Matthew Edward Billingham, Fraser James Proud, Pierre Ramondenc
This analysis challenges the typical way interventions have been planned and executed, both on an operational and a commercial basis, and examines where there is room for significant improvement in the industry. Perhaps more importantly, it examines the case for performing interventions and tries to explain the challenges (“headwinds”) in what is an opportunity to achieve both financial and net-zero emissions goals. Benchmarked data have already shown that opportunity absolutely exists to do more, and we investigate why the intervention opportunity is underserved. By appreciating the issues operators face when justifying and designing intervention activities, the challenges can thus be addressed by proper alignment to the best outcome. Intervention global expenditure is a small percentage of the total cost of exploration and production, and yet there is a strong value case for such operations. This study examines why this is so and then looks at how to address those issues. There is a huge array of well integrity and reservoir performance challenges that can bottleneck production, and the industry has delivered many innovative solutions to address these issues. Reduced capital expenditure over the past years and the pressure to maintain production sustainably should create a perfect climate for intervention. However, an asset mindset that is often risk averse to entering a producing well, as well as complex workflows, will too often detract from the opportunity to intervene. New workflows—including digital—can simplify the identification of candidate wells, and intervention techniques can help determine the success rate of the operations, as well as incremental production gains, more reliably to enable more robust outcomes. However, current contracting techniques and conventional key performance indicators can also cause further misalignment as to the true goal of interventions being to increase production sustainably. Those issues and how they have been resolved are addressed in this study. New workflows and commercial models have been used to facilitate the quicker identification of intervention opportunities, enabling collaborative planning and optimal solution identification, combined with feedback mechanisms to ensure continuous close collaboration between technical experts enabled by digital tools, which can disrupt the conventional intervention model. Case examples support the arguments made and demonstrate a new way of performing interventions. New digital workflows combined with strong collaborative, technical domain knowledge and a wide array of possible intervention solutions can change current typical intervention models. With these changes, further improvements can then be made to the conventional business models used to maximize the intervention opportunity and the sustainability opportunities it brings with regard to getting the most out of existing infrastructure.
{"title":"The Intervention Opportunity: Why the Industry Does Not Do More and How New Collaborative Workflows with Aligned Outcomes Can Change This","authors":"Matthew Edward Billingham, Fraser James Proud, Pierre Ramondenc","doi":"10.2118/212922-pa","DOIUrl":"https://doi.org/10.2118/212922-pa","url":null,"abstract":"\u0000 This analysis challenges the typical way interventions have been planned and executed, both on an operational and a commercial basis, and examines where there is room for significant improvement in the industry. Perhaps more importantly, it examines the case for performing interventions and tries to explain the challenges (“headwinds”) in what is an opportunity to achieve both financial and net-zero emissions goals. Benchmarked data have already shown that opportunity absolutely exists to do more, and we investigate why the intervention opportunity is underserved. By appreciating the issues operators face when justifying and designing intervention activities, the challenges can thus be addressed by proper alignment to the best outcome.\u0000 Intervention global expenditure is a small percentage of the total cost of exploration and production, and yet there is a strong value case for such operations. This study examines why this is so and then looks at how to address those issues. There is a huge array of well integrity and reservoir performance challenges that can bottleneck production, and the industry has delivered many innovative solutions to address these issues. Reduced capital expenditure over the past years and the pressure to maintain production sustainably should create a perfect climate for intervention. However, an asset mindset that is often risk averse to entering a producing well, as well as complex workflows, will too often detract from the opportunity to intervene. New workflows—including digital—can simplify the identification of candidate wells, and intervention techniques can help determine the success rate of the operations, as well as incremental production gains, more reliably to enable more robust outcomes. However, current contracting techniques and conventional key performance indicators can also cause further misalignment as to the true goal of interventions being to increase production sustainably. Those issues and how they have been resolved are addressed in this study.\u0000 New workflows and commercial models have been used to facilitate the quicker identification of intervention opportunities, enabling collaborative planning and optimal solution identification, combined with feedback mechanisms to ensure continuous close collaboration between technical experts enabled by digital tools, which can disrupt the conventional intervention model. Case examples support the arguments made and demonstrate a new way of performing interventions.\u0000 New digital workflows combined with strong collaborative, technical domain knowledge and a wide array of possible intervention solutions can change current typical intervention models. With these changes, further improvements can then be made to the conventional business models used to maximize the intervention opportunity and the sustainability opportunities it brings with regard to getting the most out of existing infrastructure.","PeriodicalId":22252,"journal":{"name":"SPE Journal","volume":null,"pages":null},"PeriodicalIF":3.6,"publicationDate":"2024-03-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140277937","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
This study presents a novel multiscale approach for assessing the accessibility of shale oil in cores by use of focused ion beam-scanning electron microscopy (FIB-SEM) equipment to build digital core, watershed, and maximum ball methods to extract pore size and shape factor. Then, molecular simulation is used to study the availability of shale oil in individual pores with different shapes and radii. Finally, combining the results of the above two scales, machine learning is used to predict shale oil availability across the entire core. On the core scale, the watershed and maximum ball methods are used to extract the core pore network model, and it is found that square pores occupy the highest proportion among the three pore types, and most of the radii are distributed in the range of 2–3 nm. The molecular-scale dynamic simulation results show that the adsorption forms of shale oil are different in different pores, and the adsorption of shale oil in circular pores is less than that in flat pores. The proportion of shale oil adsorption in square pores is the highest, followed by triangular pores, and the proportion of shale oil adsorption in circular pores is the lowest. The random forest machine learning algorithm is used to predict the availability of shale oil with different pore shapes and obtain the shale oil availability ratio of the whole core. The results show that the pores with a more obvious angular structure show a lower shale oil availability ratio. In general, the impact of pore shapes on shale oil availability is not significant, and the difference between different pore shapes is only 10%. The multiscale evaluation method for shale oil availability proposed in this study is helpful to better understand the availability of shale oil in reservoirs and to optimize recovery strategies.
