Day 2 Wed, April 10, 2019最新文献

{"title":"Practical Upscaling of Immiscible WAG Hysteresis Parameters from Core to Full Field Scale","authors":"O. Talabi, J. Moreno, R. K. Malhotra, Boon Keat Tham","doi":"10.2118/194634-MS","DOIUrl":"https://doi.org/10.2118/194634-MS","url":null,"abstract":"\u0000 Immiscible water-alternating-gas (iWAG) flooding is often considered as a tertiary recovery technique in waterflooded or about-to-be waterflooded reservoirs to increase oil recovery due to better mobility control and potentially favorable hysteretic changes to phase relative permeabilities. In such cases, typically, reservoir simulation models already exist and have been calibrated, often modifying saturation functions during the history matching stage. However, to utilize such models in forecasting iWAG performance, additional parameters may be required. These can be acquired by simulation of WAG coreflood experiments. While in many published cases, the parameter values obtained from matching experimental results are used without modification, this may not be advisable since the parameters are only valid at the core scale at which they were obtained. This paper discusses the challenge of systematically upscaling WAG parameters obtained at core scale to an existing full field model.\u0000 In this work, we use a multi-stage upscaling process from core scale to full field scale. The first stage uses a core scale model to match ‘representative’ core flood experiments and obtain WAG parameters. The second uses a well-to-well high-resolution 1D section of the full field model populated using gridblocks of core size to generate ‘reference’ WAG performance using the unaltered WAG parameters obtained from core. The third stage uses a similar 1D model but populated using gridblocks at full field model resolution to match the results from the reference model while adjusting the WAG parameters as little as possible. Finally, a model using the full field model resolution as well as the full field relative permeability functions which, it is assumed, have been tuned to match the history and account for dispersion is used to match the reference model results and obtain final upscaled WAG parameters.\u0000 The upscaled WAG parameters obtained at the end of this multi-stage process can be used at the field scale. This process allows clear quantification of the uncertainty associated with the upscaling process. Simulations at the third stage showed that once the full field to core scale grid size ratio exceeded a certain point (2500:1), there was a marked increase in the difference between upscaled and reference model results. It was found that if WAG parameters were changed in the full field model resolution model in order to match recovery results in the reference model, Land's parameter could change by up to 10% and relative permeability reduction factor could increase by up to 30% although it is expected that this will vary from case to case. It is therefore recommended to identify and use full field model resolutions to as close to the threshold as possible. The practice of using the core scale iWAG parameters in the full field model directly could under-estimate actual recovery, and overestimate injectivity. When considering the WAG mechanism alone, the value of th","PeriodicalId":11150,"journal":{"name":"Day 2 Wed, April 10, 2019","volume":"5 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-04-08","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79349687","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":"Correlating the Performance of Friction Reducers with Source Water Chemistry","authors":"S. Hazra, Vanessa M. Madrid, T. Luzan, M. Domelen, C. Copeland","doi":"10.2118/195199-MS","DOIUrl":"https://doi.org/10.2118/195199-MS","url":null,"abstract":"\u0000 This paper provides a detailed evaluation of the impact that field source water chemistry has on the performance of friction reducers being used for hydraulic fracturing. In this research, correlations are established between friction reducer performance and source water chemical composition, allowing operators to shorten the learning curve within their fracturing operations, use the most appropriate fluid systems, and potentially mitigate job failures.\u0000 Extensive testing has been conducted to evaluate friction reducer performance in the presence of different ionic components such as calcium, magnesium, iron and chloride. Performance testing was determined by varying individual ions, as well as using source waters from multiple field locations having total dissolved solid (TDS) levels of well over 100,000 ppm. Testing parameters included friction reduction, hydration rate via viscosity, and rheological characterization for viscosifying-type friction reducers. Principal component analysis was used as statistical tool to characterize the variation in water chemistry and to establish its relationship with friction reducer performance.","PeriodicalId":11150,"journal":{"name":"Day 2 Wed, April 10, 2019","volume":"72 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-04-08","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84297085","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":"Nitrogen Cap Drilling A Managed Pressure Drilling Alternative for Highly Fractured Carbonate Reservoir","authors":"Alexey Podust, C. Starkey, J. Wood, Gareth Cameron","doi":"10.2118/194535-MS","DOIUrl":"https://doi.org/10.2118/194535-MS","url":null,"abstract":"\u0000 Nitrogen Cap Drilling (NCD) is a technique developed by Tengizchevroil (TCO) that enables drilling a highly fractured reservoir under conditions where more conventional pressurized mud cap drilling techniques are not viable. NCD is an extension of the closed hole circulating drilling (CHCD) technique (Ref SPE Paper # 79850) previously developed and used extensively by TCO for drilling a highly fractured carbonate reservoir where severe loss circulation is encountered and incurable.