Day 4 Thu, August 19, 2021最新文献

{"title":"Critical Review of the Thai and Malaysian Decommissioning Landscapes","authors":"A. Tung, Wanarun Wanarunwong, Pattaramon Vuttipittayamongkol","doi":"10.4043/31132-ms","DOIUrl":"https://doi.org/10.4043/31132-ms","url":null,"abstract":"\u0000 As the wave of oil and gas decommissioning activities begins across Thailand and Malaysia, issues related to the management of oil and gas decommissioning activities also begin to take shape, appearing in the form of disputes (Tanakasempipat 2019), schedule delays (Zainal Abidin and Mahasan 2019), scope creeps (Xu et al. 2019; Yap 2018), and cost overruns (Yusof, Ros and Omar 2018). One avenue to overcome the issues related to the management of oil and gas decommissioning activities in Thailand and Malaysia, is to enhance project managers’ understanding of the Thai and Malaysian oil and gas decommissioning landscape. Therefore, a research involving semi-structured interviews with 20 industrial representatives was conducted over the period of 2019 and 2020.\u0000 This paper presents the findings from the research, detailing the regulatory structure and process, the supply chain and research capabilities, the operator's planning and execution behaviours for oil and gas decommissioning, and public stakeholders’ behaviours towards oil and gas decommissioning activities. The research findings will be presented in the form of a list of considerations, which project managers can utilize when managing future oil and gas decommissioning activities in Thailand and Malaysia. In addition, emergent research findings will also be summarized as a list recommendations for legislative and regulatory government bodies in order to further enhance the effectiveness of current regulatory arrangements.","PeriodicalId":11084,"journal":{"name":"Day 4 Thu, August 19, 2021","volume":"10 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-08-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83834240","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":"Decommissioning Offshore Structures by Extraction of Foundation Mono piles Applying a Vibratory Hammer","authors":"Rob van Dorp, P. Middendorp, M. Bielefeld, G. Verbeek","doi":"10.4043/31006-ms","DOIUrl":"https://doi.org/10.4043/31006-ms","url":null,"abstract":"\u0000 The vibratory hammer is one of the tools for the extraction of offshore foundation piles as well as monopiles for the decommissioning of offshore structures. In addition to the standard application, where a pile is driven downward to be installed, a vibratory hammer can also be applied to extract piles. For an efficient and commercially attractive application of vibratory hammers for this purpose, the extraction process needs to be modeled during the planning phase to ensure that the appropriate equipment is used. This paper describes how pile driving simulation software can be used to model the extraction process. This is further illustrated through a case study covering the extraction phase of the 1st (onshore) and 2nd (offshore) part of the Delft Offshore Turbine Project. A monopile with a diameter of 4.0 m was extracted approximate 6 months after installation onshore and then extracted several times offshore shortly after installation in the 2nd phase. The paper will not only present the actual extraction predictions, but also the monitoring data obtained during extraction and the results of the post-analysis.","PeriodicalId":11084,"journal":{"name":"Day 4 Thu, August 19, 2021","volume":"51 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-08-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88268874","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":"Solving Decommissioning and Abandonment Problems When Planning to Shear 9 5/8-inch Casing in a 13 5/8-inch × 10k RAM BOP","authors":"D. E. Cain, K. Klopfenstein, James Robert McMullan","doi":"10.4043/31062-ms","DOIUrl":"https://doi.org/10.4043/31062-ms","url":null,"abstract":"\u0000 A decommissioning and abandonment requirement to shear 9 5/8-inch casing in certain circumstances with a 13 5/8-inch × 10,000 psi rated working pressure, RWP, Shear RAM type blowout preventer, BOP, resulted in a need to develop a novel casing shear device and shear calculation method. Results of shear testing, future engineering planning guidance, the new shear calculation method, and comparison to legacy technology are included in this paper.\u0000 Interaction with the end user to understand requirements, a five-step problem solving procedure, a basis of design process, materials justification, verification analysis, validation testing, and describing an improved shear operator force/pressure calculation are all described. Shear larger casing in the required and restrictive RAM BOP and well bore presented a problematic challenge. Equally, tubular fish size was required to support fishing extraction operations following shear. Validation test results exceeded requirements and resulted in the need for a new approach to the shear calculation method.