V. Silva, A. Moliterno, C. Araujo, Francis Pimentel, Jose Ronaldo Chaves Melo, C. Falcao, T. Pessoa
Petrobras acquired the right to produce 3.058 billion boe under the Transfer of Rights (ToR) in Buzios field, which still has a recoverable surplus, recently auctioned by the Brazilian Petroleum Regulatory Agency. Properly planning the production development of a supergiant field and under two tax regimes, requires a large multidisciplinary effort of data acquisition, characterization and modelling. Located in the Santos Basin Pre-Salt Pole, the Buzios field is a deep-water supergiant that has a large thickness of carbonate reservoirs, with significant areal and vertical variation. The presence of faults, fractures, karsts and other diagenetic processes adds complexity to the field, which motivated the development and implantation of industry innovations to enable its development. The presence of high levels of CO2 and H2S in the reservoir fluid, the risk of inorganic scaling and asphaltene deposition and risks of early fluid channeling and low sweep efficiency due to the aforementioned geological complexities are challenges that need to be addressed. One of these challenges is to ensure a better seismic data for the reservoir characterization. The 3D seismic data from a streamer acquisition did not have sufficient quality for this. The geological complexity of the field, the great reservoir depth and mainly the very irregular topography of the overlying evaporitic sequence indicated the need for rich azimuth seismic data. This led to the world's largest ultra-deep water seismic survey using Ocean Bottom Nodes (OBN) technology. This paper will address the static and dynamic data acquisition from the wells and the Early Productions Systems (EPS), as well as the challenges that arose and were faced by Petrobras through technology and innovation, and the complexity of the reservoir dynamic modelling. Furthermore, the OBN seismic acquisition in Buzios will be discussed in more detail, as well as the frontier that this acquisition opens to the development of the field.
{"title":"Buzios Drainage Strategy: A Combination Of Reservoir Characterization, Risks Mitigation And Unique Contract Features","authors":"V. Silva, A. Moliterno, C. Araujo, Francis Pimentel, Jose Ronaldo Chaves Melo, C. Falcao, T. Pessoa","doi":"10.4043/31170-ms","DOIUrl":"https://doi.org/10.4043/31170-ms","url":null,"abstract":"\u0000 Petrobras acquired the right to produce 3.058 billion boe under the Transfer of Rights (ToR) in Buzios field, which still has a recoverable surplus, recently auctioned by the Brazilian Petroleum Regulatory Agency. Properly planning the production development of a supergiant field and under two tax regimes, requires a large multidisciplinary effort of data acquisition, characterization and modelling.\u0000 Located in the Santos Basin Pre-Salt Pole, the Buzios field is a deep-water supergiant that has a large thickness of carbonate reservoirs, with significant areal and vertical variation. The presence of faults, fractures, karsts and other diagenetic processes adds complexity to the field, which motivated the development and implantation of industry innovations to enable its development. The presence of high levels of CO2 and H2S in the reservoir fluid, the risk of inorganic scaling and asphaltene deposition and risks of early fluid channeling and low sweep efficiency due to the aforementioned geological complexities are challenges that need to be addressed.\u0000 One of these challenges is to ensure a better seismic data for the reservoir characterization. The 3D seismic data from a streamer acquisition did not have sufficient quality for this. The geological complexity of the field, the great reservoir depth and mainly the very irregular topography of the overlying evaporitic sequence indicated the need for rich azimuth seismic data. This led to the world's largest ultra-deep water seismic survey using Ocean Bottom Nodes (OBN) technology.\u0000 This paper will address the static and dynamic data acquisition from the wells and the Early Productions Systems (EPS), as well as the challenges that arose and were faced by Petrobras through technology and innovation, and the complexity of the reservoir dynamic modelling. Furthermore, the OBN seismic acquisition in Buzios will be discussed in more detail, as well as the frontier that this acquisition opens to the development of the field.","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":"80380823","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}
Some of the most critical elements of a rotating control device (RCD) are the rotary seals that prevent a pressurized abrasive drilling fluid from destroying the rolling element bearings. The rotary seals prevent the drilling fluid from damaging the bearings by sealing the annular gap between the rotating mandrel and the stationary bearing housing. The combination of pressure causing seal material to bulge into the annular gap and the relative runout between the mandrel and housing can cause extrusion damage of the seal. The relative rotation and runout between the seal and mandrel in an abrasive environment leads to abrasive wear of the seal. Finally, the relatively high surface speed and contact pressure between the seal and mandrel leads to adhesive wear of the seal. When the drilling fluid pressure below the RCD is low there are several suitable rotary seal designs that can provide acceptable RCD life at most rotary drilling speeds. To meet higher speed and pressure conditions for the 100 hour minimum duration, established in API 16RCD, many RCD designs employ a sealing approach that splits the sealing tasks across two seals. One seal excludes the abrasive drilling fluid at low differential pressure and another seal, capable of operating at high differential pressure, retains a clean lubricant that is at nearly the same pressure as the drilling fluid. This sealing system generally requires an external lubricant pressurization system to provide the necessary fluid and pressure environment for the seals. Some drilling sites that operate at these conditions cannot accommodate these large, complex, expensive lubricant systems due to space or access constraints, or economic considerations. This paper describes an innovative sealing system that enables an RCD to operate at 1,500 psi and 100 RPM for 200 hours without requiring an external lubricant pressurization system. This claim is based on extensive laboratory testing of three new technologies included in this sealing system. Key results and summaries from the test program are included in this paper. The three key technologies are: A hydrodynamic spring-loaded lip seal that can be used to exclude abrasive drilling fluid at low-differential pressure or retain a clean lubricant at high differential pressure. A direct-compression hydrodynamic seal that can retain a clean lubricant at high differential pressure. A self-actuating miniature valve that replaces the lubricant supply function of an external lubricant pressurization system.
