Natural Resources Committee on Feb. 1st, 2011

[Dr. Anthony R. Ingraffea]

That's an excellent question.

I'll amplify on the comment I made earlier. It's all about the scale of an operation. It takes upwards of 30,000 cubic metres of water to hydraulically fracture a shale gas well. That's 50 to 100 times more water than has traditionally been used in conventional wells. That also implies that the waste stream coming back from that well is going to be equally large.

When the industry says that they've had vast experience, 60 years of experience, with hydraulic fracturing, what they fail to say is that they've had fewer than 10 years of experience on a large scale using these unconventional methods to develop gas from shale.

It comes down to two things--one, the larger volume of fluids being used and fluid waste being produced, and two, the absolute necessity, because of the geological differences between gas distribution and shale and gas trapping in traditional wells, that it take a large number of wells per square kilometre, three wells per square kilometre. That means thousands and thousands, or tens of thousands, of wells for a particular place.

[Nathan Cullen, NDP, Skeena—Bulkley Valley, BC]

So the--

[Dr. Anthony R. Ingraffea]

Multiply the tens of thousands of wells by the high volume per well and you get astronomically large numbers, which the industry hasn't shown it's able to dispose of yet.

[Nathan Cullen, NDP, Skeena—Bulkley Valley, BC]

So a two-part question with respect to the...because we've asked for what's in this fluid that they're putting down the well site to force the gas back out, and it ranges.

First, can you mention a few of the chemicals that are used in this compound that's sent down the well? And what percentage is typical for industry to recover back? If they put 30,000 cubic metres down a well, what is typical?

Second, we've heard from Minister Northrup that in New Brunswick at least---I'm not sure if you've necessarily studied New Brunswick in particular, but you get his points, I think, from his testimony--they're trying to incorporate different regulations that allow for more stringent observation of the industry so that the fears of landowners and people concerned about contaminated water will be assuaged by the way in which New Brunswick is setting up their industry. Does that not give you comfort?

First, then, can you talk about the fluids that are going down and what's in them, and what kind of recovery we likely will see in terms of the percentage? Lastly, is what New Brunswick is setting up, from what you've heard today at least, not moving the ball forward or progressive in terms of protecting the public and the environment?

[Dr. Anthony R. Ingraffea]

I'll try to answer those three questions very quickly.

In a typical high-volume slick-water hydraulic fracturing operation in a shale gas formation, there are roughly five types of chemicals that are necessary. I won't give you their chemical names—one can look those up—but one needs to add a lubricant to the water so that pumping the high volume used under very high pressure over a very long distance can be done with a reasonable amount of horsepower at the surface. That lubricant is typically a hydrocarbon derivative. There is a biocide necessary to kill the bacteria that otherwise would grow in the well and clog the well. There is an anticorrosive to prevent rusting of the all-important steel casing—that's the first line of defence for the entire life of a well that's expected to last 20 to 50 years. There's an antifouling agent to stop scaling—that is, deposits of hard minerals on the inside of the casing in the well that would otherwise clog it. And there is an acid that is used to clean out perforations right before the hydraulic fracturing process and immediately after the start of it.

Those are the general categories of chemicals. Some of them are relatively benign, even though you would not want to be drinking them or having them in your trout streams. Others are known to be toxic, carcinogenic, and don't belong in the human environment. But I should also emphasize that once the fluid comes back—and I'm trying to answer your second question now—it contains not only the chemicals that were put in on the way down but the material that was picked up from the shale. As I mentioned before, notably, in black shales, shales containing gas, the most dangerous of those are the heavy metals--strontium, barium, uranium, and radium--some of which are also naturally occurring radioactive materials.

The industry is fond of saying that most of what they pump down stays down. What they fail to talk about is the timeframe in which they're counting. Typically, the returned fluid, after the fracturing process, is counted as returned fracturing fluid only during about the first week or two of flowback operations. However, all shale gas wells continue to produce fracturing fluid and brine containing heavy metals for the entire life of the well. One has to be very careful. One cannot say that on average, 50% of the fluid comes back. One has to say under what timeframe one is making that measurement. Typically almost all of the fracturing fluid comes back during the life of the well.

