On October 27, Minister Bruce Northrup and officials from the departments of Natural Resources and Environment starred in a webcast to answer questions about shale gas exploration and development. When invited to submit questions, I thought this was a perfect opportunity to try to get answers to my top five questions about fracking. The webcast was a pleasant surprise! While I’ve been mired in reading, trying to get detailed information about how fracking could unfold in New Brunswick, suddenly I had an “all-I-could-eat” buffet of the kind of information that I’ve been searching for. Specifically, how could fracking roll out in New Brunswick over the next 5-10 years? What does the government know that I don’t that makes them so comfortable with fracking?
Something that became obvious to me while watching the webcast is that the provincial government has a very clear and tangible idea of how shale gas exploration/extraction could unfold in New Brunswick. However, I just don’t think that the vision has been effectively communicated to date. When one looks at the shale gas web site for example, there are lots of PDF files full of general information, but what’s lacking is enough context to make it meaningful and practical. For me, the webcast served to “make it real” for probably the first time.
I thought I would jot down a summary of the answers provided in the webcast. My purpose here isn’t to debate the veracity or quality of the answers. I think it’s important to keep in mind that this information was delivered inside of an hour and more information is available. Also, it truly is early on in the process and there’s much to be decided in the coming years. The answers are somewhat vague and high-level at times due to circumstances. That said, it was a great start to a public conversation on fracking and there is a wealth of useful information here for concerned citizens.
Let’s start with some interesting facts provided during the webcast that I didn’t know, despite all of the reading I’ve done. Here’s some quick hits of interesting trivia about shale gas in New Brunswick:
At McCully Field operated by Corridor Resources, there are 30 wells producing. Discovered in 2000, McCully Field produces currently producing 18 million cubic feet per day. It’s been there for 10 years.
The Department of Natural Resources has a steering committee in place composed of nine people to oversee the rollout of this file. While examining the feasibility of shale gas in New Brunswick, they have visited other jurisdictions in Arkansas, Pennsylvania, British Columbia, and Alberta. Now, their job amongst other things is “working hard to get the facts out.”
The Shale Gas Steering Committee is also deciding upon the royalty regime for shale gas. The current proposal is a three-part royalty system where the biggest share goes to GNB, second largest part goes to the landowner, and a third part of the royalties goes towards the community itself.
Northrup claims that there is not a full moratorium on shale gas exploration in Quebec. Exploration and testing still ongoing according to him. Quebec’s industry won’t be full scale for 3-5 years down the road, just like New Brunswick.
New Brunswick is separated into three geologic zones. The zone referred to as the Carboniferous Maritimes Basin, which makes up about 40% of NB’s land mass, is the only place where there is potential for shale gas exploration and extraction.
With horizontal drilling, it’s possible to have “multi-well pads” that put 20 wells on a single pad (like Horn River). A multi-well pad could be 2 hectares in size, but cover 700 acres of land. The well head covers a small surface area, but extends over a large distance underground.
Now, on to the questions. It seems to me that there were three main types of questions asked out the 120 that were submitted to government. The first type of question addressed some of the fervent misinformation that is circulating around this issue.
What about the rumoured royalty break for industry in the first year of exploration? The minister said this was completely false, and unequivocally denied the rumour.
What about the radioactive radium-226 that comes up in the flowback? It is possible for naturally occurring radioactive material (NORM) to come up in the waste water, but we are not seeing any elevated levels of NORM to date in New Brunswick. Several parameters are being tested when water comes up to ensure that if it appears, it is handled appropriately by the waste water disposal facility.
Could “Gasland” happen here? The Shale Gas Steering Committee doesn’t feel that those circumstances translate to New Brunswick. For example, evaporation pits are not allowed in New Brunswick based on our regulations. Also, the government has discussed in the past how Gasland has been somewhat discredited in their view.
The next category of questions seems to be somewhat general and posed by people who want to understand fracking better, as well as the regulations that are (or will be) in place.
What kind of public consultation is required? Under the Phased Environmental Impact Assessment (EIA), there is a requirement for public consultation at every phase of the construction. Continuous public updates must be provided.
What’s the risk of an environmentally significant incident resulting from fracking? There is always risk, and these are being investigated by the steering committee to ensure strong regulations are in place.
When will stronger regulations be coming out for the public to see? Northrup says that the regulations have been in place for quite a while. Additional new regulations went into place on June 23, 2011, on top of a phased EIA. Northrup notes that the licenses provided to date are only to drill exploratory wells. He says that NB may have one exploratory well more this year, and 4-5 more per year in 2012-2013.
Will you allow communities to decide whether they want shale gas activity in their borders? Northrup says he’s been very clear that permission must be obtained to go onto a homeowner’s land. Companies simply cannot go onto their land without their permission. Also, permission must be sought from a municipality before exploration can happen within its borders. This may be cold comfort to some anti-fracking advocates who would also oppose fracking taking place on Crown land, but it may ease the concerns of some homeowners.
Will locations of potential sites be made public? Yes, this is part of the phased EIA process. Industry must “conduct baseline testing on all potable water wells within a minimum distance of 200 metres of seismic testing and 500 metres of oil or gas drilling before operations can begin. These will be minimum requirements and may be increased depending upon the situation.” It must also “provide full disclosure of all proposed, and actual, contents of all fluids and chemicals used in the hydraulic fracturing (fracking) process”; and “establish a security bond to protect property owners from industrial accidents, including the loss of/or contamination of drinking water, that places the burden of proof on industry.” (Source)
What is in place to ensure water is protected? Department of Environment officials say water protection is a top concern. DOE say they are watching both usage and supply very closely, including surface and ground water.
