The Experts below are selected from a list of 288 Experts worldwide ranked by ideXlab platform
Alireza Ahadori - One of the best experts on this subject based on the ideXlab platform.
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a computational intelligence scheme for prediction equilibrium water dew point of Natural Gas in teg dehydration systems
Fuel, 2014Co-Authors: Mohammad Ali Ahmadi, Reza Soleimani, Alireza AhadoriAbstract:Abstract Raw Natural Gases are frequently saturated with water during production operations. It is crucial to remove water from Natural Gas using dehydration process in order to eliminate safety concerns as well as for economic reasons. Triethylene glycol (TEG) dehydration units are the most common type of Natural Gas dehydration. Making an assessment of a TEG system takes in first ascertaining the minimum TEG concentration needed to fulfill the water content and dew point specifications of the pipeline system. A flexible and reliable method in modeling such a process is of the essence from Gas engineering view point and the current contribution is an attempt in this respect. Artificial neural networks (ANNs) trained with particle swarm optimization (PSO) and back-propagation algorithm (BP) were employed to estimate the equilibrium water dew point of a Natural Gas Stream with a TEG solution at different TEG concentrations and temperatures. PSO and BP were used to optimize the weights and biases of networks. The models were made based upon literature database covering VLE data for TEG–water system for contactor temperatures between 10 °C and 80 °C and TEG concentrations ranging from 90.00 to 99.999 wt%. Results showed PSO-ANN accomplishes more reliable outputs compared with BP-ANN in terms of statistical criteria.
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rapid estimation of equilibrium water dew point of Natural Gas in teg dehydration systems
Journal of Natural Gas Science and Engineering, 2009Co-Authors: Alireza Ahadori, Hari VuthaluruAbstract:Abstract Evaluation of a triethylene glycol (TEG) system involves first establishing the minimum triethylene glycol (TEG) concentration required to meet the outlet Gas water dew point specification. In the present work, simple-to-use correlation, which is simpler than currently available models involving a large number of parameters, requiring more complicated and longer computations, has been developed for the rapid estimation of the water dew point of a Natural Gas Stream in equilibrium with a TEG solution at various temperatures and TEG concentrations. This correlation can be used to estimate the required TEG concentration for a particular application or the theoretical dew point depression for a given TEG concentration and contactor temperature. Actual outlet dewpoints depend on the TEG circulation rate and number of equilibrium stages, but typical approaches to equilibrium are 6–11 °C. Equilibrium dewpoints are relatively insensitive to pressure and this correlation may be used up to 10 300 kPa (abs) with little error. The proposed correlation covers VLE data for TEG–water system for contactor temperatures between 10 °C and 80 °C and TEG concentrations ranging from 90.00 to 99.999 wt%. The average absolute deviation percent from the data reported in the literature is 0.5% which shows the excellent performance of proposed correlation. This simple-to-use correlation can be of immense practical value for the Gas engineers to have a quick check on equilibrium water dew point of Natural Gas at various temperatures and TEG weight percents. In particular, personnel dealing with Natural Gas dehydration and processing would find the proposed approach to be user friendly involving no complex expressions with transparent calculations.
Jaime A. Valencia - One of the best experts on this subject based on the ideXlab platform.
