S. Hati, Hemlata Chawla, Arnab Ghosh, U. Guru, B. Ray, R. Guru, Sambit Pattanaik
As oil and gas exploration and development forays into unconventional plays, more specifically, basement exploration, its characterization and understanding have become very important. The present study aims at understanding the reservoir quality in terms of complex mineralogy and lithology variations, porosity, fracture properties and distribution near and away from the borehole using an integrated approach with the help of elemental spectroscopy, borehole acoustic imager, borehole micro-resistivity imager, nuclear magnetic resonance and borehole acoustic reflection survey. A comprehensive petrophysical characterization of different mineralo-facies of basement was carried out using elemental spectroscopy, formation micro-resistivity imager, borehole acoustic imager and combinable magnetic resonance along with basic open-hole data. Two distinct rock groups were identified – silica rich, iron poor zones having open fractures with good fracture density, porosity and aperture and silica poor, iron rich zones with no open fractures, poor fracture density, porosity and apertures. The zones with open fractures were the prime zones identified for further testing and completion. However, the near well bore analysis could not explain the oil flow from one zone having open fractures, whereas another similar zone showed no flow. Borehole Acoustic Reflection Survey processing was attempted to understand how extent of fractures beyond the borehole wall contributed to productivity from a well. The presence of laterally continuous fracture network at an interval that coincides with the depths from which the well is flowing, in turn validated from production log data, explained fluid flow from basement. Furthermore, the absence of such network can cause no flow even though near well-bore possible open fractures are present. Present study established the fact that, identification of potential open fractured zones in basement is a lead for reservoir zone delineation, however, a lateral extent of such basement reservoir facies is the key for successful basement hydrocarbon exploration.
{"title":"A Comprehensive Reservoir Quality Characterization for Fractured Basements in India","authors":"S. Hati, Hemlata Chawla, Arnab Ghosh, U. Guru, B. Ray, R. Guru, Sambit Pattanaik","doi":"10.2118/193092-MS","DOIUrl":"https://doi.org/10.2118/193092-MS","url":null,"abstract":"\u0000 As oil and gas exploration and development forays into unconventional plays, more specifically, basement exploration, its characterization and understanding have become very important. The present study aims at understanding the reservoir quality in terms of complex mineralogy and lithology variations, porosity, fracture properties and distribution near and away from the borehole using an integrated approach with the help of elemental spectroscopy, borehole acoustic imager, borehole micro-resistivity imager, nuclear magnetic resonance and borehole acoustic reflection survey.\u0000 A comprehensive petrophysical characterization of different mineralo-facies of basement was carried out using elemental spectroscopy, formation micro-resistivity imager, borehole acoustic imager and combinable magnetic resonance along with basic open-hole data. Two distinct rock groups were identified – silica rich, iron poor zones having open fractures with good fracture density, porosity and aperture and silica poor, iron rich zones with no open fractures, poor fracture density, porosity and apertures. The zones with open fractures were the prime zones identified for further testing and completion. However, the near well bore analysis could not explain the oil flow from one zone having open fractures, whereas another similar zone showed no flow.\u0000 Borehole Acoustic Reflection Survey processing was attempted to understand how extent of fractures beyond the borehole wall contributed to productivity from a well. The presence of laterally continuous fracture network at an interval that coincides with the depths from which the well is flowing, in turn validated from production log data, explained fluid flow from basement. Furthermore, the absence of such network can cause no flow even though near well-bore possible open fractures are present.\u0000 Present study established the fact that, identification of potential open fractured zones in basement is a lead for reservoir zone delineation, however, a lateral extent of such basement reservoir facies is the key for successful basement hydrocarbon exploration.","PeriodicalId":11014,"journal":{"name":"Day 1 Mon, November 12, 2018","volume":"10 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84097772","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 Lower Cretaceous McMurray Formation in western Canada has over 1.8 trillion barrels of bitumen resource in place. Due to the bitumen in its natural state having a very low API (6-12°) and corresponding high viscosity, traditional primary (pump jacks) and secondary (water flood) recovery techniques cannot be used. Instead, economic extraction of the bitumen occurs via surface mining and subsurface steam-assisted gravity drainage (SAGD). Using the Pike and Jackfish oil sands project areas as a case study, it will be shown that successful SAGD operations requires a thorough understanding of the depositional fabric and stratigraphic architecture of the reservoir. Within the study area, reservoir intervals in the form of cross-bedded sandstones and sandy inclined heterolithic strata (IHS) are present within both the middle and upper McMurray. Overlying the middle McMurray are upper McMurray parasequence cycles reflective of brackish bays and deltaic embayment deposits. In many areas, however, these parasequences are absent and instead substituted by fluvial channels with brackish water overprint. The facies within these fluvial channels are very similar in character to the those seen within the middle McMurray. To help progress our understanding of baffles and barriers to flow within these aforementioned reservoir facies, dip meter and seismic data are presented as data that can be used. From this, a better understanding of the complex interplay of facies and stratigraphic relationships can be made. More importantly, clearer insights into SAGD performance (pre- and post-steam) can also be achieved. Using the McMurray Formation as an underpinning, the wider implications of understanding fluvial sedimentation will be addressed by using reservoirs from the Middle East as examples. For example, many siliciclastic reservoirs in locations such as Kuwait (Wara Formation) and Iraq (Zubair Formation) are also influenced to a large degree by fluvial sedimentation. Not unlike SAGD, any successful secondary recovery techniques applied within these reservoirs will also require a detailed characterization of the channel stacking patterns and channel orientations prior to implementation.
