Thomas A. Preli, A. D. Shirolikar, William Thomas Dick, K. Thurston, Daria Igorevna Bougai, Joseph Cordoway, David Michael Dauterive
In 2009, the Vito field was discovered in more than 4,000 ft of water approximately 150 miles offshore from New Orleans, Louisiana. The project produces from reservoirs nearly 30,000 feet below sea level. This paper will discuss how a Deep Water development operator ("Development Operator") worked with two pipeline operators ("Pipeline Operators") to enable the Vito project and advance Deep Water together through care and simplicity. While the three companies had independent scopes of work, there were many opportunities for synergies during the project execution to deliver a cost competitive and integrated export solution. A "fit for purpose" approach was applied to achieve a common goal. The Vito project went through an optimization process called Minimum Technical Scope (MTS) to enable expected enhanced safety performance, better environmental performance, and lower unit development costs. The topics discussed in this paper can be applied to future deep-water developments around the globe where the development operator does not have a direct ownership interest in the export pipelines. In addition, certain concepts could be applied on projects where the development operator is responsible for the entire deep-water development. This paper discusses the scoping decisions taken across the integrated export system and how trade-offs were assessed to arrive at the MTS solution. The benefits that a common strategy can deliver for materials and installation, common construction equipment mobilizations and demobilizations, and the safety and environmental benefits from the coordination are addressed. Lastly, the paper discusses the working relationship between the Operators. Cost competitiveness can be a challenge for every deep water project. Many of the items discussed in this paper hopefully provoke future development operators to apply some of the concepts so that deep-water can advance with care and simplicity. This paper is part of a Vito Project series at OTC 2023, and the other papers are listed in the references.
{"title":"Vito Project: A Case Study Between a Development Operator and Pipeline Operators Advancing Deep Water Together","authors":"Thomas A. Preli, A. D. Shirolikar, William Thomas Dick, K. Thurston, Daria Igorevna Bougai, Joseph Cordoway, David Michael Dauterive","doi":"10.4043/32261-ms","DOIUrl":"https://doi.org/10.4043/32261-ms","url":null,"abstract":"\u0000 In 2009, the Vito field was discovered in more than 4,000 ft of water approximately 150 miles offshore from New Orleans, Louisiana. The project produces from reservoirs nearly 30,000 feet below sea level. This paper will discuss how a Deep Water development operator (\"Development Operator\") worked with two pipeline operators (\"Pipeline Operators\") to enable the Vito project and advance Deep Water together through care and simplicity. While the three companies had independent scopes of work, there were many opportunities for synergies during the project execution to deliver a cost competitive and integrated export solution. A \"fit for purpose\" approach was applied to achieve a common goal. The Vito project went through an optimization process called Minimum Technical Scope (MTS) to enable expected enhanced safety performance, better environmental performance, and lower unit development costs.\u0000 The topics discussed in this paper can be applied to future deep-water developments around the globe where the development operator does not have a direct ownership interest in the export pipelines. In addition, certain concepts could be applied on projects where the development operator is responsible for the entire deep-water development.\u0000 This paper discusses the scoping decisions taken across the integrated export system and how trade-offs were assessed to arrive at the MTS solution. The benefits that a common strategy can deliver for materials and installation, common construction equipment mobilizations and demobilizations, and the safety and environmental benefits from the coordination are addressed. Lastly, the paper discusses the working relationship between the Operators.\u0000 Cost competitiveness can be a challenge for every deep water project. Many of the items discussed in this paper hopefully provoke future development operators to apply some of the concepts so that deep-water can advance with care and simplicity.\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":"117350249","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}
Angelo Santicchia, E. Aloigi, Salvatore Terracina, E. Torselletti, Daniele Scarsciafratte, E. Girault, Giorgio Arcangeletti, L. Di Vito, F. Iob, A. Fonzo
The qualification of a pipeline system for hydrogen transport, even if strictly related to offshore pipelines, is a broad field that requires a systematic approach from basic material knowledge to complex physical models, fracture, and fatigue assessments. The combination of embrittlement with the severe loads of an offshore pipeline calls for a comprehensive awareness of material performance under such conditions. To achieve that, the first step has been the classification of failure modes by type of installation condition and selection of the tests required to characterize materials against them. A second step was to strengthen the state-of-the-art knowledge on data and tests availability for such failure modes. A third step was to set up and conduct a dedicated testing campaign focusing on girth welds and develop a pipeline system qualification procedure. The technological and standardizations gaps, identified in the design, construction and installation process chain are described, along with the actions taken by an offshore EPCI contractor to overcome and fix them. The analysis of qualification requirements, including available test types and testing protocols, led to a matrix of potential tests to be done in hydrogen and air environment for the steel base material, seam weld and girth weld of offshore pipelines. The final design of the test campaign included the minimum number of key tests necessary to assess the effect of atomic hydrogen inside the steel matrix and the related changes in mechanical properties, including the evaluation of tensile behavior and ductility, impact properties, fracture toughness (through KIH and rising load tests) and the critical soaking time in H2 environment. The tests were performed in different concentrations of hydrogen (i.e., different blending scenarios) at a given pressure which was considered potentially representative of the future main operating conditions in offshore hydrogen transportation systems. The main findings of the R&D work presented in the paper confirm that the qualification approach should include material properties testing under various conditions to support and provide a strong and sound scientific basis for the standardization process of the offshore EPCI pipeline system. The new tests and test conditions concur to complete the knowledge on the materials suitability for transporting hydrogen and hydrogen blends in offshore pipelines.
