F. Papot, Celma Alexandre, M. Abdulssalam, Ambrosio Chita, A. Pina, Antonio Chipoque, P. Glénat
This paper describes a recent hydrate plug issue experienced in a 12inch gas export line of one of TOTAL E&P operated FPSOs in the deep water of West Africa. In summer 2018, due to long-term maintenance work on the dehydration unit of the FPSO's gas compression, the off- spec produced gas was injected into a remote subsea gas well injector to avoid gas flaring, in line with TOTAL's flaring policy. Methanol was continuously injected for hydrate inhibition. Unfortunately, at the end of the operation, a hydrate plug occurred in the 12-inch gas export line. Through a multi–disciplinary crisis management team, all necessary efforts and procedures were implemented to remove the plug from the line in less than 1 week. The main steps included topsides depressurisation, a subsea intervention, additional hydrate inhibitor injection (Methanol and especially MEG) and liquid flushing operations.
{"title":"Remediation of Hydrate Plug in Gas Export Line – A West Africa Deep Water Case","authors":"F. Papot, Celma Alexandre, M. Abdulssalam, Ambrosio Chita, A. Pina, Antonio Chipoque, P. Glénat","doi":"10.4043/29946-ms","DOIUrl":"https://doi.org/10.4043/29946-ms","url":null,"abstract":"\u0000 This paper describes a recent hydrate plug issue experienced in a 12inch gas export line of one of TOTAL E&P operated FPSOs in the deep water of West Africa. In summer 2018, due to long-term maintenance work on the dehydration unit of the FPSO's gas compression, the off- spec produced gas was injected into a remote subsea gas well injector to avoid gas flaring, in line with TOTAL's flaring policy. Methanol was continuously injected for hydrate inhibition. Unfortunately, at the end of the operation, a hydrate plug occurred in the 12-inch gas export line. Through a multi–disciplinary crisis management team, all necessary efforts and procedures were implemented to remove the plug from the line in less than 1 week. The main steps included topsides depressurisation, a subsea intervention, additional hydrate inhibitor injection (Methanol and especially MEG) and liquid flushing operations.","PeriodicalId":10927,"journal":{"name":"Day 3 Thu, October 31, 2019","volume":"27 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-10-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"72761160","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}
N. M. Júnior, Cristiano Eduardo Agostini, Cleidilson Moura dos Santos, Roger Savoldi Roman, E. Schnitzler, Mateus Dias Magalhães, M. Ferreira, C. O. Souza
This paper presents the findings of a comprehensive structural analysis in which the influence of thermal transient pressure behavior on the trapped annuli in an injection well in a Brazilian pre-salt field was assessed, mainly motivated by physical evidence of a well failure. The study focus on a transient heat flow in radial direction during a well failure investigation, and its impact in tubular design safety factor under a given casing design methodology. During the investigation of this well integrity failure, a thermal analysis was performed considering the well construction history, but standard simulations using a world-class commercial software was not enough to explain the failure. Thus, a modified thermal analysis for casing and tubing was made in order to evaluate the design safety factor during each operation. This modified thermal analysis consists in splitting each operation in short time steps, in order to capture the short transient behavior. It was found that, during short transient time, the collapse stresses reached higher values than predicted in the previous standard steady-state modeling. Such result is basically related to the transient effect caused by radial heat flow. Based on theoretical studies and comparing them to downhole P&T sensors in confined annuli, a correlation was stablished and showed the importance of this type of analysis. In certain scenarios, where the confined annuli are subjected to progressive and non-proportional cooling down effect between the casing layers, a sudden pressure drop may occur in the internal side of the casing, without reaching the same pressure drop on the external side, which can lead to a dramatic external differential pressure for a given string. In wells with multiple confined annuli, such as in ultra-deepwater projects, this type of analysis represents a greater challenge. The results obtained so far have shown that the permanent and transient radial heat flow cannot be neglected in some scenarios and, therefore, open a new frontier for well design, especially when the tubing and multiple casing trapped annuli are subjected to rapid transient cool down.