What plans are in place to handle increased truck traffic that will be required to reach well pads? The province of New Brunswick is 50 per cent Crown land. The minister says DNR wants to stay away from populated areas, away from roads, and preferably drill “in the middle of a forest.”
How many wells are we talking about? DNR does not have a clear idea because exploration is still ongoing. Licenses to explore are all that has been granted to date for the new wells. To extract the gas, companies need a license to lease land from GNB.
Are you able to name three dangers that result in hydro-fracking? The main concern is water, which is discussed in more detail below. Officials did highlight one other risk though. In Pennsylvania, “communication” (connectivity) exists with poorly-drilled or abandoned well bores from the past. New Brunswick also has a long history of oil and gas extraction and exploration, with over 300 wells drilled back to 1859. Communication with old wells could be a concern for us, but officials note that it’s not a major concern because we know where our old wells are.
What are the key experiences that Northrup has brought back from other jurisdictions? Northrup mentioned that he visited places where compressor stations were out in the open with no surrounding buildings, and they could be heard a half-mile away. Compressor noise will be addressed by regulations in New Brunswick. All compressors will be inside of utility buildings lined with at least six inches of noise-dampening insulation.
Air quality monitoring – what types will be done? The Department of Environment could be monitoring air quality eventually. Some testing has been done on the existing wells and nothing has been discovered to date.
What regulations are presently in place concerning noise, including low frequency noises? Also, what about dust and truck traffic – are there already regulations in place? Noise and dust are covered by the Department of Environment’s Clean Air Act, and restricted to 10db above present ambient levels. Some restrictions around compressor noise are covered by the Department of Energy’s Pipeline Act. Moving forward, the Shale Gas Steering Committee will be developing an environmental protection plan (EPP), and things like truck traffic will be addressed in the EPP.
The third large category of questions concerned technical questions about how fracking is performed, and how it could be specifically executed in New Brunswick:
What kind of processing takes place at the surface once the gas is brought up from shale by fracking? Once the gas is brought up to the well, it gets treated to a usable condition before distribution. Water flowback is separated from gas at the surface using a gas/water separator, and then it goes through a lateral pipeline to the gas plant where it is processed by cooling units. These cooling units lower the gas below the dew point to remove the heavier hydrocarbons (condensates), which can be sold to refineries. The “dryer” gas then goes into the main pipeline for distribution.
What is the composition of the fracking fluid that will be used in New Brunswick? How much will be left in the ground? The composition of the fracking fluid depends on the type of shale gas “play”. The percentages of the chemicals vary in each of the fluids depending on the shale. The fluid is used 2.5 kilometers underground, and won’t interfere with water aquifers. When issues occur, it’s usually with flowback around the wellhead.
Where does the water for fracking come from? There are a number of options proposed for NB as the Shale Gas Steering Committee continues looking at other jurisdictions, like reusing flowback water for example. While drinking water from municipal systems that had excess capacity have been used for fracking to date, non-potable water sources are planned to be used going forward. Some examples of non-potable water include use seawater or treated waste water from municipalities. But, DOE is also looking at surface water too and examining how it can be sustainably done. Other jurisdictions are using impoundments to collect rain water. Presently, water is trucked in but in the future temporary pipelines will very likely be used.
How is the waste water from fracking processed afterwards? Going forward, only “closed loop systems” will be used in NB; in other words, there will never be open air holding ponds for fracking waste water. For today’s wells, waste water flowback is collected in tanks and treated at a waste water facility in Debert, Nova Scotia. In Alberta, Northrup toured a water purification system on site at a well, and he implicitly suggested that a similar plant could be an option for New Brunswick in the future.
What’s the lifespan of the chemicals used in fracking fluid? The lifespan of the chemicals used in fracking fluid depends on composition and concentration of ingredients in the process being used. As mentioned earlier, regulations require disclosure of fluid ingredients. Some factors to consider are the soil conditions, solubility of the chemical, and fluid movement. The DOE official says it is not like PCB’s and DDT’s that have a very long life.
How many shale gas well sites in NB were drilled horizontally using fracking? How many were drilled under a lease and how many were drilled under a license to search? We have three wells drilled in the province to date – one directionally, and two were drilled horizontally and fracked (Apache wells in Elgin under a lease for Corridor Resources). Government says that companies can perform the same kind of work on a license to search as you can on a lease.
How long will each well last? It’s reasonable to assume that NB’s wells could last 20-30 years. When a well is done producing gas (or a well was drilled but not used), it needs to be “reclaimed” according to DNR regulations. The company submits a decommissioning plan to DNR which will involve a series of permanent cement plugs in various zones in the well bore, then a surface plug with a welded steel cap is affixed about 1.5 metres below the surface.
What are the effects of various levels of exploration on forest ability to conservation and timber supply targets? This question refers to “forest fragmentation”. Existing Crown logging roads will be used as much as possible to create “multi-use corridors” and haul routes. Multi-well pads will reduce forest fragmentation. At this time, it’s hard to say how it would work since it’s very early in the process.
What kinds of supporting infrastructure will be set up? How many compressors and gas treating facilities? DNR says it’s still early days but there are many kinds of possible infrastructure – gas plants, compressor stations, work-yards with steel casings, drilling rigs, and also man camps in the initial stages.
Who will pay if issues arise, and what type of liability rests with the company even if they’ve left the province? Companies are held liable in a few different ways. Under the Oil and Natural Gas Act, companies are liable and held accountable for restorations. There is a well-abandonment bond held in trust by DNR to reclaim a well. There is the surety bond (also known as “the no-quibble guarantee”) to handle things like possible on-site spills.
Are you still awake? Sorry for the long post, I wanted to squeeze all of this information into a single place. In the future, I’ll try to dig deeper into some of these answers as information becomes clearer. For now, I extend my kudos to the government for their communication efforts to date.