{"title":"Offshore Hydrogen Pipeline System Qualification: Design and Materials/Welds Testing in Hydrogen Environment","authors":"Angelo Santicchia, E. Aloigi, Salvatore Terracina, E. Torselletti, Daniele Scarsciafratte, E. Girault, Giorgio Arcangeletti, L. Di Vito, F. Iob, A. Fonzo","doi":"10.4043/32158-ms","DOIUrl":"https://doi.org/10.4043/32158-ms","url":null,"abstract":"\u0000 The qualification of a pipeline system for hydrogen transport, even if strictly related to offshore pipelines, is a broad field that requires a systematic approach from basic material knowledge to complex physical models, fracture, and fatigue assessments.\u0000 The combination of embrittlement with the severe loads of an offshore pipeline calls for a comprehensive awareness of material performance under such conditions. To achieve that, the first step has been the classification of failure modes by type of installation condition and selection of the tests required to characterize materials against them. A second step was to strengthen the state-of-the-art knowledge on data and tests availability for such failure modes. A third step was to set up and conduct a dedicated testing campaign focusing on girth welds and develop a pipeline system qualification procedure.\u0000 The technological and standardizations gaps, identified in the design, construction and installation process chain are described, along with the actions taken by an offshore EPCI contractor to overcome and fix them. The analysis of qualification requirements, including available test types and testing protocols, led to a matrix of potential tests to be done in hydrogen and air environment for the steel base material, seam weld and girth weld of offshore pipelines.\u0000 The final design of the test campaign included the minimum number of key tests necessary to assess the effect of atomic hydrogen inside the steel matrix and the related changes in mechanical properties, including the evaluation of tensile behavior and ductility, impact properties, fracture toughness (through KIH and rising load tests) and the critical soaking time in H2 environment. The tests were performed in different concentrations of hydrogen (i.e., different blending scenarios) at a given pressure which was considered potentially representative of the future main operating conditions in offshore hydrogen transportation systems.\u0000 The main findings of the R&D work presented in the paper confirm that the qualification approach should include material properties testing under various conditions to support and provide a strong and sound scientific basis for the standardization process of the offshore EPCI pipeline system. The new tests and test conditions concur to complete the knowledge on the materials suitability for transporting hydrogen and hydrogen blends in offshore pipelines.","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":"129480630","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}
M. Meade, Yeukayi Nenjerama, C. Parton, Veronica Richter McDonald, Nathan Fischer, S. Kapoor, A. Yakovlev, Valerie Lafitte, W. Smith, G. Landry, Xia Wei
Portland cements are integral components in the oilfield well construction process; however, the confluence of various business drivers have created the need to find sustainable alternatives materials. Geopolymers, already well known in traditional construction industries, show promise as alternatives to Portland cement in oilfield wells. Yet, successfully moving geopolymers from a concept in the laboratory to execution at the wellsite remains to be established. This paper presents evaluation of geopolymer cementing for use in oil and gas wells, specifically the primary cementing of liner strings in the Permian Basin. To evaluate geopolymer cementing for oil and gas well construction, a field example project was divided into four phases: development of robust slurry design in the laboratory, confirmation of compatibility with oilfield equipment, scalability for safe execution in the field, and validation through post-job evaluation techniques. The laboratory work included an engineered, innovative approach to chemistry to obtain a slurry matching and exceeding performance of Portland cement−based designs. Yard trials were performed to verify compatibility of geopolymers with industry-standard oilfield cementing equipment. The geopolymer-based designs were then scaled up to meet typical cementing job volumes and executed at the wellsite without deviating from conventional operating procedures. Post-job evaluation techniques to validate the placement included pressure matching and cement bond logs. Results have shown that for primary cementing applications, geopolymers can be an effective alternative to Portland cements. This case demonstrates that geopolymer cementing was able to fit into the oilfield cementing workflow without major changes to job design process, onsite execution, or post-job evaluation. Post-job pressure match of hydraulic simulations versus recorded pressure during job execution confirmed proper placement and conventional sonic and ultrasonic cement bond logging tools were able to confirm the presence of geopolymers within the wellbore providing further assurance. Introduction of geopolymer cementing requires the adaptation of innovative chemistry into the slurry design and consequently sourcing of materials typically not used in Portland cement blends. Additionally, attention to quality control of raw materials is required to ensure consistency of performance. Overall, geopolymer cementing can be successfully implemented into oilfield primary casing cementing applications using the existing infrastructure that has evolved from the historic use of Portland cement. Geopolymer cementing offers a unique opportunity for the oilfield industry to decrease CO2 emissions related to well construction and reduce dependence on the constrained supply of Portland cements. The case of cementing intermediate liner in the Permian Basin validates the scalability of the concept from inception in the laboratory to wellsite execution.