{"title":"Sealing Advancements for Rotating Control Devices","authors":"Aaron Richie, Lannie Laroy Dietle","doi":"10.4043/31159-ms","DOIUrl":"https://doi.org/10.4043/31159-ms","url":null,"abstract":"\u0000 Some of the most critical elements of a rotating control device (RCD) are the rotary seals that prevent a pressurized abrasive drilling fluid from destroying the rolling element bearings. The rotary seals prevent the drilling fluid from damaging the bearings by sealing the annular gap between the rotating mandrel and the stationary bearing housing. The combination of pressure causing seal material to bulge into the annular gap and the relative runout between the mandrel and housing can cause extrusion damage of the seal. The relative rotation and runout between the seal and mandrel in an abrasive environment leads to abrasive wear of the seal. Finally, the relatively high surface speed and contact pressure between the seal and mandrel leads to adhesive wear of the seal.\u0000 When the drilling fluid pressure below the RCD is low there are several suitable rotary seal designs that can provide acceptable RCD life at most rotary drilling speeds. To meet higher speed and pressure conditions for the 100 hour minimum duration, established in API 16RCD, many RCD designs employ a sealing approach that splits the sealing tasks across two seals. One seal excludes the abrasive drilling fluid at low differential pressure and another seal, capable of operating at high differential pressure, retains a clean lubricant that is at nearly the same pressure as the drilling fluid. This sealing system generally requires an external lubricant pressurization system to provide the necessary fluid and pressure environment for the seals. Some drilling sites that operate at these conditions cannot accommodate these large, complex, expensive lubricant systems due to space or access constraints, or economic considerations.\u0000 This paper describes an innovative sealing system that enables an RCD to operate at 1,500 psi and 100 RPM for 200 hours without requiring an external lubricant pressurization system. This claim is based on extensive laboratory testing of three new technologies included in this sealing system. Key results and summaries from the test program are included in this paper. The three key technologies are:\u0000 A hydrodynamic spring-loaded lip seal that can be used to exclude abrasive drilling fluid at low-differential pressure or retain a clean lubricant at high differential pressure. A direct-compression hydrodynamic seal that can retain a clean lubricant at high differential pressure. A self-actuating miniature valve that replaces the lubricant supply function of an external lubricant pressurization system.","PeriodicalId":11072,"journal":{"name":"Day 1 Mon, August 16, 2021","volume":"45 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-08-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90722296","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}
T. Roy, Dan Markel, Casey Harrison, F. SheltonJames, Leonard Harp, D. Groesbeck, Gustavo Grullon, Christian Wilkinson, Sanghamitra Chakravarty, R. Shenoy, I. Roy
Strengthening materials through grain refinement often results in reduced ductility necessitating means to augment their elongation to failure for engineering applications. Grain boundary engineering (GBE), encompassing novel thermo-mechanical processing has shown promise of simultaneously enhancing both strength and ductility of materials and fracture behavior, especially with low stacking fault energy materials. The ultrahigh strength and reasonable ductility originate from dislocations being effectively blocked at the nano-twinned boundaries resulting in dislocation accumulation and entanglement. This necessitates the careful design of alloys and nano-composites, an effective harnessing of these unique sub-micron features to the benefit of engineering downhole tools for strategic applications. Enabled by these novel material developments, here we present two such articles for the unconventionals. First, a frangible barrier to abet placement of casings and liners through trapping an air column below the barrier while supporting a fluid column in the casing above, providing an up-thrust, a buoyant force that significantly reduces drag and lateral casing weight during placement. This is a viable concept because "shales don't kick". Second is the unmet need for a clean perforating tunnel allowing reduced fluid friction thus better reservoir connectivity. This has been achieved through the development of a novel shape charge with a reactive liner which during the detonation event, additionally generates reactive metallic glassy phase(s) and high entropy alloy complex(s) and their segregation in the deposited jet debris that lines the perf-tunnel. During flowback, reaction with aqueous fluids selectively etch these phases and stimulates the disintegration of the impervious skin on the perf-tunnel into fine particulates subsequently removing them, leaving behind a clear, clean tunnel.
