Day 4 Thu, May 16, 2019最新文献

{"title":"Alternative ESP Deployment in an Offshore Oilfield Angola, West Africa","authors":"S. Vierkandt, Lanre Olabinjo, D. Malone, J. English","doi":"10.2118/194412-MS","DOIUrl":"https://doi.org/10.2118/194412-MS","url":null,"abstract":"\u0000 Chevron began development of an offshore oilfield in Angola, West Africa, in 1997 using ESP's as the preferred artificial lift method due to favorable reservoir and fluid characteristics, and limited capacity of the available gas lift injection infrastructure. The initial ESP's were deployed on coil tubing (CT) to reduce initial costs, future ESP replacement downtime and the dependence on the availability of a jack-up rig. Due to difficulties experienced in supporting the CT operations in the remote area, subsequent new completions and ESP replacements have been carried out utilizing standard threaded tubing. To date, there are 28 wells producing with ESP's from 3 platforms.\u0000 ESP run life has been excellent over the life of the field with 5-year MTF, and some ESP's surviving longer than 10 years. However, when an ESP fails it must compete with other economic opportunities within the +600 well portfolio for rig time to replace the failed equipment and return to production. Over time increasing rig day rates and declining oil production rates have created challenging economics. Typically, more than one ESP failure on a platform is required to provide competitive project economics to justify mobilizing a rig, resulting in well downtime increasing to an average of over 12 months.\u0000 This paper describes the process undertaken to evaluate and select an alternative deployed ESP system to significantly reduce workover costs and time-waiting-on-replacement, improve economics and ensure continued field development. This was a collaborative effort of more than a dozen partners, service companies and contractors across 3 continents. It includes detailed evaluation of the existing well bores and requirements for the new ESP's. Requirements comprised a new wellhead design, larger tubing (resulting in tighter tolerances), a new cable clamp design, VFD controller certification, confirming pumps could be replaced on tractor due to high well deviation, etc. One example was the decision to perform the ESP connector head, motor lead cable and ESP cable splices in a US factory to improve reliability and reduce time over rig floor connections. Multiple FIT tests were performed and evaluated to ensure project success.\u0000 The first two new alternatively deployed ESP's were successfully installed and placed on production in June 2017. A surface electrical failure in a VFD in early 2018 resulted in a damaged downhole ESP motor in one well. The motor was successfully retrieved and replaced via wireline tractor, at a hole angle of 88°, under pressure, without killing the well. The well was successfully returned to production in August 2018.","PeriodicalId":334026,"journal":{"name":"Day 4 Thu, May 16, 2019","volume":"14 17","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-05-06","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"120865947","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":"20 Years of Rigless ESPs in Alaska; What went Right, What went Wrong, What's Next?","authors":"John C. Patterson, G. Dornan, M. D. Jensen, G. Targac, Dave L Malone, Samer Cheblak, J. Y. Julian, Matthew Walker","doi":"10.2118/194419-MS","DOIUrl":"https://doi.org/10.2118/194419-MS","url":null,"abstract":"\u0000 This paper is not a technical paper about electric submersible pumps (ESP's), instead it traces the 20-year journey that has led to the development and successful application of multiple generations of rigless ESP conveyance systems in a commercial oilfield. The end result, after many lessons learned, is a success story in which over 300 rig interventions have been eliminated over a 20-year period, with savings of 100's of millions of dollars in intervention costs, reduced HSE exposure and many millions of barrels of additional production.\u0000 Utilization of ESP technology in the West Sak viscous oil field in Alaska is challenging. The unconsolidated nature of the West Sak sands impacts the performance and reliability of conventional ESP systems due to sand production. This challenging environment causes ESP pump erosion and accumulation of sand in the tubing above the pump and in the lower completion below the ESP.\u0000 The initial development of the West Sak formation was the basis for the original development of the through-tubing conveyed progressing cavity pump (TTCESPCP) in the mid 1990's. With time, the West Sak completions evolved from vertical wells to long horizontals, resulting in production capacity increasing beyond the capabilities of the 3.5 in. and 4 in. TTCESPCP systems. This led to the development of a 4.5 in. through-tubing ESP in the early 2000's. In this design, the PCP of the TTCESPCP system was replaced with a high capacity, centrifugal pump or through-tubing convenyed ESP (TTCESP).