Post From Dinar Speculator By Charlie: SHALE OIL OVER-HYPED Part 2
This post goes along with & compliments previous chats & posts by Charlie educating us on the different aspects of Oil and how it affects us from an energy standpoint as well as a financial one - Links to previous chat will be at the end of Part 2
The Shocking Data Proving Shale Oil Is Massively Over-hyped
David Hughes: Yeah. The actual peak before 2020 was for the two top plays, which are the Bakken and the Eagle Ford. The Bakken and Eagle Ford make up 62% of current tight oil production.
So those are really the two biggies. I also went through Permian Basin plays. But the Permian Basin is unlike the Bakken and Eagle Ford; the Permian Basin is really a very old place.
They have been around for 40 to 60 years. Other plays like the Niobrara and the Austin Chalk would fall into that category too. So these are really old plays that we have known about for a long time and they are redeveloping them with better technology. With fracking.
The Bakken and Eagle Ford are unique in that they kind of rose from nothing. They're true tight oil shale oil plays. I was able to do forecasts for those two for tight oil and for the Permian basically I just looked at all of the historical data. I didn’t actually make projections.
But if you look at the Bakken and Eagle Ford, the two most important tight oil plays in the US, I went through those and did the same scenario based on drilling rate and looked at the most likely scenario.
So for example, for the Bakken, not withstanding the current low oil prices, I assume that the drilling will continue at 2,000 wells per year and then gradually fall to 1,000 wells per year as they move into the outlying, low quality parts of the play.
And if you do that, Bakken production rises to about 1.2 barrels a day. In or around 2015, 2016 you get a peak followed by a long decline. Same thing for the Eagle Ford. The Eagle Ford is actually the number one tight oil play in the US right now. They are plowing 3,500 wells per year into Eagle Ford.
Yeah, its just incredible, it’s 10 wells per day. And I assumed that drilling was going to continue at that rate and gradually decline to about 2,000 wells per year as they move into the outlying parts of the play.
If you do that, it peaks considerably higher. I am just trying to think right off hand… I think my most likely scenario was around 1.4 to 1.5 million barrels a day and that will happen around 2016, 2017.
If they ramped up drilling in Eagle Ford they could go much higher. They can probably top out at 1.8 million barrels a day. Also the Eagle Ford produces a lot of associated gas.
So there is a lot of value in those wells. You look at the trajectory, peaking in 2016, 2017 and declining. When you add up the production in 2040 in the Bakken and the Eagle Ford compared to the EIA forecast for the Bakken and Eagle Ford, mine are less than a tenth of the production in 2040.
Chris Martenson: Less than a tenth.
David Hughes: Less than a tenth. The other interesting thing is the EIA seems to have underestimated short term production. So my projections are actually for higher production early on and a higher peak than the EIA. But you know, much worse scenario down the road. Much lower productivity by the time you get to 2040.
Chris Martenson: This is interesting. I assume you have read or heard of the University of Texas at Austin study on shale gas that concluded that US government estimates of the amount of natural gas that can be extracted by fracking are far too optimistic and that shale gas production will peak in 2020, I think they put it, and decline rapidly. As I understood it what they did is they didn’t look at county level resolution.
They broke down all the plays into square mile resolution, which some counties are thousands of square miles. So this resolution is much higher and that helps them identify sweet spots or not sweet spots more accurately, I assume. So I am wondering, did you read that?
And how did their study conclusions differ from yours or do your conclusions match? Then given your answer to that, what is the EIA doing wrong, or what should they consider amending in their approach to be more realistic. So first on the study – did you see it and how do your conclusions match?
David Hughes: Oh yeah, I've got a detailed comparison in "Drilling Deeper" between my work and UT's work and they are very comparable. You know, if you look at the section by a square mile by square mile resolution, you can do that but in fact the critical parameters — one of the key parameters you get for every well is IP, right?
That is the highest one month production or the highest six month production of every well, which I mapped, which gives you a pretty good idea of where the sweet spots are.
There is a lot of other parameters you can look at for shale gas, thermal maturity, organic matter content, porosity, natural fracture density, things like that, but those parameters are not measured at a square mile resolution. They are measured generally at a much broader scale.
So I think that you can do a pretty good job at the county level, which is the level that I took it — and parts of counties. When I looked at the total play area, I looked at the boundaries between productive wells and non productive wells so we could put a limit.
I only used that portion of the county that was productive in determining the productive play area.
