_. Setiohadi, Praja Hadistira, Muhammad Alfianoor Yudhatama, Daniel Sitompul, Dhika Escodianto Hutabarat, Andre Wiharja, R. Panjaitan, C. Agriawan, R. Kusumawatie, V. R. Wedhaswari, Bagus Setyo Darmanto, A. Osman, C. Azwar, Wiwin Winarti, Andre Simanjuntak
The operator was drilling their first high-pressure high-temperature (HPHT) exploration well with narrow pressure window in a swamp area of East Kalimantan. The gas field was discovered in 1977 and production started in 1990. Since then, more than 1500 wells have been drilled in this area yielding a total gas production of 9.7 Tcf. Currently T field enters established mature field status which has quite marginal reserves. Therefore, further exploration is seen as one of the solutions to locate additional reserves to enhance overall gas production. The well was drilled directionally with no offset well nearby. While drilling the 6-in open hole section, an unexpected high-pressure zone was penetrated. The zone condition was made worse by lost circulation and a high gas reading. Two cement plugs were placed using a managed pressure cementing with pump and pull method. The first plug was set by applying surface back pressure (SBP) to maintain equivalent bottom hole pressure (BHP) between lowermost pore pressure (PP) and fracture gradient (FG) at the previous shoe. After pumping 1 m3 of cement into the annulus, pump and pull operations commenced. While performing post job circulation on the first plug, it was observed that the returned fluid density at surface was less than original mud weight, indicating the possibility of contaminant invasion from formation. After waiting for the cement to reach 500 psi compressive strength, pressure buildup was observed when annulus was shut-in, indicating an inadequate pressure seal across the cement plug Applying lessons learned from setting the first plug, new design considerations were implemented such as increasing cement volume in the annulus to 4 m3 prior to the pump and pull operation to minimize cement overlapping risk and applying SBP at BHP near FG. A contingency plan was in place to determine the appropriate SBP value to be applied whenever the pumping rate was changed. A second plug job was performed safely and flawlessly by achieving the top of cement as desired. A successful inflow test was performed with indication of no contaminant invasion nor pressure bypass around the cement plug. The rig was able to continue its next operation to sidetrack the well. This paper presents the design considerations, methodology applied, and lessons learned two managed pressure cement plugs using pump and pull method in a well bore with a narrow pore-frac window where the new techniques were implemented to enhance success of the plug job despite the complexity and risk inherent with an underbalanced operation.
{"title":"A New Approach for Designing an Underbalanced Cementing Plug Using a Managed Pressure Cementing and Pump-Pull Method with Narrow Pore-Frac Pressure Window in HPHT Exploration Well: An Offshore East Kalimantan, Indonesia Case Study","authors":"_. Setiohadi, Praja Hadistira, Muhammad Alfianoor Yudhatama, Daniel Sitompul, Dhika Escodianto Hutabarat, Andre Wiharja, R. Panjaitan, C. Agriawan, R. Kusumawatie, V. R. Wedhaswari, Bagus Setyo Darmanto, A. Osman, C. Azwar, Wiwin Winarti, Andre Simanjuntak","doi":"10.2118/210539-ms","DOIUrl":"https://doi.org/10.2118/210539-ms","url":null,"abstract":"\u0000 The operator was drilling their first high-pressure high-temperature (HPHT) exploration well with narrow pressure window in a swamp area of East Kalimantan. The gas field was discovered in 1977 and production started in 1990. Since then, more than 1500 wells have been drilled in this area yielding a total gas production of 9.7 Tcf. Currently T field enters established mature field status which has quite marginal reserves. Therefore, further exploration is seen as one of the solutions to locate additional reserves to enhance overall gas production. The well was drilled directionally with no offset well nearby. While drilling the 6-in open hole section, an unexpected high-pressure zone was penetrated. The zone condition was made worse by lost circulation and a high gas reading.