Hongying Zhao, S. Pierobon, Adam Pettigrew, Jacques Doan-Prevost, O. Garnier, T. Haas
The high energy intensity of steam-based heavy oil extraction processes is leading the industry to investigate solvent-aided processes for heavy oil/bitumen recovery. The diffusion coefficient of solvent in heavy oil is a key parameter to determine how effective these processes are. Measuring the diffusion coefficient is challenging, especially at in-situ conditions, i.e., at elevated temperature and pressure. This paper presents a microfluidics-based method for measuring the diffusion coefficient of propane and butane, the most commonly used light hydrocarbons in solvent process, into heavy oil at high temperature and pressure conditions. A silicon-glass microfluidic chip was designed and fabricated using the Deep Reactive Ion Etching (DRIE) and anodic bonding. The diffusion tests were performed at temperatures ranging from 20°C to 120°C and pressures up to 100 bar. Upon blue light excitation, heavy oil naturally fluoresces at visible wavelengths, and the intensity varies with solvent concentration. Based on this mechanism, the light intensity change of the heavy oil in a 100-micron channel was recorded with a camera connected to the microscope during the diffusion process. An image processing method was developed accordingly to create a map of fluorescence light intensity versus diffusion time and distance, which was further processed numerically to calculate the diffusion coefficient with measured correlations between light intensity and solvent concentration. At all testing conditions both solvents were liquid which inevitably would cause asphaltene precipitation at oil-solvent interface as demonstrated by the observations during the diffusion tests. It was also found that the asphaltene precipitation phenomena were more pronounced with butane than propane. To measure the diffusion coefficient, a method using solvent diluted oil was developed to avoid the asphaltene precipitation issue. The measured diffusion coefficient of propane was around 0.6 × 10-10 m2/s using pure solvent method, and that of butane was in the range of 1—9 × 10-9 m2/s, at their corresponding testing conditions. For both solvents the diffusion coefficients increased with temperature while no satisfactory trend was observed with pressure within 100 bar.
{"title":"Measurement of Propane and Butane Diffusion into Heavy Oil using Microfluidics - Is Small Better?","authors":"Hongying Zhao, S. Pierobon, Adam Pettigrew, Jacques Doan-Prevost, O. Garnier, T. Haas","doi":"10.2118/193015-MS","DOIUrl":"https://doi.org/10.2118/193015-MS","url":null,"abstract":"\u0000 The high energy intensity of steam-based heavy oil extraction processes is leading the industry to investigate solvent-aided processes for heavy oil/bitumen recovery. The diffusion coefficient of solvent in heavy oil is a key parameter to determine how effective these processes are. Measuring the diffusion coefficient is challenging, especially at in-situ conditions, i.e., at elevated temperature and pressure. This paper presents a microfluidics-based method for measuring the diffusion coefficient of propane and butane, the most commonly used light hydrocarbons in solvent process, into heavy oil at high temperature and pressure conditions.\u0000 A silicon-glass microfluidic chip was designed and fabricated using the Deep Reactive Ion Etching (DRIE) and anodic bonding. The diffusion tests were performed at temperatures ranging from 20°C to 120°C and pressures up to 100 bar. Upon blue light excitation, heavy oil naturally fluoresces at visible wavelengths, and the intensity varies with solvent concentration. Based on this mechanism, the light intensity change of the heavy oil in a 100-micron channel was recorded with a camera connected to the microscope during the diffusion process. An image processing method was developed accordingly to create a map of fluorescence light intensity versus diffusion time and distance, which was further processed numerically to calculate the diffusion coefficient with measured correlations between light intensity and solvent concentration.\u0000 At all testing conditions both solvents were liquid which inevitably would cause asphaltene precipitation at oil-solvent interface as demonstrated by the observations during the diffusion tests. It was also found that the asphaltene precipitation phenomena were more pronounced with butane than propane. To measure the diffusion coefficient, a method using solvent diluted oil was developed to avoid the asphaltene precipitation issue.\u0000 The measured diffusion coefficient of propane was around 0.6 × 10-10 m2/s using pure solvent method, and that of butane was in the range of 1—9 × 10-9 m2/s, at their corresponding testing conditions. For both solvents the diffusion coefficients increased with temperature while no satisfactory trend was observed with pressure within 100 bar.","PeriodicalId":11208,"journal":{"name":"Day 2 Tue, November 13, 2018","volume":"1 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89174369","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}
Corrosion, erosion, abrasion and chemical attack of process equipment is a challenge that costs the Oil and gas industry billions per year. Although corrosion/wear/chemical resistant coatings are commonly in use today, enhanced performance requires improved polymer coating materials and coating methods. In the past 20 years coating technology has come far in terms of material development and also in terms of documenting real results. The objective of this paper is to outline the advances and benefits of composite coatings in the oil and gas industry. Facing the challenge to replace expensive materials and technologies with the use of composites delivers to the Oil&Gas industries savings measured by the duration of the protection, saved time for replacement and use of non expensive materials as a substrate. This can be achieved with the use of technology that provides faster and repairable methods of surface treatment and adding the value of improved equipment efficiency.
