Thank you, Mr. Chairman and members of the committee.
My name is David Pryce. I'm vice-president of western Canada operations with the Canadian Association of Petroleum Producers. I appreciate the opportunity to talk with you today, and my apologies that I was not able to get down to Ottawa.
With me today I have Cam Cline, who's an engineer with 23 years of experience, and Marc Dubord, who's a hydrogeologist with 15 years of experience. They're representing the Canadian Society for Unconventional Gas and are here to provide assistance in answering any of the technical questions you may have.
I understand you have our slide deck with you. If you turn to the first slide, it will show the outline.
What I want to do is cover very briefly what natural gas from coal is and where it is in Alberta, then talk about typical operations we have in developing this resource. I also want to spend a little time talking about a stakeholder consultation process that has gone on in Alberta and about some of the issues and concerns and what's being done to address them, and then, finally, put this in the context of Canadian gas production.
It's a lengthy deck, so I will move quickly through it to meet the time constraints. If you have questions that I don't cover, you can catch us at the end of this.
On the next page, “Natural Gas from Coal in Alberta” is the title. Really, natural gas from coal is found across Canada. I want to focus on Alberta because that's where the industry activity is occurring at this time. The map shows the various horizons or zones where natural gas from coal—or coal-bed methane, as it is also known—can be found.
I want to focus on the three zones that are attracting industry interest at the moment. The first is the Horseshoe Canyon. It has about 66 trillion cubic feet of resource and is probably the largest play in the world right now. But it is in its infancy, as all of them are. Current production is around 600,000 cubic feet per day. That's where our focus is at the moment.
The second, the Mannville zone, is a huge resource, and it is at the point of trying to determine technically whether it can be produced on a commercial basis. It is associated with salty water typically.
The third zone is the Ardley zone, another large resource, which can be associated with either salt water or fresh water and in some cases is dry. This particular zone is sitting in abeyance for development, as we wait for rules to be developed on how we will deal with the fresh water that might be produced with it. So there's not a lot of activity in that particular horizon.
I think the bottom line is that there's a huge resource potential. It is in its infancy, and we are looking at ways to make this a commercial play.
The next slide—the next few slides, really—talk about the typical footprint we might have out on the landscape. This particular one is a drilling operation that is in effect. It is an operation that really is for coal-bed methane, or natural gas from coal. It has a much smaller footprint as we do these kinds of activities: smaller and fewer pieces of equipment and minimal surface disturbance is the typical way we do things. We don't necessarily strip off the vegetation and topsoil; we try to get in and out with minimal disturbance.
The next slide shows the next phase in activity. This is a well stimulation operation. This is where we inject, typically, nitrogen gas down the hole to try to enhance and flush the reservoir to better encourage production. As with the drilling operation, a minimal footprint objective is what we're trying to achieve.
In the next slide, titled “Well Construction”, what we're trying to convey is the engineering and regulatory measures that are in place to ensure that we separate our production zone from the upper water aquifers. What we are required to do by regulation is apply a surface casing and cement it in place and then a production casing and cement it in place. The intent of that, as I said, is to separate the producing zones from the upper aquifer zones.
If you move to the next slide, titled “Well Depths”, what we're trying to show is the vertical depiction of the different wells we deal with. On the left side is a typical residential or farm domestic well. That's usually completed in the 10- to 100-metre range. The next well is the dry “natural gas from coal” well typical of a Horseshoe Canyon well, subject to those well completion requirements I mentioned before. It is usually completed in the zone somewhere around 200 to 800 metres in depth to access those coal seams. Again, it's typically a dry well, with no fluids associated with it.
The next one is the Mannville well. It is deeper and typically associated with salt water.
The final well is a typical disposal well. The point of this last piece is to indicate that any salt water we produce we are required by regulation to inject downhole. When you look at the slide as a whole, we're trying to show that there is a significant vertical separation between the upper water aquifers, where domestic wells typically occur, and the producing zones we have.
The next two slides show the pipelining procedures. We install pipelines to get the gas to market. With coal-bed methane the pipelines are relatively small--six inches down to less than four inches. When it's around six inches we do a little bit of topsoil stripping to preserve and protect the topsoil. Then we plow the line in.
