M. Pickarts, J. Delgado-Linares, E. Brown, V. Veedu, C. Koh
Numerous solids including gas hydrates, waxes, and asphaltenes have the potential to form in the production lines of gas and oil fields. This creates a highly non-ideal scenario as the accumulation of said species leads to flow assurance issues, especially with long-term processes like deposition. Since an ever-increasing amount of material is deposited in place at the pipe surface, production stoppage or active mitigation efforts become inevitable. The latter production issues result in increased safety risks and operational expenditures. Therefore, a cost-effective, passive deposition mitigation technology, such as a pipeline coating or surface treatment is especially appealing. The ability to address multiple pipeline flow assurance issues simultaneously without actively disrupting production would represent a dramatic step forward in this area. This study is part of a long-term ongoing effort that evaluates the performance and application of an omniphobic surface treatment for solids deposition prevention in industrially relevant systems. In particular, this specific work concentrates on the efficacy and robustness of the treatment under fully flowing conditions. The apparatuses utilized for this include two flowloops: a lab-scale, high-pressure flowloop for gas hydrate and surface treatment durability studies, and a bench-scale, atmospheric pressure loop for crude oil and asphaltene experiments. Film growth in high-pressure flowloop tests corroborated previous reports of delayed gas hydrate nucleation observed in rocking cells. Without the aid of the memory effect, treated oil-dominated experiments never experienced hydrate formation, spending upwards of a week in the hydrate stability zone (at the subcooled/fluid test conditions). Subsequent tests which utilized the memory effect then revealed that the hydrate formation rate reduced in the presence of the surface treatment compared to a bare stainless-steel surface. This testing was part of a larger set of trials conducted in the flowloop, which lasted about one year. The surface treatment durability under flowing conditions was evaluated during this time. Even after experiencing ∼4000 operating hours and 2 full pressure cycles, no evidence of delamination or damage was detected. Finally, as part of an extension to previous work, corroded surface asphaltene deposition experiments were performed in a bench-top flowloop. Treated experiments displayed an order of magnitude reduction in both total oil (all fractions of crude oil) and asphaltene fraction deposited.
{"title":"Surface Treatment Strategies for Mitigating Gas Hydrate & Asphaltene Formation, Growth, and Deposition in Flowloops","authors":"M. Pickarts, J. Delgado-Linares, E. Brown, V. Veedu, C. Koh","doi":"10.4043/31189-ms","DOIUrl":"https://doi.org/10.4043/31189-ms","url":null,"abstract":"\u0000 Numerous solids including gas hydrates, waxes, and asphaltenes have the potential to form in the production lines of gas and oil fields. This creates a highly non-ideal scenario as the accumulation of said species leads to flow assurance issues, especially with long-term processes like deposition. Since an ever-increasing amount of material is deposited in place at the pipe surface, production stoppage or active mitigation efforts become inevitable. The latter production issues result in increased safety risks and operational expenditures. Therefore, a cost-effective, passive deposition mitigation technology, such as a pipeline coating or surface treatment is especially appealing. The ability to address multiple pipeline flow assurance issues simultaneously without actively disrupting production would represent a dramatic step forward in this area.\u0000 This study is part of a long-term ongoing effort that evaluates the performance and application of an omniphobic surface treatment for solids deposition prevention in industrially relevant systems. In particular, this specific work concentrates on the efficacy and robustness of the treatment under fully flowing conditions. The apparatuses utilized for this include two flowloops: a lab-scale, high-pressure flowloop for gas hydrate and surface treatment durability studies, and a bench-scale, atmospheric pressure loop for crude oil and asphaltene experiments.\u0000 Film growth in high-pressure flowloop tests corroborated previous reports of delayed gas hydrate nucleation observed in rocking cells. Without the aid of the memory effect, treated oil-dominated experiments never experienced hydrate formation, spending upwards of a week in the hydrate stability zone (at the subcooled/fluid test conditions). Subsequent tests which utilized the memory effect then revealed that the hydrate formation rate reduced in the presence of the surface treatment compared to a bare stainless-steel surface. This testing was part of a larger set of trials conducted in the flowloop, which lasted about one year. The surface treatment durability under flowing conditions was evaluated during this time. Even after experiencing ∼4000 operating hours and 2 full pressure cycles, no evidence of delamination or damage was detected. Finally, as part of an extension to previous work, corroded surface asphaltene deposition experiments were performed in a bench-top flowloop. Treated experiments displayed an order of magnitude reduction in both total oil (all fractions of crude oil) and asphaltene fraction deposited.","PeriodicalId":11072,"journal":{"name":"Day 1 Mon, August 16, 2021","volume":"4 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-08-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87269115","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 deepwater and ultra-deepwater wells, hydraulic debris removal, or the circulating of debris to surface, serves as the primary method of removing debris from the wellbore during the displacement of drilling fluid to completion fluid. In a standard cased hole completion, this operation typically takes place after the last liner has been set and before the completion is run. The likelihood of successful hydraulic debris removal is dependent on many factors such as debris particle size and density, flow rates and the resulting average annular velocity in the annulus, pipe movement, and the properties of the fluids circulated in the well. Mechanical debris extraction tools such as downhole filters and magnets are used to capture significant amounts of debris that are unable to be hydraulically removed from the wellbore. Versions of downhole filters and magnets that are run inside of casing and magnets run inside of the riser are common across the industry, however downhole filter tools run in the riser are less common and their use in these operations is not an industry standard. This paper examines a data set generated over two years containing more than 30 runs that include the use of a downhole filter tool run in the riser during wellbore clean out operations.
