Pub Date : 2021-04-01DOI: 10.22050/IJOGST.2021.269283.1581
A. Alihosseini, A. H. Zadeh, M. Monajjemi, Mahdi Nazary Sarem
Abstract Wellbore stability is of one of challenges in drilling industry. Shale formation is of one of the most problematic rocks during drilling because the rock has very low permeability and very small pores (nanometers). In this study, the viability of the Alumina nanoparticles in Water-Based Mud (WBM) is assessed. The effect of Alumina nanoparticles (alpha and gamma) as mud additives to improve the rheological properties in water- base drilling fluids are experimentally investigated. The Alumina nanoparticles has specific chemical and physical properties such as: high compressive strength, high hardness, high thermal conductivity, these properties improve the rheological properties of water base drilling fluid, reduce filtration loss and meet environmental regulations. The results of experiments indicated that Alumina nanoparticle are improving rheological properties such as: yield point (YP), gel strength (GEL 10s, Gel 10min) of water- base drilling, that can be used to improve the rheological and filtration properties of drilling fluids. The experimental data showed that, Alumina nanoparticle as a Nano additive, possessed excellent properties such as thermal stability, rheology enhancing, fluid loss control and lubrication. Also, it could plug the shale formation effectively and improve the pressure bearing capability of formation significantly. In addition, Alumina nanoparticles reduced 60% API/HPHT fluid loss by 60% in comparison with blank sample. The most striking feature is that shale integrity improved by Nano fluid between 60 and 70 percent in comparison with blank sample. Also, data experimental of CT Scan are shown that the filter cakes formed by each of the Nano-drilling fluid samples with alpha alumina and gamma alumina base are more cohesive and cause an integrated filter cake on the well.
{"title":"Study of Rheological Properties of Water-based Drilling Fluid in the Well Strength (Using Alumina Nanoparticles)","authors":"A. Alihosseini, A. H. Zadeh, M. Monajjemi, Mahdi Nazary Sarem","doi":"10.22050/IJOGST.2021.269283.1581","DOIUrl":"https://doi.org/10.22050/IJOGST.2021.269283.1581","url":null,"abstract":"Abstract Wellbore stability is of one of challenges in drilling industry. Shale formation is of one of the most problematic rocks during drilling because the rock has very low permeability and very small pores (nanometers). In this study, the viability of the Alumina nanoparticles in Water-Based Mud (WBM) is assessed. The effect of Alumina nanoparticles (alpha and gamma) as mud additives to improve the rheological properties in water- base drilling fluids are experimentally investigated. The Alumina nanoparticles has specific chemical and physical properties such as: high compressive strength, high hardness, high thermal conductivity, these properties improve the rheological properties of water base drilling fluid, reduce filtration loss and meet environmental regulations. The results of experiments indicated that Alumina nanoparticle are improving rheological properties such as: yield point (YP), gel strength (GEL 10s, Gel 10min) of water- base drilling, that can be used to improve the rheological and filtration properties of drilling fluids. The experimental data showed that, Alumina nanoparticle as a Nano additive, possessed excellent properties such as thermal stability, rheology enhancing, fluid loss control and lubrication. Also, it could plug the shale formation effectively and improve the pressure bearing capability of formation significantly. In addition, Alumina nanoparticles reduced 60% API/HPHT fluid loss by 60% in comparison with blank sample. The most striking feature is that shale integrity improved by Nano fluid between 60 and 70 percent in comparison with blank sample. Also, data experimental of CT Scan are shown that the filter cakes formed by each of the Nano-drilling fluid samples with alpha alumina and gamma alumina base are more cohesive and cause an integrated filter cake on the well.","PeriodicalId":14575,"journal":{"name":"Iranian Journal of Oil and Gas Science and Technology","volume":"4 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-04-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88746191","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 : 2021-04-01DOI: 10.22050/IJOGST.2021.276860.1587
S. N. Apourvari, Mehdi Rezaei Abiz, S. Jafari, M. Schaffie
Although experimental studies confirmed the effectiveness of nanoparticles in enhanced oil recovery applications, no comprehensive investigation has been carried out to reveal the effect of different subsurface factors on this improvement. Proper application of nanoparticles mainly depends on their ability to travel long distances within a reservoir without agglomeration, retention and blocking the pore throats. This study strengthens our understanding about the effect of the main subsurface factors on the nanofluid-assisted enhanced oil recovery. For doing so, a transport approach utilizing kinetic Langmuir model is developed and validated using experimental data. Thereafter, the effect of reservoir rock type and its properties (clay content and grain size), salinity of injected fluid, and reservoir temperature on the transport and retention of nanoparticles in porous media in relation to enhanced oil recovery methods is investigated. Since the amount of nanoparticles in the injected fluid and on the rock surface (as deposited) control the mobility and wettability alteration, the effect of subsurface factors and salinity of injected fluid on this deposition is also analyzed. The results showed that the rock type and its properties significantly affect the transport and retention of nanoparticles in porous media. It was also found that the brine salinity has the greatest impact on the amount of nanoparticles deposited on the rock surface. The surface covered by NPs increased from 10 to 82 % after changing salinity from 3 weight percent NaCl to API brine.