\u0000 CHCD is a pressurized mud cap drilling technique that relies on the ability to fill the well with a fluid density lighter than the reservoir pressure gradient in order to maintain communication with the reservoir pressure. Once the reservoir pressure gradient drops below the density of the lightest fluid available, the well will no longer support a full column of fluid to surface and an alternate drilling method must be employed.\u0000 TCO has developed NCD as a response to this operating reality in the Tengiz field. The NCD technique involves filling the annulus with a heavier than reservoir pressure gradient fluid once severe lost returns are encountered. The annulus fluid level does not reach the surface, and the resulting air gap is pressurized with nitrogen gas. This nitrogen \"cap\" is contained under the Rotating Control Device (RCD) which allows for maintaining pressure communication with the formation. Well status is continuously monitored by tracking the wellhead pressure and measuring the annulus fluid level. The bottom hole pressure is balanced by manipulating the composition of the annular fluid column and controlling the wellhead pressure.\u0000 In 2017, TCO conducted successful field trials and demonstrated that NCD is a viable technique to enable the continuation of the low reservoir pressure drilling program in Tengiz. TCO has since adopted NCD as the standard technique in wells where CHCD is not technically viable or operationally preferable. This paper will describe NCD technique development, equipment, procedures, operational implementation, and key learnings to date.","PeriodicalId":11150,"journal":{"name":"Day 2 Wed, April 10, 2019","volume":"3 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-04-08","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84895256","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":"Extension of Oil Well Economic Life by Simultaneous Production of Oil and Electricity","authors":"Kai Wang, Xingru Wu","doi":"10.2118/195211-MS","DOIUrl":"https://doi.org/10.2118/195211-MS","url":null,"abstract":"\u0000 Oil production decline and excessive water production are prevalent in mature fields and unconventional plays, which significantly impact the profitability of the wells and result in costly water treatment and disposal. To seek for a sustainable development of those wells, reducing the operation cost and extending their economic lives, this paper presents a method of synergistic production of hydrocarbon and electricity, which could harvest the unexploited geothermal energy from the produced water and transfer heat to electricity in the wellbore. Such method is cost-effective, since it does not require any surface power plant facility, and it is replicable in numerous wells including both vertical wells and horizontal wells. By simultaneous coproduction of oil and electricity, the value of existing assets could be fully developed, operation cost could be offset, and the economic life of the well could be extended.\u0000 This recently proposed method incorporated thermoelectric power generation technology and oil production. In this method, electricity could be produced by thermoelectric generator (TEG) mounted outside of the tubing wall under temperature gradient created by produced fluid and injected fluids. The aim of this paper is to illustrate the economic practicability of oil-electricity coproduction by using thermoelectric technology in oil wells based on previously proposed design. We examined the technical data of high water-cut oil wells in North Dakota and collected required information with respect to performance thermoelectric power generations. Special emphasis was placed on the key parameters related to project economics, such as thermoelectric material, length of TEG and injection rate. Sensitive studies were carried out to characterize the impact of the key parameters on project profits. We showed that by simultaneously production of oil and electricity, $234,480 of additional value could be generated without interfering with oil production.\u0000 The proposed method capitalizes on the unexploited value of produced water and generates additional benefits. This study could provide a workflow for oil and gas operators to evaluate an oil-electricity coproduction project and could act as a guidance to perform and commercialize such project to balance parts of the operation cost and extend the life of the existing assets.","PeriodicalId":11150,"journal":{"name":"Day 2 Wed, April 10, 2019","volume":"4 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-04-08","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"76341634","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":"An Integrated Study of Water Coning Control with Downhole Water Sink Completion Approaches in Multilayered - Strong Water Drive Reservoir to Improve Oil Recovery","authors":"Jupriansyah Jupriansyah","doi":"10.2118/194565-MS","DOIUrl":"https://doi.org/10.2118/194565-MS","url":null,"abstract":"\u0000 A reservoir with bottom water drive mechanism has a high tendency to generate water coning effect in their production life. As a result of water coning phenomenon, the well has a low critical safe rate which limits the productivity of the reservoir. Consequently, a new innovation for completion design in an oil well with a bottom aquifer drive is needed. The author offers a Downhole Water Sink (DWS) system to solve this problem.