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copied from Hydraulic fracturing in Canada Hydraulic fracturing in Canada was first used in Alberta in 1953 to extract hydrocarbons from the giant Pembina oil field, the biggest conventional oil field in Alberta, which would have produced very little oil without fracturing. Since then, over 170,000 oil and gas wells have been fractured in Western Canada.[1][2]: 1298 Hydraulic fracturing is a process that stimulates natural gas or oil in wellbores to flow more easily by subjecting hydrocarbon reservoirs to pressure through the injection of fluids or gas at depth causing the rock to crack or to widen existing cracks.[3]: 4 New hydrocarbon production areas have been opened as hydraulic fracturing stimulating techniques are coupled with more recent advances in horizontal drilling. Complex wells that are many hundreds or thousands of metres below ground are extended even further through drilling of horizontal or directional sections.[4] Massive fracturing has been widely used in Alberta since the late 1970s to recover gas from low-permeability sandstones such as the Spirit River Formation.[5]: 1044 The productivity of wells in the Cardium, Duvernay, and Viking formations in Alberta, Bakken formation in Saskatchewan, Montney and Horn River formations in British Columbia would not be possible without hydraulic fracturing technology. Hydraulic fracturing has revitalized legacy oilfields.[6] "Hydraulic fracturing of horizontal wells in unconventional shale, silt and tight sand reservoirs unlocks gas, oil and liquids production that until recently was not considered possible."[7] Conventional oil production in Canada was on a decrease since about 2004 but this changed with the increased production from these formations using hydraulic fracturing.[6] Hydraulic fracturing is one of the primary technologies employed to extract shale gas or tight gas from unconventional reservoirs.[3]
In 2012 Canada averaged 356 active drilling rigs, coming in second to the United States with 1,919 active drilling rigs. The United States represents just below 60 percent of worldwide activity.[8]: 21
Geological formations
editThe Spirit River, Cardium, Duvernay, Viking, Montney (AB and BC), and Horn River formations are stratigraphical units of the Western Canadian Sedimentary Basin (WCSB) which underlies 1,400,000 square kilometres (540,000 sq mi) of Western Canada and which contains one of the world's largest reserves of petroleum and natural gas. The Montney Formation, located in Northeast British Columbia and West-Central Alberta, and the Duvernay Formation located in central Alberta, are currently the most prospective formations in the WCSB for development of unconventional oil and gas reservoirs that require hydraulic fracturing stimulations. The Bakken formation is a rock unit of the Williston Basin that extends into southern Saskatchewan. In the early 2000s significant increases in production the Williston Basin began because of application of horizontal drilling techniques, especially in the Bakken Formation.[9]
-
Outline of the Western Canadian Sedimentary Basin -
![Generalized map showing the location of the Montney Formation.[10]](//upload.wikimedia.org/wikipedia/commons/thumb/2/27/Montney_Formation.jpg/93px-Montney_Formation.jpg)
Generalized map showing the location of the Montney Formation.[10] -
![Duvernay depositional extent in central Alberta, Canada.[11]](//upload.wikimedia.org/wikipedia/commons/thumb/0/0a/Duvernay_depositional_extent_in_central_Alberta%2C_Canada.tif/lossless-page1-120px-Duvernay_depositional_extent_in_central_Alberta%2C_Canada.tif.png)
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North America showing position of Williston Basin -
Location of Williston Basin (USGS)
![Generalized map showing the location of the Montney Formation.[10]](/wiki/File:Montney_Formation.jpg)
![Duvernay depositional extent in central Alberta, Canada.[11]](http://upload.wikimedia.org/wikipedia/commons/thumb/0/0a/Duvernay_depositional_extent_in_central_Alberta%2C_Canada.tif/lossless-page1-120px-Duvernay_depositional_extent_in_central_Alberta%2C_Canada.tif.png)
Technologies
editThe first commercial application of hydraulic fracturing was by Halliburton Oil Well Cementing Company (Howco) in 1949 in Stephens County, Oklahoma and in Archer County, Texas, using a blend of crude oil and a proppant of screened river sand into existing wells with no horizontal drilling.[3]: 5 [12]: 27 In the 1950s about 750 US gal (2,800 L; 620 imp gal) of fluid and 400 lb (180 kg) were used. By 2010 treatments averaged "approximately 60,000 US gal (230,000 L; 50,000 imp gal) of fluid and 100,000 lb (45,000 kg) of propping agent, with the largest treatments exceeding 1,000,000 US gal (3,800,000 L; 830,000 imp gal) of fluid and 5,000,000 lb (2,300,000 kg) of proppant."[12]: 8 [13]
In 2011 the Wall Street Journal summarized the history of hydraulic fracturing,[4]
"Only a decade ago Texas oil engineers hit upon the idea of combining two established technologies to release natural gas trapped in shale formations. Horizontal drilling—in which wells turn sideways after a certain depth—opens up big new production areas. Producers then use a 60-year-old technique called hydraulic fracturing—in which water, sand and chemicals are injected into the well at high pressure—to loosen the shale and release gas (and increasingly, oil)."
— Wall Street Journal 2011
Horizontal oil or gas wells were unusual until the 1980s. Then in the late 1980s, operators along the Texas Gulf Coast began completing thousands of oil wells by drilling horizontally in the Austin Chalk, and giving 'massive' hydraulic fracturing treatments to the wellbores. Horizontal wells proved much more effective than vertical wells in producing oil from the tight chalk.[13] In the late 1990s in Texas, by combining horizontal drilling and multi-stage hydraulic fracturing, large-scale commercial shale gas production was possible, and since then shale gas wells became longer, and the number of stages per well increased.[14] At present, as shale gas companies target deeper, hotter, more unstable reservoirs, drilling technologies that tackle challenges in various environments have been developed.
| Drilling Technology | Description | Environment |
|---|---|---|
| Underbalanced drilling[15][16][17] | - Drilling fluid operated at pressure less than pore pressure;
- Using compressed gas or foam; - Speeds up penetration rate, reduces drilling costs and formation damage. |
Depleted zones, highly fractured and porous formation. |
| Percussion/hammer drilling[18] | - Repeated impact to break rock at drill bit;
- Drill bit contact with formation is 2% of operational time; - Less tool wear; - Impact and rebound can be self-sufficient and self-sustained. |
Hard rock formations |
| Radial drilling[19][20][21] | - 50 to 100 meters long laterals from mother well;
- Controlled direction; - Increase drainage radius and flow profile near wellbores; - Rotary, jet-impact, plasma drilling methods. |
Near cap rock, water table, faults, and depleted zones. |
| Drilling with liner/casing[22][23] | - Installing liner with out extracting drilling assembly;
- Prevents fracturing, closure and collapse of wellbore. |
Swelling shales, creeping formations, high pressure zones, and depleted zones. |
| Monodiameter drilling liner[24] | - Creates continuous diameter of casing using expandable tubular technology;
- Decreases amount of drilling fluid and cement volumes, casing weight, and cutting disposal. |
Same environment as conventional telescoping casing installation. |
| Non-invasive drilling fluids[25] | - Polymer, water, and oil mixture;
- Polymer seal pore throats and fractures; - Prevents infiltration of fluid into formation. |
Depleted zones, highly fractures and porous formations. |
| Reversible invert emulsion fluid[26] | - Can switch between water-in-oil and oil-in-water emulsion;
- Water-in-oil fluid prevent fluid loss, washout, and swelling; - Oil-in-water offer better cleanup for better cementing. |
Swelling shales, salt zones, highly fractured and porous formations. |
In parallel with advancement in drilling technologies, injection technologies have also seen changes.
