Reda Bouamra, P. Petit, S. Smuk, Christophe Vielliard
The oil and gas industry has long perceived computational fluid dynamics (CFD) as a computationally expensive, high-end simulation method to analyzing extremely complex behavior. However, the recent increase in computational power and the democratization of CFD packages have enabled 3D modeling to become part of the regular in-house execution scope. This paper presents a range of flow assurance CFD applications and shows the impact of 3D workflows in the overall system design, the adoption of standard specifications, and fast-track project executions. As oil and gas fluid journeys from the reservoir pore space to production facilities, it faces a wide range of complex flow assurance issues related to the nature of the live production fluids (compositional changes, viscosity, compressibility), the production system environment (high and low pressures) and its interaction with hardware (erosion, flow induced vibration, scaling). One-dimensional mechanistic models are used to solve these flow hindrance issues in wells and pipelines but provide limited results in the complex geometries of subsea and subsurface equipment. In subsurface applications, a CFD workflow was used to tune near-wellbore reservoir properties based on advanced 1D and 3D thermal modeling of the completion interval. Accurate thermal modeling was then used to manage downhole flow assurance issues (e.g., asphaltenes and scale buildup). In subsea equipment, the methodology was used to fast-track project execution by using standardized equipment using project specific parameters at an early stage. CFD analyses were used to estimate the risk of erosion and flow-induced vibration in a subsea tree. The thermal aspect was not neglected because CFD conjugated heat transfer was used to detect cold spots and improve the thermal behavior of insulated equipment (trees, manifold) during normal production and shutdown. To avoid long and expensive material qualification campaigns, CFD was used to define the temperature gradient in trees and compare the design temperatures of materials against their calculated temperatures. The ability to perform advanced CFD calculations has become a true enabler in the ability to adopt standardized equipment and supplier-led specifications on subsea field development applications, thus contributing to better capital efficiency and shorter time from discovery to production. Several concrete examples from wide-ranging subsea field development projects worldwide are presented to illustrate the added value of CFD in all stages of engineering, from concept definition to project execution.
{"title":"A 3D Digital Approach to Flow Assurance","authors":"Reda Bouamra, P. Petit, S. Smuk, Christophe Vielliard","doi":"10.4043/29360-MS","DOIUrl":"https://doi.org/10.4043/29360-MS","url":null,"abstract":"\u0000 The oil and gas industry has long perceived computational fluid dynamics (CFD) as a computationally expensive, high-end simulation method to analyzing extremely complex behavior. However, the recent increase in computational power and the democratization of CFD packages have enabled 3D modeling to become part of the regular in-house execution scope. This paper presents a range of flow assurance CFD applications and shows the impact of 3D workflows in the overall system design, the adoption of standard specifications, and fast-track project executions.\u0000 As oil and gas fluid journeys from the reservoir pore space to production facilities, it faces a wide range of complex flow assurance issues related to the nature of the live production fluids (compositional changes, viscosity, compressibility), the production system environment (high and low pressures) and its interaction with hardware (erosion, flow induced vibration, scaling). One-dimensional mechanistic models are used to solve these flow hindrance issues in wells and pipelines but provide limited results in the complex geometries of subsea and subsurface equipment.\u0000 In subsurface applications, a CFD workflow was used to tune near-wellbore reservoir properties based on advanced 1D and 3D thermal modeling of the completion interval. Accurate thermal modeling was then used to manage downhole flow assurance issues (e.g., asphaltenes and scale buildup). In subsea equipment, the methodology was used to fast-track project execution by using standardized equipment using project specific parameters at an early stage. CFD analyses were used to estimate the risk of erosion and flow-induced vibration in a subsea tree. The thermal aspect was not neglected because CFD conjugated heat transfer was used to detect cold spots and improve the thermal behavior of insulated equipment (trees, manifold) during normal production and shutdown. To avoid long and expensive material qualification campaigns, CFD was used to define the temperature gradient in trees and compare the design temperatures of materials against their calculated temperatures.\u0000 The ability to perform advanced CFD calculations has become a true enabler in the ability to adopt standardized equipment and supplier-led specifications on subsea field development applications, thus contributing to better capital efficiency and shorter time from discovery to production. Several concrete examples from wide-ranging subsea field development projects worldwide are presented to illustrate the added value of CFD in all stages of engineering, from concept definition to project execution.","PeriodicalId":10968,"journal":{"name":"Day 3 Wed, May 08, 2019","volume":"78 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-04-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83373938","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}
