Marathon Buys PDC Acreage

Marathon has purchased from PDC about 72K undeveloped acres and most of the company's Bakken wells for almost $35 million effective 12/31. The transaction brings Marathon's net acreage up to 320K acres. Fox News

PDC and Marathon had a AMI in a large part of Bailey Field in Dunn Co., where each was developing their interests in a checkerboard pattern, but PDC hadn't been active in the area since last summer. Marathon is going to need a few more rigs besides the six it currently operates to hold a lot of its proven acreage, where the leases mostly expire in two years or less.

Speaking of Marathon, here are a few pictures of their operations in Bailey Field near Killdeer in Dunn Co.









It also appears that Billings, MT based Nance Pet. has sold most or all of their interest in ND to St. Marys Land & Exploration.

Some Reader Input

David expended some effort in writing some comments to a recent post that deserve some better exposure. He wrote:

EOG seems pretty confident that they can recover 750,000 bbls of oil from each section drilled in the Parshall/Bakken field almost irrespective of the initial bopd figure. According to Mark Papa in one of his responses during an analyst presentation, the Bartelson 1 well, one of the first completed which initially produced 1800 bopd, produced an average of 600 bopd over an entire year, but was at a little over 400 bopd rate 1 year out. The wells seem to pop off initially at quite variable rates, ranging from about 700 bopd to 2000+ bopd, but once the initial pressure is off, they all seem to move fairly quickly into a rate of 500-600 bopd, and then the rate of decline is much less rapid after that.

I've been trying to determine what assumption about well life EOG is using for the 750,000 barrels recovery from each 640 acre spacing--as near as I can tell that assumes a well life of about 5 years, possibly 6. EOG is experimenting right now drilling a third well on a 1280 acre spacing from the opposite corner across the Bartelson and Patten sections 1 and 2 of 152-90. If you listened to their request in Bismarck, they aren't really expecting this strategy to increase recovery on the two sections relative to what they are getting from the two existing wells(they think that the oil from the new well simply cuts production from the two older wells on the 640 acre spacing) However, this is an experiment (EOG's words) and there is a possibility that this will become a normal method to increase recovery rates, and a third well running crosswise of the laterals on two of the current 640 acre spacings may turn out to be the norm in the Parshall and Austin fields (those two fields will eventually be one).

The EOG economics are pretty simple: a very average well producing 500 bopd for 6 months generates over a million $ of oil a month at current prices and pretty much covers all their direct drilling costs of 5+ million $. As a capital budgeting project, this number is nothing short of fantastic, and EOG has been saying this over and over again in their reports to shareholders. What is pulled out after the 6 months is over less royalties and the cost of running and maintaining the pump goes straight to EOG's bottom line.

With oil around $90 a bbl, the economic incentive for EOG and others to experiment with new technologies to up the recovery rate on each section is huge. EOG seems pretty confident that there is 9 million bbl of oil under each section in the Parshall/Austin field, and that this first round of wells using the laterals, fracturing etc, is going to bring about 8 % of that to market. But if there is any way to pull more of the total 9 million bbls of oil out, the economic incentive to find that technology given what has already happened is huge. No doubt, 5 years from now EOG and others drilling the field will have further honed their techniques. EOG isn't going to walk away from a field that has been treating them this way from a purely capital budgeting standpoint. The only part of the puzzle I havent quite figured out is why the majors have not already landed. EOG is a big company, in the S&P 500, but small by the standards of a major oil company.

Does anyone have a number to toss out with respect to how much gas a typical well in the Parshall/Austin field might produce once the pipeline is in and the gas gets old rather than flared off? I have been guessing that the value of the gas might be 10-15% of the value of the crude oil produced each month, but this is only an uneducated hunch on my part.

I think the Feb-March date EOG is talking about corresponds to the date that the wells will be connected to the crude pipeline as well. At the moment the number of trucks needed just to haul off the oil from the 22 wells producing 500 bopd has been substantial--things should get a lot simpler with the pipeline in place.

How many barrels do each of those storage tanks hold? There are typically 8 or 9 set up on each well in the field. EOG is confident enough that the wells will come in that they set the tanks just as the wells are being started. [typically 400 bbls for the permanent tanks on location]

Here are some production histories from the Patten and Bartelson wells and projection for the infill well on the 1280.

And an earlier projection of production for the Warberg 1-25H well that indicates an EUR of about 400K bbls.