| Injection Technology | Description | Drawbacks |
|---|---|---|
| Gas[27][28][29][30] | - Commonly use carbon dioxide and nitrogen;
- Does not plug pore throats; - Carbon dioxide replaces adsorbed natural gas in reservoir; - Faster flowback; - Avoids use of water; - Higher production if using carbon dioxide. |
- Low proppant carrying capacity;
- High velocity proppant erodes equipment; - Pressurized containers for transport and storage. |
| Liquid carbon dioxide[28][30][31] | - Liquid at -34.5 C° and 1.4 MPa;
- High proppant carrying capacity; - Turns to gas in reservoir; - Replaces adsorbed gas in reservoir; - Does not plug pore throats; - Fast flowback; - Avoids use of water; - Higher production. |
- Transport and storage of low temperature gas;
- Potential greenhouse effect. |
| Supercritical Carbon dioxide(SC‐CO2)[32] | - Usually at depths greater than 1,000 m
-Not lower than (L‐CO2) temperatures. - Viscosity of SC‐CO2 is much lower than normal L-CO2. -SC‐CO2 breakdown pressure is lower than L-CO2 |
-Difficult to change to this liquid state;
-Difficult to get this low temperature; -In this case depth and pressure also difficult to achieve |
| Liquefied petroleum gas(LPG)[33] | -No waste production and environment friendly
-Almost 100% of propane gas is pumped back -Only 50% of hydraulic frack fluid remains underground |
-Much more expensive than water;
-Potential risks to use in field work operation; -Transport and storage is a challange |
| High energy gas fracturing(HEGF)[34] | -To produce multiple radial fractures in formation
-cheapness in operation cost; -simpleness in implementation; -little pollution to formation |
-Not well suited to overcoming certain types of recurring damage mechanisms,
such as salt deposition |
| Foam[28] | - Liquid aerated, typically with N2;
- Has wide range of viscosities based on foam ratio; - Less water usage; - Reduces swelling but cannot eliminate it; - Reduces water-locking. |
- Reduces but cannot eliminate swelling and water-locking issues. |
| Impulse sand fracturing[35] | -effective and environmental firendly
-Highly increase well production -Decrease the volume of fracturing proppant -Lower sand plugging risks -High initial fluid rate |
-Expensive
-Take long-time to plugging in - |
Cost and lifespan of hydraulic fracturing
editOil producers spend US$12 million upfront to drill a well but it is so efficient and produces so well during its short, 18-month, lifespan that oil producers using this technology can still make a profit even with oil at $50 a barrel.[36]
Lifespan of hydraulic fracturing:
The lifecycle of shale gas development can vary from a few years to decades and occurs in six major stages, as described by Natural Resources Canada, assuming all approvals from the various regulatory authorities have been obtained:
- Stage One: Exploration, which involves applying for the appropriate licenses and permits, leasing the mineral rights, Indigenous consultations, community consultations and geophysical study, including geological assessments and seismic surveys[37];
- Stage Two: Site preparation and well construction, which includes exploratory drilling to determine the physical and chemical characteristics of the rock and to assess the quality and quantity of the resource[37];
- Stage Three: Drilling, which includes horizontal drilling[37];
- Stage Four: Stimulation, which is the use of hydraulic fracturing to enable the hydrocarbons to fow to the wellbore[37];
- Stage Five: Well operation and production, which can operate for 10 to 30 years; and[37],
- Stage Six: End of production and reclamation, which requires the company to properly seal the well, clean and inspect the site. Reclamation occurs over several years as the company remediates any contamination, restores soil profles, replants native vegetation and any other reclamation work required by local regulations[37].
Well cost
Shale gas wells can be very expensive because of the cost of horizontal drilling (a function of technology needed to drill horizontal and the extra time required to drill) and technology-heavy hydraulic fracturing techniques that may take several days to fracture a single well[38]. A horizontal well in the Montney Formation will typically cost approximately 5 to 8 million dollars[38]. In the Horn River Basin, a horizontal well costs up to 10 million dollars[38]. Horizontal wells in the Utica Shale are expected to cost 5 to 9 million dollars[38]. Vertical wells targeting biogenic shale gas, like in the Colorado Shale, are far less expensive: the resource is shallow and the wells cost less than $350,000 each[38].
Alberta
editBecause of its vast oil and gas resources, Alberta is the busiest province in terms of hydraulic fracturing. The first well to be fractured in Canada was the discovery well of the giant Pembina oil field in 1953 and since then over 170,000 wells have been fractured. The Pembina field is a "sweet spot" in the much larger Cardium Formation, and the formation is still growing in importance as multistage horizontal fracturing is increasingly used.
The Alberta Geological Survey evaluated the potential of new fracturing techniques to produce oil and gas from shale formations in the province, and found at least five prospects which show immediate promise: the Duvernay Formation, the Muskwa Formation, the Montney Formation, the Nordegg Member, and the basal Banff and Exshaw Formations.[39] These formations may contain up to 1.3 quadrillion cubic feet (37×1012 m3) of gas-in-place.
Between 2012 and 2015, 243 horizontal multistage fractured wells were drilled in the Duvernay Formation producing 36.9 million of barrel of oil equivalent (MMBOE) distributed in 1.6 MMBOE of oil, 11.7 MMBOE of natural-gas condensate, and 23.6 MMBOE of natural gas.[11] 201 of these wells were drilled in the Kaybob assessment area, whereas 36 wells were drilled in the Edson-Willesden Green area and 6 wells in the Innisfail area, with horizontal lengths between 1000 and 2800 meters and well spacings between 150 and 450 meters. The development of condensate-rich areas in the Duvernay formation remain steady as the natural-gas condensate is a key product to dilute the bitumen produced from the closely-located oil sands deposits in Athabaska, Peace River, and Cold Lake, and is traded with the same reference price as WTI oil.