{"title":"Overview of Reservoir Deposits in the Pike and Jackfish Oil Sands Project Areas, Southern Athabasca Oil Sands, Canada","authors":"G. Baniak, E. M. Caddel, Kelly G. Kingsmith","doi":"10.2118/193065-MS","DOIUrl":"https://doi.org/10.2118/193065-MS","url":null,"abstract":"\u0000 The Lower Cretaceous McMurray Formation in western Canada has over 1.8 trillion barrels of bitumen resource in place. Due to the bitumen in its natural state having a very low API (6-12°) and corresponding high viscosity, traditional primary (pump jacks) and secondary (water flood) recovery techniques cannot be used. Instead, economic extraction of the bitumen occurs via surface mining and subsurface steam-assisted gravity drainage (SAGD). Using the Pike and Jackfish oil sands project areas as a case study, it will be shown that successful SAGD operations requires a thorough understanding of the depositional fabric and stratigraphic architecture of the reservoir.\u0000 Within the study area, reservoir intervals in the form of cross-bedded sandstones and sandy inclined heterolithic strata (IHS) are present within both the middle and upper McMurray. Overlying the middle McMurray are upper McMurray parasequence cycles reflective of brackish bays and deltaic embayment deposits. In many areas, however, these parasequences are absent and instead substituted by fluvial channels with brackish water overprint. The facies within these fluvial channels are very similar in character to the those seen within the middle McMurray. To help progress our understanding of baffles and barriers to flow within these aforementioned reservoir facies, dip meter and seismic data are presented as data that can be used. From this, a better understanding of the complex interplay of facies and stratigraphic relationships can be made. More importantly, clearer insights into SAGD performance (pre- and post-steam) can also be achieved.\u0000 Using the McMurray Formation as an underpinning, the wider implications of understanding fluvial sedimentation will be addressed by using reservoirs from the Middle East as examples. For example, many siliciclastic reservoirs in locations such as Kuwait (Wara Formation) and Iraq (Zubair Formation) are also influenced to a large degree by fluvial sedimentation. Not unlike SAGD, any successful secondary recovery techniques applied within these reservoirs will also require a detailed characterization of the channel stacking patterns and channel orientations prior to implementation.","PeriodicalId":11014,"journal":{"name":"Day 1 Mon, November 12, 2018","volume":" 44","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"91412011","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}
It becomes evident today's Oil&Gas projects in average have higher electrical power demand than years back. In most cases technical decisions are to simply increase current to compensate power needs. Design ratings for operating and short-circuit currents of medium-voltage switchgear on generator voltage level are limiting grid design. This is the case especially for power islands. Stepping up generator voltage can be a perfect solution in particular for power grids feeding extended oil fields. Installing step-up transformers for each generator unit and working with a network voltage up to 33 kV or higher sometimes creates disposition to believe that this is a more expensive solution. A load-flow and short-circuit calculation for the main substation is required to properly size the switchgear and the other distribution equipment derived from planned grid arrangement and oil field process specific operation modes. It has also to be considered expected power supply quality, reliability and availability. A cost comparison will be based on total cost of ownership between the solution with main substation on generator voltage level of 11 kV and the solutions with step-up transformers up to 22 or up to 33 kV. This comparison will also include the additional heat losses of overhead lines or cables to and between the wellpads for a year of operation. When using higher voltages, there should be no limitation with respect to grid design and grid operation. Generally, the voltage level has to be adequate for the supply purpose. A network should be designed to avoid use of current limiters. With proper voltage level selection the bus sectionalizers can remain in NC position. It is possible that generator units are operated that loss of one set can be compensated to avoid any interruption of power supply. Power generation can be increased when feeding via transformers to higher voltage levels of switchgear. The Power Plant Switchgear will require only a reduced short-circuit level and lower design currents for busbars and feeders to achieve optimized grid design. Unit transformers between generators and switchgear will prevent any negative influence of ground faults from the grid to the generators. Also with respect to heat losses, maintenance, grid availability and reliability as well as aging the advantages are clearly on the higher voltage level. The required power grid will be assessed based on different voltage levels. The optimized solution for the oil field will be discussed in detail. Solution approach with higher voltage levels and optimized grid design will have reserves to deliver additional electrical power for extensions and also for operation in depletion mode. There are now oil fields which do not allow bridging distances between wellpads by means of overhead lines but by underground cabling because of environmental conditions. Considering this aspect in cost comparison between different grid designs and voltage levels the advantage fo
