R. Chin, V. V. Asperen, J. Riesenberg, Graham McVinnie
{"title":"The Savvy Separator Series: Part 3. Scrubber Debottlenecking","authors":"R. Chin, V. V. Asperen, J. Riesenberg, Graham McVinnie","doi":"10.2118/1015-0022-OGF","DOIUrl":"https://doi.org/10.2118/1015-0022-OGF","url":null,"abstract":"","PeriodicalId":19446,"journal":{"name":"Oil and gas facilities","volume":"53 1","pages":"22-27"},"PeriodicalIF":0.0,"publicationDate":"2015-10-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83976766","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}
Can the price of oil fall to US 20/bbl? In a word: No. As I pondered what to write about for my column, the media reported that Goldman Sachs claimed that oil could drop to USD 20/bbl. Scary stuff. But when I read the article, the global investment firm said that oil price is volatile and could possibly fall to USD 20, and if it did, the price would quickly rebound. The oil price cannot be USD 20 for any long period because we cannot produce enough oil to feed the world at that price. But if the price of oil is based on supply and demand, how could it fall to USD 20 at any point in time? I am not an expert on the prediction of the future price of oil and certainly not on the dynamics of short-term price movements, so I visited the Internet.
{"title":"Oil at USD 20 per Barrel: Can It Be?","authors":"H. Duhon","doi":"10.2118/1015-0004-OGF","DOIUrl":"https://doi.org/10.2118/1015-0004-OGF","url":null,"abstract":"Can the price of oil fall to US 20/bbl? In a word: No. As I pondered what to write about for my column, the media reported that Goldman Sachs claimed that oil could drop to USD 20/bbl. Scary stuff. But when I read the article, the global investment firm said that oil price is volatile and could possibly fall to USD 20, and if it did, the price would quickly rebound. The oil price cannot be USD 20 for any long period because we cannot produce enough oil to feed the world at that price. But if the price of oil is based on supply and demand, how could it fall to USD 20 at any point in time? I am not an expert on the prediction of the future price of oil and certainly not on the dynamics of short-term price movements, so I visited the Internet.","PeriodicalId":19446,"journal":{"name":"Oil and gas facilities","volume":"2 1","pages":"4-5"},"PeriodicalIF":0.0,"publicationDate":"2015-10-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"74436827","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}
S. Truchon, L. Brzuzy, Deborah Fawcett, M. Fonseca
{"title":"Innovative Assessments for Selecting Offshore-Platform-Decommissioning Alternatives","authors":"S. Truchon, L. Brzuzy, Deborah Fawcett, M. Fonseca","doi":"10.2118/173519-PA","DOIUrl":"https://doi.org/10.2118/173519-PA","url":null,"abstract":"","PeriodicalId":19446,"journal":{"name":"Oil and gas facilities","volume":"80 1","pages":"47-55"},"PeriodicalIF":0.0,"publicationDate":"2015-10-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"75352297","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":"Water Management for Enhanced Oil Recovery Projects","authors":"S. Whitfield","doi":"10.2118/0815-0014-OGF","DOIUrl":"https://doi.org/10.2118/0815-0014-OGF","url":null,"abstract":"","PeriodicalId":19446,"journal":{"name":"Oil and gas facilities","volume":"47 1","pages":"14-19"},"PeriodicalIF":0.0,"publicationDate":"2015-08-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"74281555","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}
C. Sarica, Ge Yuan, W. Shang, E. Pereyra, G. Kouba
nation angle for relatively low gasand liquid-flow rates. Sarica et al. (2014) divided the severe-slugging cycle into four steps, as described in Fig. 1. The classic pipe geometry for severe slugging is a slightly downward section upstream of a riser. In Step 1, gas and liquid velocities are low enough to allow stratified flow in the downward-sloping pipe section followed by liquid bridging and accumulation at the bottom of the riser. The hydrostatic pressure of the accumulated liquid initially increases equal to or faster than the buildup of gas pressure upstream of the liquid slug (Step 2). When the gas pressure eventually exceeds the hydrostatic head of the liquid slug, the gas will begin to push the liquid slug out of the riser and start to penetrate the riser (Step 3). The pressure in the gas reduces as the liquid is removed from the riser and the gas expands, increasing the velocities in the riser. After most of the liquid and gas exit the riser, the velocity of the gas is no longer high enough to sweep the liquid upward. Liquid film not swept from the riser starts falling back down the riser (Step 4), and