Even as the price of oil declined dramatically in 2014, hydraulic fracturing in so-called "sweet spots" such as the Cardium and Duvernay in Alberta, remained financially viable.[40]
British Columbia
editThe most shale gas activity in Canada has taken place in the province of British Columbia.[14] In 2015, 80% of the natural gas production in the province was produced from unconventional sources, where the portion of the Montney Formation located in BC contributed 3.4 billion cubic feet per day (Bcf/d), corresponding to 64.4% of the province's total gas production. This formation contains 56% of the province's recoverable raw gas that corresponds to an estimate of 29.8 trillion cubic feet (Tcf), and the remaining recoverable gas is distributed in other unconventional gas plays as the Liard Basin, Horn River Basin, and Cordova Basin, all of them located in the Northeast portion of the province.[41]
Talisman Energy, which was acquired by the Spanish company Repsol in 2015, is one operator company that "has extensive operations in the Montney shale gas area."[42] In late July 2011 the Government of British Columbia gave Talisman Energy, whose head office is in Calgary, a twenty-year long-term water licence to draw water from the BC Hydro-owned Williston Lake reservoir.
In 2013, the Fort Nelson First Nation, a remote community in northeastern B.C. with 800 community members, expressed frustration with royalties associated with gas produced through hydraulic fracturing in their territory. Three of British Columbia's four shale-gas reserves – the Horn River, Liard and Cordova Basins are on their lands. "Those basins hold the key to B.C.'s LNG ambitions."[43]
Saskatchewan
edit
The Bakken shale oil and gas boom underway since 2009, driven by hydraulic fracturing technologies, has contributed to record growth, high employment rates and increase in population, in the province of Saskatchewan. Hydraulic fracturing has benefited small towns like Kindersley which saw its population increase to over 5,000 with the boom. Kindersley sells its treated municipal wastewater to oilfield service companies to use in hydraulic fracturing.[6] As the price of oil dropped dramatically in late 2014 partially in response to the shale oil boom, towns like Kindersley are more vulnerable.
Quebec
editThe Utica Shale, a stratigraphical unit of Middle Ordovician age underlies much of the northeastern United States and in the subsurface in the provinces of Quebec and Ontario.[45]
Drilling and producing from the Utica Shale began in 2006 in Quebec, focusing on an area south of the St. Lawrence River between Montreal and Quebec City. Interest has grown in the region since Denver-based Forest Oil Corp. announced a significant discovery there after testing two vertical wells. Forest Oil said its Quebec assets may hold as much as four trillion cubic feet of gas reserves,[46] and that the Utica shale has similar rock properties to the Barnett shale in Texas.
Forest Oil, which has several junior partners in the region, has drilled both vertical and horizontal wells. Calgary-based Talisman Energy has drilled five vertical Utica wells, and began drilling two horizontal Utica wells in late 2009 with its partner Questerre Energy, which holds under lease more than 1 million gross acres of land in the region. Other companies in the play are Quebec-based Gastem and Calgary-based Canbriam Energy.
The Utica Shale in Quebec potentially holds 4×1012 cu ft (110×109 m3) at production rates of 1×106 cu ft (28,000 m3) per day[46][47] From 2006 through 2009 24 wells, both vertical and horizontal, were drilled to test the Utica. Positive gas flow test results were reported, although none of the wells were producing at the end of 2009.[48] Gastem, one of the Utica shale producers, took its Utica Shale expertise to drill across the border in New York state.[49]
In June 2011, the Quebec firm Pétrolia claimed to have discovered about 30 billion barrels of oil on the island of Anticosti, which is the first time that significant reserves have been found in the province.[50]
Debates on the merits of hydraulic fracturing have been on-going in Quebec since at least 2008.[51][52] In 2012 the Parti Québécois government imposed a five-year moratorium on hydraulic fracturing in the region between Montreal and Quebec City, called the St. Lawrence Lowlands, with a population of about 2 million people.[52]
Prior to announcing her provincial election campaign, former Premier of Quebec and former leader of the Parti Québécois (PQ), Pauline Marois, announced that the PQ party would spend $115 million to help finance two exploratory shale gas operations as a prelude to hydraulic fracturing for oil on Anticosti Island that would have been a catalyst for ending the moratorium.[53]|: 37 [52][54]
In February 2014, prior to announcing her provincial election campaign, former Premier of Quebec and former leader of the Parti Québécois (PQ), Pauline Marois, announced that the provincial government would help finance two exploratory shale gas operations as a prelude to hydraulic fracturing on the island, with the province pledging $115-million to finance drilling for two separate joint ventures in exchange for rights to 50% of the licences and 60% of any commercial profit.[52][53]: 37 [55] It was the first oil and gas deal of any size for the province. With the change in government that occurred in April 2014, the Liberals of Philippe Couillard could change that decision.
Petrolia Inc., Corridor Resources and Maurel & Prom formed one joint-venture, while Junex Inc. was still seeking a private partner.[56]
In November 2014 a report published by Quebec’s advisory office of environmental hearings, the Bureau d’audiences publiques sur l’environnement (BAPE), found "shale gas development in the Montreal-to-Quebec City region wouldn’t be worthwhile." BAPE warned of a "magnitude of potential impacts associated with shale gas industry in an area as populous and sensitive as the St. Lawrence Lowlands."[51][57] The Quebec Oil and Gas Association challenged the accuracy of BAPE's report. On 16 December 2014 Quebec's Premier Philippe Couillard responded to the BAPE report stating there will be no hydraulic fracturing due to a lack of economic or financial interest and a lack of social acceptability.[52]
Nova Scotia
editThe oil and gas industry in Nova Scotia dates back to 1869, when the first exploration well was drilled in the Lake Ainslie area on Cape Breton Island[58]. While a few discoveries have been made onshore in the Maritime provinces, such as the Stoney Creek and McCully fields in New Brunswick, onshore Nova Scotia has not been seen as highly prospective for conventional oil and gas, and no commercial discoveries have been made to date[58]. Commercial discoveries have been made in the offshore, where oil has been produced from the Cohasset and Panuke fields and where gas is produced today from the Sable Island complex and Deep Panuke field[58].
In recent years, the development of horizontal drilling and hydraulic fracture completion technologies has rendered low-quality “unconventional” reservoirs capable of production at commercial rates[58]. Exploration companies are thus re-evaluating the production potential of many areas, including onshore Nova Scotia[58].
Potential Oil and Gas Resource Base
The sedimentary basins of onshore Nova Scotia are prospective for oil and gas in unconventional reservoirs. The essential elements – thick unconventional reservoir rocks and organic materials to generate oil and gas – are present and widespread[58].
