V. M. Taboada, S. Cao, F. A. F. López, D. C. Roque, P. B. Nabor
Equations to calculate the modulus reduction curve (G/Gmax-γ) and material damping ratio curve (D-γ) of calcareous clay and clayey carbonate mud of the Bay of Campeche and Tabasco Coastline are developed. This was achieved using a database of 156 resonant column tests and 468 strain-controlled cyclic direct simple shear tests performed in clays with 10 % ≤ CaCO3 ≤90 %. The effects of carbonate content (CaCO3), mean effective confining pressure (σ′m), plasticity index (PI), and overconsolidation ratio (OCR) on the shape of the modulus reduction and material damping ratio curves are shown based on the available laboratory data and the equations developed to calculate these curves. It is shown that as CaCO3 increases, the normalized shear modulus (G/Gmax) curve tends to shift downward and the damping ratio (D) curve tends to shift upward; as σ′m and PI increase, the G/Gmax curve tends to shift upward and the damping ratio curve tends to shift downward; and the value of OCR has practically no effect on the position of the curves. The validation of the calculated values of G/Gmax and D shows the best predictions are found at low shear strains for G/Gmax and at large shear strains for D, falling within ± 25 % of the measured values, and shows that due to limitations in the model at large strains (γ > 1 %) for G/Gmax and at low strains (γ < 0.05 %) for D, the calculated values fall within ± 50 % of the measured values. The equations developed to calculate the curves of G/Gmax-γ and D-γ of calcareous clay and clayey carbonate mud are recommended for preliminary or perhaps even final seismic site response evaluations. However, considering the scatter of the data points around the curves, the equations should be used with caution, and parametric and sensitivity studies are strongly recommended to assess the importance of this scatter. In large critical projects, direct experimental determinations of G/Gmax and D for the soils of interest are suggested to be more appropriate.
{"title":"Normalized Modulus Reduction and Damping Ratio Curves for Bay of Campeche Calcareous Clay to Carbonate Mud","authors":"V. M. Taboada, S. Cao, F. A. F. López, D. C. Roque, P. B. Nabor","doi":"10.4043/31153-ms","DOIUrl":"https://doi.org/10.4043/31153-ms","url":null,"abstract":"\u0000 Equations to calculate the modulus reduction curve (G/Gmax-γ) and material damping ratio curve (D-γ) of calcareous clay and clayey carbonate mud of the Bay of Campeche and Tabasco Coastline are developed. This was achieved using a database of 156 resonant column tests and 468 strain-controlled cyclic direct simple shear tests performed in clays with 10 % ≤ CaCO3 ≤90 %. The effects of carbonate content (CaCO3), mean effective confining pressure (σ′m), plasticity index (PI), and overconsolidation ratio (OCR) on the shape of the modulus reduction and material damping ratio curves are shown based on the available laboratory data and the equations developed to calculate these curves. It is shown that as CaCO3 increases, the normalized shear modulus (G/Gmax) curve tends to shift downward and the damping ratio (D) curve tends to shift upward; as σ′m and PI increase, the G/Gmax curve tends to shift upward and the damping ratio curve tends to shift downward; and the value of OCR has practically no effect on the position of the curves. The validation of the calculated values of G/Gmax and D shows the best predictions are found at low shear strains for G/Gmax and at large shear strains for D, falling within ± 25 % of the measured values, and shows that due to limitations in the model at large strains (γ > 1 %) for G/Gmax and at low strains (γ < 0.05 %) for D, the calculated values fall within ± 50 % of the measured values. The equations developed to calculate the curves of G/Gmax-γ and D-γ of calcareous clay and clayey carbonate mud are recommended for preliminary or perhaps even final seismic site response evaluations. However, considering the scatter of the data points around the curves, the equations should be used with caution, and parametric and sensitivity studies are strongly recommended to assess the importance of this scatter. In large critical projects, direct experimental determinations of G/Gmax and D for the soils of interest are suggested to be more appropriate.","PeriodicalId":11072,"journal":{"name":"Day 1 Mon, August 16, 2021","volume":"1 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-08-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84862561","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}
Integrity management is an ongoing lifecycle process for ensuring safe operation and fitness for service of offshore oil and gas production systems, including risers. Risers offer a means of transporting fluids between subsea wells and the host platform crossing the splash zone that is probably the most critical region for corrosion and exposure to external damages. Furthermore, with their proximity to the personnel on the platform and to the topside equipment, risers are considered safety critical, and are therefore, subject to planned inspections followed by an engineering assessment of the findings. This paper discusses the motivation and business driver for developing and implementing a new and cost effective risers’ inspection methodology in the splash zone based on innovative robotic platforms. The technical features and the capabilities of the robot are outlined. Traditionally, risers’ inspections are carried out by rope access technicians and divers or ROV below the water line using conventional technologies as spot ultrasonic thickness measurements, traditional radiography and visual assessment. This type of inspection is based on a first visual assessment followed by NDE testing only if some finding is spotted. Internal defects or defect under coating, e.g. splashtron, can be easily overlooked, compromising the entire assessment process. Additionally such activities are often limited by accessibility, weather, and Personnel On-Board (POB) accommodations, but primarily they involve risks to inspector's safety. Backbone of the presented methodology is the use of a robotic crawler that has the key advantage to inspect autonomously the risers, navigating over obstacles like clamps and supports. The robot can carry a variety of payloads for visual inspections, surface profiling, and NDE examinations with the ability to scan large surfaces with or without coating and detect internal and external defects. It can operate in the topside, splash zone and subsea sections of the riser. The inspection data are processed in real time for an immediate assessment of the integrity of the asset. Examples are presented and comparison is made between traditional inspection methodologies and robotic autonomous methodologies to demonstrate the improvement of inspection effectiveness and efficiency. The paper also discusses the potential areas of future development, which include Artificial Intelligence (AI) algorithms to further automatize the process and methodologies of risers’ inspection and data analysis.