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CO2 management at ExxonMobil’s LaBarge field, Wyoming, USA
Energy Procedia, 2011Co-Authors: P.e. Michael E. Parker, Scott Northrop, Jaime A. Valencia, Robert E. Foglesong, William T. DuncanAbstract:Abstract Production of Natural Gas from the LaBarge field in southwest Wyoming began in 1986. This Gas contains high concentrations of carbon dioxide (CO 2 ), and from the very beginning, ExxonMobil has successfully implemented several technologies and approaches to effectively manage the substantial volumes of CO 2 associated with its production. Many of the technologies and approaches used for managing CO 2 at LaBarge are examples of technologies and approaches being proposed for use in carbon capture and storage (CCS) by other industries. The Shute Creek Treating Facility (SCTF) processes the Gas produced from the LaBarge field. The SCTF handles the lowest hydrocarbon content Natural Gas commercially produced in the world. The Gas composition entering Shute Creek is 65% CO 2 , 21% methane, 7% nitrogen, 5% hydrogen sulfide (H 2 S) and 0.6% helium. The SCTF separates CO 2 , methane, and helium for sale and removes hydrogen sulfide for disposal. Most of the CO 2 captured at Shute Creek is used for enhanced oil recovery (EOR). EOR is consistently cited as one of the most viable early opportunities for large scale implementation of CCS. ExxonMobil’s LaBarge operation is the largest deployment of this approach to CCS in the world today. Currently ExxonMobil provides 4 to 5 million tonnes per year of CO 2 for EOR. Ongoing facility expansion will increase this capacity to over 7 million tonnes per year in 2010. A concentrated acid Gas Stream of about 60% hydrogen sulfide and 40% CO 2 is injected into a carefully selected section of the same reservoir from which it was produced, safely disposing of the hydrogen sulfide along with approximately 400,000 tonnes of CO 2 per year. Other technologies and approaches that have reduced CO 2 emissions include the ExxonMobil patented low BTU fuel co-generation system that substantially reduces CO 2 emissions when compared to emissions from purchased power. Cumulatively, through the application of these technologies at LaBarge, ExxonMobil will have the capacity to capture and manage over 75% of the CO 2 produced from the LaBarge field. Additionally, new technologies are being developed that may provide additional reductions in emissions, either at this site or at others with similarly challenged production Streams. Construction of a commercial demonstration facility for ExxonMobil’s Controlled Freeze Zone TM (CFZ) Gas treatment technology has been completed at Shute Creek and operations are about to begin. The CFZ TM technology allows the single step separation of CO 2 and other contaminants from a Natural Gas Stream without the use of solvents or absorbents. Its successful commercial demonstration would enable the development of increasingly sour Gas resources around the world by substantially reducing Gas treatment and geo-sequestration costs from these sources.
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co2 management at exxonmobil s labarge field wyoming usa
Energy Procedia, 2011Co-Authors: P Michael E E Parker, Scott Northrop, Jaime A. Valencia, Robert E. Foglesong, William T. DuncanAbstract:Abstract Production of Natural Gas from the LaBarge field in southwest Wyoming began in 1986. This Gas contains high concentrations of carbon dioxide (CO 2 ), and from the very beginning, ExxonMobil has successfully implemented several technologies and approaches to effectively manage the substantial volumes of CO 2 associated with its production. Many of the technologies and approaches used for managing CO 2 at LaBarge are examples of technologies and approaches being proposed for use in carbon capture and storage (CCS) by other industries. The Shute Creek Treating Facility (SCTF) processes the Gas produced from the LaBarge field. The SCTF handles the lowest hydrocarbon content Natural Gas commercially produced in the world. The Gas composition entering Shute Creek is 65% CO 2 , 21% methane, 7% nitrogen, 5% hydrogen sulfide (H 2 S) and 0.6% helium. The SCTF separates CO 2 , methane, and helium for sale and removes hydrogen sulfide for disposal. Most of the CO 2 captured at Shute Creek is used for enhanced oil recovery (EOR). EOR is consistently cited as one of the most viable early opportunities for large scale implementation of CCS. ExxonMobil’s LaBarge operation is the largest deployment of this approach to CCS in the world today. Currently ExxonMobil provides 4 to 5 million tonnes per year of CO 2 for EOR. Ongoing facility expansion will increase this capacity to over 7 million tonnes per year in 2010. A concentrated acid Gas Stream of about 60% hydrogen sulfide and 40% CO 2 is injected into a carefully selected section of the same reservoir from which it was produced, safely disposing of the hydrogen sulfide along with approximately 400,000 tonnes of CO 2 per year. Other technologies and approaches that have reduced CO 2 emissions include the ExxonMobil patented low BTU fuel co-generation system that substantially reduces CO 2 emissions when compared to emissions from purchased power. Cumulatively, through the application of these technologies at LaBarge, ExxonMobil will have the capacity to capture and manage over 75% of the CO 2 produced from the LaBarge field. Additionally, new technologies are being developed that may provide additional reductions in emissions, either at this site or at others with similarly challenged production Streams. Construction of a commercial demonstration facility for ExxonMobil’s Controlled Freeze Zone TM (CFZ) Gas treatment technology has been completed at Shute Creek and operations are about to begin. The CFZ TM technology allows the single step separation of CO 2 and other contaminants from a Natural Gas Stream without the use of solvents or absorbents. Its successful commercial demonstration would enable the development of increasingly sour Gas resources around the world by substantially reducing Gas treatment and geo-sequestration costs from these sources.
