As part of offshore workover operations in the Danish North Sea to safeguard the future of producing oil wells, older completions are being changed to new 5 in Glass Reinforced Epoxy (GRE) lined completions using workover rigs. During one of the several phases of this operation in one of these wells, slickline (SL) was being used to remove scale using a bailer when the Bottom Hole Assembly (BHA) got stuck and lost in the well. The wire was pulled to 70% of its breaking strength of 2150 lb with no indication of the SL jar firing. The fish left in the wellbore was a 37 ft long tool consisting of a roller stem, spang jar, and a 3 in pump bailer assembly. The top fishing point was a 1.75 in fish neck rope socket, with the top of the fish at 7219 ft. This horizontal oil producer was first drilled and completed in 2001 using a jack-up rig over a platform. The job objective for Coiled Tubing (CT) was to return the well to the original workover plan by safely fishing the lost BHA while considering the following conditions: The fishing tool combined with the fish would be too long for the available lubricator length.The hydrostatic pressure of the existing well fluid would be insufficient to overcome the reservoir pressure.A pressure-tested barrier is present between the casing and tubing annulus.The deep-set plug installed in the tubing at ~7350 ft has been pressure and inflow tested to 2900 psi.
{"title":"Complex Coiled Tubing Fishing Operation of Slickline Tools with No Kill Fluid in the Well in Danish North Sea","authors":"K. Kaul, A. Jari, T. Blanckaert","doi":"10.2118/218368-ms","DOIUrl":"https://doi.org/10.2118/218368-ms","url":null,"abstract":"As part of offshore workover operations in the Danish North Sea to safeguard the future of producing oil wells, older completions are being changed to new 5 in Glass Reinforced Epoxy (GRE) lined completions using workover rigs. During one of the several phases of this operation in one of these wells, slickline (SL) was being used to remove scale using a bailer when the Bottom Hole Assembly (BHA) got stuck and lost in the well. The wire was pulled to 70% of its breaking strength of 2150 lb with no indication of the SL jar firing. The fish left in the wellbore was a 37 ft long tool consisting of a roller stem, spang jar, and a 3 in pump bailer assembly. The top fishing point was a 1.75 in fish neck rope socket, with the top of the fish at 7219 ft.\u0000 This horizontal oil producer was first drilled and completed in 2001 using a jack-up rig over a platform.\u0000 The job objective for Coiled Tubing (CT) was to return the well to the original workover plan by safely fishing the lost BHA while considering the following conditions: The fishing tool combined with the fish would be too long for the available lubricator length.The hydrostatic pressure of the existing well fluid would be insufficient to overcome the reservoir pressure.A pressure-tested barrier is present between the casing and tubing annulus.The deep-set plug installed in the tubing at ~7350 ft has been pressure and inflow tested to 2900 psi.","PeriodicalId":517791,"journal":{"name":"Day 2 Wed, March 20, 2024","volume":"64 3","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-03-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140394811","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}
Currently, jointed pipe completions on live wells are performed by either a workover rig with a rig assist snubbing jack or a stand-alone snubbing jack. These technologies require extensive training and operator input to convey tubing in and out of the wellbore. Conventional snubbing jacks run the risk of losing control of the string when they are transferring load between travelling and stationary slips. The main objective of the Jointed Pipe Injector Technology is to provide a safer alternative by reducing operator input and reducing the risk of losing control of the string while reducing the time it takes to move tubular strings in and out of the wellbore under pressure. Applying a jointed pipe injector into the well completions package where a typical jack would function removes the transfer of load because it maintains constant grip on the tubing, much like a coiled tubing injector. By integrating additional sensors into this package make-up and break-out procedures may be carried out remotely, further reducing operator intervention for remedial operations. Through the recent deployment of a rig-assist jointed pipe injector in the DJ Basin, the oilfield service companies have been able to reduce operator training time from months to weeks. Operator input has been reduced by over 94% compared to a conventional rig assist snubbing unit. Tubulars can be tripped in or out of the well at twice the speed of the conventional rig assist jack. The main injector control has been located remotely, reducing the number of personnel at risk on the work floor by 33%. The deployment of the jointed pipe injector in well completion applications leads to levels of automation, control, and mechanization typically seen in modern drilling packages.
