Summary The dry-gas seal (DGS) is a critical integrity component of the centrifugal or screw compressor, providing shaft sealing and preventing uncontrolled escape of process gas from the casing. Failure of this component in the compressor can result in plant outage and considerable revenue loss to the operating company. The DGS relies on a very thin gas film that is formed between a stationary ring and a rotating ring. Pressurized and clean seal gas is introduced to work as the gas film, preventing leakage of the compressor casing gas. Minor seal-gas leakage from the gas seal is at low pressure, and is usually collected in an enclosed system for disposal (e.g., low-pressure or atmospheric flare). Failure of the DGS seal is often not caused by its intrinsic design issues, but rather by aspects peripheral to the seal. The need for pressurized seal gas necessitates the evaluation of possible sources of gas supply during normal operation and startup. Possible sources of supply evaluated in this study include high-pressure gas-export pipeline, multitrain arrangement to supply gas from the operating train to the standby train, and the use of gas boosters. Seal-gas cleanliness demands fine gas filtration as mandatory before gas entry to the seals. Because the seal gas undergoes different levels of pressure reduction within the seal, potential liquid (or condensation) and, in some cases, solid (hydrate) formation in the gas seals must be studied together with its mitigating measures in the design to avoid seal failure. The possible presence of other contaminants because of sour-gas components is addressed, along with suggested treatment methods. Other design considerations, such as reverse rotation, depressurization limitations, and reverse pressurization, are also addressed. Whether engineers are engaged in designing the gas-compression system or in troubleshooting the facilities operation, a clear understanding of these various aspects is important. This paper does not address the design of the DGS, which is proprietary to the manufacturer. On the basis of past experiences, this paper describes the various salient features and peripheral requirements of the DGS, and offers recommendations for interfacing with the compressor vendor from the process-system-design and -operation perspectives.
{"title":"Process-Design Considerations for a Compressor Dry-Gas Seal-System Interface","authors":"C. Leong, Sanjiv Goyal","doi":"10.2118/178912-PA","DOIUrl":"https://doi.org/10.2118/178912-PA","url":null,"abstract":"Summary The dry-gas seal (DGS) is a critical integrity component of the centrifugal or screw compressor, providing shaft sealing and preventing uncontrolled escape of process gas from the casing. Failure of this component in the compressor can result in plant outage and considerable revenue loss to the operating company. The DGS relies on a very thin gas film that is formed between a stationary ring and a rotating ring. Pressurized and clean seal gas is introduced to work as the gas film, preventing leakage of the compressor casing gas. Minor seal-gas leakage from the gas seal is at low pressure, and is usually collected in an enclosed system for disposal (e.g., low-pressure or atmospheric flare). Failure of the DGS seal is often not caused by its intrinsic design issues, but rather by aspects peripheral to the seal. The need for pressurized seal gas necessitates the evaluation of possible sources of gas supply during normal operation and startup. Possible sources of supply evaluated in this study include high-pressure gas-export pipeline, multitrain arrangement to supply gas from the operating train to the standby train, and the use of gas boosters. Seal-gas cleanliness demands fine gas filtration as mandatory before gas entry to the seals. Because the seal gas undergoes different levels of pressure reduction within the seal, potential liquid (or condensation) and, in some cases, solid (hydrate) formation in the gas seals must be studied together with its mitigating measures in the design to avoid seal failure. The possible presence of other contaminants because of sour-gas components is addressed, along with suggested treatment methods. Other design considerations, such as reverse rotation, depressurization limitations, and reverse pressurization, are also addressed. Whether engineers are engaged in designing the gas-compression system or in troubleshooting the facilities operation, a clear understanding of these various aspects is important. This paper does not address the design of the DGS, which is proprietary to the manufacturer. On the basis of past experiences, this paper describes the various salient features and peripheral requirements of the DGS, and offers recommendations for interfacing with the compressor vendor from the process-system-design and -operation perspectives.","PeriodicalId":19446,"journal":{"name":"Oil and gas facilities","volume":"40 1","pages":"72-76"},"PeriodicalIF":0.0,"publicationDate":"2015-12-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"76772946","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}
prediction of pig velocity, pig-generated slug volume, slug duration, backpressure increase in the pipeline, and process-plant upset. Control of these parameters is very difficult during bypass-pigging operations because of its transient nature. The fluid behavior through bypass holes, subsequent downstream flow regime, and the nature of turbulence are unknown. Transient modeling and simulation results of bypass pigging with help of the OLGA Dynamic Multiphase Flow Simulator (available from Schlumberger) do not match with actual field results. Wax blockage of bypass holes also leads to erroneous results. In this paper, efforts are made to develop empirical correlations to approximate various parameters on the basis of experimental results in comparison with simulation-model prediction. Later, an innovative bypass geometry/profile is proposed and designed, and experimental results are evaluated.