the accumulation of liquid starts again. Severe slugging will cause periods of no liquid and gas production in the separator followed by very high liquidand gas-flow rates. The resulting large pressure and flow-rate fluctuations are highly undesirable. Several mitigation techniques are proposed in the literature. A thorough summary of these techniques can be found in Sarica and Tengesdal (2000). Surfactant application and gas lift are typically considered to be separate methods. The combination of both can provide a better mitigation of severe slugging by complementing one another. As mentioned by Sarica and Tengesdal (2000), Yocum (1973) was the first to identify multiple severe-slugging-mitigation techniques. These are reduction of the line diameter, splitting the flow into dual or multiple streams, gas injection into the riser, the use of mixing devices at the riser base, choking, and backpressure increase. Here, we will classify severe-slugging-mitigation methods into three groups: passive, active, and hybrids (combination of both passiveand active-mitigation methods). Passive methods require energy from the system; the most relevant are given as follows: 1. Choking: One of the most common mitigation techniques is the installation of a choke valve at the top of the riser. By choking the flow, the riser operational pressure changes, stabilizing the flow. Several publications regarding choking exist in the literature, as detailed in Sarica and Tengesdal (2000). Unfortunately, because of the backpressure created by choking, production is affected, and a minimum amount of energy is required for this method to be successful. This technique can be combined with a feedback control to regulate the largest choke opening that will stabilize the flow. 2. Backpressure increase: This method requires significant pressure increases at the separator
{"title":"Feasibility and Evaluation of Surfactants and Gas Lift in Combination as a Severe-Slugging-Suppression Method","authors":"C. Sarica, Ge Yuan, W. Shang, E. Pereyra, G. Kouba","doi":"10.2118/170595-PA","DOIUrl":"https://doi.org/10.2118/170595-PA","url":null,"abstract":"nation angle for relatively low gasand liquid-flow rates. Sarica et al. (2014) divided the severe-slugging cycle into four steps, as described in Fig. 1. The classic pipe geometry for severe slugging is a slightly downward section upstream of a riser. In Step 1, gas and liquid velocities are low enough to allow stratified flow in the downward-sloping pipe section followed by liquid bridging and accumulation at the bottom of the riser. The hydrostatic pressure of the accumulated liquid initially increases equal to or faster than the buildup of gas pressure upstream of the liquid slug (Step 2). When the gas pressure eventually exceeds the hydrostatic head of the liquid slug, the gas will begin to push the liquid slug out of the riser and start to penetrate the riser (Step 3). The pressure in the gas reduces as the liquid is removed from the riser and the gas expands, increasing the velocities in the riser. After most of the liquid and gas exit the riser, the velocity of the gas is no longer high enough to sweep the liquid upward. Liquid film not swept from the riser starts falling back down the riser (Step 4), and the accumulation of liquid starts again. Severe slugging will cause periods of no liquid and gas production in the separator followed by very high liquidand gas-flow rates. The resulting large pressure and flow-rate fluctuations are highly undesirable. Several mitigation techniques are proposed in the literature. A thorough summary of these techniques can be found in Sarica and Tengesdal (2000). Surfactant application and gas lift are typically considered to be separate methods. The combination of both can provide a better mitigation of severe slugging by complementing one another. As mentioned by Sarica and Tengesdal (2000), Yocum (1973) was the first to identify multiple severe-slugging-mitigation techniques. These are reduction of the line diameter, splitting the flow into dual or multiple streams, gas injection into the riser, the use of mixing devices at the riser base, choking, and backpressure increase. Here, we will classify severe-slugging-mitigation methods into three groups: passive, active, and hybrids (combination of both passiveand active-mitigation methods). Passive methods require energy from the system; the most relevant are given as follows: 1. Choking: One of the most common mitigation techniques is the installation of a choke valve at the top of the riser. By choking the flow, the riser operational pressure changes, stabilizing the flow. Several publications