Currently, low oil prices pose a challenge to the financial state of the industry. Therefore, it is very important that companies optimize costs while maintaining or even increasing oil production. At the same time, with oil production declining due high water cuts and facility volume limitations in an offshore production system, it is necessary to look for solutions in order to maintain economic viability by increasing oil recovery in mature reservoirs. Among some alternatives, the subsea separator represents a good prospect for dealing with these challenges. This paper aims to describe a methodology to perform the technical feasibility study of deploying an Oil/Water Subsea Separator in Brazilian Offshore Field. The technical results were then used as part of an economic analysis which is outside the scope of the present paper. The study is comprised four wells that are linked to the manifold and the subsea separator. In the subsea separator, 70% of the produced water is separated and reinjected in a disposal well. Hence, the fluids which remains (oil, gas and 30% of water) flows up to the platform. Since this reinjected water volume is not flowing to the platform anymore, more fluid can be processed, allowing the wells to operate on larger potentials resulting in an increased cumulative oil production to the field. Computational simulation approach was followed by using the pore flow simulation, flow assurance simulation and a coupler that integrates both of these.
{"title":"Methodology to a Feasibility Study to Implement an Oil/Water Subsea Separation","authors":"Guilherme Cosme Viganô","doi":"10.4043/29895-ms","DOIUrl":"https://doi.org/10.4043/29895-ms","url":null,"abstract":"\u0000 Currently, low oil prices pose a challenge to the financial state of the industry. Therefore, it is very important that companies optimize costs while maintaining or even increasing oil production. At the same time, with oil production declining due high water cuts and facility volume limitations in an offshore production system, it is necessary to look for solutions in order to maintain economic viability by increasing oil recovery in mature reservoirs. Among some alternatives, the subsea separator represents a good prospect for dealing with these challenges.\u0000 This paper aims to describe a methodology to perform the technical feasibility study of deploying an Oil/Water Subsea Separator in Brazilian Offshore Field. The technical results were then used as part of an economic analysis which is outside the scope of the present paper.\u0000 The study is comprised four wells that are linked to the manifold and the subsea separator. In the subsea separator, 70% of the produced water is separated and reinjected in a disposal well. Hence, the fluids which remains (oil, gas and 30% of water) flows up to the platform. Since this reinjected water volume is not flowing to the platform anymore, more fluid can be processed, allowing the wells to operate on larger potentials resulting in an increased cumulative oil production to the field. Computational simulation approach was followed by using the pore flow simulation, flow assurance simulation and a coupler that integrates both of these.","PeriodicalId":11089,"journal":{"name":"Day 2 Wed, October 30, 2019","volume":"1 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-10-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89296465","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}
We introduce a new digital rocks-based method for interpreting NMR T2 distributions in well log data acquired in vuggy deep-water carbonate reservoirs. Our method accounts for adverse borehole conditions such as mud invasion and large washouts in vuggy zones, usually neglected in conventional interpretation procedures of NMR logs. The new approach is based on describing the measured distribution of transverse relaxation times as the superposition of a finite set of log-normal components. Each component accounts for specific relaxation rates for drilling mud and original formation fluids. We carefully design our NMR interpretation model after processing whole core X-ray computed tomography (CT) images acquired in whole core samples. Estimation of density and atomic number from dual-energy CT data enabled to directly probe fluid content in the vuggy space, while image segmentation targeting the vuggy space allowed to estimate vuggy porosity and flow properties inside the vug network. Our model was able to explain correlated anomalies shown by caliper, photoelectric, and NMR T2 logarithmic mean logs for the vuggy regions in the dataset studied. The decomposition of inverted NMR T2 distributions in a set of basis functions naturally handles the uncertainty related to inversion parameters, making the task of calculating fluid concentrations and permeability indices more robust with respect to small variations in cutoff values. Permeabilities in vuggy zones estimated from NMR logs using this new method are more accurate than those rendered by conventional techniques based on T2 cutoffs or logarithmic averages, without the need to artificially introduce new fitting parameters. Using this approach, we can also explicitly quantify vuggy porosity, which is in good agreement with values obtained from segmented whole core tomographic images for this particular dataset. The combined use of the above interpretation methods confirms the value of digital rock techniques to improve the evaluation of well logs acquired in complex carbonate formations, specifically in the calculation of permeability across vuggy depth segments. Results can be used to improve well log interpretation in wells devoid of core data and/or high-resolution borehole images.