{"title":"Effectiveness of Bypass-Pigging Solutions in Multiphase-Flow Pipelines With Waxy Crude Oil: Evaluation and Innovative Solution","authors":"Sasidharan Adiyodi Kenoth, A. Matar, D. K. Gupta","doi":"10.2118/178424-PA","DOIUrl":"https://doi.org/10.2118/178424-PA","url":null,"abstract":"prediction of pig velocity, pig-generated slug volume, slug duration, backpressure increase in the pipeline, and process-plant upset. Control of these parameters is very difficult during bypass-pigging operations because of its transient nature. The fluid behavior through bypass holes, subsequent downstream flow regime, and the nature of turbulence are unknown. Transient modeling and simulation results of bypass pigging with help of the OLGA Dynamic Multiphase Flow Simulator (available from Schlumberger) do not match with actual field results. Wax blockage of bypass holes also leads to erroneous results. In this paper, efforts are made to develop empirical correlations to approximate various parameters on the basis of experimental results in comparison with simulation-model prediction. Later, an innovative bypass geometry/profile is proposed and designed, and experimental results are evaluated.","PeriodicalId":19446,"journal":{"name":"Oil and gas facilities","volume":"75 1","pages":"51-65"},"PeriodicalIF":0.0,"publicationDate":"2015-12-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83033959","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}
Steam Generation for Thermal EOR Three methods of steam generation have been considered (Fig. 1): • Fuel-fired once-through steam generator (Boiler) • Cogeneration (Cogen) with a power plant by use of a oncethrough heat-recovery steam generator • Solar steam generator (Solar) by use of concentrating solar power (CSP) The first method, Boiler, burns fuel directly to generate steam. Boilers have the most-flexible operations, but are most dependent on fuel costs. The second method uses the high-temperature flue gas from the gas turbine (GT) as “waste heat” to produce steam in a once-through heat-recovery steam generator (Cogen). Cogen steam production is linked to the power production of the GT. Operators sometimes add supplementary firing to the Cogen, called duct burners. The steam produced from duct burning has the advantage of rebalancing the electricity vs. thermal demand, but it is linked directly to fuel price. The third method, Solar, uses mirrors to concentrate the sun’s energy to generate steam. Three solar steam plants have been built: The 21Z in California (2011) and the Amal SSGP in Oman (2012) use enclosed-trough technology, and the Coalinga project in California (2011) uses tower technology. Coalinga ceased solar operations in 2014. In July 2015, a 6,000-tons-of-steam/D (1-GW) enclosed-trough solar plant (Miraah) was announced in Oman. Solar has the highest capital expenditure (Capex) of the methods considered, but consumes no fuel. The pros and cons of these three methods are summarized in Table 1.
