The development of HPHT oilfield equipment has typically resulted in the construction of heavy-walled designs, where the increase in rated working pressure is accommodated by an increase in sectional thickness. This manner of design, however, is limited by practical difficulties which arise in the areas of manufacturing, handling/lifting, and uniformity of through-thickness material properties. Designs of more efficient size and weight may be developed by relaxing assumed design factors and hydrotest pressures, but this requires more rigorous analysis, validation, and QA measures. In particular, designers must address the fatigue susceptibility of HPHT equipment which, even in purely static conditions, may fail under cycles of shut-in pressure alone. These failures typically originate from stress risers such as cross-bores, seat pockets, or transitions in bore diameter, which exhibit complex stress states under the action of internal pressure. A fracture mechanics (FM) based analysis of such features has presented a longstanding challenge to designers and analysts as general solutions for their KI and σref are not presently available. It is therefore the objective of this paper to provide a useful methodology for conducting FM-based analysis of arbitrary geometry using the KI and σref solutions provided in API 579-1/ASME FFS-1. The method is presented in the form of a case study which describes the FM-based fatigue analysis of a seat pocket radius within a valve body. Here, the mode I behavior of a hypothetical surface-breaking, semi-elliptical flaw located at the seat pocket radius is evaluated by means of 3D finite element analysis. This method generally comprises two parts. The first involves the development of a 3D finite element model similar to what would be used in a conventional durability analysis. From this model, stresses are extracted along an anticipated fracture plane and used in conjunction with a weight function method to derive KI and σref from solutions provided in API 579-1/ASME FFS-1. These solutions are then used to compute the number of cycles to unstable fracture. The second part involves the direct incorporation of cracks into the finite element model. The approach benefits from a submodeling technique which reduces computational expense and allows the method to be used on complex structures. The numerical model is used in conjunction with conventional linear-elastic fracture mechanics assumptions to derive KI solutions for the geometry of interest. These KI results are used to confirm the conservatism of the code-based solutions and, thereby, the conservatism of the previous FM analysis. The method described in this paper allows designers to rapidly develop and execute FM-based fatigue analyses of arbitrary geometric features in timeframes similar to those associated with traditional S-N analysis.
{"title":"Fracture Mechanics Based Fatigue Assessment of an HPHT Valve Body","authors":"J. Sahoo, M. Campbell, M. Cerkovnik","doi":"10.4043/29249-MS","DOIUrl":"https://doi.org/10.4043/29249-MS","url":null,"abstract":"\u0000 The development of HPHT oilfield equipment has typically resulted in the construction of heavy-walled designs, where the increase in rated working pressure is accommodated by an increase in sectional thickness. This manner of design, however, is limited by practical difficulties which arise in the areas of manufacturing, handling/lifting, and uniformity of through-thickness material properties. Designs of more efficient size and weight may be developed by relaxing assumed design factors and hydrotest pressures, but this requires more rigorous analysis, validation, and QA measures.\u0000 In particular, designers must address the fatigue susceptibility of HPHT equipment which, even in purely static conditions, may fail under cycles of shut-in pressure alone. These failures typically originate from stress risers such as cross-bores, seat pockets, or transitions in bore diameter, which exhibit complex stress states under the action of internal pressure. A fracture mechanics (FM) based analysis of such features has presented a longstanding challenge to designers and analysts as general solutions for their KI and σref are not presently available.\u0000 It is therefore the objective of this paper to provide a useful methodology for conducting FM-based analysis of arbitrary geometry using the KI and σref solutions provided in API 579-1/ASME FFS-1. The method is presented in the form of a case study which describes the FM-based fatigue analysis of a seat pocket radius within a valve body. Here, the mode I behavior of a hypothetical surface-breaking, semi-elliptical flaw located at the seat pocket radius is evaluated by means of 3D finite element analysis.\u0000 This method generally comprises two parts. The first involves the development of a 3D finite element model similar to what would be used in a conventional durability analysis. From this model, stresses are extracted along an anticipated fracture plane and used in conjunction with a weight function method to derive KI and σref from solutions provided in API 579-1/ASME FFS-1. These solutions are then used to compute the number of cycles to unstable fracture.\u0000 The second part involves the direct incorporation of cracks into the finite element model. The approach benefits from a submodeling technique which reduces computational expense and allows the method to be used on complex structures. The numerical model is used in conjunction with conventional linear-elastic fracture mechanics assumptions to derive KI solutions for the geometry of interest. These KI results are used to confirm the conservatism of the code-based solutions and, thereby, the conservatism of the previous FM analysis.\u0000 The method described in this paper allows designers to rapidly develop and execute FM-based fatigue analyses of arbitrary geometric features in timeframes similar to those associated with traditional S-N analysis.","PeriodicalId":10968,"journal":{"name":"Day 3 Wed, May 08, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-04-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"75178424","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}
Interest in dual nitrogen expander liquefaction technology for floating liquefied natural gas (FLNG) applications is driven by the following factors: inflammable refrigerantsimplicitylow weightno refrigerant sloshing or maldistribution due to motionquick start-upeasy adjustment for changing feed conditions The downside is that dual nitrogen expander technology offers significantly lower liquefaction efficiency than competing FLNG technologies. The proper selection and sizing of the upstream gas treating and liquefaction system is critical during Front End Engineering Design (FEED) to ensure that the system footprint, weight and center-of-gravity is appropriately estimated as this effects the sizing, design and performance of the floating hull. This paper will demonstrate how the process design can be optimized over a range of feed compositions or conditions if some flexibility is built into the liquefaction heat exchange during design. This preserves flexibility as a key advantage of the technology. The intent is to reduce process inefficiencies and promote competitiveness with other technologies. Note that there are many different nitrogen expander technology configurations available in the market. The configuration used here is generic and used to demonstrate the optimization concept. With 10 independent variables and coupling between the variables, this optimization is difficult to perform using simple manual methods. Therefore we will employ a coupled simulation-optimization method. This paper also provides insight to the application of coupled simulation-optimization to problems, as illustrated by the specific application to a dual titrogen expander technology. Although this method is applicable to the initial design of liquefaction processes, the focus here is on off-design optimization of the facility later in the design cycle and in operation. This optimization methodology is shown to provide benefits beyond the initial process design, extending into the operation of the facility. The methodology does not rely upon a specific tool set and there are non-academic tools that support this approach.