{"title":"Improved Digital Rocks-Based Model for NMR Permeability Estimation in Vuggy Deepwater Carbonates","authors":"R. Victor, C. Torres‐Verdín, M. Prodanović","doi":"10.4043/29731-ms","DOIUrl":"https://doi.org/10.4043/29731-ms","url":null,"abstract":"\u0000 We introduce a new digital rocks-based method for interpreting NMR T2 distributions in well log data acquired in vuggy deep-water carbonate reservoirs. Our method accounts for adverse borehole conditions such as mud invasion and large washouts in vuggy zones, usually neglected in conventional interpretation procedures of NMR logs.\u0000 The new approach is based on describing the measured distribution of transverse relaxation times as the superposition of a finite set of log-normal components. Each component accounts for specific relaxation rates for drilling mud and original formation fluids. We carefully design our NMR interpretation model after processing whole core X-ray computed tomography (CT) images acquired in whole core samples. Estimation of density and atomic number from dual-energy CT data enabled to directly probe fluid content in the vuggy space, while image segmentation targeting the vuggy space allowed to estimate vuggy porosity and flow properties inside the vug network.\u0000 Our model was able to explain correlated anomalies shown by caliper, photoelectric, and NMR T2 logarithmic mean logs for the vuggy regions in the dataset studied. The decomposition of inverted NMR T2 distributions in a set of basis functions naturally handles the uncertainty related to inversion parameters, making the task of calculating fluid concentrations and permeability indices more robust with respect to small variations in cutoff values. Permeabilities in vuggy zones estimated from NMR logs using this new method are more accurate than those rendered by conventional techniques based on T2 cutoffs or logarithmic averages, without the need to artificially introduce new fitting parameters. Using this approach, we can also explicitly quantify vuggy porosity, which is in good agreement with values obtained from segmented whole core tomographic images for this particular dataset.\u0000 The combined use of the above interpretation methods confirms the value of digital rock techniques to improve the evaluation of well logs acquired in complex carbonate formations, specifically in the calculation of permeability across vuggy depth segments. Results can be used to improve well log interpretation in wells devoid of core data and/or high-resolution borehole images.","PeriodicalId":11089,"journal":{"name":"Day 2 Wed, October 30, 2019","volume":"18 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-10-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"75232929","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
R. B. Vadinal, Stephan R. Perrout, Rodrigo De Campos Chuvas, Adriano Gouveia Lima Gomes dos Passos, Leonardo Pacheco da Silva
This work presents the lessons learned from the studies carried out to understand the non-fulfillment of the hydraulic isolation required during the liner 10 ¾" cement job. Analyzing the drilling parameters performed and the events of cementing, it is possible that the stationary solids bed and the consequent poor conditioning of the well were probably responsibles for the failure to obtain the hydraulic isolation required for the cementing operation. The investigation report recommends some good practices for avoiding and/or removing the cuttings-bed. The results of some simulations carried out during the investigation studies showed that drillpipe rotation speed contributes significantly to reduce the cuttings-bed height. Additionally to the extended reach, the well studied is a design well, has a complex trajectory, and the computer simulations revealed that ROP control is mandatory to obtain a proper hole cleaning and well conditioning. It was identified that the reduction of the hole diameter has a huge impact on well conditioning, drilling fluid displacement and cement slurry displacement. At last, the paper presents some recommendations for backreaming, mainly for evaluation of ideal operational parameters; adjust the drilling rates according to the hydraulic simulation, to ensure the hole cleaning and optimize the total time of the drilling intervention.
