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}
Shusheng Guo, Shiyue Wang, S. Daungkaew, Bei Gao, S. Chouya, O. Mullins, Jesus A. Cañas, S. Betancourt, A. Gisolf, T. Khunaworawet, D. Ling
Since early 1990's, Downhole Fluid Analysis (DFA) has been developed to monitor mud filtrate contamination for Wireline Formation Tester downhole sampling. DFA can also provide accurate reservoir fluid information in real time such as hydrocarbon composition including CO2. However, DFA technology cannot measure Nitrogen because N2 has no absorption in the Near Infrared Region (NIR). Therefore, it cannot be directly detected with any spectrometer measurement downhole. This paper will present innovative methods that can be used to predict the amount of N2 in each reservoir. These new techniques can help many clients in the EAG and as well as other basins to accurately quantify N2 without the need to wait for PVT laboratory analysis which generally takes several months to complete. Detection of non-hydrocarbon gases in oil and gas fluids, such as nitrogen gas, is very important for reservoir assessment and management. N2 content affects reserve estimation, especially in the area where reservoir fluids have high N2 contents. In our experience, there are several basins in Asia where N2 and CO2 coexist in the same reservoirs. N2 was charged into reservoirs from the source rock in the same geological time as Hydrocarbon (HC). The CO2 then later charged into the same reservoirs. Xu et al (2008) and Mullins (2019) suggested that the ratio of HC. and N2 are in proportional for each basin. However, the CO2 which was later charged are variable in each reservoir depending on CO2 source and charging area. The relationship between HC. and N2 can be used to predict amount of N2 using three proposed methods (1) Basin Base Method (2) Iteration Methods using DFA spectrometer and InSitu Density measurements., and (3) Equation of State (EOS) Method. This nitrogen prediction techniques were developed to better characterize reservoir fluids and overcome the limitation of the existing technology that's unable to detect and measure nitrogen at downhole conditions. This method can offer extra information, especially for our new Ora Intelligent Wireline Formation Tester technology where answer products will be expanded to tailor client objectives. The N2 and HC. relationship from each basin are examined in detail from our DFA and PVT data base. The ratio of N2 and HC. were then recorded as initial value for Basin Base Method. Then the second N2 prediction technique that uses individual hydrocarbon compositions and downhole density measurements were conducted to calculate missing N2 mass from spectrometer measurements. A ternary diagram was prepared to visualize and determine correlation of the gas composition components. It was found that straight line can be obtained on the Ternary diagram between N2, HC., and CO2 for each reservoir. A detailed calculation based on fluid components and partial densities together with iteration process allows to estimate the mass percentage of nitrogen. The results were then compared with actual value from PVT lab. These nitrogen predi
自20世纪90年代初以来，井下流体分析(DFA)就被开发出来，用于监测电缆地层测试器井下取样的泥浆滤液污染。DFA还可以实时提供准确的储层流体信息，如碳氢化合物成分(包括CO2)。然而，DFA技术无法测量氮气，因为氮气在近红外区域(NIR)没有吸收。因此，井下任何光谱仪都无法直接检测到。本文将介绍可用于预测每个储层中N2含量的创新方法。这些新技术可以帮助EAG和其他盆地的许多客户准确量化N2，而无需等待PVT实验室分析，通常需要几个月的时间才能完成。油气流体中非烃气体(如氮气)的检测对储层评价和管理具有重要意义。N2含量影响储量估算，特别是在储层流体N2含量高的地区。根据我们的经验，亚洲有几个盆地在同一储层中同时存在N2和CO2。N2与烃(HC)在同一地质时代从烃源岩充入储层。随后，二氧化碳被充入相同的储存库。Xu et al .(2008)和Mullins(2019)认为HC的比值。和N2在各盆地呈正比关系。然而，根据不同的CO2源和不同的充注区域，每个储层的充注CO2量是不同的。HC的关系。可采用3种方法(1)盆地基础法(2)DFA谱仪迭代法和原位密度测量法。(3)状态方程(EOS)法。开发这种氮预测技术是为了更好地表征储层流体，克服了现有技术无法在井下条件下检测和测量氮的局限性。这种方法可以提供额外的信息，特别是对于我们新的Ora智能电缆地层测试技术，答案产品将扩展以适应客户的目标。N2和HC。从我们的DFA和PVT数据库中详细检查了每个盆地的关系。N2和HC的比值。然后记录为盆地基础法的初始值。然后，采用第二种氮气预测技术，利用单个碳氢化合物组成和井下密度测量数据，计算光谱仪测量数据中缺失的氮气质量。制作了三元图，以直观地显示和确定气体组成成分的相关性。结果表明，在N2、HC的三元图上可以得到一条直线。和每个储层的二氧化碳。基于流体组分和局部密度的详细计算以及迭代过程可以估计氮的质量百分比。然后将结果与PVT实验室的实际值进行比较。这些氮预测技术已经使用来自东南亚和其他地区的各种数据集进行了测试和验证。该技术可以扩展为储层流体地球动力学(RFG)的一部分，以评估储层的横向连通性，并更好地了解储层的CO2和N2电荷。