{"title":"Advanced Reinforced Polymer Composite Coatings Revolutionize Corrosion and Wear Protection, and Offer Energy Savings in the Oil and Gas Industry","authors":"R. Borisov, Paul Lenehan, N. Wilson","doi":"10.2118/193124-MS","DOIUrl":"https://doi.org/10.2118/193124-MS","url":null,"abstract":"\u0000 Corrosion, erosion, abrasion and chemical attack of process equipment is a challenge that costs the Oil and gas industry billions per year. Although corrosion/wear/chemical resistant coatings are commonly in use today, enhanced performance requires improved polymer coating materials and coating methods. In the past 20 years coating technology has come far in terms of material development and also in terms of documenting real results. The objective of this paper is to outline the advances and benefits of composite coatings in the oil and gas industry. Facing the challenge to replace expensive materials and technologies with the use of composites delivers to the Oil&Gas industries savings measured by the duration of the protection, saved time for replacement and use of non expensive materials as a substrate. This can be achieved with the use of technology that provides faster and repairable methods of surface treatment and adding the value of improved equipment efficiency.","PeriodicalId":11208,"journal":{"name":"Day 2 Tue, November 13, 2018","volume":"248 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"75912778","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 expanding focus on total cost of ownership (TCO) in the oilfield is driving the application of global best practices in drilling and completion operations. Measurable benefits can result from a proactive approach to separating, treating, and handling disposal streams that accounts for both short- and long-term effects and is tailored to the specific needs of projects in the Middle East. This paper provides a versatile decision-making tool to help determine the optimal processes for a variety of conditions based on efficiency, economics, and sustainability. The most effective treatment solutions and services seek to address multiple factors, including logistics and expenses, drilling efficiency and performance, remote locations with infrastructure limitations, and strict environmental regulations. Interdependencies between the fluids, equipment, and services will also influence the selection of appropriate separation and treatment processes. A useful decision tree is based on the critical goals of waste volume reduction and maximum recovery of valuable components. Making the right choices in both of these areas will provide effective long-term results and economic benefits. This paper summarizes multiple case histories that demonstrate successful cuttings and waste stream processing, including both land and offshore operations. In some cases, a mobile or well-specific treatment system works best; others rely on a central treatment facility to serve an entire field or multirig operation. The results achieved in each case contribute to a step-by-step planning tool in matrix format that can be used to design the best set of equipment and services for each location. The matrix accounts for many factors, including rig equipment and capacities, proposed drilling and completion fluids, lithology, risk assessment, system maintenance, potential process rates and throughput, mobilization, environmental regulations, and infrastructure requirements. The decision tree presented facilitates the treatment selection process by incorporating useful benchmarks for volumes, process rates, expected base oil/fluid recovery, installation costs/requirements, scalability, longevity, and decommissioning (and/or relocation of the treatment system). It provides a practical starting point for planning an efficient, fit-for-purpose treatment configuration, scaled to match operational needs, reduce total cost of ownership, and meet or exceed existing and future standards.
