GeoArabia, Journal of the Middle East Petroleum Geosciences最新文献

{"title":"Horizontal wells optimize production in a super K sandstone reservoir Minagish Field, West Kuwait. 9th Middle East Geosciences Conference, GEO 2010.","authors":"T. El-Gezeery","doi":"10.3997/2214-4609-pdb.248.281","DOIUrl":"https://doi.org/10.3997/2214-4609-pdb.248.281","url":null,"abstract":"The Burgan reservoirs in the Minagish Field are clastic sandstone reservoirs with super-K permeability. The upper reservoir layer consists of fluvial sandstones with grain sizes ranging between medium to coarse. The average porosity is about 28 to 35% and the average permeability varies between 0.7 to 10 Darcy. This reservoir has been a production challenge due to early water breakthrough resulting from coning. We present a case study in which horizontal well technology has been used to mitigate risk of water coning besides enhancing productivity. At the early stages six vertical wells were completed in the Burgan reservoirs with low production rates. Water coning was a major problem because of the homogeneous massive nature of the sand bodies that probably have vertical to horizontal ratios (Kv/Kh) close to 1. The high ratio between the oil viscosity and the water viscosity is also a major reason for coning. Although the first horizontal well drilled in 2005 (with 950 feet of net pay) achieved unprecedented production rates, its production life was short. Water coning and early water breakthrough was due to several factors: (1) low stand-off with the oil/water contact (OWC); (2) high off-take rates; and (3) the presence of a fault acting as a conduit. The second horizontal well was completed at the uppermost part of the reservoir where the facies grade from marine siltstones and shales to fluvial clean sand package. Only 300 ft of the heel out of 1,000 ft horizontal section has been penetrated. Based on the study sweet spots were defined by taking into account: (1) control on production rates; (2) stand-off from the overlying marine shale; (3) level of the oil/water contact; and (4) absence of significant faulting. Five horizontal wells were drilled and successfully completed in targeted sweet spots, achieving a dry oil production and minimizing the possibility of water coning.","PeriodicalId":275861,"journal":{"name":"GeoArabia, Journal of the Middle East Petroleum Geosciences","volume":"81 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"1900-01-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"134445868","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":"Application of magnesium yield measurement from neutron spectroscopy tool in formation evaluation of northern Kuwait fields. 9th Middle East Geosciences Conference, GEO 2010.","authors":"D. Kho","doi":"10.3997/2214-4609-pdb.248.267","DOIUrl":"https://doi.org/10.3997/2214-4609-pdb.248.267","url":null,"abstract":"Evaluation of porosity and lithology has always been done through a combination of density, photoelectric factor (PEF), neutron, gamma-ray, and sonic measurements. None of these directly gives porosity or lithology. Therefore, common practice includes building petrophysical models to extract these reservoir properties. Geoscientists involved in petrophysical analysis using multi-mineral solvers are aware of the difficulty and the uncertainty of the process; for example, changing a fluid property in the model will change the lithology as well as the porosity. The logs themselves are also known to have their own measurement uncertainties. The density log, for example, is affected by bad hole, lithology, barite, and light hydrocarbons. The neutron log is affected by lithology, fluid hydrogen index, and the borehole properties (temperature, pressure, hole size, stand-off, mud cake, mud weight, etc.). The interpretation is also complicated by the fact that different neutron tools from different logging companies have different sensitivities to lithology. Sonic log data is also used for interpretation even though it is affected by fractures, vuggy porosity, anisotropy, etc. The PEF curve is commonly used as an additional tool to solve for the lithology. However, if the mud contains barite the measurement becomes unusable.\u0000\u0000Dolomite and solid bitumen quantifications have been the challenging issues in carbonate evaluation. The dolomite diagenesis involves the recrystallization which makes the dolomite less susceptible to porosity reduction caused by overburden pressure. This unique characteristic of the crystallized dolomite makes it an important reservoir rock especially in deep carbonate reservoirs. On the other hand, the presence of solid bitumen is always associated with poor reservoir quality. Also, the physical properties of the solid bitumen cause it to appear as hydrocarbon. If not corrected, the formation evaluation result will give incorrect porosity and water saturation computation.