C. M. D. Jesus, A. Compan, Jéferson Coêlho, Alysson Espindola de Sá Silveira, M. Blauth
The representation of karst petrophysical properties on geologic models has been a challenge, mostly because of the lack of reliable information about the mega and giga pore network, such as large vugs, caves, conduits and enlarged fractures. Since image logs currently have provided the capability of measuring morphological properties in this pore scale, specific techniques have been developed with the objective of obtaining quantitative data that capture these properties. In order to evaluate morphological properties that are representative of mega and giga pores, it is necessary to individually segment each pore structure. A set of computational geometry and image processing techniques were used to measure morphological properties, such as area, perimeter, longest internal path (LIP), internal length (IL), and structure diameter. The area and perimeter of the structure are computed directly on the segmented borehole image log data. The application of this technique allows the classification of different mega and giga pore types. The quantitative evaluation of karst porosity developed in this work has been applied in a brazilian karstified pre-salt carbonate reservoir. The results have shown good correlation with dynamic properties, such as fluid losses while drilling and high productivity intervals measured in production logs. It was possible to identify two distinct correlations between the increase of pore diameter and permeability response of fractured and vuggy-cavy reservoirs. This new technique is helpful for improving the knowledge and representability of the pore scales in order to honor the complexity of the structures generated by the karstification processes. Additionally, new workflows have been developed to incorporate the pore diameters in the geological modeling of karstified reservoirs. The distinct properties of each medium, in the future, might be represented in a model with the assignment of specific fluid mechanics equations, such as Darcys and Hagen-Poiseuilles, for each one. There is a new ground to be gained in fluid flow simulation at these wide ranges of scales and heterogeneous distribution. For that reason, one of the aims of this paper is to stimulate the petrophysical and geological communities towards this goal, as more representative properties of karst porosity heterogeneity become available.
{"title":"Evaluation of Karst Porosity Morphological Properties through Borehole Image Logs – Correlation with Dynamic Reservoir Properties from a presalt Oil Field","authors":"C. M. D. Jesus, A. Compan, Jéferson Coêlho, Alysson Espindola de Sá Silveira, M. Blauth","doi":"10.4043/29722-ms","DOIUrl":"https://doi.org/10.4043/29722-ms","url":null,"abstract":"\u0000 The representation of karst petrophysical properties on geologic models has been a challenge, mostly because of the lack of reliable information about the mega and giga pore network, such as large vugs, caves, conduits and enlarged fractures. Since image logs currently have provided the capability of measuring morphological properties in this pore scale, specific techniques have been developed with the objective of obtaining quantitative data that capture these properties.\u0000 In order to evaluate morphological properties that are representative of mega and giga pores, it is necessary to individually segment each pore structure. A set of computational geometry and image processing techniques were used to measure morphological properties, such as area, perimeter, longest internal path (LIP), internal length (IL), and structure diameter. The area and perimeter of the structure are computed directly on the segmented borehole image log data. The application of this technique allows the classification of different mega and giga pore types.\u0000 The quantitative evaluation of karst porosity developed in this work has been applied in a brazilian karstified pre-salt carbonate reservoir. The results have shown good correlation with dynamic properties, such as fluid losses while drilling and high productivity intervals measured in production logs. It was possible to identify two distinct correlations between the increase of pore diameter and permeability response of fractured and vuggy-cavy reservoirs. This new technique is helpful for improving the knowledge and representability of the pore scales in order to honor the complexity of the structures generated by the karstification processes. Additionally, new workflows have been developed to incorporate the pore diameters in the geological modeling of karstified reservoirs. The distinct properties of each medium, in the future, might be represented in a model with the assignment of specific fluid mechanics equations, such as Darcys and Hagen-Poiseuilles, for each one.\u0000 There is a new ground to be gained in fluid flow simulation at these wide ranges of scales and heterogeneous distribution. For that reason, one of the aims of this paper is to stimulate the petrophysical and geological communities towards this goal, as more representative properties of karst porosity heterogeneity become available.","PeriodicalId":11089,"journal":{"name":"Day 2 Wed, October 30, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-10-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"76832451","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}
Matheus de Freitas Bezerra, Guilherme Cosme Viganô, J. L. Giuriatto
Nowadays gas-lift is still a very expressive artificial lift method, for instance considering the whole Brazilian oil production profiles, gas lifted wells are responsible for 30% of monthly production. Due this huge importance, the injection efficiency should be ensured to avoid lid gas losses and maximize the production. Then, this study had as objective to develop a Gas Lift Optimization workflow and define the optimum lift rates to increase the reservoir recovery and improve gas usability due to platform constraints of a Brazilian deep-water field. That workflow comprises a reservoir and flow assurance simulators, achieving more accurate responses compared to regular workflows. Taking advantages of the proposed method, multidisciplinary teams could work together which increases the representativeness of such studies providing important outcomes for decision makers. At this study, due to a gas-lift optimization was observed an increase of 0.5% at cumulative production with a huge gas-lift reduction of around 40%, resulting in a better financial balance of the project, saving a considerable amount of lift-gas. The methodology adopted to optimize the injected gas lift rate and consequently increase/maintain cumulative oil production proved adequate for application in oil fields that are highly dependent on artificial lift methods. Therefore, exploration and production projects can be financial healthier.