{"title":"Riser Robotic Inspection - Reducing Safety Risk While Improving Efficiency and Effectiveness","authors":"Neré J. Mabile, Alessandro Vagata","doi":"10.4043/31200-ms","DOIUrl":"https://doi.org/10.4043/31200-ms","url":null,"abstract":"\u0000 Integrity management is an ongoing lifecycle process for ensuring safe operation and fitness for service of offshore oil and gas production systems, including risers. Risers offer a means of transporting fluids between subsea wells and the host platform crossing the splash zone that is probably the most critical region for corrosion and exposure to external damages. Furthermore, with their proximity to the personnel on the platform and to the topside equipment, risers are considered safety critical, and are therefore, subject to planned inspections followed by an engineering assessment of the findings. This paper discusses the motivation and business driver for developing and implementing a new and cost effective risers’ inspection methodology in the splash zone based on innovative robotic platforms. The technical features and the capabilities of the robot are outlined.\u0000 Traditionally, risers’ inspections are carried out by rope access technicians and divers or ROV below the water line using conventional technologies as spot ultrasonic thickness measurements, traditional radiography and visual assessment. This type of inspection is based on a first visual assessment followed by NDE testing only if some finding is spotted. Internal defects or defect under coating, e.g. splashtron, can be easily overlooked, compromising the entire assessment process. Additionally such activities are often limited by accessibility, weather, and Personnel On-Board (POB) accommodations, but primarily they involve risks to inspector's safety.\u0000 Backbone of the presented methodology is the use of a robotic crawler that has the key advantage to inspect autonomously the risers, navigating over obstacles like clamps and supports. The robot can carry a variety of payloads for visual inspections, surface profiling, and NDE examinations with the ability to scan large surfaces with or without coating and detect internal and external defects. It can operate in the topside, splash zone and subsea sections of the riser. The inspection data are processed in real time for an immediate assessment of the integrity of the asset.\u0000 Examples are presented and comparison is made between traditional inspection methodologies and robotic autonomous methodologies to demonstrate the improvement of inspection effectiveness and efficiency.\u0000 The paper also discusses the potential areas of future development, which include Artificial Intelligence (AI) algorithms to further automatize the process and methodologies of risers’ inspection and data analysis.","PeriodicalId":11072,"journal":{"name":"Day 1 Mon, August 16, 2021","volume":"18 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-08-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"75400885","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}
Leonardo Gitahy, D. Manso, Guilherme Carvalho, M. Lewis, Dario Migliaresi
Raven is the third stage of the West Nile Delta development (following Taurus / Libra and Giza / Fayoum) from two BP-operated offshore concession blocks, North Alexandria and West Mediterranean Deepwater. The Raven project included the design of various rigid pipelines, of which one specifically is the subject of this paper. The 16" RSM to RP in-field flowline is approximately 4.8 km long, connecting a manifold (RSM) to a PLEM (RP) through a route that crosses a prominent geological feature identified as the Rosetta Channel, a submerged canyon that extends for about 30 km. The Rosetta Channel is about 2.5 km wide at the location of the 16" flowline route crossing, with steep slopes going down for approx. 40m (in height) on the RSM side, and then climbing up approx. 150m (in height) towards the RP side. Although it is typically preferred to avoid very rough geophysical features, this is not always possible or practicable and it is not uncommon to come across challenging seabed features that demand complex engineering solutions in order to minimise risks and associated costs. This paper addresses the numerous technical challenges involved in the design of the 16" flowline that crosses the Rosetta Channel. Following close collaboration between all involved stakeholders, a robust, reliable and cost-effective solution was achieved after a detailed engineering process, where the final design required a unique combination of mitigations including seabed excavation, pre-lay rock carpets, post-lay rock berms, cable jetting, curve bollards and sleepers.