The next slide shows the plowed-in pipeline four inches or smaller. We're able to plow that right in without any topsoil disturbance. The goal overall is to minimize the footprint, minimize the disturbance, and protect the topsoil.
Next is the sound attenuating compressor. Noise is one of the issues that has been raised from time to time, and we have the technical capability to minimize that through sound attenuation control. We are subject to the rules of the Alberta Energy and Utilities Board and the National Energy Board, which set the standards or criteria around noise. Where it's needed and appropriate, we have the ability to apply sound attenuating equipment on compressors.
The next slide is on stakeholder consultation. This is not a new issue for the industry, nor is it a new opportunity in terms of a resource. It was developed several years in advance in the United States. We've been learning from that experience, but we also have our own experience in developing conventional oil and gas. With that experience comes the regulatory environment. Notwithstanding that, because it's a resource that's moving forward in Alberta, questions arise around how to develop it responsibly.
The Government of Alberta installed a MAC, or multi-stakeholder advisory committee, in 2003. It was led by the departments of energy and environment. As a stakeholder group they tried to identify the issues that might be of concern to folks to determine if the regulatory environment addressed them or if new measures were required.
Do we have confidence that the regulatory environment is adequate? Does it protect the water? Does it deal with the surface impacts that might be associated with natural gas from coal development, such as well density, the number of wells and their proximity together, the number of roads, the level of activity and noise, and the cumulative effects of those things? There are also questions around air quality, the overall pace of activity, and the effectiveness of the interrelationship or communication among industry, government, and the land owners.
Our view is that we have a pretty strong regulatory environment in place. It has been in place for decades, as a result of the evolution of the conventional aspect of the oil and gas industry. Coal-bed methane development is quite similar in its process to conventional development methods. So the regulatory environment deals with issues around well density or well spacing, flaring, noise, and how we protect downhole for the upper aquifers with the casing and cement methodologies. It deals with handling saline water or produced water and mechanisms whereby we're required to have consultations with the landowners.
In Alberta we have surface rights and subsurface rights, and we need to reconcile those rights. We have a Water Act in Alberta that's been in place for more than a decade. It provides controls for our industry, through permitting and licensing processes, as we look at ground water and surface water.
Having said that, the MAC process raised some questions and challenged whether there were things that could be done better. I'll talk to that in the next few slides.
Thank you, Mr. Chairman.
First, I'd like to thank the members of this committee for actually agreeing to hear this issue. Thank you very much.
My name is Robert Schwartz. I live near Red Deer, a city located in the southern third of Alberta, approximately 100 kilometres east of the eastern slopes of the Rockies.
Is coal-bed methane a federal environmental issue? To answer this question, we must understand what coal-bed methane gas is and how CBM production differs from conventional oil and gas production. We must also understand the magnitude of the proposed development and how it will affect the hydrology of the interprovincial watershed.
I would like to quote two passages from Alberta's Earth Sciences Report 2003-2004. The first quote is:
These tests suggest producing water from these aquifers initiates flow from the aquifers, flow across aquifer-aquitard boundaries and potentially flow from surface water bodies. These connections became evident under relatively low flow conditions when compared to production rates that would be associated with coalbed methane development.
The second quote from the same report states:
Under this scenario, one of the potential receptors of this produced water is surface water, such as rivers and lakes.
I would also like to quote Mr. Neil McCrank, past chairman of the Alberta Energy and Utilities Board, the regulatory body that we deal with there. In 2006, as a speaker at a Canadian Society for Unconventional Gas conference, Mr. McCrank stated that there will be 25 to 50 times as many wells drilled for coal-bed methane than have been drilled for conventional oil and gas.
To date there have been 327,000 conventional oil and gas wells drilled in Alberta. If the past chairman of AEUB is correct, there will be 8 million to 16 million CBM wells drilled in this province. Most of these 8 million to 16 million wells will produce coal-bed methane gas from many shallow or thin coal layers that also contain fresh water. These coal seams have a hydrological connection to the interprovincial watershed. These seams can be seen at many places along both the Red Deer River and North Saskatchewan River.
