A. Parrella, S. Bughi, Giovanni Profeta, G. Curti, Henry Yuan, Amr Hailat, Marijn Hooghoudt, J. Francis, P. Watson
This paper is based on experience obtained during design of Payara Project, offshore Guyana, where 10" production and 16" water injection pipelines were found to be potentially susceptible to walking. Offshore pipelines that are subject to HT/HP conditions, riser tensions and seabed slopes can be susceptible to walking, which may jeopardize the integrity of connected subsea structures. Should the cumulated walking during the operating life of the pipeline exceed the maximum allowed displacement, an anchoring system could be required to mitigate the movement. However, predicting pipeline walking is a complex matter, depending on parameters often affected by significant uncertainty, such as pressure and temperature conditions, heating and cooldown cycles, soil pipe interaction, planned buckle evolution and route modifications. For this reason, a walking assessment performed during detail design can lead to uncertain results, and question arises as to the best timing to install walking mitigation structures (WMS). A Wait-and-See approach represents a good compromise, mediating between CAPEX and OPEX needs, and allowing a risk-based decision process based on pipeline behavior as monitored during planned surveys. However, the installation of WMS during operation may require ancillary structures to be installed on ‘day one’ that could nullify the strategic advantage given by the Wait-and-See, not to mention the mob/demob cost of the vessel used for installation. The Pipe Clamping Mattress (PCM), patented by Shell and commercialized by MMA Offshore, has been proposed as a convenient and effective way to anchor the pipeline, either at day one or during operation. The PCM comprises a two-winged mattress fabricated by pivoting two concrete blocks around a central hinge, and which is shaped to engage and clamp the pipe. A log mattress is then positioned to provide additional clamping force. The overall weight of PCM provides the clamping grip required to prevent pipeline slippage as well as the additional axial resistance needed to mitigate or arrest walking. An advanced FE Model for PCM performance study has been developed in ABAQUS based on the CEL methodology (Coupled Eulerian-Lagrangian). In comparison to more conventional models, this technique models the seabed as a deformable Eulerian domain, in which PCM and pipeline can penetrate. Seabed settlement and soil displacement due to system motion can be fully calculated, estimating the evolution of axial resistance and the growth of berms at the PCM sides. The objective of this paper is to improve the understanding of pipeline/PCM interaction, in particular with respect to: Verifying the overall embedment of the pipeline/PCM system.Verifying and assessing the PCM restraining capacity against axial displacement.Assessing the minimum number of PCMs required to ensure walking prevention/arrest.
{"title":"Advanced Modelling of Clamped Mattress for Pipeline Walking Prevention and Mitigation","authors":"A. Parrella, S. Bughi, Giovanni Profeta, G. Curti, Henry Yuan, Amr Hailat, Marijn Hooghoudt, J. Francis, P. Watson","doi":"10.4043/32620-ms","DOIUrl":"https://doi.org/10.4043/32620-ms","url":null,"abstract":"\u0000 This paper is based on experience obtained during design of Payara Project, offshore Guyana, where 10\" production and 16\" water injection pipelines were found to be potentially susceptible to walking. Offshore pipelines that are subject to HT/HP conditions, riser tensions and seabed slopes can be susceptible to walking, which may jeopardize the integrity of connected subsea structures. Should the cumulated walking during the operating life of the pipeline exceed the maximum allowed displacement, an anchoring system could be required to mitigate the movement. However, predicting pipeline walking is a complex matter, depending on parameters often affected by significant uncertainty, such as pressure and temperature conditions, heating and cooldown cycles, soil pipe interaction, planned buckle evolution and route modifications. For this reason, a walking assessment performed during detail design can lead to uncertain results, and question arises as to the best timing to install walking mitigation structures (WMS).\u0000 A Wait-and-See approach represents a good compromise, mediating between CAPEX and OPEX needs, and allowing a risk-based decision process based on pipeline behavior as monitored during planned surveys. However, the installation of WMS during operation may require ancillary structures to be installed on ‘day one’ that could nullify the strategic advantage given by the Wait-and-See, not to mention the mob/demob cost of the vessel used for installation.\u0000 The Pipe Clamping Mattress (PCM), patented by Shell and commercialized by MMA Offshore, has been proposed as a convenient and effective way to anchor the pipeline, either at day one or during operation. The PCM comprises a two-winged mattress fabricated by pivoting two concrete blocks around a central hinge, and which is shaped to engage and clamp the pipe. A log mattress is then positioned to provide additional clamping force. The overall weight of PCM provides the clamping grip required to prevent pipeline slippage as well as the additional axial resistance needed to mitigate or arrest walking.\u0000 An advanced FE Model for PCM performance study has been developed in ABAQUS based on the CEL methodology (Coupled Eulerian-Lagrangian). In comparison to more conventional models, this technique models the seabed as a deformable Eulerian domain, in which PCM and pipeline can penetrate. Seabed settlement and soil displacement due to system motion can be fully calculated, estimating the evolution of axial resistance and the growth of berms at the PCM sides. The objective of this paper is to improve the understanding of pipeline/PCM interaction, in particular with respect to: Verifying the overall embedment of the pipeline/PCM system.Verifying and assessing the PCM restraining capacity against axial displacement.Assessing the minimum number of PCMs required to ensure walking prevention/arrest.","PeriodicalId":196855,"journal":{"name":"Day 2 Tue, May 02, 2023","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2023-04-24","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"115923430","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 the search for attractive hydrocarbon resources, geological targets are often encountered that are designated as high-pressure, high-temperature (HPHT). To ensure an HPHT well meets or exceeds design life, a very thorough design review is needed for all aspects of the well architecture to ensure integrity is maintained throughout. Often overlooked, improper handling and installation through lack of knowledge, equipment selection, or technology have led to many well integrity issues in HPHT wells. The presence of certain corrosive downhole species, combined with the high temperatures and pressures of these wells can accelerate corrosion mechanisms on well bore tubulars at an early stage of the well's life. To address this challenge, corrosion resistant alloy (CRA) tubulars, along with temperature and pressure monitoring equipment, are often designed into the well architecture to ensure well integrity is preserved. These elements must be handled and installed carefully as impressions, marks, and cuts from make-up and handling operations can further accelerate corrosion failures on the tubular, such as stress corrosion cracking, while compromising the integrity of the downhole measuring equipment. To ensure these wells have the best chance of meeting target design life, special consideration should be given to the control line and tubing handling equipment. Specialized equipment, such as control line manipulation systems, offer extra protection to lines as they are manipulated for clamp installation, as well as increased safety and efficiency within the operations. Compensation systems prevent damage to threaded connections during stabbing and make-up while intelligent connection analyzed make-up systems use artificial intelligence and machine learning to provide real-time accurate, consistent, and reliable connection integrity assessments. And lastly, specialized reduced penetration or non-marking technologies can be utilized for make-up and handling of CRA tubulars to minimize or eliminate iron transfer and impressions imparted into the tubular body. By eliminating these, the potential for corrosion cracking due to stress concentrations and other risks of corrosion are also eliminated. One industry sponsored study examined the condition of 406 injection and production wells on the Norwegian shelf. Of these wells, 18% of the wells suffered from well integrity incidents, while nearly 40% of these incidents were due to the tubular string, emphasizing the need for specialized attention and equipment selections for HPHT wells.