{"title":"Optimization Methodology of Artificial Lift Rates for Brazilian Offshore Field","authors":"Matheus de Freitas Bezerra, Guilherme Cosme Viganô, J. L. Giuriatto","doi":"10.4043/29889-ms","DOIUrl":"https://doi.org/10.4043/29889-ms","url":null,"abstract":"\u0000 Nowadays gas-lift is still a very expressive artificial lift method, for instance considering the whole Brazilian oil production profiles, gas lifted wells are responsible for 30% of monthly production. Due this huge importance, the injection efficiency should be ensured to avoid lid gas losses and maximize the production. Then, this study had as objective to develop a Gas Lift Optimization workflow and define the optimum lift rates to increase the reservoir recovery and improve gas usability due to platform constraints of a Brazilian deep-water field. That workflow comprises a reservoir and flow assurance simulators, achieving more accurate responses compared to regular workflows. Taking advantages of the proposed method, multidisciplinary teams could work together which increases the representativeness of such studies providing important outcomes for decision makers. At this study, due to a gas-lift optimization was observed an increase of 0.5% at cumulative production with a huge gas-lift reduction of around 40%, resulting in a better financial balance of the project, saving a considerable amount of lift-gas. The methodology adopted to optimize the injected gas lift rate and consequently increase/maintain cumulative oil production proved adequate for application in oil fields that are highly dependent on artificial lift methods. Therefore, exploration and production projects can be financial healthier.","PeriodicalId":11089,"journal":{"name":"Day 2 Wed, October 30, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-10-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83820140","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}
D. Obando, F. Fornasier, Ary J. Junior, H. Matos, R. Andrade
In the Peregrino field, located in the Campos Basin offshore Brazil, the operator adopted the use of water-based drilling fluids for drilling development wells due to rig limitations. In the 12 ¼-in. sections of several wells drilled in this field, high dispersion of shale minerals suffered by the drilling fluid caused increments of viscosity, which subsequently affected the drilling process through higher-than-expected circulation pressures, dilution rates, and costs. Although the wells have been drilled within the estimated times and budgets, an improvement in the fluid inhibition capability was initiated. A detailed laboratory effort was conducted to obtain a combination of inhibitors capable of controlling excessive clay dispersion, minimizing fluid rock interaction, and reducing dilution requirements while helping to ensure an adequate rheological profile throughout the interval. Laboratory validation of the interaction between the fluid and rock samples provided a better understanding of the inhibition mechanisms and helped ensure that stability of the reactive minerals drilled could be maintained. Various additives were tested against samples of commercial-reactive and field-reactive clays. Product concentrations were adjusted to reduce the interaction between the drilling fluid and the formation while helping to ensure that fluid capabilities, such as cuttings suspension, filtration control, and bridging, were maintained. An adequate environmental profile to enable safe disposal of fluid in compliance with local environmental regulations was also obtained. After identifying an adequate solution, a detailed utilization plan was developed and put in place. To aid proper deployment while drilling, specific mixing procedures at the support liquid mud plant, transportation vessels, and at the rig site were determined. The next step was to assign a candidate well for the application – an Extended Reach Well (ERW) with step-out ratio of 2.9. While drilling the 12-¼-in. section of the pilot well with the proposed fluid technology, a significant improvement was observed on cuttings integrity, which led to a reduction in the required volume of dilution and a subsequent drilling fluids cost reduction Also, better hole quality and reduced operational risks were obtained. The well was safely drilled with a 76° sail inclination, 7938 meters of Measured Depth (MD) and 2368 meters of True Vertical Depth (TVD), and lessons learned from the first utilization of the described fluid system were implemented on subsequent wells to continue obtaining the benefits of the new fluid formulation. High Performance Water Based Drilling Fluids (HPWBDF) are not new and are thought by most to be a mature technology. However, advancements in water-based drilling fluid additives have enabled these systems to mimic the performance of non-aqueous systems more closely. This paper discusses how understanding the chemistry of the formations to be drilled and customizing