{"title":"Application of Coupled Simulation Optimization Methodology to Study Dual Nitrogen Expander Liquefaction Response to Feed Gas Variations from an Optimized Design","authors":"S. Tierling, D. Attaway","doi":"10.4043/29591-MS","DOIUrl":"https://doi.org/10.4043/29591-MS","url":null,"abstract":"\u0000 Interest in dual nitrogen expander liquefaction technology for floating liquefied natural gas (FLNG) applications is driven by the following factors: inflammable refrigerantsimplicitylow weightno refrigerant sloshing or maldistribution due to motionquick start-upeasy adjustment for changing feed conditions\u0000 The downside is that dual nitrogen expander technology offers significantly lower liquefaction efficiency than competing FLNG technologies. The proper selection and sizing of the upstream gas treating and liquefaction system is critical during Front End Engineering Design (FEED) to ensure that the system footprint, weight and center-of-gravity is appropriately estimated as this effects the sizing, design and performance of the floating hull.\u0000 This paper will demonstrate how the process design can be optimized over a range of feed compositions or conditions if some flexibility is built into the liquefaction heat exchange during design. This preserves flexibility as a key advantage of the technology. The intent is to reduce process inefficiencies and promote competitiveness with other technologies. Note that there are many different nitrogen expander technology configurations available in the market. The configuration used here is generic and used to demonstrate the optimization concept.\u0000 With 10 independent variables and coupling between the variables, this optimization is difficult to perform using simple manual methods. Therefore we will employ a coupled simulation-optimization method.\u0000 This paper also provides insight to the application of coupled simulation-optimization to problems, as illustrated by the specific application to a dual titrogen expander technology. Although this method is applicable to the initial design of liquefaction processes, the focus here is on off-design optimization of the facility later in the design cycle and in operation.\u0000 This optimization methodology is shown to provide benefits beyond the initial process design, extending into the operation of the facility. The methodology does not rely upon a specific tool set and there are non-academic tools that support this approach.","PeriodicalId":10968,"journal":{"name":"Day 3 Wed, May 08, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-04-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"81197789","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}
Deepwater natural gas hydrate resources potentially exceed all other conventional and non-conventional hydrocarbon resources on a world-wide basis. However, before these offshore gas hydrate resources can be classified as reserves, it must be demonstrated that gas hydrates can be produced under conditions that make economic sense. The purpose of this paper is to provide an overview of the technical issues that will challenge the development of deepwater natural gas hydrates.
