Raja Muhammad Hafizi Raja Ismail, Faieqah Zainal Abidin, Mya Thuzar, M. F. Rameli, Avinash Kishore Kumar, M. W. Moh Wahi, Yap Yun Thiam
Exploration well with carbonate reservoir is a challenging well to plan for due to risk of total losses because of karst presence. It became even more challenging for a subsea well with high bottom hole temperature (BHT) and prospect of well testing. Flow of HT reservoir fluids (BHT up to 175 deg C) to surface will resulted in significant heat transfer to adjacent casing & its annulus fluids, and lead to annular pressure build-up (APB). High APB will lead to loss of well integrity via 13-3/8" intermediate casing burst and 9-7/8" production casing collapse if left unmitigated. As per The Company technical standards, two APB mitigations were required in a subsea well. The first selected mitigation is an open casing shoe. The exposed shoe will act as a natural relief valve whenever APB exceeding its fracture pressure (FP), therefore, limit the APB to its FP. However, it is challenging to keep the 9-7/8" casing top of cement (TOC) below the 13-3/8" casing shoe and fulfil the open shoe barrier requirement for this well where the open hole interval is relatively short and subject to be plugged off by barite sagging, insufficient open shoe length for safety margin of excess cement and requirement of minimum annulus cement length for shoe integrity. Extra mitigations were addressed through extensive lab tested solids-free annulus fluid to mitigate barite sagging. Open shoe interval also designed with multiple weak sands exposure and higher FP were considered for worst-case APB simulation. The second barrier is the 13-3/8" intermediate casing and 9-7/8" production casing itself. Based on WellCAT simulation, the intermediate casing unable to meet The Company standards of burst (safety factor, SF < 1.1) in the worst-case scenario whereby APB is unmitigated. The casing burst pressure rating was recalculated using API Bulletin 5C3 equation with the inputs taken from minimum actual casing wall thickness measurement and internal yield pressure from its mill certificate. Technical derogations were raised and approved once the casing passed all the load cases using the revised burst rating by minimum SF of 1.0. The well was delivered successfully with the open hole barrier for both casing was executed flawlessly despite the complex fluid train while cementing.
{"title":"Concerted Approach for Annular Pressure Build-Up APB Mitigations to Safeguard Well Integrity of Subsea, High Temperature Carbonate Exploration Well","authors":"Raja Muhammad Hafizi Raja Ismail, Faieqah Zainal Abidin, Mya Thuzar, M. F. Rameli, Avinash Kishore Kumar, M. W. Moh Wahi, Yap Yun Thiam","doi":"10.4043/31689-ms","DOIUrl":"https://doi.org/10.4043/31689-ms","url":null,"abstract":"\u0000 Exploration well with carbonate reservoir is a challenging well to plan for due to risk of total losses because of karst presence. It became even more challenging for a subsea well with high bottom hole temperature (BHT) and prospect of well testing. Flow of HT reservoir fluids (BHT up to 175 deg C) to surface will resulted in significant heat transfer to adjacent casing & its annulus fluids, and lead to annular pressure build-up (APB). High APB will lead to loss of well integrity via 13-3/8\" intermediate casing burst and 9-7/8\" production casing collapse if left unmitigated. As per The Company technical standards, two APB mitigations were required in a subsea well. The first selected mitigation is an open casing shoe. The exposed shoe will act as a natural relief valve whenever APB exceeding its fracture pressure (FP), therefore, limit the APB to its FP. However, it is challenging to keep the 9-7/8\" casing top of cement (TOC) below the 13-3/8\" casing shoe and fulfil the open shoe barrier requirement for this well where the open hole interval is relatively short and subject to be plugged off by barite sagging, insufficient open shoe length for safety margin of excess cement and requirement of minimum annulus cement length for shoe integrity. Extra mitigations were addressed through extensive lab tested solids-free annulus fluid to mitigate barite sagging. Open shoe interval also designed with multiple weak sands exposure and higher FP were considered for worst-case APB simulation. The second barrier is the 13-3/8\" intermediate casing and 9-7/8\" production casing itself. Based on WellCAT simulation, the intermediate casing unable to meet The Company standards of burst (safety factor, SF < 1.1) in the worst-case scenario whereby APB is unmitigated. The casing burst pressure rating was recalculated using API Bulletin 5C3 equation with the inputs taken from minimum actual casing wall thickness measurement and internal yield pressure from its mill certificate. Technical derogations were raised and approved once the casing passed all the load cases using the revised burst rating by minimum SF of 1.0. The well was delivered successfully with the open hole barrier for both casing was executed flawlessly despite the complex fluid train while cementing.","PeriodicalId":11081,"journal":{"name":"Day 2 Wed, March 23, 2022","volume":"19 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87124568","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 front-end loading (FEL) project management process is a method that is trusted and ingrained into most Exploration and Production oil and gas companies worldwide. The entire FEL is modeled after the Waterfall model which is sequential in nature. The waterfall model can be construed to be too slow in adapting to changes resulting in a significant number of oil and gas projects having a high tendency of cost overruns, schedule delays and not meeting stakeholder objectives. On the other hand, the agile model employed by IT, software and technology companies offers a refreshing view to achieving the desired result in projects. However, these two industries have substantial differences between them, for example in project value and regulation. This explains the reluctance by major oil and gas companies to implement agile as part of their project management approach. Nevertheless, as the environmental and organizational factors in project management in all sectors are changing at a rapid pace, seeking alternative and workable approach is vital. The paper seeks to evaluate the concept of adapting the agile methodology for FEL in oil and gas field development projects. The paper identifies areas for integrating agile such as in FEL selection criteria and further suggests to seek a balance between the two contrasting methods. Overall, the results from a case study in the oil and gas industry indicates that by adapting agile approach into the current FEL practice, it's more likely that the right project would be sanctioned, therefore, increasing the chances of project success.
