Monday, May 12, 2008

Marathon Attempting To Drain The Lake

In the last edition of The Rocky Mountain Oil Journal, it was noted that Marathon has moved one of its H&P rigs to the Big Lake in attempt to establish Bakken production thereunder. This Marathon activity is apparently unrelated to the breaking story on Fox News regarding the bonanza that awaits them.

Marathon Oil Drilling Under Lake Sakakawea-McKenzie County North Dakota

Marathon Oil has spud in their second horizontal Bakken test in McKenzie County North Dakota. The company has moved in Helmrich & Payne rig #256 and is making hole at the Myrmidon #1-2H ne-ne 2-151n-94w. Bottom hole location for this test will be the sw-sw 11-151n-94w. Of interest, this will be the first North Dakota horizontal Bakken test that will attempt to establish production beneath Lake Sakakawea, the third largest man-made lake in the United States, after Lake Mead and Lake Powell. This reservoir has a length of about 178 miles and contains roughly 1,320 miles of shoreline.

Originally the Myrmidon #1-2H prospect was generated by Black Rock Resources (BRR), a consortium of several companies including Savant Oil and Gas, Castle Rock Resources, Kirkwood Oil and Gas, and several individuals. The acreage that Marathon is drilling on is part of a 100,000 acre lease block that BRR sold to Marathon Oil for a reported $43 million. Prior to this sale, BRR had asked and received permission to create a 1,280 acre spacing drilling unit that included all of section 2 and 11 of 151n-94w. In supporting the request for the creation of this horizontal Bakken drilling unit before the Industrial Commission, the following reservoir and economic data was presented at the hearing:

Bakken Reservoir and Recovery Data

Reservoir Type Middle Bakken Silty Dolomite

Spacing 1280 acres

Stimulation Type Gelled Water/Sand Frac

Reservoir Thickness 38 ft

Porosity 9%

Water Saturation 25%

Oil Gravity 42 degrees API

GOR 800 scf/stb

Oil Formation Volume Factor 1.5 Res. BBL/STBO

OOIP 16,981,000 bbls

EUR 800,000 BBLS

Recovery Factor 5.5%

Well Economics

Capital Cost $6,000,000

Expected IP: 650 BOPD

Ultimate Recovery 800,000 BBLS Oil

960,000 Mcf Gas

Royalty Burden 20%

Operating Cost $6,000 per month

Prices $60/bbl Constant Oil Price

$6.50/MMbtu Constant Gas Price

Economic Projections

Future Net Revenue $4,590,000

Operating Costs $2,041,000

Production Taxes $5,048,000

Rate of Return >100%

Undiscounted Return on Investment 6.5

Bear in mind, that when BBR presented this data to the Industrial Commission, the company used a constant oil price of $60 per barrel. Current Williston Basin sweet is now selling for $112.75 per barrel.

Nearest Bakken penetration to the Myrmidon #1-2H is about a mile to the northwest at a field well within Antelope Field, a multi-pay oil pool. Originally drilled by Comdisco Operating and now controlled by Chesapeake Operating, the Gudbranson #1 nw-se 34-152n-34w was completed pumping 192 bopd and 96 mcfgpd from the vertical Sanish section 10,650’-10,660’. Since first being put on production in the latter part of 1990, this well has cumulated over 91,349 bo, 88.5 mcfg and 3,467 bw. Antelope Field itself is a southeast plunging anticline and was discovered in 1953. Producing from the Devonian, Madison, Red River, Sanish, Silurian and Winnipeg/Deadwood, this field has produced over 41.3 mmbo, 61.6 bcfg and 46.4 mmbw.

As mentioned, the Myrmidon #1-2H is the second Bakken test drilled by Marathon Oil in McKenzie County. The first sideways test drilled by the company scales about 36 miles southwest at the Dolezal #24-24H se-sw 24-146n-99w. Completed in November of 2006, this single lateral Bakken producer was given an IP of 82 bopd, 68 mcfgpd and 103 bwpd. Incorporated into Ranch Creek Field, the Dolezal #24-24H has produced over 29.3 k bo and 33 mmcfg. Ranch Creek Field is a Bakken oil pool discovered by PDC Corporation at the Carmona #31-1H ne-nw 1-146n-99w. Marathon Oil has now assumed operatorship of this discovery well.

Content courtesy of The Rocky Mountain Oil Journal


Anonymous said...

After the rig is removed, and a pump is placed on the well head, is there a limit to how much oil could be pumped in a day?

Anonymous said...

