Seetharaman Navaneetha Kannan, Magne Torsvik, L. Ugueto, Stephan Hatscher, Sriram Ravichandran, Dendy Sloan, L. Zerpa, Carolyn Koh
Gas hydrate plugs formed in subsea flowlines create complex challenges in plug remediation operations and can result in significant operational expenditures. In Vega, a Norwegian gas condensate subsea asset, a hydrate blockage was identified in a 12" ID flowline in June 2020. This work chronicles a series of operational activities in the detection of the hydrate blockage, modeling assessment, and safe and successful plug remediation efforts. Under the assumption that multiple plugs were present in the flowline, gas pockets could have formed in between the plugs, creating intermediate high-pressure regions. The two-sided depressurization of the flowline below hydrate equilibrium pressure (10 bara at 5°C) established successful pressure communication from both ends of the flowline. The field data interpretation showed the release of gas pockets and the corresponding pressure spikes during plug dissociation. The operational experiences from hydrate plug detection and melting, as well as modeling activities, provide valuable input for future hydrate remediation operations. The collective team effort in recording and analyzing all the instances addresses three main concerns of paramount significance in the oil and gas industry, which include the safety of personnel, equipment, and the environment.
{"title":"Safe and Successful Gas Hydrate Plug Remediation in Vega Asset – Norwegian Gas Condensate Subsea Production System","authors":"Seetharaman Navaneetha Kannan, Magne Torsvik, L. Ugueto, Stephan Hatscher, Sriram Ravichandran, Dendy Sloan, L. Zerpa, Carolyn Koh","doi":"10.2118/215580-ms","DOIUrl":"https://doi.org/10.2118/215580-ms","url":null,"abstract":"\u0000 Gas hydrate plugs formed in subsea flowlines create complex challenges in plug remediation operations and can result in significant operational expenditures. In Vega, a Norwegian gas condensate subsea asset, a hydrate blockage was identified in a 12\" ID flowline in June 2020. This work chronicles a series of operational activities in the detection of the hydrate blockage, modeling assessment, and safe and successful plug remediation efforts. Under the assumption that multiple plugs were present in the flowline, gas pockets could have formed in between the plugs, creating intermediate high-pressure regions. The two-sided depressurization of the flowline below hydrate equilibrium pressure (10 bara at 5°C) established successful pressure communication from both ends of the flowline. The field data interpretation showed the release of gas pockets and the corresponding pressure spikes during plug dissociation. The operational experiences from hydrate plug detection and melting, as well as modeling activities, provide valuable input for future hydrate remediation operations. The collective team effort in recording and analyzing all the instances addresses three main concerns of paramount significance in the oil and gas industry, which include the safety of personnel, equipment, and the environment.","PeriodicalId":130107,"journal":{"name":"Day 1 Tue, September 05, 2023","volume":"360 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-09-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"123430696","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}
Saudi Aramco (SA) took a long and patient journey to reduce flaring, which has gone through several phases of growth and progression. The journey began with the development of the Master Gas System (MGS). That enable the company to achieve zero routine flaring as per the world bank definition. Today, Saudi Aramco achieved a remarkable flaring intensity of 4.60 scf/boe. This figure amounts to less than 1% of raw gas production.
{"title":"Journey Towards Near Zero Flaring - A Case Study","authors":"Mohammed Almubayedh, Abdullmajeed Alsanad","doi":"10.2118/215505-ms","DOIUrl":"https://doi.org/10.2118/215505-ms","url":null,"abstract":"\u0000 Saudi Aramco (SA) took a long and patient journey to reduce flaring, which has gone through several phases of growth and progression. The journey began with the development of the Master Gas System (MGS). That enable the company to achieve zero routine flaring as per the world bank definition. Today, Saudi Aramco achieved a remarkable flaring intensity of 4.60 scf/boe. This figure amounts to less than 1% of raw gas production.","PeriodicalId":130107,"journal":{"name":"Day 1 Tue, September 05, 2023","volume":"65 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-09-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"116444101","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
This paper will demonstrate the improved safety advantages, rig time savings and the associated cost reductions available by using pre-installed cable protectors during run-in-hole (RIH) operations for completions where downhole cables are at risk of damage. Pre-installed cable protectors can greatly reduce the number of personnel operating in the ‘red zone’, eliminate costly shipping logistics and reduce the amount of time needed installing cable protectors on the rig floor, thus providing safety benefits and improving RIH timing.