{"title":"Debris Capture Distribution in Deepwater Wells with Riser Filter Tool","authors":"Peter Reid Maher","doi":"10.4043/31050-ms","DOIUrl":"https://doi.org/10.4043/31050-ms","url":null,"abstract":"\u0000 In deepwater and ultra-deepwater wells, hydraulic debris removal, or the circulating of debris to surface, serves as the primary method of removing debris from the wellbore during the displacement of drilling fluid to completion fluid. In a standard cased hole completion, this operation typically takes place after the last liner has been set and before the completion is run. The likelihood of successful hydraulic debris removal is dependent on many factors such as debris particle size and density, flow rates and the resulting average annular velocity in the annulus, pipe movement, and the properties of the fluids circulated in the well. Mechanical debris extraction tools such as downhole filters and magnets are used to capture significant amounts of debris that are unable to be hydraulically removed from the wellbore. Versions of downhole filters and magnets that are run inside of casing and magnets run inside of the riser are common across the industry, however downhole filter tools run in the riser are less common and their use in these operations is not an industry standard. This paper examines a data set generated over two years containing more than 30 runs that include the use of a downhole filter tool run in the riser during wellbore clean out operations.","PeriodicalId":11072,"journal":{"name":"Day 1 Mon, August 16, 2021","volume":"142 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-08-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"85369552","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}
C. Temizel, C. H. Canbaz, Karthik Balaji, Ahsen Ozesen, Kirill Yanidis, Hasanain Alsaheib, Nouf Alsulaiman, Mustafa A. Basri, Nayif Jama
Machine learning models have worked as a robust tool in forecasting and optimization processes for wells in conventional, data-rich reservoirs. In unconventional reservoirs however, given the large ranges of uncertainty, purely data-driven, machine learning models have not yet proven to be repeatable and scalable. In such cases, integrating physics-based reservoir simulation methods along with machine learning techniques can be used as a solution to alleviate these limitations. The objective of this study is to provide an overview along with examples of implementing this integrated approach for the purpose of forecasting Estimated Ultimate Recovery (EUR) in shale reservoirs. This study is solely based on synthetic data. To generate data for one section of a reservoir, a full-physics reservoir simulator has been used. Simulated data from this section is used to train a machine learning model, which provides EUR as the output. Production from another section of the field with a different range of reservoir properties is then forecasted using a physics-based model. Using the earlier trained model, production forecasting for this section of the reservoir is then carried out to illustrate the integrated approach to EUR forecasting for a section of the reservoir that is not data rich. The integrated approach, or hybrid modeling, production forecasting for different sections of the reservoir that were data-starved, are illustrated. Using the physics-based model, the uncertainty in EUR predictions made by the machine learning model has been reduced and a more accurate forecasting has been attained. This method is primarily applicable in reservoirs, such as unconventionals, where one section of the field that has been developed has a substantial amount of data, whereas, the other section of the field will be data starved. The hybrid model was consistently able to forecast EUR at an acceptable level of accuracy, thereby, highlighting the benefits of this type of an integrated approach. This study advances the application of repeatable and scalable hybrid models in unconventional reservoirs and highlights its benefits as compared to using either physics-based or machine-learning based models separately.