{"title":"Powerful Material Technology Removes Barriers","authors":"T. Roy, Dan Markel, Casey Harrison, F. SheltonJames, Leonard Harp, D. Groesbeck, Gustavo Grullon, Christian Wilkinson, Sanghamitra Chakravarty, R. Shenoy, I. Roy","doi":"10.4043/31311-ms","DOIUrl":"https://doi.org/10.4043/31311-ms","url":null,"abstract":"\u0000 Strengthening materials through grain refinement often results in reduced ductility necessitating means to augment their elongation to failure for engineering applications. Grain boundary engineering (GBE), encompassing novel thermo-mechanical processing has shown promise of simultaneously enhancing both strength and ductility of materials and fracture behavior, especially with low stacking fault energy materials. The ultrahigh strength and reasonable ductility originate from dislocations being effectively blocked at the nano-twinned boundaries resulting in dislocation accumulation and entanglement. This necessitates the careful design of alloys and nano-composites, an effective harnessing of these unique sub-micron features to the benefit of engineering downhole tools for strategic applications. Enabled by these novel material developments, here we present two such articles for the unconventionals. First, a frangible barrier to abet placement of casings and liners through trapping an air column below the barrier while supporting a fluid column in the casing above, providing an up-thrust, a buoyant force that significantly reduces drag and lateral casing weight during placement. This is a viable concept because \"shales don't kick\". Second is the unmet need for a clean perforating tunnel allowing reduced fluid friction thus better reservoir connectivity. This has been achieved through the development of a novel shape charge with a reactive liner which during the detonation event, additionally generates reactive metallic glassy phase(s) and high entropy alloy complex(s) and their segregation in the deposited jet debris that lines the perf-tunnel. During flowback, reaction with aqueous fluids selectively etch these phases and stimulates the disintegration of the impervious skin on the perf-tunnel into fine particulates subsequently removing them, leaving behind a clear, clean tunnel.","PeriodicalId":11072,"journal":{"name":"Day 1 Mon, August 16, 2021","volume":"42 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-08-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"85752751","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}
Managing asphaltene accumulation in offshore Gulf-of-Mexico wells is a significant challenge. Until recently there was no real-time chemical monitoring that could advise on whether chemical inhibition was making a particular well more, or less, stable. This changed with the development of real-time hardware that directly measures the ratio of asphaltene flowing in the oil. A new generation of that hardware has now been launched which meets all of the Qualification and HSE requirements for deployment on offshore platforms. A microwave resonator was designed to receive fluid at wellhead conditions, i.e., without a reduction in pressure or temperature, and the parameters of that resonator were optimized to maximize microwave intensity for typical oilfield fluids. The microwave circuitry is incorporated in an explosion-proof container with Class 1 Div 2 rated electrical and fluid connections. By combining that resonator with a solenoid that can generate a large magnetic field around a flowline, the resulting device resonates electrons within asphaltene molecules to create a unique signature that is proportional to the total asphaltene count. Estimates of oil-water cut and gas-oil ratio are also obtained as part of the processing and this combination gives the percentage of asphaltene within the oil. The use of this hardware with controlling software and cloud processing creates a unique Internet-of-Things device which can be used to optimize asphaltene-related flow assurance challenges offshore. Pressure testing up to 5ksi and 120C gives the device a working envelope well exceeding typical offshore production hardware requirements. For a fixed fluid, the computation of asphaltene ratio was shown to be independent of applied pressure. Conversely, it was found that in a live well chemical properties of fluids can change over the course of a few hours even when the surface pressure and flow-rates stay the same. In one well, the surface asphaltene percentage within an oil was seen to vary from 0.3% to 3% because of alternating deposition and erosion of an asphaltene layer that had been forming along the ID of production tubing. Over the course of a series of tests in the Middle East, it was observed that those wells with uniform asphaltene percentage were seen as less troublesome to manage compared to wells with a higher deviation. In two Permian fields subject to CO2 flooding, a geographic variation in asphaltene percentage which correlated to the long-term exposure to injected gas was observed. It has long been standard for chemical properties of fluids to be obtained by sending samples to a lab. This paper demonstrates additional value that can be obtained from getting that data in real-time, especially when viewed in the context of an overall chemical management program.