Prospectivity occurs in three major rock units within the basins as followed:
1) Horton Group (oldest):
- Production of oil and gas occurs from Horton Group sandstones in the Moncton Basin of New Brunswick[58]. While these reservoirs are technically conventional, horizontal drilling and hydraulic fracturing have been used to enhance production[58]. Resources in conventional Horton reservoirs are estimated at 300 to 1185 million barrels of oil and from 6.1 to 23.7 TCF of gas[58].
- High gas flow rates have been attained from hydraulically-fractured horizontal wells in Horton Group shales in the Moncton Basin[58]. Vertical test wells (with small hydraulic fractures) drilled into analogous shales of the Windsor-Kennetcook Basin in Nova Scotia did not produce gas[58]. Resources in Horton Group shales are estimated at 17 to 69 TCF over much of the Windsor-Kennetcook Basin[58]. Analogous shales in other Nova Scotia basins are seen as generally prospective, but no resource assessments have been published[58].
- Thick, tight sandstones occur in the Horton Group across all Nova Scotia basins, but no assessment of their oil and gas resource potential has been published[58].
2) Windsor and Mabou Groups - Carbonate reefs in the basal Windsor Group are the targets for oil exploration, and exploration wells have been drilled in the Shubenacadie Basin[58]. As a productive pool has not been encountered, it is unclear whether fracturing would be required to produce it[58]. - Oil and gas potential may occur in tight carbonate (and sandstone) reservoirs in the basal and upper parts of the Windsor-Mabou section, but no assessment of their resource potential has been published[58].
3) Cumberland and Pictou Groups (youngest) - Widespread coals are prospective in several basins for coalbed methane, and resource estimates on the order of 1 TCF have been published[58]. - Resources in conventional Cumberland/Pictou sandstone reservoirs (including offshore areas) are estimated at 317-1230 million barrels of oil and 12.1 36.8 TCF of gas[58]. - Thick, tight sandstones occur in the Cumberland and Pictou groups across all Nova Scotia basins, but no assessment of their resource potential has been published[58].
Exploration and Production
The Government of Nova Scotia announced plans to introduce legislation to prohibit high-volume hydraulic fracturing for onshore shale gas on September 3, 2014. They introduced that legislation as amendments to the Petroleum Resources Act on September 30, 2014 putting that moratorium into effect[59].
Nova Scotia currently has six companies exploring for either coal gas or conventional oil and gas on almost 875,000 hectares of land[59]. There are a total of nine agreements, which may be broken down as follows: five exploration agreements, one conventional oil and gas production lease, one coal gas exploration agreement and two coal gas production agreements[59].
East Coast Energy is attempting to dewater the Foord Coal seam in Stellarton, where they have drilled a successful horizontal well in search of coal bed methane (coal gas)[59]. The rest of the industry in the province has been dormant for the last three years[59].
As of 2014, there have been no commercial discoveries and no royalties have been collected in the onshore activity, but the province is on the edge of this potential opportunity[59].
Public Health Protection, Socio-Economic and Social Ecological Impacts on Communities and Water Resource Impacts.
Risks and benefits of development would be variable according to social, demographic, and geographic factors[58]. Although none of the potential negative impacts could be defined as catastrophic, there remain many outstanding questions requiring further research to fully elucidate effects on populations and ecosystems[58].There is insufficient knowledge at the present time to describe how theoretical or actual risks and benefits may fall both in the short and the long term at the community level[58].
New Brunswick
editNew Brunswick’s increased use of natural gas was facilitated by a single event: the arrival of natural gas from Nova Scotia’s Sable Ofshore Energy Project via the Maritimes and Northeast Pipeline (MNP) in January 2000[60]. The arrival and the growth of natural gas as an energy source for New Brunswick industrial, commercial and institutional users and the accompanying decrease in heavy and light fuel oil. New Brunswick’s economy is now heavily linked to natural gas and will be for many years to come[60].
Potential Oil and Gas Resource Base
Shale and tight sand resources occur within the Caledonian Highlands of the Maritimes Basin in New Brunswick; particularly the 3,700-square-kilometre Moncton Subbasin[61]. Crystalline volcanic and plutonic rocks that are between 560 to 540 million years old constitute prominent hills that have elevations up to 400 metres[61]. Deeply embedded streams drain southward to Chignecto Bay and northward to the Petitcodiac River[61]. Low-lying rounded hills form ridges on both the northwest and southeast boundary of the Central Plateau[61]. Moderate to steeply dipping Early Carboniferous-aged rocks create these ridges[61].
McCully Field is located near Sussex, New Brunswick and houses the major tight sand zone[61]. This area is relatively flat-lying due to the shallowly dipping Early Carboniferous aged rocks[61]. On the west side of the Petitcodiac River and south of Moncton, New Brunswick, Stoney Creek Field hosts tight sand zones containing both oil and gas. Southeast of Stoney Creek Field, shales at Hillsborough host natural gas, while tight sands at Hopewell host oil[61].
All known shale/tight resources are in the Moncton Sub-basin[61]. McCully Field, near Sussex New Brunswick, is currently producing sweet natural gas[61]. Corridor Resources Inc. currently holds the natural gas lease along with its partner, PCS New Brunswick Division[61]. Most of the gas is from fracture-completed tight sand zones in the Hiram Brook[61]. The McCully Field is estimated to contain an in-place shale gas resource of 67.3 trillion cubic feet[61]. Corridor Resources Inc. has expanded its exploration to the Elgin area, just east of McCully Field[61]. Kicking Horse Energy Inc. currently holds a lease for Stoney Creek Field in southeastern New Brunswick[61]. This play is similar to McCully Field in that it is characterized by tight sand zones[61]. The resource estimate at Stoney Creek is 30 million barrels of oil in-place[61]. Other leases held by Kicking Horse Energy Inc. include Hillsborough and Hopewell, just southeast of Stoney Creek Field[61]. At Hillsborough, there is an estimated 10.9 trillion cubic feet of natural gas resource in-place, occurring in Frederick Brook shales[61]. Tight sands of the Hiram Brook are also being assessed at Hillsborough. To date, the Hopewell play is currently being compared to Stoney Creek, and there are plans for future exploration[61].
Exploration and Production
editThe following timeline illustrates the development of New Brunswick’s natural gas production industry, post-1999.
• 2003: Natural gas is discovered and begins at McCully. Producing reservoir is Hiram Brook formation sandstone[62].
• 2007: A 45-kilometre pipeline is constructed to connect the McCully gas feld with the Maritimes and Northeast mainline and a gas processing plant is constructed in McCully area[62].
• 2007: Two natural gas gathering pipelines are constructed (450 metres and 2,000 metres in length) to tie in two existing well pads (F-28 and L-38) to the existing gathering system[62].