regarding choking exist in the literature, as detailed in Sarica and Tengesdal (2000). Unfortunately, because of the backpressure created by choking, production is affected, and a minimum amount of energy is required for this method to be successful. This technique can be combined with a feedback control to regulate the largest choke opening that will stabilize the flow. 2. Backpressure increase: This method requires significant pressure increases at the separator ","PeriodicalId":19446,"journal":{"name":"Oil and gas facilities","volume":"39 1","pages":"78-87"},"PeriodicalIF":0.0,"publicationDate":"2015-08-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"81294389","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}
environment compared with onshore liquefied-natural-gas plants or other floating offshore installations. As a consequence, the explosion risk is expected to be higher than that for some other offshore floating facilities. Because of the general evolution of design practices, alternative approaches such as performance with risk-based design can be used. The performance-based approach relies on the explicit definition of the safety objectives and functional requirements (e.g., performance standards). The design process focuses on the objectives, not the means to reach them. Because it is based on the definition of realistic explosion scenarios, which could be deterministic (e.g., scenario-based approach) or probabilistic (risk-based), the design process requires more resources (skills, computational tools) that allow the contractor to demonstrate the compliance of the solution with the safety objectives. This could be a challenge because any design solution is specific to the installation and requires the acceptance of the operator, the local authority, and the classification society. All participants should ensure that they understand, agree with, and are aware of the limitation of the proposed design solution, to avoid further rework. During the entire engineering process, different barriers are investigated to reduce the risk of potential losses (people, assets) from the potential explosion hazards to as low as reasonably practicable, as shown in Fig. 1. Even if inherent safety is a key driver during the design phase of the facility, additional risk-reduction measures that combine prevention, detection, control, and mitigation are usually implemented. Emergency response (e.g., rescue of people) remains the ultimate option. Many of these barriers should be designed or verified against major-accident events to fulfill their function during and after the initial explosion event. This paper focuses on the design process and associated challenges of such barriers because they require an integrated multidisciplinary approach that combines the expertise of safety, structural, and equipment engineers.
{"title":"Challenges in a Multidisciplinary Approach for Explosion Design for Floating Facilities","authors":"L. Paris, M. Cahay","doi":"10.2118/174556-PA","DOIUrl":"https://doi.org/10.2118/174556-PA","url":null,"abstract":"environment compared with onshore liquefied-natural-gas plants or other floating offshore installations. As a consequence, the explosion risk is expected to be higher than that for some other offshore floating facilities. Because of the general evolution of design practices, alternative approaches such as performance with risk-based design can be used. The performance-based approach relies on the explicit definition of the safety objectives and functional requirements (e.g., performance standards). The design process focuses on the objectives, not the means to reach them. Because it is based on the definition of realistic explosion scenarios, which could be deterministic (e.g., scenario-based approach) or probabilistic (risk-based), the design process requires more resources (skills, computational tools) that allow the contractor to demonstrate the compliance of the solution with the safety objectives. This could be a challenge because any design solution is specific to the installation and requires the acceptance of the operator, the local authority, and the classification society. All participants should ensure that they understand, agree with, and are aware of the limitation of the proposed design solution, to avoid further rework. During the entire engineering process, different barriers are investigated to reduce the risk of potential losses (people, assets) from the potential explosion hazards to as low as reasonably practicable, as shown in Fig. 1. Even if inherent safety is a key driver during the design phase of the facility, additional risk-reduction measures that