Day 2 Wed, March 22, 2023最新文献

{"title":"Subsea Well Annular Integrity Repair Using Coiled Tubing and Pressure Activated Sealant","authors":"J. Johns, Chris Anderson, Juan A. Anguiano, S. Jones","doi":"10.2118/212925-ms","DOIUrl":"https://doi.org/10.2118/212925-ms","url":null,"abstract":"\u0000 Production from a subsea well was halted due to hurricane activity in the Gulf of Mexico. When the well was returned to production, the annulus experienced a loss of pressure integrity. To achieve regulatory compliance and return the well to production, annular integrity had to be restored in a safe, expeditious manner. This paper will describe the process of operations undertaken to cure this well integrity issue utilizing pressure activated sealant deployed via coiled tubing.\u0000 Pressure activated sealants have been utilized for a number of years to efficiently cure leaks in a wide variety of applications. One of the first challenges to be addressed when considering a sealant repair is the method of getting the material to the leak site. For the purpose of the subsea well in question, coiled tubing was used to convey the sealant to the sea floor from a service vessel. An ROV then connected the coil to an external tree cap via a flying lead after which the sealant was introduced to the annulus by lube and bleed pressure cycles.\u0000 The annular integrity issue was analyzed in an effort to determine leak severity and location. Pressure trends noted at annular pressures of 4000 psi indicated a leak ranging from 0.15 – 1.5 lit/min. Gradient analysis indicated that the leak was deep in the completion potentially at a liner lap or the packer. Based on this information a sealant blend approximately 2 ppg heavier than the completion fluid was developed for the purpose of curing the leak. An external tree cap was installed on the well in order to provide access to the annulus of the well via a hot stab connection. About eleven cubic meters of sealant was transferred to the annulus through 2\" coiled tubing extended to the sea floor connected to the well via a flying lead. A series of lubricate and bleed cycles were performed to accomplish this without exceeding predetermined pressure limits. After allowing the sealant to settle on the packer, annular pressure was maintained to allow the sealant to cure at the leak site. The pressure differential at the leak caused the liquid sealant to form an elastomeric seal. A positive pressure test was obtained shortly after the process and the well was returned to production.\u0000 An example of how using pressure activated sealants designed to polymerize only at a leak site affords options to expensive workovers on subsea wells will be provided herein. The use of this technology in concert with coiled tubing deployment represents an expeditious, economic approach to solving complex well integrity issues.","PeriodicalId":303929,"journal":{"name":"Day 2 Wed, March 22, 2023","volume":"27 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-03-14","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"125329674","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":"Sustained Annulus Pressure: A Case Study into the Application and Integration of Distributed Optical Fiber Sensing","authors":"M. Webster, Elena Fiorilo, Maria Eugenia Salamanca, Andrea Cristina Lopez, Carlos Pedro Rodolfo Orlandi, Lena Urmantseva","doi":"10.2118/212919-ms","DOIUrl":"https://doi.org/10.2118/212919-ms","url":null,"abstract":"\u0000 Distributed Fiber Optic Sensing (DFOS) allowed us to continuously gather information behind casing, while changing the wells surface conditions. The objective of this case study is to identify the potential causes of the sustained annulus pressure using distributed optical data, integrated it with conventional well information to help define remedial action.\u0000 The sensing fiber was deployed utilising fiber-enabled slickline allowing the measurement of the whole well over the duration of the survey. Conventional memory Gamma Ray, CCL, Pressure and Temperature sensors were also run on the fiber slickline. A program consisting of an initial baseline, a sequence of bleed off, shutin and production periods were used to create measurable events for the fiber to detect over a 7 hour survey period. With the integration of the information provided by the memory tools, it is possible to determine the location of the sustained pressure contribution and the fluid behavior related to the pressure and temperature changes. The combination of simple data acquisition and rapid processing at wellsite ensured data quality and enabled the option of potential remediation during the same visit to the well.\u0000 This case study from South America highlights the application of this service in a remote wellsite location with sustained casing pressure issues, the authors concluded that the contribution point was located at the Rayoso Formation and the entry point was the 9 5/8\" shoe. Liquid dropout effects during the production phase were confirmed with pressure indications from the memory gauge at the bottom of the fiber.