• 2007: Expansion of the McCully natural gas production including the construction of six new well pads and gathering pipelines. • 2008: Further expansion of the McCully natural gas system including construction of a 3.4 kilometre pipeline to tie in well pad I-39[62].
• 2009: First hydraulic fracturing of a horizontally drilled well in New Brunswick in the McCully area[62].
• 2009: Start of exploratory drilling and hydraulic fracturing in the Elgin area, south of Petitcodiac[62].
• 2009-2010: The first shale-targeted wells are drilled in New Brunswick – four wells in the Elgin area, south of Petitcodiac. None are producing. • 2014: The last hydraulic fracturing carried out in New Brunswick to date. Corridor Resources conducted hydraulic fracturing using liquid propane at five wells in the McCully and Elgin areas[62].
The Stoney Creek field, south of Moncton near Hillsborough, is a historic producing field that commenced in 1909, with reported production of over 800,000 barrels of oil and 28 billion cubic feet of natural gas[61]. Contact Exploration (Kicking Horse) recommenced commercial production of oil in 2007 and also has plans to exploit a vast shale gas target within the region[61]. In 2000, Corridor Resources began to drill and evaluate the potential for natural gas production and to determine deep well injection disposal potential of brine production from the PCS mine in Penobsquis[61]. It was determined that the targeted formation was unsuitable for brine disposal, but significant volumes of natural gas were encountered, in what is now known as the McCully field[61]. Since June 2007 natural gas has also been exported to the northeastern United States via the Maritimes and Northeast Pipeline[61]. SWN Resources Canada acquired exploration licences in March 2010, covering 1.1 million hectares, and is still in the exploration stage[61].
Currently, eight companies hold 56 agreements to explore for oil and natural gas on more than 1.15 million hectares of land in the province[61]. SWN Resources Canada completed two geophysical surveys in 2013, additional to seismic surveys undertaken in 2010 and 2011[61]. In the summer of 2014, Corridor Resources completed a five well hydraulic fracturing operation, exploiting both tight gas sands and shale targets[61]. Corridor is currently producing natural gas from 32 wells. Kicking Horse is currently producing oil from 16 wells[61]. SWN has tentative plans to drill exploration wells throughout licenced holdings[61].
In December of 2014, the Government of New Brunswick introduced legislation to impose a moratorium on all types of hydraulic fracturing in the province until more research and information is made available and the risks to health, water and environment are fully understood[61].
Hydraulic fracturing fluid
editUnder the Canada Oil and Gas Operations Act, the National Energy Board (NEB) requests operators to submit the composition of the hydraulic fracturing fluids used in their operation that will be published online for public disclosure on the FracFocus.ca website.[63]
Common hydraulic fracturing fluid composition include[14]:
| Additive type | Purpose and description |
|---|---|
| Water | Fresh water |
| Proppant | Maintains fracture openings |
| Friction reducer | Reduces friction pressure, decreases the necessary pump energy and subsequent air emissions |
| Disinfectant (Biocide) | Inhibits the growth of bacteria that can destroy gelled fracture fluids or produce methane-contaminating gases |
| Surfactant | Modifies surface and interfacial tension and breaks or prevents emulsions, aiding fluid recovery |
| Crosslinker | Used for gels that can be either linear or cross-linked. The cross-linked gels have the advantage of higher viscosities that do not break down quickly |
| Scale inhibitor | Prevents mineral deposits that can plug the formation |
| Corrosion inhibitor | Prevents pipes and connectors rusting |
| Breaker | Introduced at the end of a fracturing treatment to reduce viscosity and release proppants into the fractures and increase the recovery of the fracturing fluid |
| Clay stabilization | Prevents the swelling of expandable clay minerals, which can block fractures |
| Iron control | Prevents the precipitation of iron oxides |
| Gelling agent | Increases the viscosity of the fracturing fluid to carry more proppant into fractures |
| pH adjusting agent | Adjusts/controls the pH to enhance the effectiveness of other additives |
Most of hydraulic fracturing operations in Canada are done using water[14]. Canada is also one of the most successful countries in the world to use carbon dioxide as fracturing fluid with 1,200 successful operations by the end of 1990[64][29][28]. Liquefied petroleum gas is also used as a fracturing fluid in provinces where usage of water is prohibited such as New Brunswick.[65]
Environmental impact
editThe potential environmental impacts of hydraulic fracturing operations are universal and affect Canada similarly to other world regions utilizing this stimulation and recovery technique to exploit hydrocarbon reserves. Potential environmental impacts include surface and/or groundwater contamination, air emissions, noise pollution, and land disturbance and wildlife segregation or displacement during the construction of leases. [14]
One of the greatest environmental concerns is contamination of the Fresh Groundwater Zone (FGWZ) through migration of fugitive gas from the target or intermediate zone along the annuli in wells with poorly cemented or deteriorating surface casing (“leaky” wells) or through natural and pre-existing fracture networks into the FGWZ. [14] In 2014, less than 5% of Alberta's 316,439 total wells were considered leaky. [66] Disregarding methane emissions from leaky wells, greenhouse gas (GHG) emissions released throughout the natural gas life cycle are significantly less than those emitted throughout the life cycle of oil or coal.[14] Until recently, Canadian provinces such as Alberta, Saskatchewan, and Nova Scotia produced over half of their electricity from coal combustion whereas Ontario has already completely phased out coal-powered electricity.[67] Switching from coal- to natural gas-powered electricity can reduce carbon dioxide emissions by ~50% and also decrease the amount of NOx and SOx emitted to atmosphere.[14]
Lack of baseline data or before-and-after hydraulic fracturing sample collection and analysis makes it challenging to quantify environmental impacts (if any) resulting from hydraulic fracturing. [14]
Possible related earthquakes