The southern third of the province of Alberta is the headwaters of this major interprovincial drainage system. This headwater drainage area flows via the Oldman River, the Bow River, the Battle River, the Red Deer River, and the North Saskatchewan River. The Red Deer River and the North Saskatchewan, in particular, are used as a spawning ground for Lake Winnipeg whitefish and touladi. All of the rivers mentioned are used, to some degree, as spawning habitat for many fish species originating in Manitoba. These river systems all discharge into Hudson Bay via the Nelson River. These river systems, as well as being a vital component of a viable fish population in Manitoba, are a vital source of potable water in Saskatchewan.
The geological layering of subsurface Alberta is interesting. We know that on the surface, precipitation and river flow is from west to east. Precipitation that becomes ground water through soil absorption follows the underlying geology and flows as groundwater from east to west in the Red Deer area. Much of this groundwater does not travel far west before it is discharged through springs and seeps into the deep gorges of these interprovincial river systems.
If one thinks of the eastern slopes and foothills of the Rockies as a 100,000-square-mile sponge that moderates river flows, this would be a correct analogy. This hypothetical sponge would lie above the Lee Park formation. The Lee Park formation is the shallowest impermeable formation above which all other formations are considered to be unconsolidated. The hydrology above the Lee Park formation is known to have small impermeable lenses capable of trapping gas. As a whole, all geology above the Lee Park formation is considered permeable and homogeneous. What Alberta allows to happen in this sponge will certainly have downstream consequences.
The AEUB special report number 81, published in September 2006, admits in the executive summary that a hydraulic connection exists between the different portions of coal-bearing formations on a regional scale. Most coal-bed methane development will take place above the Lee Park formation, whereas most conventional oil and gas production takes place below the Lee Park.
I hope my explanation of the general geology of Alberta has kindled a federal interest in what type of activity takes place above the Lee Park. All water above the Lee Park, whether it's precipitation, groundwater, or surface water, eventually ends up as interprovincial river flow.
Conventional oil and gas production takes place predominantly below the Lee Park. These host rock formations are capped by impermeable lenses of material that prevent the upward natural migration of oil and gas. The oil and gas trapped in these host rock formations is thermogenic--that is to say, conventional oil and gas has been produced by heat and pressure. This process of converting prehistoric plant and animal matter into oil and gas has long since expired. There is no more conventional oil and gas being created. Because of the geological age of conventional oil and gas, it is nearly always associated with highly saline water, which is the remnant of a vast inland salt water ocean.
Provincial regulation mandates that conventional oil and gas wells isolate potable groundwater from saline water by means of cemented surface casings, inside which are cemented production casings that are run right to the bottom of the well. The hypothetical freshwater sponge zone mentioned earlier is by and large protected, although a significant percentage of all surface casings develop leaks. These leaks are required to be repaired under current provincial conventional oil and gas regulations.
Coal-bed methane is a completely different situation. CBM is produced from shallow geologic zones that have historically been excluded from production by previous regulations.
The origin of CBM is entirely different from conventional oil and gas. CBM is the result of present-time microbiological organisms that produce methane as a waste. This microbiological process is dependent on the presence of non-saline water. The coal seam only acts as a host rock in which the methane collects. The presence of coal is not critical, or even necessary, for the microbiological production of methane gas; coal seams are merely the most porous geological formations and thus the most efficient medium from which to extract methane. I'd like to add that some coal seams have a porosity high enough that they will allow a water flow rate of 800 metres a day. These are aquifers, and moving aquifers.
The regulations that have historically protected these hypothetical sponges have been relaxed. The new regulations have, by and large, been put forward by industry and summarily adopted by the Alberta government regulators. These new regulations allow for and authorize many practices that will have a profound negative effect on groundwater and consequently river water.
The new CBM regulations allow for the dewatering of coal seams and the injection of this water into deeper saline zones. This dewatering of coal seams, necessary to induce gas flow into the well bore, will have the delayed effect of reducing river flows, as the creation of dry depressurized zones in the near-surface geology will surely acquire river water to replace that which was removed.
