We recently sat down with noted shale geologist Dan Steward to get some first-hand insight in inside the industry from some of the earliest days in shale gas. Steward was part of the pioneering team with Mitchell Energy that revolutionized the shale gas industry, beginning with the Barnett play in Texas.
Dan Steward (standing between the white valves) led Mitchell Energy’s team in finding profitable shale gas. Image from The History and Making of the Barnett Shale DVD.
Canary: So, pulling oil and gas from rock… Where did it all begin?
Steward: This all started out in tight gas. It didn’t start off in shales. Most of the tight gas was sandstone and shales.
Canary: And it was just basically the shale that ended up being the big winner in that?
Steward: Yeah, one of the things that a lot of people aren’t aware of is that tight gas – like tight sandstone and tight shales – also were pretty big help. But it’s the shales that significantly kicked things into high gear, and as a result of the technologies applied to the shales, we’ve been able to go back and apply some of that to even tighter sandstones and tighter limestones.
Canary: And who really started it all?
Steward: Someone from the 1940s.
Canary: Really? What about your former boss? We hear so much about George Mitchell and his moniker “Father of Fracing.”
Steward: George Mitchell should never have been given that nickname. He never claimed to be the “Father of Fracing.” He’s also the father of 10 children! But that’s not what he’s remembered for. He is remembered for what he did in shale gas – so if you’ve got to give the man an industry title, I’d say it would be the “Father of Shale Gas.”
George Mitchell couldn’t have cared less whether he got credited with it. He did it for the company he was in charge of and for the country because he felt that this country had to have something else! I think he did it to protect his company, his employees, and his country. And as it turns out, it’s a plus for the whole world.
But keep in mind: It was industry as a whole, not just Mitchell. [The US Department of Energy (DOE) and the Gas Research Institute (GRI) were] funneling money into other companies, as well, for doing large fracs – Mitchell was just one of them, and the first one was, in fact, the Cotton Valley Limestone. It just so happened that George Mitchell was the first to take what industry and the government were trying to do and apply it to shales.
Canary: When your team at Mitchell started your work on shale gas, were you optimistic?
Steward: In the early years, shale gas was a real pipe dream. If tight gas was a pipe dream, shale gas was a REAL pipe dream.
We now have massive hydraulic fracing, but prior to all this work, people fraced – but they weren’t considered massive hydraulic fractures. A massive hydraulic fracture uses tremendous amounts of frac fluid in high pressure to break the rock. In the old days, the fracs tended to be relatively small. When I was a kid in Kentucky, in 1965 my father was fracing sandstones with small fractures. This is before any of this stuff started with GRI/DOE. So people were doing it, but they were small fracs, not massive hydraulic fracs.
We have learned so much from all of this work, since George Mitchell got started with the Barnett. We have a whole lot better understanding of all potential tight gas reservoirs (which would include tight sandstones, tight limestones, and tight shales). By the late 1970s, the majors felt like they knew everything they needed to know about the organic-rich source rock. The reason they thought that is because they were only interested in them from the standpoint of sourcing hydrocarbons in a basin where you had reservoirs of hydrocarbons to migrate to. That was the interest of the majors – and, for the most part, most companies. But when George Mitchell got started in the Barnett, we were looking at it from the standpoint of, “Can we make it work?”
Canary: Can you share some more about the early days in your search for shale gas with Mitchell Energy?
Steward: Well, tight Cotton Valley Limestone was one of the largest. By the standards of the time, 
it was a really good well, but by today’s standards, it was not a huge producer. This was an initial test. By the standards, it was a very significant test because this was, at the time, one of the largest if not THE largest frack outside the nuclear ones, done with conventional-type technology. And it proved commercial, but it was not huge.
[After the first horizontal, the trial-and-error efforts] increased production in the well and made it a commercial venture. That’s when George Mitchell started applying large fracks.
