Waste heat is the by-product of industrial energy usage. Approximately one-third of the energy consumed by the oil and gas industry is discharged as thermal losses into the environment or via cooling systems. And the main reasons for waste heat discharge are process inefficiencies and technology limitations in the conversion of thermal to mechanical energy. Nevertheless, because the oil and gas industry demands large amounts of thermal, electrical and mechanical energy, a huge amount of waste heat is subsequently available. Organic Rankine Cycle (ORC) technology has made economical utilization of lower temperature heat sources possible. ORC's efficiency percentage for waste heat recovery varies between single digit to the mid-20s, depending on the waste heat source temperature and the cooling medium. Even the recovery of a few MW of thermal energy with a single-digit cycle efficiency for a plant consuming an average of 100 MW (134 102 hp) thermal energy is a considerable efficiency improvement. Studies by the Oakridge National Laboratory (USA) show that 75% of waste heat comes with sufficiently high temperatures (> 150°C, or > 302°F). This report projects a 2-5-year return of investment for ORC-based waste heat to power plant systems, which represents an attractive financial payback. The recovery of waste heat from oil and gas operations remains mostly underutilized. Furthermore, economically feasible power generation from waste heat has been limited to medium- to high- temperature waste heat resources. This paper will explore technical solutions to these challenges facing the oil and gas industry In this paper, three cases of waste heat from a gas turbine's exhaust flue gas are presented. The turbines have nominal output of 7.5, 15, and 25 MW (10 057, 20 115 and 33 525 hp) electrical power at an ambient air temperature of 15°C (59°F). A heat recovery unit (HRU) can recover thermal energy from exhaust flue gas. The heat recovery loop (HRL) could exchange thermal power with an ORC system, which in turn has the potential to produce electrical power. It will be demonstrated that this configuration has a HRL/ORC cycle efficiency of approximately 10% when the ambient air temperature is about 30°C (86°F).
{"title":"Waste Heat to Power System in Oil and Gas Industry Improves Plant Power Efficiency","authors":"R. Agahi","doi":"10.2118/197421-ms","DOIUrl":"https://doi.org/10.2118/197421-ms","url":null,"abstract":"\u0000 Waste heat is the by-product of industrial energy usage. Approximately one-third of the energy consumed by the oil and gas industry is discharged as thermal losses into the environment or via cooling systems. And the main reasons for waste heat discharge are process inefficiencies and technology limitations in the conversion of thermal to mechanical energy. Nevertheless, because the oil and gas industry demands large amounts of thermal, electrical and mechanical energy, a huge amount of waste heat is subsequently available.\u0000 Organic Rankine Cycle (ORC) technology has made economical utilization of lower temperature heat sources possible. ORC's efficiency percentage for waste heat recovery varies between single digit to the mid-20s, depending on the waste heat source temperature and the cooling medium. Even the recovery of a few MW of thermal energy with a single-digit cycle efficiency for a plant consuming an average of 100 MW (134 102 hp) thermal energy is a considerable efficiency improvement. Studies by the Oakridge National Laboratory (USA) show that 75% of waste heat comes with sufficiently high temperatures (> 150°C, or > 302°F). This report projects a 2-5-year return of investment for ORC-based waste heat to power plant systems, which represents an attractive financial payback.\u0000 The recovery of waste heat from oil and gas operations remains mostly underutilized. Furthermore, economically feasible power generation from waste heat has been limited to medium- to high- temperature waste heat resources. This paper will explore technical solutions to these challenges facing the oil and gas industry\u0000 In this paper, three cases of waste heat from a gas turbine's exhaust flue gas are presented. The turbines have nominal output of 7.5, 15, and 25 MW (10 057, 20 115 and 33 525 hp) electrical power at an ambient air temperature of 15°C (59°F). A heat recovery unit (HRU) can recover thermal energy from exhaust flue gas. The heat recovery loop (HRL) could exchange thermal power with an ORC system, which in turn has the potential to produce electrical power. It will be demonstrated that this configuration has a HRL/ORC cycle efficiency of approximately 10% when the ambient air temperature is about 30°C (86°F).","PeriodicalId":11091,"journal":{"name":"Day 3 Wed, November 13, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"85094577","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 main seek for the whole oil industry is to find a way to prolong the economic life of the existing mature fields, as a result of the difficulty of finding new big assets. The waterflooding efficiency can be dramatically enhanced by the application of new technologies with the target of sweeping higher amounts of unswept oil. IOR/EOR methods are investigated to improve the oil production from the giant Belayim Onshore mature field located in Gulf of Suez, Egypt. The field was previously developed by using sea water peripheral injection. The existing water injection strategy is found not be the optimum strategy to increase the sweep efficiency and the recovery factor as a result of the huge lateral heterogeneity and different mobility ratio. This paper describes the work done to improve the efficiency of water injection by the application of different IOR/EOR technologies specifically Low Salinity water. First, Coreflooding experiments on porous medium have been performed in the tertiary mood to detect the effect of IOR compared to the sea water injection. It was found that LS can increase oil recovery nearly to 7% more. After finishing the lab phase, simulation runs have been performed to predict the enhancement on field scale. The coreflooding experiments have been simulated using a wettability alteration model to determine the LS parameters and the new relative permeability curves. These parameter were the input into a sector model of fine gridding. The model was history matched using the wells production and injection data for the LS pilot area under study. Different forecast scenarios have been run and the incremental increase in oil recovery was reported against the current water injection scheme A number of Single Well Tracer Tests have been performed to detect the effect of Low Salinity water flooding on well scale. The test was designed to incorporate a number of injection, production and shut in cycles in the pilot well with the aim determining the residual oil saturation with the current scheme of sea water injection and after switching into low salinity water. It was found that Low salinity water has achieved very promising results that produced a remarkable reduction in Sor at the range of (5-11) saturation units. In order to estimate the full-field effect of the LS waterflooding as a promising EOR method, all the major aspects have been taken into account including the expected reduction in residual oil saturation, permeability alteration as a result of possible fine migration or clay swell and the possible change in the sweeping efficiency. Finally, all the produced results from the experimental and simulation work have been incorporated into an economic study to determine the feasibility of constructing a desalination plant for the full-field application phase