\u0000 Two cement plugs were placed using a managed pressure cementing with pump and pull method. The first plug was set by applying surface back pressure (SBP) to maintain equivalent bottom hole pressure (BHP) between lowermost pore pressure (PP) and fracture gradient (FG) at the previous shoe. After pumping 1 m3 of cement into the annulus, pump and pull operations commenced. While performing post job circulation on the first plug, it was observed that the returned fluid density at surface was less than original mud weight, indicating the possibility of contaminant invasion from formation. After waiting for the cement to reach 500 psi compressive strength, pressure buildup was observed when annulus was shut-in, indicating an inadequate pressure seal across the cement plug\u0000 Applying lessons learned from setting the first plug, new design considerations were implemented such as increasing cement volume in the annulus to 4 m3 prior to the pump and pull operation to minimize cement overlapping risk and applying SBP at BHP near FG. A contingency plan was in place to determine the appropriate SBP value to be applied whenever the pumping rate was changed. A second plug job was performed safely and flawlessly by achieving the top of cement as desired. A successful inflow test was performed with indication of no contaminant invasion nor pressure bypass around the cement plug. The rig was able to continue its next operation to sidetrack the well.\u0000 This paper presents the design considerations, methodology applied, and lessons learned two managed pressure cement plugs using pump and pull method in a well bore with a narrow pore-frac window where the new techniques were implemented to enhance success of the plug job despite the complexity and risk inherent with an underbalanced operation.","PeriodicalId":336268,"journal":{"name":"Day 2 Wed, September 28, 2022","volume":"92 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-09-27","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"126212663","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}
Michael Cadd, Susannah Stott, R. Graham, Ryan Nowell, Josef Schachner
This case study shows how three highly depleted reservoirs with large negative drilling windows, previously considered un-drillable, were safely entered by combining Managed Pressure Drilling (MPD) and drill-in liner technologies with a novel losses response strategy. The challenge was to bridge the gap between the high pore pressure overburden and the low fracture strength reservoir. The reservoir had been depleted by some 12,000psi since production started, creating a 3,000psi negative drilling window. Conventional strategies to prevent losses were deemed unlikely to succeed, and the focus was instead on how best to respond to the near-inevitable onset of total losses. The gap was bridged using a low static mud weight in combination with high applied surface back pressure to give an Equivalent Mud Weight (EMW) suitable for the high-pressure overburden, whilst allowing immediate reduction in bottom hole pressure in the event of total losses on entry into the weakened reservoir. Endurance testing allowed the MPD equipment to be operated outside of its normal pressure envelope. In the reference case, losses would be managed by reducing Surface Back Pressure (SBP) while continuing to drill ahead. In the low-pressure case, Pressurised Mud Cap Drilling (PMCD) would be used to bullhead the well to a lighter mud while drilling ahead, before restoring returns. A contingency plan was in place for managing elevated gas levels in the returns, which was anticipated following a large reduction of bottom hole pressure across the overburden shales. In the extreme case where high gas levels from the shales prevented bringing returns to surface, cementing would also be carried out in Pressurised Mud Cap mode. A drill-in liner was used because many of the scenarios would not permit safe tripping and Wellbore Strengthening material was included in the mud in an attempt to reduce the severity of the losses. Total losses were seen on two of the three wells, and all three wells were successfully completed. This paper will discuss the technology and techniques used along with the planning and procedures required to enable successful well construction in this challenging environment.