editThe sharp seismicity increase observed in recent years in the Western Canada Sedimentary Basin is inferred to be triggered by hydraulic-fracturing operations.[68] Most of the seismic events reported in this period are closely located to hydraulic fracturing wells completed in western Alberta and northeast British Columbia. In response to this increased seismicity, the Alberta Energy Regulator released in 2015 the Subsurface Order No. 2 that makes mandatory to implement a Traffic-Light Protocol (TLP) based on the local magnitude (ML) of seismic events detected during the monitored operations.[69] According to this TLP, the hydraulic fracturing operations can continue as planned when the ML of the detected seismic events are below 2.0 (green light), must be modified and reported to the regulator when a seismic event of ML between 2.0 and 4.0 is detected (amber light), and must be immediately ceased when a seismic event of ML > 4.0 is detected within 5 km of a hydraulic fracturing well (red light). The BC Oil and Gas Commission implemented a similar TLP where the seismicity and surface ground motions must be adequately monitored during hydraulic fracturing operations, and must be suspended if a ML > 4 is detected within 3 km from the well.[70] ML > 4 has been chosen as a red-light threshold by both jurisdictions in western Canada (Alberta and British Columbia) as a seismic with magnitude below 4 corresponds to a minor earthquake that may be lightly felt, but with no expected property damage. [71] The following table lists some amber or red-light TLP seismic events reported in the Horn River Basin in northeast BC, and in Fox Creek, Alberta. The increased seismic activity in these two areas have been closely attributed to hydraulic fracturing operations.[72]
| Time (local) | M | Epicenter | Comments | Coordinates | Notes |
|---|---|---|---|---|---|
| October 4, 2014 10:17:24 | 4.3 | 139 km (86 mi) S of Fort Nelson, BC | Lightly felt in Fort Nelson and Fort St. John, BC. No reports of damage. | 57°33′36″N 122°56′24″W / 57.56000°N 122.94000°W | [73] |
| January 14, 2015 09:06:25 | 3.8 | 38 km (24 mi) west of Fox Creek, AB | No damage reported | 54°21′00″N 117°22′48″W / 54.35000°N 117.38000°W | [74][75] |
| January 22, 2015 23:49:18 | 4.4 | 36 km (22 mi) west of Fox Creek, AB | Lightly felt in Fox Creek | 54°28′12″N 117°15′36″W / 54.47000°N 117.26000°W | [74][75] |
| June 13, 2015 17:57:55 | 4.6 | 36 km (22 mi) east of Fox Creek, AB | Felt lightly in Drayton Valley, Edmonton and Edson | 54°06′07″N 116°57′00″W / 54.10194°N 116.95000°W | [75][76][77] |
| August 17, 2015 13:15:00 | 4.6 | 114 km (71 mi) WNW of Fort St. John, BC | Lightly felt in Charlie Lake, BC. No reports of damage. | 57°00′00″N 122°07′48″W / 57.00000°N 122.13000°W | [78] |
| January 12, 2016 12:27:21 | 4.4 | 25 km (16 mi) north of Fox Creek, AB | Felt as far south as St. Albert, just northwest of Edmonton. | 54°28′12″N 117°15′36″W / 54.47000°N 117.26000°W | [79][80][81] |
Regulations associated with hydraulic fracturing, by province
editIn Canada, hydraulic fracturing operations are governed by a number of provincial acts, regulations, guidelines, and directives. In this section, existing regulatory instruments are listed by province. Note: lists of provincial governing regulations are not exhaustive and new directives are drafted and implemented by the provincial government as necessary.
| Acts | Note |
|---|---|
| Oil and Gas Activities Act | [82] |
| Petroleum and Natural Gas Act | [83] |
| Environmental Management Act | [84] |
| Water Sustainability Act | [85] |
| Regulations | Note |
| Drilling and Production Regulation | [86] |
| Environmental Protection and Management Regulation | [87] |
| Consultation and Notification Regulation | [88] |
| Oil and Gas Activities Act General Regulation | [89] |
| Guidelines | Note |
| Flaring and Venting Reduction Guideline | [90] |
| British Columbia Oil and Gas Commission (BCOGC) Directives | Note |
| Directive 2010-07: Reporting of Water Production and Flow Back Fluids | [91] |
| Acts | Note |
|---|---|
| Oil and Gas Conservation Act | [92] |
| Responsible Energy Development Act | [93] |
| Environmental Protection and Enhancement Act | [94] |
| Water Act | [95] |
| Regulations | Note |
| Oil and Gas Conservation Regulations | [96] |
| Responsible Energy Development Act General Regulation | [97] |
| Environmental Assessment Regulation | [98] |
| Release Reporting Regulation | [99] |
| Alberta Energy Regulator (AER) Directives | Note |
| Directive 008: Casing Cement Depth | [100] |
| Directive 009: Casing Cementing Minimum Requirements | [101] |
| Directive 010: Minimum Casing Design Requirements | [102] |
| Directive 047: Waste Reporting Requirements for Oilfield Waste Management Facilities | [103] |
| Directive 050: Drilling Waste Management | [104] |
| Directive 051: Injection and Disposal Wells - Well Classifications, Completions, Logging, and Testing Requirements | [105] |
| Directive 055: Storage Requirements for the Upstream Petroleum Industry | [106] |
| Directive 058: Oilfield Waste Management Requirements for the Upstream Petroleum Industry | [107] |
| Directive 059: Well Drilling and Completions Data Filing Requirements | [108] |
| Directive 060: Upstream Petroleum Industry Flaring, Incinerating, and Venting | [109] |
| Directive 070: Emergency Preparedness and Response Requirements for the Petroleum Industry | [110] |
| Directive 080: Well Logging | [111] |
| Directive 083: Hydraulic Fracturing - Subsurface Integrity | [112] |
| Acts | Note |
|---|---|
| The Oil and Gas Conservation Act | [113] |
| The Water Security Agency Act | [114] |
| Regulations | Note |
| The Oil and Gas Conservation Regulation | [115] |
| The Oil Shale Regulations, 1964 | [116] |
| Guidelines | Note |
| Guideline PNG026: Gas Migration | [117] |
| Saskatchewan Hydraulic Fracturing Fluids and Propping Agents Containment and Disposal Guideline | [118] |
| Saskatchewan Ministry of the Economy (ECON) Directives | Note |
| Directive PNG005: Casing and Cementing Requirements | [119] |
| Directive PNG006: Horizontal Oil Well Requirements | [120] |
| Directive PNG015: Well Abandonment Requirements | [121] |
| Directive S-10: Saskatchewan Upstream Petroleum Industry Associated Gas Conservation | [122] |
| Directive S-20: Saskatchewan Upstream Flaring and Incineration Requirements | [123] |
| Acts | Note |
|---|---|
| The Oil and Gas Act | [124] |
| The Water Rights Act | [125] |
| The Water Protection Act | [126] |
| The Groundwater and Water Well Act | [127] |
| Regulations | Note |