{"title":"Structural Analysis of Thermal Behavior On Cooling Trapped Annular Pressure In Water and Gas Injection Wells","authors":"N. M. Júnior, Cristiano Eduardo Agostini, Cleidilson Moura dos Santos, Roger Savoldi Roman, E. Schnitzler, Mateus Dias Magalhães, M. Ferreira, C. O. Souza","doi":"10.4043/29832-ms","DOIUrl":"https://doi.org/10.4043/29832-ms","url":null,"abstract":"\u0000 This paper presents the findings of a comprehensive structural analysis in which the influence of thermal transient pressure behavior on the trapped annuli in an injection well in a Brazilian pre-salt field was assessed, mainly motivated by physical evidence of a well failure. The study focus on a transient heat flow in radial direction during a well failure investigation, and its impact in tubular design safety factor under a given casing design methodology.\u0000 During the investigation of this well integrity failure, a thermal analysis was performed considering the well construction history, but standard simulations using a world-class commercial software was not enough to explain the failure. Thus, a modified thermal analysis for casing and tubing was made in order to evaluate the design safety factor during each operation. This modified thermal analysis consists in splitting each operation in short time steps, in order to capture the short transient behavior. It was found that, during short transient time, the collapse stresses reached higher values than predicted in the previous standard steady-state modeling. Such result is basically related to the transient effect caused by radial heat flow.\u0000 Based on theoretical studies and comparing them to downhole P&T sensors in confined annuli, a correlation was stablished and showed the importance of this type of analysis. In certain scenarios, where the confined annuli are subjected to progressive and non-proportional cooling down effect between the casing layers, a sudden pressure drop may occur in the internal side of the casing, without reaching the same pressure drop on the external side, which can lead to a dramatic external differential pressure for a given string.\u0000 In wells with multiple confined annuli, such as in ultra-deepwater projects, this type of analysis represents a greater challenge. The results obtained so far have shown that the permanent and transient radial heat flow cannot be neglected in some scenarios and, therefore, open a new frontier for well design, especially when the tubing and multiple casing trapped annuli are subjected to rapid transient cool down.","PeriodicalId":10927,"journal":{"name":"Day 3 Thu, October 31, 2019","volume":"41 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-10-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"74199610","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}
Sarah Bernardes de Almeida, A. Winter, L. Pires, O. V. Trevisan
Carbonate reservoirs are characterized by neutral or oil-wet surfaces and the injection of water as a secondary recovery method may result in low oil recovery factors. The injection of low salinity brines has shown to be a method that can lead to significant additional oil recoveries, since they promote alteration of the surface wettability towards a more water-wet condition. Several studies indicated that some ions present in the injected brine (Ca2+, Mg2+ and SO42-) are able to act in the ionic exchanges that promote the wettability alteration. Also, the decrease of the concentration of Na+ and Cl- resulted in an additional oil recovery factor in some studies. The studies of oil recovery at laboratory scale are usually performed in Amott's cells or by coreflooding. In this paper, the study of oil recovery using a high-speed centrifuge (HSC) is proposed in an innovative way with the aim to validate it as an apparatus for the study of wettability alteration. For this, six Silurian dolomite outcrop cores were used. Primary drainage process was performed on the HSC to establish the initial water saturation condition. Formation water and oil from a Brazilian pre-salt field with 2% weight of naphthenic acid were used as the saturation fluids. The cores were aged at 110 °C for 20 days to alter the initial water-wet condition. Two sets of tests were performed in the HSC to study the effects of the reduction of Na+ and Cl- ions in seawater composition. Additional oil recovery was observed using brine depleted of Na+ and Cl- ions. Besides, it was observed the influence of the sample permeability on oil recovery. The high concentration of Na+ and Cl- ions hinder the access of the potential ions (Ca2+, Mg2+ and SO42-) to the rock surface and, as consequence, hamper the wettability alteration mechanism. Removing these ions, the potential ions can reach easier to the surface and alters its wettability towards a more water-wet condition, promoting the additional oil recovery. Thus, the results showed that HSC could be used as preliminary apparatus for the wettability alteration studies in carbonate samples.
{"title":"Wettability Alteration in Carbonate Rocks by the Low Salinity Water using a High-Speed Centrifuge","authors":"Sarah Bernardes de Almeida, A. Winter, L. Pires, O. V. Trevisan","doi":"10.4043/29868-ms","DOIUrl":"https://doi.org/10.4043/29868-ms","url":null,"abstract":"\u0000 Carbonate reservoirs are characterized by neutral or oil-wet surfaces and the injection of water as a secondary recovery method may result in low oil recovery factors. The injection of low salinity brines has shown to be a method that can lead to significant additional oil recoveries, since they promote alteration of the surface wettability towards a more water-wet condition. Several studies indicated that some ions present in the injected brine (Ca2+, Mg2+ and SO42-) are able to act in the ionic exchanges that promote the wettability alteration. Also, the decrease of the concentration of Na+ and Cl- resulted in an additional oil recovery factor in some studies. The studies of oil recovery at laboratory scale are usually performed in Amott's cells or by coreflooding. In this paper, the study of oil recovery using a high-speed centrifuge (HSC) is proposed in an