\u0000 With time and successful experience utilizing the TTC systems, it became evident that although the through-tubing technology resulted in significant savings and increased production, the design was lacking in one major aspect – the ability to remove sand accumulation in the 7-5/8 in. production casing below the end of tubing. The inability to perform interventions without pulling the tubing, was leading to expensive and avoidable rig workovers not related to the ESP equipment. The resulting economics drove the development of a through-tubing, slickline (SL) deployed ESP that, when all components are removed, leaves a minimum diameter of 3.80 in. for well interventions below the end of the tubing. The wireline retrievable ESP (WRESP) system was launched in 2005 and was fully commercialized in 2014.\u0000 Numerous papers have been written on this specific technology and references are provided at the end of this paper. This list does not represent a complete listing of all through-tubing technologies, as there are other systems with substantially different characteristics. This paper will focus only on the through-tubing technology development and evolution in Alaska. It will present the 20-year development history of the Alaskan through-tubing technology, how the system is deployed, answers to frequently ask questions, and as the title suggests – What went Right, What went Wrong, and What's Next?\u0000 The development and successful commercial deployment of th","PeriodicalId":334026,"journal":{"name":"Day 4 Thu, May 16, 2019","volume":"61 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-05-06","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"122620173","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":"Improving Gas Separation in ESP for Unconventional Wells in 5-1/2\" Casing. Case Studies in the Permian Basin","authors":"G. González, C. Loaiza","doi":"10.2118/194418-MS","DOIUrl":"https://doi.org/10.2118/194418-MS","url":null,"abstract":"\u0000 New unconventional wells have been a huge challenge for ESPs in the Permian Basin due to horizontal wells with high-formation GORs or GLRs. The pumped fluid can cause issues such as gas interference, gas locking, short run life, low production, poor energy efficiency, increased failure rates, shutdowns, so forth. A major problem is gas presence around the ESPs, because it causes the motor to rapidly overheat since the gas is incapable of adequately cooling.\u0000 In short term, the presence of gas in the flow reduces the pump efficiency and in severe conditions leads to gas lock in the impeller which could damage the equipment. In the long term, the motor life is shortened as a function of the temperature increase. In general, for every 18F of operating temperature increase, the life of the insulation material is reduced by 50% and leading the motor material to be severely affected. The gas handling capacity of standard ESPs is very low, and the efficiency of the traditional rotary gas separator might not be as expected that is why a new and innovative downhole gas separator has been introduced in recent applications to combat the gas slug's problems.\u0000 The new gas mitigation technology consists of a shrouded ESP with a double stage of gas separation connected at the bottom of the shroud that act as intake and was designed to break the gas slugs and avoid gas entrance into ESPs by forcing free gas to go around the shroud and produce through the casing. The fluid is now forced to pass through an additional gas separator (New Gas Mitigation Technology), which helps on gas mitigation as well as lower motor temperature\u0000 This paper summarizes different case studies in wells located in the Permian Basin that had reported frequent shutdowns due to gas lock and high motor temperature. All the pump parameters are analyzed before and after the installation to conclude on optimization; in these wells, an increase on production was observed, and better performance of the pump. Other results observed were the reduction of the shutdowns and no gas mode with stable condition along with significantly breaking the drawdown barrier of the 700 psi (ESP PIP). This success was noted on most of our wells where the lowest of them operated at 290 psi (ESP PIP). Additionally, some operational and analytics guides are provided to understand how to identify and control the gas problem in ESPs.","PeriodicalId":334026,"journal":{"name":"Day 4 Thu, May 16, 2019","volume":"34 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-05-06","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"122922276","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":"Use of New Design Tool Improves ESP Design Across the Life of Well in Unconventional Applications","authors":"A. Williams","doi":"10.2118/194417-MS","DOIUrl":"https://doi.org/10.2118/194417-MS","url":null,"abstract":"\u0000 Sizing electric submersible pumps (ESPs) for unconventional wells presents new challenges compared to traditional applications, typically conventional, vertical wells. These challenges are due to the highly dynamic, rapidly changing nature of unconventional wells compared to conventional wells. Traditional ESP sizing software is not structured to design for dynamic conditions, but rather a single point in time. The objective is to design an ESP tool fit for unconventional design applications.