A. Aslanyan, A. Popov, I. Zhdanov, E. Pakhomov, D. Gulyaev, R. Farakhova, R. Guss, M. Dementeva
This paper presents a practical case of Field Development Planning (FDP) process with extensive use of petroleum asset digital twin facilities. The paper explains the process of setting up both the digital twin and the performance metrics which were used to steer the multivariate trials on redevelopment activities towards the optimal investment scenario. The petroleum asset is represented by a block of the large oilfield in Western Siberia with ongoing waterflood project at mature stage. The process of building FDP was performed through a series of interactive sessions with the petroleum asset digital twin which includes three major group of functionalities: Convert redevelopment activities (drilling, workovers, production optimization and surface facilities) into the production response and basic investment indicators including NPV, PI, IRR, MIRR, ROI Provide technical performance metrics (such as formation pressure, watercut and recovery responses, potential case of integrity failures, behind casing channelings, spontaneous formation fracturing, surface pipeline pressure losses) that can help understand the results of the FDP activities Provide well and cross-well surveillance simulations (pressure tests, production and integrity logging) to help identify the candidates for future monitoring. Two different multidisciplinary teams undertook 12 FDP iterations over two different 3D full-field model realizations to arrive at the best investment scenarios for each model. After that the FDP team has picked up the best practices from both FDPs in the form of those field development actions which turned to be financially successful in both model realizations. All those cases were prioritized and merged into the ultimate FDP scenario and verified across both digital asset realizations. The new FDP suggested the new drilling opportunities, few integrity workovers, few conversions and a new production target strategy for producers and injectors. Apart from investment benefits, the new FDP provides substantial accelerated oil withdrawals and increase in ultimate recovery comparing to the no-future-activity scenario.
{"title":"Multiscenario Development Planning by Means of the Digital Twin of the Petroleum Field","authors":"A. Aslanyan, A. Popov, I. Zhdanov, E. Pakhomov, D. Gulyaev, R. Farakhova, R. Guss, M. Dementeva","doi":"10.2118/208970-ms","DOIUrl":"https://doi.org/10.2118/208970-ms","url":null,"abstract":"\u0000 This paper presents a practical case of Field Development Planning (FDP) process with extensive use of petroleum asset digital twin facilities. The paper explains the process of setting up both the digital twin and the performance metrics which were used to steer the multivariate trials on redevelopment activities towards the optimal investment scenario.\u0000 The petroleum asset is represented by a block of the large oilfield in Western Siberia with ongoing waterflood project at mature stage.\u0000 The process of building FDP was performed through a series of interactive sessions with the petroleum asset digital twin which includes three major group of functionalities:\u0000 Convert redevelopment activities (drilling, workovers, production optimization and surface facilities) into the production response and basic investment indicators including NPV, PI, IRR, MIRR, ROI Provide technical performance metrics (such as formation pressure, watercut and recovery responses, potential case of integrity failures, behind casing channelings, spontaneous formation fracturing, surface pipeline pressure losses) that can help understand the results of the FDP activities Provide well and cross-well surveillance simulations (pressure tests, production and integrity logging) to help identify the candidates for future monitoring.\u0000 Two different multidisciplinary teams undertook 12 FDP iterations over two different 3D full-field model realizations to arrive at the best investment scenarios for each model.\u0000 After that the FDP team has picked up the best practices from both FDPs in the form of those field development actions which turned to be financially successful in both model realizations. All those cases were prioritized and merged into the ultimate FDP scenario and verified across both digital asset realizations.\u0000 The new FDP suggested the new drilling opportunities, few integrity workovers, few conversions and a new production target strategy for producers and injectors. Apart from investment benefits, the new FDP provides substantial accelerated oil withdrawals and increase in ultimate recovery comparing to the no-future-activity scenario.","PeriodicalId":146458,"journal":{"name":"Day 1 Wed, March 16, 2022","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2022-03-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"127658133","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 Garay Andrade, Julio Sanz Vera, Fabian Salas, Claudio Pucci, Alejandro Castro, Vlamir Bastos, Ewaldo Schubert, B. Theuveny
A novel implementation of an economical, self-sustainable and environmentally friendly solution for tight gas field production monitoring in a remote location in Tierra Del Fuego, allows early-stage production measurements necessary in the unconventional reservoir analysis for the field recovery process optimization. This innovative solution is based on the development of a portable skid designed for production test measurement in a multi-well pad, that combine a multiport selector valve and a multiphase flow meter, making possible to remotely select a well to measure and transfer flow data in real time. The commands for the well selection and the data transmission can be done via satellite with an encrypted software directly from the Operator's office. A PhotoVoltaic (PV) solar panel was developed to provide a reliable self-sufficient power for the entire system from 100% clean energy. Located in Chile's Tierra del Fuego region, the Magallanes Basin comprises two main structural regions: a normal faulted eastern region and a thrust faulted western area. These remote tight gas fields undergoing rapid decline are big challenges to explore, develop and produce economically. They demand a close initial surveillance through timely production tests to acquire representative data, which allows consolidation of a reservoir analysis and development methodologies to optimize ultimate and cost-effective recovery. An innovated approach was successful implemented for production monitoring using the Multiphase Measurement Skid, which provided the required data quality and frequency along with flexibility to perform production test in multiple wells, all remotely controlled from the Operator's office. The entire system is self-sufficient and powered by solar panels designed, which brings sustainability avoiding the use of generator and dealing with fuel logistics making this solution environmentally friendly carbon-free emission. Such sustainable and self-sufficient solution to monitor single to multiple wells (up to eight), combines an automated multiport valve system with multiphase measurement technology for remote operations. Its operation is simple and efficient, amd it provides a continuous data stream of well test information to the production and reservoir engineers managing the field.