The new regulations allow for the commingling of production of a well from all zones capable of being produced. In other words, this allows shallow CBM gas to be produced from the same well bore as, and at the same time as, deep conventional gas.
As a point of reference, in water well construction, the practice of producing potable water from more than one aquifer has been banned for years.
It is reasonable to expect that water will drain from an upper freshwater formation into the lower saltwater formations—
I grew up in Montreal. I now live in Alberta. I'm very sorry, but I have forgotten all my French. I live near Rosebud, Alberta. It's a small, little-theatre cultural town with a lot of beautiful historic resource.
I have worked in the oil patch for 25 years. I have also been banished by the regulator that Mr. David Pryce was so proudly discussing earlier in his presentation. I believe I was banished—this was in writing—by the energy regulator because they were trying to intimidate me.
I have evidence of EnCana Corporation not complying with the noise regulations, and the EUB actually covering up for the non-compliance in writing. I believe that the EUB, the regulator, did this to try to silence me. They copied the RCMP. So I'm very surprised that you, honourable members, here have allowed me to speak, because I do believe this was the first time this had happened in Alberta. I have been informed that the banishment was a violation of the Canadian Charter of Rights.
I grew up proud to be a Canadian. I grew up proud of our water, of our leadership on peace and mediation, and environmental issues globally. I have worked in other parts of the world. I have to admit, I'm ashamed to be Canadian now, and I plead to you all as this committee to listen carefully and review the documents, and carefully consider whether the federal government needs to get involved.
I have never seen such atrocities in my 25-year career of working in the oil patch as I have now seen in the boom: human rights violations, environmental degradation, and disrespect of the legislation and the regulations.
In regard to noise, the other day when I was leaving from the airport, the night before I left, the compressor noise—we're surrounded by 13 EnCana compressors—drove me to distraction. Occasionally the noise is mitigated, but not always. There's a straw-bale wall surrounding these compressors.
I have direct experience with the water. This is my water, on fire, from my tap, poured into a pop bottle, a water bottle. There is no sugar in there. A few minutes later I set it on fire. I've lived in my place since 1998, 50 acres. CBM came and my water dramatically changed--a chemical burst on my skin and eyes. My dogs not only refused to drink the water, but they would back up. White smoke was coming off the water.
There were whistling taps. I didn't know what it was. I was really busy. I thought it was my plumbing. I thought, “Oh my goodness, I have to replace the taps.” Little did I know that I was living in an explosive time bomb. It was methane and other hydrocarbons coming out of my taps. Sometimes I couldn't even close my taps there was so much gas. I couldn't get suds out of my soap or shampoo anymore; the water changed.
Also, living rurally, you know you get stains on your plumbing and toilets—sorry to speak so intimately. All of a sudden my toilets went pristine, brand new. Something got rid of the stains, I think probably what was burning my skin.
Mr. Pryce mentioned the good regulations. This happened in 2004. These are the two aquifers in my community. This is an EnCana well. It fractured into—into—our aquifers. So the protection and the separation that was discussed is not possible. Perforations, which explode through the casing, and then the fracs, and who knows what solvents went into our aquifers?
In the States, EnCana was found to contaminate groundwater and did not protect health and safety.
This again is another picture of my water, a different picture. I don't do this in the house anymore because the flame exploded so high it shot up to the ceiling. I'm a blur in the picture—this is me here—because I had to jump; it scared me.
We have one out of 20 resource wells leaking. The landowner in an investigation is usually blamed, instead of comprehensive testing of the resource wells. There are ways to find out which gas wells are leaking. They can be fixed. In this case, EnCana has stated publicly that they do not need to cooperate with this investigation because they don't believe in the science that can lead to finding out which wells are leaking.
The regulators misinform the public. We have thousands of resource wells leaking.
The new testing that came up only began when a number of concerned citizens went to the legislature and went to the public. The MAC committee was still in deliberation. I believe the testing requirements wouldn't have happened.
