Rex Lun Kai Lo, Sion Dan Tiyor, Aizal Haziq Bin Abdul Razak, Ahmad Hakam Bin Abdul Razak
The current global low oil price environment has driven many operators to consider having a quicker and more efficient operations and reduction of the well construction cost. Recently in Field A which was located in offshore Sarawak, Malaysia, four monobore completion wells were successfully batch drilled and cemented offline through ingenious planning. This involves skidding of rig floor away from the well to allow access for the cementing operations to be performed underneath the rig floor simultaneously while drilling operations are allowed to resume above it. This paper will discuss about the offline activities performed, well barriers classification and the offline cementing techniques including the cementing design slurries employed from the top hole section until the final tubing section cementing. Offline activities were able to be performed before and after the rig skidding package is moved from one slot to another, thus reducing the overall project time. These activities included but were not limited to offline cementing, wellhead installation and tubular rack back on the derrick. Once the conductor was cleaned to the shoe, casing was run and the rig will skid to the next conductor slot and offline cementing adapters were installed on the wellhead. As the rig continues with the drilling operations, cementing operations will be performed offline below the rig floor. For the conductor section, 3 conduits were run and cemented simultaneously within a conductor offline. For the next section, the intermediate hole was drilled to its section TD, casing was run to bottom and cement head was installed offline after the rig skidded to next well. The next operation which included mud circulation and casing cementing was also performed offline. These same operational steps were repeated for all wells including the offline tubing cementing operations. The cement slurries were designed as per well requirement which was a conventional Class-G cement slurry design for the conductor and the intermediate section. LCM material and sealing spacer were prepared onboard to mitigate any potential losses which could happen during drilling or cementing operations. For the tubing cementing section, self-healing cement system was introduced to ensure well integrity and zonal isolation is guaranteed for the life of the well. All four wells were drilled and completed within 34 days, resulting in a time saving of 30 hours just for cementing operations; which was 23 % of cumulative time savings. This drilling and cementing approach will be a footprint to the operator for all future development wells.
{"title":"Full Offline Well Cementing Implementation Resulting in Significant Time Savings and Improvement in Operational Efficiency","authors":"Rex Lun Kai Lo, Sion Dan Tiyor, Aizal Haziq Bin Abdul Razak, Ahmad Hakam Bin Abdul Razak","doi":"10.4043/31545-ms","DOIUrl":"https://doi.org/10.4043/31545-ms","url":null,"abstract":"\u0000 The current global low oil price environment has driven many operators to consider having a quicker and more efficient operations and reduction of the well construction cost. Recently in Field A which was located in offshore Sarawak, Malaysia, four monobore completion wells were successfully batch drilled and cemented offline through ingenious planning. This involves skidding of rig floor away from the well to allow access for the cementing operations to be performed underneath the rig floor simultaneously while drilling operations are allowed to resume above it. This paper will discuss about the offline activities performed, well barriers classification and the offline cementing techniques including the cementing design slurries employed from the top hole section until the final tubing section cementing.\u0000 Offline activities were able to be performed before and after the rig skidding package is moved from one slot to another, thus reducing the overall project time. These activities included but were not limited to offline cementing, wellhead installation and tubular rack back on the derrick. Once the conductor was cleaned to the shoe, casing was run and the rig will skid to the next conductor slot and offline cementing adapters were installed on the wellhead. As the rig continues with the drilling operations, cementing operations will be performed offline below the rig floor.\u0000 For the conductor section, 3 conduits were run and cemented simultaneously within a conductor offline. For the next section, the intermediate hole was drilled to its section TD, casing was run to bottom and cement head was installed offline after the rig skidded to next well. The next operation which included mud circulation and casing cementing was also performed offline. These same operational steps were repeated for all wells including the offline tubing cementing operations.\u0000 The cement slurries were designed as per well requirement which was a conventional Class-G cement slurry design for the conductor and the intermediate section. LCM material and sealing spacer were prepared onboard to mitigate any potential losses which could happen during drilling or cementing operations. For the tubing cementing section, self-healing cement system was introduced to ensure well integrity and zonal isolation is guaranteed for the life of the well.\u0000 All four wells were drilled and completed within 34 days, resulting in a time saving of 30 hours just for cementing operations; which was 23 % of cumulative time savings. This drilling and cementing approach will be a footprint to the operator for all future development wells.","PeriodicalId":11217,"journal":{"name":"Day 4 Fri, March 25, 2022","volume":"88 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78627337","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}
To survive in oil and gas industry, Operating Expenditure (OPEX) must be well controlled for profit maximization. One of the most resource-utilizing activities in Zawtika offshore field is remote wellhead platform (WHP) visit which was previously bi-weekly for operations activities, maintenance activities such as preventive maintenance (PM), etc., inspection activities like flowline erosion monitoring and wells annulus pressure monitoring, thereby high Marine Gas Oil (MGO) consumption due to vessel trips/routes and increased in manpower utilization. Currently, Zawtika Offshore field has a main platform called Zawtika Processing and Living Quarter Platform (ZPQ) and 10 remote wellhead platforms (WHPs). When it is considered for future, there will be more remote wellhead platforms (WHPs) which will increase more OPEX for new phases. To tackle this, this paper describes that Myanmar Asset Zawtika launched a LEAN (Lean Six Sigma) initiative based on safely and cost-effectively reducing the frequency of remote wellhead platforms (WHP) visits, using collaborative 52 week planning to lessen OPEX cost from MGO consumption and manpower requirements as well as maintaining Zawtika Reliability and Asset Integrity (RAI) with the view of achieving resource optimization. This paper also illustrates the effective planning process across multiple functions/disciplines within different sessions/departments and at various locations called 52 weeks plan incorporating with "Integrated Operation Plan (IOP)" guideline established for the first time for Zawtika offshore field to help optimize the resources and activities plan of individual field or asset by ensuring the safety while sustaining the integrity. This paper also outlines the reduction in Greenhouse Gas (GHG) calculated back from MGO reduction which is one of PTTEP strategies for Sustainable Development (SD).