When I did the comparison I talked to Scott Tinker at UT. Basically their base case and my most likely case are very close.
There are only two studies that they published so far – the Barnet and the Fayetteville — so I did a detailed comparison. In fact, they may be a little more pessimistic than me in some cases. But you know, we are in broad agreement that the EIA is wildly optimistic.
Chris Martenson: What would the EIA need to do to become more realistic?
Where are they – we know that the – so I mean we know the EIA in the case of the Monterey shale they turned to a private firm and just did some back of the envelope calculations and then had to downgrade the Monterey estimates of what that reserve was going to be at by 96%.
Something that you had come to a conclusion a long time before. Obviously the EIA had some methodological issues or they relied on the wrong parties in the case of the Monterey.
But more generally, what is the EIA doing that is giving them these inflated estimates do you think?
David Hughes: I scratch my head about that. If you go through "Drilling Deeper," — it's a free download for your guests or audience — I've done a comparison.
The Barnett, my most likely case, compared to the EIA; it is really kind of bizarre. The EIA agrees that the Barnett peaked in 2012 and it is going to decline but then they have a ramp up to nearly the equivalent of the 2012 peak in 2040. So it doesn’t fit with the fundamentals of the play.
The only thing I can think of is they have a phenomenal faith in technology. That somehow someone is going to pull a technological rabbit out of his hat.
Same thing if you go through play by play I have done the comparison. One of them I think the Bone Spring in the Permian I think the EIA is too conservative, but every other one they are way too optimistic.
Chris Martenson: Well this is really important because as I look at it I see chemical companies and power utilities, all of them investing tens, hundreds of billions of dollars in new property, plant, and equipment.
Investments with 40, 50 year life cycle horizons. Because they are taking advantage of, I am quoting here, "100 years of cheap, natural gas," mostly from the shale plays. If you were going to advise these companies, what would you – would you tell them that you think the EIA's assessments are not the ones they should be using?
David Hughes: Absolutely. And that is one of the reasons I was so interested in doing "Drilling Deeper." And I have laid out, if you go through it, there is 20 pages a play and a lot of the basic fundamental data that has never been available is there in charts and graphs. Let’s just take a play like the Bakken.
45% field decline, sweet spots are getting to be drilled out. We know that they need to drill 1,500 wells a year just to keep production flat.
But as you go into lower quality rock and the well quality in most of the plays is only about half of what it is in the sweet spot. If you have to rely on the lower quality price of the play you need 3,000 wells per year instead of 1,500 to offset the field decline. But the wells aren’t any cheaper.
They cost the same amount to drill. Obviously you need a lot higher prices in order to make that happen. And you can go through play after play and see the same thing.
We are drilling the best parts of the plays now and it is just going to get worse down the road. We are going to need higher and higher prices.
The EIA has not only made what I consider really optimistic estimates on production, they have also made optimistic estimates on price. A lot of the infrastructure that is being built as you say is based on the assumption of cheap prices for the foreseeable future. That is not in the cards.
With cheap prices, we are going to see production go down a lot faster than my estimates. My estimates are best case, so I assume that the capital will always be there to drill the wells and that there will be no environmental concerns that restrict access to drilling locations.
So in that way I am best case. Even if you look at my best case, that will be rather disturbing to me if I was a petro chemical company or somebody that was investing a lot in gas fired generation.
Chris Martenson: Alright. Let me test one of the assumptions then. There are a couple of key assumptions that are really driving the overall scenario then. First is going to be the decline rates of each wells and that leads you to say here is why we need to replace 1,500 wells. Let’s start there with that decline rate.
I was reading this Bloomberg article yesterday and I am quoting here, “Shale production will keep growing because the rate of decline from wells has been overstated, Ed Morris, head of commodities research at Citigroup said."
So I am already reading things where they are tossing out that decline rates have been over estimated, but when I read your report what I saw is that you didn’t estimate these decline rates; you measured them, right? So what is the difference between these? Did you estimate them?
It looked to me like a measurement. Like you just said "let’s sum up all of these wells by vintage and see how fast they decline." That’s not an estimate. That is more of a measurement. What do you think the disagreement here is?
David Hughes: Well, if you want an optimist, Ed Morris makes the EIA look like the most conservative organization on the planet. He has always been wildly optimistic. If you look at his latest forecast for tight oil, we're going up to 7 million barrels a day and it is just going to stay there forever.
I am not sure what Ed uses to make those kind of statements, but what I used is every well. My decline curve for the play in every play is all the wells in the play.
