R. Marindha, P. S. Kurniawati, Gerardus Putra Pancawisna, R. Hidayat, G. D. Dahnil, K. Umar, Risal Rahman, Nasrulloh Alfarisy, Eko Marsudiono, Clement Chhin
In order to answer the future challenges associated with offshore logistics, minimalist platform and job simplicity, smaller footprint of coiled tubing set is required for pumping job. Although coiled tubing (CT) is one of the most efficient deployment method for multiple wellsite operations and various objectives. Often it is difficult to capture all the benefits of its application in some offshore wells. Limited crane capacity and deck space at the platform often provide challenges to efficiently execute a CT operation. Minimalist and crowded platforms may not allow conducive condition to set up a conventional CT system. As part of continuous improvement in Well Intervention, smaller size of CT called Micro CT is deployed to unload the completion fluid using nitrogen pumping. This is to provide sufficient drawdown prior to clean up or perforation jobs. Micro CT is a small coiled tubing typically with 1" outside diameter and 10,000 ft length. It is approximately half the weight and a third smaller compared to the conventional CT. The start-up project of 1st Micro CT job in Indonesia is commenced with unloading Job in Bekapai and South Mahakam wells. Five (5) unloading job are successfully performed within allocated time frame and budget. There were no major safety issues recorded. Total of 60% cost saving was generated from the reduced mobilization trips of supply boat while 40% cost saving is from improved diesel consumption efficiency. From operational aspect, less annular friction can be achieved and led save up to 35% in N2 consumption. Moreover, it saves10 – 20% rig up time in comparison to conventional CT. On top of that, those 5 unloading jobs was completed with liquid unloading efficiency of more than 70% from the target. This paper will elaborate the experience of an Asset Operator in deploying 1st Micro CT application safely and will discuss in detail some of the measurable milestone achievement from the project.
{"title":"First Application of Micro Coiled Tubing in Indonesia at Offshore Mahakam","authors":"R. Marindha, P. S. Kurniawati, Gerardus Putra Pancawisna, R. Hidayat, G. D. Dahnil, K. Umar, Risal Rahman, Nasrulloh Alfarisy, Eko Marsudiono, Clement Chhin","doi":"10.2118/205535-ms","DOIUrl":"https://doi.org/10.2118/205535-ms","url":null,"abstract":"\u0000 In order to answer the future challenges associated with offshore logistics, minimalist platform and job simplicity, smaller footprint of coiled tubing set is required for pumping job.\u0000 Although coiled tubing (CT) is one of the most efficient deployment method for multiple wellsite operations and various objectives. Often it is difficult to capture all the benefits of its application in some offshore wells. Limited crane capacity and deck space at the platform often provide challenges to efficiently execute a CT operation. Minimalist and crowded platforms may not allow conducive condition to set up a conventional CT system.\u0000 As part of continuous improvement in Well Intervention, smaller size of CT called Micro CT is deployed to unload the completion fluid using nitrogen pumping. This is to provide sufficient drawdown prior to clean up or perforation jobs.\u0000 Micro CT is a small coiled tubing typically with 1\" outside diameter and 10,000 ft length. It is approximately half the weight and a third smaller compared to the conventional CT. The start-up project of 1st Micro CT job in Indonesia is commenced with unloading Job in Bekapai and South Mahakam wells. Five (5) unloading job are successfully performed within allocated time frame and budget. There were no major safety issues recorded. Total of 60% cost saving was generated from the reduced mobilization trips of supply boat while 40% cost saving is from improved diesel consumption efficiency. From operational aspect, less annular friction can be achieved and led save up to 35% in N2 consumption. Moreover, it saves10 – 20% rig up time in comparison to conventional CT. On top of that, those 5 unloading jobs was completed with liquid unloading efficiency of more than 70% from the target.\u0000 This paper will elaborate the experience of an Asset Operator in deploying 1st Micro CT application safely and will discuss in detail some of the measurable milestone achievement from the project.","PeriodicalId":11017,"journal":{"name":"Day 2 Wed, October 13, 2021","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2021-10-04","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"91118451","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}
A. Muklas, C. Kurniawan, Hendra Kusuma, Bonni Ariwibowo, P. R. Safiraldi, N. S. Elthaf
In October 2019, electrical submersible pump (ESP) XY-107 experienced an overload shutdown. Troubleshooting actions have been conducted such as reverse rotation, used rocking method, voltage boost, inject gas through the annulus, and even fluid circulation, yet still failed to reactivate the well. Pump stuck condition was suspected and urgently need a solution. A study was performed to determine the cause of pump stuck. XY-107 is produced from limestone formation, therefore suggesting possibility of scale deposit formation in this well. Upon physical inspection inside the well's flowline, lump of deposit was recovered and suspect similar material could have occurred inside the pump. Rig intervention is a common solution for the ESP pump stuck condition. However, it required high cost (around 80,000 USD) and a longer well service job period up to 5 days. With scale deposit as the suspect, an unconventional solution was proposed to soak the well with acid to dissolve stuck-material by rigless operation. It was much cheaper than rig intervention (only about 4,000 USD) and with a shorter time of 1 day. Yet, acid selection is critical to avoid material damage during operation. Since conventional acid system is known to be corrosive to the metal components, hazardous, and difficult to handle; chelating acid was chosen as an alternative since it is known as a metal-friendly and able to dissolve carbonate and iron deposit. Treatment to address pump stuck situation was executed in March 2020. The chemical treatment was injected by pumping and circulating chelating solution from tubing to the annulus. ESP then soaked for 48-hours long. The treatment has successfully revived the well. It produced with no significant issue for 8 months and even double the oil production. This successful treatment proves chelating technique is safer for ESP and able to regain well production. Significant cost saving up to 76,000 USD was realized by avoiding rig intervention and shortening time of well services. Detailed study, laboratory testing, treatment procedure, and further analysis are discussed in this paper. Chelating acidizing is an uncommon acid system to stimulate carbonates and sandstone in our operating area. Since its successful performance during the trial, more acid campaign using chelating was conducted to enhance oil production. However, this acid system was never been tried as a solution treatment for pump stuck condition and the case of well XY-107 was the first time in the company's history.
