Mustafa Almuallim, R. Agarwal, A. Ruzhnikov, Paul Silva, Jaffar Al Shaikh, A. Aldape, Mohammad Al-Herz
Considering the nature of lumpsum turnkey contracts in the Middle East, multiple performance optimization initiatives have been engineered to accelerate well delivery without compromising well acceptance and compliance criteria. One of the most critical operations in these wells is the successful and efficient running of Inflow Control Device (ICD) as part of the lower completion across ±5, 000 feet of 6⅛-in. open hole lateral. Historically, this operation was associated with severe non-productive events and in worst case scenario, abandonment of entire section and eventual sidetrack. This study discusses detailed engineering analysis to enhance open preparation without a need to perform wiper trip with drilling BHA by creatively optimizing the design of cleanout and reaming bottom hole assemblies (BHAs) and the strategy of logging operation. Historically, dedicated trips were separately performed for borehole logging, open hole conditioning and cased hole cleanout. These trips were combined into a single BHA through application of fit-for-purpose technologies and optimization of operational sequence to minimize completion phase operational time. Moreover, risk of differential sticking while running completion string across highly permeable horizontal lateral was reduced by utilization of optimum completion fluids and efficient centralization program. Finally, an integrated model of real-time monitoring that interlinks trajectory, open hole, and BHA data and produces a sophisticated and accurate simulation of wellbore conditions based on previous logging and tripping data allowing for in-time intervention even prior to running completion string into wellbore. During the completion campaign of over 30 wells, all engineering, operational and monitoring solutions have been implemented and successfully allowed for 31%-time reduction in completion related operation. The creative drilling BHA design enabled elimination of mechanical wellbore risks associated with wellbore tortuosity and under-gauge and washed-out hole and thereby eradicating the need for wiper trip during drilling phase which was conducted to confirm hole conations prior to preforming Wire Line Tough Logging Condition (TLC) operation. This decreased well construction time by more than ±12-24 hours as the drilling BHA was directly pulled out hole to surface after reaching target well depth. Combined BHA strategy and optimization of operational sequence enabled wellbore cleanout, logging, and simulation to be conducted on single BHA run instead of three runs (TLC-logging run, reaming/ dummy BHA run, cleanout BHA run) which reduced overall well construction time by over ±48 hours. The three BHA runs were not historically possible to be combined due to tools and technology limitation as will be discussed in the following manuscript. Finally, proper selection of optimum drilling fluids, and bridging strategy integrated with enhanced centralization program and real-time monitoring system
{"title":"Holistic Approach Recipe for a Successful Deployment of ICD Lower Completion Achieving 31% Time Optimization for LSTK Projects in a Middle East Field","authors":"Mustafa Almuallim, R. Agarwal, A. Ruzhnikov, Paul Silva, Jaffar Al Shaikh, A. Aldape, Mohammad Al-Herz","doi":"10.2523/iptc-22871-ms","DOIUrl":"https://doi.org/10.2523/iptc-22871-ms","url":null,"abstract":"\u0000 Considering the nature of lumpsum turnkey contracts in the Middle East, multiple performance optimization initiatives have been engineered to accelerate well delivery without compromising well acceptance and compliance criteria. One of the most critical operations in these wells is the successful and efficient running of Inflow Control Device (ICD) as part of the lower completion across ±5, 000 feet of 6⅛-in. open hole lateral. Historically, this operation was associated with severe non-productive events and in worst case scenario, abandonment of entire section and eventual sidetrack.\u0000 This study discusses detailed engineering analysis to enhance open preparation without a need to perform wiper trip with drilling BHA by creatively optimizing the design of cleanout and reaming bottom hole assemblies (BHAs) and the strategy of logging operation. Historically, dedicated trips were separately performed for borehole logging, open hole conditioning and cased hole cleanout. These trips were combined into a single BHA through application of fit-for-purpose technologies and optimization of operational sequence to minimize completion phase operational time. Moreover, risk of differential sticking while running completion string across highly permeable horizontal lateral was reduced by utilization of optimum completion fluids and efficient centralization program. Finally, an integrated model of real-time monitoring that interlinks trajectory, open hole, and BHA data and produces a sophisticated and accurate simulation of wellbore conditions based on previous logging and tripping data allowing for in-time intervention even prior to running completion string into wellbore.\u0000 During the completion campaign of over 30 wells, all engineering, operational and monitoring solutions have been implemented and successfully allowed for 31%-time reduction in completion related operation. The creative drilling BHA design enabled elimination of mechanical wellbore risks associated with wellbore tortuosity and under-gauge and washed-out hole and thereby eradicating the need for wiper trip during drilling phase which was conducted to confirm hole conations prior to preforming Wire Line Tough Logging Condition (TLC) operation. This decreased well construction time by more than ±12-24 hours as the drilling BHA was directly pulled out hole to surface after reaching target well depth. Combined BHA strategy and optimization of operational sequence enabled wellbore cleanout, logging, and simulation to be conducted on single BHA run instead of three runs (TLC-logging run, reaming/ dummy BHA run, cleanout BHA run) which reduced overall well construction time by over ±48 hours. The three BHA runs were not historically possible to be combined due to tools and technology limitation as will be discussed in the following manuscript. Finally, proper selection of optimum drilling fluids, and bridging strategy integrated with enhanced centralization program and real-time monitoring system","PeriodicalId":283978,"journal":{"name":"Day 1 Wed, March 01, 2023","volume":"70 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-02-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"131645246","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}