{"title":"Real-Time Digital Chemistry Offshore Transforms Flow Assurance Management","authors":"J. Lovell, Omar Kulbrandstad, Sai Madem, D. Meza","doi":"10.4043/31121-ms","DOIUrl":"https://doi.org/10.4043/31121-ms","url":null,"abstract":"\u0000 Managing asphaltene accumulation in offshore Gulf-of-Mexico wells is a significant challenge. Until recently there was no real-time chemical monitoring that could advise on whether chemical inhibition was making a particular well more, or less, stable. This changed with the development of real-time hardware that directly measures the ratio of asphaltene flowing in the oil. A new generation of that hardware has now been launched which meets all of the Qualification and HSE requirements for deployment on offshore platforms.\u0000 A microwave resonator was designed to receive fluid at wellhead conditions, i.e., without a reduction in pressure or temperature, and the parameters of that resonator were optimized to maximize microwave intensity for typical oilfield fluids. The microwave circuitry is incorporated in an explosion-proof container with Class 1 Div 2 rated electrical and fluid connections. By combining that resonator with a solenoid that can generate a large magnetic field around a flowline, the resulting device resonates electrons within asphaltene molecules to create a unique signature that is proportional to the total asphaltene count. Estimates of oil-water cut and gas-oil ratio are also obtained as part of the processing and this combination gives the percentage of asphaltene within the oil. The use of this hardware with controlling software and cloud processing creates a unique Internet-of-Things device which can be used to optimize asphaltene-related flow assurance challenges offshore.\u0000 Pressure testing up to 5ksi and 120C gives the device a working envelope well exceeding typical offshore production hardware requirements. For a fixed fluid, the computation of asphaltene ratio was shown to be independent of applied pressure. Conversely, it was found that in a live well chemical properties of fluids can change over the course of a few hours even when the surface pressure and flow-rates stay the same. In one well, the surface asphaltene percentage within an oil was seen to vary from 0.3% to 3% because of alternating deposition and erosion of an asphaltene layer that had been forming along the ID of production tubing. Over the course of a series of tests in the Middle East, it was observed that those wells with uniform asphaltene percentage were seen as less troublesome to manage compared to wells with a higher deviation. In two Permian fields subject to CO2 flooding, a geographic variation in asphaltene percentage which correlated to the long-term exposure to injected gas was observed.\u0000 It has long been standard for chemical properties of fluids to be obtained by sending samples to a lab. This paper demonstrates additional value that can be obtained from getting that data in real-time, especially when viewed in the context of an overall chemical management program.","PeriodicalId":11072,"journal":{"name":"Day 1 Mon, August 16, 2021","volume":"53 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-08-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88518465","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 investigation presents a powerful predictive model to determine crude oil formation volume factor (FVF) using state-of-the-art computational intelligence (CI) techniques. FVF is a vital pressure-volume-temperature (PVT) parameter used to characterize hydrocarbon systems and is pivotal to reserve evaluation studies and reservoir engineering calculations. Ideally, FVF is measured at the laboratory scale; however, prognostic tools to evaluate this parameter can aid in optimizing time and cost estimates. The database utilized in this study is obtained from open literature and covers statistics of crude oils of Pakistan, Iran, UAE, and Malaysia. Resultantly, this allows to move step forward towards the creation of a generalized model. Multiple CI algorithms are considered, including Artificial Neural Networks (ANN) and Artificial Neural Fuzzy Inference Systems (ANFIS). Models for CI are developed utilizing an optimization strategy for various parameters/hyper-parameters of the respective algorithms. Unique permutations and combinations for the number of perceptron and their resident layers is investigated to reach a solution that provides the most optimum output. These intelligent models are produced as a function of the parameters intrinsically affecting FVF; reservoir temperature, solution GOR, gas specific gravity, and crude oil API gravity. Comparative analysis of various CI models is performed using visualization/statistical analysis and the best model pointed out. Finally, the mathematical equation extraction to determine FVF is accomplished with the respective weights and bias for the model presented. Graphical analysis using scatter plots with a coefficient of determination (R2) illustrates that ANN equation produces the most accurate predictions for oil FVF with R2 in excess of 0.96. Moreover, during this study an error metric is developed comprising of multiple analysis parameters; Average Absolute Error (AAE), Root Mean Squared Error (RMSE), correlation coefficient (R). All models investigated are tested on an unseen dataset to prevent the development of a biased model. Performance of the established CI models are gauged based on this error metric, which demonstrates that ANN outperforms the other models with error within 2% of the measured PVT values. A computationally derived intelligent model proves to provide the strongest predictive capabilities as it maps complex non-linear interactions between various input parameters leading to FVF.