{"title":"First Global Implementation of Geopolymer in Primary Casing Cementing","authors":"M. Meade, Yeukayi Nenjerama, C. Parton, Veronica Richter McDonald, Nathan Fischer, S. Kapoor, A. Yakovlev, Valerie Lafitte, W. Smith, G. Landry, Xia Wei","doi":"10.4043/32218-ms","DOIUrl":"https://doi.org/10.4043/32218-ms","url":null,"abstract":"\u0000 Portland cements are integral components in the oilfield well construction process; however, the confluence of various business drivers have created the need to find sustainable alternatives materials. Geopolymers, already well known in traditional construction industries, show promise as alternatives to Portland cement in oilfield wells. Yet, successfully moving geopolymers from a concept in the laboratory to execution at the wellsite remains to be established. This paper presents evaluation of geopolymer cementing for use in oil and gas wells, specifically the primary cementing of liner strings in the Permian Basin.\u0000 To evaluate geopolymer cementing for oil and gas well construction, a field example project was divided into four phases: development of robust slurry design in the laboratory, confirmation of compatibility with oilfield equipment, scalability for safe execution in the field, and validation through post-job evaluation techniques. The laboratory work included an engineered, innovative approach to chemistry to obtain a slurry matching and exceeding performance of Portland cement−based designs. Yard trials were performed to verify compatibility of geopolymers with industry-standard oilfield cementing equipment. The geopolymer-based designs were then scaled up to meet typical cementing job volumes and executed at the wellsite without deviating from conventional operating procedures. Post-job evaluation techniques to validate the placement included pressure matching and cement bond logs.\u0000 Results have shown that for primary cementing applications, geopolymers can be an effective alternative to Portland cements. This case demonstrates that geopolymer cementing was able to fit into the oilfield cementing workflow without major changes to job design process, onsite execution, or post-job evaluation. Post-job pressure match of hydraulic simulations versus recorded pressure during job execution confirmed proper placement and conventional sonic and ultrasonic cement bond logging tools were able to confirm the presence of geopolymers within the wellbore providing further assurance. Introduction of geopolymer cementing requires the adaptation of innovative chemistry into the slurry design and consequently sourcing of materials typically not used in Portland cement blends. Additionally, attention to quality control of raw materials is required to ensure consistency of performance. Overall, geopolymer cementing can be successfully implemented into oilfield primary casing cementing applications using the existing infrastructure that has evolved from the historic use of Portland cement.\u0000 Geopolymer cementing offers a unique opportunity for the oilfield industry to decrease CO2 emissions related to well construction and reduce dependence on the constrained supply of Portland cements. The case of cementing intermediate liner in the Permian Basin validates the scalability of the concept from inception in the laboratory to wellsite execution.","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":"123380195","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}
Exploration in the 1970s and early 1980s identified approximately 4.2 TCF of natural gas and 123 million barrels of natural gas liquids on the Labrador Shelf within the Hopedale and Saglek basins. At the time, development was deemed unfeasible due to insufficient reserves and the threat posed by icebergs. Subsequent work has shown the original iceberg risk analysis to be very conservative. An iceberg risk model was developed to update the previous analysis and additional data was collected through a series of field programs. This resulted in a large multibeam mosaic covering the Makkovik Bank and pipeline landfall at Cape Harrison, and the development of a large iceberg scour database. An alternate landfall has also been identified at Cartwright with lower iceberg risk than the originally selected site. In 2010, the Oil and Gas Corporation of Newfoundland and Labrador (OilCo) undertook a regional oil seep mapping and interpretation study covering all offshore Newfoundland and Labrador, to help identify areas of interest with active petroleum systems. Based on these results, from 2011 to 2020 Oilco acquired 2D and 3D long offset broadband seismic datasets targeting the Chidley Basin, in the slope and deepwater off Labrador. This data has been used to map and quantify potential hydrocarbon systems within the basin. In 2021, Beicip-Franlab conducted a resource assessment on behalf of OilCo, based on available geological and geophysical data from the Chidley Basin. As reported in "Offshore Newfoundland & Labrador Resource Assessment, Labrador South NL-CFB03", "results show the very likely occurrence of a working petroleum system in the Chidley Basin capable of efficiently generating and preserving liquid and gas hydrocarbons in the slope and deepwater basin". Hence, the probability of additional resources to increase the total reserves available to support a gas development is considered high. If exploration drilling confirms the presence of gas, then the total gas available for development will include the original 4.2 TCF and any new reserves. Hence, the two barriers originally identified to the development of Labrador gas (iceberg risk and gas reserves) may be resolved.