{"title":"Creating Optimal Power Supply for Extensive Onshore Oil Fields","authors":"W. Baerthlein, D. Audring","doi":"10.2118/192782-MS","DOIUrl":"https://doi.org/10.2118/192782-MS","url":null,"abstract":"\u0000 It becomes evident today's Oil&Gas projects in average have higher electrical power demand than years back. In most cases technical decisions are to simply increase current to compensate power needs. Design ratings for operating and short-circuit currents of medium-voltage switchgear on generator voltage level are limiting grid design. This is the case especially for power islands. Stepping up generator voltage can be a perfect solution in particular for power grids feeding extended oil fields.\u0000 Installing step-up transformers for each generator unit and working with a network voltage up to 33 kV or higher sometimes creates disposition to believe that this is a more expensive solution.\u0000 A load-flow and short-circuit calculation for the main substation is required to properly size the switchgear and the other distribution equipment derived from planned grid arrangement and oil field process specific operation modes. It has also to be considered expected power supply quality, reliability and availability.\u0000 A cost comparison will be based on total cost of ownership between the solution with main substation on generator voltage level of 11 kV and the solutions with step-up transformers up to 22 or up to 33 kV. This comparison will also include the additional heat losses of overhead lines or cables to and between the wellpads for a year of operation.\u0000 When using higher voltages, there should be no limitation with respect to grid design and grid operation. Generally, the voltage level has to be adequate for the supply purpose. A network should be designed to avoid use of current limiters. With proper voltage level selection the bus sectionalizers can remain in NC position. It is possible that generator units are operated that loss of one set can be compensated to avoid any interruption of power supply.\u0000 Power generation can be increased when feeding via transformers to higher voltage levels of switchgear. The Power Plant Switchgear will require only a reduced short-circuit level and lower design currents for busbars and feeders to achieve optimized grid design. Unit transformers between generators and switchgear will prevent any negative influence of ground faults from the grid to the generators. Also with respect to heat losses, maintenance, grid availability and reliability as well as aging the advantages are clearly on the higher voltage level. The required power grid will be assessed based on different voltage levels. The optimized solution for the oil field will be discussed in detail.\u0000 Solution approach with higher voltage levels and optimized grid design will have reserves to deliver additional electrical power for extensions and also for operation in depletion mode.\u0000 There are now oil fields which do not allow bridging distances between wellpads by means of overhead lines but by underground cabling because of environmental conditions. Considering this aspect in cost comparison between different grid designs and voltage levels the advantage fo","PeriodicalId":11014,"journal":{"name":"Day 1 Mon, November 12, 2018","volume":"13 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84921606","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}
Salvatore Spagnolo, Francesco Incollà, C. Guglielmo
Eni installed the world's first offshore Rigless Fully Retrievable Electrical Submersible Pump (RFR-ESP) system in an Eni Congo field in April 2012. The ESP failed after four years, and the system was successfully replaced rigless, by means of a slickline unit and a pumping unit. The job included the complete path from design and operations definition to the ESP commissioning and follow-up. Replacement operations were split in three different phases: Pull Out Of Hole (POOH): retrieval of the system and verification of the failed item(s).Run In Hole preparation: order, shipment, test and preparation of the items to be run in hole.Run In Hole (RIH): system deployment, commissioning and follow-up. The separation in time of the three phases was mainly due to the logistic arrangements required for the shipment of the various items to be replaced. Major attention was given to HSEQ aspects in every phase. The job resulted in the complete rigless replacement of the retrievable part of the ESP system, which allowed remarkable cost savings, compared to a rig intervention for the same scope of work, in terms of both direct costs and gains for avoiding well downtime and production delay. Better results and further contractions of times and costs could have been achieved by improving the management of operations and logistics. However, being this the first job of this kind worldwide, it was challenging in that no model or benchmark was available at that time. Some lessons learnt from the POOH phase were directly applied during the RIH phase, while others were reported in order to be implemented in future similar jobs. Since the economic impact of this type of job is remarkable, the sharing of knowledge is key to enhance performance of analogous applications, in a safe and efficient manner. This paper describes the job performed, explaining the choices made, the criticalities encountered, as well as the lessons learnt and the benefits achieved.
