Khalid Obaid, A. Noufal, A. Almessabi, A. Abdelaal, K. Elsadany, E. Gofer, O. Aly, G. Nyein, A. Mukherjee
This study summarizes the efforts taken to provide reliable reservoir characterizations products to mitigate seismic interpretation challenges and delineation of the reservoirs. ADNOC has conducted seismic exploration activities to assess Miocene to Upper Cretaceous aged reservoirs in East Onshore Abu Dhabi. The Oligo-Miocene section comprises of interbedded salt (mainly halite), anhydrite, limestones and marls. Deposited in the foreland basin related to the Oman thrust-belt. Ranging in thickness from nearly 1.5 km in the depocenter to almost nil on the forebulge located to the west of the studied area. The well data based geological model suggests that initially porous rocks (presumably grain-supported carbonates) encompassed polyphase sulfate cementation during recurrent subaerial exposure in which pores and grains were recrystallized sometimes completely too massive, tight anhydrite beds. This heterogeneity of the complex shallow section showing high variation of velocity impact seismic imaging, and interpretation to model the stratigraphic/structural framework and link it with reservoir characterization. Hence, ADNOC decided to conduct a trial on state-of-art technique Litho-Petro-Elastic (LPE) AVA Inversion to mitigate the seismic interpretation challenges and delineate the reservoirs. The LPE AVA inversion provides a single-loop approach to reservoir characterization based on rock physics models and compaction trends, reducing the dependency on a detailed prior the low frequency model, Where the rock modelling and lithology classification are not separate steps but interact directly with the seismic AVO inversion for optimal estimates of lithologies and elastic properties. The LPE inversion scope requires seismic data conditioning such as CMP gathers de-noising, de-multiple, flattening and amplitude preservation, in addition to detailed log conditioning, petro-elastic and rock physics analysis to maximize the quality and value of the results. The study proved that the LPE AVA Inversion can be used to guide seismic interpreters in mapping the structural framework in challenging seismic data, as it managed to improve the prospect evaluation.
{"title":"First Case Study for Litho-Petro-Elastic AVA Pre-Stack Inversion for Complex Tight Reservoirs Miocene – Upper Cretaceous in East Onshore Abu Dhabi","authors":"Khalid Obaid, A. Noufal, A. Almessabi, A. Abdelaal, K. Elsadany, E. Gofer, O. Aly, G. Nyein, A. Mukherjee","doi":"10.2118/208090-ms","DOIUrl":"https://doi.org/10.2118/208090-ms","url":null,"abstract":"\u0000 This study summarizes the efforts taken to provide reliable reservoir characterizations products to mitigate seismic interpretation challenges and delineation of the reservoirs. ADNOC has conducted seismic exploration activities to assess Miocene to Upper Cretaceous aged reservoirs in East Onshore Abu Dhabi. The Oligo-Miocene section comprises of interbedded salt (mainly halite), anhydrite, limestones and marls. Deposited in the foreland basin related to the Oman thrust-belt. Ranging in thickness from nearly 1.5 km in the depocenter to almost nil on the forebulge located to the west of the studied area.\u0000 The well data based geological model suggests that initially porous rocks (presumably grain-supported carbonates) encompassed polyphase sulfate cementation during recurrent subaerial exposure in which pores and grains were recrystallized sometimes completely too massive, tight anhydrite beds. This heterogeneity of the complex shallow section showing high variation of velocity impact seismic imaging, and interpretation to model the stratigraphic/structural framework and link it with reservoir characterization. Hence, ADNOC decided to conduct a trial on state-of-art technique Litho-Petro-Elastic (LPE) AVA Inversion to mitigate the seismic interpretation challenges and delineate the reservoirs.\u0000 The LPE AVA inversion provides a single-loop approach to reservoir characterization based on rock physics models and compaction trends, reducing the dependency on a detailed prior the low frequency model, Where the rock modelling and lithology classification are not separate steps but interact directly with the seismic AVO inversion for optimal estimates of lithologies and elastic properties. The LPE inversion scope requires seismic data conditioning such as CMP gathers de-noising, de-multiple, flattening and amplitude preservation, in addition to detailed log conditioning, petro-elastic and rock physics analysis to maximize the quality and value of the results.\u0000 The study proved that the LPE AVA Inversion can be used to guide seismic interpreters in mapping the structural framework in challenging seismic data, as it managed to improve the prospect evaluation.","PeriodicalId":11069,"journal":{"name":"Day 2 Tue, November 16, 2021","volume":"79 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84095209","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}
Oleksandr Spuskanyuk, David C. Haeberle, B. M. Baumert, B. King, Benjamin T. Hillier
The growing number of upcoming well abandonments has become an important driver to seek efficiencies in optimizing abandonment costs while establishing long term well integrity and complying with local regulatory requirements. With an increasing global inventory of Plug and Abandonment (P&A) candidates, Exxonmobil has been driven to look for the most reliable, safe, and cost-efficient P&A technologies. ExxonMobil's P&A guidelines are consistent with and often more stringent than the local regulatory requirements but are also achievable, at least in part, with rigless technologies, leading to a more cost-efficient approach while ensuring well integrity. The objective of this paper is to demonstrate the success of rigless abandonments and their benefits compared to rig-based solutions. When developing a well abandonment plan, it is essential to consider a number of factors. These include local regulations, identification of zones to be isolated and suitable caprocks, and recognition of constraints including well history, conditions and uncertainties. Teams should begin