Thin Zar Soe, Anucha Leelaratsameephanit, W. Chantarataneewat, C. Peerakham, Phanuwat Jitputti, T. Kiatrabile
PTTEP's Myanmar Asset Zawtika offshore field is located in the Gulf of Moattama, offshore Myanmar, referred to as the Zawtika Gas Development and Production Area. The area lies approximately 300 km south of Yangon and 290 km west of Tavoy on the Myanmar coast. Zawtika offshore gas field consists of Zawtika Processing and Living Quarter platform (ZPQ) which was designed to provide fully automatic, integrated and centralized platform/ process control, and ZWP1 which is connected to ZPQ via interconnecting bridge and 10 remote wellhead platforms which are ZWP2, ZWP3, ZWP4, ZWP5, ZWP6, ZWP7, ZWP8, ZWP9, ZWP10 and ZWP11, located in the Gulf of Moattama offshore Myanmar. In order to prolong field gas potential, the data analysis, planning and management on daily gas potential loss is important to better understand the field behavior. The issues of gas losses are captured and categorized based on difficulties of recovery. "Deferment" is defined as the short-term temporary reduction in Production Availability which results in delay of gas production due to the effects of system constraints/ limitations, scheduled shut down activities on wells or facilities associated with safety, production, maintenance, operation and unplanned interruptions. "Lock-in" is defined as the long-term gas potential reduction that requires longer time and higher investment to solve and unlock that potential. Under PTTEP Operation Excellent Management System (OEMS), one of the essential elements for optimized operation is deferment/lock-in potential management. With this importance in focus, this paper discusses Deferment Management Enhancement for PTTEP's Myanmar asset operation which goal is to enhance deferment analysis and management by using data analytics in information technology environment in alignment with PTTEP Digital Transformation direction. The data obtained from this enhancement can be used in short-term and long-term planning activities for production system optimization including project investments, reservoir management and integrated operations planning, and especially in providing in-depth analysis to minimize deferment volume to maximize return on investment. Production deferment/lock-in guideline is developed within PTTEP's Myanmar Asset to structure Hydrocarbon Availability Model (HAM) for Zawtika according to PTTEP Operations Standard and define deferment and lock-in gas potential data collection basis and their categorizations. ZPDMS deferment module is then enhanced based on this guideline with the extra capability to facilitate site data entry which has been a problem since start-up due to satellite link constraint from Zawtika offshore field. This enhancement also consolidates lock-in/deferment causes, and coding structures, integrates subsurface potential calculation and surface production data, and introduces key visualization pages (e.g. Deferment Dashboard, etc.) for better deferment management performance analysis. After the full implemen
{"title":"Zawtika Deferment Management Enhancement: A Systematic Way to Unlock Gas Potential for Optimized Operations","authors":"Thin Zar Soe, Anucha Leelaratsameephanit, W. Chantarataneewat, C. Peerakham, Phanuwat Jitputti, T. Kiatrabile","doi":"10.4043/31572-ms","DOIUrl":"https://doi.org/10.4043/31572-ms","url":null,"abstract":"\u0000 PTTEP's Myanmar Asset Zawtika offshore field is located in the Gulf of Moattama, offshore Myanmar, referred to as the Zawtika Gas Development and Production Area. The area lies approximately 300 km south of Yangon and 290 km west of Tavoy on the Myanmar coast. Zawtika offshore gas field consists of Zawtika Processing and Living Quarter platform (ZPQ) which was designed to provide fully automatic, integrated and centralized platform/ process control, and ZWP1 which is connected to ZPQ via interconnecting bridge and 10 remote wellhead platforms which are ZWP2, ZWP3, ZWP4, ZWP5, ZWP6, ZWP7, ZWP8, ZWP9, ZWP10 and ZWP11, located in the Gulf of Moattama offshore Myanmar.\u0000 In order to prolong field gas potential, the data analysis, planning and management on daily gas potential loss is important to better understand the field behavior. The issues of gas losses are captured and categorized based on difficulties of recovery. \"Deferment\" is defined as the short-term temporary reduction in Production Availability which results in delay of gas production due to the effects of system constraints/ limitations, scheduled shut down activities on wells or facilities associated with safety, production, maintenance, operation and unplanned interruptions. \"Lock-in\" is defined as the long-term gas potential reduction that requires longer time and higher investment to solve and unlock that potential.\u0000 Under PTTEP Operation Excellent Management System (OEMS), one of the essential elements for optimized operation is deferment/lock-in potential management. With this importance in focus, this paper discusses Deferment Management Enhancement for PTTEP's Myanmar asset operation which goal is to enhance deferment analysis and management by using data analytics in information technology environment in alignment with PTTEP Digital Transformation direction. The data obtained from this enhancement can be used in short-term and long-term planning activities for production system optimization including project investments, reservoir management and integrated operations planning, and especially in providing in-depth analysis to minimize deferment volume to maximize return on investment.\u0000 Production deferment/lock-in guideline is developed within PTTEP's Myanmar Asset to structure Hydrocarbon Availability Model (HAM) for Zawtika according to PTTEP Operations Standard and define deferment and lock-in gas potential data collection basis and their categorizations. ZPDMS deferment module is then enhanced based on this guideline with the extra capability to facilitate site data entry which has been a problem since start-up due to satellite link constraint from Zawtika offshore field. This enhancement also consolidates lock-in/deferment causes, and coding structures, integrates subsurface potential calculation and surface production data, and introduces key visualization pages (e.g. Deferment Dashboard, etc.) for better deferment management performance analysis.\u0000 After the full implemen","PeriodicalId":11011,"journal":{"name":"Day 3 Thu, March 24, 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":"74068615","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. H. Ariffin, Ryan Guillory, Bee Chan Low, F. A. Salleh
Greenhouse gas emission (GHG) is the main contributor to global warming, so the industry players need to take a huge step to reduce GHG. Furthermore, the implementation of carbon tax has eroded oil project values and drives teams to think about ways to reduce the carbon tax. This paper highlights the subsurface studies, gas balancing method, and surface modification effort to reduce the gas emission in Field B while reaping the benefits not just of reduced carbon tax but increased oil production and revenue. Gas injection is not just increasing reservoir pressure but also reduces emission. Several reservoirs in the field have been depleted by 66% to 500 psi. The team converted the existing oil wells to gas injection wells instead of spending high CAPEX to drill new gas injection well. This way the team can confirm the benefit of gas injection with a low-risk cash injection. The field has a high amount of unproduced Non-Associated Gas (NAG), but this NAG cannot be produced without a gas evacuation plan. Producing the NAG will cause the field to vent higher with existing facilities installations. So, the team came out with a plan to monetize the gas by installing a new gas pipeline and new gas processing platform. Furthermore, the Associated Gas (AG) which was vented previously can be channeled to the new compression system to further reduce the emission. Currently, the gas from the surge tank is lined up straight to the vent stack. A Vapour Recovery Unit (VRU) was proposed to install upstream of the surge vessels. The VRU will pump the gas back to an AG gas compressor and straight to the gas sales line. The gas injection project has increased the reservoir pressure from 500 psi to 700 psi. As a result, one idle well reactivated to produce oil, two wells were drilled from the same reservoir, and gas venting was reduced by up to 7 MMscf/d. Because of this success, several other wells were identified for gas injection candidates in other reservoirs. NAG gas project is expected to provide 100 MMscf/d revenue. In addition to that, the NAG project also helps to reduce AG venting because of AG compressor limitations. The additional AG volumes are around 5 MMscf/d. VRU installation is still undergoing doability and commerciality study because the gas from the surge vessel is minimal. However, the team's dream towards zero gas emission is a step closer if VRU installation is brought forward. Because the field is not well equipped with a gas meter for each piece of equipment. An accurate and understanding of gas balance estimation is important to drive zero gas emission.