{"title":"Long Exposure Chelating Acid Treatment to Release ESP Stuck Pump","authors":"A. Muklas, C. Kurniawan, Hendra Kusuma, Bonni Ariwibowo, P. R. Safiraldi, N. S. Elthaf","doi":"10.2118/205628-ms","DOIUrl":"https://doi.org/10.2118/205628-ms","url":null,"abstract":"\u0000 In October 2019, electrical submersible pump (ESP) XY-107 experienced an overload shutdown. Troubleshooting actions have been conducted such as reverse rotation, used rocking method, voltage boost, inject gas through the annulus, and even fluid circulation, yet still failed to reactivate the well. Pump stuck condition was suspected and urgently need a solution.\u0000 A study was performed to determine the cause of pump stuck. XY-107 is produced from limestone formation, therefore suggesting possibility of scale deposit formation in this well. Upon physical inspection inside the well's flowline, lump of deposit was recovered and suspect similar material could have occurred inside the pump. Rig intervention is a common solution for the ESP pump stuck condition. However, it required high cost (around 80,000 USD) and a longer well service job period up to 5 days. With scale deposit as the suspect, an unconventional solution was proposed to soak the well with acid to dissolve stuck-material by rigless operation. It was much cheaper than rig intervention (only about 4,000 USD) and with a shorter time of 1 day. Yet, acid selection is critical to avoid material damage during operation. Since conventional acid system is known to be corrosive to the metal components, hazardous, and difficult to handle; chelating acid was chosen as an alternative since it is known as a metal-friendly and able to dissolve carbonate and iron deposit. Treatment to address pump stuck situation was executed in March 2020. The chemical treatment was injected by pumping and circulating chelating solution from tubing to the annulus. ESP then soaked for 48-hours long.\u0000 The treatment has successfully revived the well. It produced with no significant issue for 8 months and even double the oil production. This successful treatment proves chelating technique is safer for ESP and able to regain well production. Significant cost saving up to 76,000 USD was realized by avoiding rig intervention and shortening time of well services. Detailed study, laboratory testing, treatment procedure, and further analysis are discussed in this paper.\u0000 Chelating acidizing is an uncommon acid system to stimulate carbonates and sandstone in our operating area. Since its successful performance during the trial, more acid campaign using chelating was conducted to enhance oil production. However, this acid system was never been tried as a solution treatment for pump stuck condition and the case of well XY-107 was the first time in the company's history.","PeriodicalId":11017,"journal":{"name":"Day 2 Wed, October 13, 2021","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2021-10-04","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88824348","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}
Mingjun Chen, Peisong Li, Yili Kang, Gao Xinping, Dongsheng Yang, Maoling Yan
The low flowback efficiency of fracturing fluid would severely increase water saturation in a near-fracture formation and limit gas transport capacity in the matrix of a shale gas reservoir. Formation heat treatment (FHT) is a state-of-the-art technology to prevent water blocking induced by fracturing fluid retention and accelerate gas desorption and diffusion in the matrix. A comprehensive understanding of its formation damage removal mechanisms and determination of production improvement is conducive to enhancing shale gas recovery. In this research, the FHT simulation experiment was launched to investigate the effect of FHT on gas transport capacity, the multi-field coupling model was established to determine the effective depth of FHT, and the numerical simulation model of the shale reservoir was established to analyze the feasibility of FHT. Experimental results show that the shale permeability and porosity were rising overall during the FHT, the L-1 permeability increased by 30- 40 times, the L-2 permeability increased by more than 100 times. The Langmuir pressure increased by 1.68 times and the Langmuir volume decreased by 26%, which means the methane desorption efficiency increased. Results of the simulation demonstrate that the FHT process can practically improve the effect of hydraulic fracturing and significantly increase the well production capacity. The stimulation mechanisms of the FHT include thermal stress cracking, organic matter structure changing, and aqueous phase removal. Furthermore, the special characteristics of the supercritical water such as the strong oxidation, can not be ignored, due to the FHT can assist the retained hydraulic fracturing fluid to reach the critical temperature and pressure of water and transform to the supercritical state. The FHT can not only alleviate the formation damage induced by the fracturing fluid, but also make good use of the retained fracturing fluid to enhance the permeability of a shale gas reservoir, which is an innovative method to dramatically enhance gas transport capacity in shale matrix.
