From The Bismarck Tribune, nothing new for regular readers of the blog: new technology could recover more oil from early Bakken wells. Data points:
re-fracks
targeting wells drilled between 2008 and 2010
industry says currently recovery 5 to 15% of OOIP
140 wells in the Bakken have already been re-fracked
generally, to be economical, re-fracking needs to produce an additional 200K to 250K of crude oil
not all areas amenable to re-fracking
Comments:
about 2,500 wells drilled per year back in 2008 - 2010
economical at what price? $25/bbl? $50/bbl? $100/bbl?
when we first started blogging, the "word on the street" was that Bakken operators were recovering 1 - 3%; then Whiting made headlines when they suggested as much as 8%, and said they were targeting a much higher rate of recover
I've never seen a figure as high as a 15% recovery rate in the Bakken
Lynn Helms has said, in the past, what each 1% increase in recovery means in the Bakken
if primary recovery rate goes from 3% to 6% -- that is a doubling of production
This is a pretty good update (consider the source). The most interesting data point in the linked article has to do with the recovery rate from unconventional plays. I have two tags that haven't been used in years: recovery rate and recoverable.
When I first started blogging about the Bakken, I believe it was said that 1 - 3% of original oil in place was recoverable (with primary production). I believe it was Whiting who first suggested that operators were recovering significantly more than 3% of OOIP in the Bakken, and that was years ago. Now in the linked oilprice.com article:
But now the recovery rate, from 5 percent to 12 percent, may reach 25 percent in coming years.
It is not a matter of if but when this technological revolution extends across all oil-producing regions outside the Middle East. There is strong evidence of the aforesaid rising oil production as well, with the EIA forecasting a U.S. daily crude output of 9.2 million barrels this year. It is expected to reach 9.7mpd in 2018 (sic).
The rise in oil prices and U.S. production are directly proportional. This is one of the reasons that, as prices have recovered over past few months, we have witnessed a historic build in inventories.
from the July, 2015, hearing dockets: QEP, Grail-Bakken, 24 wells on each of two 1280-acre units, McKenzie
see comment(s) for other examples
And these are just a few of many, many examples.
And conservatively, it was suggested some years ago, the Bakken would be producing oil until 2100.
Disclaimer: I am inappropriately exuberant about the Bakken.
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Putting Things Into Perspective
High Tech vs Low Tech
America drops the MOAB the other day. First reports: 16 members of ISIS killed. That has been updated to suggest that 94 members of ISIS were killed; no non-combatants killed.
The Spurs have been in the NBA for 40 years. They have been in the play-offs 37 of those years. The next closes: Los Angeles Lakers, 35 years; and, then the Portland Trailblazers, 32 years.
And the best part: their home court is the ATT Center. What an incredible investment made by ATT some years ago when the corporation was headquartered in San Antonio.
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Putting Things Into Perspective
These 138JC Penney Stores Needed To Be Closed
The store closures will represent 13% to 14% of J.C. Penney's current store base and less than 5% of annual sales.
Note: in a long note like this, there will be factual and typographical errors. It has not been proofread. It is difficult to tell opinion from fact, either from the source or from my comments. Assume everything is irrational exuberance. I have no formal training or background in the oil industry. I have read The Prize but have yet to finish The Frackers. The easily influenced and gullible folks should probably skip this entire blog. There will be simple arithmetic errors. I often round numbers up or down, depending on my mood and hidden agenda. If this information is important to you, go to the source. This is not an investment site. Do not make any investment or financial decisions based on anything you read here or think you may have read here. By "here" I mean this entire blog, all 18,000+ posts.
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Maybe I will start here and see where this leads.
Look back at this post on July 21, 2010 -- five years ago? -- if the math was done correctly, this is what the NDGS estimated the EUR per section (640 acres) in the Bakken/Three Forks would be:
McKenzie: 257,602 bbls/section
Williams: 332,402 bbls/section
Mountrail: 296,754 bbls/section
Dunn: 228,146 bbls/section
Burke: 332,152 bbls/section
Divide: 154,560 bbls/section
Disclaimer: I often make simple arithmetic errors. It is possible the calculations and/or assumptions were incorrect. However, this post has been up since July 21, 2010, and no one has suggested they were wrong.