{"title":"Hybrid Modeling In Unconventional Reservoirs To Forecast Estimated Ultimate Recovery","authors":"C. Temizel, C. H. Canbaz, Karthik Balaji, Ahsen Ozesen, Kirill Yanidis, Hasanain Alsaheib, Nouf Alsulaiman, Mustafa A. Basri, Nayif Jama","doi":"10.4043/31010-ms","DOIUrl":"https://doi.org/10.4043/31010-ms","url":null,"abstract":"\u0000 Machine learning models have worked as a robust tool in forecasting and optimization processes for wells in conventional, data-rich reservoirs. In unconventional reservoirs however, given the large ranges of uncertainty, purely data-driven, machine learning models have not yet proven to be repeatable and scalable. In such cases, integrating physics-based reservoir simulation methods along with machine learning techniques can be used as a solution to alleviate these limitations. The objective of this study is to provide an overview along with examples of implementing this integrated approach for the purpose of forecasting Estimated Ultimate Recovery (EUR) in shale reservoirs.\u0000 This study is solely based on synthetic data. To generate data for one section of a reservoir, a full-physics reservoir simulator has been used. Simulated data from this section is used to train a machine learning model, which provides EUR as the output. Production from another section of the field with a different range of reservoir properties is then forecasted using a physics-based model. Using the earlier trained model, production forecasting for this section of the reservoir is then carried out to illustrate the integrated approach to EUR forecasting for a section of the reservoir that is not data rich.\u0000 The integrated approach, or hybrid modeling, production forecasting for different sections of the reservoir that were data-starved, are illustrated. Using the physics-based model, the uncertainty in EUR predictions made by the machine learning model has been reduced and a more accurate forecasting has been attained. This method is primarily applicable in reservoirs, such as unconventionals, where one section of the field that has been developed has a substantial amount of data, whereas, the other section of the field will be data starved. The hybrid model was consistently able to forecast EUR at an acceptable level of accuracy, thereby, highlighting the benefits of this type of an integrated approach.\u0000 This study advances the application of repeatable and scalable hybrid models in unconventional reservoirs and highlights its benefits as compared to using either physics-based or machine-learning based models separately.","PeriodicalId":11072,"journal":{"name":"Day 1 Mon, August 16, 2021","volume":"13 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-08-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89764618","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}
B. Grove, T MacgillivrayJoseph, Cook Jason Karl, C HoelscherChristopher
An operator was developing a High-Pressure High-Temperature (HPHT) field in the U.S. Gulf of Mexico (GOM). Completion design for the injector wells was cased-and-perforated, with no mechanical sand control. This led to the requirement for a tubing-conveyed perforating (TCP) system, featuring deep-penetrating (DP) charges which would meet specific performance requirements, in order to enable the wells to achieve injectivity targets. A perforating system was therefore developed and qualified to meet these requirements. This was an integrated system development, including both mechanical and explosive components, with simultaneous attention to performance, reliability, and quality assurance in the eventual field environment. The development program yielded a 4-3/4-inch carrier system, perforating charges, firing head, and gun hanger. All key components and systems were qualified in customer-witnessed testing, and demonstrated to meet or exceed operational function and performance requirements. The pressure and temperature rating of the newly-developed system is 30,000 psi at 425 °F. Explosive train function reliability was demonstrated at 380 °F for up to 28 days. The newly-developed perforating shaped charge was confirmed to exceed the stringent penetration depth and casing hole diameter performance requirements at downhole conditions. The firing head offers operational flexibility by being configurable for up to 15 pressure cycles prior to detonation, with an adjustable initiation threshold pressure to reduce risk to the completion string. The gun hanger was customized and demonstrated to exceed load requirements, and reliably set and release, in a test configuration featuring operator-provided field casing.
{"title":"Development of Perforating System for Unique HPHT Injection Application","authors":"B. Grove, T MacgillivrayJoseph, Cook Jason Karl, C HoelscherChristopher","doi":"10.4043/31167-ms","DOIUrl":"https://doi.org/10.4043/31167-ms","url":null,"abstract":"\u0000 An operator was developing a High-Pressure High-Temperature (HPHT) field in the U.S. Gulf of Mexico (GOM). Completion design for the injector wells was cased-and-perforated, with no mechanical sand control. This led to the requirement for a tubing-conveyed perforating (TCP) system, featuring deep-penetrating (DP) charges which would meet specific performance requirements, in order to enable the wells to achieve injectivity targets.\u0000 A perforating system was therefore developed and qualified to meet these requirements. This was an integrated system development, including both mechanical and explosive components, with simultaneous attention to performance, reliability, and quality assurance in the eventual field environment.\u0000 The development program yielded a 4-3/4-inch carrier system, perforating charges, firing head, and gun hanger. All key components and systems were qualified in customer-witnessed testing, and demonstrated to meet or exceed operational function and performance requirements.\u0000 The pressure and temperature rating of the newly-developed system is 30,000 psi at 425 °F. Explosive train function reliability was demonstrated at 380 °F for up to 28 days. The newly-developed perforating shaped charge was confirmed to exceed the stringent penetration depth and casing hole diameter performance requirements at downhole conditions. The firing head offers operational flexibility by being configurable for up to 15 pressure cycles prior to detonation, with an adjustable initiation threshold pressure to reduce risk to the completion string. The gun hanger was customized and demonstrated to exceed load requirements, and reliably set and release, in a test configuration featuring operator-provided field casing.","PeriodicalId":11072,"journal":{"name":"Day 1 Mon, August 16, 2021","volume":"108 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-08-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88981748","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}
