Day 3 Wed, August 07, 2019最新文献

{"title":"Third Party Tariff: A Key Input to NOV Projects Decision Analysis & Decision Quality","authors":"P. Obeahon, C. Ikpera, A. Laoye","doi":"10.2118/198852-MS","DOIUrl":"https://doi.org/10.2118/198852-MS","url":null,"abstract":"\u0000 The paper seeks to find the optimum solution on how to develop some portion of a unitized field. The case study involves two fields straddling across four oil mining leases (OMLs), in Niger Delta, Nigeria. Each field were operated independently by JV-A and JV-B until mid-2016 when the operatorship of the straddling reservoirs (SRs) in the unit was granted to JV-B by the regulators, as it is a law in Nigeria that all straddling reservoirs should be developed as a unit under a single operator.\u0000 The decision on whether JV-A should grant JV-B the right to also operate the non-straddling reservoirs (NSRs) in the unit will depend on the amount of tariff imposed. JV-A will be required to pay hydrocarbon transportation and processing tariffs if it flows its share of the produced hydrocarbon through JV-B's existing facility. The exact amount of tariff is unknown and will be negotiated. Additionally, four feasible evacuation routes exist and will be considered for this evaluation to decide the most profitable and capital efficient investment option.\u0000 The result shows that the opportunity is very sensitive to hydrocarbon handling tariff; necessitating JV-A choice of evacuation route. In addition, the paper demonstrates how using appropriate project framing and considerations of who will operate the JV-A's non-straddling reservoirs, relied heavily on different hydrocarbon transportation and processing tariffs. It is hoped that this paper having highlighted the importance of tariff charges and the role of proper framing on decision quality will encourage decision makers to adopt this approach during decision analysis and ultimately improve the quality of investment decisions particularly for Non-operated venture (NOV) projects.","PeriodicalId":11250,"journal":{"name":"Day 3 Wed, August 07, 2019","volume":"22 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-08-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"74575466","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":"Gains of an Effective Community Management Framework: The OML26 Experience","authors":"Blessyn Okpowo, Ebenezer Ageh, Peter Agodo, A. Okon, B. Mfon, Tata Emmanuel","doi":"10.2118/198802-MS","DOIUrl":"https://doi.org/10.2118/198802-MS","url":null,"abstract":"\u0000 The Oil Mining License (OML) 26 Asset is in Isoko North Local Government Area, about 60km east of Warri in Delta State, an onshore asset in the northern Niger Delta. NPDC and FHN are partners for a joint operation of the mining lease and currently executes its function through an Asset Management Team (AMT), comprising employees of NPDC and FHN.\u0000 The company (OML 26 JV) entered into a Global Memorandum of Understanding (GMOU) with OML 26 host communities to create an understanding and guide its relationship with the communities. The GMOU did not produced the desired result as OML 26 operations have often been interrupted by Community related issues. There is a lack of mutual trust on both sides and the Community and its agents tend to hold the company to ransom at the slightest opportunity. In a bid to reverse the trend, the AMT took the initiative to step back and assess the root cause of the acrimony, thoroughly engage the right elements within the Community to gauge their perspectives, and then developed a series of initiatives aimed at regaining the trust of the host communities. A framework is being developed that has engendered collaboration with the host communities (within its operating area) to build a mutually beneficial and symbiotic relationship that enables each party to achieve their goals and aspirations albeit in a peaceful, hitch free atmosphere. The AMT in line with the vision of the JV Partners is committed to sustainable community development, human capital development and capacity building, economic empowerment, and infrastructural growth. This paper highlights the key elements of the framework and the engagement strategies that has enabled the AMT to enjoy relative peace and operational stability while ramping up production and executing developmental projects in the communities.","PeriodicalId":11250,"journal":{"name":"Day 3 Wed, August 07, 2019","volume":"17 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-08-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83099697","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":"Single Trip Tubing Conveyed Perforations Across Multi-Lobed Differentially Depleted Reservoir Complexes In A Highly Deviated Well – Challenges, Lessons Learned & Best Practices","authors":"Ejimofor Agbo, Chinedu Anyanwu, Oluwasola Olowoyeye, Titus Ini, Victor