{"title":"Striving Towards Zero Gas Emission","authors":"M. H. Ariffin, Ryan Guillory, Bee Chan Low, F. A. Salleh","doi":"10.4043/31392-ms","DOIUrl":"https://doi.org/10.4043/31392-ms","url":null,"abstract":"\u0000 Greenhouse gas emission (GHG) is the main contributor to global warming, so the industry players need to take a huge step to reduce GHG. Furthermore, the implementation of carbon tax has eroded oil project values and drives teams to think about ways to reduce the carbon tax.\u0000 This paper highlights the subsurface studies, gas balancing method, and surface modification effort to reduce the gas emission in Field B while reaping the benefits not just of reduced carbon tax but increased oil production and revenue.\u0000 Gas injection is not just increasing reservoir pressure but also reduces emission. Several reservoirs in the field have been depleted by 66% to 500 psi. The team converted the existing oil wells to gas injection wells instead of spending high CAPEX to drill new gas injection well. This way the team can confirm the benefit of gas injection with a low-risk cash injection.\u0000 The field has a high amount of unproduced Non-Associated Gas (NAG), but this NAG cannot be produced without a gas evacuation plan. Producing the NAG will cause the field to vent higher with existing facilities installations. So, the team came out with a plan to monetize the gas by installing a new gas pipeline and new gas processing platform. Furthermore, the Associated Gas (AG) which was vented previously can be channeled to the new compression system to further reduce the emission.\u0000 Currently, the gas from the surge tank is lined up straight to the vent stack. A Vapour Recovery Unit (VRU) was proposed to install upstream of the surge vessels. The VRU will pump the gas back to an AG gas compressor and straight to the gas sales line.\u0000 The gas injection project has increased the reservoir pressure from 500 psi to 700 psi. As a result, one idle well reactivated to produce oil, two wells were drilled from the same reservoir, and gas venting was reduced by up to 7 MMscf/d. Because of this success, several other wells were identified for gas injection candidates in other reservoirs.\u0000 NAG gas project is expected to provide 100 MMscf/d revenue. In addition to that, the NAG project also helps to reduce AG venting because of AG compressor limitations. The additional AG volumes are around 5 MMscf/d.\u0000 VRU installation is still undergoing doability and commerciality study because the gas from the surge vessel is minimal. However, the team's dream towards zero gas emission is a step closer if VRU installation is brought forward.\u0000 Because the field is not well equipped with a gas meter for each piece of equipment. An accurate and understanding of gas balance estimation is important to drive zero gas emission.","PeriodicalId":11011,"journal":{"name":"Day 3 Thu, March 24, 2022","volume":"19 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86602993","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 Netherlands, a large number of onshore wells are near urban areas or close to forests where environmental emission and noise reduction are important to consider. With more than 23 different well site locations to be abandoned, a significant amount of collaboration is required to ensure there is minimal interruption and impact to the local community and the environment. To achieve this, the operator together with Baker Hughes as the project management lead, formulated a unique, low-impact solution with fully electrified equipment that mostly uses grid power. Alongside other service partners, the majority of the onsite equipment are electrically driven, such as the rigless well abandonment unit, cement pumps, ancillary equipment, and the slickline unit. A noise dampener and decibel readers were put in place to minimize and track sound emissions. Such collaboration and integration with all providers were carefully identified and mitigated through a series of non-technical risks (NTRs) to ensure compliance with local regulations. Extra steps were taken to ensure that smell and noise remain unnoticed by the surrounding environment. Frequent communications are sent to the public by the operator to keep everyone informed prior to any mobilization. After a one-year campaign, there have been zero LTI, zero accidents, zero non-compliance incidents and above all, safe and secured end-of-life oil wells in an urban setting with many more to follow suit. This paper will provide insight into the integrated operations of a well abandonment project in a unique urban setting and the challenges to successfully abandon wells of varying complexity. This project is to be accomplished in compliance with the local mining and environmental regulations with no remaining liabilities, all while limiting total project costs. The supply chain stepped up by providing a cost-effective solution through multi-party collaboration, multi-skilling, technology innovation, and logistical solutions. The project planning, start-up phase, and an overview of the first year of operations will be presented.