{"title":"The Achievement of Resource Optimisation on Lean Remote Wellhead Platform Visit with Collaborative 52 Weeks Plan","authors":"Thin Zar Soe, Anucha Leelaratsameephanit, Phanuwat Jitputti, Sayan Charoensook, Alongkorn Rodthip, Sathit Chitkla, Apichai On-Dam, Perapon Sirijitt","doi":"10.4043/31426-ms","DOIUrl":"https://doi.org/10.4043/31426-ms","url":null,"abstract":"\u0000 To survive in oil and gas industry, Operating Expenditure (OPEX) must be well controlled for profit maximization. One of the most resource-utilizing activities in Zawtika offshore field is remote wellhead platform (WHP) visit which was previously bi-weekly for operations activities, maintenance activities such as preventive maintenance (PM), etc., inspection activities like flowline erosion monitoring and wells annulus pressure monitoring, thereby high Marine Gas Oil (MGO) consumption due to vessel trips/routes and increased in manpower utilization. Currently, Zawtika Offshore field has a main platform called Zawtika Processing and Living Quarter Platform (ZPQ) and 10 remote wellhead platforms (WHPs). When it is considered for future, there will be more remote wellhead platforms (WHPs) which will increase more OPEX for new phases.\u0000 To tackle this, this paper describes that Myanmar Asset Zawtika launched a LEAN (Lean Six Sigma) initiative based on safely and cost-effectively reducing the frequency of remote wellhead platforms (WHP) visits, using collaborative 52 week planning to lessen OPEX cost from MGO consumption and manpower requirements as well as maintaining Zawtika Reliability and Asset Integrity (RAI) with the view of achieving resource optimization. This paper also illustrates the effective planning process across multiple functions/disciplines within different sessions/departments and at various locations called 52 weeks plan incorporating with \"Integrated Operation Plan (IOP)\" guideline established for the first time for Zawtika offshore field to help optimize the resources and activities plan of individual field or asset by ensuring the safety while sustaining the integrity. This paper also outlines the reduction in Greenhouse Gas (GHG) calculated back from MGO reduction which is one of PTTEP strategies for Sustainable Development (SD).","PeriodicalId":11217,"journal":{"name":"Day 4 Fri, March 25, 2022","volume":"4 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"76100287","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}
Annas Omar Mohammad, A. A. Bakar, Khairil Azam Mohd Khaidzir, Donald Robert McKen, L. Yeow, T. McCluskey
This paper describes the implementation of Pressurized Mud Cap Drilling (PMCD) and Casing Downhole Isolation Valve (CDIV) technology for the Pegaga Development Project to mitigate heavy fluid losses, allowing safe and effective drilling operations to reach well TD. The project consists of seven gas producers (deviated wells), drilled using a jack-up rig from a 10-slot wellhead deck. This paper also describes the planning and operational challenges met to ensure the smooth application of PMCD, starting with selection of the rig and supply vessels, challenges related to adverse weather conditions, long distances between the supply base and drilling location, sufficient mud tank capacity, continuous supply of Light Annular Mud (LAM) for PMCD operations and pandemic related personnel movement restrictions. A continuous learning process was applied for the drilling team where challenges experienced in drilling the first well in PMCD mode and lessons learned were captured and applied to the subsequent wells to improve drilling results. A comprehensive decision tree was established and refined to help the offshore team to make quick decisions when needed to switch to PMCD mode. The Pegaga gas field is located in Block SK320 in the Central Luconia Province, off the coast of Sarawak, offshore Malaysia. The main reservoir is a Pinnacle Carbonate reservoir, which is made up of vugular/karstified carbonates that are likely to cause severe or total losses. The top-hole sections for all seven wells were batched drilled before the PMCD system was rigged up prior to commencing the 12-1/4" intermediate and 8-1/2" reservoir hole sections. The 12-1/4" sections were drilled to above the target gas reservoir carbonate formations, with the PMCD system on standby in case the carbonate formations and severe losses were encountered shallower than prognosed. A single 9-5/8" CDIV (NACE standard) was run with the 9-5/8" × 10-3/4" casing string and permanently set (cemented) in the 12-1/4" open hole, which was the first time this had been done in Malaysia. The CDIVs were set in the open hole to reduce the potential volume of gas below the CDIV and reduce the mud volume required for tripping in PMCD conditions, while increasing the safety and efficiency of PMCD operations. Seven wells were drilled to TD, five in PMCD mode, two conventionally. The lower and upper completions were run and set on six wells, with four of the lower completions run and set in PMCD mode. The CDIV was used to isolate the open hole for tripping out the BHA and running in the lower completion on two of the PMCD wells, while the other three used the top kill method.