Sustaining hydrocarbon production using artificial lifting technology could be daunting to say the least. Over time, both surface and subsurface challenges associated to artificial lift applications and electric submersible pumping systems in particular, that impact hydrocarbon production make the system unappealing and uneconomical for field development. This paper attempts to review the challenges impacting ESP system optimization for sustainable hydrocarbon production in both brown and green fields during the current big data era. The producing environment as well as the ESP components used in field development and production require continuous optimization across the ESP system spectrum. Analysis and diagnosis of the producing well completion is essential to achieving a better optimization and sustainability of the desired production target. A two-approach system optimization is preferred to address the challenges impacting sustainable hydrocarbon production in an ESP completed well. The approach enumerated in the paper relies on the innovative technological advancement of data capturing, segmentation, and integration brought about by the fourth industrial revolution. The approach involves a top-to-bottom optimization in addition to real-time data integration. The increasing sophistication in ESP system platforms’, mobility, surveillance, connectivity, and storage technologies, joined with the ability to process and rapidly analyze data, improve agility, and support real-time on the spot automated decision making. These enhancements allow action execution to overcome the numerous challenges impacting production sustainability in ESP completed wells. This brings about increased and timely engagement between the equipment manufacturer, operator and the well. In addition, there is reduction in well downtime, increased uptime with overall resultant of sustained hydrocarbon production. A comprehensive approach to artificial lift hydrocarbon production optimization in an ESP completed well using data interwoven connectivity is preferred as the best approach to reactivate, boost, and sustain hydrocarbon production in this era of digitalization.
{"title":"Sustainable Hydrocarbon Production Through ESP System Optimization in the Digital Era","authors":"T. C. Kalu-Ulu, Saud A. Khamees, Cleavant Flippin","doi":"10.2523/iptc-23085-ms","DOIUrl":"https://doi.org/10.2523/iptc-23085-ms","url":null,"abstract":"\u0000 Sustaining hydrocarbon production using artificial lifting technology could be daunting to say the least. Over time, both surface and subsurface challenges associated to artificial lift applications and electric submersible pumping systems in particular, that impact hydrocarbon production make the system unappealing and uneconomical for field development. This paper attempts to review the challenges impacting ESP system optimization for sustainable hydrocarbon production in both brown and green fields during the current big data era.\u0000 The producing environment as well as the ESP components used in field development and production require continuous optimization across the ESP system spectrum. Analysis and diagnosis of the producing well completion is essential to achieving a better optimization and sustainability of the desired production target. A two-approach system optimization is preferred to address the challenges impacting sustainable hydrocarbon production in an ESP completed well. The approach enumerated in the paper relies on the innovative technological advancement of data capturing, segmentation, and integration brought about by the fourth industrial revolution.\u0000 The approach involves a top-to-bottom optimization in addition to real-time data integration. The increasing sophistication in ESP system platforms’, mobility, surveillance, connectivity, and storage technologies, joined with the ability to process and rapidly analyze data, improve agility, and support real-time on the spot automated decision making. These enhancements allow action execution to overcome the numerous challenges impacting production sustainability in ESP completed wells. This brings about increased and timely engagement between the equipment manufacturer, operator and the well. In addition, there is reduction in well downtime, increased uptime with overall resultant of sustained hydrocarbon production.\u0000 A comprehensive approach to artificial lift hydrocarbon production optimization in an ESP completed well using data interwoven connectivity is preferred as the best approach to reactivate, boost, and sustain hydrocarbon production in this era of digitalization.","PeriodicalId":283978,"journal":{"name":"Day 1 Wed, March 01, 2023","volume":"29 6 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-02-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"133919879","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}
Huu Huy Vu, Manisa Rangponsumrit, N. Hoang, Duy Hung Nguyen, Hai Nam Tran, Ngoc Nguyen Phi, Tony Roche, Viet Long Dang, Minh Dung Tran
TGT field is located offshore Vietnam, at a water depth of 45m and approximately 100km Southeast of Vung Tau. The field started production in 2011 and is currently producing about 13k bopd. The produced crude is 38-40 deg. API with viscosity of 0.45 cP at reservoir conditions and classified as light oil. The field consists of three wellhead platforms with nearly 40 production wells, all being gas lifted. Emulsion, which is rarely encountered in downhole environment and not reported in the surrounding oil fields, was diagnosed to be present in production tubing of TGT wells by two indications: measured bottom-hole flowing pressure (BHFP) remarkably higher than calculated value, and emulsion observed on surface well fluid samples. Upon completion of the laboratory testing for chemical selection, in early 2020 a field trial was carried out by injecting demulsifier into the production tubing of selected wells via the chemical injection line or together with lift gas. A successful field trial resulted in a clear reduction of BHFP of the wells along with a production increase by approximately 13% from 8 tested wells. Due to the low-cost of the application and major economic gain compared to other IOR methods, long-term downhole demulsifier injection has been applied in additional wells for increasing the field production. Unlike for heavy oil developments, there is a lack of publications on downhole emulsion and demulsification for light oil fields. This paper describes a case study for application in a light oil field, covering identification of the wells having an emulsion issue in the production tubing, laboratory testing for selecting demulsifier, challenges in chemical deployment and the field trial results.