{"title":"Development of Deepwater Natural Gas Hydrates","authors":"S. Hancock, R. Boswell, T. Collett","doi":"10.4043/29374-MS","DOIUrl":"https://doi.org/10.4043/29374-MS","url":null,"abstract":"\u0000 Deepwater natural gas hydrate resources potentially exceed all other conventional and non-conventional hydrocarbon resources on a world-wide basis. However, before these offshore gas hydrate resources can be classified as reserves, it must be demonstrated that gas hydrates can be produced under conditions that make economic sense. The purpose of this paper is to provide an overview of the technical issues that will challenge the development of deepwater natural gas hydrates.","PeriodicalId":10968,"journal":{"name":"Day 3 Wed, May 08, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-04-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79031672","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}
Raymond A. Eghorieta, Victor Pugliese, Ekarit Panacharoensawad
Drift velocity for two-phase air and high viscosity oil has been studies in depth, in this research. The drift velocity is one of the key parameters used in the prediction of gas-liquid two-phase flow hydrodynamic behavior. Improvement on the drift velocity closure relationship allows a better design for pipelines and wellbores system that experience two-phase flow phenomena. Researchers have relied on empirical correlations as a means to predict the drift velocity. These empirical correlations have been limited to the flow of gas and low viscosity (20 cp and lower) liquid. In this study, the effect of drift velocity on gas and high viscosity two-phase flow in pipelines have been investigated. Drift velocity experiments and numerical calculation were carefully performed. A well-designed 1.5-in internal diameter flow loop facility with the capability of pressure drop and liquid holdup measurement was used for this drift flux velocity measurement. Various computational intensive simulations for drift velocities have been performed. A new empirical correlation was developed for the prediction of the drift velocity in horizontal and near horizontal pipelines. The effects of inclination and pipe diameters have been accounted for in the new correlation which increase its range of applicability. The correlation was validated and compared with other existing drift velocity correlations and experimental data. The new closure relationship allows a significant improvement on the pressure drop prediction for the cases of two-phase gas and high-viscosity-liquid flow in pipe. This enable the transient calculation for subsea pipeline transporting gas and high-viscosity oil by using a drift flux model.
{"title":"Experimental and Numerical Studies on the Drift Velocity of Two-Phase Gas and High-Viscosity-Liquid Slug Flow in Pipelines","authors":"Raymond A. Eghorieta, Victor Pugliese, Ekarit Panacharoensawad","doi":"10.4043/29252-MS","DOIUrl":"https://doi.org/10.4043/29252-MS","url":null,"abstract":"\u0000 \u0000 \u0000 Drift velocity for two-phase air and high viscosity oil has been studies in depth, in this research. The drift velocity is one of the key parameters used in the prediction of gas-liquid two-phase flow hydrodynamic behavior. Improvement on the drift velocity closure relationship allows a better design for pipelines and wellbores system that experience two-phase flow phenomena.\u0000 \u0000 \u0000 \u0000 Researchers have relied on empirical correlations as a means to predict the drift velocity. These empirical correlations have been limited to the flow of gas and low viscosity (20 cp and lower) liquid. In this study, the effect of drift velocity on gas and high viscosity two-phase flow in pipelines have been investigated. Drift velocity experiments and numerical calculation were carefully performed. A well-designed 1.5-in internal diameter flow loop facility with the capability of pressure drop and liquid holdup measurement was used for this drift flux velocity measurement. Various computational intensive simulations for drift velocities have been performed.\u0000 \u0000 \u0000 \u0000 A new empirical correlation was developed for the prediction of the drift velocity in horizontal and near horizontal pipelines. The effects of inclination and pipe diameters have been accounted for in the new correlation which increase its range of applicability.\u0000 \u0000 \u0000 \u0000 The correlation was validated and compared with other existing drift velocity correlations and experimental data. The new closure relationship allows a significant improvement on the pressure drop prediction for the cases of two-phase gas and high-viscosity-liquid flow in pipe. This enable the transient calculation for subsea pipeline transporting gas and high-viscosity oil by using a drift flux model.\u0000","PeriodicalId":10968,"journal":{"name":"Day 3 Wed, May 08, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-04-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"73978216","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}
M. Ducasse, C. Colmard, T. Delahaye, F. Vertallier, Stéphane Rigaud
A new Floating Sub-Structure concept has been developed for Floating Offshore Wind Turbine (FOWT). It consists of a floating tubular sub-structure connected with tendons to a counterweight providing pendulum-restoring forces. The whole floating system is anchored with six low-tension mooring lines. Model tests were carried out in wave basin test facilities at Ecole Centrale de Nantes to provide insight into hydrodynamic behavior of the system under operational and extreme wave conditions. Two installation depths were studied: intermediate and deeper water depth configurations with 75 and 150 meters water depth respectively. Two wind turbine capacities were tested: 8MW and 12MW. Responses of the system were investigated under different irregular wave conditions: operational condition with significant wave height Hs = 4 m and two extreme wave conditions with significant wave heights Hs=8m and 14 m. Sensitivity tests were also performed for various wave periods Tp (Tp = 8, 12 and 16 seconds). Results of these tests demonstrate that the floater is extremely stable with very low pitch motions as well as low vertical & horizontal accelerations both in operational and extreme wave conditions. Detailed results are presented in this paper. This stable dynamic behavior is obtained because natural periods of the floater are far away from wave spectrum peak and it thus leads to low dynamic loads in the mooring lines. This beneficial seakeeping feature and the possibility of accommodating even larger wind turbines with minor modifications on the floater design make the proposed FOWT a relevant concept for the upcoming offshore floating wind market.