\u0000 DFOS enabled slickline provides information that allows potential remediation during the same well visit. This case study presents a simple deployment and interpretation methodology reducing time and costs and bringing fiber technology to a mass market. Partnering with key suppliers to simplify the process, helped to make fiber a routine part of an integrated surveillance service.","PeriodicalId":303929,"journal":{"name":"Day 2 Wed, March 22, 2023","volume":"1 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-03-14","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"121615737","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":"Ceramic Sand Screens Unlock Potential in Mature Columbus Basin Offshore Fields","authors":"Wayne Hosein, Ejaz Juman, Surendr Ramcharitar, B. Gundemoni, P. Barth, R. Jackson","doi":"10.2118/212920-ms","DOIUrl":"https://doi.org/10.2118/212920-ms","url":null,"abstract":"\u0000 Ceramics have long held significance as a prime material to humans and today can be found in any industry. This paper discusses the successful application of standalone ceramic screens as an emerging technology solution for well restoration and sand control in Columbus Basin offshore fields. In well sand screens, they are proposed to significantly boost erosional limits and durability, when compared to traditional metallic screens. This hypothesis was tested in oil and high-rate gas wells in highly unconsolidated and low volume reservoirs which were previously shut-in or undeveloped for various reasons. In all cases, development through traditional rig-based sand control techniques would have been uneconomic. This paper presents the job design approach including candidate selection, screen selection, erosion testing, and deployment. Well performance post implementation is also examined.\u0000 Initial screening for up-hole recomplete candidates showed that a sand control completion was required to access reserves from the unconsolidated reservoirs. Additionally, the proposed reservoir intervals were short and resulted in high flow velocities challenging even traditional sand control techniques such as cased hole gravel packs. Applying a ceramic standalone screen as a solution was based on the building of a natural sand pack to retain the formation sand with screen slot sizing designed to minimize plugging. Various screen slot sizes, geometries and analogous cores were tested in laboratory sand retention tests to retain the largest sand particle sizes and allow a natural sand pack to develop. Interpretation of the results was often challenging due to the wide variabilities in particle size distributions inherent to the nature of the sands being tested – non-uniform, poorly sorted and high fines content.\u0000 Deployment of the screens was performed rig-less and was further complicated by aged offshore infrastructure with de-rated cranes, limited deck space and compact well bays. Bespoke solutions were developed to allow screen deployment without the use of the platform crane and straddle systems to enable downhole connection of multiple screen sections. Standalone screen designs were developed for failed sand control repairs and newly perforated sections.\u0000 Start-up of the wells was performed with a bean-up strategy allowing for a stabilized natural sand pack development. Both oil and high-rate gas wells showed similar results with sand free production from the onset with minimal plugging on most applications. This paper will discuss the importance of candidate selection to minimize same. Utilizing job data and flowing measurable parameters, the ceramic screens flow velocity performance was estimated to be between five and ten times greater than those associated with traditional metallic sand screens under the same standalone application. Further laboratory erosion work was also performed to de-risk the flow rate potential of installed ceramic screens, sign","PeriodicalId":303929,"journal":{"name":"Day 2 Wed, March 22, 2023","volume":"22 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-03-14","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"131837715","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":"For Permanent Plug and Abandon Operations, There is No Acceptable Level of Leakage. Can a Noise Tool be Used to Define No Leakage?","authors":"D. Troup","doi":"10.2118/212889-ms","DOIUrl":"https://doi.org/10.2118/212889-ms","url":null,"abstract":"\u0000 A plug and abandon (P&A) operation aims to isolate the subsurface from the surface and success is traditionally gauged by fulfilling arbitrary criteria such as a physical length of an annular barrier. Multiple examples exist where a perfectly legal barrier has leaked. This paper intends to demonstrate that a sufficiently sensitive noise tool can provide the closest measure possible to verification of \"no leakage\".