Xu Gong, Hossein Shahandeh, Gordon Maclsaac, H. Motahhari, M. Beckman, Lu Dong
Cyclic Solvent Process (CSP) is a non-thermal solvent-based heavy oil recovery technology that was invented and developed by Imperial Oil Resources Limited through a multi-year integrated research program. The commercial viability of potential development concepts and their associated uncertainties are also an active area of investigation. A key input to an economic model is the global (or development level) flow stream. The conventional approach of developing the global flow stream involves the determination of well schedule through a well prioritization algorithm that adheres to a set of flow stream capacity constraints. The resulting flow streams can then be passed to an economic tool to evaluate a set of KPIs (Key Performance Indicators) in an uncoupled manner. One of the main challenges encountered in this approach is that it is difficult to optimize the overall economic performance due to (1) the absence of well-defined objective function, (2) the decoupling of the flow stream generation and the economic calculations, (3) the pre-defined characteristics of the well prioritization algorithm. The main objective of this study is to develop a mathematical optimization model for CSP commercial projects. A two-stage optimization framework, which integrates Genetic Algorithm (GA) as master optimizer and Mixed Integer Linear Programming (MILP) as sub-optimizer, is described. A conceptual commercial scenario is simulated as a case study and economic uplift is demonstrated.
{"title":"Cyclic Solvent Process Commercial Optimization","authors":"Xu Gong, Hossein Shahandeh, Gordon Maclsaac, H. Motahhari, M. Beckman, Lu Dong","doi":"10.2118/208965-ms","DOIUrl":"https://doi.org/10.2118/208965-ms","url":null,"abstract":"\u0000 Cyclic Solvent Process (CSP) is a non-thermal solvent-based heavy oil recovery technology that was invented and developed by Imperial Oil Resources Limited through a multi-year integrated research program. The commercial viability of potential development concepts and their associated uncertainties are also an active area of investigation. A key input to an economic model is the global (or development level) flow stream. The conventional approach of developing the global flow stream involves the determination of well schedule through a well prioritization algorithm that adheres to a set of flow stream capacity constraints. The resulting flow streams can then be passed to an economic tool to evaluate a set of KPIs (Key Performance Indicators) in an uncoupled manner. One of the main challenges encountered in this approach is that it is difficult to optimize the overall economic performance due to (1) the absence of well-defined objective function, (2) the decoupling of the flow stream generation and the economic calculations, (3) the pre-defined characteristics of the well prioritization algorithm.\u0000 The main objective of this study is to develop a mathematical optimization model for CSP commercial projects. A two-stage optimization framework, which integrates Genetic Algorithm (GA) as master optimizer and Mixed Integer Linear Programming (MILP) as sub-optimizer, is described. A conceptual commercial scenario is simulated as a case study and economic uplift is demonstrated.","PeriodicalId":11077,"journal":{"name":"Day 2 Thu, March 17, 2022","volume":"1 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"74377716","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}
Due to extensive energy requirements and the volume of emitted greenhouse gases associated with burning natural gas to generate steam in the SAGD process, there has been always a strong motivation to develop oil recovery processes for bitumen reservoirs with lower energy and emissions intensities. A hybrid steam-solvent co-injection process, which is to synergize the advantages of both SAGD and VAPEX processes and minimize their drawbacks is the subject of ongoing research and field piloting since early 2000. Most of the past efforts of the steam-solvent process were primarily focused on improving the oil rate or improving the process's economic benefits. However, due to Canada's ambitious greenhouse emission reduction target (net zero emission by 2050) along with the significant increase of carbon tax ($170 by 2030), the primary focus of the oil industry is shifting towards reducing steam injection and cutting the GHG emission drastically. This study revisited the steam-solvent process to find a suitable combination of solvent type and operating strategies that can reduce the steam injection and GHG emission significantly, and without significantly compromising the oil production. Two hydrocarbon pure solvents, propane and butane were recommended in this project to cut the steam injection drastically and without having a significant negative impact on the oil production. Among the two solvents, butane may be preferred. However, to reduce the cost further and cut energy input, propane may be a better choice than butane. Propane is cheaper than butane and it requires less energy to vaporize propane. The process should start with steam-only injection (as SAGD) and next inject solvent after the chamber is somewhat developed. The solvent may not be effective if the oil production is already in the natural decline stage. At later stages, the solvent retention in the reservoir could also be high. During the solvent injection period, a small amount of steam could be continuously injected with the solvent or steam could be intermittently injected as needed to keep enough energy in the reservoir. This will help to vaporize the solvent and prevent the chamber from being cooled down significantly.