在Tierra Del Fuego偏远地区，采用了一种经济、可持续、环保的致密气田生产监测解决方案，可以在非常规油藏分析中进行必要的早期生产测量，以优化油田采收率过程。这种创新的解决方案是基于便携式滑橇的开发，该滑橇设计用于多井台的生产测试测量，它结合了一个多端口选择阀和一个多相流量计，可以远程选择井进行实时测量和传输流量数据。选择井的命令和数据传输可以通过卫星与加密软件直接从作业者办公室完成。开发了光伏(PV)太阳能电池板，为整个系统提供可靠的自给自足的100%清洁能源。Magallanes盆地位于智利火地岛地区，由两个主要构造区组成:东部正断层区和西部逆冲断层区。这些迅速衰退的偏远致密气田是经济勘探、开发和生产的重大挑战。他们要求通过及时的生产测试进行密切的初始监测，以获取有代表性的数据，从而巩固油藏分析和开发方法，以优化最终的经济效益采收率。采用多相测量撬(multi - phase Measurement Skid)，一种创新的生产监测方法得到了成功实施，该方法提供了所需的数据质量和频率，以及在多口井中进行生产测试的灵活性，所有这些都可以从作业者的办公室进行远程控制。整个系统是自给自足的，由设计的太阳能电池板供电，这带来了可持续性，避免了发电机的使用，并处理了燃料物流，使该解决方案对环境友好，无碳排放。这种可持续和自给自足的解决方案可以监测单口到多口井(最多8口)，将自动化多口阀系统与多相测量技术相结合，用于远程操作。该系统操作简单、高效，可为生产和油藏工程师提供连续的试井数据流。
{"title":"Enhancement of Production Data in Tight Gas Reservoir Through an Automated Multiphase Measurement Skid for Remote Operation","authors":"Carlos Garay Andrade, Julio Sanz Vera, Fabian Salas, Claudio Pucci, Alejandro Castro, Vlamir Bastos, Ewaldo Schubert, B. Theuveny","doi":"10.2118/208976-ms","DOIUrl":"https://doi.org/10.2118/208976-ms","url":null,"abstract":"\u0000 A novel implementation of an economical, self-sustainable and environmentally friendly solution for tight gas field production monitoring in a remote location in Tierra Del Fuego, allows early-stage production measurements necessary in the unconventional reservoir analysis for the field recovery process optimization.\u0000 This innovative solution is based on the development of a portable skid designed for production test measurement in a multi-well pad, that combine a multiport selector valve and a multiphase flow meter, making possible to remotely select a well to measure and transfer flow data in real time. The commands for the well selection and the data transmission can be done via satellite with an encrypted software directly from the Operator's office. A PhotoVoltaic (PV) solar panel was developed to provide a reliable self-sufficient power for the entire system from 100% clean energy.\u0000 Located in Chile's Tierra del Fuego region, the Magallanes Basin comprises two main structural regions: a normal faulted eastern region and a thrust faulted western area. These remote tight gas fields undergoing rapid decline are big challenges to explore, develop and produce economically. They demand a close initial surveillance through timely production tests to acquire representative data, which allows consolidation of a reservoir analysis and development methodologies to optimize ultimate and cost-effective recovery. An innovated approach was successful implemented for production monitoring using the Multiphase Measurement Skid, which provided the required data quality and frequency along with flexibility to perform production test in multiple wells, all remotely controlled from the Operator's office. The entire system is self-sufficient and powered by solar panels designed, which brings sustainability avoiding the use of generator and dealing with fuel logistics making this solution environmentally friendly carbon-free emission.\u0000 Such sustainable and self-sufficient solution to monitor single to multiple wells (up to eight), combines an automated multiport valve system with multiphase measurement technology for remote operations. Its operation is simple and efficient, amd it provides a continuous data stream of well test information to the production and reservoir engineers managing the field.","PeriodicalId":146458,"journal":{"name":"Day 1 Wed, March 16, 2022","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2022-03-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"122089476","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}
Determination of true residual oil saturation and oil relative permeability curve for heavy oil/water systems requires extensive effort and time as the breakthrough time occurs early in the imbibition process and the history match techniques are not able to obtain these two parameters perfectly. The aim of this work is to provide a new insight into the determination of residual oil saturation and oil relative permeability from core flooding in heavy oil/water systems at different temperatures. Literature claimed that the ratio of water relative permeability to oil relative permeability should be considered besides the production and pressure drop data in history matching to determine the residual oil saturation more accurately. In this regard, different relative permeability curves from our previous experimental works are incorporated in a series of simulations that were run for up to 100 PV of water injection. Production and pressure drop data were generated where a normal error distribution is added to the input data. The history matching runs (considering relative permeability ratio) are carried out to examine how many pore volumes of water need to be injected to reach the true residual oil saturation accurately in different experiments. The history matching results (with a Corey relative permeability model), employing the production data, pressure drop data, and the ratio of water relative permeability to oil relative permeability, which can be calculated fairly accurate from the Welge method, confirm that water relative