Another reader, Larry, sent along a graph plotting EOG's drilling permits and active rigs, indicating more rigs are likely to appear in the near future.

Some Austin Well Info, Mountrail Co.

Regarding temporary spacing for their Austin 1-02H well, sec. 2, 154N, 90W, Mountrail Co., EOG indicated that the well last month was averaging 800-some bopd, and that they have been fracing their wells before producing them and are utilizing a liner and swell packers in their completions. They are projecting an EUR (estimated ultimate recovery) of about 750K bbls over the life of the well, and estimated the mid-Bakken’s porosity to be about 7% (pretty good for the Bakken) and attributed about one-half percent porosity to fracturing. They said the reservoir properties are similar to those at the main area of development in Parshall field to the south. The company stated that they expected gas sales from the Parshall field area to begin around February or March of next year.

Speaking of EURs, from recent articles in the media it seems that some people are still claiming that billions of bbls are possibly going to be recovered from the Bakken. Those figures are derived from what seems to be a “let’s pull a number out of the hat” recovery percentage of the 400-some billion bbl estimate of oil in place from Price’s non-peer reviewed Bakken study. Specifically, they are indicating a recovery factor of 1-3 percent of the oil in place, which would result in 4-12 billion bbls of Bakken production.

There is nothing wrong with being optimistic, but is such an estimate realistic? Keep in mind that there will be no EUR from every section of land that is not going to be drilled, which at this point appears to be no small amount in a lot of the relevant counties, and which the estimates quoted in the media appear to totally ignore. Then too it is important to recognize that recovery of a billion bbls would require 2,000 wells that each have a EUR of 500K bbls. Consequently, 8,000 such wells would be needed to meet the lowest estimated EUR of four billion barrels. I invite anybody who is throwing out these estimates to forgo giving unsupportable broad brush estimates that lack specifics and explain where these 8K wells will be drilled, and whether an average EUR of 500K per well is realistic considering that many companies outside of the Parshall area are using EURs of around 300K per 1280 acre unit.

In The News

The Minot Daily News has a fairly good article mainly about the recent BLM lease sale. The only issue I have is including a map of the entire area where the Bakken is present. The only relevant area of the Bakken, however, is where the formation is deep enough so that heat and pressure caused hydrocarbon generation from the shales. Continental has a good map of that area, although pushing into Stark Co. quite so far is a little aggressive in my opinion.

Then the Missoulian has an article that mainly tracks the Wall Street Journal article a few years back about Richard Findley. One glaring error is it's statement that "[i]t was Findley's idea to drill a well sideways - a technique called 'horizontal drilling.'" While Findley may have initiated the use of horizontal drilling in the middle Bakken, the drilling technique was used elsewhere in the world before it was ever used in the Bakken, and in any event, it was utilized in the upper Bakken shale in the late 80s and early 90s in ND. They should have confirmed that with Canadian Hunter Expl., as its now defunk subsidiary, American Hunter, lost about $50 million in that little adventure.

Recent Parshall Completions

Some recently released EOG well completion rates in the Parshall Field area:

Ralph 1-32H, sec 32, 153-89, 1,329 bopd, 53k bbls cummulative from Aug. to Oct.

Florence 1-04H, sec. 4, 152-90, 1,015 bopd, 61k bbls July to Oct.

Geving 1-09H, sec. 9, 152-90, 895 bopd, 39k bbls Aug. to Oct.

Do I Hear $20k An Acre?

Well, it seems that the money from $90 oil has to go somewhere and quite a bit of it, $5.28 million to be precise, went from Sinclair Oil to the federal government at the BLM lease sale today for a 320 acre tract in Mountrail Co. That's a $16,500/acre bonus. This kind of stuff isn't sustainable, if you ask me (and nobody has by the way).

Based on this, I suppose the company is offering private mineral owners, what, about $10K/acre? Actually, probably more a like a couple hundred dollars.

Be sure to see the comments left by Larry and roccojoco for some useful information.

(The article has confusing language so that it may seem like it is referring to a purchase of the mineral rights, but it was a lease and not a purchase).

KTVQ in Billings

and

Minot Daily News (changed from Grand Forks Herald as the link went dead).

What Goes Up . . . .

Findley predicts Montana's Bakken boom is "cooling down" (although I thought Elm Coulee Field production was already in decline for the past year or so).

KTVQ in Billings

Kodiak O&G Picking Up Leases, Dunn Co.

