A reader sent it to me. A huge thank you to the reader.
The article has to do with enhanced oil recovery (EOR) using nitrogen instead of CO2.
One should review primary, secondary, and tertiary oil production at wiki.
I'm getting out of my comfort zone and could be very, very wrong on this, but reading the wiki article as well as Schlumberger definitional resources, and then the new article (linked below), it looks like using nitrogen to help recover oil could fall into either secondary or tertiary production.
Again, outside of my comfort zone, it appears "secondary" production has to do with increasing reservoir pressure whereas "tertiary" production has to with decreasing viscosity. Depending on "how" one used a gas such as CO2 or N2 determines whether it is "secondary" or "tertiary" recovery. EOR is generally "synonymous" with tertiary recovery. (Further confusing matters, there is some suggestion that the operators consider this use of nitrogen to be part of primary production; see below.)
Again, this is all colloquial.
[Confusing matters further, nitrogen apparently can also be used for fracking, or at least has been tried. At the bottom of the blog, I have a "Fracking_Nitrogen" tag, for example.]
junewarren-nickle's energy group.com is reporting:
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.)This is a long, long article and many, many data points.
First, of all, this is a Canadian story, with subject wells in Saskatchewan and Manitoba. I talked about the Bakken in Manitoba in a recent post, but in that post, the Canadian Three Forks was referred to as the Torquay.
Second: in this new article, the difference between using CO2 and N2 is spelled out very nicely. The big difference is that using N2 is much less expensive than using CO2, is readily available, and doesn't get into the issue of global warming/greenhouse emissions.
A third data point has to do with the general recovery rate of crude oil from the Bakken/Three Forks in this area (Saskatchewan/Manitoba):
Total net original oil in place (OOIP) 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.Note the "downspacing": 40 acres. (In one test, they plan to go to 20-acre spacing, also.)
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.
Note the recovery rate: 7.4% of the net original oil in place (OOIP) prior to N2 flooding.
With N2 flooding, they propose a recovery rate of 9.2%.
Note the EUR of these Bakken/Three Forks wells: 256,000 bbls. Compare with EURs of Bakken/Three Forks in North Dakota -- suggested to range between 400,000 and one million bbls.
This is where it gets a little confusing. In bold in the above paragraph, it sounds like they consider N2 flooding part of primary production: "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."
This seems accurate because almost immediately, the article talks about "secondary" / EOR production:
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.And here, the author writes "secondary" and "EOR."
Be that as it may. It's a long, long article, with many, many data points. As noted at the beginning, this may turn out to be an article we come back to again and again.
Oh, by the way, there is at least instance in which N2 injection was being considered by an operator in the North Dakota Bakken. In the August, 2012, NDIC hearing dockets, case 18402:
- 18402, Whiting, nitrogen injectivity test in the Sanish, Mountrail
Perhaps the most important takeaway from this article: rate of recovery before additional measures -- about 7%. My hunch is that newer, more aggressive technology in the North Dakota Bakken is resulting in a great percentage recovery.