{"title":"The FEL-Agile Hybrid Approach to Selecting the ‘Right’ Oil & Gas project","authors":"Ashvin Nesan","doi":"10.4043/31659-ms","DOIUrl":"https://doi.org/10.4043/31659-ms","url":null,"abstract":"\u0000 The front-end loading (FEL) project management process is a method that is trusted and ingrained into most Exploration and Production oil and gas companies worldwide. The entire FEL is modeled after the Waterfall model which is sequential in nature. The waterfall model can be construed to be too slow in adapting to changes resulting in a significant number of oil and gas projects having a high tendency of cost overruns, schedule delays and not meeting stakeholder objectives. On the other hand, the agile model employed by IT, software and technology companies offers a refreshing view to achieving the desired result in projects. However, these two industries have substantial differences between them, for example in project value and regulation. This explains the reluctance by major oil and gas companies to implement agile as part of their project management approach. Nevertheless, as the environmental and organizational factors in project management in all sectors are changing at a rapid pace, seeking alternative and workable approach is vital. The paper seeks to evaluate the concept of adapting the agile methodology for FEL in oil and gas field development projects. The paper identifies areas for integrating agile such as in FEL selection criteria and further suggests to seek a balance between the two contrasting methods. Overall, the results from a case study in the oil and gas industry indicates that by adapting agile approach into the current FEL practice, it's more likely that the right project would be sanctioned, therefore, increasing the chances of project success.","PeriodicalId":11081,"journal":{"name":"Day 2 Wed, March 23, 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":"88934637","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}
Xiaodong Han, L. Zhong, Qiuxia Wang, Wei Zhang, Jian Zou, Hao Liu, Hongyu Wang
Maximizing the future economic return of the asset is an important issue in petroleum engineering. For heavy oil reservoir developed with steam flooding, its production cost is much higher than that of conventional production methods. Commonly used parameters optimization method such as single factor analysis and orthogonal test cannot guarantee to obtain global optimal economic benefits. It is necessary and urgent to form a better optimization method to achieve higher profit. A new framework is proposed and presented to optimize well control parameters of both steam injection wells and oil production wells by integrating the reservoir simulator into the optimization algorithms. A net present value (NPV) formula for evaluation of horizontal well steam flooding project is proposed and the optimization objective is to maximize the NPV of production over the life. The generally acknowledged Particle swarm optimization (PSO) is used for solution of the optimization problem. This method has been tested for a typical offshore horizontal well steam flooding project. Results indicate that PSO gives good solutions for this problem and the following conclusions can be obtained. The NPV of the optimized project is improved and larger than the NPV of its initial guess. The control frequency has great influence on the optimal NPV, and the optimal NPV increases with the increase of the control frequency. Steam injection and oil production rates need to be controlled and decreased at the latter stage for mitigating ineffective steam cycle between injection and production wells. The new method has been used for well control optimization of the first offshore horizontal well steam flooding pilot and this method would which will provide powerful technical support for the high efficiency development of the heavy oil resource with steam flooding.