Kodiak O&G from Denver states that it is continuing to pick up leases in Dunn Co., and plans to spud its first well with an unnamed joint partner early next year.

Petro-Hunt's Unconventional Hidden Gem At Charlson

With all the bluster over the exceptional wells in the Parshall area, it's easy to overlook what appears to be the best long-term Bakken producer in the state, the Petro-Hunt LLC USA 2D-3-1H well in Charlson Field about 25 miles west of the Parshall area activity. This well has consistently flowed over 20K bbls/month (presumably still on a choke) since going on line in October of '06 from the fractured Sanish siltstone in the extreme upper portion of the Three Forks Formation just below the lower Bakken Shale. This past Sept. the well again produced 20,666 bbls, 26 mmcfg and only four bbls of water during 30 days of production. Total production since Oct. of '06 has been 270K bbls, 331 mmcfg and 143 bbls of water.

In late July, Petro-Hunt completed an extension in the section to the south, the USA 11B-2-2H, sec. 11, 153N-95W, which appears to be another excellent well. The well had an IP flowing rate of 700 bopd, 850 mcfgd, and no water. From late July through September it produced 44K bbls, 45 mmcfg, and 34 bbls water.

This summer, the company also redrilled a well in sec. 14 after a fish was left in the first hole that was drilled at the same location. During the drilling of the first well, the rig took a pretty good gas kick, but was brought under control. This well has not yet been officially completed. Petro-Hunt is currently drilling an east offset in sec. 12, and the company definitely has a nice little (or maybe big) sweet spot in this area.

Brigham And Whiting Updates, Mountrail Co.

Brigham Exploration has one well currently drilling and is planning to spud two more:










Whiting Pet. knows that the best way to impress investors is to use lots of pictures. Yes!! They are proud of their Perry-State well, and rightfully so.














And a picture from an American O&G well in Wyoming (note it's in WY, not ND) that I'm throwing in just because I like it.

State Lease Sale Results

I doubt if anyone thinks there were any surprises at the state auction today. The top bid, and only one over $1K/acre, went to Northern Oil for 80 acres in sec. 8, 152N, 91W, Mountrail Co., where they paid $2,150/acre. Three other tracts in the same general area went for $500-600, which were the only other tracts available in the county. The area is about six miles west/southwest of current activity in Parshall Field, and Slawson has several wells planned in the immediate area.

Other highlights include Ward Co. with bids generally ranging in the $200-300 range in the overall area of T.152-156, R.85-87. The high bid in the county was $380 and went to Cody Oil.

Acreage in McLean Co, in the overall area of T.148-150, R.87-90, went for about $150-500, with the high bid of $570.

Dunn Co had a number of tracts in the east central part of the county in the general area of T.144-145, R.91-92, that for the most part were in the $350 range. The high bids in the county were for some isolated Missouri River tracts in T.149, R.92, that went for $575/acre.

Boom In The News

The Grand Forks Herald has been running a huge series of articles about the "boom", including one about the mineral owners around Parshall ("A neighbor whose well came in earlier received a check for $570,000, his share after four months of production, Geving said.").
grandforkshearld.com

And the inevitable article about how many billions of bbls are in the ground.
grandforkshearld.com

These links may not work as you may need to register to read the articles, but it's worth it. Just look for a series called "Boom Times."

When An Agreement For A 640 Actually Means It Will Be A 1280

So, say a mineral owner (“MO”) executes a lease with an oil company (“OC”) that restricts the OC’s pooling authority to create a pool of not more than 640 acres, or in other words, restricting the OC to limit any spacing unit involving the lands to not more than 640 acres. Keep in mind that the state regs allow the creation of a 640 acre drilling unit for horizontal wells without any hearing, and any unit larger than 640 is considered an exception unit and requires a hearing. Then, say the OC requests that the NDIC create a 1280 acre drilling unit that includes the lands with the leases having the 640 acre pooling limitation, and the MO, citing the restrictive pooling provision in the lease, objects to the creation of the 1280 at the IC hearing. Oh, whatever shall the IC do in such a situation?

Well, that situation occurred at the IC hearings in September, and the IC said the lease provision was a matter between private parties. It said the proper venue for the dispute was the courts and not the IC, which has limited powers to regulate the orderly development of wells, etc., etc., etc., and not to resolve disputes between private parties. It then created the 1280 acre drilling unit. Now, it is apparently technically true as stated by the IC that the creation of a drilling unit (which was at issue here) does not actually effectuate the pooling of any interests, as that occurs when the IC creates a spacing unit after holding another hearing. But isn’t that like saying that a trespass only occurs after the trespasser chopped down your trees, as only at that later time was the trespass apparent?