{"title":"A Comprehensive Scheme for Application of Low Salinity Waterflooding Technique in Mature Fields","authors":"H. Elmasry, Mohamed Anwar, E. Moussa","doi":"10.2118/197398-ms","DOIUrl":"https://doi.org/10.2118/197398-ms","url":null,"abstract":"\u0000 The main seek for the whole oil industry is to find a way to prolong the economic life of the existing mature fields, as a result of the difficulty of finding new big assets. The waterflooding efficiency can be dramatically enhanced by the application of new technologies with the target of sweeping higher amounts of unswept oil. IOR/EOR methods are investigated to improve the oil production from the giant Belayim Onshore mature field located in Gulf of Suez, Egypt. The field was previously developed by using sea water peripheral injection. The existing water injection strategy is found not be the optimum strategy to increase the sweep efficiency and the recovery factor as a result of the huge lateral heterogeneity and different mobility ratio.\u0000 This paper describes the work done to improve the efficiency of water injection by the application of different IOR/EOR technologies specifically Low Salinity water. First, Coreflooding experiments on porous medium have been performed in the tertiary mood to detect the effect of IOR compared to the sea water injection. It was found that LS can increase oil recovery nearly to 7% more. After finishing the lab phase, simulation runs have been performed to predict the enhancement on field scale. The coreflooding experiments have been simulated using a wettability alteration model to determine the LS parameters and the new relative permeability curves. These parameter were the input into a sector model of fine gridding. The model was history matched using the wells production and injection data for the LS pilot area under study. Different forecast scenarios have been run and the incremental increase in oil recovery was reported against the current water injection scheme\u0000 A number of Single Well Tracer Tests have been performed to detect the effect of Low Salinity water flooding on well scale. The test was designed to incorporate a number of injection, production and shut in cycles in the pilot well with the aim determining the residual oil saturation with the current scheme of sea water injection and after switching into low salinity water. It was found that Low salinity water has achieved very promising results that produced a remarkable reduction in Sor at the range of (5-11) saturation units.\u0000 In order to estimate the full-field effect of the LS waterflooding as a promising EOR method, all the major aspects have been taken into account including the expected reduction in residual oil saturation, permeability alteration as a result of possible fine migration or clay swell and the possible change in the sweeping efficiency.\u0000 Finally, all the produced results from the experimental and simulation work have been incorporated into an economic study to determine the feasibility of constructing a desalination plant for the full-field application phase","PeriodicalId":11091,"journal":{"name":"Day 3 Wed, November 13, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82155230","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}
In the past, accessing laterals after a multipacker completion system installation in a multilateral well presented significant risks to drilling operations because certain crucial operations, such as acid stimulation, required a rig on location. Recently, a Middle East operator successfully installed an isolated multilateral completion system. The system was deployed in a well located in an onshore field in the Arabian Gulf region. The isolated multilateral system was customized for multilateral wells that require re-entry capability to access the lateral. The system provided a completion window equipped with landing profiles and sealbores that enable deflector settings for lateral access or isolation sleeves for lateral control. Additionally, a unique latch coupling allowed for installation at the optimum azimuth and depth of the system for lateral re-entry operations. Historically, in installations that required access to the lateral, a pilot hole had to be drilled and subsequently plugged and abandoned to avoid running a dual-packer completion, followed by running a single packer as an alternative to enable safe stimulation of the lateral. Using the new multilateral isolation system enabled the first combined observation and producer well with a dual-packer completion string. The well represented a technical milestone for the service company in the development of multiple reservoir fields. Using the isolated multilateral completion system allowed the operator to achieve the following results: Maintain accessibility to the observation bore for future monitoring and producing from the other laterals. Improve surface infrastructure by reducing the number of wells to be drilled. Save on drilling and completion costs with individual observation wells. Achieve accessibility through the completion on either lateral independently. Perform acid stimulation treatments using a rigless unit at any point during the life of the well through a multipacker completion. Risk reduction with drilling rigs because critical operations, such as acid stimulation and well testing, can be satisfactorily performed using a rigless unit instead of a rig on location. The identification of further benefits and lessons learned will be addressed in future work. In conclusion, the Middle East operator had achieved success in the deployment of newly acquired technology for the multilateral/single-bore completion with multipacker systems.
