May 2011 - draft

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1.
Introduction ....................................................................................................................... 4
2.
Shale Gas Extraction: How it Impacts Water ................................................................... 8
2.1
Depleting Water Resources .......................................................................................... 8
2.2
Water Contamination Risks .........................................................................................10
2.2.1
Sub-surface contamination risks ..........................................................................11
2.2.2
Surface contamination risks .................................................................................13
2.2.3
Blow-out risks .......................................................................................................15
3.
Regulating the B.C. Gas Industry’s Water Use ..............................................................16
3.1
Overview of the Oil and Gas Commission ....................................................................16
3.2
Allocating Water ..........................................................................................................17
3.2.1
Untracked Uses ...................................................................................................18
3.3
Baseline Data ..............................................................................................................20
3.4
Disclosure ....................................................................................................................21
3.5
Disposal .......................................................................................................................21
3.6
Enforcement and Compliance ......................................................................................22
4.
Developments in Other Jurisdictions .............................................................................25
4.1
Disclosure ....................................................................................................................25
4.2
Hydraulic Fracturing Moratoriums ................................................................................26
5.
Recommendations ...........................................................................................................27
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British Columbia has been a producer of natural gas for half a century, and until recently, the conventional wisdom was that the province’s economic gas reserves would be significantly depleted within a decade. The readily accessible gas was running out and the other reserves were either too remote or too costly to extract. That conventional wisdom has been flipped on its head in the past several years because the costs of extracting hard-to-access sources of gas, notably shale gas, have dropped significantly. The impacts are far-reaching. B.C. is now sitting on gas reserves that are significant on a continental basis.
Shale gas (a type of unconventional gas) reserves are trapped in geological formations that make it difficult to extract the gas.
1
It is called unconventional because extraction relies on new technologies. The most important of these technologies are:
1.
hydraulic fracturing, which involves injecting pressurized water, gases, chemicals and sand into gas wells to break apart the rock and allow the gas to flow more easily, and;
2.
directional drilling, which allows multiple wells to be drilled from a single well pad.
B.C.’s shale gas reserves are found in the northeast, primarily in two main deposits: the Montney
Basin near Dawson Creek, and the Horn River Basin near Fort Nelson. According to projections from the Canadian Association of Petroleum Producers, production from Horn River and
Montney Basins could account for 22% of North American shale gas production by 2020 (see
Figure 1). The combined 52 billion cubic metres per year (5 billion cubic feet per day) forecast to
be coming the Horn River and Montney Basin in 2020 would be equivalent to 70% of the gas used in Canada in 2009.
2
1 Coalbed methane is another form of unconventional gas development. For further information, see: Coalbed
Methane: A Citizen’s Guide, May 2003, http://www.
wcel .org/wcelpub/2003/14027.pdf
2 Canadian Gas Association publications - http://www.cga.ca/publications/gasstats.htm
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Figure 1. Projected gas extraction for Canadian and U.S. shale gas reserves
Source: Canadian Association of Petroleum Producers. “Canada’s Shale Gas.” February 2010 www.capp.ca/GetDoc.aspx?DocID=165107&DT=PDF -
The shift to shale gas in North America is already well underway. The Barnett Shale in Texas has been subject to hydraulic fracturing and gas extraction since the late nineties. Likewise, companies have begun extracting gas from the Marcellus Shale, which sits under New York,
Pennsylvania, Ohio and West Virginia.
While the shift to shale gas started relatively recently in B.C., these sources still accounted for as much as 39% of B.C.’s natural gas production in 2008, predominantly from the Montney Basin.
3
The economic potential of exploiting the province’s shale gas reserves has been well documented. As an illustration, the province is counting on $1.8 billion in revenue from gas royalties and leases in 2013/14 – 4% of forecasted provincial revenues.
4
While jurisdictions with shale gas reserves are unquestionably attracted to the potential economic windfall, health and environmental concerns are also beginning to dominate the debate in some jurisdictions – particularly because of potential contamination of ground and surface water resources. Jurisdictions such as New York, Quebec, Maryland and France have all recently placed temporary moratoriums on hydraulic fracturing until the risks are better understood.
5
The
U.S. Environmental Protection Agency is also undertaking a major study to understand those impacts.
6
Health and environmental concerns from gas development are not new to British Columbia, where the northeast of the province has lived with oil and gas development for over 50 years.
There have been long-standing concerns about gas development fragmenting the B.C. landscape and endangering species that rely on those ecosystems (e.g. boreal caribou).
7
Numerous concerns have also been raised about the potential health impacts of sour gas leaks, including a recent call for a public inquiry supported by First Nations, landowners, and a range of organizations.
8
3 BC Ministry of Energy Mines and Petroleum Resources. Power Point Presentation. “Shale Gas Activity in British
Columbia: Exploration and Development of BC’s Shale Gas Areas.” Slide 7. April 8, 2010.
4 Charts 1.5 and 1.7 in the B.C. Government Budget and Fiscal Plan, 2011/2012 – 2013/2014, February 15, 2011.
5 New York - http://open.nysenate.gov/legislation/bill/A7400-2011 . Quebec - http://www.mddep.gouv.qc.ca/communiques_en/2011/c20110308-shale-gas.htm
. Maryland - http://mlis.state.md.us/2011rs/billfile/hb0852.htm
. France - http://www.businessweek.com/magazine/content/11_15/b4223060759263.htm
6 EPA TOR - http://water.epa.gov/type/groundwater/uic/class2/hydraulicfracturing/upload/HFStudyPlanDraft_SAB_020711.pdf.
7 See for example - Forest Practices Board, March 2011, A Case Study of the Kiskatinaw River Watershed (an
Appendix to Cumulative Effects: From Assessment towards Management) http://www.fpb.gov.bc.ca/SR39_CEA_Case_Study_for_the_Kiskatinaw_River_Watershed.pdf, p. 9 and Appendix
2.
8 Feb 2, 2011 - Letter from University of Victoria Environmental Law Centre on behalf of the Peace Environment and Safety Trustees Society – accessed March 29, 2011 -
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Depending on the pace and scale of development, shale gas extraction could continue or exacerbate these concerns. It also raises two additional environmental concerns that have received limited attention in B.C. to date:

Water Impacts . Hydraulic fracturing typically requires large volumes of water, which is a resource in short-supply in northeast B.C. Further, the water used for fracturing is contaminated through the process, so it cannot be returned to fresh water systems.