As such, wasn’t the IC ignoring the practical effects of its order and the correlative rights of the MO who bargained for the restrictive pooling provision with the OC? In other words, by granting the order, the IC gave authority to the OC to drill a horizontal well across the 1280, and assuming the horizontal wellbore transverses both sections and is commercial, exactly how can a 640 acre spacing unit ever be created at a later time in such a situation? The answer is that it can’t, unless in the unlikely event the OC plugs back the lateral so that it does not extend beyond the hardline boundary for a 640 acre unit that contains the well site (and such a plug back order by the IC would inevitably lead to waste), or the IC deems the east or west halves of the two sections a 640 acre unit in the event the wellbore stays exclusively in the either half. However, I’m unaware that the IC has ever created a 640 acre spacing unit after a well was drilled on a 1280 drilling unit that was created for a single lateral.

Consequently, unless some bizarre series of events later occurred, the granting of the 1280 acre drilling unit effectively created a 1280 spacing unit. Thus, in a practical sense, the only stage in the regulatory process that the lease provision could prevent the creation of a 1280 spacing unit was at the initial hearing for the drilling unit.

So, it seems the only option for the MO after such an order is entered is to obtain an injunction to prevent the drilling of the well until the validity and effect of the lease provision can be determined by the courts. Now it should be noted that neither party may have standing, i.e., an actual “case or controversy,” to have a court hear the issue until after the IC issues an order either granting or denying the request for a 1280. But at bottom, the real and practical issue in this situation is whether the MO or the OC should have the burden of invoking a court’s review.

The IC could have found that the MO had an apparently valid lease provision (obviously an open question, although easily researched) that would be violated if it granted the OC’s request because a well transversing two sections cannot later be made into a 640 acre spacing unit, and accordingly, that it would deny the request because otherwise the correlative rights of the MO would be adversely affected. Then the OC, who is arguably attempting to breach a lease provision, would have the burden of going to court if it still wanted the 1280, instead of the MO having to go to court to rescind it after it already has been created.

My reading of this decision is that the IC is stating that it is the job of the courts to protect the correlative rights of the MO in this situation, rather than the job of the IC, although one of the primary duties of the IC’s O&G Division is to protect the correlative rights of all owners while regulating oil and gas development.

As it stands now, it appears that the MO must present evidence at the drilling unit hearing that the 1280 is not feasible on grounds independent of a contrary lease provision (geologic, economic reasons) in order to possibly prevent the creation of a 1280. In addition, shouldn’t the burden of proof be just a tab bit higher for the party seeking an exception to the rules, i.e., that the requesting party have a little higher burden in overcoming any objections to such a request in order to prevail? After all, there is a reason it is called an exception.

If the MO doesn’t seek an injunction and the well is drilled and later spaced at 1280, what damages does the MO have to prove in court? Well, that would be tricky, as the MO would have to present evidence of some difference in the amount of royalties between a 640 and the 1280. It’s likely that the breach of such a lease provision would be deemed a breach of a covenant and not a condition of the lease, the latter being a basis for terminating the lease, and the former being a basis for only collecting damages that resulted from the breach.

An even tricker situation is presented when there are multiple working interest owners in the proposed unit, and the OC that agreed to the restrictive pooling clause is not the same OC as is requesting the creation of the 1280. Does this “secondary” OC have any duty to abide by, or have its rights limited by, the terms of an agreement to which it wasn’t a party? Too many issues are raised there to be addressed here.

Now, it should be noted that the case last month involved special circumstances. The southern sections in the standup units to be created, which didn’t have the restrictive lease clauses, were entirely under the waters of Lake Sakajawea and over a half mile from shore. The northern sections that had the lease restrictions, however, had some terra firma available. Therefore, the only practical way to reach the offshore sections was to drill a long lateral through the sections that had the lease clause. Although that case involved peculiar circumstances, it doesn’t mean that the IC’s determination would have been any different in a "normal" case, since the legal principles involved are the same.

In any event, the apparent violation of a lease provision should be a factor that the IC considers when determining the size of a drilling or spacing unit, especially when the violation adversely effects a party’s correlative rights. Apparently the IC feels it shouldn’t be a factor.