{"title":"Pre-Installed Cable Protectors Will Save Time and Improve Safety While Running Completions","authors":"J. Bibby, A. Brodie, J. Fiorucci","doi":"10.2118/215527-ms","DOIUrl":"https://doi.org/10.2118/215527-ms","url":null,"abstract":"\u0000 This paper will demonstrate the improved safety advantages, rig time savings and the associated cost reductions available by using pre-installed cable protectors during run-in-hole (RIH) operations for completions where downhole cables are at risk of damage. Pre-installed cable protectors can greatly reduce the number of personnel operating in the ‘red zone’, eliminate costly shipping logistics and reduce the amount of time needed installing cable protectors on the rig floor, thus providing safety benefits and improving RIH timing.","PeriodicalId":130107,"journal":{"name":"Day 1 Tue, September 05, 2023","volume":"1120 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-09-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"134401616","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
In two planned large-scale CCS projects in the Netherlands – Porthos and Aramis – depleted gas fields will be used for CO2 storage. These fields are characterized by low reservoir pressures. For example, the Porthos project is planned to inject into a field with a reservoir pressure below 20 bar. Project design and operational philosophy need to be specifically tailored to the storage reservoir properties in order to avoid excessively low temperatures when injecting into such fields. This paper describes how these challenges were addressed for the Porthos project. In most CCS projects, a CO2 mixture is transported in a surface network at high pressure and ambient temperature and injected into an aquifer. At the high reservoir pressure typical of aquifer storage the CO2 stream remains in dense phase or supercritical conditions in the entire system. This dense phase transport strategy is not feasible for the P18 field since the bottomhole pressure (BHP) is around 25 bar at the required injection rates. At this low pressure, CO2 will exist in two-phase conditions which results in very low temperatures of −10 °C. These low temperatures are unacceptable since they may result in hydrate formation in the reservoir and well integrity issues. A specific operating philosophy and project design was developed to avoid unacceptably low temperatures. At a reservoir pressure below 50 bar, CO2 is injected in gas phase in the pipeline and wells. Once the reservoir reaches a pressure of 50 bar the pipeline pressure is increased to 85 bar to achieve dense phase conditions. The well is operated in two-phase conditions but due to the higher BHP well temperatures are now acceptable. However, if CO2 is transported at ambient temperature the injection flow range per well is very narrow and the required project injection range cannot be met. This is addressed by using the heat of compression to heat the CO2 stream and insulating the pipeline to achieve elevated arrival temperature. Without these specific choices, safe injection into the P18 field would not have been possible.
{"title":"Porthos – CO2 Storage in Highly-Depleted Gas Fields","authors":"W. Schiferli","doi":"10.2118/215562-ms","DOIUrl":"https://doi.org/10.2118/215562-ms","url":null,"abstract":"\u0000 In two planned large-scale CCS projects in the Netherlands – Porthos and Aramis – depleted gas fields will be used for CO2 storage. These fields are characterized by low reservoir pressures. For example, the Porthos project is planned to inject into a field with a reservoir pressure below 20 bar. Project design and operational philosophy need to be specifically tailored to the storage reservoir properties in order to avoid excessively low temperatures when injecting into such fields. This paper describes how these challenges were addressed for the Porthos project.\u0000 In most CCS projects, a CO2 mixture is transported in a surface network at high pressure and ambient temperature and injected into an aquifer. At the high reservoir pressure typical of aquifer storage the CO2 stream remains in dense phase or supercritical conditions in the entire system. This dense phase transport strategy is not feasible for the P18 field since the bottomhole pressure (BHP) is around 25 bar at the required injection rates. At this low pressure, CO2 will exist in two-phase conditions which results in very low temperatures of −10 °C. These low temperatures are unacceptable since they may result in hydrate formation in the reservoir and well integrity issues.\u0000 A specific operating philosophy and project design was developed to avoid unacceptably low temperatures. At a reservoir pressure below 50 bar, CO2 is injected in gas phase in the pipeline and wells. Once the reservoir reaches a pressure of 50 bar the pipeline pressure is increased to 85 bar to achieve dense phase conditions. The well is operated in two-phase conditions but due to the higher BHP well temperatures are now acceptable. However, if CO2 is transported at ambient temperature the injection flow range per well is very narrow and the required project injection range cannot be met. This is addressed by using the heat of compression to heat the CO2 stream and insulating the pipeline to achieve elevated arrival temperature. Without these specific choices, safe injection into the P18 field would not have been possible.","PeriodicalId":130107,"journal":{"name":"Day 1 Tue, September 05, 2023","volume":"14 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-09-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"122008834","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}