\u0000 The novel shear RAM geometry was developed utilizing shear calculation methods which were based on legacy considerations. API 16A shear validation procedures and two legacy shear calculation methods where employed. Shear calculations are used to anticipate the RAM BOP operator pressures required to shear a specific tubular. The larger than historically allowed casing size to be sheared in a 13 5/8-inch × 10,000 psi RAM BOP meant higher operator pressures were anticipated for each operator option. A Novel shear RAM geometry was developed as a design intent to lower shear force/pressure. There was an observation during validation testing that the geometry exceeded expectations to lower shear pressure significantly. This observation led to a conclusion that an improved shear calculation method was required for this application. This novel calculation method description / statistical treatment, test results, RAM design methods, and tabular shear engineering planning information are included in this paper.\u0000 One additional requirement of the shear RAM geometry was to provide an upper and lower fish deformed surface which could be easily retrieved thru the 13 5/8-inch BOP bore. An additional observation was that the fish width requirement was achieved.\u0000 The novel shear calculation method allows an engineer to precisely plan for bonnet actuation pressures when larger casing is sheared. The precise calculation of shear force/pressure also assists with BOP operator size and type selection. The engineer will gain casing size versus shear pressure for specific operator options in tabular format. Planners will gain insight into tubular fish deformation estimation allowing mitigation of tubular extraction risk during operations planning.","PeriodicalId":11084,"journal":{"name":"Day 4 Thu, August 19, 2021","volume":"9 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-08-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88796964","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":"Experience with Chemical Injection and Umbilicals in Pre-Salt Fields","authors":"Sidnei Guerreiro Da Silva, André Athayde Gonçalves, William Albuquerque da Silva, Rafael Di Lorenzo Filho","doi":"10.4043/31164-ms","DOIUrl":"https://doi.org/10.4043/31164-ms","url":null,"abstract":"\u0000 The characteristics of Pre-Salt carbonate reservoirs demand downhole chemical injection to prevent scale, asphaltene, and wax deposits, besides the need of H2S scavenger, and MEG, normally injected at Xmas tree (WCT). The poor performance of injection systems installed in Santos Basin, together with production risks associated to the lack of chemical injection, led the project team to re-evaluate design requirements, such as chemical products characteristics, production systems equipments, umbilicals, and chemical injection valves. In addition, umbilical failures are being observed in other deep-water fields, related to subsea control systems functions. This paper focuses on Company operational experience and lessons learned related to umbilicals and downhole chemical injection.","PeriodicalId":11084,"journal":{"name":"Day 4 Thu, August 19, 2021","volume":"202 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-08-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77002172","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":"Increasing the Cost Effectiveness of Mechanically Lined Pipe for Risers Installed by Reel-Lay","authors":"R. Jones, G. Toguyeni, James Hymers, Peter Tanscheit, Nelson Bittar Romeu, Venu Rao, J. Banse","doi":"10.4043/31325-ms","DOIUrl":"https://doi.org/10.4043/31325-ms","url":null,"abstract":"\u0000 The use of mechanically lined pipe (MLP) using a thin liner, i.e. 2.5mm, can provide a more cost effective linepipe material solution relative to a standard 3.0mm liner. This is especially the case for the more expensive liner materials with higher corrosion resistance, including Alloy 625. Thin liners, i.e. 2.5mm, can be used without compromising pipeline integrity and performance, whilst still fulfilling design requirements defined in most pipeline design standards, including DNVGL-ST-F101. The suitability of 2.5mm liner MLP has previously been demonstrated in service over a range of pipeline bundle projects installed with the controlled depth tow method, but not to date for risers installed by reel-lay. This paper presents the details and test results of the qualification programme to support its use for both flowlines and risers installed by reel-lay.\u0000 The qualification MLP test pipes, which comprised an outer diameter (OD) 219.1mm × wall thickness (WT) 15.9mm X65 + 2.5mm Alloy 625, were manufactured using established manufacturing procedures and facilities. Reeling and fatigue test strings were fabricated using qualified welding solutions. The fabricated test strings were subject to internal visual inspection and dimensional measurement using laser metrology in order to provide a benchmark for comparison post reeling. The test strings were given a simulated reeling procedure using bending and straightening formers representative of a reel-lay vessel with the smallest reel hub diameter, this being a conservative material straining condition. An internal pressurisation technique, as per standard installation practice for the present pipe lay contractor for MLP, was applied during the simulated reeling procedure. Post reeling the internal laser metrology inspection procedure was repeated in order to confirm the integrity of the liner and to check for the presence of any evidence of liner wrinkling or damage. Subsequently, full scale fatigue testing was performed using the high frequency resonance bending procedure. Testing was performed to ultimate failure to determine the fatigue endurance limit of the thin liner MLP.