Pub Date : 2017-12-29DOI: 10.7569/jnge.2017.692505
Qing Bian, D. Paradine, K. Wreford, Jennifer Eby, Y. Jamin, P. Sriram
Abstract This article presents new methods for accurately determining quantities of acid gas (CO2 and H2S) removed from acid gas removal (AGR) units in natural gas processing plants, and their applications to actual production data, with an emphasis on CO2 quantity determination. Greenhouse gas (GHG) emissions from anthropogenic activities contribute to climate change. The natural gas sector releases significant quantities of GHGs. AGR is a key step in natural gas processing, whereby H2S and CO2 are stripped from raw natural gas. Determining accurate CO2 emission quantities arising from AGR units has been challenging in the context of GHG emission quantification. The US Environmental Protection Agency and the Western Climate Initiative have each developed GHG quantification methods for petroleum and natural gas systems which include the AGR process. However, there is uncertainty about the accuracy of these approaches since not all aspects of the AGR process are taken into consideration. The proposed new methods for AGR GHG quantification are assessed using production data over three years from three natural gas plants. Assuming all other process factors are held constant, quantities of removed acid gas are functions of: •CO2 and H2S content in the inlet and outlet gas streams; and •the gas volume of either the inlet or outlet stream, depending on which quantification method is used. It is revealed that two main factors contribute to inaccurate GHG quantification from AGR units in practice so far: •the use of inlet gas stream volume instead of outlet gas stream volume; and, •failure to account for H2S content in the gas. In this study, inaccurately measured inlet gas stream volume was the primary cause of AGR CO2 quantification error and uncertainty. All calculation methods using inlet gas stream volume overestimated the CO2 quantity removed from an AGR unit by 3–11%. Quantification accuracy using volumes measured by inlet gas meters is limited because there is commonly a loss of gas volume from the inlet stream before it enters an AGR unit, and acid gas corrodes the metals in gas stream meters, which reduces meter accuracy. The H2S content of raw natural gas also has a significant impact on the accuracy of AGR CO2 removal quantification. Results show that methods using outlet gas stream volume without considering H2S content underestimate removed CO2 quantity by a factor of 1.1 times the H2S content in inlet gas stream. The error induced by this method linearly correlates to H2S content in the inlet gas stream. The higher the H2S content in the inlet stream, the larger the error. Calculation using outlet gas stream volume and H2S content in both inlet and outlet gas streams is recommended as a default method for quantifying GHG emissions from AGR units. Meanwhile, quantification methods for removed hydrogen sulfide (H2S) are also presented from the AGR process.
{"title":"Application of Accurate Quantification Methods for Determining Emissions from the Acid Gas Removal Process in Natural Gas Processing","authors":"Qing Bian, D. Paradine, K. Wreford, Jennifer Eby, Y. Jamin, P. Sriram","doi":"10.7569/jnge.2017.692505","DOIUrl":"https://doi.org/10.7569/jnge.2017.692505","url":null,"abstract":"Abstract This article presents new methods for accurately determining quantities of acid gas (CO2 and H2S) removed from acid gas removal (AGR) units in natural gas processing plants, and their applications to actual production data, with an emphasis on CO2 quantity determination. Greenhouse gas (GHG) emissions from anthropogenic activities contribute to climate change. The natural gas sector releases significant quantities of GHGs. AGR is a key step in natural gas processing, whereby H2S and CO2 are stripped from raw natural gas. Determining accurate CO2 emission quantities arising from AGR units has been challenging in the context of GHG emission quantification. The US Environmental Protection Agency and the Western Climate Initiative have each developed GHG quantification methods for petroleum and natural gas systems which include the AGR process. However, there is uncertainty about the accuracy of these approaches since not all aspects of the AGR process are taken into consideration. The proposed new methods for AGR GHG quantification are assessed using production data over three years from three natural gas plants. Assuming all other process factors are held constant, quantities of removed acid gas are functions of: •CO2 and H2S content in the inlet and outlet gas streams; and •the gas volume of either the inlet or outlet stream, depending on which quantification method is used. It is revealed that two main factors contribute to inaccurate GHG quantification from AGR units in practice so far: •the use of inlet gas stream volume instead of outlet gas stream volume; and, •failure