{"title":"A Multiscale Approach for Assessing Shale Oil Availability: Digital Core, Molecular Simulation, and Machine Learning Analysis","authors":"Yifan Yin, Zhixue Sun","doi":"10.2118/219475-pa","DOIUrl":"https://doi.org/10.2118/219475-pa","url":null,"abstract":"\u0000 This study presents a novel multiscale approach for assessing the accessibility of shale oil in cores by use of focused ion beam-scanning electron microscopy (FIB-SEM) equipment to build digital core, watershed, and maximum ball methods to extract pore size and shape factor. Then, molecular simulation is used to study the availability of shale oil in individual pores with different shapes and radii. Finally, combining the results of the above two scales, machine learning is used to predict shale oil availability across the entire core. On the core scale, the watershed and maximum ball methods are used to extract the core pore network model, and it is found that square pores occupy the highest proportion among the three pore types, and most of the radii are distributed in the range of 2–3 nm. The molecular-scale dynamic simulation results show that the adsorption forms of shale oil are different in different pores, and the adsorption of shale oil in circular pores is less than that in flat pores. The proportion of shale oil adsorption in square pores is the highest, followed by triangular pores, and the proportion of shale oil adsorption in circular pores is the lowest. The random forest machine learning algorithm is used to predict the availability of shale oil with different pore shapes and obtain the shale oil availability ratio of the whole core. The results show that the pores with a more obvious angular structure show a lower shale oil availability ratio. In general, the impact of pore shapes on shale oil availability is not significant, and the difference between different pore shapes is only 10%. The multiscale evaluation method for shale oil availability proposed in this study is helpful to better understand the availability of shale oil in reservoirs and to optimize recovery strategies.","PeriodicalId":22252,"journal":{"name":"SPE Journal","volume":null,"pages":null},"PeriodicalIF":3.6,"publicationDate":"2024-03-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140280095","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Sand control screens are necessary for steam-assisted gravity drainage (SAGD) wells drilled into oil sands to prevent sand production. However, the accumulation of mobilized fine particles near the wellbore can result in screen plugging, adversely affecting the well’s flow performance. This research assesses the effects of formation water salinity on fines migration and the flow performance of sand control screens in SAGD wells. The study primarily examines these effects through sand retention testing (SRT) conducted under representative rock and multiphase flow conditions. This research developed a novel SRT methodology, which implemented the salinity effect in multiphase flow through sandpack and sand control screen. Two sand retention tests were designed, both using identical procedures in two-phase fluid flow (oil and brine), flow rate, and water cut. The first test used constant salinity, emulating existing SRT procedures in the literature. The second test, however, used gradually reducing levels of salinity to emulate declining salinities around SAGD production wells caused by the flow of condensed steam. The results indicated a significant decrease in the retained permeability of the screen coupon due to fines migration triggered by the reduction of salinity. Single-phase oil flow stages did not show noticeable produced fine particles at the outlet. In two-phase flow conditions, high flow rate and water cut stages induced higher produced fine particles under constant salinity, reflecting the hydrodynamic effects in fines migration. However, observations confirmed a substantial mass concentration of fine particles was mobilized, retained, and produced by reducing salinity. The findings of this study reveal the importance of the salinity effect on fines migration and the flow performance of SAGD wells where high saline formation water is diluted by low-saline condensate steam. Testing results indicate the necessity of incorporating the chemical effects in sand retention tests. Further research considering high-pressure and high-temperature conditions around SAGD wells and interactions with other formation damage mechanisms would extend this research.