combine prevention, detection, control, and mitigation are usually implemented. Emergency response (e.g., rescue of people) remains the ultimate option. Many of these barriers should be designed or verified against major-accident events to fulfill their function during and after the initial explosion event. This paper focuses on the design process and associated challenges of such barriers because they require an integrated multidisciplinary approach that combines the expertise of safety, structural, and equipment engineers.","PeriodicalId":19446,"journal":{"name":"Oil and gas facilities","volume":"96 1","pages":"57-63"},"PeriodicalIF":0.0,"publicationDate":"2015-08-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82891845","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}
As early as 500,000 years ago, man was using fire to light his cave. This was a very inefficient source of light, yielding about 0.6 lm-h per 1,000 Btu of energy. A step change improvement occurred about 40,000 years ago with the burning of animal fats and oils. Candles became common about 4,000 years ago, but burning wax to get light was also inefficient, yielding only 4 lm-h per 1,000 Btu. This type of resource was also expensive. It has been estimated that a common man would have had to work an entire day to afford a few minutes of light. Unless you were wealthy, night was a dark and dangerous place. It was thousands of years before the next significant improvement occurred when sperm whale oil came on the scene in about 1700, yielding 10 times as much light per Btu of energy at a much lower cost. A day’s work would buy 4 hours of light. A downside was that many men died while harvesting whale oil, and after 150 years of its use as a fuel for lighting, the sperm whale was nearing extinction. The oil industry saved the sperm whale. The discovery of significant quantities of oil in Pennsylvania and elsewhere in the 1850s and beyond and the development of drilling and refining methods created a much lower-cost and more abundant source of energy. One day of labor yielded 75 hours of light. The next and most dramatic improvement was the development of electric light. One day of work earned 4,000 lm-h per Btu or 10,000 hours of light. Light was available to the common man in nearly unlimited quantities. People who are fortunate enough to live in developed countries enjoy unlimited light, which is not the case everywhere in the world. . Availability of affordable energy is perhaps the largest divider between the haves and havenots today. The Complexity of Light For the end user, switching on a light bulb is much simpler than lighting a fire. But the systems behind the bulb are complex. To get light from an electric bulb the following are needed: • Mining for fuel (gas, coal, oil, and uranium) • Power plants to generate the electricity • Mining industries to obtain raw materials for light bulb, wiring, and other components • Transmission and distribution systems to deliver the generated electricity to homes and businesses • Light bulb manufacturing, distribution, and retail sales • Electrical wiring systems in buildings • An advanced political/social system that enables all of the above
{"title":"Simplification: A Moral Imperative","authors":"H. Duhon","doi":"10.2118/0815-0005-OGF","DOIUrl":"https://doi.org/10.2118/0815-0005-OGF","url":null,"abstract":"As early as 500,000 years ago, man was using fire to light his cave. This was a very inefficient source of light, yielding about 0.6 lm-h per 1,000 Btu of energy. A step change improvement occurred about 40,000 years ago with the burning of animal fats and oils. Candles became common about 4,000 years ago, but burning wax to get light was also inefficient, yielding only 4 lm-h per 1,000 Btu. This type of resource was also expensive. It has been estimated that a common man would have had to work an entire day to afford a few minutes of light. Unless you were wealthy, night was a dark and dangerous place. It was thousands of years before the next significant improvement occurred when sperm whale oil came on the scene in about 1700, yielding 10 times as much light per Btu of energy at a much lower cost. A day’s work would buy 4 hours of light. A downside was that many men died while harvesting whale oil, and after 150 years of its use as a fuel for lighting, the sperm whale was nearing extinction. The oil industry saved the sperm whale. The discovery of significant quantities of oil in Pennsylvania and elsewhere in the 1850s and beyond and the development of drilling and refining methods created a much lower-cost and more abundant source of energy. One day of labor yielded 75 