{"title":"Simulation Study of Nanoparticle Transport in Porous Media: Effects of Salinity and Reservoir Parameters","authors":"S. N. Apourvari, Mehdi Rezaei Abiz, S. Jafari, M. Schaffie","doi":"10.22050/IJOGST.2021.276860.1587","DOIUrl":"https://doi.org/10.22050/IJOGST.2021.276860.1587","url":null,"abstract":"Although experimental studies confirmed the effectiveness of nanoparticles in enhanced oil recovery applications, no comprehensive investigation has been carried out to reveal the effect of different subsurface factors on this improvement. Proper application of nanoparticles mainly depends on their ability to travel long distances within a reservoir without agglomeration, retention and blocking the pore throats. This study strengthens our understanding about the effect of the main subsurface factors on the nanofluid-assisted enhanced oil recovery. For doing so, a transport approach utilizing kinetic Langmuir model is developed and validated using experimental data. Thereafter, the effect of reservoir rock type and its properties (clay content and grain size), salinity of injected fluid, and reservoir temperature on the transport and retention of nanoparticles in porous media in relation to enhanced oil recovery methods is investigated. Since the amount of nanoparticles in the injected fluid and on the rock surface (as deposited) control the mobility and wettability alteration, the effect of subsurface factors and salinity of injected fluid on this deposition is also analyzed. The results showed that the rock type and its properties significantly affect the transport and retention of nanoparticles in porous media. It was also found that the brine salinity has the greatest impact on the amount of nanoparticles deposited on the rock surface. The surface covered by NPs increased from 10 to 82 % after changing salinity from 3 weight percent NaCl to API brine.","PeriodicalId":14575,"journal":{"name":"Iranian Journal of Oil and Gas Science and Technology","volume":"228 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-04-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"85569100","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 : 2021-04-01DOI: 10.22050/IJOGST.2021.284524.1592
S. Tsegaye
The lithofacies and environments of deposition interpretations of the Calub-Hilala field towards central trough of Ogaden Basin have been carried out. Geophysical well logs from three deep exploration wells; Calub-1, Bodle-1 and Hilala-2 were used. A methodology was piloted in establishing the sedimentary facies, their successions and environments of deposition. Gamma ray, neutron, sonic and resistivity logs were used for lithologic and depositional environment identification respectively. An attempt were also made to identify formation tops and well to well lithostratigraphic correlation basing gamma ray log trends and correlating with cored interval of the wells for Lithological comparisons. Lithofacies interpretation was carried out with Schlumberger’s Petrel 2009TMsoftware. Correlation techniques were conducted to delineate the subsurface trends of these facies with electrafacies to compare facies interpretation results that were implied using the wire line log signatures.Ten (10) formations; Calub, Bokh, Gumburo, Adigrat, Transition, Hamanlei (Lower, Middle and Upper), Urandab, Gebredare, Gorrahei, Mustahil and Five (5) log facies; a cylindrical-shaped log trends representing aeolian, braded fluvial; a funnel-shaped facies representing a crevasse splay; a carbonate shallowing upward sequence and shallow marine sheet sand; bell-shaped facies representing transgressive marine shelf; a symmetrical- shaped facies representing sandy offshore and an irregular shaped facies representing fluvial floodplain were recognized. The environments of deposition delineated for the study area are alluvial and transgressive – regressive marine.