{"title":"Efficiency, Economics and Compliance: A Practical Planning Tool for Optimizing Cuttings Treatment","authors":"E. J. Chauvin","doi":"10.2118/192825-MS","DOIUrl":"https://doi.org/10.2118/192825-MS","url":null,"abstract":"\u0000 The expanding focus on total cost of ownership (TCO) in the oilfield is driving the application of global best practices in drilling and completion operations. Measurable benefits can result from a proactive approach to separating, treating, and handling disposal streams that accounts for both short- and long-term effects and is tailored to the specific needs of projects in the Middle East. This paper provides a versatile decision-making tool to help determine the optimal processes for a variety of conditions based on efficiency, economics, and sustainability.\u0000 The most effective treatment solutions and services seek to address multiple factors, including logistics and expenses, drilling efficiency and performance, remote locations with infrastructure limitations, and strict environmental regulations. Interdependencies between the fluids, equipment, and services will also influence the selection of appropriate separation and treatment processes.\u0000 A useful decision tree is based on the critical goals of waste volume reduction and maximum recovery of valuable components. Making the right choices in both of these areas will provide effective long-term results and economic benefits.\u0000 This paper summarizes multiple case histories that demonstrate successful cuttings and waste stream processing, including both land and offshore operations. In some cases, a mobile or well-specific treatment system works best; others rely on a central treatment facility to serve an entire field or multirig operation. The results achieved in each case contribute to a step-by-step planning tool in matrix format that can be used to design the best set of equipment and services for each location.\u0000 The matrix accounts for many factors, including rig equipment and capacities, proposed drilling and completion fluids, lithology, risk assessment, system maintenance, potential process rates and throughput, mobilization, environmental regulations, and infrastructure requirements.\u0000 The decision tree presented facilitates the treatment selection process by incorporating useful benchmarks for volumes, process rates, expected base oil/fluid recovery, installation costs/requirements, scalability, longevity, and decommissioning (and/or relocation of the treatment system). It provides a practical starting point for planning an efficient, fit-for-purpose treatment configuration, scaled to match operational needs, reduce total cost of ownership, and meet or exceed existing and future standards.","PeriodicalId":11208,"journal":{"name":"Day 2 Tue, November 13, 2018","volume":"27 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"72690931","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}
Carbonate reservoir complexities are both described and hidden by the use of the common and generic term, "heterogeneous", with usually little serious effort then expended to define and quantify the meaning and dimensions of the term. Saudi Aramco, the custodian of the world’s largest petroleum reserves in carbonate reservoirs, is making long-term efforts to bring light to the carbonate "heterogeneity" darkness. We are constructing the industry’s largest integrated petrophysical and geological databases for our major carbonate reservoirs. Our large databases contain porosity, permeability, grain density and pore system information from core plugs carefully integrated with a full suite of well log data and core descriptions. These cores have been described in detail using the most current carbonate sequence stratigraphic techniques and all these data have been captured digitally and integrated consistently and carefully. Our database for one field contains 1695 limestone pore systems (a pore system is defined by a single Thomeer hyperbola), obtained from 931 plug samples by Thomeer analysis of core plug mercury capillary pressure data (MICP) with plans to expand the measurements to 1500 plug samples for just this one major reservoir by the year 2020. The current core plugs for the database now include samples from 30 cored wells (up from the 10 cored wells of the previous Rosetta Stone project) to obtain statistically robust reservoir petrophysical data at the facies level. Pore system data are now also being acquired in vertical wells for constrained reservoir layering and vertical reservoir model tie points using nuclear magnetic resonance (NMR) well log data and the CIPHER software for the Thomeer parameter MICP-consistent spectral porosity analysis. At Saudi Aramco, our extensive facies – petrophysical properties database process delivers the reference reservoir property database for our major carbonate reservoir models. The reference database improves our understanding and modelling of the variation and covariation of the facies and petrophysical rock types (PRTs) for reservoir modeling. It also provides sound statistical support for the population of the reservoir with petrophysical pore system properties within the sequence stratigraphic facies framework. For the reservoir dynamics, the database allows detailed investigations into the statistical linkages of pore system properties which control permeability and relative permeability developed by Clerke and coworkers to the sequence stratigraphic reservoir facies. We report here selected results from a very large quantity of relationships and statistical attributes that can be derived from this database. At the general carbonates level, these reference databases demonstrate that the reservoir complexity hidden in the shadow of "heterogeneity" is actually the prevalence and statistical distribution of these multimodal pore systems and their attributes.