{"title":"Near-Wellbore Salinity Effect on Sand Control Plugging by Fines Migration in Steam-Assisted Gravity Drainage Producer Wells","authors":"Hoda Dadjou, R. Miri, M. Salimi, A. Nouri","doi":"10.2118/219477-pa","DOIUrl":"https://doi.org/10.2118/219477-pa","url":null,"abstract":"\u0000 Sand control screens are necessary for steam-assisted gravity drainage (SAGD) wells drilled into oil sands to prevent sand production. However, the accumulation of mobilized fine particles near the wellbore can result in screen plugging, adversely affecting the well’s flow performance. This research assesses the effects of formation water salinity on fines migration and the flow performance of sand control screens in SAGD wells. The study primarily examines these effects through sand retention testing (SRT) conducted under representative rock and multiphase flow conditions.\u0000 This research developed a novel SRT methodology, which implemented the salinity effect in multiphase flow through sandpack and sand control screen. Two sand retention tests were designed, both using identical procedures in two-phase fluid flow (oil and brine), flow rate, and water cut. The first test used constant salinity, emulating existing SRT procedures in the literature. The second test, however, used gradually reducing levels of salinity to emulate declining salinities around SAGD production wells caused by the flow of condensed steam.\u0000 The results indicated a significant decrease in the retained permeability of the screen coupon due to fines migration triggered by the reduction of salinity. Single-phase oil flow stages did not show noticeable produced fine particles at the outlet. In two-phase flow conditions, high flow rate and water cut stages induced higher produced fine particles under constant salinity, reflecting the hydrodynamic effects in fines migration. However, observations confirmed a substantial mass concentration of fine particles was mobilized, retained, and produced by reducing salinity.\u0000 The findings of this study reveal the importance of the salinity effect on fines migration and the flow performance of SAGD wells where high saline formation water is diluted by low-saline condensate steam. Testing results indicate the necessity of incorporating the chemical effects in sand retention tests. Further research considering high-pressure and high-temperature conditions around SAGD wells and interactions with other formation damage mechanisms would extend this research.","PeriodicalId":22252,"journal":{"name":"SPE Journal","volume":null,"pages":null},"PeriodicalIF":3.6,"publicationDate":"2024-03-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140273757","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
3D bulk polymer, as an alternative to linear polymer, has exhibited large potential in formulating high-performance water-based drilling fluids. Understanding the mechanism behind the enhanced rheological stability of drilling fluids by microspherical polymers is critical for designing and developing new high-performance drilling fluids. In this work, we conducted a pioneering investigation that integrated experimental techniques with computational modeling, to explore the enhancement mechanism involved in the targeted drilling fluids. Inverse emulsion polymerization experiments were first carried out to fabricate the microspherical polymer acrylic acid (AA), acrylamide (AM), and 2-acryloylamino-2-methyl-1-propanesulfonic acid [P(AA-AM-AMPS)], and then physicochemical properties of microspherical polymer were characterized. Subsequently, the performance of drilling fluids with microspherical polymer as an additive was systematically evaluated. Finally, molecular simulations were used to investigate the characteristics of chemical active sites, molecular conformation, and structural variation at various temperatures. The results showed that the final microspherical polymer has a core-shell structure, with an average size of 198.3 nm and a molecular weight of 6.2×106 g/mol. The 3D structure exhibits good thermal stability, and thermal decomposition occurs above 220°C. The drilling fluids formulated with the microspherical polymer showed better rheological stability in the medium-low (4–65°C) and medium-ultrahigh (40–240°C) temperature ranges, compared with the relevant drilling fluids with the parallel linear polymer. Analyses on electrostatic potentials (ESPs) and frontier molecular orbital (FMO) revealed that active groups within the confined sphere domain mainly include carbonyl C = O and amide -CO(NH2). Additionally, these active groups exhibit a hierarchical distribution in the outer molecular region. Analyses on the radius of gyration (Rg) and the radial distribution function g(r) further validated the core-shell structure of microspherical polymer and its temperature-resistant stability. Moreover, a new self-consistent structural compensation model was proposed to rationalize the structure-activity relationship of microspherical polymer in drilling fluids. The computational results align well with the experimental findings. This pioneering work will provide valuable information for both the synthesis of new functional additives and the formulation of tailored-performance drilling fluids.
三维块状聚合物作为线性聚合物的替代品，在配制高性能水基钻井液方面具有巨大潜力。了解微球聚合物增强钻井液流变稳定性的机理对于设计和开发新型高性能钻井液至关重要。在这项工作中，我们进行了一项开创性的研究，将实验技术与计算建模相结合，探索目标钻井液的增强机理。首先进行了反乳液聚合实验，制备了微球聚合物丙烯酸（AA）、丙烯酰胺（AM）和 2-丙烯酰氨基-2-甲基-1-丙磺酸[P(AA-AM-AMPS)]，然后对微球聚合物的理化性质进行了表征。随后，对以微球聚合物为添加剂的钻井液的性能进行了系统评估。最后，利用分子模拟研究了不同温度下的化学活性位点特征、分子构象和结构变化。结果表明，最终的微球聚合物具有核壳结构，平均尺寸为 198.3 nm，分子量为 6.2×106 g/mol。这种三维结构具有良好的热稳定性，在 220°C 以上会发生热分解。与使用平行线性聚合物的相关钻井液相比，使用微球形聚合物配制的钻井液在中低温（4-65°C）和中高温（40-240°C）范围内具有更好的流变稳定性。对静电位（ESP）和前沿分子轨道（FMO）的分析表明，封闭球域内的活性基团主要包括羰基 C = O 和酰胺 -CO(NH2)。此外，这些活性基团在分子外部区域呈现分层分布。对回转半径（Rg）和径向分布函数 g(r) 的分析进一步验证了微球聚合物的核壳结构及其耐温稳定性。此外，还提出了一种新的自洽结构补偿模型，以合理解释微球聚合物在钻井液中的结构-活性关系。计算结果与实验结果非常吻合。这项开创性工作将为新型功能添加剂的合成和定制高性能钻井液的配制提供有价值的信息。
