Gas hydrates are naturally-occurring crystalline inclusion compounds. They comprise compressed molecules of gas (usually methane) that are ‘lodged’ within a solid lattice of water molecules. For this reason, the gas molecules are called ‘guests’ and the water molecules are called ‘hosts’. Gas hydrates form where there are sources of water and methane under favorable thermodynamic conditions of relatively high pressure and low temperature. Objective of the study is to evaluate Petrophysical Properties from drilled well of NGHP expedition 2 for Gas Hydrate. To identify different hydrate formation and estimation of hydrate saturation. The Work flow to estimate Petrophysical properties is guided by the high resistivity, low transit time and low density. It includes evaluation of different overlays and cross plots of wells like picket plot to firm up different parameters. Porosity is measured by density log, water saturation using Archie's equation; gas hydrate saturation using DMR method and its validation for the results obtained from Pressure core. Electrical resistivity and acoustic travel time mainly used to identify potential Gas Hydrate zones with overlay technique from density porosity and acoustic travel time and other density porosity with total NMR porosity, along with resistivity log are used for identifying potential Gas Hydrate zones in this study. Porosity estimated from density log is used for calculation Hydrate saturation. Gas Hydrate saturation is estimated using standard Archie's equation and Density Magnetic Resonance (DMR) method. Wherever NMR log data is good, saturation estimated from both are in good agreement. Log derived Gas Hydrate saturation are compared and validated with Gas Hydrate saturation obtained from pressure cores. Very good Gas Hydrate saturated zones are observed above BSR in 21 wells in the range of 40-90%. Out of these 21 wells, 16 wells are also having Gas Hydrate saturation in the range of 30-50%. Good Gas Hydrate saturation wells are mainly in area B and C in KG deep water Basin. This study will be very useful in preparation of Geological model for estimation of Gas Hydrate reservesaccurately. This study will also help in NGHP-3 for identifying suitable sites to carry out pilot production testing of Gas Hydrates.
{"title":"Petrophysical Evaluation of Gas-Hydrate Formations in National Gas Hydrates Programme Expedition 02 in India","authors":"Sikha Rani Mondal, K. Chopra","doi":"10.4043/29614-MS","DOIUrl":"https://doi.org/10.4043/29614-MS","url":null,"abstract":"\u0000 Gas hydrates are naturally-occurring crystalline inclusion compounds. They comprise compressed molecules of gas (usually methane) that are ‘lodged’ within a solid lattice of water molecules. For this reason, the gas molecules are called ‘guests’ and the water molecules are called ‘hosts’. Gas hydrates form where there are sources of water and methane under favorable thermodynamic conditions of relatively high pressure and low temperature.\u0000 Objective of the study is to evaluate Petrophysical Properties from drilled well of NGHP expedition 2 for Gas Hydrate. To identify different hydrate formation and estimation of hydrate saturation.\u0000 The Work flow to estimate Petrophysical properties is guided by the high resistivity, low transit time and low density. It includes evaluation of different overlays and cross plots of wells like picket plot to firm up different parameters. Porosity is measured by density log, water saturation using Archie's equation; gas hydrate saturation using DMR method and its validation for the results obtained from Pressure core.\u0000 Electrical resistivity and acoustic travel time mainly used to identify potential Gas Hydrate zones with overlay technique from density porosity and acoustic travel time and other density porosity with total NMR porosity, along with resistivity log are used for identifying potential Gas Hydrate zones in this study. Porosity estimated from density log is used for calculation Hydrate saturation. Gas Hydrate saturation is estimated using standard Archie's equation and Density Magnetic Resonance (DMR) method. Wherever NMR log data is good, saturation estimated from both are in good agreement. Log derived Gas Hydrate saturation are compared and validated with Gas Hydrate saturation obtained from pressure cores. Very good Gas Hydrate saturated zones are observed above BSR in 21 wells in the range of 40-90%. Out of these 21 wells, 16 wells are also having Gas Hydrate saturation in the range of 30-50%. Good Gas Hydrate saturation wells are mainly in area B and C in KG deep water Basin. This study will be very useful in preparation of Geological model for estimation of Gas Hydrate reservesaccurately. This study will also help in NGHP-3 for identifying suitable sites to carry out pilot production testing of Gas Hydrates.","PeriodicalId":10968,"journal":{"name":"Day 3 Wed, May 08, 2019","volume":"87 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-04-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90933494","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}
S. Guzman, M. Taboada, Albino Pombo, R. Martín, Ana Bezunartea, Andy Knights-Cooper, J. Moreu
