Pub Date : 2020-07-31DOI: 10.4236/ojogas.2020.54016
A. Novianto, Sutanto , Suharsono , C. Prasetyadi, T. Setiawan
Kendeng Basin stretches in an E-W direction from the Quaternary Merapi-Ungaran Volcano range in the West to the Madura Strait East of Jawa Timur Province, Indonesia. With Quaternary volcanic deposits covering this basin, its subsurface configuration has not been accurately identified. Several scholars suggest that its configuration forms an asymmetrical basin deepening to the south as a result of volcanic deposits and extending E-W direction. This paper answers what configuration Kendeng Basin has, including whether it consists of a simple asymmetrical shape as previous studies have interpreted or other patterns due to tectonic processes that took place during its formation. The research employed Gravity and Magnetic method, and the results were processed by spectral and gradient analyses. Both analyses revealed that Kendeng Basin formed Horst-Graben structures extending in an E-W direction based on a response to compression and strain forces during its formation. A structure with an E-W direction controls the shape of the Horst-Graben and is transected by a structural pattern extending in a NE-SW direction or known as the Meratus pattern. These findings provide an alternative to the concept of oil and gas exploration, which, until today, is merely known from the emergence of oil seepages in Kendeng Basin.
{"title":"Structural Model of Kendeng Basin: A New Concept of Oil and Gas Exploration","authors":"A. Novianto, Sutanto , Suharsono , C. Prasetyadi, T. Setiawan","doi":"10.4236/ojogas.2020.54016","DOIUrl":"https://doi.org/10.4236/ojogas.2020.54016","url":null,"abstract":"Kendeng Basin stretches in an E-W direction from the Quaternary Merapi-Ungaran Volcano range in the West to the Madura Strait East of Jawa Timur Province, Indonesia. With Quaternary volcanic deposits covering this basin, its subsurface configuration has not been accurately identified. Several scholars suggest that its configuration forms an asymmetrical basin deepening to the south as a result of volcanic deposits and extending E-W direction. This paper answers what configuration Kendeng Basin has, including whether it consists of a simple asymmetrical shape as previous studies have interpreted or other patterns due to tectonic processes that took place during its formation. The research employed Gravity and Magnetic method, and the results were processed by spectral and gradient analyses. Both analyses revealed that Kendeng Basin formed Horst-Graben structures extending in an E-W direction based on a response to compression and strain forces during its formation. A structure with an E-W direction controls the shape of the Horst-Graben and is transected by a structural pattern extending in a NE-SW direction or known as the Meratus pattern. These findings provide an alternative to the concept of oil and gas exploration, which, until today, is merely known from the emergence of oil seepages in Kendeng Basin.","PeriodicalId":65460,"journal":{"name":"长江油气:英文版","volume":" ","pages":""},"PeriodicalIF":0.0,"publicationDate":"2020-07-31","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"46090483","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 : 2020-05-22DOI: 10.4236/ojogas.2020.53009
A. Kerunwa
The combination of injection of lower saline brine and surfactant will increase recovery in sandstone rocks than either when any of the techniques is singly applied. In this work, core IFT test, pH test, flooding experiments and measurement of dispersion were performed on four core samples which were grouped into two: group A, which were not fired at a temperature of 500°C for 24 hours and group B which were fired. Two low saline brines were prepared: LS1 which was derived by the dilution of seawater four times and LS2 which was derived by ten times diluting the seawater. The surfactant used was ethoxylated alcohol surfactant. Coreflood experiments were then performed on the rock sample starting with the injection of low saline followed by low saline brine combined with surfactant (LSS). Results from the experiments show that with the injection of LS1 brine and LSS1 higher increment in recoveries were obtained for group B than for group A cores. The same trend was also noticed with the injection of LS2 and LSS2. From the results, LS1 gave higher increment in oil recovery than LS2. Also LSS1 gave higher recoveries when compared with LSS2. In all the cases tested, core samples which were fired gave higher recoveries even though they had low permeabilities of 993 md for sample 3 and 1017 md for sample 4 than those which were not fired with higher permeabilities of 1050 md and 1055 md for samples 1 and 2 with respectively. This was attributed to the alteration of wettability as well as that of permeability caused by sample firing. The dispersion profiles of the rock samples show that all samples are homogeneous.
