Rodica Mihai, E. Cayeux, B. Daireaux, L. Carlsen, A. Ambrus, P. Simensen, Morten Welmer, Matthew Jackson
During recent years there has been an increased focus on automating drilling operations and several solutions are in daily use. We describe here results and lessons learned from testing on a full-scale test rig, the next step in drilling automation, namely autonomous drilling. By autonomous drilling we mean a system capable of taking its own decisions by evaluating the current conditions and adapting to them while considering multiple horizon strategies to fulfill the drilling operation goal. Autonomous drilling was demonstrated during a series of experiments at a full-scale test rig in Norway. The focus of the experiments was to reach the target depth as quickly and as safely as possible. Since the formation at the test rig is very hard, a previously drilled well was filled with weak cement of variable strengths to allow for fast drilling. As part of the experiments, it was planned to have drilling incidents to test the system capabilities in managing arising issues and recover from them. During the experiments no real-time downhole measurements were available, only surface data. In total 500 meters have been drilled in autonomous mode. The autonomous system is built as a hierarchical control system containing layers of protection for the machines, well and the commands, in addition to recovery procedures, optimization of the rate of penetration and autonomous decision-making. The system continuously evaluates the current situation and by balancing estimated risks and performance, e.g. risk of pack-off versus prognosed time to reach the target depth, decides the best action to perform next. The autonomous decision-making system is tightly connected with the control of the drilling machines and therefore it executes the necessary commands to follow up the computed decision. Drilling incidents may occur at any time and an autonomous system needs to be able to adapt to the current situation, such that it can manage drilling incidents by itself and recover from them, when possible. During the experiments, several drilling incidents occurred, and the system reacted as expected. Surface data, together with internally computed data from the autonomous decision-making algorithms, were logged during the experiments. Memory-based downhole data was available after the experiments were concluded. Based on all the data collected, an analysis of the behavior of the system was performed after the experiments. During the drilling experiments at the full-scale rig, the autonomous system adapted its decisions to the surrounding environment and tackled both smooth drilling situations and drilling incidents. To cope with possible lower situational awareness, the autonomous system manages by itself transitions from autonomous to manual mode if necessary. This feature, together with fault detection and isolation capabilities, are crucial for safe operation of an autonomous system.
{"title":"Demonstration of Autonomous Drilling on a Full-Scale Test Rig","authors":"Rodica Mihai, E. Cayeux, B. Daireaux, L. Carlsen, A. Ambrus, P. Simensen, Morten Welmer, Matthew Jackson","doi":"10.2118/210229-ms","DOIUrl":"https://doi.org/10.2118/210229-ms","url":null,"abstract":"\u0000 During recent years there has been an increased focus on automating drilling operations and several solutions are in daily use. We describe here results and lessons learned from testing on a full-scale test rig, the next step in drilling automation, namely autonomous drilling. By autonomous drilling we mean a system capable of taking its own decisions by evaluating the current conditions and adapting to them while considering multiple horizon strategies to fulfill the drilling operation goal.\u0000 Autonomous drilling was demonstrated during a series of experiments at a full-scale test rig in Norway. The focus of the experiments was to reach the target depth as quickly and as safely as possible. Since the formation at the test rig is very hard, a previously drilled well was filled with weak cement of variable strengths to allow for fast drilling. As part of the experiments, it was planned to have drilling incidents to test the system capabilities in managing arising issues and recover from them. During the experiments no real-time downhole measurements were available, only surface data.\u0000 In total 500 meters have been drilled in autonomous mode. The autonomous system is built as a hierarchical control system containing layers of protection for the machines, well and the commands, in addition to recovery procedures, optimization of the rate of penetration and autonomous decision-making. The system continuously evaluates the current situation and by balancing estimated risks and performance, e.g. risk of pack-off versus prognosed time to reach the target depth, decides the best action to perform next. The autonomous decision-making system is tightly connected with the control of the drilling machines and therefore it executes the necessary commands to follow up the computed decision. Drilling incidents may occur at any time and an autonomous system needs to be able to adapt to the current situation, such that it can manage drilling incidents by itself and recover from them, when possible. During the experiments, several drilling incidents occurred, and the system reacted as expected.\u0000 Surface data, together with internally computed data from the autonomous decision-making algorithms, were logged during the experiments. Memory-based downhole data was available after the experiments were concluded. Based on all the data collected, an analysis of the behavior of the system was performed after the experiments.\u0000 During the drilling experiments at the full-scale rig, the autonomous system adapted its decisions to the surrounding environment and tackled both smooth drilling situations and drilling incidents. To cope with possible lower situational awareness, the autonomous system manages by itself transitions from autonomous to manual mode if necessary. This feature, together with fault detection and isolation capabilities, are crucial for safe operation of an autonomous system.","PeriodicalId":113697,"journal":{"name":"Day 2 Tue, October 04, 2022","volume":"22 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-09-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"122303109","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 new and robust tracer technology is introduced based on encapsulated Nano-sized synthetic DNA. This cutting-edge technology enables bonding of synthetic DNA strands with unique sequences to a magnetic core particle and encapsulating them with silica making it possible to have unlimited number of identifiable tracers, each with a unique signature. Each manufactured batch of DNA tracer is then coated with a special chemical to make the batch water-wet or oil-wet. The presented novel technology of encapsulated Nano-sized DNA tracers is shown to be superior to the currently used water chemical tracers, fluorobenzoic acid or FBA, in many ways both in the applications of EOR and flowback analyses in hydraulic fracturing. Unlike the chemical tracers, the DNA tracers don't partition, don't chemically react with the formation minerology, don't disintegrate with time, are stable at high reservoir temperatures and don't lag flood front velocity if used in secondary recovery projects such as waterflooding. In addition, unlike the available limited number of chemical tracers, there are unlimited number of identifiable DNA tracers. In waterflooding, the DNA tracers are used to characterize fluid flow accurately and precisely in a reservoir and to identify heterogeneity of the reservoir. The technology can also be used to evaluate flowback analyses in hydraulic fracturing to fully understand fracture behavior, pipeline leakage identification, groundwater movement, contamination tracking in water streams, etc.