{"title":"Application of Heat Treatment to Prevent Fracturing Fluid-Induced Formation Damage and Enhance Matrix Permeability in Shale Gas Reservoirs","authors":"Mingjun Chen, Peisong Li, Yili Kang, Gao Xinping, Dongsheng Yang, Maoling Yan","doi":"10.2118/205591-ms","DOIUrl":"https://doi.org/10.2118/205591-ms","url":null,"abstract":"\u0000 The low flowback efficiency of fracturing fluid would severely increase water saturation in a near-fracture formation and limit gas transport capacity in the matrix of a shale gas reservoir. Formation heat treatment (FHT) is a state-of-the-art technology to prevent water blocking induced by fracturing fluid retention and accelerate gas desorption and diffusion in the matrix. A comprehensive understanding of its formation damage removal mechanisms and determination of production improvement is conducive to enhancing shale gas recovery. In this research, the FHT simulation experiment was launched to investigate the effect of FHT on gas transport capacity, the multi-field coupling model was established to determine the effective depth of FHT, and the numerical simulation model of the shale reservoir was established to analyze the feasibility of FHT. Experimental results show that the shale permeability and porosity were rising overall during the FHT, the L-1 permeability increased by 30- 40 times, the L-2 permeability increased by more than 100 times. The Langmuir pressure increased by 1.68 times and the Langmuir volume decreased by 26%, which means the methane desorption efficiency increased. Results of the simulation demonstrate that the FHT process can practically improve the effect of hydraulic fracturing and significantly increase the well production capacity. The stimulation mechanisms of the FHT include thermal stress cracking, organic matter structure changing, and aqueous phase removal. Furthermore, the special characteristics of the supercritical water such as the strong oxidation, can not be ignored, due to the FHT can assist the retained hydraulic fracturing fluid to reach the critical temperature and pressure of water and transform to the supercritical state. The FHT can not only alleviate the formation damage induced by the fracturing fluid, but also make good use of the retained fracturing fluid to enhance the permeability of a shale gas reservoir, which is an innovative method to dramatically enhance gas transport capacity in shale matrix.","PeriodicalId":11017,"journal":{"name":"Day 2 Wed, October 13, 2021","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2021-10-04","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84700433","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}
Hongtao Liu, Ai Zhengqing, Jingcheng Zhang, Zhongtao Yuan, Jianguo Zeng, Xu Liqun, T. Bin
The average porosity and permeability in the developed clastic rock reservoir in Tarim oilfield in China is 22.16% and 689.85×10-3 μm2. The isolation layer thickness between water layer and oil layer is less than 2 meters. The pressure of oil layer is 0.99 g/cm3, and the pressure of bottom water layer is 1.22 g/cm3, the pressure difference between them is as bigger as 12 to 23 MPa. It is difficult to achieve the layer isolation between the water layer and oil layer. To solve the zonal isolation difficulty and reduce permeable loss risk in clastic reservoir with high porosity and permeability, matrix anti-invasion additive, self-innovate plugging ability material of slurry, self-healing slurry, open-hole packer outside the casing, design and control technology of cement slurry performance, optimizing casing centralizer location technology and displacement with high pump rate has been developed and successfully applied. The results show that: First, the additive with physical and chemical crosslinking structure matrix anti-invasion is developed. The additive has the characteristics of anti-dilution, low thixotropy, low water loss and short transition, and can seal the water layer quickly. Second, the plugging material in the slurry has a better plugging performance and could reduce the permeability of artificial core by 70-80% in the testing evaluation. Third, the self-healing cement slurry system can quickly seal the fracture and prevent the fluid from flowing, and can ensuring the long-term effective sealing of the reservoir. Fourth, By strict control of the thickening time (operation time) and consistency (20-25 Bc), the cement slurry can realize zonal isolation quickly, which has achieved the purpose of quickly sealing off the water layer and reduced the risk of permeable loss. And the casing centralizers are used to ensure that the standoff ratio of oil and water layer is above 67%. The displacement with high pump rate (2 m3/min, to ensure the annular return velocity more than 1.2 m/s) can efficiently clean the wellbore by diluting the drilling fluid and washing the mud cake, and can improve the displacement efficiency. The cementing technology has been successfully applied in 100 wells in Tarim Oilfield. The qualification rate and high quality rate is 87.9% and 69% in 2019, and achieve zone isolation. No water has been produced after the oil testing and the water content has decreased to 7% after production. With the cementing technology, we have improved zonal isolation, increased the crude oil production and increased the benefit of oil.
{"title":"The Research and Application of Cementing Isolation Technology in High Porosity and Permeability of Developed Clastic Rock Reservoir in Tarim Basin","authors":"Hongtao Liu, Ai Zhengqing, Jingcheng Zhang, Zhongtao Yuan, Jianguo Zeng, Xu Liqun, T. Bin","doi":"10.2118/205588-ms","DOIUrl":"https://doi.org/10.2118/205588-ms","url":null,"abstract":"\u0000 The average porosity and permeability in the developed clastic rock reservoir in Tarim oilfield in China is 22.16% and 689.85×10-3 μm2. The isolation layer thickness between water layer and oil layer is less than 2 meters. The pressure of oil layer is 0.99 g/cm3, and the pressure of bottom water layer is 1.22 g/cm3, the pressure difference between them is as bigger as 12 to 23 MPa. It is difficult to achieve the layer isolation between the water layer and oil layer.\u0000 To solve the zonal isolation difficulty and reduce permeable loss risk in clastic reservoir with high porosity and permeability, matrix anti-invasion additive, self-innovate plugging ability material of slurry, self-healing slurry, open-hole packer outside the casing, design and control technology of cement slurry performance, optimizing casing centralizer location technology and displacement with high pump rate has been developed and successfully applied.\u0000 The results show that: First, the additive with physical and chemical crosslinking structure matrix anti-invasion is developed. The additive has the characteristics of anti-dilution, low thixotropy, low water loss and short transition, and can seal the water layer quickly. Second, the plugging material in the slurry has a better plugging performance and could reduce the permeability of artificial core by 70-80% in the testing evaluation. Third, the self-healing cement slurry system can quickly seal the fracture and prevent the fluid from flowing, and can ensuring the long-term effective sealing of the reservoir. Fourth, By strict control of the thickening time (operation time) and consistency (20-25 Bc), the cement slurry can realize zonal isolation quickly, which has achieved the purpose of quickly sealing off the water layer and reduced the risk of permeable loss. And the casing centralizers are used to ensure that the standoff ratio of oil and water layer is above 67%. The displacement with high pump rate (2 m3/min, to ensure the annular return velocity more than 1.2 m/s) can efficiently clean the wellbore by diluting the drilling fluid and washing the mud cake, and can improve the displacement efficiency.\u0000 The cementing technology has been successfully applied in 100 wells in Tarim Oilfield. The qualification rate and high quality rate is 87.9% and 69% in 2019, and achieve zone isolation. No water has been produced after the oil testing and the water content has decreased to 7% after production. With the cementing technology, we have improved zonal isolation, increased the crude oil production and increased the benefit of oil.","PeriodicalId":11017,"journal":{"name":"Day 2 Wed, October 13, 2021","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2021-10-04","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84889409","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}