\u0000 Because of the rapidly changing conditions of unconventional wells, it is difficult to balance the lifetime sizing needs of the equipment with needs of the equipment during peak demand. Changing flow rates, water cuts, pump intake pressure (PIP), and gas oil ratio (GOR) have a great effect on stage size, total dynamic head (TDH), and motor horsepower (HP) requirements at different points over time. The new design tool will allow the user to upload a well type curve and help chose a pump and motor combination by calculating different TDH and motor horsepower requirements for each day over the life of the well.\u0000 Optimized ESP sizing will allow oil and gas operators to install one initial ESP at the completion of the well which lasts until production rates have declined to the conversion point of a lower rate form of artificial lift. This has significant cost savings implications both for capital and operational budgets, by avoiding overspending on oversized equipment upon the initial install of the wells, and greatly reduced the work of the operations team by eliminating workovers needed to downsize equipment. The use of this design tool allows much more rigorous reviews of vendor designs, to avoid over sizing equipment while still capturing high initial production rates during the early production life of the well.\u0000 ESPs designed using the new design tool will be compared to historical ESP designs provided by the vendors on analogous wells. Production numbers, run life, and historical ESP data streams will be compared between wells designed using the old methodology vs the new design tool.","PeriodicalId":334026,"journal":{"name":"Day 4 Thu, May 16, 2019","volume":"8 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-05-06","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"127696990","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":"Electrical Submsersible Pump Powered Injection ESPPI Systems Enable the Development of West of the Nile Egypt Assets","authors":"M. Muñoz, M. Aboutaleb, J. Dwiggins","doi":"10.2118/194408-MS","DOIUrl":"https://doi.org/10.2118/194408-MS","url":null,"abstract":"\u0000 Qarun Petroleum Company (QPC), a joint venture between the Egyptian General Petroleum Corporation (EGPC) and Apache Egypt, operates over 350 ESP wells in brownfields across the Egyptian Western Desert. QPC's oil production is heavily dependent on the performance of waterfloods and artificial lift systems. In recent years, QPC entered a development campaign in the West of Nile (WON) region, an area located west of the Nile River approximately 159 kilometers from Cairo. The fertile land has ready access to irrigation and therefore long been developed as an agricultural area, surrounded by densely populated villages. Land access is restricted and operations must be conducted to ensure minimal impact to the environment. Oilfield development in WON is challenging and required alternative solutions to conventional waterflood operations. QPC engineers turned to ESP Powered Injection (ESPPI) systems as an alternative to traditional waterflooding and re-engineered the technology to overcome the operational, economic, and environmental challenges.\u0000 ESP Powered Injection (ESPPI) systems utilize conventional ESPs in combination with a bypass system (Y-tool) and an injection string to provide water production and injection support from a single wellbore to one or more wells in the same injection pattern. The system eliminates the need for surface pumping, water separation, storage, and flow lines. QPC has successfully installed and presently operates nine (9) ESPPI systems in the environmentally sensitive WON region of Egypt.\u0000 This paper aims to detail the specifications and functionality of ESPPI systems, main challenges and benefits derived from closed monitored installations and operational surveillance, and the economic advantage of its application for QPC.","PeriodicalId":334026,"journal":{"name":"Day 4 Thu, May 16, 2019","volume":"198 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-05-06","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"134254414","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":"Reliability Analysis of High-Power and High-Flow-Rate Subsea ESP Systems in Jubarte","authors":"L. Vergara, Francisco Bacellar, Marcelo Neves, A. Watson, G. Harris","doi":"10.2118/194395-MS","DOIUrl":"https://doi.org/10.2118/194395-MS","url":null,"abstract":"\u0000 The artificial lift system selected to produce the Jubarte Field uses high-power and high-flow-rate subsea electrical submersible pump (ESP) systems with gas lift as a contingency in case of the need for ESP replacement. The gas lift mandrels are installed in the production well completion. The ESP systems are rated for 1,500 hp at full load and were deployed inside caissons constructed on the seabed, located 210 m downstream of the main production wellhead. The integrated unit is called a pumping module or módulo de bombeio (MOBO) in Portuguese.\u0000 Industry perception of average ESP run time, high replacement costs associated with intervention of the subsea ESP systems, and the limited track record available for comparable systems at the time of field development required a comprehensive approach to improve on system reliability from the beginning. The use of advanced technologies to extend the traditional concept of industrial process control to the management of the MOBO systems allowed continuous monitoring of ESPs to maintain operation within the design envelope.