{"title":"Facies interpretation from well logs applied to Calub-Hilala field within Ogaden Basin, Ethiopia","authors":"S. Tsegaye","doi":"10.22050/IJOGST.2021.284524.1592","DOIUrl":"https://doi.org/10.22050/IJOGST.2021.284524.1592","url":null,"abstract":"The lithofacies and environments of deposition interpretations of the Calub-Hilala field towards central trough of Ogaden Basin have been carried out. Geophysical well logs from three deep exploration wells; Calub-1, Bodle-1 and Hilala-2 were used. A methodology was piloted in establishing the sedimentary facies, their successions and environments of deposition. Gamma ray, neutron, sonic and resistivity logs were used for lithologic and depositional environment identification respectively. An attempt were also made to identify formation tops and well to well lithostratigraphic correlation basing gamma ray log trends and correlating with cored interval of the wells for Lithological comparisons. Lithofacies interpretation was carried out with Schlumberger’s Petrel 2009TMsoftware. Correlation techniques were conducted to delineate the subsurface trends of these facies with electrafacies to compare facies interpretation results that were implied using the wire line log signatures.Ten (10) formations; Calub, Bokh, Gumburo, Adigrat, Transition, Hamanlei (Lower, Middle and Upper), Urandab, Gebredare, Gorrahei, Mustahil and Five (5) log facies; a cylindrical-shaped log trends representing aeolian, braded fluvial; a funnel-shaped facies representing a crevasse splay; a carbonate shallowing upward sequence and shallow marine sheet sand; bell-shaped facies representing transgressive marine shelf; a symmetrical- shaped facies representing sandy offshore and an irregular shaped facies representing fluvial floodplain were recognized. The environments of deposition delineated for the study area are alluvial and transgressive – regressive marine.","PeriodicalId":14575,"journal":{"name":"Iranian Journal of Oil and Gas Science and Technology","volume":"6 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-04-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90598443","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 : 2021-04-01DOI: 10.22050/IJOGST.2021.278551.1588
Behzad Orangii, M. Riahi
This paper investigates the role of the effective thickness of the Asmari reservoir formation zones on oil production in one of the Iranian carbonate oil fields. Effective thickness is a term that includes the total gross thickness of rocks by lithofacies for a selected wellbore. The lithology of the Asmari Formation in the studied area consists of dolomite, sandstone, lime, dolomitic-lime, sandstone-shale, and shale limestone dolomites. Based on the existing well-logs, the average shale volume, the effective arithmetic means of porosity in the gross intervals, and average water saturation or hydrocarbon-bearing increments of the studied field is calculated from well-logs. The depth interval of 2214 to 2296, in wellbore #A shows 9.6% average shale volume, 27.2% average water saturation, and 20.9% average porosity. The depth interval of 2213 to 2280, in wellbore #B, shows 6% average shale volume, 21.25% average water saturation, and 28.5% average porosity. Based on our petrophysical assessments we divide the Asmari reservoir in the studied field into eight zones. Zone 1 is made of carbonate (calcareous and dolomitic), zones 2 to 5 are mainly sandstone, zones 7 and 8 are calcareous and shale and zone 6 is a mixture of all the above-mentioned rocks. Among these eight zones, there are two main hydrocarbon productive zones. The numerical calculation of in situ oil volume showed that zone two contains 65% of oil volume in this reservoir. This zone with more than 80% of sand has the highest net hydrocarbon column.