Since their initial discovery in the 1960’s, gas hydrates have been considered to be an important potential source of unconventional natural gas. Significant progress has been made relative to our understanding of the geologic and engineering controls on the ultimate energy potential of gas hydrate; however, more work is required to realize the promise of gas hydrates as a future energy source. Gas hydrates have been encountered, recovered or inferred to exist in numerous sedimentary basins in Arctic permafrost settings, regions of alpine permafrost, marine sediments of outer continental margins and in deep lakes. Despite the great abundance of potential gas hydrate resources in the world, a large portion of these resources reside in clay-rich sediments and fracture dominated reservoir systems, and are not generally considered producible with existing technology, but may have future potential with the emergence of new technologies. For a large portion of the world, gas hydrate in sand reservoirs have become a viable production target and the focus of the first production testing efforts. Production tests in Arctic Canada (Mackenzie Delta) and Alaska have shown that gas can be produced from highly-concentrated gas hydrate accumulations in coarse-grained (i.e., sand rich) reservoir systems with conventional production technologies. Production can be achieved through the depressurization method and by more complex methods such as molecular substitution (e.g., CO2-CH4 exchange). In 2013, the gas hydrate production test was conducted in a marine setting in the offshore of Japan. An additional test was conducted in Japan in 2017 to further evaluate alternative well completion technologies. Also in 2018, China initiated a 60-day gas hydrate production test in the Shenhu region of the South China Sea. This report reviews the results of gas hydrate engineering and production testing studies associated with the Mallik, Mount Elbert, and Iġnik Sikumi projects in northern Canada and Alaska. The results of the marine gas hydrate producing testing efforts in the Nankai Trough (Japan) and in the South China Sea (China) are also summarized.
{"title":"Gas Hydrate Production Testing – Knowledge Gained","authors":"T. Collett","doi":"10.4043/29516-MS","DOIUrl":"https://doi.org/10.4043/29516-MS","url":null,"abstract":"\u0000 Since their initial discovery in the 1960’s, gas hydrates have been considered to be an important potential source of unconventional natural gas. Significant progress has been made relative to our understanding of the geologic and engineering controls on the ultimate energy potential of gas hydrate; however, more work is required to realize the promise of gas hydrates as a future energy source. Gas hydrates have been encountered, recovered or inferred to exist in numerous sedimentary basins in Arctic permafrost settings, regions of alpine permafrost, marine sediments of outer continental margins and in deep lakes. Despite the great abundance of potential gas hydrate resources in the world, a large portion of these resources reside in clay-rich sediments and fracture dominated reservoir systems, and are not generally considered producible with existing technology, but may have future potential with the emergence of new technologies. For a large portion of the world, gas hydrate in sand reservoirs have become a viable production target and the focus of the first production testing efforts.\u0000 Production tests in Arctic Canada (Mackenzie Delta) and Alaska have shown that gas can be produced from highly-concentrated gas hydrate accumulations in coarse-grained (i.e., sand rich) reservoir systems with conventional production technologies. Production can be achieved through the depressurization method and by more complex methods such as molecular substitution (e.g., CO2-CH4 exchange). In 2013, the gas hydrate production test was conducted in a marine setting in the offshore of Japan. An additional test was conducted in Japan in 2017 to further evaluate alternative well completion technologies. Also in 2018, China initiated a 60-day gas hydrate production test in the Shenhu region of the South China Sea.\u0000 This report reviews the results of gas hydrate engineering and production testing studies associated with the Mallik, Mount Elbert, and Iġnik Sikumi projects in northern Canada and Alaska. The results of the marine gas hydrate producing testing efforts in the Nankai Trough (Japan) and in the South China Sea (China) are also summarized.","PeriodicalId":10968,"journal":{"name":"Day 3 Wed, May 08, 2019","volume":"1 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-04-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"81900441","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
H. Lendenmann, T. Laneryd, E. Virtanen, Raphael Cagienard, T. Wagner, Kim Missing
The electrical Variable Speed Drive (VSD) system presented is designed for installation on the sea floor to drive nearby electric motors for pumps and gas compressors. A modular concept of the VSD is developed and intended to operate a wide range of subsea motors of powers from 0.5 to 18 MVA, with voltages from 2.0 kV to 7.2 kV or more, and fundamental frequencies up to 300 Hz. Step-out distances from a few km to over 600 km can be accommodated. The pressure compensated design effectively removes limits as to the depth of deployment. Pressure compensation is achieved by submerging the drive hardware including the drive transformer in a dielectric liquid which also acts as coolant. The electric power components, including capacitors, semiconductors, and the control electronics are designed with increased margins and redundant hardware, pressure resistance, and materials chosen for compatibility with the dielectric liquid, to achieve a highly reliable design of the overall VSD. The drive was deployed into shallow water in a harbor in Vaasa Finland for testing. A top side station was built implementing a "Power-In-the-Loop" approach, where the VSD output energy is recovered back into the drive input such that the grid supply only provides the lost power, but not the much higher circulated power. The drive operated more than 1000 h at 22 kV input and 6.9 - 7.2 kV output voltage at different power levels. We conclude from this first shallow water test, that all components of the VSD system work properly together up to 1000 A output current. Different operation conditions reflecting the envisioned application, including redundancy capability were successfully tested. The thermal performance was extensively verified, including an optional external heat exchanger to achieve high ratings even in warm waters. To our knowledge this is the first time a medium voltage drive is operated at 9 to 12 MVA for an extended time submerged in a sea water environment. All its modules are designed to operate down to depths of 10’000 ft / 3000 m or more and are concluding qualification according to API17F and SEPS 1002.