{"title":"Best Practices for Handling Completion Tubulars to Ensure Design Life Well Integrity in HPHT Wells","authors":"J. Angelle, Neil Alleman","doi":"10.4043/32305-ms","DOIUrl":"https://doi.org/10.4043/32305-ms","url":null,"abstract":"\u0000 In the search for attractive hydrocarbon resources, geological targets are often encountered that are designated as high-pressure, high-temperature (HPHT). To ensure an HPHT well meets or exceeds design life, a very thorough design review is needed for all aspects of the well architecture to ensure integrity is maintained throughout. Often overlooked, improper handling and installation through lack of knowledge, equipment selection, or technology have led to many well integrity issues in HPHT wells.\u0000 The presence of certain corrosive downhole species, combined with the high temperatures and pressures of these wells can accelerate corrosion mechanisms on well bore tubulars at an early stage of the well's life. To address this challenge, corrosion resistant alloy (CRA) tubulars, along with temperature and pressure monitoring equipment, are often designed into the well architecture to ensure well integrity is preserved. These elements must be handled and installed carefully as impressions, marks, and cuts from make-up and handling operations can further accelerate corrosion failures on the tubular, such as stress corrosion cracking, while compromising the integrity of the downhole measuring equipment.\u0000 To ensure these wells have the best chance of meeting target design life, special consideration should be given to the control line and tubing handling equipment. Specialized equipment, such as control line manipulation systems, offer extra protection to lines as they are manipulated for clamp installation, as well as increased safety and efficiency within the operations. Compensation systems prevent damage to threaded connections during stabbing and make-up while intelligent connection analyzed make-up systems use artificial intelligence and machine learning to provide real-time accurate, consistent, and reliable connection integrity assessments. And lastly, specialized reduced penetration or non-marking technologies can be utilized for make-up and handling of CRA tubulars to minimize or eliminate iron transfer and impressions imparted into the tubular body. By eliminating these, the potential for corrosion cracking due to stress concentrations and other risks of corrosion are also eliminated. One industry sponsored study examined the condition of 406 injection and production wells on the Norwegian shelf. Of these wells, 18% of the wells suffered from well integrity incidents, while nearly 40% of these incidents were due to the tubular string, emphasizing the need for specialized attention and equipment selections for HPHT wells.","PeriodicalId":196855,"journal":{"name":"Day 2 Tue, May 02, 2023","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2023-04-24","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"114534626","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}
E. Sørgård, Elizabeth Anne Oko, John Isaac Baird, Jason Alexander Greenaway, Rob Rabei, Pradeep Pillai, Stacy Marie Fresquez
The Vito field is located in 4,100 feet of water producing from reservoirs nearly 30,000 feet below sea level. Vito was discovered in 2009 approximately 135 miles southwest of New Orleans, Louisiana. The project underwent major field development strategy change to remain competitive in 2015 oil price environment and price resiliency going forward. The Vito project was seen as a strategic fit to the operator's existing Mars Corridor. The original Vito development strategy was to build a clone of the mega-project of Appomattox to maximize Net Present Value and Ultimate Recovery. However, as the market changed vastly in 2015, the project team refreshed the design concept to focus on capital efficiency. This paper provides an overview of the overall revised Field Development Concept of Vito. Vito has best in class resource density when compared to other Gulf of Mexico fields, which allows for a compact field development of 8 subsea wells at a single drill center. This allowed the project to not include a drilling rig on the host platform and instead deploy a new generation Deepwater rig for drilling and completions. There is severe depletion drilling risk on Vito which led the project to drill and complete all 8 wells prior to first oil. To improve ultimate recovery with low capital efficiency in well bore gas lift was included in the design. In addition, the Mars Corridor export system was looked at and required debottlenecking on both the oil and gas side. This paper is part of a Vito Project series at OTC 2023, and the other papers are listed in the references.