with low cost operations without a rig if possible, estimate costs and effectiveness to achieve the barrier requirements, and evaluate batch operation opportunities for multi-well programs. ExxonMobil case studies are shown to help describe in detail how to make decisions about applicability of rigless abandonment options and how to properly execute such abandonments to achieve compliance with the barrier requirements. It has been demonstrated that significant cost savings can be achieved by staging the abandonment program in a way that lower cost technologies are utilized during the early stages of well abandonment, starting with wireline where possible, followed by coiled tubing and finally by a pulling unit, as appropriate. P&A execution could be achieved without a rig in a majority of cases, including most offshore wells, with the need to use a rig only in special circumstances or phases of execution. It is important to note that the barrier placement and safety of rigless P&A execution will not be compromised, as compared to the rig-based P&As. Additional cost savings could be achieved by further optimizing P&A design at the well design stage, ensuring that there are no built-in limiters that would prevent rigless P&A execution at the end of well life. Several case studies from ExxonMobil's global offshore experience demonstrate the feasibility and effectiveness of rigless P&A operations, with significant cost savings compared to rig-based P&As. It has been evident that rigless P&A choice is applicable to the variety of ExxonMobil's P&A projects of different complexities, with the same or superior quality of abandonment and safety record.
{"title":"Enabling Safe and Efficient Well Plug & Abandonments Through Use of Rigless Technologies","authors":"Oleksandr Spuskanyuk, David C. Haeberle, B. M. Baumert, B. King, Benjamin T. Hillier","doi":"10.2118/207456-ms","DOIUrl":"https://doi.org/10.2118/207456-ms","url":null,"abstract":"\u0000 The growing number of upcoming well abandonments has become an important driver to seek efficiencies in optimizing abandonment costs while establishing long term well integrity and complying with local regulatory requirements. With an increasing global inventory of Plug and Abandonment (P&A) candidates, Exxonmobil has been driven to look for the most reliable, safe, and cost-efficient P&A technologies. ExxonMobil's P&A guidelines are consistent with and often more stringent than the local regulatory requirements but are also achievable, at least in part, with rigless technologies, leading to a more cost-efficient approach while ensuring well integrity. The objective of this paper is to demonstrate the success of rigless abandonments and their benefits compared to rig-based solutions.\u0000 When developing a well abandonment plan, it is essential to consider a number of factors. These include local regulations, identification of zones to be isolated and suitable caprocks, and recognition of constraints including well history, conditions and uncertainties. Teams should begin with low cost operations without a rig if possible, estimate costs and effectiveness to achieve the barrier requirements, and evaluate batch operation opportunities for multi-well programs. ExxonMobil case studies are shown to help describe in detail how to make decisions about applicability of rigless abandonment options and how to properly execute such abandonments to achieve compliance with the barrier requirements.\u0000 It has been demonstrated that significant cost savings can be achieved by staging the abandonment program in a way that lower cost technologies are utilized during the early stages of well abandonment, starting with wireline where possible, followed by coiled tubing and finally by a pulling unit, as appropriate. P&A execution could be achieved without a rig in a majority of cases, including most offshore wells, with the need to use a rig only in special circumstances or phases of execution. It is important to note that the barrier placement and safety of rigless P&A execution will not be compromised, as compared to the rig-based P&As. Additional cost savings could be achieved by further optimizing P&A design at the well design stage, ensuring that there are no built-in limiters that would prevent rigless P&A execution at the end of well life.\u0000 Several case studies from ExxonMobil's global offshore experience demonstrate the feasibility and effectiveness of rigless P&A operations, with significant cost savings compared to rig-based P&As. It has been evident that rigless P&A choice is applicable to the variety of ExxonMobil's P&A projects of different complexities, with the same or superior quality of abandonment and safety record.","PeriodicalId":11069,"journal":{"name":"Day 2 Tue, November 16, 2021","volume":"16 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78356927","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}
Accurate permeability estimation in tight carbonates is a key reservoir characterization challenge, more pronounced with heterogeneous pore structures. Experiments on large volumes of core samples are required to precisely characterize permeability in such reservoirs which means investment of large amounts of time and capital. Therefore, it is imperative that an integrated model exists that can predict field-wide permeability for un-cored sections to optimize reservoir strategies. Various studies exist with a scope to address this challenge, however, most of them lack universality in application or do not consider important carbonate geometrical features. Accordingly, this work presents a novel correlation to determine permeability of tight carbonates as a function of carbonate pore geometry utilizing a combination of machine learning and optimization algorithms. Primarily, a Deep Learning Neural Network (NN) is constructed and further optimized to produce a data-driven permeability predictor. Customization of the model to tight-heterogenous pore-scale features is accomplished by considering key geometrical carbonate topologies, porosity, formation resistivity, pore cementation representation, characteristic pore throat diameter, pore diameter, and grain diameter. Multiple