{"title":"An Electrifying Integrated Solution Towards a Safe and Environmentally Sound Well Abandonment in Urban Setting","authors":"Syahnon Mohamad, L. Joppe","doi":"10.4043/31394-ms","DOIUrl":"https://doi.org/10.4043/31394-ms","url":null,"abstract":"\u0000 In the Netherlands, a large number of onshore wells are near urban areas or close to forests where environmental emission and noise reduction are important to consider. With more than 23 different well site locations to be abandoned, a significant amount of collaboration is required to ensure there is minimal interruption and impact to the local community and the environment.\u0000 To achieve this, the operator together with Baker Hughes as the project management lead, formulated a unique, low-impact solution with fully electrified equipment that mostly uses grid power. Alongside other service partners, the majority of the onsite equipment are electrically driven, such as the rigless well abandonment unit, cement pumps, ancillary equipment, and the slickline unit. A noise dampener and decibel readers were put in place to minimize and track sound emissions.\u0000 Such collaboration and integration with all providers were carefully identified and mitigated through a series of non-technical risks (NTRs) to ensure compliance with local regulations. Extra steps were taken to ensure that smell and noise remain unnoticed by the surrounding environment. Frequent communications are sent to the public by the operator to keep everyone informed prior to any mobilization.\u0000 After a one-year campaign, there have been zero LTI, zero accidents, zero non-compliance incidents and above all, safe and secured end-of-life oil wells in an urban setting with many more to follow suit.\u0000 This paper will provide insight into the integrated operations of a well abandonment project in a unique urban setting and the challenges to successfully abandon wells of varying complexity. This project is to be accomplished in compliance with the local mining and environmental regulations with no remaining liabilities, all while limiting total project costs. The supply chain stepped up by providing a cost-effective solution through multi-party collaboration, multi-skilling, technology innovation, and logistical solutions. The project planning, start-up phase, and an overview of the first year of operations will be presented.","PeriodicalId":11011,"journal":{"name":"Day 3 Thu, March 24, 2022","volume":"87 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"85939653","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}
Formation evaluation and appraisal in Central Luconia carbonate reef is challenging when drilling operation change from conventional drilling to pressurised mud cap drilling (PMCD). PMCD drilling has always been the choice to deal with unmanageable losses condition. It is normally applied in carbonate reservoir with karst and vugs. Under this drilling condition, annular pressure and surface pressure is maintained above the formation that is able to take the cuttings and fluids. At the same time, light annular fluid is pumped down the annulus to maintain hole fill and avoid gas migration. Seawater, acts as sacrificial mud is pumped down the drill string to cool the bit and to transport the cuttings to loss zones. Meanwhile, for an exploration well, the primary objective is to prove hydrocarbon presence and hydrocarbon fluid contact through logging while drilling (LWD) as wireline logging is not favourable from operational perspective. One of the key challenges of interpreting hydrocarbon saturation in PMCD operation is suppression of resistivity value due to sea-water invasion. Indeed, with PMCD, the well is appeared to have high water saturation even though 1 MHz phase shift 36" spacing deep phase resistivity is used in the interpretation. However, this is inconsistent with gas kick occurred at the top of carbonate or gas shows prior to conversion from conventional drilling to PMCD operation. Another observation of resistivity log response in PMCD drilling is that the phase shift resistivity from different sensor spacing (6", 12", 24" and 36", with smaller number indicate shallower depth of investigation, and higher number indicate deeper depth of investigation) appears to have separation, which indicates invasion profile which happens at one time-frame. Although 1D inversion for true resistivity (Rt) can be carried out with multiple sensor spacing phase resistivity and invasion diameter (Di) as inputs, the inversion result does not yield satisfactory result that match pre-PMCD resistivity value. The objective of the paper/ abstract is to highlight the benefits or running dual – resistivity in LWD bottom-hole assembly (BHA) in PMCD well to capture time-lapse resistivity measurement, estimate Rt which is time-dependant and pin-pointing gas-water contact in the exploration/ appraisal wells. This new proposed concept and methodology is still at its early stage, yet designed to make better decision during operational time. Such an approach will provide benefits to petrophysics community in the PMCD well interpretation with minimal incremental cost.
随着钻井作业从常规钻井转向加压泥浆帽钻井(PMCD)， Central Luconia碳酸盐岩礁的地层评价与评价面临挑战。PMCD钻井一直是处理难以控制的漏失情况的选择。通常应用于具有岩溶和溶洞的碳酸盐岩储层。在这种钻井条件下，环空压力和地面压力保持在能够带走岩屑和流体的地层上方。同时，将轻质环空流体泵入环空，以保持井眼充填，避免气体运移。海水作为牺牲泥浆被泵入钻柱以冷却钻头并将岩屑输送到漏失层。同时，对于一口探井来说，主要目的是通过随钻测井(LWD)来证明油气的存在和油气流体的接触，因为从操作角度来看，电缆测井并不有利。在PMCD作业中，解释油气饱和度的关键挑战之一是由于海水侵入而抑制电阻率值。事实上，使用PMCD，即使在解释中使用1 MHz相移36”间距深相电阻率，该井的含水饱和度也很高。然而，这与常规钻井转换为PMCD作业之前发生在碳酸盐岩顶部或气层的气涌不一致。PMCD钻井中电阻率测井响应的另一个观察结果是，不同传感器间距(6”、12”、24”和36”，数值越小表示探测深度越浅，数值越大表示探测深度越深)的相移电阻率出现分离现象，表明入侵剖面发生在同一时间段。以多传感器间距相电阻率和侵入直径Di为输入，虽然可以进行真电阻率(Rt)的一维反演，但反演结果与pmcd前电阻率值并不匹配。本文的目的是强调在PMCD井的LWD底部钻具组合(BHA)中使用双电阻率的好处，以获取时移电阻率测量数据，估计随时间变化的Rt，并在勘探/评价井中精确定位气水接触。这个新提出的概念和方法仍处于早期阶段，但旨在在操作期间做出更好的决策。这种方法将以最小的增量成本为岩石物理学界提供PMCD井解释的好处。
{"title":"Hydrocarbon Saturation Determination in Case of Total Losses: Invasion Profile Modelling with Dual Resistivity – A Possible Application in PMCD Drilling","authors":"K. Ling, H. Zulkiply","doi":"10.4043/31353-ms","DOIUrl":"https://doi.org/10.4043/31353-ms","url":null,"abstract":"\u0000 \u0000 \u0000 Formation evaluation and appraisal in Central Luconia carbonate reef is challenging when drilling operation change from conventional drilling to pressurised mud cap drilling (PMCD). PMCD drilling has always been the choice to deal with unmanageable losses condition. It is normally applied in carbonate reservoir with karst and vugs. Under this drilling condition, annular pressure and surface pressure is maintained above the formation that is able to take the cuttings and fluids. At the same time, light annular fluid is pumped down the annulus to maintain hole fill and avoid gas migration. Seawater, acts as sacrificial mud is pumped down the drill string to cool the bit and to transport the cuttings to loss zones.\u0000 Meanwhile, for an exploration well, the primary objective is to prove hydrocarbon presence and hydrocarbon fluid contact through logging while drilling (LWD) as wireline logging is not favourable from operational perspective. One of the key challenges of interpreting hydrocarbon saturation in PMCD operation is suppression of resistivity value due to sea-water invasion. Indeed, with PMCD, the well is appeared to have high water saturation even though 1 MHz phase shift 36\" spacing deep phase resistivity is used in the interpretation. However, this is inconsistent with gas kick occurred at the top of carbonate or gas shows prior to conversion from conventional drilling to PMCD operation. Another observation of resistivity log response in PMCD drilling is that the phase shift resistivity from different sensor spacing (6\", 12\", 24\" and 36\", with smaller number indicate shallower depth of investigation, and higher number indicate deeper depth of investigation) appears to have separation, which indicates invasion profile which happens at one time-frame. Although 1D inversion for true resistivity (Rt) can be carried out with multiple sensor spacing phase resistivity and invasion diameter (Di) as inputs, the inversion result does not yield satisfactory result that match pre-PMCD resistivity value. The objective of the paper/ abstract is to highlight the benefits or running dual – resistivity in LWD bottom-hole assembly (BHA) in PMCD well to capture time-lapse resistivity measurement, estimate Rt which is time-dependant and pin-pointing gas-water contact in the exploration/ appraisal wells. This new proposed concept and methodology is still at its early stage, yet designed to make better decision during operational time. Such an approach will provide benefits to petrophysics community in the PMCD well interpretation with minimal incremental cost.