{"title":"Well Control Optimization of Offshore Horizontal Steam Flooding Wells Using Artificial Intelligence Algorithm","authors":"Xiaodong Han, L. Zhong, Qiuxia Wang, Wei Zhang, Jian Zou, Hao Liu, Hongyu Wang","doi":"10.4043/31466-ms","DOIUrl":"https://doi.org/10.4043/31466-ms","url":null,"abstract":"\u0000 Maximizing the future economic return of the asset is an important issue in petroleum engineering. For heavy oil reservoir developed with steam flooding, its production cost is much higher than that of conventional production methods. Commonly used parameters optimization method such as single factor analysis and orthogonal test cannot guarantee to obtain global optimal economic benefits. It is necessary and urgent to form a better optimization method to achieve higher profit.\u0000 A new framework is proposed and presented to optimize well control parameters of both steam injection wells and oil production wells by integrating the reservoir simulator into the optimization algorithms. A net present value (NPV) formula for evaluation of horizontal well steam flooding project is proposed and the optimization objective is to maximize the NPV of production over the life. The generally acknowledged Particle swarm optimization (PSO) is used for solution of the optimization problem. This method has been tested for a typical offshore horizontal well steam flooding project. Results indicate that PSO gives good solutions for this problem and the following conclusions can be obtained. The NPV of the optimized project is improved and larger than the NPV of its initial guess. The control frequency has great influence on the optimal NPV, and the optimal NPV increases with the increase of the control frequency. Steam injection and oil production rates need to be controlled and decreased at the latter stage for mitigating ineffective steam cycle between injection and production wells.\u0000 The new method has been used for well control optimization of the first offshore horizontal well steam flooding pilot and this method would which will provide powerful technical support for the high efficiency development of the heavy oil resource with steam flooding.","PeriodicalId":11081,"journal":{"name":"Day 2 Wed, March 23, 2022","volume":"44 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"85778602","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}
Saurabh Anand, M. A. Hamzah, B. Madon, Kok Kin Chun, Anis Izzuddin Othman, M. S. B. M. Ismail, M. Rahim
Accessing behind casing opportunities plays a key role in ensuring that production targets are achieved in the PETRONAS operated fields in Malaysian basin. This is however getting more challenging as these fields comprising mostly of stacked clastic reservoirs get matured. This paper provides a comprehensive review of all thru tubing perforation jobs done over last two years in PETRONAS operated fields in the region with focus on failure reasons and future mitigation measures to ensure higher rate of success. As a part of this study, all the historical thru tubing perforation jobs done to access behind casing opportunities over last 2 years across more than 22 producing fields in the region with PETRONAS as the operator were analyzed in detail. These jobs were then studied with respect to the main factors which impacts overall job success or failure. These included but was not limited to fluid contacts, gun, and charge type, nearby well performance, zone saturation data availability, completion type, contractor performance etc. In addition, post job details like sand production, artificial lift performance which contributed to well behavior post perforation were also evaluated. Exhaustive gun perforation and well model simulations were conducted to model post perforation well performance. Actual data with distribution and impact of the above-mentioned parameters will be discussed at length in the paper. Key findings which contribute to the overall successful thru tubing perforation jobs and lessons learnt for future perforation jobs will be presented in the paper. Based on the comprehensive review and in-depth analysis, the operator has gained great visibility on key focus areas for thru tubing perforation jobs to increase success rate for completing the behind casing opportunities. Results specially re-iterate the importance of saturation data, gun selection and sand control among other parameters for successful thru tubing perforation jobs in matured stacked reservoirs. The study also indicate why these parameters are even more important for multiple tubular perforations such as cement packers, complex dual string completions, multiple tubular perforation etc. Based on the findings from the study, the paper will recommend key points to consider while completing behind casing opportunities in challenging environment. While a lot of literature and study is available on perforations in general, the author could not find any noticeable work which is based on large amount of actual field data on how to improve thru tubing perforation jobs in matured stacked reservoirs in complex completions. This paper aims to help operators improve on the existing practices to ensure better and more successful results while completing behind casing opportunities using thru tubing perforations.
