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Chapter 4
Development fields

Figure 4-1 Development fields

Figure 4-1 Development fields

4.1 The reservoirs

The Mackenzie Gas Project is anchored on the production of natural gas from three development fields near the edge of the Mackenzie Delta. These three fields— Niglintgak, Taglu and Parsons Lake—would produce about 172 Gm³ (6.1 Tcf) of sweet natural gas (see Table 4-1). This is enough gas to heat one million average Canadian homes for almost fifty years.

Each field consists of reservoirs of trapped natural gas. Typically, oil and gas reservoirs are found and the boundaries identified through activities such as two dimensional and three dimensional seismic surveys and drilling and testing of exploratory wells and delineation wells. Results from surveys and tests provide technical information on the sub-surface rock and the trapped gas. Computer models use this information to predict the best locations to put production wells for the most efficient method of extracting the gas. Appendix D –

Table 4-1 Recoverable volumes of natural gas in the development fields

Table 4-1 Recoverable volumes of natural gas in the development fields
Field Recoverable
volumes
of natural gas
Niglintgak 27 Gm³ (0.95 Tcf)
Taglu 81 Gm³ (2.8 Tcf)
Parsons Lake 64 Gm³ (2.3 Tcf)

Development Field Reservoirs: Characteristics and Exploration History provides additional information on the field reservoirs and exploration history.

Total supply from the anchor fields is projected to be about 24 Mm³/d (0.850 Bcf/d) of

sales gas, with level production for 12 years, following which production would decline until the reservoirs are depleted (see Figure 4-2).

Natural gas liquids production would begin at 1756 m³/d (11,050 Bbl/d) and would immediately decline (see Figure 4-3).

Figure 4-2 Natural gas supply

Figure 4-2 Natural gas supply

Figure 4-3 Natural gas liquids supply

Figure 4-3 Natural gas liquids supply

4.2 Niglintgak


4.2.1 Design of the Niglintgak facilities

Niglintgak is the westernmost of three natural gas fields associated with the project and is the starting point of the proposed Mackenzie Gathering System. Located entirely within Kendall Island Bird Sanctuary, Niglintgak is approximately 120 kilometres northwest of Inuvik and 85 kilometres west of Tuktoyaktuk.

Shell Canada Limited (Shell) is the Proponent for a Development Plan for the Niglintgak field under the Canada Oil and Gas Operations Act. Development of the field is estimated to cost $800 million with an estimated annual average operations and maintenance expenditure of $10 million per year for the period 2019 to 2023. Construction is planned over four winter seasons from 2014 to 2018 with production operations to commence in 2018 and continue for about 25 years.

The proposed production facilities include:

  • six to twelve production wells located on three well pads;
  • a system of above-ground flow lines;
  • a gas conditioning facility located in the Kumak Channel;
  • a disposal well; and
  • infrastructure including an emergency shelter and helipads.

Shell proposes to start construction by barging supplies and equipment to Camp Farewell (refer to Figure 4-1) during late summer 2014 in preparation for winter work. Production is scheduled to start in the summer of 2018. Highlights of the proposed construction and drilling activities are shown in Table 4-2.

Table 4-2 Niglintgak construction highlights schedule

Table 4-2 Niglintgak construction highlights schedule
Activity Season
and year
Barge supplies and equipment into Camp Farewell Late summer 2014
Start constructing well pad pilings, flow line pilings and well pad decking Winter 2014/15
Option to commence drilling at south well pad Winter 2014/15
Dredge gas conditioning facility transportation route, if required Summer 2015
Construct flow lines including horizontal directional drill Winter 2015/16
Excavate gas conditioning facility set-down site and prepare foundation Winter 2016/17
Transport gas conditioning facility to set-down location Summer 2017
Complete drilling and completion program and demobilize Winter 2017/18
Start up operations and production Summer 2018

Wells and well pads

All drilling would be conducted from three well pads (north, central and south) which would lie along the shoreline of the Mackenzie River’s Middle Channel (see Figure 4-5). Each well pad would be built of steel decking and elevated on steel piles.

From these pads, Shell plans to initially drill six production wells. Once production begins and more is learned about the reservoir, as many as six contingent wells may be needed to optimize natural gas recovery. Shell also indicated that some wells may require commingled production in order to recover gas with a minimal well count. Commingled production is production of oil and gas from more than one pool or zone through a common well-bore without separate measurement of the production from each pool or zone.

Flow lines and water disposal well

After the natural gas is extracted from the reservoir, it would be transported along 10 kilometres of insulated above-ground flow lines to a gas conditioning facility, where the gas would be separated from any liquid hydrocarbons and water. Water that has been removed would be sent to a disposal well on the south well pad. The flow lines would be elevated at least 2.2 metres above ground on vertical supports.

Figure 4-4 Niglintgak production facilities

Figure 4-4 Niglintgak production facilities

Gas conditioning facility

Shell’s proposed gas conditioning facility would be prefabricated and housed on a lightweight, ice-strengthened steel barge. The gas conditioning facility, designed for a maximum capacity of 4.3 Mm³/d (150 MMcf/d) consists of several production modules designed to:

  • separate the gas from free water and hydrocarbon liquids;
  • inject produced water into a disposal well;
  • compress and dehydrate the gas;
  • inject hydrocarbon liquids into the sales gas line; and
  • chill and meter the sales gas before it is pumped into the buried lateral pipeline which connects to the Mackenzie Gathering System.

Shell plans to tow the gas conditioning facility barge through the Beaufort Sea and into Little Kumak Channel in the Mackenzie Delta, where it would be set down on the Kumak Channel flood plain at a location north of the Little

Kumak Channel. The current design calls for a barge with a 1.5 metre draft that stretches 50 metres across and 150 metres in length, which is slightly larger than a soccer field. Once the barge reaches its final location, it would be installed onto steel-pile foundations.

Barging

The gas conditioning facility would be transported by barge through the Beaufort Sea and up the Mackenzie River. In summer, beluga whales, bowhead whales and ringed seals all make the southeast Beaufort Sea home. There is the possibility that personnel would encounter groups of marine mammals; however, encounters are anticipated to be short term. Measures such as reducing vessel speeds, using an onboard mammal monitor to watch for aggregations of bowheads, and redirecting vessels to avoid whales could be used to

mitigate these concerns. Impacts on water quality during transportation are not expected to be significant as no dredging is anticipated.

Shell’s preferred route to the set-down location runs through the previously dredged Kittigazuit Bay (location shown on Figure 4-1), which is part of an existing shipping lane. This would eliminate the need to dredge the shallow waters at the mouth of the Mackenzie River. Shell plans to perform bathymetry and if required, conduct additional dredging on the transportation route. Proposed production facilities for the Niglintgak field (see Figure 4-4) are described opposite.

Camp Farewell

Camp Farewell, which includes an airstrip, an equipment laydown area, a barge landing site and fuel storage facilities, would be used to support drilling and construction activities at Niglintgak. The camp is Shell’s staging and storage facility within Kendall Island Bird Sanctuary and has operated to support northern exploration and drilling activities since the late 1960s. It is located 15 kilometres southeast of the Niglintgak field and provides accommodation for 35 workers and support staff.

Figure 4-5 Niglintgak field map

Figure 4-5 Niglintgak field map

Views of the Board

We are satisfied with the general approach, conceptual design and plan proposed by Shell for the Niglintgak field. We note that when Shell drills and produces gas from its wells, new geological and reservoir data will be acquired that will determine if additional faulting and compartmentalization exists and whether any contingent wells would be required. Condition N18 requires Shell to submit to the National Energy Board an updated resource management plan within 18 months after production commences or prior to the drilling of contingent wells.

We consider Shell’s conceptual plan requiring commingled production in some wells in order to optimize gas recovery with a minimal well count to be acceptable. The National Energy Board will consider commingled production on an individual well basis during drilling and production operations in accordance with section 66 of the Canada Oil and Gas Drilling and Production Regulations.

Condition N31 stipulates that the approval of the Development Plan for the Niglintgak field under subsection 5.1(4) of the Canada Oil and Gas Operations Actis subject to the Minister of Indian Affairs

and Northern Development Canada providing confirmation that Shell has satisfactorily met the Benefits Plan requirements of section 5.2 of the Canada Oil and Gas Operations Act.

4.2.2 Development plan issues

During the hearing, we heard the following related to the development of the Niglintgak field:

  • matters raised by adjacent rights holders;
  • geographic and design issues related to permafrost, subsidence, flood protection and climate change;
  • air quality issues and greenhouse gas emissions;
  • activity and facility noise levels and environmental footprint in Kendall Island Bird Sanctuary; and
  • management of spoils from dredging operations.

Matters raised by adjacent rights holders

On 3 November 2004, the National Energy Board issued a declaration of Commercial Discovery (CDD) for the Niglintgak field, which includes land held and operated by several different parties. Shell is the sole interest holder of Significant Discovery Licence SDL019,

which encompasses most of the field (see Figure 4-6). A Significant Discovery Licence interest holder has the right to drill wells and, in the future, obtain production rights for subsurface oil and gas resources.

Shell's plans for developing the field are based on the results of reservoir modeling. Shell's models show a reservoir that is smaller and relatively shallow in comparison to the other two fields—the gas reserves lie only about 1000 metres below the surface—and much of the reserves lie underneath the Mackenzie River and its tributaries.

The reservoir is in the poorly consolidated Reindeer Sands geological formation and consists of several separate zones resulting from subsurface faulting. To fully recover the gas in the reservoir, Shell proposes a total of six to twelve wells on the three well pads. These sites were selected because the land has been disturbed by previous drilling activity.

Most of the activity would take place on the north pad where Shell plans to initially drill four gas wells. Initially, one gas well would be drilled on the central pad, and the south pad would contain both a gas well and a water disposal well. To reach the gas reserves, Shell plans to directionally drill under the Mackenzie River. The shallow depth of the reservoir will limit the length of these directionally drilled wells.

Figure 4-6 Commercial discovery declaration area and significant discovery licences for Niglintgak as of 2006

Figure 4-6 Commercial discovery declaration area and significant discovery licences for Niglintgak as of 2006

To the north of Significant Discovery Licence SDL019 lies the Significant Discovery Licence SDL016 land held by Mosbacher Operating Ltd. (Mosbacher), Talisman Energy Inc., and Chevron Canada Resources (Chevron) which is also the operator for these lands. To the south, east and west of Shell’s land, is Exploration Licence EL3941 held by Chevron and BP Canada Energy Company with Chevron being the operator.

Chevron and Mosbacher, as interest holders for lands adjacent to the Niglintgak field are concerned that Shell’s proposed development would drain their gas resources. Mosbacher and Chevron would prefer to develop the Niglintgak field in collaboration with Shell, either by unitization or by providing third-party access to common facilities.