{"title":"Bridging the Gap: Highly Depleted Reservoir Entry in a Mature HPHT Field","authors":"Michael Cadd, Susannah Stott, R. Graham, Ryan Nowell, Josef Schachner","doi":"10.2118/210543-ms","DOIUrl":"https://doi.org/10.2118/210543-ms","url":null,"abstract":"\u0000 This case study shows how three highly depleted reservoirs with large negative drilling windows, previously considered un-drillable, were safely entered by combining Managed Pressure Drilling (MPD) and drill-in liner technologies with a novel losses response strategy.\u0000 The challenge was to bridge the gap between the high pore pressure overburden and the low fracture strength reservoir. The reservoir had been depleted by some 12,000psi since production started, creating a 3,000psi negative drilling window. Conventional strategies to prevent losses were deemed unlikely to succeed, and the focus was instead on how best to respond to the near-inevitable onset of total losses. The gap was bridged using a low static mud weight in combination with high applied surface back pressure to give an Equivalent Mud Weight (EMW) suitable for the high-pressure overburden, whilst allowing immediate reduction in bottom hole pressure in the event of total losses on entry into the weakened reservoir. Endurance testing allowed the MPD equipment to be operated outside of its normal pressure envelope. In the reference case, losses would be managed by reducing Surface Back Pressure (SBP) while continuing to drill ahead. In the low-pressure case, Pressurised Mud Cap Drilling (PMCD) would be used to bullhead the well to a lighter mud while drilling ahead, before restoring returns. A contingency plan was in place for managing elevated gas levels in the returns, which was anticipated following a large reduction of bottom hole pressure across the overburden shales. In the extreme case where high gas levels from the shales prevented bringing returns to surface, cementing would also be carried out in Pressurised Mud Cap mode. A drill-in liner was used because many of the scenarios would not permit safe tripping and Wellbore Strengthening material was included in the mud in an attempt to reduce the severity of the losses.\u0000 Total losses were seen on two of the three wells, and all three wells were successfully completed. This paper will discuss the technology and techniques used along with the planning and procedures required to enable successful well construction in this challenging environment.","PeriodicalId":336268,"journal":{"name":"Day 2 Wed, September 28, 2022","volume":"1 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-09-27","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"129616771","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}
The use of Managed Pressure Drilling (MPD) techniques allows the rapid differentiation of formation breathing or wellbore ballooning from a gas kick through a series of quick shut-in, build-up and flowback tests. These tests have proven to reduce uncertainty, NPT, and total drilling time by ensuring that operations do not enter secondary well control after mistaking flowback for a kick. Such tests provide definitive results when done correctly. However, when performed incorrectly, the wellbore response can appear either ambiguous or indicative of a kick. When done correctly, the ballooning test shows dissipation in both pressure build-up and flowback over time. However, when done incorrectly, both pressure and flowback can appear to gain drive. This is caused by induced losses being allowed to start equalizing with the wellbore with significant flowback volume prior to beginning the shut-in, build-up and flowback testing. As a result, ballooning testing can show classic signs of a gas kick as increasing pressure and flowback is observed or ambiguous results from the rising and then falling pressure and flowback. This can necessitate some combination of entering costly secondary well control and the need to trip back in to circulate bottoms up only to observe minimal signs of reservoir fluids. This paper presents type modelling that accounts for the observed unexpected results and reiterates rigid testing parameters for the successful implementation of diagnostic testing.
{"title":"Fingerprinting Formation Breathing and Wellbore Ballooning: Getting Mixed Signals","authors":"P. Gunn, Maria Retuta","doi":"10.2118/210548-ms","DOIUrl":"https://doi.org/10.2118/210548-ms","url":null,"abstract":"\u0000 The use of Managed Pressure Drilling (MPD) techniques allows the rapid differentiation of formation breathing or wellbore ballooning from a gas kick through a series of quick shut-in, build-up and flowback tests. These tests have proven to reduce uncertainty, NPT, and total drilling time by ensuring that operations do not enter secondary well control after mistaking flowback for a kick. Such tests provide definitive results when done correctly. However, when performed incorrectly, the wellbore response can appear either ambiguous or indicative of a kick.\u0000 When done correctly, the ballooning test shows dissipation in both pressure build-up and flowback over time. However, when done incorrectly, both pressure and flowback can appear to gain drive. This is caused by induced losses being allowed to start equalizing with the wellbore with significant flowback volume prior to beginning the shut-in, build-up and flowback testing.\u0000 As a result, ballooning testing can show classic signs of a gas kick as increasing pressure and flowback is observed or ambiguous results from the rising and then falling pressure and flowback. This can necessitate some combination of entering costly secondary well control and the need to trip back in to circulate bottoms up only to observe minimal signs of reservoir fluids. This paper presents type modelling that accounts for the observed unexpected results and reiterates rigid testing parameters for the successful implementation of diagnostic testing.","PeriodicalId":336268,"journal":{"name":"Day 2 Wed, September 28, 2022","volume":"1 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-09-27","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"128366040","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}