针对浮式海上风力发电机组，提出了一种新的浮式子结构概念。它由一个浮动的管状子结构组成，该子结构与提供钟摆恢复力的配重的肌腱相连。整个浮式系统由六条低压系泊绳锚定。模型测试在Ecole Centrale de Nantes的波浪池测试设施中进行，以深入了解系统在操作和极端波浪条件下的水动力行为。研究了两种安装深度:中间水深75米和较深水深150米配置。测试了两种风力涡轮机的容量:8MW和12MW。研究了系统在有效波高Hs= 4 m的运行工况和有效波高Hs=8m和14 m的两种极端波高工况下的响应。对不同波周期Tp (Tp = 8、12和16秒)进行敏感性试验。这些测试结果表明，无论是在工作条件还是极端波浪条件下，该浮子在非常低的俯仰运动以及低的垂直和水平加速度下都非常稳定。本文给出了详细的结果。这种稳定的动力特性是由于浮子的自然周期远离波谱峰值，从而使系泊索的动载荷较低。这种有利的耐波性和容纳更大的风力涡轮机的可能性，对浮子设计进行微小的修改，使拟议的FOWT成为即将到来的海上浮式风力市场的相关概念。
{"title":"Basin Test Validation of New Pendulum Offshore Wind Turbine","authors":"M. Ducasse, C. Colmard, T. Delahaye, F. Vertallier, Stéphane Rigaud","doi":"10.4043/29623-MS","DOIUrl":"https://doi.org/10.4043/29623-MS","url":null,"abstract":"\u0000 A new Floating Sub-Structure concept has been developed for Floating Offshore Wind Turbine (FOWT). It consists of a floating tubular sub-structure connected with tendons to a counterweight providing pendulum-restoring forces. The whole floating system is anchored with six low-tension mooring lines. Model tests were carried out in wave basin test facilities at Ecole Centrale de Nantes to provide insight into hydrodynamic behavior of the system under operational and extreme wave conditions. Two installation depths were studied: intermediate and deeper water depth configurations with 75 and 150 meters water depth respectively. Two wind turbine capacities were tested: 8MW and 12MW. Responses of the system were investigated under different irregular wave conditions: operational condition with significant wave height Hs = 4 m and two extreme wave conditions with significant wave heights Hs=8m and 14 m. Sensitivity tests were also performed for various wave periods Tp (Tp = 8, 12 and 16 seconds). Results of these tests demonstrate that the floater is extremely stable with very low pitch motions as well as low vertical & horizontal accelerations both in operational and extreme wave conditions. Detailed results are presented in this paper. This stable dynamic behavior is obtained because natural periods of the floater are far away from wave spectrum peak and it thus leads to low dynamic loads in the mooring lines. This beneficial seakeeping feature and the possibility of accommodating even larger wind turbines with minor modifications on the floater design make the proposed FOWT a relevant concept for the upcoming offshore floating wind market.","PeriodicalId":10968,"journal":{"name":"Day 3 Wed, May 08, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-04-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"75157321","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}
Practices for engineering, design, qualification, and implementation of drilling, completions, production, and intervention equipment for high-pressure high-temperature (HPHT) developments have matured sufficiently to enable the next frontier of projects in the Gulf of Mexico (GoM). Per the code of federal regulations, the Bureau of Safety and Environmental Enforcement (BSEE) regulates oil and gas exploration, development, and production operations on the Outer Continental Shelf (OCS). Unlike historical OCS projects with pressures less than 15,000 psi and temperatures less than 350°F where subsea production equipment is governed by codes and standards referenced in 30 CFR 250.804(b), equipment required for well completion or well control in HPHT environments in most instances exceeds the ratings prescribed in these established codes and standards. Industry's initial attempt to address all wellbore issues and challenges associated with HPHT from sand face to pipeline in a holistic manner was through API TR PER15K, 1st Ed. which was released in March 2013. API PER15K was never intended to serve as a guideline for HPHT design verification and validation, thus additional direction was needed. To address the need for extension of industry codes and standards to ratings needed for HPHT equipment, the 1st Edition of API 17TR8 was released in February 2015 and represented Industry's initial guideline for HPHT subsea equipment development. Through use of the guideline, key lessons learned, and technical gaps were identified and incorporated into the document, which is now reflected in the 2nd Edition released in March 2018. As industry-led equipment development programs have progressed to a mature stage, Chevron has identified two topics in API 17TR8 which serve as the fundamental drivers for defining equipment operational limitations: Extreme/Survival ratings for equipment designed according to Elastic-Plastic (E-P) design methods as prescribed in ASME Section VIII Div. 2 & Div. 3,Equipment serviceability criteria. The current guidance in 17TR8 is quite clear as it relates to defining equipment capacity via FEA but puts the onus on the Offshore Equipment Manufacturer (OEM) and Operator to define how serviceability can impact operational limits. Industry has presented work to validate the normal, extreme, and survival load factors for E-P analysis (Ref. Dril-Quip OTC-27605-MS), but most of this work has been performed on non-complex, single body geometries. Similarly, the industry is wrestling with a consistent view of how to address serviceability. This paper discusses the following: 1.) Recommended design codes in API 17TR8 and an Operator's perspective on application of these codes; 2.) How to address uncertainties that exist in the design, qualification, and manufacturing process; 3.) Using the aforementioned guidelines when performing a component-based verification & validation process; 4.) How to define system operational limits and ensure sys
