Corrosion underneath riser hangers and clamps in the splash zone area is historically challenging for inspectors. It is a chronic problem for offshore pipeline operators which could lead to significant failures and loss of primary containment. When the degradation of the protective coating system occurs, it will result in external severe corrosion. The splash zone riser is exposed to intermittent seawater wetting. Especially at crevice areas which can form and accelerate small concentration corrosion cells creating indiscernible localized corrosion or deep grooves. Close visual inspection (CVI) is a conventional nondestructive examination (NDE) technique to notify a sign of corrosion. This is a very subjective and qualitative measurement. Wall loss, depth, and sizing are unknown. In order to identify the condition underneath the riser clamp without clamp removal, the company has studied the principle of advanced NDE techniques, mockup tests, and field trials. The main objective is to identify, quantify, and prioritize the severity of corrosion anomalies underneath the clamp for further maintenance and repair plans to prevent pipeline failure. The selected techniques are Computed Radiography Testing (CRT), Medium-Range Ultrasonic testing (MRUT), and Long-Range Ultrasonic testing (LRUT). The result shows that LRUT can be further developed to suit the company's purposes.
{"title":"Advanced Inspection Technologies for Corrosion Underneath Splash Zone Riser Hangers and Clamps","authors":"Kamonwan Ruangpattanatawee, Chatchai Laemkhowthong, Suthisak Thepsriha, Sorakom Promsakulchai, M. Thammachart, Chanapol Limsakul, Athipkiat Lertthanasart","doi":"10.4043/31679-ms","DOIUrl":"https://doi.org/10.4043/31679-ms","url":null,"abstract":"\u0000 Corrosion underneath riser hangers and clamps in the splash zone area is historically challenging for inspectors. It is a chronic problem for offshore pipeline operators which could lead to significant failures and loss of primary containment. When the degradation of the protective coating system occurs, it will result in external severe corrosion. The splash zone riser is exposed to intermittent seawater wetting. Especially at crevice areas which can form and accelerate small concentration corrosion cells creating indiscernible localized corrosion or deep grooves.\u0000 Close visual inspection (CVI) is a conventional nondestructive examination (NDE) technique to notify a sign of corrosion. This is a very subjective and qualitative measurement. Wall loss, depth, and sizing are unknown. In order to identify the condition underneath the riser clamp without clamp removal, the company has studied the principle of advanced NDE techniques, mockup tests, and field trials. The main objective is to identify, quantify, and prioritize the severity of corrosion anomalies underneath the clamp for further maintenance and repair plans to prevent pipeline failure. The selected techniques are Computed Radiography Testing (CRT), Medium-Range Ultrasonic testing (MRUT), and Long-Range Ultrasonic testing (LRUT). The result shows that LRUT can be further developed to suit the company's purposes.","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":"79078277","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}
Wan Farra Ayesha Binti Wan Muhaimin, M. S. Liew, N. Zawawi, L. E. Shawn, Anas Khaled Al Sheikh, Siddique Mohd Yatim Bin Salim, K. U. Danyaro
In the study of structural strength, the reserve strength ratio provides a measure of the ultimate strength capacity of a structure. Under actual site conditions, the reserve strength ratio may vary from its design values with loss of stiffness and changes in structural integrity. Changes in the vibrational response of a structure due to loss of stiffness is observed as a form of structural health monitoring (SHM). The aim of this study is to investigate the relationship and sensitivity of the reserve strength ratio of a structure to changes in natural frequency due to damage occurrences as a measure of global structural integrity. The reduction of stiffness is simulated by the sequential removal of members according loading path within the model. To obtain the values used for comparison, a non-linear pushover analysis and eigenvalue analysis is utilized to obtain the Reserve Strength Ratio (RSR) and eigenvalue for intact as well as simulated progressive damage conditions. The pattern recognized from the analysis performed indicated that as the reserve strength ratio (RSR) is reduced with reduction of stiffness by the removal of primary and secondary members, the eigenvalues for each respective model showing similar reductions.
{"title":"An Investigation on the Influence of Structural Damage on Eigenvalue Characteristics and Reserve Strength Ratio of Onshore Lattice Steel Structures","authors":"Wan Farra Ayesha Binti Wan Muhaimin, M. S. Liew, N. Zawawi, L. E. Shawn, Anas Khaled Al Sheikh, Siddique Mohd Yatim Bin Salim, K. U. Danyaro","doi":"10.4043/31525-ms","DOIUrl":"https://doi.org/10.4043/31525-ms","url":null,"abstract":"\u0000 In the study of structural strength, the reserve strength ratio provides a measure of the ultimate strength capacity of a structure. Under actual site conditions, the reserve strength ratio may vary from its design values with loss of stiffness and changes in structural integrity. Changes in the vibrational response of a structure due to loss of stiffness is observed as a form of structural health monitoring (SHM). The aim of this study is to investigate the relationship and sensitivity of the reserve strength ratio of a structure to changes in natural frequency due to damage occurrences as a measure of global structural integrity. The reduction of stiffness is simulated by the sequential removal of members according loading path within the model. To obtain the values used for comparison, a non-linear pushover analysis and eigenvalue analysis is utilized to obtain the Reserve Strength Ratio (RSR) and eigenvalue for intact as well as simulated progressive damage conditions. The pattern recognized from the analysis performed indicated that as the reserve strength ratio (RSR) is reduced with reduction of stiffness by the removal of primary and secondary members, the eigenvalues for each respective model showing similar reductions.","PeriodicalId":11011,"journal":{"name":"Day 3 Thu, March 24, 2022","volume":"42 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"80104431","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}
Krongrath Suwannasri, Cheong Yaw Peng, S. Asawachaisujja, R. Uttareun, O. Limpornpipat, A. Suphawajruksakul, P. Chongrueanglap
