During the hydraulic fracturing process, the created rough fracture surface and fracturing fluids with high viscosity greatly challenge proppants placement in the thin aperture of fractures. Thus, it is essential to detailly investigate the effect of surface roughness on the proppant distribution. In addition, the multiphase flow in the rough nanoscale microfractures in the variety of orientations have not been cleared. Taking all of these into consideration; rock grain geometries, packing mechanisms, the presence of clay content, and in-situ stress field will be affected and will affect the presence of the microcracks, and consequently control the permeability and porosity of the sedimentary rock. In the failed rock after fracturing work, a processed zone where the pre-existing natural fractures get activated, and induced microcracks including intergranular and intragranular grain boundaries are brought to connect to the main fracture. Hence, the rock grain and pore size distributions at fracture processed zone are altered. This, in turn, controls the fluid transport in the rocks. Our novel approach incorporates the image analysis software (ImageJ) by organizing desired image processing codes to study the critical features of the post-fracturing core sample, including main fracture roughness, mechanical rock properties, crack density, grain, and pore size distributions. Tennessee sandstone was undergone the hydraulic fracturing test and polished on a cross-section perpendicular to the main fracture. This cross-section was recorded by the high-resolution SEM images after ion-milling. Corresponding grain size and pore size distributions are studied at each representative location with respect to its distance to the main fracture to probe alterations of the fracturing process from the core sample original state. The results of grain size and pore size distributions are compared. The discussions of their alterations mechanisms and their effects on the rock porosity and permeability are analyzed. We find that the roughness presence of fractures strongly increases conduits open to fluid flow. In addition, our developed image processing code perfectly captured the rock grains with the promising precision. Further, we are able to observe the grain size deduction due to the incremental intragranular grain boundaries while intergranular grain boundaries are still majorities outside the fracture processed zone (FPZ). Grain size renders a lognormal distribution at each representative location and coincides with the permeability distribution of most reservoir rocks. Grain size averages also match the literature values with reasonable uncertainties (20%). The pore size distribution and its average value vary spatially. Results from this study kindle the insights of the heterogeneity of the fractured formation with proper petrophysics parameters quantitatively. We also found that the aspect ratio from 2D image analysis does not reflect the significance in
{"title":"Quantification of Fracture Roughness and its Effects on the Grain and Pore Size Distribution of the Fractured Rock Using Image Analysis Technique","authors":"Yiwen Gong, Ilham El-monier","doi":"10.2118/193134-MS","DOIUrl":"https://doi.org/10.2118/193134-MS","url":null,"abstract":"\u0000 During the hydraulic fracturing process, the created rough fracture surface and fracturing fluids with high viscosity greatly challenge proppants placement in the thin aperture of fractures. Thus, it is essential to detailly investigate the effect of surface roughness on the proppant distribution. In addition, the multiphase flow in the rough nanoscale microfractures in the variety of orientations have not been cleared. Taking all of these into consideration; rock grain geometries, packing mechanisms, the presence of clay content, and in-situ stress field will be affected and will affect the presence of the microcracks, and consequently control the permeability and porosity of the sedimentary rock. In the failed rock after fracturing work, a processed zone where the pre-existing natural fractures get activated, and induced microcracks including intergranular and intragranular grain boundaries are brought to connect to the main fracture. Hence, the rock grain and pore size distributions at fracture processed zone are altered. This, in turn, controls the fluid transport in the rocks.