transport natural gas from an existing transmission line to an existing oil well
$3.55 million
enhanced recovery
think about that: spending $3.55 million to test enhanced recovery from an existing well
at $100 at the well head:
$3,550,000 / $100 = 35,500 bbls of oil
2,000 bbls / month = 18 months
specifics:
origin: East MonDak WBI Energy Transmission Line
terminus: Continental's Buddy Domindgo Well Pad
natural gas to be compressed and injected downhole into the existing well to test the feasibiliity of this method for prolonging thee well's production life;
without enhanced recovery:
the current technology will leave 80 to 85 percent of the oil tied up in shale rocks behind, North Dakota Director of Mineral Resources Lynn Helms has said in past monthly oil production reports — an enormous target, that makes even a 1 to 2 percent gain in oil recovery highly economic.
Continental has already acquired all of the rights of way needed for the
project, and expects to take two months completing the project once it
is permitted.
Too bad the NDIC map is not available to locate the origin and terminus.
But look at that: primary production in the Bakken recovering upwards of 15% of OOIP, link here:
500 billion bbls OOIP
15% of 500 billion = 75 billion bbls
at 1 million bbls / day x 365 = 365 million bbls / year
75 billion / 365 million bbls = 205 years.
others have said 250 billion bbls OOIP
15% of 250 billion = 37.5 billion bbls
= 102 years
Note: I am inappropriately exuberant with regard to the Bakken and often make simple arithmetic errors.
Disclaimer: this is not an investment site. Do not make any investment, financial, job, travel, or relationship decisions based on what you read here or think you may have read here.
Now, back to the linked article. Summary:
Continental Resources doubles its estimate for oil recovery from North Dakota's Bakken shale, claiming 30B-40B barrels of the 250B barrels of oil in place will be recovered instead of the 20B barrels it estimated in 2011
"With today's completion technology we are recovering 15% and potentially 20% of the oil in place on a primary basis," CLR President Jack Stark said during today's earnings conference call, "substantially higher than the recoveries that we thought possible back in 2011."
"There's a lot more oil to come out of the Bakken," said Chairman and CEO Harold Hamm.
Using a North Dakota industry estimate that ~50K potential wells remain to be drilled in the Bakken, Stark said each well would have to produce 570K barrels to reach CLR's new estimates for recoverable oil - "clearly a reasonable expectation for Bakken wells on average," according to Stark.
North Dakota oil production averaged a record 1.29M bbl/day in August, and CLR says its output accounted for 12% of that production.
Earlier: Continental Resources +2.5% as Bakken production reaches quarterly record (October 29, 2018)
This is a keeper. Read those stats again.
OOIP: CLR is apparently sticking with 250 billions of original oil in place (OOIP) in the Bakken; that's a far cry from a trillion-bbl reservoir suggested at one time; but, I'm sticking with the Bakken being a 500-bbl OOIP reservoir, and wouldn't bet against a trillion bbls, but I'm inappropriate exuberant about the Bakken.
Primary production, defintion: in the early days of the Bakken, the consensus -- tight oil was called "tight" for a reason; drillers would only be able to recover 1 - 3% of OOIP in primary production. Primary production is all that production before enhanced recovery is required, such as water flooding and/or CO2 injection. Oil recovered after work-overs; re-fracks; etc, is still considered primary production. Primary production can go on for decades.
Primary production, Whiting, the early days: in the early days of the Bakken, the consensus was that drillers would get only 1 -3% of the OOIP by primary production. This blog was the first, as far as I am aware, that suggested drillers were getting as much as 4 - 6% even when pundits were still talking about 1 - 3%. Then Whiting, either intentionally or by mistake, mentioned in one of their conference calls that they were either already getting upwards of 12% or expected to reach that threshold before it was all over. That was a long, long time ago, and my memory may be faulty, but I vaguely recall something along that line.