Geology anf fracturing dictates the maximum, but obviously below that any amount smaller than that can be pumped in a day. Apparently there is a tradeoff between well life and pressing a well to pump too much too fast. Each well has an optimal pump rate, a rate that may vary over time as the well gets older, that maximizes the amount of oil obtained from the well over the longest possible period of time, and the operators attempt to identify this unique pump rate for every well. OIl left in the well in time t may very well be worth more money if pumping is delayed to time t+1

Anonymous said...

These numbers interest me a lot, in part because I do benefit/cost and project analysis at work, and they fill in some holes with respect to costs I was wondering about--for example an estimated cost of running a well of $6000 a month once the pump is in place. $100 oil suggests they need a well to pump 60 bbl a month (2 bbl a day) to justify running the pump.
But also, these numbers are interesting in that they are very similar to the numbers EOG started giving analysts in conference calls last fall, and at that point in time there was mostly shock and disbelief.
The 800,000 bbl EUR number as I understand it is the expected bbl of oil that will be pumped over the life of the well. The companies seem reluctant to toss out the well life number they are using, but my hunch is that they are probably at 10-12 years, or an average somewhere in the 70-80,000 bbl a year range average over the well life. To me this average annual number seema a little high over that long a period, but we now have both EOG and Marathon tossing out almost the same number, and these guys are well paid to do reliable guesses on such matters.
OK, let's use their number. Our guess is what price should we assume for light sweet ND crude average over the next 10-12 years. Lacking a better number, how about $120 a bbl? Remember we are not asking what crude sold for in the past. Rather, we want a reasonable guess as to what it might sell for average over the next 10-12 years. I like this number because then a well with an 800,000 bbl EUR produces just under a billion $ worth of oil over its life (Amazing!), this under 1280 acres. Conveniently, leases are typically for 12.5 to 15 % of the gross wellhead value, so basically the lease will pay at least 12.5 million $ over the EUR. Conveniently, the Marathon spacing is 1280 acres, which means that a mineral acre with this single well is worth almost exactly $10,000 total over the life of the well! The royalty owners have to subtract the oil and gas and oil extraction taxes plus pay state and federal income tax on this gross amount, this for the well Marathon created with these company estimates they use for planning and capital budgeting purposes.

Marathon assumes that once this well is pumped out, the billion $ worth of oil they pumped represents 5.5 % of the oil that is actually under the spacing, leaving 94.5 % to be recovered incrementally by new holes and drilling technologies.

EOG's Parshall field numbers differ slightly from the Marathon field. EOG is basically at 750,000-800,000 bbl EUR on a 640 not 1280 acre spacing, and are claiming that this represents about 9 % not 5 % of the oil actually under the surface. A 640 acre spacing means that the gross royalty payment over the life of the well could raise the gross royalty payment per mineral acre to $20,000 not $10,000 over the life of the well, but ultimately leaves less in the ground (only 91% of the total) to be potentiually recoverable with new technologies and future wells.
But basically EOG and Marathon are saying the same thing except for differences that could be tied to the geology underlying Dunn vs Mountrail county. Marathon has yet to get any wells to hit 3,000 bopl ip in Dunn as EOG has in Mountrail. The Marathon number is 650 bopd ip in Dunn whereas EOG probably would use 1,000 bopd ip on average in Mountrail.

For those who are still skeptics, and point out to the Williston oil bust in support of their skepticism, I don't see either company walking away from any of this any time soon. The numbers are just too strong, and once the initial group of wells start to taper off in production, they will likely be right back out in the field with the next- generation technology trying to extract some of that remaining 90% of the oil still in the ground that they didn't get in the first round of drilling. For better or worse, both Mountrail and Dunn counties had better get used to having the oil people around. Crude prices have a unique way of stimulating all of this, but reading between the lines, Marathon is telling you they would still be out there drilling if crude were only $60 a bbl. I suppose we can envision a world in which crude drops to $25 a bbl and these companies say that what they are doing no longer makes real economic sense, but somehow I think that a world with $25 is a fantasy world. In my distant memory I can recall filling my car with gas that cost 27 cents a gallon, too! EOG stock has gone up over 50% since the EOG exectutives presented their similar numbers last winter to analysts (who were mostly sitting in stark disbelief) so even the skeptics are now believers.

Anonymous said...

Thanks for the comments. I have one question. Is Marathon assuming they will ultimately recover 800,000 barrels from one horizontal well?

It seems to me they will have to drill several horizontal wells in the 1,280 acre spacing unit to recover the 800,000 barrels. Thus, their capital costs over the life of the spacing unit would be more than the $6 million for the initial well.

Anonymous said...

The data are for a single well. If they were going to do something different in terms of well numbers to get the 800,000 bbl EUR, the data would have to reflect that by doubling the drilling cost for the calculation. But they say 6 mill which is approximately the cost of a single vertical well with a 2-mile long lateral.