{"title":"Shallow Water Testing of 9 - 12 MVA Variable Speed Drive for Subsea Installation","authors":"H. Lendenmann, T. Laneryd, E. Virtanen, Raphael Cagienard, T. Wagner, Kim Missing","doi":"10.4043/29656-MS","DOIUrl":"https://doi.org/10.4043/29656-MS","url":null,"abstract":"\u0000 The electrical Variable Speed Drive (VSD) system presented is designed for installation on the sea floor to drive nearby electric motors for pumps and gas compressors. A modular concept of the VSD is developed and intended to operate a wide range of subsea motors of powers from 0.5 to 18 MVA, with voltages from 2.0 kV to 7.2 kV or more, and fundamental frequencies up to 300 Hz. Step-out distances from a few km to over 600 km can be accommodated.\u0000 The pressure compensated design effectively removes limits as to the depth of deployment. Pressure compensation is achieved by submerging the drive hardware including the drive transformer in a dielectric liquid which also acts as coolant. The electric power components, including capacitors, semiconductors, and the control electronics are designed with increased margins and redundant hardware, pressure resistance, and materials chosen for compatibility with the dielectric liquid, to achieve a highly reliable design of the overall VSD.\u0000 The drive was deployed into shallow water in a harbor in Vaasa Finland for testing. A top side station was built implementing a \"Power-In-the-Loop\" approach, where the VSD output energy is recovered back into the drive input such that the grid supply only provides the lost power, but not the much higher circulated power.\u0000 The drive operated more than 1000 h at 22 kV input and 6.9 - 7.2 kV output voltage at different power levels. We conclude from this first shallow water test, that all components of the VSD system work properly together up to 1000 A output current. Different operation conditions reflecting the envisioned application, including redundancy capability were successfully tested. The thermal performance was extensively verified, including an optional external heat exchanger to achieve high ratings even in warm waters.\u0000 To our knowledge this is the first time a medium voltage drive is operated at 9 to 12 MVA for an extended time submerged in a sea water environment. All its modules are designed to operate down to depths of 10’000 ft / 3000 m or more and are concluding qualification according to API17F and SEPS 1002.","PeriodicalId":10968,"journal":{"name":"Day 3 Wed, May 08, 2019","volume":"35 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-04-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88493223","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
This paper introduces a Bayesian methodology to conduct landslide hazard assessment. The proposed approach demonstrates how a probabilistic method can incorporate evolving information about a site for progressively more certain geotechnical characterization. The probabilistic method presented herein is called the Bayesian framework, which integrates a physics-based model defining certain characteristic or phenomenon related to the site, state of evidence on the model parameters, and experimental observations to produce an updated state of evidence on the model parameters and more confident model predictions. This study focuses on landslide geohazard of a site using the physics-based infinite block slope model to estimate the probability of submarine slope failure. The probability of failure against sliding is estimated using the predictions of the infinite slope model under static loading condition for different states of evidence on the model parameters. A state of evidence reflects the level of knowledge about a parameter which describes an attribute of the site such as bathymetry or geotechnical properties of the in-situ soil. This research studies the influence of increasing states of evidence on the confidence gain in model predictions and subsequent updates in the estimates of probability of failure. Predictions based on the infinite slope model are made using the Monte-Carlo algorithm through random sampling of the model parameters. The state of evidence on the model parameters is incorporated in the algorithm by considering the model parameters as random variables following a probability distribution function. These probability distributions, also known as the prior probability distributions, represent the initial state of evidence on the model parameters. The Bayesian framework is used to conduct sequential calibration of the infinite slope model using synthetically generated data on the shear strength of the in-situ soil. These experimental observations represent the state of evidence on the soil conditions. In this paper two sets of data containing 5 and 20 data ‘sample’ points, respectively are used to calibrate the infinite slope model. Calibration of the model results in an updated state of evidence on the model parameters and generates a new set of probability distributions known as the posterior probability distributions. The posterior distributions more accurately describe the potential range of value that the parameters can attain. Comparison between the model predictions based on the initial state of evidence and the updated states of evidence shows a gain in the certainty of the model predictions.
