Sometimes It's In The Very Fine Print -- Downspacing In The Bakken -- August 18, 2016

I'm going over the most recent Mike Filloon contribution to SeekingAlpha again. I don't think he mentioned this in his narrative, and I don't think I've seen it elsewhere. Here's the graphic. See if you can spot something fairly significant.

The graphic is from Goldman Sachs Global Investment Research, undated. Besides the obvious multiple formations that are highlighted, note the second bullet:

Middle Bakken and Three Forks-1 zones have been largely derisked. Confidence in downspacing from 320-acre well spacing is key catalyst for more resource credit for the play.

That one line could be interpreted a number of ways. But I think it's pretty clear, based on "downspacing from 320-acre well spacing," that analysts have already factored in 320-acre spacing for the middle Bakken and the first bench of the Three Forks.

I think regular readers of the blog have felt we've "always been there" -- at 320-acre spacing for both the middle Bakken and the first bench. I assume the analysts mean two middle Bakken wells/section and two TF-1 wells/section or eight wells per the standard 1280-acre spacing unit in the Bakken. If so, yes, we've been there for quite some time. (In fact, I already have a tag, "320_Acre_Spacing." See tags associated with this post for similar tags and similar posts.)

The analyst's do not specify "good" Bakken from "better" or "best" Bakken. This seems to imply an average across the basin. In some areas we are well beyond 8 wells in one standard 1280-acre drilling unit. In fact, if we can drill along section lines (in an overlapping 2560-acre unit, for example), the better and the best Bakken should easily be able to support six MB and six TF-1 wells in a 1280-acre unit. With 660-ft spacing, it's more than that.

Just idle chatter. Don't quote me on this. Keep it a secret.

At FAQs, question #2 (FAQs are not always updated; FAQs have opinions and facts are interspersed and I don't necessarily point that out):

2. How many wells will "they" drill in a section? How many wells in all in the North Dakota Bakken? It is estimated that up to 50,000 wells will be needed for the Bakken Pool. -- current as of May, 2013. The number of wells per section continues to increase. Goldman Sachs has a graphic, 2016, suggesting 320-acre downspacing is the norm in MB and TF-1. Back in August, 2012, the NDIC dockets suggest there would be up to 16 wells in a 1280-acre spacing unit in the "core" Bakken. In the June, 2013, dockets, the "norm" for 1280-acre spacing units seems to be increasing to 10 wells but CLR is moving toward 17, 24, or more wells per spacing units. In late 2013, CLR had pilot projects for 34 wells in a drilling unit of 1280 acres (two sections). And:

In a January, 2013, presentation, the Director, NDIC, suggested that it may take as many as 48 wells/spacing unit to drill out some areas of the best Bakken. At the time he said that, most spacing units were two sections. Therefore, Lynn Helms was suggesting as many as 24 wells/section in the best part of the Bakken which includes productive formations from the middle Bakken through ALL lower benches of the Three Forks.

Monday, October 5, 2015 -- Part IV; Was It The Volkswagen Janitorial Staff?

Memo to self: come back to this one later. This is interesting This well was taken off-line while EOG "executed a downspacing and infill drilling program." The well was placed on inactive status, and I had expected such a good well to come back on-line when the other neighboring wells were completed. But I see now that the well is on AB (abandoned) status:

• 17011, AB/1,663, EOG, Parshall 4-20H, t7/08; cum 415K 6/14; IA as of 5/14; shut in while EOG executes a downspacing and infill drilling program; dated August 19, 2014;

No sundry form with explanation. The sundry form dated August 19, 2014, does foreshadow possible explanations.

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Blame It On The Boss

Volkswagen wouldn't be first company to go belly up. Enron did. GM almost did; their financial "arm" relabeled. But top exec says Volkswagen's emissions scandal could kill the company.

The crisis, which has wiped out $34 billion in the company's value as shares have fallen, stems from the disclosure by the U.S. Environmental Protection Agency last month that VW had rigged nearly 5 million diesel cars in the U.S. to pass emissions tests even though they spewed far greater emissions on the highway.

VW admitted to the fraud and said 11 million vehicles are affected worldwide.
The New York Times reported Sunday that the cheating began in 2008 after Volkswagen's engineers figured out that the new diesel engines they had developed at great expense would not meet emissions standards in the U.S. and other countries. So they installed software to beat the tests, the Times reported based on unnamed sources with knowledge of the inquiry.