{"title":"The role of effective thickness of the Asmari Formation zones on oil production","authors":"Behzad Orangii, M. Riahi","doi":"10.22050/IJOGST.2021.278551.1588","DOIUrl":"https://doi.org/10.22050/IJOGST.2021.278551.1588","url":null,"abstract":"This paper investigates the role of the effective thickness of the Asmari reservoir formation zones on oil production in one of the Iranian carbonate oil fields. Effective thickness is a term that includes the total gross thickness of rocks by lithofacies for a selected wellbore. The lithology of the Asmari Formation in the studied area consists of dolomite, sandstone, lime, dolomitic-lime, sandstone-shale, and shale limestone dolomites. Based on the existing well-logs, the average shale volume, the effective arithmetic means of porosity in the gross intervals, and average water saturation or hydrocarbon-bearing increments of the studied field is calculated from well-logs. The depth interval of 2214 to 2296, in wellbore #A shows 9.6% average shale volume, 27.2% average water saturation, and 20.9% average porosity. The depth interval of 2213 to 2280, in wellbore #B, shows 6% average shale volume, 21.25% average water saturation, and 28.5% average porosity. Based on our petrophysical assessments we divide the Asmari reservoir in the studied field into eight zones. Zone 1 is made of carbonate (calcareous and dolomitic), zones 2 to 5 are mainly sandstone, zones 7 and 8 are calcareous and shale and zone 6 is a mixture of all the above-mentioned rocks. Among these eight zones, there are two main hydrocarbon productive zones. The numerical calculation of in situ oil volume showed that zone two contains 65% of oil volume in this reservoir. This zone with more than 80% of sand has the highest net hydrocarbon column.","PeriodicalId":14575,"journal":{"name":"Iranian Journal of Oil and Gas Science and Technology","volume":"73 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-04-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"81219288","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 : 2021-03-03DOI: 10.22050/IJOGST.2021.265594.1578
B. Behzadi, M. Noei, A. Azimi, M. Mirzaei, Hossien Anaraki Ardakani
Water can contain microorganisms and cause deposition and corrosion in cooling tower systems.Therefore, treatment of thewater of cooling towers is important and essential.Various biocides are used to remove bacteria and disinfect the water of cooling towers,the most commonly used of whichare sodium hypochlorite and chlorine compounds. Two chlorinated water,(hypochlorous acid) and (sodium hypochlorite) were tested in this studyon two pilot and industrial cooling towers.The results of experiments on the pilot tower showed that the performance of hypochlorous acid in disinfection and removal of bacteria and microorganisms has a high capability.The total bacterial count decreased from 10000 (cfu/ml) to less than 800 (cfu/ml) compared to sodium hypochlorite.Experiments and researches were performed on the industrial cooling tower of the Petrochemical Acetic Acid Unit for six months, in which pH, Free Chlorine, TBC and SRB were measured.Very high disinfection power of hypochlorous acid compared to sodium hypochloriteand also low pH of hypochlorous acid compared to sodium hypochlorite led to a significant reduction in the use of chemicals in the cooling tower.The results of Experiments and TBC and SRB tests showed very good performance of using hypochlorous acid
{"title":"Experimental optimization of the disinfection performance of sodium hypochlorite and hypochlorous acid in pilot and industrial cooling towers","authors":"B. Behzadi, M. Noei, A. Azimi, M. Mirzaei, Hossien Anaraki Ardakani","doi":"10.22050/IJOGST.2021.265594.1578","DOIUrl":"https://doi.org/10.22050/IJOGST.2021.265594.1578","url":null,"abstract":"Water can contain microorganisms and cause deposition and corrosion in cooling tower systems.Therefore, treatment of thewater of cooling towers is important and essential.Various biocides are used to remove bacteria and disinfect the water of cooling towers,the most commonly used of whichare sodium hypochlorite and chlorine compounds. Two chlorinated water,(hypochlorous acid) and (sodium hypochlorite) were tested in this studyon two pilot and industrial cooling towers.The results of experiments on the pilot tower showed that the performance of hypochlorous acid in disinfection and removal of bacteria and microorganisms has a high capability.The total bacterial count decreased from 10000 (cfu/ml) to less than 800 (cfu/ml) compared to sodium hypochlorite.Experiments and researches were performed on the industrial cooling tower of the Petrochemical Acetic Acid Unit for six months, in which pH, Free Chlorine, TBC and SRB were measured.Very high disinfection power of hypochlorous acid compared to sodium hypochloriteand also low pH of hypochlorous acid compared to sodium hypochlorite led to a significant reduction in the use of chemicals in the cooling tower.The results of Experiments and TBC and SRB tests showed very good performance of using hypochlorous acid","PeriodicalId":14575,"journal":{"name":"Iranian Journal of Oil and Gas Science and Technology","volume":"7 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-03-03","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87639537","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 : 2021-01-01DOI: 10.22050/IJOGST.2020.241095.1556
Z. Hosseini, Sajjad Gharechelou, A. Mahboubi, R. Moussavi-Harami, A. Kadkhodaie-Ilkhchi, M. Zeinali