{"title":"The Impact of Core Firing on EOR of Low Salinity-Surfactant Flooding","authors":"A. Kerunwa","doi":"10.4236/ojogas.2020.53009","DOIUrl":"https://doi.org/10.4236/ojogas.2020.53009","url":null,"abstract":"The combination of injection of lower saline brine and surfactant will increase recovery in sandstone rocks than either when any of the techniques is singly applied. In this work, core IFT test, pH test, flooding experiments and measurement of dispersion were performed on four core samples which were grouped into two: group A, which were not fired at a temperature of 500°C for 24 hours and group B which were fired. Two low saline brines were prepared: LS1 which was derived by the dilution of seawater four times and LS2 which was derived by ten times diluting the seawater. The surfactant used was ethoxylated alcohol surfactant. Coreflood experiments were then performed on the rock sample starting with the injection of low saline followed by low saline brine combined with surfactant (LSS). Results from the experiments show that with the injection of LS1 brine and LSS1 higher increment in recoveries were obtained for group B than for group A cores. The same trend was also noticed with the injection of LS2 and LSS2. From the results, LS1 gave higher increment in oil recovery than LS2. Also LSS1 gave higher recoveries when compared with LSS2. In all the cases tested, core samples which were fired gave higher recoveries even though they had low permeabilities of 993 md for sample 3 and 1017 md for sample 4 than those which were not fired with higher permeabilities of 1050 md and 1055 md for samples 1 and 2 with respectively. This was attributed to the alteration of wettability as well as that of permeability caused by sample firing. The dispersion profiles of the rock samples show that all samples are homogeneous.","PeriodicalId":65460,"journal":{"name":"长江油气:英文版","volume":" ","pages":""},"PeriodicalIF":0.0,"publicationDate":"2020-05-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"48345597","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 : 2020-05-13DOI: 10.4236/ojogas.2020.53008
A. Buntoro, C. Prasetyadi, R. A. Wibowo, nbsp, Suranto
Brownshale is a lithology unit in the middle of the Pematang Formation consisting of brown to black shale that is deposited in the lacustrine environment. Brownshale from the results of previous studies stated as the main source rock in the Central Sumatra Basin, which is spread over several troughs, namely Balam, Aman, Rangau, Kiri, and Bengkalis Troughs, where Bengkalis Trough is the most extensive Trough. In the shale hydrocarbon prospecting analysis, Brownshale from previous researchers concluded that it had good prospects, based on several parameters including: TOC values with poor to very good quality. Brownshale formation is a type of kerogene as kerogen type of II/III, brittleness index greater than 0.48, and rock compressive strength below 10,000 Psi. One method in the development phase of shale hydrocarbon is to determine the fracable sweetspot window using drill cuttings and TOC, because there is no core data available. Based on the results of the well log analysis of well BS-03, it is obtained information that the Brownshale formation has a thickness of 1028 feet with intercalation laminated shale/sand section, so the mineral content varies greatly. From the ternary diagram of XRD (bulk analysis) results of drill cuttings of Brownshale formation of well BS-03, it can be seen that mineral distribution of Quartz-Clay-Calcite (Q-C-C) is spread between zone 1 to zone 3, namely: Dominant Quartz - Minor Clay & Carbonate (Zone 1: Brittle Quartz Rich), Dominant Carbonate - Quartz & Minor Clay (Zone 2: Brittle Carbonate Rich), and Quartz & Carbonate Balance - Clay minor (Zone 3: Ductile, hard to frac). This shows that not all Brownshale formation intervals are easy to frac (high fracability). From the XRD result, percentage of mineral content (bulk analysis) of Brownshale drill cuttings, there is an interesting phenomenon, i.e. the presence of sillimanite and kaliophilite minerals significantly starting at a depth of 10,780 ft and below, where both minerals have tenacity: brittle, and also from the results of the MBT analysis seen an interesting phenomenon, i.e. at a depth interval of about 10,780 ft the value of CEC drops below 3 meq/100 grams, and can be categorized as the brittle shale. Referring to the presence of sillimanite and kaliophilite minerals, as well as low MBT values, then at intervals of 10,780 ft below, it can be seen that at the bottom of the depth interval as a fracable sweetspot window, and at the upper depth interval of the Brownshale formation, it is believed to be a fracture barrier.