The cheating resulted from not wanting scrap the years of effort they had put into developing the engine. The report says VW is yet to pinpoint who was responsible for the cheating. Several engineers have admitted to creating the software aimed at cheating the tests.

The software may have been contained in parts from a big auto industry supplier, Continental. But a Continental spokesman denied that the company knew of any contaminated software and wasn't in a position to measure emissions.

Blame it on the boss:

Blame It On The Bossa Nova, Eydie Gorme     Later: we now "know" that this was not the work of the top three engineers at Volkswagen. 

Let the jokes begin: Well if the boss (CEO) didn't know about it, and three top engineers didn't know about it, it pretty much means the janitorial staff was responsible.

EOG SOP For Shutting In Neighboring Wells When Fracking New Wells -- June 13, 2015

EOG has a long note on a sundry form regarding its "downspacing and infill drilling program" in the file report for this well, explaining an SOP for shutting in neighboring wells when fracking new wells:

• 16532, 1,285, EOG, N&D 1-05H, Parshall, t7/07; cum 457K 4/15;

The sundry form was dated August 14, 2014.

The NDIC GIS map server appears to be off-line at the moment. When it is back up, if I remember, I will post a screenshot of the activity around this particular well.

CLR Has A New Presentation -- August 6, 2014

CLR has a new presentation.

Data points:

• 2Q14 Bakken production: 108,573 boe
• completed industry's first full-field development in prolific Antelope area (MB, TF1, TF2, and TF3)
• successfully completed three 1,320-foot density pilots since beginning density pilot program: Hawkinson, Rollefstad, and Tangsrud
• completed the first 660-foot density pilot at the Wahpeton unit
• three additional planned 660-foot density pilots to be completed: Lawrence, Mack, and Hartman
• average completed well costs: $8.0 million (FY13 target) met; fiscal year 2014 target: $7.5 million
• CLR continues to model the 603K EUR well as the average
• better EURs projected with slick water completions
• Madison 2-28H: after 29 days, 35% higher than 603K; 50% higher than neighboring wells
•  Sacramento 2-10H: after 192 days, 50% higher than 603K; 60% higher than average of neighboring wells
• both the Madison and the Sacramento wells are located in Williams County, east of Williston
•  the graph at slide 9 (Sacramento, Madison wells) is quite stunning
• large proppant volume & slick water providing better completions
•  large proppant volume, 3 test wells: 39% higher than 603K average; 30% higher than neighboring wells
•  slick water, 3 test wells: 35% higher than 603K average; 25% higher than average of neigboring wells

• incremental cost of enhanced completion designs estimated at $1.5 to 2 million
• Rest of presentation relates to the SCOOP

Long term: has CLR moved average Bakken/Three Forks well from 603K to 815K EUR (low end)? (using new completion techniques)

Random Data Point From EOG's 1Q14 Earnings Conference Call

From EOG's 1Q14 Earnings Conference Call 

In the Eagle Ford:

In modeling production from the Eagle Ford we are on a growth track for the next 10 years; and, I want to repeat: in modeling production from the Eagle Ford, we are on a growth track for the next 10 years before we even begin to see production level out.

So, what about the Bakken? What is EOG's modeling for the Bakken?

In the question and answer period:

Analyst: I liked your comments on your 10 years of growth in the Eagle Ford. Given that you model back, can you about how many years of growth do you see in the Bakken?

Bill Thomas: We have not done that extensive model in the Bakken yet, because we’re really in the initial stages of downspacing, and I want to ask Billy Helms to make some comments on that.

Billy Helms: For our Bakken as we illustrated, we’re still very satisfied, very pleased with our 1,300 foot spacing test. But we realized that our NPV, net present value, was not maximized. So, we’re going to be doing lots of additional testing, we did talk about 700 foot spacing pattern and we’ll be testing some various spacing patterns as we try to define how to maximize net present value. 

This is a similar approach as we've done in most of our shale plays across the company. and until we really find out what that formula looks like, we're really kind of hesitant to state what the upside not be there, but certainly we will provide some more effort on that as we go forward the year, and we're very confident that we're going to have success there.

 I think, if I recall correctly, a reader told me that EOG took lessons learned in the Eagle Ford back to the Bakken, and are already seeing better results with new completion techniques. This short interchange tends to confirm that.

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Downspacing: Relationship Effects Of Neighboring Wells

In that same conference call, this exchange:

David Heikkinen - Heikkinen Energy Advisors: On the maximizing NPV, one of the things we've talked a lot about is your IRR doesn't change much, but your EUR may decline per well as NPV goes up. Is that a fair characterization of how your downspacing could actually roll forward?