\u0000 Our novel approach incorporates the image analysis software (ImageJ) by organizing desired image processing codes to study the critical features of the post-fracturing core sample, including main fracture roughness, mechanical rock properties, crack density, grain, and pore size distributions. Tennessee sandstone was undergone the hydraulic fracturing test and polished on a cross-section perpendicular to the main fracture. This cross-section was recorded by the high-resolution SEM images after ion-milling. Corresponding grain size and pore size distributions are studied at each representative location with respect to its distance to the main fracture to probe alterations of the fracturing process from the core sample original state. The results of grain size and pore size distributions are compared. The discussions of their alterations mechanisms and their effects on the rock porosity and permeability are analyzed.\u0000 We find that the roughness presence of fractures strongly increases conduits open to fluid flow. In addition, our developed image processing code perfectly captured the rock grains with the promising precision. Further, we are able to observe the grain size deduction due to the incremental intragranular grain boundaries while intergranular grain boundaries are still majorities outside the fracture processed zone (FPZ). Grain size renders a lognormal distribution at each representative location and coincides with the permeability distribution of most reservoir rocks. Grain size averages also match the literature values with reasonable uncertainties (20%). The pore size distribution and its average value vary spatially. Results from this study kindle the insights of the heterogeneity of the fractured formation with proper petrophysics parameters quantitatively. We also found that the aspect ratio from 2D image analysis does not reflect the significance in ","PeriodicalId":11079,"journal":{"name":"Day 4 Thu, November 15, 2018","volume":"79 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83910742","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}
Tossapol Tongkum, Ian P. McManus, Feras Abu-Jafar, Viraphon Thanasarnpisut, Jorge Andres Vargas Bermea, Kingkarn Kaewpraphan, P. Wuttikamonchai
Lost circulation, while cementing, compromises the objectives of cementing an oil or gas well. Losses encountered during cementingcan cause a weak casing shoe, poor zonal isolation, early water breakthrough for an oil producer, as well as increasing the possibility of costly intervention work. Execution of primary cementing operations can be subject to unplanned circumstances; when a slurry is being pumped or displaced and losses are recorded, in most circumstances the operation switches to damage limitation by slowing down the pumping rate. The Nong Yao field (Figure 1)is characterized with an interbedded unconsolidated sand / clay lithology within a highly compartmentalized structure, and as such, well construction operations have encountered unpredictable lost circulation during 7-in. casing cementation (but rarely during the drilling phase). Over 60% of the wells recorded losses during 7-in. cementing; it became evident that a proper loss mitigation plan was necessary to combat lost circulation and improve the probability of successful cementation execution. Although the primary objective is to achieve zonal isolation, equally as important for Nong Yao drilling operations are provision of annulus barriers, slurry compressive strength development, "gas tight" qualities, optimum slurry Thickening Time (TT) to allow for safe batch drilling operations. Figure 1 Nong Yao field localization To overcome the challenges, an "out of the box" approach was essentialwhich yielded two innovative solutions: i) a combination of advanced lightweight cementwith engineered reticular fiber (ERF) systems, which allows safer placement of the cement in the annulus, while minimizing the potential losses; ii) a combination of several lost circulation materials (LCM) in an optimized ratio in an engineered fiber-basedlost circulation weighted spacer package, which has an additional function of preventing and mitigating risk of losses during cementing. This approach was intended to reinforce the loss zones by using the four-step methodology; disperse, bridge, plug and sustain. The severity of lost circulation while cementing was significantly reduced without compromising the abovementioned objectives. This paper will discuss the successful implementation of the new approach solution by integrating different technologies to overcome the challenges of unpredictable losses during cementation. Two case histories from numerous jobs will be discussed with cement post-job evaluation via playback simulations and standard cement bond logs, which validates that the new approach increases the chance of achieving well objectives. Consequently, the risk of unplanned (UNP) operations and costly remedial operations are substantially reduced.