{"title":"Pegaga Development Drilling Operations with PMCD and CDIV Applications","authors":"Annas Omar Mohammad, A. A. Bakar, Khairil Azam Mohd Khaidzir, Donald Robert McKen, L. Yeow, T. McCluskey","doi":"10.4043/31436-ms","DOIUrl":"https://doi.org/10.4043/31436-ms","url":null,"abstract":"\u0000 This paper describes the implementation of Pressurized Mud Cap Drilling (PMCD) and Casing Downhole Isolation Valve (CDIV) technology for the Pegaga Development Project to mitigate heavy fluid losses, allowing safe and effective drilling operations to reach well TD. The project consists of seven gas producers (deviated wells), drilled using a jack-up rig from a 10-slot wellhead deck.\u0000 This paper also describes the planning and operational challenges met to ensure the smooth application of PMCD, starting with selection of the rig and supply vessels, challenges related to adverse weather conditions, long distances between the supply base and drilling location, sufficient mud tank capacity, continuous supply of Light Annular Mud (LAM) for PMCD operations and pandemic related personnel movement restrictions.\u0000 A continuous learning process was applied for the drilling team where challenges experienced in drilling the first well in PMCD mode and lessons learned were captured and applied to the subsequent wells to improve drilling results. A comprehensive decision tree was established and refined to help the offshore team to make quick decisions when needed to switch to PMCD mode.\u0000 The Pegaga gas field is located in Block SK320 in the Central Luconia Province, off the coast of Sarawak, offshore Malaysia. The main reservoir is a Pinnacle Carbonate reservoir, which is made up of vugular/karstified carbonates that are likely to cause severe or total losses.\u0000 The top-hole sections for all seven wells were batched drilled before the PMCD system was rigged up prior to commencing the 12-1/4\" intermediate and 8-1/2\" reservoir hole sections. The 12-1/4\" sections were drilled to above the target gas reservoir carbonate formations, with the PMCD system on standby in case the carbonate formations and severe losses were encountered shallower than prognosed. A single 9-5/8\" CDIV (NACE standard) was run with the 9-5/8\" × 10-3/4\" casing string and permanently set (cemented) in the 12-1/4\" open hole, which was the first time this had been done in Malaysia. The CDIVs were set in the open hole to reduce the potential volume of gas below the CDIV and reduce the mud volume required for tripping in PMCD conditions, while increasing the safety and efficiency of PMCD operations.\u0000 Seven wells were drilled to TD, five in PMCD mode, two conventionally. The lower and upper completions were run and set on six wells, with four of the lower completions run and set in PMCD mode. The CDIV was used to isolate the open hole for tripping out the BHA and running in the lower completion on two of the PMCD wells, while the other three used the top kill method.","PeriodicalId":11217,"journal":{"name":"Day 4 Fri, March 25, 2022","volume":"11 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89285356","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}
Various type of nanoparticles has been studied in last decade for improve oil recovery purpose and observed its mechanisms of displacing oil concluded as disjoining pressure that involved wettability alteration, log-jamming, and viscosity effect. This paper focus on the investigation of new potential mechanism of nanoparticles to improve oil recovery with study case in an offshore Malaysian oilfield. The silica-based nanoparticles were used in this study, and additives of polymer and surfactant were involved to improve stability of fluid and observe any potential of novel mechanism. The nanoparticles were characterized under electron microscope, dispersed, and sonicated in saline water as replicated of injected water to be nanofluids for particular concentrations. A degassed crude oil from Malaysian field was used with viscosity of 3 cP. All fluids measured their rheology and fluid properties. A polymer additive was used to improve particles stability dispersed in saline water. Meanwhile, a surfactant additive was added into the formulation to observe any synergetic effect of displacing oil. The interfacial tension (IFT), optical contact angle (OCA), and relative permeability measurement using native cores at reservoir condition to observe potential novel mechanism. The additive showed better performance in term of stability and wettability alteration through IFT reduction and reducing contact angle to render more water-wet through dynamic OCA measurement. The synergistic effect was observed when surfactant added into the nanofluids, and classified as fragmentation. The IFT reduced significantly when nanofluids contact with crude oil from field after 10-20 minutes and oil drop started disintegration. This phenomenon was identified consistently through OCA measurement. It altered surface of rock from medium water-wet to strong water-wet. The relative permeability measurement showed consistent wettability alteration that the curve shifted from water-wet to be stronger water-wet. This observation not only showcases the great potential of nanoparticles but also providing a new reference for synthesizing and formulating nanoparticles as a technique to improve oil recovery.