permeability exponent is generally independent of the volume of injected water. Since the irreducible water saturation can be determined nicely during the oil flooding due to the inverse mobility ratio, the water relative permeability is not a function of volume of injected water. In contrast, determination of the true residual oil saturation in five experiments out of six is predicted with an error less than 5%. For several systems at different temperatures, at least 40 PV of water needs to be injected to result in accurate residual oil saturation determination. The oil exponent determination reveals a deviation of 20%-60% from the entered value to the simulation. The ratio of water relative permeability to oil relative permeability should be inserted into the simulation for acceptable history matching of relative permeability determination. The estimation of true residual oil saturation for relative permeability determination from the experimental data cannot be achieved easily. In this study, a new technique described by in the literature has been examined and tested to determine the required pore volume of injected water in different heavy oil/water systems within a wide range of temperatures.
{"title":"A New Insight into the Determination of True Residual Oil Saturation and Oil Relative Permeability from the Experimental Data in Heavy Oil/Water Systems","authors":"S. Esmaeili, A. Kantzas, B. Maini","doi":"10.2118/208913-ms","DOIUrl":"https://doi.org/10.2118/208913-ms","url":null,"abstract":"\u0000 Determination of true residual oil saturation and oil relative permeability curve for heavy oil/water systems requires extensive effort and time as the breakthrough time occurs early in the imbibition process and the history match techniques are not able to obtain these two parameters perfectly. The aim of this work is to provide a new insight into the determination of residual oil saturation and oil relative permeability from core flooding in heavy oil/water systems at different temperatures.\u0000 Literature claimed that the ratio of water relative permeability to oil relative permeability should be considered besides the production and pressure drop data in history matching to determine the residual oil saturation more accurately. In this regard, different relative permeability curves from our previous experimental works are incorporated in a series of simulations that were run for up to 100 PV of water injection. Production and pressure drop data were generated where a normal error distribution is added to the input data. The history matching runs (considering relative permeability ratio) are carried out to examine how many pore volumes of water need to be injected to reach the true residual oil saturation accurately in different experiments.\u0000 The history matching results (with a Corey relative permeability model), employing the production data, pressure drop data, and the ratio of water relative permeability to oil relative permeability, which can be calculated fairly accurate from the Welge method, confirm that water relative permeability exponent is generally independent of the volume of injected water. Since the irreducible water saturation can be determined nicely during the oil flooding due to the inverse mobility ratio, the water relative permeability is not a function of volume of injected water. In contrast, determination of the true residual oil saturation in five experiments out of six is predicted with an error less than 5%. For several systems at different temperatures, at least 40 PV of water needs to be injected to result in accurate residual oil saturation determination. The oil exponent determination reveals a deviation of 20%-60% from the entered value to the simulation. The ratio of water relative permeability to oil relative permeability should be inserted into the simulation for acceptable history matching of relative permeability determination.\u0000 The estimation of true residual oil saturation for relative permeability determination from the experimental data cannot be achieved easily. In this study, a new technique described by in the literature has been examined and tested to determine the required pore volume of injected water in different heavy oil/water systems within a wide range of temperatures.","PeriodicalId":146458,"journal":{"name":"Day 1 Wed, March 16, 2022","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2022-03-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"125774325","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}
Khaled Abdelaal, Ken Atere, Keith LeRoy, A. Eddy, R. Smith
