P. Potter, Guaraci Bornia, N. Ng, David M. Robbins, Daryl Attaway, Shakib Amini, B. Zhu, Ayman Wafai, Eric Croucher
This paper discusses the design, development and testing of an optimized subsea wellhead annulus seal. Historically annulus seal qualification and validation testing requirements are defined in API 6A and API 17D requiring a PR2F temperature and pressure cyclic test program, and x3 lockdown load cycles. Throughout the operational life of a production subsea wellhead, the annulus seal can be subjected to many start-up and shut-down cycles, leading to substantially more lockdown load cycles on the annulus seal than initially validated (OTC-30784-MS). Traditionally, it has been left up to operators to define their own requirements over and above API. Operating conditions experienced by the annulus sealing system and the subsea wellhead equipment can be exceptionally challenging. Prior to landing and locking the annulus sealing system in place, the sealing surfaces of both the wellhead system and the annulus seal are subjected to a multitude of operational and environmental conditions such as cuttings/ debris from circulating well fluids, possible damage from lowering the annulus seal through several thousand feet of subsea riser and a BOP stack and misalignment of the seal during installation. The annulus sealing system of the subsea wellhead equipment is a critical secondary well barrier for well control. Either in exploration or production mode, with the casing cemented in place, the annulus sealing system locks the subsea casing hanger into position, providing a metal-to-metal seal across the annulus of the intermediate casing. The purpose of the annulus sealing system is to ensure it does not unseat and lose integrity in the event there is any pressure from below the seal due to a leak, reduced hydrostatic pressure from above or from thermal expansion during the production life of the well.
{"title":"A Subsea Wellhead Annulus Seal Ready to Meet Challenging and Critical Endurance and Performance Needs","authors":"P. Potter, Guaraci Bornia, N. Ng, David M. Robbins, Daryl Attaway, Shakib Amini, B. Zhu, Ayman Wafai, Eric Croucher","doi":"10.4043/31351-ms","DOIUrl":"https://doi.org/10.4043/31351-ms","url":null,"abstract":"\u0000 This paper discusses the design, development and testing of an optimized subsea wellhead annulus seal. Historically annulus seal qualification and validation testing requirements are defined in API 6A and API 17D requiring a PR2F temperature and pressure cyclic test program, and x3 lockdown load cycles. Throughout the operational life of a production subsea wellhead, the annulus seal can be subjected to many start-up and shut-down cycles, leading to substantially more lockdown load cycles on the annulus seal than initially validated (OTC-30784-MS). Traditionally, it has been left up to operators to define their own requirements over and above API.\u0000 Operating conditions experienced by the annulus sealing system and the subsea wellhead equipment can be exceptionally challenging. Prior to landing and locking the annulus sealing system in place, the sealing surfaces of both the wellhead system and the annulus seal are subjected to a multitude of operational and environmental conditions such as cuttings/ debris from circulating well fluids, possible damage from lowering the annulus seal through several thousand feet of subsea riser and a BOP stack and misalignment of the seal during installation.\u0000 The annulus sealing system of the subsea wellhead equipment is a critical secondary well barrier for well control. Either in exploration or production mode, with the casing cemented in place, the annulus sealing system locks the subsea casing hanger into position, providing a metal-to-metal seal across the annulus of the intermediate casing. The purpose of the annulus sealing system is to ensure it does not unseat and lose integrity in the event there is any pressure from below the seal due to a leak, reduced hydrostatic pressure from above or from thermal expansion during the production life of the well.","PeriodicalId":11217,"journal":{"name":"Day 4 Fri, March 25, 2022","volume":"1 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89810135","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}
In the current situation of the industry, high numbers of prospects are being considered as not economical to develop due to various factors including low reserves, high complexity and stranded locations with no suitable host facility to tie-in to nearby. This paper will discuss how the utilization of direct-hydraulic subsea control technology, when coupled with shallow water tree technology, can be deployed to enable technically and commercially viable solutions for marginal shallow water fields. Under these circumstances, direct hydraulic technology has a number of advantages over traditional EH-MUX control systems, such that direct hydraulics can enable the development of fields which would otherwise be uneconomical. These advantages include – By using Direct Hydraulic technology, the project was able to achieve a commercially attractive and technically fit-for-purpose design, leading to successful project sanction (the first such project in Malaysian waters), and opening the door for similar future developments to follow. This paper will present information and methods that will be of benefit to other Operators in the subsea industry who are seeking to unlock reserves that are currently in marginal fields and would be uneconomical to develop using other methods. The benefits that can be gained are both in terms of proof of concept using off-the-shelf designs, and opening up otherwise uneconomical fields for development. In this particular case, the project opens up a further 6 new fields which were previously considered uneconomic to develop.