{"title":"Lookback Analysis and Benchmarking to Improve Success Rate of Thru Tubing Perforations for Accessing Behind Casing Opportunities in Brown Fields","authors":"Saurabh Anand, M. A. Hamzah, B. Madon, Kok Kin Chun, Anis Izzuddin Othman, M. S. B. M. Ismail, M. Rahim","doi":"10.4043/31642-ms","DOIUrl":"https://doi.org/10.4043/31642-ms","url":null,"abstract":"\u0000 Accessing behind casing opportunities plays a key role in ensuring that production targets are achieved in the PETRONAS operated fields in Malaysian basin. This is however getting more challenging as these fields comprising mostly of stacked clastic reservoirs get matured. This paper provides a comprehensive review of all thru tubing perforation jobs done over last two years in PETRONAS operated fields in the region with focus on failure reasons and future mitigation measures to ensure higher rate of success.\u0000 As a part of this study, all the historical thru tubing perforation jobs done to access behind casing opportunities over last 2 years across more than 22 producing fields in the region with PETRONAS as the operator were analyzed in detail. These jobs were then studied with respect to the main factors which impacts overall job success or failure. These included but was not limited to fluid contacts, gun, and charge type, nearby well performance, zone saturation data availability, completion type, contractor performance etc. In addition, post job details like sand production, artificial lift performance which contributed to well behavior post perforation were also evaluated. Exhaustive gun perforation and well model simulations were conducted to model post perforation well performance. Actual data with distribution and impact of the above-mentioned parameters will be discussed at length in the paper. Key findings which contribute to the overall successful thru tubing perforation jobs and lessons learnt for future perforation jobs will be presented in the paper.\u0000 Based on the comprehensive review and in-depth analysis, the operator has gained great visibility on key focus areas for thru tubing perforation jobs to increase success rate for completing the behind casing opportunities. Results specially re-iterate the importance of saturation data, gun selection and sand control among other parameters for successful thru tubing perforation jobs in matured stacked reservoirs. The study also indicate why these parameters are even more important for multiple tubular perforations such as cement packers, complex dual string completions, multiple tubular perforation etc. Based on the findings from the study, the paper will recommend key points to consider while completing behind casing opportunities in challenging environment.\u0000 While a lot of literature and study is available on perforations in general, the author could not find any noticeable work which is based on large amount of actual field data on how to improve thru tubing perforation jobs in matured stacked reservoirs in complex completions. This paper aims to help operators improve on the existing practices to ensure better and more successful results while completing behind casing opportunities using thru tubing perforations.","PeriodicalId":11081,"journal":{"name":"Day 2 Wed, March 23, 2022","volume":"81 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86219138","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}
T. S. Robinson, P. Batruny, Dalila Gomes, M. Hashim, M. H. Yusoff, M. Arriffin, A. Mohamad
Drilling rate of penetration (ROP) is a major contributor to drilling costs. ROP is influenced by many different controllable and uncontrollable factors that are difficult to distinguish with the naked eye. Thus, machine learning (ML) models such as neural networks (NN) have gained momentum in the drilling industry. Existing models were either field-based or tool-based, which impacted the accuracy outside of the trained field. This work aims to develop one generally applicable global ROP model, reducing the effort needed to re-develop models for every application. A drilling dataset was gathered from exploration and development wells in both onshore and offshore operations from a variety of fields and regions. The wells were curated to have different water depths, down hole drive such as Rotary Steerable System (RSS), PDM, Standard Rotary, bit types (Mill Tooth, TCI, PDC) and inclinations (vertical or deviated). A deep neural network was used for modelling the relationship between ROP and inputs taken from real-time surface data, such as Torque, Weight-on-Bit (WOB), rotary speed (RPM), flow and pressure measurements. The performance of the ROP model was analyzed using historical data via summary statistics such as Mean Absolute Percentage Error, as well as graphical results such as residuals distributions, cumulative distribution functions of errors, and plots of ROP vs depth for independent holdout testing wells not included in the model fitting process. Analysis was done both in aggregate, and for each specific well. The ROP model was demonstrated to generalize effectively in all cases, with only minor increases in error metrics for the holdout test wells, where the Mean Absolute Percentage Error averaged across wells was ~20%, compared to 17.5% averaged across training wells. Furthermore, residuals distributions were centered close to zero, indicating low systematic error. This work proves the case for a "global" ROP prediction model applicable "out-of-the-box" to a broad set of drilling operations. A global ROP model has the potential to eliminate learning curves, reducing time and costs associated with having to develop a new model for every field. Furthermore, a model that effectively captures the relationships between parameters controllable by drillers and ROP can be used for automatically identifying drilling parameters that improve ROP. Preliminary field-testing of the ROP optimization system yielded positive results, with many examples of increased ROP realized after following drilling parameter recommendations provided by the software.
