Capital and Perseverance
Making shale gas happen in Europe may take bravery and some big euro bucks
Following numerous presentations by the highest profile players in shale gas, the ShaleTech 2010 conference ended in a roundtable discussion, offering delegates the opportunity to speak freely about what they felt was needed to get shale gas flowing in Europe.
Tim Benton, Vice President Geosciences at GMX Resources began the lively discussion by talking about the process of putting the infrastructure together in Europe to be able to go in and exploit the potential and new places.
“Europe’s not a new place, but certainly the operational execution, for shale at least in Europe is maybe not quite there yet, and so how do you navigate that process?” he asked “You’ve got a concession, but how do you execute the opportunity and what sorts of trades need to be made with the guys that own the concessions versus the people that have the boots on the ground?”
Addressing Mr. Benton, OMV’s Markus Mostegel asked, “I know you had a notion of European shale gas before you got here today. If you’ve got acreage here, will you go for it and what do you see as the critical points?”
“OMV’s Anton Baumgartner just made the comment that Austria has some gas storage capacity, which, to me, does not sound that substantial relative to the total consumption of natural gas,” replied Benton.
Within the European Union, Europe had somewhere around 80 billion cubic meters of gas according to one of the participants, noting that including Ukraine and Belarus it had much more.
“In North America you’ve got about 24 trillion cubic feet (TCF) a year consumption and about 4 TCF of storage,” reported Benton. “You could argue that’s somewhat in balance. The next question for Europe to think about is, ‘should that be bigger?’ Is this something the EU should promote, or should there be governmental action so people are more comfortable making a decision to use more natural gas – not being nervous about the ability to assess that.”
Schlumberger’s Hanspeter Rohner piped in.
“When you look at Europe today, I don’t think it’s such a big problem to get gas to the consumer. You see there are a lot of plans and it looks like you need a certain percentage of gas storage, but there’s nobody but Italy who are really building storage. They are also a major transporter of gas.”
He continued, “From my point of view, to get gas to the consumer is not such a big issue. There are pipeline plans in place from Russia, so I think E.ON and other big players are thinking about that, so I don’t think there’s a bottleneck. The bottleneck is, if you had large amounts of gas from shale gas, how to get it to the main pipelines.”
“Was your question aiming at security of supply and possible governmental encouragement?” asked one participant of Tim Benton.
“I think it goes to the overall dynamics of people making the decision to pay the big ante, and it is a big ante to be in the play. It’s not a small company game. It’s big capital, a big commitment to infrastructure, boots on the ground. It’s not for the weak of heart at the end of the day.”
One participant asked, “Is that because of the cookie cutter method – is that where the cost comes in? If you used a more high tech method, could you make it more viable for the smaller guys?”
“We saw this in North America,” explained Benton, “the whole issue of stimulation, of frack availability in these plays.”
“In the US we have trouble,” added Randall Miller, President – Integrated Reservoir Solutions at Core Laboratories. “There’s a shortage of fracking, sand, pumps, people. The two models that Schlumberger presented are actually quite interesting: they were talking about the cookie cutter approach, fairly low tech – that’s actually what the ultimate goal is to try and get to, because I think that’s where the cost savings are. But to ensure and reduce your risk, to understand that you’re targeting the right rock, using the right fracture stimulation techniques, I think you do need to do the science up front and then become comfortable with it, and then get to the point where you can say ‘okay, we’ve kind of got this figured out and now we’ve spent millions and millions of dollars to get there.”
Miller continued, “In the US where the companies are making money is when they now go into cost reduction, economies of scale – fracking multiple wells at once – and making it a little bit more ‘cookie cutter’. So the entry price is usually very large to get to that economic part. There’s a lot of money put up front on that learning curve. What’s been good recently in the US is – the Barnett obviously had the longest learning curve, and after that the Fayetteville, something like 4 years. For Haynesville, the learning curve has been very short, and I think it’s fairly short in the Eagle Ford. It’s really in Europe where hopefully you’re learning curve can be compressed, which reduces that amount of upfront capital. But ultimately the service business, the support, having the water and all that – you can’t go around fracking three wells a year and make money here in shale gas.”
“How many wells need to be drilled to make it economic?” was a question also posed by participants.
Tim Benton replied: “The energy business has always been a very capital intensive business, not necessarily labor intensive. Most of the money being spent is on materials, the tangibles, the casing, building of roads and infrastructure. At the Woodford, the average well makes about 400 million cubic feet in the first year. The AFEs that BP is circling is about $6 million to drill a well in the Woodford – you’ve spent that and you’ve got $4.8 million in unrecovered capital at the end of the first year. And what sort of decline, performance profile are you looking at? People desperately want to know what’s the real gas in place, what the recovery factor is going to be, what are the decline rates? I’m not saying the Woodford is typical but 800 horizontal wells have been drilled there times $6 million – is that $5 billion dollars?”
“There are a couple of other interesting components,” said Randall Miller. “If you go back and you look, historically in these plays, say 5 years in the Barnett or Fayettville, 3 or 4 years in the Woodford, a couple years in the Haynesville, what you see is the average well production going up. It is improving. That’s one of the things about the shale plays is, as you go along and improve the technologies, experiment in the field you do see the rates and the EURs go up.
He continued, “Another interesting component about it is, when you start to plot it by operator. Of course you’ve got to break out some of that by region, because some of them may not be operating in the sweet spot, but if you even take the ones that are in the sweet spot you see a difference in EUR over time with different operators. Some are better than others, at least in terms of production. A lot of that’s published and you can see that primarily in the Barnett, big time. The big challenge you’ll see in Europe are the well costs, but the only way that’s going to come down is if you’re successful and you’re going to bring in more wells – then the Schlumbergers and the Halliburtons are going to bring all there services in and you well see those costs go down over time and your economics will change.”
It was pointed out that in Europe a good statistical example was imperative.
“The first few wells in Poland will be key,” said Miller. “If there’s good results reported, it’s going to be a shot in the arm. If there’s several disappointing results reported, everybody’s going to start to pucker.”
“There’s no showcase in Europe right now,” added E.ON Ruhrgas’s Gerd Ullrich. “And there’s nothing that could be used to encourage management to believe the story. This keeps us from advancing further. Everything that comes beyond the first successful pilot case – that is well laid out here at this conference, that we don’t even have a single set of statistics to work from. Somebody has to provide a showcase that would spark it and encourage companies to invest money. We are talking about millions to get that start – each well in our area in Europe is at 10-15 million euros in an environment where our management says ‘there’s too much gas on the market.’ And this situation will be maintained for the next 2-3 years, so in that respect there’s not much desire to have a new source of gas.”
Tim Benton offered further reflection on the North American experience and how it might be applied to Europe.
“When you look at North America, the history of success has been to a large extent on the backs and on the visions of mavericks – the small companies, the people that said ‘why not? Why can’t we?’ These were guys that risked everything to go do that and a good question is, is there the will in Europe based upon having some comfort showing that it can be done in North America. Irrespective of that, I think it requires someone who’s brave.”
“I heard an expert from Shell make a comment that these shales all work for different reasons, so don’t go into it thinking you can completely rely on everything you learned from the North American experience,” he added. “You’ve got to have people thinking creatively about it and challenging every assumption along the way.”