{"title":"Direct Hydraulic Control Systems as a Key Enabler for Developing Shallow Water Marginal Fields","authors":"Steven Hammond, Iman Zahari, Awaluddin Berwanto","doi":"10.4043/31412-ms","DOIUrl":"https://doi.org/10.4043/31412-ms","url":null,"abstract":"\u0000 \u0000 \u0000 In the current situation of the industry, high numbers of prospects are being considered as not economical to develop due to various factors including low reserves, high complexity and stranded locations with no suitable host facility to tie-in to nearby.\u0000 This paper will discuss how the utilization of direct-hydraulic subsea control technology, when coupled with shallow water tree technology, can be deployed to enable technically and commercially viable solutions for marginal shallow water fields.\u0000 \u0000 \u0000 \u0000 Under these circumstances, direct hydraulic technology has a number of advantages over traditional EH-MUX control systems, such that direct hydraulics can enable the development of fields which would otherwise be uneconomical.\u0000 These advantages include –\u0000 \u0000 \u0000 \u0000 By using Direct Hydraulic technology, the project was able to achieve a commercially attractive and technically fit-for-purpose design, leading to successful project sanction (the first such project in Malaysian waters), and opening the door for similar future developments to follow.\u0000 \u0000 \u0000 \u0000 This paper will present information and methods that will be of benefit to other Operators in the subsea industry who are seeking to unlock reserves that are currently in marginal fields and would be uneconomical to develop using other methods. The benefits that can be gained are both in terms of proof of concept using off-the-shelf designs, and opening up otherwise uneconomical fields for development. In this particular case, the project opens up a further 6 new fields which were previously considered uneconomic to develop.\u0000","PeriodicalId":11217,"journal":{"name":"Day 4 Fri, March 25, 2022","volume":"104 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88545045","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}
Arsenic (As) and Mercury (Hg) are impurities unique to condensate produced from reservoir in the Gulf of Thailand and thus, the treatment process is critical to meet PTTEP's sale obligation. Mercury has been successfully removed by filtration, but no proven technology exists for arsenic removal until now. Normally, there are 3 condensate tankers to transfer offloading condensate to Petrochemical plant. In case any batch of condensate is rejected by customer. Trader is generally required at least 2 weeks to manage the tanker holding the high As condensate. Thus, the business impact of this project is cost saving from reducing the frequency of tanker demurrage. The major financial ramification is a key driver for exploring the alternative treatment techniques for As removal. Several techniques to remove As content in condensate have been explored and tested to find a suitable solution to this major challenge. Several technologies were tested in-house, and solid bed adsorption is found to be the most effective with approximately 90% removal efficiency. The scaled-up unit is developed for pilot test with operating conditions designed to simulate actual site conditions for further large-scale development. The Arsenic Removal Mobile Unit is designed for a capacity of 4,670 BPD located at the Condensate Tank Terminal prior to installation at offshore facilities. Basic engineering was performed in-house by PTTEP according to adsorbent specifications with modular fabrication for flexibility of installation and relocation. Detailed engineering and construction were performed by contractor under PTTEP supervision. The engineering and procurement of long lead equipment were performed by PTTEP. Furthermore, in parallel, the engineering team are also performed to provide a basis design facility, plan & schedule for installing a permanent arsenic removal unit at Offshore locations (Full-scale). This test result will prove the performance of selected adsorbent and how the adsorbent reacts with actual condensate in full scale. PTTEP is the only company who have been studied about arsenic removal technology from condensate. This initiative has been carried through from preliminary conception to prototype field trials for practical application with an ambitious end-goal of commercialization. The success of this project will provide confidence for large-scale ARU investment to support the condensate management strategy. The expected benefit gain is saving revenue loss of each relevant party. Once this unit is installed at offshore. It will unlock field potential and increase operating flexibility. For downstream industry, it will reduce the adverse impact on downstream petrochemical plants. The service life of catalyst can be prolonged and reduce a toxicity risk to personnel. The high arsenic contaminated in disposal water shall be resolved.