{"title":"Laboratory Investigation of Chemical Tracers vs. DNA Tracers","authors":"M. Asadi, Tyler Blair, Sarah Comstock","doi":"10.2118/209954-ms","DOIUrl":"https://doi.org/10.2118/209954-ms","url":null,"abstract":"\u0000 A new and robust tracer technology is introduced based on encapsulated Nano-sized synthetic DNA. This cutting-edge technology enables bonding of synthetic DNA strands with unique sequences to a magnetic core particle and encapsulating them with silica making it possible to have unlimited number of identifiable tracers, each with a unique signature. Each manufactured batch of DNA tracer is then coated with a special chemical to make the batch water-wet or oil-wet. The presented novel technology of encapsulated Nano-sized DNA tracers is shown to be superior to the currently used water chemical tracers, fluorobenzoic acid or FBA, in many ways both in the applications of EOR and flowback analyses in hydraulic fracturing. Unlike the chemical tracers, the DNA tracers don't partition, don't chemically react with the formation minerology, don't disintegrate with time, are stable at high reservoir temperatures and don't lag flood front velocity if used in secondary recovery projects such as waterflooding. In addition, unlike the available limited number of chemical tracers, there are unlimited number of identifiable DNA tracers. In waterflooding, the DNA tracers are used to characterize fluid flow accurately and precisely in a reservoir and to identify heterogeneity of the reservoir. The technology can also be used to evaluate flowback analyses in hydraulic fracturing to fully understand fracture behavior, pipeline leakage identification, groundwater movement, contamination tracking in water streams, etc.","PeriodicalId":113697,"journal":{"name":"Day 2 Tue, October 04, 2022","volume":"111 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-09-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"123970108","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}
Operators in the unconventional shale oil space are becoming increasingly focused on methods to reduce emissions, mitigate issues due to NGL production, increase sales oil production, and increase safety. Moreover, for facilities to operate unmanned facility designs are required to be simple and robust. Each facility configuration optimizes for a different utility: some allow more flexibility for the economic investment, while others offer familiarity of operation. The option that adds the most flexibility per dollar invested focuses on low-pressure separation with simultaneous heat introduction with minimum necessary storage tanks. Three different facilities are compared utilizing hydrocarbon recovery, NGL production, gas production, compression power, and Reid Vapor Pressure as key metrics. The three layouts include: a heater treater, a vapor recovery tower, and a novel elevated heated separation design that combines the utility of a heater treater and vapor recovery tower. The novel low-pressure stabilization system allows for stabilized oil to be pumped either to storage tanks or directly to the custody transfer point. Emissions stemming from tank vapor and tank vapor management systems are avoided as the oil is stabilized before entering the storage tanks or being transported directly to custody transfer. The novel system can be scaled for higher production rates seen at central processing facilities where traditional equipment such as heater treaters would require operating several parallel production trains. The novel design avoids known operational safety and maintenance issues regarding direct fired heaters and tanks; thus, improving safety and operational cost. Existing facilities designs include equipment such as direct fired heater treaters, inline heat exchangers, vapor recovery towers and tanks. The results from all process simulations and operational data is summarized in an overview comparing the performance of the various facility designs.
