Day 1 Tue, March 19, 2024最新文献

{"title":"Successful Intervention in U and W Shaped Wells in Eagleford Basin – A Case History","authors":"V. Unnikrishnan, Guruswami Navin","doi":"10.2118/218324-ms","DOIUrl":"https://doi.org/10.2118/218324-ms","url":null,"abstract":"\u0000 An operator in Eagleford basin, decided to optimize production, by minimizing drilling efforts. This led to two wells drilled in a distinctive \"U\" and \"W\" shape, which would result in equivalent treatable laterals lengths in a lease with tight boundaries.\u0000 Plug and Perf stimulation technique was carried out in these two wells and post stimulation cleanout had to be performed. Intervention in these unique shaped wells need to be planned with the proper Bottomhole Assembly (BHA) configurations to ensure that that no misrun occurs. Though these wells are drilled successfully with the rig, since there is rotational and axial capabilities, it does not necessarily mean that a Coiled Tubing (CT) intervention would be less challenging. The frac plugs for isolation were set not just in the straight sections of the well but also in some part of the bend as well.\u0000 This paper will highlight the operational planning that was involved prior to performing intervention in these two wells. A complete coiled tubing modelling along with bending analysis on the milling BHA was performed to ensure that the downhole assembly does not undergo any failures due to well profile.\u0000 A total of 32 frac plugs in \"W\" shaped well and 38 frac plugs in \"U\" shaped well were successfully cleaned/milled out. The two wells were completed with 5 ½\", 23 lb/ft casing with a Measured Depth (MD) of 17,846 ft and 21,064 ft respectively. A 4 ½\" Tricone bit along with a 3 1/8\" workover motor and extended reach tool was utilized for the operation.\u0000 Due to the pre-planning performed during the BHA selection, it eliminated a second run in each well, thereby allowing the operator to save around $150,000 on intervention costs. This paper will act as a guideline for any future intervention planned in wells with unique geometry.","PeriodicalId":517630,"journal":{"name":"Day 1 Tue, March 19, 2024","volume":"229 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-03-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140284784","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":"New Coiled Tubing Fatigue Management System with Real-Time Vessel Data: Step-Change to Cost and Reliability in Open-Water Interventions","authors":"S. H. Fonseca, C. Bridge, Z. Liu, W. Brouwer, N. Vodnikov, P. Spesivtsev","doi":"10.2118/218297-ms","DOIUrl":"https://doi.org/10.2118/218297-ms","url":null,"abstract":"\u0000 Early attempts to monitor coiled tubing (CT) fatigue in open-water interventions relied on basic statistical methods with a constant damage rate and broad generalizations of sea conditions. The new CT fatigue management system (FMS) comprises hardware and software that improve fatigue tracking. It tracks high-cycle fatigue (HCF) and low-cycle fatigue (LCF) simultaneously and in real time, elevating the accuracy, immediacy, and reliability of CT fatigue monitoring in open-water interventions.\u0000 The hardware monitors vessel pitch and roll in real time and relays the data to an acquisition system where they are combined with CT depth and circulating pressure. The new acquisition software consumes these data as well as a CT string fatigue life database and geometry and positions of the CT string, work drum, and payout sheave. LCF and HCF are accurately modeled, and the string fatigue life is updated in real time. That information allows the operation to strategically cycle the CT pipe to manage fatigue more efficiently and extend the time before a trim is necessary.\u0000 The traditional statistical method recorded a cumulative CT fatigue damage of 16% over a 14-hour job. In that same timeframe, the CT FMS measured a cumulative fatigue of 3.8%. Since the CT FMS updates damage rate continuously in response to vessel dynamics and uses a nonlinear methodology to combine HCF and LCF, it reduces inaccuracy and eliminates unnecessary safety factors associated with the statistical method. By improving precision and reliability, the real-time CT FMS safely extended the useful life of CT pipes by 75%.\u0000 The CT FMS also improves operational integrity by introducing alarm threshold settings and custom material parameters. Alarms are raised reflecting fatigue life growth, tubing payout, and changes to sea conditions. This provides the operator with real-time, actionable data to ensure a more even distribution of the fatigue along the CT. Besides extending useful life, this reduces the risk of CT failure, which can lead to costly downtime, reputational damage, and production losses. The string's operating limits are more accurately monitored, which extends the capacity of the CT into harsher environments, longer operations, and riserless interventions of wider workscope. The CT FMS automates workflows that previously required a dedicated technician, reducing crew size on board.