs. To address the above issues, this study proposes systematically intelligent designs for stage and cluster parameters in the tight conglomerate oil reservoir in the Ma131 well area. First, through sensitivity analysis, the key parameters for stage division (storage coefficient, brittleness index, and minimum horizontal principal stress) are identified, and a stage division algorithm is developed based on the similarity of these key parameters. In order to quickly calculate the productivity of different cluster designs, a single cluster production prediction dataset was established by using the fracturing-production integrated numerical simulation method. Based on the results of fracturing stage division, cluster spacing and injection volume are quickly optimized using the above dataset, and the cluster locations are optimized with the objective of balanced fracture initiation and propagation. Finally, the automatic designs of fracturing stage and cluster starting from the well logging data is realized. Then, the proposed optimization method is applied to a practical well and both the production and profit are increased with the optimized designs. The proposed method can efficiently and intelligently optimize the stage and cluster designs for horizontal wells with the consideration of fracture propagation, productivity, and economic benefits, which helps provide theoretical and methodological support for fracturing designs in unconventional reservoirs such as the tight conglomerate oil reservoirs in this work.</div></div>","PeriodicalId":37433,"journal":{"name":"Petroleum","volume":"11 1","pages":"Pages 56-70"},"PeriodicalIF":4.2,"publicationDate":"2025-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"143534632","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"OA","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
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