|Chemical Methods for Ugnu Viscous Oils
||Last Reviewed 6/27/2012
The objective of this project is to develop improved chemical oil recovery options for the Ugnu reservoir overlying the Milne Point unit in North Slope, Alaska.
University of Texas, Austin, TX 78712-1160
The North Slope of Alaska has large (about 20 billion barrels) deposits of viscous oil in the Ugnu, West Sak, and Shraeder Bluff reservoirs. These shallow reservoirs overlie existing productive reservoirs such as Kuparuk and Milne Point. The viscosity of the Ugnu reservoir overlying Milne Point varies from 200 cP to 10,000 cP and the depth is about 3500 ft. The same reservoir extends to the west overlying the Kuparuk River Unit and on to the Beaufort Sea. The depth of the reservoir decreases and the viscosity increases toward the west. Currently, the operators are planning to test cold heavy oil production with sand (CHOPS) in Ugnu, but oil recovery is expected to be low (< 10%). Improved oil recovery techniques must be developed for these reservoirs. Proximity to the permafrost is an issue for thermal methods; thus non-thermal methods must be considered. In the past, gasflood and alkaline-surfactant-polymer methods have been developed for light oils and polymer methods have been developed for medium viscosity oil. Hydrocarbon gases are now available for injection into oil reservoirs to improve oil recovery, but their availability will be limited once a gas pipeline is constructed. Thus, the objective of this proposal is to develop chemical methods to recover oil from the Ugnu reservoir (overlying Milne Point) with a limited use of gas solvents.
This project will identify the applicability of chemical techniques for heavy oil recovery at the laboratory-scale. Project personnel will evaluate mechanisms of heavy oil recovery in many new secondary recovery processes (e.g., alkaline-surfactant, alkaline-surfactant-polymer, and colloidal dispersion gel floods) as well as the sweep efficiency and the microscopic displacement efficiency of these processes. Mechanistic numerical models will be developed for each of these processes to explain laboratory results and determine field-scale implications. Research leading to a successful chemical recovery method could result in the economically viable recovery of many billions of barrels of oil from the Ugnu reservoir without damaging the permafrost. The scientific and technical insight gained from this project can potentially be applied to other heavy oil reservoirs.
Accomplishments This project is completed resulting in the following determinations:
- Ugna oil is biodegraded and hence contains some organic acids. The acids react with injected alkali to produce soap. This soap helps in lowering interfacial tension between water and oil which in turn helps in the formation of macro- and micro-emulsions. Additional synthetic surfactants are still needed to form emulsions, but a lower amount is required because of the presence of organic acids in the oil.
- Tertiary ASP flooding is very effective for the 330 cP viscous oil in the 1D sand pack. This chemical formulation includes 1.5% of an alkali, 0.4% of a non-ionic surfactant, and 0.48% of a polymer. Secondary waterflood in a 1D sand pack showed a cumulative recovery of 0.61 PV with about a 3 PV injection. The residual oil saturation to waterflood was 0.26. Injection of a tertiary alkaline-surfactant-polymer slug followed by tapered polymer slugs could recover almost 100% of the remaining oil. The tertiary alkali-surfactant-polymer flood of the 330 cP oil is stable in three-dimensions as verified by a flood in a transparent 5-spot model. A secondary polymer flood is also effective for the 330 cP viscous oil in the 1D sand pack. The secondary polymer flood 5-spot flood recovered about 0.78 PV of oil with about 1 PV injection. The remaining oil saturation was 0.09. Pressure drops were reasonable (<2 psi/ft.) and depended mainly on the viscosity of the polymer slug injected.
- For the heavy crude oil (viscosity 10,000 cP), low viscosity (10–100 cP) oil-in-water emulsions can be obtained at salinity up to 20,000 ppm by using a hydrophilic surfactant along with an alkali at a high water-to-oil ratio (WOR) of 9:1. Very dilute surfactant concentrations (~0.1 wt%) of the synthetic surfactant are required to generate the emulsions. Decreasing the WOR reverses the type of emulsion to water-in-oil. For a low salinity (0 ppm NaCl), the emulsion remained oil/water even when the WOR was decreased. Hence low salinity injection water is preferred if an oil-in-water emulsion is to be formed.
- Secondary waterflooding of the 10,000 cP heavy oil followed by tertiary injection of alkaline surfactants is very effective. The waterflood had early water breakthrough, but recovered a substantial amount of oil beyond breakthrough. The waterflood recovered 20%–37% PV of the oil in the 1D sand pack with about a 3 PV injection. Tertiary alkali-surfactant injection increases the heavy oil recovery to 50%–70% PV in the 1D sand packs. As the salinity increased, the oil recovery due to alkaline surfactant flood increased, water-in-oil emulsion was produced, and the pressure drop increased. With low salinity (deionized) water, the oil recovery was lower, but so was the pressure drop because only oil-in-water emulsion was produced. Secondary waterflood of the 10,000 cP heavy oil in the 5-spot sand packs recovered 30%–35% OOIP with about a 2.5 PV injection. Tertiary injection of the alkaline-surfactant solution increased the cumulative oil recovery from 51% to 57% OOIP in the 5-spot sand packs. As water displaces the heavy oil, it fingers through the oil with a fractal structure (fractal dimension = 1.6), as seen in the micro-model experiments. Alkaline-surfactant solution emulsified the oil around the brine fingers allowing oil to flow to the production well. A fractional flow model incorporating the effect of viscous fingering was able to match the laboratory experiments and can be used in reservoir simulators. The chemical techniques look promising in the laboratory and should be tested in the field.
- Two papers describing many of these results were completed and presented at the November, 2011 Society of Petroleum Engineers (SPE) Annual Conference in Denver, Colorado:
- SPE 146839: Sweep Efficiency of Heavy Oil Recovery by Chemical Methods
- SPE 146841: Viscous Fingering during Non-Thermal Heavy Oil Recovery
Current Status (June 2012)
This project ended on 3/31/12. All proposed project work has been completed. The final report is available below under "Additional Information".
Project Start: October 1, 2008
Project End: March 31, 2012
DOE Contribution: $704,431
Performer Contribution: $180,061
NETL – Chandra Nautiyal (Chandra.Nautiyal@NETL.DOE.GOV or 281-494-2488)
University of Texas at Austin – Kishore Mohanty (email@example.com or 512-471-3077)
If you are unable to reach the above personnel, please contact the content manager.
Final Project Report [PDF-2.90MB]