目前，现场油井的接合管完井作业是由带有钻机辅助挤压千斤顶的修井钻机或独立挤压千斤顶完成的。这些技术需要大量的培训和操作人员的投入，才能将油管送入和送出井筒。传统的缓冲式千斤顶在移动和静止滑块之间传递载荷时，有可能失去对管串的控制。联合管道注入器技术的主要目标是提供一种更安全的替代方案，减少操作人员的投入，降低对管串失去控制的风险，同时缩短在压力下将油管串移入和移出井筒所需的时间。 在一般千斤顶起作用的完井装置中应用合股管喷射器，可以消除负载转移，因为它能保持对油管的持续抓紧，这一点与盘管喷射器非常相似。通过将额外的传感器集成到这套设备中，可以远程执行补油和破井程序，进一步减少了操作员对补救作业的干预。 通过最近在 DJ 盆地部署的钻机辅助连接管注入器，油田服务公司能够将操作员培训时间从数月缩短到数周。与传统的钻机辅助套管注入装置相比，操作人员的投入减少了 94% 以上。油管进出井的速度是传统钻机辅助千斤顶的两倍。主喷射器控制装置位于远程，使工作现场面临危险的人员数量减少了 33%。 在完井应用中部署连接管注入器，可实现现代钻井成套设备中常见的自动化、控制和机械化水平。
{"title":"Improving Well Completion Efficiency Though the Implementation of Jointed Pipe Injector Technology","authors":"A. Richard, H. Miller, J. Herrmann","doi":"10.2118/218370-ms","DOIUrl":"https://doi.org/10.2118/218370-ms","url":null,"abstract":"\u0000 \u0000 \u0000 Currently, jointed pipe completions on live wells are performed by either a workover rig with a rig assist snubbing jack or a stand-alone snubbing jack. These technologies require extensive training and operator input to convey tubing in and out of the wellbore. Conventional snubbing jacks run the risk of losing control of the string when they are transferring load between travelling and stationary slips. The main objective of the Jointed Pipe Injector Technology is to provide a safer alternative by reducing operator input and reducing the risk of losing control of the string while reducing the time it takes to move tubular strings in and out of the wellbore under pressure.\u0000 \u0000 \u0000 \u0000 Applying a jointed pipe injector into the well completions package where a typical jack would function removes the transfer of load because it maintains constant grip on the tubing, much like a coiled tubing injector. By integrating additional sensors into this package make-up and break-out procedures may be carried out remotely, further reducing operator intervention for remedial operations.\u0000 \u0000 \u0000 \u0000 Through the recent deployment of a rig-assist jointed pipe injector in the DJ Basin, the oilfield service companies have been able to reduce operator training time from months to weeks. Operator input has been reduced by over 94% compared to a conventional rig assist snubbing unit. Tubulars can be tripped in or out of the well at twice the speed of the conventional rig assist jack. The main injector control has been located remotely, reducing the number of personnel at risk on the work floor by 33%.\u0000 \u0000 \u0000 \u0000 The deployment of the jointed pipe injector in well completion applications leads to levels of automation, control, and mechanization typically seen in modern drilling packages.\u0000","PeriodicalId":517791,"journal":{"name":"Day 2 Wed, March 20, 2024","volume":"32 2","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-03-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140395440","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}
Raniganj coal bed methane (CBM) field in India has over three hundred wells producing gas since 2010. Over time due to extensive dewatering, reservoir pressures have dropped to sub-hydrostatic levels, with some wells having water levels as low as 500m below the surface (~0.3 psi/ft gradient). Due to continuous production, the sand influx is ubiquitous in these moderately deviated wells requiring efficient well cleanout methodologies to continue production from old wells which have been shut due to sand ingress into the wellbore. This paper illustrates a detailed case study of effective well cleanout using Foam Assisted Coiled Tubing Cleanout. This methodology helped established standard practices across the entire field for foam cleanouts in old shut-in wells, helping in resuming gas production and avoiding expensive infill well drilling. Conventional two-phase nitrified cleanouts are sub-optimal due to very low bottom hole pressure (BHP) which requires higher nitrogen (N2) pumping rates and still had insufficient annular velocities considering 1.75-in. diameter coiled tubing (CT). Also, this poses a greater risk of the CT becoming stuck in the event of sudden lost returns. Hence, to establish circulation, all the existing thief zones need to be plugged. Using conventional lost circulation materials like calcium carbonates was not feasible due to the uncertain and expensive post-job clean-up required to restore zone permeability. Hence foam was selected for temporary zone plugging which can restore zone permeability automatically once foam disintegrates as per its half-life. Various foam recipes were tested to achieve the desired foam life, as it was imperative that it exceeded job treatment time. Also, localized work instructions were developed as per coal seam behavior, initial frac treatment pressures, and the production history of the well. These work instructions were then later developed into a standard operating practice (SOP) after achieving successful well cleanouts in a few initial pilot wells. In these 5.5-in. monobore completion wells, effective zonal isolation was required to sustain the higher flow velocities required for cleanouts. This was ensured by several CT simulation iterations aiming for foam quality of at least 75%. In absence of downhole pressure data, BHP was calculated from frac bottom hole treating pressures and ISIP. Also, the volumes of the foaming agent were optimized, and benchmarks were set for when to stop pumping the foaming agent and start taking pre-calculated sand bites. Considering that significant amounts of sand were to be cleaned out, it was important to calculate bite size, simulate the solids transport and maximum additional pressure head created during cleanouts. This paper presents a detailed case study of conducting Foam Cleanouts using Coiled Tubing in CBM wells having ultra-low BOTTOM HOLEP and big completion size of 5.5-in. The paper also describes in-depth procedures, lessons learned, and CT