在20世纪70年代和80年代初的勘探中，在Hopedale和Saglek盆地的Labrador大陆架上发现了大约4.2万亿立方英尺的天然气和1.23亿桶液化天然气。当时，由于储量不足和冰山的威胁，开发被认为是不可行的。后来的研究表明，最初的冰山风险分析是非常保守的。开发了冰山风险模型以更新先前的分析，并通过一系列实地项目收集了额外的数据。这导致了覆盖马科维克银行和哈里森角管道登陆的大型多波束马赛克，以及大型冰山冲刷数据库的发展。在卡特赖特也确定了一个备选着陆点，其冰山风险比最初选择的地点要低。2010年，纽芬兰和拉布拉多石油天然气公司(OilCo)开展了一项覆盖纽芬兰和拉布拉多所有近海的区域石油渗透测绘和解释研究，以帮助确定活跃石油系统的兴趣区域。基于这些结果，2011年至2020年，Oilco在Labrador附近的Chidley盆地斜坡和深水区获得了2D和3D长偏移宽带地震数据集。这些数据已被用于绘制和量化盆地内潜在的油气系统。2021年，Beicip-Franlab代表OilCo根据Chidley盆地的现有地质和地球物理数据进行了资源评估。正如“Newfoundland & Labrador Offshore Resource Assessment, Labrador South NL-CFB03”所报道的那样，“结果表明，Chidley盆地很可能存在一个有效的石油系统，能够有效地在斜坡和深水盆地中生成和保存液态和天然气碳氢化合物”。因此，额外资源增加总储量以支持天然气开发的可能性很高。如果勘探钻探确认了天然气的存在，那么可供开发的天然气总量将包括原始的4.2 TCF和任何新的储量。因此，最初确定的Labrador天然气开发的两个障碍(冰山风险和天然气储量)可能会得到解决。
{"title":"Labrador Gas – History and Opportunity","authors":"T. King, E. Gillis","doi":"10.4043/32655-ms","DOIUrl":"https://doi.org/10.4043/32655-ms","url":null,"abstract":"\u0000 Exploration in the 1970s and early 1980s identified approximately 4.2 TCF of natural gas and 123 million barrels of natural gas liquids on the Labrador Shelf within the Hopedale and Saglek basins. At the time, development was deemed unfeasible due to insufficient reserves and the threat posed by icebergs. Subsequent work has shown the original iceberg risk analysis to be very conservative. An iceberg risk model was developed to update the previous analysis and additional data was collected through a series of field programs. This resulted in a large multibeam mosaic covering the Makkovik Bank and pipeline landfall at Cape Harrison, and the development of a large iceberg scour database. An alternate landfall has also been identified at Cartwright with lower iceberg risk than the originally selected site.\u0000 In 2010, the Oil and Gas Corporation of Newfoundland and Labrador (OilCo) undertook a regional oil seep mapping and interpretation study covering all offshore Newfoundland and Labrador, to help identify areas of interest with active petroleum systems. Based on these results, from 2011 to 2020 Oilco acquired 2D and 3D long offset broadband seismic datasets targeting the Chidley Basin, in the slope and deepwater off Labrador. This data has been used to map and quantify potential hydrocarbon systems within the basin. In 2021, Beicip-Franlab conducted a resource assessment on behalf of OilCo, based on available geological and geophysical data from the Chidley Basin. As reported in \"Offshore Newfoundland & Labrador Resource Assessment, Labrador South NL-CFB03\", \"results show the very likely occurrence of a working petroleum system in the Chidley Basin capable of efficiently generating and preserving liquid and gas hydrocarbons in the slope and deepwater basin\". Hence, the probability of additional resources to increase the total reserves available to support a gas development is considered high. If exploration drilling confirms the presence of gas, then the total gas available for development will include the original 4.2 TCF and any new reserves. Hence, the two barriers originally identified to the development of Labrador gas (iceberg risk and gas reserves) may be resolved.","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":"114617013","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
A. Trandafir, S. Adhikari, P. Peralta, A. Broughton, Jack Dow Fraser, Deanne Hargrave
This study presents site-specific CPT-based correlation relationships for preconsolidation pressure, undrained shear strength, relative density and effective friction angle, developed for geotechnical characterization of foundation zone sediments at the Atlantic Shores offshore wind farm development. Results of laboratory geotechnical tests on samples from 49 soil borings performed at the Lease Area were correlated with corresponding measured cone resistance values from companion seabed or downhole CPTs. Ranges of overconsolidation ratios estimated using CPT-derived preconsolidation pressures from site-specific correlation relationships are in good agreement with overconsolidation ratios derived from laboratory measured preconsolidation pressures for various cohesive soil units. Interpreted ranges of cone resistance factors (i.e., Nkt) required in CPT-based undrained shear strength evaluation for cohesive soil units are significantly wider compared to the typical range of 15 to 20 representative for Gulf of Mexico clay sediments, as a result of large variability in soil plasticity as well as intermixed nature of the soils. Representative ranges of relative density and effective friction angle obtained from CPT data using site-specific correlation relationships, developed for the cohesionless soils at the Lease Area, are consistent with ranges of laboratory measured values.