\u0000 The introduction of CT in open-water interventions brought with it the risk of CT failure, which is inherent to any operation that handles CT pipe. This industry first, real-time CT FMS combines HCF and LCF monitoring and is a step change from the traditional methods to address these CT-related risks. Furthermore, the CT FMS elevates overall operational integrity, increases operational efficiency, and extends the operational envelope and application of CT in open-water interventions.","PeriodicalId":517630,"journal":{"name":"Day 1 Tue, March 19, 2024","volume":"21 13","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-03-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140285024","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":"Autonomous Restriction Navigation Through Wellbore in Wireline and Slickline Operations","authors":"S. DiPasquale, J. Meirkhan","doi":"10.2118/218360-ms","DOIUrl":"https://doi.org/10.2118/218360-ms","url":null,"abstract":"\u0000 A novel technique of autonomous restriction navigation that significantly increases efficiency and safety is presented. New algorithms orchestrate the automated winch control system to prevent over-speeding when passing through restrictions, which diminishes incidents of unintentional pull-off and toolstring damage caused by entering wellbore obstructions at high speed. Every pull-off incident would significantly reduce the production of the well because the toolstring and cable must be recovered. This new dynamic speed scheduling system optimizes restriction navigation, showing an order of magnitude improvement over industry-standard human-driven winch operation.\u0000 A new forward-looking algorithm analyzes restrictions in the direction of conveyance to predict the time and distance to future encounters with restrictions. It uses toolstring length, current depth, cable speed, and the winch controller's deceleration rate to maintain the maximum allowed speed until the exact moment deceleration must occur for the toolstring to enter a restriction at the proper speed. Finally, it maintains a higher winch gear even at low speeds when passing through restrictions except in those situations when extra-low speed is required.\u0000 The new technique has been extensively tested in intervention campaigns in the North Sea, allowing comparison against manual operation and previous-generation automated conveyance. Winch operators would often fail to slow down at restrictions or would slow down too early or too late. Previous-generation automation, due to its lack of forward-looking algorithms, would not decelerate until the toolstring encountered the restriction and could accelerate with the toolstring still in the restriction. To prevent this, the wellsite supervisor would need to spend extra time manually calculating top and bottom restriction depths for each conveyance direction, often leading to overestimation or miscalculation of the restriction declarations. In case studies from field trials, the new technique consistently uses the correct restriction speed for the entire toolstring length. Users only need to declare wellbore speed restrictions as they appear on the well diagram. In manual operation, an experienced user will retain high winch gear through a restriction, whereas previous automation would stop and change gear. The new technique digitalizes winch driving competency by incorporating high-gear retention. After a year of field trials with zero incidents, several case studies with multiple restrictions in the well confirm the greater efficiency of the new navigation technique over previous generations.\u0000 The developed comprehensive automated speed-control logic and restriction navigation technique maximizes conveyance speed while eliminating risk and costly errors. Its intrinsic value increases when operations are performed in highly sophisticated well completions and tortuous wells, which are becoming more common.","PeriodicalId":517630,"journal":{"name":"Day 1 Tue, March 19, 2024","volume":"82 11","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-03-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140395461","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":"Intervention Synergy Improving Production Enhancement Efficiency for Remote Offshore Well Intervention Operation","authors":"M. M. M. Hanafi, N. Ismail, I. Anoar, V. Ong, S. Hamzah, K. K. Anuar, K. Singh, C. Cavalleri, N. Yong, M. F. I. Zailani, P. Ramondenc, M. Hofacker","doi":"10.2118/218364-ms","DOIUrl":"https://doi.org/10.2118/218364-ms","url":null,"abstract":"\u0000 Pulsed neutron spectroscopy is commonly used in the Malay Basin for cased hole formation evaluation to assess development potential and reserve opportunities. Sandstone formations in many fields have caused complications due to sand deposition in mature wells, making logging operations difficult. This work explores the enhancement of operational efficiency on remote offshore platforms by utilizing coiled tubing to convey pulsed neutron evaluation, thereby addressing the demands associated with facilitating more-effective well access operation and formation evaluation assessment.