{"title":"Influence of Hole Cleaning on the Liner Cement Job in Papa Terra Field","authors":"R. B. Vadinal, Stephan R. Perrout, Rodrigo De Campos Chuvas, Adriano Gouveia Lima Gomes dos Passos, Leonardo Pacheco da Silva","doi":"10.4043/29786-ms","DOIUrl":"https://doi.org/10.4043/29786-ms","url":null,"abstract":"\u0000 This work presents the lessons learned from the studies carried out to understand the non-fulfillment of the hydraulic isolation required during the liner 10 ¾\" cement job. Analyzing the drilling parameters performed and the events of cementing, it is possible that the stationary solids bed and the consequent poor conditioning of the well were probably responsibles for the failure to obtain the hydraulic isolation required for the cementing operation. The investigation report recommends some good practices for avoiding and/or removing the cuttings-bed. The results of some simulations carried out during the investigation studies showed that drillpipe rotation speed contributes significantly to reduce the cuttings-bed height. Additionally to the extended reach, the well studied is a design well, has a complex trajectory, and the computer simulations revealed that ROP control is mandatory to obtain a proper hole cleaning and well conditioning. It was identified that the reduction of the hole diameter has a huge impact on well conditioning, drilling fluid displacement and cement slurry displacement. At last, the paper presents some recommendations for backreaming, mainly for evaluation of ideal operational parameters; adjust the drilling rates according to the hydraulic simulation, to ensure the hole cleaning and optimize the total time of the drilling intervention.","PeriodicalId":11089,"journal":{"name":"Day 2 Wed, October 30, 2019","volume":"39 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-10-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"73398494","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. Delgado, Pedro Henrique Neves Goncalves, Magda Maria de Regina Chambriard
The magnitude of the pre-salt projects, most located in Brazil ultra-deep waters, coupled with the enormous potential already auctioned, leads to the following questions: what will be Brazil's share in the world's deep-water development? How should suppliers prepare themselves to assist Brazil in the task of making these opportunities viable? Since 2013, the country awarded over R$ 43 billion in signing bonuses. Despite the pessimism associated to the oil price drop in 2014, Brazil has gone forward with the development of pre-salt areas and the resume of the bidding rounds, reaching the top 10th position in world's biggest oil producers (BP 2019). This paper forecasts the oil potential for these areas, as well as the Brazilian oil production for the next 15 years and the demand for facilities to reach that potential. Those forecasts clarify the increasing importance of Brazilian deep-water oil in the global scenario.
{"title":"Brazil Oil and Gas Sector Piece De Resistance: The Pre-Salt Play Developments","authors":"F. Delgado, Pedro Henrique Neves Goncalves, Magda Maria de Regina Chambriard","doi":"10.4043/29840-ms","DOIUrl":"https://doi.org/10.4043/29840-ms","url":null,"abstract":"\u0000 The magnitude of the pre-salt projects, most located in Brazil ultra-deep waters, coupled with the enormous potential already auctioned, leads to the following questions: what will be Brazil's share in the world's deep-water development? How should suppliers prepare themselves to assist Brazil in the task of making these opportunities viable?\u0000 Since 2013, the country awarded over R$ 43 billion in signing bonuses. Despite the pessimism associated to the oil price drop in 2014, Brazil has gone forward with the development of pre-salt areas and the resume of the bidding rounds, reaching the top 10th position in world's biggest oil producers (BP 2019).\u0000 This paper forecasts the oil potential for these areas, as well as the Brazilian oil production for the next 15 years and the demand for facilities to reach that potential. Those forecasts clarify the increasing importance of Brazilian deep-water oil in the global scenario.","PeriodicalId":11089,"journal":{"name":"Day 2 Wed, October 30, 2019","volume":"18 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-10-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77347622","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}
Erna Kakadjian, April Shi, J. Porter, Prahlad Yadav, D. Clapper, W. Pessanha