{"title":"Steam-Solvent Process: A Gamechanger in Cutting Emissions in In-Situ Recovery of Oil Sands","authors":"M. Chowdhuri, Alex Filstein, Haibo Huang","doi":"10.2118/208966-ms","DOIUrl":"https://doi.org/10.2118/208966-ms","url":null,"abstract":"\u0000 Due to extensive energy requirements and the volume of emitted greenhouse gases associated with burning natural gas to generate steam in the SAGD process, there has been always a strong motivation to develop oil recovery processes for bitumen reservoirs with lower energy and emissions intensities. A hybrid steam-solvent co-injection process, which is to synergize the advantages of both SAGD and VAPEX processes and minimize their drawbacks is the subject of ongoing research and field piloting since early 2000. Most of the past efforts of the steam-solvent process were primarily focused on improving the oil rate or improving the process's economic benefits. However, due to Canada's ambitious greenhouse emission reduction target (net zero emission by 2050) along with the significant increase of carbon tax ($170 by 2030), the primary focus of the oil industry is shifting towards reducing steam injection and cutting the GHG emission drastically. This study revisited the steam-solvent process to find a suitable combination of solvent type and operating strategies that can reduce the steam injection and GHG emission significantly, and without significantly compromising the oil production. Two hydrocarbon pure solvents, propane and butane were recommended in this project to cut the steam injection drastically and without having a significant negative impact on the oil production. Among the two solvents, butane may be preferred. However, to reduce the cost further and cut energy input, propane may be a better choice than butane. Propane is cheaper than butane and it requires less energy to vaporize propane. The process should start with steam-only injection (as SAGD) and next inject solvent after the chamber is somewhat developed. The solvent may not be effective if the oil production is already in the natural decline stage. At later stages, the solvent retention in the reservoir could also be high. During the solvent injection period, a small amount of steam could be continuously injected with the solvent or steam could be intermittently injected as needed to keep enough energy in the reservoir. This will help to vaporize the solvent and prevent the chamber from being cooled down significantly.","PeriodicalId":11077,"journal":{"name":"Day 2 Thu, March 17, 2022","volume":"40 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84907577","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}
In this work, theoretical models have been formulated, validated, and applied to characterize the dynamic wormhole growth and propagation dynamics during CHOPS processes by integrating rate transient analysis (RTA) and a pressure-gradient-based (PGB) sand failure criterion. More specifically, a coupling fluid-solid flow model is proposed by incorporating the recently proposed PGB sand failure criterion with sand production. Then, the source function method is applied to solve the fluid flow problem in the matrix subsystem by considering each generated wormhole segment as a sink source, while the finite difference method is applied to solve the fluid-sand flow problem in the wormhole subsystem. The sand failing at each segment is induced and propagated once the PGB sand failure criterion has been reached. Furthermore, transient rate type curves are generated to determine the dynamic wormhole network conditioned to the measured fluids and sand production profiles. Also, effects of the PGB sand failure criterion and reservoir properties on the transient rate behaviour for CHOPS wells can be examined and analyzed. A gradual increase in the production rate profile occurs at the early times due to the wormhole growth and propagation. The wormhole network can be dynamically characterized by matching both the sand production rate and transient fluid production rate. The former is found to be greatly affected by the breakdown pressure gradient, while the effective wormhole coverage and intensity dominate the latter. Once the pressure responses on a static wormhole network are validated with numerical simulation, the newly proposed method has been extended to field applications under various constraints, demonstrating that the fluid and sand production data of CHOPS wells can be integrated to accurately characterize the dynamic wormhole network within a unified, consistent, and efficient framework.