\u0000 The principle that fluid moving in a turbulent fashion will emit acoustic energy is very well established and is used in many successful noise logging tools. When the fluid movement is very small, the level of noise is correspondingly small, and conventional tools may miss them. A tool optimised for low energy sensitivity was evaluated in a series of text fixtures and cemented casing sections recovered from real wells to quantify the lower levels of noise detectability. Following this, logs were recorded in previously abandoned wells, detecting minute leakage despite full compliance with guidelines.\u0000 An industry leading acoustic tool was redesigned from the sensor through to the electronics to enhance its detection range to as low as possible. The sensor to electronics design was optimised to lift the low energy response by a factor of 10, while the intrinsic baseline noise was lowered to significantly increase the dynamic range available. A field test confirmed the low energy response to be 25 decibel (dB) better than pre-modification. Controlled testing under a range of conditions for both liquid and gas leakage resulted in the detection threshold being delineated for a variety of conditions. In addition to this the examination of statistical sampling parameter revealed meaningful acoustic signatures associated with varying flow regimes at very low rates. Field validation of the tool in a previously abandoned well confirmed the low threshold of the optimised tool and an intermittent leak of extremely low rate successfully mapped.\u0000 This paper demonstrates through controlled testing and field deployment that compliance with P&A barrier condition regulations absolutely does not guarantee zero leakage, but that an optimised acoustic tool is able to detect even very tiny leaks. The judicious use of such technology during the abandonment procedure to verify a barrier is actually sealing will prevent costly returns to remediate faulty procedures.","PeriodicalId":303929,"journal":{"name":"Day 2 Wed, March 22, 2023","volume":"66 6","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-03-14","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"133009002","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":"Addressing Challenges in Setting Thru-Tubing Whipstock in UBCTD","authors":"Ali A. Almusallam, Yousef Abdulmohsen BinAmmar","doi":"10.2118/212909-ms","DOIUrl":"https://doi.org/10.2118/212909-ms","url":null,"abstract":"\u0000 In Underbalance Coiled Tubing Drilling (UBCTD), well pre-setting can be defined as the required drilling or work-over activity to set the last casing string at the top of a productive layer. This cost can be avoided by utilizing a thru-tubing casing exits (whipstock). This paper will address the challenges and enablers for direct wells’ intervention without pre-setting.\u0000 To close the gap between sending existing wells for pre-setting and direct well intervention with UBCTD, an extensive case-by-case analysis on UBCTD candidates is carried out. In essence, the approach was selected on the basis of utilizing existing technologies to their full potential or re-designing the tools to be able to fulfill the requirements. Since some candidates don't tolerate failures and allow for only one attempt, tools were always subjected to the highest level of quality checks and deployed in the best possible conditions.\u0000 Setting thru-tubing whipstocks in a typical well will require a low to medium inclination, rigid cement behind the casing and enough room below end of tubing. One of the main challenges in UBCTD is weight transfer for milling a window through the metal, especially in high inclination. Applying excessive weight on the window could agitate and dislocate the whipstock. Consequently, this could result in having stuck incidents while passing through the window during tripping. Thus, for such an application, the whipstock has been empowered with stronger slips for robust casing engagement.\u0000 In another challenge for cases with limited room below end of tubing, the window milling BHA was redesigned to be shorter. Also, close monitoring on the milling parameters was employed to ensure smoothness of the window and to avoid losing it and, indeed, losing the well. Such practice becomes standard to observe the milling parameters and benchmark them to guarantee the best window possible. This approach allows entry on wells with poor or absent cement behind the casing.