A unitization agreement would allow parties to jointly develop the field in exchange for a predetermined share of the end product. Shell is opposed to a unitization agreement. Shell also stated that no order for unitization to prevent waste under section 38 of the Canada Oil and Gas Operations Actis required as there would be no waste. Shell argued that Chevron and Mosbacher, like Shell, have rights to drill wells and develop their lands, but unlike Shell, Chevron and Mosbacher have chosen not to exercise those rights. In Shell’s opinion, the Chevron and Mosbacher lands lie on the outer fringes of the reservoir and there is not enough information about Chevron’s and Mosbacher’s potential gas reserves to conduct meaningful

[1] Exploration Licence EL394 has expired and Production Licence PL25 was issued on 17 September 2008 for sections 17, 28 and 39. The current representative interest holder of Production Licence PL25 is MGM Energy Corp.

discussion around unitization. Shell believes the only way Mosbacher and Chevron can prove the extent of gas reserves under their land is by drilling their own wells. This could be assisted by allowing Chevron and Mosbacher access to Shell’s well pads so that they may directionally drill wells onto their lands. According to Shell, their proposed well pads could be adjusted to accommodate additional drilling activities, provided all parties could reach a mutually agreeable financial arrangement. If Chevron and Mosbacher choose to drill wells from Shell’s well pads, the pads could be extended by 15 metres for each additional well.

According to Shell’s estimates, the maximum horizontal reach for wells in the Niglintgak Field is approximately 1.3 to 1.5 kilometres. Chevron and Mosbacher could potentially drill a well from Shell’s north and central well pads into their adjacent lands. If an arrangement is reached during the design phase, Shell would consider modifying its facilities, including installing additional river crossings and enlarging flow line structural supports for future expansion and meeting additional fuel gas and power supply requirements for well pads.

Typically when gas fields are developed, wells are positioned according to an established grid of “spacing units”, such as that set out in the National Energy Board’s 2009 Draft Spacing Requirements2. The 2009 Draft Spacing Requirements establish a 250 metre off-target

[2] The 2009 Draft Spacing Requirements were issued on 31 December 2009 and replaced the Draft Spacing Unit Regulations.

area3 intended to provide adjacent interest holders the opportunity to develop wells on their lands. Shell indicated that the 250 metre off-target area is appropriate, but requested a variance in accordance with the 2009 Draft Spacing Requirements in order to allow for the optimum location of some wells.

In final argument, both Chevron and Mosbacher indicated that the proposed Niglintgak Development Plan was sub-optimal with respect to minimizing waste and referenced sections 18 and 19 of the Canada Oil and Gas Operations Act. In the absence of joint development, both Chevron and Mosbacher submitted to us that Shell should not be granted a variance in accordance with the 2009 Draft Spacing Requirements for Significant Discovery Licence SDL019 as this would exacerbate drainage of gas from their lands.

Chevron asked us to consider a condition that would require field development to take into consideration the area needs when designing and sizing facilities. Chevron also asked for a condition restricting well density to no more than one well per spacing unit for all Shell lands. The third condition requested by Chevron would require Shell to provide a one grid unit set-back between Significant Discovery Licence SDL019 and lands of differing ownership.

Mosbacher suggested a condition that would direct Shell to include all land in Significant Discovery Licence SDL016 within the commercial

[3] The 250 metre off-target area replaces the one grid unit set-back outlined in the Draft Spacing Unit Regulations.

discovery declaration area as part of the Niglintgak Development Plan. Secondly, Mosbacher asked for a condition requiring Shell to fully explore joint production arrangements with other interested parties. The third condition requested by Mosbacher would have Shell make available drilling pad space on reasonable commercial terms to allow Mosbacher and other interested parties the opportunity to drill additional wells on a timely basis.

Views of the Board

We are of the view that if the interest holders of the adjacent lands wish to develop their lands a joint and collaborative approach to the development of the Niglintgak field would be advantageous to all parties involved. The benefits would include a minimal duplication of facilities and a minimal environmental footprint within Kendall Island Bird Sanctuary. It is also our view that joint development is best obtained through voluntarily commercial negotiations and agreements between the parties involved. We note that the compulsory unitization4 provisions in the Canada Oil and Gas Operations Actrequire participation from Shell as it holds a large portion of the lands comprising the Niglintgak commercial discovery declaration area. Shell has stated that it requires that

[4] Compulsory unitization, sections 39 to 47 of the Canada Oil and Gas Operations Actcame into force on 31 July 2010. Compulsory unitization requires one or more working interest owners who are parties to a unit agreement and a unit operating agreement and own in the aggregate sixty-five percent or more of the working interests in a unit area to apply for a unitization order with respect to the agreements.

Chevon and Mosbacher drill wells on their lands to demonstrate productivity before serious discussions could occur on joint development or unitization of the Niglintgak field. In this regard, Condition N2 requires the Niglintgak north, central and south well pads to be designed so each may be expanded to allow for the drilling of at least one well by third parties. If the parties involved are able to work out commercial terms including timing, the condition would provide Chevron and Mosbacher the opportunity to drill directional wells to delineate the field on their lands with a minimal environmental footprint in Kendall Island Bird Sanctuary.

As there currently is no joint production arrangement between the interest holders of Significant Discovery Licence SDL016 and Shell, we are of the view that there is no basis for Mosbacher’s condition directing Shell to include all sections of land in Significant Discovery Licence SDL016 within the commercial discovery declaration area as part of the Niglintgak Development Plan. As noted, the first step that needs to be taken to commence meaningful discussions on joint production arrangements is the drilling of wells by Chevron and Mosbacher. Without wells on their lands, adjacent interest holders cannot make volume commitments with respect to third party access to Shell’s facilities. Therefore, we are not persuaded to include the Mosbacher condition requiring Shell to fully explore joint production arrangements with other interested parties or the Chevron condition

requiring field development to take into consideration the area needs when designing and sizing facilities.

In the absence of joint development arrangements, we are of the view that the 2009 Draft Spacing Requirements are appropriate and provide an approach that balances the optimization of gas recovery with the protection of the correlative rights of adjacent land interest holders. Condition N19 requires Shell to comply with the 2009 Draft Spacing Requirements. We are not persuaded by Chevron to require a one grid unit set-back between Significant Discovery Licence SDL019 and lands of differing ownership. We consider the 250 metre off-target area for gas wells to be appropriate noting that it is consistent with set-backs used in Alberta, British Columbia, Saskatchewan and Yukon.

The 2009 Draft Spacing Requirements set a limit of one producing well in spacing units adjacent to lands of differing ownership, but for spacing units not adjacent to lands of differing ownership, there is no off-target area and more than one producing well is permitted5. Therefore, we are not persuaded by Chevron to restrict well density to no more than one well per spacing unit for all Shell lands.

[5] Part IV of the 2009 Draft Spacing Requirements.

According to the 2009 Draft Spacing Requirements, Shell would not need a variance for the proposed preliminary well locations. Any future application for a variance would be considered by the National Energy Board at that time and would be assessed in accordance with the 2009 Draft Spacing Requirements, or any orders dealing with spacing that may supersede it.

We are of the view that the proposed production scheme is appropriate for a conventional gas field such as Niglintgak. With Condition N19 in place requiring compliance with the 2009 Draft Spacing Requirements, interest holders of Significant Discovery Licence SDL0166 and Production Licence PL25 have the opportunity to drill wells and develop their lands. We do not consider there to be sufficient grounds to find that the Niglintgak Development Plan is suboptimal in terms of minimizing waste7, as suggested by Chevron and Mosbacher.

[6] The lands comprising Significant Discovery Licence SDL016 are eligible for a production licence as those lands were included in the NEB’s commercial discovery declaration dated 16 September 2004.

[7] Waste as defined in section 18 of the Canada Oil and Gas Operations Act

Geographic and design issues

Permafrost

The Niglintgak field is located within a zone of intermediate discontinuous permafrost. Well operations could produce not only warm natural gas, but also circulate other warm liquids, such as reservoir and drilling fluids, which could thaw the permafrost. Thawing of the permafrost may alter the landscape.

To reduce disturbance to the permafrost, Shell proposes to space the wells a minimum of 15 metres apart, and implement a number of other mitigative measures to reduce thawing of the permafrost by warm fluids from well operations. In addition, the well pads would be constructed on a raised steel deck, and the flow lines would be insulated and elevated.

One reason Shell chose the proposed set-down location for the gas conditioning facility is that the site is underlain by permafrost, which provides several options for excavation of the area. Shell’s preferred approach is a combination of winter mechanical excavation and summer dredging. Once the gas conditioning facility is in place, the site would be dammed off and drained to isolate it from the channel to allow the permafrost layer to re-establish naturally.

Did you know?

Horizontal directional drill

A method for installing pipelines or other utilities beneath rivers, streams, channels, roads and other obstacles without requiring a trench and with minimal disruption to the surface. A drill rig is used to bore an underground passage for the pipeline or utility with a directionally controlled drill head. The passage is reamed out to an appropriate size and the pipe or utility is then pulled through.

The location of the gas conditioning facility requires the flow lines from the north and central pads to cross the Kumak Channel, a distance of approximately one kilometre. A feasibility assessment for a horizontal directional drill indicated that ice-rich, thaw-unstable permafrost effectively surrounds the Kumak Channel, but concluded the crossing may be successfully constructed with the application of mitigative measures, such as using chilled drilling fluids, to prevent permafrost thaw.

Shell’s alternative to the horizontal directional drill would be a trenched flow line crossing about 900 metres downstream of the proposed horizontal directional drill crossing bordering the Little Kumak Channel.

Views of the Board

We are satisfied with Shell’s general approach to addressing permafrost integrity for the Niglintgak development. We note that because warm fluids get circulated up and down the wellbore during drilling and production operations, it is important for safety and environmental protection reasons that the permafrost thaw bulbs around wellbores do not coalesce. Condition N3 requires the interwell spacing on Niglintgak well pads to be no less than 15 metres unless Shell utilizes mitigation measures approved by the National Energy Board.

We are of the view that Shell’s preliminary horizontal directional drill design is satisfactory. We note that horizontal directional drill design has been used only once in permafrost areas and that this increases the potential for unforeseen issues during installation. We agree with the use of temperature controlled drilling muds for the horizontal directional drill crossing. When this is not possible, the alternative use of freezing temperature depressants has potential undesirable long term impacts on slope stability and their use as an option in horizontal directional drill must be carefully considered before implementation. Condition N7 requires Shell to provide: a hazard analysis and contingency plan for the proposed horizontal directional drill crossing; detailed final design drawings for the proposed horizontal directional drill

crossing and the contingent open cut crossing; a monitoring program of slope stability, scour, drainage impedance and erosion issues for the crossing; and evidence of consultation with other appropriate regulators and government departments.

Subsidence

The reservoir for the Niglintgak field is located in the Reindeer Sands Formation, formed 60 million years ago in the Early Tertiary Period. When natural gas from the Niglintgak field is extracted from the poorly consolidated Reindeer Sands Formation, the sands may become more tightly packed and the surface could settle. This phenomenon is called subsidence. With this subsidence, the Niglintgak field, which is located within the active Mackenzie Delta floodplain, may be more prone to flooding. The low lying terrain of Niglintgak Island presently experiences annual spring floods as snow melt raises water levels in lakes, rivers and their tributaries throughout the Mackenzie Delta.