{"title":"Selected Results from Big Carbonate Pore System Database: A Case Study from Saudi Aramco","authors":"S. S. Din, E. Clerke, Ahmad Badawi","doi":"10.2118/193163-MS","DOIUrl":"https://doi.org/10.2118/193163-MS","url":null,"abstract":"\u0000 Carbonate reservoir complexities are both described and hidden by the use of the common and generic term, \"heterogeneous\", with usually little serious effort then expended to define and quantify the meaning and dimensions of the term. Saudi Aramco, the custodian of the world’s largest petroleum reserves in carbonate reservoirs, is making long-term efforts to bring light to the carbonate \"heterogeneity\" darkness. We are constructing the industry’s largest integrated petrophysical and geological databases for our major carbonate reservoirs.\u0000 Our large databases contain porosity, permeability, grain density and pore system information from core plugs carefully integrated with a full suite of well log data and core descriptions. These cores have been described in detail using the most current carbonate sequence stratigraphic techniques and all these data have been captured digitally and integrated consistently and carefully. Our database for one field contains 1695 limestone pore systems (a pore system is defined by a single Thomeer hyperbola), obtained from 931 plug samples by Thomeer analysis of core plug mercury capillary pressure data (MICP) with plans to expand the measurements to 1500 plug samples for just this one major reservoir by the year 2020. The current core plugs for the database now include samples from 30 cored wells (up from the 10 cored wells of the previous Rosetta Stone project) to obtain statistically robust reservoir petrophysical data at the facies level. Pore system data are now also being acquired in vertical wells for constrained reservoir layering and vertical reservoir model tie points using nuclear magnetic resonance (NMR) well log data and the CIPHER software for the Thomeer parameter MICP-consistent spectral porosity analysis.\u0000 At Saudi Aramco, our extensive facies – petrophysical properties database process delivers the reference reservoir property database for our major carbonate reservoir models. The reference database improves our understanding and modelling of the variation and covariation of the facies and petrophysical rock types (PRTs) for reservoir modeling. It also provides sound statistical support for the population of the reservoir with petrophysical pore system properties within the sequence stratigraphic facies framework. For the reservoir dynamics, the database allows detailed investigations into the statistical linkages of pore system properties which control permeability and relative permeability developed by Clerke and coworkers to the sequence stratigraphic reservoir facies.\u0000 We report here selected results from a very large quantity of relationships and statistical attributes that can be derived from this database. At the general carbonates level, these reference databases demonstrate that the reservoir complexity hidden in the shadow of \"heterogeneity\" is actually the prevalence and statistical distribution of these multimodal pore systems and their attributes.","PeriodicalId":11208,"journal":{"name":"Day 2 Tue, November 13, 2018","volume":"37 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"81086778","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
An alternative method is presented for estimation of reservoir properties that are usually estimated in a classic buildup test are obtained using flowing conditions thereby eliminating the need for shut-in periods and measurement of static pressure data. The proposed approach is based on the effect of two consecutive periods of production with different rates in a single well-reservoir model. The well is initially produced at a constant rate until pseudo-steady state conditions are reached, followed by a different rate that will generate a pressure transient response measured at bottom of the wellbore. A mathematical formulation is applied to estimate the reservoir pressure as function of radius of investigation, which is equal to the bottom hole pressure observed during a shut-in buildup test. A single well-reservoir model with known petrophysical parameters, fluid properties, pressure and temperature is used as a reference to evaluate the proposed methodology. The reservoir (i.e. the simulation model) is tested by applying two methods: the first one, is the simulation of a classic buildup test, and the second one, is the simulation of two flow rates periods according to the new theory; the results are compared with the model of reference, calculating percentage of error for permeability, skin, and average reservoir pressure. Additionally, it is demonstrated that a shut-in period is not required to obtain data equivalent to a classic buildup test since it is possible to calculate it from dynamic behavior. The ability to complete a well pressure transient analysis test from flowing conditions and provide valid and reliable results has a direct impact in reduction of cost and deferred production for companies involved in oil and gas operations.