\u0000 Utilizing the current wells’ assets as they are, and avoiding re-entry or mechanical pre-setting can save tremendous cost. Salvaging wells can be tricky with multiple choices and this would be always be a great opportunity with the tools and process upgraded. Thru-tubing whipstocks can now be handled in different fashions based on case-by-case applications.","PeriodicalId":303929,"journal":{"name":"Day 2 Wed, March 22, 2023","volume":"696 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-03-14","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"115119382","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":"Enhancing Coiled Tubing Offshore Operating Limit Case Study","authors":"M. Sonawane, M. Ge, B. Toleman, M. Campbell","doi":"10.2118/212874-ms","DOIUrl":"https://doi.org/10.2118/212874-ms","url":null,"abstract":"\u0000 Coiled tubing (CT) is being increasingly used in open water mode for offshore light well intervention such as subsea hydraulic pumping applications. Traditionally coiled tubing has been popular in land based intervention applications; whereas for offshore applications using a CT deployed through a riser (in-riser mode) is very common.\u0000 However more recently, light well intervention (LWI) operations with CT deployed in open water mode are gaining traction due to improved efficiencies compared to traditional intervention methods. Coiled tubing systems are an integral part of a LWI system and are used for injection and hydraulic pumping operations.\u0000 In open water mode coiled tubing pipe is susceptible to direct hydrodynamic loading from waves and currents and vessel motions. The strength response and fatigue performance of the coiled tubing pipe can severely limit operability and increase down time for these operations when compared to riser based operations.\u0000 In this paper we will present a case study where coiled tubing has been used for LWI and subsea pumping operations. The paper will highlight some of the key challenges in design and operation of open water mode CT systems for offshore applications, from a loading standpoint and will also discuss challenges arising from lack of industry standards and codes. Analysis methodology and outcomes from this study will be presented to demonstrate how the CT strength response limits operations. Multiple mitigation options that were used to enhance operability will be discussed: these include judicious use of operational parameters, field measurement based environmental data and pipe depressurization to attain feasibility in harsh environments. In addition, modeling refinements based on 3 Dimensional (3D) Finite Element Analysis (FEA) of the CT injector guides and strain based design criteria will be discussed.\u0000 The paper will include recommendations based on experience from these case studies and highlight the need for a common industry standard to better assist Operators and OEMs with future designs.","PeriodicalId":303929,"journal":{"name":"Day 2 Wed, March 22, 2023","volume":"65 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-03-14","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"121452305","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":"Pushing Coiled Tubing Design and Manufacturing Boundaries to Service 50,000-ft Mega-Reach Wells in Abu Dhabi","authors":"I. Galvan, G. Mallanao, G. McClelland, Ray Rowland, Daniel Novak","doi":"10.2118/212892-ms","DOIUrl":"https://doi.org/10.2118/212892-ms","url":null,"abstract":"\u0000 Extended-reach drilling target records in the Upper Zakum region have now reached 50,000-ft depth, surpassing manufacturing, equipment, and operational boundaries of the coiled tubing (CT) industry. However, custom-fit CT manufacturing equipment and logistical procedures are being evaluated to boost manufacturing capabilities that will allow to build multipurpose CT strings configurations with larger operating envelopes that can perform well across a variety of wellbore designs and target depths, including the recent record of 50,000-ft.\u0000 Over the past five years, highly engineered 2.375-in CT strings ranging from 31,000-ft to 43,000-ft in length have been deployed in the region, to service and maintain these complex wells trajectories over 4.5:1 MD/TVD ratios. The CT design makeups and length have progressed over time to have heavy reliance on extended reach hydraulic tractors by utilizing quench and temper materials that allowed greater diameter to wall thickness ratios (D/t), while satisfying pressure, load, and fatigue ratings. Nevertheless, the newest target depths require significant upgrades to CT manufacturing equipment, extended reach downhole tools and surface equipment.\u0000 CT has become an integral component to reduce cost and time in the region, and its utilization has increased because of the collaboration between the well operator, CT service providers, extended reach tool companies and CT manufacturers to improve its suitability, reliability, and predictability. The CT string engineering for 50,000-ft mega-reach wells required an iterative string design methodology that heavily considered the actual field reliability (actual tensile load ratings) of the CT hydraulic tractors and chemical friction reducers to determine the optimal CT lengths and wall thickness configurations. The CT manufacturing capabilities and surface equipment were maximized to optimize wellbore accessibility. A thorough evaluation of each stage of the CT manufacturing process revealed areas where equipment would reach capacity based on the CT design specifications. The resultant studies discuss comprehensive ground-up development, engineering, testing, and qualification of CT manufacturing requiring capital investments to produce the massive CT strings. The strings are 10 miles long weighing around 100 – 110 MT including the working drum. Funding for such a large-scale project is currently pending, with the operators’ demand for such strings and the projected return on investment influencing the decision.