{"title":"Nanofluids Development to Improve Oil Recovery: A Synergistic Effect Investigation","authors":"L. Hendraningrat, N. Razali, Chee Sheau Chien","doi":"10.4043/31625-ms","DOIUrl":"https://doi.org/10.4043/31625-ms","url":null,"abstract":"\u0000 Various type of nanoparticles has been studied in last decade for improve oil recovery purpose and observed its mechanisms of displacing oil concluded as disjoining pressure that involved wettability alteration, log-jamming, and viscosity effect. This paper focus on the investigation of new potential mechanism of nanoparticles to improve oil recovery with study case in an offshore Malaysian oilfield.\u0000 The silica-based nanoparticles were used in this study, and additives of polymer and surfactant were involved to improve stability of fluid and observe any potential of novel mechanism. The nanoparticles were characterized under electron microscope, dispersed, and sonicated in saline water as replicated of injected water to be nanofluids for particular concentrations. A degassed crude oil from Malaysian field was used with viscosity of 3 cP. All fluids measured their rheology and fluid properties. A polymer additive was used to improve particles stability dispersed in saline water. Meanwhile, a surfactant additive was added into the formulation to observe any synergetic effect of displacing oil. The interfacial tension (IFT), optical contact angle (OCA), and relative permeability measurement using native cores at reservoir condition to observe potential novel mechanism.\u0000 The additive showed better performance in term of stability and wettability alteration through IFT reduction and reducing contact angle to render more water-wet through dynamic OCA measurement. The synergistic effect was observed when surfactant added into the nanofluids, and classified as fragmentation. The IFT reduced significantly when nanofluids contact with crude oil from field after 10-20 minutes and oil drop started disintegration. This phenomenon was identified consistently through OCA measurement. It altered surface of rock from medium water-wet to strong water-wet. The relative permeability measurement showed consistent wettability alteration that the curve shifted from water-wet to be stronger water-wet.\u0000 This observation not only showcases the great potential of nanoparticles but also providing a new reference for synthesizing and formulating nanoparticles as a technique to improve oil recovery.","PeriodicalId":11217,"journal":{"name":"Day 4 Fri, March 25, 2022","volume":"15 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78387840","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}
Offshore marginal fields historically have been discoveries that have not been pursued due to factors such as size of field, lack of infrastructures, product incompatibility with the nearest host or uneconomic assets. However, according to Energy Information Administration Report (2021), Malaysia’s total liquid field production have been declining since reaching peak of 762,000 b/d in 20161. To offset the decline, marginal fields are being considered. This trend is also being echoed in other Asian oil and gas producing nations. Through the advancement of technology, standardization and focus on cost control during the last oil downturn; marginal fields are now seen as economically viable and are being sanctioned to keep up with the falling production demand. These fields are typically developed via the use of minimum often unmanned wellhead platform or through Jack up Shallow water Subsea systems. It is a vital consideration for the operator to make in selecting either of the methodologies or a combination of the two. The offshore marginal fields being classified here are usually based in shallower water depth (<100m) and have 7-12 years production lifespan. The aim of this paper is to highlight key technical considerations that will assist the operator in making informed decision to develop the marginal fields using Integrated offshore solutions (IOS). Case study scenario is presented in which the operator was able to optimize their field layout, perform equipment selection by leveraging standardization and engineering and focus on minimizing installation and completion timelines.
{"title":"Marginal Field Development: Evaluation of Offshore Developments","authors":"Ekalavya Arora.","doi":"10.4043/31520-ms","DOIUrl":"https://doi.org/10.4043/31520-ms","url":null,"abstract":"\u0000 Offshore marginal fields historically have been discoveries that have not been pursued due to factors such as size of field, lack of infrastructures, product incompatibility with the nearest host or uneconomic assets. However, according to Energy Information Administration Report (2021), Malaysia’s total liquid field production have been declining since reaching peak of 762,000 b/d in 20161. To offset the decline, marginal fields are being considered. This trend is also being echoed in other Asian oil and gas producing nations.\u0000 Through the advancement of technology, standardization and focus on cost control during the last oil downturn; marginal fields are now seen as economically viable and are being sanctioned to keep up with the falling production demand. These fields are typically developed via the use of minimum often unmanned wellhead platform or through Jack up Shallow water Subsea systems. It is a vital consideration for the operator to make in selecting either of the methodologies or a combination of the two. The offshore marginal fields being classified here are usually based in shallower water depth (<100m) and have 7-12 years production lifespan.\u0000 The aim of this paper is to highlight key technical considerations that will assist the operator in making informed decision to develop the marginal fields using Integrated offshore solutions (IOS). Case study scenario is presented in which the operator was able to optimize their field layout, perform equipment selection by leveraging standardization and engineering and focus on minimizing installation and completion timelines.","PeriodicalId":11217,"journal":{"name":"Day 4 Fri, March 25, 2022","volume":"13 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78454660","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}
M. Mahmoudpour, P. Pourafshary, B. Moradi, M. Rasaei, K. Hassani
Smart water flooding has recently been considered as an attractive EOR method due to its lack of expensive chemicals. Alterations in oil/brine/rock interactions in porous media, such as wettability by smart water, affects oil recovery. Different mechanisms, such as wettability alteration, changes in the viscosity, changes in the interfacial tension and control of small particle migration, make nanofluid injection an effective method. In this study, the injection of a combination of smart water and silica nanoparticles is investigated for EOR. Different characterization measurements, such as contact angle, interfacial tension, zeta potential, X-ray diffraction, viscosity and core flooding are performed to investigate the effect of the developed method on oil recovery and the mechanisms changing sweep efficiency. Our results show that the highest oil recovery is achieved by the injection of smart water with a high concentration of sulfate ions combined with silica nanoparticles with a concentration of 0.1 wt.%. The addition of silica nanoparticles to smart water improves the wettability alteration mechanism, as well as increasing the fluid viscosity and affecting the sweep efficiency. Therefore, the application of the developed hybrid method exhibits distinct advantages compared to stand-alone smart water flooding.