Shell predicts a maximum subsidence of 0.45 metres at the surface over the centre of the reservoir, which correlates with the centre of the Middle Channel, and predicts subsidence of 0.15 metres at the set-down location of the gas conditioning facility. Shell has indicated that it is considering using global positioning system targets on each of the well sites, the gas conditioning facility, on flow lines and at a number of benchmark locations to monitor subsidence.

Joint Review Panel Report recommendation 6-10 asked us to require Shell to file with the National Energy Board a program to monitor subsidence and flooding due to hydrocarbon extraction for the Niglintgak field. In a letter dated 28 January 2010 responding to the Joint Review Panel Report recommendations the Proponents submitted to us that recommendation 6-10 be rejected as our proposed Condition 7 (dated 5 February 2007) for the Niglintgak field was sufficient. In the Proponents’ view, it was unlikely to be technically feasible to monitor flooding due to hydrocarbon extraction since it would be very difficult to differentiate flooding due to hydrocarbon extraction from natural flooding. The Proponents said that flooding at Niglintgak is a natural and annual occurrence.

In argument, Environment Canada suggested the following revisions to the condition:

  • clarify and enhance consultation;
  • include the monitoring of flooding due to subsidence in order to determine the loss of nesting habitat;
  • include monitoring of reservoir compaction in order to differentiate project-induced subsidence from natural changes in ground elevation; and
  • allow the use of the most appropriate technology at the time including airborne and remote sensing techniques.

Shell responded in argument by proposing the condition include the terms “best management practices” and “best available technology” in regards to monitoring.

Views of the Board

We are of the view that it will be important to monitor and confirm Shell’s estimates of subsidence due to hydrocarbon extraction because the Niglintgak field is located inside Kendall Island Bird Sanctuary and is one of the first proposed developments in the Mackenzie Delta where subsidence due to gas extraction is predicted to occur. Condition N4 requires Shell to submit a program to measure and monitor accumulated subsidence and to monitor flooding for the life of the field.

Environment Canada indicated monitoring of reservoir compaction was needed to differentiate project-induced subsidence from natural changes in ground elevation. Condition N4 requires that elevation benchmarks be located outside of the projected gas-extraction-subsidence-area. We believe that these elevation benchmarks will act as control or reference points to provide data to estimate natural subsidence. We are not persuaded that monitoring of reservoir compaction is necessary.

We agree with Environment Canada that the condition should allow for the use of the most appropriate technology at the time. This is similar to Shell’s suggestion to use the terms “best management practices” and “best available technology” in the condition. Condition N4 has been amended to reflect this.

We agree with Environment Canada’s suggestion to clarify and enhance consultation and Condition N4 has been revised in this regard.

Flood protection and climate change

Shell’s approach to flood protection was to estimate a maximum value for subsidence due to gas extraction and add factors such as the maximum predicted flood level, rising sea levels due to climate change, an increased severity of storm surges, permafrost thaw, and maximum wave height. These factors were all taken into consideration when developing the preliminary design for the well pads, flow lines and the barge-based gas conditioning facilities. Shell determined that permafrost thaw subsidence on areas vulnerable to flooding was much smaller, by an order of magnitude, than subsidence from gas extraction and, therefore, permafrost thaw subsidence was not significant.

Subsidence at the original set-down location of the gas conditioning facility was predicted to be 0.15 metres. A substructure design height of 5.75 metres was determined for the gas conditioning facility, which included consideration of subsidence, foundation settlement, maximum flood level, rise in sea level, storm surge, wave crest and a freeboard of 0.3 metres as additional protection (see Figure 4-7). The well pads would be set between 3 and 4 metres above grade and the flow lines would be elevated a minimum of 2.2 metres above grade.

Shell believes that it has used a conservative approach to estimate the effect of thawing permafrost in its determination of the design height of its facilities. Should the waters of the Mackenzie River ever threaten the facilities, some modification to the facilities and flow lines would be considered. This could include:

  • increasing the height of the equipment platforms and flow lines;
  • increasing the number of restraint points on flow lines and certain well site equipment, such as tanks;
  • installing a flood barrier around the plant perimeter at deck level;
  • increasing the depth of the substructure and raising the elevation of the plant on the gas conditioning facilities; and
  • installing ice barriers.

Warming of the global and regional climate could raise sea levels and affect weather patterns. The Niglintgak field is located in the low-lying Mackenzie Delta near the Beaufort Sea.

We heard concerns that seasonal flooding and storm surges could affect these facilities during the life of the project. Shell provided evidence that the facilities would be high enough to protect them from storm surges and flooding even if sea levels rise.

The Sierra Club of Canada was concerned about the lack of peer-reviewed research publications on the effects of climate change, specifically for the Mackenzie Delta over the 30 year life span that was used by Shell in the design of the Niglintgak facilities. The Sierra Club of Canada stated that from a design perspective, there is uncertainty regarding the effects of climate change on the permafrost, the rise in sea level and the degree of flooding. The Sierra Club of Canada referred to the Arctic Climate Impact Assessment prepared by the International Arctic Science Committee. The Arctic Climate Impact Assessment states that the Arctic is experiencing the most rapid and severe climate change on earth, including the disappearance of Arctic sea ice which allows higher waves and storm surges.

Shell indicated that the direct impact of sea level rise over 30 years should not exceed 0.1 metre This was based on research from the United States Environmental Protection Agency (September 1995) and the Intergovernmental Panel on Climate Change in 2001.

These documents contain extensive analysis of all the parameters that could influence sea level rise from climate change. Shell noted that the change in the annual average mean sea level, recorded at Tuktoyaktuk between 1971 and 2005 indicates that sea level changes are at a low level (less than 0.1 metres over 35 years). Shell believes previously mentioned research and Environment Canada data endorses its view that the direct impact of sea level rise over 30 years should not exceed 0.1 metres, but that an increase in the magnitude of storm surges needs to be considered. Shell indicated that it will look at whatever evidence and information is available, and if it leads to a different conclusion, Shell would need to increase design margins and would do that. Facility designs

Figure 4-7 Niglintgak substructure design height

Figure 4-7 Niglintgak substructure design height

will include adaptive management and future mitigations, where appropriate.

The Joint Review Panel was generally satisfied that Shell had taken climate change into account in its design. Nevertheless the Joint Review Panel recommended that the National Energy Board add a condition to the certificate which would require Shell to file final design plans that incorporate further design analysis of the impacts of climate change on permafrost and terrain stability over the design life of the project and post-abandonment. The Joint Review Panel was of the view that this analysis should be conducted for a series of representative locations, conditions and terrain types and should incorporate climate variability, in particular, upper limit temperature scenarios to account for the range of future temperature conditions, including variability and extremes, and the impact of this variability on stream flow regimes. The Joint Review Panel added that the results should be incorporated into monitoring, mitigation and adaptive management plans. The Joint Review Panel thought that this analysis should be provided to other appropriate regulators in sufficient time for review and to provide input to the National Energy Board.

Indian and Northern Affairs Canada suggested in final argument that the Proponents should demonstrate how upper limit temperature scenarios have been considered in their design.

Further specific discussion on climate change regarding project design is found in Chapter 6.

Views of the Board

We are satisfied with Shell’s climate change estimates used in the design. Given the uncertainty regarding climate change predictions and the vintage of studies and data used by Shell, a prudent step would be to assess the design using upper limit temperature scenarios as suggested by the Joint Review Panel. As the name implies, upper limit temperature scenarios would be less likely to occur than what has been used by Shell for the design of the project.

Condition N8 requires Shell to provide final detailed design information that incorporates an analysis of the impacts of climate change and variability on permafrost and terrain stability for the Niglintgak facility using potential upper limit temperature scenarios which may occur during the operational life of the facilities. Shell will also provide information about how upper limit temperature scenarios may impact precipitation, rise in sea level, storm surges, ice floes and flood levels, and watercourse crossing designs. We are of the view that government departments such as Environment Canada, Indian and Northern Affairs Canada and Natural Resources Canada should be consulted to benefit from their expertise for the field design.

Air quality issues

Air quality in the North is considered to be of high quality and Northerners are very concerned that it remains that way. Both Environment Canada and the Proponents agreed that existing air quality in the proposed project area is good and, along with other government regulators, emphasized the need to “keep clean areas clean.” This principle requires new industrial development to be “planned, constructed and operated in a manner that minimizes the degradation of air quality in these areas.”

Air quality issues for the project included project emissions for the pipeline and development fields, monitoring, and greenhouse gases in the context of monitoring climate change. The Joint Review Panel noted that the National Energy Board would be the prime regulator of air emissions from the project and that Environment Canada and the Government of the Northwest Territories would play advisory roles. The Joint Review Panel recognized the National Energy Board’s expertise and experience in regulating interprovincial aspects of the oil, gas and electric utility industries, including environmental matters. The Joint Review Panel also recognized the extensive environmental and local knowledge that Environment Canada and the Government of the Northwest Territories can provide.

Air emissions can be related to the project-specific effects of construction, operations, and waste incineration. Air quality impacts can be local to regional in the case of particulate matter and sulphur dioxide, or global in

the case of greenhouse gases. Emissions would occur during the construction phase through intermittent flaring during well testing at the Niglintgak field.

Further specific details pertaining to emissions for the pipeline are discussed in Chapter 3 and discussion on air emissions pertaining to facility design is found in Chapter 6.

The Joint Review Panel report indicated that the Proponents’ baseline information was compiled from historical data and results of air quality monitoring that was carried out over one year near the communities of Inuvik and Norman Wells, and periodically at the Parsons Lake and Taglu gas fields. The Proponents’ monitoring data and other sources indicated that background concentrations of air contaminants are generally below detection levels or applicable guidelines. The one exception that is not below detection levels is ozone; relatively high background levels were monitored in Inuvik and Norman Wells. The Proponents indicated that elevated ozone levels at high latitudes in the northern hemisphere are thought to result from the intrusion of stratospheric ozone. The Proponents stated that all ground-level concentrations of compounds released by the project during operations at the gas fields, the Inuvik Area Facility, and compressor and heater station sites would increase, but would be below those outlined in applicable federal and territorial guidelines at all locations in the production area and along the pipeline corridor.

Environment Canada recommended that the Proponents design and implement suitable air quality monitoring programs with its help. Environment Canada focused its recommendations on pollution prevention and the use of best available technology and best management practices to minimize the degradation of air quality. Further discussion around application of these principles may be found in Chapter 6.

The Dehcho Elders and Harvesters indicated that the project needs to be designed to minimize air quality impacts, with monitoring plans in place to verify the predicted emissions and impacts. Corrective action needs to be taken quickly to avoid impacts upon the land and wildlife from degraded air quality.

Greenhouse gas emissions

Parties were concerned about the impacts of the project on climate change, especially in light of Canada’s international efforts under the United Nations Framework Convention on Climate Change and the Kyoto Protocol.

Greenhouse gas emissions arising from the project include carbon dioxide, methane and nitrous oxides with each compound having a different climate change potential. During operation, the project would emit greenhouse gases from burning natural gas at combustion related sources such as compressors and methane gas released through normal venting procedures and minor leaks (fugitive emissions). Further specific discussion on air emissions pertaining to facility design is found in Chapter 6.