Dr. Rabindra Das, P. Tiwari, M. Z. B. A. Rahman, M. N. Mohamad, P. Chidambaram, Nur Myra Rahayu Razali, M. H. Yakup, Saeed Majidaie, Tan Seng Wah, M. N. F. B. C. Mat, M. S. B. E. Amir, Nik M Fadhlan, R. Tewari, Salina Bt Baharuddin
Deep saline aquifers offer significant potential for CO2 storage, with successful small-scale projects worldwide and major initiatives such as Gorgon in their early stages. In Peninsular Malaysia (PM) the daily CO2 production rate is expected to reach to the tune of ∼480 to 570 MMscf once the high contaminant gas fields are put on development. Several depleted hydrocarbon fields in PM region have been studied in the past for potential storage of the CO2 to be produced. Previously studies have been conducted on various depleted hydrocarbon fields within the PM region to assess their suitability for storing the anticipated CO2 volume. Nevertheless, the limited storage capacity and availability of these depleted reservoirs necessitate the exploration of alternative solutions. The deep saline aquifers in Peninsular Malaysia emerge as a viable option, as they can address the existing storage capacity limitations and facilitate the efficient development of high contaminant gas fields in the region, thereby enabling expedited monetization efforts. A comprehensive screening matrix was devised to identify strategic saline aquifers, considering various factors such as fault density, presence of top seals, reservoir depth, thickness, extension, pressure, temperature, porosity, number of wells drilled, and data availability. This holistic approach enabled the identification of structures that met the screening criteria. Further analysis was conducted on these selected structures to determine their theoretical CO2 storage capacity. Based on the evaluated capacities and their potential for cluster development, the structures were ranked accordingly. This systematic process allowed for the identification and prioritization of saline aquifers with the greatest potential for CO2 storage and cluster development. This study involves the feasibility study of one such identified clusters comprising three drilled dry structures that were analyzed for their containment and capacity through extensive 3D data interpretation for generation of structural maps, mapping of major and minor faults, and attribute extraction, trap & seal analysis, faults & wells integrity analysis, 1D caprock integrity analysis, and effective storage capacity estimation through dynamic simulation. The study concluded that two out of the three studied structures are associated with high trap risks and may not be suitable for injection & long-term storage of CO2. Further their close proximity to the regional fault would limit their viability for being potential open aquifer systems. The third structure which has well defined trap, seal & reservoir was found to be associated with relatively low effective CO2 storage capacity as based on the current analysis the storage capacity estimation was restricted to only one of the stratigraphic intervals only. The adapted workflow and lessons learnt during this study can be applied to future saline aquifer screening studies involving dry wells in the r
{"title":"CO2 Storage Potential Evaluation of Restricted Saline Aquifers in Peninsular Malaysia Offshore","authors":"Dr. Rabindra Das, P. Tiwari, M. Z. B. A. Rahman, M. N. Mohamad, P. Chidambaram, Nur Myra Rahayu Razali, M. H. Yakup, Saeed Majidaie, Tan Seng Wah, M. N. F. B. C. Mat, M. S. B. E. Amir, Nik M Fadhlan, R. Tewari, Salina Bt Baharuddin","doi":"10.2118/215531-ms","DOIUrl":"https://doi.org/10.2118/215531-ms","url":null,"abstract":"\u0000 Deep saline aquifers offer significant potential for CO2 storage, with successful small-scale projects worldwide and major initiatives such as Gorgon in their early stages. In Peninsular Malaysia (PM) the daily CO2 production rate is expected to reach to the tune of ∼480 to 570 MMscf once the high contaminant gas fields are put on development. Several depleted hydrocarbon fields in PM region have been studied in the past for potential storage of the CO2 to be produced. Previously studies have been conducted on various depleted hydrocarbon fields within the PM region to assess their suitability for storing the anticipated CO2 volume. Nevertheless, the limited storage capacity and availability of these depleted reservoirs necessitate the exploration of alternative solutions. The deep saline aquifers in Peninsular Malaysia emerge as a viable option, as they can address the existing storage capacity limitations and facilitate the efficient development of high contaminant gas fields in the region, thereby enabling expedited monetization efforts.\u0000 A comprehensive screening matrix was devised to identify strategic saline aquifers, considering various factors such as fault density, presence of top seals, reservoir depth, thickness, extension, pressure, temperature, porosity, number of wells drilled, and data availability. This holistic approach enabled the identification of structures that met the screening criteria. Further analysis was conducted on these selected structures to determine their theoretical CO2 storage capacity. Based on the evaluated capacities and their potential for cluster development, the structures were ranked accordingly. This systematic process allowed for the identification and prioritization of saline aquifers with the greatest potential for CO2 storage and cluster development. This study involves the feasibility study of one such identified clusters comprising three drilled dry structures that were analyzed for their containment and capacity through extensive 3D data interpretation for generation of structural maps, mapping of major and minor faults, and attribute extraction, trap & seal analysis, faults & wells integrity analysis, 1D caprock integrity analysis, and effective storage capacity estimation through dynamic simulation.