{"title":"Design Challenge of the West Nile Delta Gas Development: The Rosetta Channel Crossing","authors":"Leonardo Gitahy, D. Manso, Guilherme Carvalho, M. Lewis, Dario Migliaresi","doi":"10.4043/31257-ms","DOIUrl":"https://doi.org/10.4043/31257-ms","url":null,"abstract":"\u0000 Raven is the third stage of the West Nile Delta development (following Taurus / Libra and Giza / Fayoum) from two BP-operated offshore concession blocks, North Alexandria and West Mediterranean Deepwater. The Raven project included the design of various rigid pipelines, of which one specifically is the subject of this paper. The 16\" RSM to RP in-field flowline is approximately 4.8 km long, connecting a manifold (RSM) to a PLEM (RP) through a route that crosses a prominent geological feature identified as the Rosetta Channel, a submerged canyon that extends for about 30 km. The Rosetta Channel is about 2.5 km wide at the location of the 16\" flowline route crossing, with steep slopes going down for approx. 40m (in height) on the RSM side, and then climbing up approx. 150m (in height) towards the RP side.\u0000 Although it is typically preferred to avoid very rough geophysical features, this is not always possible or practicable and it is not uncommon to come across challenging seabed features that demand complex engineering solutions in order to minimise risks and associated costs.\u0000 This paper addresses the numerous technical challenges involved in the design of the 16\" flowline that crosses the Rosetta Channel. Following close collaboration between all involved stakeholders, a robust, reliable and cost-effective solution was achieved after a detailed engineering process, where the final design required a unique combination of mitigations including seabed excavation, pre-lay rock carpets, post-lay rock berms, cable jetting, curve bollards and sleepers.","PeriodicalId":11072,"journal":{"name":"Day 1 Mon, August 16, 2021","volume":"1 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-08-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"73076960","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}
Esso Exploration and Production Guyana Limited ("ExxonMobil"), an affiliate of Exxon Mobil Corporation, and its co-venturers Hess Guyana Exploration Limited and CNOOC Petroleum Guyana Limited, discovered oil in the Stabroek block offshore Guyana during the first half of 2015. The success of safely drilling their first well (Liza-1), followed a history of 40 dry holes in the Guiana Basin prior to ExxonMobil beginning ultra-deepwater oil and gas exploration in 2008 (Varga et al. 2021). Guyana, with a small population of 750,000, was primarily economically focused on agriculture, manufacturing, and the mining of bauxite and gold. ExxonMobil identified the need for an early, focused, coordinated, and long-lasting approach to local content planning to provide tangible results for Guyana. Developing local businesses to actively participate in the industry and enter the supply chain while raising awareness of how the oil and gas industry operates was paramount, as was managing expectations of the Guyanese government and populace about local content. ExxonMobil recognized that the established mining sector in Guyana had the potential to provide a base of local suppliers able to transition into the emerging oil and gas sector. It subsequently undertook a number of assessments and studies on the local economy to further understand the local context. The finding of these assessments highlighted that most Guyanese companies were operating in the small local economy or working within the Caribbean region, limiting their exposure to international standards and providing little impetus to become globally competitive. Despite having technical competencies that could be utilized in the oil and gas industry, shortfalls were apparent in the areas of auditable systems, business processes, quality assurance, and safety. Closing the gaps would take time and investment, and a shift in culture in some parts. An internal assessment of ExxonMobil's supplier development programs was conducted, and a Guyana supplier development program was developed by drawing from best practices around the globe. ExxonMobil, with the support of its Stabroek Block co-venturers, took a proactive decision and devised a plan to engage an independent third party to run a "fit for purpose" enterprise development centre (EDC) to support the technical development in country through local content prior to final investment decision (FID). In order to be equipped to provide early roll out of local content development, and 6 months before FID for Liza 1, ExxonMobil released a Request for Proposal (RFP). Bidders were invited to submit proposals on how the EDC would function "fit for purpose" and compliment rather than compete with current Guyanese activities and vendors. The successful bidder, DAI Global LLC (DAI), had a proven track record of international socioeconomic project successes and was selected to form a unique and collaborative, strategic relationship with ExxonMobil. Although DAI h
2015年上半年，埃克森美孚公司的子公司埃索圭亚那勘探与生产有限公司(“埃克森美孚”)及其合作伙伴赫斯圭亚那勘探有限公司和中海油圭亚那石油有限公司在圭亚那近海Stabroek区块发现了石油。在2008年埃克森美孚开始超深水油气勘探之前，他们在圭亚那盆地成功钻出了第一口井(Liza-1)，此前在圭亚那盆地钻了40口干井(Varga et al. 2021)。圭亚那只有75万人口，经济上主要以农业、制造业、铝土矿和金矿开采为主。埃克森美孚认为，需要采取一种早期、重点突出、协调一致、持久的方法来进行本地内容规划，以便为圭亚那提供切实的成果。发展当地企业积极参与该行业并进入供应链，同时提高对石油和天然气行业运作方式的认识至关重要，同时管理圭亚那政府和民众对当地内容的期望也至关重要。埃克森美孚认识到，圭亚那现有的采矿部门有潜力为能够过渡到新兴的石油和天然气部门的当地供应商提供一个基础。它随后对当地经济进行了一些评估和研究，以进一步了解当地情况。这些评估的结果突出表明，大多数圭亚那公司都是在小型的当地经济中经营，或在加勒比区域内经营，限制了它们接触国际标准的机会，也没有什么动力使它们具有全球竞争力。尽管拥有可以在油气行业中使用的技术能力，但在可审计系统、业务流程、质量保证和安全方面的不足是显而易见的。缩小差距需要时间和投资，在某些地区还需要文化的转变。对埃克森美孚的供应商发展计划进行了内部评估，并借鉴了全球最佳实践，制定了圭亚那供应商发展计划。在Stabroek区块合作方的支持下，埃克森美孚采取了积极主动的决定，并制定了一项计划，聘请独立第三方运营一个“适合目的”的企业发展中心(EDC)，在最终投资决策(FID)之前，通过当地内容支持该国的技术发展。为了尽早推出本地内容开发，在Liza 1 FID的6个月前，埃克森美孚发布了一份征求建议书(RFP)。投标人被邀请提交建议书，说明EDC将如何“符合目的”运作，并对圭亚那目前的活动和供应商进行恭维而不是竞争。中标者DAI Global LLC (DAI)在国际社会经济项目方面有着良好的成功记录，并被选中与埃克森美孚建立独特的合作战略关系。虽然DAI以前在新兴市场有经验，但圭亚那的挑战是将圭亚那的供应商基础扩大到一个新的部门。ExxonMobil和DAI的全球经验共同创造了一个灵活的管理结构，能够适应随后的勘探成功和不断扩大的行业需求。短期和长期项目都将用于吸引企业参与，以满足企业在不同发展阶段不断变化的需求。此外，ExxonMobil的远见卓识将当地内容要求和中心合同使用纳入主承包商合同，为EDC的长期可行性提供了支持。在圭亚那成立的经济发展中心被命名为地方商业发展中心(中心)。中心的设计提供了一个支持性的环境，在这里寻找和获取有关石油和天然气行业的信息是一种舒适的体验。该中心包括教室、会议空间、办公室和网络区域，赞助参与项目，并为进入该行业的公司提供指导。该中心利用研究和数据来推动其项目的内容和重点，解决商界的相关需求。例如，一项关于当地企业国际竞争力的发展评估基线研究表明，圭亚那三分之二的企业不具备国际竞争力，需要基本业务系统(如财务管理、供应链管理和人力资源)的支持。埃克森美孚进行的其他利益相关者焦点小组研究表明，人们缺乏对石油和天然气行业的基础知识。获得这项研究的预fid允许在规划上有一个良好的开端，并在中心开放后仅3个月就实施了工作计划。