Alternatives North submitted that the National Energy Board and the Government of Canada have a public interest mandate that requires consideration of greenhouse gas emissions.

Ecology North deemed that high project-specific standards for greenhouse gas emissions based on a robust and strong definition of best available technology and accompanied by penalties in the cases where they do not meet those project standards or targets, would provide the best possible protection in terms of minimizing upstream greenhouse gas emissions associated with the project.

Sierra Club of Canada submitted that we need to specify an actual target and it is not enough to just leave it up to the Proponents. Sierra Club of Canada indicated that the target should at least match the general recommended target in Joint Review Panel recommendation 8-8.

Views of the Board

We understand the importance of clean air in the North and that air quality must be considered in a cumulative manner. We also recognize the need to minimize greenhouse gas emissions resulting from the project. The Joint Review Panel directed several recommendations to us relating to air quality and air emissions. We have addressed air issues through several conditions for the Mackenzie Gas Project. These conditions are focused on the Proponents taking appropriate measures to minimize air emissions and address air quality. We are committed to working

collaboratively with Environment Canada and the Government of the Northwest Territories to protect air quality in the North, recognizing the extensive environmental and local knowledge that these agencies can provide.

Conditions N14 and N16 address technologies for reducing emissions, incorporation of best management practices and best available technologies, and facility design. Condition N15 requires the submission of a report evaluating incinerator emissions from camps and station facilities and technologies and practices must be reflected in the waste management plans required by Condition N12. Condition N17 requires Shell to minimize and reduce emissions from flaring. Further specific discussion for these conditions regarding air emissions pertaining to facility design is found in Chapter 6.

Air quality monitoring is part of comprehensive environmental monitoring under an environmental management system. Through environmental management, systems are established to address effects of the project on the environment and of the environment on the project, with the overall goal of minimizing negative impacts. Adaptive management is a systematic process for continually improving management practices by learning from their outcomes.

Environmental monitoring is an important part of environmental management that directly supports adaptive management by observing and evaluating the effects that occur, then changing or adding mitigative measures as appropriate to limit or reverse the environmental effects. Environmental monitoring can include:

  • compliance monitoring, to verify that all environmental mitigation is implemented as presented in the Environmental Protection Plan and environmental alignment sheets and that work is in compliance with environmental regulations; and
  • effects monitoring, to assess the effects resulting from project-environment interactions and evaluate the effectiveness of approved mitigation measures. This is further discussed in section 3.3.6.

Shell is expected to implement Environmental Protection and Monitoring and Surveillance Programs which include protection of the environment as one of the main goals. A monitoring program may:

  • identify any issues or potential concerns that may compromise the protection of the environment;
  • include methods for developing measures to prevent or mitigate the impact of the identified issues;
  • provide for continued monitoring of sites to evaluate success of mitigative measures undertaken;
  • provide a system for implementing additional mitigative measures as necessary; and
  • provide a feedback system that allows for adaptation of successful mitigation to future pipeline projects.

Monitoring programs may have specific goals and targets and could include methods for evaluating and interpreting collected data such as air quality or emissions data. Monitoring may include any relevant environmental practices (e.g., vegetation establishment, water quality sampling, waste disposal).

Responsibilities of the National Energy Board regarding monitoring include:

  • conducting environmental inspections of facilities, verifying compliance with terms and conditions, and assessing the effectiveness of mitigation;
  • monitoring ongoing operation, verifying reclamation and maintenance of the project site to acceptable standards; and
  • conducting environmental audits, evaluating environmental management systems and environmental programs.

We generally require the filing of environmental post-construction monitoring reports as a condition of an authorization. The information in monitoring reports should include:

  • confirmation of proper implementation of mitigation and reclamation measures used;
  • identification of the outstanding environmental issues; and
  • discussion of the company’s plans for how outstanding issues will be resolved.

Condition N11 requires Shell to submit an Environmental Protection Plan which includes monitoring of activities. Condition N15 includes the requirement for monitoring incinerator emissions.

A commitment to continuous improvement, outlined in Joint Review Panel recommendation 8-6, is expected to be a component of an operator’s management system pursuant to paragraph 5(2)(b) of the Canada Oil and Gas Drilling and Production Regulations. This is addressed in Condition N11. We are of the view that the commitment to continuous improvement is not limited to greenhouse gas emissions but should apply to all discharges to the environment, which in this case is the atmosphere. Condition N11 also covers the requirements for methods and locations of monitoring.

Condition N16 requires the Proponents to file a report outlining the use of best available technology for station facility construction. Selection of best available technology is the most significant factor in determining achievable air emissions targets. Condition N11 outlines the requirements for an Environmental Protection Plan. The condition requires the Proponents to submit maximum

proposed greenhouse gas targets and reduction strategies for air emissions including particulate matter, NOx and greenhouse gases. Condition N11 also addresses other matters from the Joint Review Panel recommendations including employee training, monitoring, public communication, and required consultation with Environment Canada and the Government of the Northwest Territories. With these conditions, we find it acceptable for the Proponents to develop greenhouse gas targets for the project consistent with use of best management practices and in consultation with appropriate government agencies.

Kendall Island Bird Sanctuary

Kendall Island Bird Sanctuary was established in 1961 and is the only protected area in the Mackenzie Delta. It is one of the most significant wetland complexes in North America and the deltaic landscape of the Niglintgak field is a haven for the more than 90 species of birds that migrate to the region annually. The 623 square kilometre Kendall Island Bird Sanctuary provides critical habitat for thousands of songbirds, waterfowl and shore birds that use the area for breeding and staging. Kendall Island Bird Sanctuary has been identified as a Key Habitat Site which is defined as an area that supports at least one percent of the national population of a migratory bird species for any portion of its annual cycle. Kendall Island Bird Sanctuary is considered by Environment Canada to be an important component of Canada’s effort to conserve biodiversity. Under the Migratory Birds Sanctuary Regulations, Environment Canada has authority over surface developments in Kendall Island Bird Sanctuary and has established a limit of one percent or 600 hectares as the allowable surface disturbance in the Sanctuary for all oil and gas activities. As a result, Environment Canada encourages project design considerations that result in the least possible long-term impact on habitat. To reduce impacts on migratory birds, Environment Canada has indicated that it may restrict or apply special conditions to activities such as construction, operation, monitoring and decommissioning in Kendall Island Bird Sanctuary during the period between May

through October when the Sanctuary is occupied by birds. Furthermore, Environment Canada has indicated its preference for Shell to construct above-ground flow lines within Kendall Island Bird Sanctuary. In final argument Shell indicated it is committed to using above-ground flow lines to reduce surface disturbance.

Activity and facility noise levels

The Niglintgak anchor field is located in Kendall Island Bird Sanctuary which is a federally protected area managed for the conservation of migratory birds and protection of habitat for northern-breeding birds. Shell holds Significant Discovery Licence SDL019 that grants it subsurface oil and gas rights. Environment Canada has regulatory authority for activities within Kendall Island Bird Sanctuary, and will issue permit conditions governing noise emissions from development under the Migratory Bird Sanctuary Regulations. Environment Canada and the Proponent have both agreed to follow Alberta’s Energy Resources Conservation Board Directive 038 for noise regulation. There is currently no legislation or standard in the Northwest Territories governing noise emissions.

Alberta’s Energy Resources Conservation Board Directive 038 indicates a recommended noise target for remote areas even if no human residences are present. This is considered the “business as usual” requirement. The Directive has provisions to change the typical target when there are unique circumstances, including

if an area is “pristine”—a pure, natural area that might have dwellings but no industrial presence. Environment Canada recommends continuous noise emissions, as measured from the fence line of the facility, not exceed Alberta’s Energy Resources Conservation Board Directive 038 “best practices” permissible sound levels during the period from 10 May to 30 September when migratory birds are present in the Sanctuary because Kendall Island Bird Sanctuary is considered a pristine area.

Shell has indicated the primary noise generation sources at the Niglintgak facilities such as compressors, power generation equipment and aerial coolers, will be designed so that the resulting sound levels will be below the maximum permissible noise levels provided in Alberta’s Energy Resources Conservation Board Directive 038. The Proponents agree with Environment Canada that the appropriateness, both technically and economically, of the proposed regulatory requirement will be further informed when detailed design progresses and before finalizing Environment Canada permit conditions. For facilities in Kendall Island Bird Sanctuary, the Proponents will continue to evaluate and apply noise mitigation options beyond those required to meet the “business as usual” interpretation of Alberta’s Energy Resources Conservation Board Directive 038, provided these are practical. Shell is expected to provide detailed engineering and noise modeling results to Environment Canada.

Shell plans to schedule activities to avoid critical migratory bird nesting periods where practical. Because the Niglintgak field is relatively shallow at 1000 metres, drilling times can be reduced compared to Taglu and Parsons Lake. Shell is proposing a winter-only drilling program, and completions for most wells during winter months over three to four consecutive years. However, two well completions are proposed by Shell in the intervening summer seasons. Other construction activities such as barging, bathymetric work, dredging, transporting and setting of the gas conditioning facility would also occur in summer.

Both the Proponents and Environment Canada shared the view that requirements for noise regulation in Kendall Island Bird Sanctuary, both for the National Energy Board and migratory bird sanctuary requirements, can only be finalized after detailed engineering and design work is completed, after the noise impact analysis is prepared, and after discussions between the parties. Environment Canada will continue to work with the National Energy Board, Proponents and other regulators on issues related to noise in Kendall Island Bird Sanctuary. Shell indicated that it is committed to adhering to requirements in Alberta’s Energy Resources Conservation Board Directive 038, as well as continuing evaluation of noise mitigation through detailed engineering and planning in order to arrive at practical solutions to concerns raised by Environment Canada.

Views of the Board

We agree with Environment Canada that regulating impacts of noise in a nationally protected bird sanctuary requires special consideration and application of best practices and the use of best available technology with the intent of “continuous improvement of pipeline safety and environmental protection”. Condition N9 applies to regulating noise in the Niglintgak field and is intended to minimize disturbance from facilities inside Kendall Island Bird Sanctuary. The Condition requires meeting Alberta’s Energy Resources Conservation Board Directive 038 “business as usual” standard with allowance for achieving the more stringent standard that Environment Canada recommended to the Joint Review Panel and the Joint Review Panel accepted. There is flexibility built in to the condition to adjust the standard as informed by final detailed engineering, an independently verified noise impact analysis report, and continued consultation for final determination of the fence line, which is the measurement base for a distance-based regulatory standard.

Overall footprint

Shell’s preliminary design anticipates less than ten hectares of total new disturbance within Kendall Island Bird Sanctuary. This new disturbance includes the entire gas conditioning facility, the three well pads, the above-ground flow lines and modifications to the pre-existing Camp Farewell and a stockpile site.

To prepare a level set-down site for the gas conditioning facility, up to 50 000 cubic metres of silt, mud and other material would need to be excavated. The majority of material would be removed in the winter and, if required, some minor dredging or the removal of mud from the channel floor would occur the following summer. One reason Shell chose the proposed location for the gas conditioning facility is that the site is underlain by permafrost, which provides several options for excavation of the area. Shell’s preferred approach is a combination of winter mechanical excavation and summer dredging.