{"title":"Reduction of Residual Oil in Oil-Wet Carbonate Formations by Application of Hybrid Smart Water/Silica Nanofluid Enhanced Oil Recovery Method","authors":"M. Mahmoudpour, P. Pourafshary, B. Moradi, M. Rasaei, K. Hassani","doi":"10.4043/31488-ms","DOIUrl":"https://doi.org/10.4043/31488-ms","url":null,"abstract":"Smart water flooding has recently been considered as an attractive EOR method due to its lack of expensive chemicals. Alterations in oil/brine/rock interactions in porous media, such as wettability by smart water, affects oil recovery. Different mechanisms, such as wettability alteration, changes in the viscosity, changes in the interfacial tension and control of small particle migration, make nanofluid injection an effective method. In this study, the injection of a combination of smart water and silica nanoparticles is investigated for EOR. Different characterization measurements, such as contact angle, interfacial tension, zeta potential, X-ray diffraction, viscosity and core flooding are performed to investigate the effect of the developed method on oil recovery and the mechanisms changing sweep efficiency. Our results show that the highest oil recovery is achieved by the injection of smart water with a high concentration of sulfate ions combined with silica nanoparticles with a concentration of 0.1 wt.%. The addition of silica nanoparticles to smart water improves the wettability alteration mechanism, as well as increasing the fluid viscosity and affecting the sweep efficiency. Therefore, the application of the developed hybrid method exhibits distinct advantages compared to stand-alone smart water flooding.","PeriodicalId":11217,"journal":{"name":"Day 4 Fri, March 25, 2022","volume":"2 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84403787","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}
This paper describes the study of the first field in Malaysia for Carbon Capture and Storage (CCS) deployment by PETRONAS. PETRONAS has the ambition to make Malaysia a regional carbon storage hub and with that in mind, has the strategic plan for CCS deployment across the depleted gas fields in Malaysia with an estimate of 46 trillion cubic feet of storage volume in total. Sarawak Basin, Malaysia has a large numbers of hydrocarbon fields with high CO2 content which are yet to be developed. CCS is required for developing these high CO2 fields to be in line with net zero carbon direction of PETRONAS. After initial screening and risk management assessment, some of the depleted carbonate fields in the region are considered for the next phase of study related to the deployment of CO2 storage. The field discussed in this paper is believed to have common strong aquifer with neighbouring fields and has a highly heterogeneous reservoir. It also has anumber of extensive and localized baffles/barriers together with highly karstified areas, resulting in significant variations of reservoir characteristics and hence, dramatically affect the flow behaviour in the reservoir, in terms of pressure and water breakthrough. With its high porosity and permeability properties, high compaction and subsidence resulted from pore collapse phenomenon was observed in the reservoir and seabed, respectively. These behaviours need to be captured accurately during the CCS assessment for a reliable estimation of hydrocarbon in place, hydrocarbon interval and aquifer pressures, reservoir compaction, seabed subsidence and hence, the CO2 storage capacity. Dynamic reservoir simulation coupled with geomechanical modelling was used in the study to accurately predict the reservoir and overburden behaviours in the complex reservoir which was necessary for the CO2 storage capacity assessment. In the 2-way fully coupled dynamic-geomechanics modelling, geomechanical analysis is conducted to evaluate the field behaviour including reservoir compaction, seabed subsidence, fault stability and caprock integrity. With the change in the pressure and temperature, either by production or injection, the reservoir stress will change with associated deformation which in turn change the porosity and permeability which will subsequently impact the new pressure distribution and corresponding compaction and subsidence. In addition, the stress changes could result in fault reactivation and caprock integrity breach. Due to the interaction, the stress state was[WT1] updated by coupling the effects of geomechanics on reservoir simulation, so that the compaction and stress changes in the field can be honoured to accurately match the seabed subsidence and reservoir pressure distribution. These enable robust prediction of the storage capacity of the reservoir as well as field integrity. The 2-way fully coupled dynamic-geomechanics study results drive key decisions in the planning of the CCS strategy development
{"title":"CO2 Storage Assessment in a Malaysian Depleted Carbonate Reservoir With 2-Way Fully Coupled Dynamic-Geomechanics Modeling for Safe Long-Term Storage","authors":"M. A. Mustafa, S. S. M Ali, M. H. Yakup, C. Tan","doi":"10.4043/31414-ms","DOIUrl":"https://doi.org/10.4043/31414-ms","url":null,"abstract":"\u0000 This paper describes the study of the first field in Malaysia for Carbon Capture and Storage (CCS) deployment by PETRONAS. PETRONAS has the ambition to make Malaysia a regional carbon storage hub and with that in mind, has the strategic plan for CCS deployment across the depleted gas fields in Malaysia with an estimate of 46 trillion cubic feet of storage volume in total. Sarawak Basin, Malaysia has a large numbers of hydrocarbon fields with high CO2 content which are yet to be developed. CCS is required for developing these high CO2 fields to be in line with net zero carbon direction of PETRONAS. After initial screening and risk management assessment, some of the depleted carbonate