{"title":"Experimental Investigation and Computational Insights of Enhanced Rheological Stability of Water-Based Drilling Fluids by Microspherical Polymers","authors":"Lin Xu, Jiamin Shen, Mingbiao Xu, Shuqi Wu, Xiaotang Wang, Yu Bao, Meilan Huang, Chunyan Yu, Yu Ding","doi":"10.2118/219469-pa","DOIUrl":"https://doi.org/10.2118/219469-pa","url":null,"abstract":"\u0000 3D bulk polymer, as an alternative to linear polymer, has exhibited large potential in formulating high-performance water-based drilling fluids. Understanding the mechanism behind the enhanced rheological stability of drilling fluids by microspherical polymers is critical for designing and developing new high-performance drilling fluids. In this work, we conducted a pioneering investigation that integrated experimental techniques with computational modeling, to explore the enhancement mechanism involved in the targeted drilling fluids. Inverse emulsion polymerization experiments were first carried out to fabricate the microspherical polymer acrylic acid (AA), acrylamide (AM), and 2-acryloylamino-2-methyl-1-propanesulfonic acid [P(AA-AM-AMPS)], and then physicochemical properties of microspherical polymer were characterized. Subsequently, the performance of drilling fluids with microspherical polymer as an additive was systematically evaluated. Finally, molecular simulations were used to investigate the characteristics of chemical active sites, molecular conformation, and structural variation at various temperatures. The results showed that the final microspherical polymer has a core-shell structure, with an average size of 198.3 nm and a molecular weight of 6.2×106 g/mol. The 3D structure exhibits good thermal stability, and thermal decomposition occurs above 220°C. The drilling fluids formulated with the microspherical polymer showed better rheological stability in the medium-low (4–65°C) and medium-ultrahigh (40–240°C) temperature ranges, compared with the relevant drilling fluids with the parallel linear polymer. Analyses on electrostatic potentials (ESPs) and frontier molecular orbital (FMO) revealed that active groups within the confined sphere domain mainly include carbonyl C = O and amide -CO(NH2). Additionally, these active groups exhibit a hierarchical distribution in the outer molecular region. Analyses on the radius of gyration (Rg) and the radial distribution function g(r) further validated the core-shell structure of microspherical polymer and its temperature-resistant stability. Moreover, a new self-consistent structural compensation model was proposed to rationalize the structure-activity relationship of microspherical polymer in drilling fluids. The computational results align well with the experimental findings. This pioneering work will provide valuable information for both the synthesis of new functional additives and the formulation of tailored-performance drilling fluids.","PeriodicalId":22252,"journal":{"name":"SPE Journal","volume":null,"pages":null},"PeriodicalIF":3.6,"publicationDate":"2024-03-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140278843","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
This study investigates the influences of wettability and stepdown pressure on pressure-driven bubble nucleation within a gas-supersaturated oil-water system. Two gases—carbon dioxide (CO2), which is highly soluble in water, and methane (CH4), which is sparingly soluble in water—were used individually for the bubble nucleation experiments. Equal heights of oil (n-decane) and water, in a wettability-controlled glass vial placed in a saturation cell, were saturated with either of the gases at 6000-mbar pressure, followed by applying a stepdown pressure of either 6000 mbar, 500 mbar, or 100 mbar to start the bubble nucleation process. The average bubble nucleation pressures for CO2 and CH4 gases on a hydrophobic vial surface with 500-mbar stepdown pressure were 4333 ± 289 mbar and 3833 ± 289 mbar, respectively. It is important to note that the bubble nucleation took place exclusively on the portion of the solid surface submerged in water. However, bubble nucleation did not take place with 100-mbar stepdown pressure for either gas in the hydrophobic vial despite the pressure being brought down to atmospheric pressure. As expected, bubble nucleation did not take place in the hydrophilic vial for the gases despite the pressure being brought down to atmospheric pressure from the saturation pressure, regardless of the stepdown pressure. In addition, bubble nucleation did not take place in CO2-supersaturated water in the oil-wetted hydrophilic and hydrophobic vials, even at maximum supersaturation.
{"title":"Effects of Stepdown Pressure and Wettability on Bubble Nucleation in Gas-Supersaturated Oil-Water Systems","authors":"Sushobhan Pradhan, P. Bikkina","doi":"10.2118/219740-pa","DOIUrl":"https://doi.org/10.2118/219740-pa","url":null,"abstract":"\u0000 This study investigates the influences of wettability and stepdown pressure on pressure-driven bubble nucleation within a gas-supersaturated oil-water system. Two gases—carbon dioxide (CO2), which is highly soluble in water, and methane (CH4), which is sparingly soluble in water—were used individually for the bubble nucleation experiments. Equal heights of oil (n-decane) and water, in a wettability-controlled glass vial placed in a saturation cell, were saturated with either of the gases at 6000-mbar pressure, followed by applying a stepdown pressure of either 6000 mbar, 500 mbar, or 100 mbar to start the bubble nucleation process. The average bubble nucleation pressures for CO2 and CH4 gases on a hydrophobic vial surface with 500-mbar stepdown pressure were 4333 ± 289 mbar and 3833 ± 289 mbar, respectively. It is important to note that the bubble nucleation took place exclusively on the portion of the solid surface submerged in water. However, bubble nucleation did not take place with 100-mbar stepdown pressure for either gas in the hydrophobic vial despite the pressure being brought down to atmospheric pressure. As expected, bubble nucleation did not take place in the hydrophilic vial for the gases despite the pressure being brought down to atmospheric pressure from the saturation pressure, regardless of the stepdown pressure. In addition, bubble nucleation did not take place in CO2-supersaturated water in the oil-wetted hydrophilic and hydrophobic vials, even at maximum supersaturation.","PeriodicalId":22252,"journal":{"name":"SPE Journal","volume":null,"pages":null},"PeriodicalIF":3.6,"publicationDate":"2024-03-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140400292","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Successful large-scale compositional reservoir simulations require robust and efficient phase-split calculations. In recent years, there has been progress in three-phase-split calculations. However, there may be convergence issues when the number of equilibrium phases increases to four. Part of the problem is from the poor initial guesses. In phase-split computations, the results from stability provide good initial guesses. Successive substitution (SS) is a key step in phase-split calculations. The method, if efficient, can provide good initial guesses for the final step, the Newton method that has a rapid rate of convergence. In this contribution, we present a robust algorithm with high efficiency and robustness in phase-split calculations in two, three, and four phases. We find that a key step is the SS. The convergence may even be very slow away from the critical point and phase boundaries. A modified SS is used which may reduce the number of iterations many times. In the course of this investigation, we observe some regions often inside the phase envelopes (far from the phase boundary or critical points) with a very high number of SS iterations. The adoption of the improved SS iterations leads to a significant speedup of the multiphase-split computations. In some mixtures, the average reduction is more than 70%.