I have yet to see any persuasive evidence that a single long lateral adequately drains the entire width of a 1280 acre unit. Some companies are saying they need a 1280 for a single well because such a well drains the entire unit, but then say, but hey, if it’s a good well, we will drill another well on the unit. And for some reason the IC buys it. There is only one thing here that we know for sure - - there will be one well on the unit. So therefore, why doesn’t the IC start with the premise that there will be only one well and create a 640, and then a create a second 640 when and if a second well is planned.

I find it especially ironic that the IC doesn’t want to get involved in private lease matters regarding a restrictive pooling clause, and yet everyone knows the unspoken motive for the 1280 requests is so the companies can tie up a lot of leases by drilling a single well. Doesn’t the IC consider it to be getting involved in private lease matters when it creates larger units than necessary and thus allows leases to be held by production when they should otherwise expire if a second well isn’t drilled?

Major Discovery Announced By EOG North Of Parshall Field

EOG released its 3rd Quarter results today and confirmed two high volume wells with IPs around 2K bopd about a dozen miles north of Parshall Field and one in the northern portion of the existing field. Those wells are the two Austin wells in secs 2 and 3, 154N, 90W, and the Wenco well in sec. 30, 153N, 89W, Mountrail Co. It goes without saying that there are a lot of development well locations between these two areas assuming the reservoir is continuous. The company also plans to increase its rig count from six to eight by early next year.

.

Time For A Reality Rant

You know, I get just a little tired of companies trolling for investors and general media reports that keep bringing up the hundreds of billions of barrels that supposedly exist in the Bakken everytime the formation is mentioned. My question to them is "so what?" Instead, why not tell me what percentage of that figure is recoverable, as isn't that what's really important? For the ignorant, these reports make it sounds like all that previously unknown oil is just waiting down there for whomever wants to put a straw into this vast underground pool like Spindletop and then just let it flow. That is hardly the case.

These enormous estimates are generated by calculating the oil in place on a section basis times the areal extent of the Bakken. Most companies are estimating about 3-5 MM bbls/section, which is open to debate, but is certainly reasonable. Now the tricky part comes in calculating what percentage of that amount is recoverable. A ten percent recovery rate would yield between 300-500K bbls/section. This certainly appears to be a reasonable rate in areas of exceptional formation quality, such as in the Parshall area, although the jury is still out as to the long term producibility of those wells. But again, it is certainly not an unreasonable calculation for that area based on the scant production history that exists. In other areas currently being developed with less favorable geology, perhaps half that, or five percent, is a reasonable recovery rate, as 300K is an often used estimate for 1280 acre units. However, in some fringe areas, the recovery rate with current technology is only a fraction of one percent, and a number of those wells will be hard pressed to ever make 100K, or even 50K, even after twenty years of production.

So what's the point here, you may ask. The point is: how much of the Bakken acreage being used to calculate hundreds of billions of bbls has poor geologic factors that has a recovery rate with current technology of less than one percent? My guess is a lot of it. Consequently, the hundreds of billions suddenly become hundreds of millions in relevant terms. Marathon and EOG both guess that they have recoverable reserves of roughly 100 MM bbls on their acreage. New technology in the next ten years could double or triple that, who knows. Now, is a couple hundred million bbls that nobody thought could be produced five years ago something to take lightly? Of course not. It's the equivalent of finding new Billings Nose, Little Knife, and MonDak Fields. It is hardly hundreds of billions of bbls though.

So if anybody tells me they think there are 800 trillion bbls down there, I really don't care. Tell me how many of those bbls you can economically put in a tank, then I'll care.

UPDATE 10/29: In today's Bismarck Tribune, while speaking at an energy expo in Bismarck, a Sr. VP for Marathon stated that the middle Bakken is a "'marginal play,' one that requires the company to move quickly from one well to the next with fewer people." Yeah, but the economics have changed rapidly what with the current hundred dollar oil. Now, 100K of recoverable reserves can gross ten million dollars in future revenue, as opposed to half that with fifty dollar oil. Marathon's original economic model was based on forty to fifty dollar oil. But I don't think anyone wants to make any hedges on what the price will be a year from now, as with a world recession, it could be thirty or less.