R. Alfajri, Herbert Sipahutar, Heru Irianto, Harry Kananta, Catur Sunawan Balya, Muhammed Ghiffari, A. Maltsev, Andrei Lobanov
Electrical Submersible Pump (ESP) is an artificial lift that often associated with big production rate, which is at least 300 bbls/day. ESP also has limitation in handling unconsolidated sand reservoir, high GOR wells, and minimum casing ID. As technology flourished, these handicaps for an ESP well are no longer valid. A breakthrough was established for ESP utilization. However people's perception of ESP persists. Extreme well ESP is changing that perception. There are three types of extreme well ESP: high solid content, high GOR, and slim-line ESP. High solid content ESP has open impellers. This type of impeller creates no space between impeller and diffuser, hence no solids accumulation. Multiphase pump (MPP) is used to handle high GOR problem. MPP stage design has axial screw type impeller and gas handling diffuser. Gas from reservoir fluid will be compressed and broken into smaller bubbles resulting in homogenous gas-liquid mixture, hence no gas lock during production. For well with small casing ID e.g., 4-1/2" casing, slim-line ESP with 3.19" outside diameter is utilized. These three types of extreme well ESP were all utilized in Central Sumatera Asset of Pertamina EP. High solid content ESPs were installed in five wells (MJ-134, MJ-132, MJ-128, STT-25, and KTT-23) in four different structures with production range of 30 to 1200 bbls/day. Basic Sediment (BS) number in this asset varies from 0.1% up to 40%, which results in suspending wells and repeating well services. In wells MJ-134, high solid content ESP was able to produce up to 50% BS number at the beginning of production. It showed excellent lifting capability in severe sand problem condition. While in wells STT-25 and KTT-23, utilizing high solid content ESP increases well's lifetime and generates gain in production. High GOR ESPs were installed in wells PPS-01 and SGC-15. Both wells has around 2000 scf/stb GOR. Conventional ESP would have a hard time producing these gassy wells. By using MPP, well PPS-01 produced smoothly and even later optimized to have bigger production. Producing well SGC-15 faced another handicap in form of scale deposition. Scale preventer was also installed for this well. Slim-line ESP was installed in well BJG-01 that has 4-1/2" casing. Grossing up the wells with slim-line ESP contributes production gain. Since October 2019 this project has produced cumulative production of 56,199 bbls oil and counting, and been considered successful in solving extreme well problems. Being proven able to handle high BS number, high GOR, and produce well with small casing size, extreme well ESP is altering old mindset in ESP utilization. All of handicaps mentioned above were redeemed obsolete. This breakthrough starts the dawn of new perception in artificial lift selection.
{"title":"Extreme Well Electrical Submersible Pump: Altering Perception in Artificial Lift Selection","authors":"R. Alfajri, Herbert Sipahutar, Heru Irianto, Harry Kananta, Catur Sunawan Balya, Muhammed Ghiffari, A. Maltsev, Andrei Lobanov","doi":"10.2118/205584-ms","DOIUrl":"https://doi.org/10.2118/205584-ms","url":null,"abstract":"\u0000 Electrical Submersible Pump (ESP) is an artificial lift that often associated with big production rate, which is at least 300 bbls/day. ESP also has limitation in handling unconsolidated sand reservoir, high GOR wells, and minimum casing ID. As technology flourished, these handicaps for an ESP well are no longer valid. A breakthrough was established for ESP utilization. However people's perception of ESP persists. Extreme well ESP is changing that perception.\u0000 There are three types of extreme well ESP: high solid content, high GOR, and slim-line ESP. High solid content ESP has open impellers. This type of impeller creates no space between impeller and diffuser, hence no solids accumulation. Multiphase pump (MPP) is used to handle high GOR problem. MPP stage design has axial screw type impeller and gas handling diffuser. Gas from reservoir fluid will be compressed and broken into smaller bubbles resulting in homogenous gas-liquid mixture, hence no gas lock during production. For well with small casing ID e.g., 4-1/2\" casing, slim-line ESP with 3.19\" outside diameter is utilized.\u0000 These three types of extreme well ESP were all utilized in Central Sumatera Asset of Pertamina EP. High solid content ESPs were installed in five wells (MJ-134, MJ-132, MJ-128, STT-25, and KTT-23) in four different structures with production range of 30 to 1200 bbls/day. Basic Sediment (BS) number in this asset varies from 0.1% up to 40%, which results in suspending wells and repeating well services. In wells MJ-134, high solid content ESP was able to produce up to 50% BS number at the beginning of production. It showed excellent lifting capability in severe sand problem condition. While in wells STT-25 and KTT-23, utilizing high solid content ESP increases well's lifetime and generates gain in production. High GOR ESPs were installed in wells PPS-01 and SGC-15. Both wells has around 2000 scf/stb GOR. Conventional ESP would have a hard time producing these gassy wells. By using MPP, well PPS-01 produced smoothly and even later optimized to have bigger production. Producing well SGC-15 faced another handicap in form of scale deposition. Scale preventer was also installed for this well. Slim-line ESP was installed in well BJG-01 that has 4-1/2\" casing. Grossing up the wells with slim-line ESP contributes production gain.\u0000 Since October 2019 this project has produced cumulative production of 56,199 bbls oil and counting, and been considered successful in solving extreme well problems. Being proven able to handle high BS number, high GOR, and produce well with small casing size, extreme well ESP is altering old mindset in ESP utilization. All of handicaps mentioned above were redeemed obsolete. This breakthrough starts the dawn of new perception in artificial lift selection.","PeriodicalId":11017,"journal":{"name":"Day 2 Wed, October 13, 2021","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2021-10-04","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87375859","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}
Irfan Taufik Rau, J. Sianturi, Azarya Hesron, A. Suardiputra