Harshad Patil, E. Dietrich, Ian Knight, Greg Matherne, Svein Hovland
This paper highlights a case study where MPD (Managed Pressure Drilling) techniques were utilized while floating long string casings in the 10,000ft laterals in the Haynesville, saving the client more than 30-40% of rig time. The challenges encompassing the events that cause casing floating equipment conversion, either due to excessive gas, flow out from well or drag, are illustrated herein. This paper demonstrates the specific MPD techniques which facilitated floating casing to TD (Target Depth) and prevent its untimely conversion. The use of unique MPD methods illustrated herein enabled prevention of excess gas, hole collapse and situations relating to ballooning which enabled floating the casing to TD. These MPD methods helped reduce casing running times from 34-48hrs to 24-27hrs and prevented shut-in or "stop & circulate" scenarios during running casing. These shut-ins and/or "stop & circulate" scenarios were largely caused by increased flow out readings as the gas expanded at surface along with indications of well ballooning. Ballooning scenarios were later found to be associated with high surge pressures and higher SBP required to mitigate gas at surface. A holistic approach was taken to identify methods to mitigate such events. It was obvious that MPD pressures had to be manipulated for managing surge to mitigate ballooning, but excessive trip gas which necessitated higher MPD pressures while running casing had to be primarily evaluated. It was later found that excessive gas in these 10,000ft laterals were not just a function of swabbing pressures while POOH (pulling out of hole) with BHA (Bottomhole Assembly), but also related to POOH practices and methods which affected wellbore stability. To enable floating casing all the way to TD, first the MPD pressures and bottoms-up circulation strategy while POOH with BHA were analyzed and modified for the client. Second, the MPD balanced pill volume (which is typically spotted in the vertical) and its spotting procedure/calculations were revised to ensure minimizing gas encroachment and migration in vertical hole section. The design of this balanced pill accommodated automatic heavy pill displacement out of the well without the need for stopping and circulating pill while running casing. And third, the MPD control system was modified to automatically manipulate the MPD pressures as the casing was lowered to manage surge and prevent losses/ballooning. This paper illustrates how all of these methods enabled floating the casing in 10,000ft lateral in Haynesville.
{"title":"Floating Casings in 10,000ft Laterals with MPD in Haynesville","authors":"Harshad Patil, E. Dietrich, Ian Knight, Greg Matherne, Svein Hovland","doi":"10.2118/210554-ms","DOIUrl":"https://doi.org/10.2118/210554-ms","url":null,"abstract":"\u0000 This paper highlights a case study where MPD (Managed Pressure Drilling) techniques were utilized while floating long string casings in the 10,000ft laterals in the Haynesville, saving the client more than 30-40% of rig time. The challenges encompassing the events that cause casing floating equipment conversion, either due to excessive gas, flow out from well or drag, are illustrated herein. This paper demonstrates the specific MPD techniques which facilitated floating casing to TD (Target Depth) and prevent its untimely conversion. The use of unique MPD methods illustrated herein enabled prevention of excess gas, hole collapse and situations relating to ballooning which enabled floating the casing to TD.\u0000 These MPD methods helped reduce casing running times from 34-48hrs to 24-27hrs and prevented shut-in or \"stop & circulate\" scenarios during running casing. These shut-ins and/or \"stop & circulate\" scenarios were largely caused by increased flow out readings as the gas expanded at surface along with indications of well ballooning. Ballooning scenarios were later found to be associated with high surge pressures and higher SBP required to mitigate gas at surface. A holistic approach was taken to identify methods to mitigate such events. It was obvious that MPD pressures had to be manipulated for managing surge to mitigate ballooning, but excessive trip gas which necessitated higher MPD pressures while running casing had to be primarily evaluated. It was later found that excessive gas in these 10,000ft laterals were not just a function of swabbing pressures while POOH (pulling out of hole) with BHA (Bottomhole Assembly), but also related to POOH practices and methods which affected wellbore stability.\u0000 To enable floating casing all the way to TD, first the MPD pressures and bottoms-up circulation strategy while POOH with BHA were analyzed and modified for the client. Second, the MPD balanced pill volume (which is typically spotted in the vertical) and its spotting procedure/calculations were revised to ensure minimizing gas encroachment and migration in vertical hole section. The design of this balanced pill accommodated automatic heavy pill displacement out of the well without the need for stopping and circulating pill while running casing. And third, the MPD control system was modified to automatically manipulate the MPD pressures as the casing was lowered to manage surge and prevent losses/ballooning. This paper illustrates how all of these methods enabled floating the casing in 10,000ft lateral in Haynesville.","PeriodicalId":336268,"journal":{"name":"Day 2 Wed, September 28, 2022","volume":"20 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-09-27","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"124683191","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}
André Alonso Fernandes, Davi Valle Ferreira, E. Schnitzler, Fabiano Hamilton de Castro, Isadora Luisa de Paiva Goncalves do Carmo, Pedro Menezes Santana, Roger Savoldi Roman