成功的大规模成分储层模拟需要稳健高效的分相计算。近年来，三相分裂计算取得了进展。然而，当平衡相的数量增加到四个时，可能会出现收敛问题。问题的部分原因是初始猜测不准确。在分相计算中，稳定性结果提供了良好的初始猜测。连续置换（SS）是相分裂计算中的一个关键步骤。该方法如果高效，就能为最后一步--收敛速度极快的牛顿法--提供良好的初始猜测。在本文中，我们提出了一种在两相、三相和四相分相计算中具有高效率和鲁棒性的鲁棒算法。我们发现，关键步骤是 SS。在远离临界点和相边界的地方，收敛速度甚至会非常慢。我们使用了一种改进的 SS，它可以将迭代次数减少很多倍。在这一研究过程中，我们观察到一些区域往往位于相位包络线内（远离相位边界或临界点），迭代次数非常多。采用改进的 SS 迭代方法后，多相分离计算速度显著加快。在某些混合物中，平均降低了 70% 以上。
{"title":"Robust Multiphase-Split Calculations Based on Improved Successive Substitution Schemes","authors":"M. Jex, J. Mikyška, A. Firoozabadi","doi":"10.2118/219490-pa","DOIUrl":"https://doi.org/10.2118/219490-pa","url":null,"abstract":"\u0000 Successful large-scale compositional reservoir simulations require robust and efficient phase-split calculations. In recent years, there has been progress in three-phase-split calculations. However, there may be convergence issues when the number of equilibrium phases increases to four. Part of the problem is from the poor initial guesses. In phase-split computations, the results from stability provide good initial guesses. Successive substitution (SS) is a key step in phase-split calculations. The method, if efficient, can provide good initial guesses for the final step, the Newton method that has a rapid rate of convergence. In this contribution, we present a robust algorithm with high efficiency and robustness in phase-split calculations in two, three, and four phases. We find that a key step is the SS. The convergence may even be very slow away from the critical point and phase boundaries. A modified SS is used which may reduce the number of iterations many times. In the course of this investigation, we observe some regions often inside the phase envelopes (far from the phase boundary or critical points) with a very high number of SS iterations. The adoption of the improved SS iterations leads to a significant speedup of the multiphase-split computations. In some mixtures, the average reduction is more than 70%.","PeriodicalId":22252,"journal":{"name":"SPE Journal","volume":null,"pages":null},"PeriodicalIF":3.6,"publicationDate":"2024-03-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140400739","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Wei Xiong, Lienan Zhang, Yu-Long Zhao, Shao-Mu Wen, Kai Bao, O. Møyner, Knut-Andreas Lie
We present a new algorithm based on automatic differentiation that enables precise computation of the derivatives of the Z-factor, facilitating the utilization of Newton’s method or coupling with a robust flow solver. Leveraging a free open-source code [MATLAB Reservoir Simulation Toolbox (MRST)], we develop an electrolyte cubic plus association (e-CPA) equation of state (EoS) model to accurately represent the injection of carbon dioxide (CO2) in brine. By integrating flow and thermodynamics, we construct an advanced compositional simulator using MRST’s object-oriented, automatic differentiation framework and the newly developed e-CPA EoS model. This simulator offers flexibility through both overall-composition and natural-variable formulations, achieved by selecting different primary variables. The Péneloux volume translation technique is employed to modify the EoS model’s volume, ensuring accurate density calculation for the mixture. Additionally, we introduce a viscosity model, e-CPA-FV, which accurately predicts the viscosity of carbon capture and storage (CCS) fluids, surpassing the accuracy of the traditional Lohrenz-Bray-Clark (LBC) model. Our simulator demonstrates superior performance in predicting CO2-brine systems compared with the standard formulation based on the Peng-Robinson (PR) EoS and can handle brine with various salts. The self-contained source code necessary to reproduce all examples is available on the open-access Zenodo digital repository (doi: 10.5281/zenodo.10691505).