{"title":"Shale Hydrocarbon Development Based on Drill Cuttings & TOC Analysis: Case Study of Brownshale Drill Cuttings of Well BS-03, Pematang Formation, Bengkalis Trough, Central Sumatra Basin","authors":"A. Buntoro, C. Prasetyadi, R. A. Wibowo, nbsp, Suranto","doi":"10.4236/ojogas.2020.53008","DOIUrl":"https://doi.org/10.4236/ojogas.2020.53008","url":null,"abstract":"Brownshale is a lithology unit in the middle of the Pematang Formation consisting of brown to black shale that is deposited in the lacustrine environment. Brownshale from the results of previous studies stated as the main source rock in the Central Sumatra Basin, which is spread over several troughs, namely Balam, Aman, Rangau, Kiri, and Bengkalis Troughs, where Bengkalis Trough is the most extensive Trough. In the shale hydrocarbon prospecting analysis, Brownshale from previous researchers concluded that it had good prospects, based on several parameters including: TOC values with poor to very good quality. Brownshale formation is a type of kerogene as kerogen type of II/III, brittleness index greater than 0.48, and rock compressive strength below 10,000 Psi. One method in the development phase of shale hydrocarbon is to determine the fracable sweetspot window using drill cuttings and TOC, because there is no core data available. Based on the results of the well log analysis of well BS-03, it is obtained information that the Brownshale formation has a thickness of 1028 feet with intercalation laminated shale/sand section, so the mineral content varies greatly. From the ternary diagram of XRD (bulk analysis) results of drill cuttings of Brownshale formation of well BS-03, it can be seen that mineral distribution of Quartz-Clay-Calcite (Q-C-C) is spread between zone 1 to zone 3, namely: Dominant Quartz - Minor Clay & Carbonate (Zone 1: Brittle Quartz Rich), Dominant Carbonate - Quartz & Minor Clay (Zone 2: Brittle Carbonate Rich), and Quartz & Carbonate Balance - Clay minor (Zone 3: Ductile, hard to frac). This shows that not all Brownshale formation intervals are easy to frac (high fracability). From the XRD result, percentage of mineral content (bulk analysis) of Brownshale drill cuttings, there is an interesting phenomenon, i.e. the presence of sillimanite and kaliophilite minerals significantly starting at a depth of 10,780 ft and below, where both minerals have tenacity: brittle, and also from the results of the MBT analysis seen an interesting phenomenon, i.e. at a depth interval of about 10,780 ft the value of CEC drops below 3 meq/100 grams, and can be categorized as the brittle shale. Referring to the presence of sillimanite and kaliophilite minerals, as well as low MBT values, then at intervals of 10,780 ft below, it can be seen that at the bottom of the depth interval as a fracable sweetspot window, and at the upper depth interval of the Brownshale formation, it is believed to be a fracture barrier.","PeriodicalId":65460,"journal":{"name":"长江油气:英文版","volume":" ","pages":""},"PeriodicalIF":0.0,"publicationDate":"2020-05-13","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"48392654","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 : 2020-01-22DOI: 10.4236/ojogas.2020.52005
Atif Zafar, Yuliang Su, Wendong Wang, S. G. Alam, Danish Khan, M. Yasir, A. AlRassas, I. Ahmad
In-situ conversion of process of oil shale has been technically proven as a pilot field project. Gradually heating the reservoir by using subsurface electric heaters converts the oil shale reservoir kerogen into oil, gas and other producible components. This process also enhances the internal energy of the porous media as well as the subsurface fluid. Heat is transmitted in the reservoir within each fluid by different processes i.e. , due to the flow of fluid called advective process, and due to molecular diffusion where dispersive and diffusive processes take place. Heat transfer through conduction and convection mechanisms in the porous media are modeled mathematically and numerically incorporating the advective, dispersive and diffusive processes in the reservoir. The results show the production of oil and gas as a result of conversion of kerogen due to modeled heat dissipation.