Primary production, CLR, now: CLR says that "we are now recovering 15% of the OOIP and Harold Hamm thinks they could eventually get to 20%. Let's do the math:
a EUR-type curve of 1 million bbls
15% of what = 1 million bbls
OOIP: 6.7 million bbls [check the math: 0.15 x 6.7 = 1 million bbls]
so, let's go with 6.7 million bbls OOIP for any given well
20% of 6.7 million bbls OOIP takes us to 1.34 million bbls -- CLR is already reporting EUR-type curves of over 1.2 million bbls
Number of wells yet to be drilled in the Bakken: 50,000. The North Dakota Bakken boom began in 2007, and was headed for about 2,000 new wells/year but then plateaued at about 1,000 to 1,5000 new wells per year. Using 1,500 new wells / year, eleven years in the Bakken puts us at [11 x 1500] 16,500 Bakken wells. So, let's see what NDIC says. According to the most recent Director's Cut, there were 15,103 producing wells in August, 2018, which by the way, was an all-time record. Wow, not too far off the mark. So, we can safely say , one can expect about 1,500 new wells/year. 50,000 new wells / 1,500 = 33 more years of drilling.
Years of production: just for grins, let's assume the OOIP is actually 500 billion bbls -- again, I'm inappropriately exuberant with regard to the Bakken -- and let's assume that for whatever reason, North Dakota maxes out at 2 million bopd production. Let's do the math:
15% primary recovery
15% of 500 billion bbls = 75 billion bbls
75 billion bbls / 2 million bopd / 365 = 100 years of production
Now if each well has a EUR of, let's say 1.5 million bbls, how many wells would that require?
75 billion bbls by primary recovery / 1.5 million bbls / well = 50,000 wells
50,000 wells -- interesting. We're back to the same number suggested above -- another 50,000 wells to drill out the Bakken
Disclaimer: math is not my first language. There will be simple arithmetic errors on this page. In addition, in a long note like this there will be factual and typographical errors. This is done for my benefit. No one should take any of this too seriously.
Staggering: With 60,000 wells in the Bakken, using current technology and current completion strategies the oil companies will extract one-tenth of all the original-oil-in-place (OOIP) -- Lynn Helms.
How many producing wells right now? About 14,000. At the height of the boom, oil companies completed about 2,000 wells/year. Now, with the slump in oil prices, about 600 wells will be completed this year.
At 1,000 wells / year, to add another 40,000 wells, 40 years of drilling activity. And that will get us 10% of the OOIP.
To date: amount oil companies have invested in drilling wells, completing wells, and laying pipeline to transport Bakken oil -- $125 billion. About $2 million / every North Dakota resident (adults and children).
As long as we're having fun, let's work this backwards:
assume each well in primary production eventually produces 1 million bbls / oil (over 30 years of production)
60,000 wells x 1 million bbls = 60,000 million or 60 billion bbls of oil
60 billion bbls of oil is one-tenth of OOIP which means the OOIP reservoir is 600 billion bbls
It’s the beginning of the end for the Bakken Shale play.
The decline in Bakken oil production that started in January 2015 is
probably not reversible. New well performance has deteriorated, gas-oil
ratios have increased and water cuts are rising. Much of the reservoir
energy from gas expansion is depleted and decline rates should
accelerate. More drilling may increase daily output for awhile but won’t
resolve the underlying problem of poorer well performance and declining
per-well reserves.
December 2016 production fell 92,000 barrels per day (b/d)–a whopping
9% single-month drop (Figure 1). Over the past two years, output has
fallen 285,000 b/d (23%). This was despite an increase in the number of
producing wells that reached an all-time high of 13,520 in November. That number fell by 183 wells in December.
What a doofus.
Bakken production remains over one million bopd. Bakken crude oil production rose 1.4% month-over-month in most recent report and that was despite the fact that a) WTI is still not priced in Bakken's favor; b) the number of producing wells has remained about constant; c) there are about 1,500 wells shut in for various reasons; and, d) there are about 800 DUCs that can be brought on line in days, not months.
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.
41. What is the current estimate of recoverable reserves of oil in North Dakota?
Update, June 7, 2013: this is very, very clear -- Denver conference.