{"title":"Vito Project: Vito Field Development","authors":"E. Sørgård, Elizabeth Anne Oko, John Isaac Baird, Jason Alexander Greenaway, Rob Rabei, Pradeep Pillai, Stacy Marie Fresquez","doi":"10.4043/32319-ms","DOIUrl":"https://doi.org/10.4043/32319-ms","url":null,"abstract":"\u0000 The Vito field is located in 4,100 feet of water producing from reservoirs nearly 30,000 feet below sea level. Vito was discovered in 2009 approximately 135 miles southwest of New Orleans, Louisiana. The project underwent major field development strategy change to remain competitive in 2015 oil price environment and price resiliency going forward.\u0000 The Vito project was seen as a strategic fit to the operator's existing Mars Corridor. The original Vito development strategy was to build a clone of the mega-project of Appomattox to maximize Net Present Value and Ultimate Recovery. However, as the market changed vastly in 2015, the project team refreshed the design concept to focus on capital efficiency.\u0000 This paper provides an overview of the overall revised Field Development Concept of Vito. Vito has best in class resource density when compared to other Gulf of Mexico fields, which allows for a compact field development of 8 subsea wells at a single drill center. This allowed the project to not include a drilling rig on the host platform and instead deploy a new generation Deepwater rig for drilling and completions. There is severe depletion drilling risk on Vito which led the project to drill and complete all 8 wells prior to first oil. To improve ultimate recovery with low capital efficiency in well bore gas lift was included in the design. In addition, the Mars Corridor export system was looked at and required debottlenecking on both the oil and gas side.\u0000 This paper is part of a Vito Project series at OTC 2023, and the other papers are listed in the references.","PeriodicalId":196855,"journal":{"name":"Day 2 Tue, May 02, 2023","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2023-04-24","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"125918419","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}
K. Klungtvedt, Jan Kristian Vasshus, Gunvald Nesheim, P. D. Scott
The objective is to understand the impact of applying lost circulation materials preventatively to achieve strengthening of the wellbore when drilling fractured carbonate reservoirs. With a successful application, drilling with higher differential pressure can be enabled so that longer reservoir sections may be drilled, avoid splitting sections, and more remote parts of the reservoir may be reached. Having conducted extensive laboratory tests to evaluate the sealing strength, ease of mixing and circulation, resistance towards degradation, and the abrasivity (erosivity) of selected lost circulation materials, a novel loss prevention material (LPM) product was selected for application into multiple wells. A simple model was developed to predict the wellbore strengthening effect for a given concentration of the product in the fluid system. The product was thereafter applied preventatively for drilling slim-hole reservoir sections in deviated wells on the Norwegian Continental Shelf, where differential pressures were expected to be challenging. An LPM recovery system was used to maintain desired concentrations of LPM in the active system. Data were collected from the operations to provide a robust understanding of the ease of application and the functionality of the selected LPM material. Multiple fractured carbonate reservoirs were drilled under different pore-pressure conditions and with different drilling fluid densities. The results show that wells could be drilled without losses in conditions of around 2,400 psi overbalance, with product concentrations of less than half the maximum tested concentrations. Also, a field record of drilling a long horizontal reservoir section without tool failure was set, under conditions of unexpectedly high pore-pressures. The LPM recovery system proved to be successful with the novel materials, and very high rates of product retention was obtained, proving both the efficiency of the recovery plan and the material's resistance towards degradation. The field application highlights the potential for preventative treatment of the drilling fluid to achieve a strengthening of the wellbore and to integrate this with a simple method for estimating the fracture pressure of the formation at various levels of product concentrations. With this information in hand, both producer and injector wells can be planned for more optimal placements in the reservoir to enhance oil recovery.
{"title":"Managing High Differential Pressures in Fractured Carbonate Reservoir by Use of Wellbore Strengthening Material","authors":"K. Klungtvedt, Jan Kristian Vasshus, Gunvald Nesheim, P. D. Scott","doi":"10.4043/32173-ms","DOIUrl":"https://doi.org/10.4043/32173-ms","url":null,"abstract":"\u0000 The objective is to understand the impact of applying lost circulation materials preventatively to achieve strengthening of the wellbore when drilling fractured carbonate reservoirs. With a successful application, drilling with higher differential pressure can be enabled so that longer reservoir sections may be drilled, avoid splitting sections, and more remote parts of the reservoir may be reached.\u0000 Having conducted extensive laboratory tests to evaluate the sealing strength, ease of mixing and circulation, resistance towards degradation, and the abrasivity (erosivity) of selected lost circulation materials, a novel loss prevention material (LPM) product was selected for application into multiple wells. A simple model was developed to predict the wellbore strengthening effect for a given concentration of the product in the fluid system. The product was thereafter applied preventatively for drilling slim-hole reservoir sections in deviated wells on the Norwegian Continental Shelf, where differential pressures were expected to be challenging. An LPM recovery system was used to maintain desired concentrations of LPM in the active system. Data were collected from the operations to provide a robust understanding of the ease of application and the functionality of the selected LPM material.\u0000 Multiple fractured carbonate reservoirs were drilled under different pore-pressure conditions and with different drilling fluid densities. The results show that wells could be drilled without losses in conditions of around 2,400 psi overbalance, with product concentrations of less than half the maximum tested concentrations. Also, a field record of drilling a long horizontal reservoir section without tool failure was set, under conditions of unexpectedly high pore-pressures. The LPM recovery system proved to be successful with the novel materials, and very high rates of product retention was obtained, proving both the efficiency of the recovery plan and the material's resistance towards degradation.\u0000 The field application highlights the potential for preventative treatment of the drilling fluid to achieve a strengthening of the wellbore and to integrate this with a simple method for estimating the fracture pressure of the formation at various levels of product concentrations. With this information in hand, both producer and injector wells can be planned for more optimal placements in the reservoir to enhance oil recovery.","PeriodicalId":196855,"journal":{"name":"Day 2 Tue, May 02, 2023","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2023-04-24","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"122932357","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}