innovative way with the aim to validate it as an apparatus for the study of wettability alteration. For this, six Silurian dolomite outcrop cores were used. Primary drainage process was performed on the HSC to establish the initial water saturation condition. Formation water and oil from a Brazilian pre-salt field with 2% weight of naphthenic acid were used as the saturation fluids. The cores were aged at 110 °C for 20 days to alter the initial water-wet condition. Two sets of tests were performed in the HSC to study the effects of the reduction of Na+ and Cl- ions in seawater composition. Additional oil recovery was observed using brine depleted of Na+ and Cl- ions. Besides, it was observed the influence of the sample permeability on oil recovery. The high concentration of Na+ and Cl- ions hinder the access of the potential ions (Ca2+, Mg2+ and SO42-) to the rock surface and, as consequence, hamper the wettability alteration mechanism. Removing these ions, the potential ions can reach easier to the surface and alters its wettability towards a more water-wet condition, promoting the additional oil recovery. Thus, the results showed that HSC could be used as preliminary apparatus for the wettability alteration studies in carbonate samples.","PeriodicalId":10927,"journal":{"name":"Day 3 Thu, October 31, 2019","volume":"71 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-10-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"75098623","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}
Ronaldo Giro, Silas Pereira Lima Filho, Ferreira Rodrigo Neumann Barros, Michael S. Engel, M. Steiner
The global average Recovery Factor (RF) in oil fields is only about 20-40%. A possible reason for such a low RF might be that Enhanced Oil Recovery (EOR) techniques are not yet broadly applied. This could be for economic reasons, concerns regarding the effectiveness of EOR and potential damage to the reservoir, or the lack of reservoir-specific recommendations. In this contribution, we introduce a methodology that selects EOR materials for specific reservoir conditions by using Artificial Intelligence (AI) methods. We investigate the consistency of the screening results with the results obtained by state-of-the-art techniques that are used to identify EOR methods only, i.e., without EOR material specificity. Our method correlates physical and chemical representations of injection fluids, including EOR materials, with reservoir-specific information on lithology, porosity, permeability, as well as oil, water and salt conditions. We have used machine learning on the combined data set in order to provide recommendation for EOR cocktail for injection fluids. Reservoir specific data input on rock, oil, and water conditions available in well logs is transformed by the AI model into a reservoir-specific recommendation of EOR candidate materials for optimized EOR effectiveness. The screening criteria are ranked based on EOR effectiveness and the similarity of key reservoir parameters at pore scale. Methodologically, a Naïve Bayes Classifier with 10-fold cross-validation over the full training data set classified all instances with an accuracy of up to 90%. In order to compare with the EOR method screening criteria typically used in the industry, we have created a test data set containing instances based on averaged parameter values for representing each EOR method. In this case, our method is capable of classifying the test data set with nearly 100% accuracy. Our methodology allows to produce recommendations for EOR cocktails, including concentrations of their chemical components, for specific reservoir conditions that are readily available through well logs.
{"title":"Artificial Intelligence-Based Screening of Enhanced Oil Recovery Materials for Reservoir-Specific Applications","authors":"Ronaldo Giro, Silas Pereira Lima Filho, Ferreira Rodrigo Neumann Barros, Michael S. Engel, M. Steiner","doi":"10.4043/29754-ms","DOIUrl":"https://doi.org/10.4043/29754-ms","url":null,"abstract":"\u0000 The global average Recovery Factor (RF) in oil fields is only about 20-40%. A possible reason for such a low RF might be that Enhanced Oil Recovery (EOR) techniques are not yet broadly applied. This could be for economic reasons, concerns regarding the effectiveness of EOR and potential damage to the reservoir, or the lack of reservoir-specific recommendations.\u0000 In this contribution, we introduce a methodology that selects EOR materials for specific reservoir conditions by using Artificial Intelligence (AI) methods. We investigate the consistency of the screening results with the results obtained by state-of-the-art techniques that are used to identify EOR methods only, i.e., without EOR material specificity.\u0000 Our method correlates physical and chemical representations of injection fluids, including EOR materials, with reservoir-specific information on lithology, porosity, permeability, as well as oil, water and salt conditions. We have used machine learning on the combined data set in order to provide recommendation for EOR cocktail for injection fluids. Reservoir specific data input on rock, oil, and water conditions available in well logs is transformed by the AI model into a reservoir-specific recommendation of EOR candidate materials for optimized EOR effectiveness. The screening criteria are ranked based on EOR effectiveness and the similarity of key reservoir parameters at pore scale.\u0000 Methodologically, a Naïve Bayes Classifier with 10-fold cross-validation over the full training data set classified all instances with an accuracy of up to 90%. In order to compare with the EOR method screening criteria typically used in the industry, we have created a test data set containing instances based on averaged parameter values for representing each EOR method. In this case, our method is capable of classifying the test data set with nearly 100% accuracy. Our methodology allows to produce recommendations for EOR cocktails, including concentrations of their chemical components, for specific reservoir conditions that are readily available through well logs.","PeriodicalId":10927,"journal":{"name":"Day 3 Thu, October 31, 2019","volume":"36 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-10-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79815325","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}
