Day 3 Wed, October 23, 2019最新文献

{"title":"More Oil and Less Water: Heavy Oil Field Application of the Autonomous Inflow Control Devices AICD in Long Horizontal Wells – A Case study from South Sultanate of Oman","authors":"Ameera Harrasi, Maria Jimenez-Chavez, A. Al-Jumah, Asma Barwani, Ali Lawati, A. Sabahi, G. Urdaneta, M. Gokmen, Khalfan Harthy, H. Busaidi, F. Saadi, Yaqoob Abri, M. Harthi, Said Rahbi, Ibrahim Abri, Majid Siyabi, Huda Hooti","doi":"10.2118/198554-ms","DOIUrl":"https://doi.org/10.2118/198554-ms","url":null,"abstract":"\u0000 The multidisciplinary authors have summarized the results from the Autonomous Inflow Control Device (AICD) deployment in multiple oil fields, and presented it in this paper as a practice worth replication in a similar heavy oil environment, due its many benefits in optimizing field development. AICDs have been tested mainly in labs and controlled environments with few comprehensive field trials. This paper will form the basis for that which will add to the state of knowledge in the industry.\u0000 The AICD technology was piloted in few wells of these fields. It comprises of mechanical devices installed with the sand face completion, which react in real time to the properties of the flowing fluids, decreasing/delaying the water influx (or gas if it would be the case) from high productivity zones, promoting increased oil production from other compartments of the formation, therefore, equalizing the drawdown along the horizontal section of the well and performing a dynamic water shut-off operation. No cables are required, as the devices work on the basis of viscosity and density difference between the oil and the water.\u0000 The AICD-completed wells showed initial water cut in the range 1% to 2%. Which has reduced significantly in comparison to nearby analogues. The initial net oil rate resulted to be more than 2 times of the expected one, with an acceleration of ~10,000 bbls of net oil during the first month. After the initial production period, the technology is still delaying the aggressive water cut development usually observed in these fields, having provided 2 times the expected net oil rate during the first 3 months, with an acceleration of approximately 20,000 bbls of net oil over this period. It has been concluded that the application of the technology is successful and will be deployed as a baseline in all future horizontal wells drilled.","PeriodicalId":182237,"journal":{"name":"Day 3 Wed, October 23, 2019","volume":"23 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-10-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"129380169","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":"Selective Perforation for Thin Separated Layers Using Addressable Switches: Operation Design and Limitations Overcome","authors":"M. Arafa, Osama Abdelalim Taha, Abdelhadi Atef Ayyad, Ahmed Sheta, M. Vazquez, Shahira Elfiky","doi":"10.2118/198540-ms","DOIUrl":"https://doi.org/10.2118/198540-ms","url":null,"abstract":"\u0000 This paper aims to highlight the benefits of using selective perforation as a method of risk reduction and optimization during perforating thin separated oil-bearing intervals going through selection criteria, job design, economic evaluation and precautions during the operation.\u0000 During the design of four perforation jobs in a campaign using the conventional through tubing perforation (TTP) technique, it was noticed that the number of runs were too much with consequent high intervention risk, thus alternatives were evaluated to mainly reduce intervention risk with a smart, reliable, cost effective and simple perforation technique within the pre-determined operation time frame. The other options included alternative deployment methods such as coiled tubing (CTU) perforation, extended reached perforation (ERP) and selective perforation techniques. A comparison between options has been made based on the following criteria: availability, simplicity, reliability, intervention risk and feasibility.\u0000 As a result of proper filtration and comparison between all different options, the selective perforation using addressable switches was selected to be the optimum solution for this case based on the comparison criteria mentioned above. Going through the design phase, multible loading sheets for guns laydown have been generated and optimized to reach the simplest operational procedures and minimum number of runs. Then, workshops have been made for engineers in both office and field to be familiar with the operation to reduce operational risks and consolidate the operational procedures. The design of service for the whole job including the final operational procedures, risk assessment and gun loading sheets was finalized and distributed to all disciplines to assure alignment during the operation. During job execution, operation has been followed step by step using single point of accountability (SPA) to accelerate and align decision making and plan modification during operational issues. Finally, a post job evaluation has been made to document the whole procedures of design and execution and the lessons learned during the operations. A final comparison between conventional and actual selective perforation job showed the reduction in number of runs and thus time and intervention risk by 33%. In addition, the incremental increase in cost was completely covered by the time saving from the utilization of supporting vessels (Rig & boats).