Emah","doi":"10.2118/198757-MS","DOIUrl":"https://doi.org/10.2118/198757-MS","url":null,"abstract":"\u0000 This paper demonstrates how 280ft of oil column spread unevenly across multiple and differentially depleted reservoir units separated by shale layers of varying thicknesses in a highly deviated (62 deg.) well was perforated in a one trip system and how the project cost was minimized by achieving multiple perforations in a single trip whilst retaining capacity to effectively cure losses and mitigating post-perforation well control risks. Against the conventional perforation methodology where reservoir units are perforated individually, isolated before carrying out the next perforation in the subsequent reservoir. The one trip system was designed and deployed in one run targeting all the 6 separate carefully selected sand lobes in one run ensuring good standoff from the contact and zonal isolation behind casing. Successful execution was confirmed with all the expected physical outcomes which includes pipe vibration, brine loss as well inspection of the spent guns. A post perforation noise and production logging also confirmed flow across all planned perforation intervals. Perforation of a highly deviated well in differentially depleted multi-lobed reservoirs present significant operational risks. This paper illustrates how one can safely collapse multiple conventional perforation runs into a single trip with its attendant benefits on cost efficiency, crossflow and well control. This is the first of its kind in a swampy terrain, shallow offshore Niger Delta.","PeriodicalId":11250,"journal":{"name":"Day 3 Wed, August 07, 2019","volume":"47 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-08-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88579467","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":"Machine Learning Application to Permeability Prediction Using Log & Core Measurements: A Realistic Workflow Application for Reservoir Characterization","authors":"Francis Eriavbe, Uzoamaka Okene","doi":"10.2118/198874-MS","DOIUrl":"https://doi.org/10.2118/198874-MS","url":null,"abstract":"\u0000 The use of Artificial Intelligence continues to grow in popularity within the geosciences in view of ever-growing complexity and magnitude of available subsurface data. This is equally evident by the need for faster and accurate interpretations required to find hydrocarbons in ever more challenging and increasingly complex basins. This drive is made necessary in a continuously evolving and cost conscious petroleum industry business environment.\u0000 Advances in computing architecture now easily allows for more common application of machine learning techniques in day to day geoscience workflows. The use of machine learning in permeability prediction is becoming ever more common place as more specialists adopt this technique for modelling and prediction purposes. Typical machine learning techniques include Fuzzy Logic, Artificial Neural Networks (ANN) and Self Organizing Maps (SOM) amongst others which are run both in supervised and unsupervised modes. The described workflow in this paper was carried out using an available commercial standard petrophysical package with ANN built in modules. This paper describes a typical workflow for predicting reservoir permeability based on an integrated workflow utilizing core measurements integrated with available log data.\u0000 Permeability is a key rock parameter for understanding fluid flow dynamics and flow rates and its modelling usually poses some unique challenges. Traditionally and statistically, this can be done at a fairly coarse level in cored wells by utilizing Poro-Perm correlations that usually do not capture fine scale variability observed at core scale measurement. These Poro-Perm transforms are subsequently applied on uncored wells to predict permeability. This paper analyses a workflow that aims to utilize a depth-normalized log and core data set trained using an Artificial Neural Network (ANN) module, blind tested on few key cored wells and subsequently used to predict permeability in uncored wells. In conclusion, the recommended workflow will ensure much more realistic and better matching permeability predictions.","PeriodicalId":11250,"journal":{"name":"Day 3 Wed, August 07, 2019","volume":"31 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-08-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87950090","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":"A Non-Resistivity Approach for Estimating Water Saturation A Case Study in Niger-Delta, Nigeria","authors":"Olabode Awuyo, A. Sunday, A. Fadairo","doi":"10.2118/198753-MS","DOIUrl":"https://doi.org/10.2118/198753-MS","url":null,"abstract":"\u0000 The notion of Water Saturation is of importance in determining the hydrocarbon saturation (1-Sw) in reservoirs, calculating hydrocarbon in place, hence a vital evidence of reliable formation evaluation. Preconceptions in reserves quantification and hydrocarbon in place estimations arise once the outcome of the water saturation value is erroneous. Several models in the literature have been used for estimating water saturation and oftentimes the variance in confidence level of their results lead to substantial variance in original hydrocarbon in place volumes. Obtaining a better resolution with deeper understanding of the gaps observed in the existing approaches for estimating water saturation (Sw) values have been a major challenge in accurate calculation of hydrocarbon in place.