{"title":"Identification of Downhole Emulsion in a Light Oil Development and Demulsifier Injection for Increasing Production","authors":"Huu Huy Vu, Manisa Rangponsumrit, N. Hoang, Duy Hung Nguyen, Hai Nam Tran, Ngoc Nguyen Phi, Tony Roche, Viet Long Dang, Minh Dung Tran","doi":"10.2523/iptc-22754-ea","DOIUrl":"https://doi.org/10.2523/iptc-22754-ea","url":null,"abstract":"\u0000 TGT field is located offshore Vietnam, at a water depth of 45m and approximately 100km Southeast of Vung Tau. The field started production in 2011 and is currently producing about 13k bopd. The produced crude is 38-40 deg. API with viscosity of 0.45 cP at reservoir conditions and classified as light oil.\u0000 The field consists of three wellhead platforms with nearly 40 production wells, all being gas lifted. Emulsion, which is rarely encountered in downhole environment and not reported in the surrounding oil fields, was diagnosed to be present in production tubing of TGT wells by two indications: measured bottom-hole flowing pressure (BHFP) remarkably higher than calculated value, and emulsion observed on surface well fluid samples.\u0000 Upon completion of the laboratory testing for chemical selection, in early 2020 a field trial was carried out by injecting demulsifier into the production tubing of selected wells via the chemical injection line or together with lift gas. A successful field trial resulted in a clear reduction of BHFP of the wells along with a production increase by approximately 13% from 8 tested wells. Due to the low-cost of the application and major economic gain compared to other IOR methods, long-term downhole demulsifier injection has been applied in additional wells for increasing the field production.\u0000 Unlike for heavy oil developments, there is a lack of publications on downhole emulsion and demulsification for light oil fields. This paper describes a case study for application in a light oil field, covering identification of the wells having an emulsion issue in the production tubing, laboratory testing for selecting demulsifier, challenges in chemical deployment and the field trial results.","PeriodicalId":283978,"journal":{"name":"Day 1 Wed, March 01, 2023","volume":"285 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-02-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"122691618","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
The electric submersible pump (ESP) is one of the most reliable artificial lift methods for delivering high flow rates in oil wells. If well designed for reservoir properties, ESPs may run for several years before failing. Despite many ESP design advancements, electrical connections remain within the most prominent points of failure in high H2S environments. This paper presents an innovative approach to mitigate electrical connection failures by encapsulating the ESP system for extended ESP run life in high H2S environments. Following an ESP design review to explore current practices in mitigating ESP electrical-connection failures in sour wells, an innovative ESP system was designed to eliminate electrical-connections’ contact with well fluid. The ESP is connected from the top to a production tubing, encapsulated within a pressure-retaining pod, and located above a deeply set production packer. The motor head is designed to partially set outside the pod to accommodate electrical-cable connection, while partially encapsulated within the pod to deliver the necessary electrical supply to the ESP motor. The tubing-casing annulus (TCA) is then filled with inhibited-brine to protect the electrical connections. Experts in the field typically select special ESP metallurgy and electrical connections (i.e., metal to metal) in high H2S wells to extend the run life of ESP systems. Although the development of multiple versions of electrical connections can mitigate H2S attacks, field experience has shown progress in sour environments where ESP run life is not yet matching mild environments. Most efforts were made to minimize H2S attacks on ESP electrical-connections by developing robust ESP systems, but little to no effort was made to eliminate the risk. This challenge can be undertaken by encapsulating the ESP system to avert electrical connection contact with well fluid. Thus, it provided a radical solution to one of the most common ESP failure points in sour environments. The encapsulated ESP system is a new concept, for which a patent is pending, designed to address electrical connection failures for an extended run life in high H2S environments. This paper will discuss the background and design of the system and its potential to eliminate electrical connection integrity issues.