Capturing the reservoir heterogeneity is crucial for optimizing field development. Lang-Lebah field is a Miocene carbonate platform with approximately 5 sq.km. in size and over 1 km in height with a high degree of heterogeneity in both vertical and horizontal directions. In this study, we conducted a seismic-based characterization to capture reservoir heterogeneity and then ran sequential gaussian simulation with a data from wells to build a static model for field development purpose. The method mainly comprises of four steps. The first step is to establish a relationship between reservoir properties (such as facie and porosity) to elastic properties (such as P- and S-wave impedances) to build conditional probability. The second step is running pre-stack inversion to derive P- and S-wave impedances as inputs for the third step. The posterior probability of each facie is determined through Bayesian classification using inverted impedances and the derived conditional probability as inputs. The last step is employing sequential gaussian simulation to build a static model using derived posterior probability of each facie and porosity cube. The static model encapsulates heterogeneity in terms of carbonate facie and reservoir properties. The observed heterogeneity is highly consistent with the understanding of geological model of this carbonate platform. The result shows lateral heterogeneity in each zone of high energy facies (such as reef margin) at the windward flank of the platform and low energy facies (such as lake) at platform interior. Thus, this result was elaborated for geological concept beyond the using well data alone. The result also shows a vertical succession from different carbonate reservoir deposit regarding to accommodation as carbonate build-out to a typical carbonate platform build-up continue to carbonate build-in. In addition, flooding event or surfaces, which is part of reservoir barrier, was also identified and included in this static model. The details of this successful novel study lay a fundamental work process for battling the challenge of gigantic carbonate characterization for field development. Because of this sophisticated model, we can properly plan the sequence of production and producing well targeting based on the derived reservoir heterogeneity resulting in enabling several Tscf of reserves and minimizing development costs.
{"title":"Encapsulating Complex Carbonate Facie Heterogeneity into Static Reservoir Model through Seismic-Based Characterization, Lang-Lebah Field, Central Luconia, Offshore Sarawak","authors":"Krongrath Suwannasri, Cheong Yaw Peng, S. Asawachaisujja, R. Uttareun, O. Limpornpipat, A. Suphawajruksakul, P. Chongrueanglap","doi":"10.4043/31517-ms","DOIUrl":"https://doi.org/10.4043/31517-ms","url":null,"abstract":"\u0000 Capturing the reservoir heterogeneity is crucial for optimizing field development. Lang-Lebah field is a Miocene carbonate platform with approximately 5 sq.km. in size and over 1 km in height with a high degree of heterogeneity in both vertical and horizontal directions. In this study, we conducted a seismic-based characterization to capture reservoir heterogeneity and then ran sequential gaussian simulation with a data from wells to build a static model for field development purpose.\u0000 The method mainly comprises of four steps. The first step is to establish a relationship between reservoir properties (such as facie and porosity) to elastic properties (such as P- and S-wave impedances) to build conditional probability. The second step is running pre-stack inversion to derive P- and S-wave impedances as inputs for the third step. The posterior probability of each facie is determined through Bayesian classification using inverted impedances and the derived conditional probability as inputs. The last step is employing sequential gaussian simulation to build a static model using derived posterior probability of each facie and porosity cube.\u0000 The static model encapsulates heterogeneity in terms of carbonate facie and reservoir properties. The observed heterogeneity is highly consistent with the understanding of geological model of this carbonate platform. The result shows lateral heterogeneity in each zone of high energy facies (such as reef margin) at the windward flank of the platform and low energy facies (such as lake) at platform interior. Thus, this result was elaborated for geological concept beyond the using well data alone. The result also shows a vertical succession from different carbonate reservoir deposit regarding to accommodation as carbonate build-out to a typical carbonate platform build-up continue to carbonate build-in. In addition, flooding event or surfaces, which is part of reservoir barrier, was also identified and included in this static model.\u0000 The details of this successful novel study lay a fundamental work process for battling the challenge of gigantic carbonate characterization for field development. Because of this sophisticated model, we can properly plan the sequence of production and producing well targeting based on the derived reservoir heterogeneity resulting in enabling several Tscf of reserves and minimizing development costs.","PeriodicalId":11011,"journal":{"name":"Day 3 Thu, March 24, 2022","volume":"1 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"81337929","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. Guzmán, Thanushya Krishnan, Yong Chin Gwee, Yvonne Wu
A subsea well in Deepwater field in Malaysia observed high sand production during the first half of 2019, this well had been on production for around 7 years. Further evaluation during the second half of 2019 determined that the downhole sand control had been compromised and the well would require intervention to bring back its locked in potential. Technical and Economical evaluations were conducted to determine the most feasible well restoration activity. This paper covers the aspects from technology selection to operation challenges and identified solutions. Riserless well intervention was initially identified to restore production from this well and compared with other alternatives. After technical and economical evaluations, the use of a surface desander was identified as the best solution to unlock production from this well while a more permanent solution was evaluated. A surface desander was installed upstream of first stage separation. Well and facilities operating envelopes were updated to determine the operating window for the well as per last observed conditions before the well was shut in. However, once the well was back online a much higher than anticipated watercut was observed and different solutions, in term of surface settings, were tested to determine a new operation window. The use of surface desander to handle subsea sand control failure requires a steady flow against a significant choke to the flowline at the end of the riser. Changes in reservoir watercut provided a significant challenge to flow the well at steady conditions and limited the efficacy of surface desander. Flow assurance is a key parameter to avoid sand deposition along the subsea flowline to the platform. Use of a neighbor well proved to allow continuous steady production and a new logic was designed to maximize production from both wells while keeping sand from reaching the production facilities.