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worldwide development potential for sour Gas
Energy Procedia, 2011Co-Authors: W F J Burgers, P S Northrop, Haroon S Kheshgi, Jaime A. ValenciaAbstract:Abstract In this study, we summarize data on the location and scale of proven and probable sour Gas resources and compare with size and location of oil fields. This provides an indication of the location and scale of opportunities to gain further experience in the application of CCS. This by using captured carbon dioxide (CO 2 ) from sour Gas resources, which are presently undeveloped or underdeveloped, for carbon dioxide enhanced oil recovery (CO 2 -EOR). Currently there are globally many undeveloped or underdeveloped sour Gas accumulations containing a significant fraction of CO 2 . The high CO 2 content between 15% and 80%, as well as in some cases the addition of hydrogen sulfide (H 2 S), severely limits the economic and environmental viability of sour Gas resources. Globally a total resource of around 4 trillion m 3 of net hydrocarbon Gas and 15000 MT of associated CO 2 has been identified. This was done by summing individual undeveloped and underdeveloped fields with ultimate recoverable proven and probable resources larger than 14 billion m 3 each of net hydrocarbon Gas and CO 2 content between 15% and 80%. Development of these fields could be enabled by the availability of a cost effective Gas separation method such as the Controlled Freeze Zone TM (CFZ) technology, and of viable CO 2 enhanced oil recovery opportunities (CO 2 -EOR) to reduce the cost of CO 2 capture, transportation and storage. Sour Gas resources have been mapped globally using the IHS fields and reservoirs database from 2009. The largest concentrations of sour Gas are located in SE Asia & NW Australia, Central USA, Middle East and North Africa. In the USA, Middle East and North Africa, which are oil rich, there is significant potential for CO 2 -EOR opportunities. The relative absence of significant oil accumulations in SE Asia & NW Australia will in many cases require the storage of CO 2 in saline aquifers, as is planned for the Gorgon field in Australia. The challenges of developing Natural Gas fields with a high CO 2 content can be best illustrated by ExxonMobil’s development of the LaBarge field. This field, located in SW Wyoming, USA, was discovered in 1963, but production was delayed until 1986 because of the challenging Gas composition of 65% carbon dioxide, 21% methane, 7% nitrogen, 5% hydrogen sulfide, and 0.6% helium. It is the lowest hydrocarbon content Natural Gas commercially produced in the world. Currently the majority of the recovered CO 2 is transported and sold to EOR operators. Additionally, construction of a commercial demonstration facility for ExxonMobil’s Controlled Freeze Zone™ (CFZ) Gas treatment technology has been completed at Shute Creek, Wyoming. The CFZ™ technology allows the single step separation of CO 2 and other contaminants from a Natural Gas Stream without the use of solvents or absorbents.
Hari Vuthaluru - One of the best experts on this subject based on the ideXlab platform.
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rapid estimation of equilibrium water dew point of Natural Gas in teg dehydration systems
Journal of Natural Gas Science and Engineering, 2009Co-Authors: Alireza Ahadori, Hari VuthaluruAbstract:Abstract Evaluation of a triethylene glycol (TEG) system involves first establishing the minimum triethylene glycol (TEG) concentration required to meet the outlet Gas water dew point specification. In the present work, simple-to-use correlation, which is simpler than currently available models involving a large number of parameters, requiring more complicated and longer computations, has been developed for the rapid estimation of the water dew point of a Natural Gas Stream in equilibrium with a TEG solution at various temperatures and TEG concentrations. This correlation can be used to estimate the required TEG concentration for a particular application or the theoretical dew point depression for a given TEG concentration and contactor temperature. Actual outlet dewpoints depend on the TEG circulation rate and number of equilibrium stages, but typical approaches to equilibrium are 6–11 °C. Equilibrium dewpoints are relatively insensitive to pressure and this correlation may be used up to 10 300 kPa (abs) with little error. The proposed correlation covers VLE data for TEG–water system for contactor temperatures between 10 °C and 80 °C and TEG concentrations ranging from 90.00 to 99.999 wt%. The average absolute deviation percent from the data reported in the literature is 0.5% which shows the excellent performance of proposed correlation. This simple-to-use correlation can be of immense practical value for the Gas engineers to have a quick check on equilibrium water dew point of Natural Gas at various temperatures and TEG weight percents. In particular, personnel dealing with Natural Gas dehydration and processing would find the proposed approach to be user friendly involving no complex expressions with transparent calculations.