{"title":"Customized High-Performance Water-Based Drilling Fluid Helps Improve Drilling Efficiency in Extended-Reach Wells on the Peregrino Field","authors":"D. Obando, F. Fornasier, Ary J. Junior, H. Matos, R. Andrade","doi":"10.4043/29738-ms","DOIUrl":"https://doi.org/10.4043/29738-ms","url":null,"abstract":"\u0000 In the Peregrino field, located in the Campos Basin offshore Brazil, the operator adopted the use of water-based drilling fluids for drilling development wells due to rig limitations. In the 12 ¼-in. sections of several wells drilled in this field, high dispersion of shale minerals suffered by the drilling fluid caused increments of viscosity, which subsequently affected the drilling process through higher-than-expected circulation pressures, dilution rates, and costs. Although the wells have been drilled within the estimated times and budgets, an improvement in the fluid inhibition capability was initiated.\u0000 A detailed laboratory effort was conducted to obtain a combination of inhibitors capable of controlling excessive clay dispersion, minimizing fluid rock interaction, and reducing dilution requirements while helping to ensure an adequate rheological profile throughout the interval.\u0000 Laboratory validation of the interaction between the fluid and rock samples provided a better understanding of the inhibition mechanisms and helped ensure that stability of the reactive minerals drilled could be maintained. Various additives were tested against samples of commercial-reactive and field-reactive clays. Product concentrations were adjusted to reduce the interaction between the drilling fluid and the formation while helping to ensure that fluid capabilities, such as cuttings suspension, filtration control, and bridging, were maintained. An adequate environmental profile to enable safe disposal of fluid in compliance with local environmental regulations was also obtained.\u0000 After identifying an adequate solution, a detailed utilization plan was developed and put in place. To aid proper deployment while drilling, specific mixing procedures at the support liquid mud plant, transportation vessels, and at the rig site were determined. The next step was to assign a candidate well for the application – an Extended Reach Well (ERW) with step-out ratio of 2.9. While drilling the 12-¼-in. section of the pilot well with the proposed fluid technology, a significant improvement was observed on cuttings integrity, which led to a reduction in the required volume of dilution and a subsequent drilling fluids cost reduction Also, better hole quality and reduced operational risks were obtained. The well was safely drilled with a 76° sail inclination, 7938 meters of Measured Depth (MD) and 2368 meters of True Vertical Depth (TVD), and lessons learned from the first utilization of the described fluid system were implemented on subsequent wells to continue obtaining the benefits of the new fluid formulation.\u0000 High Performance Water Based Drilling Fluids (HPWBDF) are not new and are thought by most to be a mature technology. However, advancements in water-based drilling fluid additives have enabled these systems to mimic the performance of non-aqueous systems more closely. This paper discusses how understanding the chemistry of the formations to be drilled and customizing ","PeriodicalId":11089,"journal":{"name":"Day 2 Wed, October 30, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-10-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"75585304","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
K. Havard, B. Durairajan, S. Stith, S. Goyal, Philipp Trunk, M. Nagaraj, Dexter Trahan, Guillaume Descamps, M. Dykstra, Leonardo Louback, Marcus Norvell, C. Pinard, Youdan Zhang, Rob Rabei, M. Halpin
This case study highlights the challenge of identifying the root cause of bit failures and provides an iterative design solution for maximizing drilling performance on a deepwater Gulf of Mexico (GoM) field development project. The well design and project economics required drilling through two distinct lithologies: salt followed by subsalt sediments consisting of plastic shale, abrasive sands, and marl. The operator wanted to drill through these in the same interval, in one run, while simultaneously achieving high rates of penetration (ROP) and maintaining durability for the entire interval. Offset wells from previous operations in the area provided an initial starting point for the design, despite being quite different from the new well plan. A new drill bit and reamer combination were developed and built for the first well. In addition, the bottomhole assembly (BHA) design was optimized and detailed drilling parameter roadmaps were provided for the field crew. When the first run resulted in a premature bit failure, an in-depth post-run analysis was completed. A rapid response root-cause analysis was conducted, which resulted in a new bit design and expedited manufacturing to deliver the new bit within the tight timeline between consecutive wells. Historical data from the Exploration &Appraisal (E&A) wells in the field indicated coring as the prevalent form of bit failure in the subsalt interval and loosely correlated with drilling of a middle Miocene sandstone. However, the wide range of bit vendors, bit sizes, and dull conditions in the data created uncertainty on root cause of failure. Although a good ROP was achieved in the salt section on the first field development well, the bit suffered premature wear in the subsalt interval, resulting in two additional trips to drill the interval. Each worn bit was thoroughly analyzed in conjunction with the drilling parameters and mud logging data from each bit run. Against the previous assumption of coring being a result of drilling abrasive sandstones, it was now determined that the failure mechanism was most likely a result of drilling shales with high bottomhole pressure causing plastic behavior, regrinding of cuttings at the bit face, and insufficient cuttings evacuation. An entirely new bit design was generated to prevent this failure mode and manufactured in time for the next well. The new bit design combined with revised drilling parameters strategy resulted in the most successful run ever in the field: 10,854 ft drilled (7,000 ft of reaming) in one run at high ROP in the salt followed by good ROP and excellent durability in subsalt formations.