{"title":"Alternative Method for Pressure Transient Analysis","authors":"F. Franco, A. Rincón, M. Useche","doi":"10.2118/193261-ms","DOIUrl":"https://doi.org/10.2118/193261-ms","url":null,"abstract":"\u0000 An alternative method is presented for estimation of reservoir properties that are usually estimated in a classic buildup test are obtained using flowing conditions thereby eliminating the need for shut-in periods and measurement of static pressure data.\u0000 The proposed approach is based on the effect of two consecutive periods of production with different rates in a single well-reservoir model. The well is initially produced at a constant rate until pseudo-steady state conditions are reached, followed by a different rate that will generate a pressure transient response measured at bottom of the wellbore. A mathematical formulation is applied to estimate the reservoir pressure as function of radius of investigation, which is equal to the bottom hole pressure observed during a shut-in buildup test.\u0000 A single well-reservoir model with known petrophysical parameters, fluid properties, pressure and temperature is used as a reference to evaluate the proposed methodology. The reservoir (i.e. the simulation model) is tested by applying two methods: the first one, is the simulation of a classic buildup test, and the second one, is the simulation of two flow rates periods according to the new theory; the results are compared with the model of reference, calculating percentage of error for permeability, skin, and average reservoir pressure. Additionally, it is demonstrated that a shut-in period is not required to obtain data equivalent to a classic buildup test since it is possible to calculate it from dynamic behavior.\u0000 The ability to complete a well pressure transient analysis test from flowing conditions and provide valid and reliable results has a direct impact in reduction of cost and deferred production for companies involved in oil and gas operations.","PeriodicalId":11208,"journal":{"name":"Day 2 Tue, November 13, 2018","volume":"40 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86239131","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}
Permeability estimation in carbonate reservoirs is challenging and it generally consists of core-calibrated algorithms applied on open-hole logs. Moreover, due to inherent multi-scale heterogeneities, apparent permeability from production logging tool (PLT) is usually necessary to let the static log-based prediction honor dynamic data. The correspondence between dynamic corrections and carbonate rock types is a long-standing problem and an elegant solution is presented by integrating advanced nuclear magnetic resonance (NMR) log modeling with multi-rate PLT interpretation. The methodology, discussed on an oil-bearing carbonate reservoir, starts with a rigorous mapping between NMR responses and pore-size distribution, mainly determined by special core analyses (SCAL). Hence, a robust porosity partition template and a physically-based permeability formula are established downhole relying on the quantitative integration of SCAL and advanced NMR modeling. Multi-rate PLT and well test data are then analyzed to evaluate the boost needed for log permeability to match the dynamic behavior of the wells. Finally, porosity partition outcomes are used as pointwise predictors of dynamic permeability enhancement by means of a probabilistic approach. In details, a system built upon mercury injection capillary pressure measurements, representative of the entire reservoir, shows a well-defined pore structure consisting of micropores, mesopores and macropores. At the same time, a quantitative link is established between NMR transverse relaxation time and pore-size distributions through an effective surface relaxivity parameter, both at laboratory and reservoir conditions. This allows discriminating micro, meso and macro-porosity downhole. Effective surface relaxivity also plays a critical role in the subsequent NMR permeability estimation based on a capillary tube model of the porous media and exploiting the full NMR/pore-size distributions. Although the match with core data proves the reliability of the comprehensive rock characterization, log permeability values underestimate the actual dynamic performances from well test. Therefore, the standard apparent permeability method from multi-rate PLT interpretation provides the necessary correction from the dynamic standpoint. Macro-porosity content is demonstrated to be the driver for a quantitative estimation of the excess in matrix permeability and an additional term complements the original NMR permeability predictor in order to honor the dynamic evidences. The approach makes use of a probabilistic framework aimed at considering the uncertainties in the a-priori simultaneous static and dynamic characterization. The presented innovative methodology addresses the well-known issue of quantitatively incorporating dynamic log modeling into a purely static workflow, thus leading to a more accurate permeability estimation. This is fundamental for production optimization and reservoir modeling purposes in highly hete