\u0000 This paper presents a non-resistivity approach for estimating water saturation using Leverett J-function and Reservoir Quality Index with dependency on fluid and facies Values. The innovative approach involves the use of Saturation Height Modelling through Leverett J- function, build facies through Magnetic Resonance Graphical-Based clustering (MRGC) option, use of Regression method and making a simple scripting using logging language (LOGLAN) program in Geolog to achieve the purpose. This current approach has been applied to Niger-Delta alternate shale-sand formation in optimisation of somewhat low recovery of the hydrocarbon reserves due to probably erroneous over estimation of Water Saturation value from Resistivity-based approach. Reliable results from current non-resistivity approach were obtained with average Water Saturation value of 25% as compared to resistivity approach presented by Juhasz with average water saturation value of 32% and non-resistivity approach presented by Brooks-Corey with average water saturation value of 26% and Leverett J- function with average water saturation values of 27% respectively.","PeriodicalId":11250,"journal":{"name":"Day 3 Wed, August 07, 2019","volume":"27 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-08-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84446901","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":"Maximising Oil Recovery in Mature Water Floods Using Automated Pattern Flood Management","authors":"Edet Ita Okon, Joseph Adeoluwa Adetuberu, D. Appah","doi":"10.2118/198797-MS","DOIUrl":"https://doi.org/10.2118/198797-MS","url":null,"abstract":"\u0000 One of the most significant challenges for extending production life in mature waterflood fields is high water production. Couple with high reservoir heterogeneity, extensive layering and faulting, these fields often developed irregular flood patterns after decades of production which compounded the challenge to optimizing recovery from these fields. The severity of this problem can be seen in the Niger Delta oil fields where there are several matured fields that are producing at high water cut after many years of water flooding. The main objective of this study is to maximize oil recovery from a matured waterflood oil field while reducing the water cut. To achieve this objective, simulation studies were conducted on two cases scenarios. The first case was modelling and running waterflood simulation studied without applying pattern flood management (No PFM) while the second case scenario was done by exploring an automated pattern flood management (PFM). This was done with the aid of Petrel E&P software platform and ECLIPSE FrontSim to efficiently optimize the rate of water allocated to individual injectors. Using data from one of the oil fields operating in the Niger Delta, their performances were compared. The PFM gave the best result with a cumulative oil production of 30,727,470 STB when compared with the case of No PFM which gave a cumulative oil production of 26,968,224 STB (about 12% increase in oil recovery). The PFM water cut was 16% when compared with the case of No PFM which gave a water cut of 47% (about 63% reduction in water production). Hence, The PFM approach has made it possible to reduce water injection in more than 30% of the injectors while more than 62% of the producers experienced increase production and reduced water cut. The productivity increased upon automation of the workflow will enable engineers to identify the optimal injection allocation factors. It will also help engineers to understand and produce from the reservoir at an optimized decline rate and ensure the increase in ultimate recovery.","PeriodicalId":11250,"journal":{"name":"Day 3 Wed, August 07, 2019","volume":"1 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-08-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88921504","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":"Switching from Water Injection Scheme to Gas Injection Scheme for Improved Oil Recovery in a Niger Delta Oilfield","authors":"J. Akpabio, B. E. Jackson, Celestine A. Udie","doi":"10.2118/198835-MS","DOIUrl":"https://doi.org/10.2118/198835-MS","url":null,"abstract":"\u0000 The ‘JEB’ oilfield has been