\u0000 Additionally Finite Element Analysis (FEA) was performed to further validate the satisfactory reeling performance of the thin liner MLP. The FE numerical analysis embraced manufacture of the MLP pipe and test samples coupled with the reeling procedure. Sensitivity analysis on pipe strength and geometrical mismatch was performed to demonstrate the robustness of the linepipe material solution and reeling procedure.\u0000 All of the critical qualification activities were performed and verified by DNVGL and in accordance with the guidance of DNVGL-RP-A203 Technology Qualification process.\u0000 The paper highlights the qualification programme performed to enable the cost effective use of thin liner MLP, specifically Alloy 625, for risers installed by reel-lay.","PeriodicalId":11084,"journal":{"name":"Day 4 Thu, August 19, 2021","volume":"47 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-08-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88001907","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":"Using Third Interface Echo TIE Response Through Inner Casing to Enucleate the Outer Casing Geometry in 3D View","authors":"Apoorva Kumar, Palak Bansal, Gaurav Agrawal, Kamaljeet Singh, Shaktim Dutta","doi":"10.4043/31319-ms","DOIUrl":"https://doi.org/10.4043/31319-ms","url":null,"abstract":"\u0000 Casings can deform over the life of the well due to various reasons such as changing stress regimes, geological fault and fractures causing pinching, pressure differential created due to production, increased pressure due to injection, squeezing formations such as shale and salt, etc. A detailed casing deformation evaluation can provide insights to the operators in correlating the deformation to suitable reasons in their field.\u0000 There are various methods to evaluate the innermost casing or tubing using ultrasonic and mechanical caliper measurements but there is no technology available to evaluate outer or second casing deformation without first retrieving the inner casing or tubing. This work introduces and encapsulates the novel methodology of transforming the outer or second casing third interface echo (TIE) response, obtained by advanced ultrasonic and flexural measurement inside innermost casing or tubing, into a 3D wellbore view to suitably visualize and analyze the outer or second string deformations.\u0000 The work involves measuring the azimuthal radius and thickness of the innermost casing with the ultrasonic evaluation technique and computing the azimuthal annular distance between the two casings using the flexural wave TIE arrival time and its velocity in the annular fluid. The computed values are then combined to generate an array of azimuthal internal radius values of the outer or second casing and is finally converted into a 3D wellbore image for better and straight-forward visualization.\u0000 To validate the methodology, a shop inspection test (SIT) was carried out where the dimensions of the inner and the outer casing were precisely measured with a mechanical caliper tool. Following that, ultrasonic and flexural measurement tool was run inside the innermost casing to obtain the response of both casings.\u0000 The comparison showed a close match between the actual values and the measurements. Also, the 3D wellbore shape clearly showed the geometry of the outer string validating the methodology used in the creation of the 3D shape. The work can enable the operators to carry out time lapse outer string analysis on a periodic basis to give them early indications of any deformation in the outer or second string.\u0000 This novel technique or methodology also has valuable application in plug and abandonment (P&A) where the inner tubing and casing retrieval can be hindered due to outer casing deformation. This technique can also help in designing the right drilling BHA for sidetracking based on the minimum ID of the outer pipe through which slot recovery or side-track has to be performed.","PeriodicalId":11084,"journal":{"name":"Day 4 Thu, August 19, 2021","volume":"12 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-08-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82049911","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":"Next Generation High-Definition Geomagnetic Model for Wellbore Positioning, Incorporating New Crustal Magnetic Data","authors":"M. Nair, A. Chulliat, A. Woods, P. Alken, B. Meyer, B. Poedjono, Nicholas Zachman, J. Hernandez","doi":"10.4043/31044-ms","DOIUrl":"https://doi.org/10.4043/31044-ms","url":null,"abstract":"\u0000 Magnetic wellbore positioning depends on an accurate representation of the Earth's magnetic field,where the borehole azimuth is inferred by comparing the magnetic field measured-whiledrilling (MWD) with a geomagnetic reference model. Therefore, model accuracy improvements reduce the position uncertainties. An improved high-resolution model describing the core, crustal and external components of the magnetic field is presented, and it is validated with anindependent set of measurements. Additionally, we benchmark it against other high-resolution geomagnetic models. The crustal part of the improved high-definition model is based on NOAA/NCEI's latest magnetic survey compilation \"EMAG2v3\" which includes over 50 millionnew observations in several parts of