Sunday, August 26, 2007

That Nagging Well Density Problem

This will be a long post folks, so if you don’t like reading dry material, it’s best to skip this one.

This past week the issue of well density came to a head in a hearing of the Industrial Comm. when Marathon sought to create a few 1280 acre drilling units in Dunn Co. As background, the state regs allow a horizontal well to be drilled upon a unit only as large as 640 acres. Therefore, if a company plans a H well on a 640 acre unit, it only has to apply for a drilling permit, but a hearing is required to create a unit larger than 640 acres. Now until this hearing, there has been little opposition to any application for a 1280 acre unit that I can recall (outside of Murphy Creek field that will be discussed later). What caused the contention during this case was that in some of the proposed drilling units, Hunt owned a substantial, but less than majority interest. In one unit, however, Hunt owned 50% as it controlled the interest in one section, and Marathon controlled the other section.

Hunt objected to the 1280 acre unit(s) where it had an interest, and maintained that it wanted to develop its acreage on 640 acre units and cited that it expected to transfer its success with its completion techniques in the Parshall area to other areas in the play. Now it should be mentioned that the proper spacing for Bailey Field was also considered at this hearing. Marathon, the most active company in the field, maintains that it wanted flexibility in the field rules to allow for the possibility of a second and perhaps a third lateral in each 1280 acre unit. It proposed that it be allowed to place the initial lateral no closer than 1320 ft. from the east or west unit boundary (these are all standup units and the field rules required that the lateral more or less transverse the center of the two sections).

By placing its lateral close to one side of the unit, Marathon could then drill a second lateral on the other side of the unit, if it was shown that a second lateral was economic. The company said it may also drill a third lateral in some units and it has identified at least one unit where that would be economic. Marathon stated that it needed a number of months to evaluate the productive trend of a well to determine the permeability, and hence, whether a second lateral would be utilized. Marathon’s engineer originally didn’t place a precise length of time this evaluation would take, but after questioning by the commission, stated that a minimum of three months would be needed (if I recall correctly). Marathon presented a number of exhibits indicating how big an areal extend it believed a lateral was effectively draining.

The commission then questioned Marathon’s engineer regarding it’s prior application to drill two separate grassroot vertical wells, each with a lateral, by skidding the rig a few feet after drilling the first well. (See 7/16 post). After steadfastly maintaining that it needed time to evaluate whether a second lateral would be drilled, the commission finally got the Marathon engineer to admit that it would in fact skid the rig and drill some second wells immediately after finishing the first and would not require a evaluation phase in that case. The commission then asked the million dollar question that if you drill the initial lateral close to the west line of the 1280 acre unit, for example, and then decide not to drill a second lateral on the east half, how does that protect the correlative rights of the owners in either half of the unit, when it appears that all the production is coming from the west 640 acres in the unit.

The Marathon engineer then gave some rather unpersuasive testimony, in my opinion, that he believed that the east half would in fact have “some” contribution to the well’s production. (However, if the permeability was good enough for the east half to contribute “some” oil way over to the wellbore on the west half, wouldn’t that justify a second lateral on the east half?) Meanwhile, Marathon’s “area of mutual interest” partner, PDC, had developed a portion of the field on 640 acre units, but didn’t have an objection to Marathon’s proposed plan of development. Marathon stated that the wells on PDC’s 640 acre units were demonstrating half or less of the performance of Marathon’s wells on 1280 acre units. When questioned why they couldn’t wait with the units that involved Hunt and let Hunt develop its own lands and use its own drilling and completion methods on 640 acre units, which Hunt thought superior to Marathon’s, Marathon stated that they had five rigs active and a drilling schedule to follow.

In an area not far from the Marathon/Hunt issue, when Kerr-McGee (properties now operated by Encore) originally applied for drilling units in Murhpy Creek field, it asked for 1280 acre units with a dual co-planar placed on one side of the unit. The company stated, much like Marathon, that this initial well placement would allow a second well on the unit, if justified. There was some mineral owner opposition on one unit and the company then began developing the field by utilizing dual laterals from a single vertical well on 640 acre units. Encore has since switched to utilizing a single lateral diagonally across a 640 acre unit. Marathon made an application last month to expand the boundaries of the Murphy Creek field to create eighteen new 1280 acre spacing units, which was heard at the hearing last week. (See 7/30 post). In the meanwhile, before the hearing, Encore received about a half dozen drilling permits in the Murphy Creek area for wells on 640 acre spacing on lands that were contained in Marathon’s application. During the hearing, Marathon stated it had reached agreement with Encore, and Encore would develop a number of sections on 640 acre units, which Marathon dropped from its application, and Marathon would request that the remaining units be made into 1280 acre drilling units, instead of spacing units.

Now my personal opinion on some of these matters, for whatever it's worth. I don’t believe that a lateral run down the center of a unit drains the entire unit, absent some extensive natural fracturing. I’m not buying this proprietary completion techniques story that some companies are touting. There are some commonly know conditions that are believed to have “busted up” the Bakken in certain areas, which some companies have exploited. In my opinion, geology is the primary driver of the success of these wells. EOG has been telling Wall Street that it believes some (most?) of its success in Parshall Field is attributable to its completion techniques, but then admits that up until now its success has been confined to one small area, where it seems apparent that there is excellent natural fracturing. Hunt also makes somewhat similar claims. When Hunt comes down to the Bailey Field area and brings in wells like those in Parshall Field, I will amend my opinion.