{"title":"World's First Arsenic in Condensate Removal for Oil & Gas Industry and its Universal Applications for Adsorption Facilities","authors":"Taradon Piromchart, Supaluck Watanapanich, S. Limprachaya, Patara Limpanachaipornkul, Thirawat Sanitmuang, Jutiporn Jaiyen, Noppadol Iamtanasinchai, Ekkalak Somroop, Worachet Pimthaweepol, Udom Choktheeraworachai, W. Moonrat, Prakarn Yormin, Sunatda Arayachukiat, Kittichai Chinkiri, Urissa Thunmasarnrit, C. Hayook, Thanapong Sakpunjachotti, Thawich Kaoluan, Natavut Buranaboonwong, Nattaporn Jiravasanaich","doi":"10.4043/31368-ms","DOIUrl":"https://doi.org/10.4043/31368-ms","url":null,"abstract":"\u0000 Arsenic (As) and Mercury (Hg) are impurities unique to condensate produced from reservoir in the Gulf of Thailand and thus, the treatment process is critical to meet PTTEP's sale obligation. Mercury has been successfully removed by filtration, but no proven technology exists for arsenic removal until now. Normally, there are 3 condensate tankers to transfer offloading condensate to Petrochemical plant. In case any batch of condensate is rejected by customer. Trader is generally required at least 2 weeks to manage the tanker holding the high As condensate. Thus, the business impact of this project is cost saving from reducing the frequency of tanker demurrage. The major financial ramification is a key driver for exploring the alternative treatment techniques for As removal. Several techniques to remove As content in condensate have been explored and tested to find a suitable solution to this major challenge.\u0000 Several technologies were tested in-house, and solid bed adsorption is found to be the most effective with approximately 90% removal efficiency. The scaled-up unit is developed for pilot test with operating conditions designed to simulate actual site conditions for further large-scale development.\u0000 The Arsenic Removal Mobile Unit is designed for a capacity of 4,670 BPD located at the Condensate Tank Terminal prior to installation at offshore facilities. Basic engineering was performed in-house by PTTEP according to adsorbent specifications with modular fabrication for flexibility of installation and relocation. Detailed engineering and construction were performed by contractor under PTTEP supervision. The engineering and procurement of long lead equipment were performed by PTTEP. Furthermore, in parallel, the engineering team are also performed to provide a basis design facility, plan & schedule for installing a permanent arsenic removal unit at Offshore locations (Full-scale). This test result will prove the performance of selected adsorbent and how the adsorbent reacts with actual condensate in full scale.\u0000 PTTEP is the only company who have been studied about arsenic removal technology from condensate. This initiative has been carried through from preliminary conception to prototype field trials for practical application with an ambitious end-goal of commercialization. The success of this project will provide confidence for large-scale ARU investment to support the condensate management strategy. The expected benefit gain is saving revenue loss of each relevant party. Once this unit is installed at offshore. It will unlock field potential and increase operating flexibility. For downstream industry, it will reduce the adverse impact on downstream petrochemical plants. The service life of catalyst can be prolonged and reduce a toxicity risk to personnel. The high arsenic contaminated in disposal water shall be resolved.","PeriodicalId":11217,"journal":{"name":"Day 4 Fri, March 25, 2022","volume":"46 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"73469075","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}
Ding Xiong, Shehzad Ahmed, W. Alameri, E. Al-Shalabi
Foam injection is designed to reduce the effects of high reservoir heterogeneities and fluid viscosity contrasts during gas flooding, and hence, improve sweep efficiency. However, harsh reservoir conditions in the Middle Eastern reservoirs pose a serious problem to foam stability, leading to a poor mobility control for foam injection. In this study, different surfactant types and their combinations were tested to screen and optimize foam performance in harsh salinity (20 wt%) at high pressure and high temperature (HPHT) conditions (1000 psi and 80 °C) based on series of bulk foam experiments. For this purpose, different commercial amphoteric and amine-based switchable surfactants were utilized and their compatibility in 20 wt% brine were ensured at HPHT conditions. Initial screening was performed by conducting series of foam stability and foaming ability tests at high temperature. The surface tension and surfactant solution rheology tests were performed to analyze foam behavior. The mixtures of amphoteric and amine-based surfactants were then investigated to improve bulk foam performance. Foam stability and foam texture at different foam qualities under HPHT conditions were also studied. Bulk foam experiments showed that betaine (B-1235) surfactant outperformed other surfactant types through achieving the highest foam generation with excellent foam stability performance. Betaine foam endurance was found to be comparable to that of viscoelastic diamine surfactant. However, poor foam generation was observed when diamine was used as a single surfactant. The optimum concentration for betaine surfactant was found to be 0.25 wt%. A mixture of betaine and amine-based surfactant improved the latter foam properties and its performance was found to be higher than that of single surfactant. The foam stability of mixed surfactant was approximately 8 folds higher than that of single amine-based surfactant. Furthermore, foam texture directly controls foam decay profile, and the optimum foam quality based on static pressurized foam cell test was found to be 90% due to the formation of uniform and closely packed bubbles. This research identified high performing individual as well as a mixed surfactant systems for designing foam EOR projects for Middle Eastern harsh reservoir conditions.
