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The Shocking Data Behind Shale Oil

December 16, 2014

Hooray, oil is suddenly much cheaper than it used to be. That’s great news, right?

Not so fast. For certain it’s not good news for those counting on a continued rise in US oil production from the "shale miracle". Many drillers were challenged to operate profitably when oil was above $70 per barrel. Very few will remain solvent with oil in the $50s (as it is as of this writing).

Drilling America image via shutterstock. Reproduced with permission.

Drilling America image via shutterstock. Reproduced with permission.

So, expect US oil production to suffer from these lower prices if they persist. But even if oil prices rise and rise soon, there’s new data that indicates the total amount of extractable oil from America’s shale plays is less —much less — than what we’re being told (or better put, "sold").

On today’s podcast, Chris Martenson talks with oil analyst David Hughes, who has analyzed the major shale plays utilizing a massive database of well production results from America’s shale basins. The data show that declines tend to be hyperbolic in all shale fields. The average first-year decline is 70%; down to 85% by year three. And we’re drilling the best parts of these plays first: meaning that future wells will yield less even under the best results.

We’re pinning our hopes of "oil independence" on faulty assumptions. Worse, we’re using it to dismiss the Peak Oil theme at exactly the time we should be using this extra oil to construct the infrastructure for our next energy age (whatever that may look like), while we still have the net energy available to us:

Let’s just take a play like the Bakken.: 45% annual 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, the well quality in most of the play’s extent is only about half of what it is in the sweet spot. If you have to rely on the lower quality part 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. To be profitable for producers, it’s going to take 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 today is based on the assumption of cheap prices for the foreseeable future. That is not in the cards. With these recent cheap prices we are going to see production go down a lot faster than my estimates. My estimates are best case: 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 the best case. But even if you take my best case, the medium and long-term supply picture from shale is disturbing.

Sadly, corporations tend to think about the next couple of quarters. Politicians may think about the next election, but an energy sustainability plan has to have a vision of decades we certainly don’t see that in all the hype read every day. 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 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 the basic data on these shale plays as I could. It’s 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. 

Click the play button below to listen to Chris’ interview with David Hughes (47m:24s)

TRANSCRIPT 

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?

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.

Links
Drilling Deeper report

Drilling California report

This interview was originally published at Peak Prosperity.org

  • ThisOldMan

    The following related observation from Carl Pope caught my eye:

    “This price slump is temporary. But we can make it permanent. The biggest factor in the price collapse is not 3.5 million barrels a day of U.S. shale oil but 7 mbd lowered global demand. About half that reduction is competition from biofuels, more efficient vehicles and reduced reliance on driving. (Slow economic growth drained another 3.5 mbd from demand.)”

    http://ecowatch.com/2014/12/16/carl-pope-future-of-energy/

  • peakchoicedotorg

    Carl Pope (former CEO of Sierra Club) took $26 million from Chesapeake Energy fracking company.

    What is misleadingly called “recession” had more to do with reduction of oil demand than more efficient vehicles or alleged “reduced reliance on driving.”

    I don’t think Mr. Pope has ever said anything about the physical limits to growth on a finite planet, nor does Sierra Club suggest that the trillion dollar plus highway expansion plans in the USA should be stopped. Good luck finding anything from Sierra Club that suggests the need for an environmental response to Peak Anything, nor do they use their network to urge their supporters to get involved with Transition Town type efforts. They do urge people to keep voting for politicians who promote pollution so long as they are Democrats.