{"title":"Encapsulated ESP System: An Innovative Solution for Extended Run Life in High H2S Environments","authors":"Anwar S. Alghamdi","doi":"10.2523/iptc-22802-ea","DOIUrl":"https://doi.org/10.2523/iptc-22802-ea","url":null,"abstract":"\u0000 The electric submersible pump (ESP) is one of the most reliable artificial lift methods for delivering high flow rates in oil wells. If well designed for reservoir properties, ESPs may run for several years before failing. Despite many ESP design advancements, electrical connections remain within the most prominent points of failure in high H2S environments. This paper presents an innovative approach to mitigate electrical connection failures by encapsulating the ESP system for extended ESP run life in high H2S environments.\u0000 Following an ESP design review to explore current practices in mitigating ESP electrical-connection failures in sour wells, an innovative ESP system was designed to eliminate electrical-connections’ contact with well fluid. The ESP is connected from the top to a production tubing, encapsulated within a pressure-retaining pod, and located above a deeply set production packer. The motor head is designed to partially set outside the pod to accommodate electrical-cable connection, while partially encapsulated within the pod to deliver the necessary electrical supply to the ESP motor. The tubing-casing annulus (TCA) is then filled with inhibited-brine to protect the electrical connections.\u0000 Experts in the field typically select special ESP metallurgy and electrical connections (i.e., metal to metal) in high H2S wells to extend the run life of ESP systems. Although the development of multiple versions of electrical connections can mitigate H2S attacks, field experience has shown progress in sour environments where ESP run life is not yet matching mild environments. Most efforts were made to minimize H2S attacks on ESP electrical-connections by developing robust ESP systems, but little to no effort was made to eliminate the risk. This challenge can be undertaken by encapsulating the ESP system to avert electrical connection contact with well fluid. Thus, it provided a radical solution to one of the most common ESP failure points in sour environments.\u0000 The encapsulated ESP system is a new concept, for which a patent is pending, designed to address electrical connection failures for an extended run life in high H2S environments. This paper will discuss the background and design of the system and its potential to eliminate electrical connection integrity issues.","PeriodicalId":283978,"journal":{"name":"Day 1 Wed, March 01, 2023","volume":"90 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-02-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"124574998","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}
Rasim Serdar Rodoplu, I. Brohi, K. S. Al-Mohanna, A. A. Qahtani
Different approaches and techniques were utilized in the industry to overcome challenges in sanding formations, including frac-packs, indirect fracturing, and resin coated proppants. Due to complexities in the results achieved, open hole multistage fracturing (OH MSF) with a sand control completion system was introduced with the goal of expanding the technology portfolio for controlling sand production and proppant flowback. Offset wells drilled in a prolific gas-bearing unconsolidated sandstone formation showed high sand and proppant production restricting the potential from these wells. Therefore, it was necessary to develop a new OH MSF completion strategy to address sand/proppant control and combine it with proppant fracturing at the same time. This paper highlights OH MSF technology that utilizes screened port sleeves capable of withstanding fracturing pressures and harsh environments. The new completion system consists of a hydraulic frac port opened by applying pressure in the first stage. In addition, the fracturing ports for the next stages are opened by dropping activation balls. Each stage needs to be equipped with a sleeve fused with a screen for sand and/or proppant control. Stages are separated by open hole packers for zonal isolation in the open hole section. It is an innovative system that combines MSF completion with sand control components. Due to the complex nature of the completion, rigless well intervention operations must be well planned, discussed, and conducted with close monitoring during all the operations. In particular, frac port opening/closing, sand screened sleeves opening with coiled tubing (CT) well interventions, proppant fracturing operations, and e-line production logging tools (PLTs). Besides, if the transmissibility is high with a high leak off and quick closure of fracture, then frac operations should be performed with the objective of creating a tip screen out (TSO) scenario to achieve good proppant packing close to the wellbore area. Production rates after completing proppant fracturing, CT milling, and shifting interventions exceeded the expectations without any sand or proppant flowback. The candidate well's rate remained higher than offset wells and no sand nor proppant were observed on the surface. The new OH MSF with sand control completion technology will enable performing OH MSF treatments in gas formations with a high sanding tendency. In addition, it helps to diversify technologies utilized to enhance production without producing formation sand or proppant. Utilization in the right candidate in conjunction with an optimum engineering approach and optimized design will ensure obtaining the benefits of this new completion system to overcome similar challenges.