{"title":"CPT-Based Geotechnical Characterization of Foundation Zone Sediments at Atlantic Shores Offshore Wind Farm Development","authors":"A. Trandafir, S. Adhikari, P. Peralta, A. Broughton, Jack Dow Fraser, Deanne Hargrave","doi":"10.4043/32512-ms","DOIUrl":"https://doi.org/10.4043/32512-ms","url":null,"abstract":"\u0000 This study presents site-specific CPT-based correlation relationships for preconsolidation pressure, undrained shear strength, relative density and effective friction angle, developed for geotechnical characterization of foundation zone sediments at the Atlantic Shores offshore wind farm development. Results of laboratory geotechnical tests on samples from 49 soil borings performed at the Lease Area were correlated with corresponding measured cone resistance values from companion seabed or downhole CPTs. Ranges of overconsolidation ratios estimated using CPT-derived preconsolidation pressures from site-specific correlation relationships are in good agreement with overconsolidation ratios derived from laboratory measured preconsolidation pressures for various cohesive soil units. Interpreted ranges of cone resistance factors (i.e., Nkt) required in CPT-based undrained shear strength evaluation for cohesive soil units are significantly wider compared to the typical range of 15 to 20 representative for Gulf of Mexico clay sediments, as a result of large variability in soil plasticity as well as intermixed nature of the soils. Representative ranges of relative density and effective friction angle obtained from CPT data using site-specific correlation relationships, developed for the cohesionless soils at the Lease Area, are consistent with ranges of laboratory measured values.","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":"126568738","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}
M. Nikolinakou, Xiaonan Wang Dosser, P. Flemings, M. Johri
We predict pressure and stress in the 3D Mad Dog field using the Full Effective Stress (FES) pressure-prediction workflow. The FES workflow incorporates the full stress tensor (e.g., lateral stress and deviatoric stresses) into pressure prediction: it uses a geomechanical model to predict mean total and shear stresses in the 3D field and a relationship between velocity and equivalent effective stress (instead of vertical effective stress) to account for both mean- and shear-induced pore pressure generation. In complex geologic settings, such as salt basins or thrust belts, compaction depends on non-vertical and differential stresses; in such settings, the FES method offers a significant improvement over the traditional approach, that is based on the vertical effective stress. We focus our study on the anticline below the Mad Dog salt at the original platform area. We quantify the mean and shear-induced overpressures and show that shear-induced pressures account for 80% of the total overpressure in front of the salt. We also show that shear-induced pressures are the source of more than 1.5ppg overpressure in the anticline below salt, where the mean-stress approach alone predicts underpressures (less than hydrostatic). Higher pressures and the decrease in lateral stress in the anticline area lead to a 1ppg drilling window (defined in this paper as the difference between the pore pressure and minimum principal stress at any given depth). This drilling window is shifted to higher overpressures by 0.4ppg compared to the VES prediction. We find that the stress ratio in the mudrocks decreases to ~55% of its uniaxial value. Furthermore, we show that the velocity-informed geomechanical model is able to predict the pore pressure regression observed at Mad Dog and the regional hydraulic connectivity in the area. The three-dimansional (3D) geomechanical model is built in Horizon (Elfen). The known pressure regression in the sands is modeled; mudrock pore pressures are initialized using the VES estimate. Modified Cam Clay is used to quantify mean- and shear-induced compaction. Overall, we demonstrate that incorporating the full stress tensor is important for pressure and stress prediction at Mad Dog, and that the FES method, by providing both pressure and stress, can help improve drilling-window estimates.