Fast forward to 2015: in general, operators won't drill a well in the Bakken if it doesn't have a EUR of at least 500,000 bbls crude oil. Using the numbers above, two sections in the best county (Williams) would get you 660,000 bbls/1280-acre unit (two sections).
Fact: the standard for almost anywhere in the Bakken is at least 4 wells per 1280-acre drilling unit, but for all practical purposes, it is at least 8 wells per 1280-acre drilling unit.
Staggering: 12 wells in a 1280-acre unit. EUR / well = 500,000 x 12 = 6,000,000 bbls / 1280 = 5,000 bbls/acre = 3,000,000 bbls/section. Compare with above (Williams: 332,402 bbls/section). But that's just 500K EURs. For at least two years now, we've known that the operators, whether they admit it or not, at looking for 1 million EURs in the sweet spots in the Bakken.
But for those paying attention, two years earlier, Whiting suggested that they could get 20%.
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We Interrupt This Post To Emphasize One Data Point
If you take a look at that last linked post, the Whiting/CEO said that they were not getting all of the oil that's out there with the current spacing in the Bakken. I'm assuming there are multiple interpretations of what he said.
Although it's being changed on a case-by-case basis, the fact remains that there are NDIC setback rules for each spacing unit. The smaller the drilling unit, the greater the percentage of "lost oil" due to the setback rules. I don't know the rules but for argument's sake, let's say that the horizontal lateral must not come closer than 250 feet to the drilling unit line; that the heel of the horizontal (the kick-off point) cannot be closer than 250 feet to the edge of the drilling unit line; and, that toe of the horizontal (the end of the lateral) must stop no closer than 250 feet to the edge of the drilling unit line.
The point is this: the amount of recoverable oil is not due only to technology; it can be affected by man-made administrative rules which can be changed.
Think about the setback rules and the radial effectiveness of fracking. Yes, there's a disconnect there, isn't there?
Hold that thought: we might come back to it later.
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The EOG 2Q15 Conference Call
To understand the Bakken better there are only a handful of transcripts I am interested in regarding earnings for 2Q15. I've looked at two of them: EOG and CLR. The next one that I will be looking at is Oasis. Summaryy, notes, and comments on Oasis 2Q15 conference call here.
Before moving on to the Oasis transcript, I want to spend a bit of time rambling about the EOG conference call. Shortly after I posted my notes on the EOG transcript, a reader wrote, commented, and asked:
EOG said they would drill their
DUCs (fracklog) in 2016 no matter what, regardless if prices recover. Since half the money is spent, then it becomes the best investment
available to complete those wells. Fair enough...but then why not
complete them now?
Surely after this little flirt with $60+ and prices getting beaten down,
it is pretty clear that the big V shape ain't happening?
I also don't understand why they
did a short lateral, the #30286, Riverview in the Antelope oil field. Surely cost efficiency is better at long
laterals? If it was just a test, why not do it at the distance they
expect to do in the future? Or is all their acreage so old that they
can't run long laterals?
Comment: The easy question first, to get it out of the way: is their acreage such that they cannot run long laterals? Answer: No. They can run whatever they want. If they have don't have the "correct" spacing unit size, the NDIC will give it to them, if EOG asks nicely. With regard to the short lateral Riverview that appears to have set the Bakken/Three Forks record for first-month production: the Riverview 102-31H was drilled on an even smaller unit than a 640 -- it was a 320-acre
unit, going to the north. That half-section is also part of a 640-acre
drilling unit, and it is also part of a1280-acre drilling unit. So, they could have drilled a 320-, a 640-, or a 1280-acre spaced well from that location.