{"title":"What's the Best Way to Stabilize Oil in the Permian? An Examination of Different Facilities Layouts","authors":"I. Chan, S. Baaren, Anthony Sarcletti","doi":"10.2118/210446-ms","DOIUrl":"https://doi.org/10.2118/210446-ms","url":null,"abstract":"\u0000 Operators in the unconventional shale oil space are becoming increasingly focused on methods to reduce emissions, mitigate issues due to NGL production, increase sales oil production, and increase safety. Moreover, for facilities to operate unmanned facility designs are required to be simple and robust.\u0000 Each facility configuration optimizes for a different utility: some allow more flexibility for the economic investment, while others offer familiarity of operation. The option that adds the most flexibility per dollar invested focuses on low-pressure separation with simultaneous heat introduction with minimum necessary storage tanks.\u0000 Three different facilities are compared utilizing hydrocarbon recovery, NGL production, gas production, compression power, and Reid Vapor Pressure as key metrics. The three layouts include: a heater treater, a vapor recovery tower, and a novel elevated heated separation design that combines the utility of a heater treater and vapor recovery tower.\u0000 The novel low-pressure stabilization system allows for stabilized oil to be pumped either to storage tanks or directly to the custody transfer point. Emissions stemming from tank vapor and tank vapor management systems are avoided as the oil is stabilized before entering the storage tanks or being transported directly to custody transfer.\u0000 The novel system can be scaled for higher production rates seen at central processing facilities where traditional equipment such as heater treaters would require operating several parallel production trains. The novel design avoids known operational safety and maintenance issues regarding direct fired heaters and tanks; thus, improving safety and operational cost.\u0000 Existing facilities designs include equipment such as direct fired heater treaters, inline heat exchangers, vapor recovery towers and tanks. The results from all process simulations and operational data is summarized in an overview comparing the performance of the various facility designs.","PeriodicalId":113697,"journal":{"name":"Day 2 Tue, October 04, 2022","volume":"19 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-09-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"122117387","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}
Sadek Salim, Mayada Sayed, I. Abdo, Emad Abdel Hakim, M. Farouk, A. Hegazy, Abd El Moneim El Araby, Mohamed Ghanim, K. Saleh, Omar ElZahaby, Mariam Elnahrawi, A. ElKaragi
Gulf of Suez basin is one of the most complex areas of exploration that requires a fit-for-basin solution to reveal the true potential of the carbonate reservoirs. The multi-domain integration of the interpreted lithology from high-resolution imaging tools recorded in the open hole section with electrofacies integrated with NMR and cased hole elemental spectroscopy data provides the 1st time application to derive synthetic core with high-resolution facies in the drilled wells with complex heterogeneity challenges. 3D seismic attributes, stratigraphical and structural analysis, revealed a potential three-way dip closure with an expected high-quality carbonate reservoir. An automated processing workflow converts gamma-ray yields from the energy spectrum measured behind casing into the dry weight and mineral fractions. The computed mineralogical outputs are then described based on a standardized ternary diagram approach to generate dry-weight mineralogy-based lithofacies. The synthetic high-resolution lithofacies are integrated with MDT, NMR, and spectroscopy to capture mobility, type of fluid, and saturation associated with lithofacies changes which is integrated with well integrity analysis to plan, design, and execute of innovative technique for carbonate stimulation. This paper demonstrates reviving exploration activity in one of the brownfields and the first application for borehole imaging integrated with cased hole spectroscopy on the recent discovery well to select perforation. Once a robust lithofacies classification is obtained, this is used for detailed stratigraphic analysis, well to well correlation, cross-sections, mapping or refined static reservoir modeling, and perforation zones selection which represents the first success story for this innovative technique. This multi-domain integration helped to design a customized acidizing technique to reveal the true reservoir potential that had a 3 fold increase in productivity index compared to offset fields in the same basin. The workflow can be applied to multiple cases as a cost-effective solution in multiple scenarios and different formation types especially if there is no core available in old wells. Furthermore, the innovative acidizing technique can effectively stimulate any carbonate reservoir.
{"title":"Developing a Fit-For-Basin Novel Solution with the First Application of iCore Behind Cased Borehole in a Complex Heterogeneous Miocene Carbonate Reservoir: Bakr Oil Field, Central Province of Gulf of Suez","authors":"Sadek Salim, Mayada Sayed, I. Abdo, Emad Abdel Hakim, M. Farouk, A. Hegazy, Abd El Moneim El Araby, Mohamed Ghanim, K. Saleh, Omar ElZahaby, Mariam Elnahrawi, A. ElKaragi","doi":"10.2118/210230-ms","DOIUrl":"https://doi.org/10.2118/210230-ms","url":null,"abstract":"\u0000 Gulf of Suez basin is one of the most complex areas of exploration that requires a fit-for-basin solution to reveal the true potential of the carbonate reservoirs. The multi-domain integration of the interpreted lithology from high-resolution imaging tools recorded in the open hole section with electrofacies integrated with NMR and cased hole elemental spectroscopy data provides the 1st time application to derive synthetic core with high-resolution facies in the drilled wells with complex heterogeneity challenges. 3D seismic attributes, stratigraphical and structural analysis, revealed a potential three-way dip closure with an expected high-quality carbonate reservoir. An automated processing workflow converts gamma-ray yields from the energy spectrum measured behind casing into the dry weight and mineral fractions. The computed mineralogical outputs are then described based on a standardized ternary diagram approach to generate dry-weight mineralogy-based lithofacies. The synthetic high-resolution lithofacies are integrated with MDT, NMR, and spectroscopy to capture mobility, type of fluid, and saturation associated with lithofacies changes which is integrated with well integrity analysis to plan, design, and execute of innovative technique for carbonate stimulation.\u0000 This paper demonstrates reviving exploration activity in one of the brownfields and the first application for borehole imaging integrated with cased hole spectroscopy on the recent discovery well to select perforation. Once a robust lithofacies classification is obtained, this is used for detailed stratigraphic analysis, well to well correlation, cross-sections, mapping or refined static reservoir modeling, and perforation zones selection which represents the first success story for this innovative technique. This multi-domain integration helped to design a customized acidizing technique to reveal the true reservoir potential that had a 3 fold increase in productivity index compared to offset fields in the same basin.\u0000 The workflow can be applied to multiple cases as a cost-effective solution in multiple scenarios and different formation types especially if there is no core available in old wells. Furthermore, the innovative acidizing technique can effectively stimulate any carbonate reservoir.","PeriodicalId":113697,"journal":{"name":"Day 2 Tue, October 04, 2022","volume":"1 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-09-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"123091631","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}