That was significant because, from that point on, George was pushing his people to apply these large fracks in a lot of other tight reservoirs. And then we first started looking at the Barnett. By the time that we got started in the Barnett, his company had been applying these large fracks to the Cotton Valley limestone. I think he had even done some in Cotton Valley sandstone, in the tight Wilcox sandstone, and in other sandstones throughout the country. He had started applying [large fracs] as a result of that well.
Canary: You’re clearly proud of your role in Mitchell’s groundbreaking successes. But you also credit the government as a partner in the process.
Steward: Sure, I have always felt like the government was a contributor. That Cotton Valley well was significant, and the government had been involved in it. But the government helped in that well – they did not help in all the subsequent ones that contributed toward industry’s understanding of that application. So I’d say that the government got things kind of started, but then it took a lot of private industry dollars to carry it through to fruition.
The government [through DOE/GRI] did contribute to our horizontals – and they contributed to other people’s horizontals. But then companies started really using horizontals. Some were failures, and some were successes. For instance, we even tried to do two additional horizontals in the Barnett. They were commercial failures in that they would not pay back their costs, but they were mechanical successes in that better helped us understand what to do with the horizontals and make successes out of them. And the government had no contribution to those two failures.
When we started partnering with the government, we released data to them that we had paid money for, and they evaluated. So the partnering involved them looking at a number of different things. The partnering wasn’t just to drill a horizontal. They also took some of the cores we had done and did some evaluations on them. We had spent the money on those cores; they did the evaluation. So we contributed, they contributed, and that was beneficial. But when it came down to the horizontal drilling, they didn’t pay 100% of that. They paid a large piece of it, but we paid a large piece – and they only helped us on that one horizontal. Subsequent to that, we did two non-commercial horizontals that helped us figure out what we were doing wrong and what we needed to do differently. They were non-commercial, and they were both on our nickel. The government didn’t have anything to do with those.
A lot of technology that is used today did get looked at by government and GRI, but it didn’t necessarily come to fruition with them. It was private enterprise – just like the horizontal Barnett. The first horizontal Barnett with GRI/DOE was not commercial as it was initially completed. But because of what we learned by the other two, we were able to go back into that original well, retreat it, restimulate it, and make it commercial. We didn’t know how to originally, and it was not a commercial venture originally. But because of subsequent work by Mitchell – using Mitchell funds – we figured out what we were doing wrong. We were able to reenter that well and make it commercial. And this is a lot of what happened.
Microseismic fracing was another technology that was an experiment. It was actually developed in the UK to help predict mine failures. But then DOE/GRI started looking at it to see if we could use it for frac-mapping wells on the subsurface. At the time that they started experimenting with it, the only frac-mapping that could be done in industry that had any effectiveness is what we call “tilt meter.” It evaluated the tilting of the surface due to the fracing, and they modeled that to determine the direction of the frac and how far out it went. Microseismic frac-mapping was something the government started working with Sandia Labs. We tried it in two wells, and both the tests failed. Then, a private enterprise developed the techniques and got the tools where they’d work for Union Pacific Railroad Exploration at Carthage Field in East Texas, showing us evidence that the technology and tools were now successful. In 2000, we started applying it.
So theoretically, the government-funded project started first. But then private enterprise was able to make it work and then apply it. The government spent some money on that technique, but private industry spent money on the technique also. So who do you give credit to? You give credit to BOTH of them.
This is an exaggeration, but just because someone gives you a nickel to try something and it worked that one time, you may end up spending $1,000 to reapply it over the next few years. But the person who gave you the nickel at the forefront shouldn’t get the same amount of credit as you did for trying to replicate the first success.
Canary: Were there instances where the efforts of GRI/DOE and Mitchell Energy did not sync up? In other words, did you have differences of opinion on the research you were doing?