hours of light. The next and most dramatic improvement was the development of electric light. One day of work earned 4,000 lm-h per Btu or 10,000 hours of light. Light was available to the common man in nearly unlimited quantities. People who are fortunate enough to live in developed countries enjoy unlimited light, which is not the case everywhere in the world. . Availability of affordable energy is perhaps the largest divider between the haves and havenots today. The Complexity of Light For the end user, switching on a light bulb is much simpler than lighting a fire. But the systems behind the bulb are complex. To get light from an electric bulb the following are needed: • Mining for fuel (gas, coal, oil, and uranium) • Power plants to generate the electricity • Mining industries to obtain raw materials for light bulb, wiring, and other components • Transmission and distribution systems to deliver the generated electricity to homes and businesses • Light bulb manufacturing, distribution, and retail sales • Electrical wiring systems in buildings • An advanced political/social system that enables all of the above","PeriodicalId":19446,"journal":{"name":"Oil and gas facilities","volume":"31 1","pages":"5-7"},"PeriodicalIF":0.0,"publicationDate":"2015-08-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77797656","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 2 The Effect of Inlet Geometries on Flow Distribution","authors":"R. Chin","doi":"10.2118/0815-0026-OGF","DOIUrl":"https://doi.org/10.2118/0815-0026-OGF","url":null,"abstract":"","PeriodicalId":19446,"journal":{"name":"Oil and gas facilities","volume":"20 1","pages":"26-31"},"PeriodicalIF":0.0,"publicationDate":"2015-08-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88078903","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}
J. Johnstone, M. D. Spangler, C. Heitzman, G. A. Wimberley, A. R. Flores
API RP 752 (2009) allows for the evaluation of building locations to use three different assessment approaches: 1. Consequence-based analysis: This approach generally requires that the impacts from maximum credible events (MCEs) be calculated or modeled to determine the impact on a structure. 2. Risk-based analysis: Use of risk-based analysis involves conducting a quantitative analysis to determine risk on the basis of the consequence and the frequency of the hazardous event. 3. Spacing-tables approach: Under API RP 752 (2009), the spacing-table approach is to be used only when determining the minimum distance from a fire to a building. These tables are not appropriate for toxic or explosive events for which the consequence is dependent on the release rate, length of release, wind direction, material released, and many other factors. API RP 752 (2009) was developed primarily for use at facilities that include natural-gas plants, natural-gas-liquefication plants, and other onshore facilities covered by the Occupational Safety and Health Administration (OSHA) process-safety management standard (OSHA 1992). API RP 752 (2009) provides an excellent overview of the issues and factors regarding hazards associated with buildings and provides references as to where additional information can be obtained. The recommended practice does not provide information relating to an oil-production or a gas-treatment facility, detailing out critical items such as MCEs, impacts from hazardous incidents, acceptatble risk criteria, and risk analaysis. The objective of this paper is to present a detailed approach that can serve as the basis for determining safe distances between buildings and processing equipment.
API RP 752(2009)允许使用三种不同的评估方法对建筑位置进行评估:1。基于结果的分析:这种方法通常需要对最大可信事件(mce)的影响进行计算或建模，以确定对结构的影响。2. 基于风险的分析:使用基于风险的分析包括进行定量分析，根据危险事件的后果和频率来确定风险。3.间隔表法:根据API RP 752(2009)，间隔表法仅用于确定从火灾到建筑物的最小距离。这些表不适用于毒性或爆炸性事件，因为其后果取决于释放速率、释放长度、风向、释放的物质和许多其他因素。API RP 752(2009)主要用于包括天然气厂、天然气液化厂和职业安全与健康管理局(OSHA)过程安全管理标准(OSHA 1992)所涵盖的其他陆上设施。API RP 752(2009)对与建筑物相关的危险问题和因素提供了很好的概述，并提供了从哪里可以获得额外信息的参考。推荐的做法没有提供与石油生产或气体处理设施相关的信息，没有详细说明关键项目，如mce、危险事件的影响、可接受的风险标准和风险分析。本文的目的是提出一种详细的方法，可以作为确定建筑物和加工设备之间安全距离的基础。