One of the biggest challenges when drilling in deep water is the excessive dependence of drilling fluid rheological properties on temperature. Conventional drilling fluids often have high viscosity at the seabed temperature, which increases the Equivalent Circulating Density (ECD) and surge pressures when running pipe or initiating circulation, elevating the risk of fracturing the wellbore. This paper describes the development of a drilling fluid for deep-water applications, with minimum viscosity variation with temperature. Multiple laboratory formulations were evaluated during the development of the new, non-aqueous based drilling fluid that meets deep-water's challenging rheological and barite suspension requirements. CaCl2 brine was used as the internal emulsion phase, and synthetic isomerized olefin as the base oil. The testing followed the API Recommended Practice for Field Testing Oil-based Drilling Fluids. Samples were aged at dynamic conditions for 16 hours at several temperatures. Then, rheological properties and high-pressure high-temperature (HPHT) fluid loss, emulsion stability, and dynamic sagging were tested. Static sag experiments were also carried out for up to seven days together with improved step down rheology tests. A low-impact, non-aqueous drilling fluid (LIDF) was designed to minimize ECD increases by reducing the effect of cold temperature on the fluid viscosity. The fluid offers a superior low viscosity profile and rapid-set, easy-break gel strengths, while maintaining low shear rate viscosity at high temperatures with optimal weight material suspension. The fluid is also compatible with all contaminants usually found during the drilling operation and meets all the regulatory requirements for the Gulf of Mexico and other deep-water operational areas. Field application demonstrated that LIDF reduced the effect of temperature on the fluid rheological properties and minimized the risk of induced formation losses. These same rheological features reduced non-productive time associated with cement displacement and barite sagging. Supporting laboratory and field data are presented to demonstrate the superior performance of the fluid in maintaining rheological and barite suspension properties over a wide range of temperatures. The properties of the LIDF are achieved by matching the effects of emulsifier, organophilic clay, and rheological modifiers to maintain correct rheological properties at low and high temperatures.
{"title":"Low Impact Drilling Fluid for Deepwater Drilling Frontier","authors":"Erna Kakadjian, April Shi, J. Porter, Prahlad Yadav, D. Clapper, W. Pessanha","doi":"10.4043/29802-ms","DOIUrl":"https://doi.org/10.4043/29802-ms","url":null,"abstract":"\u0000 One of the biggest challenges when drilling in deep water is the excessive dependence of drilling fluid rheological properties on temperature. Conventional drilling fluids often have high viscosity at the seabed temperature, which increases the Equivalent Circulating Density (ECD) and surge pressures when running pipe or initiating circulation, elevating the risk of fracturing the wellbore. This paper describes the development of a drilling fluid for deep-water applications, with minimum viscosity variation with temperature.\u0000 Multiple laboratory formulations were evaluated during the development of the new, non-aqueous based drilling fluid that meets deep-water's challenging rheological and barite suspension requirements. CaCl2 brine was used as the internal emulsion phase, and synthetic isomerized olefin as the base oil. The testing followed the API Recommended Practice for Field Testing Oil-based Drilling Fluids. Samples were aged at dynamic conditions for 16 hours at several temperatures. Then, rheological properties and high-pressure high-temperature (HPHT) fluid loss, emulsion stability, and dynamic sagging were tested. Static sag experiments were also carried out for up to seven days together with improved step down rheology tests.\u0000 A low-impact, non-aqueous drilling fluid (LIDF) was designed to minimize ECD increases by reducing the effect of cold temperature on the fluid viscosity. The fluid offers a superior low viscosity profile and rapid-set, easy-break gel strengths, while maintaining low shear rate viscosity at high temperatures with optimal weight material suspension. The fluid is also compatible with all contaminants usually found during the drilling operation and meets all the regulatory requirements for the Gulf of Mexico and other deep-water operational areas. Field application demonstrated that LIDF reduced the effect of temperature on the fluid rheological properties and minimized the risk of induced formation losses. These same rheological features reduced non-productive time associated with cement displacement and barite sagging.\u0000 Supporting laboratory and field data are presented to demonstrate the superior performance of the fluid in maintaining rheological and barite suspension properties over a wide range of temperatures. The properties of the LIDF are achieved by matching the effects of emulsifier, organophilic clay, and rheological modifiers to maintain correct rheological properties at low and high temperatures.","PeriodicalId":11089,"journal":{"name":"Day 2 Wed, October 30, 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":"81944743","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
A. Oshiro, R. Mendes, G. Diederichs, Dalisson Santos Vieira, Acacio Sarnaglia Do Amaral