{"title":"Heat Dissipation Modeling of In-Situ Conversion Process of Oil Shale","authors":"Atif Zafar, Yuliang Su, Wendong Wang, S. G. Alam, Danish Khan, M. Yasir, A. AlRassas, I. Ahmad","doi":"10.4236/ojogas.2020.52005","DOIUrl":"https://doi.org/10.4236/ojogas.2020.52005","url":null,"abstract":"In-situ conversion of process of oil shale has been technically proven as a pilot field project. Gradually heating the reservoir by using subsurface electric heaters converts the oil shale reservoir kerogen into oil, gas and other producible components. This process also enhances the internal energy of the porous media as well as the subsurface fluid. Heat is transmitted in the reservoir within each fluid by different processes i.e. , due to the flow of fluid called advective process, and due to molecular diffusion where dispersive and diffusive processes take place. Heat transfer through conduction and convection mechanisms in the porous media are modeled mathematically and numerically incorporating the advective, dispersive and diffusive processes in the reservoir. The results show the production of oil and gas as a result of conversion of kerogen due to modeled heat dissipation.","PeriodicalId":65460,"journal":{"name":"长江油气:英文版","volume":" ","pages":""},"PeriodicalIF":0.0,"publicationDate":"2020-01-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"45709800","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 : 2020-01-01DOI: 10.4236/ojogas.2020.53007
A. Kerunwa, Princewill O. Ariche, Nkemakolam Chinedu Izuwa
Hydraulic fracturing is among the approaches used to optimize production from a gas condensate reservoir. A detailed economic analysis is required to evaluate the profitability and feasibility of hydraulic fracturing as an optimization option in a gas condensate reservoir operating below dewpoint. The objective of this research is to evaluate the economic benefits derivable from the use of hydraulic fracturing to improve gas and liquid recovery from a gas condensate reservoir operating below dewpoint. This research considers the use of four profit indicators to ascertain the profitability of hydraulic fracturing in a gas condensate reservoir operating below dewpoint by increasing the fracture halflength, fracture width and fracture permeability. The production data of the reservoir was obtained and the economic calculations done on excel spreadsheet and plots generated. The four profit indicators considered in the research are Net Present Value, Payout, Discounted Cash Flow Rate of Return and Profit per Dollar Invested. The economic justification was done by carrying out a comparative economic analysis from the result obtained when the reservoir of study was unfractured with that obtained when the reservoir was fractured at various fracture parameters. The economic analysis was done considering a royalty and tax rate of 18.5% and 30% respectively and a gas price of $2/MSCF and condensate price of $30/bbl. This is done so as to find out if the additional cost of hydraulic fracturing can be offset by the recovery from the reservoir when its pressure declined below dewpoint. The result obtained showed that the additional recovery due to hydraulic fracturing by increasing the fracture halflength, fracture width and fracture permeability was not enough to justify the application of hydraulic fracturing when the reservoir pressure declined below dewpoint.