After drilling in the Gulf area of Middle East for approximately nine months, the operation’s project team struggled to find a consistent and repeatable roadmap for significant rate of penetration (ROP) improvements. The team was relying on the driller to manually control the ROP, weight on bit (WOB), differential pressure, pump pressure, and torque. Regardless of the driller’s experience, it is difficult for a single person to successfully monitor and adjust for multiple and continuously changing variables in real time. Extreme variation and lack of control on drilling parameters (such as WOB, torque, and differential pressure) prevented repeatable ROP improvements, despite having a sound drilling plan. To solve this problem, the team tasked a third party to 1) deploy its electronic drilling recorder (EDR) to improve data quality, 2) integrate its multi-parameter DAS™ system into the rig’s programmable logic controls (PLC) system, and 3) deploy drilling optimization software solutions in real time. The overall objective was to build a decision-supporting tool to overcome the main ROP limiters through proper identification and mitigation, thus yielding higher ROP and creating newly optimized drilling parameters for future wells. A pilot program consisting of two rigs and six wells per rig (12 wells in total) was executed utilizing this new approach. Over each section of each well, the team followed a traditional continuous improvement cycle of "Identify– Plan – Execute – Review". The EDR was able to accurately identify and record the drilling control limits (such as for ROP, WOB, torque, or differential pressure). The DAS system was also able to demonstrate improved control of WOB, ROP and, torque limits, and target differential pressures. Delivering this information in real time encouraged conversations around modifications to the existing well plan. During post-well analysis, the data allowed the optimization team to clearly identify the limiter of each hole section for changes in future well planning. A flexible dashboard platform was utilized to assist the optimization team by developing enhanced graphics to improve the visibility and accuracy of the real-time performance monitoring. These dashboards target critical operations and allow more data to be taken into consideration, thus providing a more holistic and structured decision-making process. The pilot program showed measurable improvement in several areas. Overall, on-bottom ROP improved by 10.5%, shoe track drill-out times were reduced by 31%, and physical inspections showed significant reductions in bit wear. Additionally, the higher quality of data recording contributed to a noticeable improvement on processing multiple data-analytics modules. This paper describes the challenges and step-by-step chronology of solutions deployed to achieve continuous improvement and to maximize ROP by effectively focusing on process execution. The knowledge required to execute a fit-for-purpose
{"title":"Holistic Real-Time Drilling Parameters Optimization Delivers Best-in-Class Drilling Performance and Preserves Bit Condition - A Case History from an Integrated Project in the Middle East","authors":"Khaled Abdelaal, Ken Atere, Keith LeRoy, A. Eddy, R. Smith","doi":"10.2118/208958-ms","DOIUrl":"https://doi.org/10.2118/208958-ms","url":null,"abstract":"\u0000 After drilling in the Gulf area of Middle East for approximately nine months, the operation’s project team struggled to find a consistent and repeatable roadmap for significant rate of penetration (ROP) improvements. The team was relying on the driller to manually control the ROP, weight on bit (WOB), differential pressure, pump pressure, and torque. Regardless of the driller’s experience, it is difficult for a single person to successfully monitor and adjust for multiple and continuously changing variables in real time.\u0000 Extreme variation and lack of control on drilling parameters (such as WOB, torque, and differential pressure) prevented repeatable ROP improvements, despite having a sound drilling plan. To solve this problem, the team tasked a third party to 1) deploy its electronic drilling recorder (EDR) to improve data quality, 2) integrate its multi-parameter DAS™ system into the rig’s programmable logic controls (PLC) system, and 3) deploy drilling optimization software solutions in real time. The overall objective was to build a decision-supporting tool to overcome the main ROP limiters through proper identification and mitigation, thus yielding higher ROP and creating newly optimized drilling parameters for future wells.\u0000 A pilot program consisting of two rigs and six wells per rig (12 wells in total) was executed utilizing this new approach. Over each section of each well, the team followed a traditional continuous improvement cycle of \"Identify– Plan – Execute – Review\". The EDR was able to accurately identify and record the drilling control limits (such as for ROP, WOB, torque, or differential pressure). The DAS system was also able to demonstrate improved control of WOB, ROP and, torque limits, and target differential pressures. Delivering this information in real time encouraged conversations around modifications to the existing well plan. During post-well analysis, the data allowed the optimization team to clearly identify the limiter of each hole section for changes in future well planning.