{"title":"Collaborative Bit and Reamer Design Solution for Performance Drilling in Salt and High Durability in Challenging Subsalt Interval in One Run, Deepwater Gulf of Mexico","authors":"K. Havard, B. Durairajan, S. Stith, S. Goyal, Philipp Trunk, M. Nagaraj, Dexter Trahan, Guillaume Descamps, M. Dykstra, Leonardo Louback, Marcus Norvell, C. Pinard, Youdan Zhang, Rob Rabei, M. Halpin","doi":"10.4043/29783-ms","DOIUrl":"https://doi.org/10.4043/29783-ms","url":null,"abstract":"\u0000 This case study highlights the challenge of identifying the root cause of bit failures and provides an iterative design solution for maximizing drilling performance on a deepwater Gulf of Mexico (GoM) field development project. The well design and project economics required drilling through two distinct lithologies: salt followed by subsalt sediments consisting of plastic shale, abrasive sands, and marl. The operator wanted to drill through these in the same interval, in one run, while simultaneously achieving high rates of penetration (ROP) and maintaining durability for the entire interval.\u0000 Offset wells from previous operations in the area provided an initial starting point for the design, despite being quite different from the new well plan. A new drill bit and reamer combination were developed and built for the first well. In addition, the bottomhole assembly (BHA) design was optimized and detailed drilling parameter roadmaps were provided for the field crew. When the first run resulted in a premature bit failure, an in-depth post-run analysis was completed. A rapid response root-cause analysis was conducted, which resulted in a new bit design and expedited manufacturing to deliver the new bit within the tight timeline between consecutive wells.\u0000 Historical data from the Exploration &Appraisal (E&A) wells in the field indicated coring as the prevalent form of bit failure in the subsalt interval and loosely correlated with drilling of a middle Miocene sandstone. However, the wide range of bit vendors, bit sizes, and dull conditions in the data created uncertainty on root cause of failure. Although a good ROP was achieved in the salt section on the first field development well, the bit suffered premature wear in the subsalt interval, resulting in two additional trips to drill the interval. Each worn bit was thoroughly analyzed in conjunction with the drilling parameters and mud logging data from each bit run. Against the previous assumption of coring being a result of drilling abrasive sandstones, it was now determined that the failure mechanism was most likely a result of drilling shales with high bottomhole pressure causing plastic behavior, regrinding of cuttings at the bit face, and insufficient cuttings evacuation. An entirely new bit design was generated to prevent this failure mode and manufactured in time for the next well. The new bit design combined with revised drilling parameters strategy resulted in the most successful run ever in the field: 10,854 ft drilled (7,000 ft of reaming) in one run at high ROP in the salt followed by good ROP and excellent durability in subsalt formations.","PeriodicalId":11089,"journal":{"name":"Day 2 Wed, October 30, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-10-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"76123312","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
K. Beltrán-Jiménez, H. Lohne, E. Ford, H. J. Skadsem, M. Souza, Øystein Arild
In South America, the discussion regarding permanent plug and abandonment (P&A) at the end of the useful life of the fields is relatively recent, but it has become increasingly important due to the maturity of certain oil fields. In Brazil, for example, the Campos, Santos and Espirito Santos Basins alone have 350 temporarily abandoned wells that should be abandoned in the coming decade. The long-term integrity of the wells once plugged and abandoned is, however, not yet considered. There is a need to perform assessments of the risk of leakage, reviewing both the probability of failure of the well barrier elements and the possible magnitude of leakage rates should one or more well barriers be compromised. This article presents a quantitative risk assessment framework that can be used to analyze the probability of barrier failure and potential consequences in terms of leakage rates. Data of a real well is used to quantify the leakage rates after a hypothetic permanent plug and abandonment operation using as reference the plug and abandonment requirements in Brazil and Norway. For both cases, the leakage paths between the reservoir and the wellhead are studied and include: the leakage through bulk cement, cracks/fractures in well barriers elements (impermeable formations, plug, and annular cement) and the presence of micro-annuli. A stochastic framework, using Monte Carlo simulations, is used to propagate uncertainty, yielding probability distributions for leakage rates. As the leakage rates are also a function of time, an analysis considering time-dependent factors such as reservoir re-pressurization is also included. The leakage scenarios for the well is presented considering the P&A requirements included in resolution N 46 (issued by the National Agency of Petroleum, Natural Gas and Biofuels (ANP) in 2016), the guidelines for the abandonment of the Brazilian Petroleum Gas and Biofuels Institute (IBP) and NORSOK D-010. Some requirements, such as plug length and barrier verification methods, are different between these two guidelines. The results are discussed in relation to the P & A requirements and the effect on the total leakage rates for each well case.