{"title":"Characterization of Dynamic Wormhole Growth and Propagation During CHOPS Processes by Integrating Rate Transient Analysis and Pressure-Gradient-Based Sand Failure Criterion","authors":"Liwu Jiang, Jinju Liu, Tongjing Liu, Daoyong Yang","doi":"10.2118/208938-ms","DOIUrl":"https://doi.org/10.2118/208938-ms","url":null,"abstract":"\u0000 In this work, theoretical models have been formulated, validated, and applied to characterize the dynamic wormhole growth and propagation dynamics during CHOPS processes by integrating rate transient analysis (RTA) and a pressure-gradient-based (PGB) sand failure criterion. More specifically, a coupling fluid-solid flow model is proposed by incorporating the recently proposed PGB sand failure criterion with sand production. Then, the source function method is applied to solve the fluid flow problem in the matrix subsystem by considering each generated wormhole segment as a sink source, while the finite difference method is applied to solve the fluid-sand flow problem in the wormhole subsystem. The sand failing at each segment is induced and propagated once the PGB sand failure criterion has been reached. Furthermore, transient rate type curves are generated to determine the dynamic wormhole network conditioned to the measured fluids and sand production profiles. Also, effects of the PGB sand failure criterion and reservoir properties on the transient rate behaviour for CHOPS wells can be examined and analyzed. A gradual increase in the production rate profile occurs at the early times due to the wormhole growth and propagation. The wormhole network can be dynamically characterized by matching both the sand production rate and transient fluid production rate. The former is found to be greatly affected by the breakdown pressure gradient, while the effective wormhole coverage and intensity dominate the latter. Once the pressure responses on a static wormhole network are validated with numerical simulation, the newly proposed method has been extended to field applications under various constraints, demonstrating that the fluid and sand production data of CHOPS wells can be integrated to accurately characterize the dynamic wormhole network within a unified, consistent, and efficient framework.","PeriodicalId":11077,"journal":{"name":"Day 2 Thu, March 17, 2022","volume":"83 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90756753","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}
We analyze flowback production data of 502 multi-fractured horizontal oil and gas wells completed in the Montney Formation and 83 oil wells completed in the Duvernay and Horn River Formations. The main goal of this paper is to evaluate the possibility of distinguishing between formation and fracturing water based on the water-flowback response. We hypothesize that: 1) the slope of water-flowback harmonic decline (HD) profile is reversely proportional to formation water mobility, 2) the deviations from the unit slope on rate-normalized pressure (RNP) plots is proportional to the slope of HD, and 3) the slope of water-flowback HD correlates with the initial water saturation (Swi). To verify our hypothesis, we 1) classify the observed HD trends of water-flowback rate based on slopes, 2) construct RNP diagnostic plots of the studied wells, 3) analyze log data and estimate average Swi by using Archie equation (1952) for the studied wells. 4) investigate the effects of Swi on the water-flowback pattern. The results show that there are two distinct flowback patterns. The first flowback pattern shows sharp slope (>10-41/day) of water-flowback HD profile and relatively high slope values (0.64 to 0.984 kpa/m3) of the corresponding RNP plots. However, the second pattern shows very low slope of HD (<5 × 10-5 1/day), with some wells showing no significant decline of water rate through the entire flowback process, also relatively low slope values (0 to 0.23) of the corresponding RNP plots. Analysis of the log data shows a positive correlation between Swi and slope of water-flowback HD profile. We also found that the slopes are proportional to the slope of RNP. These results indicate that as Swi increases, slope of HD decreases and there is more deviation from the unit-slope on the RNP plots.
{"title":"Flowback Pattern-Recognition to Distinguish Between Formation and Fracturing Water Recovery","authors":"Zhanyuan Liu, T. Moussa, H. Dehghanpour","doi":"10.2118/208959-ms","DOIUrl":"https://doi.org/10.2118/208959-ms","url":null,"abstract":"\u0000 We analyze flowback production data of 502 multi-fractured horizontal oil and gas wells completed in the Montney Formation and 83 oil wells completed in the Duvernay and Horn River Formations. The main goal of this paper is to evaluate the possibility of distinguishing between formation and fracturing water based on the water-flowback response. We hypothesize that: 1) the slope of water-flowback harmonic decline (HD) profile is reversely proportional to formation water mobility, 2) the deviations from the unit slope on rate-normalized pressure (RNP) plots is proportional to the slope of HD, and 3) the slope of water-flowback HD correlates with the initial water saturation (Swi). To verify our hypothesis, we 1) classify the observed HD trends of water-flowback rate based on slopes, 2) construct RNP diagnostic plots of the studied wells, 3) analyze log data and estimate average Swi by using Archie equation (1952) for the studied wells. 