{"title":"Economic Evaluation of Hydraulic Fracturing in a Gas Condensate Reservoir Operating below Dewpoint","authors":"A. Kerunwa, Princewill O. Ariche, Nkemakolam Chinedu Izuwa","doi":"10.4236/ojogas.2020.53007","DOIUrl":"https://doi.org/10.4236/ojogas.2020.53007","url":null,"abstract":"Hydraulic fracturing is among the approaches used to optimize production from a gas condensate reservoir. A detailed economic analysis is required to evaluate the profitability and feasibility of hydraulic fracturing as an optimization option in a gas condensate reservoir operating below dewpoint. The objective of this research is to evaluate the economic benefits derivable from the use of hydraulic fracturing to improve gas and liquid recovery from a gas condensate reservoir operating below dewpoint. This research considers the use of four profit indicators to ascertain the profitability of hydraulic fracturing in a gas condensate reservoir operating below dewpoint by increasing the fracture halflength, fracture width and fracture permeability. The production data of the reservoir was obtained and the economic calculations done on excel spreadsheet and plots generated. The four profit indicators considered in the research are Net Present Value, Payout, Discounted Cash Flow Rate of Return and Profit per Dollar Invested. The economic justification was done by carrying out a comparative economic analysis from the result obtained when the reservoir of study was unfractured with that obtained when the reservoir was fractured at various fracture parameters. The economic analysis was done considering a royalty and tax rate of 18.5% and 30% respectively and a gas price of $2/MSCF and condensate price of $30/bbl. This is done so as to find out if the additional cost of hydraulic fracturing can be offset by the recovery from the reservoir when its pressure declined below dewpoint. The result obtained showed that the additional recovery due to hydraulic fracturing by increasing the fracture halflength, fracture width and fracture permeability was not enough to justify the application of hydraulic fracturing when the reservoir pressure declined below dewpoint.","PeriodicalId":65460,"journal":{"name":"长江油气:英文版","volume":"1 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2020-01-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"70474501","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 : 2019-10-10DOI: 10.4236/ojogas.2019.44022
Z. Yin, Pingnan Yuan, Xiang Lian, Y. Zheng, Heng Zheng
The saturate, aromatics, resin and asphaltene components of paraffin-base (PB) and naphthenic-base (HB) crude oil are separated by chromatographic column. The acidic components of crude oil are extracted by compounded polar solvents and identified by methyl esterification of diazomethane. The acidic components before and after asphaltene removal are investigated by gas chromatography-mass spectrometer. The effect of four fractions in simulated oil on interfacial activity is discussed. The results show PB is rich in naphthalene series and tri-aromatic steroids, and HB has a high content of phenanthrene series, chrysene series and methylpyrene, besides higher content of naphthalene series. The long carbon chain acids in HB oil decrease significantly by asphaltenes removal, confirming the presence of heavy oil acids in asphaltene. A little amount of saturates and aromatics in simulated oil can reduce the interfacial tension (IFT). When the content of asphaltenes of simulated oil is increased, IFT is initially decreased and finally increased because of stability of asphaltenes. When resin is increased, IFT is initially increased and then decreased. Simulated oil containing the resin from naphthenic-base oil is more sensitive to alkali than that of paraffin-base resin, which can reduce the IFT between oil and water at a larger range.