{"title":"3D Mad Dog Pressure and Stress Prediction Coupling Seismic Velocities, Pressure, and Stress Measurements","authors":"M. Nikolinakou, Xiaonan Wang Dosser, P. Flemings, M. Johri","doi":"10.4043/32555-ms","DOIUrl":"https://doi.org/10.4043/32555-ms","url":null,"abstract":"\u0000 We predict pressure and stress in the 3D Mad Dog field using the Full Effective Stress (FES) pressure-prediction workflow. The FES workflow incorporates the full stress tensor (e.g., lateral stress and deviatoric stresses) into pressure prediction: it uses a geomechanical model to predict mean total and shear stresses in the 3D field and a relationship between velocity and equivalent effective stress (instead of vertical effective stress) to account for both mean- and shear-induced pore pressure generation. In complex geologic settings, such as salt basins or thrust belts, compaction depends on non-vertical and differential stresses; in such settings, the FES method offers a significant improvement over the traditional approach, that is based on the vertical effective stress. We focus our study on the anticline below the Mad Dog salt at the original platform area. We quantify the mean and shear-induced overpressures and show that shear-induced pressures account for 80% of the total overpressure in front of the salt. We also show that shear-induced pressures are the source of more than 1.5ppg overpressure in the anticline below salt, where the mean-stress approach alone predicts underpressures (less than hydrostatic). Higher pressures and the decrease in lateral stress in the anticline area lead to a 1ppg drilling window (defined in this paper as the difference between the pore pressure and minimum principal stress at any given depth). This drilling window is shifted to higher overpressures by 0.4ppg compared to the VES prediction. We find that the stress ratio in the mudrocks decreases to ~55% of its uniaxial value. Furthermore, we show that the velocity-informed geomechanical model is able to predict the pore pressure regression observed at Mad Dog and the regional hydraulic connectivity in the area. The three-dimansional (3D) geomechanical model is built in Horizon (Elfen). The known pressure regression in the sands is modeled; mudrock pore pressures are initialized using the VES estimate. Modified Cam Clay is used to quantify mean- and shear-induced compaction. Overall, we demonstrate that incorporating the full stress tensor is important for pressure and stress prediction at Mad Dog, and that the FES method, by providing both pressure and stress, can help improve drilling-window estimates.","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":"128027619","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}
Epoxy passive fire protection (PFP) products are extensively used for fire proofing of structures and assets around the world. Significant projects such as construction of large hydrocarbon processing industry (HPI) plants may require a global supply chain meaning that a structure or an assembly may be manufactured one location and assembled in another. Manufacturing, application of coatings, handling, transportation, and construction will for many large projects take place in different climates. It is therefore important that an epoxy PFP product shows excellent cold climate properties for all climate performance. This study presents mechanical properties of one newly developed and three commercially available epoxy PFP products. The flexural strain of the newly developed epoxy PFP was found to be similar or higher than the other tested products for temperatures between −50 °C and 20 °C. Further, the strength at break, i.e. at the point of fracture, of the tested epoxy PFP products was found to increase as a function of decreasing temperature. Leading to the conclusion that the newly developed epoxy PFP was more robust at especially at lower temperatures, compared to the commercially available products. An Arctic test station located outside Longyearbyen at Svalbard in Norway was used for outdoor cold climate exposure After approximately one year, it was found that a low flexibility product showed significant cracking, whereas the more robust newly developed epoxy PFP showed no visual degradation.
{"title":"Arctic Field Testing – Developing the Next Generation Passive Fire Protection","authors":"A. W. Skilbred, Zuzanna Wierzba, J. Irving","doi":"10.4043/32568-ms","DOIUrl":"https://doi.org/10.4043/32568-ms","url":null,"abstract":"\u0000 Epoxy passive fire protection (PFP) products are extensively used for fire proofing of structures and assets around the world. Significant projects such as construction of large hydrocarbon processing industry (HPI) plants may require a global supply chain meaning that a structure or an assembly may be manufactured one location and assembled in another. Manufacturing, application of coatings, handling, transportation, and construction will for many large projects take place in different climates. It is therefore important that an epoxy PFP product shows excellent cold climate properties for all climate performance.\u0000 This study presents mechanical properties of one newly developed and three commercially available epoxy PFP products. The flexural strain of the newly developed epoxy PFP was found to be similar or higher than the other tested products for temperatures between −50 °C and 20 °C. Further, the strength at break, i.e. at the point of fracture, of the tested epoxy PFP products was found to increase as a function of decreasing temperature. Leading to the conclusion that the newly developed epoxy PFP was more robust at especially at lower temperatures, compared to the commercially available products.\u0000 An Arctic test station located outside Longyearbyen at Svalbard in Norway was used for outdoor cold climate exposure After approximately one year, it was found that a low flexibility product showed significant cracking, whereas the more robust newly developed epoxy PFP showed no visual degradation.","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":"125697739","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}
P. Peralta, K. Vembu, Jack Dow Fraser, S. Adhikari, A. Trandafir, X. Long, Deanne Hargrave
The cyclic soil behavior of North Sea clays and silica sands have been well-documented (Andersen 2004, 2009, etc), and have been used globally to develop soil models and design foundations for structures subjected to cyclic wave loading. The recent development of offshore wind farms within the Atlantic Offshore Continental Shelf (OCS) in the U.S. have prompted the large-scale design of fixed-bottom foundations of offshore wind structures, which are designed to be highly dynamic. In contrast to North Sea soils, very few data have been published regarding the strength behavior of typical Atlantic OCS soils. This has prompted the need to review industry-accepted soil models and cyclic design procedures based on empirical data and model testing from the North Sea and whether these may be applicable to Atlantic OCS soils. This paper presents cyclic soil data from a series of triaxial and direct simple shear tests on clay, silt, and sand samples from the Atlantic Shores Offshore Wind Lease Area in offshore New Jersey. A comparison of the soil behavior is made to published North Sea soils data and recommendations are provided on soil parameters for application to foundation design procedures for offshore wind structures within the Atlantic OCS.