{"title":"Experimental Evaluation of Amphoteric and Switchable Surfactants for Improving Foam Performance Under Harsh Reservoir Conditions","authors":"Ding Xiong, Shehzad Ahmed, W. Alameri, E. Al-Shalabi","doi":"10.4043/31334-ms","DOIUrl":"https://doi.org/10.4043/31334-ms","url":null,"abstract":"\u0000 Foam injection is designed to reduce the effects of high reservoir heterogeneities and fluid viscosity contrasts during gas flooding, and hence, improve sweep efficiency. However, harsh reservoir conditions in the Middle Eastern reservoirs pose a serious problem to foam stability, leading to a poor mobility control for foam injection. In this study, different surfactant types and their combinations were tested to screen and optimize foam performance in harsh salinity (20 wt%) at high pressure and high temperature (HPHT) conditions (1000 psi and 80 °C) based on series of bulk foam experiments. For this purpose, different commercial amphoteric and amine-based switchable surfactants were utilized and their compatibility in 20 wt% brine were ensured at HPHT conditions. Initial screening was performed by conducting series of foam stability and foaming ability tests at high temperature. The surface tension and surfactant solution rheology tests were performed to analyze foam behavior. The mixtures of amphoteric and amine-based surfactants were then investigated to improve bulk foam performance. Foam stability and foam texture at different foam qualities under HPHT conditions were also studied.\u0000 Bulk foam experiments showed that betaine (B-1235) surfactant outperformed other surfactant types through achieving the highest foam generation with excellent foam stability performance. Betaine foam endurance was found to be comparable to that of viscoelastic diamine surfactant. However, poor foam generation was observed when diamine was used as a single surfactant. The optimum concentration for betaine surfactant was found to be 0.25 wt%. A mixture of betaine and amine-based surfactant improved the latter foam properties and its performance was found to be higher than that of single surfactant. The foam stability of mixed surfactant was approximately 8 folds higher than that of single amine-based surfactant. Furthermore, foam texture directly controls foam decay profile, and the optimum foam quality based on static pressurized foam cell test was found to be 90% due to the formation of uniform and closely packed bubbles. This research identified high performing individual as well as a mixed surfactant systems for designing foam EOR projects for Middle Eastern harsh reservoir conditions.","PeriodicalId":11217,"journal":{"name":"Day 4 Fri, March 25, 2022","volume":"101 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"80812989","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}
There is no doubt that greenhouse gas emissions, particularly CO2, needs to be reduced to mitigate the effects of climate change. While carbon management can be achieved through a number of technological and engineering approaches ranging from energy efficiency (i.e., highly energy integrated system and process intensification) to renewable energy (wind, solar, hydrogen), CO2 capture & storage (CCS) has been identified as having a key role in the energy transition. Captured anthropogenic CO2 can be permanently stored in saline aquifers and depleted reservoirs. Saline aquifers (normally unsuitable for industrial or human exploitation) offer the largest storage capacity; however, there is, usually, lack of geological characterization leading to high risks due to large uncertainty. On the other hand, depleted gas fields, close to economical life cessation, are deemed an excellent alternative as safe and long-term storage is already proven and immense geological characterisation has been gathered during production life. Moreover, there is great potential to repurpose the existing offshore infrastructure (pipelines, platforms, and wells) as to minimize capital expenditure and delaying decommissioning costs. Repurposing existing production systems can also be an efficient way to achieve rapid deployment of CCS at large scale. In this paper, we present the key engineering challenges, risks, and opportunities in the re-use of existing oil and gas offshore infrastructure for CO2 transport and injection. We highlight the complex operational constraints and interactions between different components of the transportation network. The design and operation of the transportation network is governed by the following drivers: Safe design Robust and flexible operation Minimize cost (or delay expenditure as long as possible) Minimize emissions of greenhouse gases associated to the operation of the transport network (i.e., energy efficiency) Start operation with minimum modifications
{"title":"Reusing Existing Infrastructure for CO2 Transport: Risks and Opportunities","authors":"E. Luna-Ortiz","doi":"10.4043/31457-ms","DOIUrl":"https://doi.org/10.4043/31457-ms","url":null,"abstract":"\u0000 There is no doubt that greenhouse gas emissions, particularly CO2, needs to be reduced to mitigate the effects of climate change. While carbon management can be achieved through a number of technological and engineering approaches ranging from energy efficiency (i.e., highly energy integrated system and process intensification) to renewable energy (wind, solar, hydrogen), CO2 capture & storage (CCS) has been identified as having a key role in the energy transition.\u0000 Captured anthropogenic CO2 can be permanently stored in saline aquifers and depleted reservoirs. Saline aquifers (normally unsuitable for industrial or human exploitation) offer the largest storage capacity; however, there is, usually, lack of geological characterization leading to high risks due to large uncertainty. On the other hand, depleted gas fields, close to economical life cessation, are deemed an excellent alternative as safe and long-term storage is already proven and immense geological characterisation has been gathered during production life. Moreover, there is great potential to repurpose the existing offshore infrastructure (pipelines, platforms, and wells) as to minimize capital expenditure and delaying decommissioning costs. Repurposing existing production systems can also be an efficient way to achieve rapid deployment of CCS at large scale.\u0000 In this paper, we present the key engineering challenges, risks, and opportunities in the re-use of existing oil and gas offshore infrastructure for CO2 transport and injection. We highlight the complex operational constraints and interactions between different components of the transportation network. The design and operation of the transportation network is governed by the following drivers:\u0000 Safe design Robust and flexible operation Minimize cost (or delay expenditure as long as possible) Minimize emissions of greenhouse gases associated to the operation of the transport network (i.e., energy efficiency) Start operation with minimum modifications","PeriodicalId":11217,"journal":{"name":"Day 4 Fri, March 25, 2022","volume":"155 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88041571","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}
