P. Tiwari, P. Chidambaram, A. I. Azahree, Dr. Rabindra Das, P. A. Patil, Zoann Low, P. Chandran, R. Tewari, M. A. Abdul Hamid, M. Yaakub
CO2 sequestration is a process for eternity with a possibility of zero-degree failure. One of the key components of the CO2 Sequestration Project is to have a site-specific, risk-based and adaptive Monitoring, Measurement and Verification (MMV) plan. The storage site has been studied thoroughly and is understood to be inherently safe for CO2 sequestration. However, it is incumbent on operator to manage and minimize storage risks. MMV planning is critical along with geological site selection, transportation and storage process. Geological evaluation study of the storage site suggests the containment capacity of identified large depleted gas reservoirs as well as long term conformance due to thick interval. The fault-seal analysis and reservoir integrity study contemplate long-term security of the CO2 storage. An integrated 3D reservoir dynamic simulation model coupled with geomechanical and geochemical models were performed. This helps in understanding storage capacity, trapping mechanisms, reservoir integrity, plume migration path, and injectivity. To demonstrate that CO2 plume migration can be mapped from the seismic, a 4D Seismic feasibility study was carried out using well and fluid data. Gassmann fluid substitution was performed in carbonate reservoir at well, and seismic response of several combination of fluid saturation scenarios on synthetic gathers were analyzed. The CO2 dispersion study, which incorporate integration of subsurface, geomatic and metocean & environment data along with leakage character information, was carried out to understand the potential leakage pathway along existing wells and faults which enable to design a monitoring plan accordingly. The monitoring of wells & reservoir integrity, overburden integrity will be carried out by Fiber Optic System to be installed in injection wells. Significant difference in seismic amplitude observed at the reservoir top during 4D seismic feasibility study for varying CO2 saturation suggests that monitoring of CO2 plume migration from seismic is possible. CO2 plume front with as low as 25% saturation can be discriminated provided seismic data has high signal noise ratio (SNR). 3D DAS-VSP acquisition modeling results show that a subsurface coverage of approximately 3 km2 per well is achievable. Laboratory injectivity studies and three-way coupled modelling simulations established that three injection wells will be required to achieve the target injection rate. As planned injection wells are field centric and storage site area is large, DAS-VSP find limited coverage to monitor the CO2 plume front. Hence, surface seismic acquisition will be an integral component of full field monitoring and time-lapsed evaluations for integrated MMV planning to monitor CO2 plume migration. The integrated MMV planning is designed to ensure that injected CO2 in the reservoir is intact and safely stored for hundreds of years after injection. Field specific MMV technologies for CO2 plume migration with p
{"title":"Safeguarding CO2 Storage in a Depleted Offshore Gas Field with Adaptive Approach of Monitoring, Measurement and Verification MMV","authors":"P. Tiwari, P. Chidambaram, A. I. Azahree, Dr. Rabindra Das, P. A. Patil, Zoann Low, P. Chandran, R. Tewari, M. A. Abdul Hamid, M. Yaakub","doi":"10.2118/204590-ms","DOIUrl":"https://doi.org/10.2118/204590-ms","url":null,"abstract":"\u0000 CO2 sequestration is a process for eternity with a possibility of zero-degree failure. One of the key components of the CO2 Sequestration Project is to have a site-specific, risk-based and adaptive Monitoring, Measurement and Verification (MMV) plan. The storage site has been studied thoroughly and is understood to be inherently safe for CO2 sequestration. However, it is incumbent on operator to manage and minimize storage risks. MMV planning is critical along with geological site selection, transportation and storage process.\u0000 Geological evaluation study of the storage site suggests the containment capacity of identified large depleted gas reservoirs as well as long term conformance due to thick interval. The fault-seal analysis and reservoir integrity study contemplate long-term security of the CO2 storage. An integrated 3D reservoir dynamic simulation model coupled with geomechanical and geochemical models were performed. This helps in understanding storage capacity, trapping mechanisms, reservoir integrity, plume migration path, and injectivity. To demonstrate that CO2 plume migration can be mapped from the seismic, a 4D Seismic feasibility study was carried out using well and fluid data. Gassmann fluid substitution was performed in carbonate reservoir at well, and seismic response of several combination of fluid saturation scenarios on synthetic gathers were analyzed.\u0000 The CO2 dispersion study, which incorporate integration of subsurface, geomatic and metocean & environment data along with leakage character information, was carried out to understand the potential leakage pathway along existing wells and faults which enable to design a monitoring plan accordingly. The monitoring of wells & reservoir integrity, overburden integrity will be carried out by Fiber Optic System to be installed in injection wells. Significant difference in seismic amplitude observed at the reservoir top during 4D seismic feasibility study for varying CO2 saturation suggests that monitoring of CO2 plume migration from seismic is possible. CO2 plume front with as low as 25% saturation can be discriminated provided seismic data has high signal noise ratio (SNR).\u0000 3D DAS-VSP acquisition modeling results show that a subsurface coverage of approximately 3 km2 per well is achievable. Laboratory injectivity studies and three-way coupled modelling simulations established that three injection wells will be required to achieve the target injection rate. As planned injection wells are field centric and storage site area is large, DAS-VSP find limited coverage to monitor the CO2 plume front. Hence, surface seismic acquisition will be an integral component of full field monitoring and time-lapsed evaluations for integrated MMV planning to monitor CO2 plume migration. The integrated MMV planning is designed to ensure that injected CO2 in the reservoir is intact and safely stored for hundreds of years after injection. Field specific MMV technologies for CO2 plume migration with p","PeriodicalId":11024,"journal":{"name":"Day 4 Wed, December 01, 2021","volume":"35 5 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77961218","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
This paper presented an integrated CO2 injection and sequestration modelling study performed on a depleted carbonate gas reservoir, which has been identified as one of potential CO2 sequestration site candidate in conjunction with nearby high CO2 gas fields development and commercialization effort to monetize the fields. 