\u0000 DWS is a dual completion design innovation where two tubing strings are installed into the well to produce both water and oil simultaneously by different tubing. The main principle of DWS is to create a stable pressure drawdown in oil and water zone so that a stable oil-water contact is formed. DWS application in a multilayered reservoir expected to be able to resolve the water coning phenomenon thus the recovery factor increased and the well becomes economic to be produced. In this paper, the study approach involved by numerical simulation within IMPES methodology (Implicit Pressure Explicit Saturation) and Thomas’s algorithm to solve iteration. Completion modeling is creating two wells on the similar coordinate in several layered reservoirs aims to produce oil and water separately on tubing on the well.\u0000 The percentage of water cut on oil production tubing is 0% while the percentage of water cut on water production tubing is 100%. This thing shows that DWS completion system will give a greater cumulative oil production in a high production rate and the oil is oil-free water. It is observed that the successful implementation of DWS in a multilayered reservoir is taken place. The well with DWS design configuration for the WDP system shows a better performance of oil productivity compares to a conventional well completion design. This result is supported by no water production observed at oil production tubing on the surface well level. There are some parameters that affect DWS system application modeling i.e. mobility ratio, vertical and absolute horizontal permeability (kv & kh) also perforation interval.\u0000 Down-Hole Water Sink is an appropriate innovation to eliminate water coning and producing oil with high recovery factor. DWS application in a multilayered reservoir with bottom aquifer driving mechanism shows a better performance of oil productivity compares to a conventional well completion design. This result is supported by no water production observed at oil production tubing on the surface well level.","PeriodicalId":11150,"journal":{"name":"Day 2 Wed, April 10, 2019","volume":"21 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-04-08","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"91078242","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":"Gas Assisted Gravity Drainage GAGD for Improving Recovery from a Field in North-East India","authors":"Nabajit Baruah, D. Mandal, Smita Swarup Jena, S. Sahu","doi":"10.2118/194585-MS","DOIUrl":"https://doi.org/10.2118/194585-MS","url":null,"abstract":"\u0000 This paper examines the prospect of Gas Assisted Gravity Drainage (GAGD) process in improving recovery from a sandstone reservoir by injecting produced gas back into the crestal part of the reservoir. Besides recovery improvement, immiscible gas injection ensures near Zero Flaring strategy. The process has been found to be ideal in reservoirs with high permeability and reasonable dip to maximize oil production wherever a sufficient gas source exists. Based on the study, gas injection is recommended at the crestal part of the reservoir under study at the rate equivalent to the produced gas to maintain pressure, arrest gas cap shrinkage and improve recovery.","PeriodicalId":11150,"journal":{"name":"Day 2 Wed, April 10, 2019","volume":"83 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-04-08","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77134519","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":"Evaluation of Small-Scale Gas-to-Liquid Economic Feasibility to Mitigate North Dakota Flaring Issue","authors":"Pascoela da Silva Sequeira, R. Moghanloo","doi":"10.2118/195209-MS","DOIUrl":"https://doi.org/10.2118/195209-MS","url":null,"abstract":"\u0000 The booming of shale gas production has affected the natural gas price in the United States (U.S). Natural gas price has plummeted due to the excessive capacity. On the other hand, the import of crude oil and its production of diesel, gasoline, and others are increasing. The problem lies in finding a practical, economical and efficient way of making natural gas marketable. A potential solution is Small-scale Gas-to-Liquids plants. Small-scale GTL can fulfill some of the petroleum products demand such as Gasoline, Ultra-low-sulfur diesel, and jet-fuel. Small-scale GTL plants especially can benefit countries where the gas production is higher than gas demand, yet these countries depend on imported oil.\u0000 A Monte Carlo simulation approach is used to conduct sensitivity analysis on various parameters such as the feedstock/natural gas price, plant capacity, plant efficiency, capital expenditure (CAPEX), operational expenditure (OPEX), and products selling prices. The range for natural gas prices and gasoline prices are obtained from average historical data in the United States for the past five (10) years where the shale gas production is booming. The CAPEX is attained from previous GTL project plants before using the Power-Sizing model and literature. The annual OPEX is the percentage fraction of the CAPEX. The plant capacity was chosen based on the diseconomy factor estimated from previous GTL projects. Even with the premium quality of GTL products, the selling price for the products is equal to regular crude oil products.