{"title":"Use of Surface Desander to Bring Back Subsea Production. How to Overcome Reservoir, Well and Facilities Challenges","authors":"M. Guzmán, Thanushya Krishnan, Yong Chin Gwee, Yvonne Wu","doi":"10.4043/31610-ms","DOIUrl":"https://doi.org/10.4043/31610-ms","url":null,"abstract":"\u0000 A subsea well in Deepwater field in Malaysia observed high sand production during the first half of 2019, this well had been on production for around 7 years. Further evaluation during the second half of 2019 determined that the downhole sand control had been compromised and the well would require intervention to bring back its locked in potential. Technical and Economical evaluations were conducted to determine the most feasible well restoration activity. This paper covers the aspects from technology selection to operation challenges and identified solutions.\u0000 Riserless well intervention was initially identified to restore production from this well and compared with other alternatives. After technical and economical evaluations, the use of a surface desander was identified as the best solution to unlock production from this well while a more permanent solution was evaluated. A surface desander was installed upstream of first stage separation. Well and facilities operating envelopes were updated to determine the operating window for the well as per last observed conditions before the well was shut in. However, once the well was back online a much higher than anticipated watercut was observed and different solutions, in term of surface settings, were tested to determine a new operation window.\u0000 The use of surface desander to handle subsea sand control failure requires a steady flow against a significant choke to the flowline at the end of the riser. Changes in reservoir watercut provided a significant challenge to flow the well at steady conditions and limited the efficacy of surface desander.\u0000 Flow assurance is a key parameter to avoid sand deposition along the subsea flowline to the platform. Use of a neighbor well proved to allow continuous steady production and a new logic was designed to maximize production from both wells while keeping sand from reaching the production facilities.","PeriodicalId":11011,"journal":{"name":"Day 3 Thu, March 24, 2022","volume":"7 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90168322","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}
Junnyaruin Barat, Arie Muchalis Utta, Shaturrvetan Karpaya, L. Maluan, Sharon Ellen Lidwin
Since the beginning of production, well NA2 and NA3 wells had issues with wellhead integrity due to thermal growth and wellhead tilting. Seepage was observed from wellhead and based on gas chromatography test, the seepage is Synthetic Based Mud (SBM), possibly from B and C annulus (intermediate and surface casing). For well NA3, seepage was observed coming out from the connection of Casing Head and Drive Pipe Housing House (DPHH) while for Well A2, seepage was found between DPHH and conductor. The issues arise from the failed elastomer seals found at the connections of leak of each well suspected due to well growth/shrink and tilting which caused the wear and tear of the seals. The seepage of both wells was rectified by injecting the failed elastomer seals with pressure activated sealant to the P-seal and grease to the elastomer. Both wells managed to produce at the capped production rate without seepage as of today. Another main issue at Field N is the leaking of metal-to-metal seal at Xmas Tree which led to production deferment. Due to the failed barrier at surface, interim philosophy was established to operate the field and rectification plan was implemented to ensure the well is producing safely at the calculated risk. This paper describes the analysis and diagnosis, operating philosophy outline by operator which led to the well safely producing at the desired rate: (1) Standing Instruction (SI) for Well Production Ramp Up and Down based on trending of production and temperature to ensure wellhead growth and tilting will not affecting the integrity of sealant, (2) Finite Element Analysis (FEA) and Wellhead Growth Study to develop operating limit and maximum allowable growth, correlated with well production and temperature, (3) logging and survey for well leak detection and echometer survey, (4) Wellhead Seal Injection for corrective maintenance upon seepage observed, (5) manual measurement of growth and tilting and utilizing laser sensor for automation, (6) External Slip Lock Brace Support (ESBS) Installation to mitigate abnormal relative growth and (7) risk assessment for well integrity. The holistic approach in diagnostic, monitoring and operating philosophy enabled the well to be ramped up to higher production despite the threat of losing the gas production. PCSB also avoided the utilization of rig to rectify the well which resulted in cost avoidance for the company.
{"title":"Holistic Analysis, Diagnostics and Operating Philosophy for Wellhead Leak Issue for Gas Producer, Offshore Malaysia","authors":"Junnyaruin Barat, Arie Muchalis Utta, Shaturrvetan Karpaya, L. Maluan, Sharon Ellen Lidwin","doi":"10.4043/31553-ms","DOIUrl":"https://doi.org/10.4043/31553-ms","url":null,"abstract":"\u0000 Since the beginning of production, well NA2 and NA3 wells had issues with wellhead integrity due to thermal growth and wellhead tilting. Seepage was observed from wellhead and based on gas chromatography test, the seepage is Synthetic Based Mud (SBM), possibly from B and C annulus (intermediate and surface casing). For well NA3, seepage was observed coming out from the connection of Casing Head and Drive Pipe Housing House (DPHH) while for Well A2, seepage was found between DPHH and conductor. The issues arise from the failed elastomer seals found at the connections of leak of each well suspected due to well growth/shrink and tilting which caused the wear and tear of the seals. The seepage of both wells was rectified by injecting the failed elastomer seals with pressure activated sealant to the P-seal and grease to the elastomer. Both wells managed to produce at the capped production rate without seepage as of today. Another main issue at Field N is the leaking of metal-to-metal seal at Xmas Tree which led to production deferment. Due to the failed barrier at surface, interim philosophy was established to operate the field and rectification plan was implemented to ensure the well is producing safely at the calculated risk.