3D compositional modelling, geomechanical and geochemical assessment were conducted to strategize optimum subsurface CO2 injection and sequestration development concept for project execution. Available history matched black oil simulation model was converted into compositional model. Sensitivity analyses on optimum injection rate, number and types of injectors, solubility of CO2 in water, injection locations and impact of hysteresis to plume distribution were investigated. Different types of CO2 trapping mechanisms including hydrodynamic, residual/capillary, solubility and mineral trapping were studied in detailed. Coupled modelling study was performed on base case scenario to assess geomechnical and geochemical risks associated with CO2 injection and sequestration process before-, during- and post- CO2 injection operation to provide assurance for a safe and long-term CO2 sequestration in the field. Available history matched black oil model was successfully converted into compositional model, in which CO2 is treated and can be tracked as a separate component in the reservoir throughout the production and injection processes. Integrating all the results obtained from sensitivities analyses, the proposed optimum subsurface CO2 injection and sequestration development concept for the field is to inject up to 400 MMscf/D of CO2 rate via four injectors. CO2 injection rate is forecasted to sustain more than 3 years from injection start date before declining with time. In terms of CO2 storage capacity, constraining injection pressure up to initial reservoir pressure, maximum CO2 storage capacity is estimated ~65 Million tonnes. Nevertheless, considering maximum allowable CO2 injection pressure estimated from coupled modelling study and operational safety factor, the field is capable to accommodate a total of ~77 Million tonnes of CO2, whereby 73% of total CO2 injected will exists in mobile phase and trapped underneath caprock whilst the other 24% and 3% will be trapped as residual/capillary and dissolved in water respectively. Changes of minerals and porosity were observed from 3D geochemical modelling, however, changes are negligible due to the fact that geochemical reaction is a very slow process. This paper highlights and shares simulation results obtained from CO2 injection and sequestration studies performed on 3D compositional model to generate an optimum subsurface CO2 injection and sequestration development concept for project execution in future. Integration with geomechanical and geochemical modelling studies are crucial to assess site's capability to accommodate CO2 within the geological formation and provide assurance fo
{"title":"Integrated CO2 Modeling Studies to Assess CO2 Sequestration Prospect in a Depleted Carbonate Gas Reservoir, Malaysia","authors":"M. A. A Jalil, Sharidah M Amin, S. S. M Ali","doi":"10.2118/204810-ms","DOIUrl":"https://doi.org/10.2118/204810-ms","url":null,"abstract":"\u0000 This paper presented an integrated CO2 injection and sequestration modelling study performed on a depleted carbonate gas reservoir, which has been identified as one of potential CO2 sequestration site candidate in conjunction with nearby high CO2 gas fields development and commercialization effort to monetize the fields. 3D compositional modelling, geomechanical and geochemical assessment were conducted to strategize optimum subsurface CO2 injection and sequestration development concept for project execution.\u0000 Available history matched black oil simulation model was converted into compositional model. Sensitivity analyses on optimum injection rate, number and types of injectors, solubility of CO2 in water, injection locations and impact of hysteresis to plume distribution were investigated. Different types of CO2 trapping mechanisms including hydrodynamic, residual/capillary, solubility and mineral trapping were studied in detailed. Coupled modelling study was performed on base case scenario to assess geomechnical and geochemical risks associated with CO2 injection and sequestration process before-, during- and post- CO2 injection operation to provide assurance for a safe and long-term CO2 sequestration in the field.\u0000 Available history matched black oil model was successfully converted into compositional model, in which CO2 is treated and can be tracked as a separate component in the reservoir throughout the production and injection processes. Integrating all the results obtained from sensitivities analyses, the proposed optimum subsurface CO2 injection and sequestration development concept for the field is to inject up to 400 MMscf/D of CO2 rate via four injectors. CO2 injection rate is forecasted to sustain more than 3 years from injection start date before declining with time. In terms of CO2 storage capacity, constraining injection pressure up to initial reservoir pressure, maximum CO2 storage capacity is estimated ~65 Million tonnes. Nevertheless, considering maximum allowable CO2 injection pressure estimated from coupled modelling study and operational safety factor, the field is capable to accommodate a total of ~77 Million tonnes of CO2, whereby 73% of total CO2 injected will exists in mobile phase and trapped underneath caprock whilst the other 24% and 3% will be trapped as residual/capillary and dissolved in water respectively. Changes of minerals and porosity were observed from 3D geochemical modelling, however, changes are negligible due to the fact that geochemical reaction is a very slow process.\u0000 This paper highlights and shares simulation results obtained from CO2 injection and sequestration studies performed on 3D compositional model to generate an optimum subsurface CO2 injection and sequestration development concept for project execution in future. Integration with geomechanical and geochemical modelling studies are crucial to assess site's capability to accommodate CO2 within the geological formation and provide assurance fo","PeriodicalId":11024,"journal":{"name":"Day 4 Wed, December 01, 2021","volume":"34 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78699692","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
S. Batarseh, D. P. San Roman Alerigi, Abdullah Al Harith, Wisam J. Assiri
This study evaluates physical and chemical changes induced by high thermal gradients on the formation and their impact to the stability. The heat sources that effect the formation’s stability are varied, including drilling (due to drilling bit friction), perforation, electromagnetic heating (laser or microwave), and thermal recovery or stimulation (steam, resistive heating, combustion, microwave, etc.). This study uses an integrated approach to characterize rock heterogeneity and mapping heat propagation from different heat sources. The information obtained from the study is vital to accurately design and enhance well completion and stimulation This is an integrated analysis approach combining different advanced characterization and visualization techniques to map heat propagation in the formation. Advanced statistical analysis is also used to determine the key parameters and build fundamental prediction algorithms. Characterization on the samples was performed before, during, and after the exposure to thermal sources; it comprised thin-section, high speed infrared thermography (IR), differential thermal analysis and thermogravimetric analyzer (DTA/TGA), scanning electron microscope (SEM), X-ray diffraction (XRD), X-ray fluorescence (XRF), uniaxial stress, and autoscan (provide hardness, composition, velocity, and spectral absorption). The results are integrated, and machine learning is used to derive a predictive algorithm of heat propagation and mapping in the formation with reference to the key formation variables and heterogeneity distribution. Rock heterogeneity affects the rate and patterns of heat propagation into the formation. Within the rock sample, minerals, laminations, and cementations lead to a heterogeneous, and sometimes anisotropic, distribution of thermal properties (thermal conductivity, heat capacity, diffusivity, etc.). These properties are also affected by the rock structure (porosity, micro-cracks, and fractures) and saturation distribution. The results showed the impact of heat on the mechanical properties of the rocks are due to clays dehydration, mineral dissociations, and micro cracks. High speed thermal imaging provides a unique visualization of heat propagation in heterogeneous rocks. Statistical analysis identified key parameters and their impact on thermal propagation; the output was used to build a machine learning algorithm to predict heat distributions in core samples and near-wellbore. Characterizing rock properties and understanding how heterogeneity modifies heat propagation in rocks enables the design of optimal completion and stimulation strategies. This paper discusses how advanced characterization and analysis, combined with novel algorithms, can improve this understanding, and unleash innovation and optimization. The data and information gathered are critical to develop numerical models for field-scale applications.