Ann Jie Lim, Abigail Lian De Cruz, Lakshmi Narayana Koyyalamudi, Mohd Syahezat Ismail, Azri Khairudin, Mohd Shakir Mohd Nawi, Izyan Haziqah Isrofeil, Luqman Hakim Zulkafli, M. S. M. Adib, Arsyamimi Mohamed
Producing wells in Field T, Malaysia offshore have faced significant production impairment due to deposition of calcite and barite scale in the tubing and reservoir. A proactive approach is strategized to inhibit the scale formation along the inner wall of production tubing and reservoir through a scale inhibitor squeeze (SISQ) treatment with a lifespan of 2 years. The main objective of this approach is to eliminate the need of frequent stimulation jobs to maintain the production. Several attempts of scale inhibitor pumping in the past had been applied in the operator's production fields with different scale inhibitor (SI) formulations. However, some of the SISQ jobs were unsuccessful meanwhile some did not meet the treatment life targeted. A Root Cause Failure Analysis (RCFA) was conducted and the best practices and recommendations from the previous scale treatments were incorporated into this scale inhibitor squeeze treatment while the lessons learnt were implemented to prevent reoccurrence of unwanted events. In the past, most of the failed acidizing and SISQ jobs were caused by misdiagnosis of the root cause of production drop in wells, causing wrong selection of candidates right from the beginning. Another cause is the reaction between the chemical and existing scale in the tubing wall that resulted in the disintegration of the deposits, which subsequently block the flow of the well. There were also instances where coreflooding tests were not conducted due to unavailability of core samples. From the past failure contributors, the best practice proposed is to initiate any scale inhibition program by determining the correct root cause of production drop and to proceed with remedying the existing scale buildup. Examples of the solutions are through scale clean out, acidizing or workover before implementing a prevention solution such as SISQ. During the chemical selection stage, scale inhibitors should be selected based on a series of lab tests to study the performance of scale inhibitors, potential of damage formation, scale inhibitor retention core flood analysis, scale inhibitor thermal stability and fluids compatibility. Both wells B15 and D04 SS on which the SISQ jobs were conducted after acidizing job, have until now sustained their production. The MIC is well above 5 ppm target although approaching the end of 2-year treatment life. The Multifinger Imaging Tool (MIT) run downhole after one and a half years also indicated insignificant scale buildup on tubing wall. Permanent downhole gauge flowing pressure is also stable indicating no severe skin buildup. The produced water ions data, however, is insufficient to provide a view on the upward or downward trend of the scaling ions. In future replications, produced water ions sampling frequency should be increased.
{"title":"Case Study: Effective and Economical Approach to Prevent Scale Formation Using Scale Inhibitor Squeeze into Reservoir","authors":"Ann Jie Lim, Abigail Lian De Cruz, Lakshmi Narayana Koyyalamudi, Mohd Syahezat Ismail, Azri Khairudin, Mohd Shakir Mohd Nawi, Izyan Haziqah Isrofeil, Luqman Hakim Zulkafli, M. S. M. Adib, Arsyamimi Mohamed","doi":"10.4043/32456-ms","DOIUrl":"https://doi.org/10.4043/32456-ms","url":null,"abstract":"\u0000 Producing wells in Field T, Malaysia offshore have faced significant production impairment due to deposition of calcite and barite scale in the tubing and reservoir. A proactive approach is strategized to inhibit the scale formation along the inner wall of production tubing and reservoir through a scale inhibitor squeeze (SISQ) treatment with a lifespan of 2 years. The main objective of this approach is to eliminate the need of frequent stimulation jobs to maintain the production.\u0000 Several attempts of scale inhibitor pumping in the past had been applied in the operator's production fields with different scale inhibitor (SI) formulations. However, some of the SISQ jobs were unsuccessful meanwhile some did not meet the treatment life targeted. A Root Cause Failure Analysis (RCFA) was conducted and the best practices and recommendations from the previous scale treatments were incorporated into this scale inhibitor squeeze treatment while the lessons learnt were implemented to prevent reoccurrence of unwanted events.\u0000 In the past, most of the failed acidizing and SISQ jobs were caused by misdiagnosis of the root cause of production drop in wells, causing wrong selection of candidates right from the beginning. Another cause is the reaction between the chemical and existing scale in the tubing wall that resulted in the disintegration of the deposits, which subsequently block the flow of the well. There were also instances where coreflooding tests were not conducted due to unavailability of core samples. From the past failure contributors, the best practice proposed is to initiate any scale inhibition program by determining the correct root cause of production drop and to proceed with remedying the existing scale buildup. Examples of the solutions are through scale clean out, acidizing or workover before implementing a prevention solution such as SISQ. During the chemical selection stage, scale inhibitors should be selected based on a series of lab tests to study the performance of scale inhibitors, potential of damage formation, scale inhibitor retention core flood analysis, scale inhibitor thermal stability and fluids compatibility.\u0000 Both wells B15 and D04 SS on which the SISQ jobs were conducted after acidizing job, have until now sustained their production. The MIC is well above 5 ppm target although approaching the end of 2-year treatment life. The Multifinger Imaging Tool (MIT) run downhole after one and a half years also indicated insignificant scale buildup on tubing wall. Permanent downhole gauge flowing pressure is also stable indicating no severe skin buildup. The produced water ions data, however, is insufficient to provide a view on the upward or downward trend of the scaling ions. In future replications, produced water ions sampling frequency should be increased.","PeriodicalId":196855,"journal":{"name":"Day 2 Tue, May 02, 2023","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2023-04-24","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"132441658","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}