Comment: EOG's expertise in the Bakken, for whatever reason, has been short
laterals. If they wanted longer laterals they could always ask for
larger drilling units. And in fact they did just that in the January,
2015, hearing dockets. [Case #23595, EOG, multiple wells on 16 1280-acre
units; multiple wells on 15
1920-acre units;
Parshall-Bakken oil field]. That doesn't mean the horizontals will be longer. They could still drill short laterals on
bigger drilling units, of course. All those 2560-acre drilling units? They all have long laterals -- the very same length used on 1280-acre drilling units, even if the entire 2560-acre unit is a laydown or a standup.
Comment: the reader says, "surely cost efficiency is better at long laterals." I'm not so sure. I discussed that elsewhere. If folks are interested in my thoughts on this, I will talk about it again. I will probably have to talk about it again, just to refresh my memory and for archival purposes.
Comment: the reader asked why EOG is waiting until 2016 to complete the DUCs? I think one can come up with a dozen different, not necessarily mutually exclusive reasons. I will list some knee-jerk thoughts to remind me when I expand on this subject in the future:
CAPEX
survival mode
liquidity
time involved in studying off-set and existing wells
re-evaluating completion techniques
geo-political considerations (Harold Hamm says things are going to change as early as September, 2015, just a month or two from now)
EOG has a history of not fracking in cold weather; that may or may not be true; it is a fact that is is much more difficult and much more expensive to drill in cold weather
determining best wells to complete: flaring rules, transportation costs (moving oil from any given pad by truck or by pipeline)
I'm sure readers can come up with a dozen other reasons why EOG is waiting to start completing the DUCs in 1H16. I think the #1 reason is "re-evaluating completion techniques" -- the main theme that I took from the EOG conference call. I think the Riverview well was a huge test for EOG. I wouldn't be a bit surprised if there were competing views on how to complete the well with some geologists on the team really, really excited about trying something new, or doing the same thing just a whole lot better. And with the results, they were really, really vindicated. It's possible that a lot of thought went into that well ahead of time but no one thought it was going to be as good as it was. Analogy: you have five million dollars to build a house. You can build a 50,000 square-foot McMansion or a 5,000 square-foot house. Which house is going to be aesthetically the nicer home to live in? No right answer; it's in the eye of the beholder. I personally would go for a $5 million 5,000 square foot house. With a basement. Oh, and for the 50,000 square-foot McMansion, I give the architect six months to work on it. For the 5,000 square-foot house, I give the architect two years to work on it.
As Good As I Once Was, Toby Keith
Comment: the "V ain't happening." I don't know. It's hard to say whether the "V" will happen or not. Common sense says we won't see a "V-shaped" recovery in the price of oil, but neither the Mideast nor President Obama are known for their common sense. Regardless of whether a "V-shape" recovery occurs or not, remember what EOG said some months ago: they can make more money on $65 oil than on $95 oil. There may be some hyperbole there but it's not the price of oil that is important; it's the margins.
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With Regard To The Price Of Oil
I am always conflicted when writing about the Bakken. I started the blog to help me understand the Bakken, not for investment purposes. I still have little interest in writing about the Bakken from an investment point of view. That's why I have spent so much more time on the EOG conference call than on the CLR conference call. The CLR conference call seemed to emphasize the economics, the financial end of things. The EOG call seemed to be one of those incredible moments in time when the CEO admitted that he has to go back to the drawing board, to re-think everything he has thought about completing wells in the Bakken. Remember, EOG had the first "real" discovery well in the Bakken that set off the current Bakken boom (folks can disagree with me on that), and here we are, eight years later, not only knowing a whole lot more about the Bakken, but apparently seeming to know less than we thought. And in a conference call, we get hints that the light bulb just went really, really bright in the CEO's head. And I think some folks missed that. Mike Filloon certainly did not miss it.
Huge digression. Sorry.
The point I was going to make. I am always conflicted when writing about the Bakken. I started the blog
to help me understand the Bakken, not for investment purposes. If I wrote simply for myself, the blog would be a lot different. Based on feedback from readers, I have to keep in mind there are at least threefourfivesix seven audiences affected by the Bakken boom or interested in the Bakken:
everyday folks in western North Dakota, raising families in a boom-and-bust environment
the rough necks and truckers that make this all happen
the curious lookie-lou
royalty owners who still live in the Bakken and see first-hand what is happening
royalty owners who left the Bakken years ago (or never lived there) and have little understanding of what is going on; they just like their royalty checks
royalty owners who have inherited good fortune from "forward-thinking relatives" (see comment)
For newbies, this is an incredibly important post, that takes us back to the early days of the Bakken. It gets us back into the discussion of primary, secondary, and tertiary recovery. The following all has to do with primary recovery.
In the beginning, the general consensus was the the amount of oil recoverable through primary production was estimated to be 3%, perhaps less. Some estimated as much as 5%. However, when I started running the numbers, and looking at the press releases, I was convinced that 8% recoverable through primary production was more likely than 3%, and there were reports back as early as 2012 suggesting rates of recovery could be much, much higher.
Even a one percent increase in recovery through primary production means as much as an extra 5 billion bbls (500 billion bbls original oil in place [OOIP] x 0.01 = 5 billion bbls.
3% through primary recovery: 15 billion bbls
6%: 30 billion bbls
9%: 45 billion bbls (and I think that's the current conservative general consensus)
One more fact that I’ll remind you of, just to blow your mind a little bit more. Six or eight years ago we were estimating a recovery factor of just 3.5% in the Bakken shale reservoirs from our horizontal wells. With additional work, micro-seismic study, well production history, big data analytics, etc., we’re now estimating that we’re recovering 15-18% of the oil in place.
We further estimate, with our current technology, that the technically recoverable oil in the Bakken is 65 to 90 billion barrels.
Let’s pick the midpoint at 78 billion barrels of recoverable oil and assume a recovery factor of 16.5%. That implies we have about 470 billion barrels in place, of which 78 billion barrels can be recovered.
Now let’s assume that over the next decade that the drilling and extraction technologies continue to improve and we are able to harvest another 5% of the oil in place — again, we now know exactly where it is and we know the exact profile of the geology/geophysics of the shale rock.
That’s another almost 24 billion barrels of crude oil (470 billion x .05), which would be equivalent to discovering another Prudhoe Bay size oil field in the Bakken area! All it takes is more experience and technology gain to get the oil we know is there.
The article also takes us back to OOIP. It's hard to say exactly what the "insider" was suggesting when he wrote:
... we’re now estimating that we’re recovering 15-18% of the oil in place.
We
further estimate, with our current technology, that the technically
recoverable oil in the Bakken is 65 to 90 billion barrels.
I can only assume the "insider" was "equating" the two. So working backwards:
15 to 18% of what = 65 to 90 billion bbls
15% of what = 65 billion bbls OR 18% of what = 90 billion bbls.
At the time 500 billion bbls OOIP was first being bandied about (before 2013), only the middle Bakken and the upper Three Forks (which we now call the upper bench or the first bench of the Three Forks) were being targeted (and then, mostly the middle Bakken; very few wells were actually targeting the upper Three Forks prior to 2013).
These discussions help explain the price operators were willing to pay for mineral acres back in the early days and why the Bakken remains so exciting.
So, now, to collect the Mark Perry Carpe Diem three recent posts on the Bakken:
I was the first one to review a new book on Amazon. My review here. The book here. I also just posted my review of Oliver Sacks' autobiography. The book here. Generally speaking, I find there are more than enough reviews, and more than enough words for each review, that my reviews can be short and sweet.
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Coming Into Work A Bit Later
I called my dad to wish him a Happy Father's Day and to ask him how his day was going.
He was in a great mood as usual.
I called him at the office. He mentioned that he was just getting in. I had called about 10:45 a.m. He says he was now coming in a bit later than usual. Instead of coming in at 9:30, he now comes in about 10:30 every morning.