{"title":"First Successful Replacement of Fully Retrievable ESP by Slickline","authors":"Salvatore Spagnolo, Francesco Incollà, C. Guglielmo","doi":"10.2118/192839-MS","DOIUrl":"https://doi.org/10.2118/192839-MS","url":null,"abstract":"\u0000 Eni installed the world's first offshore Rigless Fully Retrievable Electrical Submersible Pump (RFR-ESP) system in an Eni Congo field in April 2012. The ESP failed after four years, and the system was successfully replaced rigless, by means of a slickline unit and a pumping unit.\u0000 The job included the complete path from design and operations definition to the ESP commissioning and follow-up.\u0000 Replacement operations were split in three different phases: Pull Out Of Hole (POOH): retrieval of the system and verification of the failed item(s).Run In Hole preparation: order, shipment, test and preparation of the items to be run in hole.Run In Hole (RIH): system deployment, commissioning and follow-up.\u0000 The separation in time of the three phases was mainly due to the logistic arrangements required for the shipment of the various items to be replaced.\u0000 Major attention was given to HSEQ aspects in every phase.\u0000 The job resulted in the complete rigless replacement of the retrievable part of the ESP system, which allowed remarkable cost savings, compared to a rig intervention for the same scope of work, in terms of both direct costs and gains for avoiding well downtime and production delay.\u0000 Better results and further contractions of times and costs could have been achieved by improving the management of operations and logistics. However, being this the first job of this kind worldwide, it was challenging in that no model or benchmark was available at that time.\u0000 Some lessons learnt from the POOH phase were directly applied during the RIH phase, while others were reported in order to be implemented in future similar jobs. Since the economic impact of this type of job is remarkable, the sharing of knowledge is key to enhance performance of analogous applications, in a safe and efficient manner.\u0000 This paper describes the job performed, explaining the choices made, the criticalities encountered, as well as the lessons learnt and the benefits achieved.","PeriodicalId":11014,"journal":{"name":"Day 1 Mon, November 12, 2018","volume":"75 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"80866408","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}
Riaz Khan, M. Salib, Ali Ba Hussain, Atiqurrahman Bin Abd Rashid, G. Aydinoglu, U. Farooq
In this study field, the objective was to identify the causes of low resistivity pay that was limited towards the southwest of the field. Restricting the focus only on diagenesis has not yielded conclusive explanations to delineate the affected area. Alternatively, investigating the influence of structural evolution (folding and tilting) on hydrocarbon charging mechanism and diagenesis has significantly contributed to a reasonable explanation. This, in turn, can potentially impact decisions related to reservoir characterization and field development planning. The field has adequate coverage of data from vertical (appraisal and observers) and horizontal wells (producers and injectors). The approach of structural flattening at different time intervals was applied in understanding the structural evolution of the field as part of regional tectonic history of the area. The delineation of areas in different paleo-positions has helped in grouping Wells into categories for thorough investigation. Detailed analyses of conventional and advanced logs, and core data were performed which included: petrographic analysis, pore throat and bound water evaluation, and assessment of resistivity log signatures in reference to the paleo-positions of the Wells. The structural evolution and corresponding hydrocarbon charging mechanisms (drainage and imbibition) have influenced the reservoir hydrocarbon saturation in the field from northeast to southwest. The northeast tilting was triggered by Zagros loading, combined with thermal uplift associated with Red Sea opening. This resulted in imbibition in the extreme northeast and second phase of primary drainage in the extreme southwest of the field. As a result, the area that was previously in water leg during early Tertiary provided more exposure to diagenetic processes which enhanced the total porosity (up to 5p.u.) with high bound water and low resistivity pay. The areal coverage within water leg has been well defined in this study by evaluating the positions of paleo structural closures and hydrocarbon charging mechanisms. This would be useful in capturing diagenetic overprint in properties modeling as well as defining appropriate rock types for better saturation height function and volumetric estimations in this area. Consequently, the field development strategy was to develop the central area, in the first phase, since it was less affected by fluids saturation variations caused by the structural evolution. The study has provided improvement in reservoir characterization techniques for well placement and enhanced field development planning. The methodology and approach used in this study are usually applied, to some extent, during exploration stages or basin modeling at regional scale with limited data availability and it is not utilized enough for Well placement and reserves estimations in the development stage. The approach applied here, with substantial data availability and integration, can potentially help i
{"title":"Understanding the Influence of Structural Evolution Folding and Tilting on Hydrocarbon Accumulation Drainage and Imbibition and Reservoir Quality Diagenesis for Enhanced Field Development Planning, a Case Study of Lower Cretaceous Carbonate Reservoir, Abu Dhabi, UAE","authors":"Riaz Khan, M. Salib, Ali Ba Hussain, Atiqurrahman Bin Abd Rashid, G. Aydinoglu, U. Farooq","doi":"10.2118/193237-MS","DOIUrl":"https://doi.org/10.2118/193237-MS","url":null,"abstract":"\u0000 In this study field, the objective was to identify the causes of low resistivity pay that was limited towards the southwest of the field. Restricting the focus only on diagenesis has not yielded conclusive explanations to delineate the affected area. Alternatively, investigating the influence of structural evolution (folding and tilting) on hydrocarbon charging mechanism and diagenesis has significantly contributed to a reasonable explanation. This, in turn, can potentially impact decisions related to reservoir characterization and field development planning.\u0000 The field has adequate coverage of data from vertical (appraisal and observers) and horizontal wells (producers and injectors). The approach of structural flattening at different time intervals was applied in understanding the structural evolution of the field as part of regional tectonic history of the area. The delineation of areas in different paleo-positions has helped in grouping Wells into categories for thorough investigation. Detailed analyses of conventional and advanced logs, and core data were performed which included: petrographic analysis, pore throat and bound water evaluation, and assessment of resistivity log signatures in reference to the paleo-positions of the Wells.