This paper describes the conceptual design and estimates the CAPEX breakdown of a novel floater type for offshore wind turbines: the Reduced-Draft Spar (RDS). This floater, which resembles a GBS although it is in essence a spar, has excellent seakeeping at a reduced draft. Aiming at reducing the CAPEX, the RDS design allows the installation of the wind turbine at the manufacturing site. Furthermore, no auxiliary means are required to provide stability during towing and in-place installation (mooring and electric hook-up, and ballasting to the operational draft). It also promotes the use of structural concrete and cost-effective high-density ballast for its construction. In addition, the whole concept benefits from the implementation of an Active Ballast System (ABS) to compensate the mean tilt angle while operating. An extensive model test campaign was carried out in summer 2018 at INTA-CEHIPAR model basin to validate the concept. The tests scope was focused on calibrating a state-of-the-art numerical hydrodynamic model for further stages of development. An 8MW RDS model, with a scale factor of 1:50 and a 3-line spread mooring system, was tested in Transport and Installation (T&I), operational and survival conditions to assess the concept feasibility. The ABS was simulated using pre-calibrated counteracting weights. Stability during T&I was also checked. In addition, the unit CAPEX was estimated and compared to equivalent semi and spar units made of steel. The RDS can operate at intermediate water depths (60 to 80 m, where spars cannot) and deep waters, and also avoids the use of expensive auxiliary means for T&I. The results from the model tests confirm a dynamic behavior of the RDS similar to that of classic spars, which is beneficial for the offshore WT. Regarding the CAPEX, estimations indicate relevant savings compared to classic spars or semis. Although it is a large massive unit, the use of concrete combined with heavy ballast makes the concept feasible. Due to the ABS, the required platform's size is smaller and the fatigue life of the WT components increases. Furthermore, an adequate ABS control system increases the net energy production since the energy consumption is negligible compared to the extra generated power. The use of civil construction manufacturing technologies such as floating docks and assemble of pre-manufactured parts leads to major CAPEX savings. The US coast has a huge offshore wind energy resource at water depths greater than 60m, where the RDS floating concept has a promising future. The concept could be used as well in the Offshore Oil& Gas.
{"title":"The Reduced-Draft Spar: A Novel Cost-Effective Concept for Floating Offshore Wind Turbines","authors":"S. Guzman, M. Taboada, Albino Pombo, R. Martín, Ana Bezunartea, Andy Knights-Cooper, J. Moreu","doi":"10.4043/29495-MS","DOIUrl":"https://doi.org/10.4043/29495-MS","url":null,"abstract":"\u0000 This paper describes the conceptual design and estimates the CAPEX breakdown of a novel floater type for offshore wind turbines: the Reduced-Draft Spar (RDS). This floater, which resembles a GBS although it is in essence a spar, has excellent seakeeping at a reduced draft.\u0000 Aiming at reducing the CAPEX, the RDS design allows the installation of the wind turbine at the manufacturing site. Furthermore, no auxiliary means are required to provide stability during towing and in-place installation (mooring and electric hook-up, and ballasting to the operational draft). It also promotes the use of structural concrete and cost-effective high-density ballast for its construction. In addition, the whole concept benefits from the implementation of an Active Ballast System (ABS) to compensate the mean tilt angle while operating.\u0000 An extensive model test campaign was carried out in summer 2018 at INTA-CEHIPAR model basin to validate the concept. The tests scope was focused on calibrating a state-of-the-art numerical hydrodynamic model for further stages of development. An 8MW RDS model, with a scale factor of 1:50 and a 3-line spread mooring system, was tested in Transport and Installation (T&I), operational and survival conditions to assess the concept feasibility. The ABS was simulated using pre-calibrated counteracting weights. Stability during T&I was also checked.\u0000 In addition, the unit CAPEX was estimated and compared to equivalent semi and spar units made of steel. The RDS can operate at intermediate water depths (60 to 80 m, where spars cannot) and deep waters, and also avoids the use of expensive auxiliary means for T&I. The results from the model tests confirm a dynamic behavior of the RDS similar to that of classic spars, which is beneficial for the offshore WT. Regarding the CAPEX, estimations indicate relevant savings compared to classic spars or semis.\u0000 Although it is a large massive unit, the use of concrete combined with heavy ballast makes the concept feasible. Due to the ABS, the required platform's size is smaller and the fatigue life of the WT components increases. Furthermore, an adequate ABS control system increases the net energy production since the energy consumption is negligible compared to the extra generated power. The use of civil construction manufacturing technologies such as floating docks and assemble of pre-manufactured parts leads to major CAPEX savings.\u0000 The US coast has a huge offshore wind energy resource at water depths greater than 60m, where the RDS floating concept has a promising future. The concept could be used as well in the Offshore Oil& Gas.","PeriodicalId":10968,"journal":{"name":"Day 3 Wed, May 08, 2019","volume":"108 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-04-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"91336241","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":"150 1","pages":""},"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}
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":"30 1","pages":""},"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}
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":"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":"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}
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":"26 1","pages":""},"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}
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":"95 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":"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}
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":"81 1","pages":""},"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}
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":"38 1","pages":""},"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}
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":"30 1","pages":""},"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}
京公网安备 11010802042870号
京ICP备2023020795号-1
扫码关注我们
求助内容：
应助结果提醒方式：