Climate impacts . Extracting and processing natural gas produces greenhouse gas emissions, and the gas sector already accounts for 20% of B.C.’s emissions.
9
Proposed increases in production combined with higher levels of emissions from an equivalent volume of shale gas (relative to conventional sources) will make it increasingly difficult, or impossible, for B.C. to meet its emissions reductions objectives.
Those water impacts are the focus of this report. Specifically:

Section 2 explores known and potential impacts to water resources from shale gas
extraction in B.C. While this report attempts to draw on the most recent research available, it is important to acknowledge that many knowledge gaps still exist and there is considerable uncertainty and variability in the data.

Section 3 discusses the current regulatory environment in B.C. for water use and disposal
in the oil and gas industry. In many cases, B.C.’s environmental protection is lagging behind the new pressures introduced by the anticipated pace of shale gas development and the new challenges associated with shale gas relative to conventional gas.

Section 4 provides an overview of regulatory developments in other jurisdictions
attempting to manage shale gas development or respond to development proposals.

Section 5 recommends ways in which B.C. can improve its planning and regulatory
framework for shale gas development to provide better protection for the province’s water resources.
This research fits into a context in which British Columbians strongly support better protection of B.C.’s water resources. A poll released late in 2010 found that 91% of British Columbians consider freshwater to be B.C.’s most precious resource, and 94% favour making the protection of nature and wildlife a priority in any changes to B.C.’s Water Act.
10
The B.C. government has started to respond to those public priorities by endeavoring to improve the way that water resources are protected and managed in the province.
11
A major part of that commitment is the effort to modernize the province’s Water Act , which, among other things, establishes the permitting regime for water uses by the oil and gas industry.
The degree to which the B.C. government responds to the questions and concerns raised in this http://www.elc.uvic.ca/documents/11%2002%2002%20Ltr%20to%20Hansen%20re%20Inquiry%20(final%20and%
20SIGNED).pdf
9 calculated from Environment Canada’s 2008 emissions inventory
10 http://assets.wwf.ca/downloads/bc_water_polling_summary___nov_2010_2.pdf
11 See http://www.livingwatersmart.ca/
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research will dictate the degree to which the province’s natural gas sector meets the expectations of British Columbians in terms of water stewardship.
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To extract shale gas, companies first drill long horizontal wells into the target formations and then pump hydraulic fluids down the well until the pressure within the formation builds to the point at which long (500 to 800 foot) fractures are created.
12
During the completion phase of the well, hydraulic fracturing is an ongoing process as different segments of the horizontal portion of the well must be fractured separately.
13
Hydraulic fluids are primarily fresh water (approximately 98%) with chemical additives and sand to prop open fractures. The amount of water needed varies depending on the type of shale gas formation. Companies use between 7.6 and 26.5 million litres of water per well on average to extract gas from the Marcellus Shale in the United States, with multiple wells drilled from each pad.
14
This is comparable to Shell’s experience in its Groundbirch operation in the Montney
Basin, where wells have required 5 to 10 million litres of water per well.
15
Some industry estimates for shale gas wells in northeast B.C. are significantly higher, ranging up to 90 million litres of water being needed per well.
16
A recent B.C. example came close to that estimate. In the spring of 2010, Apache Corporation conducted what was at the time, the largest North American hydraulic fracturing job ever, consisting of 274 separate fractures on a 16 well pad in the Horn River Basin.
17
A total of 980
12 WRI 2010
13 Ken Campbell, P.Geo Senior Hydrologist. Schlumberger Presentation on: “Shale Gas Development and Water
Issues In Northeastern British Columbia.” Slide 8. Canadian Institute Sixth Annual Shale Gas Conference. Calgary,
Alberta. January 26 – 27, 2010.
14 J. W. Ubinger, J.J. Walliser, C. Hall, R. Oltmanns, Pennsylvania Environmental Council, “Developing the Marcellus
Shale: Environmental Policy and Planning Recommendations for the Development of the Marcellus Shale Play in
Pennsylvania. July 2010.
15 Personal communications - Christa Seaman, Shell Canada, Emerging Regulatory Policy Issue Advisor - May 4,
2011.
16 Ken Campbell, P.Geo Senior Hydrologist. Schlumberger Presentation on: “Shale Gas Development and Water
Issues In Northeastern British Columbia.” Slide 9. Canadian Institute Sixth Annual Shale Gas Conference. Calgary,
Alberta. January 26 – 27, 2010.
17 Apache Corporation. Press Release: “The Horn River Project - Ootla team celebrates largest completions in
North America.” July 2010. Available at: http://www.apachecorp.com/explore/Browse_Archives/View_Article.aspx?Article.ItemID=1130
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million litres of fresh water was used to complete the operation, which amounts to an average of
61 million litres per well.
18
In the Horn River Basin, about 100 wells were to be drilled in 2010.
19
Over time though, continued drilling activity could dramatically impact water resources. For example, Apache
Corporation plans to drill 3,000 wells in the Horn River Basin.
20 Based on a range of 60 to 90 million litres of water required per well, the combined water used to fracture 3,000 wells would total 180 to 270 billion litres.
21
The Metro Vancouver region used 421 billion litres of water in
2009.
22
If the water demands were closer to the volumes needed in the Marcellus Shale (7.6 to 25.5 million litres per well), the total demands for 3,000 wells would range from 23 to 80 billion litres. Significantly, these amounts represent potential water usage for just one operator in the
Horn River Basin. They do not account for the other operators in the Horn River Basin or the operators in the Montney Basin.
To provide context, B.C. oil and gas companies were licenced or authorized to use 86.5 billion litres of surface water in 2009, plus an addition 6.7 billion litres authorized from groundwater wells.
23
If the shift to water-intensive shale gas resources continues and the level of activity in the gas sector also increases, there will almost certainly be pressure to increase those authorizations.
Putting these numbers into a more meaningful context – e.g. what will development in the
Montney Basin mean for the health of the Kiskatinaw watershed – is more challenging, and not possible with information currently available. Detailed answers depend on the characteristics of the watershed and the timing and volume of water withdrawals. Experience in B.C. does however demonstrate that the water demands for natural gas extraction can directly conflict with other priorities such as the health of a watershed. For instance, parts of northeast B.C. experienced ‘persistent and severe summer drought’ conditions in 2010, which prompted the Oil
18 Apache Corporation. Press Release: “The Horn River Project - Ootla team celebrates largest completions in
North America.” July 2010. Available at: http://www.apachecorp.com/explore/Browse_Archives/View_Article.aspx?Article.ItemID=1130
19 Horn River Basin Producers Group, Shale Gas Frequently Asked Questions. Accessed January 23, 2011 at http://www.northernrockies.ca/EN/main/business/economic-development/Horn_River_Basin/producers_Group.html
20 Oil & Gas Inquirer. “Big Stuff - British Columbia's shale and tight gas plays are already world-class, and there may be more to come.” December 2009. Available at: http://www.oilandgasinquirer.com/printer.asp?article=profiler%2F091201%2FPRO2009%5FD10000%2Ehtml No estimates of the number or density of well pads were available.
21 This calculation assumes no produced water is recycled in future fracturing operations. Based on WRI report, there is a potential for up to 25% recycling in the Marcellus Shale. The same percentage applied to B.C. shale gas operations would drop the estimate to between 135 and 202.5 billion litres.
22 Metro Vancouver – “Water Consumption Statistics 2009” http://www.metrovancouver.org/about/publications/Publications/2009WaterConsumptionStatsReportNew.pdf
23 Oil and Gas Commission (2010) – Oil and Gas Water Use in B.C.
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and Gas Commission to suspend surface water withdrawals in four river basins in the Peace
Region for several months.
24
While drought conditions were an important part of this incident, increasing demand for water from the natural gas sector will increase the likelihood of similar incidents occurring on rivers throughout the Peace.
The potential for these demands to dominate a localized area are clearly demonstrated in Dawson
Creek. Bulk water sales from the City to the oil and gas industry have doubled every year since
2004, and in 2008, 340 million litres – or 16% – of Dawson Creek’s drinking water supply was sold to the oil and gas industry for use in its operations.
25
These bulk water sales are on top of the short-term uses allocated to the oil and gas industry from streams, rivers, and lakes in the region, and other untracked uses that are arranged for.
There are opportunities to reduce fresh water demands including: recycling produced water, using saline water and using wastewater from other users. An example of a project in this category is Shell’s agreement to help finance a wastewater treatment facility for Dawson Creek, with an agreement that Shell will have access to 3.4 million litres of treated water per day of the plant’s total output of 5 million litres per day.