{"title":"Early Interventions for Guyanese Business Development and Optimization","authors":"Treacy Roberts, N. Gaskin-Peters","doi":"10.4043/31016-ms","DOIUrl":"https://doi.org/10.4043/31016-ms","url":null,"abstract":"\u0000 \u0000 \u0000 Esso Exploration and Production Guyana Limited (\"ExxonMobil\"), an affiliate of Exxon Mobil Corporation, and its co-venturers Hess Guyana Exploration Limited and CNOOC Petroleum Guyana Limited, discovered oil in the Stabroek block offshore Guyana during the first half of 2015. The success of safely drilling their first well (Liza-1), followed a history of 40 dry holes in the Guiana Basin prior to ExxonMobil beginning ultra-deepwater oil and gas exploration in 2008 (Varga et al. 2021). Guyana, with a small population of 750,000, was primarily economically focused on agriculture, manufacturing, and the mining of bauxite and gold. ExxonMobil identified the need for an early, focused, coordinated, and long-lasting approach to local content planning to provide tangible results for Guyana. Developing local businesses to actively participate in the industry and enter the supply chain while raising awareness of how the oil and gas industry operates was paramount, as was managing expectations of the Guyanese government and populace about local content.\u0000 ExxonMobil recognized that the established mining sector in Guyana had the potential to provide a base of local suppliers able to transition into the emerging oil and gas sector. It subsequently undertook a number of assessments and studies on the local economy to further understand the local context. The finding of these assessments highlighted that most Guyanese companies were operating in the small local economy or working within the Caribbean region, limiting their exposure to international standards and providing little impetus to become globally competitive. Despite having technical competencies that could be utilized in the oil and gas industry, shortfalls were apparent in the areas of auditable systems, business processes, quality assurance, and safety. Closing the gaps would take time and investment, and a shift in culture in some parts. An internal assessment of ExxonMobil's supplier development programs was conducted, and a Guyana supplier development program was developed by drawing from best practices around the globe. ExxonMobil, with the support of its Stabroek Block co-venturers, took a proactive decision and devised a plan to engage an independent third party to run a \"fit for purpose\" enterprise development centre (EDC) to support the technical development in country through local content prior to final investment decision (FID).\u0000 In order to be equipped to provide early roll out of local content development, and 6 months before FID for Liza 1, ExxonMobil released a Request for Proposal (RFP). Bidders were invited to submit proposals on how the EDC would function \"fit for purpose\" and compliment rather than compete with current Guyanese activities and vendors. The successful bidder, DAI Global LLC (DAI), had a proven track record of international socioeconomic project successes and was selected to form a unique and collaborative, strategic relationship with ExxonMobil. Although DAI h","PeriodicalId":11072,"journal":{"name":"Day 1 Mon, August 16, 2021","volume":"62 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-08-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"73707852","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}
Audrey L. Varga, M. Chandler, Worth B. Cotton, Erik A. Jackson, Ross J. Markwort, Randy A. Perkey, B. Renik, Tina Riley, S. I. Webb
Exploration in the Guyana-Suriname Basin has been a decades-long endeavor, including technical challenges and a lengthy history of drilling with no offshore success prior to the Liza discovery. The 1929 New Nickerie well was the first onshore well in Suriname, and was followed by 30 years of dry holes before the heavy-oil Tambaredjo field was discovered in the 1960s. In the 1990s, nearly 40 years after the Tambaredjo discovery, ExxonMobil utilized the 1970s-vintage, poor-to moderate-quality, 2D seismic and gravity data available to create a series of hand-drawn, level-of-maturity (LOM) source and environments-of-deposition (EOD) maps over the basin to move their exploration efforts forward. This work established the genetic fundamentals necessary for understanding the hydrocarbon system and led to negotiation for and capture of the Stabroek Block in 1999. The Liza-1 success in 2015 spurred extensive activity in the Basin by ExxonMobil and the Stabroek Block co-venturers, Hess Guyana Exploration Limited and CNOOC Petroleum Guyana Limited (Austin et al. 2021). The collection of extensive state-of-the art seismic data has been leveraged to enable successful exploration of multiple play types across the Guyana-Suriname Basin. Further data collection, including over 2 km of conventional core and additional seismic data acquisition and processing, has enabled ExxonMobil to adopt interpretation techniques that are applied across the entire basin to characterize and understand the subsurface better. From initial hand-drawn maps to the use of advanced technology today, ExxonMobil's work in the Guyana-Suriname Basin has relied on integration of geologic and geophysical understanding as well as the ability to leverage new technology to continue a successful exploration program with 8 billion barrels discovered to date.