{"title":"New Innovative Methods to Predict N2 in Real Time: Expand New Wireline Formation Testing Platform Products to Fit Basins","authors":"Shusheng Guo, Shiyue Wang, S. Daungkaew, Bei Gao, S. Chouya, O. Mullins, Jesus A. Cañas, S. Betancourt, A. Gisolf, T. Khunaworawet, D. Ling","doi":"10.4043/31487-ms","DOIUrl":"https://doi.org/10.4043/31487-ms","url":null,"abstract":"\u0000 Since early 1990's, Downhole Fluid Analysis (DFA) has been developed to monitor mud filtrate contamination for Wireline Formation Tester downhole sampling. DFA can also provide accurate reservoir fluid information in real time such as hydrocarbon composition including CO2. However, DFA technology cannot measure Nitrogen because N2 has no absorption in the Near Infrared Region (NIR). Therefore, it cannot be directly detected with any spectrometer measurement downhole. This paper will present innovative methods that can be used to predict the amount of N2 in each reservoir. These new techniques can help many clients in the EAG and as well as other basins to accurately quantify N2 without the need to wait for PVT laboratory analysis which generally takes several months to complete.\u0000 Detection of non-hydrocarbon gases in oil and gas fluids, such as nitrogen gas, is very important for reservoir assessment and management. N2 content affects reserve estimation, especially in the area where reservoir fluids have high N2 contents. In our experience, there are several basins in Asia where N2 and CO2 coexist in the same reservoirs. N2 was charged into reservoirs from the source rock in the same geological time as Hydrocarbon (HC). The CO2 then later charged into the same reservoirs. Xu et al (2008) and Mullins (2019) suggested that the ratio of HC. and N2 are in proportional for each basin. However, the CO2 which was later charged are variable in each reservoir depending on CO2 source and charging area. The relationship between HC. and N2 can be used to predict amount of N2 using three proposed methods (1) Basin Base Method (2) Iteration Methods using DFA spectrometer and InSitu Density measurements., and (3) Equation of State (EOS) Method. This nitrogen prediction techniques were developed to better characterize reservoir fluids and overcome the limitation of the existing technology that's unable to detect and measure nitrogen at downhole conditions. This method can offer extra information, especially for our new Ora Intelligent Wireline Formation Tester technology where answer products will be expanded to tailor client objectives.\u0000 The N2 and HC. relationship from each basin are examined in detail from our DFA and PVT data base. The ratio of N2 and HC. were then recorded as initial value for Basin Base Method. Then the second N2 prediction technique that uses individual hydrocarbon compositions and downhole density measurements were conducted to calculate missing N2 mass from spectrometer measurements. A ternary diagram was prepared to visualize and determine correlation of the gas composition components. It was found that straight line can be obtained on the Ternary diagram between N2, HC., and CO2 for each reservoir. A detailed calculation based on fluid components and partial densities together with iteration process allows to estimate the mass percentage of nitrogen. The results were then compared with actual value from PVT lab. These nitrogen predi","PeriodicalId":11011,"journal":{"name":"Day 3 Thu, March 24, 2022","volume":"124 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86286890","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
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}
Gerardus Putra Pancawisna, R. Hidayat, G. D. Dahnil, Risal Rahman, P. S. Kurniawati, R. Marindha, K. Umar, _. Ferdian, Irwan Setyaji, Muhammad Masrur, Stian Steinsholm