{"title":"A Successful Deployment of Level 4 Multilateral Isolation Completion System","authors":"Nawaf Al Ansari, Baidy Racine","doi":"10.2118/197581-ms","DOIUrl":"https://doi.org/10.2118/197581-ms","url":null,"abstract":"\u0000 In the past, accessing laterals after a multipacker completion system installation in a multilateral well presented significant risks to drilling operations because certain crucial operations, such as acid stimulation, required a rig on location.\u0000 Recently, a Middle East operator successfully installed an isolated multilateral completion system. The system was deployed in a well located in an onshore field in the Arabian Gulf region.\u0000 The isolated multilateral system was customized for multilateral wells that require re-entry capability to access the lateral. The system provided a completion window equipped with landing profiles and sealbores that enable deflector settings for lateral access or isolation sleeves for lateral control. Additionally, a unique latch coupling allowed for installation at the optimum azimuth and depth of the system for lateral re-entry operations.\u0000 Historically, in installations that required access to the lateral, a pilot hole had to be drilled and subsequently plugged and abandoned to avoid running a dual-packer completion, followed by running a single packer as an alternative to enable safe stimulation of the lateral. Using the new multilateral isolation system enabled the first combined observation and producer well with a dual-packer completion string.\u0000 The well represented a technical milestone for the service company in the development of multiple reservoir fields. Using the isolated multilateral completion system allowed the operator to achieve the following results:\u0000 Maintain accessibility to the observation bore for future monitoring and producing from the other laterals. Improve surface infrastructure by reducing the number of wells to be drilled. Save on drilling and completion costs with individual observation wells. Achieve accessibility through the completion on either lateral independently. Perform acid stimulation treatments using a rigless unit at any point during the life of the well through a multipacker completion. Risk reduction with drilling rigs because critical operations, such as acid stimulation and well testing, can be satisfactorily performed using a rigless unit instead of a rig on location.\u0000 The identification of further benefits and lessons learned will be addressed in future work.\u0000 In conclusion, the Middle East operator had achieved success in the deployment of newly acquired technology for the multilateral/single-bore completion with multipacker systems.","PeriodicalId":11091,"journal":{"name":"Day 3 Wed, November 13, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79465080","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}
This paper presents details of the development of the Middle East to India Deepwater Pipeline (MEIDP) providing information on the technical and commercial feasibility of the deepwater gas transportation system, which will reach a record water depth of 3450m, cross two continental slopes, an earthquake subduction zone (the Owen Fracture Zone) and outfall debris of the river Indus fan in 2500m water depth. High pressure trunk lines have proved to be the safest, cheapest way of transporting gas to market for short to medium distances up to 2,500 kilometers, making the proposed SAGE - Middle East to India Deepwater Pipeline the optimal solution for gas delivery to the Indian Subcontinent. Linking Middle East gas fields of Saudi Arabia, UAE and Oman to India across the Arabian Sea for an offshore distance of 1200 kilometers. The MEIDP gas transmission pipeline is designed to transport up to 1.1BCFD gas into the Indian energy markets. The economic and political drivers for such a project are presented together with details of the overall project cost and tariff calculation to allow successful gas utilization by India's gas starved and stranded power stations. The pipeline project history and current design status will be reviewed together with findings of the Marine Reconnaissance survey between Oman and India. The challenges faced by the project from both a design and installation perspective are discussed together with some of the detailed geohazard assessments performed for the pipeline crossing and active fault zone (OFZ) and the Indus Fan. The qualification plan developed with DNVGL is described together with details of the future construction schedule for first Gas. As a project that builds from the Oman-India project of the 1990's; the changes in risk profile in terms of industry and vessel readiness are reviewed, and the readiness of the next generation of installation vessels to install such a pipeline is discussed.