4) investigate the effects of Swi on the water-flowback pattern. The results show that there are two distinct flowback patterns. The first flowback pattern shows sharp slope (>10-41/day) of water-flowback HD profile and relatively high slope values (0.64 to 0.984 kpa/m3) of the corresponding RNP plots. However, the second pattern shows very low slope of HD (<5 × 10-5 1/day), with some wells showing no significant decline of water rate through the entire flowback process, also relatively low slope values (0 to 0.23) of the corresponding RNP plots. Analysis of the log data shows a positive correlation between Swi and slope of water-flowback HD profile. We also found that the slopes are proportional to the slope of RNP. These results indicate that as Swi increases, slope of HD decreases and there is more deviation from the unit-slope on the RNP plots.","PeriodicalId":11077,"journal":{"name":"Day 2 Thu, March 17, 2022","volume":"16 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"74020182","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 significant portion of the time required to drill an oilwell is spent moving the drillpipe in or out of the wellbore, called "Tripping". The drill crew must trip pipe for numerous reasons. These include changing the bit as it wears out, inserting new casing strings, cleaning and treating the drillpipe and/or wellbore to allow more efficient drilling, and to run in various tools that perform specific jobs required at certain times in the oilwell construction plan. The traditional tripping process (TTP) inherently creates pressure transients developed from stopping and starting the vertical motion of the drillpipe during connections. These pressure transients called, "Swapping" and "Surging", contribute to borehole instability, restrict tripping speed, and increase non-productive time (NPT). This paper focuses on the benefits that can be gained from a bottom hole pressure (BHP) surge/swab perspective. Specifically, how these undesirable pressure transients can be dramatically reduced by modifying the TTP from a start/stop (batch) process to a continuous tripping process (CTP), where drillpipe tripping speed is kept constant throughout the entire tripping sequence and thereby significantly reducing the numerous starts and stops associated with traditional tripping. In this paper both the TTP and CTP systems were kinematically modeled using a custom simulator coded in C#. It is important to note that all the equipment used in the modified CTP exists and has only been reconfigured to facilitate a continuous process. This is inclusive of real-life limits for such items as derrick height, traveling block (TB) height as well as velocity, acceleration and inertia limits for TB, crown blocks, drawworks, their associated reeving configurations as well as racking system arms, grippers, and latches. The simulation results indicates that for a continuous tripping system we can achieve a ~73% slower average pipe speed that has an overall tripping speed approximately 4 times faster than traditional tripping. CTP decreased BHP deviation significantly. The continuous tripping process was awarded a patent by USTPO in 2016, US 9,441.247 B2.
{"title":"Mitigating Surge and Swab by Changing Tripping from a Batch to a Continuous Process","authors":"Rick Pilgrim, S. Butt","doi":"10.2118/208923-ms","DOIUrl":"https://doi.org/10.2118/208923-ms","url":null,"abstract":"\u0000 A significant portion of the time required to drill an oilwell is spent moving the drillpipe in or out of the wellbore, called \"Tripping\". The drill crew must trip pipe for numerous reasons. These include changing the bit as it wears out, inserting new casing strings, cleaning and treating the drillpipe and/or wellbore to allow more efficient drilling, and to run in various tools that perform specific jobs required at certain times in the oilwell construction plan.\u0000 The traditional tripping process (TTP) inherently creates pressure transients developed from stopping and starting the vertical motion of the drillpipe during connections. These pressure transients called, \"Swapping\" and \"Surging\", contribute to borehole instability, restrict tripping speed, and increase non-productive time (NPT). This paper focuses on the benefits that can be gained from a bottom hole pressure (BHP) surge/swab perspective. Specifically, how these undesirable pressure transients can be dramatically reduced by modifying the TTP from a start/stop (batch) process to a continuous tripping process (CTP), where drillpipe tripping speed is kept constant throughout the entire tripping sequence and thereby significantly reducing the numerous starts and stops associated with traditional tripping.\u0000 In this paper both the TTP and CTP systems were kinematically modeled using a custom simulator coded in C#. It is important to note that all the equipment used in the modified CTP exists and has only been reconfigured to facilitate a continuous process. This is inclusive of real-life limits for such items as derrick height, traveling block (TB) height as well as velocity, acceleration and inertia limits for TB, crown blocks, drawworks, their associated reeving configurations as well as racking system arms, grippers, and latches.\u0000 The simulation results indicates that for a continuous tripping system we can achieve a ~73% slower average pipe speed that has an overall tripping speed approximately 4 times faster than traditional tripping. CTP decreased BHP deviation significantly. The continuous tripping process was awarded a patent by USTPO in 2016, US 9,441.247 B2.","PeriodicalId":11077,"journal":{"name":"Day 2 Thu, March 17, 2022","volume":"9 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79191286","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}
Advancements in digital technology and digitalization of industrial process have opened new frontiers for the oil and gas industry. The amount of historical data generated from drilled wells over the past decades of operations is currently being digitized and processed to provide operators with the option to make more informed decisions based on previous experiences that current staff may not be aware of due to the constant loss of experience during industry downturns. The industry is combating this loss of experience through the innovative use of digitalization, integrated operations, and automation. Real time support centers operating under integrated operations business model are now utilizing digital twins (high fidelity models of the ongoing process being supported) to run forecasting simulations and compare results to digitalized historical data with the help of artificial intelligence and expert systems to aid with decision making and training junior staff. The existence of high-fidelity models, and digital twins is a solid foundation for automation. In this paper a review of the emergence of these technologies is used to identify where digital twins can be used as the foundation of automation solutions that would shift the focus of drilling crews from efficiency to operation and process safety.