{"title":"Economics Of Steam Generation For Thermal Enhanced Oil Recovery","authors":"M. Chaar, Milton Venetos, J. Dargin, D. Palmer","doi":"10.2118/172004-PA","DOIUrl":"https://doi.org/10.2118/172004-PA","url":null,"abstract":"Steam Generation for Thermal EOR Three methods of steam generation have been considered (Fig. 1): • Fuel-fired once-through steam generator (Boiler) • Cogeneration (Cogen) with a power plant by use of a oncethrough heat-recovery steam generator • Solar steam generator (Solar) by use of concentrating solar power (CSP) The first method, Boiler, burns fuel directly to generate steam. Boilers have the most-flexible operations, but are most dependent on fuel costs. The second method uses the high-temperature flue gas from the gas turbine (GT) as “waste heat” to produce steam in a once-through heat-recovery steam generator (Cogen). Cogen steam production is linked to the power production of the GT. Operators sometimes add supplementary firing to the Cogen, called duct burners. The steam produced from duct burning has the advantage of rebalancing the electricity vs. thermal demand, but it is linked directly to fuel price. The third method, Solar, uses mirrors to concentrate the sun’s energy to generate steam. Three solar steam plants have been built: The 21Z in California (2011) and the Amal SSGP in Oman (2012) use enclosed-trough technology, and the Coalinga project in California (2011) uses tower technology. Coalinga ceased solar operations in 2014. In July 2015, a 6,000-tons-of-steam/D (1-GW) enclosed-trough solar plant (Miraah) was announced in Oman. Solar has the highest capital expenditure (Capex) of the methods considered, but consumes no fuel. The pros and cons of these three methods are summarized in Table 1.","PeriodicalId":19446,"journal":{"name":"Oil and gas facilities","volume":"43 1","pages":"42-50"},"PeriodicalIF":0.0,"publicationDate":"2015-12-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88856475","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}
{"title":"The Savvy Separator Series: Part 4. The Ghosts of Separators Past, Present, and Future","authors":"Past Members, Present, R. Chin","doi":"10.2118/1215-0018-OGF","DOIUrl":"https://doi.org/10.2118/1215-0018-OGF","url":null,"abstract":"","PeriodicalId":19446,"journal":{"name":"Oil and gas facilities","volume":"86 1","pages":"18-23"},"PeriodicalIF":0.0,"publicationDate":"2015-12-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"81140626","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}
{"title":"Designing Efficient Facilities in Challenging Locations","authors":"S. Whitfield","doi":"10.2118/1215-0011-OGF","DOIUrl":"https://doi.org/10.2118/1215-0011-OGF","url":null,"abstract":"","PeriodicalId":19446,"journal":{"name":"Oil and gas facilities","volume":"34 1","pages":"11-17"},"PeriodicalIF":0.0,"publicationDate":"2015-12-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82132456","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}
Ed Grave, M. D. Olson, A. Menchaca, R. Westra, M. R. Akdim
Introduction Dehydration plays a fundamental role in the production and processing of crude oil. The removal of water from heavy crude is a challenge for many oil-processing facilities, even when only topside applications are considered (Moraes et al. 2013). It can also pose a big challenge for processing medium crudes, and in general for any highly emulsified hydrocarbon liquids, such as those obtained from high-pressure applications and enhanced-oil-recovery (EOR) processes. Besides using mechanical means to separate water from oil, other common methods of enhanced dehydration include heating, use of chemical demulsifiers, and electrostatic treatment (Silset 2008). Other possible techniques are pH adjustment, filtration, and membrane separation (Eow et al. 2001). Heat treatment can effectively destabilize water-in-oil (WIO) emulsions; however, it is also energy intensive and typically results in a larger system footprint. Capital and operational expenditure can be considerable in conventional applications (Pruneda et al. 2005), and the use of heat treatment is either economically unattractive or impractical in subsea, Arctic, remote, or marginal field applications. Further, the solubility of water in oil increases with temperature. As the oil cools during transportation, free water drops out in the pipeline, which could cause flow-assurance issues. Besides