{"title":"The Effect of Bayesian Updating in the Hazard Assessment of Submarine Landslides","authors":"Roneet Das, P. Varela, Z. Medina-Cetina","doi":"10.4043/29669-MS","DOIUrl":"https://doi.org/10.4043/29669-MS","url":null,"abstract":"\u0000 This paper introduces a Bayesian methodology to conduct landslide hazard assessment. The proposed approach demonstrates how a probabilistic method can incorporate evolving information about a site for progressively more certain geotechnical characterization. The probabilistic method presented herein is called the Bayesian framework, which integrates a physics-based model defining certain characteristic or phenomenon related to the site, state of evidence on the model parameters, and experimental observations to produce an updated state of evidence on the model parameters and more confident model predictions. This study focuses on landslide geohazard of a site using the physics-based infinite block slope model to estimate the probability of submarine slope failure. The probability of failure against sliding is estimated using the predictions of the infinite slope model under static loading condition for different states of evidence on the model parameters. A state of evidence reflects the level of knowledge about a parameter which describes an attribute of the site such as bathymetry or geotechnical properties of the in-situ soil. This research studies the influence of increasing states of evidence on the confidence gain in model predictions and subsequent updates in the estimates of probability of failure. Predictions based on the infinite slope model are made using the Monte-Carlo algorithm through random sampling of the model parameters. The state of evidence on the model parameters is incorporated in the algorithm by considering the model parameters as random variables following a probability distribution function. These probability distributions, also known as the prior probability distributions, represent the initial state of evidence on the model parameters. The Bayesian framework is used to conduct sequential calibration of the infinite slope model using synthetically generated data on the shear strength of the in-situ soil. These experimental observations represent the state of evidence on the soil conditions. In this paper two sets of data containing 5 and 20 data ‘sample’ points, respectively are used to calibrate the infinite slope model. Calibration of the model results in an updated state of evidence on the model parameters and generates a new set of probability distributions known as the posterior probability distributions. The posterior distributions more accurately describe the potential range of value that the parameters can attain. Comparison between the model predictions based on the initial state of evidence and the updated states of evidence shows a gain in the certainty of the model predictions.","PeriodicalId":10968,"journal":{"name":"Day 3 Wed, May 08, 2019","volume":"197 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-04-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"74749097","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
The capability to predict fatigue damage continues to be critical for determining the operational life and inspection intervals of connectors and components used in offshore applications. Subsea well intervention systems are subjected to wave induced cyclic bending moments and understanding the fatigue performance of equipment is essential for determining safe operating envelopes. In this paper, a validated fatigue analysis methodology is presented for non-preloaded connectors that are used within subsea well intervention systems. The fatigue analysis methodology addresses limitations in current standards when calculating the fatigue capacities of non-preloaded connectors with different interacting component materials (i.e. low alloy steel and nickel based alloys). The methodology considers the effect on the fatigue life of both non-axisymmetric geometry/loading, FAT loading, as well as the interaction of different connector materials, capturing any potential change in hot spot locations. Three different non-preloaded connections (i.e. consisting of threaded and load shoulder connectors) were analysed using 3-D finite element analysis models, where ΔM-N curves and the associated crack initiation locations were calculated for each connector. Full-scale resonance fatigue tests were successfully performed on the three different connector types, validating the ΔM-N curves calculated using the fatigue analysis methodology. Fatigue failure (i.e. through-wall crack) was achieved in all tests between 100,000 and 5,000,000 cycles matching the predicted crack initiation location from the analysis for each connection. The validated methodology provides accurate calculation of the fatigue life and correct identification of hot spot locations. Using the validated approach described in this paper within the design process can lead to significant improvements in future designs of connectors, enabling safer operational limits and extending the service life of subsea systems.
