Day 4 Thu, August 19, 2021最新文献

{"title":"Friction Reduction Technology Tailored to Extreme Flow Rates","authors":"K. Trinh, Yufang Sandra Xia, Santiago Franco Tamara, D. Pérez, Chigozie Emuchay, Roman Vladimirovich Che","doi":"10.4043/31329-ms","DOIUrl":"https://doi.org/10.4043/31329-ms","url":null,"abstract":"\u0000 Non-thru bore drilling tools often feature limited flow range capabilities due to their design complexity. An ever-growing demand in high flow rates required a new technical solution that has the lowest possible pressure drop across the tool. Potential erosion issues as well as consistent functionality of the tool were key design requirements. A new friction reduction technology is presented that addresses the applications with flow rates ranging from low to high.\u0000 Initial computational fluid dynamics (CFD) analysis suggested the flow split can be executed by restriction at the tail end of the power section. This, however, was challenged by the first test run that took place at 550gpm (5¼-in. tool outside diameter [OD]). While the run objectives were met in its entirety, upon tear down, the early signs of erosion were noticed on the valve assembly. With this evidence on hand, a critical design change was implemented, and as a result, the restriction was moved down the power section to spare the vortex at its tail end. Further improvement was retrofitted to protect the restriction itself with a simple addition of a sleeve.\u0000 Further field runs were executed with the new tool setup. As the run count progressed, the newly redesigned technology achieved the objectives by delivering effective friction reduction at consistent frequency and pressure drop. It soon became evident that the step change in flow rate did not affect the tool wear and tear.\u0000 Since its inception the tool has set two field records. The first commercial run marked the fastest curve in the county. As this technology rises to prominence in the US and international markets, more operators are experiencing the savings and lower Authorization For Expenditure (AFEs).\u0000 The novelty of the design presented in this paper is in the drilling engineer's ability to design and construct wells with increased complexity (high dog leg severity [DLS], directional difficulty index [DDI], extended reach, and multi-lateral) where friction reduction technologies are critical to achieving run objectives. This technology fills a technical gap by meeting the new standards of high torque and flow rates in a compact and robust design. At the time of this writing, no other friction reduction technology meets these tool specifications.","PeriodicalId":11084,"journal":{"name":"Day 4 Thu, August 19, 2021","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2021-08-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83241953","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":"Significant Performance Improvement with MPD in HPHT Narrow Drilling Window Campaign in the North Sea","authors":"Babar Kamal, A. Saboor, Graeme MacFarlane, Frank Kernche","doi":"10.4043/31217-ms","DOIUrl":"https://doi.org/10.4043/31217-ms","url":null,"abstract":"\u0000 Significant depletion in reservoir pressure, huge uncertainties in pore and fracture pressure, high overburden pressure on top of reservoir, Narrow Mud Weight Window (NMWW) and Partial/Total losses whilst entering the reservoir made these HPHT (High Pressure High Temperature) wells conventionally un-drillable. Due to these substantial challenges these wells were considered not only costly but also carry a high probability of failure to reach well TD (Total Depth). MPD (Managed Pressure Drilling) is a safer and more effective drilling technique as compared to conventional drilling, especially in wells with NMWW and downhole hazards. The precise determination and dynamic downhole pressure management was imperative to complete these wells without well control incidents. The Constant Bottom Hole Pressure (CBHP) variant in combination of automated MPD system was deployed with a mud weight statically underbalanced while dynamically managed above formation pore pressure to minimize the overbalance across the open hole. MPD enabled the operator to efficiently navigate Equivalent Circulation Density (ECD) through the pore and fracture pressure window, allowed significant improvements throughout the entire campaign.\u0000 This paper discusses the challenges faced during the last three wells drilled in the campaign which includes equipment issues, commissioning delays, losses whilst drilling, Managed Pressure Cementing (MPC), 7\" drill-in-liner and plugged/blocked lines due to weather and mud conditions. The paper describes HPHT infill drilling experience, specific techniques, practices as well as lessons learned from each well during the campaign were implemented to address challenges and to improve performance. The MPD system commissioning was optimized by repositioning the lines which saved significant critical rig time. The blowdown points were added on the lines that were not operational continuously therefore a procedure was developed for flushing to avoid plugging. Optimized drilling strategy was also developed where MW was further reduced to avoid losses as observed in previous wells and CBHP was maintained by manipulating Surface Back Pressure (SBP) from surface.