The paper is aimed to present the engineering design and execution of first application of coiled hose in Indonesia to perform nitrogen unload including its first deployment with roller boogies in the world to tackle the challenge of highly deviated well. The new well of XX-107 was completed with 2 (two) gravel pack zones and tubingless section. In order to produce the well from the gravel pack zones, completion fluid, which filled in the XX-107 well, should be displaced to ensure underbalance condition once the SSDs of those gravel pack zones were opened. After comparing several available methods, coiled hose was chosen to perform nitrogen unload due to its compact and lightweight nature in comparison to conventional coiled tubing. Coiled hose enabled seamless deployment right after the well was completed by the workover unit. Furthermore, the maximum deviation of 84 deg in XX-107 well provided additional challenge to access the well since coiled hose was gravity feed. Several simulations were performed and they resulted in the utilization of roller boogies to minimize friction during RIH and increase the reach of coiled hose in this well. As a result, this operation achieved its main objective of displacing the completion fluid out of the well and created underbalance condition in front of the gravel pack zones. Although the efficiency was only 67.5%, it managed to create 1071 psi of underbalance value and consequently the well flowed at 8 MMscfd. Its lightweight nature was like electricline unit and it consumed less space on the upper deck of the platform. Moreover, the deployment and setup process was performed offline which optimized the operating time event further. The cumulative operating time was only 13 hours including demobilization process while in terms of logistic coiled hose only required 1 trip whereas coiled tubing unit required at least 3 trips. Lastly, this operation requires only 10 personnel for 24-hr operation in comparison to 15 coiled tubing personnel which meant, in this Covid-19 pandemic, provided less risky solution.
{"title":"First Application of Coiled Hose in Indonesia and First Deployment of Coiled Hose with Roller Boogies in the World to Access Highly Deviated Well","authors":"Gerardus Putra Pancawisna, R. Hidayat, G. D. Dahnil, Risal Rahman, P. S. Kurniawati, R. Marindha, K. Umar, _. Ferdian, Irwan Setyaji, Muhammad Masrur, Stian Steinsholm","doi":"10.4043/31407-ms","DOIUrl":"https://doi.org/10.4043/31407-ms","url":null,"abstract":"\u0000 The paper is aimed to present the engineering design and execution of first application of coiled hose in Indonesia to perform nitrogen unload including its first deployment with roller boogies in the world to tackle the challenge of highly deviated well.\u0000 The new well of XX-107 was completed with 2 (two) gravel pack zones and tubingless section. In order to produce the well from the gravel pack zones, completion fluid, which filled in the XX-107 well, should be displaced to ensure underbalance condition once the SSDs of those gravel pack zones were opened. After comparing several available methods, coiled hose was chosen to perform nitrogen unload due to its compact and lightweight nature in comparison to conventional coiled tubing. Coiled hose enabled seamless deployment right after the well was completed by the workover unit. Furthermore, the maximum deviation of 84 deg in XX-107 well provided additional challenge to access the well since coiled hose was gravity feed. Several simulations were performed and they resulted in the utilization of roller boogies to minimize friction during RIH and increase the reach of coiled hose in this well.