{"title":"MEIDP – India's Transnational Pipeline from the Middle East","authors":"I. Nash, C. Spradbery","doi":"10.2118/197776-ms","DOIUrl":"https://doi.org/10.2118/197776-ms","url":null,"abstract":"\u0000 This paper presents details of the development of the Middle East to India Deepwater Pipeline (MEIDP) providing information on the technical and commercial feasibility of the deepwater gas transportation system, which will reach a record water depth of 3450m, cross two continental slopes, an earthquake subduction zone (the Owen Fracture Zone) and outfall debris of the river Indus fan in 2500m water depth.\u0000 High pressure trunk lines have proved to be the safest, cheapest way of transporting gas to market for short to medium distances up to 2,500 kilometers, making the proposed SAGE - Middle East to India Deepwater Pipeline the optimal solution for gas delivery to the Indian Subcontinent. Linking Middle East gas fields of Saudi Arabia, UAE and Oman to India across the Arabian Sea for an offshore distance of 1200 kilometers. The MEIDP gas transmission pipeline is designed to transport up to 1.1BCFD gas into the Indian energy markets.\u0000 The economic and political drivers for such a project are presented together with details of the overall project cost and tariff calculation to allow successful gas utilization by India's gas starved and stranded power stations. The pipeline project history and current design status will be reviewed together with findings of the Marine Reconnaissance survey between Oman and India. The challenges faced by the project from both a design and installation perspective are discussed together with some of the detailed geohazard assessments performed for the pipeline crossing and active fault zone (OFZ) and the Indus Fan. The qualification plan developed with DNVGL is described together with details of the future construction schedule for first Gas.\u0000 As a project that builds from the Oman-India project of the 1990's; the changes in risk profile in terms of industry and vessel readiness are reviewed, and the readiness of the next generation of installation vessels to install such a pipeline is discussed.","PeriodicalId":11091,"journal":{"name":"Day 3 Wed, November 13, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84696546","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}
Pojana Vimolsubsin, W. Teeratananon, I. Chigbo, T. Lerdsuwankij, P. Millot
This paper presents the successful application of a new-generation slim pulsed neutron logging tool for identification of bypassed oil in the Nong Yao field. The field comprises of different small pools of oil developed with horizontal wells. The wells are drilled with long lateral sections to increase the drainage area in an attempt to increase sweep efficiencies. However, the sweep efficiencies remained uncertain given reservoir heterogeneity and the nature of water encroachment into the wells. Reservoir saturation monitoring through tubing is usually required for an effective reservoir management program in such a mature field, and a cost-effective method for future opportunity identification. The traditional slim pulsed neutron logging (PNL) tools often provided inconclusive results especially when deployed in complex completion conditions. A new-generation slim pulsed neutron logging tool, which provides high-resolution spectroscopy with a much-improved accuracy and precision was investigated and introduced. This tool delivers self-compensated sigma and neutron porosity measurements in a wide range of conditions, including complex completions and with varying amount of gas in the wellbore or annulus. This new PNL tool was run in the Nong Yao field in December 2017 with the objective to prove the remaining oil at the top of a reservoir. The objective was to acquire data in GSH (sigma, fast neutron cross section, Porosity) and IC (spectroscopy) modes in 8-1/2" hole with conventional completion (7" casing + 2-7/8" tubing). Despite challenging borehole fluid conditions, the data acquired confirmed remaining oil in the reservoir and a new well drilled in 2018 targeting this bypassed oil is currently producing with very good oil production. This successful implementation of PNL in 2017 led to the adoption of the tool as a good alternative for confirming bypassed oil in the Nong Yao field. This strategy has been adopted for well target validation and horizontal well placement to support the 2019-2020 infill drilling campaigns. In December 2018, this tool was run again in three selected candidate wells to prove the remaining bypassed oil and oil saturation away from currently producing wells. The results acquired in all three cases showed clear oil/water contact movement and sweep where present, confirming sufficient remaining oil volume to justify the drilling of new infill wells to develop these volumes during the 2019-2020 infill drilling campaigns. The new generation PNL tool provides a low-cost alternative for effective reservoir depletion monitoring. Proper reservoir management, additional opportunity identification, and infill drilling target optimization are all benefits that can accrue from accurately locating bypassed oil. Field development plans can then be further optimized, resulting in increased asset value.