{"title":"Challenging Foam Sand Cleanout Operation in Ultra-Low Reservoir Pressure Wells Resumes Production in a CBM Field","authors":"S. Craig, A. Gupta, B. Kumar","doi":"10.2118/218311-ms","DOIUrl":"https://doi.org/10.2118/218311-ms","url":null,"abstract":"\u0000 Raniganj coal bed methane (CBM) field in India has over three hundred wells producing gas since 2010. Over time due to extensive dewatering, reservoir pressures have dropped to sub-hydrostatic levels, with some wells having water levels as low as 500m below the surface (~0.3 psi/ft gradient). Due to continuous production, the sand influx is ubiquitous in these moderately deviated wells requiring efficient well cleanout methodologies to continue production from old wells which have been shut due to sand ingress into the wellbore. This paper illustrates a detailed case study of effective well cleanout using Foam Assisted Coiled Tubing Cleanout. This methodology helped established standard practices across the entire field for foam cleanouts in old shut-in wells, helping in resuming gas production and avoiding expensive infill well drilling.\u0000 Conventional two-phase nitrified cleanouts are sub-optimal due to very low bottom hole pressure (BHP) which requires higher nitrogen (N2) pumping rates and still had insufficient annular velocities considering 1.75-in. diameter coiled tubing (CT). Also, this poses a greater risk of the CT becoming stuck in the event of sudden lost returns. Hence, to establish circulation, all the existing thief zones need to be plugged. Using conventional lost circulation materials like calcium carbonates was not feasible due to the uncertain and expensive post-job clean-up required to restore zone permeability. Hence foam was selected for temporary zone plugging which can restore zone permeability automatically once foam disintegrates as per its half-life. Various foam recipes were tested to achieve the desired foam life, as it was imperative that it exceeded job treatment time. Also, localized work instructions were developed as per coal seam behavior, initial frac treatment pressures, and the production history of the well. These work instructions were then later developed into a standard operating practice (SOP) after achieving successful well cleanouts in a few initial pilot wells.\u0000 In these 5.5-in. monobore completion wells, effective zonal isolation was required to sustain the higher flow velocities required for cleanouts. This was ensured by several CT simulation iterations aiming for foam quality of at least 75%. In absence of downhole pressure data, BHP was calculated from frac bottom hole treating pressures and ISIP. Also, the volumes of the foaming agent were optimized, and benchmarks were set for when to stop pumping the foaming agent and start taking pre-calculated sand bites. Considering that significant amounts of sand were to be cleaned out, it was important to calculate bite size, simulate the solids transport and maximum additional pressure head created during cleanouts.\u0000 This paper presents a detailed case study of conducting Foam Cleanouts using Coiled Tubing in CBM wells having ultra-low BOTTOM HOLEP and big completion size of 5.5-in. The paper also describes in-depth procedures, lessons learned, and CT ","PeriodicalId":517791,"journal":{"name":"Day 2 Wed, March 20, 2024","volume":"2 4","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-03-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140395963","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}
Johnny Bardsen, Bjørn Engvald Staveland Nilsen, Tormod Froyland, P. Ramondenc, Jordi Segura, A. Gabdullin, Lev Kotlyar, S. H. Fonseca
Depleted wells require underbalanced coiled tubing cleanouts (CTCO) in which natural production from the reservoir assists solids transport. Conventional cleanout methods relying on fluid circulation pose a risk of fluid loss, reducing annular velocity and increasing the risk of formation damage or stuck CT pipe incidents. The use of nitrified fluids addresses some of those risks, but also introduces a new set of challenges. In addition to technical challenges, cleanout operations face logistics and operational constraints, which directly impact the feasibility and viability of the intervention. Digital tools provide a path toward increased efficiency and success rate of CTCO, but the suite of legacy software often used in CT operations relies on monolithic implementations, which limit the possible optimization of the planning and the connection between design and execution data. More generally, reliance on manual operations (whether during the design or execution phases) often leads to missing on potential optimization opportunities. The transformation of CTCO leveraging a new cloud-based CT hydraulics (CTH) simulator, real-time execution advisors, and autonomous conveyance brings a new level of flexibility and interconnectivity to the design and execution phases. CTH features state-of-the-art flow and transport models, which improve CTCO design capabilities, providing the required insights during execution time to optimize the cleanout operation. During the design phase of underbalanced CTCO, the designer needs to work with uncertainty on several parameters, such as reservoir pressure or PI distribution of the horizontal section. The architecture of the CTH allows sensitizing over every parameter, which generates a combinatorial number of scenarios, driving a larger-than-usual processing demand. The cloud-based service's processing capacity meets these demands during the job design phase to generate a large database of sensitized scenarios and delineate a safe and effective operational envelope. Two case studies show how CTH can be used during the design phase to ensure more efficient job execution in two horizontal oil wells in the Valhall brownfield. In the first one, the simulator was used to guarantee that the cleanout execution would be possible even if contingency plans due to gas lift valve failure had to be triggered. In the second, sensitivity analysis was conducted over the pumping rate and formation pressure, identifying a safe operating envelope that, once coupled with an adequate execution approach, led to 20% oil base savings. Efficiency of CTCO operations is further improved by implementing autonomous conveyance execution during the operations. This includes automatic control of depth and speed, achieving more than 10% more efficient speeds during run-in-hole and pull-out-of-hole activities. Pull tests need to be performed at set intervals during conveyance to ensure that the pipe is not getting stuck, which accelerates fati