{"title":"Thermal Effect on Formation Stability Due to Heterogeneity","authors":"S. Batarseh, D. P. San Roman Alerigi, Abdullah Al Harith, Wisam J. Assiri","doi":"10.2118/204663-ms","DOIUrl":"https://doi.org/10.2118/204663-ms","url":null,"abstract":"\u0000 This study evaluates physical and chemical changes induced by high thermal gradients on the formation and their impact to the stability. The heat sources that effect the formation’s stability are varied, including drilling (due to drilling bit friction), perforation, electromagnetic heating (laser or microwave), and thermal recovery or stimulation (steam, resistive heating, combustion, microwave, etc.). This study uses an integrated approach to characterize rock heterogeneity and mapping heat propagation from different heat sources. The information obtained from the study is vital to accurately design and enhance well completion and stimulation\u0000 This is an integrated analysis approach combining different advanced characterization and visualization techniques to map heat propagation in the formation. Advanced statistical analysis is also used to determine the key parameters and build fundamental prediction algorithms. Characterization on the samples was performed before, during, and after the exposure to thermal sources; it comprised thin-section, high speed infrared thermography (IR), differential thermal analysis and thermogravimetric analyzer (DTA/TGA), scanning electron microscope (SEM), X-ray diffraction (XRD), X-ray fluorescence (XRF), uniaxial stress, and autoscan (provide hardness, composition, velocity, and spectral absorption). The results are integrated, and machine learning is used to derive a predictive algorithm of heat propagation and mapping in the formation with reference to the key formation variables and heterogeneity distribution.\u0000 Rock heterogeneity affects the rate and patterns of heat propagation into the formation. Within the rock sample, minerals, laminations, and cementations lead to a heterogeneous, and sometimes anisotropic, distribution of thermal properties (thermal conductivity, heat capacity, diffusivity, etc.). These properties are also affected by the rock structure (porosity, micro-cracks, and fractures) and saturation distribution. The results showed the impact of heat on the mechanical properties of the rocks are due to clays dehydration, mineral dissociations, and micro cracks. High speed thermal imaging provides a unique visualization of heat propagation in heterogeneous rocks. Statistical analysis identified key parameters and their impact on thermal propagation; the output was used to build a machine learning algorithm to predict heat distributions in core samples and near-wellbore.\u0000 Characterizing rock properties and understanding how heterogeneity modifies heat propagation in rocks enables the design of optimal completion and stimulation strategies. This paper discusses how advanced characterization and analysis, combined with novel algorithms, can improve this understanding, and unleash innovation and optimization. The data and information gathered are critical to develop numerical models for field-scale applications.","PeriodicalId":11024,"journal":{"name":"Day 4 Wed, December 01, 2021","volume":"194 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89755495","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Carlos Alejandro Terrones Brand, Miguel Alejandro Basso Mora, Rajeswary Kandasamy, Sergio Comarin, Felipe Rene Bustos Guevara, Beatriz Vega, Susana Pasaran
Mexico has set challenging oil and gas production to meet worldwide demand. In order to deliver promised oil production outputs in this challenging environment, the operator came up with efficient partnerships with key service providers to leverage resources and technical know-how whilst encouraging knowledge transfer and drilling project cost reduction. By working with various service companies, the operator creates a competitive environment where each strives to outperform the other. One such success case is in the "S" field, a heavy oil field producing via steam injection in the South of Mexico. Utilizing a creative design and execution methodology, the "S" project team succeeded to deliver improved project performance over the course of drilling the 14 wells in the campaign. The average well operational time was successfully reduced by 10%, hence maximizing the well construction index to 122 m/day and reducing overall well costs. The main strategy to optimize performance is to re-engineer solutions for profitability such as performing a study to replace OBM by WBM, designing a new wellhead system, collaborating with the rig contractor to reduce flat time activities, redesigning cement properties for losses mitigation, improvement of ROP by merging new technologies and local practices, among others. Complementary to this, the strategy is to prioritize realistic areas of improvement by the development and utilization of a new tool called Best of the Best (BoB), a methodology breaking down all well activities in order to measure its fastest time per well and then aiming to achieve that aggressive goal. Detailed follow up in the field allows to reduce operational times by allowing the wellsite team monitor and suggest new and improved ways of doing a routine task all of which result in lower costs per foot. Utilizing this BoB approach and stringent performance monitoring while drilling (pre-actual-post) activity analysis, allowed superior performance to be achieved. The project reached a 60% improvement on well times from the first well drilled to the best performing well. The best well was drilled in 8.68 days versus a field average of 18 days (217 m/day construction index). This generated 369,000 bbls of earlier oil production, 176 days ahead vs client expectations. Furthermore, in coordination with field staff, lessons learned were captured. But this is not enough since fast and effective communication is required, and the BoB methodology provides the solution to share optimization tricks quickly and effectively between crews, to continue well to well improvement and overall project and field level learning. Improved well delivery results is possible only by aligning the detailed planning and execution follow up in both the wellsite and a remote operations centre which monitored drilling activity in real time from town. This synergy and proactive communication system is also a key factor in the project delivery. This paper will present th