\u0000\u0000New development in neutron capture spectroscopy tool provides significant data to quantify the mineralogy in carbonate, especially the dolomite content through magnesium yield measurement. Combination of the spectroscopy data and magnetic resonance data can be used to identify and correct the solid bitumen effects. Real examples from deep carbonate reservoir in northern Kuwait fields and the validation against core data will be presented.","PeriodicalId":275861,"journal":{"name":"GeoArabia, Journal of the Middle East Petroleum Geosciences","volume":"57 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"1900-01-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"122574917","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":"Critical factors of carbonate pore systems: Implications for reservoirs in the Middle East. 9th Middle East Geosciences Conference, GEO 2010.","authors":"O. Weidlich","doi":"10.3997/2214-4609-pdb.248.217","DOIUrl":"https://doi.org/10.3997/2214-4609-pdb.248.217","url":null,"abstract":"Generating predictive models for reservoir quality distribution is challenging for carbonate reservoirs. Usually, quantitative porosity data for these models are exclusively derived from conventional core-plug measurements or log data (log-derived effective porosity, bulk density, interval transit time, and nuclear magnetic resonance in rare cases). For this study, conventional porosity-permeability plots from plugs and log data of Cretaceous and Jurassic carbonates were analysed using data from several offshore wells in Qatar. The following observations are based on data from Kharaib, Yamama, Upper Sulaiy, Lower Sulaiy and Arab samples: (1) Porosity-permeabilty plots of the above stratigraphic units show a significant overlap of data despite some minor trends. (2) Core plug porosity data do not decrease with depth. (3) Cross plots of log-derived and core-plug porosities show no trend; for example core-plug porosities were higher, similar or lower than equivalent porosity log data (notably neutron pososity).\u0000\u0000Our observations suggest that additional parameters need to be considered to improve reservoir models. The concept of reservoir rock types has been repeatedly regarded as an effective tool that integrates geologic observations with porosity and permeability data. We combine under consideration of sedimentologic and diagenetic factors conventional porosity data from plugs and logs with image analysis-based pore size, analysis from high-resolution core photos and thin sections. With this approach we established a six-fold reservoir rock type concept for the investigated Jurassic – Cretaceous carbonates to better characterize the variability of pore space and pore geometries of reservoir units.","PeriodicalId":275861,"journal":{"name":"GeoArabia, Journal of the Middle East Petroleum Geosciences","volume":"24 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"1900-01-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"114780189","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":"Origin, distribution and petrophysical properties of high porosity/permeability sub-horizontal drains within a dolomitised sequence: Lessons learned from outcrop analogue. 9th Middle East Geosciences Conference, GEO 2010.","authors":"Di Cuia, A. Riva, B. Caline, C. Pabian-Goyheneche","doi":"10.3997/2214-4609-pdb.248.131","DOIUrl":"https://doi.org/10.3997/2214-4609-pdb.248.131","url":null,"abstract":"Dolomite sequences and intervals often show the best reservoir potentials and are considered as key productive zones. It is difficult to completely unravel the diagenetic evolution of a carbonate sequence because of the complexity and variety of the processes that affect the rocks through their evolution. This is mainly due to the interactions between different processes and, in subsurface, because of the lack of complete datasets or the limited spatial representativity of well data. The origins and spatial variability of reservoir properties in structurally-controlled, partially dolomitised reservoirs are poorly understood because of their complexity. The use of outcrop analogues for better understanding subsurface reservoirs is essential to reduce some of the main reservoir uncertainties. The geometry, internal heterogeneity and petrophysical properties of dolomite bodies were studied in a Jurassic partially dolomitised outcrop analogue in the Southern Alps using an integrated, multidisciplinary approach. Dolomitisation of the lower part of the studied section led to the development of good petrophysical properties for a potential hydrocarbon reservoir, in particular by the formation of porosity systems interconnected with fracture and fault networks, hence assuring a