\u0000 The study concluded that two out of the three studied structures are associated with high trap risks and may not be suitable for injection & long-term storage of CO2. Further their close proximity to the regional fault would limit their viability for being potential open aquifer systems. The third structure which has well defined trap, seal & reservoir was found to be associated with relatively low effective CO2 storage capacity as based on the current analysis the storage capacity estimation was restricted to only one of the stratigraphic intervals only.\u0000 The adapted workflow and lessons learnt during this study can be applied to future saline aquifer screening studies involving dry wells in the r","PeriodicalId":130107,"journal":{"name":"Day 1 Tue, September 05, 2023","volume":"128 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-09-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"134397331","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 objectives of the study were to explore fatigue levels on swing shifts, whereby workers work on day shifts for the first week and roll over to night shifts for the second week, compared to regular shifts; sleep health when workers were off work onshore compared to their time offshore; and the effects of fatigue on performance. The study also identified some of the factors that may cause feelings of fatigue. Mixed-method, self-report surveys collected data on sleep hygiene, sleep health, and fatigue. Three semi-structured interviews were conducted with the workers who were on swing shifts to help understand the impacts of fatigue with three offshore workers. A number of statistical tests and qualitative analysis were carried out. Results obtained from the survey showed experiences of mild fatigue levels and mild severity of fatigue across the workforce. Interviews revealed that workers on swing shifts experienced higher levels of fatigue which impacted their performance via poorer communication, attention, reaction time, and motivation. It was also found that fatigue negatively impacted physical functioning and ability to carry out duties and responsibilities. Importantly, sleep health scores in swing shift workers were significantly worse when they were offshore compared to onshore. Such finding was not observed in workers who operated on regular shifts. Factors such as sleep health, sleep quality, and energy levels negatively correlated with self-reported fatigue levels. In general, present findings supported previous literature which found that swing shift may have caused or increased fatigue levels due to the adaptation process to a different wake-sleep cycle that took days. It was found that swing shift operators experienced worse sleep health when they were offshore compared to onshore. This study identified some of the possible sources and effects of fatigue that can directly inform interventions in terms of subjects for focus.
{"title":"Swing to Fatigue: Exploring Fatigue and Sleep Health and their Differences Between Regular and Swing Shift Patterns in Oil and Gas Offshore Workers","authors":"J. Mihulkova, R. Donald, A. Henderson","doi":"10.2118/215535-ms","DOIUrl":"https://doi.org/10.2118/215535-ms","url":null,"abstract":"\u0000 The objectives of the study were to explore fatigue levels on swing shifts, whereby workers work on day shifts for the first week and roll over to night shifts for the second week, compared to regular shifts; sleep health when workers were off work onshore compared to their time offshore; and the effects of fatigue on performance. The study also identified some of the factors that may cause feelings of fatigue.\u0000 Mixed-method, self-report surveys collected data on sleep hygiene, sleep health, and fatigue. Three semi-structured interviews were conducted with the workers who were on swing shifts to help understand the impacts of fatigue with three offshore workers. A number of statistical tests and qualitative analysis were carried out.\u0000 Results obtained from the survey showed experiences of mild fatigue levels and mild severity of fatigue across the workforce. Interviews revealed that workers on swing shifts experienced higher levels of fatigue which impacted their performance via poorer communication, attention, reaction time, and motivation. It was also found that fatigue negatively impacted physical functioning and ability to carry out duties and responsibilities. Importantly, sleep health scores in swing shift workers were significantly worse when they were offshore compared to onshore. Such finding was not observed in workers who operated on regular shifts. Factors such as sleep health, sleep quality, and energy levels negatively correlated with self-reported fatigue levels.