Katia Regina Silva Alves da Rosa, R. A. Fontes, F. Rosário, T. C. Freitas, M. Penna, B. Castro, M. G. F. D. Silva, Giselle Maria Lopes Leite da Silva, Jussara de Mello Silva, Mariana Rocha Figueiredo
Scale occurrence can cause oil and gas production loss with high economic impacts. Currently, the use of chemicals is one of the key strategies for scale management. A laboratory tests protocol is essential to qualify and guarantee chemical effectiveness in the field. The objective of this work is to present a protocol that includes improvements in the procedures to evaluate scale inhibitors and allows wide application to several production scenarios. The protocol is an improvement based on published international technical standards and the literature. These adjustments of the experimental procedures enabled the representation of a wide range of scaling scenarios from reservoir to topside facilities. An efficient application of scale inhibitor includes the definition of the ionic composition of aqueous fluids as well as the pressure and temperature conditions of the target scenario. To perform the laboratory tests, synthetic waters are prepared to represent the water production scenario, including pH. The tests are performed using synthetic produced water, including evaluation of fluids compatibility (one or two phase experiment), thermal stability and static and dynamic performance (DSL-dynamic scale loop). The proposed test protocol allows the qualification of scale inhibitors to the production scenario considered, reducing the associated uncertainties of upscaling from laboratory to field. The availability of the company's protocols makes it possible to achieve greater accuracy in the recommendation of commercial scale inhibitors, allowing a better cost-benefit with the optimization of the effective minimum concentrations. In addition, this availability encourages the development of new generation inhibitors for challenging scenarios with high scaling potential. The improved protocol is designed to represent critical salt precipitation scenarios, similar to those found in the Brazilian Pre-salt (high salinity, high temperature, high saturation ratio, high CO2 content), and has been successfully applied in the screening and qualification of scale inhibitors.
{"title":"Improved Protocol for Scale Inhibitor Evaluation: A Meaningful Step on Scale Management","authors":"Katia Regina Silva Alves da Rosa, R. A. Fontes, F. Rosário, T. C. Freitas, M. Penna, B. Castro, M. G. F. D. Silva, Giselle Maria Lopes Leite da Silva, Jussara de Mello Silva, Mariana Rocha Figueiredo","doi":"10.4043/29683-ms","DOIUrl":"https://doi.org/10.4043/29683-ms","url":null,"abstract":"\u0000 Scale occurrence can cause oil and gas production loss with high economic impacts. Currently, the use of chemicals is one of the key strategies for scale management. A laboratory tests protocol is essential to qualify and guarantee chemical effectiveness in the field. The objective of this work is to present a protocol that includes improvements in the procedures to evaluate scale inhibitors and allows wide application to several production scenarios. The protocol is an improvement based on published international technical standards and the literature. These adjustments of the experimental procedures enabled the representation of a wide range of scaling scenarios from reservoir to topside facilities. An efficient application of scale inhibitor includes the definition of the ionic composition of aqueous fluids as well as the pressure and temperature conditions of the target scenario. To perform the laboratory tests, synthetic waters are prepared to represent the water production scenario, including pH. The tests are performed using synthetic produced water, including evaluation of fluids compatibility (one or two phase experiment), thermal stability and static and dynamic performance (DSL-dynamic scale loop). The proposed test protocol allows the qualification of scale inhibitors to the production scenario considered, reducing the associated uncertainties of upscaling from laboratory to field. The availability of the company's protocols makes it possible to achieve greater accuracy in the recommendation of commercial scale inhibitors, allowing a better cost-benefit with the optimization of the effective minimum concentrations. In addition, this availability encourages the development of new generation inhibitors for challenging scenarios with high scaling potential. The improved protocol is designed to represent critical salt precipitation scenarios, similar to those found in the Brazilian Pre-salt (high salinity, high temperature, high saturation ratio, high CO2 content), and has been successfully applied in the screening and qualification of scale inhibitors.","PeriodicalId":10927,"journal":{"name":"Day 3 Thu, October 31, 2019","volume":"32 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-10-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84479625","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}
Life extension of ageing floating production facilities can be an effective way to maximize profitability of mature assets by extending production and offset decommissioning expenditures, increasing profitability. Utilizing existing assets can be also an option to develop and tie-back new marginal fields in a more economical way rather than develop new large greenfield facilities. Nonetheless, the benefits of extending the life of the production system might be reverted not only due to the installed capital cost of replacement of a mooring system, but also due to loss or deferred production. The present paper proposes a holistic approach for assessment of the mooring system in order to achieve the intended performance of the asset, taking into consideration not only the system design but also the knowledge accumulated during the original operational life of the legacy system.