In answer to the third question, whether I take comfort from my friends in New Brunswick saying they're trying to keep up with regulations, I don't know. I don't know what their starting point was for their regulations. I don't know what the current, perhaps modified, set of regulations looks like. I would only suggest that they go to perhaps the closest match to New Brunswick, which I would say is Pennsylvania, and take a look at the substantially revised regulations that have been put in place just in the last year as a result of only three years of substantial development.

[Nathan Cullen, NDP, Skeena—Bulkley Valley, BC]

Thank you for that.

In my remaining time, I'm sorry, I'm not going to get to you, Mr. Northrup, but I am curious about some questions, so hopefully I will get to you in round two.

Quickly to you, Mr. Angevine, with respect to the Fraser Institute, and I'm sorry you're here more on economic issues today than you are on necessarily the specifics we're talking about, which is this particular alternative oil and gas industry, various institutes in Washington have been calling on the President to remove subsidies from the oil and gas industry--heritage and other groups that are hardly tree huggers. I'm curious as to whether the Fraser Institute holds a similar view, in terms of the distortion of the market, of the current subsidies that go towards the oil and gas industry to enhance production and give them a leg up, if you will.

Secondly, why is there urgency to develop extremely large amounts of natural gas reserves at a time when prices are at near historical low levels? I don't understand. In your testimony, you talked about the need for speed. It seems to me that if prices are where they're at, if government doesn't offer up any subsidy to the industry, the market will simply decide that at $3, this isn't worth doing.

[The Chair, Conservative, Leon Benoit]

Could you make your response brief, Dr. Angevine?

[Dr. Gerry Angevine]

Yes.

On the question of subsidies, certainly the Fraser Institute position would be that subsidies on all forms of energy should be removed so that there's a level playing field and resources, including renewable resources, get developed on their economic merit. Is that sufficient at this point? To expand on that would really simply underscore the fact that there's no role that the institute sees, in general, for subsidizing oil and gas or any other form of energy resource development.

On the matter of urgency, the Continental Energy strategy research is being carried out on the premise that if market conditions, competitive forces, could lead to more rapid development of Canadian oil and gas resources, then anything that's non-market standing in the way of that development that cannot be justified and isn't necessary should be removed or reduced. That's why I spoke to the non-market barriers. Certainly we see the market today developing natural gas with some very low price levels, and we find that people who have looked and compared the shale in different parts of the U.S. have noted that some shale development is more economic than others. They're speaking to prices, and in some cases our cost for a thousand cubic feet is below $4, so this gas development may proceed, but other more costly sources will not.

[The Chair, Conservative, Leon Benoit]

Thank you.

Thank you, Mr. Cullen.

We go now to the government side. Mr. Allen, for up to seven minutes. Go ahead, please.

[Mike Allen, Conservative, Tobique—Mactaquac, NB]

Thank you, Chair, and thank you to our witnesses for being here. I especially want to note my friends from New Brunswick. It's always good to have New Brunswick folks here at the natural resources committee.

I want to start, Mr. Northrup, with one of your comments with respect to New Brunswick regulation at least keeping up with where we are at this point in time. You said you will continue to develop that regulation and that Apache has done some test drills in the Elgin area of New Brunswick. How far out, realistically, is your department seeing the actual development of these wells before, if everything goes well, we would see everything go into a production state to sync up with your comments about the regulation making sure it stays ahead of that?

[Bruce Northrup]

Thank you, Mike. It's always a pleasure to hear your lovely voice and see your half-body on TV.

It's a pleasure to be here.

We've done very well as far as the EIA process, phasing it in, in the Apache, in the Elgin area, as far as the process goes from beginning to end. They have drilled two wells there. They've completed two wells there, and they've been very up front with the people around the area as far as communication goes. They put flyers out to the people around that area as to what they're doing that day, what they're doing the next week, and what they're doing in the next two weeks. They've also gone into the community as far as hiring the local fire department to do security for them. This is all about community involvement, and Apache has done a great job there.