Hazlan Abdul Hakim, Nooraini Mohamed, Kamri Jusoh, M. Annuar, Fakhrul Radzi Zahri, M. Q. Ahmad Ani, Azrul Mizam Ibrahim
In order to extract the remaining reserves from a depleted carbonate field as well as to explore the possibility of finding additional reserves in a new fault block, PETRONAS is required to drill an Extended Reach Drilling (ERD) well from the existing platform in the FX field. The new target block is located approximately 4 km from the existing platform. This paper summarizes the planning challenges as well as the solutions in delivering the ERD well in a carbonate reservoir. During the design phase, the team put a high emphasis in avoiding any complications while drilling an ERD well in a carbonate reservoir especially in managing severe or total losses. As such, the subsurface team came out with a novel approach in mapping the karst in the carbonate reservoir allowing optimum placement of the well trajectory. With the optimized target, the well was designed accordingly, addressing all the challenges that were raised during the detailed risk assessment such as hole cleaning issues, wellbore instability, Equivalent Circulating Density (ECD) management, Torque and Drag (T&D) during drilling as well as running casings/liner, cement integrity in high angle well etc. An ERD consultant was engaged to facilitate the design and execution phases. The final well design and implementation plans were finalized with the ERD consultant's assistance which addressed all the anticipated challenges. An Advanced 1D Mechanical Earth Model (MEM) was constructed with the latest offset data to determine the proper mud weight window to drill the ERD well. The finalized Torque and Drag simulation provided the necessary strategies in completing the well including expected drilling parameters as well as delivering the casing and liner to bottom. Ensuring cement integrity while managing ECD by implementing new technology was also planned. The new technologies and specific approaches implemented to deliver the ERD well in a carbonate reservoir include detailed Seismic analysis to detect and predict the presence of karst in the carbonate, Pseudo Catenary well trajectory to optimize the well trajectory, 9-5/8" liner full air flotation to get the liner to bottom, Definitive Survey While Drilling to reduce vertical uncertainties as well as minimizing the stationary time and flow diverter to ensure cement integrity especially in the high angle / horizontal sections.
{"title":"A Novel Engineering Approach in Drilling an ERD Well in a Carbonate Field, Malaysia","authors":"Hazlan Abdul Hakim, Nooraini Mohamed, Kamri Jusoh, M. Annuar, Fakhrul Radzi Zahri, M. Q. Ahmad Ani, Azrul Mizam Ibrahim","doi":"10.4043/31568-ms","DOIUrl":"https://doi.org/10.4043/31568-ms","url":null,"abstract":"\u0000 In order to extract the remaining reserves from a depleted carbonate field as well as to explore the possibility of finding additional reserves in a new fault block, PETRONAS is required to drill an Extended Reach Drilling (ERD) well from the existing platform in the FX field. The new target block is located approximately 4 km from the existing platform. This paper summarizes the planning challenges as well as the solutions in delivering the ERD well in a carbonate reservoir.\u0000 During the design phase, the team put a high emphasis in avoiding any complications while drilling an ERD well in a carbonate reservoir especially in managing severe or total losses. As such, the subsurface team came out with a novel approach in mapping the karst in the carbonate reservoir allowing optimum placement of the well trajectory. With the optimized target, the well was designed accordingly, addressing all the challenges that were raised during the detailed risk assessment such as hole cleaning issues, wellbore instability, Equivalent Circulating Density (ECD) management, Torque and Drag (T&D) during drilling as well as running casings/liner, cement integrity in high angle well etc. An ERD consultant was engaged to facilitate the design and execution phases.\u0000 The final well design and implementation plans were finalized with the ERD consultant's assistance which addressed all the anticipated challenges. An Advanced 1D Mechanical Earth Model (MEM) was constructed with the latest offset data to determine the proper mud weight window to drill the ERD well. The finalized Torque and Drag simulation provided the necessary strategies in completing the well including expected drilling parameters as well as delivering the casing and liner to bottom. Ensuring cement integrity while managing ECD by implementing new technology was also planned. The new technologies and specific approaches implemented to deliver the ERD well in a carbonate reservoir include detailed Seismic analysis to detect and predict the presence of karst in the carbonate, Pseudo Catenary well trajectory to optimize the well trajectory, 9-5/8\" liner full air flotation to get the liner to bottom, Definitive Survey While Drilling to reduce vertical uncertainties as well as minimizing the stationary time and flow diverter to ensure cement integrity especially in the high angle / horizontal sections.","PeriodicalId":11217,"journal":{"name":"Day 4 Fri, March 25, 2022","volume":"67 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77179333","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}
Claudine Champavere, E. Lacher, S. Moe, Gunasekaran Settiyannan, Egil Mulstad Skrivervik
This paper explains the technology development to date of subsea electric valve actuation solutions for subsea production systems and discusses the roadmap for the future. Key experiences, and how these solutions are gradually becoming standard choice for many operators is discussed, from the subsea industry first applications 20 years ago.