{"title":"Successful Development and Deployment of a Global ROP Optimization Machine Learning Model","authors":"T. S. Robinson, P. Batruny, Dalila Gomes, M. Hashim, M. H. Yusoff, M. Arriffin, A. Mohamad","doi":"10.4043/31680-ms","DOIUrl":"https://doi.org/10.4043/31680-ms","url":null,"abstract":"\u0000 Drilling rate of penetration (ROP) is a major contributor to drilling costs. ROP is influenced by many different controllable and uncontrollable factors that are difficult to distinguish with the naked eye. Thus, machine learning (ML) models such as neural networks (NN) have gained momentum in the drilling industry. Existing models were either field-based or tool-based, which impacted the accuracy outside of the trained field. This work aims to develop one generally applicable global ROP model, reducing the effort needed to re-develop models for every application.\u0000 A drilling dataset was gathered from exploration and development wells in both onshore and offshore operations from a variety of fields and regions. The wells were curated to have different water depths, down hole drive such as Rotary Steerable System (RSS), PDM, Standard Rotary, bit types (Mill Tooth, TCI, PDC) and inclinations (vertical or deviated). A deep neural network was used for modelling the relationship between ROP and inputs taken from real-time surface data, such as Torque, Weight-on-Bit (WOB), rotary speed (RPM), flow and pressure measurements. The performance of the ROP model was analyzed using historical data via summary statistics such as Mean Absolute Percentage Error, as well as graphical results such as residuals distributions, cumulative distribution functions of errors, and plots of ROP vs depth for independent holdout testing wells not included in the model fitting process. Analysis was done both in aggregate, and for each specific well.\u0000 The ROP model was demonstrated to generalize effectively in all cases, with only minor increases in error metrics for the holdout test wells, where the Mean Absolute Percentage Error averaged across wells was ~20%, compared to 17.5% averaged across training wells. Furthermore, residuals distributions were centered close to zero, indicating low systematic error. This work proves the case for a \"global\" ROP prediction model applicable \"out-of-the-box\" to a broad set of drilling operations.\u0000 A global ROP model has the potential to eliminate learning curves, reducing time and costs associated with having to develop a new model for every field. Furthermore, a model that effectively captures the relationships between parameters controllable by drillers and ROP can be used for automatically identifying drilling parameters that improve ROP. Preliminary field-testing of the ROP optimization system yielded positive results, with many examples of increased ROP realized after following drilling parameter recommendations provided by the software.","PeriodicalId":11081,"journal":{"name":"Day 2 Wed, March 23, 2022","volume":"136 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"80309952","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}
Aminah Qayyimah Mohd Aji, B. Maulianda, D. Mohshim, Khaled Abdalla Elraeis, K. E. H. Ku Ishak
Gas adsorption-desorption highly affect gas storage and production behaviour in shale nanopores. The study of methane adsorption isotherm in shale has been extensively conducted experimentally. The shale compositions and reservoir conditions prominently control the adsorption capacity of methane. However, to date, there is a lack of discussion on the effect of heterogeneous TOC towards the adsorption isotherm and comparison with adsorption isotherm modelling. This study used the gravimetric method for supercritical methane adsorptions - desorption isotherms measurements. Isotherms measurements were conducted with three shale samples with various TOC values (9.67, 13.9, and 15.4 wt.%) from the Eagle Ford formation at pressure up to 10 MPa and temperature at 120 °C. The isotherms gathered were fitted with standard adsorption-desorption isotherm models, Langmuir, Freundlich and extended Sips to test the applicability of these models depicted the adsorption of supercritical methane. The results show that EF C with the highest TOC content (15.4 wt.%) has the highest adsorption-desorption methane capacity, more than 0.7 mmol/g, compared to other samples. The composition differences between these samples indicate that the organic contents were likely a major controlling factor of the adsorption capacities obtained. The TOC provides a higher surface area for adsorption to occur. Thus, a higher adsorption-desorption capacity was observed through this study. On the other hand, the adsorption and desorption curves did not intercept due to the hysteresis caused by the capillary condensation. The significant binding capacity of the shale surface for methane gas molecules leads to the hysteresis observed during methane desorption. It was observed that the Freundlich model was the most accurate adsorption model in describing the adsorption-desorption behaviour with tested shales with average R2 more than 0.90 and ARE (%) less than 10 % compared to other models with 15.8 % (Langmuir) and 18.9 % (Sips). This study also proved the influence of organic matter on predicting the adsorption-desorption capacity with adsorption isotherms highlighting the importance of modelling the TOC of shale with adsorption isotherm to determine the adsorption-desorption properties.
气体的吸附-解吸对页岩纳米孔隙的储气和产气行为影响很大。页岩中甲烷吸附等温线的实验研究已经广泛开展。页岩成分和储层条件对甲烷的吸附能力起着重要的控制作用。然而，迄今为止，缺乏关于非均相TOC对吸附等温线的影响的讨论以及与吸附等温线模型的比较。本文采用重量法对超临界甲烷吸附-解吸等温线进行了测量。在压力为10 MPa、温度为120℃的条件下，对Eagle Ford地层中三种TOC值(9.67、13.9和15.4 wt.%)不同的页岩样品进行了等温线测量。收集的等温线与标准吸附-解吸等温线模型、Langmuir、Freundlich和扩展Sips进行拟合，以测试这些模型描述超临界甲烷吸附的适用性。结果表明:与其他样品相比，TOC含量最高的EF C (15.4 wt.%)具有最高的甲烷吸附-解吸能力，大于0.7 mmol/g;这些样品的组成差异表明有机含量可能是获得吸附能力的主要控制因素。TOC为吸附提供了更高的表面积。因此，通过本研究观察到较高的吸附-解吸能力。另一方面，由于毛细凝结产生的滞后，吸附和解吸曲线没有截距。页岩表面对甲烷气体分子的显著结合能力导致甲烷解吸过程中观察到的滞后现象。结果表明，Freundlich模型是描述页岩吸附-解吸行为最准确的吸附模型，平均R2大于0.90,ARE(%)小于10%，而Langmuir模型为15.8%，Sips模型为18.9%。该研究还证明了有机质对吸附等温线预测吸附-脱附能力的影响，强调了用吸附等温线模拟页岩TOC对确定吸附-脱附性质的重要性。