An appraisal well was drilled in Brazilian pre-salt area using overbalance drilling fluid, with conventional techniques. While drilling reservoir (in a 12 1/4" phase), total losses were found. Unsuccessful attempts with LCM and cement pills revealed that only MPD/PMCD techniques could deliver the well to TD. It was decided to anticipate the installation of the 9 5/8" casing, covering only the upper portion of the reservoir, and well was suspended. The remaining reservoir could be drilled later with a rig equipped with MPD system. This well was designed as a 2-zones intelligent completion in cased hole configuration. Due to the fluid losses a new design had to be considered. Due to reservoir uncertainties, definition on the separation between zones would only be taken after drilling the remaining reservoir section. To overcome this challenge without adding time and complexity to the overall design, the best solution was to perforate the cased hole section after drilling the remaining section, meaning doing it with reservoir communicated to the wellbore and in PMCD mode. Several options were evaluated to design the TCP operation in PMCD. Well control strategies, contingencies, thermal effects, and dynamic shocks were considered. The solution consisted in running the TCP with a closed string, without NRVs and having robust contingencies in case of washout or drillpipe failure after perforating. The well was drilled, and total fluid losses occurred again. It was then successfully perforated still in PMCD, then lower and upper completion were installed. Despite these challenges, this was the fastest intelligent completion in all Petrobras pre-salt fields so far.
{"title":"Perforating Using MPD Techniques: Design and Execution","authors":"André Alonso Fernandes, Davi Valle Ferreira, E. Schnitzler, Fabiano Hamilton de Castro, Isadora Luisa de Paiva Goncalves do Carmo, Pedro Menezes Santana, Roger Savoldi Roman","doi":"10.2118/210542-ms","DOIUrl":"https://doi.org/10.2118/210542-ms","url":null,"abstract":"\u0000 An appraisal well was drilled in Brazilian pre-salt area using overbalance drilling fluid, with conventional techniques. While drilling reservoir (in a 12 1/4\" phase), total losses were found. Unsuccessful attempts with LCM and cement pills revealed that only MPD/PMCD techniques could deliver the well to TD. It was decided to anticipate the installation of the 9 5/8\" casing, covering only the upper portion of the reservoir, and well was suspended. The remaining reservoir could be drilled later with a rig equipped with MPD system.\u0000 This well was designed as a 2-zones intelligent completion in cased hole configuration. Due to the fluid losses a new design had to be considered. Due to reservoir uncertainties, definition on the separation between zones would only be taken after drilling the remaining reservoir section.\u0000 To overcome this challenge without adding time and complexity to the overall design, the best solution was to perforate the cased hole section after drilling the remaining section, meaning doing it with reservoir communicated to the wellbore and in PMCD mode.\u0000 Several options were evaluated to design the TCP operation in PMCD. Well control strategies, contingencies, thermal effects, and dynamic shocks were considered. The solution consisted in running the TCP with a closed string, without NRVs and having robust contingencies in case of washout or drillpipe failure after perforating.\u0000 The well was drilled, and total fluid losses occurred again. It was then successfully perforated still in PMCD, then lower and upper completion were installed. Despite these challenges, this was the fastest intelligent completion in all Petrobras pre-salt fields so far.","PeriodicalId":336268,"journal":{"name":"Day 2 Wed, September 28, 2022","volume":"64 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-09-27","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"133927823","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}
_. Setiohadi, Praja Hadistira, Muhammad Alfianoor Yudhatama, Daniel Sitompul, Dikha Escodianto Hutabarat, Andre Wiharja, C. Agriawan, A. Martadinata, _. Sudiariaji, Agus Sidianto, Andry Prasthio, F. Irawan
The first ever HPHT exploration well in Kalimantan was drilled by Swamp Barge Rig with narrow pressure window environment. The well was planned to be drilled using 2.9 SG mud weight to 4575 m vertical depth with 0.10 SG pressure window. Maximum predicted bottom hole temperature of the well was 186° C while the maximum expected wellhead pressure (MEWHP) reached 11,300 Psi. MPD becomes mandatory to complete the well and becomes a novel implement for swamp barge rig operation. Therefore, MPD workshop was held among the teams to ensure all personnel become familiar with the system. On other hand, the equipment configuration was set with some modifications to accommodate the operation requirement, contingency, tight stack up below rotary table and hoisting devices limitation. Rotating Control Device (RCD) was stacked up part by part on tight moon pool space. Several modifications were done properly and gave operation flexibility plus robust contingency. RCD alignment was reset periodically and natural rubbers were utilized to enhanced rubbers lifetime in high temperature condition. EKD system with Coriolis utilization was being main mitigation during drilling with limited kick margin that will allow reservoir section to be accessed. Formation pressure investigation was also performed to give additional information on formation pressure for better well assessment. SBP application on dual gradient tripping and managed pressure cementing give a means to secure the well safely and properly during high gas event with losses condition. As the result, MPD implementation enables the operator to complete HPHT exploration well on swamp barge rig project safely despite the complexity and risk of narrow formation pressure window operation.