{"title":"Combat Unpredictable Losses during Casing Cementation in a Compartmentalized Structure, Nong Yao Field, Gulf of Thailand","authors":"Tossapol Tongkum, Ian P. McManus, Feras Abu-Jafar, Viraphon Thanasarnpisut, Jorge Andres Vargas Bermea, Kingkarn Kaewpraphan, P. Wuttikamonchai","doi":"10.2118/192906-ms","DOIUrl":"https://doi.org/10.2118/192906-ms","url":null,"abstract":"\u0000 Lost circulation, while cementing, compromises the objectives of cementing an oil or gas well. Losses encountered during cementingcan cause a weak casing shoe, poor zonal isolation, early water breakthrough for an oil producer, as well as increasing the possibility of costly intervention work. Execution of primary cementing operations can be subject to unplanned circumstances; when a slurry is being pumped or displaced and losses are recorded, in most circumstances the operation switches to damage limitation by slowing down the pumping rate.\u0000 The Nong Yao field (Figure 1)is characterized with an interbedded unconsolidated sand / clay lithology within a highly compartmentalized structure, and as such, well construction operations have encountered unpredictable lost circulation during 7-in. casing cementation (but rarely during the drilling phase). Over 60% of the wells recorded losses during 7-in. cementing; it became evident that a proper loss mitigation plan was necessary to combat lost circulation and improve the probability of successful cementation execution. Although the primary objective is to achieve zonal isolation, equally as important for Nong Yao drilling operations are provision of annulus barriers, slurry compressive strength development, \"gas tight\" qualities, optimum slurry Thickening Time (TT) to allow for safe batch drilling operations.\u0000 Figure 1 Nong Yao field localization\u0000 To overcome the challenges, an \"out of the box\" approach was essentialwhich yielded two innovative solutions: i) a combination of advanced lightweight cementwith engineered reticular fiber (ERF) systems, which allows safer placement of the cement in the annulus, while minimizing the potential losses; ii) a combination of several lost circulation materials (LCM) in an optimized ratio in an engineered fiber-basedlost circulation weighted spacer package, which has an additional function of preventing and mitigating risk of losses during cementing. This approach was intended to reinforce the loss zones by using the four-step methodology; disperse, bridge, plug and sustain. The severity of lost circulation while cementing was significantly reduced without compromising the abovementioned objectives.\u0000 This paper will discuss the successful implementation of the new approach solution by integrating different technologies to overcome the challenges of unpredictable losses during cementation. Two case histories from numerous jobs will be discussed with cement post-job evaluation via playback simulations and standard cement bond logs, which validates that the new approach increases the chance of achieving well objectives. Consequently, the risk of unplanned (UNP) operations and costly remedial operations are substantially reduced.","PeriodicalId":11079,"journal":{"name":"Day 4 Thu, November 15, 2018","volume":"39 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"81090768","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. Hadhrami, A. Riyami, Ralf Schulz, A. Moiseenkov, F. Khayrutdinov, Dmitrii Smirnov, Nawal Al Kindi
Field "A" produces from a mixed-wet formation comprising of fine grained silicilite. The field is a sour light tight oil reservoir with permeability range from 0.001 – 0.1 mD, the only way to flow the existing vertical wells is through hydraulic fracs. Historically the wells have been fracced using water based frac fluids, which have caused severe negative consequences related to well integrity and reduced productivity. With a recovery factor of <1% after 15 years of production, the main challenge and objective lies in enhancing productivity and unlocking the huge volumes of this reservoir through optimizing the field development concept, completion, frac design and execution. A study was conducted with a recommendation to develop the field by drilling slanted wells with ~10 – 15 frac stages. The frac design in itself is unconventional or hybrid where the targeted frac half length is 5x more than the existing conventional ones. The use of oil based frac fluid instead of water is an opportunity actively pursued to enhance productivity and eliminate issues related to scale and corrosion that in the past have resulted in a loss of production. Findings of the study have clearly indicated that developing the field with several slanted multi frac wells is economically attractive; with an increase in Net Present Value (NPV) by ~60% and decrease in Unit Technical Cost (UTC) by ~30% compared to developing the field conventionally with vertical wells.