\u0000 In general, present findings supported previous literature which found that swing shift may have caused or increased fatigue levels due to the adaptation process to a different wake-sleep cycle that took days. It was found that swing shift operators experienced worse sleep health when they were offshore compared to onshore. This study identified some of the possible sources and effects of fatigue that can directly inform interventions in terms of subjects for focus.","PeriodicalId":130107,"journal":{"name":"Day 1 Tue, September 05, 2023","volume":"5 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-09-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"133825940","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 North Sea Transition Deal (NSTD) agreed in 2021 between the UK government and the offshore oil and gas industry placed a strong emphasis on emission reduction. Amongst various enhancement options, immediate reductions in production related emissions from improved production efficiency, energy efficiency, operational process change, consideration of fuel usage and equipment upgrades was recommended. In this study, the feasibility of retrofitting an Organic Rankine Cycle (ORC) unit was assessed by determining the power generated from heat on the power generator turbines on Serica Energy's Bruce platform. The modification proposes using the heat generated, to generate sufficient power to meet platform's demand. The study's findings show that a 40% increase in energy efficiency is achievable. The study also indicates that using the ORC reduced fuel usage by 0.5 – 1.6 kg/s and CO2emissions by 96.86 – 310 metric tonnes of Carbon Dioxide (CO2) equivalent per day. Economic analysis also demonstrates that the added benefits of ORC such as increased revenue from additional gas sales and savings from lower carbon tax outweigh the investment capital cost of £20 million. This maturity of this technology which has been successfully demonstrated in other environments has not yet been implemented on offshore oil and gas installations makes this an attractive option for companies. Given the relatively small impact on plant layout and weight, this study also discusses the wider benefits that using ORC could have on the running of aging offshore platforms especially if redundant equipment can be decommissioned, reducing abandonment expenditure (ABEX) scope in advance of the cessation of production (CoP).
{"title":"Heat to Power Feasibility Study on Oil and Gas Offshore Installations Using Organic Rankine Cycle (ORC)","authors":"A. Ranjinehkhojasteh, O. Folayan","doi":"10.2118/215600-ms","DOIUrl":"https://doi.org/10.2118/215600-ms","url":null,"abstract":"\u0000 The North Sea Transition Deal (NSTD) agreed in 2021 between the UK government and the offshore oil and gas industry placed a strong emphasis on emission reduction. Amongst various enhancement options, immediate reductions in production related emissions from improved production efficiency, energy efficiency, operational process change, consideration of fuel usage and equipment upgrades was recommended.\u0000 In this study, the feasibility of retrofitting an Organic Rankine Cycle (ORC) unit was assessed by determining the power generated from heat on the power generator turbines on Serica Energy's Bruce platform. The modification proposes using the heat generated, to generate sufficient power to meet platform's demand.\u0000 The study's findings show that a 40% increase in energy efficiency is achievable. The study also indicates that using the ORC reduced fuel usage by 0.5 – 1.6 kg/s and CO2emissions by 96.86 – 310 metric tonnes of Carbon Dioxide (CO2) equivalent per day. Economic analysis also demonstrates that the added benefits of ORC such as increased revenue from additional gas sales and savings from lower carbon tax outweigh the investment capital cost of £20 million.\u0000 This maturity of this technology which has been successfully demonstrated in other environments has not yet been implemented on offshore oil and gas installations makes this an attractive option for companies. Given the relatively small impact on plant layout and weight, this study also discusses the wider benefits that using ORC could have on the running of aging offshore platforms especially if redundant equipment can be decommissioned, reducing abandonment expenditure (ABEX) scope in advance of the cessation of production (CoP).","PeriodicalId":130107,"journal":{"name":"Day 1 Tue, September 05, 2023","volume":"80 6 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-09-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"130692137","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
This paper presents the "cold flow" technology and tests performed to qualify a subsea concept as a step towards taking the technology into use. By combining subsea cooling and the traditional cold flow seeding method with a novel inductive heating mechanism, all hydrate and wax potential can be converted into small and inert solid particles in a subsea cooler downstream of the wellhead. The particles will travel suspended in the bulk flow at ambient seabed temperature towards the host facility without any additional flow assurance measures, like pipeline insulation, heating, or chemical injection. The paper contains a description of the Empig cold flow technology, and the initial concept launched by SINTEF. Furthermore, a description of a hydrocarbon flow loop used in the testing of the technology together with a brief description of test results. A subsea cooler unit used for a pit test is then presented. This section contains a discussion on its design principles, a description of the marinized heating system, and test results.