Low salinity/engineered water injections (LSWI/EWI) have gained popularity as effective techniques for enhancing oil recovery. Surfactant flooding is also a well-established and commercially-available technique in the oil and gas industry. In this paper, a numerical 2D simulation model was developed to investigate the effect of hybrid surfactant-LSWI/EWI on oil recovery from carbonate cores under harsh conditions. The developed simulation model was validated by history-matching recently conducted surfactant corefloods in the secondary mode of injection. Oil recovery, pressure drop, and surfactant concentration data were utilized. The surfactant flooding model was then coupled with a geochemical model that captures different reactions during LSWI/EWI. The geochemical reactions considered include aqueous, dissolution/precipitation, and ion-exchange reactions. Different simulation scenarios were considered and compared including waterflooding, surfactant flooding, engineered water injection, hybrid surfactant-EWI, and hybrid surfactant-LSWI. Additionally, sensitivity analysis was performed on the hybrid surfactant-EWI process through capturing changes in surfactant injected concentration and adsorption. For the case of LSWI/EWI, wettability alteration was considered as the main mechanism underlying incremental oil recovery. However, both wettability alteration and interfacial tension reduction mechanisms were considered for surfactant flooding depending on the type of surfactant used. The results showed that the hybrid surfactant-EWI altered the wettability and achieved higher oil recovery than that of surfactant-LSWI and other techniques. This highlights the importance of selecting the right combinations of potential ions for a certain reservoir to maximize oil recovery rather than a simple water dilution. The results also highlight the importance of surfactant adsorption and surfactant concentration for the hybrid surfactant-EWI technique. This work provides insights into the application of hybrid surfactant-LSWI/EWI on oil recovery especially in carbonates. The novelty of this work is further expanded through comparing surfactant-LSWI with surfactant-EWI and understanding the controlling parameters of surfactant-EWI through sensitivity analysis.
{"title":"A New Insight into Hybrid Surfactant and Low Salinity/Engineered Water Injections in Carbonates Through Geochemical Modeling","authors":"A. Adila, E. Al-Shalabi, W. Alameri","doi":"10.4043/31128-ms","DOIUrl":"https://doi.org/10.4043/31128-ms","url":null,"abstract":"\u0000 Low salinity/engineered water injections (LSWI/EWI) have gained popularity as effective techniques for enhancing oil recovery. Surfactant flooding is also a well-established and commercially-available technique in the oil and gas industry. In this paper, a numerical 2D simulation model was developed to investigate the effect of hybrid surfactant-LSWI/EWI on oil recovery from carbonate cores under harsh conditions. The developed simulation model was validated by history-matching recently conducted surfactant corefloods in the secondary mode of injection. Oil recovery, pressure drop, and surfactant concentration data were utilized. The surfactant flooding model was then coupled with a geochemical model that captures different reactions during LSWI/EWI. The geochemical reactions considered include aqueous, dissolution/precipitation, and ion-exchange reactions. Different simulation scenarios were considered and compared including waterflooding, surfactant flooding, engineered water injection, hybrid surfactant-EWI, and hybrid surfactant-LSWI. Additionally, sensitivity analysis was performed on the hybrid surfactant-EWI process through capturing changes in surfactant injected concentration and adsorption.\u0000 For the case of LSWI/EWI, wettability alteration was considered as the main mechanism underlying incremental oil recovery. However, both wettability alteration and interfacial tension reduction mechanisms were considered for surfactant flooding depending on the type of surfactant used. The results showed that the hybrid surfactant-EWI altered the wettability and achieved higher oil recovery than that of surfactant-LSWI and other techniques. This highlights the importance of selecting the right combinations of potential ions for a certain reservoir to maximize oil recovery rather than a simple water dilution. The results also highlight the importance of surfactant adsorption and surfactant concentration for the hybrid surfactant-EWI technique. This work provides insights into the application of hybrid surfactant-LSWI/EWI on oil recovery especially in carbonates. The novelty of this work is further expanded through comparing surfactant-LSWI with surfactant-EWI and understanding the controlling parameters of surfactant-EWI through sensitivity analysis.","PeriodicalId":11072,"journal":{"name":"Day 1 Mon, August 16, 2021","volume":"2677 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-08-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"80948226","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 PerryRobert, Jeremy Pitts, A. Strikovski, Utkarsh Sinha