fields in the region are considered for the next phase of study related to the deployment of CO2 storage. The field discussed in this paper is believed to have common strong aquifer with neighbouring fields and has a highly heterogeneous reservoir. It also has anumber of extensive and localized baffles/barriers together with highly karstified areas, resulting in significant variations of reservoir characteristics and hence, dramatically affect the flow behaviour in the reservoir, in terms of pressure and water breakthrough. With its high porosity and permeability properties, high compaction and subsidence resulted from pore collapse phenomenon was observed in the reservoir and seabed, respectively. These behaviours need to be captured accurately during the CCS assessment for a reliable estimation of hydrocarbon in place, hydrocarbon interval and aquifer pressures, reservoir compaction, seabed subsidence and hence, the CO2 storage capacity. Dynamic reservoir simulation coupled with geomechanical modelling was used in the study to accurately predict the reservoir and overburden behaviours in the complex reservoir which was necessary for the CO2 storage capacity assessment. In the 2-way fully coupled dynamic-geomechanics modelling, geomechanical analysis is conducted to evaluate the field behaviour including reservoir compaction, seabed subsidence, fault stability and caprock integrity. With the change in the pressure and temperature, either by production or injection, the reservoir stress will change with associated deformation which in turn change the porosity and permeability which will subsequently impact the new pressure distribution and corresponding compaction and subsidence. In addition, the stress changes could result in fault reactivation and caprock integrity breach. Due to the interaction, the stress state was[WT1] updated by coupling the effects of geomechanics on reservoir simulation, so that the compaction and stress changes in the field can be honoured to accurately match the seabed subsidence and reservoir pressure distribution. These enable robust prediction of the storage capacity of the reservoir as well as field integrity. The 2-way fully coupled dynamic-geomechanics study results drive key decisions in the planning of the CCS strategy development ","PeriodicalId":11217,"journal":{"name":"Day 4 Fri, March 25, 2022","volume":"63 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"76381462","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}
K. A. Karim, Md Anuar Desa, Mohd Hailmi Othman, Hayati Hussien
A lateral buckling mitigation design solution had been proposed for PETRONAS project to control pipeline expansion along a proposed 28" gas pipeline. Unfortunately, the design which considers typical conservative approaches, had lead to excessive addition cost beyond the expected amount of Final Investment Decision (FID) and project sanction. Moreover, the mitigation scheme had been proposed without adequate study of alternative options by rationalization of various pipeline design parameters including design pressure and temperature profile, pipe WT, CWC thickness, soil data which may involve influencing other disciplines. The proposed solution also requires additional cost to offshore construction work. This paper provides insights on the assessment and design approaches carried out to optimize lateral buckling solution for the 28" offshore gas export pipeline. As the issue had come about when the carbon steel linepipe bidding process was almost completed, the pipeline project team had limited wall thickness available. With that in mind, PETRONAS’s pipeline in-house engineering team had performed probability assessment to identify the characteristic VAS along the pipeline. This approach was taken to reduce the previous conservative assumption whereby only single isolation buckling case has been introduced. For the purpose of lowering the pipeline temperature profile, an option of utilizing mother pipe for bend wall thickness at the hot end area without concrete coating was investigated. The study aimed to get a combination of wall thicknesses, with and without concrete weight coating that allow uncontrolled buckling formation within the safety limit so that additional offshore construction work can be eliminated. All the assessment was according to DNV-RP-F110 and DNV-OS-F101 limit state requirement. The characteristic VAS determined from probability assessment is much shorter compare to conservative assumption of isolated single buckle formation. The expansion issue along the proposed pipeline was achieved by removing concrete weight coating section along the first 10km of the pipeline with higher wall thickness to counterbalance the stability issue as well as providing higher resistance against local buckling, fracture and fatigue. Thinner wall thickness provided with concrete weight coating (CWC) was selected for the pipeline section between 10km to 20km when the effective force is lower. For cost effective design, the mitigation scheme needs to be rationalized with various parameters from design pressure and temperature profile, pipe WT, CWC thickness, soil data and offshore construction. Lesson learnt from multiple recent projects shows clear indication that global buckling of a pipeline needs to be investigated, confirmed and optimized prior to initiation of line pipe procurement or even prior to FID especially for a long distance pipeline. In order to avoid unnecessary additional cost impact, it is important to eliminate uncertainty