{"title":"Risk-Based Analysis and Engineering of Safe Distances Between Occupied Structures and Processing Equipment","authors":"J. Johnstone, M. D. Spangler, C. Heitzman, G. A. Wimberley, A. R. Flores","doi":"10.2118/173507-PA","DOIUrl":"https://doi.org/10.2118/173507-PA","url":null,"abstract":"API RP 752 (2009) allows for the evaluation of building locations to use three different assessment approaches: 1. Consequence-based analysis: This approach generally requires that the impacts from maximum credible events (MCEs) be calculated or modeled to determine the impact on a structure. 2. Risk-based analysis: Use of risk-based analysis involves conducting a quantitative analysis to determine risk on the basis of the consequence and the frequency of the hazardous event. 3. Spacing-tables approach: Under API RP 752 (2009), the spacing-table approach is to be used only when determining the minimum distance from a fire to a building. These tables are not appropriate for toxic or explosive events for which the consequence is dependent on the release rate, length of release, wind direction, material released, and many other factors. API RP 752 (2009) was developed primarily for use at facilities that include natural-gas plants, natural-gas-liquefication plants, and other onshore facilities covered by the Occupational Safety and Health Administration (OSHA) process-safety management standard (OSHA 1992). API RP 752 (2009) provides an excellent overview of the issues and factors regarding hazards associated with buildings and provides references as to where additional information can be obtained. The recommended practice does not provide information relating to an oil-production or a gas-treatment facility, detailing out critical items such as MCEs, impacts from hazardous incidents, acceptatble risk criteria, and risk analaysis. The objective of this paper is to present a detailed approach that can serve as the basis for determining safe distances between buildings and processing equipment.","PeriodicalId":19446,"journal":{"name":"Oil and gas facilities","volume":"23 1","pages":"48-56"},"PeriodicalIF":0.0,"publicationDate":"2015-08-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"73865755","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}
phased structure still has ferrite, but the resulting alloy is ductile enough for static structures such as storage tanks. LNG-storage-tank iron/nickel alloys (9%-nickel alloys are most commonly used), with piping and similar attachments made from austenite stainless steel, have better resistance to thermal fatigue. Corrosion is not a problem at cryogenic temperature, so galvanic coupling between nickel steel and stainless steel is not a source of problems. Austenitic stainless steels at LNG temperatures may be used for building smaller storage tanks, but large containment vessels are usually welded from 9%-nickel steel because of expense considerations. This practice is well-established worldwide (Mokhatab et al. 2014). 3.5%-nickel steel was introduced into cryogenic applications in 1944 for construction of an LNG tank; stainless-steel alloys were scarce because of shortages resulting from World War II. Shortly after going into service, on 20 October 1944, the tank failed. In 1946, investigations by the US Bureau of Mines concluded that the incident was a result of the low-temperature embrittlement of the inner shell of the cylindrical tank. The 3.5%-nickel steel was not used further for cryogenic applications (Mannan 2005). Since 1985, ADGAS has been operating three 80 000-m3, aboveground, double-containment-type tanks, designed according to API Standard 620 (2013), that consist of an inner tank and an outer tank. The inner tank is made of 9%-nickel steel. The outer tank has a post-tensioned concrete wall with a reinforced concrete roof. A secondary bottom is connected to the outer-tank wall to provide a flexible liquid seal. The entire construction is made of 9%-nickel steel. Between 2012 and 2013, a longevity study of the storage and export areas was conducted to ensure their fitness for service up to 2019, as a base case, and 2045, as an extended case. Recertification of “conventional” static equipment, piping, jetty, electrical components, instrumentation, rotating elements, structure, and concrete foundations are not addressed in this paper—only LNG tanks are covered. These tanks have never been inspected internally. The most-important outcome from this study is to advise whether to keep them running beyond their design life or to conduct an intrusive inspection to verify their condition. In this paper, the focus will be given first to the 9%-nickel steel, its properties, and its use in LNG-storage tanks. The different LNGtank design generations and their particularities will be described. A general overview of LNG-tank failures, as recorded in the industry, is presented. Finally, the approach adopted by ADGAS to recertify the LNG tanks is explained. Basically, it is a matter of whether to conduct an intrusive inspection or to keep the tanks operating on the basis of industry practice. For this, well-documented cases will be presented, mainly from Ishikawajima-Harima Heavy Industries, Brunei LNG, Gaz de France, and Malaysia LNG.