{"title":"Roadmap to Unlock Light, Tight and Highly Laminated Oil Resources in South Oman","authors":"A. Hadhrami, A. Riyami, Ralf Schulz, A. Moiseenkov, F. Khayrutdinov, Dmitrii Smirnov, Nawal Al Kindi","doi":"10.2118/192669-MS","DOIUrl":"https://doi.org/10.2118/192669-MS","url":null,"abstract":"\u0000 Field \"A\" produces from a mixed-wet formation comprising of fine grained silicilite. The field is a sour light tight oil reservoir with permeability range from 0.001 – 0.1 mD, the only way to flow the existing vertical wells is through hydraulic fracs. Historically the wells have been fracced using water based frac fluids, which have caused severe negative consequences related to well integrity and reduced productivity. With a recovery factor of <1% after 15 years of production, the main challenge and objective lies in enhancing productivity and unlocking the huge volumes of this reservoir through optimizing the field development concept, completion, frac design and execution.\u0000 A study was conducted with a recommendation to develop the field by drilling slanted wells with ~10 – 15 frac stages. The frac design in itself is unconventional or hybrid where the targeted frac half length is 5x more than the existing conventional ones. The use of oil based frac fluid instead of water is an opportunity actively pursued to enhance productivity and eliminate issues related to scale and corrosion that in the past have resulted in a loss of production.\u0000 Findings of the study have clearly indicated that developing the field with several slanted multi frac wells is economically attractive; with an increase in Net Present Value (NPV) by ~60% and decrease in Unit Technical Cost (UTC) by ~30% compared to developing the field conventionally with vertical wells.","PeriodicalId":11079,"journal":{"name":"Day 4 Thu, November 15, 2018","volume":"84 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82068246","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}
BP is a joint venture partner in GUPCO, which operates in the Gulf of Suez, Egypt. The asset is over 50 years old and has a large operational foot print. This includes 3 onshore process facilities handling over 450,000 barrels of fluid per day from over 100 offshore structures and 200 pipelines. The field is supported by gas lift and water injection from two onshore facilities. The asset presents a challenge from an integrity perspective, namely corrosion and production chemistry threats. These are managed through an inspection program and anomaly management process. This case study presents how our asset integrity is managed and forward plan for improvement. The important relationship with the risk management process is highlighted.
{"title":"A Case Study from a 53 Year Old Asset - The Importance of Integrity and Risk Management for a Mature Asset","authors":"A. Jadoon","doi":"10.2118/193271-MS","DOIUrl":"https://doi.org/10.2118/193271-MS","url":null,"abstract":"\u0000 BP is a joint venture partner in GUPCO, which operates in the Gulf of Suez, Egypt. The asset is over 50 years old and has a large operational foot print. This includes 3 onshore process facilities handling over 450,000 barrels of fluid per day from over 100 offshore structures and 200 pipelines. The field is supported by gas lift and water injection from two onshore facilities.\u0000 The asset presents a challenge from an integrity perspective, namely corrosion and production chemistry threats. These are managed through an inspection program and anomaly management process.\u0000 This case study presents how our asset integrity is managed and forward plan for improvement. The important relationship with the risk management process is highlighted.","PeriodicalId":11079,"journal":{"name":"Day 4 Thu, November 15, 2018","volume":"31 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77368793","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 oil and gas industry has advanced over time in terms of seismic data acquisition. From conventional data acquisition to full/wide/multi-azimuth broadband data, there is an abundance of subsurface information aimed mainly at enhancing structural resolution, for improved prospect definition. Conventional seismic imaging tends towards the higher amplitude specular/continuous part of the seismic dataset for generating reflection events. During this process amplitudes or energy related to small scale features and faults can be contaminated, therefore in order to capture that information, it is essential to preserve the wavefield while imaging.
{"title":"Improved Imaging for Fault and Fracture Characterization: Southwest Onshore Abu Dhabi Case Study","authors":"J. Vargas, K. Shaukat, A. Elila, Pankaj Kumar","doi":"10.2118/192911-MS","DOIUrl":"https://doi.org/10.2118/192911-MS","url":null,"abstract":"\u0000 The oil and gas industry has advanced over time in terms of seismic data acquisition. From conventional data acquisition to full/wide/multi-azimuth broadband data, there is an abundance of subsurface information aimed mainly at enhancing structural resolution, for improved prospect definition. Conventional seismic imaging tends towards the higher amplitude specular/continuous part of the seismic dataset for generating reflection events. During this process amplitudes or energy related to small scale features and faults can be contaminated, therefore in order to capture that information, it is essential to preserve the wavefield while imaging.","PeriodicalId":11079,"journal":{"name":"Day 4 Thu, November 15, 2018","volume":"173 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77994048","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}
Harindranath Nambakkam, Eisa Al Jenaibi, S. Sajjad, Farah Sayegh
Comprehensive Energy studies entices in identifying potential energy savings in gas processing industry. The approach is to study, measure, analyze and quantify: Current energy situations with regards to processes and equipment operations;Sources or areas of energy losses in processes and equipment;Productive use of waste heat/energy;Alternative (cost-effective) energy substitutes;Modalities for augmenting energy losses and energy wastage in processes and plant equipmentMeasures which do not require large investments, but can lead to 8 to 10 percent savings in energy consumption. The Comprehensive Energy study has resulted in the identification of 31 potential energy saving opportunities, which could allow the company to achieve expected savings of up to 20%. Out of thirty one savings opportunities, seven were identified as potential quick wins with 10% saving potential, eight opportunities would require further analysis and investigation and sixteen opportunities were kept in abeyance due to economic factors. Quick wins, such as: Review of Advanced Process Control (APC), Sniffer Valve Leakage Survey, Plant wide control tuning, Efficiency check on LP and Residue gas Compressors, HP Feed gas discharge pressure control and Propane compressors Desuper heater Fan Controls which contributed to 10% energy savings were identified during the study. Payback periods are very attractive, in the range of 3 months, for these quick wins.