Anonymous said...

Nick H said...


I think you need to recheck your math. $800,0000 * $120/bbl. = $96,000,000. While that is still a very large number, it is nowhere near $1 billion.


Anonymous said...

you are right. I missed a zero and the number should be just under $100,000,000

The calculations on total royalty payments over the life of the well are correct, however, with a gross amount of 12 to 15 million $ going to the mineral interest owners, before taxes, depending on a 1/8 vs 1/7 or 1/6 lease.
Rats, there is only 100 million dollars worth of oil under each spacing, not a billion $ worth!

Anonymous said...


I just remembered where I got the billion $ number from. EOG was saying 800,000 bbls represents 9 % of the total oil under the 640 acre spacing. 96 million $ divided by .09 (the % of oil recoverable with the first well on the spacing) equals approximately 1 billion dollars give or take a few million. So there is about a billion $ worth of oil under each spacing, maybe more if the Marathon number gets 800,000 bbl at a 5% first well recovery rate.

Anonymous said...

My, my, my-I'm really glad Mom was able to save those mineral acres!!

Anonymous said...

Fill me in on Natural Gas, its sale and so fouth ??

Anonymous said...

Can we get a recent IP decline chart ?

Anonymous said...

david said "$billion worth of oil under a 640 ac unit"

great david! and there is probably a billion $billion worth of coal,rock,sand, granite, iron and nickel (and dont forget water) under a section of land. the problem is extracting it economically.

Anonymous said...

..."the problem is extracting it economically." Profound.

(ROI's of 13X @ $120/BBL is not what I would call a problem)...

Anonymous said...

And note that return is with a 1/5, or 20% royalty.

Anonymous said...

Most people dont have a Sections worth of minerals, probaly more like a Quarters worth or less, and that does add up alittle, but nothing compared to what the Big Boys will make.

Anonymous said...

Have a look at Whitings May Corporate Presentation page 22 it shows a great cross-section of the Bakken formation and it appears that Parshall and Sanish fields are at the eastern end of the production zone. I for one thought it went further east. With this knowledge does it explain the higher production from Parshall or is it that theres better fracing, as no middle member is there and the upper and lower members are one. Anyone???

Anonymous said...

Sorry let me clarify. By better fracing I ment companies doing a better job and is the lack of middle member better. I am not sure if oil is present in all three members or not. Again Anyone???

Anonymous said...

The theoretical cross section diagram you are referring to depends in reality on when/where the cross section is "cut." (It wasn't all that long ago that dry holes in this area had people thinking there was nothing there).

There is definitely plenty of middle member in Parshall and Sanish fields, and some good fractures to boot.

Anonymous said...

In studying various maps traveling along ND 23, heading west toward Parshall, I am left with the impression that the Parshall field comes to a pretty abrupt end at approximately where the old Model Township Hall sits along the north side of the road, a mile or so east of the Parshall corner going down ND 37. It could possibly go a mile or so further east in spots, but that appears to be about it.

Traveling north and south within the field is a little different. Focus late last fall was on the northern edge of the field going into Austin Township, but this spring suddenly there is a lot of interest in the sections on the south edge of Parshall township (a lot of drilling will happen there this summer and fall it appears), extending all the way into northern Fertile township, where EOG is currently drilling a "test" well.

Meanwhile, the area that is starting to look really interesting for upcoming EOG drilling on the north side is the row of sections that straddles Wayzette and Austin townships with pairs of wells in adjoining sections across the road all along the boundary between the two.
These roads in north Wayzetta and South Parshall townships will be fun to see with all the wells paired on either side close to the road and the pairs of pumps spaced about a mile apart in the E-W direction. Drilling of the first wells is underway now, and this summer should be most interesting as these areas are developed. I will no doubt have more to report after I get back from my visit over the next two weeks.

Anonymous said...

I take Julie LeFever's word on which member the Bakken oil is mostly found. The three keys to the Parshall field success involve the lateral drilling and the fracing, but as Julie LeFever points out, recognizing that the middle member is the filling part of the sandwich (Oreo cookie) that should be targeted for the horizontal drilling and fracing was the third key element.

Study her presentation at,1,Horizontal Drilling Potential of the Middle Member Bakken Formation, North Dakota
and you will see that she is very much a student of Price. Price had a lot of this figured out when he died, but few would believe him--nor was he able to hee his ideas tested.

The middle member is not very thick, and as a consequence, simple vertical wells almost never were very productive. It took the combination of the three strategies--horizontal drilling, fracing and targeting the middle member to see the real payoff. But the oil is there. It always has been in gigantic multi-township areas in places.

Anonymous said...

Continental identifying multiple pay zones in Dunn Country: