Post From Dinar Speculator By Charlie: SHALE OIL OVER-HYPED Part 1
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
Transcript of Podcast
Chris Martenson: Welcome to this Peak Prosperity podcast. I am your host Chris Martenson. Today there really is no more important story than what is happening to the price of oil. Now just like in 2008 oil has been plummeting catching everyone including this analyst by surprise.
West Texas intermediate crude, the WTIC blend I am looking at right now at $58 and a few pennies here. Right here on the 12th of December. And the airwaves are packed with commentary.
And the print media are churning out copy to explain all of this to us. Mostly with the spin that the price plunge is due to US shale oil flooding the world markets.
And most are going out of their way to even find Wall Street analysts who make the claim that shale oil is profitable at $70, no $60, no $50. In fact, I even read last week one analyst claim that $25 a barrel was profitable in the shale plays.
Now why does all of this matter so much? Isn’t lower oil prices, aren’t those good for consumers and should we see all of this maybe as a gift? Well, yes for now.
But unfortunately not in the sense that in the near term a lot of shale oil and shale gas companies are going to go out of business because they were not profitable when oil was 40% higher.
And they are therefore even more unprofitable today. And over the longer term we see oil projects getting pulled left and right today.
Deep water plans have been shelved. Capital cut backs have happened in the oil sands and this means that future production will be lower than if oil prices had remained elevated. So a little consumer happiness today potentially followed by damaging oil shortfalls in the future.
The shale story, however, is weighing on this and it is not a simple story as the media likes to portray. It is more than plucky American can-do ingenuity turning straw into gold.
To really understand the shale oil future we need to understand that not all shale plays are created equally. And that within each play some regions are sweet spots and others are relative duds.
We need to know that these wells deplete horribly quickly. And that the very process of drilling these wells creates all sorts of above ground troubles, including road and bridge damage and airborne fracking aerosols that drift about harming humans and animals alike.
Now possibly, worst of all, is that the nation if not the world has latched onto the shale story as if it were some permanent savior from the unpleasant task of facing up to the idea that oil is a finite substance.
To help us understand all of this we could not have a better guess today than David Hughes, a geo-scientist who has studied the energy resources of Canada for nearly four decades including 32 years with The Geological Survey of Canada as a scientist and research manager.
Now it is his work with The Post Carbon Institute that has really caught my eye. That includes "Drill Baby Drill," a 2013 report. Probably the most comprehensive, publicly available analysis to date of the prospects for shale gas and tight oil, as shale oil is usually called in the United States.
"Drilling California," which was the first, first publicly available empirical analysis of actual oil production data from California’s much promoted Monterey formation and the subject of today’s discussion, "Drilling Deeper," which is a reality check on the Department of Energy’s expectation of long-term domestic oil and natural gas abundance. Welcome, David.
David Hughes: My pleasure, Chris.
Chris Martenson: Well, David I want to – really, I am very excited to have this conversation with you. And I want to help our listeners understand what is truly possibly in the shale plays. Obviously there is oil there.
There is gas there. We are getting both out of the ground, that’s true. But I need to cut through the marketing copy and even outright industry propaganda that has muddied the waters so that our listeners can make some informed decisions. Now let’s focus on "Drilling Deeper," your most recent study.
Tell us about this study. I want to know what it included, how it was conducted and for example, what sorts of data did you use to perform the analysis? What can you tell us about how you put this report together?
David Hughes: Well, we had access for the first time really to the EIA’s play by play forecast which was published in the "Annual Energy Outlook 2014."
And what I wanted to do is look at those forecasts and basically do a reality check on them.
So what we did is we looked at the top 12 shale plays that basically account for 88% of shale gas production. In the EIA’s forecast 82% of tight oil production. We went through that play by play.
The data source was Drilling Info, which is a commercial database out of Austin, Texas, that is used by the EIA and it is also used by most multinationals.
And it contains basically all of the well production data on a play by play basis. So one can take it apart at the play level and one can also take it apart at the county level within plays.
So I was interested in looking at the – as you referred to, all plays are not created equal. And even within plays all counties are not created equal. So we wanted to do things like you know, characterize well quality, what is the average productivity by county, by play. What are the decline rates?
Both well decline rates which are very steep if you look at a tight oil play like the Bakken for example. The average three year decline is about 85% in production. The average first year decline is about 70%.
Declines tend to be hyperbolic in all shale fields. The first year is the greatest, the second year is a bit less. Third year a bit less. So if you look at the decline of the field, which is really a combination of new wells declining quickly and older wells declining slowly, you can compute a field decline.
And so for a field like the Bakken the decline is about 45% per year, which means that 45% of production has to be replaced by more drilling in order to keep production flat.
So if you know the average rate of production for the first year of wells in a play it is quite easy to calculate the number of wells you need to drill in order to keep production flat.
And for a play like the Bakken that is about 1500 wells per year are needed just to keep production flat.
So in round numbers at $10 million a well you need to put in about $15 billion a year to keep production flat on the Bakken. Production is growing in the Bakken and that is because they are drilling 2,000 wells a year. They are 500 wells to the good in terms of growing production.
However, the higher production grows the larger the chunk that 45% drill decline takes. So you need more and more wells in order to offset decline. So basically, what we did for each of those plays is put all of that information into a spreadsheet.
So we know what the well quality is in the sweet spots and we know what the well quality is in all the rest of the play. And typically sweet spots may be 15 to maybe 20% at the outside of the total play area.
So we know that fundamental law of oil and gas companies is they drill their best locations first.
So the wells are going into the sweet spots today, but as drilling locations are used up in sweet spots they are going to have to go more and more into lower quality rocks. We can put all of that into a spreadsheet and come up with production forecasts going forward.
Chris Martenson: So this spreadsheet then, this is at the individual well level? So like well has a code that is associated, some alpha numeric code and says this is well XJ55 or whatever and you had each of those in a spreadsheet so they were sorted I guess by time so that you would have –
I mean there are thousands and thousands of wells drilled in the Bakken and some of them get started to be drilled in what 2007? And then there is a vintage in 2008, 9, 10 so did you have all that data available?
David Hughes: Yes. So for a play like the Bakken we had all of the producing wells up until about July of 2014. "Drilling Deeper" was published in late October. We tried to keep it current to mid 2014. So we had every well that was drilled from year 0 in all of those different plays.
In terms of making the forecast, basically we used the average production over the first year which allowed us to determine the number of wells that you need to offset that 45% decline.
And you know, in the spreadsheet you start off assuming—in the case of the Bakken you know, engineering companies are telling us that well technology is getting better and we are making those wells more productive.
I actually was doing a check on that for every play. I looked at the average productivity by year from 2009 until 2013. So you can see if in fact, it is going up or if it is not going up.
Chris Martenson: This is per well productivity, right? So that is what we really care about is productivity of the wells and just at this point I need to interject.
I think that the EIA has muddied the water to turning to what they call "per rig" productivity and saying people have thrown this at me a lot lately "oh 300% productivity improvement."
No, no, no that is a process improvement because what they have done is they managed to figure out ways to drill multiple wells off a single pad. And they have these things called walking rigs which allows each rig to spend less time in transit and more time drilling.
So we are drilling more wells, but what you are talking about is the per well productivity, which is what we really should care about, right? Because if we are getting more oil out of each well then yes, there is more oil coming out of the play. But if we are drilling more wells faster that is not the same thing. So you are talking about per well productivity, right?
David Hughes: Absolutely.
Chris Martenson: So what do you see there?
David Hughes: You know, the other thing is how many wells could you drill in a play? That was another fundamental parameter that we looked at for every play. If you look at investor’s presentations there is a lot of talk about down spacing. How close can you space these wells before you get interference.
There is a – what I thought was a really good paper published by an engineer at Drilling Info who looked at the Bakken in terms of down spacing. In essence if you drill two wells 300 feet apart, initially the productivity will likely be very high. It would likely be comparable between the two wells.
But if you look at it over 12 months or 24 months you can start to measure the interference so one well is cannibalizing another well’s oil. And the drilling info paper basically said below about 2,000 feet spacing you are starting to see interference if you look at a 12 to 24 month timeframe.
We made assumptions about how many wells you can drill in a play. For a play like the Bakken we assumed when the play is said and done you can drill about 32,000 wells.
There is 8,500 producing wells right now. We felt you could drill four times as many wells as are there right now. That is a key fundamental parameter in making the forecast.
So if rigs are more productive, sure you can drill those locations out quicker, but you don’t necessarily get any more oil at the end of the day. It is per well productivity that counts at the end of the day.
Chris Martenson: Let me talk about that per well productivity then. This is a central part to the story that is out there. So I want to make sure we get this right.
So a typical Bakken well they drill down whatever 10,000 feet, slant it sideways. And then they go sideways in this big horizontal stage and I guess how much we get out of a well is going to be a function of a number of things. One, the underlying geology that is just true for that rock.
Two, how long of that lateral we drilled? Is it 5,000 feet? Is it 10,000 feet? That makes a big difference in the collection area. Then I guess are we doing a five stage frack or a 30 stage frack?