{"title":"Cloud-Based Planning and Real-Time Algorithms Improve Coiled Tubing Cleanout Efficiency","authors":"Johnny Bardsen, Bjørn Engvald Staveland Nilsen, Tormod Froyland, P. Ramondenc, Jordi Segura, A. Gabdullin, Lev Kotlyar, S. H. Fonseca","doi":"10.2118/218290-ms","DOIUrl":"https://doi.org/10.2118/218290-ms","url":null,"abstract":"\u0000 Depleted wells require underbalanced coiled tubing cleanouts (CTCO) in which natural production from the reservoir assists solids transport. Conventional cleanout methods relying on fluid circulation pose a risk of fluid loss, reducing annular velocity and increasing the risk of formation damage or stuck CT pipe incidents. The use of nitrified fluids addresses some of those risks, but also introduces a new set of challenges. In addition to technical challenges, cleanout operations face logistics and operational constraints, which directly impact the feasibility and viability of the intervention.\u0000 Digital tools provide a path toward increased efficiency and success rate of CTCO, but the suite of legacy software often used in CT operations relies on monolithic implementations, which limit the possible optimization of the planning and the connection between design and execution data. More generally, reliance on manual operations (whether during the design or execution phases) often leads to missing on potential optimization opportunities. The transformation of CTCO leveraging a new cloud-based CT hydraulics (CTH) simulator, real-time execution advisors, and autonomous conveyance brings a new level of flexibility and interconnectivity to the design and execution phases.\u0000 CTH features state-of-the-art flow and transport models, which improve CTCO design capabilities, providing the required insights during execution time to optimize the cleanout operation. During the design phase of underbalanced CTCO, the designer needs to work with uncertainty on several parameters, such as reservoir pressure or PI distribution of the horizontal section. The architecture of the CTH allows sensitizing over every parameter, which generates a combinatorial number of scenarios, driving a larger-than-usual processing demand. The cloud-based service's processing capacity meets these demands during the job design phase to generate a large database of sensitized scenarios and delineate a safe and effective operational envelope. Two case studies show how CTH can be used during the design phase to ensure more efficient job execution in two horizontal oil wells in the Valhall brownfield. In the first one, the simulator was used to guarantee that the cleanout execution would be possible even if contingency plans due to gas lift valve failure had to be triggered. In the second, sensitivity analysis was conducted over the pumping rate and formation pressure, identifying a safe operating envelope that, once coupled with an adequate execution approach, led to 20% oil base savings.\u0000 Efficiency of CTCO operations is further improved by implementing autonomous conveyance execution during the operations. This includes automatic control of depth and speed, achieving more than 10% more efficient speeds during run-in-hole and pull-out-of-hole activities. Pull tests need to be performed at set intervals during conveyance to ensure that the pipe is not getting stuck, which accelerates fati","PeriodicalId":517791,"journal":{"name":"Day 2 Wed, March 20, 2024","volume":"42 6","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-03-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140284340","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}
As an oilfield reaches its expected End Of Field Life (EOFL), permanent abandonment is required to meet local regulations, specifically for wells where the Floating Production Storage and Offloading (FPSO) vessel has been de-commissioned within the last three (3) years if no monitoring has been performed in this period. However, this abandonment campaign faced well integrity issues, and the mandate from local authorities was to suspend the wells. Using Coiled Tubing (CT) with a Real-Time (RT) downhole monitoring system added value to the operation and its successful completion, saving time and avoiding unexpected events. The methodology behind this campaign followed customer requirements to either P&A or suspend the wells, depending on the case. A series of inflatable packers were included as a base for cement and/or to cement the A annulus. It was critical to punch the inner tubing to communicate with the A annulus and be able to cement it. CT with Cable (E-line) installed conveyed a punch downhole with RT communication between the surface and the Bottom Hole Assembly (BHA). The RT downhole monitoring BHA was also important for accurately correlating depth and acquiring downhole data such as pressure and temperature to help ensure the correct placement and inflation of the packers and monitoring the cement slurry behavior. A total of two (2) wells were successfully temporarily abandoned from a Drill Ship using CT to clean, punch, and place cement plugs in the annulus and tubing (using inflatable packers). The remaining wells were suspended according to V0 barrier philosophy, and throughout the operation, faster decisions were possible due to the RT downhole data from the BHA sensors being transmitted to the surface. The surface equipment and BHA selected for the operation were part of the strategy for faster rig Up (R/U), Rig Down (R/D), and changing from one well intervention method to another when required. This included using a Coiled Tubing Lifting Frame (CTLF) with an injector table to swap from CT to Wireline (WL) quickly while keeping the CT injector and stripper with the main BHA rigged up during WL interventions. The synergy between multiple service lines created an optimal solution by fine-tuning the cement slurry rheology with hydraulic simulations and using a WL punch that was deemed most suitable for the application. This paper covers the thru-tubing operation to abandon and/or suspend the wells using CT while saving overall time to R/U and R/D for both the CT and WL. It resulted in a more coordinated and reliable operation, avoiding typical problems often associated with P&A in deepwater. It describes the challenges faced and the solutions implemented to address them and complete the campaign's objective.