\u0000 This paper also discusses continuous improvements /upgrades in MPD operating software which assisted the operator in accurate monitoring of flow, SBP and BH-ECD to save significant rig cost in terms of invisible Non-Productive Time (NPT). MPD is a drilling enabler and performance enhancer which saved 80 days of Authorization for Expenditure (AFE) on this challenging HPHT campaign.","PeriodicalId":11084,"journal":{"name":"Day 4 Thu, August 19, 2021","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2021-08-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89329820","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":"Triple MPD Technique for Drilling and Intelligent Completion Deployment on an Abandoned Deepwater Well","authors":"André Alonso Fernandes, E. Schnitzler, F. Fabri, Leandro Grabarski, Marcos Vinicius Barreto Malfitani, Roger Savoldi Roman, W. M. Ascâneo","doi":"10.4043/31223-ms","DOIUrl":"https://doi.org/10.4043/31223-ms","url":null,"abstract":"\u0000 This is a case study of a presalt well that required the use of 3 different MPD techniques to achieve its goals. The well was temporary abandoned when conventional techniques failed to reach the final depth. Total fluid losses in the reservoir section required changing the well design and its completion architecture. The new open hole intelligent completion design had to be used to deliver the selective completion in this challenging scenario.\u0000 From the hundreds of wells drilled in the Santos basin presalt, there are some wells with tight or no operational drilling window. In order to drill these wells different MPD techniques are used. In most cases, the use of Surface Backpressure (SBP) technique is suitable for drilling the wells to its final depth. For the more complex cases, when higher fluid loss rates occur, the use of SBP and Pressurized Mud Cap Drilling (PMCD) enables the achievement of the drilling and completion objectives.\u0000 After the temporary abandonment of this specific well in 2018, the uncertainty of the pore pressure could not ensure that the SBP and PMCD techniques would be applicable when reentering the well. To avoid difficult loss control operations, the completion team changed the intelligent completion design to include a separated lower completion, enabling its installation with the MPD system. Besides the previously used MPD techniques, the integrated final project considered an additional technique, Floating Mud Cap Drilling (FMCD), as one of the possible contingencies for the drilling and completion phases.\u0000 Well reentry and drilling of the remaining reservoir section included the use all the previously mentioned MPD techniques (SBP, PMCD and FMCD). The lower completion deployment utilized the FMCD technique to isolate the formation quickly and efficiently, without damaging the reservoir. The planning and execution of the well faced additional difficulties due to the worldwide pandemic and personnel restrictions. The success from the operation was complete with no safety related events and within the planned budget. At the end, the execution team delivered a highly productive well with an intelligent completion system fully functional, through an integrated and comprehensive approach.\u0000 MPD use on deepwater wells is relatively new. Different operators used several approaches and MPD techniques to ensure safety and success during wells constructions over the last decade. This paper demonstrates the evolution of MPD techniques usage on deepwater wells.","PeriodicalId":11084,"journal":{"name":"Day 4 Thu, August 19, 2021","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2021-08-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82603637","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 and Trial of Technology for Open Hole Wells Performance Enhancement in GoM","authors":"L. Peixoto, W. Provost, J. Gerber","doi":"10.4043/31190-ms","DOIUrl":"https://doi.org/10.4043/31190-ms","url":null,"abstract":"\u0000 Open hole (OH) completions are not very common in the GoM, but the area has seen an uptick in OH wells in recent years, and a few big projects have elected to use the same completion archetype. There are several different ways to complete an OH well, and one of these completion techniques involves running screens across the OH in Drill-In fluid (DIF), displacing the DIF out of the OH with brine, and then setting the packer, before pumping a filter cake breaker, designed to remove the filter cake and restore the reservoir permeability to near pre-drilling levels.\u0000 A review of past open hole (OH) well completions in GoM revealed that there was an inconsistent action of the breaker on the filter-cake: sometimes the breaker would react quickly, and sometimes there was no noticeable effect. This study led to the development of a new technology to allow better displacements of the OH, with the ultimate objective of reducing initial well skin induced by the drill-in fluid (DIF) and filter cake.\u0000 It was theorized that the low displacement rates would lead to poor removal of the mud from the OH, in turn leading to a poor breaker action on the DIF filter cake and a long-term impact on well injectivity and increased OPEX, as these wells tend to need an initial stimulation within a short timeframe after initial completion. The approach used was to develop a new tool to allow faster displacement rates, and test it on a trial well, to verify the results and validate this theory.\u0000 To solve this problem, a new tool was proposed, developed and fully tested in a tight deadline of 6 months. The new module allows up to 9 bpm rates and up to 3,500 psi differential pressure before setting the packer, versus the previous ∼800 psi differential pressure limit, present in all tools in the market, for that casing size (7 5/8\").\u0000 During the first well trial, the tool allowed a displacement of the OH at double the pump rates obtained in previous wells in the same basin, with similar OH lengths, leading to the smallest volume of contaminated fluid interface seen to date, indicating a much better displacement. Once the well was put online, it achieved an injection rate above expectations, even when the drilled OH interval penetrated significantly less net sands than originally planned. The results on this single well trial seem to corroborate the theory posed, however it is recognized that more data is required to be certain of its results, and that will only come with time, as well performance is measured and compared with other wells that did not use the same technology.