{"title":"Theoretical Development of a Digital-Twin Based Automation System for Oil Well Drilling Rigs","authors":"M. R. Md Said, Rick Pilgrim, G. Rideout, S. Butt","doi":"10.2118/208902-ms","DOIUrl":"https://doi.org/10.2118/208902-ms","url":null,"abstract":"\u0000 Advancements in digital technology and digitalization of industrial process have opened new frontiers for the oil and gas industry. The amount of historical data generated from drilled wells over the past decades of operations is currently being digitized and processed to provide operators with the option to make more informed decisions based on previous experiences that current staff may not be aware of due to the constant loss of experience during industry downturns. The industry is combating this loss of experience through the innovative use of digitalization, integrated operations, and automation. Real time support centers operating under integrated operations business model are now utilizing digital twins (high fidelity models of the ongoing process being supported) to run forecasting simulations and compare results to digitalized historical data with the help of artificial intelligence and expert systems to aid with decision making and training junior staff. The existence of high-fidelity models, and digital twins is a solid foundation for automation. In this paper a review of the emergence of these technologies is used to identify where digital twins can be used as the foundation of automation solutions that would shift the focus of drilling crews from efficiency to operation and process safety.","PeriodicalId":11077,"journal":{"name":"Day 2 Thu, March 17, 2022","volume":"2016 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87783736","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
This study provides new insights into hydraulic fracture growth during a Diagnostic Fracture Injection Test (DFIT) in the presence of mechanical heterogeneity in the overpressured Montney Formation in British Columbia. A novel continuum non-local poro-elastic-plastic model of a Stimulated Rock Volume (SRV) developed in the context of the Finite Element Method is used for analysis. It is shown that DFITs in the Montney Formation can generate substantial fracture network complexity. We provide insights on potential complex fracturing patterns and distributions at the well spacing scale. Additionally, the SRV tends to span and extend several meters away on each side of the induced fracture plane. We quantify the fracture tortuosity factor which appears to deviate significantly from unity, as in the cubic law. It is further demonstrated that the aperture within the SRV can significantly drop after shut-in before it reverts and begin to heal mechanically. We show that the onset of the aperture self-healing coincides with the time when the pressure during the fall-off period becomes equal to the final effective ISIP.
{"title":"Characterizing a Complex Induced Fracture Network: A Case Study of a Diagnostic Fracture Injection Test in the Heterogeneous Overpressured Montney Formation","authors":"E. Sarvaramini, M. Dusseault","doi":"10.2118/208937-ms","DOIUrl":"https://doi.org/10.2118/208937-ms","url":null,"abstract":"\u0000 This study provides new insights into hydraulic fracture growth during a Diagnostic Fracture Injection Test (DFIT) in the presence of mechanical heterogeneity in the overpressured Montney Formation in British Columbia. A novel continuum non-local poro-elastic-plastic model of a Stimulated Rock Volume (SRV) developed in the context of the Finite Element Method is used for analysis. It is shown that DFITs in the Montney Formation can generate substantial fracture network complexity. We provide insights on potential complex fracturing patterns and distributions at the well spacing scale. Additionally, the SRV tends to span and extend several meters away on each side of the induced fracture plane. We quantify the fracture tortuosity factor which appears to deviate significantly from unity, as in the cubic law. It is further demonstrated that the aperture within the SRV can significantly drop after shut-in before it reverts and begin to heal mechanically. We show that the onset of the aperture self-healing coincides with the time when the pressure during the fall-off period becomes equal to the final effective ISIP.","PeriodicalId":11077,"journal":{"name":"Day 2 Thu, March 17, 2022","volume":"28 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89341834","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}
Matthew J. Forshaw, Rafael A. Madeira, Pedro J. Arévalo
Tripping, the process whereby a string is moved in either axial direction makes up 30% of the well construction time and is therefore responsible for a significant portion of capital expenditure by operators. Typically, the focus in the industry in optimizing this segment of the operation has centered on minimizing the slips-to-slips connection time. This references the time taken to swing in and make-up, or breakout and rack-back a stand before engaging elevators to either run-in or pull-out with the next component. This required both human-process optimization through training and technological development of topside equipment, first in isolation and then through systems automation. This paper recognizes these optimization efforts but identifies additional potential to significantly reduce invisible-lost-time (ILT) during tripping operations even further by reducing out-of-slips running time in tripping operations, all while keeping wellbore pressures within the safe operating envelope. Physics-based steady-state fluid dynamics models have been in use for decades to define