{"title":"Components of Paraffin-Base and Naphthenic-Base Crude Oil and Their Effects on Interfacial Performance","authors":"Z. Yin, Pingnan Yuan, Xiang Lian, Y. Zheng, Heng Zheng","doi":"10.4236/ojogas.2019.44022","DOIUrl":"https://doi.org/10.4236/ojogas.2019.44022","url":null,"abstract":"The saturate, aromatics, resin and asphaltene components of paraffin-base (PB) and naphthenic-base (HB) crude oil are separated by chromatographic column. The acidic components of crude oil are extracted by compounded polar solvents and identified by methyl esterification of diazomethane. The acidic components before and after asphaltene removal are investigated by gas chromatography-mass spectrometer. The effect of four fractions in simulated oil on interfacial activity is discussed. The results show PB is rich in naphthalene series and tri-aromatic steroids, and HB has a high content of phenanthrene series, chrysene series and methylpyrene, besides higher content of naphthalene series. The long carbon chain acids in HB oil decrease significantly by asphaltenes removal, confirming the presence of heavy oil acids in asphaltene. A little amount of saturates and aromatics in simulated oil can reduce the interfacial tension (IFT). When the content of asphaltenes of simulated oil is increased, IFT is initially decreased and finally increased because of stability of asphaltenes. When resin is increased, IFT is initially increased and then decreased. Simulated oil containing the resin from naphthenic-base oil is more sensitive to alkali than that of paraffin-base resin, which can reduce the IFT between oil and water at a larger range.","PeriodicalId":65460,"journal":{"name":"长江油气:英文版","volume":" ","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-10-10","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"44912593","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 : 2019-08-06DOI: 10.4236/OJOGAS.2019.44018
C. Ejike
Gas hydrates are whitish balls containing enormous amount of methane gas at deep marine sediments. This energy source will account for future energy needs as it is said to be twice the value of all recoverable energy sources tapped till date. They are formed as a result of biogenic and thermogenic matters coupled with deep water conditions such as excessive pressure and diminishing temperature. Various recovery methods have been juxtaposed till date to influence the production of its reserves. However, appropriate assessment of the hazards and shortcomings hindering the large scale production of these reserve needs to be checkmated in order to facilitate the effective development of gas from methane hydrate in a near future.
{"title":"Assessment of Hazards in Gas Hydrates Recovery","authors":"C. Ejike","doi":"10.4236/OJOGAS.2019.44018","DOIUrl":"https://doi.org/10.4236/OJOGAS.2019.44018","url":null,"abstract":"Gas hydrates are whitish balls containing enormous amount of methane gas at deep marine sediments. This energy source will account for future energy needs as it is said to be twice the value of all recoverable energy sources tapped till date. They are formed as a result of biogenic and thermogenic matters coupled with deep water conditions such as excessive pressure and diminishing temperature. Various recovery methods have been juxtaposed till date to influence the production of its reserves. However, appropriate assessment of the hazards and shortcomings hindering the large scale production of these reserve needs to be checkmated in order to facilitate the effective development of gas from methane hydrate in a near future.","PeriodicalId":65460,"journal":{"name":"长江油气:英文版","volume":" ","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-08-06","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"44209821","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}
BZ Oilfield is a medium-sized oilfield with shallow delta facies deposits in Bohai Bay of China, compared with fluvial and delta facies oilfields, there is no mature experience for reference of reservoir configuration, well pattern arrangement and development model in offshore oilfields in China. In view of the difficulty in describing the reservoir configuration of shallow water delta, the single distributary sand dam in shallow water delta is characterized by well-seismic combination and multi-attribute constraints. The mathematical mechanism model of pinch-out position of sand body is established, fine characterization of BZ shallow water delta reservoir is put forward. The horizontal well pattern arrangement type for shallow water delta reservoir is proposed and the method of well pattern optimization based on vertical displacement theory is put forward. A method of inversion of reservoir connectivity using production dynamic data by numerical well testing is proposed and a new method for optimizing water injection rate in water injection wells is proposed aiming at the difficulty of recognizing injection-production connectivity of shallow water delta reservoirs. The fine configuration of BZ shallow water delta reservoir based on distributary sand dam is proposed, which guides the recognition of remaining oil distribution law. By deploying adjustment wells, the water flooding coincidence degree of actual drilling is 86% compared with that of pre-drilling prediction, which indicates that the research results of reservoir configuration can effectively guide the understanding of oilfield geology. Through the theoretical well arrangement type of vertical displacement of single sand body in horizontal wells of shallow water delta reservoir, a high water flooding recovery rate of 35% is achieved in primary well pattern. The connectivity coefficients of injection-production boundary of shallow water delta reservoir configuration are calculated, and the water injection distribution coefficients are obtained by normalizing the directional coefficients. This paper presents a configuration method based on multi-attribute fusion under the constraints of sedimentary process. In this paper, a shallow water delta reservoir configuration method based on multi-attribute fusion constrained by sedimentary process is proposed, and the injection-production connectivity coefficient and injection well distribution coefficient of the configuration boundary are calculated.