{"title":"An Effective Economic Approach for Confirming Bypassed OilWith the Use of a New Generation Slim Pulsed Neutron Logging Tool – A Field Case from the Gulf of Thailand","authors":"Pojana Vimolsubsin, W. Teeratananon, I. Chigbo, T. Lerdsuwankij, P. Millot","doi":"10.2118/197599-ms","DOIUrl":"https://doi.org/10.2118/197599-ms","url":null,"abstract":"\u0000 This paper presents the successful application of a new-generation slim pulsed neutron logging tool for identification of bypassed oil in the Nong Yao field. The field comprises of different small pools of oil developed with horizontal wells. The wells are drilled with long lateral sections to increase the drainage area in an attempt to increase sweep efficiencies. However, the sweep efficiencies remained uncertain given reservoir heterogeneity and the nature of water encroachment into the wells.\u0000 Reservoir saturation monitoring through tubing is usually required for an effective reservoir management program in such a mature field, and a cost-effective method for future opportunity identification. The traditional slim pulsed neutron logging (PNL) tools often provided inconclusive results especially when deployed in complex completion conditions. A new-generation slim pulsed neutron logging tool, which provides high-resolution spectroscopy with a much-improved accuracy and precision was investigated and introduced. This tool delivers self-compensated sigma and neutron porosity measurements in a wide range of conditions, including complex completions and with varying amount of gas in the wellbore or annulus.\u0000 This new PNL tool was run in the Nong Yao field in December 2017 with the objective to prove the remaining oil at the top of a reservoir. The objective was to acquire data in GSH (sigma, fast neutron cross section, Porosity) and IC (spectroscopy) modes in 8-1/2\" hole with conventional completion (7\" casing + 2-7/8\" tubing). Despite challenging borehole fluid conditions, the data acquired confirmed remaining oil in the reservoir and a new well drilled in 2018 targeting this bypassed oil is currently producing with very good oil production.\u0000 This successful implementation of PNL in 2017 led to the adoption of the tool as a good alternative for confirming bypassed oil in the Nong Yao field. This strategy has been adopted for well target validation and horizontal well placement to support the 2019-2020 infill drilling campaigns.\u0000 In December 2018, this tool was run again in three selected candidate wells to prove the remaining bypassed oil and oil saturation away from currently producing wells. The results acquired in all three cases showed clear oil/water contact movement and sweep where present, confirming sufficient remaining oil volume to justify the drilling of new infill wells to develop these volumes during the 2019-2020 infill drilling campaigns.\u0000 The new generation PNL tool provides a low-cost alternative for effective reservoir depletion monitoring. Proper reservoir management, additional opportunity identification, and infill drilling target optimization are all benefits that can accrue from accurately locating bypassed oil. Field development plans can then be further optimized, resulting in increased asset value.","PeriodicalId":11091,"journal":{"name":"Day 3 Wed, November 13, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"85367356","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}
Y. Pramudyo, M. A. Hosani, Fatimah M. Al Awadhi, R. Masoud, Huda Al Besr, R. Nachiappan, K. A. Hosani, Ahmed Mohamed Al Bairaq, Ammar Faqqas Al Ameri, M. Bertouche, A. Foote, E. Michie, G. Yielding
Throughout the UAE and the wider region, several broadly E-W orientated structural lineaments are observed on seismic within the Cretaceous successions and are described as strike-slip faults. However, in the studied field, these features have not been readily observed in well data. Instead, networks of fractures and deformation features are present in core and borehole images. A study was carried out in an attempt to calibrate well and seismic data and to understand the relationship between the seismically-resolved faults and the fractures observed on core. This study focuses on a dataset from the north-east part of the field, which includes BHI images, cores, full 3D CT scans and conventional logs in four penetrations, three of which are horizontal, drilled through the faults; as well as 3D seismic data and relevant derived horizons and fault polygon interpretations. The available data have been investigated in detail, with all structural features in core, circumferential CT scans and BHI images systematically classified using simple and reproducible descriptive schemes. All the structural features have been orientated using directional data from BHI. The understanding of the character and fill of the fractures observed in core has also been incorporated. A further calibration with seismic and integration of results with information from previous studies allowed a full description of the fracture networks, of their densities within and outside the potential fault corridors of the studied field, as well as an assessment of their potential for reactivation and their possible impact on localised formation compaction. On the BHI images, several sub-vertical fractures have been identified, consisting mainly of mixed resistivity and resistive fractures, striking dominantly WNW-ESE. Particular zones along the wells have noticeably higher fracture densities, where features are organised in clusters; they are intercalated with zones where fractures are rarer. The clustering of fractures within fracture corridors are believed to be fault-related, subvertical and tabular fracture clusters that traverse an entire reservoir unit vertically and extend for several hundreds to thousands of feet laterally. These zones are believed to represent fracture corridors, which correlate with the structural lineaments observed on seismic. The fracture corridor network in the study area shows a variable deformation signature at the different scales of observations, but consists mainly of sub-vertical (dominantly >60°) deformation bands (c.50% of the features identified) and partially-cemented fractures (c.25-40%). Some of these features show a small displacement and it is believed this scaled variation in deformation within the corridors accounts for the overall larger, but relatively minor displacement observed on seismic (c.10-40ft vertical throw and possibly up to c.500m cumulative strike-slip observed in seismic).