{"title":"Life Extension of Mooring Systems- A Structured Approach","authors":"C. D. Vecchio, P. Biasotto","doi":"10.4043/29918-ms","DOIUrl":"https://doi.org/10.4043/29918-ms","url":null,"abstract":"\u0000 Life extension of ageing floating production facilities can be an effective way to maximize profitability of mature assets by extending production and offset decommissioning expenditures, increasing profitability. Utilizing existing assets can be also an option to develop and tie-back new marginal fields in a more economical way rather than develop new large greenfield facilities.\u0000 Nonetheless, the benefits of extending the life of the production system might be reverted not only due to the installed capital cost of replacement of a mooring system, but also due to loss or deferred production.\u0000 The present paper proposes a holistic approach for assessment of the mooring system in order to achieve the intended performance of the asset, taking into consideration not only the system design but also the knowledge accumulated during the original operational life of the legacy system.","PeriodicalId":10927,"journal":{"name":"Day 3 Thu, October 31, 2019","volume":"67 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-10-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83852700","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
This paper presents a probabilistic techno-economic evaluation of several turbidite prospects recognized, through 3D seismic, in deep to ultra-deep water of the Punta del Este and Pelotas sedimentary basins, offshore of Uruguay. The production potential of many prospective turbidite reservoirs on the Atlantic margin has been recognized before, and new turbidite prospects were identified in Uruguay's maritime zone after analyzing data from the world's deepest water-depth well (Raya-X1) drilled in 2016. The estimated ultimate recovery of oil and gas was determined, for each prospect, by carrying out probabilistic resource analyses (Monte Carlo simulations) using 3D seismic and key parameters from analog turbidite fields located in sedimentary basins along the Atlantic margin. Black oil fluid was assumed and the production concept involves FPSO vessels. The produced oil would be exported via tankers and the associated gas would be either sent to shore through a gas pipeline, or re-injected into the formation. For the economic evaluation, the latest fiscal terms of the applicable production-sharing contract, for offshore assets in Uruguay, were considered. The outcomes of the probabilistic economic analyses include, for each prospect, several key performance indicators such as: net present value, internal rate of return, maximum negative cash flow, breakeven oil price, government take and entitlement percentage of hydrocarbons. These indicators were determined after running Monte Carlo simulations, which considered probability distribution functions for fixed and variable capital and operational expenditures, along with well productivities and decline rates. Regarding the economics of the project, several scenarios of incremental profit oil for the government and maximum association percentage for ANCAP, the National Oil Company of Uruguay, were evaluated. The cases considered show how key negotiables and variables, featuring in the tender process offered to oil companies interested in Uruguay's offshore hydrocarbon assets, may affect the economics and development solutions of a typical field development project. Considering a plausible base case of 20% ANCAP association and no incremental profit oil for the state, the results show that, for the biggest prospects, the breakeven oil price is situated near 60 USD/bbl. The analysis also shows that the smaller prospects would need to be developed as satellites of the nearby principal prospects in order to become attractive for development. This study sheds light on the exploration potential of turbidites, offshore of Uruguay, and analyzed resource volumes, production profiles and economic returns of a hypothetic development in the case of a commercial discovery. The analyses provide useful templates for international oil companies, which, under the new and more flexible Uruguay Open Round licensing regime, may be interested in the exploration and imminent development of the Uruguayan offshore sedime
本文通过三维地震对乌拉圭近海Punta del Este和Pelotas沉积盆地的深水至超深水区几个浊积岩远景区进行了概率技术经济评价。此前，人们已经认识到大西洋边缘许多浊积岩储层的生产潜力，在分析了2016年钻探的世界上最深的井(Raya-X1)的数据后，在乌拉圭海域发现了新的浊积岩远景。通过利用三维地震数据和大西洋沿岸沉积盆地浊积岩模拟油田的关键参数进行概率资源分析(蒙特卡罗模拟)，确定了每个勘探区的油气最终采收率。黑油液是假定的，生产概念涉及FPSO船。采出的石油将通过油轮出口，伴生气将通过天然气管道输送到岸上，或者重新注入地层。在经济评价方面，审议了乌拉圭离岸资产适用的生产分成合同的最新财政条件。概率经济分析的结果包括对每个勘探区的几个关键绩效指标，如:净现值、内部回报率、最大负现金流、盈亏平衡油价、政府获取和碳氢化合物的权利百分比。这些指标是在运行蒙特卡罗模拟后确定的，该模拟考虑了固定和可变资本和运营支出的概率分布函数，以及油井产能和递减率。关于该项目的经济效益，对政府的增量利润和乌拉圭国家石油公司ANCAP的最大关联百分比的几种情况进行了评估。所考虑的案例表明，在向对乌拉圭海上油气资产感兴趣的石油公司提供招标过程中的关键谈判和变量，可能会影响典型油田开发项目的经济和开发解决方案。考虑到20%的ANCAP关联和国家没有增加利润的基本情况，结果表明，对于最大的前景，盈亏平衡油价位于60美元/桶附近。分析还表明，较小的前景需要作为附近主要前景的卫星加以开发，以便具有开发吸引力。这项研究揭示了乌拉圭近海浊积岩的勘探潜力，并分析了在商业发现的情况下假设开发的资源量、生产概况和经济回报。这些分析为国际石油公司提供了有用的模板，这些公司在新的、更灵活的乌拉圭开放回合许可制度下，可能对乌拉圭近海沉积盆地的勘探和即将开发感兴趣。