{"title":"A Novel Approach to Fatigue Life Assessment of Subsea Connectors","authors":"D. Bennet, A. Carmichael, S. J. Roberts","doi":"10.4043/29223-MS","DOIUrl":"https://doi.org/10.4043/29223-MS","url":null,"abstract":"\u0000 The capability to predict fatigue damage continues to be critical for determining the operational life and inspection intervals of connectors and components used in offshore applications. Subsea well intervention systems are subjected to wave induced cyclic bending moments and understanding the fatigue performance of equipment is essential for determining safe operating envelopes.\u0000 In this paper, a validated fatigue analysis methodology is presented for non-preloaded connectors that are used within subsea well intervention systems. The fatigue analysis methodology addresses limitations in current standards when calculating the fatigue capacities of non-preloaded connectors with different interacting component materials (i.e. low alloy steel and nickel based alloys). The methodology considers the effect on the fatigue life of both non-axisymmetric geometry/loading, FAT loading, as well as the interaction of different connector materials, capturing any potential change in hot spot locations.\u0000 Three different non-preloaded connections (i.e. consisting of threaded and load shoulder connectors) were analysed using 3-D finite element analysis models, where ΔM-N curves and the associated crack initiation locations were calculated for each connector. Full-scale resonance fatigue tests were successfully performed on the three different connector types, validating the ΔM-N curves calculated using the fatigue analysis methodology. Fatigue failure (i.e. through-wall crack) was achieved in all tests between 100,000 and 5,000,000 cycles matching the predicted crack initiation location from the analysis for each connection. The validated methodology provides accurate calculation of the fatigue life and correct identification of hot spot locations. Using the validated approach described in this paper within the design process can lead to significant improvements in future designs of connectors, enabling safer operational limits and extending the service life of subsea systems.","PeriodicalId":10968,"journal":{"name":"Day 3 Wed, May 08, 2019","volume":"16 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-04-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77129806","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
The oil and gas industry continues to push toward subsea pumping technologies that minimize required support systems and increase system reliability. Canned motor technology has been applied successfully in other applications to achieve similar objectives including driving a subsea twin-screw pump. Applied subsea, canned motors eliminate the need for any barrier fluids within the motor, the myriad of systems and complexities necessary to store and replenish these fluids, and the mechanical shaft seals required to prevent the leaking and/or contamination of these fluids within the motors. As a direct adaptation of proven applications, seeFigure 1, subsea water treatment is ideal for canned motor technology. Therefore, a development has been initiated and will be completed in 2020 to demonstrate the first truly barrier fluidless, sealless subsea pump solution. This purpose of the paper is to identify the novel elements of this technology, review the system configuration, and describe the process and challenges of this ongoing design and qualification initiative.
{"title":"Barrier Fluidless, Sealless Seawater Canned Motor Pumps","authors":"D. Stover, Luca Travaini","doi":"10.4043/29473-MS","DOIUrl":"https://doi.org/10.4043/29473-MS","url":null,"abstract":"\u0000 The oil and gas industry continues to push toward subsea pumping technologies that minimize required support systems and increase system reliability. Canned motor technology has been applied successfully in other applications to achieve similar objectives including driving a subsea twin-screw pump. Applied subsea, canned motors eliminate the need for any barrier fluids within the motor, the myriad of systems and complexities necessary to store and replenish these fluids, and the mechanical shaft seals required to prevent the leaking and/or contamination of these fluids within the motors.\u0000 As a direct adaptation of proven applications, seeFigure 1, subsea water treatment is ideal for canned motor technology. Therefore, a development has been initiated and will be completed in 2020 to demonstrate the first truly barrier fluidless, sealless subsea pump solution.\u0000 This purpose of the paper is to identify the novel elements of this technology, review the system configuration, and describe the process and challenges of this ongoing design and qualification initiative.","PeriodicalId":10968,"journal":{"name":"Day 3 Wed, May 08, 2019","volume":"39 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-04-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"80691965","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}
An important, but relatively unexplored topic in multiphase flow modelling is the effect of thermos-physical properties on multiphase models. This is relevant in the context of 1-D modelling of large multiphase systems such as pipelines from subsea wellheads to the onshore processing facility. Millions are spent on multiphase flow simulation models, but not enough attention is given to the thermophysical models which can affect the results just as much as multiphase flow correlations. A wide variety of field data have been compared to various multiphase models. More often, the multiphase flow model needs custom "Tuning" of the thermophysical properties to closely match the production data from the field. In this presentation, we discuss the impact of water content, composition of hydrocarbons, gas to oil ratio (GOR), surface tension, liquid density, and fluid enthalpy. Typically, improving accuracy of these properties will increase the prediction of multiphase models significantly. For example, error in the temperature prediction can be reduced from 10 C to 1 C, pressure uncertainties from 25% to 5%, and liquid holdup from 30% to 10%.This presentation will present examples of each using field data, before and after this improvement. This paper will also discuss using four different equations of state (EOS) for the calculations of different properties: phase equilibrium, gas density, liquid density, and enthalpy departures. This approach is used instead of the traditional approach of using 1 cubic EOD for all properties. This talk will also present error uncertainty bands for some commercial thermodynamic simulators and their corresponding impact on the multiphase flow predictions. Among all the properties mentioned above, surface tension needs particular attention since most of the multiphase models use it as a parameters. However, it is seldom measured for most of the hydrocarbon systems. Off-the-shelf thermodynamic simulators are not able to predict the surface tension accurately because of the variable content of naturally-existing surfactants in the hydrocarbon fluids. Hence, through this presentation, we raise the question if this is the limitation of the multiphase models for design, especially since most multiphase flow correlations have not been compared over a wide range of surface tensions.