\u0000","PeriodicalId":11011,"journal":{"name":"Day 3 Thu, March 24, 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":"87872111","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. A. Abitalhah, Nurul Nadia Ezzatty Abu Bakar, M. Hod, Avinash Kishore Kumar, C. Lau, Mya Thuzar
This paper presents the success story of an exploration well in Malaysia evaluating the conventional approach of stacked cement plugs against the use of sacrificial tubing with a hydraulic disconnect sub system. Plug and Abandonment (P&A) is the process where the well is sealed permanently, and permanent well barrier must extend across the full cross section prior rig move. It is vital to ensure that plugged wells do not leak after abandonment, as there could be several potential leak paths or channeling from microannulus. Thus, well integrity shall be the utmost priority in designing the P&A strategy. Conventional P&A requires multiple cement plugs of a given length to be set and pressure tested, which could however be quite time-consuming and thus costly. The number of cement plugs will be based on the length of the open hole section, hydrocarbon zones presence or caprock to meet the P&A guidelines. The guidelines require that cement plugs be placed and tested across any open hydrocarbon-bearing formations, across all casing shoes, across freshwater aquifers, and perhaps several other areas near the surface. The thought process, design requirement both for the hardware and cement slurry, and execution follow through of a P&A approach with a sacrificial tubing method, driving for cost savings and operational efficiency will be elaborated. Some of the key points for replication based on lessons learnt are P&A with sacrificial tubing is economical justified for well scenario. As for the design, tubing centralizers or rotation is required in deviated hole for proper cement placement. Rotation of tubing during cementing is recommended for effective mud removal and cement placement for the case of no centralizer placement. This paper provides the novelty of the extensive planning, execution and improvement methods that will aid the project team to save cost and time in plug and abandonment (P&A) the well.
{"title":"Abandonment of Wells Under the New Norm – Sacrificial Tubing Approach","authors":"M. A. Abitalhah, Nurul Nadia Ezzatty Abu Bakar, M. Hod, Avinash Kishore Kumar, C. Lau, Mya Thuzar","doi":"10.4043/31369-ms","DOIUrl":"https://doi.org/10.4043/31369-ms","url":null,"abstract":"\u0000 This paper presents the success story of an exploration well in Malaysia evaluating the conventional approach of stacked cement plugs against the use of sacrificial tubing with a hydraulic disconnect sub system.\u0000 Plug and Abandonment (P&A) is the process where the well is sealed permanently, and permanent well barrier must extend across the full cross section prior rig move. It is vital to ensure that plugged wells do not leak after abandonment, as there could be several potential leak paths or channeling from microannulus. Thus, well integrity shall be the utmost priority in designing the P&A strategy.\u0000 Conventional P&A requires multiple cement plugs of a given length to be set and pressure tested, which could however be quite time-consuming and thus costly. The number of cement plugs will be based on the length of the open hole section, hydrocarbon zones presence or caprock to meet the P&A guidelines. The guidelines require that cement plugs be placed and tested across any open hydrocarbon-bearing formations, across all casing shoes, across freshwater aquifers, and perhaps several other areas near the surface.\u0000 The thought process, design requirement both for the hardware and cement slurry, and execution follow through of a P&A approach with a sacrificial tubing method, driving for cost savings and operational efficiency will be elaborated.\u0000 Some of the key points for replication based on lessons learnt are P&A with sacrificial tubing is economical justified for well scenario. As for the design, tubing centralizers or rotation is required in deviated hole for proper cement placement. Rotation of tubing during cementing is recommended for effective mud removal and cement placement for the case of no centralizer placement.\u0000 This paper provides the novelty of the extensive planning, execution and improvement methods that will aid the project team to save cost and time in plug and abandonment (P&A) the well.","PeriodicalId":11011,"journal":{"name":"Day 3 Thu, March 24, 2022","volume":"125 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89280083","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}
Gerardus Putra Pancawisna, R. Hidayat, G. D. Dahnil, Risal Rahman, P. S. Kurniawati, R. Marindha, K. Umar, _. Ferdian, Irwan Setyaji, Muhammad Masrur, Stian Steinsholm
The paper is aimed to present the engineering design and execution of first application of coiled hose in Indonesia to perform nitrogen unload including its first deployment with roller boogies in the world to tackle the challenge of highly deviated well. The new well of XX-107 was completed with 2 (two) gravel pack zones and tubingless section. In order to produce the well from the gravel pack zones, completion fluid, which filled in the XX-107 well, should be displaced to ensure underbalance condition once the SSDs of those gravel pack zones were opened. After comparing several available methods, coiled hose was chosen to perform nitrogen unload due to its compact and lightweight nature in comparison to conventional coiled tubing. Coiled hose enabled seamless deployment right after the well was completed by the workover unit. Furthermore, the maximum deviation of 84 deg in XX-107 well provided additional challenge to access the well since coiled hose was gravity feed. Several simulations were performed and they resulted in the utilization of roller boogies to minimize friction during RIH and increase the reach of coiled hose in this well. As a result, this operation achieved its main objective of displacing the completion fluid out of the well and created underbalance condition in front of the gravel pack zones. Although the efficiency was only 67.5%, it managed to create 1071 psi of underbalance value and consequently the well flowed at 8 MMscfd. Its lightweight nature was like electricline unit and it consumed less space on the upper deck of the platform. Moreover, the deployment and setup process was performed offline which optimized the operating time event further. The cumulative operating time was only 13 hours including demobilization process while in terms of logistic coiled hose only required 1 trip whereas coiled tubing unit required at least 3 trips. Lastly, this operation requires only 10 personnel for 24-hr operation in comparison to 15 coiled tubing personnel which meant, in this Covid-19 pandemic, provided less risky solution.
