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Optimizing heavy oil recovery DOE-funded research uses state-of-the-art laboratory techniques to assess the best ways to recover North Slope’s heavy oil By Alan Bailey Petroleum News Staff Writer
In the past few years extended horizontal drilling techniques have made North Slope heavy oil pools such as Schrader Bluff and West Sak economic. And enhanced recovery techniques using injected fluids to drive the viscous oil from reservoir pores have further improved oil recovery.
But even with the use of these techniques a significant percentage of the 23 billion barrels of heavy oil around Kuparuk and Prudhoe Bay is likely to remain in the ground — stuck like treacle under the cold permafrost.
U.S. Department of Energy-funded research at the University of Houston has been investigating ways of further improving the recovery rates from the North Slope heavy oil reservoirs. The University of Houston’s chief researcher for the program, Dr. Kishore Mohante, has reported the results of this research, Jim Barnes, DOE project manager for the program, told Petroleum News.
Barnes said researchers used advanced laboratory techniques to find the best ways of applying enhanced oil recovery, especially a form of recovery known as WAG. The term “WAG” refers to water alternate gas, a technique in which waterflood alternates with gas injection to sweep oil from the reservoir.
“(The research program) would serve those that are operating there (on the North Slope) and those that think to operate there as a good source of information,” Barnes said.
Mohante used to work in the Alaska oil industry and is familiar with the North Slope heavy oil deposits, Barnes said. Simulated oil recovery According to the research report the University of Houston researchers built a device called a quarter 5-spot high-pressure cell to replicate in the laboratory a series of WAG sweeps through an oil-saturated sandstone core. Another apparatus called a slimtube enabled the researchers to test the displacement of oil by various injectants. Other experiments tested the interactions between solvents and oil-saturated substrates.
The tests and experiments used actual Schrader Bluff oil and tested the effectiveness of injectant sweeps with various combinations of natural gas liquids, carbon dioxide and simulated Prudhoe Bay natural gas.
In the course of their work the researchers determined a new four fluid phase model for calculating relative permeability in WAG enhanced recovery. State-of-the-art computer simulation The researchers used a state-of-the-art reservoir modeling technique known as streamliner based simulation to test the likely effect of using various enhanced recovery techniques.
“These tools have been out for several years but they’ve not been applied to my knowledge to the North Slope deposits,” Barnes said.
Traditional computer models, known as finite-difference simulators, require excessive computational time to model a 3-dimensional WAG system, according to the research report.
And using data from the quarter 5-spot experiment, the streamliner simulation could test the effect of well architecture on oil recovery efficiency — well architecture includes factors such as the length of a horizontal well. The researchers also used the computer model to test the impact on fluid flow of electromagnetic heating in a well. Using more gas beneficial The researchers found that you can improve WAG oil recovery by increasing the ratio of gas to water and by increasing the sizes of the injected slugs of fluid, Barnes said. And according to the research report the slimtube experiments and the computer simulations both indicated that mixtures of carbon dioxide and NGL work better as gas injectants than do mixtures of Prudhoe Bay natural gas and NGL.
The well architecture also impacts recovery rates. Although horizontal production wells increase access to the oil in the reservoirs, the reservoir simulation results showed that the sweep efficiency of the enhanced recovery fluids can be less for horizontal wells than for more steeply inclined wells.
There’s a similar trade off with well length — increasing the length improves well productivity but tends to reduce sweep efficiency.
The research also pointed to the potential for major improvements in well productivity through the use of electromagnetic heating in the well. However, Barnes said that the energy requirements to generate the necessary electricity for electromagnetic heating result in marginal overall efficiency improvements.
Further information about the University of Houston research can be found by going to
www.netl.doe.gov/scngo/Petroleum/WebFactSheets/ProgramExplorationProduction/ and clicking on the project entry under the “Completion and simulation” section.
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