consistent permeability through the entire sequence. The dolomitisation process determined a highly variable porosity network controlled by the original facies, the degree of dolomitisation and the structural framework. Near open fracture swarms or faults, the dolomitisation front tends to uprise, sometimes generating vertical chimneys that can cross the overlying sedimentary succession. In these zones the dolomite is massive, with a complete reworking of the original limestone, sometimes with strong evidence of hydro fracturing related to overpressured fluids. From these vertical dolomite bodies, high porosity and permeability bedding-parallel dolomitic bodies develop with lenticular or planar shape. These bodies can be 10’s of meters in length and 1–3 meters in thickness and are often stacked one on top of the other along major fault zones. Based on core samples the porosity associated with these dolomitic bodies can be up to 25–30% with an extremely good connectivity. Matrix porosity and permeability, directly measured on plug analysis, vary respectively between 0.5–25% and 0.05–40 m Darcy. These petrophysical data appear strongly related to the diagenetic facies associations.","PeriodicalId":275861,"journal":{"name":"GeoArabia, Journal of the Middle East Petroleum Geosciences","volume":"3 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"1900-01-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"124134739","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":"Biosteering the Upper Permian Khuff C reservoirs in Saudi Arabia. 9th Middle East Geosciences Conference, GEO 2010.","authors":"G. Hughes, Saleh S. Enezy, Samir Rashid","doi":"10.3997/2214-4609-pdb.248.182","DOIUrl":"https://doi.org/10.3997/2214-4609-pdb.248.182","url":null,"abstract":"Coiled-tube, under-balance drilling is being used to improve gas and condensate recovery from the Khuff C reservoir in Haradh area of southern Ghawar Field. The 2 5/8 inch diameter coiled-tube inhibits access of conventional wireline logging tools except gamma and LWD, and the only source of stratigraphic control is micropalaeontological and petrographic data gathered while drilling, referred to as biosteering. Recent experience has shown that coiled-tube drilling can successfully be steered using rapid thin-section production with micropalaeontological and petrographic analysis of cuttings samples. Stratigraphic location is achieved by reference to a local biozonation based either on core or cuttings samples from the mother bore or adjacent wells. Although of shallow-marine origin, Khuff C depositional environments were found to be highly varied over short distances, and it is necessary to establish reference biofacies-based biozonations for each well using, where possible, the closest cored well. Stratigraphic control is possible to within 2 ft vertical accuracy, and enables near real-time critical instructions to be communicated to the directional driller ahead of the gamma data. As the “eyes” of the drill, this technique has enabled maintenance of the bit within the target reservoir and resulted in significant increase in gas and condensate production.","PeriodicalId":275861,"journal":{"name":"GeoArabia, Journal of the Middle East Petroleum Geosciences","volume":"14 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"1900-01-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"131685379","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":"Wavelet transform modulus maxima lines analysis of seismic data for delineating reservoir fluids. 9th Middle East Geosciences Conference, GEO 2010.","authors":"S. Ouadfeul","doi":"10.3997/2214-4609-pdb.248.370","DOIUrl":"https://doi.org/10.3997/2214-4609-pdb.248.370","url":null,"abstract":"The main goal of the proposed idea is to use the wavelet transform modulus maxima lines (WTMM) method to delineate reservoir fluids. First a seismic seismogram is generated using the convolution of the Ricker wavelet with the reflectivity function calculated from the measured sonic and density well logs data. Obtained seismogram is analyzed by the WTMM in order to calculate the singularities spectrum based on the direct Legendre transform of the spectrum of exponents. Application of this technique at the real data of a borehole located in the Algerian Sahara is realized. Thus singularities spectrum is estimated at corresponding depth of the following fluid types: gas, oil, water, gas-oil and oil-water. Consequently, the obtained results allow taking a decision about the fluid nature contained in the reservoir rocks’ pores. We have applied the proposed technique at two other boreholes, obtained results demonstrate that the wavelet transform modulus maxima lines technique can give more idea about hydrocarbon nature and can enhance reservoir characterization.","PeriodicalId":275861,"journal":{"name":"GeoArabia, Journal of the Middle East Petroleum Geosciences","volume":"53 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"1900-01-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"128312659","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":"Sedimentology and diagenetic history with reference to reservoir quality, Triassic Lower Jilh (Kra Al Maru Reservoir), Kuwait. 