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Sunday, July 25, 2010

Disjointed Data Points -- For Now, Including Mega-Units

I have no idea where I'm going with this, but there are some interesting things being talked about among those closer to the Bakken, and among those who are much more knowledgeable than I am. I think all of this is still being sorted out.

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.
3. There are a handful of 2560-acre units in the 1-section by 4-section configuation.
  • 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.
4. The issue of mega-units raises all kinds of questions among mineral owners.
  • 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.
5. Folks are talking about horizontal wells that will be longer than the "long laterals" that are now common in the Bakken. "Long laterals" are now a bit less than two miles long in most cases (about 9,000 feet). Some folks are now talking about 2.5-mile long laterals, and some are talking about even longer laterals.

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.
10. It goes without saying, but I will say it anyway, it's going to be challenging to sort out mineral rights and royalties when 2560-acre spaced infill wells are drilled among older wells that were drilled to 640-acre spacing. Actually, it shouldn't be challenging at all (if you have minerals somewhere in that 2560-acre unit, you should receive royalties), but I'm sure folks directly affected will raise questions.

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.

Bakken Acronyms and Glossaries

I keep running into acronyms in various presentations and needed a spot to keep track of them. 

Most of these terms are "old hat" to everyone else, and readily available at the Schlumberger glossary site, but for newbies, hopefully this page will be of some help.


Oil and gas glossary.

"SXL" was not in the Schlumberger glossary and that's what prompted this webpage.


ACRONYMS AND DEFINITIONS

CAGR: compound annual growth rate

EUR: estimated ultimate recovery

FBIR: Fort Berthold Indian Reservation

HBP: held by production

IRR: Internal Rate of Return
NPV is the difference between cash inflows and cash outflows. It shows the overall profitability of each well. This NPV is figured using these values:
  • $8.9 Million in Well Costs
  • EUR (Estimated Ultimate Recovery) of 600 Mboe
  • 5-31-11 NYMEX Strip
This produces a 75% IRR (Internal Rate of Return). The IRR is best described as the rate of growth a project is estimated to generate.
LOE: lease operating expense

MHA: Mandan, Hidatsa, Arikara; Three Affiliated Tribes (TAT); Fort Berthold Indian Reservation

NPV: Net Present Value
NPV is the difference between cash inflows and cash outflows. It shows the overall profitability of each well. This NPV is figured using these values:
  • $8.9 Million in Well Costs
  • EUR (Estimated Ultimate Recovery) of 600 Mboe
  • 5-31-11 NYMEX Strip
This produces a 75% IRR (Internal Rate of Return). The IRR is best described as the rate of growth a project is estimated to generate.
OOIP: original oil in place

P1 (90), P2 (50), P3 (10), PUD (90): "slang" for oil and / or natural gas reserves

Pooling: generally the last step before drilling commences

PIP: precision identified perforations, a type of simultaneous, multi-stage fracturing; compare with "plug and perf"

PUD: proved undeveloped reserves (90% chance to recover oil with existing technology, but requires new wells)

ROCE: return on capital employed (commonly used)

ROEC: return on economic capital (not as commonly used)

SHD: Spotted Hawk Development LLC (the oil exploration and production company of MHA)

SXL: super-extended laterals; an acronym I first saw with the recent Newfield presentation; Newfield discussed SXLs back in February, 2010. These are laterals greater than 5,000 feet, something CLR has been doing for quite some time.  Most of us just refer to laterals as "short laterals" or "long laterals."

Well Status Definitions

If you arrived here from another link looking for "Areas of Interest, by Producer," this information has been moved. Click here.

On many corporate presentations, one sees PDP, PBP, PNP, and PUD. Here is a note from a discussion thread regarding these acronyms:
When evaluating the value of a field the reserves are broken down into PDP, PUD, PBP and PNP as general categories: Proved Producing, Proved Undeveloped (not yet drilled), Proved Behind Pipe (drilled but waiting for a recompletion to that reservoir) and Proved Non-producing (maybe waiting for a pipeline to be built). And this obviously just covers the proved categories. Possible and probable are the other two big categories. To fall into any proved category a well has to be drilled and logged thru the reservoir. And then, according to SEC regs, the proved category only extends one offset location in four directions from the well. One well might indicate a 2,000 acre productive field but the regs might only allow four 40 acre units classified as proved (PUD) around the discovery well.


Obviously "reserve" numbers tossed out by national oil companies (NOCs) don't come close to fitting this protocol. And as someone pointed out, the number that counts most is proved producing. And the category Proved Undeveloped is very dependent on development cost/oil prices. A field might have 500 million bbls of PUD reserves at $80/bbl but only 100 million bbls of PDP at $40/bbl.
 This source probably has one of the best definitions of PDP, PUD, PBP, and PNP.


    Bakken Production Held Back By Flaring

    (You know it's a quiet day in the oil patch if I'm reporting on flaring. Smile.)

    If I remember correctly, NDIC put in restrictions on producers to limit production if they were flaring gas. ( I believe that had to do with MDU's request to designate the Cottonwood Field a year or so ago: as part of the agreement, only so much oil could be produced in that field pending natural gas pipelines being put in.) North Dakota has one of the highest rates of flaring gas at the time I posted that, and NDIC wanted the flaring to be minimized.

    There's an interesting thread at the Bakken Discussion Group : there is still a delay in getting natural gas lines put in. I have no idea if this is having a material effect on oil production, but my assumption is that in some areas, production may be held back until natural gas lines are in.

    The Bismarck Tribune reported on the issue of flaring one year ago. At that time, North Dakota was burning off one-third of its natural gas compared to 1 percent nationwide and 3 percent worldwide.

    In May of this year (2010), the Williston Basin Interstate Pipeline Company announced plans to increase its capacity by 33 percent.

    Additional background can be found here.



    Temporary Flaring in Dunn County, North Dakota (USA)