Numerous wellbore instability problems have been reported when drilling through laminated shale formations because of anisotropic (weak) strength along bedding layers. The anisotropic strength is defined through the analysis of stress distributions around wellbore and angle of intersection (AOI) between well trajectory and weak bedding plane. This paper presents a method to calibrate a wellbore stability model, design mud weight and control breakout width based on analysis of AOI and anisotropic strength. The proposed method includes four (4) steps as follows:AOI is calculated by using bedding plane data (dip angle and dip azimuth) and well trajectory information (well inclination and azimuth).Based on single plane of weakness theory, the stress distributions around deviated wellbores in laminated shales are analyzed to show that failure can occur either along or across bedding planes depending on AOI.The profile of collapse pressure for both isotropic and anisotropic strength model are calculated along with the AOI.Drilling data (mud weight, cuttings/cavings pictures etc.) combined with azimuthal density image are used to choose and calibrate the wellbore stability model. Lab strength test results with different angle to bedding plane are used to calibrate rock strength model and field data are collected and analyzed to define acceptable breakout width. Field data demonstrates that AOI can have a significant effect on wellbore stability. It is observed that severe borehole problems occurred in hole sections with low AOI (<30°) especially when a low mud weight is used to allow a wider breakout. Minor wellbore instability still occurred in some hole sections with low AOI even when the zero breakout criteria was used for mud weight selection. The instability observed can be attributed to swab – decreased ESDs being exerted on the formation while pulling the bottom-hole-assembly out of the hole and time-dependent effect. The ‘zero breakout width’ criterion is recommended for AOI less than 30°, the ‘(90°-Inclination) breakout width’ criterion for AOI between 30° and 60°, and the ‘(90°-2/3*Inclination) breakout width’ criteria for AOI greater than 60°. If the mud weight window permits, then it would be beneficial to increase the mud weight by an extra 0.2 ppg to cover swab effects in shale formations that have an extremely low AOI (<15°). If not, mechanical means to prevent hydrostatic pressure drops such as slower pipe reciprocation or managed pressure drilling (MPD) need consideration.
{"title":"Design Mud Weight and Control Breakout Width Based on Angle of Intersection Analysis","authors":"Jianguo Zhang, Stephen Edwards","doi":"10.2118/210135-ms","DOIUrl":"https://doi.org/10.2118/210135-ms","url":null,"abstract":"\u0000 Numerous wellbore instability problems have been reported when drilling through laminated shale formations because of anisotropic (weak) strength along bedding layers. The anisotropic strength is defined through the analysis of stress distributions around wellbore and angle of intersection (AOI) between well trajectory and weak bedding plane.\u0000 This paper presents a method to calibrate a wellbore stability model, design mud weight and control breakout width based on analysis of AOI and anisotropic strength. The proposed method includes four (4) steps as follows:AOI is calculated by using bedding plane data (dip angle and dip azimuth) and well trajectory information (well inclination and azimuth).Based on single plane of weakness theory, the stress distributions around deviated wellbores in laminated shales are analyzed to show that failure can occur either along or across bedding planes depending on AOI.The profile of collapse pressure for both isotropic and anisotropic strength model are calculated along with the AOI.Drilling data (mud weight, cuttings/cavings pictures etc.) combined with azimuthal density image are used to choose and calibrate the wellbore stability model.\u0000 Lab strength test results with different angle to bedding plane are used to calibrate rock strength model and field data are collected and analyzed to define acceptable breakout width. Field data demonstrates that AOI can have a significant effect on wellbore stability. It is observed that severe borehole problems occurred in hole sections with low AOI (<30°) especially when a low mud weight is used to allow a wider breakout. Minor wellbore instability still occurred in some hole sections with low AOI even when the zero breakout criteria was used for mud weight selection. The instability observed can be attributed to swab – decreased ESDs being exerted on the formation while pulling the bottom-hole-assembly out of the hole and time-dependent effect.\u0000 The ‘zero breakout width’ criterion is recommended for AOI less than 30°, the ‘(90°-Inclination) breakout width’ criterion for AOI between 30° and 60°, and the ‘(90°-2/3*Inclination) breakout width’ criteria for AOI greater than 60°. If the mud weight window permits, then it would be beneficial to increase the mud weight by an extra 0.2 ppg to cover swab effects in shale formations that have an extremely low AOI (<15°). If not, mechanical means to prevent hydrostatic pressure drops such as slower pipe reciprocation or managed pressure drilling (MPD) need consideration.","PeriodicalId":113697,"journal":{"name":"Day 2 Tue, October 04, 2022","volume":"27 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-09-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"122526205","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}
Aditi Chakrabarti, Mathieu Dauphin, A. Andrews, Lukasz Zielinski, K. Rashid, J. Yuan, A. Speck, Adam Huynh, Justin Power, Vincent Nicolas, Raphael Gadot
Large methane emissions occur from a wide variety of sites with no discernable patterns thus requiring methodologies to frequently monitor for these releases throughout the entire production chain. To cost-effectively monitor widely dispersed well pads, we describe a continuous monitoring system based on the Internet of Things (IoT) to leverage cost-optimized methane concentration sensors permanently deployed at facilities and connected to a cloud-based interpretation platform. Testing at controlled methane release facilities enabled the validation of the sensor performance; fidelity of the atmospheric dispersion modeling underlying our interpretation; and the overall system performance in detecting, localizing, and quantifying methane releases.