Shell reduced the scope of dredging and made design modifications to avoid or reduce dredging in the delta area. As a result, the gas conditioning facility barge draught was reduced from 1.9 to 1.5 metres, the location was moved outside of Little Kumak Channel, and Shell committed to schedule its dredging activities to avoid impacts on the beluga harvest.

Shell’s current plan is to deposit the excavated material adjacent to the gas conditioning facility site within Kendall Island Bird Sanctuary. Environment Canada indicated that it would not allow placement of the excavated stockpile

within Kendall Island Bird Sanctuary if it were to result in the permanent loss of habitat. The best placement for these materials will be finalized by Shell after discussions with regulators and stakeholders, including Environment Canada, to reduce the impact on local wildlife.

To reduce the level of permanent disturbance, Shell plans to locate the well pads at previously drilled well locations and would incorporate as much of the previously disturbed land as feasible. Shell also plans to augment the steel pads with temporary ice pads for the drilling equipment. The ice pads would not leave a permanent footprint once drilling is complete.

Access to the field would be by winter road or helicopter from Camp Farewell. Shell does not propose permanent access.

In addition to the permanent footprint, Shell estimates a 17.5 hectare temporary footprint or land disturbed during the construction of ice pads and an ice road.

The disposal of drilling waste is not permitted within the Sanctuary, so Shell’s initial plan was to dispose of these drill cuttings in a sump located outside of Kendall Island Bird Sanctuary. However, Shell has since adopted its alternative method which is to transport the cuttings out of the Northwest Territories to an approved landfill in Alberta or British Columbia.

In developing its Development Plan Application, Shell met with a variety of stakeholders including Aboriginal peoples and other Northerners, various government representatives, communities

and oil and gas companies. Information from these discussions was used to develop and refine Shell’s plans. Examples of community-driven design changes to the Niglintgak Project were discussed during final argument and include reducing overall footprint by locating drilling sites at pre-disturbed locations, preferentially scheduling drilling and construction activities in the winter and using above-ground flow lines to reduce surface disturbance.

Dredging activities will occur within Kendall Island Bird Sanctuary and Environment Canada will not permit the spoil to be placed on undisturbed terrestrial habitat within Kendall Island Bird Sanctuary. Environment Canada requested that we require that Shell’s plan for excavation and dredging at the site of the gas

conditioning facility at Niglintgak describe the potential impacts associated with dredging, and include spoil management and the site-specific mitigation measures to address adverse impacts.

To address Joint Review Panel Report recommendation 9-9 regarding dredging and excavation of the set-down location for the barge-based gas conditioning facility, we proposed Condition N10 on 9 March 2010. During final argument, Environment Canada suggested that the condition be expanded to require a dredging spoil management plan. Environment Canada and a number of other parties indicated that consultation needed to be defined or clarified. Shell asked that the timing of the condition be adjusted so that the dredging plan is not linked to well pad construction.

Views of the Board

We have considered the various comments regarding Condition N10 and the condition has been amended to require a dredging spoil management plan, to clarify requirements for consultation and to adjust the timing so it is no longer linked to construction of the well pads. The best placement of dredging materials will be finalized by Shell after consultation with regulators and stakeholders, including Environment Canada, to reduce the impact on local wildlife. Environment Canada has authority over activities in Kendall Island Bird Sanctuary under the regulations.

4.3 Taglu

4.3.1 Design of the Taglu facilities

The Taglu field lies above the Arctic Circle near the northern edge of the Mackenzie Delta. Currently the largest onshore gas field ever discovered in the Mackenzie Delta, it is estimated that Taglu contains nearly three trillion cubic feet of recoverable natural gas— enough to fuel all the gas-heated homes in Canada for three years.

The Taglu field is 120 kilometres northwest of Inuvik and 70 kilometres west of Tuktoyaktuk close to the Beaufort Sea. A single development site is proposed near the middle of the field, close to the confluence of the Kuluarpak and Harry channels (see Figure 4-8).

The reservoir reaches under Richards Island and, like the proposed Niglintgak field fifteen kilometres to the southwest, much of the reservoir stretches underneath Kendall Island

Bird Sanctuary, a key habitat site for local shore birds and waterfowl. The Taglu field is found within the same geological formation as the Niglintgak field—the Reindeer Sands, a formation that is known to be poorly consolidated.

Figure 4-8 Taglu production facilities

Figure 4-8 Taglu production facilities

Imperial Oil Resources Limited (Imperial) filed a Development Plan for the Taglu field under section 5.1 of the Canada Oil and Gas Operations Act. The proposed production facilities include:

  • up to 15 production wells drilled from a single pad;
  • one or two disposal wells;
  • a gas conditioning facility;
  • associated infrastructure including pads and foundations;
  • a barge landing site;
  • an airstrip and helicopter pad;
  • buildings; and
  • a water treatment system.

The well pad and the gas conditioning facility would be located adjacent to each other (see Figure 4-9).

Construction is planned to take place from 2014 to 2018 with operations commencing in 2018. The cost for developing the field is estimated to be $2,550 million with an estimated average operations and maintenance expenditure of $26 million per year for the period 2019 to 2023.

Imperial proposes to start constructing winter roads and moving equipment onto the site in 2014. Drilling would start in the winter of 2016/17 with production beginning

Figure 4-9 Taglu field map

Figure 4-9 Taglu field map

in the summer of 2018. An overview of the construction schedule is provided in Table 4-3.

Wells and well pads

Imperial plans to directionally drill 10 to 15 production wells and one or two disposal wells from a single well pad. Figure 4-9 shows the plan view of 11 potential locations of production wells and the preliminary locations of two disposal wells. This well pad would be located near the centre of the reservoir just inside the east boundary of Kendall Island Bird Sanctuary. Once production begins and additional reservoir data becomes available, Imperial may shift the current locations of its contingent wells to optimize production of the field. Imperial plans to build its well pad facilities on elevated pile foundations. Imperial’s depletion plan for the Taglu field shows that some wells would incorporate commingled production.

The well pad would be either gravel filled with a matted and fluid sealed surface or a steel deck supported by steel piles. Gravel for the well pad and other facilities will come from existing borrow sites at Yaya Lakes (see Figure 4-1).

Flow lines

The wellheads would be located beneath the surface of the well pad in a long cellar. This cellar would provide personnel with easy access to any well for drilling or servicing with a conventional rig and provides a heated space for the flow lines and other support systems.

Gas would travel above ground on a pipe rack via insulated and heat-traced flow lines to a manifold facility and on to the gas conditioning facility. The manifold facility would direct

the flow from each well to either a production line for processing or a line for testing.

Gas conditioning facility

Reservoir fluids would be processed at the gas conditioning facility to remove free water and natural gas liquids and to dehydrate and chill the gas to meet the specifications of the gathering pipeline. Although the gas would not need to be compressed initially, the facility would be designed so that it could do so if compression were needed. Natural gas liquids and gas volumes would be measured and transported to the gathering system and produced water would be injected about one kilometre below the surface into the disposal well.

Imperial would install a safety system in the gas conditioning facility for blowdown and pressure relief to lower the gas conditioning facility pressure and to direct hydrocarbon fluids

to the flare system in a safe and controlled manner, when required.

The average daily design capacity for the Taglu gas conditioning facility would be 12.6 Mm³/d (445 MMcf/d). The facility would be designed to handle a peak maximum design capacity of 14.5 Mm³/d (510 MMcf/d), about 15 percent above average daily rates, to accommodate scheduled maintenance and production downtime among the development fields.

Infrastructure

The following infrastructure would be provided to support construction, operations and maintenance activities and to access the site:

  • pads and foundations;
  • barge landing site;
  • airstrip and helicopter pad;
  • roads;
  • living quarters;

Table 4-3 Taglu construction highlights schedule

Table 4-3 Taglu construction highlights schedule
Activity Season
and year
Construct winter roads, gas conditioning facility pad, drilling pad and airstrip Winter 2014/15
Compact gravel pads and transport construction equipment, materials and fuel Summer 2015
Construct the dock and complete construction of gravel pads for gas conditioning facility, drilling pad and completions Winter 2015/16
Barge and install small gas conditioning facility modules Summer 2016
Begin drilling program Winter 2016/17
Barge and install large gas conditioning facility modules Summer 2017
Begin well completions Winter 2017/18
Startup operations and production Summer 2018
  • control room;
  • office and administration buildings;
  • domestic water system;
  • sewage treatment system;
  • storage; and
  • telecommunication facilities.

Barging

Currently, Imperial plans to enter the East Channel of the Mackenzie River through Kittigazuit Bay, where there is a historical shipping channel. Vessel movement through Kittigazuit Bay, which is part of the Kugmallit Bay 1A Beluga Management Zone, would be scheduled in August following prime beluga whale activity in the area. Preliminary engineering indicates dredging is not required in Kittigazuit Bay to successfully transport these modules (see Figure 4-1).

Third-party use and future expansion

The Taglu production facilities are designed to produce and process the Taglu volumes predicted for the Taglu field, however, the gas conditioning facility could accommodate or be expanded to accept additional production volumes. This would depend on the timing and volume of the additional gas, the gas properties, and acceptable commercial arrangements. The well pad may also be extended, but at this point, Imperial does not have a need to extend the well pad.

Views of the Board

We find Imperial’s general approach, conceptual design and plan proposed for the Taglu field to be satisfactory. We note that new geological and reservoir data acquired during drilling and production will be used by Imperial to determine if additional faulting and compartmentalization exists and whether any contingent wells would be required. Condition T17 requires that Imperial file an updated resource management plan with the National Energy Board within 18 months after production commences or prior to the drilling of contingent wells.

Condition T18 requires Imperial to comply with the 2009 Draft Spacing Requirements in order to protect the correlative rights of any adjacent subsurface rights holders. Imperial’s preliminary production well locations for the Taglu field comply with the 2009 Draft Spacing Requirements.

We are of the view that Imperial’s conceptual plan whereby some wells would utilize commingled production to achieve maximum gas recovery is acceptable. Commingled production is production of oil and gas from more than one pool or zone through a common well-bore without separate measurement of the production from each pool or zone. The National Energy Board will consider commingled production on an individual well basis during drilling and production operations in accordance with section 66 of the Canada Oil and Gas Drilling and Production Regulations.

Condition T30 stipulates that the approval of the Development Plan for the Taglu Field under subsection 5.1(4) of the Canada Oil and Gas Operations Act is subject to the Minister of Indian Affairs and Northern Development Canada providing confirmation that Imperial has satisfactorily met the Benefits Plan requirements of section 5.2 of the Canada Oil and Gas Operations Act.

4.3.2 Development plan issues

During the hearing, Imperial discussed the following issues associated with developing the Taglu field:

  • design issues related to permafrost, subsidence, flood protection and climate change;
  • air quality issues and greenhouse gas emissions;
  • activity and facility noise levels and environmental footprint in Kendall Island Bird Sanctuary; and
  • management of spoil from dredging operations.

The design of the development field facilities is linked to the physical environment. The Taglu field is located in an active delta floodplain, with permafrost under parts of the proposed development. Facility locations are periodically flooded and the effects of flooding are a safety and facility design priority.