He says there is not a lot for him to do, so he can come in a bit later. I guess he's sort of on auto-pilot at age 93 years. His biggest problem is making sure his broker understands his "orders." He remains excited about his portfolio, particularly Apple. He got in relatively early; I missed that one. He thought Apple was a grocer or supermarket of some sort years ago. He knows that the company is having some problems now with the music end, but doesn't know the particulars.
I didn't ask, but he probably won't buy the Apple Watch.
I'm going to do a longer post on this subject in a few days. Hopefully my patience will hold. Before posting the "story," I am curious what readers think.
So here's the poll, based on your knowledge of the Bakken, what do you think is the recovery rate of original oil in place through primary production from the Bakken?
Every now and then a really good article comes across "my desk." Generally I do not know how good an article might be until weeks or months later. But something tells me this might be a very good article to bookmark for future reference.
A reader sent it to me. A huge thank you to the reader.
The article has to do with enhanced oil recovery (EOR) using nitrogen instead of CO2.
I'm getting out of my comfort zone and could be very, very wrong on this, but reading the wiki article as well as Schlumberger definitional resources, and then the new article (linked below), it looks like using nitrogen to help recover oil could fall into either secondary or tertiary production.
Again, outside of my comfort zone, it appears "secondary" production has to do with increasing reservoir pressure whereas "tertiary" production has to with decreasing viscosity. Depending on "how" one used a gas such as CO2 or N2 determines whether it is "secondary" or "tertiary" recovery. EOR is generally "synonymous" with tertiary recovery. (Further confusing matters, there is some suggestion that the operators consider this use of nitrogen to be part of primary production; see below.)
Again, this is all colloquial.
[Confusing matters further, nitrogen apparently can also be used for fracking, or at least has been tried. At the bottom of the blog, I have a "Fracking_Nitrogen" tag, for example.]
Tundra Oil and Gas Partnership is seeking regulatory
approval for an immiscible nitrogen flood in the Middle Bakken/Three
Forks tight oil formations in the Daly Sinclair field of southwest
Manitoba.
Based in Winnipeg, Tundra is a privately held light oil
producer that operated the drilling of 168 wells in Canada last year --
163 in Manitoba and five in Saskatchewan.
This isn’t the company’s
first foray into gas flooding in a tight oil formation. Since August
2008 Tundra has been operating a miscible gas pilot injecting carbon
dioxide in the southeast quarter of section 04-08-28W1 within Sinclair
Unit No. 1. Last August this pilot was approved for conversion to a
water-alternating-gas project.
Now the company is applying for an
immiscible gas injection pilot using nitrogen. (In miscible gas floods,
the injected gas forms a single homogeneous phase with the oil. The
resulting fluid has lower viscosity, reduced interfacial tension and
improved mobility. While immiscible gas doesn’t form a single phase with
the oil, it still has the benefit of improved pressure maintenance and
sweep efficiency within the reservoir.)
This is a long, long article and many, many data points.
Second: in this new article, the difference between using CO2 and N2 is spelled out very nicely. The big difference is that using N2 is much less expensive than using CO2, is readily available, and doesn't get into the issue of global warming/greenhouse emissions.
A third data point has to do with the general recovery rate of crude oil from the Bakken/Three Forks in this area (Saskatchewan/Manitoba):
Total net original oil in place (OOIP) in the proposed project area is
estimated at 2.78 million bbls for an average of 174,000 bbls per
40-acre legal subdivision.
According to Tundra’s application, oil
production per well in the proposed project area peaked in 2009 at 268
bbls a day. As of last November, average oil production per well had
fallen to 9.6 bbls a day. Production is forecast to continue declining
at a rate of nearly 29 per cent a year.
By last Nov. 30
cumulative production from the four wells within the proposed Ewart Unit
No. 5 project area was 206,500 bbls of oil and 292,800 bbls of water.
The recovery factor was 7.4 per cent of the net original oil in place.
Estimated
ultimate recovery of primary proved producing oil reserves in the
proposed project area is estimated at 256,000 bbls with 49,500 bbls
remaining as of last Nov. 30. Under the current primary production
method, ultimate oil recovery of the proposed Ewart Unit No. 5 is
forecast to be 9.2 per cent of the original oil in place.
Note the "downspacing": 40 acres. (In one test, they plan to go to 20-acre spacing, also.)
Note the recovery rate: 7.4% of the net original oil in place (OOIP) prior to N2 flooding.
With N2 flooding, they propose a recovery rate of 9.2%.
Note the EUR of these Bakken/Three Forks wells: 256,000 bbls. Compare with EURs of Bakken/Three Forks in North Dakota -- suggested to range between 400,000 and one million bbls.
This is where it gets a little confusing. In bold in the above paragraph, it sounds like they consider N2 flooding part of primary production: "Under the current primary production
method, ultimate oil recovery of the proposed Ewart Unit No. 5 is
forecast to be 9.2 per cent of the original oil in place."
This seems accurate because almost immediately, the article talks about "secondary" / EOR production:
Tundra estimates ultimate recovery of proved oil reserves in the project
area, using a secondary water-alternating-gas EOR scheme, would be
379,000 bbls of oil with 176,000 bbls remaining.
And here, the author writes "secondary" and "EOR."
Be that as it may. It's a long, long article, with many, many data points. As noted at the beginning, this may turn out to be an article we come back to again and again.
Oh, by the way, there is at least instance in which N2 injection was being considered by an operator in the North Dakota Bakken. In the August, 2012, NDIC hearing dockets, case 18402:
18402, Whiting, nitrogen injectivity test in the Sanish, Mountrail
Big disclaimer: I may have misinterpreted the linked article. I don't spend a lot of time sorting all these articles out the first time I go through them. If you are interested in this particular subject, I would ignore what I've written and go directly to the source.
Perhaps the most important takeaway from this article: rate of recovery before additional measures -- about 7%. My hunch is that newer, more aggressive technology in the North Dakota Bakken is resulting in a great percentage recovery.
This all goes back to the discussion that was started with regard to recovery rates, what naysayers were saying, what the industry in general was saying, and what Whiting was reporting. I think some of the recovery-rate data fed to us in the past was being low-balled by different folks, all with different agendas.
The vast Bakken Shale formation in North Dakota and Montana, a
cornerstone of hopes for North American energy production, will need
costly, advanced oil recovery strategies in order to tap its full
potential over the next few decades, researchers and industry officials
say.
Primary oil recovery methods centered on horizontal drilling and
hydraulic fracturing will leave 90 to 95 percent of the Bakken and
underlying Three Forks oil resource in the ground, ....
So, before you all get excited about the article, note those two data points:
even at one million bbls of oil per day, the industry is leaving as much as 95% of oil in the ground (think of the potential)
increased production to reach full potential will occur over the next few decades
I'm not sure what "next few decades" means, but I assume it's more than one, or "they" would have said "ten years." I assume it's more than two decades or "they" would have said two decades. For me, "several decades" means a minimum of thirty years before I have to get too excited about enhanced oil recovery, though I assume most folks assume it will happen more quickly.
It's amazing how so many journalists, it seems, get well ahead of their headlights. We are nowhere close to maxing out primary production in the North Dakota Bakken and some non-specialists are already concerned about secondary and tertiary production.
... every
1% in incremental recovery factor translates into an additional nine
billion barrels of estimated ultimate recoverable reserves in the field ...
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Of course that begs the question, one percent of what yields nine billion?
0.01 x ? = 9 billion
9/0.01 = 900 billion barrels of EUR?
“What is the true recovery factor? We still don’t know; we’re still
estimating it,” said Stark. However, for perspective, every 1% in
incremental recovery factor translates into an additional nine billion
barrels of estimated ultimate recoverable reserves in the field, he
added. “It’s a remarkably huge field.”
That story is full of data points for the Bakken. Consider this:
Pointing to a chart that shows U.S. horizontal oil growth by play from 2005 to 2012 (adjacent to this article), Papa said, “The point we make is, there are only two plays that make a difference on a national scale — the red and the turquoise. The Eagle Ford and the Bakken.