26
Shell anticipates this project will meet their water needs for the 10-year duration of the agreement.
27
The potential applicability of these types of alternatives on a broad scale is not well understood and they are not currently the norm in industry practice.
The composition of fracture fluids can vary widely. In shale gas extraction, typical fluids are composed of water, sand and chemicals. Contributing up to 2% by volume, these additives vary depending on the target rock formation. Typical additives include ‘friction reducers’ to reduce the resistance to the movement of the fluid through the well casing, ‘biocides’ to prevent bacteria colonization and growth that can lead to formation of hydrogen sulphide, and ‘scale inhibitors’ to prevent material build up on the casings, and sand or ceramic beads to hold fractures open.
28
The New York State Department of Environmental Conservation (NYSDEC) has compiled a list of nearly 200 chemicals used or proposed for use in hydraulic fracturing of the state’s shale gas
24 BC Oil and Gas Commission. “Water Use Suspension Directive 2010-05: Suspension of Surface Water
Withdrawals (Peace River).” Aug 11, 2010. Available at: http://www.ogc.gov.bc.ca/documents/directives/dir_2010-05_Suspension_of_Surface_Water_Withdrawals.pdf
25 Personal communications, Cheryl Shuman, Councilor, City of Dawson Creek, 2010.
26 Accessed May 19, 2011 http://utilities.worldconstructionindustrynetwork.com/news/dawson_creek_shell_canada_to_build_wastewater_treat ment_plant_100930/
27 Personal communications, Christa Seaman, Shell Canada, Emerging Regulatory Policy Issue Advisor - May 4,
2011.
28 U.S. Department of Energy, Office of Fossil Energy, National Energy Technology Laboratory, State Oil and
Natural Gas Regulations Designed to Protect Water Resources, May 2009.
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deposits. While some of the chemicals are not hazardous, NYSDEC notes significant potential negative health effects from others.
29
Industry representatives state that genuinely non-toxic fracture fluids are available for some applications, although they cost more than typical fluids.
30
In addition to the fracturing fluids, water contained in shale gas and adjoining geologic formations is often released (or produced) during hydraulic fracturing. This produced water can display high concentrations of salts, naturally occurring radioactive material (NORM), and other contaminants including arsenic, benzene, and mercury.
31
The amount of saline formation water produced from gas shales varies widely, from none to tens of thousands of litres per day.
32
The net effect is that the water used in hydraulic fracturing is heavily contaminated by fracturing fluid chemicals and by the salts and dissolved solids found in the target formation. For example, wastewater from Marcellus Shale operations can be up to one-third total dissolved solids by volume, or as much as 10 times more saline than seawater.
33
This type of wastewater mixture kills vegetation and severely degrades soil quality if discharged on land, it is harmful to aquatic life and fish, and can seriously degrade the quality of groundwater.
Recycling and reusing this water is an option, and is in some cases being done by industry.
However, where this does not occur it is important that the water be handled as safely as possible, and reinjected back into deep well aquifers (as required by B.C. Oil and Gas
Commission).
2.2.1 Sub-surface contamination risks
The primary concern related to sub-surface contamination, which is not limited to shale gas extraction, is potential failures in the steel and cement casings that surround gas wells. These casings are designed specifically for hydraulic fracturing operations to prevent any contact between the contents of the well and the surrounding rock and water underground. If they are improperly sealed, natural gas, fracturing fluids, and formation water can leak outside of the well into the target formation, drinking water aquifers, and layers of rock in between.
34
29 NYSDEC, Draft Supplemental Generic Environmental Impact Statement on the Oil, Gas and Solution Mining
Regulatory Program: Well Permit Issuance for Horizontal Drilling and High-Volume Hydraulic Fracturing to
Develop the Marcellus Shale and Other Low-Permeability Gas Reservoirs (Albany, NY: NYSDEC, 2009), 5-33–5-
65. Available online at http://www.dec.ny.gov/energy/58440.html.
30 Keith Kohl, “Making Hydraulic Fracturing Cleaner: Industry Insider Explains ‘Green’ Fracking Technologies,”
Energy and Capital, April 5, 2010.
31 WWI – 2010.
32 NRCAN footnote
33
J. W. Ubinger, J.J. Walliser, C. Hall, R. Oltmanns, Pennsylvania Environmental Council, “Developing the
Marcellus Shale: Environmental Policy and Planning Recommendations for the Development of the Marcellus Shale
Play in Pennsylvania. July 2010, p. 29.
34 Page 8 WWI fracturing paper
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Migration of natural gas to the surface, including into water wells and other surface structures, as a result of inadequate cementing/casing of oil or gas wells (in some cases old, abandoned wells), has been clearly established in multiple settings, including oil wells in Alberta and coalbed methane wells in the U.S.
35
In 2009 the Pennsylvania Department of Environmental Protection established that faulty cementing/casing of modern shale gas wells was the cause of gas migration into the water supplies of 14 homes. The company at fault (Cabot Oil and Gas
Corporation) failed to initially remedy the problem, and was eventually required to cap the wells, install water systems in the impacted homes, suspend drilling for one year in the area impacted by gas migration, and pay $240,000 into state’s well plugging account.
36
In 2007, a well that had been drilled almost 4,000 feet into a tight sand formation in Bainbridge, Ohio was not properly sealed with cement, allowing gas from a shale layer above the target tight sand formation to travel into an underground source of drinking water. The methane eventually built up until an explosion in a resident‘s basement alerted state officials to the problem.
37
A recent study from Duke University compiled systematic evidence for methane contamination of drinking water associated with shale gas extraction, and affirmed well-casing failures as the most likely cause of groundwater contamination.
38
The same study also raised an additional potential pathway for contamination in that methane could be migrating through a network of existing and created fractures towards the surface. It characterized this pathway as less likely than well-casing failure, but a concern that merited further investigation.
Concerns have also been raised about the potential for contaminated water to migrate directly between layers of shale gas and ground water aquifers. The likelihood of such an occurrence in most shale gas formations is considered very low because of their significant depth relative to groundwater aquifers. For example, the Montney and Horn River basins are at depths of 1,700 to
4,000 metres and 2,500 to 3,000 metres respectively.
39
This compares to the normal depth of domestic potable water wells in northeastern B.C., which is between 18 and 150 metres.
40
This expectation was confirmed by the Duke study, where they found no evidence of contaminants apart from methane.
41
35
Ibid., 67–69.
36 John Hanger, Secretary, Department of Environmental Protection, testimony before the Senate Environmental
Resources and Energy Committee, June 16, 2010. Available online at http://files.dep.state.pa.us/AboutDEP/AboutDEPPortalFiles/RemarksAndTestimonies/TestimonyEOGSafety_06161
0.pdf.
37 Source: WWI: Addressing the Environmental Risks from Shale Gas Development / Ohio Department of Natural
Resources, Division of Mineral Resources Management, ― Report on the Investigation of the Natural Gas Invasion of Aquifers in Bainbridge Township of Geauga County, Ohio,” (Columbus, OH: 1 September 2008
38 Osborn et. al. 2011 – Methane contamination of drinking water accompanying gas-well drilling and hydraulic fracturing
39 NRCAN briefing note on shale gas formations – table 1.
40 OGC 2010 water report
41 Osborn et. al. 2011 – Methane contamination of drinking water accompanying gas-well drilling and hydraulic fracturing
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The risk of contaminated water migrating directly between layers of shale gas and ground water aquifers has not been explored in detail for shallow shale gas deposits. Two shale gas deposits that display these characteristics are the Colorado shale (southern Alberta and Saskatchewan) and Utica shale (southern Quebec), which are at depths as shallow as 300 metres and 500 metres respectively.
42 In cases where shale gas deposits are at shallower depths, the B.C. Oil and Gas
Activities Act allows hydraulic fracturing in any wells as shallow as 600 meters, and opens the potential for shallower operations.
43
2.2.2 Surface contamination risks
Risks of surface contamination arise primarily from the transport and treatment of the recovered hydraulic fracturing fluids and any produced water. The necessity to routinely store and transport and ultimately dispose of large volumes of wastewater introduces the risk of spills to land, water, and groundwater. Temporary storage tanks, transport trucks, and pipelines can all leak or spill.
Spills of large volumes of wastewater are a familiar concern in the conventional upstream oil and gas industry and these spills of produced water generally far exceed spills of oil by volume. In
Alberta, oil and gas companies spilled 23.3 million litres of produced water compared to 6.8 million litres of oil in 2009.
44
There is also concern about how flowback waters are stored on site. While in some cases these contaminated waters are stored in tanks, they also may be stored in pits, which are more likely to leak due to improper lining or liner failure.
Estimates as to how much of the hydraulic fracturing fluid is recovered vary widely depending on the shale formation. For example:

British Columbia Oil and Gas Commission states that roughly 50 – 90% of fracturing fluids are recovered.
45

United States Environment Protection Agency states that 60 to 80% of fracturing fluids are recovered.
46

The Post-Carbon Institute states that between 30% and 70% of the injected water is brought back to the surface, in addition to any formation water present.
47
42 NRCAN briefing note on shale gas formations – table 1.
43 B.C. Oil and Gas Activities Act - Section 21 - http://www.bclaws.ca/EPLibraries/bclaws_new/document/ID/freeside/536427494#section18
44 ERCB ST57-2010: ERCB Field Surveillance and Operations Branch Provincial Summary 2009
45 BC OGC Fracturing (fracing) and Disposal of Fluids Fact Sheet.
46 See: U.S. Environmental Protection Agency. August, 2002. DRAFT Evaluation of Impacts to Underground
Sources of Drinking Water by Hydraulic Fracturing of Coalbed Methane Reservoirs. EPA 816-D-02-006. P. 7-3.
47 Will Natural gas fuel America in the 21 st Century? - David Hughes, Post-carbon institute (page 24) - May 2011
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
World Watch Institute states that roughly 25% of the fracturing fluids from Marcellus shale are recovered.
48
The B.C. Oil and Gas Commission keeps statistics on disposed water for the entire industry, and
the volumes of disposed water have risen considerably. As shown in Figure 2, approximately 1.2
billion litres of produced water was disposed in 1990, which rose to 4.2 billion litres in 2009 (an average increase of 7% per year).
49
Figure 2. Annual subsurface water disposal and injection in B.C.
Source: B.C. Oil and Gas Commission, Oil and Gas Water Use in B.C.
Treating and reusing recovered water is the best overall approach, because doing so minimizes the need for additional freshwater extraction. Currently, flow-back water is infrequently reused because of the potential for corrosion or scaling, where the dissolved salts may precipitate out of the water and clog parts of the well or the formation.
50
Pilot projects are underway in the Barnett
Shale (Texas) to explore the potential of distillation to allow recovered water to be re-used.
51
48 WWI – 2010 – page 10
49 The 4.2 billion litres disposed is a small fraction of the 86 billion litres allocated for use. This discrepancy could occur for a variety of reasons such as water allocations not being fully utilized, volumes of produced water being low relative to water consumed, and volumes of produced water being underreported. The exact cause (or causes) for this discrepancy are not currently clear.
50 NRCAN briefing note.
51 NRCAN briefing note.
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Deep well disposal of residual water that cannot be reused is the next best approach for disposal.
The success of this disposal method depends on stringency of the rules that govern the siting and design of the disposal wells, the monitoring regime that is used, and the government enforcement system. Where pits are used to store recovered water, the best approach would be to build a double lined pit with leachate collection and leachate monitoring in order to be as effective as a tank with standard overflow monitors and secondary containment.
2.2.3 Blow-out risks
Uncontrolled fluid and gas releases can occur when pressures encountered during drilling and fracturing exceed the ability of the drilling mud used to contain fluids and gases (blow-outs). The recent BP Deepwater Horizon disaster in the Gulf of Mexico is a particularly notorious example of this type of accident.
52
There have also been recent gas well blowouts in Pennsylvania and West
Virginia during drilling operations in the Marcellus Shale.
53
The risks of such blowouts are exacerbated in shale gas extraction because of the potential for pressures to change unpredictably due to nearby fracturing activity. For instance, the B.C. Oil and Gas Commission issued a safety directive in May 2010 after it found 18 instances where hydraulic fracturing led to connections being formed between the fractures of adjacent wells or drilling intersected a fracture from another well. The incidents resulted in hazardous changes in pressure during drilling that can result in suspended production, substantial remediation costs and pose a potential safety hazard.
54
In that safety advisory, the Oil and Gas Commission states:
“Fracture propagation via large scale hydraulic fracturing operations has proven difficult to predict. Existing planes of weakness in target formations may result in fracture lengths that exceed initial design expectations.”
All of the recorded incidents were successfully controlled, but they still resulted in up to 80,000 litres of produced fluids coming to the surface.
55
52 Justin Gillis and John M. Broder, “Nitrogen-Cement Mix Is Focus of Gulf Inquiry,” New York Times , May 11,
2010, A13.
53 WWI - 2010
54 BC Oil and Gas Commission. “Safety Advisory 2010 – 03: Communication During Fracture Stimulation.” May
20, 2010. Available at: http://www.ogc.gov.bc.ca/documents/safetyadvisory/SA%202010-
03%20Communication%20During%20Fracture%20Stimulation.pdf
55 BC Oil and Gas Commission. “Safety Advisory 2010 – 03: Communication During Fracture Stimulation.” May
20, 2010. Available at: http://www.ogc.gov.bc.ca/documents/safetyadvisory/SA%202010-
03%20Communication%20During%20Fracture%20Stimulation.pdf
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In order to fully understand the scope of the potential issues associated with shale gas development in B.C., it is important to have an understanding of how government regulations operate with respect to water use by industry. As will be shown below, there are concerns about the adequacy, independence and comprehensiveness of oversight at this time.
Oversight of oil and gas activities is shared among a number of provincial government bodies, primarily the Ministry of Energy and Mines 56 , and the Ministry of Forests, Lands and Natural
Resource Operations
57
. Government changes announced in October 2010 and March 2011 have resulted in a re-alignment of roles and responsibilities for resource development in British
Columbia, the implications of which are not yet fully understood.
The Ministry of Energy and Mines remains the primary ministry with policy responsibility for oil and gas development, while responsibility for oversight and implementation of the oil and gas regime in B.C. lies with the Oil and Gas Commission.
58 It was initially designed to be independent of the B.C. government, but a legal change in 2002 minimized this independence, giving the Deputy Minister of the Ministry of Energy a role on the Board of the Commission.
59
This effectively means that the B.C. government can influence the operational activities of its independent regulator.
The recent government changes have moved the Oil and Gas Commission to the Ministry of
Forests, Lands and Natural Resource Operations, in an effort to further streamline government approvals. Currently, the Oil and Gas Commission Board of Directors reports to the Minister of
Forests, Lands and Natural Resource Operations, and the Deputy Minister is the Chair of the Oil and Gas Commission’s Board of Directors. The other two board members are the CEO of the
Commission and an industry representative.
56 Formerly the Ministry of Energy.
57 Formerly the Ministry of Forests, Mines and Lands, and the Ministry of Natural Resource Operations.