\u0000 Electric coiled tubing (e-coil) systems have expanded evaluation logging applications; however, lifting heavy e-coil reels onto offshore sites, especially remote platforms, remains challenging. Battery-powered tools transmitted via fiber optic–enabled real-time coiled tubing (FOERCT), which although widely used in the past decade, have limitations such as restricted power supply and logging time. To overcome these challenges, our work introduces contemporary hybrid cables, similar in size and weight to traditional fiber optics but with high-power transmission capabilities called monocable-enabled real-time coiled tubing (MERCT) This innovation provides an efficient means of tool conveyance in offshore coiled tubing logging and enables broader remote platform operations.\u0000 The application introduced in this work harnesses hydraulic capabilities to supplement sand cleanout procedures preceding cased hole evaluation. Traditionally, these operations involve the deployment of two separate services, which increases the operational footprint and extends the time required for completion. The application of MERCT has effectively reduced the total bottomhole assembly length by eliminating battery subs, consequently obviating the necessity for offshore pressure deployment. This strategic modification significantly bolsters overall operational safety and has yielded a 83%-time savings compared to a traditional deployment method. The single-service deployment and simplification represents a twofold enhancement in efficiency when compared to the previously utilized pulsed neutron logging method.\u0000 This advancement enables the development of lightweight coiled tubing logging solutions that are well suited for the challenges posed by offshore environments, including surface and topside constraints. The synergy and plug-and-play setup offered by this innovative approach reduce equipment footprint and simplify the overall execution of operations. This leads to safer deployments while maintaining equivalent levels of effectiveness and efficiency.","PeriodicalId":517630,"journal":{"name":"Day 1 Tue, March 19, 2024","volume":"1 8","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-03-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140395970","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":"Record-Setting Workover Saves Extended Marcellus Lateral","authors":"C. W. Lesnick, J. A. Kirk, E. Luckey, D. J. McClanahan, N. Saltel, R. Lian, S. Lim","doi":"10.2118/218322-ms","DOIUrl":"https://doi.org/10.2118/218322-ms","url":null,"abstract":"\u0000 An erroneous production string cement job often leaves an operator with a tough decision to make; the technical and economic feasibility of a successful intervention must be considered and compared to sidetracking or, at worst, abandonment. CNX Resources, collaborating with Thru Tubing Solutions (TTS) and SLB, was able to develop and execute a unique (and record-setting) workover to save a 19,381 ft lateral in the Marcellus shale.\u0000 An incorrect mixture of cement slurry left CNX Resources with 20,489 ft (of 27,510 ft MD) of 51/2-in 23ppf P110 production casing cemented off. A cement lead was pumped without issue. However, while pumping the cement tail and displacement, pressure gradually increased until it reached the pressure limitations of the rig equipment, resulting in a premature shut down. Utilizing a combination of traditional drilling and completions philosophy, a series of past lessons learned, and new-age technology, CNX, TTS, & SLB managed to clear the casing of nearly 20,500 ft of cement, perf and squeeze cement 6,019 ft into the lateral, and set the deepest (from KOP on US Land) casing patch ever set by SLB. This successful, more sustainable implementation offered upwards of 17% savings compared to the alternative.\u0000 Bottom Hole Assembly (BHA) selection, solids control, and fluid system management played a vital role in the cement drillout portion of the workover. Rates of penetration of up to 85 ft/hr were achieved and maintained throughout the job. In total, it took 19 days (approximately 17.5 days in hole) to drill the 20,489 ft of cement. Perforation depths were carefully determined at 14,130 ft via ultrasonic imaging and cement bond logging. Circulation was established and cement was squeezed to exceed state regulatory requirements. Due to the unique circumstance, a custom, fit-for-purpose expandable casing patch was designed and successfully installed to isolate the squeeze perforations while returning the casing to mechanical properties fit for fracturing operations. A casing integrity test to 10,500 psi was achieved post-installation of the casing patch.