The conjugation of two or more Artificial Intelligent (AI) models used to design a single model that has increased in popularity over the recent years for exploration of hydrocarbon reservoirs. In this research, we have successfully predicted shear wave velocity (Vs) with higher accuracy through the integration of statistical and AI models using petrophysical data in a mixed carbonate-siliciclastic heterogeneous reservoir. In the designed code for multi-model, first Multivariate Linear Regression (MLR) is used to select the more relevant input variables from petrophysical data using weight coefficients of a suggested function. The most influential petrophysical data (Vp, NPHI, RHOB) are passed to Ant colony optimization (ACOR) for training and establishing initial connection weights and biases of back propagation (BP) algorithm. Afterward, BP training algorithm is applied for final weights and acceptable prediction of shear wave velocity. This novel methodology is illustrated by using a case study from the mixed carbonate-siliciclastic reservoir from one of the Iranian oilfields. Results show that the proposed integrated modeling can sufficiently improve the performance of Vs estimation, and is a method applicable to mixed heterogeneous intervals with complicated diagenetic overprints. Furthermore, predicted Vs from this model is well correlated with lithology, facies and diagenesis variations in the formation. Meanwhile, the developed AI multi-model can serve as an effective approach for estimation of rock elastic properties. More accurate prediction of rock elastic properties in several wells could reduce uncertainty of exploration and save plenty of time and cost for oil industries.
{"title":"Shear wave velocity estimation utilizing statistical and multi-intelligent models from petrophysical data in a mixed carbonate-siliciclastic reservoir, SW Iran","authors":"Z. Hosseini, Sajjad Gharechelou, A. Mahboubi, R. Moussavi-Harami, A. Kadkhodaie-Ilkhchi, M. Zeinali","doi":"10.22050/IJOGST.2020.241095.1556","DOIUrl":"https://doi.org/10.22050/IJOGST.2020.241095.1556","url":null,"abstract":"The conjugation of two or more Artificial Intelligent (AI) models used to design a single model that has increased in popularity over the recent years for exploration of hydrocarbon reservoirs. In this research, we have successfully predicted shear wave velocity (Vs) with higher accuracy through the integration of statistical and AI models using petrophysical data in a mixed carbonate-siliciclastic heterogeneous reservoir. In the designed code for multi-model, first Multivariate Linear Regression (MLR) is used to select the more relevant input variables from petrophysical data using weight coefficients of a suggested function. The most influential petrophysical data (Vp, NPHI, RHOB) are passed to Ant colony optimization (ACOR) for training and establishing initial connection weights and biases of back propagation (BP) algorithm. Afterward, BP training algorithm is applied for final weights and acceptable prediction of shear wave velocity. This novel methodology is illustrated by using a case study from the mixed carbonate-siliciclastic reservoir from one of the Iranian oilfields. Results show that the proposed integrated modeling can sufficiently improve the performance of Vs estimation, and is a method applicable to mixed heterogeneous intervals with complicated diagenetic overprints. Furthermore, predicted Vs from this model is well correlated with lithology, facies and diagenesis variations in the formation. Meanwhile, the developed AI multi-model can serve as an effective approach for estimation of rock elastic properties. More accurate prediction of rock elastic properties in several wells could reduce uncertainty of exploration and save plenty of time and cost for oil industries.","PeriodicalId":14575,"journal":{"name":"Iranian Journal of Oil and Gas Science and Technology","volume":"339 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-01-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"75473847","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 : 2021-01-01DOI: 10.22050/IJOGST.2021.252493.1567
Vahid Karamnia, S. Ashoori
One of the most important factors through the miscible gas injection process is to determine the Minimum Miscibility Pressure. According to the definition, the minimum miscibility pressure is the minimum pressure at which, at a constant temperature, the oil and gas injected can dissolve together to form a single phase. This pressure is typically abbreviated as MMP. Among the available methods for determining the minimum miscibility pressure, laboratory methods including slim tube test and ascending bubble apparatus test are more widely utilized. Although the mentioned tests have high measurement accuracy, they are very time consuming and expensive. Therefore, the determination of the minimum miscibility pressure is usually done using computational and simulation approaches that also have high accuracy. Conducting PVT tests and determining their MMP using slim tube method was previously performed. In this study, the minimum miscibility pressure of reservoirs was determined by applying three methods of simulation with PVTi software, simulation with Eclipse 300 software and using Empirical Correlations. By comparing the obtained results and the laboratory results, it was revealed that the simulation by Eclipse 300 is regarded as the fastest and most accurate approach.