A multiphase compressor has been developed that provides: compression ratios up to 40:1, the ability to handle multiphase and slugging flow, and a very broad and flexible operating range allowing it to be positioned near the wellhead. Currently the product is targeted at onshore unconventional fields, and field data have been collected on such fields. For deployment to onshore unconventional fields the multiphase compressor has been packaged within a system so that it is easily transportable and fully self-contained, requiring no external power source or utilities. Also, minimal effort is required to tie in at the wellpad (just process connections in and out), no downhole intervention is needed, and typically no site preparations are required, which allow it to be easily relocatable with minimal sunk investment cost. Onshore applications include: Artificial lift from surface to increase production and reserves, and reduce operating costs – applicable to both oil wells with moderate quantities of gas present, and gas wells suffering from liquid loading. Field data show production enhancement of up to 300% versus alternative forms of artificial lift. ‘Frac hit’ recovery to restore parent well production more quickly (by accelerated recovery of preload or ‘frac hit’ fluids from parent wells) – applicable to both oil and gas wells. Field data show accelerated fluid removal versus alternative forms of artificial lift and reservoir studies indicate around an order of magnitude faster recovery of fluids. Lower methane and CO2 emissions and operating costs from field operations – operator intensive flowbacks to open top tanks to kick wells off can instead be achieved with the multiphase compressor, which also avoids the methane emissions to the environment associated with open top tank flowbacks or CO2 emissions from flaring. Lower methane and CO2 emission field development options – by enabling multiphase gathering to centralized facilities, the emissions associated with poor pad separation and the associated fugitive emissions from on-site storage and movement of volatile liquids can be eliminated, and at the same time eliminating operating costs associated with intensive distributed operations such as road tanker export of oil from wellpads. Additionally, abandonment of late life conventional oil and gas reservoirs and wells can be deferred by avoiding slugging well flows for longer – adding both production and reserves, and removing the operating cost associated with kicking off wells. For land conventional well applications the same multiphase compressor and package can be deployed as for unconventional fields – and the system packaging can be easily adjusted to deploy to offshore platforms. The multiphase compressor has also been redesigned for subsea, and uses the same principles of operation to provide unique benefits for subsea applications: particularly for late life gas wells to add more production and reserves than would be possible fro
{"title":"Sustaining Oil and Gas Fields by Using Multiphase Gas Compression to Increase Production and Reserves, and Lower Operating Costs and Environmental Emissions Footprint","authors":"A PerryRobert, Jeremy Pitts, A. Strikovski, Utkarsh Sinha","doi":"10.4043/31072-ms","DOIUrl":"https://doi.org/10.4043/31072-ms","url":null,"abstract":"\u0000 A multiphase compressor has been developed that provides: compression ratios up to 40:1, the ability to handle multiphase and slugging flow, and a very broad and flexible operating range allowing it to be positioned near the wellhead.\u0000 Currently the product is targeted at onshore unconventional fields, and field data have been collected on such fields. For deployment to onshore unconventional fields the multiphase compressor has been packaged within a system so that it is easily transportable and fully self-contained, requiring no external power source or utilities. Also, minimal effort is required to tie in at the wellpad (just process connections in and out), no downhole intervention is needed, and typically no site preparations are required, which allow it to be easily relocatable with minimal sunk investment cost. Onshore applications include:\u0000 Artificial lift from surface to increase production and reserves, and reduce operating costs – applicable to both oil wells with moderate quantities of gas present, and gas wells suffering from liquid loading. Field data show production enhancement of up to 300% versus alternative forms of artificial lift. ‘Frac hit’ recovery to restore parent well production more quickly (by accelerated recovery of preload or ‘frac hit’ fluids from parent wells) – applicable to both oil and gas wells. Field data show accelerated fluid removal versus alternative forms of artificial lift and reservoir studies indicate around an order of magnitude faster recovery of fluids. Lower methane and CO2 emissions and operating costs from field operations – operator intensive flowbacks to open top tanks to kick wells off can instead be achieved with the multiphase compressor, which also avoids the methane emissions to the environment associated with open top tank flowbacks or CO2 emissions from flaring. Lower methane and CO2 emission field development options – by enabling multiphase gathering to centralized facilities, the emissions associated with poor pad separation and the associated fugitive emissions from on-site storage and movement of volatile liquids can be eliminated, and at the same time eliminating operating costs associated with intensive distributed operations such as road tanker export of oil from wellpads.\u0000 Additionally, abandonment of late life conventional oil and gas reservoirs and wells can be deferred by avoiding slugging well flows for longer – adding both production and reserves, and removing the operating cost associated with kicking off wells. For land conventional well applications the same multiphase compressor and package can be deployed as for unconventional fields – and the system packaging can be easily adjusted to deploy to offshore platforms.\u0000 The multiphase compressor has also been redesigned for subsea, and uses the same principles of operation to provide unique benefits for subsea applications: particularly for late life gas wells to add more production and reserves than would be possible fro","PeriodicalId":11072,"journal":{"name":"Day 1 Mon, August 16, 2021","volume":"194 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-08-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"72762742","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}