{"title":"Integrated Solutions for P&A Using a Real-Time Downhole Monitoring System Saved Rig Time and Avoided Typical Deepwater Intervention-Related Problems, Offshore Brazil","authors":"Victor Vivas, Mauro Nunes, Mario Apolinar","doi":"10.2118/218289-ms","DOIUrl":"https://doi.org/10.2118/218289-ms","url":null,"abstract":"\u0000 As an oilfield reaches its expected End Of Field Life (EOFL), permanent abandonment is required to meet local regulations, specifically for wells where the Floating Production Storage and Offloading (FPSO) vessel has been de-commissioned within the last three (3) years if no monitoring has been performed in this period. However, this abandonment campaign faced well integrity issues, and the mandate from local authorities was to suspend the wells. Using Coiled Tubing (CT) with a Real-Time (RT) downhole monitoring system added value to the operation and its successful completion, saving time and avoiding unexpected events.\u0000 The methodology behind this campaign followed customer requirements to either P&A or suspend the wells, depending on the case. A series of inflatable packers were included as a base for cement and/or to cement the A annulus. It was critical to punch the inner tubing to communicate with the A annulus and be able to cement it. CT with Cable (E-line) installed conveyed a punch downhole with RT communication between the surface and the Bottom Hole Assembly (BHA). The RT downhole monitoring BHA was also important for accurately correlating depth and acquiring downhole data such as pressure and temperature to help ensure the correct placement and inflation of the packers and monitoring the cement slurry behavior.\u0000 A total of two (2) wells were successfully temporarily abandoned from a Drill Ship using CT to clean, punch, and place cement plugs in the annulus and tubing (using inflatable packers). The remaining wells were suspended according to V0 barrier philosophy, and throughout the operation, faster decisions were possible due to the RT downhole data from the BHA sensors being transmitted to the surface.\u0000 The surface equipment and BHA selected for the operation were part of the strategy for faster rig Up (R/U), Rig Down (R/D), and changing from one well intervention method to another when required. This included using a Coiled Tubing Lifting Frame (CTLF) with an injector table to swap from CT to Wireline (WL) quickly while keeping the CT injector and stripper with the main BHA rigged up during WL interventions. The synergy between multiple service lines created an optimal solution by fine-tuning the cement slurry rheology with hydraulic simulations and using a WL punch that was deemed most suitable for the application.\u0000 This paper covers the thru-tubing operation to abandon and/or suspend the wells using CT while saving overall time to R/U and R/D for both the CT and WL. It resulted in a more coordinated and reliable operation, avoiding typical problems often associated with P&A in deepwater. It describes the challenges faced and the solutions implemented to address them and complete the campaign's objective.","PeriodicalId":517791,"journal":{"name":"Day 2 Wed, March 20, 2024","volume":"46 2","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-03-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140394984","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}
As the number of the wells designated for the abandonment or slot recovery operations increase, multiple challenges are faced during the barrier placement and removal of the casing. Achieving operational efficiency is crucial. Till now, conventional solutions included milling of the casing, throughout history, conventional solutions involved milling processes and the use of charges to establish channels for either barrier placement or cement remediation or reduction of stuck forces, thereby enhancing casing removal efficiency. This paper will explain the new technology which includes a hydro-mechanical tool that creates the slots into the casing to allows the access behind. This innovative approach aims to significantly improve efficiency during the well abandonment phase. The tool's capability extends to breaking down the barite accumulation behind the casing or facilitating the precise placement of cement for sustained casing pressure solutions or annular cement remediation. The incorporation of this advanced technology marks a paradigm shift in addressing the challenges associated with well abandonment, offering a more streamlined and effective solution.
{"title":"Increasing Efficiency in Well Abandonment Utilizing Hydromechanical Slotting Tool","authors":"Waqas Munir, Knut Inge Dahlberg","doi":"10.2118/218342-ms","DOIUrl":"https://doi.org/10.2118/218342-ms","url":null,"abstract":"\u0000 As the number of the wells designated for the abandonment or slot recovery operations increase, multiple challenges are faced during the barrier placement and removal of the casing. Achieving operational efficiency is crucial. Till now, conventional solutions included milling of the casing, throughout history, conventional solutions involved milling processes and the use of charges to establish channels for either barrier placement or cement remediation or reduction of stuck forces, thereby enhancing casing removal efficiency.\u0000 This paper will explain the new technology which includes a hydro-mechanical tool that creates the slots into the casing to allows the access behind. This innovative approach aims to significantly improve efficiency during the well abandonment phase. The tool's capability extends to breaking down the barite accumulation behind the casing or facilitating the precise placement of cement for sustained casing pressure solutions or annular cement remediation. The incorporation of this advanced technology marks a paradigm shift in addressing the challenges associated with well abandonment, offering a more streamlined and effective solution.","PeriodicalId":517791,"journal":{"name":"Day 2 Wed, March 20, 2024","volume":"15 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-03-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140395716","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}
A. Rodriguez, C. Cadavid, O. Ortega, P. Silva, L. Guarín, R. Rincón, M. Cuervo, R. Garay, J. Hernandez
This paper presents the critical aspects taken into account during the planning process of a Coiled Tubing re-entry of an old abandoned well with substandard modified wellhead, a section of 2-7/8″ tubing stuck into the surface cement plug, hazardous atmosphere readings, integrity issues exhibiting sustained casing pressure, wellbore fluids migration on surface, presence of formation faults connecting over pressured formations and background of a well control event requiring 21.1 ppg fluid during the completion stage. Due to the complexity of the Coiled Tubing intervention and information uncertainty, the planning strategy was divided in three stages: First, an initial inspection to determine the integrity status of the wellhead and accessories on the surface, then a second stage to ensure and correct the integrity of the wellhead and the last stage to carry out the intervention on coiled tubing. For the last stage the IDA-G-001 Well Intervention Guide process was followed to fulfil a strict operational discipline including several peer reviews by technical authorities to safeguard the life and environment. The well interventions team planned a critical Plug and Abandonment P&A intervention in a restricted access location; the need for more information was a challenge. The field group accomplished the challenge of milling out with Coiled tubing, the 7″ casing cement plug, and 2-7/8″ tubing with expected well pressure below the cement plug with the proper simulations, bases of design and risk assessments. Acquiring more information about the well's integrity by running electric logs was crucial for adequately designing the abandonment that fulfills the government regulations and industry standards. Consequence analysis and multidisciplinary detailed risk assessment were essential for identify contingency plans during the planning. The pre-operational QA Check list was verified for all the services involved in the abandonment, to mitigate the risk of equipment failure, and this contributed to execute the intervention according to the planing. The two first stages of wellhead inspection and subsequent integrity assurance allowed the intervention with no wellbore fluids that could contaminate the surface. The application of the corporate Guide for the Planning and Execution of Special Interventions, (Well Intervention Guide WIG), is a detailed process that, through an initial risk assessment, determines the complexity of the planning and safe execution of high-risk interventions and is a powerful tool when critical operations such as the intervention of old wells with lack of information and integrity are required.
