1. Mega-units : This refers to spacing units that are greater than 1280 acres, generally 2560 acres. Several wells have already been drilled on 2560-acre spacing. [For basics in Bakken spacing, click on FAQs at the top of this page, or click here.]
2. I count no less than seven (7) 2560-acre units in the "Whiting-owned Sanish oil field." These are all 2-section x 2-section units and all wells are short laterals or the standard "long laterals," no super-long laterals. [And, of course, there would not be, in a 2 x 2 configuration.]
- There are six wells in one of these units; all are short laterals with one still confidential, and one being drilled.
- On the second 2560-acre unit, there are four wells, all producing, all short laterals.
- On the third 2560-acre unit, there are three wells, ditto.
- On the fourth 2560-acre unit, there are three wells, all producing, all long laterals.
- On the fifth 2560-acre unit, there are two wells, ditto.
- On the sixth 2560-acre unit, there are two wells producing, both long laterals; and, two being drilled.
- On the seventh 2560-acre unit, there are two long laterals producing, two short laterals producing, and one still on the confidential list.
- Some are not yet drilled on.
- I was able to find two such units with wells, but they were both standard long laterals (file numbers: 17742, 17292, and 17432) all in the North Fork oil field.
- There are no horizontals longer than the "standard" long lateral.
- There are reports that EOG will drill a 1600-acre space well with a 2.5 mile lateral.
- With 640-acre spacing, it was easy to tell if a well was being drilled in the section where you owned minerals. Now, with 2560-acre spacing, your 10 acres might be in a section that is three sections (or even four sections) from the well itself.
- With 640-acre spacing, you might not receive any royalties even if your minerals were just feet away from a well. Now, with 2560-acre spacing, you might end up with a few royalty dollars from a well that is spudded almost four miles away from your acreage. At least that's what others are saying.
6. These very long laterals would require significantly more fracture stages.
7. Pending 1280-acre units: Take a look at Case Number 12245, Order 14497, March 23, 2010, of the North Dakota Industrial Commission by clicking here. In one order, the NDIC authorized the drilling of approximately 1,525 horizontal wells on that number of 1280-acre spacing units. This affected 85 (if I counted correctly) townships across North Dakota and there were eighteen (18) spacing units of 1280 acres each in every one of these townships with exception of but a handful.
8. Pending 2560-acre units: A similar case to authorize "across the board" 2560-acre spacing units was not approved by the commission. Requests to approve 2560-acre spacing units will be considered on a case-by-case basis. (Case 12244, Order 14496)
9. It is assumed that multi-well pads would be the norm for mega-pads, but I'm not sure that will be true in all cases.
- A 2-section by 2-section 2560-acre unit lends itself well to an Eco-Pad, two laterals going north and two laterals going south, for example. Even a 1-section by 4-section unit can be exploited with "standard" long laterals by placing the multi-well pad between the second and the third section, again with two laterals going one direction and two laterals going the opposite direction.
- However, some are suggesting that it is possible that a 4-mile lateral could be drilled from one end of the 1 x 4 mega-unit. I thought this was crazy but apparently it's been done elsewhere, and the deep water wells have horizontals that go that distance. It would require a different kind of rig than what is currently available in North Dakota.
11. By the way, has anyone ever wondered how they know where these horizontal well bore heads actually go? GPS technology is used and NDIC knows exactly where these horizontals are.
12. Going back to paragraph 2 above: I noted that one 2560-acre unit had six wells, all short laterals. The NDGS estimates the EUR by county (ultimately by section), whereas oil well companies estimate EURs per well. In an earlier post, I calculated that the EUR/section in the Sanish is about 350,000 bbls according to NDGS numbers. So, these four sections have a EUR of about 1.4 million barrels. But 1.4 million/6 wells = 233,000 bbls/well, far less than the 500,000 to 750,000 bbls EUR/well that oil companies forecast for wells in prolific oil fields like the Sanish. Worse, if some of these wells are targeting the TFS and some the Middle Bakken, the numbers are even farther apart. I remain confused.
- If each of those six wells produces 200,000 bbls overs its lifetime, that equals 1.2 million bbls. At $50/bbl, that equals $60 million for the six wells which would have cost about $36 million.
- If each of those six wells produces 400,000 bbls over its lifetime that works out to $120 million at $50/bbl. Remember, the oil companies opine up to 750,000 bbls/well EUR in these most prolific fields.
- On the other hand, if the four sections produce a total of 1.4 million bbls (NDGS estimates, as I calculate them), that amounts to about $70 million at $50/bbl.
- It's a crap shoot. Even the SEC agrees.