| Drilling and Production Regulation | [128] |
| Acts | Note |
|---|---|
| Oil, Gas and Salt Resources Act | [129] |
| Environmental Protection Act | [130] |
| Ontario Water Resources Act | [131] |
| Regulations | Note |
| Regulation 245/97: Exploration, Drilling and Production | [132] |
| Regulation 387/04: Water Taking and Transfer | [133] |
| Oil, Gas and Salt Resources of Ontario Provincial Operating Standards | [134] |
| Acts | Note |
|---|---|
| Petroleum Resources Act | [135] |
| Mining Act | [136] |
| Environmental Quality Act | [137] |
| Regulations | Note |
| Regulation respecting petroleum, natural gas and underground reservoirs | [138] |
| Regulation respecting the application of the Environmental Quality Act | [139] |
| Water Withdrawal and Protection Regulation | [140] |
| Acts | Note |
|---|---|
| Oil and Natural Gas Act | [141] |
| Underground Storage Act | [142] |
| Bituminous Shale Act | [143] |
| Clean Environment Act | [144] |
| Clean Water Act | [145] |
| Clean Air Act | [146] |
| Regulations | Note |
| Air Quality Regulation | [147] |
| Environmental Impact Assessment Regulation | [148] |
| License to Search, Development Permit and Lease Regulation | [149] |
| Responsible Environmental Management of Oil and Natural Gas Activities in New Brunswick - Rules for Industry | [150] |
| Acts | Note |
|---|---|
| Petroleum Resources Act | [151] |
| Underground Hydrocarbons Storage Act | [152] |
| Regulations | Note |
| Petroleum Resources Regulations | [153] |
| Onshore Petroleum Drilling Regulations | [154] |
| Onshore Petroleum Geophysical Exploration Regulations | [155] |
| Offshore Petroleum Drilling and Production Regulations | [156] |
| Acts | Note |
|---|---|
| Oil and Natural Gas Act | [157] |
| Environmental Protection Act | [158] |
| Regulations | Note |
| Air Quality Regulations | [159] |
| Watercourse and Wetland Protection Regulations | [160] |
| Oil and Gas Conservation Regulations | [161] |
| Permit, Lease and Survey System Regulations | [162] |
| Acts | Note |
|---|---|
| Petroleum and Natural Gas Act | [163] |
| Environmental Protection Act | [164] |
| Water Resources Act | [165] |
| Newfoundland and Labrador Atlantic Accord Implementation Newfoundland and Labrador Act | [166] |
| Acts | Note |
|---|---|
| Oil and Gas Act | [167] |
| Environment Act | [168] |
| Waters Act | [169] |
| Regulations | Note |
| Oil and Gas Drilling and Production Regulation | [170] |
| Acts | Note |
|---|---|
| Mackenzie Valley Resource Management Act (MVRMA) | [171] |
| Northwest Territories Waters Act | [172] |
| Environmental Protection Act | [173] |
| Regulations | Note |
| Northwest Territories Waters Regulations | [174] |
| Spill Contingency Planning and Reporting Regulations | [175] |
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{{cite book}}: CS1 maint: location missing publisher (link) - ^ Province of British Columbia (December 6, 2010). DIR 10-07 Reporting of Water Production and Flow Back Fluids. Victoria, Canada.
{{cite book}}: CS1 maint: location missing publisher (link) - ^ Province of Alberta (June 7, 2017). Oil and Gas Conservation Act. Edmonton, Canada: Alberta Queen's Printer. pp. 1–76.
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{{cite book}}: CS1 maint: location missing publisher (link) - ^ Alberta Energy Regulator (AER) (December 22, 2009). Directive 010: Minimum Casing Design Requirements. Calgary, Canada. pp. i - 24.
{{cite book}}: CS1 maint: location missing publisher (link) - ^ Alberta Energy Regulator (AER) (April 2, 2013). Directive 047: Waste Reporting Requirements for Oilfield Waste Management Facilities. Calgary, Canada. pp. i - 45.
{{cite book}}: CS1 maint: location missing publisher (link) - ^ Alberta Energy Regulator (AER) (July 15, 2016). Directive 050: Drilling Waste Management. Calgary, Canada. pp. 1–167.
{{cite book}}: CS1 maint: location missing publisher (link) - ^ Alberta Energy Regulator (AER) (March 1994). Directive 051: Injection and Disposal Wells - Well Classifications, Completions, Logging, and Testing Requirements. Calgary, Canada. pp. i - 34.
{{cite book}}: CS1 maint: location missing publisher (link) - ^ Alberta Energy Regulator (AER) (December 2001). Directive 055: Storage Requirements for the Upstream Petroleum Industry. Calgary, Canada. pp. i - 68.
{{cite book}}: CS1 maint: location missing publisher (link) - ^ Alberta Energy Regulator (AER) (February 1, 2006). Directive 058: Oilfield Waste Management Requirements for the Upstream Petroleum Industry. Calgary, Canada. pp. i - 215.
{{cite book}}: CS1 maint: location missing publisher (link) - ^ Alberta Energy Regulator (AER) (March 12, 2018). Directive 059: Well Drilling and Completions Data Filing Requirements. Calgary, Canada. pp. 1–93.
{{cite book}}: CS1 maint: location missing publisher (link) - ^ Alberta Energy Regulator (AER) (March 12, 2018). Directive 060: Upstream Petroleum Industry Flaring, Incinerating, and Venting. Calgary, Canada. pp. 1–99.
{{cite book}}: CS1 maint: location missing publisher (link) - ^ Alberta Energy Regulator (AER) (February 2, 2017). Directive 070: Emergency Preparedness and Response Requirements for the Petroleum Industry. Calgary, Canada. pp. 1–107.
{{cite book}}: CS1 maint: location missing publisher (link) - ^ Alberta Energy Regulator (AER) (May 17,2014). Directive 080: Well Logging. Calgary, Canada. pp. 1–20.
{{cite book}}: Check date values in:|date=(help) - ^ Alberta Energy Regulator (AER) (May 21, 2013). Directive 083: Hydraulic Fracturing - Subsurface Integrity. Calgary, Canada. pp. i - 14.
{{cite book}}: CS1 maint: location missing publisher (link) - ^ Province of Saskatchewan (2017). The Oil and Gas Conservation Act. Regina, Canada: The Queen's Printer. pp. i - 64.
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{{cite book}}: CS1 maint: location missing publisher (link) - ^ Saskatchewan Energy and Mines (October 1, 2000). Saskatchewan Hydraulic Fracturing Fluids and Propping Agents Containment and Disposal Guideline. Regina, Canada. pp. i - 9.
{{cite book}}: CS1 maint: location missing publisher (link) - ^ Province of Saskatchewan (March 2018). Directive PNG005: Casing and Cementing Requirements. Regina, Canada. pp. 1–10.
{{cite book}}: CS1 maint: location missing publisher (link) - ^ Province of Saskatchewan (November 2015). Directive PNG006: Horizontal Oil Well Requirements. Regina, Canada. pp. 1–12.
{{cite book}}: CS1 maint: location missing publisher (link) - ^ Province of Saskatchewan (November 2015). Directive PNG015: Well Abandonment Requirements. Regina, Canada. pp. 1–9.