{"title":"Comparative Analysis of Permanent P & A Requirements and Consequences in Terms of Leakage - A Case Study","authors":"K. Beltrán-Jiménez, H. Lohne, E. Ford, H. J. Skadsem, M. Souza, Øystein Arild","doi":"10.4043/29814-ms","DOIUrl":"https://doi.org/10.4043/29814-ms","url":null,"abstract":"\u0000 In South America, the discussion regarding permanent plug and abandonment (P&A) at the end of the useful life of the fields is relatively recent, but it has become increasingly important due to the maturity of certain oil fields. In Brazil, for example, the Campos, Santos and Espirito Santos Basins alone have 350 temporarily abandoned wells that should be abandoned in the coming decade. The long-term integrity of the wells once plugged and abandoned is, however, not yet considered. There is a need to perform assessments of the risk of leakage, reviewing both the probability of failure of the well barrier elements and the possible magnitude of leakage rates should one or more well barriers be compromised. This article presents a quantitative risk assessment framework that can be used to analyze the probability of barrier failure and potential consequences in terms of leakage rates. Data of a real well is used to quantify the leakage rates after a hypothetic permanent plug and abandonment operation using as reference the plug and abandonment requirements in Brazil and Norway. For both cases, the leakage paths between the reservoir and the wellhead are studied and include: the leakage through bulk cement, cracks/fractures in well barriers elements (impermeable formations, plug, and annular cement) and the presence of micro-annuli. A stochastic framework, using Monte Carlo simulations, is used to propagate uncertainty, yielding probability distributions for leakage rates. As the leakage rates are also a function of time, an analysis considering time-dependent factors such as reservoir re-pressurization is also included. The leakage scenarios for the well is presented considering the P&A requirements included in resolution N 46 (issued by the National Agency of Petroleum, Natural Gas and Biofuels (ANP) in 2016), the guidelines for the abandonment of the Brazilian Petroleum Gas and Biofuels Institute (IBP) and NORSOK D-010. Some requirements, such as plug length and barrier verification methods, are different between these two guidelines. The results are discussed in relation to the P & A requirements and the effect on the total leakage rates for each well case.","PeriodicalId":11089,"journal":{"name":"Day 2 Wed, October 30, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-10-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"75444783","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}
Gabriel Rodrigues Cabral, Helvio Ferreira da Silva, R. Bressan
When performing any redevelopment or complementary project assessment, there are usually common characteristics that an operator could face, for instance reuse of existing assets, marginal fields, etc. However, due to project development strategies in Petrobras and Brazilian regulation and scenarios, there are some specific additional challenges, such as environmental constraints. This paper aims to present actual case studies from Brazilian fields, highlighting some challenges, opportunities and keys to success with associated results, that ensured projects technical and economic feasibility. By the end of this paper, one should realize that challenges and opportunities faced in Brazilian mature fields' subsea design are often similar from a broad perspective; hence, the keys to success can also be reproduced from scenario to scenario, with few specific adaptations, case by case. Such conclusion allows a portfolio approach, anticipating challenges and, thus, motivating the development of desirable novel solutions, such as new technologies and methods of methods. This will lead to saving costs and reduction of risk and time of deployment.
{"title":"Case Studies: Opportunities and Challenges in Brazilian Mature Fields' Subsea Conceptual Design","authors":"Gabriel Rodrigues Cabral, Helvio Ferreira da Silva, R. Bressan","doi":"10.4043/29748-ms","DOIUrl":"https://doi.org/10.4043/29748-ms","url":null,"abstract":"\u0000 When performing any redevelopment or complementary project assessment, there are usually common characteristics that an operator could face, for instance reuse of existing assets, marginal fields, etc. However, due to project development strategies in Petrobras and Brazilian regulation and scenarios, there are some specific additional challenges, such as environmental constraints. This paper aims to present actual case studies from Brazilian fields, highlighting some challenges, opportunities and keys to success with associated results, that ensured projects technical and economic feasibility. By the end of this paper, one should realize that challenges and opportunities faced in Brazilian mature fields' subsea design are often similar from a broad perspective; hence, the keys to success can also be reproduced from scenario to scenario, with few specific adaptations, case by case. Such conclusion allows a portfolio approach, anticipating challenges and, thus, motivating the development of desirable novel solutions, such as new technologies and methods of methods. This will lead to saving costs and reduction of risk and time of deployment.","PeriodicalId":11089,"journal":{"name":"Day 2 Wed, October 30, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-10-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"81812403","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}
Petrobras, as the largest operator in ultra-deep waters in South America, has been using a field development concept that has proved to be winner since 2010. This concept is well suited for fields with high productivity wells, which produce more than 20,000 barrels of oil per day. In the market, this concept is known as "satellite wells". In this scenario, Petrobras has benefited from its strategy of standardizing subsea equipment, including Wet Christmas Trees (WCT), Flexible Pipes, Umbilicals and Subsea Manifolds. However, since the downturn of 2014, Petrobras has been struggling to simplify its own specifications, looking for the most attractive CAPEX solutions in the market, allowing suppliers to use their own knowledge and experiences to propose low cost solutions, meeting projects requirements. From 2015 onwards, Petrobras has been working with the suppliers, with the Early Engagement initiative, aiming that the integration synergies, existing assets and the experience of these suppliers, could bring to the projects, the benefits of CAPEX reduction, and allowing the advancement and approval of these projects internally in the company. Technological development programs to allow the use of flexible pipes that are resistant to contaminants such as CO2 and H2S, new CRA materials to be applied to rigid flowlines and low-cost riser configurations, have been pursued by Petrobras in order to enable the implementation of ultra-deep water projects.