the world, including the Gulf of Mexico and Antarctica, and does not rely on any prior information from sea-floor geology, unlike earlier versions. The core field part of the model covers years 1900 through 2020 andis inferred from polar-orbiting satellite data as well as ground magnetic observatory data. The external field part is modelled to degree and order 1 for years 2000 through 2020. The new model has internal coefficients to spherical harmonic degree and order 790, resolving magnetic anomalies to approximately 51 km wavelength at the equator. In order to quantitatively assess its accuracy, the model was compared with independent shipborne, airborne and ground magnetic measurements. We find that the newmodel has comparable or smaller errors than the other models benchmarkedagainst it over the regions of comparisons. Additionally, we compare theimproved model against magnetic datacollected from MWD; the residual error lies well within the accepted industry error model, which may lead tofuture error model improvements.","PeriodicalId":11084,"journal":{"name":"Day 4 Thu, August 19, 2021","volume":"93 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-08-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89236093","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":"Comprehensive Approach to Tackle Systemic Failure in Gas Lift Valves in Pre Salt Wells","authors":"Elaine Daniele M P C Real, Thiago Geraldo Silva, Otavio Borges Ciribelli, T. Sanomya","doi":"10.4043/30943-ms","DOIUrl":"https://doi.org/10.4043/30943-ms","url":null,"abstract":"\u0000 This work describes a comprehensive approach to tackle systemic failure in gas lift valves in pre-salt wells. Failure analyses in gas lift valves were performed after unexpected early failures leading to tubing-annulus communication. Understanding the root causes of this problem generates value for assets, increasing equipment life, preventing unnecessary workover, and reducing costs.\u0000 Suspect failed valves are systematically removed from the wells, usually by slick-line workovers, and brought to an onshore workshop, where their integrity and mechanical functionality can be analyzed. The valve's run life, equipment model and manufacturer, annular fluid, flow through the gas lift valve, operational pressure and temperature, composition of reservoir fluids and solids deposition were verified.\u0000 Besides, transient simulations were carried out to provide insights on the root causes of the failure. Also, a good understanding on how each valve works, including its engineering design, was necessary to thoroughly understand the failure process.\u0000 The study of gas-lift injection valves early failure in pre-salt wells have been an excellent way to understand the life cycle of production wells before the need to start lift gas injection. That leads to a comprehensive understanding about the effects of the fluids left in annulus and have supported Petrobras in most effectively managing of well integrity and workover costs.\u0000 The analysis incorporates the impact of oil production, water cut, completion type, annular fluid composition, anti-scaling fluid injection (composition and efficiency) and the differential pressure between the tubing of the annulus in the valve failure model. The composition of the deposit found inside the valves and the production history of the well were essential to assemble the puzzle of how the failure mechanism works. With the acquired knowledge, it has been possible to apply barriers to avoid future events of unwanted tubing-annulus communication arising from gas-lift valve failures.\u0000 This article provides a methodology and examples for a most effective understanding of the gas-lift valves failure mechanisms and their root causes, which proved to be a valuable tool for the artificial lift design and for the planning of well operations. That has contributed to maximize equipment life, cost reduction and, at last, generating value for the company.","PeriodicalId":11084,"journal":{"name":"Day 4 Thu, August 19, 2021","volume":"31 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-08-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"85099807","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":"The World Deepest Electrically Heat-Traced Flowline","authors":"Florent Hurault de Ligny, Thomas Cuau, S. Immel","doi":"10.4043/31211-ms","DOIUrl":"https://doi.org/10.4043/31211-ms","url":null,"abstract":"\u0000 Electrical heat tracing technologies for flowline applications have been in development phase for some time. Yet in recent years, the efforts to deploy this technology on real life applications have intensified, leading to several projects in the industry simultaneously adopting this solution. As often seen with technology development, implementing the serial number 1 of a technology requires one project with favorable conditions and parameters, but also the stakeholders willingness to face the challenge associated to being first, and having to cross the final gap between the qualification program and this real life application. This paper presents how a specific project met all the conditions to be the first to select and implement a deepwater EHTF® (Electrically Heat-Traced Flowline) solution.