{"title":"Effect of Thermo-Physical Properties on Multiphase Flow Modeling","authors":"D. D. Erickson, Matthew Michael Farrell Pusard","doi":"10.4043/29585-MS","DOIUrl":"https://doi.org/10.4043/29585-MS","url":null,"abstract":"\u0000 An important, but relatively unexplored topic in multiphase flow modelling is the effect of thermos-physical properties on multiphase models. This is relevant in the context of 1-D modelling of large multiphase systems such as pipelines from subsea wellheads to the onshore processing facility. Millions are spent on multiphase flow simulation models, but not enough attention is given to the thermophysical models which can affect the results just as much as multiphase flow correlations.\u0000 A wide variety of field data have been compared to various multiphase models. More often, the multiphase flow model needs custom \"Tuning\" of the thermophysical properties to closely match the production data from the field. In this presentation, we discuss the impact of water content, composition of hydrocarbons, gas to oil ratio (GOR), surface tension, liquid density, and fluid enthalpy.\u0000 Typically, improving accuracy of these properties will increase the prediction of multiphase models significantly. For example, error in the temperature prediction can be reduced from 10 C to 1 C, pressure uncertainties from 25% to 5%, and liquid holdup from 30% to 10%.This presentation will present examples of each using field data, before and after this improvement. This paper will also discuss using four different equations of state (EOS) for the calculations of different properties: phase equilibrium, gas density, liquid density, and enthalpy departures. This approach is used instead of the traditional approach of using 1 cubic EOD for all properties. This talk will also present error uncertainty bands for some commercial thermodynamic simulators and their corresponding impact on the multiphase flow predictions.\u0000 Among all the properties mentioned above, surface tension needs particular attention since most of the multiphase models use it as a parameters. However, it is seldom measured for most of the hydrocarbon systems. Off-the-shelf thermodynamic simulators are not able to predict the surface tension accurately because of the variable content of naturally-existing surfactants in the hydrocarbon fluids. Hence, through this presentation, we raise the question if this is the limitation of the multiphase models for design, especially since most multiphase flow correlations have not been compared over a wide range of surface tensions.","PeriodicalId":10968,"journal":{"name":"Day 3 Wed, May 08, 2019","volume":"91 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-04-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79487375","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}
Xianbo Luo, Zhiqiang Zhu, Baolin Yue, Hongfu Shi, Yifan He
The Archean buried hillss reservoir of Z Oilfield is the first one developed in the Bohai Bay Basin in recent years. In order to develop the offshore metamorphic buried hillss reservoir with limited wells, several solutions were present in the process of ODP (Overall Development Plan) implementation. The characterization and quantitative description of fracture: The seismic forward modeling was used to identify the relationship between seismic attributes and fracture. The results showed that pre-stack shear wave impedance inversion could predict favorable reservoir development and the different frequency properties could detect the fracture. Furthermore, the rock stress field simulation based on rock physical properties was implemented to study the direction of fracture, the detailed characterization of fractured system, the quantitative prediction of high quality reservoir space distribution including porosity of fracture. This paper studied the development mechanism of buried hills reservoir with double system-fracture and matrix by comprehensive physical simulation, numerical simulation and other data. A new injection-production pattern named PT-IB (produced wells on the top of hills and injected wells in the bottom of hills) was proposed to maximize recovery factor. A new method was adopted to avoid the injected water channeling along the fractures and to enlarge the sweep efficiency by periodic change flow field. This paper also put forward a plan about early warning and judging the water channeling based on improved water oil ratio and water oil ratio derivative curve.