在圭亚那-苏里南盆地的勘探已经进行了数十年的努力，包括技术挑战和漫长的钻井历史，在Liza发现之前没有取得海上成功。1929年的New Nickerie井是苏里南的第一口陆上井，在20世纪60年代发现Tambaredjo重油油田之前，又有30年的干井。在Tambaredjo发现近40年后的20世纪90年代，埃克森美孚利用1970年代的二维地震和重力数据，绘制了一系列手绘的盆地成熟度(LOM)源和沉积环境(EOD)图，以推进勘探工作。这项工作为了解油气系统建立了必要的遗传学基础，并导致了1999年Stabroek区块的谈判和占领。2015年Liza-1的成功开采刺激了埃克森美孚和Stabroek区块合作者Hess圭亚那勘探有限公司和中海油圭亚那石油有限公司在该盆地的广泛活动(Austin et al. 2021)。圭亚那-苏里南盆地收集了大量最先进的地震数据，成功地勘探了多种油气藏类型。进一步的数据收集，包括超过2公里的常规岩心和额外的地震数据采集和处理，使埃克森美孚能够采用适用于整个盆地的解释技术，以更好地表征和了解地下。从最初的手绘地图到今天的先进技术，埃克森美孚在圭亚那-苏里南盆地的工作依赖于地质和地球物理知识的整合，以及利用新技术的能力，继续成功的勘探计划，迄今已发现80亿桶石油。
{"title":"Innovation and Integration: Exploration History, ExxonMobil, and the Guyana-Suriname Basin","authors":"Audrey L. Varga, M. Chandler, Worth B. Cotton, Erik A. Jackson, Ross J. Markwort, Randy A. Perkey, B. Renik, Tina Riley, S. I. Webb","doi":"10.4043/30946-ms","DOIUrl":"https://doi.org/10.4043/30946-ms","url":null,"abstract":"\u0000 Exploration in the Guyana-Suriname Basin has been a decades-long endeavor, including technical challenges and a lengthy history of drilling with no offshore success prior to the Liza discovery. The 1929 New Nickerie well was the first onshore well in Suriname, and was followed by 30 years of dry holes before the heavy-oil Tambaredjo field was discovered in the 1960s. In the 1990s, nearly 40 years after the Tambaredjo discovery, ExxonMobil utilized the 1970s-vintage, poor-to moderate-quality, 2D seismic and gravity data available to create a series of hand-drawn, level-of-maturity (LOM) source and environments-of-deposition (EOD) maps over the basin to move their exploration efforts forward. This work established the genetic fundamentals necessary for understanding the hydrocarbon system and led to negotiation for and capture of the Stabroek Block in 1999.\u0000 The Liza-1 success in 2015 spurred extensive activity in the Basin by ExxonMobil and the Stabroek Block co-venturers, Hess Guyana Exploration Limited and CNOOC Petroleum Guyana Limited (Austin et al. 2021). The collection of extensive state-of-the art seismic data has been leveraged to enable successful exploration of multiple play types across the Guyana-Suriname Basin. Further data collection, including over 2 km of conventional core and additional seismic data acquisition and processing, has enabled ExxonMobil to adopt interpretation techniques that are applied across the entire basin to characterize and understand the subsurface better.\u0000 From initial hand-drawn maps to the use of advanced technology today, ExxonMobil's work in the Guyana-Suriname Basin has relied on integration of geologic and geophysical understanding as well as the ability to leverage new technology to continue a successful exploration program with 8 billion barrels discovered to date.","PeriodicalId":11072,"journal":{"name":"Day 1 Mon, August 16, 2021","volume":"25 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-08-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"81994974","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}
Yolanda Cuenca, Àngels Tejero, S. Das, Daniel Brooke-Peig, Philip Martin, F. Bechir
Sulfate removal in injection water is standard practice to prevent scaling and souring in subsea oil reservoirs. Nanofiltration membranes have been used to this purpose since 1987, when FilmTec™ SR90-400 elements were installed in an offshore platform in the North Sea. The most pressing concern in this type of systems is membrane fouling, with the associated reduction in effective plant operation time and shorten element lifespan caused by the standard Clean-in-Place (CIP) protocols. The object of this research has been to test the latest developments in biofouling-resistant sulfate removal membranes to achieve oil and gas (O&G) industry requirements. Improved chemistry and improved module engineering have enabled the production of new membrane elements that represent the next-generation in sulfate removal nanofiltration. Next-generation sulfate removal membranes have been trial-tested. In pilot testing, target performance was validated in terms of productivity, permeate quality and fouling resistance. The results of this testing indicate that improvements in membrane chemistry and module engineering have resulted in a 63% decrease in pressure drop and a much slower fouling trend over the total of 6 elements. This significant improvement should allow an important reduction in the number of cleanings, which the authors have estimated to be of 50%. Moreover, sulfate rejection values are in the range of 99.9% (below 1 ppm of sulfate in the permeate), providing great injection- quality water. Full-scale testing in a production site in the Atlantic Ocean was done to validate pilot testing results, showing a continued operation of 100 days without any need for a clean-in-place (CIP) procedure. The results obtained in the extensive testing carried out on these new antifouling elements, show that the improvements implemented in its design have the ability to improve the operation of Sulfate Removal Units (SRU). These improvements are the results of reducing maintenance costs and downtime on offshore platforms, resulting in increased operation and improved productivity.