\u0000 This paper describes the analysis and diagnosis, operating philosophy outline by operator which led to the well safely producing at the desired rate: (1) Standing Instruction (SI) for Well Production Ramp Up and Down based on trending of production and temperature to ensure wellhead growth and tilting will not affecting the integrity of sealant, (2) Finite Element Analysis (FEA) and Wellhead Growth Study to develop operating limit and maximum allowable growth, correlated with well production and temperature, (3) logging and survey for well leak detection and echometer survey, (4) Wellhead Seal Injection for corrective maintenance upon seepage observed, (5) manual measurement of growth and tilting and utilizing laser sensor for automation, (6) External Slip Lock Brace Support (ESBS) Installation to mitigate abnormal relative growth and (7) risk assessment for well integrity.\u0000 The holistic approach in diagnostic, monitoring and operating philosophy enabled the well to be ramped up to higher production despite the threat of losing the gas production. PCSB also avoided the utilization of rig to rectify the well which resulted in cost avoidance for the company.","PeriodicalId":11011,"journal":{"name":"Day 3 Thu, March 24, 2022","volume":"41 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"76317101","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}
With China committing to achieve carbon neutrality before 2060, the operator has set ambitious targets for minimizing carbon emissions from its oil and gas operations. Two extensive offshore oil fields – QHD32-6 and CDF 11-1 oil fields have been modified to transform its power solution from offshore generation to power from shore (PFS) to reduce carbon emission, improve offshore energy efficiency etc. The two fields comprise 25 production platforms, 2 FPSO with 21 crude oil generators and 9 gas turbine generators. The total peak power demand is about 200MW. Both QHD32-6 and CDF 11-1 oil fields have established their own offshore micro power grid by interlinking centralized offshore generation platforms via 35kV and 10kV submarine cables. This paper first reviews the company strategic factors as well as the national regulatory drivers behind the decision to pursue whole-scale electrification of two super complex offshore oil fields. It then explores technology challenges and solutions by means of a high voltage AC PFS such as tie-in point selection, reactive compensation considerations, key economic criteria such as operation and energy costs, and asset depreciation etc. Considering the consequences of production loss due to power outage, stringent reliability requirements were adopted. A high-speed transfer combine with a 62.3km 110kV interconnecting submarine cable between QHD32-6 and CFD11-1 offshore substations is first introduced in offshore PFS installations. Detailed configuration and its power supply continuity benefit will be discussed. Finally, major cost reduction measures such as unman and digitalization design of 220kV PFS substation are summarized, with lessons learned in a successful development of extensive on-stream oil fields electrification transformation. This electrification transformation is expected to reduce about a total 2.52 million tons of CO2 and 0.067 million tons of NOx emissions, save 2.17 billion cubic meters of fuel gas and 1.13 million tons of standard coals. In September 2021, QHD32-6 and CFD11-1 offshore oil fields have been completed the transformation and back into production. Although on account of a total 132km submarine cables and 200MW power demand, high voltage D.C. is traditionally the first choice, this paper demonstrates high voltage A.C. can be flexibly utilized for long distance large power demand by careful design. While for many upcoming offshore projects, PFS solutions have become attractive in an effort to reduce environmental footprint, this paper presents an on-stream offshore oil fields PFS transformation, extra considerations need to be addressed. The high-speed transfer solution is first used in PFS engineering that can limit a power switching time to milliseconds, exploring a new way to significantly improve power supply continuity with limited investment. Another new information is the unmanned and intelligent design of substations to increase asset adaptability, maintain system relia
{"title":"Electrification Transformation from Offshore Power Grid to Power from Shore, a Case Study to Minimize Carbon Emissions for Two Extensive Offshore Oil Fields","authors":"Yiru Hu, H. Zhang, Yinfeng Qiu","doi":"10.4043/31550-ms","DOIUrl":"https://doi.org/10.4043/31550-ms","url":null,"abstract":"\u0000 With China committing to achieve carbon neutrality before 2060, the operator has set ambitious targets for minimizing carbon emissions from its oil and gas operations. Two extensive offshore oil fields – QHD32-6 and CDF 11-1 oil fields have been modified to transform its power solution from offshore generation to power from shore (PFS) to reduce carbon emission, improve offshore energy efficiency etc. The two fields comprise 25 production platforms, 2 FPSO with 21 crude oil generators and 9 gas turbine generators. The total peak power demand is about 200MW. Both QHD32-6 and CDF 11-1 oil fields have established their own offshore micro power grid by interlinking centralized offshore generation platforms via 35kV and 10kV submarine cables.\u0000 This paper first reviews the company strategic factors as well as the national regulatory drivers behind the decision to pursue whole-scale electrification of two super complex offshore oil fields. It then explores technology challenges and solutions by means of a high voltage AC PFS such as tie-in point selection, reactive compensation considerations, key economic criteria such as operation and energy costs, and asset depreciation etc. Considering the consequences of production loss due to power outage, stringent reliability requirements were adopted. A high-speed transfer combine with a 62.3km 110kV interconnecting submarine cable between QHD32-6 and CFD11-1 offshore substations is first introduced in offshore PFS installations. Detailed configuration and its power supply continuity benefit will be discussed. Finally, major cost reduction measures such as unman and digitalization design of 220kV PFS substation are summarized, with lessons learned in a successful development of extensive on-stream oil fields electrification transformation.