\u0000 The major aim of this paper is to clarify in a step-by-step style the method of evaluating the well for addressable switches technique and how to properly prepare the people for the job and the design of service till execution followed by post job evaluation.","PeriodicalId":182237,"journal":{"name":"Day 3 Wed, October 23, 2019","volume":"68 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-10-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"122134564","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":"Acidic Steam Modeling and Simulation for Heavy Oil and Extra Heavy Oil Reservoirs","authors":"Ali Zolalemin, K. Stephen","doi":"10.2118/198535-ms","DOIUrl":"https://doi.org/10.2118/198535-ms","url":null,"abstract":"\u0000 Over the past three decades, the decline in reserves of conventional crude oil has led to the development of several methods in order to enhance oil recovery for heavy oil deposits. Globally, heavy oil accounts for approximately 50% of hydrocarbon volume in place (Ehlig-Economides et al., 2000). There exist sixteen major oil sands deposits all over the world. As a matter of fact, the two largest are the Athabasca oil sands in Northern Alberta and the Orionco - River deposit in Venezuela. By comparison, the Athabasca oil sands alone cover an area of more than 42000 km2, in which oil storage is more than all the known reserves in Saudi Arabia. It is found that only one sixth of over 1.7 trillion barrels of heavy oil are recoverable with current technologies. These technologies include mining, thermal recovery, cold production and etc. Mining only makes economic and engineering sense when the depth of overburden is less than about 75 meters. Hence, only about 10 - 20% of the oil sands can be mined. As a result, recovery of the remaining 80 - 90% of the oil sands depends on the so-called thermal-recovery process, which basically depends on using energy to produce energy. In order to begin to separate the heavy oil from the sand/carbonates, deposits have to be heated to lower the viscosity of the heavy oil. One of these thermal recovery methods is the Solvent Assisted Process (SAP) that appears tremendously successful, especially for bitumen. SAP process involves injection of solvent and steam in several wells. Even though the injector well and producer can be very close, the mechanism of SAP causes a growing steam saturated zone, known as the steam chamber, to expand gradually and eventually allow drainage from a very large volume.\u0000 Both field and numerical simulation studies have demonstrated the success of SAP drainage. The prediction of SAP performance by numerical simulation is an integral component in the design and management of a SAP project. In this regard, the solvent is chosen to be Acid in this study. In order to inject steam with solvent (acid), two separate chambers of acid and steam are heated up to a certain degree on the surface. Steam only is injected into the well. The well is shut in for 2 hrs and then put on production in which acid is mixed with steam and injected together after cleanup period.\u0000 Conventional reservoir modeling approach computes multiphase flow in porous media but generally does not take the geomechanical effects into account. Unfortunately, this assumption is not valid for oil sands, because of their high sensitivity on pore pressure and temperature variations but can be applied in carbonate formations.","PeriodicalId":182237,"journal":{"name":"Day 3 Wed, October 23, 2019","volume":"55 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-10-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"115112309","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":"Numerical Investigation of CO2 Sequestration as Hydrates in Produced Natural Gas Hydrate Formation with Different Intrinsic Permeability and Water Saturation Conditions","authors":"Sheraz Ahmad, Yiming Li, Xiangfang Li, Wei Xia, Chen Ze'en, Peng Wang, Y. Zhiming","doi":"10.2118/198569-ms","DOIUrl":"https://doi.org/10.2118/198569-ms","url":null,"abstract":"The phase transition field model equations for hydrate-bearing formation are proposed to analyze the variations in pressure, temperature, hydrate growth rate and other parameters during CO2 injection and storage as solid hydrates. The numerical algorithm results show that intrinsic permeability and water saturation has great influence on hydrate nucleation process. When the intrinsic permeability of sediment decreases from 100 mD to 10 mD and 1 mD, pressure distribution delays inside hydrate-bearing formation and indirectly it also suspends the hydrate growth process due to smaller hydrate growth rate. The slow hydrate nucleation