\u0000 The novelty of this new technology is the ability to obtain a better displacement of the OH, leading to a better breaker action and well cleanup in OH completions. Although the trial well was an injector well, the technology is equally applicable to producer wells. The paper will cover the problem description, installation procedures, development and testing of the technology, design aspects of using the ","PeriodicalId":11084,"journal":{"name":"Day 4 Thu, August 19, 2021","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2021-08-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87556361","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":"Longer Tiebacks by Electrification and Remote Power","authors":"J. Verdeil, Julien Manach","doi":"10.4043/31130-ms","DOIUrl":"https://doi.org/10.4043/31130-ms","url":null,"abstract":"\u0000 Standard field architecture is generally based on topsides production and distribution of power and chemicals necessary to operate equipment in drill centers. The paper will present efficient field architectures adapted to operate remote tie-backs with different combinations of subsea electrical power distribution, remote power generation and storage, and improved ways to mitigate corrosion, hydrates and wax issues for long tie-backs.\u0000 Developing remote resources requires several technology bricks that enable a cost effective and reliable technical solution. To reduce the CAPEX, the main objective is to reduce the number of tubes typically with one single heated flowline to avoid a long and costly service line or with one small power cable and local distribution of power to avoid a heavy and expensive large umbilical. Alternatively, power can be generated and stored at drill center location and chemicals can also be managed locally with limited OPEX.\u0000 A significant focus was done recently on technology developments enabling long distance tie-back developments. Domain of application and interest of each technology is generally well known and the delivered value is well presented. Looking for the most appropriate combination of technologies on a new field development is now the new challenge to figure out new opportunities. This paper proposes to group the long distance tie-backs fields in three main categories based on extensive studies done for several operators and to present the best architecture for each category. The first category groups very long distance single end tie-backs for which a cold flow system combined with full electrical equipment at drill center location is adapted. The second one is applicable for more consequent development where several drill centers are combined to one long and heated export line; with subsea electrical distribution to power each branch of the remote field and local management of chemicals at each drill center. The third category groups all daisy chain developments for which a heated line gathers the production coming from each fully electrical drill center.\u0000 Each field development can generally be categorized in one out of the three categories presented in this paper. Based on this categorization, the right combination of low carbon and reliable new technologies enables valuable development of long tie-backs and then increases utilization area of each existing asset.","PeriodicalId":11084,"journal":{"name":"Day 4 Thu, August 19, 2021","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2021-08-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90670699","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":"Unconventional Approach Simplifies Steel Catenary Riser Decommissioning","authors":"Ansel Orr, S. Olmos, D. Cheek, Mike Coyne, Nagu Tatineni, Yc. Park, D. Seal","doi":"10.4043/31029-ms","DOIUrl":"https://doi.org/10.4043/31029-ms","url":null,"abstract":"\u0000 A major pipeline company was tasked with decommissioning the Morpeth tension leg platform (TLP) in the Gulf of Mexico (GoM) and needed to abandon a 22-year-old, 8-in gas export steel catenary riser (SCR).\u0000 The conventional approach to decommissioning an SCR is to mobilize a topside winch package, which sometimes requires the removal of platform equipment. The next step is to carry out structural engineering checks on the platform, determine the wire's various drop point routes through the platform, and provide the engineering analysis necessary to handshake the load from the winch to a heavy lift vessel for abandonment. This was the original plan for the Morpeth TLP SCR decommissioning program.\u0000 Instead of employing this traditional approach to remove the riser using a topside winch package and heavy lift vessel, the pipeline owner requested an alternative method that had been used previously for an international operator. This novel method employed ROVs and divers to install a series of clamps to grip and secure the riser prior to cutting and used a Multiservice Vessel (MSV) to manage the disconnected riser for abandonment on the seafloor. The appeal of this integrated solution is that it does not interfere with the platform's topside operations or equipment layout and can provide potential cost savings.\u0000 This methodology was used for the first time in the GoM to remove a riser to make space for a new one to be installed. For this installation, a clamp was designed by the operator to sit on the J-lay collar and to support the weight of the riser being removed. The project was modeled in OrcaFlex to determine safety requirements and the service company carried out the riser removal. Following adaptations to accommodate the differences presented by the Morpeth TLP SCR, a similar approach was used in the SCR decommissioning project, with the service company's engineering team designing a combination of a friction and through-pin box clamp, determining their placement, mapping out the role of divers, and defining the necessary vessel movements for each phase of the operation.