\u0000 This electrification transformation is expected to reduce about a total 2.52 million tons of CO2 and 0.067 million tons of NOx emissions, save 2.17 billion cubic meters of fuel gas and 1.13 million tons of standard coals. In September 2021, QHD32-6 and CFD11-1 offshore oil fields have been completed the transformation and back into production. Although on account of a total 132km submarine cables and 200MW power demand, high voltage D.C. is traditionally the first choice, this paper demonstrates high voltage A.C. can be flexibly utilized for long distance large power demand by careful design.\u0000 While for many upcoming offshore projects, PFS solutions have become attractive in an effort to reduce environmental footprint, this paper presents an on-stream offshore oil fields PFS transformation, extra considerations need to be addressed. The high-speed transfer solution is first used in PFS engineering that can limit a power switching time to milliseconds, exploring a new way to significantly improve power supply continuity with limited investment. Another new information is the unmanned and intelligent design of substations to increase asset adaptability, maintain system relia","PeriodicalId":11011,"journal":{"name":"Day 3 Thu, March 24, 2022","volume":"114 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87965830","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}
V. Manurung, G. R. Himawan, Laila Warkhaida, Ahmad Zulharman, Novri Citajaya, Setiadi Laksono
The Kutai Basin, has been under production for more than 40 years and many wells have been drilled to develop the area. This has resulted in reservoir-induced drilling problems, like kicks and lost circulation due to depletion, while some high-pressure zones still exist. This complexity makes pore-pressure and stress analysis difficult. To address this problem, a comprehensive reservoir-evaluation program was developed by adding formation pressure testing to the planned quad-combo logging-while-drilling (LWD) program. Pressure measurements in this development stage were planned to aid the operator's understanding of the field's current hydraulic communication pathways, to relate reservoir characterization to the geological model. Emphasis was on the insight of static reservoir pressures, which are important for confirming fluid contacts and fluid density gradients. Methods of formation pressure testing have evolved over many years. Through this paper's case study, recent LWD and wireline pressure-testing technology are elaborated in depth, in relation to two sequential wells drilled offshore in the Kutai Basin. LWD pressure-testing operations were conducted in well XX-5 in a dedicated run after completion of drilling the section. The wireline test was conducted in well XX-4 as an open-hole logging run, along with the acquisition of fluid analysis data. Both systems were successfully utilized in the 6-inch hole sections of the subject wells, in a depleted reservoir, with the pressure overbalance expected to reach around 3100 psi in the pre-job planning stage. The average mobility was low in both sets of pressure test results, as also align with the reservoir's current depletion state. Challenges related to tight tests and lost seals in this mature field were experienced with both systems. The drilling environment and the formation's exposure conditions may have presented varying challenges; nevertheless, the same relatable quality has been achieved with both types of testing (LWD and wireline). This paper describes in detail the planning, design, and performance of pressure testing using LWD and wireline in the Kutai Basin. Comparisons between results are displayed to highlight the current character of the subject offshore field. This study aims to enhance future drilling and logging operations, by reviewing solutions from formation pressure testing technologies and to add value to mature and depleted field planning. Technical Categories: Geotechnical, Geoscience & Geophysics; Drilling Technology
{"title":"A Case Study of LWD and Wireline Formation Pressure Tester on Depleted Reservoir of Offshore Development Sequential Wells, Kutai Basin, East Kalimantan, Indonesia","authors":"V. Manurung, G. R. Himawan, Laila Warkhaida, Ahmad Zulharman, Novri Citajaya, Setiadi Laksono","doi":"10.4043/31637-ms","DOIUrl":"https://doi.org/10.4043/31637-ms","url":null,"abstract":"\u0000 The Kutai Basin, has been under production for more than 40 years and many wells have been drilled to develop the area. This has resulted in reservoir-induced drilling problems, like kicks and lost circulation due to depletion, while some high-pressure zones still exist. This complexity makes pore-pressure and stress analysis difficult. To address this problem, a comprehensive reservoir-evaluation program was developed by adding formation pressure testing to the planned quad-combo logging-while-drilling (LWD) program. Pressure measurements in this development stage were planned to aid the operator's understanding of the field's current hydraulic communication pathways, to relate reservoir characterization to the geological model. Emphasis was on the insight of static reservoir pressures, which are important for confirming fluid contacts and fluid density gradients.\u0000 Methods of formation pressure testing have evolved over many years. Through this paper's case study, recent LWD and wireline pressure-testing technology are elaborated in depth, in relation to two sequential wells drilled offshore in the Kutai Basin. LWD pressure-testing operations were conducted in well XX-5 in a dedicated run after completion of drilling the section. The wireline test was conducted in well XX-4 as an open-hole logging run, along with the acquisition of fluid analysis data.\u0000 Both systems were successfully utilized in the 6-inch hole sections of the subject wells, in a depleted reservoir, with the pressure overbalance expected to reach around 3100 psi in the pre-job planning stage. The average mobility was low in both sets of pressure test results, as also align with the reservoir's current depletion state. Challenges related to tight tests and lost seals in this mature field were experienced with both systems. The drilling environment and the formation's exposure conditions may have presented varying challenges; nevertheless, the same relatable quality has been achieved with both types of testing (LWD and wireline).\u0000 This paper describes in detail the planning, design, and performance of pressure testing using LWD and wireline in the Kutai Basin. Comparisons between results are displayed to highlight the current character of the subject offshore field. This study aims to enhance future drilling and logging operations, by reviewing solutions from formation pressure testing technologies and to add value to mature and depleted field planning.\u0000 Technical Categories: Geotechnical, Geoscience & Geophysics; Drilling Technology","PeriodicalId":11011,"journal":{"name":"Day 3 Thu, March 24, 2022","volume":"1 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79948272","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}