{"title":"HPHT Subsea Equipment Verification & Validation: Understanding Operational Limits","authors":"M. Vaclavik","doi":"10.4043/29474-MS","DOIUrl":"https://doi.org/10.4043/29474-MS","url":null,"abstract":"\u0000 Practices for engineering, design, qualification, and implementation of drilling, completions, production, and intervention equipment for high-pressure high-temperature (HPHT) developments have matured sufficiently to enable the next frontier of projects in the Gulf of Mexico (GoM). Per the code of federal regulations, the Bureau of Safety and Environmental Enforcement (BSEE) regulates oil and gas exploration, development, and production operations on the Outer Continental Shelf (OCS). Unlike historical OCS projects with pressures less than 15,000 psi and temperatures less than 350°F where subsea production equipment is governed by codes and standards referenced in 30 CFR 250.804(b), equipment required for well completion or well control in HPHT environments in most instances exceeds the ratings prescribed in these established codes and standards. Industry's initial attempt to address all wellbore issues and challenges associated with HPHT from sand face to pipeline in a holistic manner was through API TR PER15K, 1st Ed. which was released in March 2013. API PER15K was never intended to serve as a guideline for HPHT design verification and validation, thus additional direction was needed.\u0000 To address the need for extension of industry codes and standards to ratings needed for HPHT equipment, the 1st Edition of API 17TR8 was released in February 2015 and represented Industry's initial guideline for HPHT subsea equipment development. Through use of the guideline, key lessons learned, and technical gaps were identified and incorporated into the document, which is now reflected in the 2nd Edition released in March 2018.\u0000 As industry-led equipment development programs have progressed to a mature stage, Chevron has identified two topics in API 17TR8 which serve as the fundamental drivers for defining equipment operational limitations: Extreme/Survival ratings for equipment designed according to Elastic-Plastic (E-P) design methods as prescribed in ASME Section VIII Div. 2 & Div. 3,Equipment serviceability criteria.\u0000 The current guidance in 17TR8 is quite clear as it relates to defining equipment capacity via FEA but puts the onus on the Offshore Equipment Manufacturer (OEM) and Operator to define how serviceability can impact operational limits.\u0000 Industry has presented work to validate the normal, extreme, and survival load factors for E-P analysis (Ref. Dril-Quip OTC-27605-MS), but most of this work has been performed on non-complex, single body geometries. Similarly, the industry is wrestling with a consistent view of how to address serviceability. This paper discusses the following: 1.) Recommended design codes in API 17TR8 and an Operator's perspective on application of these codes; 2.) How to address uncertainties that exist in the design, qualification, and manufacturing process; 3.) Using the aforementioned guidelines when performing a component-based verification & validation process; 4.) How to define system operational limits and ensure sys","PeriodicalId":10968,"journal":{"name":"Day 3 Wed, May 08, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-04-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"75391475","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 new classes of hang-offs for Steel Catenary Risers (SCRs) and Steel Lazy Wave Risers (SLWRs). Bending and tension loads are totally decoupled in the riser hang-offs presented. The new hang-offs can be designed for any temperature or pressure that can be supported by SCRs or SLWRs. The novel devices have rotational stiffnesses considerably lower than are those of Flexible Joints or Titanium Stress Joints (TSJs). This results in fatigue life improvements in the upper regions of risers and in supporting vessel structure. The new hang-offs can be easily designed for greater riser deflections than are those feasible with traditional hang-offs. Methodology used in preliminary design is outlined. Simplified preliminary calculations are included and results of non-linear (large deflection) Finite Elements Analyses (FEAs) are provided. This work highlights possible practical implications of the new designs for the envelopes of the use of SCRs and SLWRs.