{"title":"Take a Closer Look to Maximize Energy Savings","authors":"Harindranath Nambakkam, Eisa Al Jenaibi, S. Sajjad, Farah Sayegh","doi":"10.2118/193255-MS","DOIUrl":"https://doi.org/10.2118/193255-MS","url":null,"abstract":"\u0000 Comprehensive Energy studies entices in identifying potential energy savings in gas processing industry.\u0000 The approach is to study, measure, analyze and quantify: Current energy situations with regards to processes and equipment operations;Sources or areas of energy losses in processes and equipment;Productive use of waste heat/energy;Alternative (cost-effective) energy substitutes;Modalities for augmenting energy losses and energy wastage in processes and plant equipmentMeasures which do not require large investments, but can lead to 8 to 10 percent savings in energy consumption.\u0000 The Comprehensive Energy study has resulted in the identification of 31 potential energy saving opportunities, which could allow the company to achieve expected savings of up to 20%. Out of thirty one savings opportunities, seven were identified as potential quick wins with 10% saving potential, eight opportunities would require further analysis and investigation and sixteen opportunities were kept in abeyance due to economic factors. Quick wins, such as: Review of Advanced Process Control (APC), Sniffer Valve Leakage Survey, Plant wide control tuning, Efficiency check on LP and Residue gas Compressors, HP Feed gas discharge pressure control and Propane compressors Desuper heater Fan Controls which contributed to 10% energy savings were identified during the study. Payback periods are very attractive, in the range of 3 months, for these quick wins.","PeriodicalId":11079,"journal":{"name":"Day 4 Thu, November 15, 2018","volume":"29 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"73465573","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 addresses the need and challenges associated with the energy harvesting methods in the downhole multilateral openhole horizontal well environment. The need for downhole energy harvesting is discussed and the functional requirements are established. Different means of energy harvesting that are available in either or both flowing and shut-in conditions are presented and the possibility of using them in the downhole horizontal wells for long-term monitoring and control systems is evaluated.
{"title":"Energy Harvesting for Downhole Applications in Open-hole Multilaterals","authors":"M. Arsalan, T. J. Ahmad, Abubaker Saeed","doi":"10.2118/192970-MS","DOIUrl":"https://doi.org/10.2118/192970-MS","url":null,"abstract":"\u0000 This paper addresses the need and challenges associated with the energy harvesting methods in the downhole multilateral openhole horizontal well environment. The need for downhole energy harvesting is discussed and the functional requirements are established. Different means of energy harvesting that are available in either or both flowing and shut-in conditions are presented and the possibility of using them in the downhole horizontal wells for long-term monitoring and control systems is evaluated.","PeriodicalId":11079,"journal":{"name":"Day 4 Thu, November 15, 2018","volume":"17 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78902857","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}
Kamaljit Singh, Raju Paul, F. Kamal, Ousama Takeiddine
Use of GIS to handle bulk power distribution has now become popular in offshore facilities due to the inherent advantage of a compact design. This paper highlights the challenges faced during GIS (and associated items) design based on experience on recent offshore projects and recommendations are proposed for methodical approach. Handling of bulk power at Extra High Voltages poses numerous risks to both personnel as well as assets. This paper discusses the key design parameters, industry standards, interface requirements with transformers/subsea cables/platform structure and installation challenges. Design engineer must be familiar with industry codes so that all design requirements, including proper selection of GIS configuration, are considered from early stages of the project. Omissions or oversight in this regard can impact the whole project. Duration for design, procurement, installation and commissioning phases must be adequately accounted for. Specialist studies such as insulation coordination, very fast transient and touch potentials shall be carried out in addition to usual power system and arc flash studies. Special consideration must be given in case of ring configuration with regard to logic diagrams and differential protection based on multiple CT locations and interconnections. Requirement of voltage selection scheme requires extensive wiring for synchronization function. Relay & CT selection shall be made considering required protection functions, interface with remote location and communication interface with Electrical Control & Monitoring System. Interfaces with transformers and subsea cables shall be in strict compliance with industry standards such as IEC 62271-209 & 211. Requirement of additional surge arrestors shall be verified. GIS exerts large static and dynamic forces on platform steel structure. These are also sensitive to forces during platform lifting and transportation. Support structure suitably shall be designed to mitigate the same. This paper addresses concerns and interface requirements to be considered during design of GIS which will benefit the design engineers, Client personnel and Structural designers along with Project Management Team for safe and smooth execution. Note: Data / details used in this paper are typical for the GIS handled by our Company that may vary based on the makes, models and ratings of GIS.