speed affects other parameters variations like, temperature distribution, accumulative hydrate growth, CO2 permeability and 1st and 2nd region boundaries movement. The hydrate growth termination effect is observed near the wellbore region at different absolute permeability conditions. The hydrate growth suspension is more prominent when the intrinsic permeability reduces from 100 mD to 10 mD and 1 mD. Therefore, CO2 injection at low temperature and high pressure conditions may form hydrates but it seems challenging in lengthier formation. So, more than one injection facilities can solve this problem with less injection pressure.","PeriodicalId":182237,"journal":{"name":"Day 3 Wed, October 23, 2019","volume":"78 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-10-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"124053247","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 Dynamics of Drilling with Oil-Based Mud, 60:40 Oil-Water Ratio – Case History in South East Kuwait Fields","authors":"Shahad Sheer, Ali Alotaibi, Ketan Gadhiya, M. Al-Khaldy, D. Abhijit, K. Al-Failkawi, Dhari Al-Saadi, A. Al-Saeedi, Abdulrahman Hamed, Faisal Al-Azmi, Girish Jayprakash","doi":"10.2118/198582-ms","DOIUrl":"https://doi.org/10.2118/198582-ms","url":null,"abstract":"\u0000 Drilling to the targeted depth of a well can be a challenge, considering the problems that may arise in the form of wellbore instability, mud losses, and/or differential sticking. The objective was to successfully drill a first-time implementation of an Oil-Based Mud (OBM) system with 60:40 Oil-Water Ratio (OWR).\u0000 The OBM system was maintained within the specified parameters in terms of mud weight, viscosity, and fluid loss. The addition of primary and secondary emulsifiers in the system enhanced electric stability (ES). Moreover, solid control equipment will be monitored continuously for immediate action if necessary. Contingency plan and a surplus of chemicals will be provided to ensure a smooth drilling and a swift movement of operations.\u0000 A fluid system was designed after extensive laboratory tests to analyze the optimal approach to drill using the first-time application of 60:40 OWR mud. It reduces the use of Diesel consumption by 26% in total OBM formulation, lowers the percentage of Low Gravity Solids (LGS) compared to the 80:20 OWR mud, and decreases the impact on the environment. Furthermore, the OBM was then reused in consequent wells with the addition of emulsifiers to reduce the cost.\u0000 This paper presents successful first-time applications of the 60:40 OWR fluid till the targeted lower Burgan formation, interbedded sandstone and shale formation. A complete laboratory analysis comparison between previous wells drilled and the current application indicates no difficulties were faced.","PeriodicalId":182237,"journal":{"name":"Day 3 Wed, October 23, 2019","volume":"193 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-10-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"115484767","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":"Cement Slurry System for the Long Open Hole Section of High-Pressure High-Temperature Deep Wells in the Sichuan Basin","authors":"Yan Haibing, Li Meiping, Chunquan Wang, Liu Yang, Wenzhong Liu, Zhao Qiyang","doi":"10.2118/198581-ms","DOIUrl":"https://doi.org/10.2118/198581-ms","url":null,"abstract":"\u0000 The depth of natural gas wells in the Sichuan Basin ranges from 5500 m to 7500 m, the temperature of the target layer ranges from 140 °C to 160 °C, the pressure coefficient of the layer is 2.05~2.35, and the length of the open hole section is 2800 m to 4000m. The complex formation with multiple production layers and multiple leakage layers results in many challenges for well construction engineering. During cementing of a deep well, the challenges include high temperature and pressure, gas migration and leakage, and \"ultra-retardation\" at the top of the cement column when a cement slurry is used to address the problem oflong-interval isolation.\u0000 To solve the complex technical problems encountered during cementing, a multi-function cement slurry system was developed for long-interval isolation at temperatures between 70 °C and 160 °C. The maximum compressive strength of the cement slurry at the top of the cement column with 4000m length was reached after 48 h and the cement slurry exhibited good leak-proof and anti-gas channeling performance. After mechanical modification, Young's modulus of the cement paste was lower than that of the conventional cement slurry (less than 6.0GPa) and the tensile strength of the cement paste was 30% higher, exhibiting an improvement in the damage resistance of the cement sheath. The cement slurry system was successfully applied to more than 100 high-temperature high-pressure wells in the Sichuan Basin, reaching maximum values of 7793 m well depth, 3954 m length of the liner cementing section, 100 °C temperature difference, and 2.40 g/cm3 cement slurry density.","PeriodicalId":182237,"journal":{"name":"Day 3 Wed, October 23, 