{"title":"Rapid Detection of Super-Emitters Utilizing an IoT-Enabled Continuous Methane Emissions Monitoring System","authors":"Aditi Chakrabarti, Mathieu Dauphin, A. Andrews, Lukasz Zielinski, K. Rashid, J. Yuan, A. Speck, Adam Huynh, Justin Power, Vincent Nicolas, Raphael Gadot","doi":"10.2118/210464-ms","DOIUrl":"https://doi.org/10.2118/210464-ms","url":null,"abstract":"\u0000 Large methane emissions occur from a wide variety of sites with no discernable patterns thus requiring methodologies to frequently monitor for these releases throughout the entire production chain. To cost-effectively monitor widely dispersed well pads, we describe a continuous monitoring system based on the Internet of Things (IoT) to leverage cost-optimized methane concentration sensors permanently deployed at facilities and connected to a cloud-based interpretation platform. Testing at controlled methane release facilities enabled the validation of the sensor performance; fidelity of the atmospheric dispersion modeling underlying our interpretation; and the overall system performance in detecting, localizing, and quantifying methane releases.","PeriodicalId":113697,"journal":{"name":"Day 2 Tue, October 04, 2022","volume":"580 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-09-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"122936046","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
This paper is a continuation of the work presented in URTeC 3718584 (Carlsen & Whitson, 2022), and focuses on practical usage of ‘fractional RTA’ theory when applied to both simulated data and field data from the SPE data repository. Most of the theory presented in Part 1 is kept for completeness. An inherent assumption in most industry RTA is equally spaced fractures. However, as shown in several field studies (Raterman 2017, Gale 2018), the distance between individual fractures tends to be unevenly spaced along the wellbore (e.g., "fracture swarms"). In this paper, we extend the original numerical RTA workflow proposed by Bowie and Ewert (2020) to account for uneven fracture spacing. Acuna's (2016, 2020) heterogeneity parameter, delta (δ), is introduced to generalize the linear flow parameter (LFP) to account for complex fracture systems (LFP’ = Akδϕ1-δ = 4nfhxfkδϕ1-δ). For evenly spaced fractures, δ = 0.5, simplifying LFP’ to the familiar LFP = A√k = 4nfhxf√k. For uneven fracture systems, 0 ≤ δ ≤ 0.5. With known (a) well geometry, (b) fluid initialization (PVT and water saturation), (c) relative permeability relations, and (d) bottomhole pressure (BHP) time variation (above and below saturation pressure), three fundamental relationships exist in terms of LFP' and OOIP. Numerical reservoir simulation is used to define these relationships, providing the foundation for numerical RTA, also wells with complex fracture systems. Namely, that wells: (1) with the same value of LFP', the gas, oil and water surface rates will be identical during infinite-acting (IA) behavior; (2) with the same ratio LFP'/OOIP, producing GOR and water cut behavior will be identical for all times, IA and boundary dominated (BD); and (3) with the same values of LFP' and OOIP, rate performance of gas, oil, and water will be identical for all times, IA and BD. These observations lead to an efficient, semi-automated process to perform rigorous RTA, assisted by a symmetry element numerical model. The numerical RTA workflow proposed by Bowie and Ewert solves the inherent problems associated with complex superposition and multiphase flow effects involving time and spatial changes in pressure, compositions and PVT properties, saturations, and complex phase mobilities. This paper extends the approach to complex fracture systems that can be described by the Acuna parameter δ. Numerical RTA workflow decouples multiphase flow data (PVT, initial saturations and relative permeabilities) from well geometry and petrophysical properties (L, xf, h, nf, φ, k, δ), providing a rigorous yet efficient and semi-automated approach to define production performance for many wells. Contributions include a technical framework to perform numerical RTA for unconventional wells, irrespective of fracture spacing. Semi-analytical models, time, and spatial superposition (convolution), pseudopressure and pseudotime transforms are not required.