{"title":"The Dynamic Character of Porosity by Nuclear Magnetic Resonance and Production Logging for a Comprehensive Permeability Prediction in Carbonate Reservoirs","authors":"M. Pirrone, G. Galli","doi":"10.2118/192858-MS","DOIUrl":"https://doi.org/10.2118/192858-MS","url":null,"abstract":"\u0000 Permeability estimation in carbonate reservoirs is challenging and it generally consists of core-calibrated algorithms applied on open-hole logs. Moreover, due to inherent multi-scale heterogeneities, apparent permeability from production logging tool (PLT) is usually necessary to let the static log-based prediction honor dynamic data. The correspondence between dynamic corrections and carbonate rock types is a long-standing problem and an elegant solution is presented by integrating advanced nuclear magnetic resonance (NMR) log modeling with multi-rate PLT interpretation.\u0000 The methodology, discussed on an oil-bearing carbonate reservoir, starts with a rigorous mapping between NMR responses and pore-size distribution, mainly determined by special core analyses (SCAL). Hence, a robust porosity partition template and a physically-based permeability formula are established downhole relying on the quantitative integration of SCAL and advanced NMR modeling. Multi-rate PLT and well test data are then analyzed to evaluate the boost needed for log permeability to match the dynamic behavior of the wells. Finally, porosity partition outcomes are used as pointwise predictors of dynamic permeability enhancement by means of a probabilistic approach.\u0000 In details, a system built upon mercury injection capillary pressure measurements, representative of the entire reservoir, shows a well-defined pore structure consisting of micropores, mesopores and macropores. At the same time, a quantitative link is established between NMR transverse relaxation time and pore-size distributions through an effective surface relaxivity parameter, both at laboratory and reservoir conditions. This allows discriminating micro, meso and macro-porosity downhole. Effective surface relaxivity also plays a critical role in the subsequent NMR permeability estimation based on a capillary tube model of the porous media and exploiting the full NMR/pore-size distributions. Although the match with core data proves the reliability of the comprehensive rock characterization, log permeability values underestimate the actual dynamic performances from well test. Therefore, the standard apparent permeability method from multi-rate PLT interpretation provides the necessary correction from the dynamic standpoint. Macro-porosity content is demonstrated to be the driver for a quantitative estimation of the excess in matrix permeability and an additional term complements the original NMR permeability predictor in order to honor the dynamic evidences. The approach makes use of a probabilistic framework aimed at considering the uncertainties in the a-priori simultaneous static and dynamic characterization.\u0000 The presented innovative methodology addresses the well-known issue of quantitatively incorporating dynamic log modeling into a purely static workflow, thus leading to a more accurate permeability estimation. This is fundamental for production optimization and reservoir modeling purposes in highly hete","PeriodicalId":11208,"journal":{"name":"Day 2 Tue, November 13, 2018","volume":"33 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86278893","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 describes an educational case study covering the development and presentation of a new petroleum engineering master's course in advanced phase behaviour. Emphasis was placed on current industry challenges, interpretation of real data and visits to industry facilities. Special attention was given to fluid sampling experience. A variety of challenges and possible solutions are covered, and benefits to both full and part-time students, the next generation of industry professionals, are described. The PE graduate program saw increasing numbers of students so more industry-related technical elective courses were required. Several courses were proposed and the Advanced PVT course was selected based on student preferences. The course was developed with a mix of lectures, computer laboratory classes, information group use, industry visits, presentations, and semi-obligatory attendance at local SPE meetings. Assignments included literature searches to find interesting publications about sampling, and personal project assignments. These were excellent for practising engineers who could analyse and report on field case studies. Due to students’ various backgrounds, course content was modified to review material that is more basic. Industry students benefited from the opportunity to concentrate on specific challenges, discuss issues outside their company and learn from other participants, but had to manage the pressure of work. Full time students had more time for studies and out-of-classroom teamwork, but had little experience to share. Choice of suitable course textbook is discussed, with details given of other supporting literature used, especially in the areas of fluid sampling and compositional analysis, where common phase behaviour texts are very limited. The course syllabus, detailed delivery techniques, example assignments and teaching tips are provided. This is believed to be a novel case study, with no similar subject being found in SPE OnePetro publications. With continuing shortages in university PE schools, this material can help young faculty and adjunct faculty develop new courses more efficiently. Teaching at Masters level was seen to increase faculty access to students starting thesis research projects. A selection of industry participants’ recent experience in fluid sampling in the UAE is given and it is intended to incorporate it in future best practice procedures.
{"title":"New Advanced PVT Course Helps Masters Students to Find Solutions to Real Industry Challenges","authors":"John M. Williams","doi":"10.2118/192913-ms","DOIUrl":"https://doi.org/10.2118/192913-ms","url":null,"abstract":"\u0000 This paper describes an educational case study covering the development and presentation of a new petroleum engineering master's course in advanced phase behaviour. Emphasis was placed on current industry challenges, interpretation of real data and visits to industry facilities. Special attention was given to fluid sampling experience. A variety of challenges and possible solutions are covered, and benefits to both full and part-time students, the next generation of industry professionals, are described.\u0000 The PE graduate program saw increasing numbers of students so more industry-related technical elective courses were required. Several courses were proposed and the Advanced PVT course was selected based on student preferences. The course was developed with a mix of lectures, computer laboratory classes, information group use, industry visits, presentations, and semi-obligatory attendance at local SPE meetings. Assignments included literature searches to find interesting publications about sampling, and personal project assignments. These were excellent for practising engineers who could analyse and report on field case studies.