{"title":"Stable Production Technology for Horizontal Well Development in Shallow Water Delta Oilfield of Bohai Bay, China","authors":"Guangyi Sun, Qiongyuan Wu, Huijiang Chang, Xiaoming Chen, Shangqi Zhai","doi":"10.4236/ojogas.2019.44021","DOIUrl":"https://doi.org/10.4236/ojogas.2019.44021","url":null,"abstract":"BZ Oilfield is a medium-sized oilfield with shallow delta facies deposits in Bohai Bay of China, compared with fluvial and delta facies oilfields, there is no mature experience for reference of reservoir configuration, well pattern arrangement and development model in offshore oilfields in China. In view of the difficulty in describing the reservoir configuration of shallow water delta, the single distributary sand dam in shallow water delta is characterized by well-seismic combination and multi-attribute constraints. The mathematical mechanism model of pinch-out position of sand body is established, fine characterization of BZ shallow water delta reservoir is put forward. The horizontal well pattern arrangement type for shallow water delta reservoir is proposed and the method of well pattern optimization based on vertical displacement theory is put forward. A method of inversion of reservoir connectivity using production dynamic data by numerical well testing is proposed and a new method for optimizing water injection rate in water injection wells is proposed aiming at the difficulty of recognizing injection-production connectivity of shallow water delta reservoirs. The fine configuration of BZ shallow water delta reservoir based on distributary sand dam is proposed, which guides the recognition of remaining oil distribution law. By deploying adjustment wells, the water flooding coincidence degree of actual drilling is 86% compared with that of pre-drilling prediction, which indicates that the research results of reservoir configuration can effectively guide the understanding of oilfield geology. Through the theoretical well arrangement type of vertical displacement of single sand body in horizontal wells of shallow water delta reservoir, a high water flooding recovery rate of 35% is achieved in primary well pattern. The connectivity coefficients of injection-production boundary of shallow water delta reservoir configuration are calculated, and the water injection distribution coefficients are obtained by normalizing the directional coefficients. This paper presents a configuration method based on multi-attribute fusion under the constraints of sedimentary process. In this paper, a shallow water delta reservoir configuration method based on multi-attribute fusion constrained by sedimentary process is proposed, and the injection-production connectivity coefficient and injection well distribution coefficient of the configuration boundary are calculated.","PeriodicalId":65460,"journal":{"name":"长江油气:英文版","volume":" ","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-08-06","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"44700008","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 : 2019-08-06DOI: 10.4236/ojogas.2019.44019
Gang Liu, Chunzhi Luo, Baijing Wang
In order to improve the plugging and anti-collapse performance of water-based drilling fluid, a polymer film-forming plugging agent LWFD is synthesized by emulsion polymerization. The effect of the agent on rheology, API filtration loss, lubricity and film plugging of polymer drilling fluid and cationic drilling fluid is evaluated in laboratory. The experimental results show that the agent has little effect on the rheology and filtration loss of polymer drilling fluid and cationic drilling fluid, and can improve the lubricity of drilling fluid. The synthesized polymer film-forming plugging agent LWFD has good plugging properties for sand discs with different permeabilities, and the agent can effectively improve the film-forming plugging and temperature resistance of drilling fluid when combined with the inorganic nano-plugging agent NMFD. The high performance polymer drilling fluid formed by introducing polymer film-forming plugging agent LWFD and inorganic nano-plugging agent NMFD into polymer drilling fluid has comparable performance as Halliburton’s SHALEDRIL high performance drilling fluid, which can meet the requirements of on-site drilling and has application value.