{"title":"Significant Cost Avoidance by Managing Challenges and Conservatism of 28? Gas Pipeline Lateral Buckling Design","authors":"K. A. Karim, Md Anuar Desa, Mohd Hailmi Othman, Hayati Hussien","doi":"10.4043/31546-ms","DOIUrl":"https://doi.org/10.4043/31546-ms","url":null,"abstract":"\u0000 A lateral buckling mitigation design solution had been proposed for PETRONAS project to control pipeline expansion along a proposed 28\" gas pipeline. Unfortunately, the design which considers typical conservative approaches, had lead to excessive addition cost beyond the expected amount of Final Investment Decision (FID) and project sanction. Moreover, the mitigation scheme had been proposed without adequate study of alternative options by rationalization of various pipeline design parameters including design pressure and temperature profile, pipe WT, CWC thickness, soil data which may involve influencing other disciplines. The proposed solution also requires additional cost to offshore construction work. This paper provides insights on the assessment and design approaches carried out to optimize lateral buckling solution for the 28\" offshore gas export pipeline.\u0000 As the issue had come about when the carbon steel linepipe bidding process was almost completed, the pipeline project team had limited wall thickness available. With that in mind, PETRONAS’s pipeline in-house engineering team had performed probability assessment to identify the characteristic VAS along the pipeline. This approach was taken to reduce the previous conservative assumption whereby only single isolation buckling case has been introduced. For the purpose of lowering the pipeline temperature profile, an option of utilizing mother pipe for bend wall thickness at the hot end area without concrete coating was investigated. The study aimed to get a combination of wall thicknesses, with and without concrete weight coating that allow uncontrolled buckling formation within the safety limit so that additional offshore construction work can be eliminated. All the assessment was according to DNV-RP-F110 and DNV-OS-F101 limit state requirement.\u0000 The characteristic VAS determined from probability assessment is much shorter compare to conservative assumption of isolated single buckle formation. The expansion issue along the proposed pipeline was achieved by removing concrete weight coating section along the first 10km of the pipeline with higher wall thickness to counterbalance the stability issue as well as providing higher resistance against local buckling, fracture and fatigue. Thinner wall thickness provided with concrete weight coating (CWC) was selected for the pipeline section between 10km to 20km when the effective force is lower.\u0000 For cost effective design, the mitigation scheme needs to be rationalized with various parameters from design pressure and temperature profile, pipe WT, CWC thickness, soil data and offshore construction. Lesson learnt from multiple recent projects shows clear indication that global buckling of a pipeline needs to be investigated, confirmed and optimized prior to initiation of line pipe procurement or even prior to FID especially for a long distance pipeline. In order to avoid unnecessary additional cost impact, it is important to eliminate uncertainty","PeriodicalId":11217,"journal":{"name":"Day 4 Fri, March 25, 2022","volume":"65 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90274987","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}
Olivier Macchion, Leszek Lukasz Stachyra, H. Morand
Subsea chokes differ from the standard choke designs that can be found in for example the IEC 60534-8-3 standard, due to their geometry but also due to the environment. Contrary to topside chokes where monitoring for sound and vibration can be carried out in a relatively straightforward manner, noise and vibration monitoring is not easily executed subsea, which means that the estimate of the generated noise needs to be calculated, or extrapolated in some way from lab data. Computational methods to validate designs often provide an alternative method to physical validation testing when size or recreating particular environments are impractical. However, to be able to use computational analysis for this purpose, it is essential to ensure that a sound and benchmarked methodology is applied. This paper discusses an optimized methodology that combines Computational Aeroacoustics and IEC 60534-8-3 for the estimation of the internal sound pressure level (SPL) generated by choke valves. Three broad types of tools (all broadband models) are available to estimate hydrodynamic induced SPL, namely: 1) one-way coupled Computational Fluid Dynamics (CFD), 2) acoustic solvers, 3) two-way coupled CFD and acoustic solvers, also called Computational Aeroacoustics (CAA) solvers. Out of these three types, CAA accounts for both the geometry of the equipment generating the internal SPL, but also models the complex interaction between hydrodynamics and acoustics, including tones generated by cavities. While the advantage in terms of output is significant, CAA comes at a large computational cost due to the requirements in space and time discretization that must be satisfied to properly resolve the frequency range from 12.5 Hz to 20 kHz. The CAA methodology presented in this paper is validated against two sets of data obtained in laboratory conditions for Mach numbers ranging from 0.08 to 0.36. Then the same methodology is applied to the specific design of the choke valve. The obtained outputs in form of an acoustical efficiency and peak frequency are then used to tune the IEC 60534-8-3 method, this allows accurate estimation of internal SPL for the given geometry. The combination of the CAA and IEC enables efficient consideration of the actual geometry of the choke with regards to internal SPL prediction against a wider range of conditions without requiring a larger set CAA calculations. The methodology presented in this paper can be applied to similar problems ensuring faster and more accurate results compared to the other available industry practices like physical testing.