{"title":"The Experiences and Lessons Learned from the Development of High Temperature and High Pressure Buried Hillss Reservoir","authors":"Xianbo Luo, Zhiqiang Zhu, Baolin Yue, Hongfu Shi, Yifan He","doi":"10.4043/29438-MS","DOIUrl":"https://doi.org/10.4043/29438-MS","url":null,"abstract":"\u0000 The Archean buried hillss reservoir of Z Oilfield is the first one developed in the Bohai Bay Basin in recent years. In order to develop the offshore metamorphic buried hillss reservoir with limited wells, several solutions were present in the process of ODP (Overall Development Plan) implementation.\u0000 The characterization and quantitative description of fracture: The seismic forward modeling was used to identify the relationship between seismic attributes and fracture. The results showed that pre-stack shear wave impedance inversion could predict favorable reservoir development and the different frequency properties could detect the fracture. Furthermore, the rock stress field simulation based on rock physical properties was implemented to study the direction of fracture, the detailed characterization of fractured system, the quantitative prediction of high quality reservoir space distribution including porosity of fracture. This paper studied the development mechanism of buried hills reservoir with double system-fracture and matrix by comprehensive physical simulation, numerical simulation and other data. A new injection-production pattern named PT-IB (produced wells on the top of hills and injected wells in the bottom of hills) was proposed to maximize recovery factor. A new method was adopted to avoid the injected water channeling along the fractures and to enlarge the sweep efficiency by periodic change flow field. This paper also put forward a plan about early warning and judging the water channeling based on improved water oil ratio and water oil ratio derivative curve.","PeriodicalId":10968,"journal":{"name":"Day 3 Wed, May 08, 2019","volume":"342 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-04-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"76397577","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
The paper will present the design of a floating platform incorporating the following systems: Conventional Wind Turbine Long and Short Period Wave Energy Capture Ocean Thermal Energy Conversion (OTEC) Open Flow Current Turbines Energy Storage The focus will be integration of the systems from a structural standpoint; effects on the cost of each system and the resulting LCOE and overnight cost; and the nameplate and peak power for given conditions. Energy mechanisms in the marine environment are the wind, waves, water currents, and seawater temperature differences. An assessment and rating of the energy resource potential of a given development site is used to inform the renewable energy technology system selection process. Offshore Renewable Energy (ORE) technologies can be summarized into the following groups: Offshore Wind Turbines are the prevalent ORE technology exploiting the present market, similar to onshore wind turbines, but mounted upon a fixed or floating offshore platform. Ocean Thermal Energy Conversion (OTEC) uses the temperature differential between surface water and seabed water to drive heat engines. Marine Hydro-Kinetic (MHK) devices convert energy from waves or fluid flow. Wave Energy Converters (WEC) are oscillating/reciprocal/pressure driven systems operating at or near the ocean surface or bottom mounted in shallow waters. Flow Energy Converters (FEC) are used in areas where velocity and direction of water flow is relatively constant or highly predictable if intermittent (tidal). Unlike an onshore wind energy site, offshore wind energy systems (especially floating ones) are surrounded by these other energy sources; the integrated renewable energy facility design process addresses selecting systems that will complement each other while capturing the energy resident in the operating environment, as well as leveraging the wind turbine supporting structure and infrastructure to reduce the costs of the WEC, FEC and OTEC systems. The amount of CAPEX spent on non-power generating equipment can be optimized by leveraging the floating system structure cost to host various ORE technologies. Between 50% and 70% of the overnight cost of a typical MHK or OTEC facility will consist of equipment and activities that do not generate power. This is one of the key differences with offshore wind which has an overnight capital cost overhead of roughly 30%. By combining multiple technologies into a single platform, it is possible to reduce the MHK overhead costs to 18 to 36%, with little or no effect on the offshore wind overhead costs. The resulting design is novel in configuration which takes the form of a Multi-source Articulated Spar Leg (MASL) platform and can reduce the Levelized Cost of Energy (LCOE – the economic measure used to compare energy systems) by at least 25%; can be fabricated and pre-commissioned in port; is fully configurable to the local conditions; is more stable than the current floating wind designs in use
{"title":"Design of a Multi-Source Offshore Renewable Energy Platform","authors":"G. Engelmann, Roy Robinson","doi":"10.4043/29670-MS","DOIUrl":"https://doi.org/10.4043/29670-MS","url":null,"abstract":"\u0000 The paper will present the design of a floating platform incorporating the following systems:\u0000 Conventional Wind Turbine\u0000 Long and Short Period Wave Energy Capture\u0000 Ocean Thermal Energy Conversion (OTEC)\u0000 Open Flow Current Turbines\u0000 Energy Storage\u0000 The focus will be integration of the systems from a structural standpoint; effects on the cost of each system and the resulting LCOE and overnight cost; and the nameplate and peak power for given conditions.\u0000 Energy mechanisms in the marine environment are the wind, waves, water currents, and seawater temperature differences. An assessment and rating of the energy resource potential of a given development site is used to inform the renewable energy technology system selection process. Offshore Renewable Energy (ORE) technologies can be summarized into the following groups:\u0000 Offshore Wind Turbines are the prevalent ORE technology exploiting the present market, similar to onshore wind turbines, but mounted upon a fixed or floating offshore platform.