{"title":"Efforts and Experiences, Developing Deepwater Projects in Brazil","authors":"Ricardo Melo Toneto de, M ClaudioValençaJG","doi":"10.4043/29871-ms","DOIUrl":"https://doi.org/10.4043/29871-ms","url":null,"abstract":"\u0000 Petrobras, as the largest operator in ultra-deep waters in South America, has been using a field development concept that has proved to be winner since 2010. This concept is well suited for fields with high productivity wells, which produce more than 20,000 barrels of oil per day. In the market, this concept is known as \"satellite wells\".\u0000 In this scenario, Petrobras has benefited from its strategy of standardizing subsea equipment, including Wet Christmas Trees (WCT), Flexible Pipes, Umbilicals and Subsea Manifolds. However, since the downturn of 2014, Petrobras has been struggling to simplify its own specifications, looking for the most attractive CAPEX solutions in the market, allowing suppliers to use their own knowledge and experiences to propose low cost solutions, meeting projects requirements.\u0000 From 2015 onwards, Petrobras has been working with the suppliers, with the Early Engagement initiative, aiming that the integration synergies, existing assets and the experience of these suppliers, could bring to the projects, the benefits of CAPEX reduction, and allowing the advancement and approval of these projects internally in the company.\u0000 Technological development programs to allow the use of flexible pipes that are resistant to contaminants such as CO2 and H2S, new CRA materials to be applied to rigid flowlines and low-cost riser configurations, have been pursued by Petrobras in order to enable the implementation of ultra-deep water projects.","PeriodicalId":11089,"journal":{"name":"Day 2 Wed, October 30, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-10-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77692485","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
K. Ren, M. J. R. Oliveira, Junfeng Zhao, Jian Zhao, Leonardo Costa de Oliveira, Cristiano Camelo Rancan, I. O. Carmo, Qicai Deng
A methodology to confirm the direct contact metamorphism of intrusive rocks and related hydrothermal modification on presalt limestone reservoirs, in Libra Block of Santos Basin, is presented. The approach is based on systemic study of cores, sidewall cores, traditional wireline logging, ECS and NMR of boreholes. Type and characteristics of metamorphism in contact aureoles between intrusive bodies and limestones are confirmed. NMR was used to evaluate porosity change of limestone. Thin sections and ECS were used to identify the precipitant types and to confirm the modification of hydrothermal fluids influences on surrounding limestones. Intrusive rocks are observed in several wells of presalt layers in Libra Block and show contact metamorphic aureoles in the surrounding limestones, characterized by a significant change on the limestone mineral size, rock color, and reservoir pore after marbleization. By combining conventional logging and NMR logging, the thicknesses of contact metamorphic aureoles are determined in multiple wells. They conform to a binomial regression relation with the thicknesses intrusive bodies. The NMR data reveals that igneous contact metamorphism exerts negative influence on pores development for carbonate reservoirs. Reservoir physical properties decrease sharply after thermal baking, generally by 4 to 8 times. The study also confirms that related hydrothermal fluids pervasively develop and have multi-types of influences on limestones, mainly due to silicification, dolomitization and calcification. They mainly brought minerals precipitation in fractures and pores that made limestone reservoir tight. In Libra presalt layers, hydrothermal modification related to intrusive bodies mainly developed at the middle-upper intervals of BVE Fm. Combined with wells correlation sections and seismic data, a state-of-the-art model of igneous contact metamorphism and hydrothermal modification on limestone reservoirs has been developed in this paper. It can help to quantitatively predict the thickness of contact metamorphism aureole around intrusive rocks. The study also clarifies the understanding of the type of hydrothermal effects on the reservoir porosity and how to map the spatial distribution of hydrothermal deposition in the reservoir.