As far as a timeframe for Apache goes, we're probably looking at around 18 months, approximately a year and a half, and with Southwest Energy, which is at the very, very early stage, we're probably looking at about three years there.

[Mike Allen, Conservative, Tobique—Mactaquac, NB]

I just have a couple of questions on your trip to Arkansas.

The first one is this. What did you learn about the regulatory environment down there? The Environmental Defense Fund and Southwest, of course, had a little bit of a meeting--I think it was at the University of New Brunswick--a couple of weeks ago, and it was actually quite productive. They were talking about the use of water. What did you see about Arkansas...? Was there any specific mention there of some states having a better regulatory environment than others?

The second question is this. What did you learn about the advances in technology with respect to chemicals and water usage and the recovery of those?

[Bruce Northrup]

As soon as we landed in Arkansas, in Little Rock, as soon as we got to the motel, we had three or four groups waiting for us there to have a meeting. These folks have been involved with the industry for probably 9 to 10 years, and we talked to them for a good two and a half hours. By the end of the conversation, we understood they weren't really against the industry itself, as far as industry goes; they were just a little upset with some of the things that had gone on in the past, and one of the things, Mike, was the sound of everything that was going on. We sat down in a lady's kitchen and they had six compressors about a half a mile from her house. And we all know how jets take off. It just sounded like a jet taking off, and that's 7 days a week, 24 hours a day, 365 days of the year.

We wanted to see the opposite of these compressors, so we went to a place where six compressors were housed inside a building, with four inches of insulation, and we stood outside that building and could hardly hear the compressors on the inside.

Southwestern promised the lady that they were in the process of putting a building over these compressors.

That's one of the things that we brought back to New Brunswick. Even before these compressors are turned on, they'll be inside a building and they'll be well insulated so that the noise is not heard by the neighbours around there. A lot of these compressors were not really out in remote areas; they were around different housing places. That was probably the number one concern, and we really appreciated the people talking to us and giving us their experiences, which we brought back to Canada. The sound was one of the main things.

As far as technology goes, it was interesting that Calfrac, from Calgary, Alberta, were there doing most of the fracking and drilling. So it was interesting to talk to them on a one-on-one basis.

They were happy employees. It was nice to see. They work seven days on, seven days off. We had some good conversations with Calgary-based Calfrac. What we want to do when we put this EIA process in--and we talked about chemicals before. We're going to make sure, Mike, that full disclosure of these chemicals is brought in. I know the doctor mentioned three or four of them, and that's exactly what Apache did. They disclosed. They had a really nice pamphlet made up and they disclosed exactly what they put into the ground. The recovered water is stored in storage tanks right around the area and then it's transported to an approved industrial water plant within a couple of hours of these wells.

[Mike Allen, Conservative, Tobique—Mactaquac, NB]

Have there been any incidences about water and spills? One of the folks from the Environmental Defense Fund talked about that. One of the biggest challenges they have is not necessarily the fracking and the contamination of the aquifer, but spills and some contamination. Have they experienced anything like that in Arkansas, and if not, what principles have they used to prevent that?

[Bruce Northrup]

We didn't experience any spills or anything in Arkansas. You can imagine in your mind where you have six or seven 18-wheelers in one spot with a drill rig, and it's all computerized, and they actually had tar ponds out on the ground so that if anything did happen they would recover it very quickly. That was very impressive.

Another thing we brought back for New Brunswick...we want to make sure that if anything does happen, if water does come up and leak outside this well, that it is contained for sure. I just want to emphasize that water is our number one priority here, along with the environment and the people around the area. And the “keep it simple” attitude is that if we can do this, we're going do it and we're going to do it right. If we can't do it and it's going to be done wrong, we won't do it.

[The Chair, Conservative, Leon Benoit]

Thank you, Mr. Allen.

We go now to the second round, to five minutes of questions and comments, starting with Mr. Tonks, and Mr. Andrews, if there is some time left.