\u0000 The structural evolution and corresponding hydrocarbon charging mechanisms (drainage and imbibition) have influenced the reservoir hydrocarbon saturation in the field from northeast to southwest. The northeast tilting was triggered by Zagros loading, combined with thermal uplift associated with Red Sea opening. This resulted in imbibition in the extreme northeast and second phase of primary drainage in the extreme southwest of the field. As a result, the area that was previously in water leg during early Tertiary provided more exposure to diagenetic processes which enhanced the total porosity (up to 5p.u.) with high bound water and low resistivity pay. The areal coverage within water leg has been well defined in this study by evaluating the positions of paleo structural closures and hydrocarbon charging mechanisms. This would be useful in capturing diagenetic overprint in properties modeling as well as defining appropriate rock types for better saturation height function and volumetric estimations in this area. Consequently, the field development strategy was to develop the central area, in the first phase, since it was less affected by fluids saturation variations caused by the structural evolution. The study has provided improvement in reservoir characterization techniques for well placement and enhanced field development planning.\u0000 The methodology and approach used in this study are usually applied, to some extent, during exploration stages or basin modeling at regional scale with limited data availability and it is not utilized enough for Well placement and reserves estimations in the development stage. The approach applied here, with substantial data availability and integration, can potentially help i","PeriodicalId":11014,"journal":{"name":"Day 1 Mon, November 12, 2018","volume":"37 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88575104","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 work suggested the use of asymmetrical six phase induction motors instead of the conventional three phase motors for safety critical equipment to improve the overall system reliability. The rule of thumb is that a single fault should not be able to draw safety critical equipment out of service. Multi-phase machine in general and six phase machine in particular are able to continue running with one phase or more open circuit. The ability of multi-phase machines even to start under fault is another useful feature. Statistically, the main reason for losing one of the motor phases is the single open gate transistor fault. The defected phase is entirely disregarded, and then the current in the rest of phases which still functioning is optimized. Consequently, if minimum copper loss criterion is applied, the paid penalty is 50% additional losses that leads to motor derating, if not pre-designed with proper safety factor. This paper introduces an alternative post fault control strategy, which allows the usage of the entire healthy power electronic switches. An achievement of reducing the post fault increase in stator copper losses to 25% is realized.
{"title":"Increased Reliability Using Asymmetrical Six Phase Induction Motor with Double Isolated Neutral","authors":"Elhussien A. Mahmoud","doi":"10.2118/193151-MS","DOIUrl":"https://doi.org/10.2118/193151-MS","url":null,"abstract":"\u0000 This work suggested the use of asymmetrical six phase induction motors instead of the conventional three phase motors for safety critical equipment to improve the overall system reliability. The rule of thumb is that a single fault should not be able to draw safety critical equipment out of service. Multi-phase machine in general and six phase machine in particular are able to continue running with one phase or more open circuit. The ability of multi-phase machines even to start under fault is another useful feature. Statistically, the main reason for losing one of the motor phases is the single open gate transistor fault. The defected phase is entirely disregarded, and then the current in the rest of phases which still functioning is optimized. Consequently, if minimum copper loss criterion is applied, the paid penalty is 50% additional losses that leads to motor derating, if not pre-designed with proper safety factor. This paper introduces an alternative post fault control strategy, which allows the usage of the entire healthy power electronic switches. An achievement of reducing the post fault increase in stator copper losses to 25% is realized.","PeriodicalId":11014,"journal":{"name":"Day 1 Mon, November 12, 2018","volume":"50 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82041236","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}
Hooisweng Ow, Sehoon Chang, Gawain Thomas, Rena Shi, Wei Wang, Hsieh Chen, M. Poitzsch, A. Abdel-Fattah
We are developing an integrated, real-time system for deploying Advanced Tracers cost-effectively in a ubiquitous and potentially long-term way. This campaign is for the sake of increasing the oil recovery factor in large waterflooded reservoirs through improved optimization of the water injection for oil production. This paper explains key features of this novel system and reports main results from the ongoing field test of our second-generation tracer material and detection methodology. Existing inter-well tracers require elaborate laboratory processing for analysis and are not compatible with ubiquitous or real-time deployment. Additionally, conventional tracer material and service costs are not economically viable for widespread and long-term deployment; also, available material barcodes compatible with carbonate reservoirs may be inadequate to monitor dozens of wells simultaneously. Our system addresses all of these inadequacies using novel materials and detection methods, with detailed modeling studies providing strong justification of the financial benefit of this tracer deployment through quantification of increased oil recovery from waterflooded reservoirs. Key elements of this new inter-well Advanced Tracers system include: An optically-detectable tracer material that can in principle be detected in real-time or near real-time at low limits of detection (LODs), even in the presence of background oil in producing water by means of an intrinsic oil background-subtraction method. The material also has high mobility in high-salinity carbonate reservoirs.A rich palette of tracer barcodes (potentially 50 - 100 or more) to enable simultaneous injection and sampling in dozens of nearby wells.Modeling feasibility studies, performed on an ensemble of different reservoir geometries and with sensitivity analyses, showing that including routine inter-well tracer data along with injection and production rates improves the history match quality and therefore, the optimization of the water injection and oil extraction rates so as to achieve a few percent increase in net present values (NPV). Recent field tests of the detectability and discrimination of injected prototype tracer materials will be described. This work adapts novel technology development at the state of the art of modern nanotechnology and bioanalysis to the long-term reservoir stewardship objectives. The integrated, real-time tracer-detection system promises financial benefits through increased NPV and/or ultimate recovery factor via better optimization of water injection.