{"title":"Probabilistic Techno-Economic Appraisal of Prospective Hydrocarbon Resources in Five Turbidites, Offshore Uruguay","authors":"P. Rodríguez, S. Ferro, R. Weijermars","doi":"10.4043/29929-ms","DOIUrl":"https://doi.org/10.4043/29929-ms","url":null,"abstract":"\u0000 This paper presents a probabilistic techno-economic evaluation of several turbidite prospects recognized, through 3D seismic, in deep to ultra-deep water of the Punta del Este and Pelotas sedimentary basins, offshore of Uruguay. The production potential of many prospective turbidite reservoirs on the Atlantic margin has been recognized before, and new turbidite prospects were identified in Uruguay's maritime zone after analyzing data from the world's deepest water-depth well (Raya-X1) drilled in 2016.\u0000 The estimated ultimate recovery of oil and gas was determined, for each prospect, by carrying out probabilistic resource analyses (Monte Carlo simulations) using 3D seismic and key parameters from analog turbidite fields located in sedimentary basins along the Atlantic margin. Black oil fluid was assumed and the production concept involves FPSO vessels. The produced oil would be exported via tankers and the associated gas would be either sent to shore through a gas pipeline, or re-injected into the formation. For the economic evaluation, the latest fiscal terms of the applicable production-sharing contract, for offshore assets in Uruguay, were considered.\u0000 The outcomes of the probabilistic economic analyses include, for each prospect, several key performance indicators such as: net present value, internal rate of return, maximum negative cash flow, breakeven oil price, government take and entitlement percentage of hydrocarbons. These indicators were determined after running Monte Carlo simulations, which considered probability distribution functions for fixed and variable capital and operational expenditures, along with well productivities and decline rates. Regarding the economics of the project, several scenarios of incremental profit oil for the government and maximum association percentage for ANCAP, the National Oil Company of Uruguay, were evaluated. The cases considered show how key negotiables and variables, featuring in the tender process offered to oil companies interested in Uruguay's offshore hydrocarbon assets, may affect the economics and development solutions of a typical field development project. Considering a plausible base case of 20% ANCAP association and no incremental profit oil for the state, the results show that, for the biggest prospects, the breakeven oil price is situated near 60 USD/bbl. The analysis also shows that the smaller prospects would need to be developed as satellites of the nearby principal prospects in order to become attractive for development.\u0000 This study sheds light on the exploration potential of turbidites, offshore of Uruguay, and analyzed resource volumes, production profiles and economic returns of a hypothetic development in the case of a commercial discovery. The analyses provide useful templates for international oil companies, which, under the new and more flexible Uruguay Open Round licensing regime, may be interested in the exploration and imminent development of the Uruguayan offshore sedime","PeriodicalId":10927,"journal":{"name":"Day 3 Thu, October 31, 2019","volume":"20 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-10-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88675270","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}
Jorge Fernando Lorenzeti Canato, Christiano Da Silva Alves, Thales Barbosa Marques
This paper shows the main concerns related to Flow Assurance during Mexilhão gas field operation. Mexilhão is located in Santos Basin, Brazil and flows from seven gas wells to a fixed platform through a subsea manifold. Well’s water depth average is about 470 meters and platform’s water depth is 172 meters. The tieback between the manifold and platform is 22 kilometers and there are two production pipelines of 12-inch diameter connecting them. The thermo-hydraulic profile of the production fluid enters in hydrate formation region and hydrate thermodynamic inhibitor (MEG) is injected to prevent hydrate formation. This MEG is recovered at the platform and it is reinjected in the wells. Dosing valves located at subsea manifold distributes the desirable quantity of MEG for each well. During eight years of operation, no production loss caused by hydrate blockage has been reported. This paper also shows the method of wax deposit management in Mexilhão subsea system. Although certain amount of wax had been anticipated to accumulate along pipeline, very little wax was found after pig runs. It has been observed that wax appears in platform process plant, however it does not seem to accumulate in the pipeline. Pig runs occur only for the purpose of corrosion monitoring. Another item discussed here is scale prevention, which could be performed with downhole inhibitor injection and it has not been required until today. Finally, transient simulation results which guided the operational procedure to increase gas flow rate are shown. There is no slug catcher at the platform, then, in order to avoid shut downs due to large liquid slug arrival at process plant, the procedure to increase gas flow rate must be performed carefully.
