长江油气:英文版最新文献

{"title":"Experimental Investigation on Hydrothermal Reduction of Sulfates to H2S and Organic Sulfides by Ethene","authors":"H. Chao, Ding Kangle, Yan Liu, Fujia Guan, Zou Mei, Zhenzhen Yu, Yi Wu","doi":"10.4236/ojogas.2020.54015","DOIUrl":"https://doi.org/10.4236/ojogas.2020.54015","url":null,"abstract":"The kinetic characteristics of alkenes involved in thermochemical sulfate reduction (TSR) have been never reported in geological literature. In this study, TSR by ethene under hydrothermal conditions was performed in the constrained simulation experiments. Typical TSR products consisted of H2S, CO2, mercaptans, sulfides, thiophenes derivatives and benzothiophene. The apparent activation energy E and apparent frequency factor A for TSR by ethene were determined as 76.370 kJ/mol and 4.579 s-1, respectively. The lower activation energy for ethene involved in TSR relative to ethane suggested that the reactivity of ethene is much higher than that of ethane, in accordance with the thermodynamic analysis. Rate constants were determined experimentally using first-order kinetics extrapolate to MgSO4 half-lives of 67.329 years - 3.053 years in deep burial diagenetic settings (120°C - 180°C). These values demonstrate that the reaction rate for TSR by ethene is extraordinarily fast in high-temperature gas reservoirs (120°C - 180°C). Consequently, the newly formed ethene from thermal cracking and TSR alteration of natural gas and/or petroleum could not survive after TSR process and were rarely detected in natural TSR reservoirs.","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":"42910495","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}

{"title":"Development and Performance Evaluation of a Deep Water Synthetic Based Drilling Fluid System","authors":"Zengwei Chen, Yongxue Lin, Ninghui Dou, C. Xiao, H. Zhou, Yu Deng, Yuqiao Zhou, Wang Song, Dichen Tan, Huaiyuan Long","doi":"10.4236/ojogas.2020.54013","DOIUrl":"https://doi.org/10.4236/ojogas.2020.54013","url":null,"abstract":"With the enhancement of environmental protection awareness, the requirements on drilling fluid are increasingly strict, and the use of ordinary oil-based drilling fluid has been strictly restricted. In order to solve the environmental protection and oil-gas reservoir protection problems of offshore oil drilling, a new synthetic basic drilling fluid system is developed. The basic formula is as follows: a basic fluid (80% Linear a-olefin + 20% Simulated seawater) + 2.5% nano organobentonite + 3.5% emulsifier RHJ-5# + 2.5% fluid loss agent SDJ-1 + 1.5% CaO + the right amount of oil wetting barite to adjust the density, and a multifunctional oil and gas formation protective agent YRZ has been developed. The performance was evaluated using a high-low-high-temperature rheometer, a high-temperature and high-pressure demulsification voltage tester, and a high-temperature and high-pressure dynamic fluid loss meter. The results show that the developed synthetic based drilling fluid has good rheological property, demulsification voltage ≥ 500 V, temperature resistance up to 160°C, high temperature and high pressure filtration loss < 3.5 mL. After adding 2% - 5% YRZ into the basic formula of synthetic based drilling fluid, the permeability recovery value exceeds 90% and the reservoir protection effect is excellent. The new synthetic deepwater drilling fluid is expected to have a good application prospect in offshore deepwater drilling.","PeriodicalId":65460,"journal":{"name":"长江油气:英文版","volume":"1 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2020-07-31","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"41875569","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}

{"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}

{"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}

{"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}

{"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}

{"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}

{"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}

{"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}

{"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}