The Restriction Diagram is a tool that delimits the minimum distance between a dynamic positioning (DP) drilling rig and surface or subsea obstacles (Platforms, anchor lines, subsea equipment) for safe operation. These diagrams are used for risk analysis and well operations restricting the operation of some rigs in some locations or avoiding very large drilling operations next to each other. They are also used as one of the parameters to determine the best position of the platform in relation to the wells, impacting any subsea layout of a new field development. The analysis of restriction diagrams are essential for risk assessment involving drilling rigs. It is important to improve the quality and robustness of the methodology presented due to safety distances. This proposal of the new model of the Restriction Diagram aims to support the risk analysis of Drilling Rigs operations including the probability of drilling rigs failure, recovery times and hydrodynamic probabilistic modeling. There is integration between all the parameters involved in the process and the propagation of its uncertainties. The reliability analysis of the dynamic positioning drilling rigs used an extensive database of incident logs, from which was extracted the occurrences of total loss of propulsive capacity of the drilling rigs that resulted in a drift-off. It was considered the operating time and failures that have occurred since 2010, as well as the drilling rig recovery time. The drift-off analysis are represented by means of hydrodynamic modeling coupled to a probabilistic simulator. This risk-based analysis from reliability and environmental conditions will give the chance of collision with obstacles for drilling operations or well intervention. This paper presents a risk assessment approach according to the new emphases that are beginning to be considered by regulatory authorities such as the Petroleum Safety Authority (PSA) in Norway, considering the integration between decision processes and uncertainty analysis.
{"title":"Restriction Diagram: Realibility Study of Drilling Ships with Dynamic Positioning System","authors":"A. Oshiro, R. Mendes, G. Diederichs, Dalisson Santos Vieira, Acacio Sarnaglia Do Amaral","doi":"10.4043/29684-ms","DOIUrl":"https://doi.org/10.4043/29684-ms","url":null,"abstract":"\u0000 The Restriction Diagram is a tool that delimits the minimum distance between a dynamic positioning (DP) drilling rig and surface or subsea obstacles (Platforms, anchor lines, subsea equipment) for safe operation. These diagrams are used for risk analysis and well operations restricting the operation of some rigs in some locations or avoiding very large drilling operations next to each other. They are also used as one of the parameters to determine the best position of the platform in relation to the wells, impacting any subsea layout of a new field development. The analysis of restriction diagrams are essential for risk assessment involving drilling rigs. It is important to improve the quality and robustness of the methodology presented due to safety distances. This proposal of the new model of the Restriction Diagram aims to support the risk analysis of Drilling Rigs operations including the probability of drilling rigs failure, recovery times and hydrodynamic probabilistic modeling. There is integration between all the parameters involved in the process and the propagation of its uncertainties.\u0000 The reliability analysis of the dynamic positioning drilling rigs used an extensive database of incident logs, from which was extracted the occurrences of total loss of propulsive capacity of the drilling rigs that resulted in a drift-off. It was considered the operating time and failures that have occurred since 2010, as well as the drilling rig recovery time. The drift-off analysis are represented by means of hydrodynamic modeling coupled to a probabilistic simulator. This risk-based analysis from reliability and environmental conditions will give the chance of collision with obstacles for drilling operations or well intervention.\u0000 This paper presents a risk assessment approach according to the new emphases that are beginning to be considered by regulatory authorities such as the Petroleum Safety Authority (PSA) in Norway, considering the integration between decision processes and uncertainty analysis.","PeriodicalId":11089,"journal":{"name":"Day 2 Wed, October 30, 2019","volume":"49 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-10-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82636893","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}
While we are currently seeing less fires, statistically, if you do have a fire in your home, you are more likely to die today than you were 20 years ago. Add to that, that every 24 seconds, a U.S. fire department responds to a fire somewhere in the country. Nationwide, a civilian died in a fire every 2 hours and 34 minutes. (From the 2017 U.S. Fire Loss Report) The reality is, we do have many of the tools to prevent damaging fires – sprinklers, smoke alarms, codes and enforcement – but they are met with resistance from everyone from policymakers and enforcers to builders and the public. Over the years we've underused, ignored or allowed codes and safety standards to become outdated.