{"title":"The Research of Polymer Film-Forming Plugging Agent for Drilling Fluid","authors":"Gang Liu, Chunzhi Luo, Baijing Wang","doi":"10.4236/ojogas.2019.44019","DOIUrl":"https://doi.org/10.4236/ojogas.2019.44019","url":null,"abstract":"In order to improve the plugging and anti-collapse performance of water-based drilling fluid, a polymer film-forming plugging agent LWFD is synthesized by emulsion polymerization. The effect of the agent on rheology, API filtration loss, lubricity and film plugging of polymer drilling fluid and cationic drilling fluid is evaluated in laboratory. The experimental results show that the agent has little effect on the rheology and filtration loss of polymer drilling fluid and cationic drilling fluid, and can improve the lubricity of drilling fluid. The synthesized polymer film-forming plugging agent LWFD has good plugging properties for sand discs with different permeabilities, and the agent can effectively improve the film-forming plugging and temperature resistance of drilling fluid when combined with the inorganic nano-plugging agent NMFD. The high performance polymer drilling fluid formed by introducing polymer film-forming plugging agent LWFD and inorganic nano-plugging agent NMFD into polymer drilling fluid has comparable performance as Halliburton’s SHALEDRIL high performance drilling fluid, which can meet the requirements of on-site drilling and has application value.","PeriodicalId":65460,"journal":{"name":"长江油气:英文版","volume":" ","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-08-06","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"45565158","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 : 2019-08-06DOI: 10.4236/ojogas.2019.44023
Xie Liangcheng, Ding Kangle, Yan Liu, Zou Mei, H. Chao
The corncob hydrochar is prepared by using a stainless autoclave at 230°C for 8 h. The products are characterized by elemental analyzer, Fourier Transform infrared spectroscopy (FT-IR), X-ray diffraction (XRD) and scanning electron microscope (SEM). The effects of hydrochar dosage, pH, adsorption time and phenol concentration on the adsorption performance of hydrochar are investigated by means of single-factor experimental analysis. Based on the experiments the adsorption thermodynamic and kinetics are tentatively discussed. The results show that abundant oxygen-containing functional groups are scattered on the surface of the corncob hydrochar. The adsorption kinetics of phenol on the hydrochar corresponds well with pseudo-second-order kinetic model. Thermodynamic studies indicate that Freundlich adsorption isotherm model is much better than Langmuir model in describing the adsorption of phenol on the corncob hydrochar at 25°C - 45°C. This study provides scientific basis for the development of cheap and efficient adsorbents for the removal of phenols derived from oilfield wastewater.
{"title":"Experimental, Thermodynamic and Kinetic Studies for the Adsorption of Phenolic Compounds Derived from Oilfield Wastewater by the Corncob Hydrochar","authors":"Xie Liangcheng, Ding Kangle, Yan Liu, Zou Mei, H. Chao","doi":"10.4236/ojogas.2019.44023","DOIUrl":"https://doi.org/10.4236/ojogas.2019.44023","url":null,"abstract":"The corncob hydrochar is prepared by using a stainless autoclave at 230°C for 8 h. The products are characterized by elemental analyzer, Fourier Transform infrared spectroscopy (FT-IR), X-ray diffraction (XRD) and scanning electron microscope (SEM). The effects of hydrochar dosage, pH, adsorption time and phenol concentration on the adsorption performance of hydrochar are investigated by means of single-factor experimental analysis. Based on the experiments the adsorption thermodynamic and kinetics are tentatively discussed. The results show that abundant oxygen-containing functional groups are scattered on the surface of the corncob hydrochar. The adsorption kinetics of phenol on the hydrochar corresponds well with pseudo-second-order kinetic model. Thermodynamic studies indicate that Freundlich adsorption isotherm model is much better than Langmuir model in describing the adsorption of phenol on the corncob hydrochar at 25°C - 45°C. This study provides scientific basis for the development of cheap and efficient adsorbents for the removal of phenols derived from oilfield wastewater.","PeriodicalId":65460,"journal":{"name":"长江油气:英文版","volume":" ","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-08-06","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"49548193","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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