So how much we shatter that rock up. All of that sort of plays in and I assume that are playing with all of those parameters over time. But you have got data that showed these wells by year.
And if we really were — I don’t know how you would factor out the longer drilling and the more fracking, but how much additional oil are we seeing coming out of the wells because we have made improvements to the drilling techniques and the fracking techniques? How much is that?
David Hughes: Well, it depends on the play. And it depends on the region within the play. So if you look at the Bakken the average well that was drilled in the Bakken went up about 7% from 2011 to 2013.
That is a combination of better technology, as you say longer horizontal laterals, more frack stages, higher water volumes, more propping and it is also a function of people drilling in the sweet spots.
It is hard to differentiate the two. I think it is a combination of both; better technology and drilling in the sweet spots.
So for a play like the Bakken we say okay, we are looking at a slight improvement in well productivity.
So I’m going to assume that is going to continue for another year or two before people start to have to drill in lower quality parts of the reservoir. And from peak well productivity, well productivity will decline as you go into the lower quality rock. The technology is never going to make up for bad reservoir rock.
The Bakken is still quite a young play. As I said, they have only drilled about 25% of the total potential locations. So there are still locations in the sweet spots. Well, those are running out fairly quickly.
If you look at an older play like the Barnett which is a shale gas play in Texas and that is where fracking really got its start. Well quality peaked in 2011. So they drilled about 20,000 wells in the Barnett now.
4,000 of those are no longer productive. Well quality peaked in 2011 and it is now down 17% from peak.
So if you look at the top counties in the Barnett they are finished .There is already eight wells per square mile and drilling has to move into lower quality rock. Production of the Barnett is now down 18%.
In a mature play like the Barnett you are really seeing the fact that geology wins out every time against technology, despite what Halliburton and some of these companies will tell you.
Chris Martenson: Now one quick thing on the Barnett. Somebody said to me once, "well that’s because natural gas prices are at say $3 to $4.00 per NCF. But if natural gas prices went back up to $10 or $12.00 from its current $3 to $4 that people would start punching more holes into the Barnett."
That is the slow down in the drill program accounts for that decline, but they could ramp it back up again if prices were higher. We know price is always a function in this story that is lurking out there.
How much do you think the Barnett would be sensitive to additional price improvements and people drilling more, and how much do you think it is past its prime, it is already done?
David Hughes: Well, I looked at that. And that is true to a certain extent – the drilling rate in the Barnett is down. It is only about 400 wells per year right now. So in every play drilling rate is the key parameter.
How fast you drill determines what the production profile looks like. So in every play I get at least three and sometimes four different scenarios of drilling rate.
And the Barnett I – my low scenario is we just keep drilling 400 wells per year. What does that look like in terms of future production? My most likely scenario is the price of gas is going to go up a bit and drilling will be bumped from 400 to 600 wells per year.
And then it will gradually decline to 500 wells per year to move into the lower quality parts of the play, which they are already moving into.
But I also did another study, another projection that said okay what if quintuple drilling rates in the Barnett? If we go from 400 to 2,000, which is what it was at its max back in about 2008.
And if you do that you can certainly stop the decline and reverse it to a new peak. That new peak would happen in about 2016. You know, if we instantaneously increased the drilling rate by five times.
However, when you look at the total production out to 2040, it doesn’t change the cumulative production that much. All you do, if you drill faster, you get it quicker.
So if you look out through say 2020-2025 in that quintuple drilling rate scenario, all of a sudden production falls below what you would have got if you follow my most likely scenario. So there is no free lunch.
You can drill fast and get it quick and then suffer the consequences later. Or you can drill at what I consider the most likely rate.
I went through that scenario for all the plays and then stacked them all up and compared my most likely scenario to what the EIA projected.
Chris Martenson: Okay. I am going to assume given the current prices that we are going to fall below your most likely scenario for a while just because prices aren’t supportive of a real robust drilling program right now.
To get back to drilling deeper—among the major conclusions of your report were that shale oil would peak in output before 2020. I think the EIA is roughly in agreement with that.
But where you disagree with the Energy Information Agency, the EIA, is that you feel they have overstated the amount of oil that the US would produce by 2040 by a really very wide margin. I want to understand those conclusions. So let’s break them down.
First, talk about the peak in shale oil happening before 2020. How did you arrive at that conclusion? I understand that you’ve modeled this. You have ran a variety of scenarios.
When I say "shale oil peaks before 2020," I assume that is under your most likely scenario. Let’s talk about that scenario and what the implications of that are. So do you still see a peak before 2020?
Comments may be made at the end of Part 2 Thank You