{"title":"First Deployment of a Novel Advanced Tracers System for Improved Waterflood Recovery Optimization","authors":"Hooisweng Ow, Sehoon Chang, Gawain Thomas, Rena Shi, Wei Wang, Hsieh Chen, M. Poitzsch, A. Abdel-Fattah","doi":"10.2118/192598-MS","DOIUrl":"https://doi.org/10.2118/192598-MS","url":null,"abstract":"\u0000 We are developing an integrated, real-time system for deploying Advanced Tracers cost-effectively in a ubiquitous and potentially long-term way. This campaign is for the sake of increasing the oil recovery factor in large waterflooded reservoirs through improved optimization of the water injection for oil production. This paper explains key features of this novel system and reports main results from the ongoing field test of our second-generation tracer material and detection methodology.\u0000 Existing inter-well tracers require elaborate laboratory processing for analysis and are not compatible with ubiquitous or real-time deployment. Additionally, conventional tracer material and service costs are not economically viable for widespread and long-term deployment; also, available material barcodes compatible with carbonate reservoirs may be inadequate to monitor dozens of wells simultaneously. Our system addresses all of these inadequacies using novel materials and detection methods, with detailed modeling studies providing strong justification of the financial benefit of this tracer deployment through quantification of increased oil recovery from waterflooded reservoirs.\u0000 Key elements of this new inter-well Advanced Tracers system include: An optically-detectable tracer material that can in principle be detected in real-time or near real-time at low limits of detection (LODs), even in the presence of background oil in producing water by means of an intrinsic oil background-subtraction method. The material also has high mobility in high-salinity carbonate reservoirs.A rich palette of tracer barcodes (potentially 50 - 100 or more) to enable simultaneous injection and sampling in dozens of nearby wells.Modeling feasibility studies, performed on an ensemble of different reservoir geometries and with sensitivity analyses, showing that including routine inter-well tracer data along with injection and production rates improves the history match quality and therefore, the optimization of the water injection and oil extraction rates so as to achieve a few percent increase in net present values (NPV).\u0000 Recent field tests of the detectability and discrimination of injected prototype tracer materials will be described.\u0000 This work adapts novel technology development at the state of the art of modern nanotechnology and bioanalysis to the long-term reservoir stewardship objectives. The integrated, real-time tracer-detection system promises financial benefits through increased NPV and/or ultimate recovery factor via better optimization of water injection.","PeriodicalId":11014,"journal":{"name":"Day 1 Mon, November 12, 2018","volume":"1 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90717776","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}
P. Sompongchaiyakul, S. Bureekul, Siriphorn Sombatjinda
More than two decades that the Gulf of Thailand (GOT) has been installed with petroleum hydrocarbon production platforms, currently over 400 platforms were installed and operated. Since mercury is a common contaminant in petroleum hydrocarbon production in Southeast Asia, minimal risk and environmental integrity should be concerned. Mercury concentration in surface sediment collected from the Gulf of Thailand in 2003 (89 stations), 2012 (174 stations) and 2013 (45 stations). Sedimentological characteristics, readily oxidizable organic carbon and calcium carbonate were determined. All analyses were carried out in our laboratory using cold vapor atomic absorption spectroscopy. The results show an increase in trace amount of mercury in the Gulf's sediment. Average concentrations of mercury in surface sediments in the lower GOT collected in 2003, 2012 and 2013 were 24.4±9.00, 34.9±21.5 and 41.4±15.3 μg/kg dry weight (carbonate free basis). It is coincident to an increment in the number of platforms for natural gas exploration and production in the Gulf of Thailand. Spatial distribution of mercury in the sediments indicates a clearly linked to the exploration, development, production, and processing in petroleum and gas operation. Although the elevation of mercury level in the GOT's sediment does not showed high risk yet, treating and recycling of mercury contaminated substances generated during production are required in order to minimize the health risk in consumption of seafood collecting from the GOT.