{"title":"First Implementation of Managed Pressure Drilling (MPD) System in Swamp Barge Rig to Drill Narrow Pressure Window HPHT Exploration Well Safely – Return of Experience from Kalimantan, Indonesia","authors":"_. Setiohadi, Praja Hadistira, Muhammad Alfianoor Yudhatama, Daniel Sitompul, Dikha Escodianto Hutabarat, Andre Wiharja, C. Agriawan, A. Martadinata, _. Sudiariaji, Agus Sidianto, Andry Prasthio, F. Irawan","doi":"10.2118/210553-ms","DOIUrl":"https://doi.org/10.2118/210553-ms","url":null,"abstract":"The first ever HPHT exploration well in Kalimantan was drilled by Swamp Barge Rig with narrow pressure window environment. The well was planned to be drilled using 2.9 SG mud weight to 4575 m vertical depth with 0.10 SG pressure window. Maximum predicted bottom hole temperature of the well was 186° C while the maximum expected wellhead pressure (MEWHP) reached 11,300 Psi. MPD becomes mandatory to complete the well and becomes a novel implement for swamp barge rig operation. Therefore, MPD workshop was held among the teams to ensure all personnel become familiar with the system. On other hand, the equipment configuration was set with some modifications to accommodate the operation requirement, contingency, tight stack up below rotary table and hoisting devices limitation. Rotating Control Device (RCD) was stacked up part by part on tight moon pool space. Several modifications were done properly and gave operation flexibility plus robust contingency. RCD alignment was reset periodically and natural rubbers were utilized to enhanced rubbers lifetime in high temperature condition. EKD system with Coriolis utilization was being main mitigation during drilling with limited kick margin that will allow reservoir section to be accessed. Formation pressure investigation was also performed to give additional information on formation pressure for better well assessment. SBP application on dual gradient tripping and managed pressure cementing give a means to secure the well safely and properly during high gas event with losses condition. As the result, MPD implementation enables the operator to complete HPHT exploration well on swamp barge rig project safely despite the complexity and risk of narrow formation pressure window operation.","PeriodicalId":336268,"journal":{"name":"Day 2 Wed, September 28, 2022","volume":"38 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-09-27","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"121372186","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}
T. McCluskey, Ching Shearn Ho, Chai Yong Tan, Eric Timbancaya, Mohammad Annas Omar, Khairil Azam Mohd Khaidzir
This paper describes how PMCD with an overbalanced drilling mud, instead of Light Annular Mud, was used to successfully drill and complete a well in gas bearing carbonates offshore Malaysia. This unconventional approach was adopted after encountering poor formation injectivity and severe dynamic losses in the 8-1/2″ reservoir section. Dynamic losses of 700 bbl/hr were encountered after drilling into the carbonate formation, but the subsequent injectivity test surface pressure prevented the well being converted to PMCD with LAM. LCM pills were spotted and the mud weight was cut by 0.2 ppg but severe dynamic losses continued. An injectivity test was performed with seawater and the surface pressure stabilized around 500 psi. Drilling resumed with overbalanced drilling mud in the annulus, which was top filled during connections to keep the hole full and to monitor the annulus with a nominal surface pressure, while seawater was pumped down the string. After reaching TD, the drilling BHA was retrieved to surface and the 7″ lower completion was run in hole while the well continued to take around 50 bbl/hr static losses. When the lower completion entered the open hole, PMCD was activated to run in and set the liner hanger. This method of unconventional PMCD may be implemented to successfully drill through carbonates with poor injectivity and severe dynamic losses, thereby improving the safety and efficiency of the drilling operations compared to conventional or floating mud cap drilling.