\u0000 This case study features the deepest 20,000+ ft drillout of cement for TTS (27,510 ft MD), a detailed look into a complicated extended lateral perforation and squeeze operation, as well as the deepest set (from KOP) casing patch for SLB on US Land (14,154 ft MD).","PeriodicalId":517630,"journal":{"name":"Day 1 Tue, March 19, 2024","volume":"31 6","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-03-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140284671","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 Initial Trials of Thermally Processed 95-Ksi Coiled Tubing","authors":"K. Elliott, N. Molero, H. Srinivasan, E. Arriaga, F. Al Qatari, M. Alsheheri","doi":"10.2118/218332-ms","DOIUrl":"https://doi.org/10.2118/218332-ms","url":null,"abstract":"\u0000 With a significant number of exploration and production programs pushing intervention boundaries, 95-ksi grade quenched and tempered (Q&T) coiled tubing (CT) has begun to be utilized in high-profile sour environments. This paper details the development of the newest 95-ksi grade of (Q&T) CT, specifically designed for increased fatigue life of existing products with performance in sour environments.\u0000 The authorship team is comprised of a multidisciplinary group within the CT business, including manufacturers, service companies, and the operator. Each stakeholder has different expectations regarding this development, but the main outputs of the program need to be (1) a repeatably manufacturable grade with (2) improved fatigue life and (3) resistance to catastrophic failure due to exposure to sour environments. This study describes the design control process that accounts for the concerns of all stakeholders.\u0000 The present review covers the initial development activity of identifying an alloy to make 95-ksi grade tubing. The process examined improvements to low cycle fatigue life and sour performance over 90-grade non-Q&T CT. Laboratory test results of 95-grade Q&T tubing are presented in this work. The low cycle fatigue testing comprises tests both with and without sour exposure. The testing without sour exposure is useful for providing comparative information to show how this grade can have an increased service life compared to 90-grade conventionally produced CT. The testing with sour exposure can be compared to the testing without exposure to show that low cycle fatigue life can be successfully modeled despite even in sour environments. The testing presents an examination of bias welds testing in low cycle fatigue as bias welds are considered a sensitive location for CT failure.\u0000 In the present decade, CT intervention requirements combining deeper extended reach horizontal sections and high-pressure cycling in sour environments are becoming more frequent, driving operators, service companies, and manufacturers to jointly pursue technologies and engineered solutions for safe and effective CT work. The study presented here paves the road for implementation of a value Q&T offering for such challenging environment.","PeriodicalId":517630,"journal":{"name":"Day 1 Tue, March 19, 2024","volume":"116 2","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-03-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140395122","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":"Identification and In-Depth Investigation of External Casing Corrosion in an Exploration Well Prior to Field Development","authors":"Selma Chikh, Amit Govil","doi":"10.2118/218314-ms","DOIUrl":"https://doi.org/10.2118/218314-ms","url":null,"abstract":"\u0000 External corrosion in new casings on the Norwegian Continental Shelf (NCS) is rare. An exception to this was discovered when reentering an exploration well that had been temporarily plugged and abandoned for 2 years. A pressure test showed the 9 5/8-in. liner was leaking. A multidisciplinary investigation was done to find the precise depth of the leak and its root cause. The proper logging technologies were carefully selected for this purpose. Due to the relatively low leak rate, it was suspected that holes in the liner were small. To locate these holes, noise, temperature, ultrasonic high-resolution corrosion, and multifinger caliper logs were recorded. One of the hypotheses for the root cause of the leak was corrosion resulting from the corrosivity of the formation fluid combined with crossflow between the depleted formations. To test this, a water-flow log was run to find any potential crossflow behind the liner. Modular dynamic tester sampling was performed to extract formation water samples from the interval for chemical composition analysis.\u0000 The high-resolution corrosion data obtained from azimuthal and ultrasonic measurements showed the presence of multiple depths of external casing corrosion. These depths coincided with sections of the liner that were uncemented and therefore directly exposed to surrounding formation water. Analysis of the temperature data and the water-flow log during static well conditions enabled finding the precise location of the leak along with the detection of upwards water (or oxygen) movement behind the casing.