{"title":"Determination of Minimum Miscibility Pressure (MMP) using PVTi Software, Eclipse 300 and Empirical Correlations","authors":"Vahid Karamnia, S. Ashoori","doi":"10.22050/IJOGST.2021.252493.1567","DOIUrl":"https://doi.org/10.22050/IJOGST.2021.252493.1567","url":null,"abstract":"One of the most important factors through the miscible gas injection process is to determine the Minimum Miscibility Pressure. According to the definition, the minimum miscibility pressure is the minimum pressure at which, at a constant temperature, the oil and gas injected can dissolve together to form a single phase. This pressure is typically abbreviated as MMP. Among the available methods for determining the minimum miscibility pressure, laboratory methods including slim tube test and ascending bubble apparatus test are more widely utilized. Although the mentioned tests have high measurement accuracy, they are very time consuming and expensive. Therefore, the determination of the minimum miscibility pressure is usually done using computational and simulation approaches that also have high accuracy. Conducting PVT tests and determining their MMP using slim tube method was previously performed. In this study, the minimum miscibility pressure of reservoirs was determined by applying three methods of simulation with PVTi software, simulation with Eclipse 300 software and using Empirical Correlations. By comparing the obtained results and the laboratory results, it was revealed that the simulation by Eclipse 300 is regarded as the fastest and most accurate approach.","PeriodicalId":14575,"journal":{"name":"Iranian Journal of Oil and Gas Science and Technology","volume":"1 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-01-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83624824","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 : 2021-01-01DOI: 10.22050/IJOGST.2020.254534.1569
A. Khalili-Garakani, M. Jafari
In Iran, power plants use liquid fuels such as heavy fuel oil (HFO) or mazut to prevent disruption in power generation. The high percentage of sulfur compounds in HFO and the lack of efforts to remove it, causing significant damage to the environment. The purpose of this research is performing a techno-economic analysis on the Hydrodesulfurization (HDS) process of HFO. The results showed that for removing 85% of sulfur compounds from HFO with a volume flow rate of 250 m3/h that includes 3.5% wt sulfur compounds, the total capital investment and the net production cost are 308.9 million US$ and 114.5 million US$/year, respectively. Besides, the sensitivity analysis indicates that with a 100% increase in the catalyst loading, the mass percentage of sulfur compounds in the HFO will be decreased by 15% more. Also, 6.4% and 32% will add to the total capital investment and net production cost, respectively. With a 100% increase in the gas to oil ratio, the mass percentage of sulfur compounds in the HFO will be decreased by 15.3% more. Also, 43.8% and 6% will be added to the total capital investment and net production cost, respectively. With a 100% increase in the pressure of the HDS process, the mass percentage of sulfur compounds in the HFO will be reduced by 20.75% more. Also, 43% and 6.75% will be added to the total capital investment and net production cost, respectively. Ultimately, with a 100% increase in the inlet temperature of beds, the mass percentage of sulfur compounds in the HFO will be reduced by 5% more. Among the effective operational parameters, hydrogen consumption has the greatest impact on net production cost and payback period, and the pressure of the Hydrodesulfurization process has the greatest impact on increasing the total capital investment of the process.
