Development of Shallow Viscous Oil Reserves on the North Slope

DE-FC26-01BC15186

Program
This project was selected in response to DOE's Oil Exploration and Production solicitation DE-PS26-01NT41048, Round 2 (focus area: Reservoir Efficiency Processes). The focus area addresses access to oil not recoverable by conventional methods. Researchers may develop unconventional recovery methods such as gas flooding, heavy oil recovery, the use of chemicals, reservoir simulation, or microbes.

Project Goal
The project was designed to develop tools to find optimum solvents, injection schedules, and well architecture for a water-alternating-gas (WAG) oil recovery process for the Alaska North Slope's shallow, viscous oil reservoirs.

Performer
University of Houston
Houston, TX

Project Results
The results of the research established the EOR methods that will yield the greatest recovery from the North Slope's heavy oil reservoirs. It determined that:

• Carbon dioxide injection works better than injection of Prudhoe Bay natural gas liquids (NGL).
• Simulation modeling demonstrated the best strategy for timing and volume of WAG floods.
• Although sweep efficiency may decrease somewhat, horizontal wells were found to deliver more heavy oil than vertical wells. The factors that influence horizontal well performance were identified and can be used to plan horizontal wellbores and predict recovery.
• The use of electromagnetic heating of the reservoir can double the recovery of heavy oil.

Benefits
An economic method of recovery for the enormous heavy oil resources on the North Slope has been the goal of North Slope operators for years. The technologies and strategies for heavy oil recovery developed by the project to optimize production through WAG injection via horizontal wellbores will significantly increase heavy oil production.

The combination of new technologies and a better understanding of what methods work best in Alaskan heavy oil reservoirs can stimulate increased heavy oil production on the North Slope and provide continued flow on the Trans-Alaska Pipeline System (TAPS).

The disposal of CO2 via injection in an EOR project will be an added environmental benefit as sequestration of a greenhouse gas.

Background
Prudhoe Bay and Kuparuk River fields on Alaska's North Slope are the largest oil fields in North America. Heavy oil presents the largest potential for undeveloped reserves from these North Slope fields. The reservoirs are the largest undeveloped heavy oil accumulations in North America, but recovery has proved a daunting challenge for North Slope operators. The producing formations lie at depths of 3,000-5,000 ft in a region of deep permafrost, which causes the heavy oil to become extremely viscous.

The North Slope fields have been exploited since the 1970s; both Prudhoe Bay and Kuparuk River fields are now in decline. Over 20% of the Nation's oil supply is carried by TAPS, but production declines have reduced the volume carried by 25% from its peak capacity. Further declines in production will make TAPS uneconomic to operate unless new resources can be developed to offset the decline restore pipeline throughput. The estimated resource of heavy oil on the North Slope recoverable with current technology is 10-20 billion barrels.

Waterflood pilots have been attempted in two North Slope heavy oil reservoirs: West Sak starting in 1984 and Schrader Bluff in 1991. Initial well productivity of 300 barrels of oil per day (19 API gravity) was considered low by North Slope standards.

The goal of this research project was to develop new technology to increase well productivity as well as reservoir recovery efficiency. WAG injection processes and modern well architectures can be effective in recovery of the high-viscosity deposits at West Sak and Schrader Bluff. Several gas streams are available for the WAG process on the North Slope that contain NGL and CO2.

Project Summary
Heavy oil samples from three North Slope reservoirs-West Sak, Schrader Bluff, and Ugnu (the extra-heavy crude)-were studied to determine the optimal means to increase recovery. The goal was to develop tools to find the most efficient solvents and establish an injection schedule and well architecture for a WAG process that would be economic for North Slope shallow, heavy oil reservoirs.

The research focused on corefloods, analysis of sweep efficiency, compositional simulation, wettability, relative permeability analyses, and streamline-based simulations of WAG processes and the effect of potential chemical changes. Simulation results confirmed that injection of CO2-NGL is superior to produced Prudhoe Bay natural gas-NGL. Aromatic solvents (toluene and decalin) were found to work better than non-aromatic solvents, such as cyclohexane. The chemical and solvents tests found that adhesion properties of asphaltenes are responsible for the mixed wettability problems in the reservoirs. A streamline module was developed that can be incorporated into existing finite difference-based compositional simulator models for waterflood, gas flood, and WAG flood predictions.

The laboratory studies combined with field analysis indicated that horizontal wells increase recovery significantly over the use of vertical wells but that sweep efficiency may decrease. Electromagnetic heating as a means of well stimulation was found to be capable of doubling oil recovery.

A 5-spot, high-pressure cell was constructed to evaluate sweep efficiency of miscible WAG floods. WAG displacement processes reduced bypassing as compared with the use of gas floods, and improved oil recovery in core experiments. As the WAG ratio decreased and the slug size was increased, oil recovery improved.

The 5-spot, high-pressure cell constructed to evaluate sweep efficiency of miscible WAG floods on Alaskan North Slope viscous oil reservoirs.

Current Status (October 2005)
Project completed on schedule.

Publication
Final report available at www.netl.doe.gov.

Project Start: September 26, 2001
Project End: September 25, 2004

DOE Contribution: $594,250
Performer Contribution: $150,000 (20% of total)

Contact Information
NETL - Jim Barnes (jim.barnes@netl.doe.gov or 918-699-2076)
University of Houston - Kishore Mohanty (mohanty@uh.edu or 713-743-4331)