{"title":"Cyclic Strength of Soils at Atlantic Shores Offshore Wind Farm","authors":"P. Peralta, K. Vembu, Jack Dow Fraser, S. Adhikari, A. Trandafir, X. Long, Deanne Hargrave","doi":"10.4043/32389-ms","DOIUrl":"https://doi.org/10.4043/32389-ms","url":null,"abstract":"\u0000 The cyclic soil behavior of North Sea clays and silica sands have been well-documented (Andersen 2004, 2009, etc), and have been used globally to develop soil models and design foundations for structures subjected to cyclic wave loading. The recent development of offshore wind farms within the Atlantic Offshore Continental Shelf (OCS) in the U.S. have prompted the large-scale design of fixed-bottom foundations of offshore wind structures, which are designed to be highly dynamic. In contrast to North Sea soils, very few data have been published regarding the strength behavior of typical Atlantic OCS soils. This has prompted the need to review industry-accepted soil models and cyclic design procedures based on empirical data and model testing from the North Sea and whether these may be applicable to Atlantic OCS soils. This paper presents cyclic soil data from a series of triaxial and direct simple shear tests on clay, silt, and sand samples from the Atlantic Shores Offshore Wind Lease Area in offshore New Jersey. A comparison of the soil behavior is made to published North Sea soils data and recommendations are provided on soil parameters for application to foundation design procedures for offshore wind structures within the Atlantic OCS.","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":"131651592","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}
M. Gabry, Amr Gharieb Ali, Mohamed Salah Saleh Elsawy
Building a geomechanical model for reservoir rocks is crucial for oil and gas operations. It is essential to solving multiple designs like wellbore stability for drilling operations, hydraulic fracturing, and sand production prediction for production operations. The best method to build a geomechanical model is to measure in the lab or calculate it from the dipole sonic log. However, it cannot be practically done routinely due to the high cost of logging and processing the dipole sonic logs. With the training of a machine learning model using conventional logging data and dipole sonic logs and static geomechanical measurements in the lab, a machine learning tool is provided to predict the dipole sonic logs and build a geomechanical model using routinely recorded well logs like gamma-ray, resistivity, neutron porosity, and density. The calculated minimum horizontal stress was calibrated practically with the derived closure pressure derived from several diagnostic fracture injection tests. This paper provides a practical implementation of a theory-controlled data learning model. It introduces an innovative way to build a calibrated machine learning tool that can predict shear and compressional wave velocities and estimate the rock mechanical properties using the regular conventional well logging data, which are helpful for oil and gas operations.