{"title":"Multi-Scale Characterisation of the Structural Lineament Across the Thamama Successions in an Onshore Giant Field, Abu Dhabi, UAE","authors":"Y. Pramudyo, M. A. Hosani, Fatimah M. Al Awadhi, R. Masoud, Huda Al Besr, R. Nachiappan, K. A. Hosani, Ahmed Mohamed Al Bairaq, Ammar Faqqas Al Ameri, M. Bertouche, A. Foote, E. Michie, G. Yielding","doi":"10.2118/197121-ms","DOIUrl":"https://doi.org/10.2118/197121-ms","url":null,"abstract":"\u0000 Throughout the UAE and the wider region, several broadly E-W orientated structural lineaments are observed on seismic within the Cretaceous successions and are described as strike-slip faults. However, in the studied field, these features have not been readily observed in well data. Instead, networks of fractures and deformation features are present in core and borehole images. A study was carried out in an attempt to calibrate well and seismic data and to understand the relationship between the seismically-resolved faults and the fractures observed on core. This study focuses on a dataset from the north-east part of the field, which includes BHI images, cores, full 3D CT scans and conventional logs in four penetrations, three of which are horizontal, drilled through the faults; as well as 3D seismic data and relevant derived horizons and fault polygon interpretations.\u0000 The available data have been investigated in detail, with all structural features in core, circumferential CT scans and BHI images systematically classified using simple and reproducible descriptive schemes. All the structural features have been orientated using directional data from BHI. The understanding of the character and fill of the fractures observed in core has also been incorporated. A further calibration with seismic and integration of results with information from previous studies allowed a full description of the fracture networks, of their densities within and outside the potential fault corridors of the studied field, as well as an assessment of their potential for reactivation and their possible impact on localised formation compaction.\u0000 On the BHI images, several sub-vertical fractures have been identified, consisting mainly of mixed resistivity and resistive fractures, striking dominantly WNW-ESE. Particular zones along the wells have noticeably higher fracture densities, where features are organised in clusters; they are intercalated with zones where fractures are rarer. The clustering of fractures within fracture corridors are believed to be fault-related, subvertical and tabular fracture clusters that traverse an entire reservoir unit vertically and extend for several hundreds to thousands of feet laterally. These zones are believed to represent fracture corridors, which correlate with the structural lineaments observed on seismic.\u0000 The fracture corridor network in the study area shows a variable deformation signature at the different scales of observations, but consists mainly of sub-vertical (dominantly >60°) deformation bands (c.50% of the features identified) and partially-cemented fractures (c.25-40%). Some of these features show a small displacement and it is believed this scaled variation in deformation within the corridors accounts for the overall larger, but relatively minor displacement observed on seismic (c.10-40ft vertical throw and possibly up to c.500m cumulative strike-slip observed in seismic).","PeriodicalId":11091,"journal":{"name":"Day 3 Wed, November 13, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"81687036","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}
This paper will consider some of the most common causes that result in major capital projects running into difficulties - including time pressure, inadequate planning, scope changes and communication failures – and will discuss potential ways to mitigate the risk, and help reduce the prospect, of future issues arising and how best to address them if they do (inevitably) arise. In particular, this paper will explore possible internal arrangements – including the involvement of the legal function at all stages of a project (from inception through procurement, execution and finalisation) - and contractual mechanisms which can be used to speed up decision making, reduce the length and complexity of negotiations, manage unexpected events and avoid commercial issues escalating into legal disputes.
{"title":"Legal Tips and Tricks for Capital Projects","authors":"Luke Robottom, Raquel Tarancon Plata","doi":"10.2118/197555-ms","DOIUrl":"https://doi.org/10.2118/197555-ms","url":null,"abstract":"This paper will consider some of the most common causes that result in major capital projects running into difficulties - including time pressure, inadequate planning, scope changes and communication failures – and will discuss potential ways to mitigate the risk, and help reduce the prospect, of future issues arising and how best to address them if they do (inevitably) arise. In particular, this paper will explore possible internal arrangements – including the involvement of the legal function at all stages of a project (from inception through procurement, execution and finalisation) - and contractual mechanisms which can be used to speed up decision making, reduce the length and complexity of negotiations, manage unexpected events and avoid commercial issues escalating into legal disputes.","PeriodicalId":11091,"journal":{"name":"Day 3 Wed, November 13, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"80200438","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}
Raja Nor Rafidah Raja Sahar, Wan Amni Wan Mohamad, Ema Farima Rustam Ali Khan, S. M. Hatta
Barium Sulfate (Barite, BaSO4) scale is the most difficult scale to remove due to its low inherent water solubility. After more than 10 years of production in Field A, barite scales are recently found deposited in the tubing and at the topside in one of the oil producer wells. In this case, barite scales are precipitated through mixing of formation water containing high concentration of barium ions and injection seawater with high sulphate concentrations. Successful method of removing barite scales is using chelant based chemicals i.e. EDTA/DTPA. The best possible way to reduce failure risks of the pilot removal application using these chemicals for Field A is through series of lab testing. This paper describes the selection of barite scales dissolver chemicals through establishment of standard laboratory screening protocols prior to field applications in PETRONAS. In the industry, there are various experimental methods to study the effect of barite dissolver chemicals on barite scales dissolution. Since PETRONAS has just recently encountered barite scales deposition issues, it is crucial to have a standardized protocol to ensure the effectiveness of the chosen chemicals to remediate the issue immediately. The protocol developed was based on various references and citations from other operators and chemical service provider. The protocols are divided into three (3) sections in series i.e. characterization of deposit samples mineralogy, barite dissolution and chemical compatibility testing. Prior to barite dissolution tests, deposit samples collected from the wells/topsides are characterized through XRD/XRF analysis, organic scale identification/analysis and acid solubility test. Finally, the most effective barite dissolver chemical will undergo chemical compatibility tests with production fluids, incumbent production chemicals and core samples. Barite scales deposits collected from Field A were found to be radioactive. Testing procedures were in-line with precautions taken to prevent risks exposure to these materials. Scale characterizations indicated samples are dominated by barium sulfate containing some small percentage of calcium carbonate scales and organic contents. Static disintegration and dynamic dissolution tests carried out shows significant results differences where application of barite dissolver chemicals in the well may require coil tubing assistance. Compatibility studies of the dissolver chemical with incumbent production chemicals shows suitability of the different chemicals when the well is flow back after treatment.