{"title":"Design and Implementation Challenges for Extra High Voltage Gas Insulated Switchgear, Transformers and Subsea Cables at Offshore Platforms","authors":"Kamaljit Singh, Raju Paul, F. Kamal, Ousama Takeiddine","doi":"10.2118/193157-ms","DOIUrl":"https://doi.org/10.2118/193157-ms","url":null,"abstract":"\u0000 Use of GIS to handle bulk power distribution has now become popular in offshore facilities due to the inherent advantage of a compact design. This paper highlights the challenges faced during GIS (and associated items) design based on experience on recent offshore projects and recommendations are proposed for methodical approach.\u0000 Handling of bulk power at Extra High Voltages poses numerous risks to both personnel as well as assets. This paper discusses the key design parameters, industry standards, interface requirements with transformers/subsea cables/platform structure and installation challenges.\u0000 Design engineer must be familiar with industry codes so that all design requirements, including proper selection of GIS configuration, are considered from early stages of the project. Omissions or oversight in this regard can impact the whole project.\u0000 Duration for design, procurement, installation and commissioning phases must be adequately accounted for. Specialist studies such as insulation coordination, very fast transient and touch potentials shall be carried out in addition to usual power system and arc flash studies.\u0000 Special consideration must be given in case of ring configuration with regard to logic diagrams and differential protection based on multiple CT locations and interconnections. Requirement of voltage selection scheme requires extensive wiring for synchronization function. Relay & CT selection shall be made considering required protection functions, interface with remote location and communication interface with Electrical Control & Monitoring System.\u0000 Interfaces with transformers and subsea cables shall be in strict compliance with industry standards such as IEC 62271-209 & 211. Requirement of additional surge arrestors shall be verified.\u0000 GIS exerts large static and dynamic forces on platform steel structure. These are also sensitive to forces during platform lifting and transportation. Support structure suitably shall be designed to mitigate the same.\u0000 This paper addresses concerns and interface requirements to be considered during design of GIS which will benefit the design engineers, Client personnel and Structural designers along with Project Management Team for safe and smooth execution.\u0000 Note: Data / details used in this paper are typical for the GIS handled by our Company that may vary based on the makes, models and ratings of GIS.","PeriodicalId":11079,"journal":{"name":"Day 4 Thu, November 15, 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":"76819499","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}
Transform has over the last 30years set up several projects for treating oil contaminated water and sludge. Special attention has been to treat and recirculate wastewater from car, container and train wash. With this experience it was decided to test and acquire an EU Environmental Technology Verification. Result of this test is that the specific developed Rootzone soil filter can adapt and decompose oil contaminant. It is documented that the treated water can be recirculated or reused for irrigation or other purposes. Approval from EU was given on the 9th of January 2018, as the first and only approval by EU of treating oil contamination. This presentation is the first given since approval.