为了满足全球需求，墨西哥的石油和天然气产量具有挑战性。为了在这种充满挑战的环境中提供承诺的石油产量，作业者与主要服务提供商建立了有效的合作伙伴关系，以利用资源和技术诀窍，同时鼓励知识转移和降低钻井项目成本。通过与不同的服务公司合作，运营商创造了一个竞争环境，每个公司都在努力超越对方。“S”油田就是一个成功的例子，该油田位于墨西哥南部，是一个通过蒸汽注入生产的稠油油田。利用创新的设计和执行方法，“S”项目团队成功地提高了项目绩效，在整个项目中钻了14口井。平均井作业时间成功缩短了10%，从而将井建设指数最大化至122米/天，并降低了总体井成本。优化性能的主要策略是重新设计解决方案以提高盈利能力，例如进行研究以WBM取代OBM，设计新的井口系统，与钻机承包商合作减少平作业时间，重新设计水泥性能以减少损失，通过合并新技术和当地实践来提高ROP等等。与此相辅相成的是，该策略是通过开发和利用一种名为Best of the Best (BoB)的新工具来优先考虑实际的改进领域，这种方法可以分解所有井的活动，以测量每口井的最快时间，然后旨在实现这一激进的目标。现场的详细跟踪可以减少作业时间，让井场团队监控并建议新的和改进的方法来完成常规任务，所有这些都可以降低每英尺的成本。利用这种BoB方法和严格的钻井活动分析时的性能监测，可以实现卓越的性能。从第一口井到性能最佳的井，该项目的钻井时间缩短了60%。最好的一口井的钻井时间为8.68天，而油田的平均钻井时间为18天(施工指数为217米/天)。这使得原油产量提前了36.9万桶，比客户预期提前了176天。此外，与外地工作人员协调，吸取了经验教训。但这还不够，因为需要快速有效的沟通，BoB方法提供了解决方案，可以在工作人员之间快速有效地分享优化技巧，继续进行井与井之间的改进，以及整个项目和现场层面的学习。只有在井场和远程操作中心进行详细的规划和后续执行，并从城镇实时监控钻井活动，才能改善井的交付效果。这种协同和主动沟通系统也是项目交付的关键因素。本文将介绍在墨西哥首次应用“Best of Best”(BoB)方法的结果。这一成功的应用强化了这样一种理念:通过结合再工程实践，开发出更具创造性的井设计，并进行严格的性能监测;任何现场性能都可以得到改善，从而获得出色的结果。
{"title":"Leveraging a New Well Delivery Methodology for Stellar Drilling Results Steam Injection Project Case Study","authors":"Carlos Alejandro Terrones Brand, Miguel Alejandro Basso Mora, Rajeswary Kandasamy, Sergio Comarin, Felipe Rene Bustos Guevara, Beatriz Vega, Susana Pasaran","doi":"10.2118/204618-ms","DOIUrl":"https://doi.org/10.2118/204618-ms","url":null,"abstract":"\u0000 Mexico has set challenging oil and gas production to meet worldwide demand. In order to deliver promised oil production outputs in this challenging environment, the operator came up with efficient partnerships with key service providers to leverage resources and technical know-how whilst encouraging knowledge transfer and drilling project cost reduction. By working with various service companies, the operator creates a competitive environment where each strives to outperform the other. One such success case is in the \"S\" field, a heavy oil field producing via steam injection in the South of Mexico. Utilizing a creative design and execution methodology, the \"S\" project team succeeded to deliver improved project performance over the course of drilling the 14 wells in the campaign. The average well operational time was successfully reduced by 10%, hence maximizing the well construction index to 122 m/day and reducing overall well costs.\u0000 The main strategy to optimize performance is to re-engineer solutions for profitability such as performing a study to replace OBM by WBM, designing a new wellhead system, collaborating with the rig contractor to reduce flat time activities, redesigning cement properties for losses mitigation, improvement of ROP by merging new technologies and local practices, among others. Complementary to this, the strategy is to prioritize realistic areas of improvement by the development and utilization of a new tool called Best of the Best (BoB), a methodology breaking down all well activities in order to measure its fastest time per well and then aiming to achieve that aggressive goal. Detailed follow up in the field allows to reduce operational times by allowing the wellsite team monitor and suggest new and improved ways of doing a routine task all of which result in lower costs per foot. Utilizing this BoB approach and stringent performance monitoring while drilling (pre-actual-post) activity analysis, allowed superior performance to be achieved. The project reached a 60% improvement on well times from the first well drilled to the best performing well. The best well was drilled in 8.68 days versus a field average of 18 days (217 m/day construction index). This generated 369,000 bbls of earlier oil production, 176 days ahead vs client expectations.\u0000 Furthermore, in coordination with field staff, lessons learned were captured. But this is not enough since fast and effective communication is required, and the BoB methodology provides the solution to share optimization tricks quickly and effectively between crews, to continue well to well improvement and overall project and field level learning. Improved well delivery results is possible only by aligning the detailed planning and execution follow up in both the wellsite and a remote operations centre which monitored drilling activity in real time from town. This synergy and proactive communication system is also a key factor in the project delivery.\u0000 This paper will present th","PeriodicalId":11024,"journal":{"name":"Day 4 Wed, December 01, 2021","volume":"81 2","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"91512080","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
J. Almorihil, A. Mouret, I. Hénaut, V. Mirallés, A. AlSofi
Gravity settling represents the main oil-water separation mechanism. Many separation plants rely only on gravity settling with the aid of demulsifiers (direct or reverse breakers) and other chemicals such as water clarifiers if they are required. Yet, other complementary separation methods exist including filtration, flotation, and centrifugation. In terms of results and more specifically with respect to the separated produced-water, the main threshold on its quality is the dispersed oil content. Even with zero discharge and reinjection into hydrocarbon formations, the presence of residual oil in the aqueous phase represents a concern. High oil content results into formation damage and losses in injectivity which necessitates formation stimulations and hence additional operational expenses. In this work, we investigated the effects of different separation techniques on separated water quality. In addition, we studied the impact of enhanced oil recovery (EOR) chemicals on the different separation techniques in terms of efficiency and water quality. Based on the results, we identified potential improvements to the existing separation process. We used synthetic well-characterized emulsions. The emulsions were prepared at the forecast water: oil ratio using dead crude oil and synthetic representative brines with or without the EOR chemicals. To clearly delineate and distinguish the effectiveness of different separation methods, we exacerbated the conditions by preparing very tight emulsions compared with what is observed on site. With that, we investigated three separation techniques: gravity settling, centrifugation, and filtration. First, we used Jar Tests to study gravity settling, then a benchtop centrifuge at two speeds to evaluate centrifugation potential. Finally, for filtration, we tested two options: membrane and deep-bed filtrations. Concerning the water quality, we performed solvent extraction followed by UV analyses to measure the residual oil content as well as light transmission measurements in order to compare the efficiency of different separation methods. The results of analyses suggest that gravity settling was not efficient in removing oil droplets from water. No separation occurred after 20 minutes in every tested condition. However, note that investigated conditions were severe, tighter emulsions are more difficult to separate compared to those currently observed in the actual separation plant. On the other hand, centrifugation significantly improved light transmission through the separated water. Accordingly, we can conclude that the water quality was largely improved by centrifugation even in the presence of EOR chemicals. In terms of filtration, very good water quality was obtained after membrane filtration. However, significant fouling was observed. In the presence of EOR chemicals, filtration lost its effectiveness due to the low interfacial tension with surfactants and water quality became poor. With deep-bed filtration