\u0000 The ability to intervene with CT is crucial to the field development strategy, and as the new wellbore designs become increasingly difficult to service, fit-for-purpose CT solutions are needed. CT manufacturing industry is engineering and developing equipment that expands the limits of CT production to bridge this gap.","PeriodicalId":303929,"journal":{"name":"Day 2 Wed, March 22, 2023","volume":"21 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-03-14","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"115619386","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":"Comparative Look at Wellbore-Rock Connection Techniques – An Integrated Perspective from Stimulation, Intervention and Laboratory Research","authors":"A. M. Khan, M. AlTammar, K. Alruwaili, Talal O. Almutary, D. Ahmed, G. Aidagulov, H. Al-Dakheel, M. Abbad","doi":"10.2118/212880-ms","DOIUrl":"https://doi.org/10.2118/212880-ms","url":null,"abstract":"\u0000 Breaking down the rock and initiating a fracture within pressure limitations is a major challenge in stimulating tight reservoirs with high tectonic stress components. Complexity increases with overbalanced mud damage and the stress cage created in the near-wellbore region during drilling. In certain formations, this results in 50% failed stages where proppant or acid were not placed. It is critical to investigate the first step in the process, which is the technique used to connect the wellbore with formation rock.\u0000 This paper presents an in-depth comparison of three primary techniques—conventional perforating, abrasive jetting with Coiled Tubing (CT), and circular notching with CT—through laboratory experiments, field cases, and, most importantly, intervention. Fracturing pressure reduction by circular notches and discrete perforation holes was compared in hydraulic fracturing laboratory experiments. These tests were conducted in a polyaxial load frame on 24×18×18 in. cement blocks, where wellbore features were precisely casted. In field case analysis, the three techniques were evaluated by comparing the injectivity index changes in offset wells in the same formations. The required intervention methods with CT and variable bottomhole assembly configurations are detailed and aligned with challenges associated with different completion types.\u0000 Hydraulic fracturing laboratory experiments were conducted at fixed confining stresses representing a general high breakdown pressure case of a horizontal openhole wellbore. The test series included the baseline case of nonintervened open hole parallel to the minimum stress, circular notch, and single and triple in-plane perforation holes. Notches and perforations were also tested in an azimuthally deviated horizontal well. Laboratory experiments confirmed the theoretically predicted superiority of notches over holes and demonstrated that notches can reduce fracture initiation pressure by up to 40%. For the field-scale evaluation, six comparison cases were built in similar reservoir and geologic conditions. A well injectivity index was calculated utilizing maximum pressures and rates achieved with different techniques. Injectivity enhancement showed up to 7X increase through abrasive jetting and circular notching over conventional perforating in casedhole and openhole wells, respectively, in wells that initially had injection. In some cases, these techniques enabled injectivity where initially there was no injection, hence yielding an infinite-scale enhancement. Finally, systematic intervention workflows were devised with different CT conveyance configurations and sequence for different completions such as abrasive jetting in cased hole, circular notching in open hole, and circular notching in open hole with packers and fracturing sleeves.\u0000 The paper presents a unique integrated comparison of three primary wellbore-rock connection techniques that will allow better engineered workflows to enhance stimulati","PeriodicalId":303929,"journal":{"name":"Day 2 Wed, March 22, 2023","volume":"3 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-03-14","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"115511657","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":"World's Deepest Single-Trip Multistage Fracturing through 2-7/8-in. 7,400-m Coiled Tubing String: Method Development and Learnings from Norway","authors":"A. Keong, Nelson Jaimes, Adlet Mussenov, H. Graterol, Bjørn Østebø, Max Sørensen, Karsten Maj, Yann Caline","doi":"10.2118/212902-ms","DOIUrl":"https://doi.org/10.2118/212902-ms","url":null,"abstract":"\u0000 The Valhall and Hod chalk fields have seen the rise of single-trip multistage fracturing (STMF) that allows stimulating two to four zones in a single day in contrast to the average of one zone every 2 to 3 days for conventional applications. Recent advancements focus on lowering operational costs while bringing wells on production faster. One way of doing this is to further improve the STMF method by the introduction of fracturing through coiled tubing (FTCT).