realizations are conducted spanning from a perceptron-based model to a multi-layered neural net with varying degrees of activation and transfer functions. Next, a physical equation is derived from the optimized model to provide a stand-alone equation for permeability estimation. Validation of the proposed model is conducted by graphical and statistical error analysis of model testing on unseen dataset. A major outcome of this study is the development of a physical mathematical equation which can be used without diving into the intricacy of artificial intelligence algorithms. To evaluate performance of the new correlation, an error metric comprising of average absolute percentage error (AAPE), root mean squared error (RMSE), and correlation coefficient (CC) was used. The proposed correlation performs with low error values and gives CC more than 0.95. A possible reason for this outcome is that the machine learning algorithms can construct relationship between various non-linear inputs (for e.g., carbonate heterogeneity) and output (permeability) parameters through its inbuilt complex interaction of transfer and activation function methodologies.
{"title":"Integrating Pore Geometrical Characteristics for Permeability Prediction of Tight Carbonates Utilizing Artificial Intelligence","authors":"Mohammad Rasheed Khan, S. Kalam, Asiya Abbasi","doi":"10.2118/208005-ms","DOIUrl":"https://doi.org/10.2118/208005-ms","url":null,"abstract":"\u0000 Accurate permeability estimation in tight carbonates is a key reservoir characterization challenge, more pronounced with heterogeneous pore structures. Experiments on large volumes of core samples are required to precisely characterize permeability in such reservoirs which means investment of large amounts of time and capital. Therefore, it is imperative that an integrated model exists that can predict field-wide permeability for un-cored sections to optimize reservoir strategies. Various studies exist with a scope to address this challenge, however, most of them lack universality in application or do not consider important carbonate geometrical features. Accordingly, this work presents a novel correlation to determine permeability of tight carbonates as a function of carbonate pore geometry utilizing a combination of machine learning and optimization algorithms.\u0000 Primarily, a Deep Learning Neural Network (NN) is constructed and further optimized to produce a data-driven permeability predictor. Customization of the model to tight-heterogenous pore-scale features is accomplished by considering key geometrical carbonate topologies, porosity, formation resistivity, pore cementation representation, characteristic pore throat diameter, pore diameter, and grain diameter. Multiple realizations are conducted spanning from a perceptron-based model to a multi-layered neural net with varying degrees of activation and transfer functions. Next, a physical equation is derived from the optimized model to provide a stand-alone equation for permeability estimation. Validation of the proposed model is conducted by graphical and statistical error analysis of model testing on unseen dataset.\u0000 A major outcome of this study is the development of a physical mathematical equation which can be used without diving into the intricacy of artificial intelligence algorithms. To evaluate performance of the new correlation, an error metric comprising of average absolute percentage error (AAPE), root mean squared error (RMSE), and correlation coefficient (CC) was used. The proposed correlation performs with low error values and gives CC more than 0.95. A possible reason for this outcome is that the machine learning algorithms can construct relationship between various non-linear inputs (for e.g., carbonate heterogeneity) and output (permeability) parameters through its inbuilt complex interaction of transfer and activation function methodologies.","PeriodicalId":11069,"journal":{"name":"Day 2 Tue, November 16, 2021","volume":"51 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82256741","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}
K. Tsusaka, Tatsuya Fuji, M. Toma, K. Fukuda, M. Shaver, D. P. Yudhia, Hiroyasu Ogasawara, S. A. Al Ali, T. Toki, Erwan Couzigou, H. Matsubuchi
The 3,000 ft long lateral holes drilled through water-injected area in the carbonate reservoir in the offshore Abu Dhabi have been forced to implement hard backreaming. The abnormal extra operational time has been taken due to poor performance in the operation to pull out a bottomhole assembly after drilling to the total depth. The study aims to analyze root-causes of the hard backreaming through the carbonate reservoir in the studied field. The speed of tripping-out was analyzed every stand of drill pipe by using time domain data of movement of traveling block. The correlations between the speed of tripping-out and rock characteristics such as porosity and constituent minerals in rocks were investigated. Hole shape was analyzed in the representative intervals of low trip-out speed using 16-sector caliper derived from azimuthal density logging. Stress concentration around the borehole wall was also analyzed using geomechanical model. The investigation revealed that hole shrinkage due to plastic deformation of the borehole wall was the most possible root-cause of the hard backreaming in the carbonate reservoir. Namely, BHA had to ream up deformed borehole wall in tripping-out. From the viewpoint of rock characteristics, the speed of tripping-out was found to be lower in the specific geologic layers with higher content of dolomite. This is because dolomite rocks cause larger resistance in reaming it in tripping-out since the strength of dolomite rocks is larger than that of limestone. Based on our findings, use of reamers on bit is found to be the better solution to improve the tripping-out performance in the problematic geologic layers instead of conventional operational attempts such as spotting of acid and use of high viscous fluids in hole cleaning. In addition, optimization of the design and position of reamers and stabilizers is essential to succeed in the future 10,000 ft long extended-reach wells in the studied oil field.