to account for H2S content in the gas. In this study, inaccurately measured inlet gas stream volume was the primary cause of AGR CO2 quantification error and uncertainty. All calculation methods using inlet gas stream volume overestimated the CO2 quantity removed from an AGR unit by 3–11%. Quantification accuracy using volumes measured by inlet gas meters is limited because there is commonly a loss of gas volume from the inlet stream before it enters an AGR unit, and acid gas corrodes the metals in gas stream meters, which reduces meter accuracy. The H2S content of raw natural gas also has a significant impact on the accuracy of AGR CO2 removal quantification. Results show that methods using outlet gas stream volume without considering H2S content underestimate removed CO2 quantity by a factor of 1.1 times the H2S content in inlet gas stream. The error induced by this method linearly correlates to H2S content in the inlet gas stream. The higher the H2S content in the inlet stream, the larger the error. Calculation using outlet gas stream volume and H2S content in both inlet and outlet gas streams is recommended as a default method for quantifying GHG emissions from AGR units. Meanwhile, quantification methods for removed hydrogen sulfide (H2S) are also presented from the AGR process.","PeriodicalId":22694,"journal":{"name":"The Journal of Natural Gas Engineering","volume":"126 1","pages":"111 - 133"},"PeriodicalIF":0.0,"publicationDate":"2017-12-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88653743","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}
Pub Date : 2017-06-21DOI: 10.7569/jnge.2016.692508
Xiao Cai, B. Guo
Abstract The use of hydraulic fracturing has been greatly increased in the petroleum industry over the past few decades. However, the issue of screen-out has remained since proppants were first used in hydraulic fracturing. Due to the serious consequences caused by the screen-out, it is desirable to avoid or delay it where possible in the implementation process of hydraulic fracturing. This paper provides a mathematical method for estimating the screen-out time during hydraulic fracturing in vertical wells. The model result is consistent with field observations. Sensitivity analyses in this paper show that the viscosity of the fracturing fluid, proppant density, injection rate and ratio of proppant volume to fracturing fluid volume significantly affect the screen-out time and characteristics of the proppant pile. This model can be used as a general tool for optimizing fracturing parameters in vertical wells in order to minimize the screen-out effect.
{"title":"Semi Analytical Model for Predicting Screen-out in Hydraulic Fracturing in Vertical Wells","authors":"Xiao Cai, B. Guo","doi":"10.7569/jnge.2016.692508","DOIUrl":"https://doi.org/10.7569/jnge.2016.692508","url":null,"abstract":"Abstract The use of hydraulic fracturing has been greatly increased in the petroleum industry over the past few decades. However, the issue of screen-out has remained since proppants were first used in hydraulic fracturing. Due to the serious consequences caused by the screen-out, it is desirable to avoid or delay it where possible in the implementation process of hydraulic fracturing. This paper provides a mathematical method for estimating the screen-out time during hydraulic fracturing in vertical wells. The model result is consistent with field observations. Sensitivity analyses in this paper show that the viscosity of the fracturing fluid, proppant density, injection rate and ratio of proppant volume to fracturing fluid volume significantly affect the screen-out time and characteristics of the proppant pile. This model can be used as a general tool for optimizing fracturing parameters in vertical wells in order to minimize the screen-out effect.","PeriodicalId":22694,"journal":{"name":"The Journal of Natural Gas Engineering","volume":"3 1","pages":"1 - 19"},"PeriodicalIF":0.0,"publicationDate":"2017-06-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90182535","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}
Pub Date : 2017-06-21DOI: 10.7569/jnge.2017.692502
Yue Hu, T. Makogon, P. Karanjkar, Kun-Hong Lee, B. Lee, A. Sum
Abstract We report methane (structure I) and methane/ethane (structure II) hydrate phase equilibrium data with calcium bromide (32 wt%) and a mixture of calcium bromide (20 wt%) + monoethylene glycol (20 wt%) solutions for pressures up to 200 MPa. As expected for thermodynamic hydrate inhibitors, the salt and glycol cause the hydrate phase equilibrium boundary to shift to lower temperatures and higher pressures. These data are the first to be reported for these systems, which are particularly useful as calcium bromide is widely used in drilling fluids and hydrate formation is a growing concern in well completion and workover fluids. The measured experimental data were compared with commonly used hydrate prediction tools to assess their reliability.