this, heat treatment causes volatile hydrocarbons to flash out of the liquid phase, which can result in appreciable volume shrinkage and API-gravity reduction in the heated crude oil (Manning and Thompson 1995). This means that there is a practical and economical limit in the amount of water that can be removed from crude oil through the use of heat treatment alone. For this reason, a combination of heat treatment and demulsifiers is by far the most-common method of enhanced dehydration because many crude-oil emulsions become unstable when treated with the right type and concentration of demulsifier (Arnold and Stewart 1998; Caird 2008; Kelland 2009) at high temperature. While chemical treatment requires a relatively lower capital investment and less energy than heat treatment, it can bear a considerable operating cost, and ensuring an uninterrupted supply of chemicals to the production site can be challenging. While the supply of chemicals to any production facility can be expensive and sensitive to changes in weather conditions, market availability, or political factors, the supply of chemicals to subsea, Arctic, remote, or marginal field applications is a far greater logistical and economical challenge. Electrostatic treatment can be effective at breaking WIO emulsions. It is also one of the most energy-efficient methods used for destabilization of WIO emulsions (Eow et al. 2001), and is considered an enabling technology for the subsea separation of produced water from heavy oil in deepwater developments (Euphemio et al. 2007). When it is used in combination with chemical and/or heat treat
{"title":"Performance Testing of an Inline Electrocoalescer Device With Medium and Heavy Crudes","authors":"Ed Grave, M. D. Olson, A. Menchaca, R. Westra, M. R. Akdim","doi":"10.2118/174090-PA","DOIUrl":"https://doi.org/10.2118/174090-PA","url":null,"abstract":"Introduction Dehydration plays a fundamental role in the production and processing of crude oil. The removal of water from heavy crude is a challenge for many oil-processing facilities, even when only topside applications are considered (Moraes et al. 2013). It can also pose a big challenge for processing medium crudes, and in general for any highly emulsified hydrocarbon liquids, such as those obtained from high-pressure applications and enhanced-oil-recovery (EOR) processes. Besides using mechanical means to separate water from oil, other common methods of enhanced dehydration include heating, use of chemical demulsifiers, and electrostatic treatment (Silset 2008). Other possible techniques are pH adjustment, filtration, and membrane separation (Eow et al. 2001). Heat treatment can effectively destabilize water-in-oil (WIO) emulsions; however, it is also energy intensive and typically results in a larger system footprint. Capital and operational expenditure can be considerable in conventional applications (Pruneda et al. 2005), and the use of heat treatment is either economically unattractive or impractical in subsea, Arctic, remote, or marginal field applications. Further, the solubility of water in oil increases with temperature. As the oil cools during transportation, free water drops out in the pipeline, which could cause flow-assurance issues. Besides this, heat treatment causes volatile hydrocarbons to flash out of the liquid phase, which can result in appreciable volume shrinkage and API-gravity reduction in the heated crude oil (Manning and Thompson 1995). This means that there is a practical and economical limit in the amount of water that can be removed from crude oil through the use of heat treatment alone. For this reason, a combination of heat treatment and demulsifiers is by far the most-common method of enhanced dehydration because many crude-oil emulsions become unstable when treated with the right type and concentration of demulsifier (Arnold and Stewart 1998; Caird 2008; Kelland 2009) at high temperature. While chemical treatment requires a relatively lower capital investment and less energy than heat treatment, it can bear a considerable operating cost, and ensuring an uninterrupted supply of chemicals to the production site can be challenging. While the supply of chemicals to any production facility can be expensive and sensitive to changes in weather conditions, market availability, or political factors, the supply of chemicals to subsea, Arctic, remote, or marginal field applications is