我们提出了一种基于自动微分的新算法，该算法能够精确计算 Z 因子的导数，便于使用牛顿法或与稳健的流动求解器耦合。利用免费的开放源代码[MATLAB 储层模拟工具箱 (MRST)]，我们开发了一种电解质立方加关联（e-CPA）状态方程（EoS）模型，以准确表示盐水中二氧化碳（CO2）的注入。通过整合流动和热力学，我们利用 MRST 面向对象的自动微分框架和新开发的 e-CPA EoS 模型，构建了一个先进的成分模拟器。通过选择不同的主变量，该模拟器可以灵活地使用整体构成和自然变量公式。我们采用贝内卢体积平移技术来修改 EoS 模型的体积，从而确保混合物密度计算的准确性。此外，我们还引入了粘度模型 e-CPA-FV，该模型可准确预测碳捕集与封存（CCS）流体的粘度，其准确性超过了传统的洛伦兹-布雷-克拉克（LBC）模型。与基于彭-罗宾逊（PR）EoS 的标准公式相比，我们的模拟器在预测 CO2-盐水系统方面表现出卓越的性能，并能处理含有各种盐分的盐水。重现所有示例所需的独立源代码可从开放式 Zenodo 数字资源库（doi: 10.5281/zenodo.10691505）获取。
{"title":"Compositional Simulation for Carbon Storage in Porous Media Using an Electrolyte Association Equation of State","authors":"Wei Xiong, Lienan Zhang, Yu-Long Zhao, Shao-Mu Wen, Kai Bao, O. Møyner, Knut-Andreas Lie","doi":"10.2118/219734-pa","DOIUrl":"https://doi.org/10.2118/219734-pa","url":null,"abstract":"\u0000 We present a new algorithm based on automatic differentiation that enables precise computation of the derivatives of the Z-factor, facilitating the utilization of Newton’s method or coupling with a robust flow solver. Leveraging a free open-source code [MATLAB Reservoir Simulation Toolbox (MRST)], we develop an electrolyte cubic plus association (e-CPA) equation of state (EoS) model to accurately represent the injection of carbon dioxide (CO2) in brine. By integrating flow and thermodynamics, we construct an advanced compositional simulator using MRST’s object-oriented, automatic differentiation framework and the newly developed e-CPA EoS model. This simulator offers flexibility through both overall-composition and natural-variable formulations, achieved by selecting different primary variables. The Péneloux volume translation technique is employed to modify the EoS model’s volume, ensuring accurate density calculation for the mixture. Additionally, we introduce a viscosity model, e-CPA-FV, which accurately predicts the viscosity of carbon capture and storage (CCS) fluids, surpassing the accuracy of the traditional Lohrenz-Bray-Clark (LBC) model. Our simulator demonstrates superior performance in predicting CO2-brine systems compared with the standard formulation based on the Peng-Robinson (PR) EoS and can handle brine with various salts. The self-contained source code necessary to reproduce all examples is available on the open-access Zenodo digital repository (doi: 10.5281/zenodo.10691505).","PeriodicalId":22252,"journal":{"name":"SPE Journal","volume":null,"pages":null},"PeriodicalIF":3.6,"publicationDate":"2024-03-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140276375","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
The Asmari-Jahrom reservoirs, located in southwest Iran, are recognized as one of the major fractured reservoirs in the world. Understanding the role of fractures in enhancing hydrocarbon flow and permeability is of utmost importance. In this study, petrophysical conventional logs [neutron porosity (NPHI), density (RHOB), sonic (DT), and gamma ray (GR)] and advanced image logs [formation microresistivity imaging (FMI)] were used to investigate the reservoir properties. The novelty of this study lies in the implementation of triple porosity on reservoir quality and identification of flow units in Asmari-Jahrom reservoirs using petrophysical and borehole image logs. By quantifying fracture and vuggy porosity and correlating them with velocity deviation log and fracture parameters [fracture aperture (VAH) and fracture density (VDC)], it was demonstrated that fracture porosity is directly related to VAH. High peaks were observed in fracture parameters, particularly in VAH diagrams where the velocity deviation log was negative and low. Total porosity from density logs was found to match secondary porosity from petrophysical logs, validating FMI results. However, FMI log resolution was higher, enabling clearer identification of fracture porosity peaks. The velocity deviation log indicated that the predominant type of porosity in the reservoir was matrix (primary) porosity. However, fracture and vuggy porosity were also observed in certain zones. Based on indirect evidence such as drilling mud loss, porosity type (matrix, fracture, and vuggy), porosity amount, and oil saturation, 18 zones were identified to determine quality zones with appropriate reservoir quality. Asmari-Jahrum reservoirs were found to possess high storage and flow capacity. The presence of multiple fracture types, especially longitudinal fractures, contributed to the development of secondary porosity and enhanced flow unit quality. Despite their complexity, these fractured carbonate reservoirs were analyzed comprehensively through integrated petrophysical and FMI log interpretation, enabling optimized reservoir performance and facilitating hydrocarbon production.
{"title":"Enhancing Reservoir Zonation through Triple Porosity System: A Case Study","authors":"Reza Hashemi, Fatemeh Saberi, Pourya Asoude, Bahman Soleimani","doi":"10.2118/219491-pa","DOIUrl":"https://doi.org/10.2118/219491-pa","url":null,"abstract":"\u0000 The Asmari-Jahrom reservoirs, located in southwest Iran, are recognized as one of the major fractured reservoirs in the world. Understanding the role of fractures in enhancing hydrocarbon flow and permeability is of utmost importance. In this study, petrophysical conventional logs [neutron porosity (NPHI), density (RHOB), sonic (DT), and gamma ray (GR)] and advanced image logs [formation microresistivity imaging (FMI)] were used to investigate the reservoir properties. The novelty of this study lies in the implementation of triple porosity on reservoir quality and identification of flow units in Asmari-Jahrom reservoirs using petrophysical and borehole image logs. By quantifying fracture and vuggy porosity and correlating them with velocity deviation log and fracture parameters [fracture aperture (VAH) and fracture density (VDC)], it was demonstrated that fracture porosity is directly related to VAH. High peaks were observed in fracture parameters, particularly in VAH diagrams where the velocity deviation log was negative and low. Total porosity from density logs was found to match secondary porosity from petrophysical logs, validating FMI results. However, FMI log resolution was higher, enabling clearer identification of fracture porosity peaks. The velocity deviation log indicated that the predominant type of porosity in the reservoir was matrix (primary) porosity. However, fracture and vuggy porosity were also observed in certain zones. Based on indirect evidence such as drilling mud loss, porosity type (matrix, fracture, and vuggy), porosity amount, and oil saturation, 18 zones were identified to determine quality zones with appropriate reservoir quality. Asmari-Jahrum reservoirs were found to possess high storage and flow capacity. The presence of multiple fracture types, especially longitudinal fractures, contributed to the development of secondary porosity and enhanced flow unit quality. Despite their complexity, these fractured carbonate reservoirs were analyzed comprehensively through integrated petrophysical and FMI log interpretation, enabling optimized reservoir performance and facilitating hydrocarbon production.","PeriodicalId":22252,"journal":{"name":"SPE Journal","volume":null,"pages":null},"PeriodicalIF":3.6,"publicationDate":"2024-03-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140268834","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Chao Gao, Duc Le, Nasar Al Qasabi, Majid M. Al Mujaini, David M. Dornier, Lei Zhang, Paul Lee, Manish Vishwanath
The main challenge for the Mukhaizna steamflood field is to allocate steam dynamically throughout the entire field, which consists of more than 3,200 wells, to obtain the most attractive reservoir performance forecast. To address this challenge, Occidental has developed a state-of-the-art closed-loop optimization solution called the Oxy Field Optimizer (OFO). The aim of this study is to enhance the accuracy, robustness, and predictability of the OFO. Recent advances include connection design, simulation stability, history-matching workflow, model predictability (blind test), and the optimizer. To improve the proxy simulator, 2D connections between wells were introduced and various strategies to handle convergence issues were implemented. The history-matching workflow has been enhanced by automating the temperature match, multistep saturation tuning, and relative permeability tuning. The results show that the implementation of gridblock material balance check, well equation check, and Not a Number (NaN) value check after line search solved multiple convergence problems. The automated temperature match process is five times faster compared with the manual process, and the automated relative permeability tuning decreased average oil mismatch by 55%. The optimizer now utilizes a parallel implementation of a novel ensemble-based optimization scheme (EnOpt) algorithm, which is twice as fast as the original implementation. These proven advances make OFO an essential tool for obtaining optimal steam allocations.
{"title":"Enhancing the Accuracy and Predictability of the Oxy Field Optimizer for Dynamic Steam Allocation in the Mukhaizna Steamflood Field","authors":"Chao Gao, Duc Le, Nasar Al Qasabi, Majid M. Al Mujaini, David M. Dornier, Lei Zhang, Paul Lee, Manish Vishwanath","doi":"10.2118/219487-pa","DOIUrl":"https://doi.org/10.2118/219487-pa","url":null,"abstract":"\u0000 The main challenge for the Mukhaizna steamflood field is to allocate steam dynamically throughout the entire field, which consists of more than 3,200 wells, to obtain the most attractive reservoir performance forecast. To address this challenge, Occidental has developed a state-of-the-art closed-loop optimization solution called the Oxy Field Optimizer (OFO). The aim of this study is to enhance the accuracy, robustness, and predictability of the OFO. Recent advances include connection design, simulation stability, history-matching workflow, model predictability (blind test), and the optimizer. To improve the proxy simulator, 2D connections between wells were introduced and various strategies to handle convergence issues were implemented. The history-matching workflow has been enhanced by automating the temperature match, multistep saturation tuning, and relative permeability tuning. The results show that the implementation of gridblock material balance check, well equation check, and Not a Number (NaN) value check after line search solved multiple convergence problems. The automated temperature match process is five times faster compared with the manual process, and the automated relative permeability tuning decreased average oil mismatch by 55%. The optimizer now utilizes a parallel implementation of a novel ensemble-based optimization scheme (EnOpt) algorithm, which is twice as fast as the original implementation. These proven advances make OFO an essential tool for obtaining optimal steam allocations.","PeriodicalId":22252,"journal":{"name":"SPE Journal","volume":null,"pages":null},"PeriodicalIF":3.6,"publicationDate":"2024-03-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140269461","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Broadband dielectric dispersion measurements are attractive options for the assessment of water-filled porosity. Dielectric permittivity is influenced by salinity as well as other rock/fluid properties. However, the effect of salinity on Maxwell-Wagner polarization (i.e., interfacial polarization) and dielectric permittivity in rock samples with complex pore structures requires further investigation. The objectives of this work are (a) to perform frequency-domain dielectric permittivity numerical simulations on 3D pore-scale rock samples at different salt concentration levels, (b) to quantify the effect of salinity on dielectric permittivity and interfacial polarization in the frequency range between 20 MHz and 5 GHz, and (c) to quantify the critical frequency (i.e., the frequency at which the relative permittivity becomes frequency-independent). We first perform pore-scale frequency domain dielectric permittivity simulations in fully water-saturated carbonate samples with complex pore structures to obtain the complex dielectric permittivity in the frequency range of 0.01–5 GHz and at different salinity levels. Next, we numerically create partially water/hydrocarbon-saturated water-wet samples and perform simulations at different salinity and water saturation levels to investigate the combined effect of salinity and water saturation on dielectric permittivity. Finally, we investigate how reliable conventional mixing models, such as the complex refractive index model (CRIM) and Hanai-Bruggeman (HB), are in the assessment of water saturation at different salinity levels. We used 3D pore-scale rock samples with complex pore structures from Austin Chalk, Estaillades Limestone, and Happy Spraberry formations. The increase in salinity from 2 to 50 parts per thousand (PPT) resulted in the relative permittivity to increase by 18% at 20 MHz. Similarly, an increase in salinity from 2 PPT to 50 PPT resulted in electrical conductivity to increase by 15 times at 20 MHz. However, at 5 GHz, the difference between the relative permittivity of the samples at different salinities was negligible. We demonstrated that the critical frequency was above 1 GHz. Thus, if complex dielectric permittivity at 1 GHz is being used, an accurate salinity assumption is required in the interpretation of conventional dielectric mixture models in carbonate formations. Finally, we observed 52% and 42% average relative errors in water saturation quantification when applying CRIM and HB models at all the frequencies of interest, respectively. The results also indicated that conventional models should not be used in the presence of uncertainty in salinity at lower frequencies. The results of this work quantified the frequency at which the water-filled pore volume rather than the Maxwell-Wagner polarization controls the relative permittivity of rock samples saturated with a wide range of brine salinity. Moreover, the results demonstrated that the relative permittivity of the rock sa
{"title":"The Effect of Salt Concentration on Dielectric Permittivity and Interfacial Polarization in Carbonate Rocks with Complex Pore Structure","authors":"Zulkuf Azizoglu, Z. Heidari","doi":"10.2118/210315-pa","DOIUrl":"https://doi.org/10.2118/210315-pa","url":null,"abstract":"\u0000 Broadband dielectric dispersion measurements are attractive options for the assessment of water-filled porosity. Dielectric permittivity is influenced by salinity as well as other rock/fluid properties. However, the effect of salinity on Maxwell-Wagner polarization (i.e., interfacial polarization) and dielectric permittivity in rock samples with complex pore structures requires further investigation. The objectives of this work are (a) to perform frequency-domain dielectric permittivity numerical simulations on 3D pore-scale rock samples at different salt concentration levels, (b) to quantify the effect of salinity on dielectric permittivity and interfacial polarization in the frequency range between 20 MHz and 5 GHz, and (c) to quantify the critical frequency (i.e., the frequency at which the relative permittivity becomes frequency-independent).\u0000 We first perform pore-scale frequency domain dielectric permittivity simulations in fully water-saturated carbonate samples with complex pore structures to obtain the complex dielectric permittivity in the frequency range of 0.01–5 GHz and at different salinity levels. Next, we numerically create partially water/hydrocarbon-saturated water-wet samples and perform simulations at different salinity and water saturation levels to investigate the combined effect of salinity and water saturation on dielectric permittivity. Finally, we investigate how reliable conventional mixing models, such as the complex refractive index model (CRIM) and Hanai-Bruggeman (HB), are in the assessment of water saturation at different salinity levels.\u0000 We used 3D pore-scale rock samples with complex pore structures from Austin Chalk, Estaillades Limestone, and Happy Spraberry formations. The increase in salinity from 2 to 50 parts per thousand (PPT) resulted in the relative permittivity to increase by 18% at 20 MHz. Similarly, an increase in salinity from 2 PPT to 50 PPT resulted in electrical conductivity to increase by 15 times at 20 MHz. However, at 5 GHz, the difference between the relative permittivity of the samples at different salinities was negligible. We demonstrated that the critical frequency was above 1 GHz. Thus, if complex dielectric permittivity at 1 GHz is being used, an accurate salinity assumption is required in the interpretation of conventional dielectric mixture models in carbonate formations. Finally, we observed 52% and 42% average relative errors in water saturation quantification when applying CRIM and HB models at all the frequencies of interest, respectively. The results also indicated that conventional models should not be used in the presence of uncertainty in salinity at lower frequencies.\u0000 The results of this work quantified the frequency at which the water-filled pore volume rather than the Maxwell-Wagner polarization controls the relative permittivity of rock samples saturated with a wide range of brine salinity. Moreover, the results demonstrated that the relative permittivity of the rock sa","PeriodicalId":22252,"journal":{"name":"SPE Journal","volume":null,"pages":null},"PeriodicalIF":3.6,"publicationDate":"2024-03-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140275683","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
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