{"title":"Hard Backreaming Due to Hole Shrinkage Through Carbonate Reservoir in Offshore Abu Dhabi","authors":"K. Tsusaka, Tatsuya Fuji, M. Toma, K. Fukuda, M. Shaver, D. P. Yudhia, Hiroyasu Ogasawara, S. A. Al Ali, T. Toki, Erwan Couzigou, H. Matsubuchi","doi":"10.2118/207252-ms","DOIUrl":"https://doi.org/10.2118/207252-ms","url":null,"abstract":"\u0000 The 3,000 ft long lateral holes drilled through water-injected area in the carbonate reservoir in the offshore Abu Dhabi have been forced to implement hard backreaming. The abnormal extra operational time has been taken due to poor performance in the operation to pull out a bottomhole assembly after drilling to the total depth. The study aims to analyze root-causes of the hard backreaming through the carbonate reservoir in the studied field. The speed of tripping-out was analyzed every stand of drill pipe by using time domain data of movement of traveling block. The correlations between the speed of tripping-out and rock characteristics such as porosity and constituent minerals in rocks were investigated. Hole shape was analyzed in the representative intervals of low trip-out speed using 16-sector caliper derived from azimuthal density logging. Stress concentration around the borehole wall was also analyzed using geomechanical model. The investigation revealed that hole shrinkage due to plastic deformation of the borehole wall was the most possible root-cause of the hard backreaming in the carbonate reservoir. Namely, BHA had to ream up deformed borehole wall in tripping-out. From the viewpoint of rock characteristics, the speed of tripping-out was found to be lower in the specific geologic layers with higher content of dolomite. This is because dolomite rocks cause larger resistance in reaming it in tripping-out since the strength of dolomite rocks is larger than that of limestone. Based on our findings, use of reamers on bit is found to be the better solution to improve the tripping-out performance in the problematic geologic layers instead of conventional operational attempts such as spotting of acid and use of high viscous fluids in hole cleaning. In addition, optimization of the design and position of reamers and stabilizers is essential to succeed in the future 10,000 ft long extended-reach wells in the studied oil field.","PeriodicalId":11069,"journal":{"name":"Day 2 Tue, November 16, 2021","volume":"5 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"76405139","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}
Aurelio Marcano Avila, Abimbola Raji, Renny Ottolina, Jose Jimenez
In the UAE, an Operator needed to perform a completion change out in a gas well, where the existing completion has been installed for over 30 years. Logging operations had revealed several leaks point in the production tubing due to corrosion. To rectify the situation, a Hydraulic Workover (HWO) Unit was proposed integrating a punch ram in the Blowout Preventer (BOP) Configuration to manage the bleed off of potential pressure trapped between the isolated sections of the completion at surface. This document describes how the highly corroded completion tubing with eleven retrievable plugs set in a live gas well was recovered. The HWO Unit was modified so that one of the cavities in the BOP stack was dressed with customized punch rams for five inch pipe, with the objective of allowing control of any potential leaks due to plug failure. The pressure relief operation could then be completed by means of punching the tubing in the controlled environment that a Stripping BOP Stack provides. This paper compiles the details of the BOP configuration and operating procedures to recover the completion by stripping out of the well and operating the punch rams with the snubbing unit. This includes the pre-job preparation required for a successful operation and the overall design with where to locate the collars and plugs for an accurate punch, and how to confirm that the plugs are holding the pressure to continue retrieving the next completion section. In the end, a safe operation was completed with zero incidents or down time allowing the intervention to continue to the next stage of recompleting the well and putting it back to production. The customer was able to get the well back to production with an alternative solution to what was initially considered, representing a significant cost and time saving.