2019","volume":"36 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-10-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"115792440","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":"Formation Evaluation Using Advanced Pulsed Neutron Tools","authors":"Abdulaziz Alqasim, Ilies Mostefai, S. Kokal, A. Alkhateeb","doi":"10.2118/198541-ms","DOIUrl":"https://doi.org/10.2118/198541-ms","url":null,"abstract":"\u0000 Pulsed neutron log provides a valuable method of evaluating cased hole formations. It is commonly used to monitor reservoir performance and depletion over a long period of time. The tool can be used to monitor sweep efficiency during waterflooding and enhanced oil recovery stages. It can provide valuable data that can be used to fine-tune the simulation model predictions.\u0000 Pulsed neutron tools are commonly run, in either capture or inelastic modes, to estimate time-lapse fluid saturation changes behind the casing they consist of one neutron generator and a number of gamma ray detectors at different distances from the neutron generator. The tools are run in different modes to investigate front movement and 2-phase/3-phase saturation profile under challenging borehole conditions.\u0000 The older generation 2-detectors tool is highly affected by the borehole environment, and therefore saturation. The two new generation 3-detectors and 4-detectors tools seem better in detecting and quantifying the fluid saturation. Subsequently, the 3-detectors tool is seemingly the best in terms of delivering robust answers in complex and unknown borehole conditions.\u0000 The log results from the new generation tools were useful for tracking the 2-phase/3-phase fluid front movement, identifying swept intervals. This paper compare the design and implementation of the different pulsed neutron tools generations, limitations and operational issues, and log results interpretation","PeriodicalId":182237,"journal":{"name":"Day 3 Wed, October 23, 2019","volume":"70 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-10-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"115798647","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":"Building More Accurate Models for Different Reservoir Types and Oil Water Delineation","authors":"M. Zeybek","doi":"10.2118/198613-ms","DOIUrl":"https://doi.org/10.2118/198613-ms","url":null,"abstract":"\u0000 Building accurate reservoir models can be quite challenging, especially highly stratified thick intervals in hydraulic communication in reservoir. Presented methodology is based on comprehensive Interval and Interference Pressure Transient Testing (IIPTT) for classified reservoir types with a systematic approach. Classification of reservoir types is based on layering, thickness, and hydraulic communication of layers in the reservoir.\u0000 The methodology describes building more accurate anisotropic reservoir models, providing well performance assessment based on integrated comprehensive IIPTT solving with efficient non-linear parameter estimation and modeling with numerical simulation for different reservoir types. The number distributed IIPTTs are optimized to ensure to achieve coverage across total thickness depending on the reservoir type.\u0000 It is demonstrated that high resolution accurate reservoir models can be built for relatively thick highly layered reservoirs in a feasible manner. In addition, field examples with classified reservoir types including flow tests supported the methodology.","PeriodicalId":182237,"journal":{"name":"Day 3 Wed, October 23, 2019","volume":"50 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-10-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"115709559","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 of Nanoparticles as Injection Media in Enhanced Oil Recovery","authors":"Muhammad Arshad, K. Feilberg, A. Shapiro, K. Thomsen","doi":"10.2118/198548-ms","DOIUrl":"https://doi.org/10.2118/198548-ms","url":null,"abstract":"\u0000 The effect of crystal morphology of two different polymorphs of mineral calcium carbonate, CaCO3, (i.e., calcite and aragonite) and a follow-up study (based on our previous work on emulsion characterization as reported in Arshad et al., 2018 a) on the thermal stability of emulsions are presented in this work.\u0000 Brines with varying salt concentration (deionized water (DIW), synthetic seawater (0.5SSW and SSW), and formation water (FW2 and FW1)), model oils (decane (D) and 1:1 vol. ratio of hexane–hexadecane (HH)), and a sample of North Sea crude oil (NSCO) were employed. Calcite fines (size ≤ 30 μm), aragonite fines (size ≤ 5 μm), and calcite nanoparticles of three different sizes (15–40, 50, and 90 nm) were used for emulsion formation in brine–oil mixtures. CaCO3 micron-sized fines (calcite and aragonite) and calcite nanoparticles were characterized by Scanning Electron Microscope (SEM) and Transmission Electron Microscope (TEM), respectively. X-ray Powder Diffraction (XRD) was performed to examine the crystal structure of calcite and aragonite fines. Branson Sonifier® SFX250 (forced emulsification) was employed for emulsion generation in brine–oil–fines/nanoparticles. An optical microscope (Axio Scope.A1) was used for characterizing the emulsion droplet size. Thermal stability of the emulsions was examined in two stages, first by keeping them at room temperature for an extended period of 12–23 months (emulsion phase readings were taken at week–1, month–5, month–12, and month–23) followed by heating them at an elevated temperature of 80 °C for a period of 40 days in a custom-made closed water bath.