{"title":"Assuring Critical Coiled Tubing Re-Entry Operations of Old Wells with Integrity Issues by the Application of the Well Intervention Guide, Provides Execution to Safeguard the Life and Environment","authors":"A. Rodriguez, C. Cadavid, O. Ortega, P. Silva, L. Guarín, R. Rincón, M. Cuervo, R. Garay, J. Hernandez","doi":"10.2118/218303-ms","DOIUrl":"https://doi.org/10.2118/218303-ms","url":null,"abstract":"\u0000 This paper presents the critical aspects taken into account during the planning process of a Coiled Tubing re-entry of an old abandoned well with substandard modified wellhead, a section of 2-7/8″ tubing stuck into the surface cement plug, hazardous atmosphere readings, integrity issues exhibiting sustained casing pressure, wellbore fluids migration on surface, presence of formation faults connecting over pressured formations and background of a well control event requiring 21.1 ppg fluid during the completion stage.\u0000 Due to the complexity of the Coiled Tubing intervention and information uncertainty, the planning strategy was divided in three stages: First, an initial inspection to determine the integrity status of the wellhead and accessories on the surface, then a second stage to ensure and correct the integrity of the wellhead and the last stage to carry out the intervention on coiled tubing. For the last stage the IDA-G-001 Well Intervention Guide process was followed to fulfil a strict operational discipline including several peer reviews by technical authorities to safeguard the life and environment.\u0000 The well interventions team planned a critical Plug and Abandonment P&A intervention in a restricted access location; the need for more information was a challenge. The field group accomplished the challenge of milling out with Coiled tubing, the 7″ casing cement plug, and 2-7/8″ tubing with expected well pressure below the cement plug with the proper simulations, bases of design and risk assessments. Acquiring more information about the well's integrity by running electric logs was crucial for adequately designing the abandonment that fulfills the government regulations and industry standards. Consequence analysis and multidisciplinary detailed risk assessment were essential for identify contingency plans during the planning. The pre-operational QA Check list was verified for all the services involved in the abandonment, to mitigate the risk of equipment failure, and this contributed to execute the intervention according to the planing. The two first stages of wellhead inspection and subsequent integrity assurance allowed the intervention with no wellbore fluids that could contaminate the surface.\u0000 The application of the corporate Guide for the Planning and Execution of Special Interventions, (Well Intervention Guide WIG), is a detailed process that, through an initial risk assessment, determines the complexity of the planning and safe execution of high-risk interventions and is a powerful tool when critical operations such as the intervention of old wells with lack of information and integrity are required.","PeriodicalId":517791,"journal":{"name":"Day 2 Wed, March 20, 2024","volume":"6 11","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-03-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140395796","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}
Concentric coiled tubing technology has many applications for well intervention activities ranging from wellbore cleanout to well unloading and delivering multiple chemicals downhole via separate conduits. Technology historically developed for ultra low bottom hole pressure applications but currently utilization of it was expanded to wellbores with positive wellhead pressure. Concentric Coiled tubing string present similar risk and challenges as Conventional CT. Stuck in hole situation is one of the most notorious situations that requires very close attention and detailed contingency recovery planning. Unlike single pipe recovery where industry has very well-established guidelines and expertise, concentric pipe technology historically lacked both detailed planning and recovery experience. This paper details out the engineering design to address recovery of the CCT. Paper highlights stages requiring for the successful project delivery, step by step guideline and lists out purpose build equipment. Although proposed engineering solutions was not implemented due to the contingency nature, nevertheless careful approach and detailed engineering, risk assessment methods used in developing precise guidelines provides very good resource into existing industry challenge.