The studied field was discovered in 1974 and has been in operation for nearly 50 years. Being deposited within a deltaic environment with enormous multi-layer sand-shale series, the field is vertically divided into dozens of geological layers. Previous reserves estimation method of manually performing dynamic synthesis followed by volumetric calculation per layer basis has become less preferable amid increasing drilling and well intervention activities. Meanwhile, reservoir simulation is also inapplicable for reserves estimation due to the field's subsurface complexity. This paper shares an approach to automate well correlation and dynamic synthesis process by integrating static and dynamic data into Visual Basic for Application (VBA) based tool in order to efficiently estimate reserves and accelerate candidate selection for new well drilling and well intervention. Performing dynamic synthesis on a certain reservoir within a well of interest involves estimation of latest fluid status, pressure, water risks, recovery factor, and drainage radius by analyzing recent static and dynamic data from surrounding wells. As the static data and dynamic data from hundreds of existing wells are available in separate databases, the study commences with collecting, updating, filtering, organizing and integrating data into one reliable database. Afterwards, the automation tool is designed to quantitatively mimic the logics of performing well correlation and dynamic synthesis using weighting factors that characterize the reliability of data based on 3 parameters: distance to the well of interest, recentness of data, and sand similarity. Since these parameters have distinctive influence depending on the dynamic property being estimated, influence factors are introduced for each parameter and each dynamic property through trial & error process. Combining weighting and influence factors with available data results in the estimated dynamic properties that become input to volumetric calculation of reserves. In order to validate the model and tool, blind tests are carried out using data from recently drilled wells which are not included in generating the estimation. Pressure blind test shows good correlation between predicted and realized values, meaning that the tool is able to predict pressure accurately. Reserves estimation blind test also shows satisfying results both at reservoir and well level. Following successful blind tests, the tool has been utilized to aid engineers in proposing new wells and well intervention candidates. As a result, 8 wells were able to be proposed in a timely manner for the sanction of future development. This paper presents an efficient, novel and robust approach in estimating reserves for heterogeneous fields where reservoir simulation is inapplicable. The tool also allows straightforward update when adding data from new wells. However, further study is required for estimation in less dense areas where the amount of surrounding well
所研究的油田于1974年被发现，已经运行了近50年。该油田沉积在巨大的多层砂页岩系列的三角洲环境中，垂直上划分为数十个地质层。随着钻井和油井干预活动的增加，以往的储量估算方法，即手动进行动态综合，然后进行每层体积计算，已经变得不那么可取了。同时，由于油田地下的复杂性，油藏模拟也不能用于储量估算。本文介绍了一种通过将静态和动态数据集成到基于Visual Basic for Application (VBA)的工具中，实现井间关联和动态综合过程自动化的方法，从而有效地估计储量，加快新井钻井和油井干预的候选选择。对某口井内的某一油藏进行动态综合，需要通过分析周围井最近的静态和动态数据来估计最新的流体状态、压力、水风险、采收率和排水半径。由于来自数百口现有井的静态数据和动态数据存在于不同的数据库中，因此研究从收集、更新、过滤、组织和整合数据到一个可靠的数据库开始。然后，自动化工具设计用于定量模拟执行井相关性和动态综合的逻辑，使用加权因子来表征数据的可靠性，该加权因子基于三个参数:与感兴趣的井的距离、数据的近时性和砂的相似性。由于这些参数对所估计的动态特性有不同的影响，因此通过试错过程对每个参数和每个动态特性引入影响因素。将加权和影响因素与现有数据相结合，得出估计的动态性质，这些动态性质成为储量体积计算的输入。为了验证模型和工具的有效性，使用了最近钻探的井的数据进行了盲测，这些数据不包括在生成估计中。压力盲测结果表明，预测值与实测值具有良好的相关性，表明该工具能够准确预测压力。储量估计盲测在油藏和井层均取得了令人满意的结果。在盲测成功后，该工具已被用于帮助工程师规划新井和修井候选井。因此，及时提出了8口井，为后续开发提供了依据。本文提出了一种高效、新颖、鲁棒的非均质油田储量估算方法。该工具还允许在添加新井的数据时进行简单的更新。然而，在密度较低、周围井数量和数据不足的地区，需要进一步研究估算。
{"title":"Automation of Well Correlation and Dynamic Synthesis for Efficient Reserves Estimation in Multi-Layered Oil and Gas Field","authors":"Irfan Taufik Rau, J. Sianturi, Azarya Hesron, A. Suardiputra","doi":"10.2118/205731-ms","DOIUrl":"https://doi.org/10.2118/205731-ms","url":null,"abstract":"\u0000 The studied field was discovered in 1974 and has been in operation for nearly 50 years. Being deposited within a deltaic environment with enormous multi-layer sand-shale series, the field is vertically divided into dozens of geological layers. Previous reserves estimation method of manually performing dynamic synthesis followed by volumetric calculation per layer basis has become less preferable amid increasing drilling and well intervention activities. Meanwhile, reservoir simulation is also inapplicable for reserves estimation due to the field's subsurface complexity. This paper shares an approach to automate well correlation and dynamic synthesis process by integrating static and dynamic data into Visual Basic for Application (VBA) based tool in order to efficiently estimate reserves and accelerate candidate selection for new well drilling and well intervention.\u0000 Performing dynamic synthesis on a certain reservoir within a well of interest involves estimation of latest fluid status, pressure, water risks, recovery factor, and drainage radius by analyzing recent static and dynamic data from surrounding wells. As the static data and dynamic data from hundreds of existing wells are available in separate databases, the study commences with collecting, updating, filtering, organizing and integrating data into one reliable database. Afterwards, the automation tool is designed to quantitatively mimic the logics of performing well correlation and dynamic synthesis using weighting factors that characterize the reliability of data based on 3 parameters: distance to the well of interest, recentness of data, and sand similarity. Since these parameters have distinctive influence depending on the dynamic property being estimated, influence factors are introduced for each parameter and each dynamic property through trial & error process. Combining weighting and influence factors with available data results in the estimated dynamic properties that become input to volumetric calculation of reserves.\u0000 In order to validate the model and tool, blind tests are carried out using data from recently drilled wells which are not included in generating the estimation. Pressure blind test shows good correlation between predicted and realized values, meaning that the tool is able to predict pressure accurately. Reserves estimation blind test also shows satisfying results both at reservoir and well level. Following successful blind tests, the tool has been utilized to aid engineers in proposing new wells and well intervention candidates. As a result, 8 wells were able to be proposed in a timely manner for the sanction of future development.\u0000 This paper presents an efficient, novel and robust approach in estimating reserves for heterogeneous fields where reservoir simulation is inapplicable. The tool also allows straightforward update when adding data from new wells. However, further study is required for estimation in less dense areas where the amount of surrounding well","PeriodicalId":11017,"journal":{"name":"Day 2 Wed, October 13, 2021","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2021-10-04","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"80947638","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}
Winanto Winanto, M. Bahroinuddin, E. Cahyono, Margaretha Thaliharjanti
KLB is an offshore platform that consists of production wells and two train gas lift compressors. During well intervention, the KLB operation team must turn off the flaring system due to potential flare radiation of more than 500 BTU/hr-ft2at the working area and gas dispersion more than 50 %-LEL at the flare tip. The relocation of the KLB flaring system to the nearest platform keeps the KLB gas lift compressor operating during this activity. The relocation scenario can maintain the KLB platform production of 700 BOPD. KLA Flowstation is the nearest platform to the KLB. It is separated one kilometer, connected by an idle subsea oil pipeline, but there are no pigging facilities due to limited space at the KLB platform. Therefore, the comprehensive assessment to relocate the KLB flaring system is a) Flare system study using Flare Network software to simulate backpressure and Mach Number at tailpipe in the KLA and KLB flaring system; b). Dynamic transient simulation using Flow Assurance Software to calculate backpressure, liquid hold up, and slugging condition in the flare KO drum; and c). Flare radiation and dispersion study. The initial condition of the idle subsea oil pipeline was full of liquid as the preservation for a pipeline to prevent a further oil spill in case of a leak during the idle condition. The dewatering process for the