{"title":"Using Wireline Logging and Thin Sections to Identify Igneous Contact Metamorphism and Hydrothermal Influence on Presalt Limestone Reservoirs in Libra Block, Santos Basin","authors":"K. Ren, M. J. R. Oliveira, Junfeng Zhao, Jian Zhao, Leonardo Costa de Oliveira, Cristiano Camelo Rancan, I. O. Carmo, Qicai Deng","doi":"10.4043/29818-ms","DOIUrl":"https://doi.org/10.4043/29818-ms","url":null,"abstract":"\u0000 A methodology to confirm the direct contact metamorphism of intrusive rocks and related hydrothermal modification on presalt limestone reservoirs, in Libra Block of Santos Basin, is presented. The approach is based on systemic study of cores, sidewall cores, traditional wireline logging, ECS and NMR of boreholes. Type and characteristics of metamorphism in contact aureoles between intrusive bodies and limestones are confirmed. NMR was used to evaluate porosity change of limestone. Thin sections and ECS were used to identify the precipitant types and to confirm the modification of hydrothermal fluids influences on surrounding limestones.\u0000 Intrusive rocks are observed in several wells of presalt layers in Libra Block and show contact metamorphic aureoles in the surrounding limestones, characterized by a significant change on the limestone mineral size, rock color, and reservoir pore after marbleization. By combining conventional logging and NMR logging, the thicknesses of contact metamorphic aureoles are determined in multiple wells. They conform to a binomial regression relation with the thicknesses intrusive bodies. The NMR data reveals that igneous contact metamorphism exerts negative influence on pores development for carbonate reservoirs. Reservoir physical properties decrease sharply after thermal baking, generally by 4 to 8 times. The study also confirms that related hydrothermal fluids pervasively develop and have multi-types of influences on limestones, mainly due to silicification, dolomitization and calcification. They mainly brought minerals precipitation in fractures and pores that made limestone reservoir tight. In Libra presalt layers, hydrothermal modification related to intrusive bodies mainly developed at the middle-upper intervals of BVE Fm.\u0000 Combined with wells correlation sections and seismic data, a state-of-the-art model of igneous contact metamorphism and hydrothermal modification on limestone reservoirs has been developed in this paper. It can help to quantitatively predict the thickness of contact metamorphism aureole around intrusive rocks. The study also clarifies the understanding of the type of hydrothermal effects on the reservoir porosity and how to map the spatial distribution of hydrothermal deposition in the reservoir.","PeriodicalId":11089,"journal":{"name":"Day 2 Wed, October 30, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-10-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84853078","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. J. R. Oliveira, V. Savastano, G. Matos, R. Schmitt, Valente Castro Valente, M. Araujo, Leonardo Campos Inocencio
Igneous (or magmatic) rocks may be critical elements in the petroleum systems. They may be related with generation, migration and trapping of oil and gas and also generate hydrothermal processes that can affect the reservoirs. In Campos and Santos basins, they occur as volcanic and intrusive bodies, affecting the pre-, intra- and post-salt sequences. Associated with fractures and faults, igneous intrusives were emplaced during reactivation of preexisting discontinuities or weakness zones, although they also cross cut them. In the continental area, adjacent to the Campos and Santos basins, intrusive igneous bodies crop out as dykes, sills and stocks. The area selected for this study is the "Pontal do Atalaia", in the city of Arraial do Cabo (RJ). The use of drone images allowed to identify the structural framework of the igneous bodies and fractures patterns associated with them. By developing tools of deep learning, it was possible to analyze the fractures and compare the results with visual interpretation. In both cases, the results indicate the predominance of fractures along roughly N-S and E-W trends. The outcomes allow the comparison and correlation to the offshore geological features to better understand the role of the igneous rocks and fractures in the tectonic evolution of Campos and Santos basins.
火成岩(或岩浆岩)可能是含油气系统的关键元素。它们可能与油气的生成、运移和圈闭有关，也可能产生影响储层的热液作用。在Campos和Santos盆地，它们以火山岩和侵入体的形式赋存，影响着盐前、盐内和盐后的层序。与裂缝和断层相关，火成岩侵入体是在先前存在的不连续或薄弱带的重新激活过程中侵入的，尽管它们也穿过它们。在毗邻坎波斯盆地和桑托斯盆地的大陆地区，侵入火成岩以岩脉、岩基和岩堆的形式出现。本研究选择的区域是位于Arraial do Cabo (RJ)市的“Pontal do Atalaia”。无人机图像的使用可以识别火成岩的结构框架和与之相关的裂缝模式。通过开发深度学习工具，可以分析骨折，并将结果与视觉解释进行比较。在这两种情况下，结果表明裂缝主要沿北向南和东西向分布。研究结果可以与海上地质特征进行对比对比，更好地了解火成岩和裂缝在Campos和Santos盆地构造演化中的作用。
{"title":"The Use of Drones and Deep Learning to Identify Igneous Rocks and Fractures","authors":"M. J. R. Oliveira, V. Savastano, G. Matos, R. Schmitt, Valente Castro Valente, M. Araujo, Leonardo Campos Inocencio","doi":"10.4043/29829-ms","DOIUrl":"https://doi.org/10.4043/29829-ms","url":null,"abstract":"\u0000 Igneous (or magmatic) rocks may be critical elements in the petroleum systems. They may be related with generation, migration and trapping of oil and gas and also generate hydrothermal processes that can affect the reservoirs. In Campos and Santos basins, they occur as volcanic and intrusive bodies, affecting the pre-, intra- and post-salt sequences. Associated with fractures and faults, igneous intrusives were emplaced during reactivation of preexisting discontinuities or weakness zones, although they also cross cut them. In the continental area, adjacent to the Campos and Santos basins, intrusive igneous bodies crop out as dykes, sills and stocks. The area selected for this study is the \"Pontal do Atalaia\", in the city of Arraial do Cabo (RJ). The use of drone images allowed to identify the structural framework of the igneous bodies and fractures patterns associated with them. By developing tools of deep learning, it was possible to analyze the fractures and compare the results with visual interpretation. In both cases, the results indicate the predominance of fractures along roughly N-S and E-W trends. The outcomes allow the comparison and correlation to the offshore geological features to better understand the role of the igneous rocks and fractures in the tectonic evolution of Campos and Santos basins.","PeriodicalId":11089,"journal":{"name":"Day 2 Wed, October 30, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-10-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"80295521","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}