W. Tolioe, L. Hanalim, Joely Bt A Ghafar, T. S. Murugesu
In an oil producing S-field within Malay basin, the existence of heterolithic and thinly laminated reservoirs are common. Standard resolution logging tools are incapable to separate inter-bedded sand-shale layers due to their low vertical resolutions and the conventional petrophysical workflow was not robust enough in capturing the actual properties of the laminated sand shale (LSS) reservoirs in S-field. As a result, the estimated permeability did not match the core permeability and required a significantly high multipliers in the dynamic model and the calculated saturation failed to match the Dean-Stark saturation. This paper explains the limitation of the conventional analysis in LSS reservoir and highlights the use of PETRONAS Thin Bed Analysis (TBA) module to estimate the actual reservoir properties in S-field. The case study in this paper shows the best practice to construct the robust fieldwide evaluation of reservoir properties, integrating core to production data and advance logs information, to determine reservoir properties. In LSS reservoirs, the conventional petrophysics outputs are often pessimistic compared to core data. Reservoir Enhancement Modeling and Reservoir Fraction Modeling (REM-RFM) is an in-house PETRONAS TBA methodology for evaluating LSS reservoirs. REM-RFM workflow is designed to obtain the net sand fraction and the actual reservoir properties to describe the reservoirs storage and flow capacity. Sand-shale lamination was quantified by digital core analysis, core UV light binning against the borehole image logs. The triaxial resistivity logs were used as inputs for the Thomas-Stieber method to determine the net sand fraction and the hydrocarbon saturation. Nuclear Magnetic Resonance (NMR) data was also incorporated to confirm the hydrocarbon pore volume on well level. The REM-RFM workflow resulted in the improved reservoir properties compared to the conventional evaluation and were better matched to the core. In the laminated sands, the enhanced shale volume was comparable to the sand streaks seen in UV fluorescence core photo and image logs data, as well the enhanced porosity and permeability were matching well with the core data. Moreover, the water saturation was matching to the saturation from dean-stark core analysis result, comparable to saturation height function model and NMR data, and REM-RFM output were comparable to Thomas-Stieber results. Once the REM-RFM was calibrated in the key wells, the parameters were then applied to the whole field. The in-house REM-RFM module discussed in this paper is an excellent addition to other industry methodologies. This module is basically a continuation of the innovative effort to characterize the conventional clastic reservoirs model performed earlier. It has been proven by applying robust evaluation, the conventional outputs are significantly improved that led to the optimizes the obvious volume of hydrocarbon estimated. In addition to that, the results can be used
马来盆地某产油油田，普遍存在异质层状薄层储层。由于标准分辨率测井工具的垂向分辨率较低，无法分离层间砂页岩层，而且常规的岩石物理工作流程在捕捉s油田层状砂页岩(LSS)储层的实际属性方面不够强大。因此，估计的渗透率与岩心渗透率不匹配，在动态模型中需要很高的乘数，计算的饱和度与Dean-Stark饱和度不匹配。本文解释了LSS油藏常规分析的局限性，并重点介绍了使用PETRONAS Thin Bed analysis (TBA)模块来估计s油田的实际储层性质。本文的案例研究展示了构建可靠的全油田储层物性评价的最佳实践，将岩心、生产数据和超前的测井信息相结合，以确定储层物性。在LSS油藏中，与岩心数据相比，常规岩石物理输出往往是悲观的。储层增强建模和储层分数建模(REM-RFM)是马来西亚国家石油公司内部用于评估LSS储层的TBA方法。REM-RFM工作流旨在获得净含砂率和实际储层性质，以描述储层的储存量和流量。通过数字岩心分析、岩心紫外线与井眼图像测井对比，对砂页岩层状进行了量化。三轴电阻率测井数据作为Thomas-Stieber方法的输入，用于确定净砂率和油气饱和度。同时利用核磁共振(NMR)数据确定了井面上的油气孔隙体积。与常规评价相比，REM-RFM工作流程改善了储层性质，并更好地与岩心匹配。在层状砂岩中，增强的页岩体积与紫外荧光岩心照片和图像测井数据中的砂纹相当，并且增强的孔隙度和渗透率与岩心数据匹配良好。水饱和度与dean-stark岩心分析结果相匹配，与饱和高度函数模型和核磁共振数据相匹配，REM-RFM输出与Thomas-Stieber结果相匹配。一旦在关键井中对REM-RFM进行了校准，这些参数就会应用到整个油田。本文中讨论的内部REM-RFM模块是对其他行业方法的极好补充。该模块基本上是对之前进行的常规碎屑储层模型特征描述的创新工作的延续。应用鲁棒性评价结果表明，常规产量得到显著提高，油气表观体积估计得到优化。除此之外，研究结果还可以用于降低从异质岩和层状砂中获利的风险。
{"title":"Integrated Advance Petrophysical Evaluation for Heterolithic Clastics Reservoir Characterization Optimization in Malay Basin","authors":"W. Tolioe, L. Hanalim, Joely Bt A Ghafar, T. S. Murugesu","doi":"10.4043/31452-ms","DOIUrl":"https://doi.org/10.4043/31452-ms","url":null,"abstract":"\u0000 In an oil producing S-field within Malay basin, the existence of heterolithic and thinly laminated reservoirs are common. Standard resolution logging tools are incapable to separate inter-bedded sand-shale layers due to their low vertical resolutions and the conventional petrophysical workflow was not robust enough in capturing the actual properties of the laminated sand shale (LSS) reservoirs in S-field. As a result, the estimated permeability did not match the core permeability and required a significantly high multipliers in the dynamic model and the calculated saturation failed to match the Dean-Stark saturation. This paper explains the limitation of the conventional analysis in LSS reservoir and highlights the use of PETRONAS Thin Bed Analysis (TBA) module to estimate the actual reservoir properties in S-field.\u0000 The case study in this paper shows the best practice to construct the robust fieldwide evaluation of reservoir properties, integrating core to production data and advance logs information, to determine reservoir properties. In LSS reservoirs, the conventional petrophysics outputs are often pessimistic compared to core data. Reservoir Enhancement Modeling and Reservoir Fraction Modeling (REM-RFM) is an in-house PETRONAS TBA methodology for evaluating LSS reservoirs. REM-RFM workflow is designed to obtain the net sand fraction and the actual reservoir properties to describe the reservoirs storage and flow capacity. Sand-shale lamination was quantified by digital core analysis, core UV light binning against the borehole image logs. The triaxial resistivity logs were used as inputs for the Thomas-Stieber method to determine the net sand fraction and the hydrocarbon saturation. Nuclear Magnetic Resonance (NMR) data was also incorporated to confirm the hydrocarbon pore volume on well level.