Rig Count Keeps Climbing

With the state rig count having risen to 55, that is the highest number in over two decades. All except maybe a dozen of those (including a rank test way over east in Wells Co.) are exploiting the Bakken. Mountrail Co. currently has fifteen of those rigs and EOG remains very active in that county with six rigs, and Hess, Whiting, and Hunt each adding a few each. A dozen rigs are in Dunn Co., with Marathon utilizing six of those and Continental and Burlington using another four. In fact, there recently was an article about H & P's new flex rigs being used by Marathon. bismarcktribune.com

In a related note, EOG is requesting its first 1280 acre unit within Parshall Field that is to encompass secs. 2 and 3, 152N, 90W, in Mountrail Co. There already are existing producers in each of these sections on 640 acre spacing, the Patten and Bartelson wells, which have produced 68K and 112K, respectively, through this past August.

Some Recent Parshall Completions

EOG has completed the Hoff 1-10H, sec. 10, 152N, 90W, in Mountrail Co. for 1,678 bbls/day and a little over a half million cfg/day. This well has produced 66K bbls from June through August of this year. The company also completed the N&D 1-05H in sec. 5 of the same township for 1,285 bbls and 404 mcfg/day. The well made just over 53K for the two months of July and August. Total field production up to and including August from wells off confidential status is just over 800K bbls.

Also, of interest, an article about leasing in western Ward County:

bismarcktribune.com

The Low Murmur Of Excitement Begins To Build

It appears that people are beginning to realize that this thing is going to a significant event, at least in some select areas of the state.

“It’s just incredible what’s going on there (in Mountrail) and Dunn County,” Ness said.

minotdailynews.com/news/articles.asp?articleID=15091

And the boom in gas processing plants in the state:

money.cnn.com/news/newsfeeds/articles/apwire/D8RRSML00.htm

Marathon Attempting The Double Frac, Dunn Co.

During a recent presentation, Marathon indicated (what I have suspected for some time) that they are planning to simultaneously fracture the laterals on the experimental two-well units that they recently received permission to establish. (see 7/16 post). This procedure, whereby both laterals are fraced at the same time to more effectively "bust up" the formation, especially in the area between the two laterals, reportedly has had some impressive success in the Barnett Shale in TX. In my opinion, this procedure has the potential to significantly transform this play, and may be the most useful technique in the Bakken since the advent of horizontal drilling itself. MOC is currently drilling on the Beck lease in Bailey Field in Dunn Co., where they presumably are going to utilize this procedure. Let's hope it's a smashing success (pun intended).

The company also had a few slides with general information that touted their efficiencies, and of interest, their determination that about two-thirds of their acreage appears to be drillable.






And a recent pic of their new office/shop complex just north of Dickinson.

Whiting Putting The Feet To The Hole, Mountrail Co.

Last spring, Whiting O&G drilled a combined 21,214 ft. of hole in three laterals extending from a single vertical wellbore at its Perry State 11-25H in sec. 25, T.153, R.92, Mountrail Co. This should cast away any doubt that the company is doing its best to effectively drain this laydown 1280 acre unit. The well was completed for 1,081 bbls/day last May and has produced about 57K bbls up to and including July. In July, it produced about 14K bbls. The company last week spudded what is presumed to be another tri-lateral well about three miles to the east at the Liffrig 11-27H, sec 27, 153N, 91W. This activity is about six miles west of activity in Parshall Field.

Over at Parshall Field, EOG has completed the Zacker 1-24H, sec 24, 153N, 90W, in June for 870 bbls/day. During June and July the well produced a total of around 50K bbls.

Marathon Prevails At August Hearings. . . Sort Of

The NDIC has issued its order regarding the August hearing when Marathon and Hunt sparred over the creation of 1280 drilling units near Bailey Field in Dunn Co where Hunt held an interest in some of the units. In its Order the IC brought those lands within Bailey Field and created 1280 acre spacing units in all the units where Hunt had an interest and had requested 640 acre units.

However, in the one unit where Hunt held 50% interest in the 1280, the IC will not allow a drilling permit to be issued for that unit until March 31, 2008, to allow Hunt to test its techniques in the vicinity and determine if they are viable.

I'll let the exhibits speak for themselves. One comment about the Marathon depletion model exhibits though, as the results from simulation models are only as good as the inputs used in them. I would want to know how many times this model was run to get this result and how many variations of inputs where used in the process. In other words, was data based on reality used as inputs, or was the model run numerous times with a variety of different input values (not necessarily based on reality) until some possible predetermined result was achieved?