\u0000 Economic metrics such as Net Present Value (NPV), Internal Rate of Return (IRR), Cost-to-Profit (C/P) ratio and Payback Period were used to assess the success of GTL technology at each given business case. Results showed that NPV, IRR, C/P ratio and payback period are most affected by CAPEX, products selling price, OPEX, and capacity of the plant, in respected order. Based on these case scenarios and parameters, sensitivity analysis is conducted using Monte Carlo's simulation of 10,000 iterations the results for NPV, IRR, C/P ratio and payback period showed that the GTL project is profitable. The NPVs for the GTL plant in this study are positive for all case scenarios.\u0000 It is expected that the outcome of this research would guide shale gas producers and private investors when considering GTL investment to monetize their assets in the United States and beyond.","PeriodicalId":11150,"journal":{"name":"Day 2 Wed, April 10, 2019","volume":"os-18 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-04-08","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87200107","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":"Validation of Produced Gas Rate Modelling in an Oil Reservoir with Very High CO2 Through Matching of Live Oil Coreflood","authors":"S. Mishra, A. Pandey","doi":"10.2118/194604-MS","DOIUrl":"https://doi.org/10.2118/194604-MS","url":null,"abstract":"\u0000 Fatehgarh reservoirs in Aishwariya field, located in Barmer Basin of Rajasthan India, have very high CO2 content in reservoir fluid. A procedure was developed earlier to model the impact of reservoir CO2 on waterflood, polymer flood and ASP flood (Mishra and Pandey 2017, 2018) in this field. Another observation is that in such a system with very high amount of CO2, produced gas rate does not follow conventional trend. Conventionally, gas is dissolved in oil and produced gas is the gas released out from the oil. However, in a system like Aishwariya with very high amount of CO2 in dissolved gas, produced gas is the cumulative of gas released out from both liquid streams i.e., oil and water. Interestingly, gas can continue to produce even after no more oil is being produced from the system. A live oil coreflood was carried out to generate produced gas rate profile under Aishwariya reservoir conditions.\u0000 The objective of this work was to validate the modelling procedure developed to predict the produced gas rate in such a system with very high amount of CO2 in reservoir fluid.\u0000 A live oil coreflood experiment was carried out using 12 inches long Bentheimer core under Aishwariya reservoir pressure and temperature conditions. After saturating the core with live oil, the core was water flooded with brine for ~3.7 pore volumes. Produced gas volume was measured at different times so as to generate gas production profile.\u0000 Two different simulation techniques were used to simulate the experiment and match the gas production profile. First technique was using a compositional simulator with EOS based PVT while the other technique was using an \"advanced processes simulator\" modeling the component distributions based on partitioning coefficients. Both methods could successfully capture the production of gas from both liquid streams; oil and water and a reasonable match for the produced gas could be obtained.\u0000 The approach developed to simulate impact of CO2 on different aqueous based flooding processes in Aishwariya field was validated by matching the coreflood experiment carried out under actual Aishwariya reservoir conditions. It helped to confirm confidence in performance prediction of aqueous based flooding mechanisms planned in Aishwariya field despite the presence of significant amount of CO2.\u0000 The paper presents history match of unconventional produced gas profile of a coreflood carried out under Aishwariya field conditions with very high amount of dissolved CO2. The proposed method can be applied to estimate produced gas rate in other fields with very high amount of CO2 in reservoir fluid.","PeriodicalId":11150,"journal":{"name":"Day 2 Wed, April 10, 2019","volume":"16 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-04-08","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78386683","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 Case Study on Identification & Mitigation of Surges in a Cluster of Composite Well Flow Line Network","authors":"M. Gupta, J. Sukanandan, V. Singh, R. Bansal, A. S. Pawar, B. Deuri","doi":"10.2118/194597-MS","DOIUrl":"https://doi.org/10.2118/194597-MS","url":null,"abstract":"\u0000 This paper discusses a case study of one of the onshore field of ONGC where while processing well fluid, frequent surge has been observed leading to shutdown of the SDVs creating severe operational problems and loss of production. It was imperative to find out the problematic wells/lines located in clusters which contribute for surge formation and mitigation approach with minimum modifications.