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dc.contributor.authorMathur, Bakul
dc.date.accessioned2017-06-06T23:24:59Z
dc.date.available2017-06-06T23:24:59Z
dc.date.issued2017-05
dc.identifier.urihttp://hdl.handle.net/11122/7623
dc.descriptionThesis (M.S.) University of Alaska Fairbanks, 2017en_US
dc.description.abstractThe heavy oil reservoirs in Alaska offer major production challenges, including proximity to the permafrost layer, very high viscosity oil and low mechanical strength pay zones. The Ugnu deposits of the Alaska North Slope (ANS) hold more than 6 billion barrels of oil. The dead oil viscosity at reservoir temperature ranges from 1,000 to 1,000,000 cp1. In an effort to sustain well life, this research focuses on the unique set of challenges occurring in the Ugnu reservoir and presents the best possible way to maximize production. The present research accentuates observations derived from the field data, which shows that deliberate sand production with the hydrocarbon stream while employing a Progressive Cavity Pump (PCP) as an artificial lift method has a favorable effect on primary oil recovery. The developments have led to the advent of a technique called Cold Heavy Oil Production with Sand (CHOPS) as an initial production method for shallow heavy oil reservoirs. Sand production leads to the formation of high porosity channels or wormholes that can range up to hundreds of meters. The co-mingling of heavy oil and sand develops foamy oil by creating a bubbly flow inside the reservoir. The combination of these wormholes with the foamy oil behavior are the primary factors that result in enhanced production during CHOPS. One of the major hindrances to its successful application is the selection of the post-CHOPS production method, which is addressed in this study with the help of modeling and simulation. Alternative recovery techniques following the primary cold production include water flooding, polymer injection, miscible gas injection and thermal recovery methods. Water flooding is unviable because of the mobility contrast between the highly viscous oil and water. The high permeability zones provide a bypass for water, consequently producing elevated water cuts. Another aspect unique to Alaskan heavy oil reservoirs is the proximity to the permafrost layer, with the hydrocarbon bearing zone making thermal recovery methods unappealing. Polymer injection and miscible gas injection become the favorable non-thermal secondary and tertiary recovery methods in this case. This study is based on modeling one of the wells drilled into the M80 sands of the Ugnu formation followed by the analysis of post-CHOPS recovery for the well. The CHOPS well modeling is done with the help of a wormhole fractal pattern and a foamy oil model. Simulation of the polymer injection is then employed from a nearby well. The results indicate almost 12% increment in recovery with polymer flooding as compared to the natural depletion. The recovery obtained from the simulations have been analyzed to provide a basis for designing the polymer injection job as an Enhanced Oil Recovery (EOR) method after CHOPS. With the promising results of this study, it can be determined that the Ugnu reservoir sands can be exploited for heavy oil with the help of polymer flooding. It can also be combined with miscible gas flooding or alkali-surfactant flooding to obtain even higher hydrocarbon recoveries.en_US
dc.description.tableofcontentsChapter 1. Introduction -- 1.1 Alaska's Heavy Oil Potential -- 1.2 Cold Heavy Oil Production with Sand (CHOPS) -- 1.3 Research Structure. Chapter 2. Literature review -- 2.1 Ugnu Geology -- 2.2 Significant Recovery Mechanisms of CHOPS -- 2.3 Modeling the CHOPS Process -- 2.3.1 Modeling Wormhole Propagation -- 2.3.1.1 Geo-mechanical Models -- 2.3.1.2 Probabilistic Models -- 2.3.2 Fluid Modeling -- 2.3.2.1 Pseudo Bubble Point Model -- 2.3.2.2 Modified Fractional Flow Model -- 2.3.2.3 Reduced Viscosity Model -- 2.3.2.4 Non-equilibrium Reaction Model -- 2.4 Enhanced Oil Recovery (EOR) After CHOPS -- 2.4.1 Water Flooding -- 2.4.2 Polymer Flooding. Chapter 3. Model construction and validation -- 3.1 Available Data -- 3.2 Model Construction -- 3.2.1 Fluid Model Construction -- 3.2.2 Reservoir Model Construction -- 3.2.2.1 Wormhole Pattern Generation -- 3.3 Model Initialization and Validation. Chapter 4. Post-chops recovery optimization -- 4.1 Water Flooding -- 4.2 Polymer Flooding -- 4.2.1 Polymer Selection -- 4.2.2 Polymer Concentration Optimization -- 4.2.3 Injection Time Optimization -- 4.2.4 Slug Size Optimization -- 4.2.5 Well Spacing. Chapter 5. Discussion of results. Chapter 6. Conclusions and recommendations -- 6.1 Conclusions -- 6.2 Recommendations. References -- Appendix.en_US
dc.language.isoen_USen_US
dc.titleLife after CHOPS: the Alaskan heavy oil reservoir perspectiveen_US
dc.typeThesisen_US
dc.type.degreemsen_US
dc.identifier.departmentDepartment of Petroleum Engineeringen_US
dc.contributor.chairDandekar, Abhijit
dc.contributor.chairKhataniar, Santanu
dc.contributor.committeePatil, Shirish
refterms.dateFOA2020-03-05T14:20:33Z


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