In any event, the one lateral put on the west side of the unit does not appear to be draining enough from the east side to justify the inclusion of those lands, in my opinion. These should be separate 640 acre units consisting of the east and west halves of the two sections. The eastern half should not be part of that unit, and if the lessees want to tie up the leases for 25 years on that east 640, they should have to drill on it.

Marathon's exhibits regarding 25 year depletion depicting the lateral: (1) in the center of the 1280; (2) 1320 ft. from the western unit boundary; (3) two laterals in the 1280; and (4) three laterals in the 1280. Without getting ridiculously technical on the pressure depletion aspects, let's just say that red is the original formation pressure and the darker the blue, the lower the formation pressure (indicating depletion).



Marathon also presented a number of exhibits depicting the expected production from each configuration and actual production for a number of wells, including those from Parshall Field, along with the economics for each well configuration scenario.




Hunt presented a number of exhibits trying to project the success in the Parshall area to the Bailey area by suggesting that the thickness of the middle Bakken was almost the same in both areas, and therefore, suggested that completion techniques were the driving force in the success at Parshall. As was pointed out, however, the formation thickness really has no significant relevance regarding the success of a well. The only relevant analysis as to whether a completion technique is controlling rather than lateral length or formation quality is initial production rates and the percentage increase in production that occurs after the frac job. If the production in Hunt's wells increases 100% and Marathon's increases only 50%, then that is some pretty good evidence that Hunt has a better completion technique.

Of interest, Hunt is calculating recoverable reserves of 350K bbls. on a single lateral in a 640 acre unit, whereas Marathon projects 333K bbls from two laterals on a 1280 acre unit (under their middle k.h analysis scenario -- k.h is essentially how easily fluids migrate to the well bore). Who is correct here???

The first exhibit shows Hunt's stage frac technique.

Another Major Player To Join Bakken Hunt In Dunn Co.

New player Newfield Expl. from Houston is planning at least two wells near Lost Bridge Field in northern Dunn Co. The company has requested that two drilling and/or spacing units be created in T.148, R.96, which is close to the southern extent of the Nesson Anticline, and north of the area currently being aggressively developed by Burlington and Continental Res. Hopefully, Newfield will be encouraged by the results from its initial wells in the play and drill many, many more.

UPDATE: Newfield had requested that its application for the September hearings be dismissed, but has reapplied for four 1280s at the October hearings, instead of the two stated above.

Dunn Co. remains the most active county in the play with twelve rigs making hole out of the 44 active rigs in the state. Williams and Mountrail Counties are tied in second place with eight rigs each. Based on the current level of activity, it appears within the realm of possibility that the southern part of Mountrail Co, the northern half of Dunn Co., and the Nesson Anticline will be almost completely drilled out in the next few years, assuming that the economics remain favorable.

More Major Development Planned For Mountrail Co.

Both Murex and Whiting have disclosed big drilling plans spanning from Sanish Field to Stanley Field in central Mountrail Co. Last month Murex applied for seventeen 1280 drilling units south and west of Stanley Field and at this month's hearings, Whiting has a current application for over twenty 1280 acre drilling and/or spacing units in the vicinity of Sanish Field. All this activity encompasses the overall area of T.152-155, R.91-93, which, at its closest point, is about six miles west and northwest of EOG's main activity in Parshall Field.

September Showdown At The NDIC Corral On Tap

In what should be the most spirited hearing since, well, last month, Marathon is attempting to flex its muscle with Encore at the upcoming September hearing regarding the Murphy Creek field area in central Dunn Co. As indicated in my recent post about well density, Marathon had requested that this field's boundaries be expanded and asked that about eighteen 1280 acre spacing units be created. Marathon had previously received permission to create three 1280 acre drilling units in secs. 4 and 9 and 5 and 8, T144, R96 and secs. 27 and 34, T145, R. 96. The company has just finished drilling the well on secs. 5 and 8, and has just spudded the well on secs. 4 and 9.

Encore as predecessor to Kerr McGee had been developing the field on 640 acre units, and is currently drilling a 640 acre unit in sec. 1, T144, R96. After Marathon applied for the 1280s last month, Encore suddenly applied for and received about a half dozen drilling permits for 640 acre units. At the hearing last month, Marathon stated that they reached agreement with Encore that Encore would develop about half the requested sections on 640 acre units, and Marathon would drop those sections from its request.