{"title":"Case History: Hydraulic Workover Unit Utilized to Recover Highly Corroded 30-Year Old Completion from a Live Gas Well in the United Arab Emirates","authors":"Aurelio Marcano Avila, Abimbola Raji, Renny Ottolina, Jose Jimenez","doi":"10.2118/207882-ms","DOIUrl":"https://doi.org/10.2118/207882-ms","url":null,"abstract":"\u0000 In the UAE, an Operator needed to perform a completion change out in a gas well, where the existing completion has been installed for over 30 years. Logging operations had revealed several leaks point in the production tubing due to corrosion. To rectify the situation, a Hydraulic Workover (HWO) Unit was proposed integrating a punch ram in the Blowout Preventer (BOP) Configuration to manage the bleed off of potential pressure trapped between the isolated sections of the completion at surface.\u0000 This document describes how the highly corroded completion tubing with eleven retrievable plugs set in a live gas well was recovered.\u0000 The HWO Unit was modified so that one of the cavities in the BOP stack was dressed with customized punch rams for five inch pipe, with the objective of allowing control of any potential leaks due to plug failure. The pressure relief operation could then be completed by means of punching the tubing in the controlled environment that a Stripping BOP Stack provides.\u0000 This paper compiles the details of the BOP configuration and operating procedures to recover the completion by stripping out of the well and operating the punch rams with the snubbing unit. This includes the pre-job preparation required for a successful operation and the overall design with where to locate the collars and plugs for an accurate punch, and how to confirm that the plugs are holding the pressure to continue retrieving the next completion section.\u0000 In the end, a safe operation was completed with zero incidents or down time allowing the intervention to continue to the next stage of recompleting the well and putting it back to production.\u0000 The customer was able to get the well back to production with an alternative solution to what was initially considered, representing a significant cost and time saving.","PeriodicalId":11069,"journal":{"name":"Day 2 Tue, November 16, 2021","volume":"18 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87512559","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}
Sharath Chandran Bodheswaran, Muhammed Razeeem Puthiyaveedu, Cibu K. Varghese, F. Kamal
Some of the platforms installed in offshore fields in India have exceeded their design lifespan but continues to operate. For these platforms to continue operating safely and successfully, major revamp is required. As the wellheads are in operation beyond their intended lifespan and requires revamping due to their heavily corroded state, decommissioning, removal and replacement of existing offshore structures presents technical and economic challenges to Operating Company's and Contractors, alike. Due to the age of these platforms, availability of technical/engineering data is minimal and often needs to be developed from scratch. The focus of this paper is on Weight Engineering and challenges in developing such data for a platform without as built information. The paper also touches on the different stages of executing the project including demolition engineering strategies applied, use of different installation aids to facilitate demolition etc during successful execution of Brownfield works in Mumbai High field by National Petroleum Construction Company (NPCC).
{"title":"Demolition of Offshore Wellhead Topsides - Weight Engineering Challenges","authors":"Sharath Chandran Bodheswaran, Muhammed Razeeem Puthiyaveedu, Cibu K. Varghese, F. Kamal","doi":"10.2118/207683-ms","DOIUrl":"https://doi.org/10.2118/207683-ms","url":null,"abstract":"\u0000 Some of the platforms installed in offshore fields in India have exceeded their design lifespan but continues to operate. For these platforms to continue operating safely and successfully, major revamp is required. As the wellheads are in operation beyond their intended lifespan and requires revamping due to their heavily corroded state, decommissioning, removal and replacement of existing offshore structures presents technical and economic challenges to Operating Company's and Contractors, alike. Due to the age of these platforms, availability of technical/engineering data is minimal and often needs to be developed from scratch.\u0000 The focus of this paper is on Weight Engineering and challenges in developing such data for a platform without as built information. The paper also touches on the different stages of executing the project including demolition engineering strategies applied, use of different installation aids to facilitate demolition etc during successful execution of Brownfield works in Mumbai High field by National Petroleum Construction Company (NPCC).","PeriodicalId":11069,"journal":{"name":"Day 2 Tue, November 16, 2021","volume":"14 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82763904","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}
Amena Alharthi, Pierre Van Laer, Trevor Brooks, Pierre-Olivier Goiran, M. Baig, Nabila Lazreq, Hamza Abdelhalim, Hassan Al Marzooqi, Marco Coscia