9th Middle East Geosciences Conference, GEO 2010.","authors":"D. Khan","doi":"10.3997/2214-4609-pdb.248.399","DOIUrl":"https://doi.org/10.3997/2214-4609-pdb.248.399","url":null,"abstract":"The name Kra Al Maru has been assigned to the additional unit at the lowermost part of the Middle Triassic Jilh Formation in Mutriba and Kra Al Maru area in western Kuwait. Stratigraphically the interval corresponds to the Jilh C Member of the Jilh Formation, and it is divisible into lower (KM-B) and upper (KM-A) units. Microfacies comprise anhydrite, dolomudstone, dolowackestone, argillaceous dolostone and dolomitic shales with minor dolopackstone, dolograinstone, lime mudstone, lime wackestone. Carbonaceous matter and terrigenous material is present at places. Anhydrite is present as early nodules and crystals, as well as late cement and vug fillings. Facies associations of both units are bioturbated, highly variable with common organic matters. The distinguishing feature of the lower unit (KM-B) is having less anhydrite than the upper unit (KM-A). The lower unit was deposited in intertidal to subtidal and lagoonal environments, as a shallowing upward sequence that grades upward to algal laminated wackestone and anhydrite. The presence of few sub-aerial exposure surfaces indicates dissolution that might have developed at the end of cycle and is indicative of slightly humid conditions. The upper unit was deposited in an intertidal to supratidal, sabkha environment under arid climate. Diagenetic events include compaction, dolomitization, and replacement by anhydrite, fracturing and stylolization. Primary porosities were reduced by compaction, overdolomitisation and late stage cementation. Both cemented and uncemented fractures are observed in the core and microfractures are seen in core plugs and have led to increased fracture porosity and permeability. The lower unit is ranked and pursued as new prospective units within the Jilh Formation.","PeriodicalId":275861,"journal":{"name":"GeoArabia, Journal of the Middle East Petroleum Geosciences","volume":"237 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"1900-01-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"116296690","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":"Impact of high-resolution seismic from reservoir modeling Minagish Oolite reservoir, Minagish Field, Kuwait. 9th Middle East Geosciences Conference, GEO 2010.","authors":"A. Ebaid","doi":"10.3997/2214-4609-PDB.248.452","DOIUrl":"https://doi.org/10.3997/2214-4609-PDB.248.452","url":null,"abstract":"The Minagish Field has several reservoirs with oil accumulated primarily in the Lower Cretaceous middle member of the Minagish Oolite rocks (MMO). This giant carbonate hydrocarbon accumulation was discovered in 1959 and accounts for over 90% of oil production in the field. As the reservoir pressure started to decline, there was a need for water injection on the flanks of the structure to support the reservoir pressure and to increase the oil production. The sequence-stratigraphic analysis based on well logs, cores and the old 3-D seismic subdivided the reservoir into 13 geological layers with multiple phases of ooid shoal development. The Minagish Oolite reservoir has a 50 to 120 feet thick tar mat underlying the oil column. It is present in many, but not all, flank wells. It occurs at differing depths, between 9,700 ft and 9,935 ft TVDSS, and is deeper to the south of the field. The water has been injected in the layers above and below the tar mat in order to support the reservoir pressure on the crest. The well surveillance data interpretation of the injector Well MN “A” shows that layers below tar mat have very low injectivity compared with the layers above. The nearby producing Well MN “B” shows a water breakthrough in the upper layers whereas the lower layers are not affected by water. The lower oolite sediments possibly have a moderately progradational clinoforms stacking pattern which are weakly imaged by the old conventional 3-D seismic data. There is some uncertainty in the definition of flooding events between wells. In 2006, a high-resolution 3-D seismic survey was acquired to improve reservoir characterization. Progradational dipping clinoforms geometries are detected to the east of Minagish structure which led us to better definition of the reservoir architecture at this particular area in the field. This has a direct impact on Minagish Oolite reservoir modeling.","PeriodicalId":275861,"journal":{"name":"GeoArabia, Journal of the Middle East Petroleum Geosciences","volume":"17 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"1900-01-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"125914968","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":"Fracture characterization and modeling of unconventional Najmah-Sargelu reservoirs of Umm Gudair Field, West Kuwait. 