Mohammad Ali Ahmadi - One of the best experts on this subject based on the ideXlab platform.
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Prediction performance of Natural Gas dehydration units for water removal efficiency using a least-square support vector machine
International Journal of Ambient Energy, 2015Co-Authors: Mohammad Ali Ahmadi, Alireza BahadoriAbstract:Natural Gas dehydration unit is employed to eliminate water from Natural Gas liquids and Natural Gas, and it is needed to avoid condensation of free water and creation of hydrates in transportation and processing facilities, prevent corrosion, and meet a water content condition. In this paper, a least-square support vector machine (LSSVM) coupled with genetic algorithm (GA) was employed to estimate the water dew point of a Natural Gas Stream in equilibrium with a triethylene glycol (TEG) solution at different TEG concentrations and temperatures. Results showed that GA–LSSVM accomplishes more reliable outputs compared with real recorded data in terms of statistical criteria.
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a computational intelligence scheme for prediction equilibrium water dew point of Natural Gas in teg dehydration systems
Fuel, 2014Co-Authors: Mohammad Ali Ahmadi, Reza Soleimani, Alireza AhadoriAbstract:Abstract Raw Natural Gases are frequently saturated with water during production operations. It is crucial to remove water from Natural Gas using dehydration process in order to eliminate safety concerns as well as for economic reasons. Triethylene glycol (TEG) dehydration units are the most common type of Natural Gas dehydration. Making an assessment of a TEG system takes in first ascertaining the minimum TEG concentration needed to fulfill the water content and dew point specifications of the pipeline system. A flexible and reliable method in modeling such a process is of the essence from Gas engineering view point and the current contribution is an attempt in this respect. Artificial neural networks (ANNs) trained with particle swarm optimization (PSO) and back-propagation algorithm (BP) were employed to estimate the equilibrium water dew point of a Natural Gas Stream with a TEG solution at different TEG concentrations and temperatures. PSO and BP were used to optimize the weights and biases of networks. The models were made based upon literature database covering VLE data for TEG–water system for contactor temperatures between 10 °C and 80 °C and TEG concentrations ranging from 90.00 to 99.999 wt%. Results showed PSO-ANN accomplishes more reliable outputs compared with BP-ANN in terms of statistical criteria.
William T. Duncan - One of the best experts on this subject based on the ideXlab platform.
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CO2 management at ExxonMobil’s LaBarge field, Wyoming, USA
Energy Procedia, 2011Co-Authors: P.e. Michael E. Parker, Scott Northrop, Jaime A. Valencia, Robert E. Foglesong, William T. DuncanAbstract:Abstract Production of Natural Gas from the LaBarge field in southwest Wyoming began in 1986. This Gas contains high concentrations of carbon dioxide (CO 2 ), and from the very beginning, ExxonMobil has successfully implemented several technologies and approaches to effectively manage the substantial volumes of CO 2 associated with its production. Many of the technologies and approaches used for managing CO 2 at LaBarge are examples of technologies and approaches being proposed for use in carbon capture and storage (CCS) by other industries. The Shute Creek Treating Facility (SCTF) processes the Gas produced from the LaBarge field. The SCTF handles the lowest hydrocarbon content Natural Gas commercially produced in the world. The Gas composition entering Shute Creek is 65% CO 2 , 21% methane, 7% nitrogen, 5% hydrogen sulfide (H 2 S) and 0.6% helium. The SCTF separates CO 2 , methane, and helium for sale and removes hydrogen sulfide for disposal. Most of the CO 2 captured at Shute Creek is used for enhanced oil recovery (EOR). EOR is consistently cited as one of the most viable early opportunities for large scale implementation of CCS. ExxonMobil’s LaBarge operation is the largest deployment of this approach to CCS in the world today. Currently ExxonMobil provides 4 to 5 million tonnes per year of CO 2 for EOR. Ongoing facility expansion will increase this capacity to over 7 million tonnes per year in 2010. A concentrated acid Gas Stream of about 