\u0000 The development of a complete \"ESP culture\" became a key element connecting the different teams involved in the operation. This required new procedures to be developed, new monitoring and surveillance teams introduced, and, most of all, management of change practices introduced to avoid issues related to the rotation of personnel involved in the operation of the ESP and related systems. The synergies created allowed the provision of timely solutions to face the challenges across the complete production system.\u0000 The gap study conducted at the beginning of the Jubarte ESP development identified many barriers and conditions preventing increased system reliability and affecting economic viability of such a large-scale project. This paper builds on such analysis using the operational data gathered during the 8 years of ESP operation, shows improvement in mean time to failure during the period, presents typical failures encountered in equipment and processes, introduces the de-risking process followed to strengthen the system, and provides the reasons behind the enhancements made.\u0000 Explanation of the measures proposed to significantly improve the reliability of these 1500-hp subsea ESP systems and the reasoning behind the enhancements will facilitate future projects of a similar nature.","PeriodicalId":334026,"journal":{"name":"Day 4 Thu, May 16, 2019","volume":"38 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-05-06","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"133358067","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":"Starting Up the Most Powerful ESP Installed into Deepwater Offshore Wells Completed with Open Hole Gravel Packing: A Real Challenge","authors":"C. Pedroso, B. Cavalcante, M. Marsili, M. Santos, P. Rocha","doi":"10.2118/194407-MS","DOIUrl":"https://doi.org/10.2118/194407-MS","url":null,"abstract":"\u0000 Atlanta Field, offshore Brazil, is probably the most challenging deep-water heavy oil field in the world.\u0000 Great challenges have been overcome to build and test the first two wells in this field which have already been detailed elsewhere (Papers OTC 25813, SPE 174893, SPE 174896, SPE 174897, SPE 173946). The refurbishment of the FPSO Petrojarl I, to enable it to process the high viscous oil will be described elsewhere. Finally, the last frontier to prove the technical and economic viability of Atlanta Project is the so called \"First Oil\" and the ESP operation.\u0000 In normal conditions starting an offshore well when equipped with an ESP (Electrical Submersible Pump) is not a trivial task. Furthermore, Atlanta's wells lower completion is composed of Open Hole Horizontal Gravel Packs, due to the completely unconsolidated reservoir. To produce the viscous oil to the FPSO, the most powerful ESPs in the world, with 1,550 HP induction motors, were installed into the wells. Because of the low temperature on the seabed (around four degrees Celsius) in the event of any (expected or unexpected) plant or pump shutdowns, the viscosity of the cold oil could increase to up 100.000 cP in a few hours, despite the flowline insulation. Finally, managing the treatment plant start up procedure is a very complex task.\u0000 All these conditions combined made the Atlanta Field Start Up a real challenge. A very restrictive procedure to increase the production drawdown, the production rates, the ESP demand and the plant processing capacities were successfully implemented.\u0000 These extremely harsh conditions and the effective procedures to cope with them are thoroughly discussed in this paper.","PeriodicalId":334026,"journal":{"name":"Day 4 Thu, May 16, 2019","volume":"19 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-05-06","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"123625266","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":"Downhole Gas Separation in a High-GLR CO2 Application","authors":"B. Nicholson, C. Tyler, C. Yicon, M. Sikes, R.. El Mahbes","doi":"10.2118/194396-MS","DOIUrl":"https://doi.org/10.2118/194396-MS","url":null,"abstract":"\u0000 Electric Submersible Pumps (ESPs) are severely affected by free gas entering into the pump, which can cause significant degradation in pump performance. Gas locking (i.e., a gas bubble blocking the fluid from passing through the impeller) results in frequent shutdowns and restarts, thereby increasing the risk of premature failure. The result is unstable production due to ESP shutdowns caused by underload or high motor temperature. Historically, the industry has used shrouds, reverse flow gas separators, dynamic gas separators, and more recently, multiphase pumps to handle the gas. Such multiphase gas handling technology adds cost and requires additional power.\u0000 Recently Oxy Permian EOR installed a multiphase encapsulated production solution to separate the gas from the liquid in the wellbore. As produced fluids pass the pump at high velocity, the heavier liquid falls back into the shroud in a low-velocity area between the tubing and the top of the shroud, allowing the gas to continue to the surface. This system has proven to separate the gas from the liquid effectively, stabilizing operations within a certain operating window. In this paper, we share field examples showing the results achieved and how uptime improved over the last year. Twenty-four (24) systems have been installed in the Permian Basin with a 99% reduction in the number of shutdowns. All have had improved operational performance, with an average 30% improvement in drawdown and a 16% increase in total fluid production.