\u0000 Following an initial survey to determine the profile of the SCR, the service company created an OrcaFlex model and decommissioning plan that would allow the vessel to safely execute the program. The model allowed the team to incorporate safety factors to ensure that the load of the riser could be managed and that the riser could be handled without jeopardizing the safety of the vessel or creating riser clashing during the process of cutting and swinging the riser away from the TLP. It was determined that a winch wire could be cantilevered off the stern of the vessel to provide overhead access to the riser and clamp connection point. With the clamps properly connected, the riser was severed in a controlled manner by ROVs and then abandoned within the right-of-way (along the pre-approved area) of the pipeline prior to the ends being plugged and covered.\u0000 In comparing the actua","PeriodicalId":11084,"journal":{"name":"Day 4 Thu, August 19, 2021","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2021-08-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"73964726","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":"Mooring Integrity Management through Digital Twin and Standardized Inspection Data","authors":"Shunsaku Matsumoto, V. Jaiswal, T. Sugimura, Shintaro Honjo, Piotr Szalewski","doi":"10.4043/31036-ms","DOIUrl":"https://doi.org/10.4043/31036-ms","url":null,"abstract":"\u0000 This paper presents a concept of a mooring digital twin frameworkand a standardized inspection datatemplate to enable digital twin. The mooring digital twin framework supports real-time and/or on-demand decision making in mooring integrity management, which minimizes the failure risk while reducing operation and maintenance cost by efficient inspection, monitoring, repair, and strengthening. An industry survey conducted through the DeepStar project 18403 identified a standard template for recording inspection data as a high priority item to enable application of the digital twins for integrity management. Further, mooring chain was selected as a critical mooring component for which a standard inspection template was needed. The characteristics of damage/performance prediction with the proposed mooring digital twin framework are (i) to utilize surrogates and/or reduced-order models trained by high-fidelity physics simulation models, (ii) to combine all available lifecycle data about the mooring system, (iii) to evaluate current and future asset conditions in a systematic way based on the concept of uncertainty quantification (UQ). The general and mooring-specific digital twin development workflows are described with the identified essential data, physics models, and several UQ methodologies such as surrogate modeling, local and global sensitivity analyses, Bayesian prediction etc. Also, the proposed digital twin system architecture is summarized to illustrate the dataflow in digital twin development andutilization. The prototype of mooring digital twin dashboard, web-based risk visualization and advisory system, is developed to demonstrate the capability to visualize the system health diagnosis and prognosis and suggest possible measures/solutions for the high-risk components as a digital twin's insight.","PeriodicalId":11084,"journal":{"name":"Day 4 Thu, August 19, 2021","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2021-08-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"80365089","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":"Novel THOR Technology for Orientation of Vertical XT to Completions","authors":"N. P. Katsounas, P. D. Pathak, Daniel Ronald Quates, Guy Mosscrop","doi":"10.4043/31033-ms","DOIUrl":"https://doi.org/10.4043/31033-ms","url":null,"abstract":"\u0000 On conventional vertical trees (VXTs) with a tubing hanger (TH) in the wellhead (WH), orientation of the VXT to the TH system is a complicated and expensive process. Leveraging patented technology, the tree to hanger orientation ring (THOR) and tooling were implemented to save CAPEX and OPEX while eliminating risks associated with conventional orientation solutions. An open-water tool installs an external alignment feature onto the wellhead, which is oriented with the tubing hanger already installed in the wellhead. The VXT then orients onto the wellhead with the help of this external alignment feature, resulting in correct orientation with the tubing hanger. This paper discusses the novel technology and its successful development and installation for a subsea project, which revolutionizes the VXT portfolio.\u0000 Rapid development of THOR technology was required along with expedient project execution. Utilizing digital-twin design techniques such as finite element analysis and operator simulations, the operating life of THOR tooling was investigated in parallel with project engineering. The novel nature of the THOR required unconventional testing, which was performed in-house. Project execution plan was implemented for engineering and manufacturing to successfully build the production equipment on schedule. Comprehensive system integration testing was completed upon the first attempt. The system was deployed to staging facilities before being delivered offshore to the customer and installed subsea in stages during April 2020. Involvement of the operators and installation contractors during the development stage made THOR's first deployment attempt a major success with zero recorded nonproductive time, even during COVID-19.