\u0000 The REM-RFM workflow resulted in the improved reservoir properties compared to the conventional evaluation and were better matched to the core. In the laminated sands, the enhanced shale volume was comparable to the sand streaks seen in UV fluorescence core photo and image logs data, as well the enhanced porosity and permeability were matching well with the core data. Moreover, the water saturation was matching to the saturation from dean-stark core analysis result, comparable to saturation height function model and NMR data, and REM-RFM output were comparable to Thomas-Stieber results. Once the REM-RFM was calibrated in the key wells, the parameters were then applied to the whole field.\u0000 The in-house REM-RFM module discussed in this paper is an excellent addition to other industry methodologies. This module is basically a continuation of the innovative effort to characterize the conventional clastic reservoirs model performed earlier. It has been proven by applying robust evaluation, the conventional outputs are significantly improved that led to the optimizes the obvious volume of hydrocarbon estimated. In addition to that, the results can be used ","PeriodicalId":11011,"journal":{"name":"Day 3 Thu, March 24, 2022","volume":"10 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"72726781","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}
Nurul Nadia Ezzatty Abu Bakar, M. Hod, M. A. Abitalhah, A. F. Omar, Hazlan Abdul Hakim
This paper will discuss the key focus areas in successfully delivering a slim well design as a Proof Of Concept (POC) for marginal fields and well cost optimization. Well Tall-A is a Near Field Exploration (NFE) well targeting marginal reservoir which utilize the slim well concept; a 2-hole section well with 9-5/8" as the conductor. For a successful well execution, three (3) key focus areas were identified which are successful operation of 9-5/8" Casing While Drilling (CWD) to section TD, sustainability of 9-5/8" casing as conductor for the whole well life cycle and achievement of well objectives. Tall-A recorded the longest and successful 9-5/8" CWD Level 2 (non-directional) for Asia Pacific with 1168m drilled footage as of year 2020. Lessons learnt from previous PCSB 9-5/8" CWD operation were incorporated for casing bit selection hence a heavy-set casing bit (8 bladed) which has been proven in drilling long hole interval in the Middle East (>1000m) was utilized. Continuous monitoring during execution is essential in ensuring the casing is set at the desired setting depth. Sustainability of the 9-5/8" casing as conductor for the whole well life cycle is critical for a slim well design concept. Several studies and extensive discussions between multiple parties has been incorporated to enable utilization of the 9-5/8" as conductor with required sufficient tension to sustain the exploration well lifecycle. A conductor study was performed which incorporated the Metocean data, rig data and connection Stress Concentration Fatigue (SCF) to qualify the 9-5/8" as conductor. To meet the primary and secondary targets; the 8-1/2" hole needs to be kicked-off early and build up to maximum 44 deg before maintain tangent to final TD at 2752m MDDF. Due to the long open hole (1475m) and well inclination within the avalanche hole cleaning regime (30 to 60 deg), the well is prone to hole cleaning problem and wellbore instability. Hence, it is critical to have good drilling practices and precise mud weight selection to ensure no hole problem encountered. The well was successfully drilled to TD, completed the well testing and P&A. In summary, well Tall-A successfully maneuvered all challenges to deliver the well safely that resulted in Best In Class (BIC) performance. The slim well design concept has been proven achievable and serve as base design for future marginal wells.
{"title":"Successful Delivery of Slim Well Design Concept for Future Marginal Fields","authors":"Nurul Nadia Ezzatty Abu Bakar, M. Hod, M. A. Abitalhah, A. F. Omar, Hazlan Abdul Hakim","doi":"10.4043/31357-ms","DOIUrl":"https://doi.org/10.4043/31357-ms","url":null,"abstract":"\u0000 This paper will discuss the key focus areas in successfully delivering a slim well design as a Proof Of Concept (POC) for marginal fields and well cost optimization.\u0000 Well Tall-A is a Near Field Exploration (NFE) well targeting marginal reservoir which utilize the slim well concept; a 2-hole section well with 9-5/8\" as the conductor. For a successful well execution, three (3) key focus areas were identified which are successful operation of 9-5/8\" Casing While Drilling (CWD) to section TD, sustainability of 9-5/8\" casing as conductor for the whole well life cycle and achievement of well objectives.\u0000 Tall-A recorded the longest and successful 9-5/8\" CWD Level 2 (non-directional) for Asia Pacific with 1168m drilled footage as of year 2020. Lessons learnt from previous PCSB 9-5/8\" CWD operation were incorporated for casing bit selection hence a heavy-set casing bit (8 bladed) which has been proven in drilling long hole interval in the Middle East (>1000m) was utilized. Continuous monitoring during execution is essential in ensuring the casing is set at the desired setting depth. Sustainability of the 9-5/8\" casing as conductor for the whole well life cycle is critical for a slim well design concept. Several studies and extensive discussions between multiple parties has been incorporated to enable utilization of the 9-5/8\" as conductor with required sufficient tension to sustain the exploration well lifecycle. A conductor study was performed which incorporated the Metocean data, rig data and connection Stress Concentration Fatigue (SCF) to qualify the 9-5/8\" as conductor. To meet the primary and secondary targets; the 8-1/2\" hole needs to be kicked-off early and build up to maximum 44 deg before maintain tangent to final TD at 2752m MDDF. Due to the long open hole (1475m) and well inclination within the avalanche hole cleaning regime (30 to 60 deg), the well is prone to hole cleaning problem and wellbore instability. Hence, it is critical to have good drilling practices and precise mud weight selection to ensure no hole problem encountered. The well was successfully drilled to TD, completed the well testing and P&A.\u0000 In summary, well Tall-A successfully maneuvered all challenges to deliver the well safely that resulted in Best In Class (BIC) performance. The slim well design concept has been proven achievable and serve as base design for future marginal wells.","PeriodicalId":11011,"journal":{"name":"Day 3 Thu, March 24, 2022","volume":"70 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84412922","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}
Siti Kathijah Binti Wahi, Z. Jamil, Nur Izyan Mukhtar, Nadiah Binti Muhammad, Ahmad Mustaza Ahmad Rusli, M. R. B. Zakaria, G. Ganeson