{"title":"First Application of Coiled Hose in Indonesia and First Deployment of Coiled Hose with Roller Boogies in the World to Access Highly Deviated Well","authors":"Gerardus Putra Pancawisna, R. Hidayat, G. D. Dahnil, Risal Rahman, P. S. Kurniawati, R. Marindha, K. Umar, _. Ferdian, Irwan Setyaji, Muhammad Masrur, Stian Steinsholm","doi":"10.4043/31407-ms","DOIUrl":"https://doi.org/10.4043/31407-ms","url":null,"abstract":"\u0000 The paper is aimed to present the engineering design and execution of first application of coiled hose in Indonesia to perform nitrogen unload including its first deployment with roller boogies in the world to tackle the challenge of highly deviated well.\u0000 The new well of XX-107 was completed with 2 (two) gravel pack zones and tubingless section. In order to produce the well from the gravel pack zones, completion fluid, which filled in the XX-107 well, should be displaced to ensure underbalance condition once the SSDs of those gravel pack zones were opened. After comparing several available methods, coiled hose was chosen to perform nitrogen unload due to its compact and lightweight nature in comparison to conventional coiled tubing. Coiled hose enabled seamless deployment right after the well was completed by the workover unit. Furthermore, the maximum deviation of 84 deg in XX-107 well provided additional challenge to access the well since coiled hose was gravity feed. Several simulations were performed and they resulted in the utilization of roller boogies to minimize friction during RIH and increase the reach of coiled hose in this well.\u0000 As a result, this operation achieved its main objective of displacing the completion fluid out of the well and created underbalance condition in front of the gravel pack zones. Although the efficiency was only 67.5%, it managed to create 1071 psi of underbalance value and consequently the well flowed at 8 MMscfd. Its lightweight nature was like electricline unit and it consumed less space on the upper deck of the platform. Moreover, the deployment and setup process was performed offline which optimized the operating time event further. The cumulative operating time was only 13 hours including demobilization process while in terms of logistic coiled hose only required 1 trip whereas coiled tubing unit required at least 3 trips. Lastly, this operation requires only 10 personnel for 24-hr operation in comparison to 15 coiled tubing personnel which meant, in this Covid-19 pandemic, provided less risky solution.","PeriodicalId":11011,"journal":{"name":"Day 3 Thu, March 24, 2022","volume":"24 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"75082624","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}
Biramarta Isnadi, Suhaimi Mahasan, Syahnaz Omar, W. H. Fazli, Yusuf Sahari, Ave Suhendra, Ellis Wong, Aiman Kamaruzaman, R. Khan
This paper describes the SPM Integrity Management approach using risk based strategies for Single Point Mooring (SPM) throughout its asset life cycle, to ensure that there is a structural integrity management processes are implemented and SPM asset fitness for purpose is always maintained. SPM is one of the most important assets for any oil and gas upstream business, as its primary function is for product export and offloading operations. PETRONAS UPSTREAM currently operate seven (7) Single Point Mooring (SPM) assets for its Malaysia Upstream/ Downstream. To manage the integrity of the SPMs, an Integrity Management system has been developed and includes newer assets and those that are approaching or exceeding design lives. To optimize and focus limited resources toward critical activities, a SPM risk-based strategy and methodology for the SPM assets has been developed. The risk based inspection approach is aligned with the Structural Integrity Management (SIM) processes of DATA, EVALUATION, STRATEGY PROGRAM of the API RP2SIM code of practice. A qualitative risk based integrity management has been developed and for its implementation, inspection and maintenance activities shall target high expenditure items. SPM design, characteristic, assessment, and inspection data have been compiled and utilized in the risk based approach development. With this risk-based approach, PETRONAS can optimize and significantly reduce its inspection and maintenance activities whilst keeping operational risk levels within acceptable limits. The risk-based approach provides that added advantage to look at inspections and maintenance activities critically and make informed decisions on resourcing and aligning inspection & maintenance campaigns for the future. Inspection and maintenance measures also include an anomaly management, RBI, data management and inspections scopes of work which are being digitized and maintained within the Company's Structural Integrity Compliance System (SICS).