{"title":"State of the Art Subsea Electric Control Systems","authors":"Claudine Champavere, E. Lacher, S. Moe, Gunasekaran Settiyannan, Egil Mulstad Skrivervik","doi":"10.4043/31585-ms","DOIUrl":"https://doi.org/10.4043/31585-ms","url":null,"abstract":"\u0000 This paper explains the technology development to date of subsea electric valve actuation solutions for subsea production systems and discusses the roadmap for the future. Key experiences, and how these solutions are gradually becoming standard choice for many operators is discussed, from the subsea industry first applications 20 years ago.","PeriodicalId":11217,"journal":{"name":"Day 4 Fri, March 25, 2022","volume":"54 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"76649826","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}
In the current climate, cost reduction has been a major enabler for project sanction. With significant drilling activity planned in relatively benign environments offshore Malaysia, there were potential casing design optimisations, and hence cost reduction opportunities, in analyzing the relevant well planning data of such projects, with a view to further optimising the standardised 13-3/8" surface casing specifications that have historically been used in similar areas. Additionally, the feasibility of using 13-3/8" casing as slim conductor on platform development wells was investigated. Well planning data for a variety of projects planned for between 2022 and 2024, which planned to use the same 13-3/8" surface casing specification, were collated and boundary conditions were established for all of the key parameters. This standardised casing string was first assessed for suitability, and areas for potential optimisation were identified. Simplified casing load analyses optimisation were performed on this optimised 13-3/8" casing specification for typical collapse loads as laid out in the company's casing design standards, to assess its suitability. Generalized fatigue life analyses were also performed on the slim 13-3/8" conductor to try to prove viability of the concept. It was shown that collapse design is the controlling factor for the cost reduction initiatives through 13-3/8" casing specification optimization, especially in an environment of severely depleted reservoir (down to 3 ppg) in the reservoir section underneath the surface casing. This is exaggerated with conservative load assumptions that is used in the industry/company standards i.e., running mud weight, 50% to 100% evacuation, extreme low pore pressure assumption as low case prognosis etc. Combination of conservative collapse prohibited the casing specification to be optimized lower. This paper addresses the 13-3/8" casing optimization through fit for purpose collapse design approach. It was shown that the reduction of the casing specification for 13-3/8" surface casing in the majority of the projects studied was justified and acceptable based on the minimum design requirements for collapse loads. Additionally, cost savings of up to approximately 7% were observed for this reduction in 13-3/8" surface casing specification depending on connection qualification and casing manufacturer.
{"title":"Surface Casing Collapse Load Design Optimization Challenges for Highly Depleted Reservoir","authors":"Yun Thiam Yap, W. Wahi, S. Campbell","doi":"10.4043/31411-ms","DOIUrl":"https://doi.org/10.4043/31411-ms","url":null,"abstract":"\u0000 In the current climate, cost reduction has been a major enabler for project sanction. With significant drilling activity planned in relatively benign environments offshore Malaysia, there were potential casing design optimisations, and hence cost reduction opportunities, in analyzing the relevant well planning data of such projects, with a view to further optimising the standardised 13-3/8\" surface casing specifications that have historically been used in similar areas. Additionally, the feasibility of using 13-3/8\" casing as slim conductor on platform development wells was investigated.\u0000 Well planning data for a variety of projects planned for between 2022 and 2024, which planned to use the same 13-3/8\" surface casing specification, were collated and boundary conditions were established for all of the key parameters. This standardised casing string was first assessed for suitability, and areas for potential optimisation were identified. Simplified casing load analyses optimisation were performed on this optimised 13-3/8\" casing specification for typical collapse loads as laid out in the company's casing design standards, to assess its suitability. Generalized fatigue life analyses were also performed on the slim 13-3/8\" conductor to try to prove viability of the concept.\u0000 It was shown that collapse design is the controlling factor for the cost reduction initiatives through 13-3/8\" casing specification optimization, especially in an environment of severely depleted reservoir (down to 3 ppg) in the reservoir section underneath the surface casing. This is exaggerated with conservative load assumptions that is used in the industry/company standards i.e., running mud weight, 50% to 100% evacuation, extreme low pore pressure assumption as low case prognosis etc. Combination of conservative collapse prohibited the casing specification to be optimized lower.\u0000 This paper addresses the 13-3/8\" casing optimization through fit for purpose collapse design approach. It was shown that the reduction of the casing specification for 13-3/8\" surface casing in the majority of the projects studied was justified and acceptable based on the minimum design requirements for collapse loads. Additionally, cost savings of up to approximately 7% were observed for this reduction in 13-3/8\" surface casing specification depending on connection qualification and casing manufacturer.","PeriodicalId":11217,"journal":{"name":"Day 4 Fri, March 25, 2022","volume":"1 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77118232","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}