{"title":"Development of a Computationally Intelligent Model to Estimate Oil Formation Volume Factor","authors":"Mohammad Rasheed Khan, S. Kalam, R. Khan","doi":"10.4043/31312-ms","DOIUrl":"https://doi.org/10.4043/31312-ms","url":null,"abstract":"\u0000 This investigation presents a powerful predictive model to determine crude oil formation volume factor (FVF) using state-of-the-art computational intelligence (CI) techniques. FVF is a vital pressure-volume-temperature (PVT) parameter used to characterize hydrocarbon systems and is pivotal to reserve evaluation studies and reservoir engineering calculations. Ideally, FVF is measured at the laboratory scale; however, prognostic tools to evaluate this parameter can aid in optimizing time and cost estimates. The database utilized in this study is obtained from open literature and covers statistics of crude oils of Pakistan, Iran, UAE, and Malaysia. Resultantly, this allows to move step forward towards the creation of a generalized model.\u0000 Multiple CI algorithms are considered, including Artificial Neural Networks (ANN) and Artificial Neural Fuzzy Inference Systems (ANFIS). Models for CI are developed utilizing an optimization strategy for various parameters/hyper-parameters of the respective algorithms. Unique permutations and combinations for the number of perceptron and their resident layers is investigated to reach a solution that provides the most optimum output. These intelligent models are produced as a function of the parameters intrinsically affecting FVF; reservoir temperature, solution GOR, gas specific gravity, and crude oil API gravity. Comparative analysis of various CI models is performed using visualization/statistical analysis and the best model pointed out. Finally, the mathematical equation extraction to determine FVF is accomplished with the respective weights and bias for the model presented.\u0000 Graphical analysis using scatter plots with a coefficient of determination (R2) illustrates that ANN equation produces the most accurate predictions for oil FVF with R2 in excess of 0.96. Moreover, during this study an error metric is developed comprising of multiple analysis parameters; Average Absolute Error (AAE), Root Mean Squared Error (RMSE), correlation coefficient (R). All models investigated are tested on an unseen dataset to prevent the development of a biased model. Performance of the established CI models are gauged based on this error metric, which demonstrates that ANN outperforms the other models with error within 2% of the measured PVT values. A computationally derived intelligent model proves to provide the strongest predictive capabilities as it maps complex non-linear interactions between various input parameters leading to FVF.","PeriodicalId":11072,"journal":{"name":"Day 1 Mon, August 16, 2021","volume":"9 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-08-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77122278","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}
Composite structures are used as corrosion insensitive load bearing reinforcement in dynamic Thermoplastic Composite Pipe (TCP) and Hybrid Flexible Pipe (HFP) applications. The qualification of such structures can follow different strategies: product level versus material characterization. DNVGL-ST-F119 proposes a generic knowledge-based approach based on a testing pyramid. The pyramid allows a generic material characterization for a large number of conditions. Testing of dedicated specimens in constant media exposure measures the actual properties and changes of the material. Regression data is obtained for end-of-life properties. Simulations can be conducted using these properties to determine performance of the product in any state and condition and validate any load cases through classical stress combination. The characterization for VESTAPE® Nylon 12 Carbon Fiber thermoplastic composite (CF-PA12) covers all failure mechanisms for matrix, fiber and interface in static, dynamic and stress rupture mode for virgin, fully hydrocarbon saturated and aged to end of life in saturated condition. Each condition assessment is carried out in complete temperature dependency for subzero, room temperature, intermediate and maximum use temperature of 176°F (80°C). Fatigue testing covers runtimes of 106 cycles whereas stress rupture assessment exceeds 12,500h which corresponds to almost 1.5 years. With dense data populations for both regression curves and static test results the coefficient of variation is controlled. All characterization logic and data are analyzed for validity and certified by the official body of the DNV-GL. The material characterization enables simulation of a variety of application designs in predictive engineering and a simplified study is made for a dynamic gas injection jumper to demonstrate relevant occurring load cases. Utilizing all data and approaches allows to define the overall application envelope of the material. For the case of the thermoplastic composite of CF-PA12 it covers static flowlines, dynamic jumpers, service lines up to dynamic risers in sour crude service up to 176°F (80°C). The knowledge-based approach allows for economic design in engineering cases without compromising safety.