58 Authorized under the Oil and Gas Commission Act [SBC 1998] Chapter 39
59 Bill 36: Energy and Mines Statutes Amendment Act, 2002. http://www.leg.bc.ca/37th3rd/1st_read/gov36-1.htm
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The Water Act requires that water users obtain water licenses for water usage. These are generally overseen by the Ministry of the Environment, with one notable exception: there is a provision in the Water Act that allows proponents to apply for a short term water permit for temporary uses of up to 1 year.
60
Administrative arrangements have been made with the Oil and Gas Commission, who oversee these provisions on behalf of the Ministry of the Environment. This means that in many instances, oil and gas users do not obtain permits from the Ministry of Environment, rather they do so from the Oil and Gas Commission. The Oil and Gas Commission does establish basic conditions for the granting of these “Section 8 permits”, 61
however, the level of oversight falls short of the process that an applicant must go through for a water license.
The oil and gas industry has generally opted to secure access to water through these section 8 permits rather than full licenses. In principle, the section 8 permits are granted for temporary one year uses, although in practice the gas sector is a year after year user of water requiring ongoing, steady access. Of the 86.5 billion litres authorized for use by the oil and gas sector in 2009, 78.6 billion litres was approved under section 8 permits (there were 807 approvals).
62
In addition, there are 40 licensed groundwater wells that have produced almost 6.7 billion litres of water over the years. It is noteworthy that while B.C. lacks comprehensive groundwater legislation, the Oil and Gas Commission requires companies using groundwater for hydraulic fracturing and other purposes to account for such withdrawals.
63
As of summer 2010, oil and gas companies had only nine active water licences, whereas there were at least 1,115 streamlined water permits in recent years.
64
Figure 3 shows the respective
usage of water licenses and short-term water use permits across B.C. in 2010. More recently, there are 13 active water licences, but the B.C. government’s water licence database is not fully current, meaning that the full extent of water licence applications in the system is not publicly available.
65
The discrepancy in water allocation processes raises serious concerns that the Oil and
Gas Commission authorizations represent a regulatory loophole that allows the oil and gas industry to secure relatively simple access to water resources with reduced requirements and oversight than other water users.
60 Water Act, R.S.B.C. 1996, c. 483, s. 8.
61 See BC Oil and Gas Commission, Oil and Gas Water Use in British Columbia, August, 2010, p. 9.
62 BC OGC – 2010 water report
63 Parfitt, Fracture Lines, p. 27.
64 Water license information obtained from the province’s Land and Resource Data Warehouse (LRDW) http://www.lrdw.ca/. Short term water use permit info from the OGC’s GIS data page http://www.ogc.gov.bc.ca/publiczone/gis.aspx.
65 Personal communication with Ben Parfitt, February 2011.
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Figure 3. The map on the left shows the distribution of water licenses across the province, whereas the map on the right illustrates that short term water use permits are granted extensively, and almost exclusively in northeast B.C.
Oil and gas companies are required to record the amount of water actually used under their permits and licenses, and although the Oil and Gas Commission has the ability to audit that information, it is not reported publicly.
66
3.2.1 Untracked Uses
According to the Oil and Gas Commission, the 86.5 billion litres and 6.7 billion litres authorized for the oil and gas industry to use from surface and ground water resources respectively are not comprehensive. They do not include water produced as a by-product of oil and gas production
(e.g. recycling produced water from hydraulic fracturing), or private agreements with others who have surface licenses or groundwater access (e.g. private landowners).
67
On this latter point, we are unaware of any system to even compile independent arrangements with landowners. One example is that in 2008, 340 million litres – or 16% – of the Dawson
Creek drinking water supply was sold to the oil and gas industry in its operations. Bulk water sales by Dawson Creek to the oil and gas industry have doubled every year since 2004, so this trend has been steadily increasing. This drinking water usage is on top of the short-term uses allocated to the oil and gas industry from streams and lakes in the region as well as the
Kiskatinaw River.
68
66 OGC water report - 2010
67 Oil and Gas Water Use in British Columbia, Exec Sum and p. 7
68 Personal communications, Cheryl Shuman, Councilor, City of Dawson Creek, 2010.
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There are other potential means through which the oil and gas industry may be accessing water that also fall outside the water licensing and permitting process. One such example is an Oil and
Gas Commission approved plan by Nexen to dig a borrow pit measuring 560 metres long, 200 metres wide and 13 metres deep near the Horn River Basin, which would be used as a water reservoir with water either pumped into the pit or allowed to infill naturally.
69
It is unclear if the water to be used from the borrow pit would fall under other authorization processes. A pit of those dimensions would hold 1.5 billion litres of water.
The Fort Nelson First Nation, upon whose territory the Horn River Basin lies, has reported that there are upwards of 50 similar borrow pits in their region.
70
Recent correspondence by the Oil and Gas Commission to the Fort Nelson First Nation further confirms that more than 40 per cent of all the freshwater used at Apache Canada’s record-setting hydraulic fracturing operation, originated from a network of borrow pits in the vicinity of its well site, all of which was activity
(400 million litres worth) outside the purview of the Water Act.
Similarly, a Forest Practices Board cumulative effects assessment of the Kiskatinaw River
Watershed near Dawson Creek confirms that there is a great deal of uncertainty about sources, when they are abstracted and how much the allocations are:
We know that the natural gas industry has a substantial permitted or approved volume that can be abstracted (0.19 m
3
per second) but we have no information on how much of that allocation is actually used or when it is abstracted. We also know that a portion of the water used by the natural gas industry comes from unrecorded sources such as groundwater wells or borrow pits and dugouts. As of 2007, there were at least 180 dugouts, mostly on private land, and 257 borrow pits, mostly on Crown land, in the study area. Very little is known about the amount of water that is pumped out of the groundwater wells in the area.
71
In discussing the potential implications of the lack of information regarding water use in the oil and gas sector, the Forest Practices Board report concludes that:
...we in no way imply that the citizens of Dawson Creek should be unconcerned about issues of water quantity or quality. In particular, there have been episodes in the past of very low flow (zero, in fact). Depending on when these occur in the future, the consequences for Dawson Creek could be severe.