CLR: the Bakken plus TF1 at 3% recovery rate, 24 billion bbls; add TF2,
TF3, and TF4, and maintain 3% recovery, and CLR estimates 32 billion
bbls. Every
1% in incremental recovery factor translates into an additional nine
billion barrels of estimated ultimate recoverable reserves in the field.
Update, August 29, 2012: CLR's corporate
presentation suggests there may be close to one trillion bbls of
original oil in place (OOIP), but from Leigh Price's estimate of 550
billion barrels. At 5% recovery, CLR states that up to 45 billion barrels of recoverable oil may exist in the Bakken.
Update, November 2, 2011: by hitting oil in a lower seam of the Three Forks, CLR/CEO Harold Hamm says that this has the potential to add incremental reserves to our estimated 24 billion boe of technically recoverable oil and natural gas in the total Bakken.
In October, 2010, Continental Resources (CLR)/CEO (Harold Hamm)
estimates the basin in North Dakota holds 24 billion barrels of
recoverable reserves. That is more than five times the "original"
estimate given two years ago (2008) by the US Geological Survey. Lynn
Helms, director of ND Dept of Mineral Resources opines that there will
be half that amount: 12 billion barrels.
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Saudi Arabia Reserves? How Big? John Kemp Weighs In
The kingdom has proven reserves of 266 billion barrels according to government estimates submitted to the Organization of the Petroleum Exporting Countries (“Annual Statistical Bulletin”, OPEC, 2015).
If these numbers are correct, Saudi Arabia’s reserves will last for another 70 years at the average production rate of 10.2 million barrels per day reported for 2015.
But there is widespread scepticism about the official estimates, which were abruptly raised without explanation from 170 billion barrels in 1987 to 260 billion in 198.
Official reserves have remained constant every year since then at 260-265 billion barrels, even as the country has consumed or exported another 94 billion barrels. If the government data is accurate, the kingdom has managed the remarkable feat of exactly replacing each produced barrel with new discoveries or increased estimates of the amount recoverable from existing fields.
But most of the country’s giant and super-giant oil fields were discovered between 1936 and 1970 and no comparable discoveries have been made since then.
OOIP: In the 1970s, there was broad agreement that the OOIP of Saudi Arabia’s discovered oil fields was around 530 billion barrels.
P1: Proved reserves, the most conservative and prudent measure, are those which are estimated to exist, and are technically and economically recoverable, with a probability of at least 90 percent.
P2: Probable reserves are those estimated to exist and be commercially recoverable with a probability of at least 50 percent.
P3: Possible reserves, the most speculative and optimistic measure, are estimated to exist and be commercially recoverable with a probability of at least 10 percent.
In the late 1970s, Aramco put proven reserves at around 110 billion barrels, while the more speculative categories of probable and possible reserves were put at 178 billion barrels and 248 billion barrels respectively.
Saudi Arabia began reporting to OPEC that its “proved” reserves stood at around 168-170 billion barrels of crude oil.
The Saudi figure was much higher than the 110 billion barrels of proved reserves reported by the Aramco partners a few years before.
But it was very close to the figure for possible reserves that the Aramco partners had reported to the U.S. Senate.
That raised the question if the Saudis had chosen to increase their reported reserve base by reporting probable reserves as proved reserves.
In 1988/89, the proved reserve figure jumped again to 260 billion barrels despite no major new discoveries.
Rystad Energy, a respected consultancy, puts Saudi Arabia’s proved reserves at 70 billion barrels, and its proved and probable reserves at 120 billion barrels.
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.
*****************************
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.
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.
June 16, 2018: the next USGS survey of the Bakken/Three Forks was scheduled for 2020. North Dakota congressional representativessuccessfully lobbied the USGS to begin the survey sooner. That was announced on December 11, 2017. This suggests to me that the USGS should begin the new survey not later than by the end of 2018. Let's hope.
May 10, 2013: back-of-the-envelope calculations. The four counties with the most activity: Dunn, McKenzie, Mountrail, Williams, around 10,000 square miles. One section is a square mile. It's pretty much agreed there will be four wells in each section in this part of the Bakken: 40,000 wells. EURs/well of 500,000 are certainly likely.40 x 500 = 20,000 x 1,000 x 1,000 = 20 billion bbls of oil in these four counties.
Now, let's say someone suggests 4 wells/section throughout the entire 4-county area is a little optimist, then we have one-half of Burke County (500 sq miles); Divide County (1,000 sq miles); Stark County (1,000 sq miles -- where Whiting's Pronghorn Prospect is): 2,500 sq miles = 2,500 sections. Let's say just two wells per section at 300,000 bbls EUR. 2 wells/section x 2,500 sections = 5,000 wells x 300,000 bbls = 5 x 300 = 1,500 x 1,000 x 1,000 = another 1.5 billion bbls, which is extremely conservative.
So, very, very conservative, 20 billion bbls. USGS says 7.3 billion, and Lynn Helms says the 5% probability figure of 11 billion bbls is a reasonable target. And I do believe that folks like Harold Hamm were looking at 20 billion bbls recoverable from the middle Bakken alone, even before considering the Three Forks.
May 10, 2013: I just noticed that Lynn Helms, Director, NDIC, released a press release on the USGS 2013 survey of the Bakken. He said he was happy with the survey, stating clearly that the figure of 11 billion barrels of recoverable oil was an appropriate target. The mean of 7.38 billion bbls was not mentioned, suggesting that Lynn Helms feels strongly that 11 billion bbls is the more likely figure.
“These world-class formations contain even more energy resource
potential than previously understood, which is important information as
we continue to reduce our nation’s dependence on foreign sources of
oil,” said Secretary of the Interior Sally Jewell. “We must develop our
domestic energy resources armed with the best available science, and
this unbiased, objective information will help private, nonprofit and
government decision makers at all levels make informed decisions about
the responsible development of these resources.”
Does this mean SecInterior Sally Jewell will support fracking?
The Bakken and Three Forks formations in North Dakota, South Dakota,
and Montana hold an estimated mean of 7.38 billion bbl of undiscovered,
technically recoverable crude oil, the US Geological Survey announced.
The updated assessment
represents a two-fold increase from the 2008 estimate of 3.65 billion
bbl in the Bakken, it noted.
The update includes the Three Forks for the
first time.
USGS’s latest assessment found that the Bakken has a 3.65 billion bbl
estimated mean resource—unchanged from 5 years ago—and Three Forks has
an estimated mean 3.73 billion bbl. The formations’ combined estimate
ranges from 4.42 million bbl, with a 95% chance of production, to 11.43
billion bbl, with a 5% chance.
Other data points:
6.7 Tcf of associated / dissolved natural gas
0.53 billion bbls of natural gas liquids
The narrative continues:
Gas estimates ranged from 3.43 Tcf (with a 95% chance of production) to
11.25 Tcf (with a 5% chance) and 0.23 billion bbl (95%) to 0.95 billion
bbl (5%) of NGLs. These estimates represent a nearly three-fold increase
in mean gas and NGL resource estimates from the 2008 assessment, due
primarily to the inclusion of Three Forks Formation, USGS said.
Later, 12:17 pm: Tweets keep coming. Bits and pieces starting to flow re: USGS estimate: Hoeven: 7.4 billion is a mean number. Top line is 11.4 billion barrels. Hoeven says both numbers likely conservative. Just between you and me, there is a huge difference between 7.4 billion and 11.4 billion. Using a calculator, I get a difference of 4 billion. The four-billion-delta exceeds the 3.6 billion bbl USGS estimate in 2008. In other words, the USGS has just announced "another Bakken" has been discovered in the United States. It is located, coincidentally enough, in western North Dakota.
The U.S. Geological Survey said today there is nearly twice as much
recoverable oil in the Williston Basin than its estimate of five years
ago.
The USGS has determined that there are approximately 7.4
billion barrels of oil that could be pumped from western North Dakota
and eastern Montana.
The last USGS study, released in April 2008,
identified 3.65 billion recoverable barrels of oil in the Bakken
formation. The new estimate includes oil that could come from the Three
Forks formation in addition to the Bakken formation.
Some have already noted: 3.65 x 2 = 7.3. The new estimate is 7.4. So I don't quite understand the GFH's reporter saying that the "7.4 is nearly twice as much." The fact is: 7.4 is more than twice as much. And then we find out that 7.4 is the "mean" number; in fact, the top line was significantly higher. [Later: now that I see more data, as provided by The Oil & Gas Journal, it makes sense why the GFH reporter said "nearly twice as much."]
We'll have to wait to see the report for the full details.
If the recovery rate is 5%, then we're talking 148 billion bbls of original oil in place.
**************************
Later, 11:57 am:
Platts is now tweeting:
USGS estimates about 7.4 billion barrels of
undiscovered/technically recoverable oil lies in the Bakken and Three
Forks tight oil formations.
I wonder where that "undiscovered" Bakken/Three Forks oil is? I assume much of it is under Harold Hamm's oil rigs, and much of it is under the multi-well pads going in. As my daughter would text: LOL.
*********************
A reader sent me a very lengthy comment regarding the USGS 2013 Survey of the Bakken/Three Forks. I am including it here for archival purposes. It will be interesting to come back in five years and re-visit this analysis:
Some thoughts regarding the recent USGS assessment of the undiscovered oil and gas in the Bakken/Three Forks.
It seems to me, based on current development, the estimate is conservative, but 7.4 billion barrels is a lot of oil!It would take average production of over 600,000 barrel of oil per day in North Dakota to produce this amount in 30 years. We know it is likely total production for the Bakken zones will continue beyond 30 years but it seems obvious there will need to be very high production in the next 10 years or so to get a 600,000 barrel average over the long term.
It also appears, USGS did not re-visit their 2008 Bakken only numbers even though new fracking and completion techniques have revolutionized development in the past five years. They added the 3.7 billion barrel estimate for the Three Forks with very little direction as to “sweet spots” or the role of the various “benches” in this zone. The only conclusion has to be the Three Forks contains a little more producible oil than the Middle Bakken alone.
I have difficulty matching the USGS study will current production results and actual drilling/permitting programs. For example, the Nesson-Little Knife Assessment Unit is an area almost 150 miles north to south and from 25 to 40 miles wide. Since the south 20 miles of this unit has not shown much promise in the Middle Bakken, I only included the 130 miles (N-S) and 30 miles average east to west. This results in 3900 square miles or 1950 1280 acre production units. The USGS Middle Bakken study shows 1.149 billion bbls of recoverable oil in this unit.
Divide 1950 units into this estimate and it results in a little
less than 600,000 barrels per 1280 acre unit. The USGS also referred to
something less than 300,000 barrels ultimate recovery for a well
draining 400 acres in “sweet spots.” Is the USGS assuming two 300,000 barrel wells per unit or three 200,000 barrel EUR wells per unit? Scanning the area from north of Dickinson to the north end of the Nesson Anticline and reviewing current production results, drilling and permitting, 2 or 3 Mid Bakken wells per unit with a total EUR for the entire 1280 acre unit of less than 600,000 barrels doesn’t seem to match with reality. Many units approach or exceed this total in their first two or three years of production.
I did a similar study of the Central Basin Assessment Unit. This unit may make sense from the geological perspective but actual drilling and production results vary greatly. A large portion of the this AU in North Dakota is in the “sweet spot."
The Montana segment has had less drilling and less impressive production results so far. In North Dakota this AU has about 1,625 1280 acre drilling units. If you allocate 90% of the undiscovered oil in Central Basin Unit to the North Dakota units, you again get about 600,000 barrels of recoverable Middle Bakken oil from each 1280-acre unit. From an economic unit perspective this would be about two Middle Bakken wells per unit.