Legal Notice: Any use of trade, product, methods, terminology (lingo, etc.) or firm names are for descriptive purposes only and do not imply endorsement by that company, Hilcorp Alaska, LLC, or any of its affiliates or parent company. The objectives of this paper are to highlight the following: The complexities of managing and maintaining a fleet of aging offshore infrastructure in Cook Inlet, Alaska, using conventional and unconventional methods. The continued search for innovative solutions and refining current processes to extend the life of these facilities. Once the facilities have reached the end of their producing life, retrofit for other potential useful opportunities such as capitalizing on the renewable resource possibilities Cook Inlet possesses. Cook Inlet, Alaska is the state's main industrial water way and home to 15 offshore production platforms owned and operated by Hilcorp Alaska. Operating in the Cook Inlet is extremely complex and difficult because of its unique environment. Many of those 15 platforms were installed in the 1960's and originally thought to have short life expectancy. Over 60 years later, due to regular inspections and repairs guided by API 2 SIM, most of the facilities are still producing. Many typical forms of inspections and repairs cannot be conducted in Cook Inlet. Operators, inspectors, contractors, and divers must get creative to overcome many hurdles to achieve the tasks necessary for operation and structural integrity. When platforms go through the P&A process, the threat of environmental hydrocarbon pollution is removed. Hilcorp is currently looking into renewable resource opportunities for these structures to further achieve its goal of extending the useful opportunities of these facilities, given their robust infrastructure. This paper details the continuing challenges and constant search for new technologies. The hope is to educate the industry on the specific resources and technology that is needed in Cook Inlet and sharing the unconventional methods that have been developed over the years. This paper does not discuss downhole operations.
{"title":"Overcoming the Challenges and Complexities of Maintaining the Integrity of Subsea Infrastructure in Cook Inlet, Alaska","authors":"Rachel B. Kidwell, Tasha M. Bacher","doi":"10.4043/32345-ms","DOIUrl":"https://doi.org/10.4043/32345-ms","url":null,"abstract":"\u0000 Legal Notice: Any use of trade, product, methods, terminology (lingo, etc.) or firm names are for descriptive purposes only and do not imply endorsement by that company, Hilcorp Alaska, LLC, or any of its affiliates or parent company.\u0000 \u0000 \u0000 The objectives of this paper are to highlight the following:\u0000 The complexities of managing and maintaining a fleet of aging offshore infrastructure in Cook Inlet, Alaska, using conventional and unconventional methods. The continued search for innovative solutions and refining current processes to extend the life of these facilities. Once the facilities have reached the end of their producing life, retrofit for other potential useful opportunities such as capitalizing on the renewable resource possibilities Cook Inlet possesses.\u0000 \u0000 \u0000 \u0000 \u0000 \u0000 \u0000 Cook Inlet, Alaska is the state's main industrial water way and home to 15 offshore production platforms owned and operated by Hilcorp Alaska. Operating in the Cook Inlet is extremely complex and difficult because of its unique environment.\u0000 Many of those 15 platforms were installed in the 1960's and originally thought to have short life expectancy. Over 60 years later, due to regular inspections and repairs guided by API 2 SIM, most of the facilities are still producing.\u0000 Many typical forms of inspections and repairs cannot be conducted in Cook Inlet. Operators, inspectors, contractors, and divers must get creative to overcome many hurdles to achieve the tasks necessary for operation and structural integrity.\u0000 When platforms go through the P&A process, the threat of environmental hydrocarbon pollution is removed. Hilcorp is currently looking into renewable resource opportunities for these structures to further achieve its goal of extending the useful opportunities of these facilities, given their robust infrastructure.\u0000 \u0000 \u0000 \u0000 This paper details the continuing challenges and constant search for new technologies. The hope is to educate the industry on the specific resources and technology that is needed in Cook Inlet and sharing the unconventional methods that have been developed over the years.\u0000 This paper does not discuss downhole operations.\u0000","PeriodicalId":196855,"journal":{"name":"Day 2 Tue, May 02, 2023","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2023-04-24","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"132626613","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 northern Gulf of Mexico basin contains geopressured zones ideal for geothermal energy production, still to be explored. These systems are defined by primarily Eocene to Miocene sands that are confined by shale beds, which facilitates the formation of anomalously high pressures and temperatures. The overpressure in these zones results in an increased geothermal gradient, which makes geopressured zones of interest for geothermal exploration. Resources are commonly found at 3 to 6 km depth and reservoir fluid temperatures can range from 90 to 200°C. There has been a substantial amount of work done to understand these geopressured reservoirs on the Gulf Coast for geothermal potential. Many of these geopressured zones extend and exist offshore in the Gulf of Mexico. The knowledge and technical success of wells completed in these geopressured zones onshore can be transferred to understand how to produce a high pressure high temperature offshore well for geothermal power production. This paper will provide a review of previous work on geopressured geothermal zones in the Gulf Coast, the challenges with these systems, how these were overcome, and the knowledge transfer of those findings for offshore geothermal opportunities in high pressure high temperature wells.