Well, that agreement must not have suited someone, because Marathon is now requesting that most of the lands that it dropped from its original request last month in favor of Encore be once again be made into 1280 spacing units, or drilling units in the alternative. It should be noted that in a number of these proposed 1280s, Encore appears to have half interest in the unit. What should be the most contentious portion of this hearing is Marathon's separate and related request that most of the drilling permits Encore received (and has not yet drilled) be suspended and/or revoked. Like I said before, its time for the IC to issue some uniform guidelines as to this density issue, especially when it pertains to the same field, and where some development has already occurred on 640 acre units, which are legal units created with only the granting of a drilling permit.

In a related development, the activity in this area appears to be headed west as Tracker Res. has applied for a 1280 acre drilling unit a few miles to the west on the eastern edge of Little Knife Field in secs. 4 and 9, T144, R97. Tracker is currently drilling a rank wildcat about 20 miles to the east in secs. 1 and 12, T.144, R.94.

Map Legend:

red/orange: Marathon's new 1280 acre requested units
blue/light green: Marathon's 1280 acre units requested last month after dropping Encore's acreage
gray: Marathon's established 1280 acre drilling units
dark green: Tracker's new 1280 acre drilling unit request
yellow: mostly Encore's 640 acre units (in the center of the field area) already drilled

Some Interesting Analysis

The savant over at Open Choke recently made some observations regarding in which oil or gas play he would invest $50M. He does a pretty good job in detailing a perfect world scenario.

openchoke.blogs.com/open_choke/2007/08/texas-waters-or.html#comments

Let's Test That Seismic Anomaly, Shall We? Mountrail Co.

Robert Griffon and his partners are currently re-entering a dry hole to drill a lateral that transverses a "bright spot" or an area that 3D seismic indicates has an anomaly in the fracturing properties of the Bakken. This well, being developed on a 320 acre drilling unit in the southeast quarter of sec 23 and northeast quarter of sec.26, T.151, R.89, is about six or seven miles southeast of EOG's current development in Parshall Field. Griffon thinks that the brighter areas as depicted on the seismic data indicate a higher level of fracturing or porosity than the darker areas. We shall see how well this interpretation works out for them.

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.

Permits By The Dozen In Dunn Co.

During the past week or so, over a dozen drilling permits were issued to primarily Marathon and Encore, and one to Tracker Res., and most within a few miles of the town of Killdeer in central Dunn Co. Just southwest of Killdeer in Murphy Creek Field, Encore and Marathon have reached some sort of agreement whereby Encore is going to develop an number of sections on 640 acre spacing and Marathon will develop its portion of the field on 1280 spacing.

It appears that the time may have to come pretty soon for the state to set some sort of uniform spacing for these Bakken wells instead of leaving it up to the individual companies, which often leads to a hodge-podge of different sized units in the same field. Some companies like Marathon are beginning to place their lateral to one side of the unit which would allow another lateral on the other side of the unit, in the event a second lateral will be economic to drill. Meanwhile, other companies are drilling a lateral through the center of a 640 or 1280 acre unit, which does not allow for infill drilling within that unit. Me thinks its time for some uniform spacing rules.

Then there is this puzzle with the apparent shortage of drilling rigs, why the two rigs that Ansbro had been utilizing in its drilling program (both Nabors rigs, I believe) have been stacked out in Willmen Field since May or June. It appears that Ansbro has temporarily suspended or permanently canceled its drilling program, but that doesn't explain why these rigs aren't being used by another company. If anybody out there knows, let me know. Some rumors are going around that Ansbro and Continental may be joining forces in some manner regarding the development of the hundreds of thousands of acres that Ansbro has under lease primarily in southwestern Dunn Co. In certain areas, Continental is actively leasing whatever acreage Ansbro for whatever reason didn't get.

Burlington Hits The Magic 1K/Day Initial Rate, Dunn Co.

Burlington Res., aka Conoco/Phillips, along with its partner in the area, Continental Res., has completed its State-Weydhal 44-36H well on 1280 acres in secs. 36, T147, R97 and 1, T146, R96, Dunn Co. for 1082 bbls/day. The well is located about nine miles NW of Killdeer on the west side of Highway 22. It has produced almost 28k bbls in three months ending in June. This area is one of the more active areas in the state with five combined rigs drilling in the Oakdale area and to the east in Baily Field.

Continental announced that they may add an additional rig to the play next month. The company also announced completion rates of the other wells in the area, the Veeder and Brown well at 344 and 519 bbls/day, respectively.