There’s been a lot of sell-side news and specific company news about plays like the Woodford, the Mississippian, the Niobrara, and so on and so forth but they barely make a spec on this chart.”
“Our prediction is that over the next five years they (non-Bakken, non-Eagle Ford plays) will barely make a spec on this chart. And so for all the news that they are generating, they’re not going to be significant players on a national scale,” he said.
Next, he pointed to a chart that showed which companies produced the most crude from horizontal plays in the U.S. EOG topped the list.
“As it stands right now, by a 2 to 1 ratio, EOG is the largest producer. … It’s no horse race at this point in time,” Papa said.
And then this:
He did, however, talk about oil recovery rates in the Bakken, putting them at approximately 10 percent versus 6 percent for the Eagle Ford.
In an earlier post (yesterday) I reminded readers that Harold Hamm thinks "the Bakken" has 900,000 bbls OOIP and has 45 billion bbls recoverable oil. That's a 5% recovery rate. I was going to point out that Bakken recovery rates seem to be closer to 8% than 5% but I've been warned about "gilding the lily." And I'm just an amateur at all this.
Of course, that 5% is across the entire Bakken, but it's still interesting to note that EOG suggests the recovery rate is significantly higher in the Bakken than the Eagle Ford.
1. 2008: The State of North Dakota estimated in 2008 that the Bakken Formation contains 149.2 billion barrels of oil in-place (OOIP) within the borders of North Dakota. (Don't you just love that "point.two"? It makes the number look much more believable than if it were 150 billion bbls, but I digress.) [Update: that link is broken, but it helps me date this presentation. This NDIC presentation must have been in 2008 because slide 30 shows 149.2 billion bbls of oil OOIP in the middle Bakken. I don't want to lose presentation, so I have archived it.]
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2. I vaguely recall that early on in the Bakken boom "they" said one could expect about 3 - 4 percent recovery of OOIP. Four percent of 150 billion --> 6 billion. In fact, from various conference calls, it appears "they" are recovering eight percent (eight percent of 150 billion --> 12 billion). Harold Hamm has said for quite some time that 24 billion is likely to be recovered. Eight percent of "what" --> 24 billion? 300 billion. So, I've always thought Bakken OOIP was around 300 billion barrels.
A research paper by USGS geochemist Leigh
Price in 1999 estimated the total amount of oil contained in the Bakken
shale ranged from 271 billion to 503 billion barrels, with a mean of 413 billion barrels -- original oil in place (OOIP). (200,000 square miles)
With the deeper benches in the Three Forks formation, CLR says there could be 900 billion barrels of OOIP in the Bakken Pool.
Ghawar is an oil field located in
Al-Ahsa Governorate, Saudi Arabia. Measuring 280 by 30 km (170 by 19
mi), it is by far the largest conventional oil field in the world. When appraised in the 1970s, the field was assessed to have 170 billion barrels of original oil in place (OOIP). (3,230 square miles)
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So, those are the data points. A lot of folks have said Leigh Price's estimate of 270 to 500 billion bbls of original oil in place in the North Dakota Bakken was on the high side.
Harold Hamm consistently opines that he thinks there is 24 billion bbls of recoverable oil from the Bakken. Eight percent recovery is certainly on the high side but there is more and more evidence that we are seeing at least eight percent recovery by the better Bakken drillers. Again 8% of what = 24? 300 billion barrels.
So: 300 billion bbls OOIP seems to be "the number."
But note: CLR above suggested that with the deeper benches of Three Forks, the OOIP might be as much as 900 billion barrels of oil (or three times as much as 300 billion barrels).
So, is CLR putting its money where its mouth is? From the linked article:
When asked about where they will spend their $550 million CapEx
increase, Hume responded "it's all entirely going to the Bakken." (They
produce in the Niobrara/DJ Basin, the Anadarko Woodford and the
Bakken.) He added, "we're obviously participating in all the acreage
sales in our key plays, mainly the Bakken. Right now, we're very
concentrated, very focused on consolidating acreage in the Bakken."