\u0000 Due to students’ various backgrounds, course content was modified to review material that is more basic. Industry students benefited from the opportunity to concentrate on specific challenges, discuss issues outside their company and learn from other participants, but had to manage the pressure of work. Full time students had more time for studies and out-of-classroom teamwork, but had little experience to share.\u0000 Choice of suitable course textbook is discussed, with details given of other supporting literature used, especially in the areas of fluid sampling and compositional analysis, where common phase behaviour texts are very limited. The course syllabus, detailed delivery techniques, example assignments and teaching tips are provided.\u0000 This is believed to be a novel case study, with no similar subject being found in SPE OnePetro publications. With continuing shortages in university PE schools, this material can help young faculty and adjunct faculty develop new courses more efficiently. Teaching at Masters level was seen to increase faculty access to students starting thesis research projects. A selection of industry participants’ recent experience in fluid sampling in the UAE is given and it is intended to incorporate it in future best practice procedures.","PeriodicalId":11208,"journal":{"name":"Day 2 Tue, November 13, 2018","volume":"60 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88805566","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}
T. Narwal, Yaqoob Riyami, M. Rashdi, Zahir Abri, Aisha Sariri, Ahmed Benchekor, A. Hadhrami, R. Dsouza, A. Brodie, Kyle Strom
In South Oman, PDO is producing from high Sour Fields (H2S 1-10%) with high reservoir pressures ranging from 50,000 to 100,000kpa for more than 20 yrs. Operating these high sour wells comes with huge challenges and risks, which can easily get escalated to very high levels in case of any integrity issues with the wells. These situations not only provide significant exposure to expensive and risky well interventions but also pose threats to production due to Simultaneous Operations (SIMOPS) issues. The authors describe case studies where team was exposed to these challenging situations due to integrity failures in two such wells. New technologies were implemented which resulted in restoring the well integrity in a very cost effective manner (cost savings worth millions) and also reduced the HSE risks on the nearby operations. As a result, production was safeguarded (3-4% of Station Capacity) by allowing drilling of new wells and oil deferment from existing wells in the nearby area was avoided.
{"title":"Successful Implementation of New Technologies in Sour Oman Fields: Securing High Risk Wells, Savings & Production Increase","authors":"T. Narwal, Yaqoob Riyami, M. Rashdi, Zahir Abri, Aisha Sariri, Ahmed Benchekor, A. Hadhrami, R. Dsouza, A. Brodie, Kyle Strom","doi":"10.2118/192711-MS","DOIUrl":"https://doi.org/10.2118/192711-MS","url":null,"abstract":"\u0000 In South Oman, PDO is producing from high Sour Fields (H2S 1-10%) with high reservoir pressures ranging from 50,000 to 100,000kpa for more than 20 yrs. Operating these high sour wells comes with huge challenges and risks, which can easily get escalated to very high levels in case of any integrity issues with the wells. These situations not only provide significant exposure to expensive and risky well interventions but also pose threats to production due to Simultaneous Operations (SIMOPS) issues.\u0000 The authors describe case studies where team was exposed to these challenging situations due to integrity failures in two such wells. New technologies were implemented which resulted in restoring the well integrity in a very cost effective manner (cost savings worth millions) and also reduced the HSE risks on the nearby operations. As a result, production was safeguarded (3-4% of Station Capacity) by allowing drilling of new wells and oil deferment from existing wells in the nearby area was avoided.","PeriodicalId":11208,"journal":{"name":"Day 2 Tue, November 13, 2018","volume":"33 7","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"91485237","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 article represents the results of the research and development project that has been conducted with the goal to create an innovative and environmental water-blocking agent for the enhancement efficiency of the improved oil recovery methods. The innovation of the developed water-blocking agent lies in the combination of unique physical and chemical properties: high thermal stability (140 °C), improved rheology (viscoplastic properties), outstanding surface activity (regulation of the wettability of rock surface), and selective blocking effect. The key factor to combine all of these properties in one solution is to apply colloidal silicon dioxide nanoparticles with modified surface as a stabilizer and surface-active phase in the emulsion system. Also, a technology on the new water-blocking agent for the effective application in the intensification of oil production (well stimulation, IOP) methods has been developed, and well-tested in the field. For the investigation of the unique properties of the new emulsion systems with colloidal silicon dioxide nanoparticles, different types of laboratory experiments were carried-out, including coreflooding tests on the oilfield cores by using the facility with parallel coreholders for stand modelling of the developed technology in the IOP. The main task of the IOP technology is to redistribute the filtration inflows in the near-wellbore zone by selectively blocking the most permeable water-saturated intervals and to penerate through the less permeable inter-layers of the bottomhole zone by the acid composition.