{"title":"Gas Hydrates Phase Equilibrium with CaBr2 and CaBr2 + MEG at Ultra-High Pressures","authors":"Yue Hu, T. Makogon, P. Karanjkar, Kun-Hong Lee, B. Lee, A. Sum","doi":"10.7569/jnge.2017.692502","DOIUrl":"https://doi.org/10.7569/jnge.2017.692502","url":null,"abstract":"Abstract We report methane (structure I) and methane/ethane (structure II) hydrate phase equilibrium data with calcium bromide (32 wt%) and a mixture of calcium bromide (20 wt%) + monoethylene glycol (20 wt%) solutions for pressures up to 200 MPa. As expected for thermodynamic hydrate inhibitors, the salt and glycol cause the hydrate phase equilibrium boundary to shift to lower temperatures and higher pressures. These data are the first to be reported for these systems, which are particularly useful as calcium bromide is widely used in drilling fluids and hydrate formation is a growing concern in well completion and workover fluids. The measured experimental data were compared with commonly used hydrate prediction tools to assess their reliability.","PeriodicalId":22694,"journal":{"name":"The Journal of Natural Gas Engineering","volume":"41 1","pages":"42 - 49"},"PeriodicalIF":0.0,"publicationDate":"2017-06-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"81069562","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}
Pub Date : 2017-06-21DOI: 10.7569/jnge.2017.692504
B. E. Roberts
Abstract Sulfur deposition in the reservoir formation and its impact on well productivity and ultimate recovery has been investigated for close to 50 years. Experimental measurements and numerical modeling studies have focused on the phase behavior of the sulfur-sour gas mixture system and the flow of sulfur and natural gas through the formation. The key results from these investigations are reviewed in this paper. The implementation of the insights gained over these 50 years of research into the field development planning and operation of sour gas fields is described.
{"title":"Flow Impairment by Deposited Sulfur - A Review of 50 Years of Research","authors":"B. E. Roberts","doi":"10.7569/jnge.2017.692504","DOIUrl":"https://doi.org/10.7569/jnge.2017.692504","url":null,"abstract":"Abstract Sulfur deposition in the reservoir formation and its impact on well productivity and ultimate recovery has been investigated for close to 50 years. Experimental measurements and numerical modeling studies have focused on the phase behavior of the sulfur-sour gas mixture system and the flow of sulfur and natural gas through the formation. The key results from these investigations are reviewed in this paper. The implementation of the insights gained over these 50 years of research into the field development planning and operation of sour gas fields is described.","PeriodicalId":22694,"journal":{"name":"The Journal of Natural Gas Engineering","volume":"20 1","pages":"105 - 84"},"PeriodicalIF":0.0,"publicationDate":"2017-06-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89678208","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}
Pub Date : 2017-06-21DOI: 10.7569/jnge.2017.692501
Jianli Li, Gang Zhao
Abstract Traditional well test models for CO2 flooding neglect dynamic mass transfer and over-simplify transient viscosity in a transition zone, making them unable to deal with more complicated and heterogeneous field situations. To eliminate this restriction/limitation, this study proposes a comprehensive transient pressure model that incorporates a convection– diffusion mass transfer process. It actually is an enhanced three-region composite model that includes CO2 bank, transition zone, and oil zone. Type curves are plotted and four flow regimes are identified: early radial flow, transition flow, pseudo-radial flow, and boundary-dominated flow. In addition, it is found that mass transfer mainly leads the transition flow regime to slower slope change, and pseudo radial flow regime with lower straight line compared with a case neglects the mass transfer in a transition zone. Moreover, it shows that a smaller injection rate and a longer injection period are better for viscosity reduction than a larger injection rate and a shorter injection period.