For example, Ansbro has an excellent well on its Kadrmas lease that blew out and caught fire. The well has produced about 60k bbls from one 2,500 ft lateral that I believe was not initially fraced. Meanwhile, the company’s dual co-planar wells with about 9k ft of lateral open, on 1280 acre units immediately to the south and east, have produced a fraction of what the Kadrmas well has. Marathon’s Stohler well in Bailey field has been one of the best Bakken performers in the state outside of Parshall field, and Marathon presumably did not use completion techniques on this well any differently than its other wells, and it is surrounded by less than stellar wells. Without information that is available only to these companies, I believe what makes these two wells “flukes” appears to be some isolated favorable formation quality, rather than completion techniques.

I also think 640 acre units, with their shorter laterals, are more favorable in terms of getting a better frac job. Marathon stated that it doesn’t use “stage fracing,” on its nearly two mile long laterals, whereby individual sections of the lateral are isolated and fraced separately. Marathon said the risk and expense of the procedure were prohibitive. The company claimed that its review of data indicates it is getting a fairly uniform frac over the entire length of the lateral without the use of stage fracing (which I find hard to believe), but didn’t know how far the fracs extended in the formation.

Perhaps when the performance and economics of the Encore and Marathon wells in Murphy Creek field, on different sized units, are compared, some of these questions can be answered. I remember attending the multi-day hearing in ‘90 or ‘91 on spacing regarding the wells in the upper Bakken shale play, which everyone believed back then as being the new Prudoe Bay. There was differing ideas then regarding whether well density should be 320 acres or 640 acres, and for the life of me I can’t remember what came of it, because the play died out a few months after the hearing. Spacing generally must have been left at 320 acres because until only recently, that was the largest unit allowed by the regs for horizontal wells. Bottom line here is that I generally agree with a comment made on a previous post that 1280s will be used to tie up leases and 640s will be used to actually produce.

If anyone has any information as to details of Hunt’s testimony (or correct my recollection in general), feel free to elaborate as I missed most of it.


Anonymous said...

Did the commission grant Marathon's request?

Teegue said...

It usually takes a month or more to get a commission order on non-expedited cases.

Anonymous said...

There is more to that story.

The IC just issued Orders for several June hearings to Continental for a similar request. In those cases the just issued Orders approved Continental’s request for the full 1280 drilling units.

Continental reported that they along with Marathon, and Burlington came up with the single 2-mile long single lateral located 1320 feet from the west (or east) line. IC staff stated that previously they would only grant a drilling unit as 2 standup 320s as that would allow them to drill the well and then they would have to prove that it drains the entire 1280 at the spacing hearing. Continental responded they need the flexibility to locate the well in the 1280 and they had data from their MT wells that shows the full 1280 contributes. The hearing was left open to allow the data to be submitted, which the Order says was subsequently received. But, the data was not included in the hearing exhibits. If the data is regarded as non-public, why?

Since they now granted the request to Continental, they will also grant it to Marathon, expect maybe for one drilling unit that Hunt objected to.

Teegue said...

I remember that case. The reason the evidence from MT isn't in the record could be that it is proprietary (but the Order doesn't so indicate) or that it hasn't been scanned yet or is oversize (but docs dated later that their submission is in the record) Seems kind of fishy.

Here are some relevant parts of the order:

(8) Continental testified that very large hydraulic fracture stimulations are done to the
horizontal wells drilled in the Bakken Formation in order to generate transverse fractures and
that these transverse fractures are reaching out a considerable distance, in excess of 1320 feet.
Continental has anecdotal evidence obtained from their horizontal Bakken Formation wells drilled in Montana that they believe proves this. Continental testified they have observed fracture stimulation f1uid in horizontal wells up to
one mile away from the horizontal well undergoing fracture stimulation; they have observed
fracture stimulation f1uid and proppant in horizontal wells up to one-half mile away from the
horizontal well undergoing fracture stimulation; they have observed pressure increases detected
by pressure bombs in horizontal wells offsetting the horizontal well undergoing fracture stimulation; and they have observed improved well performance in horizontal wells adjacent to
the horizontal well undergoing fracture stimulation.

The Bakken Formation that is under development in Montana is believed to be of better reservoir quality but similar results could conceivably be obtained here in North Dakota.

Continental stated they would be willing to submit evidence that supports their observations and also reservoir modeling evidence based on North Dakota data that supports their belief that a
horizontal well located as depicted in paragraph (7) above is capable of draining reserves from
the other half of the 1280-acre unit.
The record was left open for one week in order to receive additional evidence from Continental. Such evidence was received on July 5, 2007 and the record was closed.

(9) Continental testified that the drilling, completion, and fracture stimulation of a horizontal well located as depicted in paragraph (7) above definitely impacts the entire 1280-acre drilling unit.

(l0) Continental stated they need the f1exibility afforded by allowing the first well in a
proposed 1280-acre drilling unit to be drilled at a location not less than 1320 feet from the east and west boundaries and 500 feet from the north and south boundaries of the proposed drilling unit. Continental stated that this design allows for orderly development and would facilitate an infill drilling program or enhanced recovery project with wells having a 1320-feet interwell distance.

(11) Based upon the testimony and evidence submitted, the Commission agrees that Continental's proposed well design justifies the 1280-acre drilling unit.

(12) If the proposed well is productive, the Commission will establish spacing for the
development of the pool as provided by statutes and rules of the Commission.