\u0000 Additionally, a detailed examination of water samples taken from the 12 ¼-in. section of the sidetrack well revealed that the formation water had a low pH and a high CO2 content, which were considered significant for the context of the NCS. Based on these observations, the corrosion rate was estimated at about 4 mm/year. This conclusion relied on the confirmation of the formation water flow from the depleted formations.\u0000 This work helped to find the true root cause, which was found to be related to the selected well design, where the \"overburden\" was in communication with the reservoir section of a nearby field. As a preventive measure to avoid the recurrence of such issues in future similar wells in the NCS, the well design was changed during early field development.","PeriodicalId":517630,"journal":{"name":"Day 1 Tue, March 19, 2024","volume":"113 4","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-03-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140395127","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":"First Rigless Intervention in Bonga Deepwater","authors":"Augustine Okosun, I. Ugbor, Tobechukwu Ezeokafor","doi":"10.2118/218347-ms","DOIUrl":"https://doi.org/10.2118/218347-ms","url":null,"abstract":"\u0000 In the Bonga Deepwater project, while exploring subsea well intervention and stimulation campaign opportunity, the subsea Rigless intervention strategy, which has been in the SNEPCo team's technology maturation funnel for some years, re-surfaced. In the first quarter of 2017, the Shell Nigeria Exploration and Production Company (SNEPCo) Deepwater team led the industry to deploy the first ever riser-less technology for well intervention operations in Nigeria. The main objective was to prove the rigless intervention concept and capability in the Bonga Deepwater project. The team focused on improving production enhancement and sustaining well integrity on the Bonga Main Project by minimizing well-intervention cost without compromising process safety, achieving incident free operation, and delivered the project at 50% less than what this scope of work would have cost using a Mobile Offshore Drilling Unit (MODU). Additionally, the acid stimulations added 9,200 barrels of crude oil per day to the company's production.\u0000 As with every new project, several challenges were encountered, and new ideas were developed. The team acquired a lot of learning from the planning phase, vessel mobilization to execution. These learnings have been integrated into the team's standard operating procedure and shared with other stakeholders. Additionally, the knowledge and learnings gained from this project have been harnessed in collaboration with the service provider and Original Equipment manufacturer (OEM) to modify and upgrade an existing in-house well intervention well control package (EDP/LRP) for riserless intervention access in the Bonga Deepwater project.","PeriodicalId":517630,"journal":{"name":"Day 1 Tue, March 19, 2024","volume":"66 2","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-03-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140395583","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Electrical Coiled Tubing N2 Lifting Enabled Successful HT Production Logging and WSO Campaign","authors":"Amad Aklefa, Muamer Emhemed, Ayoub Sherik, Mohamed Ben Abdalla, Siraj Sadeg","doi":"10.2118/218298-ms","DOIUrl":"https://doi.org/10.2118/218298-ms","url":null,"abstract":"\u0000 Many deep high-temperature (HT) wells of Bu Attifel field, Libya, have died in the past years due to increasing water cut. The lack of artificial lift, issues in the water injection system, and unavailability of workover rigs led to significant oil production loss. Nitrogen (N2) kickoff was attempted several times without success, indicating the need for water shutoff (WSO) procedures. Moreover, production logging (PL) was not feasible at the time as wells were dead, and casedhole saturation logs were proven to be unreliable due to static crossflow between layers (presence of thief zones where reservoir fluid is produced by a high-pressure layer and taken by a lower-pressure layer while the well in shut-in/static condition) and reinvasion phenomena. Due to these challenges, it was suggested to use N2 lifting to assist PL in dynamic condition to determine the source of water for shutoff.\u0000 The objective of this project was to kick off the wells with N2 using electrical coiled tubing (e-coil) with PL tools attached to the e-coil bottomhole assembly. Once the well was restored to a predefined water cut, the logging was performed at different N2 injection rates. This was done regardless of well stabilization (i.e., to have downhole and surface parameters stabilized within 0.5% as per the operator's standard) because the presence of N2 along the entire production string affects the flow regime and does not allow the well to fully stabilize as per the operator's standard. Then, the logging was performed again during the transition period when the N2 pump was switched off. This step was important to prove that injecting N2 near PL tools did not affect data quality. A multiphase meter was also available to monitor cleaning up during N2 kickoff. A high-pressure/high-temperature (HP/HT) tool was used because the bottomhole temperature was over 315°F. Special kickoff and logging steps were taken to insure reliability of measurements and safety of tools and operation.