The development of unconventional target in the Shilaif formation is in line with the Unconventional objective towards adding to ADNOC reserves. For future optimization of development plans, it is of utmost importance to understand and test and therefore prove the productivity of the future Unconventional Horizontal Oil wells. The Shilaif formation was deposited in a deeper water intrashelf basin with thicknesses varying from 600 to 800 ft from deep basin to slope respectively. The formation is subdivided into 3 main composite sequences each with separate source and clean tight carbonates. The well under consideration (Well A-V for the vertical pilot and Well A-H for the horizontal wellbore) was drilled on purpose in a deep synclinal area to access the best possible oil generation and maturity in these shale Oil plays. Due to the stacked nature of these thick high-quality reservoirs, a pilot well is drilled to perform reservoir characterization and test hydrocarbon type and potential from each bench. Fracturing and testing are performed in each reservoir layer for the primary purpose to evaluate and collect key fracturing and reservoir parameter required to calibrate petrophysical and geomechanical model, landing target optimization and ultimately for the design of the development plan of this stacked play. Frac height, reservoir fluid composition and deliverability, pore pressure are among key data collected. The landing point selected based on the comprehensive unconventional core analysis integrated with petrophysical and geomechanical outcomes using post vertical frac and test results. Well A-H was drilled as a sidetrack from the pilot hole Well A-V. This lateral section was logged with LWD Triple Combo while Resistivity Image was acquired on WL. Based on the logging data the well stayed in the target Layer / formation, cutting analysis data for XRD and TOC was integrated with the petrophysical results in A-H well. Production test results from subject were among the highest rate seen during exploration and appraisal of this unconventional oil plays and compete with the current commercial top tier analog unconventional oil plays. Achieving those results in such early exploration phases is huge milestone for ADNOC unconventional exploration journey in UAE and sign of promising future development.
{"title":"Integration Success Story in Shilaif Shale Oil from Vertical Pilot to Horizontal","authors":"Amena Alharthi, Pierre Van Laer, Trevor Brooks, Pierre-Olivier Goiran, M. Baig, Nabila Lazreq, Hamza Abdelhalim, Hassan Al Marzooqi, Marco Coscia","doi":"10.2118/208135-ms","DOIUrl":"https://doi.org/10.2118/208135-ms","url":null,"abstract":"\u0000 The development of unconventional target in the Shilaif formation is in line with the Unconventional objective towards adding to ADNOC reserves. For future optimization of development plans, it is of utmost importance to understand and test and therefore prove the productivity of the future Unconventional Horizontal Oil wells.\u0000 The Shilaif formation was deposited in a deeper water intrashelf basin with thicknesses varying from 600 to 800 ft from deep basin to slope respectively. The formation is subdivided into 3 main composite sequences each with separate source and clean tight carbonates. The well under consideration (Well A-V for the vertical pilot and Well A-H for the horizontal wellbore) was drilled on purpose in a deep synclinal area to access the best possible oil generation and maturity in these shale Oil plays.\u0000 Due to the stacked nature of these thick high-quality reservoirs, a pilot well is drilled to perform reservoir characterization and test hydrocarbon type and potential from each bench. Fracturing and testing are performed in each reservoir layer for the primary purpose to evaluate and collect key fracturing and reservoir parameter required to calibrate petrophysical and geomechanical model, landing target optimization and ultimately for the design of the development plan of this stacked play. Frac height, reservoir fluid composition and deliverability, pore pressure are among key data collected. The landing point selected based on the comprehensive unconventional core analysis integrated with petrophysical and geomechanical outcomes using post vertical frac and test results. Well A-H was drilled as a sidetrack from the pilot hole Well A-V. This lateral section was logged with LWD Triple Combo while Resistivity Image was acquired on WL. Based on the logging data the well stayed in the target Layer / formation, cutting analysis data for XRD and TOC was integrated with the petrophysical results in A-H well.\u0000 Production test results from subject were among the highest rate seen during exploration and appraisal of this unconventional oil plays and compete with the current commercial top tier analog unconventional oil plays. Achieving those results in such early exploration phases is huge milestone for ADNOC unconventional exploration journey in UAE and sign of promising future development.","PeriodicalId":11069,"journal":{"name":"Day 2 Tue, November 16, 2021","volume":"16 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86682840","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 technology of simultaneous, separate operation is a mandatory condition within the framework of Russian legislation for the production of oil and gas from multilayer reservoirs, which implies a share of a load of several pumps on different reservoirs. To reduce high additional equipment costs and metal consumption of the well, an assembly of two ESPs with one engine was developed. More than forty Russian wells were supplied with double ESP system motors. The project implementation enabled using separate simultaneous operations with more wells and developing reservoirs more accurately. It became possible to develop each reservoir by employing separated data from gauges connected to two reservoirs. The use of two side motors allows using such complicated technologies as separate simultaneous operations for even small and previously not economically achievable reservoirs. According to well inflow calculations, using the most suitable pump, the correct amount of liquid from each reservoir has been produced during these operations.