{"title":"Design of New Classes of Flexible Hang-Offs for Rigid Risers","authors":"C. Wajnikonis","doi":"10.4043/29609-MS","DOIUrl":"https://doi.org/10.4043/29609-MS","url":null,"abstract":"\u0000 This paper introduces new classes of hang-offs for Steel Catenary Risers (SCRs) and Steel Lazy Wave Risers (SLWRs). Bending and tension loads are totally decoupled in the riser hang-offs presented. The new hang-offs can be designed for any temperature or pressure that can be supported by SCRs or SLWRs. The novel devices have rotational stiffnesses considerably lower than are those of Flexible Joints or Titanium Stress Joints (TSJs). This results in fatigue life improvements in the upper regions of risers and in supporting vessel structure. The new hang-offs can be easily designed for greater riser deflections than are those feasible with traditional hang-offs. Methodology used in preliminary design is outlined. Simplified preliminary calculations are included and results of non-linear (large deflection) Finite Elements Analyses (FEAs) are provided. This work highlights possible practical implications of the new designs for the envelopes of the use of SCRs and SLWRs.","PeriodicalId":10968,"journal":{"name":"Day 3 Wed, May 08, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-04-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89569589","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 investigation is made into the use of a fiber optic sensing system for monitoring and measuring fluid flow in pipes. This is done using two fiber optics sensing systems, a Distributed Acoustic Sensing "DAS" system and a Fiber Bragg Grating "FBG" system. A laboratory setup is used to conduct these tests and the setup is structured to simulate an offshore environment. The laboratory setup consists of a water reservoir that flows water through PVC pipes into a tank, fibers are attached to the pipes, and a flow meter is used to measure the flow rates. From the conducted flow experiments, a relationship between flow rates, DAS amplitudes, and FBG wavelength shifts is built. This paper presents the response of fiber optic sensing systems to flow experiments that were conducted with various flow rates, and simulated leak tests with and without flow. The results are used to establish a relationship between the fiber optic response and flow variation, to develop a method of measuring flow rates via the fiber optic systems. Such that any pipes equipped with fiber optics could be used to measure approximate flow rates. This study finds a strong correlation between the fiber optic sensing systems measurements and measured flow rates. In the FBG system, flow was found to have two influences on the FBG measurement; an increase in flow shows an increase in the FBG sensor wavelength, also, the turbulence of flow was found to be proportional to the amount of fluctuations in the FBG measurements. Such that wavelength shifts of up to 120 picometers are visible for an average flow rate of 27±0.1 Gal/min. With the DAS system, the amplitude response shows a stronger relationship to the turbulence of flow rather than the average flow rate. Such that the highest amplitude response during a flow test would always correspond to the flow valve being half open (which was found to be the most turbulent flow). In conclusion, this study indicates that fiber optic sensing systems can be used on pipelines and well casing to monitor and measure flow. Additionally, it demonstrates that taping the sensors on the pipe is enough to capture the signal produced by fluid flow in a pipe. The relationship provided between the FBG measurements and flow rates can be used to compute approximated flow rates when using an FBG sensing system to monitor flow.
{"title":"Measuring Flow in Pipelines via FBG and DAS Fiber Optic Sensors","authors":"E. Alfataierge, N. Dyaur, R. Stewart","doi":"10.4043/29433-MS","DOIUrl":"https://doi.org/10.4043/29433-MS","url":null,"abstract":"\u0000 An investigation is made into the use of a fiber optic sensing system for monitoring and measuring fluid flow in pipes. This is done using two fiber optics sensing systems, a Distributed Acoustic Sensing \"DAS\" system and a Fiber Bragg Grating \"FBG\" system. A laboratory setup is used to conduct these tests and the setup is structured to simulate an offshore environment. The laboratory setup consists of a water reservoir that flows water through PVC pipes into a tank, fibers are attached to the pipes, and a flow meter is used to measure the flow rates. From the conducted flow experiments, a relationship between flow rates, DAS amplitudes, and FBG wavelength shifts is built.\u0000 This paper presents the response of fiber optic sensing systems to flow experiments that were conducted with various flow rates, and simulated leak tests with and without flow. The results are used to establish a relationship between the fiber optic response and flow variation, to develop a method of measuring flow rates via the fiber optic systems. Such that any pipes equipped with fiber optics could be used to measure approximate flow rates.\u0000 This study finds a strong correlation between the fiber optic sensing systems measurements and measured flow rates. In the FBG system, flow was found to have two influences on the FBG measurement; an increase in flow shows an increase in the FBG sensor wavelength, also, the turbulence of flow was found to be proportional to the amount of fluctuations in the FBG measurements. Such that wavelength shifts of up to 120 picometers are visible for an average flow rate of 27±0.1 Gal/min. With the DAS system, the amplitude response shows a stronger relationship to the turbulence of flow rather than the average flow rate. Such that the highest amplitude response during a flow test would always correspond to the flow valve being half open (which was found to be the most turbulent flow).\u0000 In conclusion, this study indicates that fiber optic sensing systems can be used on pipelines and well casing to monitor and measure flow. Additionally, it demonstrates that taping the sensors on the pipe is enough to capture the signal produced by fluid flow in a pipe. The relationship provided between the FBG measurements and flow rates can be used to compute approximated flow rates when using an FBG sensing system to monitor flow.","PeriodicalId":10968,"journal":{"name":"Day 3 Wed, May 08, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-04-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86943026","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}
Venu Rao, T. Sriskandarajah, Carlos Charnaux, Alan Roy, P. Ragupathy, S. Eyssautier
Lateral buckling mitigation design for HPHT pipe-in-pipe system is technically challenging and at times the reliability of proven buckling mitigation options may come into severe technical scrutiny for some HPHT pipe in pipe systems on the undulating seabed. The Residual Curvature Method (RCM) presents as an alternative technical option for such cases. The technique comprises understraightening in intermittent sections of the ‘as-laid’ pipeline which form ‘expansion loops’ and provide a proven, reliable and cost-effective buckling mitigation. The method was successfully implemented in Statoil’s Skuld project in 2012 and subsequently a few other projects worldwide which are all single pipeline systems. However, the RC method was not used as a buckling mitigation method for a pipe in pipe system to date to the knowledge of the authors. Residual curvature method could be proven superior for HPHT Pipe-in-Pipe Systems to other lateral buckling methods (thanks to controlled well-developed buckles at pre-determined locations) under some favourable design conditions. This paper shows the robustness of the technique for a typical 12" / 16" HPHT pipe in pipe system with an operating pressure of 300barg and 150°C operating in a maximum water depth of 2000m as a case study. The PIP system is considered to be laid by a reel-lay method, which is amenable to inducing the residual curvature at the pre-determined RC locations during pipelay process. The study includes the special considerations required in deploying the method on an undulating seabed taking into account unplanned buckles or spans and the necessary adjustment to be made to pre-determined buckle sites. The study includes the effects of inner pipe snaking (with residual curvature) within a near straight outer pipe due to the reeling process and its impact on the lateral buckling behaviour. Other design features that may have a significant effect on the RC method are discussed.