{"title":"Full Generic Qualification of Nylon 12 Carbon Fiber Composite for Dynamic Thermoplastic Composite Pipe and Hybrid Flexible Pipe Applications","authors":"C. Schuett, A. Paternoster","doi":"10.4043/31266-ms","DOIUrl":"https://doi.org/10.4043/31266-ms","url":null,"abstract":"\u0000 Composite structures are used as corrosion insensitive load bearing reinforcement in dynamic Thermoplastic Composite Pipe (TCP) and Hybrid Flexible Pipe (HFP) applications. The qualification of such structures can follow different strategies: product level versus material characterization. DNVGL-ST-F119 proposes a generic knowledge-based approach based on a testing pyramid. The pyramid allows a generic material characterization for a large number of conditions.\u0000 Testing of dedicated specimens in constant media exposure measures the actual properties and changes of the material. Regression data is obtained for end-of-life properties. Simulations can be conducted using these properties to determine performance of the product in any state and condition and validate any load cases through classical stress combination.\u0000 The characterization for VESTAPE® Nylon 12 Carbon Fiber thermoplastic composite (CF-PA12) covers all failure mechanisms for matrix, fiber and interface in static, dynamic and stress rupture mode for virgin, fully hydrocarbon saturated and aged to end of life in saturated condition. Each condition assessment is carried out in complete temperature dependency for subzero, room temperature, intermediate and maximum use temperature of 176°F (80°C). Fatigue testing covers runtimes of 106 cycles whereas stress rupture assessment exceeds 12,500h which corresponds to almost 1.5 years. With dense data populations for both regression curves and static test results the coefficient of variation is controlled. All characterization logic and data are analyzed for validity and certified by the official body of the DNV-GL.\u0000 The material characterization enables simulation of a variety of application designs in predictive engineering and a simplified study is made for a dynamic gas injection jumper to demonstrate relevant occurring load cases.\u0000 Utilizing all data and approaches allows to define the overall application envelope of the material. For the case of the thermoplastic composite of CF-PA12 it covers static flowlines, dynamic jumpers, service lines up to dynamic risers in sour crude service up to 176°F (80°C). The knowledge-based approach allows for economic design in engineering cases without compromising safety.","PeriodicalId":11072,"journal":{"name":"Day 1 Mon, August 16, 2021","volume":"67 5-6","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-08-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"91497008","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}
Jianqiao Leng, Mingzhen Wei, B. Bai, R. Seright, Yin Zhang, D. Cercone, S. Ning
Polymer rheology can have either a positive or a negative effect on polymer flooding performance under varied circumstances. Many researchers have studied the effect of polymer rheology in a vertical well, but no field scale studies have been conducted to investigate whether polymer rheology is beneficial to polymer flooding in heavy oil reservoirs developed by horizontal wells. In this paper, we conducted a numerical simulation study to examine the effect of HPAM polymer rheology on a polymer flooding pilot, which is the first-ever project conducted on a heavy oil reservoir from Alaska North Slope (ANS) developed by horizontal wells. Three rheology types were considered in the study including the apparent viscosity measured during coreflooding of using a HPAM polymer, the bulk viscosity measured with a viscometer, and a Newtonian flow model. The results suggest that using the bulk viscosity in simulation underestimates the conformance control and the water-oil-ratio reduction capability of the HPAM polymer solution. When the apparent viscosity is used, the incremental oil and sweep were largely increased, and the optimal recovery period of polymer flooding was extended greatly, especially for the heterogeneous formations. Therefore, the rheology type of polymer plays a significant role in the incremental oil recovery and injection profile of the horizontal well system given the pilot testconditions. This study has provided practical guidance to field operators for the ongoing polymer flooding pilot on ANS and will also provide valuable information for other polymer projects conducted in similar conditions.
{"title":"Impact of Rheology Models on Horizontal Well Polymer Flooding in a Heavy Oil Reservoir on Alaska North Slope: A Simulation Study","authors":"Jianqiao Leng, Mingzhen Wei, B. Bai, R. Seright, Yin Zhang, D. Cercone, S. Ning","doi":"10.4043/31087-ms","DOIUrl":"https://doi.org/10.4043/31087-ms","url":null,"abstract":"\u0000 Polymer rheology can have either a positive or a negative effect on polymer flooding performance under varied circumstances. Many researchers have studied the effect of polymer rheology in a vertical well, but no field scale studies have been conducted to investigate whether polymer rheology is beneficial to polymer flooding in heavy oil reservoirs developed by horizontal wells. In this paper, we conducted a numerical simulation study to examine the effect of HPAM polymer rheology on a polymer flooding pilot, which is the first-ever project conducted on a heavy oil reservoir from Alaska North Slope (ANS) developed by horizontal wells. Three rheology types were considered in the study including the apparent viscosity measured during coreflooding of using a HPAM polymer, the bulk viscosity measured with a viscometer, and a Newtonian flow model. The results suggest that using the bulk viscosity in simulation underestimates the conformance control and the water-oil-ratio reduction capability of the HPAM polymer solution. When the apparent viscosity is used, the incremental oil and sweep were largely increased, and the optimal recovery period of polymer flooding was extended greatly, especially for the heterogeneous formations. Therefore, the rheology type of polymer plays a significant role in the incremental oil recovery and injection profile of the horizontal well system given the pilot testconditions. This study has provided practical guidance to field operators for the ongoing polymer flooding pilot on ANS and will also provide valuable information for other polymer projects conducted in similar conditions.","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":"91292542","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