{"title":"Application of Machine Learning Model for Estimating the Geomechanical Rock Properties Using Conventional Well Logging Data","authors":"M. Gabry, Amr Gharieb Ali, Mohamed Salah Saleh Elsawy","doi":"10.4043/32328-ms","DOIUrl":"https://doi.org/10.4043/32328-ms","url":null,"abstract":"\u0000 Building a geomechanical model for reservoir rocks is crucial for oil and gas operations. It is essential to solving multiple designs like wellbore stability for drilling operations, hydraulic fracturing, and sand production prediction for production operations. The best method to build a geomechanical model is to measure in the lab or calculate it from the dipole sonic log. However, it cannot be practically done routinely due to the high cost of logging and processing the dipole sonic logs.\u0000 With the training of a machine learning model using conventional logging data and dipole sonic logs and static geomechanical measurements in the lab, a machine learning tool is provided to predict the dipole sonic logs and build a geomechanical model using routinely recorded well logs like gamma-ray, resistivity, neutron porosity, and density. The calculated minimum horizontal stress was calibrated practically with the derived closure pressure derived from several diagnostic fracture injection tests.\u0000 This paper provides a practical implementation of a theory-controlled data learning model. It introduces an innovative way to build a calibrated machine learning tool that can predict shear and compressional wave velocities and estimate the rock mechanical properties using the regular conventional well logging data, which are helpful for oil and gas operations.","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":"131885923","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}
Development of Ultra deepwater wells drilled to greater than 25,000 feet total depth in Gulf of Mexico (GoM) have led to the need for High Pressure (HP) systems. Existing MQC / Junction Plates were designed for maximum 15,000 PSI and needed to be updated to meet the 20,000 PSI system requirements. This paper documents the development of 20,000 PSI (20k) Multi-Quick Connect (MQC) / Junction Plate (J-Plate). This 20k MQC was updated in terms of material strength and qualified per API 17F. All Pressure containing components and the internal MQC drive mechanism had to be updated and verified for a Design Pressure (DP) of 20,000 PSI. Design and Analysis iteration was performed to verify the structural integrity of the MQC/J-Plate under the design operational loads (both internal and external loads) with all couplers pressurized to a design pressure of 20,000 PSI and test pressure (TP) of 30,000 PSI pressure. In qualification (per API 17F) the MQC went through cycle testing for mated and unmated conditions under pressure, unbalanced pressure load, and hyperbaric testing of the MQC with environmental pressure of 4400 psig (equivalent to water depth 10,000 ft / 3,048 m). Higher yield strength materials have been used for components as required to support the loading due to the high-pressure requirement. For higher stress (stress above allowable criteria in linear elastic stress analysis) areas, Elastic-Plastic stress analysis has been performed to check the structural integrity against the plastic collapse. The results of the analyses indicate that the MQC/J-Plate satisfies all the allowable criteria for the analyzed operational load cases. The coupler seal and body have been qualified by the vendor to required pressure and temperature cycles. A completely built MQC has been qualified with lines at 20,000 PSI design and 30,000 PSI test pressure per API 17F. Qualification tests were completed for the cycle testing (Balanced and Unbalanced) and hyperbaric pressure testing and successfully completed all cycle testing. In qualification, both mated and unmated conditions were performed with five cycles. MQC/J-Plate for High Pressure High Temperature (HPHT) has complied with all requirements of TRL 6. The new 20k MQC allows for the ultra deepwater development utilizing the existing 15k reliable, field proven MQC system with minor modifications. New coupling bodies were developed to enable this high pressure MQC to work seamlessly across the production and control systems in the field.
{"title":"Junction Plate for High Pressure High Temperature System","authors":"Sunil Prakash, Pravesh Semwal, Julie Strain","doi":"10.4043/32237-ms","DOIUrl":"https://doi.org/10.4043/32237-ms","url":null,"abstract":"\u0000 Development of Ultra deepwater wells drilled to greater than 25,000 feet total depth in Gulf of Mexico (GoM) have led to the need for High Pressure (HP) systems. Existing MQC / Junction Plates were designed for maximum 15,000 PSI and needed to be updated to meet the 20,000 PSI system requirements. This paper documents the development of 20,000 PSI (20k) Multi-Quick Connect (MQC) / Junction Plate (J-Plate). This 20k MQC was updated in terms of material strength and qualified per API 17F.\u0000 All Pressure containing components and the internal MQC drive mechanism had to be updated and verified for a Design Pressure (DP) of 20,000 PSI. Design and Analysis iteration was performed to verify the structural integrity of the MQC/J-Plate under the design operational loads (both internal and external loads) with all couplers pressurized to a design pressure of 20,000 PSI and test pressure (TP) of 30,000 PSI pressure. In qualification (per API 17F) the MQC went through cycle testing for mated and unmated conditions under pressure, unbalanced pressure load, and hyperbaric testing of the MQC with environmental pressure of 4400 psig (equivalent to water depth 10,000 ft / 3,048 m).\u0000 Higher yield strength materials have been used for components as required to support the loading due to the high-pressure requirement. For higher stress (stress above allowable criteria in linear elastic stress analysis) areas, Elastic-Plastic stress analysis has been performed to check the structural integrity against the plastic collapse. The results of the analyses indicate that the MQC/J-Plate satisfies all the allowable criteria for the analyzed operational load cases. The coupler seal and body have been qualified by the vendor to required pressure and temperature cycles. A completely built MQC has been qualified with lines at 20,000 PSI design and 30,000 PSI test pressure per API 17F. Qualification tests were completed for the cycle testing (Balanced and Unbalanced) and hyperbaric pressure testing and successfully completed all cycle testing. In qualification, both mated and unmated conditions were performed with five cycles. MQC/J-Plate for High Pressure High Temperature (HPHT) has complied with all requirements of TRL 6.\u0000 The new 20k MQC allows for the ultra deepwater development utilizing the existing 15k reliable, field proven MQC system with minor modifications. New coupling bodies were developed to enable this high pressure MQC to work seamlessly across the production and control systems in the field.","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":"114771439","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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