{"title":"Modeling of Transient Pressure Response for CO2 Flooding Process by Integrating Convection and Diffusion Driven Mass Transfer","authors":"Jianli Li, Gang Zhao","doi":"10.7569/jnge.2017.692501","DOIUrl":"https://doi.org/10.7569/jnge.2017.692501","url":null,"abstract":"Abstract Traditional well test models for CO2 flooding neglect dynamic mass transfer and over-simplify transient viscosity in a transition zone, making them unable to deal with more complicated and heterogeneous field situations. To eliminate this restriction/limitation, this study proposes a comprehensive transient pressure model that incorporates a convection– diffusion mass transfer process. It actually is an enhanced three-region composite model that includes CO2 bank, transition zone, and oil zone. Type curves are plotted and four flow regimes are identified: early radial flow, transition flow, pseudo-radial flow, and boundary-dominated flow. In addition, it is found that mass transfer mainly leads the transition flow regime to slower slope change, and pseudo radial flow regime with lower straight line compared with a case neglects the mass transfer in a transition zone. Moreover, it shows that a smaller injection rate and a longer injection period are better for viscosity reduction than a larger injection rate and a shorter injection period.","PeriodicalId":22694,"journal":{"name":"The Journal of Natural Gas Engineering","volume":"18 1","pages":"20 - 41"},"PeriodicalIF":0.0,"publicationDate":"2017-06-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82539896","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}
Pub Date : 2017-05-06DOI: 10.7569/jnge.2017.692503
W. Wermink, N. Ramachandran, G. Versteeg
Abstract Vitrisol®, a novel desulphurization process that is 100% selective for H2S removal from industrial gases containing CO2, can be described with the following overall reaction equation: H2S+0.5O2→H2O+SO(s) $${H_2}S + 0.5{O_2} to {H_2}O + {S^O}(s)$$ The performance of Vitrisol® is demonstrated for two typical applications in shale gas production by comparing them to a standard amine treating process. The remainder toxic, acid gas produced by the latter technology is compressed for acid gas injection. From the results it can be concluded that significant reductions in utilities can be achieved by using Vitrisol® as depicted in the energy consumptions of the overall process. Contrary to the amine process, Vitrisol® does not require additional treatment of the non-toxic off-gas stream as the H2S is directly converted to crystalline sulphur. This study illustrates clearly that it is advantageous to first remove H2S from a gas stream containing both H2S and CO2 prior to CO2 removal to reduce utilities consumption.
Vitrisol®是一种新型的脱硫工艺% selective for H2S removal from industrial gases containing CO2, can be described with the following overall reaction equation: H2S+0.5O2→H2O+SO(s) $${H_2}S + 0.5{O_2} to {H_2}O + {S^O}(s)$$ The performance of Vitrisol® is demonstrated for two typical applications in shale gas production by comparing them to a standard amine treating process. The remainder toxic, acid gas produced by the latter technology is compressed for acid gas injection. From the results it can be concluded that significant reductions in utilities can be achieved by using Vitrisol® as depicted in the energy consumptions of the overall process. Contrary to the amine process, Vitrisol® does not require additional treatment of the non-toxic off-gas stream as the H2S is directly converted to crystalline sulphur. This study illustrates clearly that it is advantageous to first remove H2S from a gas stream containing both H2S and CO2 prior to CO2 removal to reduce utilities consumption.
