Tundra Planning Nitrogen/Water EOR Pilot In Bakken/Three Forks

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Tundra Oil and Gas Partnership is seeking regulatory approval for an immiscible nitrogen flood in the Middle Bakken/Three Forks tight oil formations in the Daly Sinclair field of southwest Manitoba.

Based in Winnipeg, Tundra is a privately held light oil producer that operated the drilling of 168 wells in Canada last year -- 163 in Manitoba and five in Saskatchewan.

This isn’t the company’s first foray into gas flooding in a tight oil formation. Since August 2008 Tundra has been operating a miscible gas pilot injecting carbon dioxide in the southeast quarter of section 04-08-28W1 within Sinclair Unit No. 1. Last August this pilot was approved for conversion to a water-alternating-gas project.

Now the company is applying for an immiscible gas injection pilot using nitrogen. (In miscible gas floods, the injected gas forms a single homogeneous phase with the oil. The resulting fluid has lower viscosity, reduced interfacial tension and improved mobility. While immiscible gas doesn’t form a single phase with the oil, it still has the benefit of improved pressure maintenance and sweep efficiency within the reservoir.)

The pilot would use two horizontal injection wells. Based on expected reservoir permeability and pressure, Tundra is forecasting an average water injection rate of 10 to 25 cubic metres a day. The nitrogen injection rate is expected to be 2,000 to 5,000 cubic metres a day.

Tundra expects to alternate between nitrogen and water injection every three to six months to optimize the flood front and minimize gas channelling and breakthroughs.

In its application to the Manitoba government for the immiscible gas injection pilot, Tundra is seeking approval to install nitrogen injection equipment at two horizontal injectors in section 34-08-28W1.

“While the theoretical benefits of miscible EOR [enhanced oil recovery] are greater than for immiscible EOR, the operating costs are also greater,” Tundra says in its application, noting the current cost of CO2 renders commercial expansion uneconomic.

The company said it plans to use nitrogen because it is “readily available in the atmosphere.” Even with the initial setup expense of the nitrogen generator, a nitrogen flood would cost less per barrel to operate than a CO2 project, the company said.

“N2 has the additional benefit of not being a greenhouse gas and is environmentally safe and will not need additional facilities to recapture the produced gases,” Tundra said.

Due to the nature of its reservoir, the company believes gas can provide greater pressure support than water due to gas’s favourable mobility ratio to oil.

Nitrogen would be generated on site because transporting liquid nitrogen is much more difficult than transporting CO2 due to nitrogen’s low boiling point, Tundra said. It would use a system that filters nitrogen from the atmosphere, then compresses and stores it.

“This is a significantly more cost effective method of delivering gas injection [than] Tundra’s existing CO2 pilot,” the company said. CO2-based EOR pilots in Western Canada typically use trucked CO2.

Injection water for the pilot would come from the Lodgepole formation, which supplies the existing Sinclair units. Produced water isn’t currently used for any water injection in the Tundra-operated Sinclair units and the company said it has no plans to use produced water for the proposed pilot.

To do the EOR project, Tundra has applied to unitize 16 legal subdivisions in Section 34 of Township 8, Range 28 W1. The proposed unit -- which would be called Ewart Unit No. 5 -- would consist of 16 tracts based on 40-acre legal subdivisions.

Tundra holds 100 per cent working interest ownership of the lands it is applying to unitize. The proposed unit would include four existing producing wells in the Middle Bakken/Three Forks reservoir.

Total net original oil in place in the proposed project area is estimated at 2.78 million bbls for an average of 174,000 bbls per 40-acre legal subdivision.

According to Tundra’s application, oil production per well in the proposed project area peaked in 2009 at 268 bbls a day. As of last November, average oil production per well had fallen to 9.6 bbls a day. Production is forecast to continue declining at a rate of nearly 29 per cent a year.

By last Nov. 30 cumulative production from the four wells within the proposed Ewart Unit No. 5 project area was 206,500 bbls of oil and 292,800 bbls of water. The recovery factor was 7.4 per cent of the net original oil in place.

Estimated ultimate recovery of primary proved producing oil reserves in the proposed project area is estimated at 256,000 bbls with 49,500 bbls remaining as of last Nov. 30.

Under the current primary production method, ultimate oil recovery of the proposed Ewart Unit No. 5 is forecast to be 9.2 per cent of the original oil in place.

Based on a study by Coho Consulting Ltd., Tundra said the section was deemed to be suitable for a nitrogen flood.

Tundra estimates ultimate recovery of proved oil reserves in the project area, using a secondary water-alternating-gas EOR scheme, would be 379,000 bbls of oil with 176,000 bbls remaining.

The company estimates an additional 123,000 bbls of proved oil reserves could be recovered via its proposed unitization and secondary EOR scheme versus the existing primary production method.

Tundra estimates water-alternating-gas injection in the proposed Ewart Unit No. 5 would boost the total recovery factor to 13.5 per cent.

Under the planned EOR scheme the existing horizontal 08-34-08-28 producer well would be converted to an injector and a new injection well would be drilled between existing horizontal producers.

Tundra’s water-alternating-gas injection pilot would test two different production patterns within the same section. One pattern would test 40-acre spacing, the other 20-acre spacing.

The 40-acre spacing pattern would be achieved by converting the existing 08-34-08-28 producer into an injector. This injector would support the production from 00/01-34-08-28 and 00/09-34-08-28.

To create the 20-acre pattern, a new open-hole horizontal injector would be drilled between 09-34-08-28 and 16-34-08-34.

Pending regulatory approval, Tundra said the pilot could begin operating next summer.

The company plans to evaluate over five years whether water-alternating-nitrogen injection will improve oil recovery where waterflooding and miscible gas flooding have been deemed uneconomic due to poor reservoir quality.