{"title":"Supercritical Methane Adsorption in Shale: Isothermal Adsorption and Desorption of Eagle Ford Shale Gas","authors":"Aminah Qayyimah Mohd Aji, B. Maulianda, D. Mohshim, Khaled Abdalla Elraeis, K. E. H. Ku Ishak","doi":"10.4043/31615-ms","DOIUrl":"https://doi.org/10.4043/31615-ms","url":null,"abstract":"\u0000 Gas adsorption-desorption highly affect gas storage and production behaviour in shale nanopores. The study of methane adsorption isotherm in shale has been extensively conducted experimentally. The shale compositions and reservoir conditions prominently control the adsorption capacity of methane. However, to date, there is a lack of discussion on the effect of heterogeneous TOC towards the adsorption isotherm and comparison with adsorption isotherm modelling. This study used the gravimetric method for supercritical methane adsorptions - desorption isotherms measurements. Isotherms measurements were conducted with three shale samples with various TOC values (9.67, 13.9, and 15.4 wt.%) from the Eagle Ford formation at pressure up to 10 MPa and temperature at 120 °C. The isotherms gathered were fitted with standard adsorption-desorption isotherm models, Langmuir, Freundlich and extended Sips to test the applicability of these models depicted the adsorption of supercritical methane. The results show that EF C with the highest TOC content (15.4 wt.%) has the highest adsorption-desorption methane capacity, more than 0.7 mmol/g, compared to other samples. The composition differences between these samples indicate that the organic contents were likely a major controlling factor of the adsorption capacities obtained. The TOC provides a higher surface area for adsorption to occur. Thus, a higher adsorption-desorption capacity was observed through this study. On the other hand, the adsorption and desorption curves did not intercept due to the hysteresis caused by the capillary condensation. The significant binding capacity of the shale surface for methane gas molecules leads to the hysteresis observed during methane desorption. It was observed that the Freundlich model was the most accurate adsorption model in describing the adsorption-desorption behaviour with tested shales with average R2 more than 0.90 and ARE (%) less than 10 % compared to other models with 15.8 % (Langmuir) and 18.9 % (Sips). This study also proved the influence of organic matter on predicting the adsorption-desorption capacity with adsorption isotherms highlighting the importance of modelling the TOC of shale with adsorption isotherm to determine the adsorption-desorption properties.","PeriodicalId":11081,"journal":{"name":"Day 2 Wed, March 23, 2022","volume":"38 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"80323037","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}
Zunaidi Ahmad Nazari, Madada Mashari, Mukesh Kumar, Eldho Paul
The ocean transportation of heavy modules on heavy transportation vessels (HTV) has a large influence on the design and construction of modularized plants. In some instances, it governs structural design loads and influences the layout and commissioning plan of modules. Proper selection of transportation routes, seasons, and vessels will reduce the impact of transportation loads and constraints on the overall module design. Details presented in this paper are based on an EPC Modularization project involving the sea transportation of 5 mega modules weighing between 5000MT to 9000MT, totaling 34000MT, which took place between November 2020 and February 2021. A summary of planning and execution strategy together with key solutions to deal with challenges faced during this project can serve as a guide for future projects.
{"title":"Challenges in Planning and Designing for the Sea Transportation of Heavy Modules of a Modularized Plant, an EPC Contractor's Perspective","authors":"Zunaidi Ahmad Nazari, Madada Mashari, Mukesh Kumar, Eldho Paul","doi":"10.4043/31658-ms","DOIUrl":"https://doi.org/10.4043/31658-ms","url":null,"abstract":"\u0000 The ocean transportation of heavy modules on heavy transportation vessels (HTV) has a large influence on the design and construction of modularized plants. In some instances, it governs structural design loads and influences the layout and commissioning plan of modules. Proper selection of transportation routes, seasons, and vessels will reduce the impact of transportation loads and constraints on the overall module design. Details presented in this paper are based on an EPC Modularization project involving the sea transportation of 5 mega modules weighing between 5000MT to 9000MT, totaling 34000MT, which took place between November 2020 and February 2021. A summary of planning and execution strategy together with key solutions to deal with challenges faced during this project can serve as a guide for future projects.","PeriodicalId":11081,"journal":{"name":"Day 2 Wed, March 23, 2022","volume":"4 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78782528","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}
S. M. Ng, R. Khan, Luong Ann Lee, Biramarta Isnadi, Horng Eng Tang, Fahima M Salleh
This paper presents a digitized Technical Limits Weight Control (TLWC) tool for integrity management of existing fixed offshore structures. The tool is currently integrated into PETRONAS's Structural Integrity Compliance System (SICS), which is a web-based application for Structural Integrity Management (SIM) of fixed offshore structures. The main capability of the TLWC tool is to allow a user (engineer/ manager) to determine the fitness for purpose of an offshore facility quickly and efficiently for the inclusion of additional topsides loading at various locations on the platform decks. The tool makes use of global ultimate strength analyses results which considers the acceptance criteria for each operating region in Malaysian Waters. The limits of these criteria are used to create contour boundaries, which depending on Centre of Gravity (CoG) shifts due to topsides loading patterns. The tool can provide a high-level check on platform suitability for such increase in loading to cater for further development or operational needs. This quick check enables decision making at early engineering stage without the use of further elaborate and costly analyses. The contour plot shown in the results indicates the limiting acceptable Reserved Strength Ratio (RSR) for that platform. The TLWC decision-making tool is ideal for practicing offshore structural integrity engineers in operations to make a quick decision with regards to addition of topside loading for platforms with marginal reserved strength. Detailed assessment is required to address potential local member overstress for the topside structural members.
