Day 3 Wed, May 08, 2019最新文献

{"title":"Subsea Demulsifier Injection to Enhance Crude Oil Production in Offshore Brownfields - A Success Case","authors":"M. Oliveira, Monica Alevatto, T. P. Sampaio, P. Dias","doi":"10.4043/29535-MS","DOIUrl":"https://doi.org/10.4043/29535-MS","url":null,"abstract":"\u0000 In Brazil oilfield scenario, there are large, clearly identified brownfield sites, many of which with high additional oil production potential. The lifting costs and conventional breakeven price per barrel associated with an existing producing field offshore, even those in decline and requiring some recompletion & workover jobs, are – in many situations - less investiment demanding than brand new greenfield development.\u0000 The formation of water in oil (W/O) emulsions is ubiquitous in oilfield production. As the water commingled in crude increases, the emulsions' stability and viscosity also increase, thence generating flow restrictions due to higher friction losses. The subsea demulsifier injection has proven to be an interesting alternative to overcome this flowing constraint in mature wells, thus maximizing the productive capacity of existing brownfields. This paper presents some results and challenges faced to implement the routine of subsea demulsifier injection, from the development of testing protocols to come up with a tailor-made chemical solution, to the hurdles associated to chemical injection through subsea umbilical- and gas lift-lines.","PeriodicalId":10968,"journal":{"name":"Day 3 Wed, May 08, 2019","volume":"52 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-04-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"76258837","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}

{"title":"Risks Minimization and Results Improvement in Offshore Projects","authors":"Hongfu Shi, Wei Zhang, Xiaodong Han, Haochuan Ling, Chaojie Kong","doi":"10.4043/29325-MS","DOIUrl":"https://doi.org/10.4043/29325-MS","url":null,"abstract":"\u0000 A new regional integrated development pattern is proposed by Bohai Oilfield Bureau, based on the existing development and production system and engineering facilities, and combined with the distribution characteristics of underground oil and gas resources in Bohai oilfields, and according to the principles of ‘overall planning, unified layout, stage promotion and subarea implementation'. Through the integration and rational allocation of exploration and development, reservoir and engineering, development and production, the overall planning of underground resources and ground engineering is carried out, and a perfect regional development pattern is gradually formed. Based on reducing the threshold of oilfield development through resources sharing and accelerating the construction of new oilfield, the reservoir potential is fully released, and the efficient development of regional oil and gas is realized.","PeriodicalId":10968,"journal":{"name":"Day 3 Wed, May 08, 2019","volume":"258 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-04-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"76203807","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}

{"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}

{"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}

{"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}

{"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}

{"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}

{"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}

{"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}

{"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}