60% hydrogen sulfide and 40% CO 2 is injected into a carefully selected section of the same reservoir from which it was produced, safely disposing of the hydrogen sulfide along with approximately 400,000 tonnes of CO 2 per year. Other technologies and approaches that have reduced CO 2 emissions include the ExxonMobil patented low BTU fuel co-generation system that substantially reduces CO 2 emissions when compared to emissions from purchased power. Cumulatively, through the application of these technologies at LaBarge, ExxonMobil will have the capacity to capture and manage over 75% of the CO 2 produced from the LaBarge field. Additionally, new technologies are being developed that may provide additional reductions in emissions, either at this site or at others with similarly challenged production Streams. Construction of a commercial demonstration facility for ExxonMobil’s Controlled Freeze Zone TM (CFZ) Gas treatment technology has been completed at Shute Creek and operations are about to begin. The CFZ TM technology allows the single step separation of CO 2 and other contaminants from a Natural Gas Stream without the use of solvents or absorbents. Its successful commercial demonstration would enable the development of increasingly sour Gas resources around the world by substantially reducing Gas treatment and geo-sequestration costs from these sources.
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co2 management at exxonmobil s labarge field wyoming usa
Energy Procedia, 2011Co-Authors: P Michael E E Parker, Scott Northrop, Jaime A. Valencia, Robert E. Foglesong, William T. DuncanAbstract:Abstract Production of Natural Gas from the LaBarge field in southwest Wyoming began in 1986. This Gas contains high concentrations of carbon dioxide (CO 2 ), and from the very beginning, ExxonMobil has successfully implemented several technologies and approaches to effectively manage the substantial volumes of CO 2 associated with its production. Many of the technologies and approaches used for managing CO 2 at LaBarge are examples of technologies and approaches being proposed for use in carbon capture and storage (CCS) by other industries. The Shute Creek Treating Facility (SCTF) processes the Gas produced from the LaBarge field. The SCTF handles the lowest hydrocarbon content Natural Gas commercially produced in the world. The Gas composition entering Shute Creek is 65% CO 2 , 21% methane, 7% nitrogen, 5% hydrogen sulfide (H 2 S) and 0.6% helium. The SCTF separates CO 2 , methane, and helium for sale and removes hydrogen sulfide for disposal. Most of the CO 2 captured at Shute Creek is used for enhanced oil recovery (EOR). EOR is consistently cited as one of the most viable early opportunities for large scale implementation of CCS. ExxonMobil’s LaBarge operation is the largest deployment of this approach to CCS in the world today. Currently ExxonMobil provides 4 to 5 million tonnes per year of CO 2 for EOR. Ongoing facility expansion will increase this capacity to over 7 million tonnes per year in 2010. A concentrated acid Gas Stream of about 60% hydrogen sulfide and 40% CO 2 is injected into a carefully selected section of the same reservoir from which it was produced, safely disposing of the hydrogen sulfide along with approximately 400,000 tonnes of CO 2 per year. Other technologies and approaches that have reduced CO 2 emissions include the ExxonMobil patented low BTU fuel co-generation system that substantially reduces CO 2 emissions when compared to emissions from purchased power. Cumulatively, through the application of these technologies at LaBarge, ExxonMobil will have the capacity to capture and manage over 75% of the CO 2 produced from the LaBarge field. Additionally, new technologies are being developed that may provide additional reductions in emissions, either at this site or at others with similarly challenged production Streams. Construction of a commercial demonstration facility for ExxonMobil’s Controlled Freeze Zone TM (CFZ) Gas treatment technology has been completed at Shute Creek and operations are about to begin. The CFZ TM technology allows the single step separation of CO 2 and other contaminants from a Natural Gas Stream without the use of solvents or absorbents. Its successful commercial demonstration would enable the development of increasingly sour Gas resources around the world by substantially reducing Gas treatment and geo-sequestration costs from these sources.