Bill Thomas: Yes, that's correct. Naturally, as you push wells closer together, you're going to end up having some sharing between wells. That's just inevitable. Our rate of return is still very, very high as you stated, but what we end up doing is adding a lot more recoverable reserves, and there is a lot more net present value to each spacing unit that we drill. So, that's kind of our overall process. And we're still early on in the space, certainly in the Bakken as we try to define that.

I interpret that to mean this: EOG suggests that downspacing (putting wells closer together) in a spacing unit, will increase the amount of oil produced in that spacing unit (and thus increase the net present value to each spacing unit. However, it appears to me he is suggesting that the EUR will decrease in wells that are close together and "sharing."

That's an important interchange, critical to understanding the Bakken. Compare that interchange with what Motley Fool and CLR suggest at this link. 

EURs. Again. There's An Important Question That Needs To Be Asked -- See If You Can Guess The Question

Updates

Later, 6:00 p.m. central time: a reader over at the Discussion Group provided the following (I'm just getting ready to take older granddaughter to swimming, so I will look at the links later). Having said that, these links are to Petroleum News which always has great information:

EOG - Downspacing expands return:

http://www.petroleumnewsbakken.com/pntruncate/261636488.shtml

Continental - Bakken-bullish:

Despite exploration results to the upside, since 2010 Continental has not revised its recoverable oil estimates for the Bakken - currently 24 billion boe.

“We’re confident that the total now is larger,” Henry told Petroleum News Bakken in a Feb. 21 e-mail. “But we don’t have a formal estimate of it yet.”

http://www.petroleumnewsbakken.com/pntruncate/621048712.shtml

Original Post

Motley Fool is asking whether the Bakken is still being undervalued:

Back in 2011, Continental Resources founder and CEO Harold Hamm made waves when he said the Bakken shale formation in North Dakota and Montana held up to 24 billion barrels of recoverable oil. This seemed completely outlandish considering that the U.S. Geological Survey had estimated total recoverable oil in the region to be about 4.3 billion barrels. Since that time, though, the results from this region have just been better and better, and it makes the investment thesis for Bakken players such as Continental, Kodiak Oil & Gas, and Enerplus all the stronger. Let's look at some astounding numbers coming out of this oil patch that are making Hamm's claims less outrageous by the day.

In the Bakken, the average well is expected to generate an EUR in the range of 400,000 to 900,000 barrels depending on where in the formation drilling occurs. Through optimization programs and testing, the EUR for wells has been improving dramatically recently. At some of Continental's recent test wells, EUR has exceeded its typical 600,000 EUR projection by as much as 50% through tighter spacing between wells and increased use of sand in the hydraulic fracturing fluid.

Such results aren't unique to Continental. Kodiak has noted that several of its most recent wells have outperformed its 900,000 EUR projection curves at its wells in Dunn County, N.D., and Enerplus' most recent wells in the Fort Berthold region have seen early production nearly double its own 800,000 projection curves. 

Hmmmm....I just "showcased" an Enerplus well earlier today -- well before I saw this article. How coincidental.

I have a poor wi-fi connection now, so I can't write as much as I would like. If I remember, I will come back to this post, but I wanted to get the article posted.

For newbies: there is data that suggests the Bakken is a trillion-barrel reservoir (previously posted) and at a measly 3% recovery rate, that yields 300 billion barrels.

But getting back to the subject line, there was a line in the Motley Fool article that should raise eyebrows. I'll come back to it later. Hint: I thought it was also mentioned in the EOG conference call in which EOG seemed to come to the opposite conclusion than Motley Fool did.

The conclusion to this little exercise will be found at this post. 

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Meanwhile, for investors ...

• Anadarko Petroleum is looking too pricey after a 25% YTD gain for Barclays analyst Thomas Driscoll, who downgrades shares to Equal Weight from Overweight.
• It is easy to understand the enthusiasm for APC considering the strong record of deepwater exploration success, the willingness to monetize assets and the large discovery in Mozambique, Driscoll says; yet Continental Resources, EOG Resources and Noble Energy all are likely to grow twice as fast as APC while lacking any appreciable premium in their shares.
• The analyst prefers Devon Energy, which he says has made decisive steps to upgrade its portfolio in recent months, significantly improving its near-term investment opportunity set.

Disclaimer: this is not an investment site. Do not make any investment decisions based on what you read here or think you may have read here.

John Kemp/Reuters On Spacing

A reader alerted me a an excellent John Kemp/Reuters article on spacing.