J. L. Veiga, Antonio Jose Renno Chaves, Breno De Souza e Silva, Ivan Noville Rocha Correa Lima, Ilvan Porto Jr Pereira, Gilberto Jr Teixeira, Aldir Pimentel da Costa
During the exploration design phase of recent pre-salt development in Santos Basin, it was identified great potential for the production of some wells, generating great expectation by how it would perform in the production phase, above the average of 30,000 bpd. The Subsea and Topside design were developed based on this expectation and therefore, diameters were limited considering the premises of 45,000 bpd production from the well to the FPSO. As a result of first oil production the expectation not only became a reality but also was largely supersede, confirming a very high production potential of up to 65,000 bpd per well, some of which are at the world top list of highest production wells for deep and ultra-deep waters. Despite the outstanding high potential of the well, full production was then, not able to be achieved due to limitations considered in the design's premises of 45,000 bpd per well, what overcome the already great expectation. In this scenario, there was intense effort to make the real production potential of the wells viable. To fit the design to the new dynamic flow conditions, a multidisciplinary technical assessment team was mobilized involving several disciplines such as: Subsea Equipment, Wells, Risers, Process, Piping, Instrumentation and Automation, in addition to Operational Safety, a non-negotiable value. After technical discussions between those different disciplines, alternative proposals were raised that could make possible a safe operation under this new challenging condition. The defined actions were implemented and currently the wells already operate on high levels of production. On the FPSO with those high production wells, due to this individual increase in the production, whose potentials exceed by 45% the design capacity, generating a significant increase in the profitability of the asset, contributing to revenues anticipation in the company's cash flow. This article presents the piping and instrumentation study to deal with a high flow velocity issue. The methodology adopted to overcome the challenges in vibration and erosion considered an unusual design approach, leading to some field test to check the effectiveness of the solution. This alternative approach allowed this increment in production rate per well piping branch.
{"title":"High Production Well Operating Plant in a Traditional Design: Piping & Instrumentation Challenges","authors":"J. L. Veiga, Antonio Jose Renno Chaves, Breno De Souza e Silva, Ivan Noville Rocha Correa Lima, Ilvan Porto Jr Pereira, Gilberto Jr Teixeira, Aldir Pimentel da Costa","doi":"10.4043/31307-ms","DOIUrl":"https://doi.org/10.4043/31307-ms","url":null,"abstract":"\u0000 During the exploration design phase of recent pre-salt development in Santos Basin, it was identified great potential for the production of some wells, generating great expectation by how it would perform in the production phase, above the average of 30,000 bpd. The Subsea and Topside design were developed based on this expectation and therefore, diameters were limited considering the premises of 45,000 bpd production from the well to the FPSO.\u0000 As a result of first oil production the expectation not only became a reality but also was largely supersede, confirming a very high production potential of up to 65,000 bpd per well, some of which are at the world top list of highest production wells for deep and ultra-deep waters.\u0000 Despite the outstanding high potential of the well, full production was then, not able to be achieved due to limitations considered in the design's premises of 45,000 bpd per well, what overcome the already great expectation.\u0000 In this scenario, there was intense effort to make the real production potential of the wells viable. To fit the design to the new dynamic flow conditions, a multidisciplinary technical assessment team was mobilized involving several disciplines such as: Subsea Equipment, Wells, Risers, Process, Piping, Instrumentation and Automation, in addition to Operational Safety, a non-negotiable value.\u0000 After technical discussions between those different disciplines, alternative proposals were raised that could make possible a safe operation under this new challenging condition.\u0000 The defined actions were implemented and currently the wells already operate on high levels of production. On the FPSO with those high production wells, due to this individual increase in the production, whose potentials exceed by 45% the design capacity, generating a significant increase in the profitability of the asset, contributing to revenues anticipation in the company's cash flow.\u0000 This article presents the piping and instrumentation study to deal with a high flow velocity issue. The methodology adopted to overcome the challenges in vibration and erosion considered an unusual design approach, leading to some field test to check the effectiveness of the solution. This alternative approach allowed this increment in production rate per well piping branch.","PeriodicalId":11072,"journal":{"name":"Day 1 Mon, August 16, 2021","volume":"29 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-08-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87639012","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}
I. Noville, Milena da Silva Maciel, Anna Luiza de Moraes y blanco de Mattos, João Gabriel Carvalho de Siqueira
This article's goal is to present some of the main flow assurance challenges faced by PETROBRAS in the Buzios oil field, from its early design stages to full operation, up to this day. These challenges include: hydrate formation in WAG (Water Alternating Gas) operations; reliability of the chemical injection system to prevent scale deposition; increasing GLR (Gas Liquid Ratio) management and operations with extremely high flowrates. Flow assurance experience amassed in Buzios and in other pre-salt oil fields, regarding all these presented issues, is particularly relevant for the development of future projects with similar characteristics, such as high liquid flow rate, high CO2 content and high scaling potential.
