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BP to try new waterflood for viscous Drawing hot, clean water from deep underground and injecting it into the viscous oil reservoir should increase production rates Alan Bailey Petroleum News
As part of its ongoing efforts to develop the huge viscous oil deposits under Alaska’s North Slope, BP Exploration (Alaska) is trying a novel technique that involves extracting hot water from an underground rock formation and then injecting that water into the viscous oil reservoir. Samson Ning, a senior reservoir engineer working on viscous oil development at Milne Point and adjunct professor at the University of Alaska Fairbanks, described the technique at the joint meeting of the Cordilleran Section of the Geological Society of America, the Pacific Section of the American Society of Petroleum Geologists and the Western Region of the Society of Petroleum Engineers on May 10 in Anchorage, Alaska.
Ning talked about BP’s viscous oil development in the OA and OB sands of the Schrader Bluff formation, above the Milne Point field, between the Prudhoe Bay and Kuparuk River fields. BP is producing viscous oil from horizontal production wells, using waterflood from vertical injection wells.
The water for the waterflood comes from neighboring oil production facilities, where it is separated from oil and gas coming from producing oil wells. This produced water contains impurities and is cold by the time that it is injected into the viscous oil reservoir.
Matrix bypass In the interests of flushing as much oil as possible from the Schrader Bluff sands, the injection pressure for the waterflood needs to be as high as possible — the higher the pressure, the more oil flows towards the production well.
The problem is, however, that high water pressures can cause a phenomenon called “matrix bypass,” in which the injected water breaks through the rock matrix to the production well bore. Instead of flushing oil from the reservoir rock, the water simply flows straight out through a production well.
And that’s a disaster when it comes to maintaining oil production rates.
“We have sudden water breakthrough … the injection rate goes up instantly. … On the producer side, the oil production goes down, the water production goes up, the bottom hole pressure and temperature increase,” Ning said.
The whole process, from the increase in injection rates to the impact on the production well typically happens within about an hour, thus indicating a direct fluid communication between the injection and production wells, Ning explained.
The phenomenon relates to fracturing of the reservoir rock when the injection pressure exceeds the rock fracture pressure, he said. But that’s not the entire explanation.
“Our fracture model only goes a couple of hundred feet at most, so it doesn’t go all the way from the injector to the producer, which is about 1,500 feet or so,” Ning said.
So something else must be happening closer to the production well. Reservoir engineers theorize that oil production into the production well erodes “worm holes” in the reservoir sands. Then, when fractures propagating from the injector meet the wormholes, injected water can flow directly to the production well bore.
The reservoir engineers have found that they can eliminate matrix bypass by choking down the injector to reduce the injection pressure. But that significantly reduces oil production rates.
“We’ve had a 40 percent drop in production capacity,” Ning said.
And to make matters worse, the reduced pressure increases the gas to oil ratio in the production well. This degassing of the oil in the reservoir increases the viscosity of the oil, thus making the oil more difficult to extract. Reservoir models show that the viscosity of the oil in a pressure-supported reservoir hardly changes over time, while the viscosity in an unsupported reservoir almost doubles during the course of a year’s production, Ning said.
Solutions It would be possible to increase production without using high injection pressures by increasing the number of injection wells. But that is an expensive solution.
Instead, the BP viscous oil team has what it thinks is a much more cost-effective solution — the injection of hot, clean water for the waterflood, instead of using cold and relatively dirty produced water. And there’s a ready source of suitable water in the Ivishak formation at a depth of about 9,000 feet under the Milne Point field. The Ivishak forms the main reservoir for the nearby Prudhoe Bay field but only contains water under Milne Point.
So in November BP drilled a water well into the Ivishak.
“We drilled a well which can produce about 20,000 barrels (of water) per day,” Ning said. The water is at a temperature of about 230 F at depth and about 210 F when it reaches the surface, he said.
BP plans to inject this water into the Schrader Bluff reservoir from S pad at Milne Point. The water will cool to about 150 to 160 F in the well bore. The oil in the Schrader Bluff formation is normally at a temperature of about 80 F and has a viscosity of 40 centipoise, Ning said. The hot injected water should raise the oil temperature in the neighborhood of the injection well to about 135 F, thus reducing the oil viscosity to about 10 centipoise.
That reduction in viscosity will cause the oil to flow more easily. But it will take a long time for the higher temperatures to permeate the reservoir — reservoir modeling indicates that it would take about 20 years of injection before most of the reservoir reaches the elevated temperatures.
Higher injection pressures Because of the very slow heating of the reservoir, the economic benefit of reducing the oil viscosity is likely to prove low. But the technique of using hot water should result in major benefits by enabling higher injection pressures to be used without causing matrix bypass. In fact, both the high temperature and the cleanliness of the water appear to enable the reservoir rock to withstand higher injection pressures. And those higher pressures will translate to higher oil production rates.
Rock mechanics calculations indicate that the technique will increase the reservoir’s fracture pressure from 2,500 pounds per square inch to 2,900 pounds per square inch, although it may take up to a year of injection for that full increase to be realized. The increase in fracture pressure should translate to an increase of 50 percent in water injection rates and an improvement of 15 percent in oil recovery, Ning said.
The hot water will also prove more effective for waterflood than cold water.
“It also reduces the injection water viscosity … and gives you a higher injection rate,” Ning said.
BP expects to start injecting the Ivishak water into the Schrader Bluff formation at S pad in August. The project needs minimal surface infrastructure and does not require surface heating of the water.
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