The article begins:

North Dakota's leading oilfield operators hope to squeeze much more oil from its shale formations by drilling wells closer together - a bold experiment that could raise ultimate recovery by billions of barrels if it succeeds.

Oil and gas wells drain hydrocarbons from a fairly large area, although it is impossible to know the exact extent since the field cannot be observed directly. This poses a tricky problem for operators and regulators.

Drill wells too close together and they interfere with one another, draining oil and gas from the same parts of the formation and reducing their efficiency. Drill wells too far apart, and some valuable oil and gas will be left behind in parts of the formation not near enough to any well bore to be recovered.

The article provides a nice overview of spacing in various states.

A huge "thank you" to the reader for sending me this link.

It is interesting to note that the Bakken as a laboratory continues to move quickly. Re-read the third paragraph in the Reuters story linked above.

Now note this, from an earlier post:

EOG initially drilled wells every 640 acres in its Parshall field in Mountrail County, ND, but recently has been drilling every 320 acres. The initial results showed not only higher production rates from the newer infill wells, but improved recovery from the initial wells.

Unconventional means just that: unconventional.

The Bakken continues to be THE laboratory for tight oil and unconventional oil. Go Bakken. 

Snippet Of Information From EOG's Recent Drilling Efforts In The Bakken -- Impact of Downspacing

Remember all that concern elsewhere about additional wells "hurting" existing wells? Common sense suggested that would not be the case. Some folks actually opined they did not want a second well on their section, concerned that it would hurt their first well.

Now we have some new information. From EOG's conference call via Petroleum News:

Earlier this year, EOG predicted Bakken production would fall in 2012 as the company pulled rigs from the play, but not the company thinks production could actually increase slightly.

The optimism comes from several efforts this year.

The first is downspacing.

EOG initially drilled wells every 640 acres in its Parshall field in Mountrail County, ND, but recently has been drilling every 320 acres. The initial results showed not only higher production rates from the newer infill wells, but improved recovery from the initial wells. 

The company plans to test at 160-acre spacing on its core acreage as well as the impact of downspacing on its nearby Bakken Lite acreage.

From the earnings transcript:

Along with the new wells, our previously reported 160-acre wells continue to outperform our expectations, and the vast majority of the planned 53 completions in 2013 will be drilled on 160-acre spacing. As we continue to gain confidence in downspacing results over the course of 2013, we will likely increase the level of drilling activity in 2014.

There's actually another story line there. Elsewhere they have been concerned about companies cutting and running now that they hold leases by production. Not.

Certainly a lot of hand wringing out there.

Trending in the Bakken -- Drilling Deeper in the Three Forks Formation -- The Bakken, North Dakota, USA

This was touched on briefly but needs to be re-emphasized as more and more folks are asking how many wells can be drilled on a spacing unit.

Whiting and Continental Resources provide nice graphics in their presentations. This information comes from the August, 2011, CLR presentation.

This is where CLR is with regard to this issue, slide 9:

• their first ECO-Pad well pair: a Middle Bakken horizontal and an Upper Three Forks 1st Bench horizontal
• the slide, interestingly enough, shows a dialogue box with "multiple fracture stages with a 500' stimulation radius"
• CLR is currently drilling horizontals into the Three Forks 2nd Bench -- 1st test drilling
• in the future, CLR plans to test the Three Forks 3rd Bench and the Three Forks 4th Bench.

CLR has interests throughout the Bakken.

Some of their ECO-Pad results, average IP for four (4) wells):

• Glasoe/Raymo, 940: east Divide county, near Burke; north of Williston
• Kennedy/Miles, 1,377: northeast McKenzie county; ground zero for 2012 activity; the bull's eye
• Arthur/Hegler 1, 1,088: northwestern Dunn county
• Bridger/Bonneville, 745: northwestern Dunn county
• Carson Peak/Morris, 1,948, northwestern Dunn county

Northeastern McKenzie County and east-central McKenzie County will be where the action is in 2012;
Northwestern Dunn County is just south and east of that area

In Montana, it appears CLR is emphasizing northeastern Richland, directly west of Alexander, Watford City area:

• Rognas 2-22H, 1,013
• Tolksdorf 1-1H, 642
• Big Sky 3-35H, 1,163
• Clayton 3-20H, 1,118
• Amestoy 1-6H, 836
• Earl 2-25H, 1,024
• David 2-20H, 831

In this area, CLR has twelve (12) wells planned -- I guess CLR's Montana motto will be " 12 in '12"