{"title":"Produced Water Quality: The Effects of Different Separation Methods for Water and Chemical Floods","authors":"J. Almorihil, A. Mouret, I. Hénaut, V. Mirallés, A. AlSofi","doi":"10.2118/204650-ms","DOIUrl":"https://doi.org/10.2118/204650-ms","url":null,"abstract":"\u0000 Gravity settling represents the main oil-water separation mechanism. Many separation plants rely only on gravity settling with the aid of demulsifiers (direct or reverse breakers) and other chemicals such as water clarifiers if they are required. Yet, other complementary separation methods exist including filtration, flotation, and centrifugation. In terms of results and more specifically with respect to the separated produced-water, the main threshold on its quality is the dispersed oil content. Even with zero discharge and reinjection into hydrocarbon formations, the presence of residual oil in the aqueous phase represents a concern. High oil content results into formation damage and losses in injectivity which necessitates formation stimulations and hence additional operational expenses. In this work, we investigated the effects of different separation techniques on separated water quality. In addition, we studied the impact of enhanced oil recovery (EOR) chemicals on the different separation techniques in terms of efficiency and water quality. Based on the results, we identified potential improvements to the existing separation process.\u0000 We used synthetic well-characterized emulsions. The emulsions were prepared at the forecast water: oil ratio using dead crude oil and synthetic representative brines with or without the EOR chemicals. To clearly delineate and distinguish the effectiveness of different separation methods, we exacerbated the conditions by preparing very tight emulsions compared with what is observed on site. With that, we investigated three separation techniques: gravity settling, centrifugation, and filtration. First, we used Jar Tests to study gravity settling, then a benchtop centrifuge at two speeds to evaluate centrifugation potential. Finally, for filtration, we tested two options: membrane and deep-bed filtrations. Concerning the water quality, we performed solvent extraction followed by UV analyses to measure the residual oil content as well as light transmission measurements in order to compare the efficiency of different separation methods.\u0000 The results of analyses suggest that gravity settling was not efficient in removing oil droplets from water. No separation occurred after 20 minutes in every tested condition. However, note that investigated conditions were severe, tighter emulsions are more difficult to separate compared to those currently observed in the actual separation plant. On the other hand, centrifugation significantly improved light transmission through the separated water. Accordingly, we can conclude that the water quality was largely improved by centrifugation even in the presence of EOR chemicals. In terms of filtration, very good water quality was obtained after membrane filtration. However, significant fouling was observed. In the presence of EOR chemicals, filtration lost its effectiveness due to the low interfacial tension with surfactants and water quality became poor. With deep-bed filtration","PeriodicalId":11024,"journal":{"name":"Day 4 Wed, December 01, 2021","volume":"24 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77702809","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
O. Sehsah, Oscar Bautista Sayago, Tom Newman, F. Mounzer
The technology described in this paper has been developed to challenge the shortcomings of the 40+ year old conventional blade stabilizer. The focus of this paper is to compare drilling performance on two lateral well sections against conventional spiral blade stabilizers. The comparison will highlight the noticeable improvement in drilling performance through analysis of relevant drilling parameters. The new design stabilizer, referred to in this paper as Innovative Drillstring Stabilizer (IDS), can be positioned in the drill string as you would typically do with a conventional spiral blade stabilizer or roller reamer. The design, however, is considerably different. The opened profile, placement and contour of the blades are designed to enhance energy transfer and flow along the tool, improving the transportation of cuttings around the tool while minimizing the occurrences of balling up. The orientation and dome shape of the blades is designed to reduce friction and torque, reduce vibration, improve weight transfer and when slide drilling minimizing the occurrence of hanging up and motor stalls. The engineered drillstring stabilizer was deployed in two wells for trial and technology acceptance purpose. An 8" OD innovative drillstring stabilizer was used as part of a steerable motor bottom hole assembly (BHA) in an integrated operations project. An in-depth performance comparison study was conducted by a specialized and independent third party between two identical BHAs. One (BHA-1), however, included conventional spiral blade stabilizers while the other (BHA-2) adopted the innovative drillstring stabilizers. The pioneering design of the IDS in BHA-2 contributed to reducing the overall torque and aiding in better weight transfer and drilling efficiency. It was possible to apply more weight and the energy transfer to the bit, based on mechanical specific energy (MSE) calculations, showed more efficient drilling conditions. As a result, the ROP, both rotating and sliding showed significant improvement with an overall increase of more than 30%. Better stabilization with BHA-2 aided in less vibration and no motor stalls. In addition, while pulling out of hole, lower hook loads were observed due to the enhanced hole cleaning features, improved hole condition and less friction along the string components. When back on surface no indications of balling-up were observed either. Today, drilling related inefficiencies, in the form of low ROP, non-productive time, damages beyond repair or stuck pipe and lost in hole incidents costs the oil and gas industry millions of dollars on an annual basis. The IDS is designed and proved to address such dysfunctions and improve drilling performance and efficiency while simultaneously stimulates a lower MSE drilling environment.