{"title":"A Technical Limits Weight Control Tool for Integrity Management of Aging Offshore Structures","authors":"S. M. Ng, R. Khan, Luong Ann Lee, Biramarta Isnadi, Horng Eng Tang, Fahima M Salleh","doi":"10.4043/31655-ms","DOIUrl":"https://doi.org/10.4043/31655-ms","url":null,"abstract":"\u0000 This paper presents a digitized Technical Limits Weight Control (TLWC) tool for integrity management of existing fixed offshore structures. The tool is currently integrated into PETRONAS's Structural Integrity Compliance System (SICS), which is a web-based application for Structural Integrity Management (SIM) of fixed offshore structures.\u0000 The main capability of the TLWC tool is to allow a user (engineer/ manager) to determine the fitness for purpose of an offshore facility quickly and efficiently for the inclusion of additional topsides loading at various locations on the platform decks. The tool makes use of global ultimate strength analyses results which considers the acceptance criteria for each operating region in Malaysian Waters. The limits of these criteria are used to create contour boundaries, which depending on Centre of Gravity (CoG) shifts due to topsides loading patterns.\u0000 The tool can provide a high-level check on platform suitability for such increase in loading to cater for further development or operational needs. This quick check enables decision making at early engineering stage without the use of further elaborate and costly analyses. The contour plot shown in the results indicates the limiting acceptable Reserved Strength Ratio (RSR) for that platform.\u0000 The TLWC decision-making tool is ideal for practicing offshore structural integrity engineers in operations to make a quick decision with regards to addition of topside loading for platforms with marginal reserved strength. Detailed assessment is required to address potential local member overstress for the topside structural members.","PeriodicalId":11081,"journal":{"name":"Day 2 Wed, March 23, 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":"76859080","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}
Since resistivity logging is much more sensitive to rocks than to hydrocarbons in granite reservoirs, conventional logging methods cannot always accurately evaluate fluid properties and identify pay zones. Drill Stem Test (DST) is often used to identify fluid properties and hydrocarbon production potentials. However, DST in granite reservoirs cannot accurately determine production from sub-layers which leads to inaccurate net pay zone identification and reserve estimation. The accurate determination of fluid properties and net pay zones in fractured granite reservoirs remains a challenging topic. This study proposes the use of Production Profile Logging (PLT)Logging in exploration wells in JZ oilfield characterized by fractured granite reservoirs, where DST could not characterize the sub-layers’ PLTs with in the thick layer of the combined test. With the use of open hole completion test, PLT logging can easily identify the production from sub-layers. The fluid density and water hold-up are consistent with the response of flowmeter logs. The method not only identifies production from sub-layers but also determines fluid properties. Meanwhile, it can quantify the production from each sub-layer according to PLT logging interpretation. It has satisfactory application in productivity evaluation in JZ oilfield. Results indicate that the use of PLT logging in four exploration wells in JZ oilfield is successful. Sub-layers are identified in DST based on PLT logging interpretations of flow rate, density, and water hold-up. The productivity index of each sub-layer is calculated by PLT logging interpretation. Combining lateral resistivity logs with sonic logging data, Draw porosity and ratio of the deep and shallow lateral resistivity plot based on each sub-layer’ production with PLT interpretation Logging results. Net pay cutoffs of JZ oilfield is determined to be φ≥3.0% and (RD/RS) *DT≥90. This method improves the accuracy of reserve evaluation and solves the problem that the estimates of net pay cutoffs are larger than actual values in DST. Compared with DST in fractured granite reservoirs, PLT logging not only leads to accurate determination of fluid properties and identification of net pay cutoffs but also largely reduces the costs. PLT logging is conventionally used to dynamically monitor cased hole wells. The novelty of this study is the successful application of PLT logging in reserve estimation. Compared to the conventional reserve estimation method based on DST, this new strategy accurately identifies net pay zones and determines net pay cutoffs in fractured granites to improve the accuracy of reserve estimation. Thus, the field can be developed more economically when oil prices are low.