We have now had, finally, a number of years of CBM, but our knowledge on groundwater is behind. The precautionary principle: where is it?
In 2005, industry advised the Alberta Energy and Utilities Board that some of their shallow fracs were damaging oil and gas wells. So they brought in some new rules. These rules should have been brought in before they began the experiments, especially for our drinking water.
This is a water well that exploded last spring. The farmer had dealt for three years with the regulator--the so-called best regulator. What's wrong with this picture? Three men were seriously injured on sampling day. After contamination, some companies refused to cough up the data that was needed to investigate and remediate.
This is a diagram that the AEUB, the energy board, and Alberta Environment go to the public with. They say it never happens. Oh, no, there is no leaking.
By the way, methane is a much worse greenhouse gas than CO2, and we have thousands of these leaking methane directly into the atmosphere. There is surface casing vent flow, and gas migration through soils. The interesting thing is that the AEUB, in 2007, is even warning that the gas leakage and the gas migration potential is worse in the shallow zones. This is where we're going to be doing our CBM and where our water is.
In Rosebud water we have 30 milligrams to 66 milligrams of dissolved methane, as well as free gas. CAPP, which is here today on the video, has a report that one milligram puts you at risk of explosion if the water passes through an unventilated place. A light switch, static in my hair, could have blown up my house.
The regulator is still in denial. They have done tests on our water. You have a table. We have benzene, toluene, ethylbenzene, and xylenes in our water. We have ethane, propane, methane, butane, and octanes, and we have kerosene in the community drinking water. In most cases, the landowner is blamed for the contamination by way of bacteria. On the table, you can look at the process we have to go through.
I read your report that came out recently on the chemicals and your Canadian Environmental Protection Act, and I plead with you to please implement this act in Alberta.
We are told that only nitrogen is used, so our water is safe because nitrogen comes from the air. I would like to show you a list. This came from Oilweek. These are a variety of products, hundreds of them, used in different stages of drilling, cracking, and servicing. Some of them contain diesel and mineral oil. In Alberta, the regulator does not require industry to disclose any of the chemicals used, not even if they're toxic, not even if it's benzene, a known carcinogen, or toluene, which damages the brain, notably in children. Toluene was found in our water.
We need to know what the chemicals are, especially so shallow, and I believe that the federal act is perfect. I noticed in your report this is seldom used and seldom implemented. I would like to ask that you use this and implement it in Alberta and ask the regulators to control the chemicals being used.
I have seen many pallets of chemicals that aren't even on this list, bags of chemicals that say, “Danger, Unregulated”. Nobody knows what's inside, driving through playground zones. We don't know now how to analyze our water. These chemicals could have gone into our water, but we don't know what to test for.
I also brought with me a pledge to protect our groundwater. You had this translated. I would like to ask every member of Parliament, not just the committee members, to sign this pledge and fax it to Honourable Minister Baird and our Honourable Premier Stelmach.
There are a few things we would like done to protect our groundwater.
CBM can be a fantastic new resource. We can all share in the prosperity. Canada is a fantastic country. I would like to see the Canada I knew as a child come back from corporate rule. I would like to see the people in charge. I would like to see public health and safety protected. There are still people in my community bathing in and drinking water with benzene and toluene. We do not need to harm people to have prosperity.
Coal-bed methane will spread far. The shales are coming. They will spread far. These impacts, violations of the Canadian Charter of Rights and Freedoms, will spread through the country if we continue to allow industry to rule.
The precautionary principle: why are we allowing perforations and fractures into these shallow zones above the base of groundwater protection? Industry still doesn't know what these shallow perfs and fracs do. They have stated this in writing to the EUB. Why don't we learn first? We can do an economical mitigation here, slow down, think first, collect some data first. Let's find out what we're doing to our groundwater. This is Canada's water. We all have water on the table here. This water will affect all of us.