\u0000 As a result, this operation achieved its main objective of displacing the completion fluid out of the well and created underbalance condition in front of the gravel pack zones. Although the efficiency was only 67.5%, it managed to create 1071 psi of underbalance value and consequently the well flowed at 8 MMscfd. Its lightweight nature was like electricline unit and it consumed less space on the upper deck of the platform. Moreover, the deployment and setup process was performed offline which optimized the operating time event further. The cumulative operating time was only 13 hours including demobilization process while in terms of logistic coiled hose only required 1 trip whereas coiled tubing unit required at least 3 trips. Lastly, this operation requires only 10 personnel for 24-hr operation in comparison to 15 coiled tubing personnel which meant, in this Covid-19 pandemic, provided less risky solution.","PeriodicalId":11011,"journal":{"name":"Day 3 Thu, March 24, 2022","volume":"24 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"75082624","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
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}
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}
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}
The Greater Bongkot North (GBN)'s condensate stabilization system initially utilizes multi-stage flashing concept through the multi-stage separators. Most of the flashing gas at the last stage separator could not be recovered as being operated at very low pressure (0.05 barg) resulting in the continuous flaring through Low Pressure (LP) Flare Header at the Production Platform of the GBN since 1st operation day. Recovery of the unrecoverable low-pressure gas has been unsolved since then. Regarding lower gas nomination forecasted and exported condensate rate in low condensate production mode, LP flare rate is being simulated at 1-3 MMSCFD whilst the existing condensate and gas recovery system shows the available capacity left over even the field potential is maintained. This information energized the opportunity of Recovery Scheme by boosting the pressure of LP Flare Gas and feeding the recovered gas to the existing FGRU compressor within the minimal modification scope. Entire feasible recovery options had been technically examined including essential requirements of modification to evaluate the Pros and Cons on each development scenarios. Key engineering challenge on recovery of the low-pressure heavy flare gas is the closed recirculation of recovered hydrocarbon which wastefully occupies the system capacity. Selection on the returning point of the recovered gas is crucial to minimize the recirculation while increasing production yield. The selected option provides less modification works whereas the entire recovered gas feeding back to the existing FGRU compressor is feasible while the existing facilities at its maximum capacity are utilized and new equipment installation requires only one (Wet Screw) compressor and one liquid recovery (Vertical in-line centrifugal) pump. Each equipment was technically selected through evaluated technical specifications and limitation of installation spaces. Furthermore, the installation scenarios on the aging production platform are key challenge as deck extension, which new equipment are installed, is heavy-lifted, and installed on the existing lower deck of Production Platform using the available margin of platform load on the existing piles. Cost estimation is conducted together with economic evaluation for investment decision. The project is budgetary approved providing an attractive positive NPV. The economic evaluation results in positive NPV mainly due to the condensate gain from the flare gas recovery insisting that greenhouse gas reduction project could be performed in the techno-economical way. The implementation of GBN New LP Flare Recovery scheme will soonest be getting started by FEED and Construction phases accordingly to shape up essential details of required engineering aspects to make the start-up of this project meets the timeline supporting Sustainable Development framework (Green-house gas reduction) as PTTEP strategic directions.