{"title":"A New Multistage Fracturing Completion Approach for Sanding Formations: First Application in the Region","authors":"Rasim Serdar Rodoplu, I. Brohi, K. S. Al-Mohanna, A. A. Qahtani","doi":"10.2523/iptc-22755-ms","DOIUrl":"https://doi.org/10.2523/iptc-22755-ms","url":null,"abstract":"\u0000 Different approaches and techniques were utilized in the industry to overcome challenges in sanding formations, including frac-packs, indirect fracturing, and resin coated proppants. Due to complexities in the results achieved, open hole multistage fracturing (OH MSF) with a sand control completion system was introduced with the goal of expanding the technology portfolio for controlling sand production and proppant flowback.\u0000 Offset wells drilled in a prolific gas-bearing unconsolidated sandstone formation showed high sand and proppant production restricting the potential from these wells. Therefore, it was necessary to develop a new OH MSF completion strategy to address sand/proppant control and combine it with proppant fracturing at the same time. This paper highlights OH MSF technology that utilizes screened port sleeves capable of withstanding fracturing pressures and harsh environments.\u0000 The new completion system consists of a hydraulic frac port opened by applying pressure in the first stage. In addition, the fracturing ports for the next stages are opened by dropping activation balls. Each stage needs to be equipped with a sleeve fused with a screen for sand and/or proppant control. Stages are separated by open hole packers for zonal isolation in the open hole section. It is an innovative system that combines MSF completion with sand control components.\u0000 Due to the complex nature of the completion, rigless well intervention operations must be well planned, discussed, and conducted with close monitoring during all the operations. In particular, frac port opening/closing, sand screened sleeves opening with coiled tubing (CT) well interventions, proppant fracturing operations, and e-line production logging tools (PLTs). Besides, if the transmissibility is high with a high leak off and quick closure of fracture, then frac operations should be performed with the objective of creating a tip screen out (TSO) scenario to achieve good proppant packing close to the wellbore area.\u0000 Production rates after completing proppant fracturing, CT milling, and shifting interventions exceeded the expectations without any sand or proppant flowback. The candidate well's rate remained higher than offset wells and no sand nor proppant were observed on the surface.\u0000 The new OH MSF with sand control completion technology will enable performing OH MSF treatments in gas formations with a high sanding tendency. In addition, it helps to diversify technologies utilized to enhance production without producing formation sand or proppant. Utilization in the right candidate in conjunction with an optimum engineering approach and optimized design will ensure obtaining the benefits of this new completion system to overcome similar challenges.","PeriodicalId":283978,"journal":{"name":"Day 1 Wed, March 01, 2023","volume":"113 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-02-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"121413268","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}
Tanporn Pitibhabhong, R. Chakraborty, S. H. Ng, C. K. Lim, I. Paton, N. Phantawee
The Sandalford area, located in Australia’s northwestern continental margin, is proximal to the Cash-Maple and Tenacious field discoveries. The area has Eocene-Paleocene Carbonates overlying siliciclastic Cretaceous section, resulting in a strong velocity inversion as well as generating complex free-surface and internal-multiple contaminations at the deeper Jurassic reservoir section. We present a reprocessing case study of a narrow-azimuth, towed-streamer seismic dataset acquired in shallow water using advanced multiple attenuation and earth model building techniques, with the main goal of improving our understanding of the complex geology beneath. The multiple attenuation part of the workflow employs a cascaded approach, initially addressing water-layer multiples, remaining free-surface multiples, and followed with internal multiples. Implementation of high-frequency visco-acoustic full-waveform inversion (Q-FWI) improved the overburden velocity model and combined with effective multiple attenuation algorithms, reduced the uncertainty of primary events in the pre-carbonate section, therefore reducing errors in common image point (CIP) tomography. The results were quality-controlled against the well data, providing new insights with improved structural and stratigraphic delineation.
{"title":"Advanced Multiple Attenuation and Model Building Techniques Provide New Insights Into the Jurassic Play of Timor sea, Offshore Australia","authors":"Tanporn Pitibhabhong, R. Chakraborty, S. H. Ng, C. K. Lim, I. Paton, N. Phantawee","doi":"10.2523/iptc-22780-ea","DOIUrl":"https://doi.org/10.2523/iptc-22780-ea","url":null,"abstract":"\u0000 The Sandalford area, located in Australia’s northwestern continental margin, is proximal to the Cash-Maple and Tenacious field discoveries. The area has Eocene-Paleocene Carbonates overlying siliciclastic Cretaceous section, resulting in a strong velocity inversion as well as generating complex free-surface and internal-multiple contaminations at the deeper Jurassic reservoir section. We present a reprocessing case study of a narrow-azimuth, towed-streamer seismic dataset acquired in shallow water using advanced multiple attenuation and earth model building techniques, with the main goal of improving our understanding of the complex geology beneath. The multiple attenuation part of the workflow employs a cascaded approach, initially addressing water-layer multiples, remaining free-surface multiples, and followed with internal multiples. Implementation of high-frequency visco-acoustic full-waveform inversion (Q-FWI) improved the overburden velocity model and combined with effective multiple attenuation algorithms, reduced the uncertainty of primary events in the pre-carbonate section, therefore reducing errors in common image point (CIP) tomography. The results were quality-controlled against the well data, providing new insights with improved structural and stratigraphic delineation.","PeriodicalId":283978,"journal":{"name":"Day 1 Wed, March 01, 2023","volume":"7 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-02-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"115672177","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}
N. Nopsiri, E. Samuel, Lee Chan Fong, Alxner Kalalo, Nicholas Moses, Agus Jayadi, Ding Yi
Amongst the challenges encountered during infill drilling and completion is the requirement to penetrate depleted zones drained during the early phases of the field development. This condition is exacerbated for completions requiring openhole gravel pack as the maximum openhole lengths are traditionally limited by the effective circulating density experienced during the openhole drilling and gravel packing. This paper discusses the techniques implemented in four openhole gravel pack completions with openhole lengths up to 858m marking a new record for the longest openhole completed by PTTEP in this field. The wells were deployed by PTTEP in the Malaysian Deepwater Block K, during the field development of Siakap North Petai Phase 2, executed between Q4 2021 and Q1 2022.