Steward: Yeah, the need for open natural fractures – that was a finding from two men in the early 1950s. When they looked at one of the big fields at the time – the Big Sandy field in eastern Kentucky producing out of the Devonian Shale – they said the only reason it’s producing is because of there are a lot of open natural fractures. And it was… in that field. (They were also using nitroglycerin to stimulate.) But then the Eastern Gas Shales Project was not able to stimulate wells that didn’t have open natural fractures and make them work. The folks in the Eastern Gas Shales project felt like the way they would work is only if you had open natural fracture.
The Eastern Gas Shales Project was published, then it seemed to just die. The reason I tend to think that was,
at a time when our country was just screaming for more gas supplies – because it was clear that we had peaked and we were running low – a lot of those scientists involved were not out there pushing, “You need to get in these shales.” We weren’t hearing that in industry or in academia.
Canary: So the conclusion was that open natural fractures were a “must” for any successful shale gas venture?
Steward: Right. We started the Barnett thinking that was a prerequisite. When Mitchell first got started, when I told people we didn’t have open natural fractures, people said, “Well you’re an idiot if you think that’ll work! You just about have to have open natural fractures.” They were good people – they were limited by their knowledge, just like we were. We proved, in the Barnett, that you didn’t! And that was a significant take-away from the Barnett.
We also came to understand why vertical wells weren’t working in other shales. Because in the area of the Barnett where we started, we had good frac containment barriers above and below, and in the Devonian in Appalachia, they didn’t.
One of the things that a lot of people don’t understand: GRI/DOE wanted us to drill in a different direction. They still thought you had to drill horizontals across natural fractures. It took us a long time to convince them that, no, you wanted to drill them in a direction so that, when you frac it, you can frac multiple times along that lateral.
If I drill a well parallel to my induced frac direction, and I frac that well, I get one frac because that frac is now parallel and on top of my wellbore. I get that one frac, that’s it. But if I drill a well perpendicular to induced frac direction, I can do multiple stages of fracs along that lateral. Let’s say I do five stages along that lateral. Each of those stages is a different frac in the rock because I moved it along that lateral. And my induced frac direction is perpendicular to the lateral, so I now have an induced frac at the toe, an induced frac back from the toe, back from that one, back from that one, and then one at the heel.
Canary: Technically speaking, could you summarize this drilling process in a bit more detail?
Steward: The toe is the very end of the lateral. And the heel is back at the area where you’re making the turn for your lateral. So you drill down vertically, then you start turning your wellbore to get it horizontal. Then once you get it horizontal, you drill in formation out to some terminus that we refer to as a toe. And you always start fracing at the toe. Then, back where the lateral started, we refer to that as the heel.
We put these huge induced fractures into the shale. After we frac it, we start producing the frac fluid off and leave all that pressure down in that frac so that it’s now substantially lower than the pressure in the shale. What that does is create a pressure sink in the frac and the high pressure in the shale recognizes that and tries to equalize the pressure regimes.
Then you pull the pressure out of the induced fracture, and when you pull it down low enough that the tight rock on the shale can start equalizing, it does. In other words, let’s say that we can pull the pressure down in the fracture a thousand pounds – and only a thousand. But in order for gas in that shale to start moving, it requires 2,000 pounds. The gas won’t move. So why would it happen that I couldn’t pull it down more than that thousand pounds? If you break into a water aquifer adjoining the shale, and that water aquifer has good porosity and permeability, it can replenish the pressure within that fracture and keep it from being drawn down low enough for the gas to move.
In coalbed methane, you’re producing water out of coals that are naturally fractured, and the fractures have water in them. All of the gas that’s in the coalbed methane is absorbed onto the organics – there’s no free gas. In 99% of the coalbed methane, there’s no free gas (except in extenuating circumstances). When you’re going after a coalbed methane project, you drill wells and start producing water off of the fractures, and you have to get the water down to a point to where the pressure in those fractures is low enough that the gas will desorb from the organics. In the Barnett and these other shales, it’s not exactly the same case, but look at it this way: By fracking, you’ve made that fracture full of water. You’re pulling the water off of it, and once you’ve pulled the water off and gotten the pressure in that fracture down low enough, the free gas starts moving. Absorbed gas won’t move immediately, but the free gas does. And if you connect with a nearby water aquifer, instead of the free gas starting to move, the water aquifer will replenish the water you’re pulling out of that fracture you’ve just induced and prevent your pressure sink from developing.