\u0000 A flexible dashboard platform was utilized to assist the optimization team by developing enhanced graphics to improve the visibility and accuracy of the real-time performance monitoring. These dashboards target critical operations and allow more data to be taken into consideration, thus providing a more holistic and structured decision-making process. The pilot program showed measurable improvement in several areas. Overall, on-bottom ROP improved by 10.5%, shoe track drill-out times were reduced by 31%, and physical inspections showed significant reductions in bit wear. Additionally, the higher quality of data recording contributed to a noticeable improvement on processing multiple data-analytics modules.\u0000 This paper describes the challenges and step-by-step chronology of solutions deployed to achieve continuous improvement and to maximize ROP by effectively focusing on process execution. The knowledge required to execute a fit-for-purpose ","PeriodicalId":146458,"journal":{"name":"Day 1 Wed, March 16, 2022","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2022-03-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"120811458","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}
A. Nguyen, Dylan Hematillake, Robert Glover, C. Diaz-Goano
This paper outlines an end-to-end case study from ideation through to the development and deployment of a novel method to estimate SAGD depletion along a producing SAGD horizontal well from temperature fall off (TFO) events, from any temperature measurement point along the well. The methodology combines reservoir engineering first principals, analytics, simulation modelling and digital product delivery components. The outputs of this work are expected to drive rapid, data-driven, and standardized approaches to subsurface optimization of SAGD well pairs through quantified estimation of remaining oil in place opportunities that could be economically exploited through operations, re-completions, re-drills and technology applications.
{"title":"Distributed Temperature Sensor Analytics: Estimating SAGD Depletion from Temperature Fall Off Data","authors":"A. Nguyen, Dylan Hematillake, Robert Glover, C. Diaz-Goano","doi":"10.2118/208895-ms","DOIUrl":"https://doi.org/10.2118/208895-ms","url":null,"abstract":"\u0000 This paper outlines an end-to-end case study from ideation through to the development and deployment of a novel method to estimate SAGD depletion along a producing SAGD horizontal well from temperature fall off (TFO) events, from any temperature measurement point along the well. The methodology combines reservoir engineering first principals, analytics, simulation modelling and digital product delivery components. The outputs of this work are expected to drive rapid, data-driven, and standardized approaches to subsurface optimization of SAGD well pairs through quantified estimation of remaining oil in place opportunities that could be economically exploited through operations, re-completions, re-drills and technology applications.","PeriodicalId":146458,"journal":{"name":"Day 1 Wed, March 16, 2022","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2022-03-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"122415096","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}
The performance of an autonomous inflow control valve (AICV), used to restrict the inflow of unwanted fluids like gas and/or steam was simulated using an industrial reservoir simulator. The simulation results were used to determine how AICVs can improve the oil recovery in steam assisted gravity drainage (SAGD) operations. Utilizing inflow or flow control devices (ICDs/FCDs) in SAGD wells is a method with promising results. FCDs delay steam breakthrough and increase the oil recovery. The recently developed technology, AICV, further improves the oil recovery from SAGD operations. This paper provides a summary of the test data acquired from the full-scale flow loop testing that replicates the downhole operating conditions. Single and multiphase flow performance of an orifice type ICD and AICV is presented and compared. The results confirm the ability of the AICV to restrict the production of gas and/or steam. A performance analysis based on the results from the experiments and well case simulations is presented. The paper also presents an innovative approach on analyzing the well conditions which brings an insight into SAGD production wells completed with AICVs. Simulations are performed in different scenarios of a SAGD late life process with non-condensable gases (NCGs), and these results confirmed a significant reduction in the gas liquid ratio (GLR), and an increased oil production when using AICV compared to the open hole case. Simulation results demonstrated that utilizing AICV in the SAGD production wells will reduce the gas and steam production by 64%. The reduction of steam production from the breakthrough zones allows a lower bottom hole pressure. This gives a higher sandface drawdown in the zones with less mobile oil, and thus a higher production from these zones. Further, this forces the steam chamber to be more evenly distributed along the different zones, resulting in increased oil recovery. Considering the environmental aspect, AICV can contribute to a considerable reduction in the steam use which will consequently reduce the energy and water usage for steam generation. As a result, utilizing AICV in SAGD operations will improve the economics of SAGD projects.