\u0000 Ocean Thermal Energy Conversion (OTEC) uses the temperature differential between surface water and seabed water to drive heat engines.\u0000 Marine Hydro-Kinetic (MHK) devices convert energy from waves or fluid flow.\u0000 Wave Energy Converters (WEC) are oscillating/reciprocal/pressure driven systems operating at or near the ocean surface or bottom mounted in shallow waters.\u0000 Flow Energy Converters (FEC) are used in areas where velocity and direction of water flow is relatively constant or highly predictable if intermittent (tidal).\u0000 Unlike an onshore wind energy site, offshore wind energy systems (especially floating ones) are surrounded by these other energy sources; the integrated renewable energy facility design process addresses selecting systems that will complement each other while capturing the energy resident in the operating environment, as well as leveraging the wind turbine supporting structure and infrastructure to reduce the costs of the WEC, FEC and OTEC systems.\u0000 The amount of CAPEX spent on non-power generating equipment can be optimized by leveraging the floating system structure cost to host various ORE technologies.\u0000 Between 50% and 70% of the overnight cost of a typical MHK or OTEC facility will consist of equipment and activities that do not generate power. This is one of the key differences with offshore wind which has an overnight capital cost overhead of roughly 30%. By combining multiple technologies into a single platform, it is possible to reduce the MHK overhead costs to 18 to 36%, with little or no effect on the offshore wind overhead costs.\u0000 The resulting design is novel in configuration which takes the form of a Multi-source Articulated Spar Leg (MASL) platform and can reduce the Levelized Cost of Energy (LCOE – the economic measure used to compare energy systems) by at least 25%; can be fabricated and pre-commissioned in port; is fully configurable to the local conditions; is more stable than the current floating wind designs in use","PeriodicalId":10968,"journal":{"name":"Day 3 Wed, May 08, 2019","volume":"18 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-04-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"85873712","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}
Recent focus of the LNG industry has been on developing technologies to decrease capital investment and increase operational efficiency to reduce overall cost of supply. Pursuing this target, a novel, compact, and high efficiency expander-based liquefaction technology has been developed to monetize gas assets. The technology uses a single phase methane refrigerant stream operating at distinguishingly high pressures followed by a single phase nitrogen refrigerant stream. Such a configuration dramatically improves energy efficiency (by 10 - 25 %) and train production capacity (by 100 - 150%) compared to other expander-based technologies, while maintaining process simplicity, lower equipment count, and lighter weight relative to mixed-refrigerant based liquefaction processes. Furthermore, integrating with a front-end heavy hydrocarbon removal unit, the technology also enables standardized liquefaction train design for a wide range of gas composition around a nominal train capacity. The standard design is well suited for parallel train configurations and phased development philosophy to drive design and execution efficiency. In addition to CAPEX savings, the weight and footprint savings are beneficial in locations where space is at a premium. While the technology platform is broadly applicable for both offshore and onshore opportunities, this paper will focus on a recent offshore LNG project which showcased the technology's significant benefit in CAPEX, weight, footprint, personnel safety, insensitivity to ocean motion, refrigerant handling and many other operation advantages. It even enabled production capacity increase from 3.5 to 4.6 on the same circular hull floating facility, proving itself as a game changer to reduce cost of supply of this liquefaction project.
{"title":"The High Pressure Expander Process Technology for LNG Applications","authors":"Liu Yijun, Fritz Pierre, A. K. Nagavarapu","doi":"10.4043/29379-MS","DOIUrl":"https://doi.org/10.4043/29379-MS","url":null,"abstract":"Recent focus of the LNG industry has been on developing technologies to decrease capital investment and increase operational efficiency to reduce overall cost of supply. Pursuing this target, a novel, compact, and high efficiency expander-based liquefaction technology has been developed to monetize gas assets. The technology uses a single phase methane refrigerant stream operating at distinguishingly high pressures followed by a single phase nitrogen refrigerant stream. Such a configuration dramatically improves energy efficiency (by 10 - 25 %) and train production capacity (by 100 - 150%) compared to other expander-based technologies, while maintaining process simplicity, lower equipment count, and lighter weight relative to mixed-refrigerant based liquefaction processes. Furthermore, integrating with a front-end heavy hydrocarbon removal unit, the technology also enables standardized liquefaction train design for a wide range of gas composition around a nominal train capacity. The standard design is well suited for parallel train configurations and phased development philosophy to drive design and execution efficiency. In addition to CAPEX savings, the weight and footprint savings are beneficial in locations where space is at a premium. While the technology platform is broadly applicable for both offshore and onshore opportunities, this paper will focus on a recent offshore LNG project which showcased the technology's significant benefit in CAPEX, weight, footprint, personnel safety, insensitivity to ocean motion, refrigerant handling and many other operation advantages. It even enabled production capacity increase from 3.5 to 4.6 on the same circular hull floating facility, proving itself as a game changer to reduce cost of supply of this liquefaction project.","PeriodicalId":10968,"journal":{"name":"Day 3 Wed, May 08, 2019","volume":"293 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-04-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"91459716","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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