\u0000 The crystal morphology study showed that although the calcite fines (≤ 30 μm) were six times bigger in size in comparison to the aragonite fines (≤ 5 μm), they generated a comparatively large amount of emulsion with relatively smaller emulsion droplets in the DIW–HH mixtures. This indicates that the crystal morphology of fines was the dominating factor in emulsion formation and emulsion droplet size instead of the size of fines and the crystal morphology should be considered as an important parameter in the selection of nanoparticles for EOR applications.\u0000 Emulsion thermal stability was examined in brine–oil–calcite nanoparticles with a wide range of brine salinity (DIW, 0.5SSW, SSW, FW2, and FW1), oil type (D, HH, and NSCO), and size of calcite nanoparticles (15–40, 50, and 90 nm). All the brine–D–calcite nanoparticles systems showed excellent thermal stability both at room temperature for 12 months and at an elevated temperature of 80 °C for 40 days. Amongst all the brine–D–calcite nanoparticles cases, a maximum cumulative de-emulsification (from month–5 to heating at 80 °C for 40 days) of 6 % was observed for the 0.5SSW–D–CaCO3 system with 50 nm calcite nanoparticles. Due to the lower boiling temperature of hexane (~ 68 °C), the brine–HH–calcite nanoparticles systems were not tested at 80 °C. They were instead tested at room temperature for an ext","PeriodicalId":182237,"journal":{"name":"Day 3 Wed, October 23, 2019","volume":"73 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-10-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"128787561","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":"Flow Characteristics Through Gas Alternating Gas Injection During Enhanced Gas Recovery","authors":"N. Mohammed, A. J. Abubakar, GC Enyi, Ghasem Nasr Ghavami","doi":"10.2118/198658-ms","DOIUrl":"https://doi.org/10.2118/198658-ms","url":null,"abstract":"\u0000 Gas and liquid flooding using carbon dioxide (CO2), nitrogen (N2), or brine solution have become one of the promising enhanced gas (EGR) and oil recovery (EOR) technologies for residual hydrocarbons (HCs) enhancement in conventional oil and gas reservoir respectively. However, the flow mechanism between the displacing and displaced fluids are not yet clear, especially for the novel gas alternating gas injection method adopted in this study. This experimental study investigates the flow mechanism of N2-CO2-CH4 through gas alternating gas injection techniques in consolidated rocks during EGR. The research presents a better flow behaviour characteristic using a novel N2 alternating CO2 during EGR. These values were used in determining the optimum injection rate with the minimum in situ mixing and high displacement front. An experimental laboratory core flooding, experiment was done to imitate a detailed process of an unsteady state N2-CO2-CH4 displacement in Bandera grey core sample at 35-40°C of temperature, 1500 psig of pressure, and at 0.2, 0.4, 0.6, 0.8 and 1.0 ml/min N2 alternating CO2 injection rates to evaluate the displacement flow characteristics, such as diffusion coefficient, dispersion coefficient, density and viscosity, mobility ratio, and dispersivity. The CO2 was injected after 4-5 cm3 of N2 injection throughout the runs at the experimental condition. The findings indicated that gas alternating gas injection technique presents a better flow behaviour characteristic compared to that of individual CO2 or N2 injection. Such prominent behaviour was observed at 0.4 ml/min injection, with higher displacement front and longer CO2 breakthrough time. The mobility ratio of N2-CO2-CH4 was lower compared to that of N2-CH4 and CO2-CH4. This was due to the inclusion of nitrogen which acts as a barrier between the CO2 and displaced CH4. The later contributed significantly for the delayed in CO2 breakthrough especially at lower injection rates (0.2-0.4 ml/min) during the gas alternating gas EGR process. The overall molecular diffusion coefficients were found to be 22.99, 18.48 and 17.33 ×10-8 m2/s for N2-CH4, CO2-CH4, and CO2-N2 binary interaction respectively at the test condition. The dispersion coefficient increases with an increase in the injection rate due to rise in the interstitial velocity as the CO2 plume traverses through the core sample during the EGR process.","PeriodicalId":182237,"journal":{"name":"Day 3 Wed, October 23, 2019","volume":"13 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-10-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"124074085","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}