{"title":"Increasing Fire Safety – Fire and Life Safety Ecosystem","authors":"Anderson Queiroz Candido","doi":"10.4043/29961-ms","DOIUrl":"https://doi.org/10.4043/29961-ms","url":null,"abstract":"While we are currently seeing less fires, statistically, if you do have a fire in your home, you are more likely to die today than you were 20 years ago. Add to that, that every 24 seconds, a U.S. fire department responds to a fire somewhere in the country. Nationwide, a civilian died in a fire every 2 hours and 34 minutes. (From the 2017 U.S. Fire Loss Report)\u0000 The reality is, we do have many of the tools to prevent damaging fires – sprinklers, smoke alarms, codes and enforcement – but they are met with resistance from everyone from policymakers and enforcers to builders and the public. Over the years we've underused, ignored or allowed codes and safety standards to become outdated.","PeriodicalId":11089,"journal":{"name":"Day 2 Wed, October 30, 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":"87946275","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}
Phased Field Development (PFD) is a well-known method to mitigate reservoir uncertainty. However, by its very nature a PFD lowers the Net Present Value (NPV) of the project compared to a Full Field Development (FFD). In this work, multiple scenarios are investigated to increase the attractiveness of PFD vis-a-vis FFD. The most promising concepts are identified and their key financial characteristics are studied with a view to providing a roadmap that can assist in efficient planning of future deepwater field developments. Annual cash flows along with revenue and profit margins are estimated and compared for the two options for a potential deepwater field development in US Gulf of Mexico.
{"title":"Increasing the Attractiveness of Phased Field Development: De-Risk Reservoir Uncertainty with Efficient Field Development Solution","authors":"Shiladitya Basu, Tirtharaj Bhaumik","doi":"10.4043/29784-ms","DOIUrl":"https://doi.org/10.4043/29784-ms","url":null,"abstract":"\u0000 Phased Field Development (PFD) is a well-known method to mitigate reservoir uncertainty. However, by its very nature a PFD lowers the Net Present Value (NPV) of the project compared to a Full Field Development (FFD). In this work, multiple scenarios are investigated to increase the attractiveness of PFD vis-a-vis FFD. The most promising concepts are identified and their key financial characteristics are studied with a view to providing a roadmap that can assist in efficient planning of future deepwater field developments.\u0000 Annual cash flows along with revenue and profit margins are estimated and compared for the two options for a potential deepwater field development in US Gulf of Mexico.","PeriodicalId":11089,"journal":{"name":"Day 2 Wed, October 30, 2019","volume":"37 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-10-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"76141693","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
The well, Halini X1, was initially tested at an average rate of 1,750 BOPD, with 26-degree API gravity and produced gas at 1.27 MMscfd. The production history showed that the well head parameters were at continous decline due to natural depletion of reservoir. Based on the observation, a complete nodal analysis of multiphase flow was conducted. The results indicated that the natural flow of well will cease when the reservoir pressure decline below 3,000 psig. Therefore, a suitable artificial lift was selected and designed to improve the vertical lift performance of well, making the production sustainbale even at low reservoir pressures. The high gas content of the reservoir fluid, deep reservoir zone, and adequate bottom hole pressure of Halini X1 favored gas lift to be more viable compared to other ALS methods both technically and economically. The results of the gas lift simulation showed enhancment in production; however by changing the tubing size from 3-1/2 inch to 4-1/2 inch further magnified the performance of gas lift injection in terms of production. Based on design, gas lift equipment was installed through workover and the well was put on gas lift injection. The detailed comparison was drawn between natural flow and the flow on gas lift. The outcomes were found with remarkable increase in the life span of well over natural flowing period and led to higher recovery of production.