在填充钻井和完井过程中遇到的挑战之一是，在油田开发的早期阶段，需要穿透枯竭的区域。这种情况在需要裸眼砾石充填的完井中更为严重，因为裸眼钻井和砾石充填期间的有效循环密度限制了裸眼最大长度。本文讨论了在4个裸眼砾石充填完井中实施的技术，裸眼长度达到858m，创造了PTTEP在该领域完成的最长裸眼的新纪录。这些井由PTTEP部署在马来西亚深水区块K，在Siakap North Petai第二期油田开发期间，于2021年第四季度至2022年第一季度执行。
{"title":"Expanding the Envelopes of Openhole Gravel Packing in Sabah Deepwater Malaysia","authors":"N. Nopsiri, E. Samuel, Lee Chan Fong, Alxner Kalalo, Nicholas Moses, Agus Jayadi, Ding Yi","doi":"10.2523/iptc-22743-ms","DOIUrl":"https://doi.org/10.2523/iptc-22743-ms","url":null,"abstract":"\u0000 Amongst the challenges encountered during infill drilling and completion is the requirement to penetrate depleted zones drained during the early phases of the field development. This condition is exacerbated for completions requiring openhole gravel pack as the maximum openhole lengths are traditionally limited by the effective circulating density experienced during the openhole drilling and gravel packing. This paper discusses the techniques implemented in four openhole gravel pack completions with openhole lengths up to 858m marking a new record for the longest openhole completed by PTTEP in this field. The wells were deployed by PTTEP in the Malaysian Deepwater Block K, during the field development of Siakap North Petai Phase 2, executed between Q4 2021 and Q1 2022.","PeriodicalId":283978,"journal":{"name":"Day 1 Wed, March 01, 2023","volume":"351 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-02-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"115465160","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}
Penporn Sirilatthaporn, Suchat Komesvarakul, S. Kumseranee, Chao Trithipchatsakul, S. Punpruk
With recent sour gas field discoveries, material selection for export pipeline carrying the sour gas and liquid is one of the key challenges in commercializing the fields especially for the large diameter and long tie-back export pipeline, and it is the focus of this paper. Both CRA clad and Carbon Steel (CS) pipes have been used for sour service pipelines with different benefit and drawback. The study was performed to investigate both technical and commercial feasibility of the two material options. Facility concept has been differentiated between options as CRA clad pipe do not require gas and liquid dehydration and treatment. The conceptual study cover design, fabrication, installation, operation, RAM and risk assessment aspects to identify the key strength and challenges including cost estimation for life cycle cost evaluation. Material selection review including project benchmarking for TMCP CS for sour service has been performed. CRA clad option provides the lowest corrosion and cracking risk leading to minimum requirement for offshore processing facility. However, additional or larger facilities are needed at onshore gas plant such as Slug Catcher and PW treatment. Two main concerns for CRA clad pipe are the buckling due to exporting > 150 deg C fluids and the supply of CRA clad pipes for such a large quantity. TMCP CS option is more conventional for export pipeline with the main concern on the susceptibility for Sulfide Stress Cracking for sour service especially after the Kashagan incident. The study investigates the recent development of LHZ mitigation actions in manufacturing process, new pre-qualification recently published for extreme sour service and project benchmarking for similar H2S concentration. It has been concluded TMCP CS, with qualified manufacturer, is suitable for the extreme sour service application. Life cycle cost estimation indicate CRA clad option is significantly more expensive than CS option with the risk on the supply of cladded pipe. Cracking risk on TMCP CS for extreme sour service is high but manageable with the proven project record and therefore CS option is opted as development concept with the lower development cost than that for CRA clad.
{"title":"Export Pipeline Material Selection for Extreme Sour Service Application","authors":"Penporn Sirilatthaporn, Suchat Komesvarakul, S. Kumseranee, Chao Trithipchatsakul, S. Punpruk","doi":"10.2523/iptc-22738-ea","DOIUrl":"https://doi.org/10.2523/iptc-22738-ea","url":null,"abstract":"\u0000 With recent sour gas field discoveries, material selection for export pipeline carrying the sour gas and liquid is one of the key challenges in commercializing the fields especially for the large diameter and long tie-back export pipeline, and it is the focus of this paper. Both CRA clad and Carbon Steel (CS) pipes have been used for sour service pipelines with different benefit and drawback. The study was performed to investigate both technical and commercial feasibility of the two material options. Facility concept has been differentiated between options as CRA clad pipe do not require gas and liquid dehydration and treatment. The conceptual study cover design, fabrication, installation, operation, RAM and risk assessment aspects to identify the key strength and challenges including cost estimation for life cycle cost evaluation. Material selection review including project benchmarking for TMCP CS for sour service has been performed. CRA clad option provides the lowest corrosion and cracking risk leading to minimum requirement for offshore processing facility. However, additional or larger facilities are needed at onshore gas plant such as Slug Catcher and PW treatment. Two main concerns for CRA clad pipe are the buckling due to exporting > 150 deg C fluids and the supply of CRA clad pipes for such a large quantity. TMCP CS option is more conventional for export pipeline with the main concern on the susceptibility for Sulfide Stress Cracking for sour service especially after the Kashagan incident. The study investigates the recent development of LHZ mitigation actions in manufacturing process, new pre-qualification recently published for extreme sour service and project benchmarking for similar H2S concentration. It has been concluded TMCP CS, with qualified manufacturer, is suitable for the extreme sour service application. Life cycle cost estimation indicate CRA clad option is significantly more expensive than CS option with the risk on the supply of cladded pipe. Cracking risk on TMCP CS for extreme sour service is high but manageable with the proven project record and therefore CS option is opted as development concept with the lower development cost than that for CRA clad.","PeriodicalId":283978,"journal":{"name":"Day 1 Wed, March 01, 2023","volume":"8 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-02-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"125620653","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}