{"title":"Usage of Two-Sided Motors as a Part of the Simultaneous Separate Operation Technology","authors":"A. Uvarov","doi":"10.2118/207322-ms","DOIUrl":"https://doi.org/10.2118/207322-ms","url":null,"abstract":"\u0000 The technology of simultaneous, separate operation is a mandatory condition within the framework of Russian legislation for the production of oil and gas from multilayer reservoirs, which implies a share of a load of several pumps on different reservoirs. To reduce high additional equipment costs and metal consumption of the well, an assembly of two ESPs with one engine was developed. More than forty Russian wells were supplied with double ESP system motors. The project implementation enabled using separate simultaneous operations with more wells and developing reservoirs more accurately. It became possible to develop each reservoir by employing separated data from gauges connected to two reservoirs. The use of two side motors allows using such complicated technologies as separate simultaneous operations for even small and previously not economically achievable reservoirs. According to well inflow calculations, using the most suitable pump, the correct amount of liquid from each reservoir has been produced during these operations.","PeriodicalId":11069,"journal":{"name":"Day 2 Tue, November 16, 2021","volume":"54 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89008798","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}
Z. Ali, A. Anuar, Nicolas Grippo, Nurshahrily Emalin Ramli, Najmi Rahim
Aging facilities and increasing complexity in operations (e.g., increasing water cut, slugging, sand or wax production) continue to widen the gap between actual production and the full potential of the field. To enable production optimization scenarios within an integrated system comprises of reservoirs, wells and surface facilities, the application of an integrated network modelling has been applied. The highlight of this paper is the synergy of Integrated Production Network Modelling (IPNM) utilizing Steady State Simulator (PROSPER-GAP) and the Transient Simulator (OLGA) tools to identify potential quick gains through gaslift optimization as well as mid and long-term system optimization alternatives. The synergy enables significant reduction in transient simulation time and reduced challenges in OLGA well matching, especially in selecting accurate modelling parameters e.g., well inflow performance (validated well (string) production data, reservoir pressure, temperature and fluid properties and the Absolute Open Flow (AOF) of each well). The paper showcased the successful production gain achieved as well as the workflows and methodologies applied for both Steady State Integrated Production Modelling (IPM Steady State) and Integrated Transient Network Modelling (IPM Transient) as tools for production enhancement. Even though IPM Steady State shows promising results in term of field optimization potential, to increase accuracy and reduce uncertainties, IPM Transient is recommended to be performed to mimic the actual transient phenomena happening in the well to facilities
{"title":"Unifying of Steady State and Transient Simulations Methodologies for Increasing Oil Production of Integrated Network of Wells, Pipeline and Topside Processing Equipment","authors":"Z. Ali, A. Anuar, Nicolas Grippo, Nurshahrily Emalin Ramli, Najmi Rahim","doi":"10.2118/207470-ms","DOIUrl":"https://doi.org/10.2118/207470-ms","url":null,"abstract":"\u0000 Aging facilities and increasing complexity in operations (e.g., increasing water cut, slugging, sand or wax production) continue to widen the gap between actual production and the full potential of the field. To enable production optimization scenarios within an integrated system comprises of reservoirs, wells and surface facilities, the application of an integrated network modelling has been applied. The highlight of this paper is the synergy of Integrated Production Network Modelling (IPNM) utilizing Steady State Simulator (PROSPER-GAP) and the Transient Simulator (OLGA) tools to identify potential quick gains through gaslift optimization as well as mid and long-term system optimization alternatives. The synergy enables significant reduction in transient simulation time and reduced challenges in OLGA well matching, especially in selecting accurate modelling parameters e.g., well inflow performance (validated well (string) production data, reservoir pressure, temperature and fluid properties and the Absolute Open Flow (AOF) of each well). The paper showcased the successful production gain achieved as well as the workflows and methodologies applied for both Steady State Integrated Production Modelling (IPM Steady State) and Integrated Transient Network Modelling (IPM Transient) as tools for production enhancement. Even though IPM Steady State shows promising results in term of field optimization potential, to increase accuracy and reduce uncertainties, IPM Transient is recommended to be performed to mimic the actual transient phenomena happening in the well to facilities","PeriodicalId":11069,"journal":{"name":"Day 2 Tue, November 16, 2021","volume":"268 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89199179","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. Kucs, Georg Ripperger, M. Doschek, Natascha Sonnleitner, Waldemar Szemat-Vielma, Nadjib Mouzali, Sonali Roy, Becky Lepp