{"title":"Innovation to Reduce Operation Downtime in Sulfate Removal Offshore Applications","authors":"Yolanda Cuenca, Àngels Tejero, S. Das, Daniel Brooke-Peig, Philip Martin, F. Bechir","doi":"10.4043/31279-ms","DOIUrl":"https://doi.org/10.4043/31279-ms","url":null,"abstract":"\u0000 Sulfate removal in injection water is standard practice to prevent scaling and souring in subsea oil reservoirs. Nanofiltration membranes have been used to this purpose since 1987, when FilmTec™ SR90-400 elements were installed in an offshore platform in the North Sea. The most pressing concern in this type of systems is membrane fouling, with the associated reduction in effective plant operation time and shorten element lifespan caused by the standard Clean-in-Place (CIP) protocols. The object of this research has been to test the latest developments in biofouling-resistant sulfate removal membranes to achieve oil and gas (O&G) industry requirements. Improved chemistry and improved module engineering have enabled the production of new membrane elements that represent the next-generation in sulfate removal nanofiltration. Next-generation sulfate removal membranes have been trial-tested. In pilot testing, target performance was validated in terms of productivity, permeate quality and fouling resistance. The results of this testing indicate that improvements in membrane chemistry and module engineering have resulted in a 63% decrease in pressure drop and a much slower fouling trend over the total of 6 elements. This significant improvement should allow an important reduction in the number of cleanings, which the authors have estimated to be of 50%. Moreover, sulfate rejection values are in the range of 99.9% (below 1 ppm of sulfate in the permeate), providing great injection- quality water. Full-scale testing in a production site in the Atlantic Ocean was done to validate pilot testing results, showing a continued operation of 100 days without any need for a clean-in-place (CIP) procedure. The results obtained in the extensive testing carried out on these new antifouling elements, show that the improvements implemented in its design have the ability to improve the operation of Sulfate Removal Units (SRU). These improvements are the results of reducing maintenance costs and downtime on offshore platforms, resulting in increased operation and improved productivity.","PeriodicalId":11072,"journal":{"name":"Day 1 Mon, August 16, 2021","volume":"10 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-08-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90535121","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}
Geophysical seismic surveys have been used in marine site characterization for subsea engineering and the design of offshore structures. Signal processing plays a key role in obtaining seismic attributes from observed seismic data to identify subsurface geological features within complex shallow sediments. Instantaneous amplitude, phase, and frequency are the most widely used seismic attributes to indicate geological features, but those time-domain data are too limited to define an accurate subsurface model in depth. Therefore, seismic inversion is also required to generate additional geospatial subsurface model information to aid in shallow stratigraphy interpretation. In this paper, we applied both geophysical signal processing and stochastic seismic inversion to a high-resolution multichannel seismic dataset from the Eastern North American Margin (ENAM). Seismic attributes from the Hilbert transform and inversion modeling results (acoustic impedance and modeling uncertainty) were integrated to define better geological horizons and discontinuities. The results show the integrated geophysical subsurface models can support seismic interpretation and improve shallow marine site characterization.
{"title":"Seismic Attributes and Acoustic Inversion for Shallow Marine Slope Stratigraphy Analysis","authors":"J. Son, Rebecca Boon, Julien Kuhn de Chizelle","doi":"10.4043/31102-ms","DOIUrl":"https://doi.org/10.4043/31102-ms","url":null,"abstract":"\u0000 Geophysical seismic surveys have been used in marine site characterization for subsea engineering and the design of offshore structures. Signal processing plays a key role in obtaining seismic attributes from observed seismic data to identify subsurface geological features within complex shallow sediments. Instantaneous amplitude, phase, and frequency are the most widely used seismic attributes to indicate geological features, but those time-domain data are too limited to define an accurate subsurface model in depth. Therefore, seismic inversion is also required to generate additional geospatial subsurface model information to aid in shallow stratigraphy interpretation. In this paper, we applied both geophysical signal processing and stochastic seismic inversion to a high-resolution multichannel seismic dataset from the Eastern North American Margin (ENAM). Seismic attributes from the Hilbert transform and inversion modeling results (acoustic impedance and modeling uncertainty) were integrated to define better geological horizons and discontinuities. The results show the integrated geophysical subsurface models can support seismic interpretation and improve shallow marine site characterization.","PeriodicalId":11072,"journal":{"name":"Day 1 Mon, August 16, 2021","volume":"15 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-08-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90771634","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}
An international operating company detected a leak during an annual ROV inspection of a water injection (WI) pipeline offshore Angola in the Gulf of Guinea. The pipeline owner made the decision to repair the damaged line using clamps, but there were multiple challenges involved in executing the repair. First was the depth of the pipeline, which was on the seabed across an area that ranged from 1,170 m to 1,410 m (3,839 ft – 4,626 ft). Additional challenges included potential complications for clamp installation because of the location of the pipe welds and the physical condition of the pipe, which had experienced considerable wall thinning in multiple areas. Bringing the pipeline back into safe service required repairs to the aging pipe within a scope of work that included site preparation, the installation of two 12-in clamp connectors, and inspection services following clamp placement to verify proper installation. Because there were welds in the WI pipeline, there was a risk that the clamp installation site would correspond with an area of the pipe that was welded, which would impact the ability of the clamps to fit snugly over the damaged area. Survey data were cross-referenced with the client's data to determine that the weld locations would not interfere with the installation. Coating removal was critical, so a purpose-built mechanical tool was designed to prepare the pipeline for clamp installation. The project also required finite element analysis (FEA) to confirm that the pipeline could withstand the seal load applied by the repair clamps. The project was carried out in three steps. The objective of the first step was to prepare and stabilize the seabed to ensure it could bear the weight of the clamp installation frame and the impact of the ROV working nearby. The second phase focused on preparing the repair locations for installation of the clamps, a process that included coating removal and surface cleaning to return the WI pipeline to bare metal finish in the clamp areas. The third phase was the preparation and installation of the 12-in repair clamps. This included the inspection and spot cleaning of pipeline surfaces, clamp installation, and clamp seal verification. The two clamps were successfully installed and passed pressure testing in February 2020, enabling the operator to bring the WI line back online and functioning safely at reduced pressure. This repair employed the highest-pressure clamp of this type installed to date (138 bar / 2,000 psi).