Permafrost and design issues

The Taglu field is located within a zone of intermediate discontinuous permafrost. As with the Niglintgak field, if the permafrost thaws, the landscape may be permanently altered. Imperial has proposed using a number of different types of design techniques to prevent the permafrost from thawing beneath its production facilities. One of these methods would be to separate each well by 18 metres. This interwell spacing

is similar to the 15 metres Shell has adopted for its wells in Niglintgak. As previously mentioned, wellheads and flow lines would be located in a heated “cellar” below the well pad. To preserve the permafrost, Imperial plans to include an active refrigeration system with the wellbore conductor in their wellsite facility. This system keeps the permafrost from melting by chilling the ground below the wellsite, to about 37 metres deep, during drilling and production. Well pad facilities and flow lines would be constructed on elevated pile foundations to prevent permafrost damage and to avoid seasonal floods during operations.

Views of the Board

We are satisfied with Imperial’s approach to addressing permafrost integrity with respect to the Taglu development. We note that all Taglu wells would be located on one well pad and that warm fluids would flow through those wellbores during drilling and production. Condition T2 requires the interwell spacing on the well pad to be no less than 15 metres unless Imperial utilizes mitigation measures approved by the National Energy Board. It is important for safety and environmental protection reasons that the permafrost thaw bulbs around wellbores do not coalesce.

Subsidence

The Taglu reservoir is within the same geological formation as the Niglintgak reservoir, the Reindeer Sands Formation. This formation of poorly consolidated sands from the Early Tertiary Period is nearly 60 million years old. As with Niglintgak, these sands could crumble and partially collapse, or subside, as gas is withdrawn from the field.

Imperial estimates the maximum amount of subsidence resulting from gas extraction would range from 0.20 to 0.42 metres. The deepest subsidence would be a low drainage area to the north of the proposed Taglu gas conditioning facility towards Big Lake. Imperial indicated that the predicted subsidence would not materially change the drainage patterns within the affected area and no “subsidence dish” would be formed.

Subsidence may also occur if the permafrost thaws as a result of climate change. This effect was estimated by Imperial to be much smaller, by an order of magnitude, compared to extraction-induced subsidence described above.

Imperial is considering using a three-dimensional global positioning system survey method to monitor and measure accumulated ground subsidence on the Taglu facilities. Details of such a program are still being assessed by Imperial.

Joint Review Panel Report recommendation 6-10 asked us to require Imperial to file with the National Energy Board a program to monitor subsidence and flooding due to hydrocarbon extraction for the Taglu field. In a letter dated 28 January 2010 responding to the Joint Review Panel Report recommendations the Proponents submitted to us that recommendation 6-10 be rejected as our proposed Condition 7 (dated 5 February 2007) for the Taglu field was sufficient. In the Proponents’ view, it was unlikely to be technically feasible to monitor flooding due to hydrocarbon extraction since it would be very difficult to differentiate flooding due to hydrocarbon extraction from natural flooding. The Proponents said that flooding at Taglu is a natural and annual occurrence.

In argument, Environment Canada suggested the following revisions to the condition:

  • clarify and enhance consultation;
  • include the monitoring of flooding due to subsidence in order to determine the loss of nesting habitat;
  • include monitoring of reservoir compaction in order to differentiate project-induced subsidence from natural changes in ground elevation; and
  • allow the use of the most appropriate technology at the time including airborne and remote sensing techniques.

Views of the Board

We are of the view that it will be important to monitor and confirm Imperial’s estimates of subsidence due to hydrocarbon extraction because the Taglu field is located inside Kendall Island Bird Sanctuary and is one of the first proposed developments in the Mackenzie Delta where subsidence due to gas extraction is predicted to occur. Condition T3 requires Imperial to submit a program to measure and monitor accumulated subsidence and to monitor flooding for the life of the field.

Environment Canada indicated monitoring of reservoir compaction was needed to differentiate project-induced subsidence from natural changes in ground elevation. Condition T3 requires that elevation benchmarks be located outside of the projected gas-extraction-subsidence-area. We believe that these elevation benchmarks will act as control or reference points to provide data to estimate natural subsidence. We are not persuaded that monitoring of reservoir compaction is necessary.

We agree with Environment Canada that the condition should allow for the use of the most appropriate technology at the time. Condition T3 has been amended to reflect this.

We agree with Environment Canada's suggestion to clarify and enhance consultation and Condition T3 has been revised in this regard.

Climate change and flood protection The Taglu reservoir is found under low lying terrain with a mean elevation of 1.5 to 1.7 metres above sea level. Imperial expects the site to be periodically flooded during spring runoff and later in the season by storm surges from the nearby Beaufort Sea. As a result, Imperial considered the following factors in the design height of the Taglu pad:

  • maximum flood level;
  • maximum wave height;
  • rise in sea level; and
  • surface effect of gas extraction induced subsidence on flood depth.

These factors and a safety margin of 0.2 metres were used by Imperial to design a well pad and facility foundation height of 3.1 metres (see Figure 4-10).

Imperial plans to monitor the facilities and implement adaptive management and contingency plans as needed. If Imperial's design height is too low, it is possible to accommodate higher water levels by adding earthen fill material to certain areas of the site to protect them from flooding. In addition, select pile-mounted facilities, such as modules and flow lines, could be raised if flooding becomes a problem. Furthermore, protective measures, such as bumper posts or strengthened pipe supports could be used to protect those parts of the Taglu facility that would be at risk from ice floes.

Although there would be a risk that flood levels during the 30 year operating life of the Taglu field could exceed the design height, Imperial considers this risk to be relatively low. However, if water levels reach an extreme height, it would be possible to shut down production. Onsite activity could cease and some or all personnel would be removed from the site.

Warming of the global and regional climate could raise sea levels and affect weather patterns. The Taglu field is located in the low-lying Mackenzie Delta near the Beaufort Sea. We heard concerns that seasonal flooding and storm surges could affect the facilities during the life of the project. The Taglu airstrip could also be subject to flooding, but in that event workers and equipment would be brought to the site by helicopter. The companies provided evidence that the facilities would be high enough to protect them from storm surges and flooding even if sea levels were to rise.

As with the Niglintgak field, the Sierra Club of Canada was concerned about the lack

of peer-reviewed research publications on the effects of climate change, specifically for the Mackenzie Delta over the 30 year life span that was used by Imperial in the design of the Taglu field facilities. The Sierra Club of Canada stated that in designing infrastructure in the Mackenzie Delta there is uncertainty as to the effects of climate change, including the effects on the permafrost, the rise in sea level and the degree of flooding.

The Joint Review Panel was generally satisfied that Imperial had taken climate change into account in its design. Nevertheless the Joint Review Panel recommended that the National Energy Board add a condition to the certificate which would require Imperial to file final design plans that incorporate further analysis of the impacts of climate change on permafrost and terrain stability over the design life of the project and post-abandonment. The Joint Review Panel was of the view that this analysis should be conducted for a series of representative locations, conditions and terrain types and

Figure 4-10 Design height for top of Taglu well pad and facility foundations

Figure 4-10 Design height for top of Taglu well pad and facility foundations

should incorporate climate variability, in particular, upper limit temperature scenarios to account for the range of future temperature conditions, including variability and extremes, and the impact of this variability on stream flow regimes. The Joint Review Panel added that the results should be incorporated into monitoring, mitigation and adaptive management plans. The Joint Review Panel thought that further design analysis should be provided to other appropriate regulators in sufficient time for review and to provide input to the National Energy Board.

The Taglu field would produce natural gas from relatively shallow underground formations. As the natural gas is removed, the ground could settle by up to almost half a metre due to the removal of natural gas. This possibility was taken into account in the design of the facilities. Imperial also indicates that climate change is implicit in the way it completed its modeling for the facility and pipeline design specifically; that is, trends in climate warming regionally have been incorporated into the modeling.

Indian and Northern Affairs Canada suggested in final argument that the Proponents should demonstrate how upper limit temperature scenarios have been considered in their design.

Further specific discussion on climate change regarding project design is found in Chapter 6.

Views of the Board

We are satisfied with Imperial's climate change rates used in the design. Given the uncertainty regarding climate change predictions and the vintage of any climate change studies or data used by Imperial, a prudent step would be to assess the design using upper limit temperature scenarios as suggested by the Joint Review Panel. As the name implies, upper limit temperature scenarios would be less likely to occur than what has been used by Imperial for the design of the project.

Condition T7 requires Imperial to provide final detailed design information that incorporates an analysis fo the impacts of climate change and variability on permafrost and terrain stability for the Taglu facility using potential upper limit temperature scenarios which may occur during the operational life of the facilities. Imperial will also provide information about how upper limit temperature scenarios may impact precipitation, rise in sea level, storm surges, ice floes and flood levels. We are of the view that government departments such as Environment Canada, Indian and Northern Affairs Canada and Natural Resources Canada should be consulted to benefit from their expertise for the field design.

Air quality issues

Air quality in the North is considered to be of high quality and Northerners are very concerned that it remains that way. Both Environment Canada and the Proponents agreed that existing air quality in the proposed project area is good and, along with other government regulators, emphasized the need to “keep clean areas clean.” This principle requires new industrial development to be “planned, constructed and operated in a manner that minimizes the degradation of air quality in these areas.”

Air quality issues for the project included project emissions for the pipeline and development fields, monitoring, and greenhouse gases in the context of monitoring climate change. The Joint Review Panel noted that the National Energy Board would be the prime regulator of air emissions from the project and that Environment Canada and the Government of the Northwest Territories would play advisory roles. The Joint Review Panel recognized the National Energy Board's expertise and experience in regulating interprovincial aspects of the oil, gas and electric utility industries, including environmental matters. The Joint Review Panel also recognized the extensive environmental and local knowledge that Environment Canada and the Government of the Northwest Territories can provide.

Air emissions can be related to the project-specific effects of construction, operations, and waste incineration. Air quality impacts

can be local to regional in the case of particulate matter and sulphur dioxide, or global in the case of greenhouse gases. Emissions would occur during the construction phase through intermittent flaring during well testing at the Taglu field. maximum flood level;

Further specific details pertaining to emissions for the pipeline are discussed in Chapter 3 and discussion on air emissions pertaining to facility design is found in Chapter 6.

The Joint Review Panel report indicated that the Proponents' baseline information was compiled from historical data and results of air quality monitoring that was carried out over one year near the communities of Inuvik and Norman Wells, and periodically at the Parsons Lake and Taglu gas fields. The Proponents' monitoring data and other sources indicated that background concentrations of air contaminants are generally below detection levels or applicable guidelines. The one exception that is not below detection levels is ozone; relatively high background levels were monitored in Inuvik and Norman Wells. The Proponents indicated that elevated ozone levels at high latitudes in the northern hemisphere are thought to result from the intrusion of stratospheric ozone. The Proponents stated that all ground-level concentrations of compounds released by the project during operations at the gas fields, the Inuvik Area Facility, and compressor and heater station sites would increase, but would be below those outlined in applicable federal and territorial

guidelines at all locations in the production area and along the pipeline corridor.