72
69 http://telegraphjournal.canadaeast.com/rss/article/1366704 , Worried About Gas Exploration? Look to B.C., Ben
Parfitt. This plan is approved under Section 14 of the Land Act, not under the Water Act.
70 Get reference from ben or someone in FN
71 Forest Practices Board, March 2011, A Case Study of the Kiskatinaw River Watershed (an Appendix to
Cumulative Effects: From Assessment towards Management) http://www.fpb.gov.bc.ca/SR39_CEA_Case_Study_for_the_Kiskatinaw_River_Watershed.pdf, p. 27.
72 Forest Practices Board, March 2011, A Case Study of the Kiskatinaw River Watershed (an Appendix to
Cumulative Effects: From Assessment towards Management) http://www.fpb.gov.bc.ca/SR39_CEA_Case_Study_for_the_Kiskatinaw_River_Watershed.pds, p. 3.
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While there is some publicly available information about oil and gas industry water allocation in northeast B.C., there are many other uses that are either not permitted, not associated with the oil and gas industry, or both. As a result, significant questions about the full water use by industry are not possible to answer currently.
The B.C. government has no groundwater observation data for northeast B.C. The provincial network of groundwater observation wells includes 146 wells, and there are two in northeast
B.C. near Charlie Lake and Tumbler Ridge.
73
And while oil and gas activity has been occurring in northeast B.C. for years, no records have been compiled of any of the previous impacts of existing water use in the region.
74
Implicit in this concern is that there is limited understanding of the respective demands for water by the environment, by people and by competing uses such as agriculture.
Geoscience BC, industry-led organization seeking to encourage mineral and oil & gas exploration investment in British Columbia, is currently undertaking a study which will develop a database of surface water, ground water and saline aquifers in the Montney region.
75
However this work began in October 2010, well after many of the tenures were granted and initial drilling activity had already commenced. Geoscience BC has also conducted some research into the aquifers in the Horn River Basis to assess their ability to supply water for hydraulic fracturing and accept produced water from fracturing activities. The results of the study indicate that within the broader Horn River Basin there are large volumes of saline water that could be used for fracturing and the potential to dispose of large volumes of wastewater. The degree to which that availability matches well with specific areas of operation will be varied and is still uncertain.
76
A 2010 report by the B.C. Auditor General has confirmed that there are concerns about the level of knowledge about water resources in the province. The B.C. Auditor General concluded that:
 the Ministry of Environment’s information about groundwater is insufficient to enable it to ensure the sustainability of the resource;
 that groundwater is not being protected for depletion and contamination or to ensure the viability of the ecosystems it supports;
73 Data for the two Peace Region wells is available here - http://www.env.gov.bc.ca/wsd/data_searches/obswell/waterlevels/obs_wells_Region_7B.html.
74 The need to improve the manner in which groundwater issues are addressed is one of the identified priority areas in the Water Act Modernization process. See British Columbia’s Water Act Modernization, Policy Proposal on
British Columbia’s new Water Sustainability Act, December 2010.
75 http://www.geosciencebc.com
. October 14, 2010, News Release Announcing Montney Water Project.
76 Petrel Robertson, January 2010 - http://www.geosciencebc.com/i/project_data/GBC_Report2010-
11/HRB_Aquifer_Project_Report.pdf
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 that control over access to groundwater is insufficient to sustain the resource and that key organizations lack adequate authority to take appropriate local responsibility.
77
B.C. does not currently require companies to disclose the chemicals and additives used in hydraulic fracturing operations either to the regulator or to the public. The Oil and Gas
Comission’s factsheet Fracturing (Fracing) and Disposal of Fluids , makes no mention of any potential dangers, chemical additives or toxic materials that could be included in fracturing fluids.
78
Similarly, the National Pollutant Release Inventory, which is a federal public inventory of pollutant releases, expressly exempts oil and gas exploration and drilling activities from its reporting requirements.
79
However, the Oil and Gas Commission is aware of increasing public calls for disclosure of the chemicals used in hydraulic fracturing operations and the growing likelihood that disclosure will be required by various federal and state regulators in the United States. In June 2010, the Oil and
Gas Commission said it was anticipating changes to the provincial Oil and Gas Activities Act that would “...
enable the Commission to require reports and analysis on all oil and gas activities, including components of frac fluids.
” 80
The website fracfocus.org provides a public database that discloses the chemicals used in hydraulic fracturing operations. Industry decisions to provide information to the database are voluntary.
In B.C., companies are required to dispose of wastewater from shale gas wells by deep well injection (e.g. injected into old gas wells) or can elect to transport it to an approved treatment facility (which would be regulated under the province’s Environmental Management Act ). We are not aware of any public information on the adequacy of these practices and are unable to comment on them.
The Drilling and Production Regulation under the Oil and Gas Activities Act permits the use of clay pits to store liquid waste material. Section 51 establishes the conditions under which pits are allowed.
77 An Audit of the Management of Groundwater Resources in British Columbia. Report 8: December 2010.
Executive Summary.
78 BC Oil and Gas Commission. Factsheet: “Fracturing (Fracing) and Disposal of Fluids.” Available at: http://www.ogc.gov.bc.ca/documents/publications/Fact%20Sheets/15_Fracturing%20%28Fracing%29%20and%20
Disposal%20of%20Fluids.pdf
79 Guide for Reporting to the National Pollutant Release Inventory, 2009, Section 3.2.2. located at: http://www.ec.gc.ca/inrp-npri/default.asp?lang=En&n=C07CFADA-1
80 OGC 2010 – page 18.
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Problems with enforcement and compliance in B.C.’s oil and gas sector have been previously documented. In 2005, an Ecojustice report noted that Oil and Gas Commission field inspection statistics in 2003 revealed that 62% of inspections identified infractions, and that the rate was
64% in 2004. A joint agency audit (including provincial ministries and the federal Department of
Fisheries and Oceans) revealed that 20% of activities were operating in disregard of the law or posed an immediate threat to the environment.
81
Similarly, a recent report by the B.C. Auditor General on the Oil and Gas Commission’s record of addressing contamination has been sharply critical.
82
Some of the conclusions that relate to compliance and enforcement include:

The public information provided by the Oil and Gas Commission on its oversight activities is not sufficient to allow the Legislative Assembly and public to understand how effectively oil and gas site contamination risks are being managed (p. 6)

That the Oil and Gas Commission’s own reported compliance rate of 98% for the
2007/08 year was deficient for two main reasons. First, because it represented the state of compliance only after operators had taken steps within the prescribed time period to remedy deficiencies found during inspections and that the initial rate of compliance before corrections were made was not reported. Second, because the Oil and Gas
Commission was unable to confirm how many inspection parameters checked related to site contamination risks. (p. 10)

That the Oil and Gas Commission does not report publicly on how many of the sites had at least one deficiency nor the number of inspections that involved a serious or major deficiency that had the potential to cause an adverse impact on the public, the environment, or both (p. 11)
While many of these recommendations have been made in some form before, it is notable that the Auditor General is now recommending that:

That the Oil and Gas Commission improve its information collection system and public reporting in order to improve transparency and accountability, including information such as the general compliance rate, statistics before and after deficiencies have been corrected, the significance of non-compliance, the degree to which the non-compliance relates to site contamination and other categories of significant deficiencies, and whether the deficiencies have been rectified.
A brief comparison of Oil and Gas Commission Field Inspection reports from 2008/2009 and
2009/2010 reveals that while some of the issues identified in the Auditor General report (such as
81 This Land is Their Land: An Audit of the Regulation of the Oil and Gas Industry in B.C., Ecojustice (formerly
Sierra Legal Defence Fund), June 2005, pp. 27-8.
82 B.C. Auditor General, Oil and Gas Site Contamination Risks: Improved Oversight Needed, 2009/2010, Report
Number 8, February 2010.
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the nature of the deficiency) are being addressed, non-compliance remains a going concern.
83
As
shown in Table 1, the number of wells drilled declined from 845 to 634, and the number of site
inspections remained relatively constant at 4,337 (4,359 in the previous year). While the noncompliance rate has declined, the review found that 17% of sites inspected were deficient, and almost all of these deficiencies were in the “serious” or “major” category (“minor” being the third classification). It is also noteworthy that these non-compliant sites are only listed after requests to address the deficiencies have not been satisfied.
Table 1. Selected Summary Data from the Field Inspection Reports
Number of wells drilled
Number of site inspections performed
Total number of sites with deficiencies overdue 84
Total number of sites with serious or major deficiencies overdue
Number of warnings issued
2008/09
845
4,359
1,130 or 25.9%
1,047 or 24.02%
22
2009/10
634
4,337
756 or 17.4%
723 or 16.7%
21
Number of prosecutions/tickets issued 26 or 0.69% 30 or 0.60%
One of the principles of good compliance policy is that a variety of tools be available to the regulator, ranging from work orders and warnings through to prosecutions. The relatively high rate of high rate of non-compliance in combination with a very low rate of prosecution (less than
1%) raises concern that the full range of tools is not being adequately deployed to deter and penalize violations.
A recent review by West Coast Environmental Law found that in 2009, the Ministry of
Environment had the lowest level of environmental convictions in 20 years.
85
One of the main reasons cited by West Coast Environmental Law is the extensive budget cutbacks and reduced staffing levels that have become the norm in the past 10 years, making it more difficult for prosecutions to be pursued.
One effective element of Ministry of Environment practice is the Quarterly Compliance and
Enforcement Summaries, which name individual polluters and the nature of the action taken against them.
86
In contrast, the Oil and Gas Commission Field Inspection reports merely list infractions, not the names of companies or the specifics of the actions taken against them. This additional level of detail would help to increase public understanding of the nature of oil and gas
83 2009/10 BC Oil and Gas Commission Field Inspection Annual Report, Oil and Gas Commission, page 9. 2008/09
BC Oil and Gas Commission Field Inspection Annual Report, Oil and Gas Commission.
84 An “overdue” deficiency is described in the reports as situations where the operator had already been asked to remedy a deficiency, but the deficiency has not been remedied in the allotted time frame.
85 http://wcel.org/resources/environmental-law-alert/bc-fails-halt-collapse-environmental-enforcement-2009
86 See http://www.env.gov.bc.ca/main/prgs/compliancereport.html#2010
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industry non-compliance and also provide a better sense of which companies are exhibiting poor performance.
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In the United States, hydraulic fracturing techniques have been used for years, and recently have been the source of increased controversy. In response to increased activity by the industry throughout the U.S., there have been calls for both improved government oversight and for the disclosure of the chemicals that are used in hydraulic fracturing. The adequacy of the information disclosed to the public about these chemicals and the risk they pose to human health and the environment has been a major issue in the U.S.
87
Similar questions are being raised in other jurisdictions where shale gas extraction has been proposed (e.g. France and Quebec).
Changes at both the federal and sub-national levels are strengthening government understanding and oversight of shale gas activity.
As of September 2010, the State of Wyoming requires companies to submit a full list of the chemicals they plan to use during fracturing operations for each individual well. Once fracturing operations are completed, companies must report the concentrations of each chemical used.
These are the most stringent disclosure requirement in the US.
In 2008, Colorado was the first state to require companies to disclose chemicals used. The rule requires that companies disclose the chemicals used in fracturing fluids to health officials and regulators, but not the public. This disclosure is only required for chemicals stored in 50 gallon drums or larger.
88
Operators are required to report to the state regulator any loss of hydraulic fracturing fluids.
Federally, the Fracturing Responsibility and Awareness of Chemicals (FRAC) Act, introduced by Representative Dianne DeGette of Colorado, and the Clean Energy Jobs and Oil Company