Continental Resources would be through drilling with one per unit with their 603,000-barrel-per-well estimate. (I think this is very optimistic, but 350,000 to 450,000 bbls of oil per well in “sweeter spots” seems more reasonable).
I will concede that the 2013 USGS numbers might be “spot on.” Time will tell. For me, I will pay attention to what current operators in the Bakken are doing. These operators most certainly have their own set of numbers for the acreage they control. The actual pay-out of these wells will determine future development. Theory and analysis are important but cannot replace actual results.
Perhaps clarification from USGS concerning recovery by 1280-acre unit will help in understanding their methodology.
Finally, I’ll say it again: “7.4 billion barrels is a lot of oil!"
I think the official USGS estimate for recoverable oil in the Bakken is about 3 billion barrels, based on an old study; I think the last study was done in 2008, but I've lost track of a lot of this stuff. Hardly matters any more, does it?
Continental Resources is pushing the envelope, estimating as much as 24 billion bbls recoverable oil in a trillion-barrel original-oil-in-place shale reservoir.
According to Fox Business, NDIC puts the number at 6.5 billion bbls recoverable oil. To date, slightly less than one-fourth billion bbls have been recovered. So when four times the current total produced has been shipped, the Bakken will still be less than a billion bbls recovered. Then, only 5.5 billion more bbls to go ... and that's the NDIC estimate. As noted above, Harold Hamm suggests 24 billion.
Alison Ritter with ND Oil and Gas can't
confirm or deny the news because it's a confidential well.
But she says
if oil is being recovered from the third bench.
There were wells at certain points in history, the
EOG well in 2006 and the Brigham well in 2009 that when you look back
yes those were historical breakthroughs.
Did we know how big at the
time? Maybe a little bit. Could this Continental well be something
like that? You never know but there certainly is that potential there
that two or three years from now we look back and say that Continental
well really told us something about what was going on with the Three
Forks," says Alison Ritter with North Dakota Oil & Gas.
Continental Resources Inc. (CLR), the largest owner of oil-drilling rights in the U.S. Bakken Shale, said the formation holds about 57 percent more crude than previously thought. The shares rose the most in more than three months.
The formation beneath North Dakota and Montana holds the equivalent of 903 billion barrels of so-called oil in place, compared with the company’s 2010 estimate of 577 billion, Oklahoma City-based Continental said in a statement today.
The Bakken’s potential expanded after the company was the first to successfully tap a deeper geological layer of the Three Forks zone, according to the statement.
The breakthrough at the Charlotte 3-22H well represents the second exploration triumph in as many months for Chairman and Chief Executive Officer Harold Hamm.
The company announced a discovery known as the South Central Oklahoma Oil Province, or SCOOP, on Oct. 9 that may add 1.8 billion barrels to Continental’s reserves in coming years.
It's hard to get a handle on the "official" estimates of original oil in place in the Bakken, but it appears that the "official" estimates have increased, Link here to an earlier discussion of OOIP: about 150 billion bbls.
Now, in the story linked at the top of this post, it appears "they" have increased this estimate to 170 billion bbls.
These numbers (150 billion bbls and 170 billion bbls) are still significantly less than what Leigh Price originally suggested and what Harold Hamm appears to be suggesting.
Everyone agrees that with primary production, "we" are recovering somewhere between 2 percent and 8 percent of the OOIP in the Bakken Pool.
Harold Hamm has opined that as much as 24 billion bbls is recoverable from the Bakken Pool.
There are estimates that, before it's over, 50,000 wells will be drilled into the Bakken. The average EUR in the Bakken is estimated to be 500,000 bbls.
This looks like a press release, but it's a huge story, nonetheless, at the Bismarck Tribune.
BNSF has created a special Unit Energy Desk to plan trains to and from the oil patch, with unit trains up to 118 oil tankers.