Greater Bongkot North (GBN)的凝析油稳定系统最初通过多级分离器采用多级闪蒸概念。由于在极低的压力(0.05巴)下运行，最后一级分离器的大部分闪蒸气体无法回收，导致GBN生产平台的低压(LP)火炬箱从第一天开始持续燃烧。从那时起，无法开采的低压气的开采一直没有解决。对于低凝析油生产模式下较低的天然气指定预测和出口凝析油率，模拟的LP耀斑率为1-3 MMSCFD，而现有的凝析油和天然气回收系统显示，即使保持了油田潜力，剩余的可用产能也能保持。该信息通过提高LP火炬气的压力，并在最小的修改范围内将回收的气体送入现有的FGRU压缩机，为回收方案提供了机会。对所有可行的恢复方案进行了技术审查，包括基本的修改要求，以评估每个开发方案的利弊。低压重火炬气回收的关键工程难题是回收烃的密闭再循环，浪费了系统容量。选择回收气的回流点对于减少再循环和提高产量至关重要。所选择的方案提供了较少的改造工程，而整个回收气体反馈到现有的FGRU压缩机是可行的，同时利用了现有设施的最大产能，新设备安装只需要一台(湿螺杆)压缩机和一台液体回收(垂直在线离心)泵。每台设备都是通过评估技术规格和安装空间限制来进行技术选择的。此外，老化的生产平台上的安装方案是关键的挑战，因为甲板扩展，新设备的安装，是重载的，并利用现有的平台荷载余量在现有的生产平台的下甲板上安装。成本估算与经济评价一起进行投资决策。该项目已获得预算批准，提供了具有吸引力的正净现值。经济评价结果显示净现值为正，主要是由于火炬气回收的凝析油收益，坚持温室气体减排项目可以从技术经济的角度进行。GBN新LP火炬回收计划的实施将很快在FEED和施工阶段开始，从而形成所需工程方面的基本细节，以使该项目的启动符合支持可持续发展框架(温室气体减排)作为PTTEP战略方向的时间表。
{"title":"The Future of Zero Continuous Flare Operation at Greater Bongkot North Field","authors":"Rattachai Nunthaworrarat, Suchart Srivaranon","doi":"10.4043/31565-ms","DOIUrl":"https://doi.org/10.4043/31565-ms","url":null,"abstract":"\u0000 The Greater Bongkot North (GBN)'s condensate stabilization system initially utilizes multi-stage flashing concept through the multi-stage separators. Most of the flashing gas at the last stage separator could not be recovered as being operated at very low pressure (0.05 barg) resulting in the continuous flaring through Low Pressure (LP) Flare Header at the Production Platform of the GBN since 1st operation day. Recovery of the unrecoverable low-pressure gas has been unsolved since then.\u0000 Regarding lower gas nomination forecasted and exported condensate rate in low condensate production mode, LP flare rate is being simulated at 1-3 MMSCFD whilst the existing condensate and gas recovery system shows the available capacity left over even the field potential is maintained. This information energized the opportunity of Recovery Scheme by boosting the pressure of LP Flare Gas and feeding the recovered gas to the existing FGRU compressor within the minimal modification scope. Entire feasible recovery options had been technically examined including essential requirements of modification to evaluate the Pros and Cons on each development scenarios.\u0000 Key engineering challenge on recovery of the low-pressure heavy flare gas is the closed recirculation of recovered hydrocarbon which wastefully occupies the system capacity. Selection on the returning point of the recovered gas is crucial to minimize the recirculation while increasing production yield. The selected option provides less modification works whereas the entire recovered gas feeding back to the existing FGRU compressor is feasible while the existing facilities at its maximum capacity are utilized and new equipment installation requires only one (Wet Screw) compressor and one liquid recovery (Vertical in-line centrifugal) pump. Each equipment was technically selected through evaluated technical specifications and limitation of installation spaces. Furthermore, the installation scenarios on the aging production platform are key challenge as deck extension, which new equipment are installed, is heavy-lifted, and installed on the existing lower deck of Production Platform using the available margin of platform load on the existing piles. Cost estimation is conducted together with economic evaluation for investment decision. The project is budgetary approved providing an attractive positive NPV. The economic evaluation results in positive NPV mainly due to the condensate gain from the flare gas recovery insisting that greenhouse gas reduction project could be performed in the techno-economical way.\u0000 The implementation of GBN New LP Flare Recovery scheme will soonest be getting started by FEED and Construction phases accordingly to shape up essential details of required engineering aspects to make the start-up of this project meets the timeline supporting Sustainable Development framework (Green-house gas reduction) as PTTEP strategic directions.","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":"89744548","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}
Yi Zhang, Gao Li, Guangchun Leng, Keda Wang, Rui Wang, P. Li
Reservoir heat treatment (RHT) can improve rock seepage capacity. Recently, it has been considered as a potential technology to enhance unconventional oil and gas recovery. This work presents a permeability evolution model to describe the thermal cracking effects of double-porosity media under temperature change and certain formation pressure. Moreover, to verify the accuracy of the model, a typical double-porosity media (tight sandstone) is selected as the sample, and the permeability of the sample is tested using a simulated formation heating device. Firstly, according to the observation results under SEM, 400°C is regarded as the transition temperature of porous and fractured media. The two-parameter exponential function and the improved "cubic law" are used to