The story has been much in the news. I bring one gift for my French friends here today. Quebec journalists are writing three stories on the water situation. In September, I believe, the Rosebud water situation will be published, but they are also writing about climate change. I find it interesting that Quebec is so concerned about what is happening to our water in Alberta that they're sending journalists out. There is an Alberta Views article. I have copies here for you. They've been handed in. Even Canadian Business magazine has published the story about the water. There I am with my water. I can't live with this water anymore. It's too dangerous. I have trucked-in water that the Alberta government is supplying and paying for. I've lost my independence. I live rurally. I have to rely on trucked-in deliveries. I want my water back. I want to protect water for others.
In conclusion, in my experience, the regulations are not working. The regulators are not working. Instead of dealing with the industry's non-compliance, they banished an ordinary citizen, considered me a threat to safety and the public. I had just found out when I got this letter from my regulator in Canada, a country that I thought was a democracy, that I was living in danger of explosion from my water. Yes, methane can be natural, but it is normally at very low levels. Nothing like the levels we have after this company, EnCana, fractured directly into our potable water supplies. They have cemented this well off, but we do not know what damage has been done to our aquifers. This is very serious.
Most of the work I do in the oil patch is on cumulative effects, and alarmingly, as our developments are dramatically increasing in Alberta, the mitigation of and assessment of cumulative effects seem to be going down. We seem to be deregulating in Alberta instead of increasing our assessment of these effects.
From the global warming perspective, the leakage of these wells, as well as potential effects on groundwater, the cumulative effects of these shallow zone developments, the unconventional developments, I think could be dire if we don't take better protection.... As Mr. Cline mentioned, a lot of the older wells are being used to commingle and perforate and frac. When they come to do the CBM, they will often come back again and again to perf and frac again and again. The cement in the surface casing as well as the production casing leaks from many different ways. When the cement is setting, if there are air bubbles or gas moving through from the deeper zones, that can create channels. The cement degrades over time. With each one of these perfs and fracs happening, cumulatively, what is the integrity of the cement going to be?
Interestingly, too, on the EUB, the data collection is so behind, and we're increasing the cumulative effects, but we have less knowledge and data collection than we really should have for the groundwater mapping and the baseline testing. For example, in my area the experiments on the CBM happened before the baseline testing, even though this multi-stakeholder committee was saying, “We have to test first. We have to protect the groundwater; it's vital for life.”
It only took pressure through the press before the baseline testing happened. I believe we still would not have baseline testing if a number of concerned Albertans had not gone to the legislature and gone public.
The EUB did a study that just finished in 2006. This is the regulator. They actually said that seven out of seven of the produced water from the coal-bed methane wells had the contaminants that we found in our Rosebud drinking water—the benzene, toluene, ethylbenzene, etc., the heavier hydrocarbons—but 11 out of the 12 water wells in the study did not, had no detectable levels. And 10 out of those 12 water wells had no detectable levels of methane, and they were all getting their water from coal. So even though CAPP has stated that 26,000 of our water wells getting coal supposedly have this natural methane, the regulator's very own study found that this was actually not true.
So hopefully, now, with the baseline testing, if we can improve on the testing.... In the baseline testing, for example, Mr. Rota, the industry is not even required to test for heavy metals or the BTAX, these contaminants that could get into drinking water. So right now we're not even able to assess the cumulative effects because the baseline testing standard isn't testing for the right things.
Mr. Cullen, I did point out to you that we did have a rough one here, which I'll just go through quickly. It's not written in stone, obviously. I'm quite happy to meet with one member from each party.
Basically, of course, we have put off Bill . It is hoped that we could deal with that on Thursday and thus get that private member's bill dealt with.
As I mentioned, on May 15 we have CO2 sequestration, and on May 17 we have my favourite subject, garbage gasification.
I would then propose that our next meeting date would be Tuesday, May 29. Hopefully, we could get the minister, which would accomplish what Mr. McGuinty—
An hon. member: [Inaudible--Editor]
The Chair: We're not here that week.
An hon. member: Oh, is that a break week?
The Chair: Yes.
On May 31, we could begin with witnesses, and so on, for Bill .
Now, that's just a rough proposal.
On June 5, four of us will be away at the G-8 plus five. I would propose cancelling that meeting because of members' being away.
That's kind of a rough, tentative schedule, if that helps at all.
Mr. Bigras, you're next.