9th Middle East Geosciences Conference, GEO 2010.","authors":"A. Al-Shamali, D. S. Ray, N. Verma, Saad Matar, V. Groen, G. Joussineau, W. Al-Khamees","doi":"10.3997/2214-4609-pdb.248.153","DOIUrl":"https://doi.org/10.3997/2214-4609-pdb.248.153","url":null,"abstract":"The Najmah-Sargelu unconventional naturally fractured carbonate reservoirs are spread across many fields in West Kuwait, some of which, such as Umm Gudair are on production for the last 25 years. Natural fractures have a significant impact on the reservoir performance as they affect well productivity. Therefore, understanding their significance through fracture characterization is helpful in well placement and field development. This presentation shows an overview of the efforts to build a 3-D stochastic fracture model for reservoir characterization in the Umm Gudair Field. The model is generated in FracaFlow© through the analysis and integration of well data like cores (including oriented core), borehole images (BHI), well-logs, mud losses, production logging and well test data along with 3-D Q-Seismic data through structural, seismic attribute and seismic facies analyses.\u0000\u0000The impact of lithology on fracture occurrence was quantified based on rock-typing and distributed using a high-resolution, sequence-stratigraphic framework. Rock types are a real 3-D fracture driver and provide a reliable means of adjusting the density of diffuse fracture in the Najmah-Sargelu reservoirs of Umm Gudair Field. Three sets of diffuse fractures were identified from borehole image data: N20°E, EW and N170°E. Large-scale fracture corridors including sub-seismic faults, identified from seismic analysis were calibrated with core and BHI fractures through fracture data analysis workflows. The model finally incorporates two scales of tectonic fractures: diffuse fractures and large-scale fractures that have a direct bearing on well and field production behavior. The fracture calibration was performed using the dynamic data set such as production log and well wise production data. Synthetic well tests were simulated and matched with the real build-up data at wells. These data were then used to propagate 3-D fracture properties (fracture porosity, fracture permeability and equivalent block size) for constructing a reservoir simulation model.","PeriodicalId":275861,"journal":{"name":"GeoArabia, Journal of the Middle East Petroleum Geosciences","volume":"55 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"1900-01-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"131081852","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":"Reservoir porosity and permeability prediction from petrographic data using artificial neural network: A case study from Saudi Arabia. 9th Middle East Geosciences Conference, GEO 2010.","authors":"O. Abdullatif","doi":"10.3997/2214-4609-pdb.248.103","DOIUrl":"https://doi.org/10.3997/2214-4609-pdb.248.103","url":null,"abstract":"Understanding reservoir heterogeneity is essential for the assessment and the prediction of reservoir properties and quality. This study investigates the prediction of the reservoir petrophysical properties of the Ordovician Upper Dibsiyah Member of the Wajid Sandstone in southwest Saudi Arabia. The artificial neural networks (ANNS) technique was used to study pattern recognition and correlation among the petrographic thin section data such as grain size, sorting, matrix and cementation percentages, and petrophysical properties of the reservoir such as porosity, permeability and lithofacies. For this purpose, artificial intelligence techniques were designed and developed and these are the multilayer perception (MLP) and the general regression neural network (GRNN). The good agreement between core data and predicted values by neural networks demonstrated a successful implementation and validation of the network’s ability to map a complex non-linear relationship between petrographic data, permeability and porosity. The GRNN technique provides better prediction of the reservoir properties than that obtained from the use of the MLP technique.","PeriodicalId":275861,"journal":{"name":"GeoArabia, Journal of the Middle East Petroleum Geosciences","volume":"11 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"1900-01-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"125142354","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}