{"title":"Geopressured Geothermal – Correlations to Offshore High Pressure High Temperature Geothermal Opportunities","authors":"Joseph F. Batir, E. Gentry, H. Soroush","doi":"10.4043/32407-ms","DOIUrl":"https://doi.org/10.4043/32407-ms","url":null,"abstract":"\u0000 The northern Gulf of Mexico basin contains geopressured zones ideal for geothermal energy production, still to be explored. These systems are defined by primarily Eocene to Miocene sands that are confined by shale beds, which facilitates the formation of anomalously high pressures and temperatures. The overpressure in these zones results in an increased geothermal gradient, which makes geopressured zones of interest for geothermal exploration. Resources are commonly found at 3 to 6 km depth and reservoir fluid temperatures can range from 90 to 200°C. There has been a substantial amount of work done to understand these geopressured reservoirs on the Gulf Coast for geothermal potential. Many of these geopressured zones extend and exist offshore in the Gulf of Mexico. The knowledge and technical success of wells completed in these geopressured zones onshore can be transferred to understand how to produce a high pressure high temperature offshore well for geothermal power production. This paper will provide a review of previous work on geopressured geothermal zones in the Gulf Coast, the challenges with these systems, how these were overcome, and the knowledge transfer of those findings for offshore geothermal opportunities in high pressure high temperature wells.","PeriodicalId":196855,"journal":{"name":"Day 2 Tue, May 02, 2023","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2023-04-24","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"131748999","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}
X. Long, Jack Fraser, S. Adhikari, Deanne Hargrave, P. Peralta, Craig Scherschel
An offshore geotechnical site investigation campaign was completed for a large wind farm development project along the US Atlantic Outer Continental Shelf (OCS) offshore New Jersey, a frontier location with few published data on soil characterization. Field exploration and a comprehensive onshore geotechnical laboratory testing program have been performed to understand the site-specific soil behavior. This paper describes the geotechnical properties of the fine-grained cohesive sediments encountered at the study site interpreted based on a consistent framework leveraging the sitewide soil data. Discussions of sample quality, soil stress history, soil compressibility and permeability, peak and critical state shear strength, strength anisotropy, and shearing rate effect for the Atlantic OCS fine-grained cohesive soils are presented from oedometer consolidation, permeability, direct simple shear, ring shear, and K0-consolidated triaxial compression and extension tests along with other conventional index and property tests. Furthermore, the Stress History and Normalized Soil Engineering Properties (SHANSEP) parameters, namely S and m, for the cohesive soils, are developed based on the specific monotonic constant volume direct simple shear (CVDSS) tests. The undrained shear strength Su profiles within the specific geotechnical cohesive soil unit developed from the SHANSEP and SP-SPW methods (Quiros, 2000) is compared to the site-specific PCPT data and laboratory undrained shear strength measurements. Comparisons of the discussed engineering properties of the Atlantic OCS fine-grained soils with other published databases for soils of the Gulf of Mexico (GOM), Offshore Trinidad, and Offshore Mozambique also are included. This paper is in a collaborative series that demonstrates the value of an integrated geoscience approach considering regulatory requirements and project design essentials. It provides a comprehensive overview of the engineering characteristics of the Atlantic OCS fine-grained soils and can assist engineers with the assignation of rate-dependant undrained shear strength parameters developed specifically for wind farm foundation design with applicability in a regional setting.
{"title":"Geotechnical Characterization of the US Atlantic Outer Continental Shelf Fine-Grained Cohesive Sediments","authors":"X. Long, Jack Fraser, S. Adhikari, Deanne Hargrave, P. Peralta, Craig Scherschel","doi":"10.4043/32197-ms","DOIUrl":"https://doi.org/10.4043/32197-ms","url":null,"abstract":"\u0000 An offshore geotechnical site investigation campaign was completed for a large wind farm development project along the US Atlantic Outer Continental Shelf (OCS) offshore New Jersey, a frontier location with few published data on soil characterization. Field exploration and a comprehensive onshore geotechnical laboratory testing program have been performed to understand the site-specific soil behavior. This paper describes the geotechnical properties of the fine-grained cohesive sediments encountered at the study site interpreted based on a consistent framework leveraging the sitewide soil data. Discussions of sample quality, soil stress history, soil compressibility and permeability, peak and critical state shear strength, strength anisotropy, and shearing rate effect for the Atlantic OCS fine-grained cohesive soils are presented from oedometer consolidation, permeability, direct simple shear, ring shear, and K0-consolidated triaxial compression and extension tests along with other conventional index and property tests.\u0000 Furthermore, the Stress History and Normalized Soil Engineering Properties (SHANSEP) parameters, namely S and m, for the cohesive soils, are developed based on the specific monotonic constant volume direct simple shear (CVDSS) tests. The undrained shear strength Su profiles within the specific geotechnical cohesive soil unit developed from the SHANSEP and SP-SPW methods (Quiros, 2000) is compared to the site-specific PCPT data and laboratory undrained shear strength measurements. Comparisons of the discussed engineering properties of the Atlantic OCS fine-grained soils with other published databases for soils of the Gulf of Mexico (GOM), Offshore Trinidad, and Offshore Mozambique also are included.\u0000 This paper is in a collaborative series that demonstrates the value of an integrated geoscience approach considering regulatory requirements and project design essentials. It provides a comprehensive overview of the engineering characteristics of the Atlantic OCS fine-grained soils and can assist engineers with the assignation of rate-dependant undrained shear strength parameters developed specifically for wind farm foundation design with applicability in a regional setting.","PeriodicalId":196855,"journal":{"name":"Day 2 Tue, May 02, 2023","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2023-04-24","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"133859090","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}
Luis Longhi Escarcena, Rafael Andrade Alves, Audrey Alves Monlevade, Yuri Lavagnino Camargo, Thais Borba Santos, L. Nakajima, G. Cuadros, Ligia de Matos, M. Viandante, D. Salim, Y. Abbas
The Frade field, located in Campos Basin, offshore Brazil, is currently being developed using the latest advancements in reservoir mapping-while-drilling (RMWD) systems to aid horizontal well placement and enhance reservoir characterization. The technologies implemented include the high-definition (HD-RMWD), and the three-dimensional (3D-RMWD) systems, which convert ultra-deep electromagnetic measurements into a map of the resistivity profile around the borehole. The HD-RMWD provides multilayer detection using a 1D deterministic parametric inversion engine that provides a detailed 2D resistivity map along the well trajectory, resulting in enhanced capabilities for geosteering and reservoir characterization. This system was implemented in the horizontal wells drilled in Frade since 2022. For landing, an actual vertical detection of around 20 m TVD has helped to set casing in the desired target, identifying the presence of shallower layers—that could result in a poor landing—when present. Within the reservoir, the radial depth of detection achieved with a two-receiver configuration was on the order of 30 m TVD, enough to map top and base of sandstone geobodies while identifying the occurrence and dipping of multiple thin beds. The 3D-RMWD extends the application of this type of technology to the most complex reservoir settings and enables azimuthal geosteering. A set of new measurements—the full 360° electromagnetic tensor—is acquired and transmitted in real time using a new data compression algorithm, and then converted into 3D resistivity volumes derived from a cloud-based 2D transverse inversion technique. Results from the use of the 3D-RMWD technology in Frade—first case in Brazil's offshore operation—showed the 3D mapping capability of different geobodies in a complex geological environment. It also showed how reservoir properties were changing transversally along the well trajectory. A previous-generation RMWD system was used in offshore Brazil for 13 years, and this paper presents the experience gained from using the latest developments. The HD-RMWD system represents a significant advance by providing a finer resistivity map around the borehole, while the 3D-RMWD technology opens a whole new area of application, especially for complex reservoir characterization and provides means for azimuthal geosteering, which is currently an avoided practice.