{"title":"Determination of Fluid Properties and Reservoir Net Pay Cutoffs by Production Logging and Conventional Logs in Exploration Wells :A Case Study of the Granite Fractured Reservoir in JZ Oilfiled in Bohai Sea","authors":"Xinlei Shi, Yunjiang Cui, Sainan Xu, Ruihong Wang, Hao Zhang","doi":"10.4043/31347-ms","DOIUrl":"https://doi.org/10.4043/31347-ms","url":null,"abstract":"\u0000 Since resistivity logging is much more sensitive to rocks than to hydrocarbons in granite reservoirs, conventional logging methods cannot always accurately evaluate fluid properties and identify pay zones. Drill Stem Test (DST) is often used to identify fluid properties and hydrocarbon production potentials. However, DST in granite reservoirs cannot accurately determine production from sub-layers which leads to inaccurate net pay zone identification and reserve estimation. The accurate determination of fluid properties and net pay zones in fractured granite reservoirs remains a challenging topic.\u0000 This study proposes the use of Production Profile Logging (PLT)Logging in exploration wells in JZ oilfield characterized by fractured granite reservoirs, where DST could not characterize the sub-layers’ PLTs with in the thick layer of the combined test. With the use of open hole completion test, PLT logging can easily identify the production from sub-layers. The fluid density and water hold-up are consistent with the response of flowmeter logs. The method not only identifies production from sub-layers but also determines fluid properties. Meanwhile, it can quantify the production from each sub-layer according to PLT logging interpretation. It has satisfactory application in productivity evaluation in JZ oilfield.\u0000 Results indicate that the use of PLT logging in four exploration wells in JZ oilfield is successful. Sub-layers are identified in DST based on PLT logging interpretations of flow rate, density, and water hold-up. The productivity index of each sub-layer is calculated by PLT logging interpretation. Combining lateral resistivity logs with sonic logging data, Draw porosity and ratio of the deep and shallow lateral resistivity plot based on each sub-layer’ production with PLT interpretation Logging results. Net pay cutoffs of JZ oilfield is determined to be φ≥3.0% and (RD/RS) *DT≥90. This method improves the accuracy of reserve evaluation and solves the problem that the estimates of net pay cutoffs are larger than actual values in DST. Compared with DST in fractured granite reservoirs, PLT logging not only leads to accurate determination of fluid properties and identification of net pay cutoffs but also largely reduces the costs.\u0000 PLT logging is conventionally used to dynamically monitor cased hole wells. The novelty of this study is the successful application of PLT logging in reserve estimation. Compared to the conventional reserve estimation method based on DST, this new strategy accurately identifies net pay zones and determines net pay cutoffs in fractured granites to improve the accuracy of reserve estimation. Thus, the field can be developed more economically when oil prices are low.","PeriodicalId":11081,"journal":{"name":"Day 2 Wed, March 23, 2022","volume":"25 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77626714","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}
Sharizal bin Amurol Jamal, Tiing-Poh Hii, Zhili Ang, Kenneth Yip, Tee Bin Lim
Malikai Tension Leg Platform (TLP) being the first TLP in Malaysian waters, was installed in 2016 at a water depth of 500m. The mooring system was designed with tender-assisted drilling (TAD) features to allow for station keeping activities during drilling operations. Malikai Phase 2 is brownfield project to develop six infill wells to be drill using existing well slots available on TLP. To drive project value of replication and standardization, similar TAD vessel was used as per Phase 1 campaign. The project execution strategy emphasizes on the reuse of Phase 1 mooring component to lower the CAPEX and re-certification of the mooring component were done to maintain the integrity of the hardware. Existence of porkmarks and large part of geo-hazard on the Malikai seafloor, remain one of the main challenges to safety pre-lay polyester on the selected routes. Furthermore, due to Covid-19 pandemic the shipment of the polyester ropes was delayed. Improvement was made in the offshore installation methodology with introduction of the direct hook-up methods to eliminate the risk of polyester damaging during pre-laid, eliminate the chain twists issue on ground chain section and that also help in preserving project schedule. The development of innovative contracting and supply chain management strategies such as competitive bidding exercise and leverage on contractor expertise to drive the efficient execution. Virtual working setting is a new way of working in marine assurances due to Covid-19 travel restrictions. This paper will provide a board overview of various aspects of Malikai Phase 2 brownfield development during pandemic condition while highlighting key success factors and lesson learned for future projects.
{"title":"Implementation of Key Risk Mitigation Strategies and Learnings Enabling Successful Efficient Execution in Malikai Phase 2 Project Mooring Campaigns","authors":"Sharizal bin Amurol Jamal, Tiing-Poh Hii, Zhili Ang, Kenneth Yip, Tee Bin Lim","doi":"10.4043/31397-ms","DOIUrl":"https://doi.org/10.4043/31397-ms","url":null,"abstract":"\u0000 Malikai Tension Leg Platform (TLP) being the first TLP in Malaysian waters, was installed in 2016 at a water depth of 500m. The mooring system was designed with tender-assisted drilling (TAD) features to allow for station keeping activities during drilling operations. Malikai Phase 2 is brownfield project to develop six infill wells to be drill using existing well slots available on TLP. To drive project value of replication and standardization, similar TAD vessel was used as per Phase 1 campaign.\u0000 The project execution strategy emphasizes on the reuse of Phase 1 mooring component to lower the CAPEX and re-certification of the mooring component were done to maintain the integrity of the hardware. Existence of porkmarks and large part of geo-hazard on the Malikai seafloor, remain one of the main challenges to safety pre-lay polyester on the selected routes. Furthermore, due to Covid-19 pandemic the shipment of the polyester ropes was delayed. Improvement was made in the offshore installation methodology with introduction of the direct hook-up methods to eliminate the risk of polyester damaging during pre-laid, eliminate the chain twists issue on ground chain section and that also help in preserving project schedule. The development of innovative contracting and supply chain management strategies such as competitive bidding exercise and leverage on contractor expertise to drive the efficient execution. Virtual working setting is a new way of working in marine assurances due to Covid-19 travel restrictions.\u0000 This paper will provide a board overview of various aspects of Malikai Phase 2 brownfield development during pandemic condition while highlighting key success factors and lesson learned for future projects.","PeriodicalId":11081,"journal":{"name":"Day 2 Wed, March 23, 2022","volume":"23 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"75448380","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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