\u0000 Conventional multistage fracturing operations use the plug-and-perforation method to complete each stage separately. With a sliding sleeve completion, coiled tubing (CT) is used to manipulate sleeves; then, proppants are pumped down the wellbore without CT in the well. Conversely, STMF uses a bottomhole assembly (BHA) with sleeve shifting tool and multiset packer for selective proppant stimulation down the CT-tubing annulus. Any underflush of proppants is cleaned by CT forward circulation. FTCT builds upon the STMF method, but proppants are pumped through CT. The underflush proppants are reverse circulated out of CT through a BHA without a check valve.\u0000 FTCT was first used in a well at 5,000-m measured depth (MD) using a 6,700-m 2 7/8-in. CT. Data from this operation were used to match the friction calculation. In the second well at 6,500-m MD, intervened with a 7,400-m-long CT, 10 zones were stimulated using FTCT, and 2 zones with conventional fracturing. FTCT only required 8.5 hours whereas conventional fracturing took 75.6 hours per zone. The underflush volume was 50% less and removed through reverse cleanout that is 4 hours faster per stage compared to STMF. In the third well at 6,700-m MD, the well was killed with 1.35-SG heavy brine due to a leak in the completion. Proppant was pumped through CT and displaced with 1.04-SG brine. An increase in pumping pressure during reverse cleanout, compounded with the difference of fluid density, led to the collapse of CT section above the BHA. The collapse created difficulties for the BHA to unset, thus creating a mechanical sticking point, and hindered the ball drop release mechanism for the BHA. Awareness of pressure limitations of CT at the thinnest section is essential to improve the reverse cleanout design since high initial forces are required to reverse circulate.\u0000 FTCT requires careful pressure analysis, especially when attempting operations in deep horizontal wells. Most standard CT cleanout simulation software lacks complete hydraulic modeling capabilities for reverse cleanout of crosslinked fluids with proppants. Data gathered from the three operations are thus important to improve the method. This study highlights associated challenges, considerations during design, operational benchmarks, and learnings from the world's longest FTCT operation in the North Sea.","PeriodicalId":303929,"journal":{"name":"Day 2 Wed, March 22, 2023","volume":"8 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-03-14","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"121991173","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":"Completion Leak Repair with Corrosion Resistant CT Velocity String","authors":"Erick Aguirre, Martin Nebiolo","doi":"10.2118/212923-ms","DOIUrl":"https://doi.org/10.2118/212923-ms","url":null,"abstract":"\u0000 An operator company in Bolivia needed a solution to a corrosion and pressure integrity problem caused by the presence of CO2 gas in the production fluids, resulting in deep tubing corrosion over certain sections of completion components with measured penetrations up to 96% of tubing's wall thickness.\u0000 Based on the corrosion's profiles, the intervention objective was to install a 16% chrome corrosion-resistant velocity string inside the production string to produce the well avoiding the exposure of those highly corroded components from the tubing.\u0000 The repair intervention concept was to set a hydraulic packer over the lower completion below the most compromised section of the production string and connect the isolation packer with 2\" OD 16%Cr coiled tubing pipe up to the surface, hanging the string on the wellhead.\u0000 The velocity string installation should be performed in a single run with the well in live condition, avoiding the need to kill the well during the intervention.\u0000 The well's lower completion was composed of TPC-fired guns, a combination of 2-7/8\" 6.4# and 3-1/2\" 9.2# N80 tubing, and a 7\" 23-29# packer. The upper completion was basically an arrangement of 3-1/2\" 9.2# N80 tubing with a retrievable SSSV set at 107 m, a sliding sleeve device, and a seal unit sub to connect the upper to the lower completion.","PeriodicalId":303929,"journal":{"name":"Day 2 Wed, March 22, 2023","volume":"52 11-12","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-03-14","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"120927212","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}