{"title":"Performance Analysis of Autonomous Inflow Control Valve in a SAGD Late Life Process with Non-Condensable Gases","authors":"S. Taghavi, H. Aakre, Britt M. E. Moldestad","doi":"10.2118/208915-ms","DOIUrl":"https://doi.org/10.2118/208915-ms","url":null,"abstract":"\u0000 The performance of an autonomous inflow control valve (AICV), used to restrict the inflow of unwanted fluids like gas and/or steam was simulated using an industrial reservoir simulator. The simulation results were used to determine how AICVs can improve the oil recovery in steam assisted gravity drainage (SAGD) operations. Utilizing inflow or flow control devices (ICDs/FCDs) in SAGD wells is a method with promising results. FCDs delay steam breakthrough and increase the oil recovery. The recently developed technology, AICV, further improves the oil recovery from SAGD operations. This paper provides a summary of the test data acquired from the full-scale flow loop testing that replicates the downhole operating conditions. Single and multiphase flow performance of an orifice type ICD and AICV is presented and compared. The results confirm the ability of the AICV to restrict the production of gas and/or steam. A performance analysis based on the results from the experiments and well case simulations is presented. The paper also presents an innovative approach on analyzing the well conditions which brings an insight into SAGD production wells completed with AICVs.\u0000 Simulations are performed in different scenarios of a SAGD late life process with non-condensable gases (NCGs), and these results confirmed a significant reduction in the gas liquid ratio (GLR), and an increased oil production when using AICV compared to the open hole case. Simulation results demonstrated that utilizing AICV in the SAGD production wells will reduce the gas and steam production by 64%. The reduction of steam production from the breakthrough zones allows a lower bottom hole pressure. This gives a higher sandface drawdown in the zones with less mobile oil, and thus a higher production from these zones. Further, this forces the steam chamber to be more evenly distributed along the different zones, resulting in increased oil recovery.\u0000 Considering the environmental aspect, AICV can contribute to a considerable reduction in the steam use which will consequently reduce the energy and water usage for steam generation. As a result, utilizing AICV in SAGD operations will improve the economics of SAGD projects.","PeriodicalId":146458,"journal":{"name":"Day 1 Wed, March 16, 2022","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2022-03-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"124738285","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}
The Winterhouse Formation (Port au Port Peninsula, western Newfoundland, Canada) is a lateral equivalent to the Utica and Macasty formations farther west. With hydrocarbon stains and odours as a guide towards a common and regional upper Ordovician hydrocarbon system, Winterhouse rocks may yet contain their own suite of source reservoir and seal strata, with coarser, sandier beds perhaps playing host to other varieties of conventional and unconventional hydrocarbon traps. Hence, addressing basic properties of fluid transmission is an important and unknown variable that needs to be addressed for this formation. In this pilot study, Mercury Intrusion Porosimetry (MIP) is applied to measure the petrophysical properties of a single tight (low porosity, low permeability) quartz-carbonate sandstone sample from a Winterhouse outcrop. As a tool, Mercury Intrusion Porosimetry is strongly dependent on conformity of sample size and shape as a determinant of pore accessibility. Hence two sample types (i) plugs and (ii) cuttings (both real and artificial) are analyzed to explore aspects of core and cuttings preparation and data reduction work flow measurements of storage and transport properties. For artificial "cuttings" a horizontal 2.5 cm core plug and rock fragments are crushed and sieved to replicate fine and coarse fractions. For porosimetry, a Micromeretrics AutoPore IV porosimeter with a maximum pressure of 33,000 psi is used to determine the porosity, pore size distribution, surface area, and bulk density of all samples. Additionally, the FEI Quanta 650 Field Emission Gun (FEG) SEM is used to take images of the pore structure. Mineralogy is determined from the GXMAP measurement mode within FEI Mineral Liberation AnalyzerTM software. A comprehensive analysis corroborating results from MIP and SEM indicates that for these tight rocks, and namely, outcrop plugs, artificial cuttings, and real drill cuttings from a nearby well, all show a similar spectrum of results, but smaller coarse fragments are recommended for reliability. In terms of the Winterhouse strata, it is clear that some of this rock is very tight and highly cemented, but that it also possesses fractures and high permeability values which may make it a good unconventional reservoir. These porosity-permeability results are simply a beginning in a search to understand the petrophysical properties of the strata on the western coast of Newfoundland. The western part of Newfoundland has seen extensive oil exploration efforts in the last few decades, these efforts have resulted in little success. A large degree of this is due to the complex geological history and overall lack of knowledge concerning the structure and diagenesis of these rocks (Cooper et al, 2001). This study will support the new sampling programs in the hope of gaining new insights into potential oil exploitation.