Suction piles are a form of foundation widely adopted in the offshore energy industry. Efforts to enhance the combined Vertical-Horizontal (V-H) performance of piles with the addition of fins, attracted interest from the engineering community in the beginning of the 21st century. Design of this enhancement was surfaced whilst examining foundation solutions for renewable energy projects. Studies to date have primarly considered relatively shallow waters comprising sandy soils, with the behaviour of fin-enhanced piles in very soft to soft clay soils, receiving less attention. The present study emphasis is on typical deep-water deposits of soft clay and attempts to evaluate the impact of varying fin length, shape, orientation and location, on the combined capacity of suction piles by means of three-dimensional finite element analyses. The paper investigates two types of load configuration; in the first instance loading at the pile head and secondly with the load attachment point located at approximately two thirds of the pile embedded length. These two configurations cover different foundation solutions, such as support for subsea infrastructure and anchoring for floating facilities, respectively. Optimum fin-enhanced suction pile configurations are presented for each application, with the results from this study indicating an increase of the load-carrying capacity in V-H space, whilst reducing the overall suction pile size. The efficiency of various configurations is presented with composite plots of increase in holding capacity, plotted against the increase in steel surface area. Preliminary recommendations on fin length, location, shape and orientation for typical suction pile applications are presented with intent to demonstrate the potential for cost savings and reduction in both operational and schedule risk.
{"title":"Effect of Fins on Combined Loaded Suction Caisson in Deepwater Clay Soils. A Numerical Analysis","authors":"Pablo Castillo Garcia, Stylianos Panayides","doi":"10.4043/30973-ms","DOIUrl":"https://doi.org/10.4043/30973-ms","url":null,"abstract":"\u0000 Suction piles are a form of foundation widely adopted in the offshore energy industry. Efforts to enhance the combined Vertical-Horizontal (V-H) performance of piles with the addition of fins, attracted interest from the engineering community in the beginning of the 21st century. Design of this enhancement was surfaced whilst examining foundation solutions for renewable energy projects. Studies to date have primarly considered relatively shallow waters comprising sandy soils, with the behaviour of fin-enhanced piles in very soft to soft clay soils, receiving less attention. The present study emphasis is on typical deep-water deposits of soft clay and attempts to evaluate the impact of varying fin length, shape, orientation and location, on the combined capacity of suction piles by means of three-dimensional finite element analyses. The paper investigates two types of load configuration; in the first instance loading at the pile head and secondly with the load attachment point located at approximately two thirds of the pile embedded length. These two configurations cover different foundation solutions, such as support for subsea infrastructure and anchoring for floating facilities, respectively. Optimum fin-enhanced suction pile configurations are presented for each application, with the results from this study indicating an increase of the load-carrying capacity in V-H space, whilst reducing the overall suction pile size. The efficiency of various configurations is presented with composite plots of increase in holding capacity, plotted against the increase in steel surface area. Preliminary recommendations on fin length, location, shape and orientation for typical suction pile applications are presented with intent to demonstrate the potential for cost savings and reduction in both operational and schedule risk.","PeriodicalId":11072,"journal":{"name":"Day 1 Mon, August 16, 2021","volume":"80 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-08-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83851295","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}
Vinicius Gasparetto, Thierry Hernalsteens, João Francisco Fleck Heck Britto, J. F. A. Leao, T. D. F. D. Santos, R. C. Oliveira
Buzios is a super-giant ultra-deep-water pre-salt oil and gas field located in the Santos Basin off Brazil's Southeastern coast. There are four production systems already installed in the field. Designed to use flexible pipes to tie back the production and injection wells to the FPSOs (Floating Production Storage and Offloading), these systems have taken advantage from several lessons learned in the previous projects installed by Petrobras in Santos Basin pre-salt areas since 2010. This knowledge, combined with advances in flexible pipe technology, use of long-term contracts and early engagement with suppliers, made it possible to optimize the field development, minimizing the risks and reducing the capital expenditure (CAPEX) initially planned. This paper presents the first four Buzios subsea system developments, highlighting some of the technological achievements applied in the field, as the first wide application of 8" Internal Diameter (ID) flexible production pipes for ultra-deep water, leading to faster ramp-ups and higher production flowrates. It describes how the supply chain strategy provided flexibility to cover the remaining project uncertainties, and reports the optimizations carried out in flexible riser systems and subsea layouts. The flexible risers, usually installed in lazy wave configurations at such water depths, were optimized reducing the total buoyancy necessary. For water injection and service lines, the buoyancy modules were completely removed, and thus the lines were installed in a free-hanging configuration. Riser configuration optimizations promoted a drop of around 25% on total riser CAPEX and allowed the riser anchor position to be placed closer to the floating production unit, promoting opportunities for reducing the subsea tieback lengths. Standardization of pipe specifications and the riser configurations allowed the projects to exchange the lines, increasing flexibility and avoiding riser interference in a scenario with multiple suppliers. Furthermore, Buzios was the first ultra-deep-water project to install a flexible line, riser, and flowline, with fully Controlled Annulus Solution (CAS). This system, developed by TechnipFMC, allows pipe integrity management from the topside, which reduces subsea inspections. As an outcome of the technological improvements and the optimizations applied to the Buzios subsea system, a vast reduction in subsea CAPEX it was achieved, with a swift production ramp-up.
