Some Initial Thoughts on Unitization and Enhanced Oil Recovery in the Bakken, North Dakota, USA

I have noticed a trend towards increased density wells, infill wells, and references to 160-acre spacing in the North Dakota Bakken in multiple sources: NDIC hearing dockets, corporate presentations, and investment blogs. [I started seeing an increase in infill well permits in the March, 2011, NDIC hearing docket, but they really started to pick up in the April, 2011, docket. There are now requests to put as many as thirteen wells in one 1280-acre spacing, and as many as six wells in one 640-acre spacing unit.]

When the number of wells begins to saturate a field, folks will start talking about "unitization," which Schlumberger defines as the combining of multiple wells to produce from a specified reservoir.

Others associate unitization with enhanced oil production (maybe that is implied in the Schlumberger definition). "Unitization is similar to pooling, but it occurs when producer(s) are ready to use enhanced oil recovery to maximize production from a common reservoir. Sixty percent of royalty owners (weighted) must agree to unitization before the NDIC will authorize it." One can find requests for unitization in non-Bakken formations in North Dakota in the hearing dockets.

Terms associated with "unitization" include pressure maintenance, secondary recovery, and tertiary or enhanced oil recovery (EOR). Wikipedia has a nice overview.  It is interesting to note the differences in definitions of these terms at the various sites. Those sites will take you to discussions of waterflooding and enhanced oil recovery (particularly the use of CO2 to increase oil production) Denbury is one of the leaders in EOR; it bought Encore (back in 2009/2010) which is active in North Dakota.

Because of the nature of the geology of the North Dakota Bakken, there are folks that argue the ND Bakken is not amenable to waterflooding or enhanced oil recovery.  That is yet to be determined. Theoretical articles support the contention that unitization won't work in the ND Bakken, but theoretical arguments several years ago also suggested that the ND Bakken was not economically viable.

Farther west, in the Alberta Basin Bakken, "they" have begun exploring enhanced oil recovery techniques. Specifically, Crescent Point is looking to use enhanced oil recovery techniques in the Alberta Bakken.

Having locked up a dominant land position in both the [Alberta] Bakken and Lower Shaunavon plays in Saskatchewan, Crescent Point Energy Corp. hopes to more than double its reserves with further exploitation and enhanced recovery.

[According to its CEO], Crescent Point is well positioned to further exploit two of Western Canada's hottest plays.

The company believes it could more than double their current reserves over the next three to five years, just through infill drilling, waterflood implementation and production optimization. EOR and production optimization could provide an additional 5,000 drilling locations and the potential to add over 500 million bbls of reserves. [This section corrected April 3, 2011; see comment section.]

As noted above, some argue that waterflooding won't work in "tight formations" like the Alberta Bakken or the North Dakota Bakken. Experts acknowledge that but Crescent Point is going to try.

For now, in the North Dakota Bakken, we're going to see increasing emphasis on infill / increased density wells. Take a look at what Whiting is doing in the Sanish. Look at BEXP's February corporate presentation with a relatively new wrinkle: increased emphasis on infill wells in their Ross Prospect and their Rough Rider Prospect (slides 16 and 18). Producers talk of "pilot" wells to see if spacing units can support additional wells.

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Connecting some dots regarding CO2 injection in the North Dakota Bakken.

EOG's #16713, Austin 1-02H: EOG requested and was given permission to test CO2 injection back in 2008.

Background of Austin 1-02H

• Short lateral in the prolific Parshall oil field, section 2-T154N-R90W
• Spudded December 13, 2007
• IP: 781 bbls
• A monster well, as many are in the Parshall: > 222K in first 10 months, prior to CO2 injection

CO2 Injection test

• CO2 injected for 11 days; half in September; half in October
• Wells monitored in the immediate 2-mile radius to see if CO2 was breaking through (communicating) with other wells; CO2 was detected in one well a mile away; not immediately detected at two other wells about same distance away.
• I found it interesting that one of the wells where CO2 was not detected, had a significant increase in monthly production following the injection; it may have just been coincidence (Bruhn 1-12H, #17128, a non-EOG well).

Current status of Austin 1-02H

• To date: this well has produced a total of 416K bbls of oil; most recently it is producing 4,000 to 5,000 bbls/month

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