\u0000 THOR technology reduces the number of components as well as the weight and size of the equipment. The novel THOR equipment can be run by a light intervention vessel rather than conventional equipment, which requires mobile offshore drilling units. The time spent to deploy the VXT system is also reduced, minimizing indirect supply-chain and field-service-related carbon emissions. This further enables reduced carbon emissions and overall carbon footprint of the entire project.\u0000 The field-proven THOR technology is an evolutionary orientation technology that simplifies the installation operations for the vertical tree and tubing hanger. This technology maintains the robust conventional system configuration post installation and hence does not affect reliability of the VXT system.","PeriodicalId":11084,"journal":{"name":"Day 4 Thu, August 19, 2021","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2021-08-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"85321498","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":"A New Fundamental Understanding of Gas in the Drilling Riser","authors":"C. Leach, Guangzhao Zhou, Veerabhadra S. Denduluri, G. K. Wong, R. Krishnamoorti, A. Prosperetti","doi":"10.4043/31248-ms","DOIUrl":"https://doi.org/10.4043/31248-ms","url":null,"abstract":"\u0000 The work described here originated from the tragic and ultimately environmentally catastrophic event at the Macondo well in April 2010. The first part of the paper addresses the causes for the sudden and often destructive ejection of hydrocarbons from a riser when a gas kick escapes timely detection. The approach differs from previous work on the subject and provides a realistic understanding of the sequence of events responsible for the phenomenon. The focus is on the crucial few minutes and seconds prior to the sudden eruption of gas and provides a quantitative illustration of the extreme rapidity of the ejection which leaves no time for a drill crew to adopt mitigation measures. It is shown that, in many cases, a back-pressure applied at the top of the well can be beneficial. The second part of the paper describes a novel method for the detection of gas which relies on the measurement of pressure differences along sections of the riser. These data are sensitive to the mean density of the fluid in the section and can therefore detect the presence of free gas. Laboratory experiments supporting the idea are described. Proper signal processing can be developed which may be able to allow for automatic mitigation measures to be taken in the event of an otherwise undetected gas influx approaching the surface.","PeriodicalId":11084,"journal":{"name":"Day 4 Thu, August 19, 2021","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2021-08-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"85919087","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":"Subsea Liquid Energy Storage – The Bridge Between Oil and Energy/Hydrogen","authors":"Kristian Mikalsen","doi":"10.4043/31294-ms","DOIUrl":"https://doi.org/10.4043/31294-ms","url":null,"abstract":"\u0000 This paper demonstrates a pioneering technology adaption for using a membrane-based subsea storage solution for oil/condensate, modified into storing clean energy storage in the form of ammonia (as a hydrogen energy carrier). The immediate application will provide an economical alternative to electrification of offshore platforms, instead of using expensive cables from shore. Storing ammonia at the seabed using innovative subsea storage technologies will dramatically reduce CO2 emissions for offshore assets. The fluid will be stored in a safe manner on the seafloor, protecting both personnel and marine life. The next step will be to include subsea ammonia storage as part of the global logistical value chain, which can power the merchant shipping fleet. Clean ammonia can be produced using renewable resources as wind or solar.\u0000 It focuses on bridging the ongoing oil/condensate storage qualification, adapted into storing ammonia. The large-scale verification test scope is explained, and we show how the test is extended to also prove the concept of safe energy/ammonia storage. The ammonia storage concept is explained, and we show how this can be included as part of a low carbon future. The focus is the immediate market for providing clean power to existing or new offshore assets. The full system solution will encompass storage tanks placed nearby the platforms at safe water depths, riser systems providing fuel to the ammonia power generators, and the tank filling systems. Bridging and adapting technologies from the petroleum industry into renewables shows the importance of utilizing the technology developments and competence of the oil and gas business.\u0000 The technical evaluations have shown that the oil/condensate storage can be adapted into storing energy/ammonia with minor modifications. Converting hydrogen into ammonia gives slight energy losses, but it is defended by the large economic benefits of storing ammonia versus pressure storage of hydrogen. The paper presents qualification work already completed and how to implement ammonia fuel storage for platforms. In addition, we show the test setup for a large-scale qualification provided by an original equipment manufacturer (OEM) company together with major Operators. Innovative modular design methods have shown that the concept can be included on existing offshore assets, which have limited topside space available. Adding green or blue ammonia as an alternative to power cables from shore have several benefits, and many of the connecting building blocks are falling into place. The main conclusion is how to adapt Novel technologies from the oil industry to store ammonia in a safe way on the seafloor.","PeriodicalId":11084,"journal":{"name":"Day 4 Thu, August 19, 2021","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2021-08-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83947024","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}