{"title":"Optimization Applied to Buzios Flexible Riser Systems and Subsea Layout","authors":"Vinicius Gasparetto, Thierry Hernalsteens, João Francisco Fleck Heck Britto, J. F. A. Leao, T. D. F. D. Santos, R. C. Oliveira","doi":"10.4043/30972-ms","DOIUrl":"https://doi.org/10.4043/30972-ms","url":null,"abstract":"\u0000 Buzios is a super-giant ultra-deep-water pre-salt oil and gas field located in the Santos Basin off Brazil's Southeastern coast. There are four production systems already installed in the field. Designed to use flexible pipes to tie back the production and injection wells to the FPSOs (Floating Production Storage and Offloading), these systems have taken advantage from several lessons learned in the previous projects installed by Petrobras in Santos Basin pre-salt areas since 2010. This knowledge, combined with advances in flexible pipe technology, use of long-term contracts and early engagement with suppliers, made it possible to optimize the field development, minimizing the risks and reducing the capital expenditure (CAPEX) initially planned.\u0000 This paper presents the first four Buzios subsea system developments, highlighting some of the technological achievements applied in the field, as the first wide application of 8\" Internal Diameter (ID) flexible production pipes for ultra-deep water, leading to faster ramp-ups and higher production flowrates. It describes how the supply chain strategy provided flexibility to cover the remaining project uncertainties, and reports the optimizations carried out in flexible riser systems and subsea layouts.\u0000 The flexible risers, usually installed in lazy wave configurations at such water depths, were optimized reducing the total buoyancy necessary. For water injection and service lines, the buoyancy modules were completely removed, and thus the lines were installed in a free-hanging configuration. Riser configuration optimizations promoted a drop of around 25% on total riser CAPEX and allowed the riser anchor position to be placed closer to the floating production unit, promoting opportunities for reducing the subsea tieback lengths. Standardization of pipe specifications and the riser configurations allowed the projects to exchange the lines, increasing flexibility and avoiding riser interference in a scenario with multiple suppliers.\u0000 Furthermore, Buzios was the first ultra-deep-water project to install a flexible line, riser, and flowline, with fully Controlled Annulus Solution (CAS). This system, developed by TechnipFMC, allows pipe integrity management from the topside, which reduces subsea inspections.\u0000 As an outcome of the technological improvements and the optimizations applied to the Buzios subsea system, a vast reduction in subsea CAPEX it was achieved, with a swift production ramp-up.","PeriodicalId":11072,"journal":{"name":"Day 1 Mon, August 16, 2021","volume":"56 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-08-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"74387735","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}
Amy Styslinger, D. Yost, G. Dickerson, Antoine Minois, Renee Wiwel
The Liza Phase 1 development project, offshore Guyana, is an unique example of what the offshore oil and gas industry is capable of when working together to deliver a common objective. ExxonMobil and the Stabroek Block co-venturers, Hess Guyana Exploration Limited and CNOOC Petroleum Guyana Limited, commenced oil production from the Liza Destiny floating production, storage, and offloading (FPSO) vessel in December of 2019, less than 5 years from the initial discovery of hydrocarbons in the Staebroek block. With the production and export of its first barrels of oil, the project completed the establishment of a nascent oil and gas industry in Guyana that is poised for tremendous growth in the coming years. The Liza Phase 1 development consists of a 120 kbd conversion FPSO (The Liza Destiny) and a network of subsea infrastructure to produce from and inject in two drill centers. It is expected to develop a resource of about 450 MBO gross estimated ultimate recovery. The water depth ranges from 1,690–1,860 m throughout the development which is located approximately 200 km offshore Guyana. This paper highlights the scope and pace of the project and discusses three specific challenges overcome: the uncertainty of the metocean conditions, extending the application of the selected riser technology, and executing in a challenging and frontier offshore location. A key to the success of the project was the unified approach between stakeholders and the commitment to act as One Team. The Liza Phase 1 project rapidly developed a newly discovered deep water resource in a frontier location while overcoming numerous challenges. By delivering Guyana's first ever oil production among industry leading cycle times, the Liza Phase 1 project has set the foundation for the future of deep water developments in Guyana.