boundary conditions for these operations. These swab and surge calculations output a velocity limit for moving pipe. Models that are more complex have begun to diffuse into the commercial environment over the last decade and enhance borehole protection by providing a coupled acceleration limit. Acceleration and velocity are inherently linked so an optimization must be performed to arrive at the optimum velocity-time curve. In this paper we present real-time engineering simulations to create a digital twin of the downhole environment and calculate optimum tripping parameters for every stand. The parameters are then passed as set-points to automated rig control systems. The paper summarizes the physics-based modelling as well as the mathematical optimization. The system, including interfaces required to implement control in the context of drilling systems automation is also described. Field examples are presented whereby exposing actual real-time measurements and derived tripping boundary conditions in an intuitive, accessible user interface can lead to performance improvements. The ability to calculate the optimum velocity-time curve is the essential ingredient in gaining efficiency while out-of-slips during tripping operations, and simultaneously staying within a safe operating envelope. The resulting reduction in invisible-lost-time demonstrated, and associated reduction in rig time has obvious financial implications for operators and increasingly more important, helps achieve critical ESG targets. Finally, the paper will touch the need, and applicability of such technology in the energy transition new frontiers, specifically geothermal.
{"title":"Tripping Optimisation for Drilling Systems Automation: Potential of Digital Twins, Transient Models and Control Systems to Reduce Invisible Lost Time in Well Construction","authors":"Matthew J. Forshaw, Rafael A. Madeira, Pedro J. Arévalo","doi":"10.2118/208961-ms","DOIUrl":"https://doi.org/10.2118/208961-ms","url":null,"abstract":"\u0000 Tripping, the process whereby a string is moved in either axial direction makes up 30% of the well construction time and is therefore responsible for a significant portion of capital expenditure by operators. Typically, the focus in the industry in optimizing this segment of the operation has centered on minimizing the slips-to-slips connection time. This references the time taken to swing in and make-up, or breakout and rack-back a stand before engaging elevators to either run-in or pull-out with the next component. This required both human-process optimization through training and technological development of topside equipment, first in isolation and then through systems automation. This paper recognizes these optimization efforts but identifies additional potential to significantly reduce invisible-lost-time (ILT) during tripping operations even further by reducing out-of-slips running time in tripping operations, all while keeping wellbore pressures within the safe operating envelope.\u0000 Physics-based steady-state fluid dynamics models have been in use for decades to define boundary conditions for these operations. These swab and surge calculations output a velocity limit for moving pipe. Models that are more complex have begun to diffuse into the commercial environment over the last decade and enhance borehole protection by providing a coupled acceleration limit. Acceleration and velocity are inherently linked so an optimization must be performed to arrive at the optimum velocity-time curve.\u0000 In this paper we present real-time engineering simulations to create a digital twin of the downhole environment and calculate optimum tripping parameters for every stand. The parameters are then passed as set-points to automated rig control systems. The paper summarizes the physics-based modelling as well as the mathematical optimization. The system, including interfaces required to implement control in the context of drilling systems automation is also described. Field examples are presented whereby exposing actual real-time measurements and derived tripping boundary conditions in an intuitive, accessible user interface can lead to performance improvements.\u0000 The ability to calculate the optimum velocity-time curve is the essential ingredient in gaining efficiency while out-of-slips during tripping operations, and simultaneously staying within a safe operating envelope. The resulting reduction in invisible-lost-time demonstrated, and associated reduction in rig time has obvious financial implications for operators and increasingly more important, helps achieve critical ESG targets. Finally, the paper will touch the need, and applicability of such technology in the energy transition new frontiers, specifically geothermal.","PeriodicalId":11077,"journal":{"name":"Day 2 Thu, March 17, 2022","volume":"10 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"74762092","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. Chin, P. Miller, Darcy Redpath, Keane Dauncey, Daniel W. Nakaska, Farhan Alimahomed