idle subsea pipeline has been conducted by purging the pipeline utilizes 0.7 MMscfd gas lift with a pressure of 100 psig to displace liquid content to 20 bbl. The transient simulation for gas swapping was conducted at a gas rate of 4.1 MMscfd as the train compressor's flaring condition. The calculated backpressure at the KLB safety valve is 12.3 psig below the required maximum of 30 psig. The calculated liquid surge volume in the Flare KO drum during flaring is 17 bbl and can be handled by surge volume inside the KO drum. The predicted condensation inside the subsea pipeline shows that the maximum operation of the flaring system is limited to 30 days. The radiation and gas dispersion to the nearest facility is within a safe limit. The KLB teams successfully conducted the relocation of the flaring system from the KLB platform to the KLA platform. The result was no interruption of production, no risk of radiation, and no potential explosion during a well intervention. Experience in the last two activities has confirmed that this method can prevent revenue loss of 19 billion rupiahs. This study has initiated a new engineering standard and best practice for flaring systems as opposed to the current practice which states that the flare location shall be at the same location as the production facilities with no pocket piping in between. This study and field experience have proved that the flaring system can be located on a different platform by conducting engineering assessments to ensure process and process safety criteria are within Company and International Standard.
{"title":"A Dynamic Simulation Assessment for Relocating Flare System into Separated Platform Utilizing Idle Subsea Main Oil line","authors":"Winanto Winanto, M. Bahroinuddin, E. Cahyono, Margaretha Thaliharjanti","doi":"10.2118/205741-ms","DOIUrl":"https://doi.org/10.2118/205741-ms","url":null,"abstract":"\u0000 KLB is an offshore platform that consists of production wells and two train gas lift compressors. During well intervention, the KLB operation team must turn off the flaring system due to potential flare radiation of more than 500 BTU/hr-ft2at the working area and gas dispersion more than 50 %-LEL at the flare tip. The relocation of the KLB flaring system to the nearest platform keeps the KLB gas lift compressor operating during this activity. The relocation scenario can maintain the KLB platform production of 700 BOPD.\u0000 KLA Flowstation is the nearest platform to the KLB. It is separated one kilometer, connected by an idle subsea oil pipeline, but there are no pigging facilities due to limited space at the KLB platform. Therefore, the comprehensive assessment to relocate the KLB flaring system is a) Flare system study using Flare Network software to simulate backpressure and Mach Number at tailpipe in the KLA and KLB flaring system; b). Dynamic transient simulation using Flow Assurance Software to calculate backpressure, liquid hold up, and slugging condition in the flare KO drum; and c). Flare radiation and dispersion study.\u0000 The initial condition of the idle subsea oil pipeline was full of liquid as the preservation for a pipeline to prevent a further oil spill in case of a leak during the idle condition. The dewatering process for the idle subsea pipeline has been conducted by purging the pipeline utilizes 0.7 MMscfd gas lift with a pressure of 100 psig to displace liquid content to 20 bbl. The transient simulation for gas swapping was conducted at a gas rate of 4.1 MMscfd as the train compressor's flaring condition. The calculated backpressure at the KLB safety valve is 12.3 psig below the required maximum of 30 psig. The calculated liquid surge volume in the Flare KO drum during flaring is 17 bbl and can be handled by surge volume inside the KO drum. The predicted condensation inside the subsea pipeline shows that the maximum operation of the flaring system is limited to 30 days. The radiation and gas dispersion to the nearest facility is within a safe limit.\u0000 The KLB teams successfully conducted the relocation of the flaring system from the KLB platform to the KLA platform. The result was no interruption of production, no risk of radiation, and no potential explosion during a well intervention. Experience in the last two activities has confirmed that this method can prevent revenue loss of 19 billion rupiahs. This study has initiated a new engineering standard and best practice for flaring systems as opposed to the current practice which states that the flare location shall be at the same location as the production facilities with no pocket piping in between. This study and field experience have proved that the flaring system can be located on a different platform by conducting engineering assessments to ensure process and process safety criteria are within Company and International Standard.","PeriodicalId":11017,"journal":{"name":"Day 2 Wed, October 13, 2021","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2021-10-04","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"91442948","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, E. A. Rosland, Elsayed Ouda Ghonim, L. Riyanto, Khairul Azhar Abu Bakar, Nurul Asyikin M. Radzuan, Nusheena Bt Mat Khair, S. M. Zaki
PETRONAS had embarked on an ambitious thru tubing ESP journey in 2016 and had installed global first truly rig less offshore Thru Tubing ESP (TTESP) in 2017. To replicate the success of the first installation, TTESP's were installed in Field – T. However, all these three TTESP's failed to produce fluids to surface. This paper provides the complete details of the troubleshooting exercise that was done to find the cause of failure in these wells. The 3 TTESP's in Field – T were installed as per procedure and was ready to be commissioned. However, during the commissioning, it was noticed that the discharge pressure of the ESP did not build-up and the TTESP's tripped due to high temperature after 15 – 30 mins of operation. Hence none of the 3 TTESP's could be successfully commissioned. Considering the strategic importance of TTESP's in PETRONAS's artificial lift plans, detailed troubleshooting exercise was done to find the root cause of failure to produce in these three wells. This troubleshooting exercise included diesel bull heading which gave some key pump performance related data. The three TTESP's installed in Field – T were of size 2.72" and had the potential to produce an average 1500 BLPD at 80% water cut. The TTESP deployment was fully rigless and was installed using 0.8" ESP power cable. The ESP and the cable was hung-off from the surface using a hanger – spool system. The entire system is complex, and the installation procedure needs to be proper to ensure a successful installation. The vast amount of data gathered during the commissioning and troubleshooting exercise was used for determining the failure reason and included preparation of static and dynamic well ESP model. After detailed technical investigative work, the team believes to have found the root cause of the issue which explains the data obtained during commission and troubleshooting phase. The detailed troubleshooting workflow and actual data obtained will be presented in this paper. A comprehensive list of lessons learnt will also be presented which includes very important aspects that needs to be considered during the design and installation of TTESP. The remedial plan is finalized and will be executed during next available weather window. The key benefit of a TTESP installation is its low cost which is 20% – 30% of a rig-based ESP workover in offshore. Hence it is expected that TTESP installations will pick-up globally and it's important for any operator to fully understand the TTESP systems and the potential pain points. PETRONAS has been a pioneer in TTESP field, and this paper will provide details on the learning curve during the TTESP journey.