When you produce the induced fracture, you initially are producing back to your frac fluids. When you eventually get most of that back out into your fracture, that creates a pressure sink within the fracture. The shale recognizes that and tries to equalize.
Canary: Sounds like your team at Mitchell Energy really learned a lot from the Barnett!
Steward: There were a lot of big takeaways from the Barnett shale – more so than the gas that it contributed to our country, which was important because of the time period that it came.
One of the big takeaways was that you didn’t have to have open natural fractures, as I’ve mentioned. Another one was that you needed to understand your induced frac containment. In vertical wells, it was a killer if you didn’t have natural ones. In horizontals, you could overcome it to a degree. That’s what made the Marcellus work: We were able to overcome the lack of good barriers. The vertical frac tended to hammer the upper and lower boundary of the shale with pressure, whereas, in the horizontal, you can place the horizontal and do things with the stimulation that will protect and try to concentrate the treatment within the shale. You’ll still lose efficiency, but you can increase efficiency within the shale. Even with the horizontal, we don’t have 100% frac efficiency (in the Marcellus) – but we have good enough frac efficiency with these long laterals in multi stages that we make fantastic wells that will more than pay back our cost.
The amount of gas in place – we found out there was a whole lot more gas in place. That was a big take-away. We also found out that water fracs would work in shales. That was a huge take-away because the industry as a whole felt like you did not put fresh water on shales. And another one was, we found out that these shales are so tight that after you produce a frac well for a while, you can re-frac it and the re-frac will go into virgin rock. And then the horizontal application was a huge take-away.
Canary: Would you say that the socioeconomic structure of our country was beneficial to your team’s efforts – and learning curve – with shale gas?
Steward: The government definitely created an entrepreneurial-friendly business climate. It’s hard for people to understand the significance of that. I’ve talked to people in China who are coming over here trying to understand what we do in the shales. They’ve essentially said, “In our country, you basically have two years in which to try and prove something. If you can’t do it in two years, it’s dead.” The Barnett took Mitchell 18 years. It was because of the private enterprise that had to have a replacement for its shallow production that it stuck with it for those 18 years.
Our country has done that. It’s not doing that right now, but prior to the current administration, it had. Right now, in my opinion, it’s hurting that. But I’m pretty conservative.
The US is basically the only country in the world I know of where mineral rights are privately owned. In England, they’re owned by the Crown. In Canada they’re owned by the government. In every other country in the world, I think, they’re owned by the government.
In the US, a lot of our minerals that aren’t owned by the government by way of forest lands, parks, and that sort of thing are owned by private citizens. And private citizens are willing to lease out land to try to make something happen, much quicker than the government is. When a private citizen does that and lives in the area, most of the money he gets is turned around and used in that area. When the government has acreage in an area and they get money by leasing that to a company, it goes into the government coffers. That local area may get a fraction of any revenue that develops out of that. So the fact that our mineral rights are owned by individuals in much of the case – most of the Barnett acreage was owned by individuals – is something you see only in the US. You can say that that’s because of the way that our country and our government was set up. So that was a huge plus.
Canary: And did the government provide other financial incentives? We’ve heard a lot, for example, about the multi-tiered pricing system for natural gas.
Steward: Having multi-tiered pricing really wasn’t a plus for Mitchell in the Barnett area. Now, in other parts of the country, it might have been. But as far as the Barnett’s concerned, it wasn’t. We had a gas contract, and that contract was one of the main drivers for our drilling and our efforts to continue building gas reserves in the area.
Basically what happened is, under that contract, with the mixture of gases, we theoretically could have gotten more for our gas because we were selling some gas at the contract price that we could have gotten an even higher price if it weren’t under contract. So what we tried to do was keep our basket of gas so that the basket price was essentially equivalent to the contract price.