Characterizing fracture geometry in unconventional reservoirs is essential to optimizing field development. Surveillance data is critical to understand how fractures propagate both vertically and laterally in any given formation. This paper is focused on low-cost, practical solutions to this problem, primarily Sealed Wellbore Pressure Monitoring (SWPM). SWPM is a novel technology recently developed by Devon Energy, which employs a sealed monitoring well to detect the arrival of hydraulic fractures from an adjacent treatment well via a pressure pulse. SWPM has recently been employed in unconventional plays in the U.S. This paper reports the results from its first application in Canada, in the Montney formation in British Columbia. SWPM data was collected from monitoring wells across four pads in the Montney, located in north-east B.C. The Montney consists of multiple stacked development targets, which emphasizes the importance of fracture characterization for optimal well placement and fracture design. Data collected from SWPM was compared with other diagnostics such as production interference testing, and fracture modeling. By integrating the information from these diagnostics, it is possible to better calibrate hydraulic fracture models and make better field development decisions earlier, with more confidence. This paper summarizes the key learnings, challenges, and limitations from the SWPM pilot. In terms of hydraulic fracture geometry, lateral fracture propagation was consistently very fast (long fracture lengths) in the Upper target; whereas in the Middle target, lateral fracture growth was shorter and fracture height growth was greater. This behavior was generally consistent with expectations based on the minimum horizontal stress profile and fracture modeling in the area. The SWPM data correlated reasonably well with production interference tests. A new metric (SWPM Intensity) was found to have the best relationship with the interference test data. This relationship is crucial as it links hydraulic fracture geometry to propped, flowing geometry. In conjunction with other diagnostics, early learnings from SWPM data have already provided significant value in informing field development decisions in the Montney. The novel SWPM Intensity metric provides an early indication of expected production interference between wells, and therefore an indication of how to balance completion intensity with well spacing. Moreover, by better understanding hydraulic fracture geometry and its relationship to propped geometry, completion designs and well spacing can be better customized by layer.
{"title":"Sealed Wellbore Pressure Monitoring in the Montney: Early Learnings","authors":"A. Chin, P. Miller, Darcy Redpath, Keane Dauncey, Daniel W. Nakaska, Farhan Alimahomed","doi":"10.2118/208921-ms","DOIUrl":"https://doi.org/10.2118/208921-ms","url":null,"abstract":"\u0000 Characterizing fracture geometry in unconventional reservoirs is essential to optimizing field development. Surveillance data is critical to understand how fractures propagate both vertically and laterally in any given formation. This paper is focused on low-cost, practical solutions to this problem, primarily Sealed Wellbore Pressure Monitoring (SWPM). SWPM is a novel technology recently developed by Devon Energy, which employs a sealed monitoring well to detect the arrival of hydraulic fractures from an adjacent treatment well via a pressure pulse. SWPM has recently been employed in unconventional plays in the U.S. This paper reports the results from its first application in Canada, in the Montney formation in British Columbia.\u0000 SWPM data was collected from monitoring wells across four pads in the Montney, located in north-east B.C. The Montney consists of multiple stacked development targets, which emphasizes the importance of fracture characterization for optimal well placement and fracture design. Data collected from SWPM was compared with other diagnostics such as production interference testing, and fracture modeling. By integrating the information from these diagnostics, it is possible to better calibrate hydraulic fracture models and make better field development decisions earlier, with more confidence.\u0000 This paper summarizes the key learnings, challenges, and limitations from the SWPM pilot. In terms of hydraulic fracture geometry, lateral fracture propagation was consistently very fast (long fracture lengths) in the Upper target; whereas in the Middle target, lateral fracture growth was shorter and fracture height growth was greater. This behavior was generally consistent with expectations based on the minimum horizontal stress profile and fracture modeling in the area. The SWPM data correlated reasonably well with production interference tests. A new metric (SWPM Intensity) was found to have the best relationship with the interference test data. This relationship is crucial as it links hydraulic fracture geometry to propped, flowing geometry.\u0000 In conjunction with other diagnostics, early learnings from SWPM data have already provided significant value in informing field development decisions in the Montney. The novel SWPM Intensity metric provides an early indication of expected production interference between wells, and therefore an indication of how to balance completion intensity with well spacing. Moreover, by better understanding hydraulic fracture geometry and its relationship to propped geometry, completion designs and well spacing can be better customized by layer.","PeriodicalId":11077,"journal":{"name":"Day 2 Thu, March 17, 2022","volume":"41 6 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83140621","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}