{"title":"Impact of Natural Gas Exploration and Production on Mercury Concentrations in Surface Sediment of the Gulf of Thailand","authors":"P. Sompongchaiyakul, S. Bureekul, Siriphorn Sombatjinda","doi":"10.2118/192739-MS","DOIUrl":"https://doi.org/10.2118/192739-MS","url":null,"abstract":"\u0000 More than two decades that the Gulf of Thailand (GOT) has been installed with petroleum hydrocarbon production platforms, currently over 400 platforms were installed and operated. Since mercury is a common contaminant in petroleum hydrocarbon production in Southeast Asia, minimal risk and environmental integrity should be concerned. Mercury concentration in surface sediment collected from the Gulf of Thailand in 2003 (89 stations), 2012 (174 stations) and 2013 (45 stations).\u0000 Sedimentological characteristics, readily oxidizable organic carbon and calcium carbonate were determined. All analyses were carried out in our laboratory using cold vapor atomic absorption spectroscopy. The results show an increase in trace amount of mercury in the Gulf's sediment. Average concentrations of mercury in surface sediments in the lower GOT collected in 2003, 2012 and 2013 were 24.4±9.00, 34.9±21.5 and 41.4±15.3 μg/kg dry weight (carbonate free basis). It is coincident to an increment in the number of platforms for natural gas exploration and production in the Gulf of Thailand. Spatial distribution of mercury in the sediments indicates a clearly linked to the exploration, development, production, and processing in petroleum and gas operation. Although the elevation of mercury level in the GOT's sediment does not showed high risk yet, treating and recycling of mercury contaminated substances generated during production are required in order to minimize the health risk in consumption of seafood collecting from the GOT.","PeriodicalId":11014,"journal":{"name":"Day 1 Mon, November 12, 2018","volume":"9 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88815134","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
A. D. Lullo, C. Passucci, K. Hester, R. Zaffaroni, R. Reinhart
Pipeline in-line inspection requires a proper cleaning of the pipeline inner walls. In the case hereby described of a 30km 12" offshore line, a significant amount of wax deposits was expected and a series hydro-mechanical cleaning tools were deployed, after a preliminary series of less aggressive pigs. Normally, the progress of the cleaning process is monitored only by the arrival conditions of the cleaning tools and of the receiving trap. To improve the process, miniaturized pressure, temperature and acceleration sensors were added to the cleaning tools, directly in the field, without any modifications to the cleaning devices and without introducing any additional risks or operating impact. After each instrumented cleaning tool, the sensor data were quickly analyzed and led to the selection of most suitable subsequent tool. In this way, it was observed that the pig conditions and the amount of material collected in the receiving trap did not fully indicate the true cleaning status of the pipeline, while the sensors provided a clearer picture. The pig sequence was thus optimized in number and type of pigs and the intelligent pig run was preformed successfully with no issues or data loss. The advantage of these tiny sensors, not foreseen in the hydro-mechanical pig design, is that they can be applied to almost any pig with minimal-to-no modifications. This information can be used in a number of ways, including detection of flow restrictions (dents, deposits), and can also be used to re-create the line elevation, profile with limited a priori information.
{"title":"Use of Miniaturized Sensors to Optimize Cleaning Operations for In-Line Inspection of a Subsea Pipeline","authors":"A. D. Lullo, C. Passucci, K. Hester, R. Zaffaroni, R. Reinhart","doi":"10.2118/193010-MS","DOIUrl":"https://doi.org/10.2118/193010-MS","url":null,"abstract":"\u0000 Pipeline in-line inspection requires a proper cleaning of the pipeline inner walls. In the case hereby described of a 30km 12\" offshore line, a significant amount of wax deposits was expected and a series hydro-mechanical cleaning tools were deployed, after a preliminary series of less aggressive pigs.\u0000 Normally, the progress of the cleaning process is monitored only by the arrival conditions of the cleaning tools and of the receiving trap. To improve the process, miniaturized pressure, temperature and acceleration sensors were added to the cleaning tools, directly in the field, without any modifications to the cleaning devices and without introducing any additional risks or operating impact. After each instrumented cleaning tool, the sensor data were quickly analyzed and led to the selection of most suitable subsequent tool.\u0000 In this way, it was observed that the pig conditions and the amount of material collected in the receiving trap did not fully indicate the true cleaning status of the pipeline, while the sensors provided a clearer picture. The pig sequence was thus optimized in number and type of pigs and the intelligent pig run was preformed successfully with no issues or data loss.\u0000 The advantage of these tiny sensors, not foreseen in the hydro-mechanical pig design, is that they can be applied to almost any pig with minimal-to-no modifications. This information can be used in a number of ways, including detection of flow restrictions (dents, deposits), and can also be used to re-create the line elevation, profile with limited a priori information.","PeriodicalId":11014,"journal":{"name":"Day 1 Mon, November 12, 2018","volume":"72 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86292282","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}