{"title":"Vitrisol® a 100% selective process for H2S removal in the presence of CO2","authors":"W. Wermink, N. Ramachandran, G. Versteeg","doi":"10.7569/jnge.2017.692503","DOIUrl":"https://doi.org/10.7569/jnge.2017.692503","url":null,"abstract":"Abstract Vitrisol®, a novel desulphurization process that is 100% selective for H2S removal from industrial gases containing CO2, can be described with the following overall reaction equation: H2S+0.5O2→H2O+SO(s) $${H_2}S + 0.5{O_2} to {H_2}O + {S^O}(s)$$ The performance of Vitrisol® is demonstrated for two typical applications in shale gas production by comparing them to a standard amine treating process. The remainder toxic, acid gas produced by the latter technology is compressed for acid gas injection. From the results it can be concluded that significant reductions in utilities can be achieved by using Vitrisol® as depicted in the energy consumptions of the overall process. Contrary to the amine process, Vitrisol® does not require additional treatment of the non-toxic off-gas stream as the H2S is directly converted to crystalline sulphur. This study illustrates clearly that it is advantageous to first remove H2S from a gas stream containing both H2S and CO2 prior to CO2 removal to reduce utilities consumption.","PeriodicalId":22694,"journal":{"name":"The Journal of Natural Gas Engineering","volume":"11 1","pages":"50 - 83"},"PeriodicalIF":0.0,"publicationDate":"2017-05-06","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82761524","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}
Pub Date : 2017-01-01DOI: 10.7569/jnge.2017.692506
G. Palmer
The Methane Number is a measure of the resistance of natural gas to detonation when it is burned as a motor fuel in an engine. Pure Methane is assigned a Methane Number of 100 and pure Hydrogen is assigned a Methane Number of zero. A natural gas having a Methane Number of 80 for example, would have the detonation properties of a mixture consisting of 80 vol% Methane and 20 vol% Hydrogen. The Methane Number concept is similar to the Octane Number for gasoline. Unlike gasoline however, there is not yet a universal standard for testing natural gas Methane Number as there is in the motor test for gasoline. Also, there is no universally accepted method for calculating the Methane Number based on the composition of natural gas.
{"title":"Methane Number","authors":"G. Palmer","doi":"10.7569/jnge.2017.692506","DOIUrl":"https://doi.org/10.7569/jnge.2017.692506","url":null,"abstract":"The Methane Number is a measure of the resistance of natural gas to detonation when it is burned as a motor fuel in an engine. Pure Methane is assigned a Methane Number of 100 and pure Hydrogen is assigned a Methane Number of zero. A natural gas having a Methane Number of 80 for example, would have the detonation properties of a mixture consisting of 80 vol% Methane and 20 vol% Hydrogen. The Methane Number concept is similar to the Octane Number for gasoline. Unlike gasoline however, there is not yet a universal standard for testing natural gas Methane Number as there is in the motor test for gasoline. Also, there is no universally accepted method for calculating the Methane Number based on the composition of natural gas.","PeriodicalId":22694,"journal":{"name":"The Journal of Natural Gas Engineering","volume":"53 1","pages":"134 - 142"},"PeriodicalIF":0.0,"publicationDate":"2017-01-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"75035384","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}
Pub Date : 2016-12-28DOI: 10.7569/jnge.2016.692506
Eugene W. Grynia, P. J. Griffin
Abstract Helium is produced from natural gas by treatment of vent gas from Nitrogen Rejection Units or LNG plants. There are 16 liquid helium plants in the world, 7 of which are outside of the United States. There are at least six industrial (specialty) gas companies in the world that have direct access to sources of helium: Air Liquide, Air Products, Linde, Matheson, Messer and Praxair. Conventional helium plants use cryogenic distillation to produce crude helium followed by PSA to purify it for liquefaction. There was a period of helium shortage in 2011–2014 which caused more efficient use of helium and helium recycling. The world is now experiencing a period of too much supply of helium, and new helium plants will come online in Qatar and Russia in 2018 and beyond. The global helium demand in 2016 is estimated at 5.9 Bcf, and the supply is around 6.0 Bcf. Helium plays an important role in modern industry and medicine. There are many applications for helium, but the single largest application is in MRI (Magnetic Resonance Imaging), which accounts for around 30% of all helium usage.