Physics-based and empirical rate-time models inherently assume constant bottomhole flowing pressure (BHP), an assumption that may not hold for many unconventional wells. Hence, applying these models without accounting for BHP variations might lead to inaccurate: (a) flow regime identification, (b) estimation of the parameters of these models, and (c) estimated ultimate recovery (EUR) and drainage volumes. This study evaluates and compares the predictions of rate-time relations including and ignoring corrections for time-varying BHP for both synthetic and shale gas wells. We generate a real gas synthetic case with errors in the time-varying BHP. First, we convert pressures into pseudopressures. Second, we deconvolve the pseudopressure history by applying the regularized exponential basis function inverse scheme to obtain an equivalent rate—the unit-pseudopressure-drop rate at standard conditions—at constant BHP. Third, we history-match the production using the scaled single-phase compressible fluid physics-based model for three different approaches: (a) using rate-time-pressure data with rate-pseudopressure deconvolution, (b) using rate-time-pressure data using just rate-pressure deconvolution, and (c) using only rate-time data. Finally, we compare the results in terms of their history-matches and estimated reservoir parameters. We conclude by illustrating the application of this procedure to shale gas wells. For the synthetic case, the fit of the single-phase compressible fluid rate-time model using rate-pseudopressure deconvolution can accurately estimate the original gas-in-place, characteristic time, gas permeability, and fracture half-length. In contrast, considerable errors are noted when either using rate-pressure deconvolution or failing to account for variable BHP. Regarding the shale gas examples, the rate-pseudopressure deconvolution scheme accurately identifies the flow regimes present in the well, which can be difficult to detect by only analyzing rate-time data. For this reason, the fits of the scaled single-phase compressible fluid model using only rate-time results in unreasonably large estimates of the reservoir parameters and EUR. In contrast, the application of rate-pseudopressure deconvolution constrains the fits of single-phase compressible fluid model yielding more realistic estimates of time of end of linear flow, and EUR. This paper illustrates the application of a workflow that accounts for variable BHP by estimating an equivalent constant unit-pseudopressure-drop gas rate (at standard conditions). We illustrate the workflow for a particular decline-curve model, but the workflow is general and can be applied to any rate-time model. The approach history matches and forecasts the production of unconventional gas reservoirs using rate-time models more accurately than assuming constant BHP.
{"title":"Rate-Pseudopressure Deconvolution Enhances Rate-Time Models Production History Matches and Forecasts of Shale Gas Wells","authors":"L. R. Ruiz Maraggi, L. Lake, M. P. Walsh","doi":"10.2118/208967-ms","DOIUrl":"https://doi.org/10.2118/208967-ms","url":null,"abstract":"\u0000 Physics-based and empirical rate-time models inherently assume constant bottomhole flowing pressure (BHP), an assumption that may not hold for many unconventional wells. Hence, applying these models without accounting for BHP variations might lead to inaccurate: (a) flow regime identification, (b) estimation of the parameters of these models, and (c) estimated ultimate recovery (EUR) and drainage volumes. This study evaluates and compares the predictions of rate-time relations including and ignoring corrections for time-varying BHP for both synthetic and shale gas wells.\u0000 We generate a real gas synthetic case with errors in the time-varying BHP. First, we convert pressures into pseudopressures. Second, we deconvolve the pseudopressure history by applying the regularized exponential basis function inverse scheme to obtain an equivalent rate—the unit-pseudopressure-drop rate at standard conditions—at constant BHP. Third, we history-match the production using the scaled single-phase compressible fluid physics-based model for three different approaches: (a) using rate-time-pressure data with rate-pseudopressure deconvolution, (b) using rate-time-pressure data using just rate-pressure deconvolution, and (c) using only rate-time data. Finally, we compare the results in terms of their history-matches and estimated reservoir parameters. We conclude by illustrating the application of this procedure to shale gas wells.\u0000 For the synthetic case, the fit of the single-phase compressible fluid rate-time model using rate-pseudopressure deconvolution can accurately estimate the original gas-in-place, characteristic time, gas permeability, and fracture half-length. In contrast, considerable errors are noted when either using rate-pressure deconvolution or failing to account for variable BHP. Regarding the shale gas examples, the rate-pseudopressure deconvolution scheme accurately identifies the flow regimes present in the well, which can be difficult to detect by only analyzing rate-time data. For this reason, the fits of the scaled single-phase compressible fluid model using only rate-time results in unreasonably large estimates of the reservoir parameters and EUR. In contrast, the application of rate-pseudopressure deconvolution constrains the fits of single-phase compressible fluid model yielding more realistic estimates of time of end of linear flow, and EUR.\u0000 This paper illustrates the application of a workflow that accounts for variable BHP by estimating an equivalent constant unit-pseudopressure-drop gas rate (at standard conditions). We illustrate the workflow for a particular decline-curve model, but the workflow is general and can be applied to any rate-time model. The approach history matches and forecasts the production of unconventional gas reservoirs using rate-time models more accurately than assuming constant BHP.","PeriodicalId":11077,"journal":{"name":"Day 2 Thu, March 17, 2022","volume":"7 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90853773","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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