{"title":"A Risk Based Approach for the Integrity Management of Single Point Mooring Systems","authors":"Biramarta Isnadi, Suhaimi Mahasan, Syahnaz Omar, W. H. Fazli, Yusuf Sahari, Ave Suhendra, Ellis Wong, Aiman Kamaruzaman, R. Khan","doi":"10.4043/31405-ms","DOIUrl":"https://doi.org/10.4043/31405-ms","url":null,"abstract":"\u0000 This paper describes the SPM Integrity Management approach using risk based strategies for Single Point Mooring (SPM) throughout its asset life cycle, to ensure that there is a structural integrity management processes are implemented and SPM asset fitness for purpose is always maintained. SPM is one of the most important assets for any oil and gas upstream business, as its primary function is for product export and offloading operations. PETRONAS UPSTREAM currently operate seven (7) Single Point Mooring (SPM) assets for its Malaysia Upstream/ Downstream. To manage the integrity of the SPMs, an Integrity Management system has been developed and includes newer assets and those that are approaching or exceeding design lives.\u0000 To optimize and focus limited resources toward critical activities, a SPM risk-based strategy and methodology for the SPM assets has been developed. The risk based inspection approach is aligned with the Structural Integrity Management (SIM) processes of DATA, EVALUATION, STRATEGY PROGRAM of the API RP2SIM code of practice. A qualitative risk based integrity management has been developed and for its implementation, inspection and maintenance activities shall target high expenditure items. SPM design, characteristic, assessment, and inspection data have been compiled and utilized in the risk based approach development.\u0000 With this risk-based approach, PETRONAS can optimize and significantly reduce its inspection and maintenance activities whilst keeping operational risk levels within acceptable limits. The risk-based approach provides that added advantage to look at inspections and maintenance activities critically and make informed decisions on resourcing and aligning inspection & maintenance campaigns for the future.\u0000 Inspection and maintenance measures also include an anomaly management, RBI, data management and inspections scopes of work which are being digitized and maintained within the Company's Structural Integrity Compliance System (SICS).","PeriodicalId":11011,"journal":{"name":"Day 3 Thu, March 24, 2022","volume":"174 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"91006317","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}
Junling Wan, Xiang Wu, B. Chang, Chao Wang, Gong Li, Fei Wang, Y. Shim
At the in-depth development phase, the current horizontal infill campaign in H oil field targets reservoirs with high remaining oil potential and the diverse complexities subject to both structural and lithological controls. These structural and lithological reservoirs are characterized by the uncertainties of formation dip and oil/water contact (OWC), severe stratigraphic heterogeneity, lateral properties change, poor sandstone connectivity, and thickness variation (less than 5 m) of the oil column and interbeds. To effectively squeeze the potential remaining reserves, the scope of the current infill campaign mainly encompasses: (1) the limited crests of the anticlinal traps with uncertain oil column and lateral changed reservoir, and (2) the unexploited marginal areas close to the reservoir pinchout line. Accordingly, it is necessary to quantitatively update the reservoir-scale subsurface profile and execute well placement operations by addressing the above uncertainties with individualized services and workflow. In these diverse reservoirs, interwell structural and stratigraphic uncertainties are high because resolution of large-scale seismic data and depth-of-investigation (DOI) of small-scale conventional logging data are limited. On these grounds, a high-definition boundary detection service (HDBDS) was employed, which can provide a stochastic resistivity inversion to remotely identify quantitative subsurface features with DOI up to 6 m and resolution of approximately 1 m. Its advantage of balancing resolution and DOI can induce the accurate description of high-definition interwell details, including formation superposition configuration, reservoir pinchout points, and dynamic OWC. Furthermore, HDBDS inversion can combine 3D seismic data and conventional logging data to effectively induce the workflow from subsurface uncertainty management to the quantitative reservoir-scale profile update and well placement. HDBDS inversion-derived workflow effectively contributed to us achieving our objectives of this infill campaign by generally revealing the high-definition reservoir profiles along the horizontal sections. Up to four boundaries and five layers were mapped simultaneously with a maximum of 3 m distance from the borehole. High coverage and probability of the updated quantitative features induced the higher reservoir profile update rate in these specific environments than that based on the conventional services. In the complex developed areas mainly subject to both structural and lithological controls, the reservoir top, lateral changed properties, and dynamic tilted OWC were quantitatively inverted to identify the effective 1.5- to 3-m oil column, lower than prognosed 5-m column. In the lithological-control reservoirs at block margins, formation superposition configuration, pinchout points, and lateral properties changing features were clearly delineated. Accordingly, the quantitative well placement operations were efficiently executed
{"title":"Resistivity-Inversion-Derived Workflow from the Subsurface Uncertainty Management to the Quantitative Reservoir-Scale Profile Update and Well Placement in Reservoirs with Diverse Complexities","authors":"Junling Wan, Xiang Wu, B. Chang, Chao Wang, Gong Li, Fei Wang, Y. Shim","doi":"10.4043/31532-ms","DOIUrl":"https://doi.org/10.4043/31532-ms","url":null,"abstract":"\u0000 At the in-depth development phase, the current horizontal infill campaign in H oil field targets reservoirs with high remaining oil potential and the diverse complexities subject to both structural and lithological controls. These structural and lithological reservoirs are characterized by the uncertainties of formation dip and oil/water contact (OWC), severe stratigraphic heterogeneity, lateral properties change, poor sandstone connectivity, and thickness variation (less than 5 m) of the oil column and interbeds. To effectively squeeze the potential remaining reserves, the scope of the current infill campaign mainly encompasses: (1) the limited crests of the anticlinal traps with uncertain oil column and lateral changed reservoir, and (2) the unexploited marginal areas close to the reservoir pinchout line. Accordingly, it is necessary to quantitatively update the reservoir-scale subsurface profile and execute well placement operations by addressing the above uncertainties with individualized services and workflow.