温特豪斯组(加拿大纽芬兰西部的Port au Port半岛)相当于尤蒂卡组和马卡斯蒂组的侧向。由于油气污渍和气味可以作为研究上奥陶统油气系统的向导，温特豪斯的岩石可能还含有自己的一套烃源储层和封闭地层，而较粗的砂质层可能是其他种类常规和非常规油气圈闭的宿主。因此，解决流体传输的基本特性是该地层需要解决的一个重要且未知的变量。在这项初步研究中，应用汞侵入孔隙度法(MIP)测量了来自Winterhouse露头的单个致密(低孔隙度、低渗透率)石英-碳酸盐岩砂岩样品的岩石物理性质。作为一种工具，压汞孔隙法在很大程度上依赖于样品大小和形状的一致性，作为孔隙可达性的决定因素。因此，分析了两种样品类型(i)桥塞和(ii)岩屑(包括真实的和人工的)，以探索岩心和岩屑制备以及数据简化工作流程的存储和运输特性测量方面。对于人工“岩屑”，一个水平的2.5厘米的岩心塞和岩石碎片被粉碎和筛选，以复制细和粗的分数。对于孔隙度测定，使用Micromeretrics AutoPore IV孔隙度计，最大压力为33,000 psi，用于测定所有样品的孔隙度、孔径分布、表面积和体积密度。此外，利用FEI量子650场发射枪(FEG)扫描电镜对孔隙结构进行了成像。矿物学由FEI Mineral Liberation AnalyzerTM软件中的GXMAP测量模式确定。综合分析证实了MIP和SEM的结果，表明对于这些致密岩石，即露头塞、人工岩屑和附近井的真实钻屑，都显示出相似的结果谱，但为了可靠性，建议使用更小的粗碎片。就Winterhouse地层而言，很明显，其中一些岩石非常致密，胶结度很高，但它也具有裂缝和高渗透率，这可能使其成为一个很好的非常规储层。这些孔隙度-渗透率结果仅仅是了解纽芬兰西海岸地层岩石物理性质的一个开始。在过去的几十年里，纽芬兰西部地区进行了大量的石油勘探工作，但收效甚微。这在很大程度上是由于复杂的地质历史和对这些岩石的结构和成岩作用的总体缺乏了解(Cooper et al, 2001)。这项研究将支持新的采样程序，以期获得潜在石油开采的新见解。
{"title":"Evaluating the Prospect of Oil Production in Tight Winterhouse Formation Rocks in Western Newfoundland","authors":"J. Hawco, E. Burden, Edison A. Sripal, L. James","doi":"10.2118/208908-ms","DOIUrl":"https://doi.org/10.2118/208908-ms","url":null,"abstract":"\u0000 The Winterhouse Formation (Port au Port Peninsula, western Newfoundland, Canada) is a lateral equivalent to the Utica and Macasty formations farther west. With hydrocarbon stains and odours as a guide towards a common and regional upper Ordovician hydrocarbon system, Winterhouse rocks may yet contain their own suite of source reservoir and seal strata, with coarser, sandier beds perhaps playing host to other varieties of conventional and unconventional hydrocarbon traps. Hence, addressing basic properties of fluid transmission is an important and unknown variable that needs to be addressed for this formation. In this pilot study, Mercury Intrusion Porosimetry (MIP) is applied to measure the petrophysical properties of a single tight (low porosity, low permeability) quartz-carbonate sandstone sample from a Winterhouse outcrop. As a tool, Mercury Intrusion Porosimetry is strongly dependent on conformity of sample size and shape as a determinant of pore accessibility. Hence two sample types (i) plugs and (ii) cuttings (both real and artificial) are analyzed to explore aspects of core and cuttings preparation and data reduction work flow measurements of storage and transport properties. For artificial \"cuttings\" a horizontal 2.5 cm core plug and rock fragments are crushed and sieved to replicate fine and coarse fractions. For porosimetry, a Micromeretrics AutoPore IV porosimeter with a maximum pressure of 33,000 psi is used to determine the porosity, pore size distribution, surface area, and bulk density of all samples. Additionally, the FEI Quanta 650 Field Emission Gun (FEG) SEM is used to take images of the pore structure. Mineralogy is determined from the GXMAP measurement mode within FEI Mineral Liberation AnalyzerTM software. A comprehensive analysis corroborating results from MIP and SEM indicates that for these tight rocks, and namely, outcrop plugs, artificial cuttings, and real drill cuttings from a nearby well, all show a similar spectrum of results, but smaller coarse fragments are recommended for reliability. In terms of the Winterhouse strata, it is clear that some of this rock is very tight and highly cemented, but that it also possesses fractures and high permeability values which may make it a good unconventional reservoir. These porosity-permeability results are simply a beginning in a search to understand the petrophysical properties of the strata on the western coast of Newfoundland. The western part of Newfoundland has seen extensive oil exploration efforts in the last few decades, these efforts have resulted in little success. A large degree of this is due to the complex geological history and overall lack of knowledge concerning the structure and diagenesis of these rocks (Cooper et al, 2001). This study will support the new sampling programs in the hope of gaining new insights into potential oil exploitation.","PeriodicalId":146458,"journal":{"name":"Day 1 Wed, March 16, 2022","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2022-03-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"130363482","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}