{"title":"Selection of Barium Sulphate/Barite Dissolver Chemical through Establishment of Standard Laboratory Screening Protocols","authors":"Raja Nor Rafidah Raja Sahar, Wan Amni Wan Mohamad, Ema Farima Rustam Ali Khan, S. M. Hatta","doi":"10.2118/197251-ms","DOIUrl":"https://doi.org/10.2118/197251-ms","url":null,"abstract":"\u0000 Barium Sulfate (Barite, BaSO4) scale is the most difficult scale to remove due to its low inherent water solubility. After more than 10 years of production in Field A, barite scales are recently found deposited in the tubing and at the topside in one of the oil producer wells. In this case, barite scales are precipitated through mixing of formation water containing high concentration of barium ions and injection seawater with high sulphate concentrations. Successful method of removing barite scales is using chelant based chemicals i.e. EDTA/DTPA. The best possible way to reduce failure risks of the pilot removal application using these chemicals for Field A is through series of lab testing. This paper describes the selection of barite scales dissolver chemicals through establishment of standard laboratory screening protocols prior to field applications in PETRONAS.\u0000 In the industry, there are various experimental methods to study the effect of barite dissolver chemicals on barite scales dissolution. Since PETRONAS has just recently encountered barite scales deposition issues, it is crucial to have a standardized protocol to ensure the effectiveness of the chosen chemicals to remediate the issue immediately. The protocol developed was based on various references and citations from other operators and chemical service provider.\u0000 The protocols are divided into three (3) sections in series i.e. characterization of deposit samples mineralogy, barite dissolution and chemical compatibility testing. Prior to barite dissolution tests, deposit samples collected from the wells/topsides are characterized through XRD/XRF analysis, organic scale identification/analysis and acid solubility test. Finally, the most effective barite dissolver chemical will undergo chemical compatibility tests with production fluids, incumbent production chemicals and core samples.\u0000 Barite scales deposits collected from Field A were found to be radioactive. Testing procedures were in-line with precautions taken to prevent risks exposure to these materials. Scale characterizations indicated samples are dominated by barium sulfate containing some small percentage of calcium carbonate scales and organic contents. Static disintegration and dynamic dissolution tests carried out shows significant results differences where application of barite dissolver chemicals in the well may require coil tubing assistance. Compatibility studies of the dissolver chemical with incumbent production chemicals shows suitability of the different chemicals when the well is flow back after treatment.","PeriodicalId":11091,"journal":{"name":"Day 3 Wed, November 13, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"80661289","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}
Mustafa R. Al-Zaid, Aslan Bulekbay, Abdulaziz Al-Harbi, S. M. Al-Driweesh
Dealing with tight high pressure/high temperature (HPHT) sour gas reservoirs encounters many challenges. One challenge associated with these reservoirs is the development of hard and heavy scale mixture in the production tubing, causing flow and accessibility restrictions. To restore full accessibility, a mechanical de-scaling operations using special milling and cleanout assemblies is the best current solution to this problem, due to the fact that chemical dissolving methods do not deliver the desired results. Another challenge is conventional perforation in some tight wells gives limited penetration, which does not establish the required wellbore reservoir communication. In this case, utilizing the abrasive jetting tool will offer the best solution to overcome the casing string, cement, formation damage achieve optimum penetration which will optimize the stimulation design and enhance the well productivity. In recent years, using coiled tubing (CT) equipped with fiber optics with aforementioned coil tubing intervention operations, have become a common practice in gas wells. Using this system provides the ability to acquire on-job real time data such as pressure, temperature and gamma ray depth correlation. Furthermore, the incorporation of a new rugged fiber optics system into the intervention strategy has enabled increasing operational success rate and results in robust control on the operation parameters, minimizing the risk of gas influx, reducing coil tubing runs and improving decision making process during the operations. This paper describes the challenges in mechanical de-scaling and slot cuttings operations, overview of different applications using CT with fiber optics system, provides a comparison between the rugged and standard fiber optics systems and lessons learned of recent implementation of the rugged CT fiber optic system.