{"title":"Keeping Subsea Pipelines Free from Wax and Hydrate Deposits by Use of a Subsea Cooler Unit","authors":"M. Kvernland, F. Lund, L. Strømmegjerde","doi":"10.2118/215591-ms","DOIUrl":"https://doi.org/10.2118/215591-ms","url":null,"abstract":"\u0000 This paper presents the \"cold flow\" technology and tests performed to qualify a subsea concept as a step towards taking the technology into use. By combining subsea cooling and the traditional cold flow seeding method with a novel inductive heating mechanism, all hydrate and wax potential can be converted into small and inert solid particles in a subsea cooler downstream of the wellhead. The particles will travel suspended in the bulk flow at ambient seabed temperature towards the host facility without any additional flow assurance measures, like pipeline insulation, heating, or chemical injection. The paper contains a description of the Empig cold flow technology, and the initial concept launched by SINTEF. Furthermore, a description of a hydrocarbon flow loop used in the testing of the technology together with a brief description of test results. A subsea cooler unit used for a pit test is then presented. This section contains a discussion on its design principles, a description of the marinized heating system, and test results.","PeriodicalId":130107,"journal":{"name":"Day 1 Tue, September 05, 2023","volume":"1 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-09-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"125691099","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}
Designing pipelines for CO2 transport comes with unique challenges when compared to conventional oil and gas transportation systems. One of which is the proximity of the CO2-rich fluid phase boundary to typical operating conditions. There are also significant risks specific to non-routine, planned operations which cross this phase boundary - such as depressurisation. This paper discusses how changes in environmental conditions can impact the safe depressurisation of CO2 pipelines. During depressurisation of a CO2 pipeline, cold temperatures are a risk due to the high Joule Thomson (JT) coefficient of CO2-rich gas. When the contents of the pipeline transition from dense to gas phase, heat will also be absorbed from the system's surroundings to supply the latent heat of vaporisation. The combination of these factors means that the surrounding ambient conditions can greatly impact the requirements for safe depressurisation. To investigate this impact, the depressurisation of three representative CO2 pipelines have been investigated using thermohydraulic modelling software, considering varying ambient conditions from Wood's project experience. The results show that factors such as ambient temperatures, wind velocities/seabed current, and the thermal conductivity of the surrounding soil have a first order impact on the minimum temperatures expected during depressurisation. The properties of the soil, such as dryness and composition - rarely the focus of detailed environmental analysis - are noted to have a particularly high impact on the minimum temperatures expected. Depending on the minimum wall design temperatures and pipeline length, this can result in significant minimum durations required to safely depressurise CO2 pipelines. It should be noted that a reasonable and economical approach for depressurisation is to assume a constant heat flux. Such an assumption provides an order of magnitude estimate as a screening procedure to determine if a more detailed survey is needed. However, in reality, the depressurisation event would cause the temperature of the soil to drop, which impacts the heat transfer from soil to pipeline. This will be discussed on a high level, with reference made to the finite element method adopted by some industry leading software packages. The case studies shown provide an understanding of how forecast conditions during these operations can determine system design margins and increase operational risks in very different ways depending on the installed pipeline environment. The outcome is an increased awareness on the importance of early project phase CO2 transport insights for transport assurance and asset integrity, and an appreciation of current best practice for CO2 pipeline modelling.
{"title":"Impact of Environmental Conditions on Safe Depressurisation of CO2 Pipelines: A Discussion on Design and Feasibility","authors":"C. McKay, S. Stokes, F. Shirani","doi":"10.2118/215549-ms","DOIUrl":"https://doi.org/10.2118/215549-ms","url":null,"abstract":"\u0000 Designing pipelines for CO2 transport comes with unique challenges when compared to conventional oil and gas transportation systems. One of which is the proximity of the CO2-rich fluid phase boundary to typical operating conditions. There are also significant risks specific to non-routine, planned operations which cross this phase boundary - such as depressurisation. This paper discusses how changes in environmental conditions can impact the safe depressurisation of CO2 pipelines.