相相结构仍然有铁素体，但所得到的合金具有足够的延展性，可以用于诸如储罐之类的静态结构。lng储罐铁/镍合金(最常用的是9%-镍合金)，管道和类似的附件由奥氏体不锈钢制成，具有更好的抗热疲劳性能。在低温下腐蚀不是问题，所以镍钢和不锈钢之间的电偶并不是问题的根源。液化天然气温度下的奥氏体不锈钢可用于建造较小的储罐，但出于费用考虑，大型容器通常由含9%镍的钢焊接而成。这种做法在世界范围内都是公认的(Mokhatab et al. 2014)。1944年，3.5%镍钢被引入低温应用，用于建造LNG储罐;由于第二次世界大战造成的短缺，不锈钢合金非常稀缺。1944年10月20日，在投入使用后不久，坦克发生了故障。1946年，美国矿业局的调查得出结论，该事件是由于圆柱形储罐的内壳在低温下脆化造成的。含3.5%镍的钢没有进一步用于低温应用(Mannan 2005)。自1985年以来，ADGAS一直在运营3个80000 -m3的地上双密封罐，根据API标准620(2013)设计，由一个内罐和一个外罐组成。内罐由含9%镍的钢制成。外罐具有后张混凝土墙和钢筋混凝土屋顶。第二底连接到罐外壁，提供灵活的液体密封。整个建筑由含镍9%的钢制成。在2012年至2013年期间，对储存区和出口区进行了寿命研究，以确保它们在2019年(基本情况)和2045年(扩展情况)之前都能正常使用。“传统”静态设备、管道、码头、电气元件、仪表、旋转元件、结构和混凝土基础的重新认证在本文中没有涉及，只涉及LNG储罐。这些储罐从未进行过内部检查。这项研究最重要的结果是建议是否让它们超过其设计寿命或进行侵入性检查以验证其状况。在本文中，重点将首先给出9%镍钢，它的性能，以及它在液化天然气储罐中的应用。不同的长坦克设计世代和他们的特点将被描述。概述了液化天然气储罐故障，在行业中记录，提出。最后，介绍了ADGAS对LNG储罐进行再认证的方法。基本上，这是一个是否进行侵入式检查或根据行业惯例保持储罐运行的问题。为此，将介绍有充分记录的案例，主要来自石川岛harima重工、文莱液化天然气、法国天然气公司和马来西亚液化天然气公司。
{"title":"Cryogenic Tanks Recertification: Case Study for Operational-Life Extension","authors":"A. Adamou","doi":"10.2118/171998-PA","DOIUrl":"https://doi.org/10.2118/171998-PA","url":null,"abstract":"phased structure still has ferrite, but the resulting alloy is ductile enough for static structures such as storage tanks. LNG-storage-tank iron/nickel alloys (9%-nickel alloys are most commonly used), with piping and similar attachments made from austenite stainless steel, have better resistance to thermal fatigue. Corrosion is not a problem at cryogenic temperature, so galvanic coupling between nickel steel and stainless steel is not a source of problems. Austenitic stainless steels at LNG temperatures may be used for building smaller storage tanks, but large containment vessels are usually welded from 9%-nickel steel because of expense considerations. This practice is well-established worldwide (Mokhatab et al. 2014). 3.5%-nickel steel was introduced into cryogenic applications in 1944 for construction of an LNG tank; stainless-steel alloys were scarce because of shortages resulting from World War II. Shortly after going into service, on 20 October 1944, the tank failed. In 1946, investigations by the US Bureau of Mines concluded that the incident was a result of the low-temperature embrittlement of the inner shell of the cylindrical tank. The 3.5%-nickel steel was not used further for cryogenic applications (Mannan 2005). Since 1985, ADGAS has been operating three 80 000-m3, aboveground, double-containment-type tanks, designed according to API Standard 620 (2013), that consist of an inner tank and an outer tank. The inner tank is made of 9%-nickel steel. The outer tank has a post-tensioned concrete wall with a reinforced concrete roof. A secondary bottom is connected to the outer-tank wall to provide a flexible liquid seal. The entire construction is made of 9%-nickel steel. Between 2012 and 2013, a longevity study of the storage and export areas was conducted to ensure their fitness for service up to 2019, as a base case, and 2045, as an extended case. Recertification of “conventional” static equipment, piping, jetty, electrical components, instrumentation, rotating elements, structure, and concrete foundations are not addressed in this paper—only LNG tanks are covered. These tanks have never been inspected internally. The most-important outcome from this study is to advise whether to keep them running beyond their design life or to conduct an intrusive inspection to verify their condition. In this paper, the focus will be given first to the 9%-nickel steel, its properties, and its use in LNG-storage tanks. The different LNGtank design generations and their particularities will be described. A general overview of LNG-tank failures, as recorded in the industry, is presented. Finally, the approach adopted by ADGAS to recertify the LNG tanks is explained. Basically, it is a matter of whether to conduct an intrusive inspection or to keep the tanks operating on the basis of industry practice. For this, well-documented cases will be presented, mainly from Ishikawajima-Harima Heavy Industries, Brunei LNG, Gaz de France, and Malaysia LNG.","PeriodicalId":19446,"journal":{"name":"Oil and gas facilities","volume":"73 1","pages":"88-100"},"PeriodicalIF":0.0,"publicationDate":"2015-08-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"85797399","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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