\u0000 This paper presents the Project from the concept selection phase, to the execution and offshore installation of the final product. This provides an overview of why this technology was selected, and how the Project was executed, with a focus on the main challenges encountered and the associated solutions.\u0000 The concept selection phase for this two-well development consisted of comparing subsea tie-in architectures to tieback architectures using one or several new risers. The EHTF® emerged as the highest value solution, offering the best compromise between technical, economical, risk and schedule criterion, as it enabled single line tieback, while significantly reducing the operational risks associated to such architecture. A FEED was launched to further define and accurately estimate the concept, in order to reach FID. Close collaboration between the Operator and the Contractor at every step of the process allowed the solution to be selected and developed in a fast track manner while enabling the Contractor to provide an optimized, tailor-made solution.\u0000 The project execution involved many work sites, including the Vigra spoolbase in Norway for EHTF® fabrication, as well as the Seven Vega, which was a brand-new addition to the pipelay vessels fleet at the time of the Project. Many challenges arose during the project execution, as the qualification program was being completed, but adequate solutions were developed, allowing the Project to continue its course.\u0000 Obviously, there were many lessons learned along the way, which will feed into further product development plans, in order to improve its technical performance and competitivity. Heat tracing solutions offer great opportunities for single line long tieback development which often come with elevated operating risk profile due to complex wax and hydrate management. Enhanced thermal performance of resistive heating systems makes it possible to operate with low power consumption, which is a key in today's world of energetic efficiency.","PeriodicalId":11084,"journal":{"name":"Day 4 Thu, August 19, 2021","volume":"63 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-08-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"81119538","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":"The Autonomous Inflow Control Valve Design and Evaluation Criteria Along with Well Performance Review for Multiple Installations Across the Globe","authors":"Tejas Kalyani, H. Aakre, V. Mathiesen","doi":"10.4043/31193-ms","DOIUrl":"https://doi.org/10.4043/31193-ms","url":null,"abstract":"\u0000 Many wells across the globe have been installed with Inflow Control Device (ICD) technology to balance the production across the production interval, addressing some of the challenges associated with horizontal and deviated wells. Nevertheless, ICDs have limitations with restricting unwanted fluids upon breakthrough. Autonomous Inflow Control Valve (AICV) technology functions similar to an ICD initially (i.e., balancing flux across the length of horizontal wells, effectively delaying breakthrough) but provides the additional benefit of shutting off the flow of unwanted fluids upon breakthrough. This paper will present comprehensive AICV completion design workflow along with multiple case histories highlighting the reservoir management benefits of the AICV technology in mitigating un-wanted inflow of water and gas and delivering improved oil production and recovery.\u0000 Like other AICDs (Autonomous Inflow Control Device), AICV can differentiate the fluid flowing through it via fluid properties such as viscosity and density at reservoir conditions. However, AICV's performance is much more effective due to its advanced design which provides further benefits using both Hagen-Poiseuille's and Bernoulli's principles. AICV technology is based on the difference in the pressure drop in a laminar flow element (LFE) compared to a turbulent flow element (TFE) and has a capability to shut-off the main flow autonomously when an unwanted fluid such as water or gas breakthrough occurs. Thus, reduces well water cut (WC) and/or gas-oil ratio (GOR) significantly. Rigorous single-phase and multiphase flow-loop tests have been conducted covering a wide range of fluid properties to characterize the AICVs flow performance. Extensive plugging testing and accelerated erosion tests have also been conducted. This paper presents some of these flow performance analysis and testing results. Furthermore, the paper will also discuss in detail a reservoir-centric AICV completion modelling and design workflow.\u0000 Finally, this papers also discuss in detail AICV well performance installed in a light oil as well as in heavy oil reservoirs and how operators achieved higher OPEX saving as well as higher ultimate recovery (UR) from the wells due to prolonged as well as significant reduction in water cut and/or lower GOR.\u0000 The AICV design methodology and performance evaluation analysis is presented through several case studies. The analysis takes into account the whole cycle: from flow loop testing to characterization, reservoir modelling, optimized AICV completion design and post-installation well performance to evaluate the AICV technology benefits.","PeriodicalId":11084,"journal":{"name":"Day 4 Thu, August 19, 2021","volume":"44 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-08-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84795282","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}