{"title":"Numerical RTA Extended to Complex Fracture Systems: Part 2","authors":"Carlsen Mathias Lia, Whitson Curtis Hays","doi":"10.2118/210420-ms","DOIUrl":"https://doi.org/10.2118/210420-ms","url":null,"abstract":"\u0000 This paper is a continuation of the work presented in URTeC 3718584 (Carlsen & Whitson, 2022), and focuses on practical usage of ‘fractional RTA’ theory when applied to both simulated data and field data from the SPE data repository. Most of the theory presented in Part 1 is kept for completeness.\u0000 An inherent assumption in most industry RTA is equally spaced fractures. However, as shown in several field studies (Raterman 2017, Gale 2018), the distance between individual fractures tends to be unevenly spaced along the wellbore (e.g., \"fracture swarms\"). In this paper, we extend the original numerical RTA workflow proposed by Bowie and Ewert (2020) to account for uneven fracture spacing.\u0000 Acuna's (2016, 2020) heterogeneity parameter, delta (δ), is introduced to generalize the linear flow parameter (LFP) to account for complex fracture systems (LFP’ = Akδϕ1-δ = 4nfhxfkδϕ1-δ). For evenly spaced fractures, δ = 0.5, simplifying LFP’ to the familiar LFP = A√k = 4nfhxf√k. For uneven fracture systems, 0 ≤ δ ≤ 0.5.\u0000 With known (a) well geometry, (b) fluid initialization (PVT and water saturation), (c) relative permeability relations, and (d) bottomhole pressure (BHP) time variation (above and below saturation pressure), three fundamental relationships exist in terms of LFP' and OOIP. Numerical reservoir simulation is used to define these relationships, providing the foundation for numerical RTA, also wells with complex fracture systems. Namely, that wells: (1) with the same value of LFP', the gas, oil and water surface rates will be identical during infinite-acting (IA) behavior; (2) with the same ratio LFP'/OOIP, producing GOR and water cut behavior will be identical for all times, IA and boundary dominated (BD); and (3) with the same values of LFP' and OOIP, rate performance of gas, oil, and water will be identical for all times, IA and BD. These observations lead to an efficient, semi-automated process to perform rigorous RTA, assisted by a symmetry element numerical model.\u0000 The numerical RTA workflow proposed by Bowie and Ewert solves the inherent problems associated with complex superposition and multiphase flow effects involving time and spatial changes in pressure, compositions and PVT properties, saturations, and complex phase mobilities. This paper extends the approach to complex fracture systems that can be described by the Acuna parameter δ.\u0000 Numerical RTA workflow decouples multiphase flow data (PVT, initial saturations and relative permeabilities) from well geometry and petrophysical properties (L, xf, h, nf, φ, k, δ), providing a rigorous yet efficient and semi-automated approach to define production performance for many wells. Contributions include a technical framework to perform numerical RTA for unconventional wells, irrespective of fracture spacing. Semi-analytical models, time, and spatial superposition (convolution), pseudopressure and pseudotime transforms are not required.","PeriodicalId":113697,"journal":{"name":"Day 2 Tue, October 04, 2022","volume":"94 4 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-09-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"125979376","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 Petroleum Resources Management System (PRMS) (PRMS, 2018) and many regulatory agencies (e.g. US Securities and Exchange Commission – US SEC) require "Reasonable Certainty" for Proved Reserves estimates. The PRMS states that Reasonable Certainty can be demonstrated by use of "definitive geoscience, engineering, or performance data", while the SEC allows the application of reliable technology which they define as a "grouping of one or more technologies (including computational methods) that has been field tested to provide reasonably certain results with consistency and repeatability" (US Code of Federal Regulations § 210.4-10). The guidance provided by the PRMS or SEC for establishing reasonable certainty is general in nature due to the difficulty in explicitly describing all possible scenarios and also allows leeway to use new technologies in the future. In this context, we see the need for more discussion on how a reasonably certain case can be developed utilizing multiple technologies. Reserves estimates are snapshots in time based on the integration of the best data, analysis and forecasts available. Proper application of reliable technologies with all available data can help to refine the uncertainty ranges of reserves. We demonstrate how an overall reasonably certain estimate can be established by utilizing multiple reliable technologies even when each technology individually may not be sufficient to establish reasonable certainty. This approach can also guide how future performance data can be integrated to refine uncertainty ranges. This paper addresses the complex challenge of establishing reasonable certainty in reserves and resource assessments. The paper discusses how multiple reliable technologies may be used in concert to establish reasonable certainty for reserves estimates through the flexibility provided by the PRMS. We share our experiences with establishing reliability based on quality of data and reservoir complexity. The practical discussions in this paper will benefit subsurface teams and reserves estimators across the industry.