\u0000 During depressurisation of a CO2 pipeline, cold temperatures are a risk due to the high Joule Thomson (JT) coefficient of CO2-rich gas. When the contents of the pipeline transition from dense to gas phase, heat will also be absorbed from the system's surroundings to supply the latent heat of vaporisation. The combination of these factors means that the surrounding ambient conditions can greatly impact the requirements for safe depressurisation. To investigate this impact, the depressurisation of three representative CO2 pipelines have been investigated using thermohydraulic modelling software, considering varying ambient conditions from Wood's project experience.\u0000 The results show that factors such as ambient temperatures, wind velocities/seabed current, and the thermal conductivity of the surrounding soil have a first order impact on the minimum temperatures expected during depressurisation. The properties of the soil, such as dryness and composition - rarely the focus of detailed environmental analysis - are noted to have a particularly high impact on the minimum temperatures expected. Depending on the minimum wall design temperatures and pipeline length, this can result in significant minimum durations required to safely depressurise CO2 pipelines. It should be noted that a reasonable and economical approach for depressurisation is to assume a constant heat flux. Such an assumption provides an order of magnitude estimate as a screening procedure to determine if a more detailed survey is needed. However, in reality, the depressurisation event would cause the temperature of the soil to drop, which impacts the heat transfer from soil to pipeline. This will be discussed on a high level, with reference made to the finite element method adopted by some industry leading software packages.\u0000 The case studies shown provide an understanding of how forecast conditions during these operations can determine system design margins and increase operational risks in very different ways depending on the installed pipeline environment. The outcome is an increased awareness on the importance of early project phase CO2 transport insights for transport assurance and asset integrity, and an appreciation of current best practice for CO2 pipeline modelling.","PeriodicalId":130107,"journal":{"name":"Day 1 Tue, September 05, 2023","volume":"1 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-09-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"128884004","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}
Indonesia is one of the big economy countries, with the share of global GDP ranked 7th in 2022. However, Indonesia is still categorized as a developing country. According to the UN and World Bank, developing countries are characterized as a country with relatively low standards of living which indicated from low to middle GNI per capita, underdeveloped industrialization relative to its population, and moderate to low Human Development Index (HDI). Based on the definition, Indonesia GNI per capita in 2022 is USD4,783.9, which based on World Bank standards in 2022 is still categorized as upper middle-income country. Then, Indonesian HDI is 0.7 which is categorized as high but ranked 130 out of 199 countries. Lastly, Indonesia experienced premature industrialization with a declining contribution of industry sector to GDP (figure 1). Nevertheless, Indonesia has a vision to become a developed country in 2045, as a 100-year commemoration of Indonesia independence. This vision, which referred to Vision of Indonesia 2045, became a national target as stated in the draft of National Long-Term Development Plan 2025-2045 (RPJPN). In the document, the Indonesian government aspires to achieve a high income country in 2045, with GNI per capita USD30,300 or nearly 5 times current condition. To achieve the aspiration, Indonesia requires GDP growth above historical average and structural transformation. The document also stated that, Indonesia should first improve the Total Factor Productivity (TFP) which in 2005-2019 grew negatively around 0.66, and to improve TFP, Indonesia requires HDI improvement, also research and innovation. Indonesia also requires growth in the industry sector as the most important factor to increase GDP, because Indonesia should pivot from hard commodities-based extraction and processing, especially coal and crude palm oil (CPO) which historically has had a positive major contribution to Indonesian balance of trade. Since energy has a strong link with the economy and is crucial in maintaining or improving lifestyle (Chontanawat et al., 2008; King & Van Den Bergh, 2018; Stern, 2019). Indonesia will require energy to support its economic growth. In the context of energy challenges, Indonesia should balance the energy trilemmas, which based on the World Energy Council are energy affordability, security, and sustainability. Based on the current condition, to ensure affordability, the Indonesian government subsidizes fossil energy sources, such as gasoline, LPG, natural gas for certain industries, and electricity which is based on coal. Then, to ensure security, Indonesia has plans to reduce its dependence on oil import and currently utilize coal as one of its abundance resources. Finally, to ensure sustainability, Indonesia pledged to develop its economy based on low carbon energy, as stated in the enhanced Nationally Determined Contribution (eNDC) that Indonesia will achieve Net Zero Emission (NZE) in 2060 or sooner. However, the commitment