Multi-tiered pricing said that new gas got a high price, unconventional gas got a high price, old gas got a low price. So in order for them to give us that high price – which they were committed to giving us – we had to sell them a basket of gases. It had to be made up of some old gas, some new gas, some enhanced gas, some unconventional gas.
In other words, we didn’t drill up a lot of unconventional gas and sell it at a contract price that was lower than the unconventional gas price. A lot of people don’t understand why Mitchell took so long to prove up the Barnett. That was one of the contributing factors.
Canary: Some person might say, “Even if they had a higher price, they still had to have these government tiers.”
Steward: Well, we were having to actually work against those government tiers in order to get our basket equivalent to the contract price.
When the multi-tiered gas pricing came in, old gas was probably at spot market price – which, I’m going to say, at the time might have been $1.50. Before multi-tier pricing, let’s say that everybody except for people that had these nice contracts were getting $1.50 for their gas. But because Mitchell had to sell gas and had this contract, at the time we may have been getting $3.25 for our old gas. But now the government comes in and wants to incentivize gas drilling, so they say, “We’re going to give you these multi-tiered prices – any old gas still only gets this, but if you can enhance that old gas well and do something to make it better, we’re going to give you an enhanced gas price (which is one price). Or if you drill a brand-new well, we’ll give you a new well price (which is another price), or if you can develop or discover a new field, we’ll give you a discovery gas price. Or if you can drill for tight gas, we’ll give you a tight gas price.
I forget how many categories there were – I think there were five or six. And I think I had to come up with all five or six. But each one of those had kind of a different price, and I think that unconventional was the highest. It may have tied with newly discovered.
Then we had to honor those gas prices. So Mitchell is sitting there with a contract that said they would pay us $3.25 (or whatever it was at the time) – but we had a whole lot of old gas, so we had to do something to get our mix up to be able to get to that higher price.
Even though we were under contract, federal law took precedent, as far as I know, so we had to do something. We were always drilling new wells, so the new well gas price helped that a lot. Then we started doing a lot of enhanced. We found that, OK, we’ve got this well that’s not doing so good. It’s old gas right now. I can put a compressor on it. That was enhancing that well’s production, so that gave us an enhanced gas price.
Then we started looking for new discoveries and tight gas. For tight gas, it had to meet certain qualifications: It had to be a very low permeability, and you had to be able to prove that it was tight gas. And if you discovered new gas, you had to be able to prove that it was a new discovery. So basically what happened, when the multi-tier pricing came along, we had to start doing things to make sure that our basket of gases was equal to the contract price.
Canary: One might argue: On the one hand, this pricing system did encourage you (or force you, almost!) to go out and do new discoveries and tight gas. But on the other hand, it really tied your hands because you weren’t able to use the old gas and get the higher profit and proceeds for it, which you would have used to then go get these new discoveries.
Steward: We already had a committed price. We already had a reason to increase our gas reserves because we needed to be able to show to that contract that we were replacing all the gas that we were producing each year. That’s a problem: You have this contract that may go on for 10 years. You have to show those people that you’re drilling for something for each MCF you take out of the ground. So we were already looking – it wasn’t like we weren’t already looking. In fact, when we started looking at the Barnett, we didn’t start looking at the Barnett because we were trying to get this higher price. We started looking at it because we had done a study that said, in 10 years, we were not going to be able to replace our yearly gas production in North Texas. And if we couldn’t replace that, then that was going to impact our contract and our ability to use our gas plan. So it was more a reason for being able to replace our reserves than it was for gas price. But I can see where people might think it was.
Things are never as simple as they can look like they are from the outside. But what I’m saying is that the multi-tier pricing really wasn’t a big driver. In my mind, it wasn’t a driver at all! The driver in the Barnett was that we knew we had 10 years remaining on our existing field, as we had to find a replacement.
Unless you know the entire history, you just don’t see the difference.