{"title":"Challenges and Solutions of Concentric Coiled Tubing Fishing","authors":"K. Rahimov, S. Nicol","doi":"10.2118/218357-ms","DOIUrl":"https://doi.org/10.2118/218357-ms","url":null,"abstract":"\u0000 Concentric coiled tubing technology has many applications for well intervention activities ranging from wellbore cleanout to well unloading and delivering multiple chemicals downhole via separate conduits. Technology historically developed for ultra low bottom hole pressure applications but currently utilization of it was expanded to wellbores with positive wellhead pressure. Concentric Coiled tubing string present similar risk and challenges as Conventional CT. Stuck in hole situation is one of the most notorious situations that requires very close attention and detailed contingency recovery planning. Unlike single pipe recovery where industry has very well-established guidelines and expertise, concentric pipe technology historically lacked both detailed planning and recovery experience. This paper details out the engineering design to address recovery of the CCT. Paper highlights stages requiring for the successful project delivery, step by step guideline and lists out purpose build equipment. Although proposed engineering solutions was not implemented due to the contingency nature, nevertheless careful approach and detailed engineering, risk assessment methods used in developing precise guidelines provides very good resource into existing industry challenge.","PeriodicalId":517791,"journal":{"name":"Day 2 Wed, March 20, 2024","volume":"2 7","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-03-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140395960","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}
_. Ilfi, Hanif Setiyawan, Ali Masyhuri, _. Rusli, Christian Eliezer Mileota, Iftikar Luthfi Ramadhan, Rinenggo Nugroho, M. Afton
The Sawah field, a waterflood field, currently produces approximately 130,000 BFPD with an average 96% water-cut. The Fluid In Fluid Out (FIFO) stands at only 0.6, resulting in suboptimal waterflood performance. One cause of the low injection rate in Sawah field is injector plugging due to solid content and/or scale, and characteristics of the reservoir itself. Pressure Transient Analysis (PTA) further validates significant skin and permeability reduction. To improve the injection rate, workover activities are conducted on the targeted well using a combination of the Acidizing and C-EBD (Cyclic Extended Breakdown) methods. This involves a chemical and mechanical effort, where the acid dissolves scale, and the C-EBD creates fractures. Compatibility tests are conducted between acid and water production, as well as acid and water injection. A 15% HCl simple acid is injected with a 3-feet penetration near the wellbore using coiled tubing. Following soaking, the treatment continues by injecting water into the reservoir in 6 cycles, with 350-700 bbls of water for each cycle. During workover activities, improved injectivity was observed through Step Rate Tests (SRT). After acidizing, a rate of 2.5 bpm at 1,600 psi was achieved, followed by 3 bpm at 1,350 psi after the first 3 cycles of C-EBD. Further injectivity improvements occurred during subsequent C-EBD cycles, with the first 3 cycles reaching 2.4 bpm at 1,300 psi, and the next 3 cycles achieving 3.5 bpm at a similar pressure. Post Put on Injection (POI), the injection rate increased from 0-30 to 5,100-8,500 BWIPD, marking the well's highest injection rate in history. This notable success opens opportunity for Sawah Field, facilitating the reactivation of trade-off wells and increased capacity to handle additional fluids from size-up jobs or new wells. The collaborative efforts of the Subsurface, Research, and Workover Teams in the Sawah field were vital in achieving this remarkable result, contributing to longer injection well lifetimes, preventing overflow at surface facilities, and enhancing employee satisfaction. A lesson learned emphasizes the need to verify flow meter readings before and during execution, facilitating the prompt identification of problems or areas for improvement. Additionally, conducting an extra Step Rate Test (SRT) before acidizing serves as an added baseline. This successful approach is currently being implemented in other injectors within the Sawah field facing similar plugging issues, showcasing its ongoing effectiveness in enhancing operational practices.
{"title":"From Zero to Hero: A New Breakthrough of Stimulation Method by Combining Acidizing and Cyclic Extended Breakdown in Sawah Field","authors":"_. Ilfi, Hanif Setiyawan, Ali Masyhuri, _. Rusli, Christian Eliezer Mileota, Iftikar Luthfi Ramadhan, Rinenggo Nugroho, M. Afton","doi":"10.2118/218353-ms","DOIUrl":"https://doi.org/10.2118/218353-ms","url":null,"abstract":"\u0000 The Sawah field, a waterflood field, currently produces approximately 130,000 BFPD with an average 96% water-cut. The Fluid In Fluid Out (FIFO) stands at only 0.6, resulting in suboptimal waterflood performance. One cause of the low injection rate in Sawah field is injector plugging due to solid content and/or scale, and characteristics of the reservoir itself. Pressure Transient Analysis (PTA) further validates significant skin and permeability reduction.\u0000 To improve the injection rate, workover activities are conducted on the targeted well using a combination of the Acidizing and C-EBD (Cyclic Extended Breakdown) methods. This involves a chemical and mechanical effort, where the acid dissolves scale, and the C-EBD creates fractures. Compatibility tests are conducted between acid and water production, as well as acid and water injection. A 15% HCl simple acid is injected with a 3-feet penetration near the wellbore using coiled tubing. Following soaking, the treatment continues by injecting water into the reservoir in 6 cycles, with 350-700 bbls of water for each cycle.\u0000 During workover activities, improved injectivity was observed through Step Rate Tests (SRT). After acidizing, a rate of 2.5 bpm at 1,600 psi was achieved, followed by 3 bpm at 1,350 psi after the first 3 cycles of C-EBD. Further injectivity improvements occurred during subsequent C-EBD cycles, with the first 3 cycles reaching 2.4 bpm at 1,300 psi, and the next 3 cycles achieving 3.5 bpm at a similar pressure. Post Put on Injection (POI), the injection rate increased from 0-30 to 5,100-8,500 BWIPD, marking the well's highest injection rate in history. This notable success opens opportunity for Sawah Field, facilitating the reactivation of trade-off wells and increased capacity to handle additional fluids from size-up jobs or new wells. The collaborative efforts of the Subsurface, Research, and Workover Teams in the Sawah field were vital in achieving this remarkable result, contributing to longer injection well lifetimes, preventing overflow at surface facilities, and enhancing employee satisfaction.\u0000 A lesson learned emphasizes the need to verify flow meter readings before and during execution, facilitating the prompt identification of problems or areas for improvement. Additionally, conducting an extra Step Rate Test (SRT) before acidizing serves as an added baseline. This successful approach is currently being implemented in other injectors within the Sawah field facing similar plugging issues, showcasing its ongoing effectiveness in enhancing operational practices.","PeriodicalId":517791,"journal":{"name":"Day 2 Wed, March 20, 2024","volume":"35 6","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-03-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140284940","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}