I looked at the most current five years worth of drilling. I also looked at well decline curves in every county. You know, all of the top counties at any rate in every place. That is data. It is just nothing imaginary about that.
Chris Martenson: Alright. So you feel like the well decline rate is something we have a handle on, we can model that. We have enough data out of the big plays, the Barnetts, the Fayettevilles, the Eagle Fords, Permian, Bakken — we've got enough. Maybe even Marsalis. We have enough data now to say, "Hey this is kind of how this plays out." Is this a fair statement?
David Hughes: That is a very fair statement.
Chris Martenson: Cool alright. So second big piece – the second big factor I have some confusion around is how much oil is ultimately going to flow from a well, which goes by the acronym EUR, the ultimate recoverable amount of oil.
I've got to tell you David, the typical EURs that I am still reading in the newspapers from the Bakken wells, they just toss around this 500,000 barrel amount; it is a lot of oil. And looking in "Drilling Deeper" I found a table you had your EURs that averaged 378,000 barrels a well. That is a big discrepancy. How do you explain that one?
David Hughes: I think if you look at — was it the Bakken you are looking at?
Chris Martenson: Yeah.
David Hughes: I think if you look at counties like Montrail and McKenzie they are higher than that. And if you look at the outlying counties like Divide and Richland they are much lower than that.
I can’t recall — I think the Montrail and the McKenzie are about 400 and the Richland and Divide and some of those are down sort of in the low 200s. So overall they may average 378 like you say.
Chris Martenson: Yeah. That was your total. So how did you derive your EURs? Was that by taking the decline rates and extrapolating them out and coming up with some idea of how long these wells will persist?
David Hughes: Yeah. The bottom line is nobody knows how much oil is going to come out of those wells until the last barrel gets pumped. So it is an assumption, right?
You fit a curve – most companies fit a hyperbolic curve or some combination of hyperbolic/exponential. What I did is I used the actual data for the first four years.
So the decline curve for the first four years in a play like the Bakken is pretty solid, you know, it is not much doubt about that. So I took the data for the first four years — how much oil is that cumulatively?
And then I fit a 13% exponential decline after that, assuming the well would live to be 30 years old, which is a totally unproven assumption.
But for the sake of comparison so I could at least compare the EUR between counties. I used a 13% exponential decline. That number is certainly arguable.
If you look at the decline in year four in the Bakken it is probably about 20%. So using 13% as a terminal decline is maybe optimistic.
The other thing that if you look at those EUR diagrams in "Drilling Deeper," you will see I have denoted the amount of oil that is produced in the first four years versus the next 26 years, and typically 50 to 60% or more of a well’s total oil will be produced in the first four years.
So you know, if you are in a sweet spot you can make your money back pretty quickly. That is one of the beauties for oil companies about shale wells. The downer is we don’t know if it will only last for 12 years, and that assumption of total EUR is just that, an assumption.
I looked at the Barnet and 4,000 wells are no longer producing and their maximum life is only about 10 years. Their average life is something like four years.
So you know, anybody that tells you a well is going to produce this much oil is really kidding you. It is only an assumption at this point in time.
Chris Martenson: The Barnett is mostly, it is all gas right? So maybe the gas plays will be different, but this is astonishing to me, David, the astonishing thing is that the Barnett really started getting drilled hard in what, 2007-ish maybe, 2008?
David Hughes: Or the Bakken, you meant?
Chris Martenson: No, I was thinking of the Barnet. When did that start getting drilled?
David Hughes: Oh okay. It really got started in the late '90s for the Barnet. I mean it really ramped up after about 2003, 2004.
Chris Martenson: Right, but that’s just like 10 years ago that is when the ramp up started and the peak happened on that gas play within a 10 year window, let’s just say, and so obviously the Bakken is going to be different because there is still what 24,000 well sites that can be drilled.
That will just take time. At 2,000 wells a year we still got 12 years of drilling. So it is going to take some time for that to really — there is plenty of room to continue that drill program, but it is not forever.
And so this is the part I really want to get to is this idea that somewhere before or around 2020 even these shale plays now are in decline from a total production standpoint.
And as far as I’m concerned, because I am 52 now, that is like tomorrow. Time seems to go faster as I get older. So this is really soon as far as I am concerned and my concern in trying to publicize all this is we got the data, you have done this incredible work, there it is.
There is really nothing to argue about with decline rates. We can quibble a little about the EURs. We can talk about how close the wells might be spaced, but really we are sort of wiggling a little.