Environment Canada recommended that the Proponents design and implement suitable air quality monitoring programs with its help. Environment Canada focused its recommendations on pollution prevention and the use of best available technology and best management practices to minimize the degradation of air quality. Further discussion around application of these principles may be found in Chapter 6.

The Dehcho Elders and Harvesters indicated that the project needs to be designed to minimize air quality impacts, with monitoring plans in place to verify the predicted emissions and impacts. Corrective action needs to be taken quickly to avoid impacts upon the land and wildlife from degraded air quality.

Greenhouse gas emissions

Parties were concerned about the impacts of the project on climate change, especially in light of Canada's international efforts under the United Nations Framework Convention on Climate Change and the Kyoto Protocol.

Greenhouse gas emissions arising from the project include carbon dioxide, methane and nitrous oxides with each compound having a different climate change potential. During operation, the project would emit greenhouse gases from burning natural gas at combustion related sources such as compressors and methane gas released

through normal venting procedures and minor leaks (fugitive emissions). Further specific discussion on air emissions pertaining to facility design is found in Chapter 6.

Alternatives North submitted that the National Energy Board and the Government of Canada have a public interest mandate that requires consideration of greenhouse gas emissions.

Ecology North deemed that high project-specific standards for greenhouse gas emissions based on a robust and strong definition of best available technology and accompanied by penalties in the cases where they do not meet those project standards or targets, would provide the best possible protection in terms of minimizing upstream greenhouse gas emissions associated with the project.

Sierra Club of Canada submitted that we need to specify an actual target and it is not enough to just leave it up to the Proponents. Sierra Club of Canada indicated that the target should at least match the general recommended target in Joint Review Panel recommendation 8-8.

Views of the Board

We understand the importance of clean air in the North and that air quality must be considered in a cumulative manner. We also recognize the need to minimize greenhouse gas emissions resulting from the project. The Joint Review Panel directed several recommendations to us relating to air quality and air emissions. We have

addressed air issues through several conditions for the Mackenzie Gas Project. These conditions are focused on the Proponents taking appropriate measures to minimize air emissions and address air quality. We are committed to working collaboratively with Environment Canada and the Government of the Northwest Territories to protect air quality in the North, recognizing the extensive environmental and local knowledge that these agencies can provide.

Conditions T13 and T15 address technologies for reducing emissions, incorporation of best management practices and best available technologies, and facility design. Condition T14 requires the submission of a report evaluating incinerator emissions from camps and station facilities and technologies and practices must be reflected in the waste management plans required by Condition T11. Condition T16 requires Imperial to minimize and reduce emissions from flaring. Further specific discussion for these conditions regarding air emissions pertaining to facility design is found in Chapter 6.

Air quality monitoring is part of comprehensive environmental monitoring under an environmental management system. Through environmental management, systems are established to address effects of the project on

the environment and of the environment on the project, with the overall goal of minimizing negative impacts. Adaptive management is a systematic process for continually improving management practices by learning from their outcomes. Environmental monitoring is an important part of environmental management that directly supports adaptive management by observing and evaluating the effects that occur, then changing or adding mitigative measures as appropriate to limit or reverse the environmental effects. Environmental monitoring can include:

  • compliance monitoring, to verify that all environmental mitigation is implemented as presented in the Environmental Protection Plan and environmental alignment sheets and that work is in compliance with environmental regulations; and
  • effects monitoring, to assess the effects resulting from project-environment interactions and evaluate the effectiveness of approved mitigation measures. This is further discussed in section 3.3.6.

Imperial is expected to implement Environmental Protection and Monitoring and Surveillance Programs which include protection of the environment as one of the main goals. A monitoring program may:

  • identify any issues or potential concerns that may compromise the protection of the environment;
  • include methods for developing measures to prevent or mitigate the impact of the identified issues;
  • provide for continued monitoring of sites to evaluate success of mitigative measures undertaken;
  • provide a system for implementing additional mitigative measures as necessary; and
  • provide a feedback system that allows for adaptation of successful mitigation to future pipeline projects.

Monitoring programs may have specific goals and targets and could include methods for evaluating and interpreting collected data such as air quality or emissions data. Monitoring may include any relevant environmental practices (e.g., vegetation establishment, water quality sampling, waste disposal). Responsibilities of the National Energy Board regarding monitoring include:

  • conducting environmental inspections of facilities, verifying compliance with terms and conditions, and assessing the effectiveness of mitigation;
  • monitoring ongoing operation, verifying reclamation and maintenance of the project site to acceptable standards; and
  • conducting environmental audits, evaluating environmental management systems and environmental programs.

We generally require the filing of environmental post-construction monitoring reports as a condition of an authorization. The information in monitoring reports should include:

  • confirmation of proper implementation of mitigation and reclamation measures used;
  • identification of the outstanding environmental issues; and
  • discussion of the company's plans for how outstanding issues will be resolved.

Condition T10 requires Imperial to submit an Environmental Protection Plan which includes monitoring of activities. Condition T14 includes the requirement for monitoring incinerator emissions.

A commitment to continuous improvement, outlined in Joint Review Panel recommendation in 8-6, is expected to be a component of an operator's Management system pursuant to paragraph 5(2)(b) of the Canada Oil and Gas Drilling and Production Regulations. This is addressed in Condition T10. We are of the view that the commitment to continuous improvement is not limited to greenhouse gas emissions but should apply to all discharges to the environment, which in this case is the atmosphere. Condition T10 also covers the requirements for methods and locations of monitoring.

Condition T15 requires the Proponents to file a report outlining the use of best available technology for station facility construction. Selection of best available technology is the most significant factor in determining achievable air emissions targets. Condition T10 outlines the requirements for an Environmental Protection Plan. The condition requires the Proponents to submit maximum proposed greenhouse gas targets and reduction strategies for air emissions including particulate matter, NOx and greenhouse gases. Condition T10 also addresses other matters from the Joint Review Panel recommendations including employee training, monitoring, public communication, and required consultation with Environment Canada and the Government of the Northwest Territories. With these conditions, we find it acceptable for the Proponents to develop greenhouse gas targets for the project consistent with use of best management practices and in consultation with appropriate government agencies.

Environmental footprint in Kendall Island Bird Sanctuary

The proposed site of the Taglu development is located near the meeting of the Kuluarpak and Harry channels of the Mackenzie River, and it lies within Kendall Island Bird Sanctuary. As discussed previously, Environment Canada has regulatory authority over the surface of the Sanctuary and has determined that the maximum allowable surface disturbance related to all oil and gas activities within Kendall Island Bird Sanctuary should be no more than one percent of the Sanctuary or 600 hectares. Environment Canada expressed concern with not only the size of the area being disturbed but also with Imperial’s plan for continuous drilling and year-round activity. The estimated total area of surface disturbance is approximately 30 hectares, representing 0.05 percent of all of Kendall Island Bird Sanctuary. All production wells would be drilled from the same well pad using directional drilling techniques. This helps to reduce the overall footprint of the development. The well pad is likely to be located just inside the eastern boundary of Kendall Island Bird Sanctuary, just west of the existing D-43 well site (see Figure 4-9). The initial drilling program would occur uninterrupted for about 16 months, with well completions to follow. Imperial is proposing a development plan which is flexible enough to accommodate contingencies that could arise during detailed design, construction and operation of the Taglu field.

The Imperial project management team will continue to look for opportunities to further reduce the footprint of the Taglu development in Kendall Island Bird Sanctuary. For example, Imperial will look at the use of existing disturbed space adjacent to the development site, being the D-43 well site pad and connecting road. The project's engineering team is also investigating the merits of using a wet gas metering system instead of the test separator system in an effort to reduce footprint. The project will also consider tankage requirements for fuel needs, as there may be opportunities for offsite staging, as well as the fabrication and construction of the gas conditioning facilities modules. Imperial hopes that by implementing options such as these, the Taglu footprint could be reduced by approximately 10 percent of the current footprint estimate.

Activity and facility noise levels

The Taglu anchor field is located in Kendall Island Bird Sanctuary which is a federally protected area managed for the conservation of migratory birds and protection of habitat for northern-breeding birds. Imperial holds Significant Discovery Licence SDL063 that grants it subsurface oil and gas rights. Environment Canada has regulatory authority for activities within Kendall Island Bird Sanctuary, and may issue permit conditions governing noise emissions from development under the Migratory Bird Sanctuary Regulations. Environment Canada and Imperial have both agreed to follow Alberta's Energy Resources Conservation Board Directive 038 for noise

regulation. This provides a solid basis for noise regulation that currently does not exist in the Northwest Territories, in other words, there is currently no legislation or standard in the Northwest Territories governing noise emissions.

Alberta's Energy Resources Conservation Board Directive 038 indicates a recommended noise target for remote areas even if no human residences are present. This is considered the “business as usual” requirement. The Directive has provisions to change the typical target when there are unique circumstances, including if an area is “pristine”—a pure, natural area that might have dwellings but no industrial presence. Environment Canada is recommending continuous noise emissions, as measured from the fence line of the facility, not exceed the Alberta's Energy Resources Conservation Board Directive 038 “best practices” permissible sound levels during the period from 10 May to 30 September when migratory birds are present in the Sanctuary because Kendall Island Bird Sanctuary is considered a pristine area.

Imperial intends to design all equipment at the Taglu gas conditioning facility so that the resulting sound levels would be below the maximum permissible noise levels provided in Alberta's Energy Resources Conservation Board Directive 038. This would include primary sources of noise generation such compressors, power generation equipment and aerial coolers. Environment Canada has also indicated that Imperial has committed to evaluating and applying noise mitigation options beyond

those required to meet Alberta's Energy Resources Conservation Board Directive 38 minimum standards provided that such options are practical. Environment Canada is awaiting detailed engineering and noise modeling results from Imperial.

Environment Canada has concerns with the level of noise associated with Imperial's Taglu well drilling operations while birds are present. Unlike Niglintgak, Imperial plans to drill in Taglu for 16 months starting in the winter of 2016 followed by year-round oil and gas activities. However, May to October is the time when birds are typically present in Kendall Island Bird Sanctuary and therefore sensitive to disturbance. As a result, Environment Canada may restrict activity or access within Kendall Island Bird Sanctuary during this period to protect bird habitat.

Imperial indicated that this would not meet its need to service and access personnel year-round for drilling, construction and operational activity. On a related matter, Imperial stated it would consider scheduling planned maintenance flaring outside the migratory birds nesting season.

When we asked how operations would be affected if drilling was restricted from May to October, Imperial indicated it would have to reassess the entire design and execution plan associated with the development. Environment Canada is continuing to have discussions with Imperial on this matter.

Imperial indicated it is committed to adhering, at a minimum, to Alberta's Energy Resources Conservation Board Directive 038. Imperial recognized that operating facilities in Kendall Island Bird Sanctuary requires additional consideration, and Imperial is committed to continuing evaluations of noise mitigation options through detailed engineering and planning, in order to arrive at practical solutions to address concerns raised by Environment Canada. As indicated in previous submissions, Imperial is committed to working with Environment Canada in reducing noise levels of production facilities in Kendall Island Bird Sanctuary, and Imperial will endeavour to reduce noise emissions beyond the requirements of Directive 038 where technically and economically possible.