{"title":"Challenging the Status Quo Leads to Enhanced Drilling Performance","authors":"O. Sehsah, Oscar Bautista Sayago, Tom Newman, F. Mounzer","doi":"10.2118/204876-ms","DOIUrl":"https://doi.org/10.2118/204876-ms","url":null,"abstract":"\u0000 The technology described in this paper has been developed to challenge the shortcomings of the 40+ year old conventional blade stabilizer. The focus of this paper is to compare drilling performance on two lateral well sections against conventional spiral blade stabilizers. The comparison will highlight the noticeable improvement in drilling performance through analysis of relevant drilling parameters.\u0000 The new design stabilizer, referred to in this paper as Innovative Drillstring Stabilizer (IDS), can be positioned in the drill string as you would typically do with a conventional spiral blade stabilizer or roller reamer. The design, however, is considerably different. The opened profile, placement and contour of the blades are designed to enhance energy transfer and flow along the tool, improving the transportation of cuttings around the tool while minimizing the occurrences of balling up. The orientation and dome shape of the blades is designed to reduce friction and torque, reduce vibration, improve weight transfer and when slide drilling minimizing the occurrence of hanging up and motor stalls. The engineered drillstring stabilizer was deployed in two wells for trial and technology acceptance purpose. An 8\" OD innovative drillstring stabilizer was used as part of a steerable motor bottom hole assembly (BHA) in an integrated operations project. An in-depth performance comparison study was conducted by a specialized and independent third party between two identical BHAs. One (BHA-1), however, included conventional spiral blade stabilizers while the other (BHA-2) adopted the innovative drillstring stabilizers.\u0000 The pioneering design of the IDS in BHA-2 contributed to reducing the overall torque and aiding in better weight transfer and drilling efficiency. It was possible to apply more weight and the energy transfer to the bit, based on mechanical specific energy (MSE) calculations, showed more efficient drilling conditions. As a result, the ROP, both rotating and sliding showed significant improvement with an overall increase of more than 30%. Better stabilization with BHA-2 aided in less vibration and no motor stalls. In addition, while pulling out of hole, lower hook loads were observed due to the enhanced hole cleaning features, improved hole condition and less friction along the string components. When back on surface no indications of balling-up were observed either.\u0000 Today, drilling related inefficiencies, in the form of low ROP, non-productive time, damages beyond repair or stuck pipe and lost in hole incidents costs the oil and gas industry millions of dollars on an annual basis. The IDS is designed and proved to address such dysfunctions and improve drilling performance and efficiency while simultaneously stimulates a lower MSE drilling environment.","PeriodicalId":11024,"journal":{"name":"Day 4 Wed, December 01, 2021","volume":"2 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77862904","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
S. Aderemi, Husain Ali Al Lawati, Mansura Khalfan Al Rawahy, Hassan Kolivand, Manish Kumar Singh, C. Darous, Francois D. Bouchet
This paper presents an innovative and practical workflow framework implemented in an Oman southern asset. The asset consists of three isolated accumulations or fields or structures that differ in rock and fluid properties. Each structure has multiple stacked members of Gharif and Alkhlata formations. Oil production started in 1986, with more than 60 commingling wells. The accumulations are not only structurally and stratigraphically complicated but also dynamically complex with numerous input uncertainties. It was impossible to assist the history matching process using a modern optimization-based technique due to the structural complexities of the reservoirs and magnitudes of the uncertain parameters. A structured history-matching approach, Stratigraphic Method (SM), was adopted and guided by suitable subsurface physics by adjusting multi-uncertain parameters simultaneously within the uncertainty envelope to mimic the model response. An essential step in this method is the preliminary analysis, which involved integrating various geological and engineering data to understand the reservoir behavior and the physics controlling the reservoir dynamics. The first step in history-matching these models was to adjust the critical water saturation to correct the numerical water production by honoring the capillary-gravity equilibrium and reservoir fluid flow dynamics. The significance of adjusting the critical water saturation before modifying other parameters and the causes of this numerical water production is discussed. Subsequently, the other major uncertain parameters were identified and modified, while a localized adjustment was avoided except in two wells. This local change was guided by a streamlined technique to ensure minimal model modification and retain geological realism. Overall, acceptable model calibration results were achieved. The history-matching framework's novelty is how the numerical water production was controlled above the transition zone and how the reservoir dynamics were understood from the limited data.
{"title":"Full-Field History-Matching of Commingling Stacked Reservoirs: A Case Study of an Oman Southern Asset","authors":"S. Aderemi, Husain Ali Al Lawati, Mansura Khalfan Al Rawahy, Hassan Kolivand, Manish Kumar Singh, C. Darous, Francois D. Bouchet","doi":"10.2118/204575-ms","DOIUrl":"https://doi.org/10.2118/204575-ms","url":null,"abstract":"\u0000 This paper presents an innovative and practical workflow framework implemented in an Oman southern asset. The asset consists of three isolated accumulations or fields or structures that differ in rock and fluid properties. Each structure has multiple stacked members of Gharif and Alkhlata formations. Oil production started in 1986, with more than 60 commingling wells. The accumulations are not only structurally and stratigraphically complicated but also dynamically complex with numerous input uncertainties.\u0000 It was impossible to assist the history matching process using a modern optimization-based technique due to the structural complexities of the reservoirs and magnitudes of the uncertain parameters. A structured history-matching approach, Stratigraphic Method (SM), was adopted and guided by suitable subsurface physics by adjusting multi-uncertain parameters simultaneously within the uncertainty envelope to mimic the model response. An essential step in this method is the preliminary analysis, which involved integrating various geological and engineering data to understand the reservoir behavior and the physics controlling the reservoir dynamics.\u0000 The first step in history-matching these models was to adjust the critical water saturation to correct the numerical water production by honoring the capillary-gravity equilibrium and reservoir fluid flow dynamics. The significance of adjusting the critical water saturation before modifying other parameters and the causes of this numerical water production is discussed. Subsequently, the other major uncertain parameters were identified and modified, while a localized adjustment was avoided except in two wells. This local change was guided by a streamlined technique to ensure minimal model modification and retain geological realism. Overall, acceptable model calibration results were achieved. The history-matching framework's novelty is how the numerical water production was controlled above the transition zone and how the reservoir dynamics were understood from the limited data.","PeriodicalId":11024,"journal":{"name":"Day 4 Wed, December 01, 2021","volume":"298 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"74172721","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Current critical flow rate models fail to accurately predict the liquid loading statuses of shale gas horizontal wells. Therefore, a new critical flow rate model for the whole wellbore of shale gas horizontal wells is established. The results of the new model are compared to those of current models through the field case analysis. The new model is based on the dynamic analysis and energy analysis of the deformed liquid-droplet, which takes into account the liquid flow rate, the liquid-droplet deformation and the energy loss caused by the change of buildup rate. The major axis of the maximum stable deformed liquid-droplet is determined based on the energy balance relation. Meanwhile, the suitable drag coefficient equation and surface tension equation applied to shale gas horizontal wells are chosen. Finally, the critical flow rate equation is established and the maximum critical flow rate of the whole wellbore is chosen as the criterion for liquid loading prediction. The precision of liquid loading prediction of the new model is compared to those of the four current models, including Belfroid's model, modified Li's model, liquid film model and modified Wang's model. Field parameters of 29 shale gas horizontal wells are used for the comparison, including parameters of 18 unloaded wells, 2 near loaded-up wells and 9 loaded-up wells. Field case analysis shows that the total precision of liquid loading prediction of the new model is 93.1%, which is higher compared to those of the current four models. The new model can accurately predict the liquid loading statuses of loaded-up wells and near loaded-up wells, while the prediction precision for unloaded wells is high enough for the field application, which is 88.9%. The new model can be used to effectively estimate the field liquid loading statuses of shale gas horizontal wells and choose drainage gas recovery technologies, which considers both the complex wellbore structure and the variation of flowback liquid flow rate in shale gas horizontal wells. The results of the new model fill the gap in existing studies and have a guiding significance for liquid loading prediction in shale gas horizontal wells.