{"title":"Helium in Natural Gas - Occurrence and Production","authors":"Eugene W. Grynia, P. J. Griffin","doi":"10.7569/jnge.2016.692506","DOIUrl":"https://doi.org/10.7569/jnge.2016.692506","url":null,"abstract":"Abstract Helium is produced from natural gas by treatment of vent gas from Nitrogen Rejection Units or LNG plants. There are 16 liquid helium plants in the world, 7 of which are outside of the United States. There are at least six industrial (specialty) gas companies in the world that have direct access to sources of helium: Air Liquide, Air Products, Linde, Matheson, Messer and Praxair. Conventional helium plants use cryogenic distillation to produce crude helium followed by PSA to purify it for liquefaction. There was a period of helium shortage in 2011–2014 which caused more efficient use of helium and helium recycling. The world is now experiencing a period of too much supply of helium, and new helium plants will come online in Qatar and Russia in 2018 and beyond. The global helium demand in 2016 is estimated at 5.9 Bcf, and the supply is around 6.0 Bcf. Helium plays an important role in modern industry and medicine. There are many applications for helium, but the single largest application is in MRI (Magnetic Resonance Imaging), which accounts for around 30% of all helium usage.","PeriodicalId":22694,"journal":{"name":"The Journal of Natural Gas Engineering","volume":"54 1","pages":"163 - 215"},"PeriodicalIF":0.0,"publicationDate":"2016-12-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86763811","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}
Pub Date : 2016-12-28DOI: 10.7569/jnge.2016.692505
Shouxi Wang, Jian Guo, Tingting Zhang, Y. Mei, Jia Wang
Abstract The coal bed methane (CBM) gathering pipeline system of Northern Fanzhuang is in Shanxi province of The People’s Republic of China, near the city of Jincheng. Its features include: low pressure, small throughputs, congestion of the landscape, and undulating terrain. As a result, the management and analysis of the system is very difficult because of the complex structure and the sensitivity to the pressure and to the flow. In response to these problems, a management system was developed using the Pipeline Simulation Network (PNS) pipeline simulation software, integrated with the geographic information system (GIS) and supervisory control and data acquisition (SCADA) system of the CBM gathering system. The management system can automatically generate the required simulation model for the selected systems, pipelines and stations from the GIS geometric information and database. It can perform online simulation with real time data from the SCADA for a quick, direct and precise evaluation of the pipeline system. All the simulation results are stored in the SQL database for history review, and are also sent to the GIS system. According to the simulation results, the status and the flow of the gathering pipeline system are visualized in GIS three-dimensional mode for a quick overall acknowledgement. In addition, more detailed information about the past and current data for each individual component in the gathering system can be searched, sorted and shown in GIS whenever required. The theory and methods for building the management system are discussed in this paper, including the architecture, the simulation model, the self-training of the model, the interaction between the PNS simulation and GIS system, and the three-dimensional search and visualization of the flow status in GIS. Finally, an example was presented to demonstrate the application using better management and regulation of the CBM gathering pipeline system.