in operation since 1992 with 24 oil producing Wells, 8 water injection Wells and no gas injection. From inception, the field was producing at the rate of 27 MSTB/D. The gas produced was 34,333.7 SCF/D which was being flared but later supplied to the Nigeria Liquefied Natural Gas (NLNG) for export. The field had very weak aquifer support and therefore had been water-flooded from early days of its production. With high water cut, it was necessary to find ways of reducing water production and increasing oil production. The study involved field data gathering, history matching of the field data and prediction of future production. Production rates from the different production schemes were simulated for fourteen years. The cumulative oil production of gas injection, water alternating gas (WAG) injection and gas alternating water (GAW) injection schemes were 4.28 MMMSTB, 3.29 MMMSTB and 3.15 MMMSTB respectively representing an incremental recovery of 38%, 6%, and 1%. The cumulative water production of gas injection, WAG injection and GAW injection were 2.65 MMMSTB, 6.52 MMMSTB and 6.90 MMMSTB respectively, which represent 64%, 10% and 5% reduction in produced water. The economic analysis showed gas injection as the best alternative injection scheme for the field with internal rate of return (IRR) of 19.26 %, while the IRR of WAG and GAW injection schemes were 12.09 % and 11.22 % respectively. Also, at 15% discount rate, the gas injection scheme had the best result with a Profitability Index (PI) greater than 1, a positive Net Present Value (NPV) while all other injection schemes had negative NPV and PI was less than one. The possibility of changing a field from water injection to gas injection has been explored, hence, before embarking on any enhanced oil recovery scheme, other alternatives should be evaluated.","PeriodicalId":11250,"journal":{"name":"Day 3 Wed, August 07, 2019","volume":"43 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-08-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"76921524","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":"Realtime Aaquisition of Formation Pressure Data For Reservoir Characterization and Safe Drilling","authors":"Loretta Umeonaku, Philip Adegboye, Emmanuel Ubadigha, Hamza Ibrahim, Francis Anwana, Gabriel Omale","doi":"10.2118/198771-MS","DOIUrl":"https://doi.org/10.2118/198771-MS","url":null,"abstract":"\u0000 Formation Pressure data is a key parameter for in-depth characterization of a reservoir's potential and capacity to produce hydrocarbon. Pressure data are analyzed to confirm fluid interface, fluid type as well as to understand reservoir connectivity/isolation and compartmentalization if any, needed to finalise on the completion strategy to be utilized for optimal production. Acquisition of this data while drilling provides early and reliable information for decision making in optimising the drilling process.\u0000 This paper demonstrates the use of Formation Pressure While Drilling (FPWD) tool to acquire formation pressure data. It examines the successful wellsite execution of FPWD service deployed in 3 deepwater wells in the Gulf of Guinea. It discusses operational sequence, quality of the results and how the operator utilized acquired data. In Well A, the test objective was to establish reservoir connectivity between a producer and an injector. For Well B, acquired pressure data was crucial in finalizing completion strategy. Well C shows how the direct pressure measurements were utilized to update the mud program in real time while drilling.\u0000 Finally, this paper reemphasizes the value of FPWD by outlining how acquired pressure data met clients objectives by providing valuable quality data which provided great insight in reservoir characterization and safely drilling the wells to Total Depth.","PeriodicalId":11250,"journal":{"name":"Day 3 Wed, August 07, 2019","volume":"15 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-08-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77028315","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":"Analysis of Boundary-Dominated Gas Well Production Data","authors":"S. Mohammed, Prosper Anumah, Justice Sarkodie-kyeremeh, Anthony Morgan, E. Acheaw","doi":"10.2118/198732-MS","DOIUrl":"https://doi.org/10.2118/198732-MS","url":null,"abstract":"\u0000 Arps’ hyperbolic model has historically been used to analyze and forecast gas well performance. This is largely due to its simplicity and explicit nature. Unfortunately, because of the variations of viscosity-compressibility product with average reservoir pressure during boundary-dominated flow (BDF) period, the Arps’ hyperbolic model overestimates gas reserves and future rates. Consequently, existing rate-decline models rely heavily on pseudotime. Unfortunately, pseudotime requires iteration, which is time-consuming.