{"title":"Rootzone for Oil Treatment and Recirculation","authors":"Jørgen Løgstrup","doi":"10.2118/193240-ms","DOIUrl":"https://doi.org/10.2118/193240-ms","url":null,"abstract":"\u0000 Transform has over the last 30years set up several projects for treating oil contaminated water and sludge. Special attention has been to treat and recirculate wastewater from car, container and train wash. With this experience it was decided to test and acquire an EU Environmental Technology Verification. Result of this test is that the specific developed Rootzone soil filter can adapt and decompose oil contaminant. It is documented that the treated water can be recirculated or reused for irrigation or other purposes. Approval from EU was given on the 9th of January 2018, as the first and only approval by EU of treating oil contamination. This presentation is the first given since approval.","PeriodicalId":11079,"journal":{"name":"Day 4 Thu, November 15, 2018","volume":"77 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84057643","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 ∼18 km long 10" pipeline was installed by MCDERMOTT as part of a gas export modification development in the Gulf of Mexico. The pipeline was initiated with a 97 Te dual-hub PLEM at a water depth of 1535 m. The fast track nature of the project required the PLEM design and fabrication to be carried out in a short time in collaboration with the installation analysts to ensure installability. Initiation of the heavy PLEM at the end of a thin wall pipe in deep water posed considerable challenges in developing an installation methodology. After evaluation of all alternatives, employing an LCV to help with PLEM initiation in a flooded condition was deemed necessary. The LCV crane was deployed after PLEM reached a certain height over the seabed. A sequence of LCV and LV-NO105 movements, pipelay tower angle alteration, and pipe and LCV crane wire payout was followed to transfer the PLEM weight to the LCV crane and rotate it to horizontal. The rigging from a clump weight, which had been installed earlier as merely a contingency hold-back device, was then connected to the PLEM. A sequence of LCV movements, LV-NO105 movements, pipe and crane wire payout was followed to land the PLEM safely on the seabed. The crane wire was disconnected after laying a short length of pipeline on the seabed. The installation procedure was developed such that the sling between the contingency clump weight and PLEM remained slack. The PLEM weight was sufficient to provide the necessary horizontal holdback, after landing in the target box, for normal pipelay. The LCV crane operated in various modes (constant tension and active heave compensation) to ensure a smooth initiation process. Maintaining a smooth synchronization of activities shared between LCV and LV-NO105 was crucial to success of the project.
{"title":"Gulf of Mexico Gas Export Modification Pipeline Installation – A Two Vessel Solution for PLEM Initiation Without a Pile","authors":"M. Samimi, G. Aden, Richard Carl Guynn, R. Duffy","doi":"10.2118/192917-MS","DOIUrl":"https://doi.org/10.2118/192917-MS","url":null,"abstract":"\u0000 The ∼18 km long 10\" pipeline was installed by MCDERMOTT as part of a gas export modification development in the Gulf of Mexico. The pipeline was initiated with a 97 Te dual-hub PLEM at a water depth of 1535 m. The fast track nature of the project required the PLEM design and fabrication to be carried out in a short time in collaboration with the installation analysts to ensure installability. Initiation of the heavy PLEM at the end of a thin wall pipe in deep water posed considerable challenges in developing an installation methodology. After evaluation of all alternatives, employing an LCV to help with PLEM initiation in a flooded condition was deemed necessary. The LCV crane was deployed after PLEM reached a certain height over the seabed. A sequence of LCV and LV-NO105 movements, pipelay tower angle alteration, and pipe and LCV crane wire payout was followed to transfer the PLEM weight to the LCV crane and rotate it to horizontal. The rigging from a clump weight, which had been installed earlier as merely a contingency hold-back device, was then connected to the PLEM. A sequence of LCV movements, LV-NO105 movements, pipe and crane wire payout was followed to land the PLEM safely on the seabed. The crane wire was disconnected after laying a short length of pipeline on the seabed. The installation procedure was developed such that the sling between the contingency clump weight and PLEM remained slack. The PLEM weight was sufficient to provide the necessary horizontal holdback, after landing in the target box, for normal pipelay. The LCV crane operated in various modes (constant tension and active heave compensation) to ensure a smooth initiation process. Maintaining a smooth synchronization of activities shared between LCV and LV-NO105 was crucial to success of the project.","PeriodicalId":11079,"journal":{"name":"Day 4 Thu, November 15, 2018","volume":"484 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77783728","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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