J. M. Mirande, J. Vassallo, P. Mambriani, C. Gonzalez, E. Fajardo, M. Vecchietti, R. Krasuk, A. Misonischnik
Unconventional horizontal wells completed with plug-and-perf fracturing techniques require coiled tubing (CT) to clean out the well before it is put into production. To remove proppant and plug debris, water is pumped into the wellbore and flowed back to the surface through the annular section between the CT and the production casing. This study describes implementation and impact of a three-phase flowmeter to measure the return rate and detect proppant and gas in real time. During CT post-fracturing cleanouts, fluid return rate is critical to monitor because the annular fluid velocity that carries solids out of the well is proportional to it. In addition, wells in Argentina must be kept in a near-balanced condition to avoid producing gas from the well. Fluid return rates used to be measured with an ultrasonic flowmeter, which experienced signal loss when there was more than 5% sand or gas in the fluid, making it unreliable for this workscope. A three-phase flowmeter was therefore implemented to achieve high-frequency and real-time measurements of water, proppant, and gas at the surface. Implementation of the three-phase flowmeter allowed cleanout optimizations without sacrificing operational safety. Having a precise and continuous measurement permitted the variation of the flowback choke strategy, increasing the return rate to a value closer to the pumping rate by 0.1 bbl/min without affecting the well balance condition. During the execution of the first four-well pad after this new flowmeter was implemented, analysis of the sand flow rate measurement showed that the wells were already clean when the CT had to be pulled out of hole (POOH) after reaching total depth, as only traces of sand were detected during this part of the operation. With this information, the job procedure was optimized by increasing the horizontal section POOH speed from 6 m/min to 12 m/min, if sand was not detected at surface. It also prevented pumping gel pills. This represented a 10% reduction in the total operating time per well and a 25% reduction in xanthan gel consumption in the next completed pad. This is the first time that a three-phase flowmeter has been implemented for post-fracturing cleanouts in Argentina Vaca Muerta operations. The increase in the precision of surface measurements means a more controlled cleanout strategy, during which flowback is evaluated in real time and the operational program can be optimized. Poor flowback control is a known contributing factor to stuck pipe incidents. This technology plays a critical role in addressing one of the major risks during CT operations.
{"title":"Flowback Three-Phase Flowmeter Implementation for Post-Fracturing Cleanouts: A Case Study from Argentina","authors":"J. M. Mirande, J. Vassallo, P. Mambriani, C. Gonzalez, E. Fajardo, M. Vecchietti, R. Krasuk, A. Misonischnik","doi":"10.2118/218337-ms","DOIUrl":"https://doi.org/10.2118/218337-ms","url":null,"abstract":"\u0000 Unconventional horizontal wells completed with plug-and-perf fracturing techniques require coiled tubing (CT) to clean out the well before it is put into production. To remove proppant and plug debris, water is pumped into the wellbore and flowed back to the surface through the annular section between the CT and the production casing. This study describes implementation and impact of a three-phase flowmeter to measure the return rate and detect proppant and gas in real time.\u0000 During CT post-fracturing cleanouts, fluid return rate is critical to monitor because the annular fluid velocity that carries solids out of the well is proportional to it. In addition, wells in Argentina must be kept in a near-balanced condition to avoid producing gas from the well. Fluid return rates used to be measured with an ultrasonic flowmeter, which experienced signal loss when there was more than 5% sand or gas in the fluid, making it unreliable for this workscope. A three-phase flowmeter was therefore implemented to achieve high-frequency and real-time measurements of water, proppant, and gas at the surface.\u0000 Implementation of the three-phase flowmeter allowed cleanout optimizations without sacrificing operational safety. Having a precise and continuous measurement permitted the variation of the flowback choke strategy, increasing the return rate to a value closer to the pumping rate by 0.1 bbl/min without affecting the well balance condition. During the execution of the first four-well pad after this new flowmeter was implemented, analysis of the sand flow rate measurement showed that the wells were already clean when the CT had to be pulled out of hole (POOH) after reaching total depth, as only traces of sand were detected during this part of the operation. With this information, the job procedure was optimized by increasing the horizontal section POOH speed from 6 m/min to 12 m/min, if sand was not detected at surface. It also prevented pumping gel pills. This represented a 10% reduction in the total operating time per well and a 25% reduction in xanthan gel consumption in the next completed pad.\u0000 This is the first time that a three-phase flowmeter has been implemented for post-fracturing cleanouts in Argentina Vaca Muerta operations. The increase in the precision of surface measurements means a more controlled cleanout strategy, during which flowback is evaluated in real time and the operational program can be optimized. Poor flowback control is a known contributing factor to stuck pipe incidents. This technology plays a critical role in addressing one of the major risks during CT operations.","PeriodicalId":517791,"journal":{"name":"Day 2 Wed, March 20, 2024","volume":"19 3‐4","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-03-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140395227","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}
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