BNSF has increased its capacity to haul up to 1 million bopd out of North Dakota and Montana. North Dakota now ships in excess of 660,000 bopd, the most recent reporting period in June. Pipeline capacity is 450,000 bopd. Another 200,000 bopd of pipeline capacity will come on line by the middle of next year, but the gap between pipeline capacity and production will continue to widen before it narrows, according to the linked story.
BNSF currently has eight oil terminals with two more coming on line this year. [There are currently 16 CBR facilities in North Dakota; I don't know if "two more" is part of the sixteen or are we looking at 18 CBR facilities?]
BNSF says it has invested almost $200 million, and has hired more than 560 employees to fill existing and new positions in North Dakota and Montana.
"BNSF has been hauling Bakken crude out
of the Williston Basin area for over five years. In that time, we have
seen the volume increase nearly 7,000 percent, from 1.3 million barrels
in 2008 to 88.9 million in 2012," said Dave Garin, BNSF group vice
president, Industrial Products.
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.]
********************
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)
********************
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."
I was sent this presentation on the Three Forks formation. It's a PDF file so it might take a few minutes to download depending on your internet connection. I don't know where it was originally presented or posted. It is undated, but most likely very current since much of the information about the Three Forks Sanish has only recently been sorted out. I first received it May 24, 2010. This is the second time it's been sent to me.
The author is Stephan H. Nordeng, NDGS.
The source rock is the upper and lower Bakken shales, which includes the upper fifty feet of the Three Forks formation and probably the lower fifty feet of the Lodgepole.
Note the relationship of the Lodgepole, Bakken and Three Forks on the second slide.
The Bakken source rock has a very high total organic content (TOC) -- as much as 11%. To put that in perspective, Schlumberger says that most source rock has a TOC of at least 0.5%. "Very rich source rock might have a TOC as high as 10%" according to Schlumberger -- and, again, the Bakken has a TOC of as much as 11%.
Slide five: note how far east and south the Three Forks Sanish in North Dakota extends; east, well beyond Minot, and south all the way to the North Dakota/South Dakota border (the TFS extends into South Dakota, west into Montana, and north into Canada).
Slide 28: when you look at slide 28, you can see graphically where the bulk of the oil in place (OIP) will be found. The "bulls-eye" or the very center of the basin is northeastern McKenzie County and southwestern Williams County. It's interesting that the Parshall oil field is fairly east of this center but yet has been so prolific for EOG. It makes one wonder about the potential yet to be seen in Williams and McKenzie Counties.
Slide 30: This is the slide that should knock your socks off. It shows the original amount of oil in place (OOIP) in barrels, and the estimated ultimate recovery (EUR) based on available technology. As predicted from slide 28, McKenzie County has the most OOIP, followed by Williams, and Mountrail, and then come Dunn, Divide, and Burke (6th).
McKenzie is by the far the biggest county. Williams, Dunn, and Mountrail are about the same size. Burke and Divide are each about half the size of Williams or Dunn, so on a per acre basis, I would bet the OOIP for Burke and Divide is similar to that of the very prolific Mountrail County.
Now in round numbers, here is the OOIP for each of these five counties (Bakken plus TFS):
McKenzie: 36.4 billion boe
Williams: 28.9
Mountrail: 28.9
Dunn: 20.1
Divide: 17.7
Burke: 17.0
Again, in round numbers, here is the EUR for each of these five counties (Bakken plus TFS):
McKenzie: 737 million boe
Williams: 714
Mountrail: 576
Dunn: 475
Divide: 200
Burke: 375
Finally, the EUR/OOIP ratio, as a percent:
McKenzie: 2.0%
Williams: 2.5%
Mountrail: 2.0%
Dunn: 2.4%
Divide: 1.1%
Burke: 2.2%
I do not understand the low percentage for Divide County.
But, in general, the USGS assumes that about 2% of the OOIP will ultimately be recovered. In fact, it appears that drillers are getting close to 3 or 4 percent. In some corporate presentations, the companies are suggesting they are getting as much as 8 percent (if I remember correctly; I have to confirm that). But my hunch is that the 2% figure provided by the USGS is a very, very conservative figure.