The objective of the paper is to communicate on the development of Web-Based Online Corrosion Design Basis Memorandum (CDBM), an online solution to accelerate, simplify & standardize CDBM development which will be piloted for Upstream Wellhead Platforms and Pipelines. CDBM is a project key document consisting of the design basis of material selection, corrosion control, testing and monitoring which is currently developed and approved manually. This digitalization initiative will take CDBM to a next level in designing corrosion features for upstream facilities in line with COMPANY aspiration of going digital. Web-based Online CDBM consists of four modules which are Corrosion Engineering Assessment, Material Option Database, Corrosion Control, Testing and Monitoring Database and Lesson Learn and Cost Database. Prior to the development of Online CDBM website, the first step is developing technical requirements and business logic spreadsheets. Eighteen internal and external degradation mechanism with regards to upstream facilities has been considered and the option for materials and corrosion control, testing and monitoring tools were populated in the spreadsheet. Element of lesson learn, and cost estimation feature also included in the spreadsheet and developed in collaboration with Operation and Cost Engineering Team. Once the business logic spreadsheet is completed, Online CDBM will be converted to a web-based solution by using the agile method where the system will be developed module by module. Four Minimum Viable Product (MVP) will be released. Online CDBM will be connected to email for notification and the programming will enable online reports, comments, review, and approval. All the information will be stored in one place with a cloud system for easy access and retrieval. Online CDBM will enable data collection and future machine learning adaption where trending and data comparison can easily be conducted. Online CDBM will have the following features: (i)Stringent Quality Control, Standardize Format and Fast Report Generation, (ii) Consistent Technical Approach and Recommendation, (iii) Fit for Purpose Material Selection, Corrosion Control, Testing and Monitoring, (iv) Effective Tracking and Approval for Data Changes & Deviation and (v) Easy Accessibility and Secure Online Database with Cloud System. From this Online CDBM initiative, work process simplification to develop CDBM will be achieved and resulting in 30% potential cost and manhour saving. In addition, a consistent technical approach and recommendation through Online CDBM will potentially incur cost avoidance by having fit-for-purpose materials, corrosion control, testing and monitoring tools as well as Price of Non Conformance (PONC) avoidance for unplanned facilities modification/replacement. In summary, Online CDBM is an opportunity for COMPANY to develop inhouse capability and indirectly will raise oil and gas technology profile. This paper can be use
{"title":"Online Corrosion Design Basis Memorandum Online CDBM-Corrosion Digital Solution at Your Fingertips","authors":"Siti Kathijah Binti Wahi, Z. Jamil, Nur Izyan Mukhtar, Nadiah Binti Muhammad, Ahmad Mustaza Ahmad Rusli, M. R. B. Zakaria, G. Ganeson","doi":"10.4043/31616-ms","DOIUrl":"https://doi.org/10.4043/31616-ms","url":null,"abstract":"\u0000 \u0000 \u0000 The objective of the paper is to communicate on the development of Web-Based Online Corrosion Design Basis Memorandum (CDBM), an online solution to accelerate, simplify & standardize CDBM development which will be piloted for Upstream Wellhead Platforms and Pipelines. CDBM is a project key document consisting of the design basis of material selection, corrosion control, testing and monitoring which is currently developed and approved manually. This digitalization initiative will take CDBM to a next level in designing corrosion features for upstream facilities in line with COMPANY aspiration of going digital.\u0000 \u0000 \u0000 \u0000 Web-based Online CDBM consists of four modules which are Corrosion Engineering Assessment, Material Option Database, Corrosion Control, Testing and Monitoring Database and Lesson Learn and Cost Database. Prior to the development of Online CDBM website, the first step is developing technical requirements and business logic spreadsheets. Eighteen internal and external degradation mechanism with regards to upstream facilities has been considered and the option for materials and corrosion control, testing and monitoring tools were populated in the spreadsheet. Element of lesson learn, and cost estimation feature also included in the spreadsheet and developed in collaboration with Operation and Cost Engineering Team. Once the business logic spreadsheet is completed, Online CDBM will be converted to a web-based solution by using the agile method where the system will be developed module by module. Four Minimum Viable Product (MVP) will be released. Online CDBM will be connected to email for notification and the programming will enable online reports, comments, review, and approval. All the information will be stored in one place with a cloud system for easy access and retrieval. Online CDBM will enable data collection and future machine learning adaption where trending and data comparison can easily be conducted.\u0000 \u0000 \u0000 \u0000 Online CDBM will have the following features: (i)Stringent Quality Control, Standardize Format and Fast Report Generation, (ii) Consistent Technical Approach and Recommendation, (iii) Fit for Purpose Material Selection, Corrosion Control, Testing and Monitoring, (iv) Effective Tracking and Approval for Data Changes & Deviation and (v) Easy Accessibility and Secure Online Database with Cloud System.\u0000 From this Online CDBM initiative, work process simplification to develop CDBM will be achieved and resulting in 30% potential cost and manhour saving. In addition, a consistent technical approach and recommendation through Online CDBM will potentially incur cost avoidance by having fit-for-purpose materials, corrosion control, testing and monitoring tools as well as Price of Non Conformance (PONC) avoidance for unplanned facilities modification/replacement. In summary, Online CDBM is an opportunity for COMPANY to develop inhouse capability and indirectly will raise oil and gas technology profile.\u0000 \u0000 \u0000 \u0000 This paper can be use","PeriodicalId":11011,"journal":{"name":"Day 3 Thu, March 24, 2022","volume":"26 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84512455","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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