Rehan Ahmed, Rohana Jaafar, Alia Rashiqah Ab Rahman, Mohd Fikhri Fikhri Sabturani, Ahmad Naim A. Khairudin
Highlights the challenges faced by matured Offshore Operating Oil and Gas Asset during implementation or enhancement of the Integrity Operating Window (IOW) monitoring and proposed solutions to address the challenges. PETRONAS Upstream has embarked on an exercise of upgrading its IOW reporting in light of the increased number of Loss of Primary Containment (LOPC) incidents and premature equipment breakdown which has resulted in Unplanned Deferment (UPD) and Health, Safety and Environment (HSE) incidents. IOWs are sets of limits used to determine the different variables that could affect the integrity and reliability of a process unit. Comparative analyses are made between the implementation of an automated online system with Artificial Intelligence capabilities versus a moreconventional manual system. We explore the advantages and disadvantages of each of these approaches including the element of cost. Integration of Pi historian and laboratory information management system (LIMS) to the IOW module will help provide real-time data and analysis to the Online and Manually implemented risk-based inspection (RBI) system. Since this is currently an ongoing exercise, the results will be based on the achievement of key performance indices, including a marked change in equipment uptime andavailability. The expectations are to upskill operations and Engineering teams in implementing andadjusting the IOW to the needs of the facility, extending asset life, and adjusting the parameters based onmachine learning or manual adjustments. Note that upgraded IOW manuals have been developed and rolled out for this pilot study, and all lessons learnt will be incorporated into any future enterprise rollout. The implementation of IOW monitoring and reporting are interfacing with other digital solutions to achieve a seamless and autonomous work process. Among digital solutions interfacing with the IOW database are Predictive Revitalization of Instrument to Maximize Efficiency (PRIME), LIMS and other in-house digital solutions such as online Corrosion Management Program and Risk-based Inspection (RBI).
{"title":"Challenges in Implementing an Integrity Operating Window IOW Program in Offshore Operations","authors":"Rehan Ahmed, Rohana Jaafar, Alia Rashiqah Ab Rahman, Mohd Fikhri Fikhri Sabturani, Ahmad Naim A. Khairudin","doi":"10.4043/31340-ms","DOIUrl":"https://doi.org/10.4043/31340-ms","url":null,"abstract":"\u0000 \u0000 \u0000 Highlights the challenges faced by matured Offshore Operating Oil and Gas Asset during implementation or enhancement of the Integrity Operating Window (IOW) monitoring and proposed solutions to address the challenges. PETRONAS Upstream has embarked on an exercise of upgrading its IOW reporting in light of the increased number of Loss of Primary Containment (LOPC) incidents and premature equipment breakdown which has resulted in Unplanned Deferment (UPD) and Health, Safety and Environment (HSE) incidents.\u0000 \u0000 \u0000 \u0000 IOWs are sets of limits used to determine the different variables that could affect the integrity and reliability of a process unit. Comparative analyses are made between the implementation of an automated online system with Artificial Intelligence capabilities versus a moreconventional manual system. We explore the advantages and disadvantages of each of these approaches including the element of cost. Integration of Pi historian and laboratory information management system (LIMS) to the IOW module will help provide real-time data and analysis to the Online and Manually implemented risk-based inspection (RBI) system.\u0000 \u0000 \u0000 \u0000 Since this is currently an ongoing exercise, the results will be based on the achievement of key performance indices, including a marked change in equipment uptime andavailability. The expectations are to upskill operations and Engineering teams in implementing andadjusting the IOW to the needs of the facility, extending asset life, and adjusting the parameters based onmachine learning or manual adjustments. Note that upgraded IOW manuals have been developed and rolled out for this pilot study, and all lessons learnt will be incorporated into any future enterprise rollout.\u0000 \u0000 \u0000 \u0000 The implementation of IOW monitoring and reporting are interfacing with other digital solutions to achieve a seamless and autonomous work process. Among digital solutions interfacing with the IOW database are Predictive Revitalization of Instrument to Maximize Efficiency (PRIME), LIMS and other in-house digital solutions such as online Corrosion Management Program and Risk-based Inspection (RBI).\u0000","PeriodicalId":11217,"journal":{"name":"Day 4 Fri, March 25, 2022","volume":"30 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78862370","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}