characterize the permeability of the pore part and the fracture part respectively. Secondly, rock is comprised of matrix grains and pore space. In the model hypothesis, the volume of the matrix grains is just a function of temperature, and the pore space is compressed or released under the action of effective stress, considering the difference of deformation between the matrix grains and the pore space, the Hooke's law based on engineering strain and natural strain is adopted for them respectively. Thirdly, the influence of temperature on crack spacing and opening is analyzed based on the energy principle and Weibull distribution. Finally, a permeability evolution model is established for the whole process of thermal expansion and cracking. The model describes two phases. In the first phase, the matrix grains expand under confining pressure, and at the same time accumulate thermal stress. In the second phase, after the thermal stress overcomes the confining pressure, the porosity recovers and cracks are gradually damaged and formed. The interaction between thermal stress and confining pressure is controlled by introducing a modulation factor. Due to the difference of component properties, the rock has obvious non-uniform thermal fracture phenomenon. Therefore, in this model, three parameters are introduced to ensure the robustness of the model: the contribution of deformation behavior of the matrix grains and pore space to crack opening, the influence of effective stress on crack opening, and the crack proportion of effective seepage. The results indicate that the model can describe the permeability evolution behavior of double-porosity media under certain confining pressure and temperature changes, it provides theoretical guidance for RHT to enhance oil and gas recovery.
{"title":"A Permeability Evolution Model of Double-Porosity Media with Consideration of Temperature and Pressure Variations","authors":"Yi Zhang, Gao Li, Guangchun Leng, Keda Wang, Rui Wang, P. Li","doi":"10.4043/31646-ms","DOIUrl":"https://doi.org/10.4043/31646-ms","url":null,"abstract":"\u0000 Reservoir heat treatment (RHT) can improve rock seepage capacity. Recently, it has been considered as a potential technology to enhance unconventional oil and gas recovery. This work presents a permeability evolution model to describe the thermal cracking effects of double-porosity media under temperature change and certain formation pressure. Moreover, to verify the accuracy of the model, a typical double-porosity media (tight sandstone) is selected as the sample, and the permeability of the sample is tested using a simulated formation heating device. Firstly, according to the observation results under SEM, 400°C is regarded as the transition temperature of porous and fractured media. The two-parameter exponential function and the improved \"cubic law\" are used to characterize the permeability of the pore part and the fracture part respectively. Secondly, rock is comprised of matrix grains and pore space. In the model hypothesis, the volume of the matrix grains is just a function of temperature, and the pore space is compressed or released under the action of effective stress, considering the difference of deformation between the matrix grains and the pore space, the Hooke's law based on engineering strain and natural strain is adopted for them respectively. Thirdly, the influence of temperature on crack spacing and opening is analyzed based on the energy principle and Weibull distribution. Finally, a permeability evolution model is established for the whole process of thermal expansion and cracking. The model describes two phases. In the first phase, the matrix grains expand under confining pressure, and at the same time accumulate thermal stress. In the second phase, after the thermal stress overcomes the confining pressure, the porosity recovers and cracks are gradually damaged and formed. The interaction between thermal stress and confining pressure is controlled by introducing a modulation factor. Due to the difference of component properties, the rock has obvious non-uniform thermal fracture phenomenon. Therefore, in this model, three parameters are introduced to ensure the robustness of the model: the contribution of deformation behavior of the matrix grains and pore space to crack opening, the influence of effective stress on crack opening, and the crack proportion of effective seepage. The results indicate that the model can describe the permeability evolution behavior of double-porosity media under certain confining pressure and temperature changes, it provides theoretical guidance for RHT to enhance oil and gas recovery.","PeriodicalId":11011,"journal":{"name":"Day 3 Thu, March 24, 2022","volume":"41 7","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"91441712","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
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