{"title":"Techno-Economic Analysis of Heavy Fuel Oil Hydrodesulfurization Process for Application in Power Plants","authors":"A. Khalili-Garakani, M. Jafari","doi":"10.22050/IJOGST.2020.254534.1569","DOIUrl":"https://doi.org/10.22050/IJOGST.2020.254534.1569","url":null,"abstract":"In Iran, power plants use liquid fuels such as heavy fuel oil (HFO) or mazut to prevent disruption in power generation. The high percentage of sulfur compounds in HFO and the lack of efforts to remove it, causing significant damage to the environment. The purpose of this research is performing a techno-economic analysis on the Hydrodesulfurization (HDS) process of HFO. The results showed that for removing 85% of sulfur compounds from HFO with a volume flow rate of 250 m3/h that includes 3.5% wt sulfur compounds, the total capital investment and the net production cost are 308.9 million US$ and 114.5 million US$/year, respectively. Besides, the sensitivity analysis indicates that with a 100% increase in the catalyst loading, the mass percentage of sulfur compounds in the HFO will be decreased by 15% more. Also, 6.4% and 32% will add to the total capital investment and net production cost, respectively. With a 100% increase in the gas to oil ratio, the mass percentage of sulfur compounds in the HFO will be decreased by 15.3% more. Also, 43.8% and 6% will be added to the total capital investment and net production cost, respectively. With a 100% increase in the pressure of the HDS process, the mass percentage of sulfur compounds in the HFO will be reduced by 20.75% more. Also, 43% and 6.75% will be added to the total capital investment and net production cost, respectively. Ultimately, with a 100% increase in the inlet temperature of beds, the mass percentage of sulfur compounds in the HFO will be reduced by 5% more. Among the effective operational parameters, hydrogen consumption has the greatest impact on net production cost and payback period, and the pressure of the Hydrodesulfurization process has the greatest impact on increasing the total capital investment of the process.","PeriodicalId":14575,"journal":{"name":"Iranian Journal of Oil and Gas Science and Technology","volume":"14 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-01-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87592204","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 : 2021-01-01DOI: 10.22050/IJOGST.2020.219350.1536
A. Khalili-Garakani, Mahya Nezhadfard, M. Jafari
Flaring of gas often having high heating value results in considerable economic and energy losses in addition to significant environmental impacts. Power generation through combined gas and steam turbine cycles may be considered as a suitable flare gas recovery process. Thermal sea-water desalination is a process that requires a considerable amount of heat; hence it may be used in downstream of power generation cycles. Energy is the largest section of the water generation cost of all desalination processes. The energy cost of thermal distillation sea-water plants is close to 50-60% of water generation costs. In the current study, the generation of power and desalinated water through the gas turbine cycle, steam cycle, and multistage flash (MSF) method using flare gas of cheshmeh khosh are investigated. The economic parameters related to the different scenarios considered for the production of power and water are evaluated in the current research. According to the economic evaluation carried out, the most economically profitable scenarios for the investigated co-generation plant is generating as much as possible power in the steam turbine and using the remaining heat in the low-pressure outlet steam in the MSF desalination process. The results show that by increasing steam turbine outlet pressure from 3 bar to 78 bar, power and water generation is changed from 697 to 581 MW and 1557 to 2109 m3/h, respectively. Also, by increasing the outlet pressure of the steam turbine from 3 to 78 bar, the total capital cost is changed from 1177 to 1192 MUSD, and the operating cost is changed from 117.85 to 117 MUSD/year. Finally, operating profit will decrease from 300 to 50 MUSD/year, and payback time will change from 3.92 to 4.75 years.