{"title":"Residual Curvature Method of Mitigating Lateral Buckling for HPHT PIP System – A case study","authors":"Venu Rao, T. Sriskandarajah, Carlos Charnaux, Alan Roy, P. Ragupathy, S. Eyssautier","doi":"10.4043/29603-MS","DOIUrl":"https://doi.org/10.4043/29603-MS","url":null,"abstract":"\u0000 Lateral buckling mitigation design for HPHT pipe-in-pipe system is technically challenging and at times the reliability of proven buckling mitigation options may come into severe technical scrutiny for some HPHT pipe in pipe systems on the undulating seabed. The Residual Curvature Method (RCM) presents as an alternative technical option for such cases. The technique comprises understraightening in intermittent sections of the ‘as-laid’ pipeline which form ‘expansion loops’ and provide a proven, reliable and cost-effective buckling mitigation. The method was successfully implemented in Statoil’s Skuld project in 2012 and subsequently a few other projects worldwide which are all single pipeline systems. However, the RC method was not used as a buckling mitigation method for a pipe in pipe system to date to the knowledge of the authors.\u0000 Residual curvature method could be proven superior for HPHT Pipe-in-Pipe Systems to other lateral buckling methods (thanks to controlled well-developed buckles at pre-determined locations) under some favourable design conditions. This paper shows the robustness of the technique for a typical 12\" / 16\" HPHT pipe in pipe system with an operating pressure of 300barg and 150°C operating in a maximum water depth of 2000m as a case study. The PIP system is considered to be laid by a reel-lay method, which is amenable to inducing the residual curvature at the pre-determined RC locations during pipelay process.\u0000 The study includes the special considerations required in deploying the method on an undulating seabed taking into account unplanned buckles or spans and the necessary adjustment to be made to pre-determined buckle sites. The study includes the effects of inner pipe snaking (with residual curvature) within a near straight outer pipe due to the reeling process and its impact on the lateral buckling behaviour. Other design features that may have a significant effect on the RC method are discussed.","PeriodicalId":10968,"journal":{"name":"Day 3 Wed, May 08, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-04-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83264829","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 presents an outline for the development and deployment of three perforating systems to address several needs of high pressure (HP) US Gulf of Mexico wells. A case study is presented, highlighting the key differences between systems, and includes comparisons between data obtained during engineering development and field deployment phases During the development phase rigorous testing was conducted in line with API RP 19B sections 2, 3.14, and 5 to characterize the perforating systems' performance. These tests were executed to assess charge performance, system pressure rating at downhole conditions, and debris characteristics at surface conditions. Following the development testing, the systems were fielded with wellbore pressure being captured on downhole gauges to assess the perforating event response comparing to pre-deployment models. Additionally, wellbore debris recovered post-perforating was evaluated on surface. The first system was to support an HP application that requires high flow area in heavy wall casing. This was the platform for other less traditional systems to expand upon. Utilizing high shot density and big hole (BH) charges, this system was tested to provide a system rating of up to 30 ksi at 425°F while retaining fishability in heavy wall casing. For this system, wellbore effects from perforating, such as dynamic underbalance and recovered debris, are qualitatively aligned with existing perforators. The second system was optimized to control dynamic transient loading on the perforating string and minimize debris in HP environments. This meant the system was required to fit into a strategy of lowering dynamic structural loads on the workstring created during perforating. The system was designed to affect the pressure interactions among the gun internals, wellbore, and the formation, and control the amount of formation material inflow and debris produced by perforating. This perforating system was developed, qualified, and successfully fielded in multiple wells without any operational issues. The third system provides increased formation penetration depth without sacrificing shot density. By using deep penetrating (DP) charges, this system is can provide penetration past drilling damage or mitigate higher formation strengths encountered at greater depths in some HP US GoM reservoirs, thus providing operators improved connectivity to the formation. Evaluating perforating system performance, not only with lab testing but with field-gathered data, is crucial to closing the development loop for HP applications where testing is not practical due to both scale and replication of wellbore conditions. In deployment, the well conditions for the systems were analogous, highlighting the differences in data, thus providing a more complete background for operators to assess the suitability of these systems in HP applications and evaluate their perforating method to maximize production.