{"title":"The Management System Based on the Dynamic Online Simulation for the CBM Gathering Pipeline System of Northern Fanzhuang","authors":"Shouxi Wang, Jian Guo, Tingting Zhang, Y. Mei, Jia Wang","doi":"10.7569/jnge.2016.692505","DOIUrl":"https://doi.org/10.7569/jnge.2016.692505","url":null,"abstract":"Abstract The coal bed methane (CBM) gathering pipeline system of Northern Fanzhuang is in Shanxi province of The People’s Republic of China, near the city of Jincheng. Its features include: low pressure, small throughputs, congestion of the landscape, and undulating terrain. As a result, the management and analysis of the system is very difficult because of the complex structure and the sensitivity to the pressure and to the flow. In response to these problems, a management system was developed using the Pipeline Simulation Network (PNS) pipeline simulation software, integrated with the geographic information system (GIS) and supervisory control and data acquisition (SCADA) system of the CBM gathering system. The management system can automatically generate the required simulation model for the selected systems, pipelines and stations from the GIS geometric information and database. It can perform online simulation with real time data from the SCADA for a quick, direct and precise evaluation of the pipeline system. All the simulation results are stored in the SQL database for history review, and are also sent to the GIS system. According to the simulation results, the status and the flow of the gathering pipeline system are visualized in GIS three-dimensional mode for a quick overall acknowledgement. In addition, more detailed information about the past and current data for each individual component in the gathering system can be searched, sorted and shown in GIS whenever required. The theory and methods for building the management system are discussed in this paper, including the architecture, the simulation model, the self-training of the model, the interaction between the PNS simulation and GIS system, and the three-dimensional search and visualization of the flow status in GIS. Finally, an example was presented to demonstrate the application using better management and regulation of the CBM gathering pipeline system.","PeriodicalId":22694,"journal":{"name":"The Journal of Natural Gas Engineering","volume":"12 1","pages":"148 - 162"},"PeriodicalIF":0.0,"publicationDate":"2016-12-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79929458","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}
Pub Date : 2016-12-28DOI: 10.7569/jnge.2016.692503
G. Ping, Yuan Zhiwang, Wang Zhouhua, Y. Yiyi
Abstract In this paper, we have derived the transformational relationship between the porosity under triaxial, biaxial stress and uniaxial stress respectively. Moreover, porosity tests under biaxial and triaxial stress for 11 groups of parallel unconsolidated core samples are conducted. Based on the transformational relationship, we have converted the tested porosity under triaxial stress into the porosity under biaxial stress and then compared it with the tested porosity under biaxial stress. The results indicate that the theoretical porosity model is reliable and deformation of unconsolidated cores is approximate elastic deformation of the rock body. Therefore, the porosity under uniaxial stress can be converted from the porosity under biaxial stress, which can simplify the experimental procedure and equipment, and provide a new way of determining subsurface porosity of unconsolidated cores. Besides, the Poisson’s ratio of unconsolidated cores is much larger than that of the normal clastic rock, and the actual conversion factor should be used for the conversion.
{"title":"Research on the New Method of Determining Subsurface Porosity of Unconsolidated Cores","authors":"G. Ping, Yuan Zhiwang, Wang Zhouhua, Y. Yiyi","doi":"10.7569/jnge.2016.692503","DOIUrl":"https://doi.org/10.7569/jnge.2016.692503","url":null,"abstract":"Abstract In this paper, we have derived the transformational relationship between the porosity under triaxial, biaxial stress and uniaxial stress respectively. Moreover, porosity tests under biaxial and triaxial stress for 11 groups of parallel unconsolidated core samples are conducted. Based on the transformational relationship, we have converted the tested porosity under triaxial stress into the porosity under biaxial stress and then compared it with the tested porosity under biaxial stress. The results indicate that the theoretical porosity model is reliable and deformation of unconsolidated cores is approximate elastic deformation of the rock body. Therefore, the porosity under uniaxial stress can be converted from the porosity under biaxial stress, which can simplify the experimental procedure and equipment, and provide a new way of determining subsurface porosity of unconsolidated cores. Besides, the Poisson’s ratio of unconsolidated cores is much larger than that of the normal clastic rock, and the actual conversion factor should be used for the conversion.","PeriodicalId":22694,"journal":{"name":"The Journal of Natural Gas Engineering","volume":"48 1","pages":"125 - 140"},"PeriodicalIF":0.0,"publicationDate":"2016-12-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"85794301","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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