{"title":"Flow Assurance Issues on Mexilhão Field Operation","authors":"Jorge Fernando Lorenzeti Canato, Christiano Da Silva Alves, Thales Barbosa Marques","doi":"10.4043/29727-ms","DOIUrl":"https://doi.org/10.4043/29727-ms","url":null,"abstract":"\u0000 This paper shows the main concerns related to Flow Assurance during Mexilhão gas field operation. Mexilhão is located in Santos Basin, Brazil and flows from seven gas wells to a fixed platform through a subsea manifold. Well’s water depth average is about 470 meters and platform’s water depth is 172 meters. The tieback between the manifold and platform is 22 kilometers and there are two production pipelines of 12-inch diameter connecting them.\u0000 The thermo-hydraulic profile of the production fluid enters in hydrate formation region and hydrate thermodynamic inhibitor (MEG) is injected to prevent hydrate formation. This MEG is recovered at the platform and it is reinjected in the wells. Dosing valves located at subsea manifold distributes the desirable quantity of MEG for each well. During eight years of operation, no production loss caused by hydrate blockage has been reported. This paper also shows the method of wax deposit management in Mexilhão subsea system. Although certain amount of wax had been anticipated to accumulate along pipeline, very little wax was found after pig runs. It has been observed that wax appears in platform process plant, however it does not seem to accumulate in the pipeline. Pig runs occur only for the purpose of corrosion monitoring.\u0000 Another item discussed here is scale prevention, which could be performed with downhole inhibitor injection and it has not been required until today. Finally, transient simulation results which guided the operational procedure to increase gas flow rate are shown. There is no slug catcher at the platform, then, in order to avoid shut downs due to large liquid slug arrival at process plant, the procedure to increase gas flow rate must be performed carefully.","PeriodicalId":10927,"journal":{"name":"Day 3 Thu, October 31, 2019","volume":"28 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-10-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"73932554","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. Quéméré, J. Court, Pierre Montaufray, Xabier Errotabehere, P. Noury, Ksenia Zakariyya, Henning Martinsen Olin
An increasing number of Brazilian floating platform units are currently entering a mature age, inducing numerous asset integrity issues. As corrosion damages FPSOs’ hull structures and outfitting, repairs and/or modifications have to be performed in explosive environment. Those features create important operational challenges, both in terms of safety and production continuity, when hot work techniques are to be used. This is the reason why Cold Pad has developed a cold work technique based on a heavy duty, bonded, mechanical fastener called C-CLAW™. On FPSOs, this novel solution allows today to repair primarily corroded outfitting like handrails, pipe supports, cable trays, electrical boxes and the like. Cold Pad and DNV GL are working together on a design philosophy, a regulatory approach, and a validation programme based on the DNVGL-ST-C501 and the so-called load and resistance factor design (LRFD) format. The article focuses on the application of the regulatory approach for the demonstration of the capacity and reliability of these fasteners. The strength of the bondline and steel fastener components, with their multiple failure mechanisms, are addressed and mainly supported by short-term test results. The article details the main challenges of that new design approach throughout the service life of bonded fasteners, and includes results and findings related to e.g. strength, susceptibility to temperature, and allowable short-term mechanical capacities based on regulatory safety factors. It also provides the early conclusions in terms of application on FPSOs and recommendations regarding fire hazards. The novelty of these bonded mechanical fastener lies, firstly in the industrial product itself, and secondly in the application of one of the most recognized offshore standards for composite components to derive its regulatory mechanical rated capacity.