{"title":"Troubleshooting Cable Deployed Thru Tubing Electrical Submersible Pumps: A Case Study from South East Asia","authors":"Saurabh Anand, E. A. Rosland, Elsayed Ouda Ghonim, L. Riyanto, Khairul Azhar Abu Bakar, Nurul Asyikin M. Radzuan, Nusheena Bt Mat Khair, S. M. Zaki","doi":"10.2118/205614-ms","DOIUrl":"https://doi.org/10.2118/205614-ms","url":null,"abstract":"\u0000 PETRONAS had embarked on an ambitious thru tubing ESP journey in 2016 and had installed global first truly rig less offshore Thru Tubing ESP (TTESP) in 2017. To replicate the success of the first installation, TTESP's were installed in Field – T. However, all these three TTESP's failed to produce fluids to surface. This paper provides the complete details of the troubleshooting exercise that was done to find the cause of failure in these wells.\u0000 The 3 TTESP's in Field – T were installed as per procedure and was ready to be commissioned. However, during the commissioning, it was noticed that the discharge pressure of the ESP did not build-up and the TTESP's tripped due to high temperature after 15 – 30 mins of operation. Hence none of the 3 TTESP's could be successfully commissioned. Considering the strategic importance of TTESP's in PETRONAS's artificial lift plans, detailed troubleshooting exercise was done to find the root cause of failure to produce in these three wells. This troubleshooting exercise included diesel bull heading which gave some key pump performance related data.\u0000 The three TTESP's installed in Field – T were of size 2.72\" and had the potential to produce an average 1500 BLPD at 80% water cut. The TTESP deployment was fully rigless and was installed using 0.8\" ESP power cable. The ESP and the cable was hung-off from the surface using a hanger – spool system. The entire system is complex, and the installation procedure needs to be proper to ensure a successful installation. The vast amount of data gathered during the commissioning and troubleshooting exercise was used for determining the failure reason and included preparation of static and dynamic well ESP model. After detailed technical investigative work, the team believes to have found the root cause of the issue which explains the data obtained during commission and troubleshooting phase. The detailed troubleshooting workflow and actual data obtained will be presented in this paper. A comprehensive list of lessons learnt will also be presented which includes very important aspects that needs to be considered during the design and installation of TTESP. The remedial plan is finalized and will be executed during next available weather window.\u0000 The key benefit of a TTESP installation is its low cost which is 20% – 30% of a rig-based ESP workover in offshore. Hence it is expected that TTESP installations will pick-up globally and it's important for any operator to fully understand the TTESP systems and the potential pain points. PETRONAS has been a pioneer in TTESP field, and this paper will provide details on the learning curve during the TTESP journey.","PeriodicalId":11017,"journal":{"name":"Day 2 Wed, October 13, 2021","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2021-10-04","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"85309489","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. Wiyoga, Jhonny Xu, Aulia Desiani Carolina, Ratna Dewanda
At times, petrophysicists are expected to evaluate potential of the well in time-constraint situations while maintaining consistency of the parameters and interpretation. Other than that, some challenges may also occur when working with older wells where the dataset are not as complete as current wells and processing parameters are not transferable. In this case study, class-based machine learning (CBML) approach is used to perform petrophysical evaluation to identify potential hydrocarbon zones in the target wells. The objective is to find solution to improve efficiency and consistency in those challenging situations. A class-based machine learning (CBML) workflow uses cross-entropy clustering (CEC)-Gaussian mixture model (GMM)- hidden Markov model (HMM) workflow that identifies locally stationary zones sharing similar statistical properties in logs, and then propagates zonation information from training wells to other wells (Jain, et al., 2019). The workflow is divided into two (2) main steps: training and prediction. Key wells which best represent the formation in the field are used to train the model. This approach automatically generates the number of cluster (class) using unsupervised or supervised depending on the input data. The model from key wells data is then used to reconstruct inputs and outputs along with uncertainty and outlier flags. This allows expert to QC and validate the generated class which is the most crucial part of the workflow. Once the model from the key wells has been built, it is applied to predict the same set of zones in the new wells that require interpretation and predict output curves. The result matched well over the good data interval with the petrophysical interpretation result from conventional approach. While in the bad interval, some discrepancies can be observed. The discrepancy was identified easily from the uncertainty and outlier flags which helps petrophysicists to identify which interval to fix or re-evaluate. Some requirements to condition the input were observed (no missing value over the input and outlier) to get the best result. A number of inputs used in the model need to be consistent over the set of wells used in the training and prediction target. This machine learning workflow speeds-up the petrophysical analysis process, reduce analyst bias and improve consistency result between one well to another within the same field. This machine learning application can also generate auto log QC, zonation class for rock typing also reconstructed logs which enrich the petrophysical interpretation even for wells with limited logs availability. This paper offers practical examples and lessons learned of CBML approach application to perform petrophysical evaluation and identify potential zones while being in time-constrained and limited resource situations.