a far greater logistical and economical challenge. Electrostatic treatment can be effective at breaking WIO emulsions. It is also one of the most energy-efficient methods used for destabilization of WIO emulsions (Eow et al. 2001), and is considered an enabling technology for the subsea separation of produced water from heavy oil in deepwater developments (Euphemio et al. 2007). When it is used in combination with chemical and/or heat treat","PeriodicalId":19446,"journal":{"name":"Oil and gas facilities","volume":"197 ","pages":"56-65"},"PeriodicalIF":0.0,"publicationDate":"2015-10-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"91466844","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. Reichl, Gernot Schneider, Torsten Schliepdiek, Oliver Reimuth
fossil-fueled power plants remain the backbone of power generation (IEA 2013b). To satisfy this demand, numerous new-builts are planned all around the world. Keeping the temperature-increase goal of 2°C for global warming in mind, this development calls for mature carbon-capture techniques that reduce the climate impact of fossil-fueled power stations. Among the most-advanced and -engineered solutions for carbon dioxide (CO2) capture are post-combustion absorption/desorption processes, usually with aqueous amine solutions as solvents (Blauwhoff et al. 1984; Kohl and Nielsen 1997; Rinker et al. 2000; da Silva and Svendsen 2004). The Technology Owner, as a modification, has developed the PostCapTM (post-combustion carbon-capture) process by use of an amino acid salt (AAS) dissolved in water as solvent. AASs are described by various authors as a promising alternative to conventional amines (e.g., Rochelle et al. 2001; van Holst et al. 2006; Abu Zhara 2009; Feron and Puxty 2011; Majchrowicz 2014). The advantages are that AASs are salts and are therefore nonvolatile, which eliminates the threat of inhalation and solvent loss through gas phase. Moreover, many AASs are naturally occurring substances that are nontoxic, nonexplosive, odorless, and biodegradable. This leads to exceptional benefits for the operability of AAS-based CO2-capture units. Capturing CO2 for climate-related reasons, however, is only one side of the story. The use of CO2 as a valuable product is one step forward. The yield from oil fields can be increased considerably by enhanced oil recovery (EOR), a tertiary method of injecting CO2 underground with high pressure and thus extracting oil. The oil/ CO2 mixture reaching ground level can be flashed off and separated by well-established technologies; the CO2 will be reinjected and will remain underground after a certain number of turnovers. Studies name a potential worldwide demand of 260 to 310 gigatons (Gt) of CO2 for EOR (Van Leeuwen 2011), which could even be extended up to 460 Gt by application to smaller oil fields (Godec 2011). The CO2 will be, finally, stored underground. The resulting oil yield is given in the studies to be approximately 880 to 1,050 billion bbl of oil (Van Leeuwen 2011) or even more than 1,500 billion bbl (Godec 2011). Near-term projections forecast an annual use of 124 megatons (Mt) of CO2 in the US only by 2020 (Wallace and Kuuskraa 2014). Aiming both at climate and economic benefits, Masdar has initiated the Abu Dhabi Carbon-Capture, -Usage, and -Storage Studies, with the objective to develop a carbon-capture network in Abu Dhabi capable of providing large reductions of CO2 emissions while providing CO2 for EOR purposes. Phase 1 of the project, the purification and transport of approximately 800,000 tons of CO2 annually emitted from a steelmaking process, has started construction and is planned to go into operation in 2016. As a further component for Masdar’s initiative, the Technology Owner and Masdar have
{"title":"Carbon Capture and Storage for Enhanced Oil Recovery: Integration and Optimization of a Post-Combustion CO 2 -Capture Facility at a Power Plant in Abu Dhabi","authors":"A. Reichl, Gernot Schneider, Torsten Schliepdiek, Oliver Reimuth","doi":"10.2118/171692-PA","DOIUrl":"https://doi.org/10.2118/171692-PA","url":null,"abstract":"fossil-fueled power plants remain the backbone of power generation (IEA 2013b). To satisfy this demand, numerous new-builts are planned all around the world. Keeping the temperature-increase goal of 2°C for global warming in mind, this development calls for mature carbon-capture techniques that reduce the climate impact of