\u0000 In these diverse reservoirs, interwell structural and stratigraphic uncertainties are high because resolution of large-scale seismic data and depth-of-investigation (DOI) of small-scale conventional logging data are limited. On these grounds, a high-definition boundary detection service (HDBDS) was employed, which can provide a stochastic resistivity inversion to remotely identify quantitative subsurface features with DOI up to 6 m and resolution of approximately 1 m. Its advantage of balancing resolution and DOI can induce the accurate description of high-definition interwell details, including formation superposition configuration, reservoir pinchout points, and dynamic OWC. Furthermore, HDBDS inversion can combine 3D seismic data and conventional logging data to effectively induce the workflow from subsurface uncertainty management to the quantitative reservoir-scale profile update and well placement.\u0000 HDBDS inversion-derived workflow effectively contributed to us achieving our objectives of this infill campaign by generally revealing the high-definition reservoir profiles along the horizontal sections. Up to four boundaries and five layers were mapped simultaneously with a maximum of 3 m distance from the borehole. High coverage and probability of the updated quantitative features induced the higher reservoir profile update rate in these specific environments than that based on the conventional services. In the complex developed areas mainly subject to both structural and lithological controls, the reservoir top, lateral changed properties, and dynamic tilted OWC were quantitatively inverted to identify the effective 1.5- to 3-m oil column, lower than prognosed 5-m column. In the lithological-control reservoirs at block margins, formation superposition configuration, pinchout points, and lateral properties changing features were clearly delineated. Accordingly, the quantitative well placement operations were efficiently executed","PeriodicalId":11011,"journal":{"name":"Day 3 Thu, March 24, 2022","volume":"36 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82224380","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}
Shusheng Guo, Shiyue Wang, S. Daungkaew, Bei Gao, S. Chouya, O. Mullins, Jesus A. Cañas, S. Betancourt, A. Gisolf, T. Khunaworawet, D. Ling
Since early 1990's, Downhole Fluid Analysis (DFA) has been developed to monitor mud filtrate contamination for Wireline Formation Tester downhole sampling. DFA can also provide accurate reservoir fluid information in real time such as hydrocarbon composition including CO2. However, DFA technology cannot measure Nitrogen because N2 has no absorption in the Near Infrared Region (NIR). Therefore, it cannot be directly detected with any spectrometer measurement downhole. This paper will present innovative methods that can be used to predict the amount of N2 in each reservoir. These new techniques can help many clients in the EAG and as well as other basins to accurately quantify N2 without the need to wait for PVT laboratory analysis which generally takes several months to complete. Detection of non-hydrocarbon gases in oil and gas fluids, such as nitrogen gas, is very important for reservoir assessment and management. N2 content affects reserve estimation, especially in the area where reservoir fluids have high N2 contents. In our experience, there are several basins in Asia where N2 and CO2 coexist in the same reservoirs. N2 was charged into reservoirs from the source rock in the same geological time as Hydrocarbon (HC). The CO2 then later charged into the same reservoirs. Xu et al (2008) and Mullins (2019) suggested that the ratio of HC. and N2 are in proportional for each basin. However, the CO2 which was later charged are variable in each reservoir depending on CO2 source and charging area. The relationship between HC. and N2 can be used to predict amount of N2 using three proposed methods (1) Basin Base Method (2) Iteration Methods using DFA spectrometer and InSitu Density measurements., and (3) Equation of State (EOS) Method. This nitrogen prediction techniques were developed to better characterize reservoir fluids and overcome the limitation of the existing technology that's unable to detect and measure nitrogen at downhole conditions. This method can offer extra information, especially for our new Ora Intelligent Wireline Formation Tester technology where answer products will be expanded to tailor client objectives. The N2 and HC. relationship from each basin are examined in detail from our DFA and PVT data base. The ratio of N2 and HC. were then recorded as initial value for Basin Base Method. Then the second N2 prediction technique that uses individual hydrocarbon compositions and downhole density measurements were conducted to calculate missing N2 mass from spectrometer measurements. A ternary diagram was prepared to visualize and determine correlation of the gas composition components. It was found that straight line can be obtained on the Ternary diagram between N2, HC., and CO2 for each reservoir. A detailed calculation based on fluid components and partial densities together with iteration process allows to estimate the mass percentage of nitrogen. The results were then compared with actual value from PVT lab. These nitrogen predi
自20世纪90年代初以来，井下流体分析(DFA)就被开发出来，用于监测电缆地层测试器井下取样的泥浆滤液污染。DFA还可以实时提供准确的储层流体信息，如碳氢化合物成分(包括CO2)。然而，DFA技术无法测量氮气，因为氮气在近红外区域(NIR)没有吸收。因此，井下任何光谱仪都无法直接检测到。本文将介绍可用于预测每个储层中N2含量的创新方法。这些新技术可以帮助EAG和其他盆地的许多客户准确量化N2，而无需等待PVT实验室分析，通常需要几个月的时间才能完成。油气流体中非烃气体(如氮气)的检测对储层评价和管理具有重要意义。N2含量影响储量估算，特别是在储层流体N2含量高的地区。根据我们的经验，亚洲有几个盆地在同一储层中同时存在N2和CO2。N2与烃(HC)在同一地质时代从烃源岩充入储层。随后，二氧化碳被充入相同的储存库。Xu et al .(2008)和Mullins(2019)认为HC的比值。和N2在各盆地呈正比关系。然而，根据不同的CO2源和不同的充注区域，每个储层的充注CO2量是不同的。HC的关系。可采用3种方法(1)盆地基础法(2)DFA谱仪迭代法和原位密度测量法。(3)状态方程(EOS)法。开发这种氮预测技术是为了更好地表征储层流体，克服了现有技术无法在井下条件下检测和测量氮的局限性。这种方法可以提供额外的信息，特别是对于我们新的Ora智能电缆地层测试技术，答案产品将扩展以适应客户的目标。N2和HC。从我们的DFA和PVT数据库中详细检查了每个盆地的关系。N2和HC的比值。然后记录为盆地基础法的初始值。然后，采用第二种氮气预测技术，利用单个碳氢化合物组成和井下密度测量数据，计算光谱仪测量数据中缺失的氮气质量。制作了三元图，以直观地显示和确定气体组成成分的相关性。结果表明，在N2、HC的三元图上可以得到一条直线。和每个储层的二氧化碳。基于流体组分和局部密度的详细计算以及迭代过程可以估计氮的质量百分比。然后将结果与PVT实验室的实际值进行比较。这些氮预测技术已经使用来自东南亚和其他地区的各种数据集进行了测试和验证。该技术可以扩展为储层流体地球动力学(RFG)的一部分，以评估储层的横向连通性，并更好地了解储层的CO2和N2电荷。
{"title":"New Innovative Methods to Predict N2 in Real Time: Expand New Wireline Formation Testing Platform Products to Fit Basins","authors":"Shusheng Guo, Shiyue Wang, S. Daungkaew, Bei Gao, S. Chouya, O. Mullins, Jesus A. Cañas, S. Betancourt, A. Gisolf, T. Khunaworawet, D. Ling","doi":"10.4043/31487-ms","DOIUrl":"https://doi.org/10.4043/31487-ms","url":null,"abstract":"\u0000 Since early 1990's, Downhole Fluid Analysis (DFA) has been developed to monitor mud filtrate contamination for Wireline Formation Tester downhole sampling. DFA can also provide accurate reservoir fluid information in real time such as hydrocarbon composition including CO2. However, DFA technology cannot measure Nitrogen because N2 has no absorption in the Near Infrared Region (NIR). Therefore, it cannot be directly detected with any spectrometer measurement downhole. This paper will present innovative methods that can be used to predict the amount of N2 in each reservoir. These new techniques can help many clients in the EAG and as well as other basins to accurately quantify N2 without the need to wait for PVT laboratory analysis which generally takes several months to complete.