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dc.contributor.authorVenepalli, Kiran Kumar
dc.date.accessioned2017-10-31T23:12:26Z
dc.date.available2017-10-31T23:12:26Z
dc.date.issued2011-08
dc.identifier.urihttp://hdl.handle.net/11122/7950
dc.descriptionThesis (M.S.) University of Alaska Fairbanks, 2011en_US
dc.description.abstractFrozen reservoirs are unique with the extra element of ice residing in them along with the conventional components of a reservoir. The sub-zero temperatures of these reservoirs make them complicated to explore. This study investigates reduction in relative permeability to oil with decrease in temperature and proposes a best-production technique for reservoirs occurring in sub zero conditions. Core flood experiments were performed on two clean Berea sandstone cores under permafrost conditions to determine the sensitivity of the relative permeability to oil (kro) over a temperature range of 23°C to -10°C and for connate water salinities ranging from 0 to 6467 ppm. Both cores showed maximum reduction in relative permeability to oil when saturated with deionized water; they showed minimum reduction when saturated with 6467 ppm of saline water. Theoretically, the radius of ice formed in the center of the pore can be determined using the Kozeny-Carman Equation by assuming the pores and pore throats as a cube with 'N' identical parallel pipes embedded in it. With obtained values of kro as input to the Kozeny-Carman Equation at -10°C, the radius of ice dropped from 0.145 [upsilon]rn to 0.069 [upsilon]rn when flooding, water salinity is increased to 6467 ppm. This analysis quantifies the reductions in relative permeability solely due to different formation salinities. Other parameters like fluid saturations and pore structure effects also are discussed. Fluids like deionized water, saline water, and antifreeze (a mixture of 60% ethylene or propylene glycol with 40% water) were tested to find the best flooding agent for frozen reservoirs. At 0°C, 9% greater recovery was observed with antifreeze than with saline water. Antifreeze showed 48% recovery even at -10°C, at which temperature the rest of the fluids failed to increase production.en_US
dc.description.tableofcontents1. Introduction -- 1.1. Conventional oils in unconventional reservoirs -- 1.2. Reservoirs in permafrost and related challenges -- 1.3. Objective -- 2. Background -- 2.1. Permafrost -- 2.2. Unfrozen water -- 2.3. Reasons for occurrence of unfrozen water in frozen ground -- 2.4. Investigation of prevailing ice within the pore -- 2.5. Reliance of water saturation on relative permeability and quantifying unfrozen water -- 2.6. Behavior of unfrozen water content ([theta]) with changes in temperature (T) -- 2.7. Frozen reservoirs -- 2.8. Umiat reservoir -- 2.8.1. Geology -- 2.8.2. Drilling and completion -- 2.8.3. Depth of the permafrost -- 2.9. Relative permeability -- 2.10. Determination of relative permeability -- 2.10. Determination of relative permeability -- 2.10.1. Steady-state technique -- 2.10.2. Unsteady-state technique -- 2.11. Reduction in relative permeability to oil and oil recovery -- 2.12. Possible reasons for reduction in relative permeability -- 2.13. Kozeny-Carman equation -- 2.14. Berea sandstone -- 3. Experimental procedure -- 3.1. Experimental setup -- 3.2. Experimental procedure -- 3.2.1. Routine core analysis -- 3.2.2. Special core analysis -- 3.2.3. Uncertainty of experimental data -- 3.3. Brookfield viscometer test procedure -- 3.4. Experimental procedure of mercury pycnometer -- 3.5. Experimental procedure for production technique -- 4. Theoretical procedure -- 4.1. Assumptions and their justifications -- 4.2. Alternative form of Kozeny-Carman equation -- 4.2.1. Flow through the circular open pipe (before freezing) -- 4.2.2. Flow through the concentric pipe (after freezing) -- 5. Results -- 5.1. Results of the core flooding experiments -- 5.1.1. Routine core analysis -- 5.1.2. Special core analysis -- 5.1.3. Effect of temperature on relative permeability -- 5.1.4. Effect of salinity on relative permeability -- 5.1.4.1. Effect of salinity from 23°C to 0°C -- 5.1.4.2. Effect of salinity from 0°C to -10°C -- 5.2. Viscosity changes with temperature -- 5.3. Estimation of freezing point depression -- 5.3.1. Estimation of depression in freezing point due to salinity -- 5.3.2. Estimation of depression in freezing point due to capillary pressure -- 5.4. Estimation of pore radius from capillary pressure data -- 5.5. Theoretical approach -- 5.6. Results of production mechanism -- 6. Discussion -- 6.1. Routine core analysis -- 6.2. Relative permeability measurements -- 6.2.1. Relative permeability to oil above 0°C -- 6.2.2. Relative permeability to oil below 0°C -- 6.2.2.1. Effect of water saturation -- 6.2.2.2. Effect of salinity and capillary pressure -- 6.2.2.3. Effect of pore structure -- 6.3. Production mechanism -- 7. Conclusions and recommendations -- 7.1. Conclusions -- 7.2. Recommendations -- References.
dc.language.isoen_USen_US
dc.subjectHydrocarbon reservoirsen_US
dc.subjectPermafrosten_US
dc.titleImplications of pore-scale distribution of frozen water for the production of hydrocarbon reservoirs located in permafrosten_US
dc.typeThesisen_US
dc.type.degreems
dc.identifier.departmentDepartment of Petroleum Engineering
refterms.dateFOA2020-03-28T01:08:39Z


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