石油资源管理系统(PRMS) (PRMS, 2018)和许多监管机构(如美国证券交易委员会- US SEC)要求对探明储量估算具有“合理的确定性”。PRMS指出，合理的确定性可以通过使用“明确的地球科学、工程或性能数据”来证明，而SEC允许应用可靠的技术，他们将其定义为“一种或多种技术(包括计算方法)的分组，这些技术已经过现场测试，可以提供具有一致性和可重复性的合理确定的结果”(美国联邦法规第210.4-10条)。由于难以明确描述所有可能的情况，PRMS或SEC为建立合理确定性提供的指导本质上是一般性的，并且也允许在未来使用新技术。在这种情况下，我们认为有必要更多地讨论如何利用多种技术开发合理确定的案例。储量估计是在综合最佳数据、分析和预测的基础上及时得出的结论。利用所有现有数据适当应用可靠技术可以帮助确定储量的不确定范围。我们演示了如何通过利用多种可靠的技术来建立一个整体的合理确定的估计，即使每种技术单独可能不足以建立合理的确定性。这种方法还可以指导如何整合未来的性能数据以细化不确定性范围。本文解决了在储量和资源评估中建立合理确定性的复杂挑战。本文讨论了如何通过PRMS提供的灵活性，协同使用多种可靠技术来建立储量估计的合理确定性。我们分享了基于数据质量和油藏复杂性建立可靠性的经验。本文中的实际讨论将使整个行业的地下团队和储量估算人员受益。
{"title":"Establishing Reasonable Certainty for Reserves Estimates by Utilizing a Combination of Reliable Technologies","authors":"K. Narayanan, Peter Gale, J. Blangy, E. Young","doi":"10.2118/210358-ms","DOIUrl":"https://doi.org/10.2118/210358-ms","url":null,"abstract":"\u0000 The Petroleum Resources Management System (PRMS) (PRMS, 2018) and many regulatory agencies (e.g. US Securities and Exchange Commission – US SEC) require \"Reasonable Certainty\" for Proved Reserves estimates. The PRMS states that Reasonable Certainty can be demonstrated by use of \"definitive geoscience, engineering, or performance data\", while the SEC allows the application of reliable technology which they define as a \"grouping of one or more technologies (including computational methods) that has been field tested to provide reasonably certain results with consistency and repeatability\" (US Code of Federal Regulations § 210.4-10). The guidance provided by the PRMS or SEC for establishing reasonable certainty is general in nature due to the difficulty in explicitly describing all possible scenarios and also allows leeway to use new technologies in the future. In this context, we see the need for more discussion on how a reasonably certain case can be developed utilizing multiple technologies.\u0000 Reserves estimates are snapshots in time based on the integration of the best data, analysis and forecasts available. Proper application of reliable technologies with all available data can help to refine the uncertainty ranges of reserves. We demonstrate how an overall reasonably certain estimate can be established by utilizing multiple reliable technologies even when each technology individually may not be sufficient to establish reasonable certainty. This approach can also guide how future performance data can be integrated to refine uncertainty ranges.\u0000 This paper addresses the complex challenge of establishing reasonable certainty in reserves and resource assessments. The paper discusses how multiple reliable technologies may be used in concert to establish reasonable certainty for reserves estimates through the flexibility provided by the PRMS. We share our experiences with establishing reliability based on quality of data and reservoir complexity. The practical discussions in this paper will benefit subsurface teams and reserves estimators across the industry.","PeriodicalId":113697,"journal":{"name":"Day 2 Tue, October 04, 2022","volume":"39 6","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-09-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"132767377","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 recent decades, a remarkable increase in induced seismicity in the Western Canada Sedimentary Basin (WCSB) has been largely attributed to the hydraulic fracturing (HF) operations in unconventional plays. However, a mitigation strategy concerning geological, geomechanical, and operational susceptibilities to HF-induced seismicity has not been well understood. In this work, an integrated method is proposed to mitigate potential risks from HF-induced seismicity in the Duvernay play near Crooked Lake. The geological susceptibility to induced seismicity is evaluated first from site-specific formation pressure, a distance to the Precambrian Basement, and the existence of pre-existing faults. The regional in-situ stress and rock mechanics are then assessed to determine the geomechanical susceptibility to induced seismicity. Next, the operational susceptibility is determined by comparing induced seismicity with operational parameters such as total injection fluids and proppant mass. Finally, a multiple linear regression (MLR)-based approach is proposed by considering the feature importance of different parameters. It is found that regions with a low formation pressure (<60MPa), a great distance to the Precambrian Basement (>260m), a low minimum principal stress (<70MPa), and a low brittleness index (<0.62) tend to be seismicity-quiescent regions. Three new horizontal wells are drilled and fractured to validate the applicability of our MLR-based approach. High-resolution monitoring results indicated that 95% of the induced events had a magnitude of less than 2.0 during and after HF operations (three-month time window and five-kilometer well-event distance), among which the maximum magnitude reached M3.05 (
{"title":"An Integrated Method to Mitigate Hazards from Hydraulic Fracturing-Induced Earthquakes in the Duvernay Shale Play","authors":"Gang Hui, F. Gu","doi":"10.2118/210287-ms","DOIUrl":"https://doi.org/10.2118/210287-ms","url":null,"abstract":"\u0000 In recent decades, a remarkable increase in induced seismicity in the Western Canada Sedimentary Basin (WCSB) has been largely attributed to the hydraulic fracturing (HF) operations in unconventional plays. However, a mitigation strategy concerning geological, geomechanical, and operational susceptibilities to HF-induced seismicity has not been well understood. In this work, an integrated method is proposed to mitigate potential risks from HF-induced seismicity in the Duvernay play near Crooked Lake. The geological susceptibility to induced seismicity is evaluated first from site-specific formation pressure, a distance to the Precambrian Basement, and the existence of pre-existing faults. The regional in-situ stress and rock mechanics are then assessed to determine the geomechanical susceptibility to induced seismicity. Next, the operational susceptibility is determined by comparing induced seismicity with operational parameters