{"title":"A New Model for Predicting Liquid Loading in Shale Gas Horizontal Wells","authors":"Chao Zhou, Zuqing He, Yashu Chen, Zhifa Wang, A. Mulunjkar, Weishu Zhao","doi":"10.2118/204786-ms","DOIUrl":"https://doi.org/10.2118/204786-ms","url":null,"abstract":"\u0000 Current critical flow rate models fail to accurately predict the liquid loading statuses of shale gas horizontal wells. Therefore, a new critical flow rate model for the whole wellbore of shale gas horizontal wells is established. The results of the new model are compared to those of current models through the field case analysis. The new model is based on the dynamic analysis and energy analysis of the deformed liquid-droplet, which takes into account the liquid flow rate, the liquid-droplet deformation and the energy loss caused by the change of buildup rate. The major axis of the maximum stable deformed liquid-droplet is determined based on the energy balance relation. Meanwhile, the suitable drag coefficient equation and surface tension equation applied to shale gas horizontal wells are chosen. Finally, the critical flow rate equation is established and the maximum critical flow rate of the whole wellbore is chosen as the criterion for liquid loading prediction. The precision of liquid loading prediction of the new model is compared to those of the four current models, including Belfroid's model, modified Li's model, liquid film model and modified Wang's model. Field parameters of 29 shale gas horizontal wells are used for the comparison, including parameters of 18 unloaded wells, 2 near loaded-up wells and 9 loaded-up wells. Field case analysis shows that the total precision of liquid loading prediction of the new model is 93.1%, which is higher compared to those of the current four models. The new model can accurately predict the liquid loading statuses of loaded-up wells and near loaded-up wells, while the prediction precision for unloaded wells is high enough for the field application, which is 88.9%. The new model can be used to effectively estimate the field liquid loading statuses of shale gas horizontal wells and choose drainage gas recovery technologies, which considers both the complex wellbore structure and the variation of flowback liquid flow rate in shale gas horizontal wells. The results of the new model fill the gap in existing studies and have a guiding significance for liquid loading prediction in shale gas horizontal wells.","PeriodicalId":11024,"journal":{"name":"Day 4 Wed, December 01, 2021","volume":"74 4","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"91484185","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Zhixiong Xu, Xue-qing Teng, Ning Li, Hongtao Liu, Caiting Zhao, Bo Zhou, Bo Zou, Wei Yu
The implementation of drilling technique for multiple lithology interbeds and high-pressure anhydrite-salt in the complex Mountain Front area has been completed. The plastic creep of the anhydrite-salt layers, the losses of the low-pressure sandstone, the overflow of the high-pressure salt-water, the narrow mud density window and frequent pipe-stuck occurrence are significant issues, which trigger significant engineering challenges downhole. This study presents the application of the reaming-while-drilling (RWD) technology which has led to minimize the downhole non-productive time (NPT) and achieve successful results. The RWD technique was applied in the composite anhydrite-salt formation of the Kumugeliemu group. Through optimized combination of the RWD tools, bits, reaming blades, and the mechanical analysis the drill string with shock-absorbing design and hydraulics optimization to guarantee the bit and the reamer blades have the proper pressure drop, hydraulic horsepower and flow-field distribution, the RWD was used with the vertical seeking tool drilling technology, resulting in minimum vibration and/or stick-slip, and achieving the expected rate of penetration (ROP) as well as target inclination. It improved the operation efficiency significantly while avoiding the downhole complexities at the same time. Since the geological structure of the offset well Keshen X (no RWD) is similar to Keshen XX (RWD technology was applied), a comparison between the two wells was performed. The reaming meterage in the composite anhydrite-salt layers in Keshen XX was 791 m, spending 15 days, average ROP is 3.73 m/hr. There was no overflew or loss during the drilling. It was smooth, no pipe sticking when checking the reaming effect during the wiper trip and the tripping out. On the other hand, Keshen X spent 29 days with average ROP of 1.35 m/hr to drill the 449 m composite anhydrite-salt rock. Moreover, it was difficult to trip in and trip out during the drilling, and the pipe sticking happened frequently, back-reaming frequently as well. There were losses during both the drilling and the casing running. Due to the unsmooth wellbore, this well increased additional 3 runs of reaming after drilling operation and 4 clean-out runs. 13 days later after the reaming operation, the anhydrite-salt rock creep was checked and found that the hole was still smooth, no pipe sticking existing. Hence, RWD technology has accomplished both goals of preventing the downhole complexities and speeding up drilling. The novel RWD technology can be well illustrated by presenting all the details of its application in salt-base formations.