{"title":"A Case Study in Production Enhancement Through Installation of Optimum Artificial Lift Technology","authors":"Sharafat Ali, Sandeep Kumar, S. A. Kalwar","doi":"10.4043/29848-ms","DOIUrl":"https://doi.org/10.4043/29848-ms","url":null,"abstract":"\u0000 The well, Halini X1, was initially tested at an average rate of 1,750 BOPD, with 26-degree API gravity and produced gas at 1.27 MMscfd. The production history showed that the well head parameters were at continous decline due to natural depletion of reservoir. Based on the observation, a complete nodal analysis of multiphase flow was conducted. The results indicated that the natural flow of well will cease when the reservoir pressure decline below 3,000 psig. Therefore, a suitable artificial lift was selected and designed to improve the vertical lift performance of well, making the production sustainbale even at low reservoir pressures.\u0000 The high gas content of the reservoir fluid, deep reservoir zone, and adequate bottom hole pressure of Halini X1 favored gas lift to be more viable compared to other ALS methods both technically and economically. The results of the gas lift simulation showed enhancment in production; however by changing the tubing size from 3-1/2 inch to 4-1/2 inch further magnified the performance of gas lift injection in terms of production.\u0000 Based on design, gas lift equipment was installed through workover and the well was put on gas lift injection. The detailed comparison was drawn between natural flow and the flow on gas lift. The outcomes were found with remarkable increase in the life span of well over natural flowing period and led to higher recovery of production.","PeriodicalId":11089,"journal":{"name":"Day 2 Wed, October 30, 2019","volume":"515 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-10-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77837601","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}
ULTRA™ is a novel and advanced flow assurance coating technology recently introduced in the Brazilian market for upcoming, and challenging, offshore projects expected in the next years. This coating technology has been used for over 9 years, and has been designed, applied and installed in offshore projects worldwide. Particularly over the last year, this thermal insulation system has been applied for a major project in Brazil. It is a thermal insulation system composed of fusion bonded epoxy and styrenic materials. A base 3-layer coating, followed by one or more insulation layers of solid or foamed styrene, and a high ductility outer shield were engineered to outperform some of existing solutions in terms of hydrostatic pressure, subsea stability, overall insulation thickness and associated installation costs. Application trials have been successfully performed to validate plant capabilities for applying the wide range of styrene-based system solutions, for shallow and deep waters. Test results demonstrated that foam and solid versions have a sweet spot in which the system outperforms similar to the wet insulation solutions existing in the Brazilian market. Its solid and foam systems demonstrated capability of delivering lower U - values (Overall Heat Transfer Coefficient) due to their lower thermal conductivity. The benefit of lower thermal conductivity is reflected in a reduced coating thickness and opportunities for potential savings during the transportation and installation activities. In the coming years, the offshore industry in Brazil will demand wet insulation systems delivering improved thermal performance. Hence, lower U value with lower CAPEX and in deeper water depths. This insulation system is a proven flow assurance coating technology, addressing those challenges and now available in the Brazilian market.
{"title":"ULTRA: Flow Assurance Coating Technology - Product Portfolio for Distinct Operating Scenarios","authors":"N. Cunha","doi":"10.4043/29772-ms","DOIUrl":"https://doi.org/10.4043/29772-ms","url":null,"abstract":"\u0000 ULTRA™ is a novel and advanced flow assurance coating technology recently introduced in the Brazilian market for upcoming, and challenging, offshore projects expected in the next years. This coating technology has been used for over 9 years, and has been designed, applied and installed in offshore projects worldwide. Particularly over the last year, this thermal insulation system has been applied for a major project in Brazil. It is a thermal insulation system composed of fusion bonded epoxy and styrenic materials. A base 3-layer coating, followed by one or more insulation layers of solid or foamed styrene, and a high ductility outer shield were engineered to outperform some of existing solutions in terms of hydrostatic pressure, subsea stability, overall insulation thickness and associated installation costs. Application trials have been successfully performed to validate plant capabilities for applying the wide range of styrene-based system solutions, for shallow and deep waters. Test results demonstrated that foam and solid versions have a sweet spot in which the system outperforms similar to the wet insulation solutions existing in the Brazilian market. Its solid and foam systems demonstrated capability of delivering lower U - values (Overall Heat Transfer Coefficient) due to their lower thermal conductivity. The benefit of lower thermal conductivity is reflected in a reduced coating thickness and opportunities for potential savings during the transportation and installation activities. In the coming years, the offshore industry in Brazil will demand wet insulation systems delivering improved thermal performance. Hence, lower U value with lower CAPEX and in deeper water depths. This insulation system is a proven flow assurance coating technology, addressing those challenges and now available in the Brazilian market.","PeriodicalId":11089,"journal":{"name":"Day 2 Wed, October 30, 2019","volume":"40 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-10-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89262400","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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