Browsing University of Alaska Fairbanks by Subject "Secondary recovery of oil"
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Evaluation of CO₂ sequestration through enhanced oil recovery in West Sak reservoirCO₂ enhanced oil recovery (EOR) has been proposed as a method of sequestering CO₂. This study evaluates using CO₂ as an EOR agent in the West Sak reservoir. The injected CO₂ mixes with the oil and reduces the oil viscosity, enhancing its recovery. A considerable amount of CO₂ is left in the reservoir and 'sequestered'. Due to low reservoir temperature, this process can lead to formation of three hydrocarbon phases in the reservoir. An equation of state was tuned to simulate the West Sak oil and complex phase behavior of the CO₂-oil mixtures. A compositional simulator capable of handling three-phase flash calculation and four-phase flow was used to simulate CO₂ injection into a three-dimensional heterogeneous pattern model. The results showed that CO₂ EOR in the West Sak reservoir increases oil recovery by 4.5% of original oil in place and 48 million metric tons of CO₂ could be sequestered. Ignoring four-phase flow underestimated oil recovery and sequestered CO₂ volume. Enriching the CO₂ with natural gas liquid decreased sequestered CO₂ volume without a significant increase in oil recovery. Dissolution of CO₂ in the water phase and different water/CO₂ slug sizes and ratios did not change the sequestered CO₂ volume and oil recovery.
Experimental investigation of low salinity water flooding to improve viscous oil recovery from the Schrader Bluff Reservoir on Alaska North SlopeAlaska's North Slope (ANS) contains vast resources of viscous oil that have not been developed efficiently using conventional water flooding. Although thermal methods are most commonly applied to recover viscous oil, they are impractical on ANS because of the concern of thawing the permafrost, which could cause disastrous environmental damage. Recently, low salinity water flooding (LSWF) has been considered to enhance oil recovery by reducing residual oil saturation in the Schrader Bluff viscous oil reservoir. In this study, lab experiments have been conducted to investigate the potential of LSWF to improve heavy oil recovery from the Schrader Bluff sand. Fresh-state core plugs cut from preserved core samples with original oil saturations have been flooded sequentially with high salinity water, low salinity water, and softened low salinity water. The cumulative oil production and pressure drops have been recorded, and the oil recovery factors and residual oil saturation after each flooding have been determined based on material balance. In addition, restored-state core plugs saturated with viscous oil have been employed to conduct unsteady-state displacement experiments to measure the oil-water relative permeabilities using high salinity water and low salinity water, respectively. The emulsification of provided viscous oil and low salinity water has also been investigated. Furthermore, the contact angles between the crude oil and reservoir rock have been measured. It has been found that the core plugs are very unconsolidated, with porosity and absolute permeability in the range of 33% to 36% and 155 mD to 330 mD, respectively. A produced crude oil sample having a viscosity of 63 cP at ambient conditions was used in the experiments. The total dissolved solids (TDS) of the high salinity water and the low salinity water are 28,000 mg/L and 2,940 mg/L, respectively. Softening had little effect on the TDS of the low salinity water, but the concentration of Ca²⁺ was reduced significantly. The residual oil saturations were reduced gradually by applying LSWF and softened LSWF successively after high salinity water flooding. On average, LSWF can improve viscous oil recovery by 6.3% OOIP over high salinity water flooding, while the softened LSWF further enhances the oil recovery by 1.3% OOIP. The pressure drops observed in the LSWF and softened LSWF demonstrate more fluctuation than that in the high salinity water flooding, which indicates potential clay migration in LSWF and softened LSWF. Furthermore, it was found that, regardless of the salinities, the calculated water relative permeabilities are much lower than the typical values in conventional systems, implying more complex reactions between the reservoir rock, viscous oil, and injected water. Mixing the provided viscous oil and low salinity water generates stable water-in-oil (W/O) emulsions. The viscosities of the W/O emulsions made from water-oil ratios of 20:80 and 50:50 are higher than that of the provided viscous oil. Moreover, the contact angle between the crude oil and reservoir rock in the presence of low salinity water is larger than that in the presence of high salinity water, which may result from the wettability change of the reservoir rock by contact with the low salinity water.
Improving ultimate recovery in the Granite Point field Tyonek C sandsThe objective of this research is to determine how the ultimate recovery of the Granite Point field can be improved. An understanding of the depositional setting, structure, stratigraphy, reservoir rock properties, reservoir fluids, aquifer, and development history of the Granite Point field was compiled. This was then leveraged to provide recommendations on how the ultimate recovery can be improved. The Granite Point field Tyonek C sands are located on an anticline structure at 8,000' to 11,000' SSTVD within the offshore Cook Inlet basin. These sands were deposited in a fluvial environment with the source material provided by the Alaska Range to the northwest. Due to uplifting, the Tyonek C sands are of relatively low porosity for their depth. The sands thin, become more numerous, and are of generally lower porosity from southwest to northeast. Oil quality is excellent and displacement efficiency of the reservoir rock with water flood exceeds 50% at breakthrough. Although displacement efficiency is high, the relative permeability to water is extremely low. The fracture gradient of the reservoir rock is on the order of magnitude of 1.0 psi/ft. Many initiatives were undertaken throughout the history of the Granite Point field to improve the rate and resource recovery, all of which were met with negligible success with the exception being the introduction of horizontal wells that were first drilled in the early 1990's. The underlying reason for the lack of success of these other initiatives is the low effective permeability to oil and the extremely low effective permeability to water. Secondary recovery with water injection was successful in the early stage of development, and can be in the future, but only when applied between wells that are connected by a sand of acceptable porosity. The results of this research indicate that to improve the ultimate recovery of the Granite Point field a thorough quantification of aquifer and injection water movement must first be understood, then horizontal wells can be placed in appropriate locations to improve the offtake and leverage the weak aquifer drive to provide pressure support.