We are not going to get 100 years of gas. We are not going to get 100 years of increasing oil production out of this whole thing, Ed Morris’ weird graphs not withstanding.
So my concern is that this is really, really important because so many decisions are being built in this country around this idea that we have solved this energy crisis and it is now in the rear view mirror, but it is really not is it?
David Hughes: Absolutely not. I have been on that same theme there Chris for many years. Corporations tend to think about the next couple of quarters.
Politicians may think about the next election, but this is an energy plan, an energy sustainability plan has to have a vision of decades and we certainly don’t see that in all the hype we read every day.
Chris Martenson: If I had my magic policy wand I would say "great, we can pretty much add up how many trillions of cubic feet of gas we think we are very likely to get at a certain price and here is how many billions of barrels of oil are left and these are two finite numbers."
And then we would take those and we would go "where would we like to be when those finally run out" — or nothing every fully runs out, but we are going to have a blob of energy that we get to use over this next period of time, let’s call it 10 or 20 years, and then it is largely gone at that point in time.
Dregs remaining. That is what I would love to have a conversation. Where do we want to be in 10 or 20 years? Because business as usual will get us to a place where we have a lot of infrastructure that can’t be supported any longer because we don’t have the goods for it.
This is the part where I get in arguments all the time, people go "oh but we are so swamped with natural gas that look it drove prices down. It just proves that technology will always find a way."
My response to that is: "Did you know that we still in the United States are a net importer of natural gas?" And most people don’t know that part because they hear we are making LNG terminal decisions because we have so much that we better just export it. It is just astonishing to me that the data that you have and the public perception it is still pretty far apart.
David Hughes: Yeah, it is. You know, I think that if you look at the mainstream media, I don’t think there is a lot of original research that is done there.
I think people tend to repeat what other people have said and it kind of takes on a momentum of its own. Which is why I was so interested in trying to lay out as much of that data as I could. It is dangerous.
I mean if you look at the infrastructure going forward in an era of declining oil and gas, the number one way to promote energy sustainability in my view is figuring out ways to use less.
And some of the infrastructure that needs to be built in order to give people an alternative to high energy throughput lifestyles takes a lot of oil and gas to build. And you know, this short term bounty that we are looking at should in fact be used to do that, not to maintain business as usual to the bitter end and then face the consequences.
Chris Martenson: I agree. I agree. Final question – and thank you for your time, so generous.
Final question is: What is the reception to the report? Has the EIA reached out? Have any government people talked to you? Is industry wanting to know more? Tell me about how it has been received so far.
David Hughes: Well, I sent a copy of the report the day it was published to John Staub at the EIA who is the head of the oil and gas team and I didn’t hear anything back.
I sent it to Scott Tinker at UT and he was pretty enthused and sent it around to his team. So they are certainly looking at it. In terms of the mainstream media, they really didn’t have a lot of major coverage of it unfortunately.
In terms of the industry, if you look at the industry lobby group, Energy in Depth is a lobby arm of the Independent Petroleum Association of America.
They took special pains to write an attack article on it. They didn’t really criticize any of the data in it. They sort of had to resort to ad homonym adjectives that apply to me, which wasn’t appreciated.
I think if you look at the second tier of media, we did get an awful lot of coverage and none of it really negative that I can see. I think the data that is in Drilling Info is data that is not available anywhere else. This is data that industry uses, but it has not been widely made available.
I am hoping that "Drilling Deeper" will have a long shelf life and people will be able to refer back to it again and again. Hopefully it will promote a bit of saner thinking in terms of our energy future going forward.
Chris Martenson: At a minimum I would hope that the good people who are running the state of North Dakota would take a look and plot a strategy based on the likely arc of their industry because it is completely calculable.
As long as they have a long-term view of that and understand where they are going I think that would be great. Listen, thank you so much for your excellent and data driven work and for your time today.
I will note that we will have a link to "Drilling Deeper" at the bottom of this podcast. People if you look at the bottom of this page you will see it right there and that will take you over to the Post Carbon website and a download. And you should read it.
You should check it out. If you like your data and you love it done well and analyzed well and with good writing around it, this is an absolutely essential report because everything depends on the energy story as we go forward and boy the disinformation out there is just magnificent right now and "Drilling Deeper" and other work by David Hughes is state of the art.
It is great stuff. So please everybody take a look at that and David thank you so much for your time today.
David Hughes: It's been my pleasure, Chris.