{"title":"Water Injection Pipeline Repair Offshore Angola Enhances Production","authors":"Kamil Sobolewski","doi":"10.4043/31015-ms","DOIUrl":"https://doi.org/10.4043/31015-ms","url":null,"abstract":"\u0000 An international operating company detected a leak during an annual ROV inspection of a water injection (WI) pipeline offshore Angola in the Gulf of Guinea. The pipeline owner made the decision to repair the damaged line using clamps, but there were multiple challenges involved in executing the repair. First was the depth of the pipeline, which was on the seabed across an area that ranged from 1,170 m to 1,410 m (3,839 ft – 4,626 ft). Additional challenges included potential complications for clamp installation because of the location of the pipe welds and the physical condition of the pipe, which had experienced considerable wall thinning in multiple areas. Bringing the pipeline back into safe service required repairs to the aging pipe within a scope of work that included site preparation, the installation of two 12-in clamp connectors, and inspection services following clamp placement to verify proper installation.\u0000 Because there were welds in the WI pipeline, there was a risk that the clamp installation site would correspond with an area of the pipe that was welded, which would impact the ability of the clamps to fit snugly over the damaged area. Survey data were cross-referenced with the client's data to determine that the weld locations would not interfere with the installation. Coating removal was critical, so a purpose-built mechanical tool was designed to prepare the pipeline for clamp installation. The project also required finite element analysis (FEA) to confirm that the pipeline could withstand the seal load applied by the repair clamps.\u0000 The project was carried out in three steps. The objective of the first step was to prepare and stabilize the seabed to ensure it could bear the weight of the clamp installation frame and the impact of the ROV working nearby. The second phase focused on preparing the repair locations for installation of the clamps, a process that included coating removal and surface cleaning to return the WI pipeline to bare metal finish in the clamp areas. The third phase was the preparation and installation of the 12-in repair clamps. This included the inspection and spot cleaning of pipeline surfaces, clamp installation, and clamp seal verification.\u0000 The two clamps were successfully installed and passed pressure testing in February 2020, enabling the operator to bring the WI line back online and functioning safely at reduced pressure.\u0000 This repair employed the highest-pressure clamp of this type installed to date (138 bar / 2,000 psi).","PeriodicalId":11072,"journal":{"name":"Day 1 Mon, August 16, 2021","volume":"29 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-08-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"76916114","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}
R. Prabhu, J. Santamaría, Nirupama A Vaidya, P. Abivin, V. Lafitte, B. Gadiyar
A gravel packing fluid system was developed for elevated temperature applications above 290°F comprised of xanthan gum and a high-temperature gravel suspension additive. This fluid system has been successfully pumped in four openhole gravel packing operations so far, validating its suitability for Alternate Path gravel packing technology involving shunt tubes. Laboratory qualification testing for this fluid showed excellent gravel suspension, rheology, and breaking profiles for cleanup and minimal damage during production. Xanthan gels have been used in gravel packing applications for many years. However, by itself, xanthan was unable to suspend gravel at temperatures above 290°F possibly due to onset of thermally activated polymer degradation. This paper demonstrates that gravel suspension ability can be vastly improved with the addition of a recently developed nano-additive. This additive is a specially designed versatile nanosized material that has a proven track record with visco-elastic surfactant fluids in the past. In the present study, we show the successful application of this additive with polymer-based carrier fluids such as xanthan, effectively increasing their application range to 325°F. With the inclusion of this suspension additive, xanthan concentration in the fluid system can also be reduced, which has other potential benefits such as better cleanup after gel break. Extensive laboratory evaluation for fluid qualification was performed prior to the job. High-pressure/high-temperature (HP/HT) rheology measurements were performed using industry-standard rheometers at various shear rates to match specific viscosity requirements for shunt tube applications. Gravel suspension tests performed using special pressurized cells immersed in oil bath at the required bottomhole static temperature showed improved gravel suspension with the nano-additive. Fluid breaking with conventional oxidative breaker was also demonstrated with viscosity measurements. Formation response tests showed very good fluid cleanup with 90% regained permeability. Laboratory testing and successful field applications have proven the effectiveness of this new fluid system.