{"title":"Guyana: Liza Phase 1 Rapid Development in a Deepwater Frontier","authors":"Amy Styslinger, D. Yost, G. Dickerson, Antoine Minois, Renee Wiwel","doi":"10.4043/31158-ms","DOIUrl":"https://doi.org/10.4043/31158-ms","url":null,"abstract":"\u0000 The Liza Phase 1 development project, offshore Guyana, is an unique example of what the offshore oil and gas industry is capable of when working together to deliver a common objective. ExxonMobil and the Stabroek Block co-venturers, Hess Guyana Exploration Limited and CNOOC Petroleum Guyana Limited, commenced oil production from the Liza Destiny floating production, storage, and offloading (FPSO) vessel in December of 2019, less than 5 years from the initial discovery of hydrocarbons in the Staebroek block. With the production and export of its first barrels of oil, the project completed the establishment of a nascent oil and gas industry in Guyana that is poised for tremendous growth in the coming years.\u0000 The Liza Phase 1 development consists of a 120 kbd conversion FPSO (The Liza Destiny) and a network of subsea infrastructure to produce from and inject in two drill centers. It is expected to develop a resource of about 450 MBO gross estimated ultimate recovery. The water depth ranges from 1,690–1,860 m throughout the development which is located approximately 200 km offshore Guyana.\u0000 This paper highlights the scope and pace of the project and discusses three specific challenges overcome: the uncertainty of the metocean conditions, extending the application of the selected riser technology, and executing in a challenging and frontier offshore location. A key to the success of the project was the unified approach between stakeholders and the commitment to act as One Team.\u0000 The Liza Phase 1 project rapidly developed a newly discovered deep water resource in a frontier location while overcoming numerous challenges. By delivering Guyana's first ever oil production among industry leading cycle times, the Liza Phase 1 project has set the foundation for the future of deep water developments in Guyana.","PeriodicalId":11072,"journal":{"name":"Day 1 Mon, August 16, 2021","volume":"54 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-08-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77180763","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}
Pseudostatic limit-equilibrium based slope stability analyses are carried out on a routine basis to evaluate stability of submarine slopes under earthquake loading. For slopes in deepwater settings, a major challenge in performing pseudostatic slope stability analyses is selection of an appropriate seismic coefficient. Most published displacement-based methodologies for seismic coefficient selection were developed using simplified sliding block models for seismic slope performance evaluation that are unable to capture the complex deformation mechanism of deepwater slopes during earthquakes. To address this challenge, this study employs two-dimensional dynamic finite-element based deformation analysis to investigate the earthquake response of submarine clay slopes characterized by morphology, stratigraphic architecture and geotechnical properties representative for the deepwater environment. Finite-element computed seismic slope performance indicators, including horizontal peak ground acceleration at the seafloor and earthquake-induced maximum shear strain within the slope, along with horizontal seismic coefficients required to trigger slope instability in limit-equilibrium based pseudostatic stability analyses are used to develop a rational shear strain-based correlation relationship for deepwater slope seismic coefficient selection.
{"title":"Seismic Coefficients for Simplified Deepwater Slope Stability Assessment Under Earthquake Loading","authors":"A. Trandafir","doi":"10.4043/31056-ms","DOIUrl":"https://doi.org/10.4043/31056-ms","url":null,"abstract":"\u0000 Pseudostatic limit-equilibrium based slope stability analyses are carried out on a routine basis to evaluate stability of submarine slopes under earthquake loading. For slopes in deepwater settings, a major challenge in performing pseudostatic slope stability analyses is selection of an appropriate seismic coefficient. Most published displacement-based methodologies for seismic coefficient selection were developed using simplified sliding block models for seismic slope performance evaluation that are unable to capture the complex deformation mechanism of deepwater slopes during earthquakes. To address this challenge, this study employs two-dimensional dynamic finite-element based deformation analysis to investigate the earthquake response of submarine clay slopes characterized by morphology, stratigraphic architecture and geotechnical properties representative for the deepwater environment. Finite-element computed seismic slope performance indicators, including horizontal peak ground acceleration at the seafloor and earthquake-induced maximum shear strain within the slope, along with horizontal seismic coefficients required to trigger slope instability in limit-equilibrium based pseudostatic stability analyses are used to develop a rational shear strain-based correlation relationship for deepwater slope seismic coefficient selection.","PeriodicalId":11072,"journal":{"name":"Day 1 Mon, August 16, 2021","volume":"1 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-08-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84993944","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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