{"title":"Regulatory Design Assessment of Cold Bonded Fasteners","authors":"M. Quéméré, J. Court, Pierre Montaufray, Xabier Errotabehere, P. Noury, Ksenia Zakariyya, Henning Martinsen Olin","doi":"10.4043/29679-ms","DOIUrl":"https://doi.org/10.4043/29679-ms","url":null,"abstract":"\u0000 An increasing number of Brazilian floating platform units are currently entering a mature age, inducing numerous asset integrity issues. As corrosion damages FPSOs’ hull structures and outfitting, repairs and/or modifications have to be performed in explosive environment. Those features create important operational challenges, both in terms of safety and production continuity, when hot work techniques are to be used. This is the reason why Cold Pad has developed a cold work technique based on a heavy duty, bonded, mechanical fastener called C-CLAW™. On FPSOs, this novel solution allows today to repair primarily corroded outfitting like handrails, pipe supports, cable trays, electrical boxes and the like. Cold Pad and DNV GL are working together on a design philosophy, a regulatory approach, and a validation programme based on the DNVGL-ST-C501 and the so-called load and resistance factor design (LRFD) format. The article focuses on the application of the regulatory approach for the demonstration of the capacity and reliability of these fasteners. The strength of the bondline and steel fastener components, with their multiple failure mechanisms, are addressed and mainly supported by short-term test results.\u0000 The article details the main challenges of that new design approach throughout the service life of bonded fasteners, and includes results and findings related to e.g. strength, susceptibility to temperature, and allowable short-term mechanical capacities based on regulatory safety factors. It also provides the early conclusions in terms of application on FPSOs and recommendations regarding fire hazards. The novelty of these bonded mechanical fastener lies, firstly in the industrial product itself, and secondly in the application of one of the most recognized offshore standards for composite components to derive its regulatory mechanical rated capacity.","PeriodicalId":10927,"journal":{"name":"Day 3 Thu, October 31, 2019","volume":"19 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-10-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79316613","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}
Experimental data confirm that the EOR-effects observed during Smart Water flooding can be explained by wettability alteration toward more water-wet conditions. Detailed knowledge about the important crude oil – brine – rock parameters affecting reservoir wetting, fluid flow and wettability alteration in oil reservoirs is needed when Smart Water EOR potential for reservoirs should be predicted. Both field observations and laboratory experiments confirm that seawater behaves as a Smart Water in limestone reservoirs, significantly improving the oil recovery. Laboratory core experiments have been performed to evaluate the effects of polar components present in crude oil on core wettability during core restoration. Spontaneous imbibition and viscous flooding oil recovery tests have been performed on the restored cores to evaluate the effect of initial core wettability on ultimate oil recoveries. The results have been compared with oil recovery tests that include wettability alteration induced by Smart Water. The experimental results confirmed that adsorption of polar components in crude oil dictates the core wettability established during the core restoration, and strongly water-wet outcrop cores became mixed-wet. The amount of oil that the core was exposed to affected the degree of water wetness, and therefore the crude oil amount needs to be accounted for in core restoration procedures. Oil recovery experiments showed that the ultimate oil recovery increased with increasing water wetness in the cores, confirming that increased positive capillary forces, resulting from wettability alteration, significantly affected fluid flow in porous media, improving oil recovery. The results are in line with the proposed chemical Smart water EOR model valid for both carbonate and sandstone. Wettability alteration toward more water-wet conditions induces increased capillary forces and improved microscopic sweep efficiency. Ultimate oil recovery in was significantly influenced by the core wettability, increasing with water wetness, confirming that capillary forces is an important recovery parameter. Only small changes in core wetting have significant effects on ultimate recoveries, confirming that laboratory core restoration procedures need to be optimized when recovery potentials for reservoirs should be estimated.
{"title":"Recent Updates on Smart Water EOR in Limestone","authors":"S. Strand, T. Puntervold","doi":"10.4043/29732-ms","DOIUrl":"https://doi.org/10.4043/29732-ms","url":null,"abstract":"\u0000 Experimental data confirm that the EOR-effects observed during Smart Water flooding can be explained by wettability alteration toward more water-wet conditions. Detailed knowledge about the important crude oil – brine – rock parameters affecting reservoir wetting, fluid flow and wettability alteration in oil reservoirs is needed when Smart Water EOR potential for reservoirs should be predicted.\u0000 Both field observations and laboratory experiments confirm that seawater behaves as a Smart Water in limestone reservoirs, significantly improving the oil recovery. Laboratory core experiments have been performed to evaluate the effects of polar components present in crude oil on core wettability during core restoration. Spontaneous imbibition and viscous flooding oil recovery tests have been performed on the restored cores to evaluate the effect of initial core wettability on ultimate oil recoveries. The results have been compared with oil recovery tests that include wettability alteration induced by Smart Water.\u0000 The experimental results confirmed that adsorption of polar components in crude oil dictates the core wettability established during the core restoration, and strongly water-wet outcrop cores became mixed-wet. The amount of oil that the core was exposed to affected the degree of water wetness, and therefore the crude oil amount needs to be accounted for in core restoration procedures.\u0000 Oil recovery experiments showed that the ultimate oil recovery increased with increasing water wetness in the cores, confirming that increased positive capillary forces, resulting from wettability alteration, significantly affected fluid flow in porous media, improving oil recovery. The results are in line with the proposed chemical Smart water EOR model valid for both carbonate and sandstone. Wettability alteration toward more water-wet conditions induces increased capillary forces and improved microscopic sweep efficiency. Ultimate oil recovery in was significantly influenced by the core wettability, increasing with water wetness, confirming that capillary forces is an important recovery parameter. Only small changes in core wetting have significant effects on ultimate recoveries, confirming that laboratory core restoration procedures need to be optimized when recovery potentials for reservoirs should be estimated.","PeriodicalId":10927,"journal":{"name":"Day 3 Thu, October 31, 2019","volume":"2 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-10-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84792615","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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