{"title":"Nanomaterials Improve Polymer-Based Gravel-Packing Fluids at High Temperature","authors":"R. Prabhu, J. Santamaría, Nirupama A Vaidya, P. Abivin, V. Lafitte, B. Gadiyar","doi":"10.4043/30967-ms","DOIUrl":"https://doi.org/10.4043/30967-ms","url":null,"abstract":"\u0000 A gravel packing fluid system was developed for elevated temperature applications above 290°F comprised of xanthan gum and a high-temperature gravel suspension additive. This fluid system has been successfully pumped in four openhole gravel packing operations so far, validating its suitability for Alternate Path gravel packing technology involving shunt tubes. Laboratory qualification testing for this fluid showed excellent gravel suspension, rheology, and breaking profiles for cleanup and minimal damage during production.\u0000 Xanthan gels have been used in gravel packing applications for many years. However, by itself, xanthan was unable to suspend gravel at temperatures above 290°F possibly due to onset of thermally activated polymer degradation. This paper demonstrates that gravel suspension ability can be vastly improved with the addition of a recently developed nano-additive. This additive is a specially designed versatile nanosized material that has a proven track record with visco-elastic surfactant fluids in the past. In the present study, we show the successful application of this additive with polymer-based carrier fluids such as xanthan, effectively increasing their application range to 325°F. With the inclusion of this suspension additive, xanthan concentration in the fluid system can also be reduced, which has other potential benefits such as better cleanup after gel break.\u0000 Extensive laboratory evaluation for fluid qualification was performed prior to the job. High-pressure/high-temperature (HP/HT) rheology measurements were performed using industry-standard rheometers at various shear rates to match specific viscosity requirements for shunt tube applications. Gravel suspension tests performed using special pressurized cells immersed in oil bath at the required bottomhole static temperature showed improved gravel suspension with the nano-additive. Fluid breaking with conventional oxidative breaker was also demonstrated with viscosity measurements. Formation response tests showed very good fluid cleanup with 90% regained permeability.\u0000 Laboratory testing and successful field applications have proven the effectiveness of this new fluid system.","PeriodicalId":11072,"journal":{"name":"Day 1 Mon, August 16, 2021","volume":"75 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-08-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79357162","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}
Lawson Burns, Theresa Allen, Jeff Karlik, J. Ding, Rea Cauthen, Mita Das, Guy Ashley, R. Szafranski
The Liza Phase 2 Project combines a novel execution approach and forward-looking technology components to develop more complex areas of the Liza resource. The project delivers technology to optimize resource development through efficient Subsea, Umbilicals, Risers, and Flowlines (SURF) equipment designs and digital elements to enable future capabilities, such as a fiber optic cable to shore. For a new approach to Floating, Production, Storage and Offloading (FPSO) delivery, the project is partnering with SBM for the first ever use of their Fast4Ward® concept. The SBM Fast4Ward® program utilizes the Multi-Purpose Floater (MPF) hull design and provides the benefits of a new build FPSO with a reduced project development time similar to that of conversions. With almost double the SURF infrastructure as Liza Phase 1, Liza Phase 2 uses learnings and standardized SURF architecture to deliver one of the industry's largest subsea developments. Establishment of win-win partnerships with the primary contractors to achieve best overall value and strategic use of part number duplication contribute to the overall success. Based on the work of ExxonMobil proprietary reservoir modelling, infrastructure is being installed to enable Water Alternating Gas (WAG) injection for the complex development while a subsea fiber optic cable enables data to shore for optimized reservoir management and advanced facilities surveillance. The project is on track to deliver ~2 years after first oil was achieved for Liza Phase 1 by building on design replication and common methodologies where possible. Through thoughtful application of standardization, learnings, and incorporation of new technologies, the project efficiently delivers advanced capabilities to the Liza field. This also enables a "Design One, Build Multiple" (D1BM) approach for future developments in Guyana.
{"title":"Guyana: Liza Phase 2 Novel Execution to Accelerate Field Development","authors":"Lawson Burns, Theresa Allen, Jeff Karlik, J. Ding, Rea Cauthen, Mita Das, Guy Ashley, R. Szafranski","doi":"10.4043/30948-ms","DOIUrl":"https://doi.org/10.4043/30948-ms","url":null,"abstract":"\u0000 The Liza Phase 2 Project combines a novel execution approach and forward-looking technology components to develop more complex areas of the Liza resource. The project delivers technology to optimize resource development through efficient Subsea, Umbilicals, Risers, and Flowlines (SURF) equipment designs and digital elements to enable future capabilities, such as a fiber optic cable to shore. For a new approach to Floating, Production, Storage and Offloading (FPSO) delivery, the project is partnering with SBM for the first ever use of their Fast4Ward® concept.\u0000 The SBM Fast4Ward® program utilizes the Multi-Purpose Floater (MPF) hull design and provides the benefits of a new build FPSO with a reduced project development time similar to that of conversions. With almost double the SURF infrastructure as Liza Phase 1, Liza Phase 2 uses learnings and standardized SURF architecture to deliver one of the industry's largest subsea developments. Establishment of win-win partnerships with the primary contractors to achieve best overall value and strategic use of part number duplication contribute to the overall success.\u0000 Based on the work of ExxonMobil proprietary reservoir modelling, infrastructure is being installed to enable Water Alternating Gas (WAG) injection for the complex development while a subsea fiber optic cable enables data to shore for optimized reservoir management and advanced facilities surveillance.\u0000 The project is on track to deliver ~2 years after first oil was achieved for Liza Phase 1 by building on design replication and common methodologies where possible. Through thoughtful application of standardization, learnings, and incorporation of new technologies, the project efficiently delivers advanced capabilities to the Liza field. This also enables a \"Design One, Build Multiple\" (D1BM) approach for future developments in Guyana.","PeriodicalId":11072,"journal":{"name":"Day 1 Mon, August 16, 2021","volume":"43 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-08-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82206394","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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