\u0000 These particular fields are constantly being injected with CO2, which presents even more challenging conditions for ESPs than merely solution gas. As the CO2 enters the wellbore, the liquid stream composition changes, as does the gas/liquid ratio (GLR), making it difficult to draw down and function consistently over time. Many different systems have been tried with varying degrees of success. This system has proved to be successful in attaining our objectives of higher drawdown, stable operations, and fewer failures.","PeriodicalId":334026,"journal":{"name":"Day 4 Thu, May 16, 2019","volume":"36 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-05-06","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"133474549","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":"Analyzing SAGD Producer Flow Instability and ESP Deterioration Using Dynamic Flow Simulations: A Field Case Study","authors":"Song Shang, C. Nascimento, N. G. Bustamante, John Graham, T. Babatunde","doi":"10.2118/194403-MS","DOIUrl":"https://doi.org/10.2118/194403-MS","url":null,"abstract":"\u0000 High-temperature electric submersible pumps (ESPs) are the most commonly used artificial lift method in steam-assisted gravity drainage (SAGD) wells. While conceptually the SAGD process should provide a low-viscosity single-phase flow to the ESP system, changing pressures and temperatures associated with well drawdown create opportunities for introduction of free gas, water vapor, or both, resulting in multiphase flow regimes. This can often lead to wellbore flow instability and ESP performance deterioration.\u0000 An innovative approach to understanding ESP performance in multiphase flow conditions in SAGD production wells was developed by Shang, S. and Gomez-Bustamante, N. (2017), using well-specific fluid PVT characteristics to create the produced mixture's phase envelope. This analytical approach is able to identify phase boundaries, determine gas-water vapor volume fraction (GWVF), and predict flow regimes as a function of surface and downhole flowing measurements.\u0000 In this case study, the authors extend the modeling work done by Shang, S. and Gomez-Bustamante, N. (2017) with the objectives of constructing a wellbore model that includes the complex downhole completion, conducting transient analysis of the entire wellbore, analyzing slugging characteristics both upstream and downstream of the ESP, and ultimately providing operational recommendations to maximize well drawdown while maintaining wellbore stability.","PeriodicalId":334026,"journal":{"name":"Day 4 Thu, May 16, 2019","volume":"29 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-05-06","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"125991896","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":"Successful First ESP Project Offshore Brunei – Building ESP Capability","authors":"Yazid Yasmin","doi":"10.2118/194385-MS","DOIUrl":"https://doi.org/10.2118/194385-MS","url":null,"abstract":"Electrical Submersible pumps (ESPs) have been installed on a large scale for the first time in offshore Brunei. Despite having produced in Brunei for 80 years the company previously only had a single ESP running, and that was in an onshore field. The primary lift method in Brunei has been gas-lift, and regionally ESPs have not been widely adopted. As ESPs were relatively novel to offshore operations a steep learning curve was expected. Poor operation practices are a threat to run life, and failures are costly (especially offshore). This paper outlines the challenges faced by the project team, and the approach taken to execute this project successfully and operate ESPs smoothly from day one.\u0000 The application for these ESPs was relatively simple, with benign environments in low temperatures and shallow setting depths. The primary challenge with introducing ESPs to offshore Brunei was developing people, and building capability and hands on experience. The main approaches for this included: Building a new ESP operations team.Learning from other assets in the company portfolio (including in the Middle East and Western Siberia) via official visits, and sending staff for short term assignments.Developing long term vendor relationship including field operations support onshore and offshore.Rolling out an ESP competency plan with a clear outline on the required competency level for all personnel and how it could be achieved.Hosting more engagement sessions closer to first oil between the operations team and project team.\u0000 This paper shares: The challenges faced by the project.Details on building a competent team to successfully startup and operate ESP wells.Early results and performance of the operations team.Lessons learnt and next steps.","PeriodicalId":334026,"journal":{"name":"Day 4 Thu, May 16, 2019","volume":"5 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-05-06","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"128523462","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}