As part of the industry 4.0 revolution, digital technologies are forever changing the way we do things. native cloud applications are able to adapt to specific processes and requirements, particularly those related to well construction planning driven by an automated collaborative solution. The operator of the future will use its engineers mainly for engineering analysis and social interactions, while the system will take over tasks such as orchestration, data mining, and experience management. Based on the definition of a new way of working and the application of new workflows, a thorough trial process was required to evaluate the solution usability and to define the minimum viable product requirements to be developed within a strategic partnership prior to rolling out the technology. The requirement was to enable globally dispersed teams, even across company borders, collaborating through automatically orchestrated processes, supported by knowledge and experience management systems in the background, to deliver a digital drilling program and ultimately accelerate the field development program. The operator decided to prove the concept through a series of pilots within a well-educated well planning team. Major assumptions to the business case were tested while planning actual drilling operations with the purpose to de-risk the value proposition. All different tested elements are captured by the users and the gaps to the final solution are ranked for joint development. The back-end interoperability of the solution supports a fully connected model, where data from subsurface systems can directly feed the well construction planning platform. The automated updates in the end-to-end workflow would ultimately simplify the way drilling engineers work, but also upscale the nature of their work by including many new elements as part of the routing analysis. Supported by the cloud computer power and flexibility, remote working is seamlessly enabled to removing the classic silos and digitally promote the collaboration. Standardization across the whole organization by corporate managed settings reduces iterative control processes. Furthermore, management of change is a key aspect to consider alongside the technical elements. The result of the extended trial confirmed that achieving the minimum viable product requirements of the operators was well within reach and confirmed the operator's value case to a large extent. In this paper we will describe the extended trial process, objectives, and associated workflows, in addition to the collaborative team nominated by both partners. The scope was user centric to assist with competency development and technology adoption. Parallel to confirming the minimum viable product, the extended pilot resulted in a prioritized list of co-developments leading to the full implementation of the operator's vision of a fully integrated well planning workflow.
{"title":"The Journey for Digital Well Delivery Technology Adoption: The How and Why","authors":"R. Kucs, Georg Ripperger, M. Doschek, Natascha Sonnleitner, Waldemar Szemat-Vielma, Nadjib Mouzali, Sonali Roy, Becky Lepp","doi":"10.2118/208143-ms","DOIUrl":"https://doi.org/10.2118/208143-ms","url":null,"abstract":"\u0000 As part of the industry 4.0 revolution, digital technologies are forever changing the way we do things. native cloud applications are able to adapt to specific processes and requirements, particularly those related to well construction planning driven by an automated collaborative solution. The operator of the future will use its engineers mainly for engineering analysis and social interactions, while the system will take over tasks such as orchestration, data mining, and experience management.\u0000 Based on the definition of a new way of working and the application of new workflows, a thorough trial process was required to evaluate the solution usability and to define the minimum viable product requirements to be developed within a strategic partnership prior to rolling out the technology. The requirement was to enable globally dispersed teams, even across company borders, collaborating through automatically orchestrated processes, supported by knowledge and experience management systems in the background, to deliver a digital drilling program and ultimately accelerate the field development program.\u0000 The operator decided to prove the concept through a series of pilots within a well-educated well planning team. Major assumptions to the business case were tested while planning actual drilling operations with the purpose to de-risk the value proposition. All different tested elements are captured by the users and the gaps to the final solution are ranked for joint development. The back-end interoperability of the solution supports a fully connected model, where data from subsurface systems can directly feed the well construction planning platform. The automated updates in the end-to-end workflow would ultimately simplify the way drilling engineers work, but also upscale the nature of their work by including many new elements as part of the routing analysis.\u0000 Supported by the cloud computer power and flexibility, remote working is seamlessly enabled to removing the classic silos and digitally promote the collaboration. Standardization across the whole organization by corporate managed settings reduces iterative control processes. Furthermore, management of change is a key aspect to consider alongside the technical elements.\u0000 The result of the extended trial confirmed that achieving the minimum viable product requirements of the operators was well within reach and confirmed the operator's value case to a large extent.\u0000 In this paper we will describe the extended trial process, objectives, and associated workflows, in addition to the collaborative team nominated by both partners. The scope was user centric to assist with competency development and technology adoption. Parallel to confirming the minimum viable product, the extended pilot resulted in a prioritized list of co-developments leading to the full implementation of the operator's vision of a fully integrated well planning workflow.","PeriodicalId":11069,"journal":{"name":"Day 2 Tue, November 16, 2021","volume":"16 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87328078","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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