Ahmad Razali Yaakob, Awaluddin Berwanto, I. Ismail, M. Rashid, M. S. H. Ahmad Zawawi, Nadiah Abdul Hamid, R. Khan, Steven Hammond
PETRONAS currently operates several subsea fields in Malaysian water. In 2019, PETRONAS embarked on developing Subsea Integrity Management (SubSIM) for Malaysian operations, to better understand and manage the operating risks of subsea assets throughout the lifecycle of a subsea field development. Subsea Integrity Management (SubSIM) is a Management System which ensures appropriate processes and procedures are applied throughout the subsea asset life cycle, from commissioning all the way through to decommissioning, to ensure that through a process of risk management, the subsea asset fitness-for-purpose will be upheld. PETRONAS has also initiated a Data-Driven Maintenance workstream whereby the PETRONAS's Upstream Inspection and Maintenance Assurance Guideline (U-IMAGe) has been determined as a key enabler for PETRONAS top-quartile oil and gas industry performance. U-IMAGe is a standard suite of guidelines for the implementation of inspection and maintenance programs in PETRONAS upstream production facilities, where subsea assets are part of this (PETRONAS, 2018b). An essential element of U-IMAGe is an effective data management to drive inspection and maintenance strategy. In order to ensure effective delivery of SubSIM and to support and strengthen the U-IMAGe implementation, PETRONAS has embarked on a Subsea Risk Based Underwater Inspection (RBUI) strategy and methodology for its subsea assets (PETRONAS 2020). As part of SubSIM that supports the U-IMAGe implementation, the Subsea RBUI approach prioritizes and optimizes inspection efforts by balancing risk costs (people, safety, environmental or business related) with inspection costs, and allows a better understanding of risk levels over the intended life of the subsea asset to initiate cost effective remedial actions. The Subsea RBUI involves identification of threats on a subsea asset, development of the integrity loops and risk assessments (PETRONAS 2020). The risk assessments are then used as a tool to develop suitable inspection plans. The risk assessments will also be used to optimise the operational inspection plans and frequencies, focusing on the safety, environmental and financial risks as well as the inspection costs. This paper will address the methodology and tools used to conduct Subsea Risk Based Underwater Inspection (RBUI) planning for subsea asset within PETRONAS Operations.
{"title":"Risk Based Underwater Inspection RBUI Methodology for Subsea Integrity Management SubSIM of Subsea Assets in Malaysian Operations","authors":"Ahmad Razali Yaakob, Awaluddin Berwanto, I. Ismail, M. Rashid, M. S. H. Ahmad Zawawi, Nadiah Abdul Hamid, R. Khan, Steven Hammond","doi":"10.4043/31354-ms","DOIUrl":"https://doi.org/10.4043/31354-ms","url":null,"abstract":"\u0000 PETRONAS currently operates several subsea fields in Malaysian water. In 2019, PETRONAS embarked on developing Subsea Integrity Management (SubSIM) for Malaysian operations, to better understand and manage the operating risks of subsea assets throughout the lifecycle of a subsea field development.\u0000 Subsea Integrity Management (SubSIM) is a Management System which ensures appropriate processes and procedures are applied throughout the subsea asset life cycle, from commissioning all the way through to decommissioning, to ensure that through a process of risk management, the subsea asset fitness-for-purpose will be upheld. PETRONAS has also initiated a Data-Driven Maintenance workstream whereby the PETRONAS's Upstream Inspection and Maintenance Assurance Guideline (U-IMAGe) has been determined as a key enabler for PETRONAS top-quartile oil and gas industry performance.\u0000 U-IMAGe is a standard suite of guidelines for the implementation of inspection and maintenance programs in PETRONAS upstream production facilities, where subsea assets are part of this (PETRONAS, 2018b). An essential element of U-IMAGe is an effective data management to drive inspection and maintenance strategy. In order to ensure effective delivery of SubSIM and to support and strengthen the U-IMAGe implementation, PETRONAS has embarked on a Subsea Risk Based Underwater Inspection (RBUI) strategy and methodology for its subsea assets (PETRONAS 2020). As part of SubSIM that supports the U-IMAGe implementation, the Subsea RBUI approach prioritizes and optimizes inspection efforts by balancing risk costs (people, safety, environmental or business related) with inspection costs, and allows a better understanding of risk levels over the intended life of the subsea asset to initiate cost effective remedial actions.\u0000 The Subsea RBUI involves identification of threats on a subsea asset, development of the integrity loops and risk assessments (PETRONAS 2020). The risk assessments are then used as a tool to develop suitable inspection plans. The risk assessments will also be used to optimise the operational inspection plans and frequencies, focusing on the safety, environmental and financial risks as well as the inspection costs.\u0000 This paper will address the methodology and tools used to conduct Subsea Risk Based Underwater Inspection (RBUI) planning for subsea asset within PETRONAS Operations.","PeriodicalId":11217,"journal":{"name":"Day 4 Fri, March 25, 2022","volume":"46 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"75320367","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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