印尼是经济大国之一，2022年占全球GDP的比重排在第七位。然而，印尼仍然被归类为发展中国家。根据联合国和世界银行的定义，发展中国家是人均国民总收入(GNI)处于中低水平、相对于人口的工业化程度不发达、人类发展指数(HDI)处于中低水平的生活水平相对较低的国家。根据这一定义，印尼2022年人均国民总收入为4783.9美元，按照世界银行2022年的标准，仍属于中高收入国家。印度尼西亚的HDI为0.7，属于高水平，但在199个国家中排名第130位。最后，印度尼西亚经历了过早的工业化，工业部门对GDP的贡献下降(图1)。尽管如此，印度尼西亚的愿景是在2045年成为发达国家，作为印度尼西亚独立100周年的纪念。这一愿景被称为“印度尼西亚2045年愿景”，已成为《2025-2045年国家长期发展计划》草案中规定的国家目标。在这份文件中，印尼政府的目标是在2045年成为高收入国家，人均国民总收入达到3.03万美元，是目前的近5倍。为了实现这一目标，印尼需要GDP增长高于历史平均水平，并进行结构转型。该文件还指出，印度尼西亚应首先提高全要素生产率(TFP)，该生产率在2005年至2019年期间在0.66左右负增长，为了提高TFP，印度尼西亚需要提高HDI，以及研究和创新。印度尼西亚还要求工业部门的增长作为增加国内生产总值的最重要因素，因为印度尼西亚应该从以硬商品为基础的开采和加工转向，特别是煤炭和粗棕榈油(CPO)，这在历史上对印度尼西亚的贸易平衡有积极的重大贡献。由于能源与经济有着密切的联系，对于维持或改善生活方式至关重要(Chontanawat等人，2008;King & Van Den Bergh, 2018;斯特恩,2019)。印尼将需要能源来支持其经济增长。在能源挑战的背景下，印尼应该平衡能源三难问题，根据世界能源理事会的说法，这三难问题是能源的可负担性、安全性和可持续性。根据目前的情况，为了确保人们的负担能力，印尼政府补贴化石能源，如汽油、液化石油气、某些行业的天然气，以及以煤炭为基础的电力。然后，为了确保安全，印度尼西亚计划减少对石油进口的依赖，目前利用煤炭作为其丰富的资源之一。最后，为了确保可持续性，印度尼西亚承诺以低碳能源为基础发展经济，正如增强的国家自主贡献(eNDC)所述，印度尼西亚将在2060年或更早实现净零排放(NZE)。然而，对能源可持续性的承诺将需要在能源可负担性和安全性方面进行再平衡，而这两方面目前仍与化石能源密切相关。因此，无论是2045年愿景还是2060年或更早的NZE，都需要在印尼的能源和经济体系中制定一个全面的转型长期目标。
{"title":"The Systemic Risks of Indonesian Energy Sector Transition Pathways (A Case Study of Energy Transition in Indonesia)","authors":"Aryanto. Yohanes Handoko, Purba. Loisa","doi":"10.2118/215513-ms","DOIUrl":"https://doi.org/10.2118/215513-ms","url":null,"abstract":"Indonesia is one of the big economy countries, with the share of global GDP ranked 7th in 2022. However, Indonesia is still categorized as a developing country. According to the UN and World Bank, developing countries are characterized as a country with relatively low standards of living which indicated from low to middle GNI per capita, underdeveloped industrialization relative to its population, and moderate to low Human Development Index (HDI). Based on the definition, Indonesia GNI per capita in 2022 is USD4,783.9, which based on World Bank standards in 2022 is still categorized as upper middle-income country. Then, Indonesian HDI is 0.7 which is categorized as high but ranked 130 out of 199 countries. Lastly, Indonesia experienced premature industrialization with a declining contribution of industry sector to GDP (figure 1).\u0000 Nevertheless, Indonesia has a vision to become a developed country in 2045, as a 100-year commemoration of Indonesia independence. This vision, which referred to Vision of Indonesia 2045, became a national target as stated in the draft of National Long-Term Development Plan 2025-2045 (RPJPN). In the document, the Indonesian government aspires to achieve a high income country in 2045, with GNI per capita USD30,300 or nearly 5 times current condition. To achieve the aspiration, Indonesia requires GDP growth above historical average and structural transformation. The document also stated that, Indonesia should first improve the Total Factor Productivity (TFP) which in 2005-2019 grew negatively around 0.66, and to improve TFP, Indonesia requires HDI improvement, also research and innovation. Indonesia also requires growth in the industry sector as the most important factor to increase GDP, because Indonesia should pivot from hard commodities-based extraction and processing, especially coal and crude palm oil (CPO) which historically has had a positive major contribution to Indonesian balance of trade.\u0000 Since energy has a strong link with the economy and is crucial in maintaining or improving lifestyle (Chontanawat et al., 2008; King & Van Den Bergh, 2018; Stern, 2019). Indonesia will require energy to support its economic growth. In the context of energy challenges, Indonesia should balance the energy trilemmas, which based on the World Energy Council are energy affordability, security, and sustainability. Based on the current condition, to ensure affordability, the Indonesian government subsidizes fossil energy sources, such as gasoline, LPG, natural gas for certain industries, and electricity which is based on coal. Then, to ensure security, Indonesia has plans to reduce its dependence on oil import and currently utilize coal as one of its abundance resources. Finally, to ensure sustainability, Indonesia pledged to develop its economy based on low carbon energy, as stated in the enhanced Nationally Determined Contribution (eNDC) that Indonesia will achieve Net Zero Emission (NZE) in 2060 or sooner. However, the commitment","PeriodicalId":130107,"journal":{"name":"Day 1 Tue, September 05, 2023","volume":"11 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-09-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"126409090","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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