{"title":"Applying High Rate Coiled Tubing with Fiber Optic System to Meet the Growing Challenges of Coiled Tubing Interventions in Sour Gas Producer Wells","authors":"Mustafa R. Al-Zaid, Aslan Bulekbay, Abdulaziz Al-Harbi, S. M. Al-Driweesh","doi":"10.2118/197867-ms","DOIUrl":"https://doi.org/10.2118/197867-ms","url":null,"abstract":"\u0000 Dealing with tight high pressure/high temperature (HPHT) sour gas reservoirs encounters many challenges. One challenge associated with these reservoirs is the development of hard and heavy scale mixture in the production tubing, causing flow and accessibility restrictions. To restore full accessibility, a mechanical de-scaling operations using special milling and cleanout assemblies is the best current solution to this problem, due to the fact that chemical dissolving methods do not deliver the desired results. Another challenge is conventional perforation in some tight wells gives limited penetration, which does not establish the required wellbore reservoir communication. In this case, utilizing the abrasive jetting tool will offer the best solution to overcome the casing string, cement, formation damage achieve optimum penetration which will optimize the stimulation design and enhance the well productivity.\u0000 In recent years, using coiled tubing (CT) equipped with fiber optics with aforementioned coil tubing intervention operations, have become a common practice in gas wells. Using this system provides the ability to acquire on-job real time data such as pressure, temperature and gamma ray depth correlation. Furthermore, the incorporation of a new rugged fiber optics system into the intervention strategy has enabled increasing operational success rate and results in robust control on the operation parameters, minimizing the risk of gas influx, reducing coil tubing runs and improving decision making process during the operations.\u0000 This paper describes the challenges in mechanical de-scaling and slot cuttings operations, overview of different applications using CT with fiber optics system, provides a comparison between the rugged and standard fiber optics systems and lessons learned of recent implementation of the rugged CT fiber optic system.","PeriodicalId":11091,"journal":{"name":"Day 3 Wed, November 13, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90442394","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}
Scott P. Northrop, J. Seagraves, S. Ramkumar, T. Cullinane
Development of sour gas reserves involves extraction, treating, and disposal steps that can be operationally complex. Historically, highly sour gas reserves are left undeveloped because of the technical challenges and high production costs. These reserves are now being reevaluated as potential sources of supply in areas with high demand for natural gas. To address development challenges, ExxonMobil has applied a dual approach to advancing technologies. First, our broad experiences and well-defined best practices are used to select technologies that best meet the "routine" aspects of sour natural gas development and production. Second, ExxonMobil's industry-leading research capabilities are applied to create new technologies that make treating of difficult sour gas streams feasible. ExxonMobil has over 70 years of experience in operating and developing technologies for gas treating. Relevant experiences will be described along with the efforts to develop and apply innovative technical solutions needed to develop these reserves. Examples include FLEXSORB™ SE solvent for acid gas enrichment and tail gas clean up, the Controlled Freeze Zone™ process for separating significant concentration of contaminants from natural gas, and cMIST™ technology for dehydration and selective H2S removal from raw gas. Each of these technologies will be discussed in some detail, as will our general experience with sour gas treating. This paper illustrates how new technologies developed by one company can become part of the body of applied science that ultimately benefits the broader industry.
{"title":"ExxonMobil's Experience with Sour Gas Treating and Acid Gas Handling","authors":"Scott P. Northrop, J. Seagraves, S. Ramkumar, T. Cullinane","doi":"10.2118/197137-ms","DOIUrl":"https://doi.org/10.2118/197137-ms","url":null,"abstract":"\u0000 Development of sour gas reserves involves extraction, treating, and disposal steps that can be operationally complex. Historically, highly sour gas reserves are left undeveloped because of the technical challenges and high production costs. These reserves are now being reevaluated as potential sources of supply in areas with high demand for natural gas.\u0000 To address development challenges, ExxonMobil has applied a dual approach to advancing technologies. First, our broad experiences and well-defined best practices are used to select technologies that best meet the \"routine\" aspects of sour natural gas development and production. Second, ExxonMobil's industry-leading research capabilities are applied to create new technologies that make treating of difficult sour gas streams feasible.\u0000 ExxonMobil has over 70 years of experience in operating and developing technologies for gas treating. Relevant experiences will be described along with the efforts to develop and apply innovative technical solutions needed to develop these reserves. Examples include FLEXSORB™ SE solvent for acid gas enrichment and tail gas clean up, the Controlled Freeze Zone™ process for separating significant concentration of contaminants from natural gas, and cMIST™ technology for dehydration and selective H2S removal from raw gas. Each of these technologies will be discussed in some detail, as will our general experience with sour gas treating.\u0000 This paper illustrates how new technologies developed by one company can become part of the body of applied science that ultimately benefits the broader industry.","PeriodicalId":11091,"journal":{"name":"Day 3 Wed, November 13, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89249644","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}
京公网安备 11010802042870号
京ICP备2023020795号-1
扫码关注我们
求助内容：
应助结果提醒方式：