[Alan Tonks, Liberal, York South—Weston, ON]

Thank you very much, Mr. Chairman.

Again, thank you to our witnesses.

My first question is to Professor Ingraffea.

You've given us a really comprehensive characterization of both the flowback and the chemicals that remain in the ground, which are part of the hydraulic fracking process. I can only infer that the level of uncertainty about matching that issue--not to mention the propane, methane, and other chemicals and gases that are created--has given the State of New York cause to take a step back and have a look at it.

Can you give us any insights on the level of technology and the research that exists, in terms of now getting an opportunity from this moratorium to match the degree of uncertainty and risk with technology that can counterbalance that? Are you aware of what is happening, and can you share that with the committee?

[Dr. Anthony R. Ingraffea]

I'll try to.

Accidental spills and discharges happen daily in Arkansas and Pennsylvania--not the blowouts experienced in the Gulf of Mexico, but truck accidents, valve failures, tank leaks, and pipeline failures. These are daily occurrences in shale development activities. Perhaps the most important area of technological development that could diminish those risks is recycling as much of the return fluids as possible so the total volume of waste fluids that need to be transported from a drilling pad to the ultimate site of disposal can be reduced. It's all a matter of risk. If you reduce the truck traffic, you reduce the total volume and the risk of accidents.

Recycling in the U.S. is in its infancy. There are two types of recycling. One can hopefully reuse some of the return fluids in subsequent wells. Very few of the companies operating in New York, Pennsylvania, Arkansas, and Texas are doing that right now because it's an enormous additional expense.

Recycling also takes the form of transporting the waste fluids away from the well pad to specially designed new technologies that can remove most of the waste from the fluid. What you're left with is a smaller volume of more highly concentrated waste that can then be transported for safe disposal to underground injection wells, for example--which by the way probably will not work in your eastern provinces, just like they won't work in Pennsylvania and New York. But they do work in Arkansas and Texas.

One has to be very careful what you compare your future to. Arkansas is not New Brunswick. Come to Pennsylvania.

[Alan Tonks, Liberal, York South—Weston, ON]

Thank you, Mr. Chairman.

Do I have a little more time?

[The Chair, Conservative, Leon Benoit]

You have a minute and a half, Mr. Tonks.

[Alan Tonks, Liberal, York South—Weston, ON]

Perhaps Mr. Andrews can ask his question.

[The Chair, Conservative, Leon Benoit]

Go ahead, Mr. Andrews.

[Scott Andrews, Liberal, Avalon, NL]

Thank you.

My question is for Professor Ingraffea as well.

In your opening statement you talked about downstream environmental concerns. Outside of the water concerns, are there any other downstream environmental concerns? Do you want to elaborate on that, or when you made that statement were you just talking about the water?

[Dr. Anthony R. Ingraffea]

No, I was not just talking about the water. I dropped the hint that there are solids and gases downstream, with potential impacts on the environment and human health. On a small scale, around a development near a compressor station, near a pad, in addition to sound there are gaseous emissions. Some of them are purposeful and some of them are accidental. You know now that most shale gas wells leak small amounts or large amounts of methane. That's the nature of the beast. It has always been that way and will always be that way. So there are leakages of gases on a small scale.

On a large scale, remember that natural gas is a non-renewable fossil fuel. When it is burned it produces carbon dioxide in the atmosphere. When you produce it, store it, and transport it through gathering lines, transmission lines, and distribution lines, in the United States--I'm not aware of the figure in Canada--somewhere between 3% and 5% of all the natural gas produced leaks into the atmosphere. Natural gas is a much more potent greenhouse gas than carbon dioxide, so even a relatively small percentage leak on a very large volume of gas results in a very significant impact on greenhouse gas emissions, and therefore potentially on climate change. So there are other effects one should consider on human health, the environment, and climate--not just from water, but also from solids and gases.

[The Chair, Conservative, Leon Benoit]

Thank you, Mr. Tonks and Mr. Andrews.

We'll go now to Mr. Anderson, for up to five minutes.