such as total injection fluids and proppant mass. Finally, a multiple linear regression (MLR)-based approach is proposed by considering the feature importance of different parameters. It is found that regions with a low formation pressure (<60MPa), a great distance to the Precambrian Basement (>260m), a low minimum principal stress (<70MPa), and a low brittleness index (<0.62) tend to be seismicity-quiescent regions. Three new horizontal wells are drilled and fractured to validate the applicability of our MLR-based approach. High-resolution monitoring results indicated that 95% of the induced events had a magnitude of less than 2.0 during and after HF operations (three-month time window and five-kilometer well-event distance), among which the maximum magnitude reached M3.05 (<red light magnitude M4.0). Therefore, the MLR-based approach was successful in mitigating potential seismicity risks, which can be applied to other regions to guide seismicity-free fracturing operations in unconventional plays.","PeriodicalId":113697,"journal":{"name":"Day 2 Tue, October 04, 2022","volume":"47 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-09-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"134296821","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}
H. Kumar, T. Bhinde, A. Popa, David Hopkinson, R. de Neufville
Unconventional oil and gas projects are long-term, capital-intensive investments with significant risks due to various unknowns. The main uncertainties include reserves, reservoir quality, expected production, and commodity prices. Operating companies need to make decisions at the start of the project to design wells/facilities that impact production and economics throughout the project life. The system may be severely constrained at the start of production and have excess capacity in late field life based on design decisions often taken at the beginning with limited information. A novel approach to improve economic returns from shale pads is presented here using a flexible design concept. A physics-based integrated model is coupled with an economics model to demonstrate the system via a field example from the Appalachian Basin. A typical pad in Appalachia has fixed capacity gas processing units (GPUs) installed for each well. The current design does not allow for expansion or reduction of processing capacity if the reservoir quality or commodity prices are different from expectations. A flexible design allows operators to redeploy processing capacity to other pads under favorable technical and market conditions (reservoir conditions and product prices), thus, decreasing average costs and increasing profitability. An integration platform was used to couple an economic model with a physics-based integrated production model consisting of a pad's reservoir, well and surface network. The coupled models were used to generate short-term forecasts (2-3 years). Scenarios were run on the integrated model based on defined uncertainties such as reservoir characteristics and economics. We evaluated two flexible options, rental GPU and in-house GPU augmentation which were compared with the current fixed design. The results demonstrate that flexible designs result in higher (>5%) net present values (NPVs) for the project compared to fixed designs. Also, the flexible designs reduce the economic risk if the future market and operating conditions turn out to be unfavorable.
{"title":"A Flexible Design Approach to Improve Economics of Shale Well Pads: A Case Study from the Appalachian Basin","authors":"H. Kumar, T. Bhinde, A. Popa, David Hopkinson, R. de Neufville","doi":"10.2118/210087-ms","DOIUrl":"https://doi.org/10.2118/210087-ms","url":null,"abstract":"\u0000 Unconventional oil and gas projects are long-term, capital-intensive investments with significant risks due to various unknowns. The main uncertainties include reserves, reservoir quality, expected production, and commodity prices. Operating companies need to make decisions at the start of the project to design wells/facilities that impact production and economics throughout the project life. The system may be severely constrained at the start of production and have excess capacity in late field life based on design decisions often taken at the beginning with limited information. A novel approach to improve economic returns from shale pads is presented here using a flexible design concept. A physics-based integrated model is coupled with an economics model to demonstrate the system via a field example from the Appalachian Basin.\u0000 A typical pad in Appalachia has fixed capacity gas processing units (GPUs) installed for each well. The current design does not allow for expansion or reduction of processing capacity if the reservoir quality or commodity prices are different from expectations. A flexible design allows operators to redeploy processing capacity to other pads under favorable technical and market conditions (reservoir conditions and product prices), thus, decreasing average costs and increasing profitability.\u0000 An integration platform was used to couple an economic model with a physics-based integrated production model consisting of a pad's reservoir, well and surface network. The coupled models were used to generate short-term forecasts (2-3 years). Scenarios were run on the integrated model based on defined uncertainties such as reservoir characteristics and economics.\u0000 We evaluated two flexible options, rental GPU and in-house GPU augmentation which were compared with the current fixed design. The results demonstrate that flexible designs result in higher (>5%) net present values (NPVs) for the project compared to fixed designs. Also, the flexible designs reduce the economic risk if the future market and operating conditions turn out to be unfavorable.","PeriodicalId":113697,"journal":{"name":"Day 2 Tue, October 04, 2022","volume":"50 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-09-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"133065038","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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