{"title":"Simulation and Economic Analysis of Combined Desalinated Water and Power Generation from Associated Gases of Cheshmeh Khosh","authors":"A. Khalili-Garakani, Mahya Nezhadfard, M. Jafari","doi":"10.22050/IJOGST.2020.219350.1536","DOIUrl":"https://doi.org/10.22050/IJOGST.2020.219350.1536","url":null,"abstract":"Flaring of gas often having high heating value results in considerable economic and energy losses in addition to significant environmental impacts. Power generation through combined gas and steam turbine cycles may be considered as a suitable flare gas recovery process. Thermal sea-water desalination is a process that requires a considerable amount of heat; hence it may be used in downstream of power generation cycles. Energy is the largest section of the water generation cost of all desalination processes. The energy cost of thermal distillation sea-water plants is close to 50-60% of water generation costs. In the current study, the generation of power and desalinated water through the gas turbine cycle, steam cycle, and multistage flash (MSF) method using flare gas of cheshmeh khosh are investigated. The economic parameters related to the different scenarios considered for the production of power and water are evaluated in the current research. According to the economic evaluation carried out, the most economically profitable scenarios for the investigated co-generation plant is generating as much as possible power in the steam turbine and using the remaining heat in the low-pressure outlet steam in the MSF desalination process. The results show that by increasing steam turbine outlet pressure from 3 bar to 78 bar, power and water generation is changed from 697 to 581 MW and 1557 to 2109 m3/h, respectively. Also, by increasing the outlet pressure of the steam turbine from 3 to 78 bar, the total capital cost is changed from 1177 to 1192 MUSD, and the operating cost is changed from 117.85 to 117 MUSD/year. Finally, operating profit will decrease from 300 to 50 MUSD/year, and payback time will change from 3.92 to 4.75 years.","PeriodicalId":14575,"journal":{"name":"Iranian Journal of Oil and Gas Science and Technology","volume":"4 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-01-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"73232485","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 : 2021-01-01DOI: 10.22050/IJOGST.2020.211087.1530
I. Hossain, M. Roy, Abir Debnath
Gasoline obtained from the fractionation of indigenous natural gas condensate has low octane number (78) and is therefore of limited uses. Lead-based octane boosting and catalytic reforming are not the viable methods for many fractionation plants. This study was therefore aimed to develop an inexpensive conceptual alternative method for boosting the octane number of gasoline. Natural gas concentrated in methane having high octane number (more than 100) was absorbed in the gasoline to boost the octane number partially (86). Selective additives i.e. ethanol, tert-butyl alcohol, methylcyclopentane, toluene, iso-octane and xylene were blended first with the gasoline to aid the absorption of natural gas molecules. The loss of absorbed gas molecules from gasoline with the increase in temperature was also observed. It is therefore required to try for avoiding any increase in temperature in the finished gasoline. The developed conceptual method is promising. The findings of this simulation study would be useful for more studies towards the development of an affordable alternative method for fractionation plants for boosting the octane number of gasoline derived from natural gas condensate.
{"title":"Boosting the Octane Number of Gasoline by Natural Gas Concentrated in Methane","authors":"I. Hossain, M. Roy, Abir Debnath","doi":"10.22050/IJOGST.2020.211087.1530","DOIUrl":"https://doi.org/10.22050/IJOGST.2020.211087.1530","url":null,"abstract":"Gasoline obtained from the fractionation of indigenous natural gas condensate has low octane number (78) and is therefore of limited uses. Lead-based octane boosting and catalytic reforming are not the viable methods for many fractionation plants. This study was therefore aimed to develop an inexpensive conceptual alternative method for boosting the octane number of gasoline. Natural gas concentrated in methane having high octane number (more than 100) was absorbed in the gasoline to boost the octane number partially (86). Selective additives i.e. ethanol, tert-butyl alcohol, methylcyclopentane, toluene, iso-octane and xylene were blended first with the gasoline to aid the absorption of natural gas molecules. The loss of absorbed gas molecules from gasoline with the increase in temperature was also observed. It is therefore required to try for avoiding any increase in temperature in the finished gasoline. The developed conceptual method is promising. The findings of this simulation study would be useful for more studies towards the development of an affordable alternative method for fractionation plants for boosting the octane number of gasoline derived from natural gas condensate.","PeriodicalId":14575,"journal":{"name":"Iranian Journal of Oil and Gas Science and Technology","volume":"1 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-01-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79639290","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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