\u0000 A transient complex network of sixty five wells flowing with a different lift mode such as intermittent gas lift, continuous gas lift etc were developed in a dynamic multiphase flow simulator OLGA. Time cycle of each well were introduced for intermittent lift wells. Simulation study reveals pulsating transient trends of liquid flow, pressure which was matched with the real time data of the plant and hence confirms the accuracy of the model. After verifying the results, different scenarios were created to determine the causes of surge formation. After finding the cause, a low cost approach was considered for surge mitigations.\u0000 An integrated rigorous simulation was carried out in OLGA, by feeding more than 12,000 data points to obtain model match. Several scenarios were also created such as optimization of lift gas quantity, optimization of elevation and size. Trend obtained after each scenario was pulsating behaviour and it matched with the real time data appearing in the SCADA system of the field. After rigorous simulation with each scenario, it was established that the cause of surge forming wells/pipelines. Once the root cause of surge has been confirmed then quantum of liquid generated due to surge was determined. Adequacy checks of the existing separators were carried out to estimate the handling capacity of the existing separators at prevalent operating condition. After adequacy check it was found that existing separators cannot handle the surge generated in that time interval leading to cross the high-high safety level, resulting closure of shut down valve (SDV). After establishment of root cause of the surge, a low cost solution with small modification in pipelines and control system/valves was adopted to arrest the surges. It was first of its kind simulation carried out for a huge network of wells/ pipelines by feeding more than 12,000 data to analyze the surge formation cause and capture its dynamism owing to wide array of suspected causes. This will help to address the challenges of efficiently reviewing the entire pipeline network while designing new well pad/GGS and will also help to arrest surge by adopting a low cost solution wherever such situation arises.","PeriodicalId":11150,"journal":{"name":"Day 2 Wed, April 10, 2019","volume":"224 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-04-08","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83661024","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":"Planning India's First CO2-EOR Project as Carbon Capture Utilization & Storage: A Step Towards Sustainable Growth","authors":"G. Mishra, R. Meena, Sujit Mitra, K. Saha, Vilas Pandurangji Dhakate, O. Prakash, Raman R. K. Singh","doi":"10.2118/194629-MS","DOIUrl":"https://doi.org/10.2118/194629-MS","url":null,"abstract":"\u0000 India is the fastest growing major economy and third largest CO2 emitter in the world. Keeping cognizance of country's energy requirement and commitment to climate change, embarking upon technologies having minimal carbon footprint is the need of the hour. Carbon capture, utilization and storage (CCUS) is one such technology which offers dual benefits of carbon sequestration & enhancing oil production from mature oils fields. This paper outlines ONGC's efforts in bringing nation's first CO2-EOR project.\u0000 In view of non-availability of natural CO2 sources in India, usage of anthropogenic CO2 captured from thermal power plants was conceptualised. Based upon CO2 source-sink matching exercise and favourable reservoir & fluid parameters, two oil fields were screened. Technical feasibility of CO2-EOR was first ascertained in laboratory by determination of minimum miscibility pressure (MMP) of CO2 through slim tube experiments. Encouraged by laboratory results, full field compositional simulation studies along with fluid characterization inputs from PVT simulator were carried out.\u0000 The MMP were found to be in range 190-250 Ksc, which is below the initial reservoir pressures of the targeted reservoirs. The proposed scheme entails drilling of around 70-80 wells inclusive of both producers & injectors and has the potential to yield an incremental recovery between 10-14 %. A sensitivity analysis based upon purity of CO2 and its adverse effect on MMP was carried out in terms of reduced oil recoveries. Since, this shall be a CCUS project, CO2 from the produced stream has to be separated, compressed and reinjected in a closed loop system. Around 5-8 MMT of CO2 will be sequestrated through Structural, Solubility and Residual trapping mechanisms as modelled in compositional simulator. IFT reduction & decrease in Sor (Residual oil saturation) as result of swelling, miscibility of CO2 with native oil were also modelled in simulator. Being first of its kind project in India, there are many inherent challenges to the CCUS project. At the source end, capturing CO2 from flue gas stream and its compression & transportation is a cost and energy intensive process. At the Sink end, CO2 being acidic and corrosive gas will need retrofit modifications in terms of special corrosion resistant metallurgy for existing processing facilities.\u0000 The learning curve from this endeavour shall create knowledge base to further expand deployment of CCUS in India, bringing a large portfolio of reservoirs under the ambit of CO2-EOR. Success of CCUS in India will not only increase domestic oil production but also cater to address the National INDC of reducing emission intensity of GDP by 33-35 percent by 2030 as per Paris agreement.","PeriodicalId":11150,"journal":{"name":"Day 2 Wed, April 10, 2019","volume":"13 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-04-08","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82077186","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}