{"title":"Flow Assurance in Buzios Field: Key Challenges and Implemented Solutions","authors":"I. Noville, Milena da Silva Maciel, Anna Luiza de Moraes y blanco de Mattos, João Gabriel Carvalho de Siqueira","doi":"10.4043/31277-ms","DOIUrl":"https://doi.org/10.4043/31277-ms","url":null,"abstract":"\u0000 This article's goal is to present some of the main flow assurance challenges faced by PETROBRAS in the Buzios oil field, from its early design stages to full operation, up to this day. These challenges include: hydrate formation in WAG (Water Alternating Gas) operations; reliability of the chemical injection system to prevent scale deposition; increasing GLR (Gas Liquid Ratio) management and operations with extremely high flowrates.\u0000 Flow assurance experience amassed in Buzios and in other pre-salt oil fields, regarding all these presented issues, is particularly relevant for the development of future projects with similar characteristics, such as high liquid flow rate, high CO2 content and high scaling potential.","PeriodicalId":11072,"journal":{"name":"Day 1 Mon, August 16, 2021","volume":"45 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-08-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86280677","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}
Gabriel Rodrigues Cabral, Helvio Ferreira da Silva, A. Oshiro, L. C. Trovoado, Thierry Hernalsteens, João Francisco Fleck Heck Britto, L. A. Pinto
Buzios field development has the potential to implement several production systems due to large reservoir volumes. Considering the oil specification, the drive to use standard solutions already in place in Pre-salt area, associated with the high production indexes of the wells, Petrobras decided to tie back all production wells in satellite configuration. These facts, together with geological hazards in the area, lead to a potentially congested seabed scenario. Hence, FPU positioning has been challenging and demanding innovative engineering solutions to optimize FPU mooring as to overcome these challenges and enable FPU positioning close to wells. This optimization gave birth to new issues, such as risk of clashing between mooring lines and lazy-wave flexible risers. Integrated riser and mooring lines dynamic analysis, together with subsea layout assessment were performed to ensure technical and economic feasibility. Furthermore, due to the Buzios reservoir, well design requirements and subsea layout specificities, all FPU were located on the edge of the reservoir and flexible risers were tied back mainly from only one board of each FPU. Hence, enhancing clearance between bow and stern mooring clusters and the optimization of the risers’ configuration were of paramount importance for enabling most of the risers’ connections on the desirable board. FPU mooring optimization led to up to 30% of mooring lines’ radius reduction (horizontal projection), and an average of up to 500m per flowline reduction, saving CAPEX, OPEX and increasing the return on investment.
{"title":"FPU Mooring Footprint Reduction in Buzios Field: Key Driver to its Successful Subsea Layout","authors":"Gabriel Rodrigues Cabral, Helvio Ferreira da Silva, A. Oshiro, L. C. Trovoado, Thierry Hernalsteens, João Francisco Fleck Heck Britto, L. A. Pinto","doi":"10.4043/31274-ms","DOIUrl":"https://doi.org/10.4043/31274-ms","url":null,"abstract":"\u0000 Buzios field development has the potential to implement several production systems due to large reservoir volumes. Considering the oil specification, the drive to use standard solutions already in place in Pre-salt area, associated with the high production indexes of the wells, Petrobras decided to tie back all production wells in satellite configuration. These facts, together with geological hazards in the area, lead to a potentially congested seabed scenario. Hence, FPU positioning has been challenging and demanding innovative engineering solutions to optimize FPU mooring as to overcome these challenges and enable FPU positioning close to wells. This optimization gave birth to new issues, such as risk of clashing between mooring lines and lazy-wave flexible risers. Integrated riser and mooring lines dynamic analysis, together with subsea layout assessment were performed to ensure technical and economic feasibility. Furthermore, due to the Buzios reservoir, well design requirements and subsea layout specificities, all FPU were located on the edge of the reservoir and flexible risers were tied back mainly from only one board of each FPU. Hence, enhancing clearance between bow and stern mooring clusters and the optimization of the risers’ configuration were of paramount importance for enabling most of the risers’ connections on the desirable board. FPU mooring optimization led to up to 30% of mooring lines’ radius reduction (horizontal projection), and an average of up to 500m per flowline reduction, saving CAPEX, OPEX and increasing the return on investment.","PeriodicalId":11072,"journal":{"name":"Day 1 Mon, August 16, 2021","volume":"40 3 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-08-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87677992","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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