Dealing with two combinations of high potential risks, HPHT wells and H2S hazards, is major challenge in project development. Reduction of offshore personnel and risk exposure hour becomes key aim of the project. Enable digitalization technologies becomes mainstream to promote project purpose. This paper demonstrates how digitalization is planned to implement and how it supports the HPHT and sour gas field development project. In addition to high risks, the overall cost of investment and the availability of modern technologies were evaluated, the plant design and operational concept focuses on remote control and operation with Not Normally Manned design concept. Digitalization will make production-effective development with the same functionality and robustness as human operations and maintenance of the facility's performance and safety. Main infrastructure including high bandwidth low latency wired/wireless network across facilities, and real-time onboard data and intelligent platform are prepared to support digitalization readiness. Personnel risk offshore is minimized through the remote-control concept which the facility is monitored from onshore with capability to remote reset/restart, health and performance monitoring, remote decision-making and execution, and crew assistance. Robotic technology will also be considered as additional means for remote monitoring. Secondary control room located offshore linked through fiber optic cable with the same degree of control as onshore will be included to allow local operations during commissioning, start-up, early operation, troubleshooting and maintenance campaigns. The project targets to deploy real-time digital data platform for monitoring and inspection producing large amounts of data for analysis to increase efficient operations. Digital twin application, where the real-time data, and repository of information on the equipment can be used for operations and maintenance purposes, can be further implemented, i.e., design phase for process control design and simulation, training simulator during plant start-up, and plant optimization during operational phase. The personnel and equipment tracking on real-time basis will also be considered to encourage fast and efficient evacuation in an emergency. All systems are designed based on best practices design in Cybersecurity concepts to enable protected related networks, equipment, location and data from attack, damage, or unauthorized access. Introducing nowadays digitalization technologies in the project, could reduce hazardous risks and number of personnel activities on the facilities as well as optimizing production operations performance. It should be started at the early stage of the project. Main challenge is lacking successfully reference and benchmarking projects. All digitalization applications and technologies should be carefully assessed and validated to ensure that they are suitable and valuable for the project requirements.
{"title":"Enabling Digitalisation in HPHT and High H2S Field Development Project","authors":"Noppadol Iamtanasinchai, Suparit Borisuth, Thapanic Khukhantin, Winyou Rinnanont, Suchat Komesvarakul","doi":"10.2523/iptc-22761-ms","DOIUrl":"https://doi.org/10.2523/iptc-22761-ms","url":null,"abstract":"\u0000 Dealing with two combinations of high potential risks, HPHT wells and H2S hazards, is major challenge in project development. Reduction of offshore personnel and risk exposure hour becomes key aim of the project. Enable digitalization technologies becomes mainstream to promote project purpose. This paper demonstrates how digitalization is planned to implement and how it supports the HPHT and sour gas field development project.\u0000 In addition to high risks, the overall cost of investment and the availability of modern technologies were evaluated, the plant design and operational concept focuses on remote control and operation with Not Normally Manned design concept.\u0000 Digitalization will make production-effective development with the same functionality and robustness as human operations and maintenance of the facility's performance and safety. Main infrastructure including high bandwidth low latency wired/wireless network across facilities, and real-time onboard data and intelligent platform are prepared to support digitalization readiness.\u0000 Personnel risk offshore is minimized through the remote-control concept which the facility is monitored from onshore with capability to remote reset/restart, health and performance monitoring, remote decision-making and execution, and crew assistance. Robotic technology will also be considered as additional means for remote monitoring. Secondary control room located offshore linked through fiber optic cable with the same degree of control as onshore will be included to allow local operations during commissioning, start-up, early operation, troubleshooting and maintenance campaigns.\u0000 The project targets to deploy real-time digital data platform for monitoring and inspection producing large amounts of data for analysis to increase efficient operations. Digital twin application, where the real-time data, and repository of information on the equipment can be used for operations and maintenance purposes, can be further implemented, i.e., design phase for process control design and simulation, training simulator during plant start-up, and plant optimization during operational phase. The personnel and equipment tracking on real-time basis will also be considered to encourage fast and efficient evacuation in an emergency.\u0000 All systems are designed based on best practices design in Cybersecurity concepts to enable protected related networks, equipment, location and data from attack, damage, or unauthorized access.\u0000 Introducing nowadays digitalization technologies in the project, could reduce hazardous risks and number of personnel activities on the facilities as well as optimizing production operations performance. It should be started at the early stage of the project. Main challenge is lacking successfully reference and benchmarking projects. All digitalization applications and technologies should be carefully assessed and validated to ensure that they are suitable and valuable for the project requirements.","PeriodicalId":283978,"journal":{"name":"Day 1 Wed, March 01, 2023","volume":"374 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-02-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"126174444","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}