本文概述了三种射孔系统的开发和部署，以满足美国墨西哥湾高压井的几种需求。介绍了一个案例研究，突出了系统之间的主要差异，并比较了工程开发和现场部署阶段获得的数据。在开发阶段，根据API RP 19B第2、3.14和5部分进行了严格的测试，以表征射孔系统的性能。这些测试的目的是评估井下条件下的装药性能、系统额定压力以及地面条件下的碎屑特性。在开发测试之后，系统被投入使用，通过井下测量仪捕获井筒压力，与部署前的模型相比，评估射孔事件的响应。此外，对射孔后回收的井筒碎屑进行了地面评估。第一个系统用于支持高压应用，该应用需要在厚壁套管中实现高流道面积。这是其他不太传统的系统扩展的平台。该系统利用高射孔密度和大射孔(BH)装药，在425°F下提供了高达30 ksi的系统额定值，同时保持了在厚壁套管中的可打捞性。对于该系统，射孔对井筒的影响，如动态欠平衡和回收的碎屑，与现有的射孔器定性一致。第二个系统进行了优化，以控制射孔管柱上的动态瞬态载荷，并最大限度地减少高压环境中的碎屑。这意味着该系统需要适应降低射孔过程中产生的工作串动态结构载荷的策略。该系统旨在影响射孔枪内部、井筒和地层之间的压力相互作用，并控制射孔产生的地层物质流入和碎屑量。该射孔系统经过开发、验证并成功应用于多口井，没有出现任何操作问题。第三种系统在不牺牲射孔密度的情况下增加了地层穿透深度。通过使用深穿透(DP)装药，该系统可以穿透钻井损害，或减轻一些高强度的美国墨西哥湾油藏在更深的深度遇到的地层强度，从而为作业者提供更好的与地层的连通性。评估射孔系统的性能，不仅要通过实验室测试，还要通过现场收集的数据，这对于关闭高压应用的开发循环至关重要，因为高压应用由于井眼条件的规模和重复性而无法进行测试。在部署过程中，系统的井况是相似的，突出了数据的差异，从而为作业者评估这些系统在高压应用中的适用性和评估射孔方法以实现产量最大化提供了更完整的背景资料。
{"title":"Developing and Fielding Perforating Systems: A Comparison in High-Pressure Wells","authors":"R. E. Robey, David Francis Suire, B. Grove","doi":"10.4043/29582-MS","DOIUrl":"https://doi.org/10.4043/29582-MS","url":null,"abstract":"\u0000 This paper presents an outline for the development and deployment of three perforating systems to address several needs of high pressure (HP) US Gulf of Mexico wells. A case study is presented, highlighting the key differences between systems, and includes comparisons between data obtained during engineering development and field deployment phases\u0000 During the development phase rigorous testing was conducted in line with API RP 19B sections 2, 3.14, and 5 to characterize the perforating systems' performance. These tests were executed to assess charge performance, system pressure rating at downhole conditions, and debris characteristics at surface conditions. Following the development testing, the systems were fielded with wellbore pressure being captured on downhole gauges to assess the perforating event response comparing to pre-deployment models. Additionally, wellbore debris recovered post-perforating was evaluated on surface.\u0000 The first system was to support an HP application that requires high flow area in heavy wall casing. This was the platform for other less traditional systems to expand upon. Utilizing high shot density and big hole (BH) charges, this system was tested to provide a system rating of up to 30 ksi at 425°F while retaining fishability in heavy wall casing. For this system, wellbore effects from perforating, such as dynamic underbalance and recovered debris, are qualitatively aligned with existing perforators.\u0000 The second system was optimized to control dynamic transient loading on the perforating string and minimize debris in HP environments. This meant the system was required to fit into a strategy of lowering dynamic structural loads on the workstring created during perforating. The system was designed to affect the pressure interactions among the gun internals, wellbore, and the formation, and control the amount of formation material inflow and debris produced by perforating. This perforating system was developed, qualified, and successfully fielded in multiple wells without any operational issues.\u0000 The third system provides increased formation penetration depth without sacrificing shot density. By using deep penetrating (DP) charges, this system is can provide penetration past drilling damage or mitigate higher formation strengths encountered at greater depths in some HP US GoM reservoirs, thus providing operators improved connectivity to the formation.\u0000 Evaluating perforating system performance, not only with lab testing but with field-gathered data, is crucial to closing the development loop for HP applications where testing is not practical due to both scale and replication of wellbore conditions. In deployment, the well conditions for the systems were analogous, highlighting the differences in data, thus providing a more complete background for operators to assess the suitability of these systems in HP applications and evaluate their perforating method to maximize production.","PeriodicalId":10968,"journal":{"name":"Day 3 Wed, May 08, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-04-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"80846177","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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