{"title":"Application of Class-Based Machine Learning for Potential Hydrocarbon Zones Identification: A Case Study","authors":"S. Wiyoga, Jhonny Xu, Aulia Desiani Carolina, Ratna Dewanda","doi":"10.2118/205617-ms","DOIUrl":"https://doi.org/10.2118/205617-ms","url":null,"abstract":"\u0000 At times, petrophysicists are expected to evaluate potential of the well in time-constraint situations while maintaining consistency of the parameters and interpretation. Other than that, some challenges may also occur when working with older wells where the dataset are not as complete as current wells and processing parameters are not transferable. In this case study, class-based machine learning (CBML) approach is used to perform petrophysical evaluation to identify potential hydrocarbon zones in the target wells. The objective is to find solution to improve efficiency and consistency in those challenging situations.\u0000 A class-based machine learning (CBML) workflow uses cross-entropy clustering (CEC)-Gaussian mixture model (GMM)- hidden Markov model (HMM) workflow that identifies locally stationary zones sharing similar statistical properties in logs, and then propagates zonation information from training wells to other wells (Jain, et al., 2019). The workflow is divided into two (2) main steps: training and prediction. Key wells which best represent the formation in the field are used to train the model. This approach automatically generates the number of cluster (class) using unsupervised or supervised depending on the input data. The model from key wells data is then used to reconstruct inputs and outputs along with uncertainty and outlier flags. This allows expert to QC and validate the generated class which is the most crucial part of the workflow. Once the model from the key wells has been built, it is applied to predict the same set of zones in the new wells that require interpretation and predict output curves.\u0000 The result matched well over the good data interval with the petrophysical interpretation result from conventional approach. While in the bad interval, some discrepancies can be observed. The discrepancy was identified easily from the uncertainty and outlier flags which helps petrophysicists to identify which interval to fix or re-evaluate. Some requirements to condition the input were observed (no missing value over the input and outlier) to get the best result. A number of inputs used in the model need to be consistent over the set of wells used in the training and prediction target. This machine learning workflow speeds-up the petrophysical analysis process, reduce analyst bias and improve consistency result between one well to another within the same field. This machine learning application can also generate auto log QC, zonation class for rock typing also reconstructed logs which enrich the petrophysical interpretation even for wells with limited logs availability.\u0000 This paper offers practical examples and lessons learned of CBML approach application to perform petrophysical evaluation and identify potential zones while being in time-constrained and limited resource situations.","PeriodicalId":11017,"journal":{"name":"Day 2 Wed, October 13, 2021","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2021-10-04","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"91129476","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}
Audra Ligafinza, F. Sajjad, M. Jabbar, Anggia Fatmawati, A. Wirawan, Wingky Suganda
During the blowout event, it is critical to track the oil spill to minimize environmental damage and optimize restoration cost. In this paper, we deliver our success story in handling oil spill from recent experiences. We utilize remote sensing technologies to establish our analysis and plan the remediation strategies. We also comprehensively discuss the techniques to analyze big data from the satellites, to utilize the downloaded data for forecasting, and to align the satellite information with restoration strategies. PHE relies on its principle to maintain minimum damage and ensures safety by dividing the steps into several aspects of monitoring, response (offshore and onshore), shoreline management and waste management. PHE utilizes latest development in survey by using satellite imaging, survey boat, chopper and UAV drone. Spill containment is done using several layers of oil boom to recover oil spill, complemented with skimmers and storage tanks. PHE encourages shoreline remediation using nets and manual recovery for capturing oil sludge. Using this combination of technologies, PHE is able to model and anticipate oil spill movement from the source up until the farthest shoreline. This enables real time monitoring and handling, therefore minimum environmental damage is ensured. PHE also employs prudent engineering design based on real time field condition in order to ensure the equipment are highly suited for the condition, as well as ensuring good supply chain of the material availability. This publication addresses the first offshore blowout mitigation and handling in Indonesia that uses novel technologies such as static oil boom, satellite imaging and integrated effort in handling shoreline damage. It is hoped that the experience can be replicated for other offshore operating contractors in Indonesia in designing blowout remediation.
{"title":"Remote Sensing in Oil Spill Handling in Offshore North West Java","authors":"Audra Ligafinza, F. Sajjad, M. Jabbar, Anggia Fatmawati, A. Wirawan, Wingky Suganda","doi":"10.2118/205607-ms","DOIUrl":"https://doi.org/10.2118/205607-ms","url":null,"abstract":"\u0000 During the blowout event, it is critical to track the oil spill to minimize environmental damage and optimize restoration cost. In this paper, we deliver our success story in handling oil spill from recent experiences. We utilize remote sensing technologies to establish our analysis and plan the remediation strategies. We also comprehensively discuss the techniques to analyze big data from the satellites, to utilize the downloaded data for forecasting, and to align the satellite information with restoration strategies.\u0000 PHE relies on its principle to maintain minimum damage and ensures safety by dividing the steps into several aspects of monitoring, response (offshore and onshore), shoreline management and waste management. PHE utilizes latest development in survey by using satellite imaging, survey boat, chopper and UAV drone. Spill containment is done using several layers of oil boom to recover oil spill, complemented with skimmers and storage tanks. PHE encourages shoreline remediation using nets and manual recovery for capturing oil sludge.\u0000 Using this combination of technologies, PHE is able to model and anticipate oil spill movement from the source up until the farthest shoreline. This enables real time monitoring and handling, therefore minimum environmental damage is ensured. PHE also employs prudent engineering design based on real time field condition in order to ensure the equipment are highly suited for the condition, as well as ensuring good supply chain of the material availability.\u0000 This publication addresses the first offshore blowout mitigation and handling in Indonesia that uses novel technologies such as static oil boom, satellite imaging and integrated effort in handling shoreline damage. It is hoped that the experience can be replicated for other offshore operating contractors in Indonesia in designing blowout remediation.","PeriodicalId":11017,"journal":{"name":"Day 2 Wed, October 13, 2021","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2021-10-04","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77885452","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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