{"title":"Pressurized Mud Cap Drilling Used to Drill and Complete Carbonate Gas Reservoir with Poor Injectivity and Severe Dynamic Losses Offshore Malaysia","authors":"T. McCluskey, Ching Shearn Ho, Chai Yong Tan, Eric Timbancaya, Mohammad Annas Omar, Khairil Azam Mohd Khaidzir","doi":"10.2118/210550-ms","DOIUrl":"https://doi.org/10.2118/210550-ms","url":null,"abstract":"\u0000 This paper describes how PMCD with an overbalanced drilling mud, instead of Light Annular Mud, was used to successfully drill and complete a well in gas bearing carbonates offshore Malaysia. This unconventional approach was adopted after encountering poor formation injectivity and severe dynamic losses in the 8-1/2″ reservoir section.\u0000 Dynamic losses of 700 bbl/hr were encountered after drilling into the carbonate formation, but the subsequent injectivity test surface pressure prevented the well being converted to PMCD with LAM. LCM pills were spotted and the mud weight was cut by 0.2 ppg but severe dynamic losses continued. An injectivity test was performed with seawater and the surface pressure stabilized around 500 psi. Drilling resumed with overbalanced drilling mud in the annulus, which was top filled during connections to keep the hole full and to monitor the annulus with a nominal surface pressure, while seawater was pumped down the string.\u0000 After reaching TD, the drilling BHA was retrieved to surface and the 7″ lower completion was run in hole while the well continued to take around 50 bbl/hr static losses. When the lower completion entered the open hole, PMCD was activated to run in and set the liner hanger.\u0000 This method of unconventional PMCD may be implemented to successfully drill through carbonates with poor injectivity and severe dynamic losses, thereby improving the safety and efficiency of the drilling operations compared to conventional or floating mud cap drilling.","PeriodicalId":336268,"journal":{"name":"Day 2 Wed, September 28, 2022","volume":"74 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-09-27","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"129440548","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}
O. Gabaldon, Romar A Gonzalez Luis, Pedro Sousa, Chen Wei, Yuanhang Chen
The Influx Management Envelope (IME) is a proven tool to assess management of influxes taken during MPD operations. Currently, IME establishes limits of manageable influx volumes for given kick intensity/surface back-pressures, to hand over from primary to secondary barrier (i.e., well-control equipment). Opportunities exist for advanced, safe operations when influx circulation up the riser is a concern but dealing with the influx in the hole may introduce additional risks, such as imposing choke line friction pressures (CLFP), particularly in ultra-deepwater operations. A closed riser system allows for safe handling of influxes using the riser/MPD equipment, while isolating the wellbore with the subsea BOP and eliminating risks of fracturing the well or taking additional influxes. We propose expanding the current regions of the IME with a zone in which the decision can be made to circulate the influx to the riser, then isolate the well to handle the influx in the riser with MPD equipment, using the opportunities and methods being developed for industry use. Potential risks to the integrity of the system are analyzed and assessed versus reasonable scenarios. This work is consistent with the current work on providing guidelines for influx management with MPD (IM Annex to API-RP92S, under balloting process by API), and for managing gas in riser with closed riser systems (Riser Gas Handling (RGH) Guidelines, by the IADC UBO&MPD Committee).