Accountability Act would both require oil and gas operators to disclose the chemicals used to fracture wells. The FRAC Act would also amend the Safe Drinking Water Act to include hydraulic fracturing in its definition of underground injection. The Independent Petroleum
Association of America (IPAA) claims that if hydraulic fracturing is regulated under the
87 M. Zoback, S. Kiasei, B. Copithorne, World Watch Institute, Addressing the Environmental Risks from Shale Gas
Devlopment. July 2010.
88
State of Colorado Oil and Gas Conservation Commission. Department of Natural Resources.
“EPA Public
Hearing” Denver, Colorado. July 12, 2010.
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Underground Injection Control (UIC) provisions of the Safe Drinking Water Act that there would be an incremental cost of approximately $100,000 per unconventional well.
89
The State of New York has legislated a one-year moratorium on hydraulic fracturing. The moratorium suspends the issuance of new permits for hydraulic fracturing until the legislature has had sufficient time to thoroughly assess the environmental impacts of horizontal drilling and hydraulic fracturing. During this period, the government will conduct public consultations on a range of industry related issues, but the primary concern is water resources. Drilling may resume once regulatory conditions necessary to protect public health and the environment are in place.
90
Similar moratoriums have been implemented in Quebec, Maryland, and France.
91
89 Advanced Resources International. April 24, 2009. Bringing Real Information on Energy Forward – Economic
Considerations Associated with Regulating the American Oil and Natural Gas Industry.
Prepared for Independent
Petroleum Association of America and the Liaison Committee of Cooperating Oil and Gas Associations. p. 17,
Table 3. - http://www.energyindepth.org/PDF/Brief/BRIEF-Economic-Consequences.pdf
90 State of New York. Bill Number S8129A Title of Bill: An act to suspend hydraulic fracturing; and providing for the repeal of such provisions upon the expiration thereof. May 2010.
91 Citations needed – Quebec = http://www.mddep.gouv.qc.ca/communiques_en/2011/c20110308-shale-gas.htm
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The previous sections have raised a number of concerns relating to the water impacts associated with shale gas development in B.C. and current gaps in the ways we plan for, and regulate, that development. In order to ensure that British Columbia understands and manages these water risks responsibly, the Pembina Institute recommends that the B.C. government:
1.
Develop water management plans for current proposed shale gas development in the
Montney and Horn River basins. The plans should articulate a pace and scale of development that limit cumulative effects such that water resources are adequately protected. The plans should require:

Integration with other cumulative effects of concerns such as greenhouse gas emissions
 frequent monitoring and public reporting of cumulative impacts
 approvals of industrial projects (such as natural gas production) to be consistent with the limits on impacts, as measured by the monitoring program.
2.
Review, and strengthen as needed, requirements regarding water monitoring, use and treatment , as well as the liability of producers in case of contamination, to ensure the sustainability of water resources in regions targeted for natural gas development. This recommendation is particularly important given some of the current gaps in scientific understanding about hydraulic fracturing.
92
New research will almost certainly change our current perception of risks, and regulations may need to be adapted as a result.
3.
Revise the water permitting and licencing provisions for oil and gas uses by ending the shortterm section 8 water authorizations. Instead, all users should be required to secure a timelimited licence, such as 3 to 5 years. The licencing requirement should apply to both surface and ground water withdrawals. This will put an end to the regulatory loophole presented by the section 8 permits that are granted through the Oil and Gas Commission instead of the
Ministry of Environment, and will also ensure that the Ministry of Environment plays a more significant role in licencing industry water takings. Placing a near-term time limit will ensure that licences are renewed as necessary, and not exist for indefinite terms.
4.
Require the Oil and Gas Commission to return licensing powers and oversight for all water takings to the Ministry of Environment (not the Ministry of Natural Resource Operations), whose primary role is environmental protection. This would help ensure that total water allocations are fair between human users and are respectful of environmental limits.
92 EPA terms of reference and BAPE conclusions
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5.
Require companies to publicly disclose chemicals and additives used in hydraulic fracturing.
Increasingly, U.S. state regulators are requiring such disclosure. Although the risk of contamination of fresh water by fracture fluids appears to be low, they are being introduced into the environment, and there is a fundamental public right to know their composition.
Responsible development of this resource means that people should have clear information on the nature and quantities of chemicals and additives that are being injected into the ground and present in produced water.
6.
Undertake an independent audit of all oil and gas water use in B.C., seeking direct information from companies on actual water use and disposal, including all currently untracked sources. Our research indicates that there is a potentially significant range of untracked sources for water used in hydraulic fracturing. Private arrangements with landowners through access to their water resources, borrow pits or other sources will add up over time and further compromise a region already experiencing annual drought conditions.
7.
Ensure transparent and comprehensive compliance and enforcement. In addition to the lack of information about the extent of water use, there are also very few water stewardship staff available to ensure that water licences are adhered to and any non-compliance is meaningfully addressed. We recommend also that the amount of information provided in the
Oil and Gas Commission Field Inspection Reports be expanded to include the names of the company responsible for episodes of non-compliance and the specific nature of the violation at issue and the action taken as a result. This practice is the case with the Ministry of
Environment Compliance and Enforcement summaries.
8.
Provide timely, updated information on all water allocations, as well as timely, updated information on all water withdrawn under permits, licences or other means, for oil and gas use. There should also be a requirement for reporting all water used (by volume and water source), for hydraulic fracturing operations, and public reporting on all flowback water and produced water by volume and where it is disposed, also by volume. The Ministry of
Environment should manage the requirements.
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