trade油田位于巴西海上Campos盆地，目前正在使用最新的随钻储层测绘(RMWD)系统进行开发，以帮助水平井定位并增强储层特征。实施的技术包括高清(HD-RMWD)和三维(3D-RMWD)系统，它们将超深电磁测量结果转换为井眼周围的电阻率剖面图。HD-RMWD采用一维确定性参数反演引擎进行多层探测，该引擎可沿井眼轨迹提供详细的二维电阻率图，从而增强了地质导向和储层表征的能力。自2022年以来，该系统已在trade地区的水平井中实施。在着陆时，实际的垂直探测深度约为20m TVD，这有助于将套管定位到目标位置，识别出较浅地层的存在，而较浅地层可能导致着陆效果不佳。在储层内，双接收器配置的径向探测深度约为30 m TVD，足以绘制砂岩地质体的顶部和底部，同时识别多个薄层的产状和倾斜。3D-RMWD将这种技术的应用范围扩展到最复杂的油藏环境，并实现了方位地质导向。利用一种新的数据压缩算法获取并实时传输一组新的测量数据——完整的360°电磁张量，然后通过基于云的二维横向反演技术转换成三维电阻率体积。3D- rmwd技术在巴西海上作业中的应用结果表明，在复杂的地质环境中，该技术具有对不同地质体进行三维测绘的能力。它还显示了储层性质是如何沿着井眼轨迹横向变化的。上一代RMWD系统在巴西海上已经使用了13年，本文介绍了使用最新开发成果所获得的经验。HD-RMWD系统通过提供井眼周围更精细的电阻率图代表了一项重大进步，而3D-RMWD技术开辟了一个全新的应用领域，特别是对于复杂的储层表征，并提供了方位角地质导向的手段，这是目前避免的做法。
{"title":"Optimizing Horizontal Well Placement in Turbidite Sands with the Use of New Reservoir Mapping-While-Drilling Systems: A Case Study from Offshore Brazil","authors":"Luis Longhi Escarcena, Rafael Andrade Alves, Audrey Alves Monlevade, Yuri Lavagnino Camargo, Thais Borba Santos, L. Nakajima, G. Cuadros, Ligia de Matos, M. Viandante, D. Salim, Y. Abbas","doi":"10.4043/32476-ms","DOIUrl":"https://doi.org/10.4043/32476-ms","url":null,"abstract":"\u0000 The Frade field, located in Campos Basin, offshore Brazil, is currently being developed using the latest advancements in reservoir mapping-while-drilling (RMWD) systems to aid horizontal well placement and enhance reservoir characterization. The technologies implemented include the high-definition (HD-RMWD), and the three-dimensional (3D-RMWD) systems, which convert ultra-deep electromagnetic measurements into a map of the resistivity profile around the borehole.\u0000 The HD-RMWD provides multilayer detection using a 1D deterministic parametric inversion engine that provides a detailed 2D resistivity map along the well trajectory, resulting in enhanced capabilities for geosteering and reservoir characterization. This system was implemented in the horizontal wells drilled in Frade since 2022. For landing, an actual vertical detection of around 20 m TVD has helped to set casing in the desired target, identifying the presence of shallower layers—that could result in a poor landing—when present. Within the reservoir, the radial depth of detection achieved with a two-receiver configuration was on the order of 30 m TVD, enough to map top and base of sandstone geobodies while identifying the occurrence and dipping of multiple thin beds.\u0000 The 3D-RMWD extends the application of this type of technology to the most complex reservoir settings and enables azimuthal geosteering. A set of new measurements—the full 360° electromagnetic tensor—is acquired and transmitted in real time using a new data compression algorithm, and then converted into 3D resistivity volumes derived from a cloud-based 2D transverse inversion technique. Results from the use of the 3D-RMWD technology in Frade—first case in Brazil's offshore operation—showed the 3D mapping capability of different geobodies in a complex geological environment. It also showed how reservoir properties were changing transversally along the well trajectory.\u0000 A previous-generation RMWD system was used in offshore Brazil for 13 years, and this paper presents the experience gained from using the latest developments. The HD-RMWD system represents a significant advance by providing a finer resistivity map around the borehole, while the 3D-RMWD technology opens a whole new area of application, especially for complex reservoir characterization and provides means for azimuthal geosteering, which is currently an avoided practice.","PeriodicalId":196855,"journal":{"name":"Day 2 Tue, May 02, 2023","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2023-04-24","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"133101776","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}
Adriano Gouveia Lima Gomes dos Passos, Gabriela Márcia Ribeiro Menezes, Flank Melo de Lima, T. Piedade, Laura Correa Musgueira Geraci, Rafael Peralta Moreira, Glaydson Ismael Machado dos Reis