fossil-fueled power stations. Among the most-advanced and -engineered solutions for carbon dioxide (CO2) capture are post-combustion absorption/desorption processes, usually with aqueous amine solutions as solvents (Blauwhoff et al. 1984; Kohl and Nielsen 1997; Rinker et al. 2000; da Silva and Svendsen 2004). The Technology Owner, as a modification, has developed the PostCapTM (post-combustion carbon-capture) process by use of an amino acid salt (AAS) dissolved in water as solvent. AASs are described by various authors as a promising alternative to conventional amines (e.g., Rochelle et al. 2001; van Holst et al. 2006; Abu Zhara 2009; Feron and Puxty 2011; Majchrowicz 2014). The advantages are that AASs are salts and are therefore nonvolatile, which eliminates the threat of inhalation and solvent loss through gas phase. Moreover, many AASs are naturally occurring substances that are nontoxic, nonexplosive, odorless, and biodegradable. This leads to exceptional benefits for the operability of AAS-based CO2-capture units. Capturing CO2 for climate-related reasons, however, is only one side of the story. The use of CO2 as a valuable product is one step forward. The yield from oil fields can be increased considerably by enhanced oil recovery (EOR), a tertiary method of injecting CO2 underground with high pressure and thus extracting oil. The oil/ CO2 mixture reaching ground level can be flashed off and separated by well-established technologies; the CO2 will be reinjected and will remain underground after a certain number of turnovers. Studies name a potential worldwide demand of 260 to 310 gigatons (Gt) of CO2 for EOR (Van Leeuwen 2011), which could even be extended up to 460 Gt by application to smaller oil fields (Godec 2011). The CO2 will be, finally, stored underground. The resulting oil yield is given in the studies to be approximately 880 to 1,050 billion bbl of oil (Van Leeuwen 2011) or even more than 1,500 billion bbl (Godec 2011). Near-term projections forecast an annual use of 124 megatons (Mt) of CO2 in the US only by 2020 (Wallace and Kuuskraa 2014). Aiming both at climate and economic benefits, Masdar has initiated the Abu Dhabi Carbon-Capture, -Usage, and -Storage Studies, with the objective to develop a carbon-capture network in Abu Dhabi capable of providing large reductions of CO2 emissions while providing CO2 for EOR purposes. Phase 1 of the project, the purification and transport of approximately 800,000 tons of CO2 annually emitted from a steelmaking process, has started construction and is planned to go into operation in 2016. As a further component for Masdar’s initiative, the Technology Owner and Masdar have","PeriodicalId":19446,"journal":{"name":"Oil and gas facilities","volume":"10 1","pages":"37-46"},"PeriodicalIF":0.0,"publicationDate":"2015-10-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"80122388","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}
{"title":"Batata 2 Remote Well Pad: Executing Sustainable Development at a Sensitive Amazon Basin Area--Decommission and Abandonment","authors":"F. L. Benalcazar, S. Valdivieso","doi":"10.2118/173555-PA","DOIUrl":"https://doi.org/10.2118/173555-PA","url":null,"abstract":"","PeriodicalId":19446,"journal":{"name":"Oil and gas facilities","volume":"413 1","pages":"66-72"},"PeriodicalIF":0.0,"publicationDate":"2015-10-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"76494137","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}
{"title":"Solving Deepwater Challenges in a Low Price Environment","authors":"S. Whitfield","doi":"10.2118/1015-0010-OGF","DOIUrl":"https://doi.org/10.2118/1015-0010-OGF","url":null,"abstract":"","PeriodicalId":19446,"journal":{"name":"Oil and gas facilities","volume":"126 1","pages":"10-15"},"PeriodicalIF":0.0,"publicationDate":"2015-10-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89613850","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}
{"title":"Managing Nontechnical Risk in Offshore Projects","authors":"S. Whitfield","doi":"10.2218/1015-0016-OGF","DOIUrl":"https://doi.org/10.2218/1015-0016-OGF","url":null,"abstract":"","PeriodicalId":19446,"journal":{"name":"Oil and gas facilities","volume":"68 1","pages":"16-21"},"PeriodicalIF":0.0,"publicationDate":"2015-10-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79879028","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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