\u0000 Detection of non-hydrocarbon gases in oil and gas fluids, such as nitrogen gas, is very important for reservoir assessment and management. N2 content affects reserve estimation, especially in the area where reservoir fluids have high N2 contents. In our experience, there are several basins in Asia where N2 and CO2 coexist in the same reservoirs. N2 was charged into reservoirs from the source rock in the same geological time as Hydrocarbon (HC). The CO2 then later charged into the same reservoirs. Xu et al (2008) and Mullins (2019) suggested that the ratio of HC. and N2 are in proportional for each basin. However, the CO2 which was later charged are variable in each reservoir depending on CO2 source and charging area. The relationship between HC. and N2 can be used to predict amount of N2 using three proposed methods (1) Basin Base Method (2) Iteration Methods using DFA spectrometer and InSitu Density measurements., and (3) Equation of State (EOS) Method. This nitrogen prediction techniques were developed to better characterize reservoir fluids and overcome the limitation of the existing technology that's unable to detect and measure nitrogen at downhole conditions. This method can offer extra information, especially for our new Ora Intelligent Wireline Formation Tester technology where answer products will be expanded to tailor client objectives.\u0000 The N2 and HC. relationship from each basin are examined in detail from our DFA and PVT data base. The ratio of N2 and HC. were then recorded as initial value for Basin Base Method. Then the second N2 prediction technique that uses individual hydrocarbon compositions and downhole density measurements were conducted to calculate missing N2 mass from spectrometer measurements. A ternary diagram was prepared to visualize and determine correlation of the gas composition components. It was found that straight line can be obtained on the Ternary diagram between N2, HC., and CO2 for each reservoir. A detailed calculation based on fluid components and partial densities together with iteration process allows to estimate the mass percentage of nitrogen. The results were then compared with actual value from PVT lab. These nitrogen predi","PeriodicalId":11011,"journal":{"name":"Day 3 Thu, March 24, 2022","volume":"124 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86286890","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}
Abdallah Magdy Darwish, A. K. Khalil, Mohamed El-Hussein El-Dessouky, Islam Ibrahim Mohamed, Tamer Hosny Abdelhalem
Halite scaling has a dreadful impact on production pipelines. Produced water from Nubia formation in "E" field has high level of total dissolved solids (TDS) concentration. Halite scale causes complete blockage of the flow paths, integrity complications and periodic production interruption. Pipeline pigging and flushing with fresh water were performed frequently to eliminate blockage and restore production. An offshore platform with six online gas lifted wells; two high rate wells are producing from Nubia formation through the production pipeline and the remaining low rate wells are producing from other formations with a lower TDS through the test pipeline. High saline water flows through the production pipeline and cools down to seabed temperature resulting in halite precipitation, which regularly blocks the pipeline and requires repetitive fresh water flushing and pigging operations. Laboratory water analysis and scale tendency were conducted in conjunction with a pipeline network model to predict the halite precipitation temperature, actual friction coefficient and optimum fluid mixing and dilution strategy. The combination of complete water analysis, scale tendency, real time remote monitoring system and pipeline network modeling showed that halite scaling started inside the subsea pipeline nearby the platform. The model matching revealed a high friction coefficient, which indicated partial plugging of the production pipeline. The model sensitivity analysis predicted that diluting the supersaturated water by mixing it with other wells’ lower salinity waters – into the same pipeline, would drop the mixture salinity with no halite scaling along the pipeline. As a result, the strategy of mixing was selected and optimized based on the modeling results and water compatibility tests to reduce losses due to back pressure and to minimize the risk of hard scale deposition. For more than a year, no halite has precipitated, which resulted in an uninterrupted production and allowed well testing of the remaining wells discretely through the test pipeline. This paper demonstrates a comprehensive case in which halite scaling issues were predicted and mitigated through an integrated scale management system. The operating expenditures of pipeline flushing and pigging operations and oil losses were decreased due to interrupted production.
{"title":"Preventing Halite Scaling in Offshore Pipelines Using Integrated Scale Management System and Modeling – Case Study from Gulf of Suez, Egypt","authors":"Abdallah Magdy Darwish, A. K. Khalil, Mohamed El-Hussein El-Dessouky, Islam Ibrahim Mohamed, Tamer Hosny Abdelhalem","doi":"10.4043/31455-ms","DOIUrl":"https://doi.org/10.4043/31455-ms","url":null,"abstract":"\u0000 Halite scaling has a dreadful impact on production pipelines. Produced water from Nubia formation in \"E\" field has high level of total dissolved solids (TDS) concentration. Halite scale causes complete blockage of the flow paths, integrity complications and periodic production interruption. Pipeline pigging and flushing with fresh water were performed frequently to eliminate blockage and restore production.\u0000 An offshore platform with six online gas lifted wells; two high rate wells are producing from Nubia formation through the production pipeline and the remaining low rate wells are producing from other formations with a lower TDS through the test pipeline. High saline water flows through the production pipeline and cools down to seabed temperature resulting in halite precipitation, which regularly blocks the pipeline and requires repetitive fresh water flushing and pigging operations. Laboratory water analysis and scale tendency were conducted in conjunction with a pipeline network model to predict the halite precipitation temperature, actual friction coefficient and optimum fluid mixing and dilution strategy.\u0000 The combination of complete water analysis, scale tendency, real time remote monitoring system and pipeline network modeling showed that halite scaling started inside the subsea pipeline nearby the platform. The model matching revealed a high friction coefficient, which indicated partial plugging of the production pipeline. The model sensitivity analysis predicted that diluting the supersaturated water by mixing it with other wells’ lower salinity waters – into the same pipeline, would drop the mixture salinity with no halite scaling along the pipeline. As a result, the strategy of mixing was selected and optimized based on the modeling results and water compatibility tests to reduce losses due to back pressure and to minimize the risk of hard scale deposition. For more than a year, no halite has precipitated, which resulted in an uninterrupted production and allowed well testing of the remaining wells discretely through the test pipeline.\u0000 This paper demonstrates a comprehensive case in which halite scaling issues were predicted and mitigated through an integrated scale management system. The operating expenditures of pipeline flushing and pigging operations and oil losses were decreased due to interrupted production.","PeriodicalId":11011,"journal":{"name":"Day 3 Thu, March 24, 2022","volume":"68 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89078134","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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