Drilling wells with TOT-3P design consists of optimizing (reducing) the steps of well construction. Drilling takes place in 3 sections (3P=3 phases) and the completion, sand containment screen plus production column (upper and lower), is performed in a single trip (TOT = True One Trip). The construction of wells in 3 sections is only possible with the deepening of the casing of the second section of the well and the capacity of this casing to have the function of surface and production. Some challenges stand out this project, such as the gain of inclination, cleaning and stability of the open well in a riserless phase, in addition to the need to return cement to the mud line for structural purposes and guarantee the solidarity set of barriers. Because drilling has only three sections, the shoe surface/production casing should be deepened in such a way that it is competent to withstand the production loadings, the pressure influence of injector wells and compose the solidary set of barriers (SSB) for abandonment, as well as enable the installation of components of the tubing at the required depth, such as the gas lift mandrel (GLM). To analyze the feasibility of the TOT-3P project, some points are studied: Analysis of flow potential of the shallow sands crossed in section II;Surface/production casing shoe racing analysis for well construction and for well productive life;Depths of tubing modulates (PDG, chemical injection mandrel and gas lift mandrel) to meet production monitoring, combat fouling and well production. Thus, integrated strategies for Drilling, Fluids and Cementation were defined in order to obtain the objectives mentioned through a bore caliper with diameter that allows a good cementation to be performed and obtained a satisfactory result in the cementation evaluation profiles, leading to the return of cement to mud line and composition of 2 solidary sets of barriers in annular above the reservoir.
采用TOT-3P设计钻井包括优化(减少)井的施工步骤。钻井分3段进行(3P=3个阶段)，完井、防砂筛管和生产柱(上、下)在一次起下钻中完成(TOT = True One trip)。三段井的建设只有在第二段井的套管加深和该套管具有地面和生产功能的能力的情况下才有可能。该项目还面临着一些挑战，比如斜度的增加、无隔水管阶段裸井的清洁和稳定性，以及为了结构目的需要将水泥回流到泥浆线，并保证屏障的完整性。由于钻井只有三个部分，因此鞋面/生产套管的深度应该能够承受生产载荷、注入井的压力影响，并形成一套完整的弃井屏障(SSB)，同时能够在所需的深度安装油管部件，如气举心轴(GLM)。为了分析TOT-3P项目的可行性，从以下几个方面进行了研究:第二段浅层砂层流过的流动潜力分析;井底/生产套管鞋对油井建设和生产寿命的影响分析;油管深度调节(PDG、化学注入心轴和气举心轴)以满足生产监测、抗结垢和油井生产的需要。因此，为了实现上述目标，制定了钻井、流体和固井的综合策略，通过直径较大的井径，可以进行良好的固井作业，并在固井评估剖面中获得满意的结果，导致水泥回流到泥浆线，并在油藏上方的环空中形成两套完整的屏障。
{"title":"Reduction of Well Construction Time with Innovative Design: Tot-3p (True One Trip - 3 Phases)","authors":"Adriano Gouveia Lima Gomes dos Passos, Gabriela Márcia Ribeiro Menezes, Flank Melo de Lima, T. Piedade, Laura Correa Musgueira Geraci, Rafael Peralta Moreira, Glaydson Ismael Machado dos Reis","doi":"10.4043/32642-ms","DOIUrl":"https://doi.org/10.4043/32642-ms","url":null,"abstract":"\u0000 Drilling wells with TOT-3P design consists of optimizing (reducing) the steps of well construction. Drilling takes place in 3 sections (3P=3 phases) and the completion, sand containment screen plus production column (upper and lower), is performed in a single trip (TOT = True One Trip).\u0000 The construction of wells in 3 sections is only possible with the deepening of the casing of the second section of the well and the capacity of this casing to have the function of surface and production. Some challenges stand out this project, such as the gain of inclination, cleaning and stability of the open well in a riserless phase, in addition to the need to return cement to the mud line for structural purposes and guarantee the solidarity set of barriers.\u0000 Because drilling has only three sections, the shoe surface/production casing should be deepened in such a way that it is competent to withstand the production loadings, the pressure influence of injector wells and compose the solidary set of barriers (SSB) for abandonment, as well as enable the installation of components of the tubing at the required depth, such as the gas lift mandrel (GLM).\u0000 To analyze the feasibility of the TOT-3P project, some points are studied: Analysis of flow potential of the shallow sands crossed in section II;Surface/production casing shoe racing analysis for well construction and for well productive life;Depths of tubing modulates (PDG, chemical injection mandrel and gas lift mandrel) to meet production monitoring, combat fouling and well production.\u0000 Thus, integrated strategies for Drilling, Fluids and Cementation were defined in order to obtain the objectives mentioned through a bore caliper with diameter that allows a good cementation to be performed and obtained a satisfactory result in the cementation evaluation profiles, leading to the return of cement to mud line and composition of 2 solidary sets of barriers in annular above the reservoir.","PeriodicalId":196855,"journal":{"name":"Day 2 Tue, May 02, 2023","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2023-04-24","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"131960577","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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