{"title":"Expanded IME with New Riser Gas Handling Operation Region","authors":"O. Gabaldon, Romar A Gonzalez Luis, Pedro Sousa, Chen Wei, Yuanhang Chen","doi":"10.2118/210538-ms","DOIUrl":"https://doi.org/10.2118/210538-ms","url":null,"abstract":"The Influx Management Envelope (IME) is a proven tool to assess management of influxes taken during MPD operations. Currently, IME establishes limits of manageable influx volumes for given kick intensity/surface back-pressures, to hand over from primary to secondary barrier (i.e., well-control equipment). Opportunities exist for advanced, safe operations when influx circulation up the riser is a concern but dealing with the influx in the hole may introduce additional risks, such as imposing choke line friction pressures (CLFP), particularly in ultra-deepwater operations. A closed riser system allows for safe handling of influxes using the riser/MPD equipment, while isolating the wellbore with the subsea BOP and eliminating risks of fracturing the well or taking additional influxes. We propose expanding the current regions of the IME with a zone in which the decision can be made to circulate the influx to the riser, then isolate the well to handle the influx in the riser with MPD equipment, using the opportunities and methods being developed for industry use. Potential risks to the integrity of the system are analyzed and assessed versus reasonable scenarios. This work is consistent with the current work on providing guidelines for influx management with MPD (IM Annex to API-RP92S, under balloting process by API), and for managing gas in riser with closed riser systems (Riser Gas Handling (RGH) Guidelines, by the IADC UBO&MPD Committee).","PeriodicalId":336268,"journal":{"name":"Day 2 Wed, September 28, 2022","volume":"3 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-09-27","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"133011068","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}
Ship and submarine production and repair have benefited significantly from more intelligently allocating resources and managing other constraints, thereby increasing efficiency, and reducing overall project duration. In complex production and repair environments, such as ship production/repair, the method of allocating resources and managing other constraints significantly affects the efficiency of progress and thus the overall project duration. Resources include human resources, equipment resources and physical-space resources. Due to the inherent complexity of resource allocation and constraint management for such complex environments, the project durations can be 25%+ longer than necessary. This paper shares the real-world results experienced by the authors as well as similar results found in the literature showing the major difference in project duration due to resource-scheduling techniques.
{"title":"Reduced Project Duration via Intelligent Scheduling for Ship Production/Repair","authors":"R. Richards","doi":"10.5957/smc-2022-055","DOIUrl":"https://doi.org/10.5957/smc-2022-055","url":null,"abstract":"Ship and submarine production and repair have benefited significantly from more intelligently allocating resources and managing other constraints, thereby increasing efficiency, and reducing overall project duration. In complex production and repair environments, such as ship production/repair, the method of allocating resources and managing other constraints significantly affects the efficiency of progress and thus the overall project duration. Resources include human resources, equipment resources and physical-space resources. Due to the inherent complexity of resource allocation and constraint management for such complex environments, the project durations can be 25%+ longer than necessary. This paper shares the real-world results experienced by the authors as well as similar results found in the literature showing the major difference in project duration due to resource-scheduling techniques.","PeriodicalId":336268,"journal":{"name":"Day 2 Wed, September 28, 2022","volume":"1 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-09-19","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"128390296","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}
Cameron Baker, R. Tagg, Eugene A. Van Rynbach, Dale Pederson, Julian Gaitley
There are several upcoming regulations focusing on the emissions from maritime transportation requiring owners to rethink their normal operations. One option available to ship owners and operators to achieve compliance with the regulations is to utilize alternate fuels with low-carbon content. These considerations have moved from the future to the present. Current new designs must include plans for future carbon reduction and the widespread availability of low-carbon fuels. This study provides a summary of the available fuels in practical terms that are useful to Naval Architects and Marine Engineers when designing vessels and it will discuss some of the design considerations that must be made to ensure a vessel is transition-ready to operate using these fuels in the near future.
{"title":"Fuel Choices for Carbon Reduction and Impact on Vessel Design","authors":"Cameron Baker, R. Tagg, Eugene A. Van Rynbach, Dale Pederson, Julian Gaitley","doi":"10.5957/smc-2022-046","DOIUrl":"https://doi.org/10.5957/smc-2022-046","url":null,"abstract":"There are several upcoming regulations focusing on the emissions from maritime transportation requiring owners to rethink their normal operations. One option available to ship owners and operators to achieve compliance with the regulations is to utilize alternate fuels with low-carbon content. These considerations have moved from the future to the present. Current new designs must include plans for future carbon reduction and the widespread availability of low-carbon fuels. This study provides a summary of the available fuels in practical terms that are useful to Naval Architects and Marine Engineers when designing vessels and it will discuss some of the design considerations that must be made to ensure a vessel is transition-ready to operate using these fuels in the near future.","PeriodicalId":336268,"journal":{"name":"Day 2 Wed, September 28, 2022","volume":"13 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-09-19","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"128495404","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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