{{cite book}}: CS1 maint: location missing publisher (link) - ^ Province of Saskatchewan (November 2015). Directive S-10: Saskatchewan Upstream Petroleum Industry Associated Gas Conservation. Regina, Canada. pp. 1–23.
{{cite book}}: CS1 maint: location missing publisher (link) - ^ Province of Saskatchewan (November 1, 2015). Directive S-20: Saskatchewan Upstream Flaring and Incineration Requirements. Regina, Canada. pp. 1–20.
{{cite book}}: CS1 maint: location missing publisher (link) - ^ Province of Manitoba (November 20, 2017). The Oil and Gas Act. Winnipeg, Canada: The Queen's Printer.
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- ^ Province of Manitoba (January 1, 2017). The Water Protection Act. Winnipeg, Canada.
{{cite book}}: CS1 maint: location missing publisher (link) - ^ Province of Manitoba (June 14, 2012). The Groundwater and Water Well Act. Winnipeg, Canada.
{{cite book}}: CS1 maint: location missing publisher (link) - ^ Province of Manitoba (2001). Drilling and Production Regulation. Winnipeg, Manitoba.
{{cite book}}: CS1 maint: location missing publisher (link) - ^ Province of Ontario (May 17, 2017). Oil, Gas and Salt Resources Act. Toronto, Canada: Queen's Printer.
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- ^ Province of Ontario (December 11, 2017). O. Reg. 245/97: Exploration, Drilling and Production. Toronto, Canada.
{{cite book}}: CS1 maint: location missing publisher (link) - ^ Province of Ontario (March 29, 2016). O. Reg. 387/04: Water Taking and Transfer. Toronto, Canada.
{{cite book}}: CS1 maint: location missing publisher (link) - ^ Province of Ontario (March 27, 2002). Oil, Gas and Salt Resources of Ontario Provincial Operating Standards. Toronto, Canada.
{{cite book}}: CS1 maint: location missing publisher (link) - ^ Province of Quebec (December 1, 2017). Petroleum Resources Act. Quebec: Queen's Printer.
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- ^ Province of New Brunswick (January 31, 2018). Oil and Natural Gas Act. Saint John, Canada: Queen's Printer.
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- ^ Province of New Brunswick (January 31, 2018). Bituminous Shale Act. Saint John, Canada: Queen's Printer.
- ^ Province of New Brunswick (January 31, 2018). Clean Environment Act. Saint John, Canada: Queen's Printer.
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- ^ Province of New Brunswick (2017). Air Quality Regulation. Saint John, Canada: Queen's Printer.
- ^ Province of New Brunswick (March 20, 2018). Environmental Impact Assessment Regulation. Saint John, Canada: Queen's Printer.
- ^ Province of New Brunswick (January 30, 2018). License to Search, Development Permit and Lease Regulation. Saint John, Canada: Queen's Printer.
- ^ Province of New Brunswick (February 15, 2013). Responsible Environmental Management of Oil and Natural Gas Activities in New Brunswick - Rules for Industry. Saint John, Canada. pp. i - 99.
{{cite book}}: CS1 maint: location missing publisher (link) - ^ Province of Nova Scotia (2000). Petroleum Resources Act. Halifax, Nova Scotia: The Queen's Printer.
- ^ Province of Nova Scotia (2001). Underground Hydrocarbons Storage Act. Halifax, Nova Scotia: The Queen's Printer.
- ^ Province of Nova Scotia (April 1, 2015). Petroleum Resources Regulations. Halifax, Nova Scotia: The Queen's Printer.
- ^ Province of Nova Scotia (April 1, 2015). Onshore Petroleum Drilling Regulations. Halifax, Nova Scotia: The Queen's Printer.
- ^ Province of Nova Scotia (April 1, 2015). Onshore Petroleum Geophysical Exploration Regulations. Halifax, Nova Scotia: The Queen's Printer.
- ^ Province of Nova Scotia (March 18, 2018). Offshore Petroleum Drilling and Production Regulations. Halifax, Nova Scotia: The Queen's Printer.
- ^ Province of Prince Edward Island (December 2, 2015). Oil and Natural Gas Act. Charlottetown, Canada: Queen's Printer. pp. 1–35.
- ^ Province of Prince Edward Island (December 23, 2017). Environmental Protection Act. Charlottetown, Canada: Queen's Printer. pp. 1–438.
- ^ Province of Prince Edward Island (August 7, 2004). Air Quality Regulations. Charlottetown, Canada: Queen's Printer. pp. 1–14.
- ^ Province of Prince Edward Island (June 1, 2012). Watercourse and Wetland Protection Regulations. Charlottetown, Canada: Queen's Printer. pp. 1–28.
- ^ Province of Prince Edward Island (February 1, 2004). Oil and Gas Conservation Regulations. Charlottetown, Canada: Queen's Printer. pp. 1–40.
- ^ Province of Prince Edward Island (April 4, 2009). Permit, Lease and Survey System Regulations. Charlottetown, Canada: Queen's Printer. pp. 1–14.
- ^ Province of Newfoundland and Labrador (2012). Petroleum and Natural Gas Act. St. John's, Canada: Queen's Printer.
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- ^ Province of Newfoundland and Labrador (2017). Water Resources Act. St. John's, Canada: Queen's Printer.
- ^ Province of Newfoundland and Labrador (June 22, 2017). Newfoundland and Labrador Atlantic Accord Implementation Newfoundland and Labrador Act. St. John's, Canada: Queen's Printer.
- ^ Yukon Territory (2016). Oil and Gas Act. Whitehorse, Yukon: Queen's Printer. pp. 1–114.
- ^ Yukon Territory (2016). Environment Act. Whitehorse, Yukon: Queen's Printer. pp. 1–108.
- ^ Yukon Territory (2007). Waters Act. Whitehorse, Yukon: Queen's Printer. pp. 1–36.
- ^ Yukon Territory (July 27, 2004). Oil and Gas Drilling and Production Regulation. Whitehorse, Yukon: Queen's Printer. pp. 1–189.
- ^ Northwest Territories (December 12, 2017). Mackenzie Valley Resource Management Act (MVRMA). Yellowknife, Northwest Territories: Queen's Printer.
- ^ Northwest Territories (April 1, 2014). Northwest Territories Waters Act. Yellowknife, Northwest Territories: Queen's Printer.
- ^ Northwest Territories (2017). Environmental Protection Act. Yellowknife, Northwest Territories: Queen's Printer.
- ^ Northwest Territories (June 13, 2016). Northwest Territories Waters Regulations. Yellowknife, Northwest Territories: Queen's Printer.
- ^ Northwest Territories (1998). Spill Contingency Planning and Reporting Regulations. Yellowknife, Northwest Territories: Queen's Printer. pp. 1–11.