{"title":"Field Application of Reaming-While-Drilling Technology in the Super Deep Composite Anhydrite-Salt Layers of Kuche Mountain Front in Tarim Oilfield","authors":"Zhixiong Xu, Xue-qing Teng, Ning Li, Hongtao Liu, Caiting Zhao, Bo Zhou, Bo Zou, Wei Yu","doi":"10.2118/204599-ms","DOIUrl":"https://doi.org/10.2118/204599-ms","url":null,"abstract":"\u0000 The implementation of drilling technique for multiple lithology interbeds and high-pressure anhydrite-salt in the complex Mountain Front area has been completed. The plastic creep of the anhydrite-salt layers, the losses of the low-pressure sandstone, the overflow of the high-pressure salt-water, the narrow mud density window and frequent pipe-stuck occurrence are significant issues, which trigger significant engineering challenges downhole. This study presents the application of the reaming-while-drilling (RWD) technology which has led to minimize the downhole non-productive time (NPT) and achieve successful results. The RWD technique was applied in the composite anhydrite-salt formation of the Kumugeliemu group. Through optimized combination of the RWD tools, bits, reaming blades, and the mechanical analysis the drill string with shock-absorbing design and hydraulics optimization to guarantee the bit and the reamer blades have the proper pressure drop, hydraulic horsepower and flow-field distribution, the RWD was used with the vertical seeking tool drilling technology, resulting in minimum vibration and/or stick-slip, and achieving the expected rate of penetration (ROP) as well as target inclination. It improved the operation efficiency significantly while avoiding the downhole complexities at the same time. Since the geological structure of the offset well Keshen X (no RWD) is similar to Keshen XX (RWD technology was applied), a comparison between the two wells was performed. The reaming meterage in the composite anhydrite-salt layers in Keshen XX was 791 m, spending 15 days, average ROP is 3.73 m/hr. There was no overflew or loss during the drilling. It was smooth, no pipe sticking when checking the reaming effect during the wiper trip and the tripping out. On the other hand, Keshen X spent 29 days with average ROP of 1.35 m/hr to drill the 449 m composite anhydrite-salt rock. Moreover, it was difficult to trip in and trip out during the drilling, and the pipe sticking happened frequently, back-reaming frequently as well. There were losses during both the drilling and the casing running. Due to the unsmooth wellbore, this well increased additional 3 runs of reaming after drilling operation and 4 clean-out runs. 13 days later after the reaming operation, the anhydrite-salt rock creep was checked and found that the hole was still smooth, no pipe sticking existing. Hence, RWD technology has accomplished both goals of preventing the downhole complexities and speeding up drilling. The novel RWD technology can be well illustrated by presenting all the details of its application in salt-base formations.","PeriodicalId":11024,"journal":{"name":"Day 4 Wed, December 01, 2021","volume":"20 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87452034","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Klemens Katterbauer, A. Marsala, Abdulaziz Al Qasim, A. Yousif
Sustainability and reducing carbon footprint has attracted attention in the oil and gas industry to optimize recovery and increase efficiency. The 4th Industrial Revolution has made an enormous impact in the oil and gas industry and on analyzing carbon footprint reduction opportunities. This allows classification of various reservoir operations, installation of permanent sensors and robots on the field, and reduction of overall power consumption. We present an overview of new AI approaches for optimizing reservoir performance while reducing their carbon footprint. We will outline the significant carbon emissions contributors for field operations and how their impact will change throughout the production's lifecycle from a reservoir. Based on this analysis, we will outline via an AI-driven optimization framework areas of improvement to reduce the carbon footprint considering the uncertainty. We analyzed the framework's performance on a synthetic reservoir model with several producing wells, water, and CO2 injecting wells. Beneficial in reducing carbon emissions from the field is the reuse and injection of CO2 for enhancing hydrocarbon production from the reservoir. One hundred different scenarios were then investigated utilizing an innovative autoregressive network model to determine the impact of these components on the overall carbon emission of the field and determine its uncertainty. The conclusions from the analysis were then incorporated into a data-driven optimization routine to minimize carbon footprint while maximizing reservoir performance. The final optimization results of the showcase outlined the ability to reduce the carbon footprint significantly.
{"title":"Minimizing Carbon Footprint by Smart Sustainable Reservoir Management","authors":"Klemens Katterbauer, A. Marsala, Abdulaziz Al Qasim, A. Yousif","doi":"10.2118/204752-ms","DOIUrl":"https://doi.org/10.2118/204752-ms","url":null,"abstract":"\u0000 Sustainability and reducing carbon footprint has attracted attention in the oil and gas industry to optimize recovery and increase efficiency. The 4th Industrial Revolution has made an enormous impact in the oil and gas industry and on analyzing carbon footprint reduction opportunities. This allows classification of various reservoir operations, installation of permanent sensors and robots on the field, and reduction of overall power consumption.\u0000 We present an overview of new AI approaches for optimizing reservoir performance while reducing their carbon footprint. We will outline the significant carbon emissions contributors for field operations and how their impact will change throughout the production's lifecycle from a reservoir. Based on this analysis, we will outline via an AI-driven optimization framework areas of improvement to reduce the carbon footprint considering the uncertainty.\u0000 We analyzed the framework's performance on a synthetic reservoir model with several producing wells, water, and CO2 injecting wells. Beneficial in reducing carbon emissions from the field is the reuse and injection of CO2 for enhancing hydrocarbon production from the reservoir. One hundred different scenarios were then investigated utilizing an innovative autoregressive network model to determine the impact of these components on the overall carbon emission of the field and determine its uncertainty. The conclusions from the analysis were then incorporated into a data-driven optimization routine to minimize carbon footprint while maximizing reservoir performance. The final optimization results of the showcase outlined the ability to reduce the carbon footprint significantly.","PeriodicalId":11024,"journal":{"name":"Day 4 Wed, December 01, 2021","volume":"21 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82842083","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
京公网安备 11010802042870号
京ICP备2023020795号-1
扫码关注我们
求助内容：
应助结果提醒方式：