F. Sajjad, Khairullah Sastradinata, S. D. Rahmawati, A. Mansur, A. Wirawan, Ecep Mujib
Common problem for dual string completion gas lift well is a misallocation problem called as a gas lift robbing, where the gas tends to be injected uncontrollably to one of the tubings. Consequently, both oil production of the strings drops since the injected gas does not meet the optimum allocation. To solve this, engineers need to shut in one of the strings using wireline which is time-consuming and uneconomic. Therefore, the objective of this paper is to introduce the modification of dual string gas lift design that can economically prevent gas lift robbing problem in the well during the production time. This finding occurred in Indonesia, Offshore North West Java field, where the orifice is preferably used as the operating valve. However, Production Pressure Operating (PPO) valve is then used to replace the orifice function to overcome the problem. The methodology starts with well selection based on the possibility to perform the new design. Then, the static bottom-hole pressure test applied in each zone to obtain an appropriate pressure. Lastly, PPO valve’s Pressure Test Rack Opening (PTRO) will be designed based on the measured bottom-hole pressure to be applied to one of the selected string to prevent the gas lift robbing. The force balance is then calculated, and the PPO valve is set to the short string with the Pressure Test Rack Opening (PTRO) 585 psig at 80°F. The oil production in the robbing well observed to increase by 45% and achieved a sustainable production after replacing its orifice with the PPO valve. Also, The PPO valve will prevent the gas robs to the selected string as it will close automatically when its tubing pressure drops bellow PTRO. Hence, the wireline activity is now unnecessary because the PPO valve will be closed automatically when the gas lift robbing occurs again. The use of PPO valve is commonly suitable as an unloader in low availability of Casing Head Pressure (CHP) and high reservoir pressure. By this study, PPO valve has been successfully replaced orifice function with high CHP and low reservoir pressure to prevent the gas lift robbing problem effectively in Offshore North West Java field.
{"title":"Gas Lift Robbing Prevention in Dual String Completion using Production Pressure Operating Valve","authors":"F. Sajjad, Khairullah Sastradinata, S. D. Rahmawati, A. Mansur, A. Wirawan, Ecep Mujib","doi":"10.2118/192474-MS","DOIUrl":"https://doi.org/10.2118/192474-MS","url":null,"abstract":"\u0000 Common problem for dual string completion gas lift well is a misallocation problem called as a gas lift robbing, where the gas tends to be injected uncontrollably to one of the tubings. Consequently, both oil production of the strings drops since the injected gas does not meet the optimum allocation. To solve this, engineers need to shut in one of the strings using wireline which is time-consuming and uneconomic. Therefore, the objective of this paper is to introduce the modification of dual string gas lift design that can economically prevent gas lift robbing problem in the well during the production time.\u0000 This finding occurred in Indonesia, Offshore North West Java field, where the orifice is preferably used as the operating valve. However, Production Pressure Operating (PPO) valve is then used to replace the orifice function to overcome the problem. The methodology starts with well selection based on the possibility to perform the new design. Then, the static bottom-hole pressure test applied in each zone to obtain an appropriate pressure. Lastly, PPO valve’s Pressure Test Rack Opening (PTRO) will be designed based on the measured bottom-hole pressure to be applied to one of the selected string to prevent the gas lift robbing.\u0000 The force balance is then calculated, and the PPO valve is set to the short string with the Pressure Test Rack Opening (PTRO) 585 psig at 80°F. The oil production in the robbing well observed to increase by 45% and achieved a sustainable production after replacing its orifice with the PPO valve. Also, The PPO valve will prevent the gas robs to the selected string as it will close automatically when its tubing pressure drops bellow PTRO. Hence, the wireline activity is now unnecessary because the PPO valve will be closed automatically when the gas lift robbing occurs again.\u0000 The use of PPO valve is commonly suitable as an unloader in low availability of Casing Head Pressure (CHP) and high reservoir pressure. By this study, PPO valve has been successfully replaced orifice function with high CHP and low reservoir pressure to prevent the gas lift robbing problem effectively in Offshore North West Java field.","PeriodicalId":11089,"journal":{"name":"Day 2 Wed, October 30, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-10-25","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90925445","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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