{"title":"Innovative Water-Blocking Agent Based on High Stable Emulsion with Nanoparticles for IOR Implementation","authors":"V. Sergeev, Ijung Kim, Juri Zeigman, R. Yakubov","doi":"10.2118/192742-MS","DOIUrl":"https://doi.org/10.2118/192742-MS","url":null,"abstract":"\u0000 This article represents the results of the research and development project that has been conducted with the goal to create an innovative and environmental water-blocking agent for the enhancement efficiency of the improved oil recovery methods. The innovation of the developed water-blocking agent lies in the combination of unique physical and chemical properties: high thermal stability (140 °C), improved rheology (viscoplastic properties), outstanding surface activity (regulation of the wettability of rock surface), and selective blocking effect. The key factor to combine all of these properties in one solution is to apply colloidal silicon dioxide nanoparticles with modified surface as a stabilizer and surface-active phase in the emulsion system. Also, a technology on the new water-blocking agent for the effective application in the intensification of oil production (well stimulation, IOP) methods has been developed, and well-tested in the field. For the investigation of the unique properties of the new emulsion systems with colloidal silicon dioxide nanoparticles, different types of laboratory experiments were carried-out, including coreflooding tests on the oilfield cores by using the facility with parallel coreholders for stand modelling of the developed technology in the IOP. The main task of the IOP technology is to redistribute the filtration inflows in the near-wellbore zone by selectively blocking the most permeable water-saturated intervals and to penerate through the less permeable inter-layers of the bottomhole zone by the acid composition.","PeriodicalId":11208,"journal":{"name":"Day 2 Tue, November 13, 2018","volume":"57 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"91526392","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}
Schlumberger has developed a unique PN-1 membrane technology in collaboration with Petronas. The technology is unique in combining two distinct types of membrane fibers in one single membrane module to reduce the overall membrane requirement by 10% and offers overall CAPEX and OPEX savings. The PN-1 technology was developed in 2009 and was successfully tested onshore and offshore facilities for total 5 years. The PN-1 technology was first deployed in an onshore gas processing facility which was awarded to Schlumberger in 2013. The facility comprised of membrane pretreatment which is mainly gas dehydration, dew pointing followed by several PN-1 membranes in first stage. The membrane design was unique to handle variable inlet feed conditions from 25 to 12% CO2 inlet gas and outlet gas at 8% CO2. The feed gas design flowrate is 700 MMSCFD and at 750 psig operating pressure. Since this is an onshore gas receiving station, the processing trains should be able to handle variable inlet CO2 concentration in the inlet feed gas and particularly membranes. Schlumberger engineered the entire pretreatment system, membrane and mercaptan removal system. The entire system was delivered and commissioned by Schlumberger on time and was brought online in 2017. The PN-1 membrane system was successful in meeting the required outlet gas CO2 specification while retaining maximum hydrocarbons in the product gas.
{"title":"Unique Dual Core Acid Gas Removal Membrane Technology Reduces Total Cost of Ownership for South East Asia Gas Plant","authors":"A. Jariwala, D. Knight, En M Faudzi Mat Isa","doi":"10.2118/192691-MS","DOIUrl":"https://doi.org/10.2118/192691-MS","url":null,"abstract":"\u0000 Schlumberger has developed a unique PN-1 membrane technology in collaboration with Petronas. The technology is unique in combining two distinct types of membrane fibers in one single membrane module to reduce the overall membrane requirement by 10% and offers overall CAPEX and OPEX savings. The PN-1 technology was developed in 2009 and was successfully tested onshore and offshore facilities for total 5 years.\u0000 The PN-1 technology was first deployed in an onshore gas processing facility which was awarded to Schlumberger in 2013. The facility comprised of membrane pretreatment which is mainly gas dehydration, dew pointing followed by several PN-1 membranes in first stage. The membrane design was unique to handle variable inlet feed conditions from 25 to 12% CO2 inlet gas and outlet gas at 8% CO2. The feed gas design flowrate is 700 MMSCFD and at 750 psig operating pressure. Since this is an onshore gas receiving station, the processing trains should be able to handle variable inlet CO2 concentration in the inlet feed gas and particularly membranes.\u0000 Schlumberger engineered the entire pretreatment system, membrane and mercaptan removal system. The entire system was delivered and commissioned by Schlumberger on time and was brought online in 2017. The PN-1 membrane system was successful in meeting the required outlet gas CO2 specification while retaining maximum hydrocarbons in the product gas.","PeriodicalId":11208,"journal":{"name":"Day 2 Tue, November 13, 2018","volume":"85 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86952605","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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