{"title":"Internal Sound Pressure Level Estimation Considering Design Through Computational Aeroacoustics","authors":"Olivier Macchion, Leszek Lukasz Stachyra, H. Morand","doi":"10.4043/31614-ms","DOIUrl":"https://doi.org/10.4043/31614-ms","url":null,"abstract":"\u0000 Subsea chokes differ from the standard choke designs that can be found in for example the IEC 60534-8-3 standard, due to their geometry but also due to the environment. Contrary to topside chokes where monitoring for sound and vibration can be carried out in a relatively straightforward manner, noise and vibration monitoring is not easily executed subsea, which means that the estimate of the generated noise needs to be calculated, or extrapolated in some way from lab data.\u0000 Computational methods to validate designs often provide an alternative method to physical validation testing when size or recreating particular environments are impractical. However, to be able to use computational analysis for this purpose, it is essential to ensure that a sound and benchmarked methodology is applied. This paper discusses an optimized methodology that combines Computational Aeroacoustics and IEC 60534-8-3 for the estimation of the internal sound pressure level (SPL) generated by choke valves.\u0000 Three broad types of tools (all broadband models) are available to estimate hydrodynamic induced SPL, namely: 1) one-way coupled Computational Fluid Dynamics (CFD), 2) acoustic solvers, 3) two-way coupled CFD and acoustic solvers, also called Computational Aeroacoustics (CAA) solvers. Out of these three types, CAA accounts for both the geometry of the equipment generating the internal SPL, but also models the complex interaction between hydrodynamics and acoustics, including tones generated by cavities. While the advantage in terms of output is significant, CAA comes at a large computational cost due to the requirements in space and time discretization that must be satisfied to properly resolve the frequency range from 12.5 Hz to 20 kHz.\u0000 The CAA methodology presented in this paper is validated against two sets of data obtained in laboratory conditions for Mach numbers ranging from 0.08 to 0.36. Then the same methodology is applied to the specific design of the choke valve. The obtained outputs in form of an acoustical efficiency and peak frequency are then used to tune the IEC 60534-8-3 method, this allows accurate estimation of internal SPL for the given geometry. The combination of the CAA and IEC enables efficient consideration of the actual geometry of the choke with regards to internal SPL prediction against a wider range of conditions without requiring a larger set CAA calculations.\u0000 The methodology presented in this paper can be applied to similar problems ensuring faster and more accurate results compared to the other available industry practices like physical testing.","PeriodicalId":11217,"journal":{"name":"Day 4 Fri, March 25, 2022","volume":"83 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86078026","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}
Raja Zahirudin Raja Ismail, Wan Ahmad Izuddin Wan Dagang, Rolf Gunnar Lie
To enable the safe replacement of five valves whose passing rates exceeded allowable limits, PETRONAS Carigali Sdn Bhd (PCSB) in 2017 used a three-module high pressure isolation tool (HPIT) to isolate one 24-inch and two 32-inch critical gas export pipelines at ANDR-A in the Angsi field in offshore Peninsular Malaysia. The SmartPlug® tool provided a double block and monitor (DBM) isolation without requiring depressurization or bleeding down the entire pipeline, which avoided prolonged shutdown. Because the three pipelines shared a common header at the ANDR-A topside, they required simultaneous isolation. Although HPIT had been deployed on main gas export pipelines several times before in Malaysia, this was the first time three isolations were required to be executed at the same time on the same platform during a single shutdown campaign. This Case Study describes the steps taken from planning, site visit and engineering to the safe and successful execution of the isolations.
为了安全更换合格率超过允许限值的5个阀门，马来西亚国家石油公司(PETRONAS Carigali Sdn Bhd, PCSB)在2017年使用了三模块高压隔离工具(HPIT)，在马来西亚半岛Angsi海上油田的ANDR-A隔离了一条24英寸和两条32英寸的关键天然气出口管道。SmartPlug®工具提供了双封块和监测(DBM)隔离，无需减压或放血整个管道，避免了长时间的关闭。由于三根管线在ANDR-A上部共用一个集管，因此它们需要同时隔离。虽然HPIT之前在马来西亚的主要天然气出口管道上部署过几次，但这是第一次在同一平台上在一次关闭期间同时执行三个隔离。本案例研究描述了从规划，现场访问和工程到安全成功地执行隔离所采取的步骤。
{"title":"Minimising Downtime During Multiple Valves Change Outs on Critical Gas Export Pipelines","authors":"Raja Zahirudin Raja Ismail, Wan Ahmad Izuddin Wan Dagang, Rolf Gunnar Lie","doi":"10.4043/31367-ms","DOIUrl":"https://doi.org/10.4043/31367-ms","url":null,"abstract":"\u0000 To enable the safe replacement of five valves whose passing rates exceeded allowable limits, PETRONAS Carigali Sdn Bhd (PCSB) in 2017 used a three-module high pressure isolation tool (HPIT) to isolate one 24-inch and two 32-inch critical gas export pipelines at ANDR-A in the Angsi field in offshore Peninsular Malaysia. The SmartPlug® tool provided a double block and monitor (DBM) isolation without requiring depressurization or bleeding down the entire pipeline, which avoided prolonged shutdown. Because the three pipelines shared a common header at the ANDR-A topside, they required simultaneous isolation. Although HPIT had been deployed on main gas export pipelines several times before in Malaysia, this was the first time three isolations were required to be executed at the same time on the same platform during a single shutdown campaign. This Case Study describes the steps taken from planning, site visit and engineering to the safe and successful execution of the isolations.","PeriodicalId":11217,"journal":{"name":"Day 4 Fri, March 25, 2022","volume":"14 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84726092","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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