Ultra-Deep electromagnetic (EM) azimuthal measurements provide critical data for well placement operations, allowing real-time assessment of resistivity boundaries over 100ft from the well. Historically, 1D and 2D inversions displayed vertical boundary changes, however they do not resolve azimuthal changes. Other 3D approaches lacked real-time aspect or endured costly deployment. This paper describes integration of real-time 3D EM Inversions for both inclination and azimuth trajectory corrections, to optimize well path and increase efficiency while drilling HA/HZ wells. Triaxial ultra-deep electromagnetic borehole logging tools provide 9 component multi-frequency data from multiple receiver assemblies, logging the 3D EM field around the wellbore. Although the raw component data shows observable signal changes representing the 3D EM field, evaluating this raw data in real-time is challenging. Therefore, a 3D EM inversion was implemented to provide real-time 3D representation of the geological structure and fluid distribution around the well. The 3D EM Inversion algorithm has been optimized to return model updates within a few minutes. The near real-time process allows well placement decisions to be made very quickly to help maintain the well path within the target reservoir. Real-time monitoring of the 3D EM inversion revealed a lateral disparity in the resistivity distribution for the target reservoir. In a particular interval, the presence of higher resistivity to the right-hand side of the well bore was revealed. The increase in resistivity was identified as improved reservoir properties. The trajectory of the well was adjusted to the right, interactively adjusting the plan. As with all deviations from the plan the impact of the azimuthal turn was assessed both in terms of safety and the potential impact on running the completion, no risks were identified, and a successful turn was conducted. Using the same methodology, a turn to the left of the well bore was conducted towards the toe of the well. Optimizing a wells TVD with inclination is common, but azimuthal changes based on LWD readings are much less so. The 3D Inversion and azimuthal resistivity measurements helped to minimize the loss of the effective length of the wellbore during the drilling in a complex geological structure. The effectiveness of the azimuthal turn can be assessed by comparing the resistivity of the actual and planned trajectories, estimated to have a 24-foot separation. The actual trajectory was placed in a zone with optimum quality reservoir without loss of the effective length (100% NTG). Real-time 3D Inversion has enabled for the first time the ability to steer azimuthally based on Ultra-deep EM data, changing the hole azimuth in real-time to target improved reservoir properties. The method of correcting the well path with azimuth as well as inclination in real-time based on 3D Inversion data ensures maximum efficiency for the well placement process in complex
{"title":"The First Successful Azimuthal Well Placement Utilizing Real-Time Azimuthal Resistivity Measurements and Ultra-Deep 3D Inversion","authors":"A. Elkhamry, N. Clegg, A. Taher, E. Bikchandaev","doi":"10.2523/iptc-22779-ea","DOIUrl":"https://doi.org/10.2523/iptc-22779-ea","url":null,"abstract":"\u0000 Ultra-Deep electromagnetic (EM) azimuthal measurements provide critical data for well placement operations, allowing real-time assessment of resistivity boundaries over 100ft from the well. Historically, 1D and 2D inversions displayed vertical boundary changes, however they do not resolve azimuthal changes. Other 3D approaches lacked real-time aspect or endured costly deployment. This paper describes integration of real-time 3D EM Inversions for both inclination and azimuth trajectory corrections, to optimize well path and increase efficiency while drilling HA/HZ wells.\u0000 Triaxial ultra-deep electromagnetic borehole logging tools provide 9 component multi-frequency data from multiple receiver assemblies, logging the 3D EM field around the wellbore. Although the raw component data shows observable signal changes representing the 3D EM field, evaluating this raw data in real-time is challenging. Therefore, a 3D EM inversion was implemented to provide real-time 3D representation of the geological structure and fluid distribution around the well. The 3D EM Inversion algorithm has been optimized to return model updates within a few minutes. The near real-time process allows well placement decisions to be made very quickly to help maintain the well path within the target reservoir.\u0000 Real-time monitoring of the 3D EM inversion revealed a lateral disparity in the resistivity distribution for the target reservoir. In a particular interval, the presence of higher resistivity to the right-hand side of the well bore was revealed. The increase in resistivity was identified as improved reservoir properties. The trajectory of the well was adjusted to the right, interactively adjusting the plan. As with all deviations from the plan the impact of the azimuthal turn was assessed both in terms of safety and the potential impact on running the completion, no risks were identified, and a successful turn was conducted. Using the same methodology, a turn to the left of the well bore was conducted towards the toe of the well. Optimizing a wells TVD with inclination is common, but azimuthal changes based on LWD readings are much less so.\u0000 The 3D Inversion and azimuthal resistivity measurements helped to minimize the loss of the effective length of the wellbore during the drilling in a complex geological structure. The effectiveness of the azimuthal turn can be assessed by comparing the resistivity of the actual and planned trajectories, estimated to have a 24-foot separation. The actual trajectory was placed in a zone with optimum quality reservoir without loss of the effective length (100% NTG).\u0000 Real-time 3D Inversion has enabled for the first time the ability to steer azimuthally based on Ultra-deep EM data, changing the hole azimuth in real-time to target improved reservoir properties. The method of correcting the well path with azimuth as well as inclination in real-time based on 3D Inversion data ensures maximum efficiency for the well placement process in complex","PeriodicalId":283978,"journal":{"name":"Day 1 Wed, March 01, 2023","volume":"57 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-02-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"124369225","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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