\u0000 This paper proposes an empirical rate-decline model for a gas well producing at a constant pressure during BDF. The proposed model utilizes a drawdown correlating parameter that accounts for formation and water compressibilities, as well as the variations of gas properties with pressure. Due to its explicit nature, the proposed rate-decline model can be used to forecast future gas well performance. An explicit model for estimating the decline exponent for a gas well is also proposed. In addition, this paper presents a semi-empirical flowing material balance (SE-FMB) method that allows the estimation of initial gas-in-place, real gas productivity index and estimated ultimate recovery. The advantages of the proposed SE-FMB over the existing methods are two-folds: first, it is iterationless; and second, it avoids the use of a functional relation (or curve fitting) of viscosity-compressibility product and pressure.\u0000 The results of this study suggest that the decline exponent for a gas well is time-independent at early-time BDF period and time-dependent at late-time BDF period. At very late-time BDF period, the decline exponent tends to zero. Thus, gas well production data exhibit a hyperbolic decline at early-time BDF period and a transition period at late-time BDF period. At very late-time BDF period, an exponential decline is expected. While the exponential-decline period is not observed in practice due to economic-rate constraints, the hyperbolic-decline period is observed in practice. The transition period may or may not be observed in practice depending on the magnitude of the drawdown parameter and the economic-rate constraints. Comparison of the models results indicates that the proposed rate-decline and the classical Arps’ hyperbolic models are consistent with the rate history during the hyperbolic-decline period; however, the proposed rate-decline model out-performs the classical Arps’ hyperbolic model when the transition period prevails. The results of this study also indicate that ignoring the formation and water compressibilities lead to an overestimation of gas reserves even for a normally-pressured gas reservoir. Simulated and field data have been used to demonstrate the validity and applicability of the proposed model and analysis method.","PeriodicalId":11250,"journal":{"name":"Day 3 Wed, August 07, 2019","volume":"49 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-08-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87982701","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":"Magnetic Resonance: Says it as it is!","authors":"Stanley Oifoghe, Victor Okowi, Eziulo Ibe","doi":"10.2118/198739-MS","DOIUrl":"https://doi.org/10.2118/198739-MS","url":null,"abstract":"\u0000 Magnetic resonance (MR) is a very robust service that delivers several formation evaluation products. Both the wireline (WL) and logging-while-drilling (LWD) services deliver shale volume, porosity, permeability, viscosity, saturation and fluid typing. In addition to these, the WL service also delivers capillary pressure and grain size analysis.\u0000 Although WL and LWD MR Services have different modes of acquisition, the result is usually the same. WL MR uses multiple frequencies, but LWD MR uses a single frequency. Multiple frequencies provide multiple magnetic field gradients that provide for more flexible hydrocarbon typing acquisition sequences, unlike the LWD MR single frequency that supplies a single hydrocarbon acquisition sequence.\u0000 Dual Wait Time (DTW) analysis is the hydrocarbon typing technique for LWD MR, but the WL hydrocarbon typing has the flexibility to choose from a range of applications that includes two-dimensional MR mapping (2D MR), density multiple wait time (DMTW) analysis, multiple gradient inter-echo spacing (MGTE) analysis, simultaneous inversion of multiple echo trains (SIMET), and T1/T2 ratio (R-T2) analysis for gas reservoirs.\u0000 Light hydrocarbons (gas) and Kaolinitic shales compromise the use of neutron-density and gamma ray models as bulk shale volume indicators. However, MR shale volume computation using clay-bound water (CBW), which is unaffected by the presence of gas or Kaolinitic shales. MR Logs can accurately determine porosity in complex lithologies and thin beds. Irreducible water saturation from MR is used to determine reservoir quality and productivity.\u0000 In the industry today, MR logs are the most tolerant to environmental challenges. They are able to \"say\" the true state of the reservoir in the midst of environmental factors like the presence of gas, shales, and thin beds, which are known to adversely impact measurements from other conventional tools","PeriodicalId":11250,"journal":{"name":"Day 3 Wed, August 07, 2019","volume":"8 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-08-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84297596","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}