Amit Kumar, Ahmed Al Dahmani, Shaheen Kunhi, Asif Iqbal, M. Amad, T. Morrow
During field inspection of Christmas (X-mas) trees in a giant oil offshore field in Abu Dhabi, a small subset of wells were reported to be severely corroded on X-mas tree studded outlets imposing high HSE risks due to possible loss of containment. A holistic analysis was conducted to identify corroded X-mas trees, establish the root-cause of corrosion and recommend a remedial action plan to control future corrosion damage and reduce HSE risk exposure. Advanced modeling tools and lab tests were used to analyze the flow behavior and field samples, respectively. Advanced modeling was performed to analyze inorganic scale potential, identify flow regimes and calculate corrosion rates in the X-mas trees to correlate with operating conditions. Solid samples from X-mas trees were analyzed using advanced microscopy techniques to identify the elemental composition and phases. Water samples were also analyzed to check bacteria content. Available data on historical operating conditions, modeling and lab analysis results were segregated into in-favor and against factors for each of the mechanisms to identify the potential root-cause of corrosion. Modeling results were used in conjunction with actual field data such as corrosion feature morphology, historical operating conditions, etc. to evaluate corrosion damage. Based on corrosion feature morphology, wells were categorized into different groups to compare the flow behavior and operating conditions with observed corrosion patterns. A thorough analysis of corrosion feature morphology and operating conditions identified flow-induced localized corrosion (FILC) as the root-cause of corrosion in severely corroded X-mas trees. X-mas tree design, fluid properties and operating parameters such as well head pressure (WHP), wellhead temperature (WHT) and flow rate were found to be key contributing factors of accelerated corrosion. Results of computational fluid dynamics (CFD) modeling showed that the horizontal section of X-mas tree is exposed to higher turbulence, water wetting and transient gas bubble formation/collapse phenomena than the vertical section due to changes in flow direction and gravity effects. Several mitigation strategies were implemented to control corrosion in the X-mas tree flange area, and reduce likelihood of leakage through the X-mas tree flange. Findings from this work led to development of an Excel based tool which can be used to assess and predict the corrosion risks to X-tree based on operating conditions.
{"title":"Holistic Study to Identify Root-Cause of Corrosion in Christmas Trees of Oil Producer Wells","authors":"Amit Kumar, Ahmed Al Dahmani, Shaheen Kunhi, Asif Iqbal, M. Amad, T. Morrow","doi":"10.2118/192663-MS","DOIUrl":"https://doi.org/10.2118/192663-MS","url":null,"abstract":"\u0000 During field inspection of Christmas (X-mas) trees in a giant oil offshore field in Abu Dhabi, a small subset of wells were reported to be severely corroded on X-mas tree studded outlets imposing high HSE risks due to possible loss of containment. A holistic analysis was conducted to identify corroded X-mas trees, establish the root-cause of corrosion and recommend a remedial action plan to control future corrosion damage and reduce HSE risk exposure.\u0000 Advanced modeling tools and lab tests were used to analyze the flow behavior and field samples, respectively. Advanced modeling was performed to analyze inorganic scale potential, identify flow regimes and calculate corrosion rates in the X-mas trees to correlate with operating conditions. Solid samples from X-mas trees were analyzed using advanced microscopy techniques to identify the elemental composition and phases. Water samples were also analyzed to check bacteria content. Available data on historical operating conditions, modeling and lab analysis results were segregated into in-favor and against factors for each of the mechanisms to identify the potential root-cause of corrosion. Modeling results were used in conjunction with actual field data such as corrosion feature morphology, historical operating conditions, etc. to evaluate corrosion damage. Based on corrosion feature morphology, wells were categorized into different groups to compare the flow behavior and operating conditions with observed corrosion patterns.\u0000 A thorough analysis of corrosion feature morphology and operating conditions identified flow-induced localized corrosion (FILC) as the root-cause of corrosion in severely corroded X-mas trees. X-mas tree design, fluid properties and operating parameters such as well head pressure (WHP), wellhead temperature (WHT) and flow rate were found to be key contributing factors of accelerated corrosion. Results of computational fluid dynamics (CFD) modeling showed that the horizontal section of X-mas tree is exposed to higher turbulence, water wetting and transient gas bubble formation/collapse phenomena than the vertical section due to changes in flow direction and gravity effects. Several mitigation strategies were implemented to control corrosion in the X-mas tree flange area, and reduce likelihood of leakage through the X-mas tree flange. Findings from this work led to development of an Excel based tool which can be used to assess and predict the corrosion risks to X-tree based on operating conditions.","PeriodicalId":11014,"journal":{"name":"Day 1 Mon, November 12, 2018","volume":"48 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82643891","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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