\u0000 Four wells were logged successfully with HP/HT PL while N2 lifting. Good-quality data were collected, which aided successful water shutoff decisions adding a production gain of more than 4,000 B/D. In the first well, three flowing surveys were performed. The first survey was at high N2 injection rate to accelerate the cleanup and achieve higher flow rates for better PL data. The second was at the minimum N2 injection rate to acquire most reliable data, and the third survey was taken when the N2 pump was switched off to verify that the N2 injection did not affect PL data quality. Comparisons suggest that data were repeating and consistent, especially the downpasses as the tool was moving in the opposite direction to the flow of N2. Special logging procedures, accurate job planning such as for N2 quantities, and logging tool design, among other factors, allowed acquisition of three PL surveys safely in a single run in 9 days after a long cleanup in high-temperature condition.\u0000 This project desc","PeriodicalId":517630,"journal":{"name":"Day 1 Tue, March 19, 2024","volume":"80 3","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-03-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140395762","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":"Digital Solution for Coiled Tubing Pipe Pull Test Automation and Placement Optimization","authors":"S. H. Fonseca, B. Armstrong, L. Fossati, W. Brouwer","doi":"10.2118/218301-ms","DOIUrl":"https://doi.org/10.2118/218301-ms","url":null,"abstract":"\u0000 A new coiled tubing (CT) pipe pull test placement optimizer and automation solution is developed and integrated into an autonomous CT unit. This method provides consistency in strategic and automated pull test placement to extend the life of the pipe and consequently reduce total cost of ownership and greenhouse (GHG) emissions. A case study in the North Sea showcases the solution in real-time operations and simulated cases demonstrate the potential impact.\u0000 Pull tests are a common means of mitigating stuck pipe in CT operations. Traditionally, they are executed at fixed intervals while the CT is run in hole. Risks associated with this rote approach include repeated pull tests at an already fatigued section, which accelerates fatigue of the CT pipe, and pull tests executed in wellbore sections with completion restrictions. The new solution addresses those risks by systematically combining the pipe's fatigue profile, weld points, and completion information to strategically adjust the pull test schedule, reducing the impact of those tests on pipe fatigue and the risks associated with drifting across downhole completion jewelry.\u0000 The pull test automation and optimization are integrated into an automation-enabled CT unit in the North Sea. The automation eliminates the human factor and the risk of repeating pull tests at the same locations on each run; it also minimizes pull tests at the weakest points, which include the weld points where cycle fatigue is accelerated, and it eliminates pull tests at restrictions, reducing the risk of abrading or damaging completion jewelry. Finally, besides standardizing pull test placement, the combination of the pull test optimization and automation frees the CT operator to focus on other critical elements of the operation such as running and monitoring the unit and downhole tools, managing the crew, and engaging the customer representative.\u0000 The performance of the pull test automation and optimization solution is tested in a simulated environment to quantify the impact on the CT pipe from new (0% fatigue) to end of life (EOL, 100% fatigue). The simulation uses a CT pipe with 1 3/4-in. outer diameter (OD) and a mission profile from a previous intervention campaign. CT of this OD is common in CT operations worldwide, making it an interesting test subject for the analysis. As compared to the traditional pull test approach, the optimized pull test placement redistributes the fatigue to less-fatigued sections of the pipe and extends the useful life of the pipe from 137 runs to EOL to 176 runs to EOL. Extending the useful life by 28% is equivalent to reducing the pipe's run-on-run cost and GHG manufacturing emission contributions by 22%.","PeriodicalId":517630,"journal":{"name":"Day 1 Tue, March 19, 2024","volume":"69 7","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-03-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140285042","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}