Riserless drilling of the upper intervals of subsea wells has been standard practice in deepwater well construction, while taking mud returns to the sea floor. It has dramatically increased the safety of drilling shallow sections of subsea wells by reducing the hazard of handling gas at the rig, should shallow gas zones be encountered. It has also been very beneficial in controlling shallow water flows in deepwater areas of the Gulf of Mexico (GOM). The shallow water flow (SWF) is a typical offshore drilling hazard, defined as the phenomenon involving the flow of water from the surrounding region of a casing up to the ocean floor together with formation sands and sometimes free gas. The flowing water is driven by a pressure difference that occurs when the drill bit has encountered the unconsolidated but over-pressured sand sections. In the past 40 years of drilling practices, the SWF hazard has been experienced in several deep-water basins around the world, especially in the deep-water area where the water depth ranges from 1300 to 8200 ft and the formation depth ranges from 300 to 4000 ft below mud line (BML). Shallow water flows from overpressure aquifers have been a serious concern in the deepwater Gulf of Mexico for drilling and production operations. They can create significant financial and operational risks for exploration and development projects. In the GOM, SWF intervals typically occur between 300 and 2,500 ft BML and in water depths greater than 1,500 ft. If left unchecked, the disturbance from the water flow can cause loss of soil strength surrounding the wellbore, thereby compromising the structural integrity of the well. In extreme cases, SWFs have led to collapsed casing and/or total loss of wellbores. The paper aims to present the origin of shallow water flows in a deepwater environment and mitigation strategies adopted by industry to carry out the operations safely.
{"title":"Assess the Impact of Shallow Water Flow Geohazard on Drilling Operations in the Riserless Sections of Deepwater Well Construction","authors":"Nitin R. Kulkarni, L. Heinze","doi":"10.2118/208917-ms","DOIUrl":"https://doi.org/10.2118/208917-ms","url":null,"abstract":"\u0000 Riserless drilling of the upper intervals of subsea wells has been standard practice in deepwater well construction, while taking mud returns to the sea floor. It has dramatically increased the safety of drilling shallow sections of subsea wells by reducing the hazard of handling gas at the rig, should shallow gas zones be encountered. It has also been very beneficial in controlling shallow water flows in deepwater areas of the Gulf of Mexico (GOM).\u0000 The shallow water flow (SWF) is a typical offshore drilling hazard, defined as the phenomenon involving the flow of water from the surrounding region of a casing up to the ocean floor together with formation sands and sometimes free gas. The flowing water is driven by a pressure difference that occurs when the drill bit has encountered the unconsolidated but over-pressured sand sections.\u0000 In the past 40 years of drilling practices, the SWF hazard has been experienced in several deep-water basins around the world, especially in the deep-water area where the water depth ranges from 1300 to 8200 ft and the formation depth ranges from 300 to 4000 ft below mud line (BML).\u0000 Shallow water flows from overpressure aquifers have been a serious concern in the deepwater Gulf of Mexico for drilling and production operations. They can create significant financial and operational risks for exploration and development projects. In the GOM, SWF intervals typically occur between 300 and 2,500 ft BML and in water depths greater than 1,500 ft. If left unchecked, the disturbance from the water flow can cause loss of soil strength surrounding the wellbore, thereby compromising the structural integrity of the well. In extreme cases, SWFs have led to collapsed casing and/or total loss of wellbores.\u0000 The paper aims to present the origin of shallow water flows in a deepwater environment and mitigation strategies adopted by industry to carry out the operations safely.","PeriodicalId":146458,"journal":{"name":"Day 1 Wed, March 16, 2022","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2022-03-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"124996495","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
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