In final argument both the Proponents and Environment Canada shared the view that requirements for noise regulation in Kendall Island Bird Sanctuary, both for the National Energy Board and migratory bird sanctuary requirements, can only be finalized after detailed engineering and design work is completed, after the noise impact analysis is prepared, and after discussions between the parties. Environment Canada will continue to work with the National Energy Board, Proponents and other regulators on issues related to noise in Kendall Island Bird Sanctuary. Imperial indicated during final argument it is committed to adhering to requirements in Alberta's Energy Resources Conservation Board Directive 038, as well as continuing evaluation of noise mitigation

through detailed engineering and planning in order to arrive at practical solutions to concerns raised by Environment Canada.

Views of the Board

We agree with Environment Canada that regulating impacts of noise in a nationally protected bird sanctuary requires special consideration and application of best practices and the use of best available technology with the intent of “continuous improvement of pipeline safety and environmental protection.” Condition T8 applies to regulating noise in the Taglu field and is intended to minimize disturbance from facilities inside Kendall Island Bird Sanctuary. The condition requires meeting the Alberta's Energy Resources Conservation Board Directive 038 “business as usual” standard with allowance for achieving the more stringent standard that Environment Canada recommended to the Joint Review Panel, and the Joint Review Panel accepted. There is flexibility built in to adjust the standard as informed by final engineering, an independently verified noise impact analysis document, and final determination of the fence line, which is the measurement base for a distance-based regulatory standard.

We acknowledge the parallel permitting process for Kendall Island Bird Sanctuary and support the need for consistency and clarity between Environment Canada and National Energy Board conditions.

Overall footprint
Many of the proposed facilities for the Taglu field, such as the well pad, gas conditioning facility, flow lines and air strip would be located inside the east boundary of Kendall Island Bird Sanctuary. The total area of permanent surface disturbance would be approximately 30 hectares.

During the project design phase, Imperial incorporated measures to reduce the overall footprint for the proposed Taglu development by:

  • locating a single well pad near the centre of the reservoir and using directional drilling techniques to drill all of the proposed wells from one common well pad. This pad would be approximately 70 metres wide by 300 metres in length with 15 metres of road access on both sides and would cause 100 metres of disturbance;
  • locating the gas conditioning facility adjacent to the well pad to eliminate the need for a network of connecting roads;
  • accessing the site with river barges in the summer and by winter road without adding a substantial number of additional access roads through Kendall Island Bird Sanctuary;
  • locating the well pad and gas conditioning facility on already disturbed land;
  • using storage areas outside of Kendall Island Bird Sanctuary for some tankage requirements; and
  • using staging areas outside of Kendall Island Bird Sanctuary, such as Tununuk Point (Bar C) for drilling materials. Tununuk Point is a previously disturbed lease area located approximately 50 kilometres south of the proposed Taglu site (see Figure 4-1).

Imperial intends to build its facilities offsite, in large modules, and ship them to Taglu for assembly. Based on consultations with area stakeholders, Imperial has identified an opportunity to increase the size of offsite fabricated modules, if the modules can be successfully transported and installed at the site. Based on the construction execution plan descriptions, the concept would reduce:

  • the footprint at Taglu within Kendall Island Bird Sanctuary;
  • some air traffic support at the site within Kendall Island Bird Sanctuary; and
  • barge traffic on the Mackenzie River.

Imperial also indicated that it considered building a barge-based gas conditioning facility, like the one planned for the Niglintgak field; however, this did not reduce the overall footprint.

The proposed location of the Taglu airstrip within Kendall Island Bird Sanctuary was a concern for Environment Canada, as it will occupy approximately seven or eight hectares.

Drilling waste in Taglu can be separated into solids (drill cuttings) and liquids (reserve pit fluids). Typically, these wastes are disposed of in a sump. However, sumps are not permitted in Kendall Island Bird Sanctuary.

Imperial plans to initially inject both solids and liquids into a dedicated disposal well and then, as drilling progresses, into the annuli of a previously drilled production well

(see Figure 4-11). With this approach, Imperial would use the dedicated disposal well as a backup if there are any issues with the production well annuli. In addition, Imperial would have a temporary onsite storage area for drill cuttings in case of any equipment or disposal problems with either the production well annuli or the dedicated disposal well.

The solids, or drill cuttings, represent about 20 percent of the total volume to be disposed of in the wells. Before the solids can be injected into a well, they would be mixed with water to create a slurry. Injection of the cuttings is planned as discrete “batch injection operations” for limited volume and discretely scheduled drilling programs. During injection operations, injection pressure and fluid properties would be monitored to verify that the reservoir is behaving as predicted and unexpected fractures are not occurring. Subsurface slurry injection of the scale and extent proposed by Imperial has not been practiced before in the Northwest Territories.

Imperial's alternative method for the disposal of drill cuttings would be to inject the reserve pit fluids into the well annuli and incinerate the drill cuttings. The residual material from incineration would be hauled to an approved disposal facility.

The Joint Review Panel was generally satisfied that Imperial had taken climate change into account in its design. Nevertheless the Joint Review Panel recommended that the National Energy Board add a condition to the certificate which would require Imperial to file final design plans that incorporate further analysis of the impacts of climate change on permafrost and terrain stability over the design life of the project and post-abandonment. The Joint Review Panel was of the view that this analysis should be conducted for a series of representative locations, conditions and terrain types and

Insofar as air traffic operations are concerned, as the Joint Review Panel noted:

Environment Canada and the Proponents assessed alternative means of accessing the Taglu site and agreed that the proposed Taglu airstrip would pose the least adverse effects.

The Joint Review Panel similarly agreed that the proposed airstrip was the best option. Imperial will continue to consult with Environment Canada in relation to the details of its proposed air operations at Taglu.

Dredging activities will occur within Kendall Island Bird Sanctuary and Environment Canada will not permit the spoil to be placed on

Figure 4-11 Drilling waste disposal

Figure 4-11 Drilling waste disposal

undisturbed terrestrial habitat within Kendall Island Bird Sanctuary. Environment Canada requested that we require that Imperial's plan for dredging the barge landing at the Taglu field should describe the potential impacts associated with dredging, including spoil management and the site-specific mitigation measures proposed to address adverse impacts. As discussed earlier, this is a condition that should also refer to the success of the consultations between the Proponents and Environment Canada.

Views of the Board

We accept Imperial's conceptual plan to dispose drill cuttings by subsurface slurry injection as this avoids the use of sumps and would minimize the environmental footprint within Kendall Island Bird Sanctuary. However, as down-hole slurry injection of this scale and extent has not been utilized in the Mackenzie Delta before, Condition T4 requires Imperial to submit a drill cuttings slurry injection management program. The National Energy Board would assess such a program with respect to subsurface containment as well as safety, protection of the environment and conservation of resources.

We have considered the various comments regarding Condition T9 for dredging and the condition has been amended to require a dredging spoil management plan and to clarify requirements for consultation with Environment Canada, Department of Fisheries and Oceans, Indian and Northern Affairs Canada and Transport Canada.

4.4 Parsons Lake

The Parsons Lake field borders the Mackenzie Delta to the east and is located 70 kilometres north of Inuvik and 55 kilometres southwest of Tuktoyaktuk on the Tuktoyaktuk Peninsula. Unlike the neighbouring Niglintgak and Taglu fields to the northwest, the Parsons Lake field is not located within the Mackenzie Delta or Kendall Island Bird Sanctuary.

ConocoPhillips Canada (North) Limited (ConocoPhillips) has requested approval of a Development Plan application for the Parsons Lake field pursuant to section 5.1 of the Canada Oil and Gas Operations Act. ConocoPhillips and ExxonMobil Canada Properties (ExxonMobil) propose to develop natural gas and natural gas liquids from Parsons Lake and ship these hydrocarbons with those from the Taglu and Niglintgak fields via the Mackenzie Gathering System to the Inuvik Area Facility.

The capital expenditures for development of the Parsons Lake field are estimated to be $1,550 million with an estimated average operations and maintenance expenditure of $25 million per year for the period 2019 to 2023.

The Parson's Lake development (see Figure 4-12) would include:

  • construction of a north pad with nine to nineteen production wells, two disposal wells, and a gas conditioning facility;

Figure 4-12 Parsons Lake production facilities

Figure 4-12 Parsons Lake production facilities
  • a south pad with three to seven production wells;
  • construction and operation of flow lines from the south pad to the north pad; and
  • supporting infrastructure, including an all-weather airstrip.

Construction is planned to take place from 2014 to 2018 with production operations commencing in 2018 and expected to continue for 25 or 30 years.

4.4.1 Design of the Parsons Lake facilities

ConocoPhillips estimates 28 hectares would be required for the development, including the north and south well pads, the airstrip, and a 2.5 kilometre long all-weather road connecting the airstrip to the main road.

Wells and well pads

Proposed phase one development would include constructing well site facilities at the north and south pads and up to three contingent satellite well pads. The north pad would initially house up to nine production wells, one waste disposal well and one cuttings injection well, with the possibility of up to ten contingent production wells. Dredging activities will occur within Kendall Island Bird Sanctuary and Environment Canada will not permit the spoil to be placed on

Phase two, preliminary plans for 2024, includes drilling three production wells and as many as four contingent production wells from the south pad.

ConocoPhillips believes that it may not be able to reach parts of the Parsons Lake field by drilling only from the north or south pads.

Table 4-4 Parsons Lake construction highlights schedule

Table 4-4 Parsons Lake construction highlights schedule
Activity Season and year
Transport and stage construction equipment to delta staging location Summer 2014
Begin construction of winter access road, begin development of borrow sites, transport material to the north pad, all-weather access road and airstrip Winter 2014/15
Construct and complete commissioning of airstrip Summer 2016
Construct winter access road for heavy module transport, transport very large modules and begin installing very large modules as part of the gas conditioning facility Winter 2016/17
Commence drilling program at north pad Winter 2016/17
Complete north pad drilling and testing program Winter 2018/19
Start up the gas conditioning facility Winter 2018
South pad drilling program, construction of the flow line from the south pad to the north pad Beyond 2019

Therefore, ConocoPhillips has identified three possible sites for contingent satellite well pads, each accommodating up to three wells. ConocoPhillips would develop the contingent wells if drilling and production operations identify and locate faults that compartmentalize the reservoir. Views of the Board

ConocoPhillips' Development Plan provides preliminary bottomhole locations for nine production wells, two contingent wells, one cuttings injection well and one waste disposal well located on the north pad and for three production wells and one contingent well from the south pad (see Figure 4-13). All would be directionally drilled except for the cuttings injection well which would likely be a vertical well. The preliminary total vertical and measured depth of these wells range from 1000 to 3150 metres and from 1000 to 4734 metres, respectively. ConocoPhillips also provided a commingled production strategy for Parsons Lake in order to effectively and economically deplete reservoir compartments.

The north pad would be built on granular material about 1.5 metres thick. The south pad and contingent satellite wells pads would be built on ice pads and with only a small area of granular material around the wellhead. All well pads would include individual wellbores, wellheads and wellhouses. Thermosiphons would be installed to maintain the permafrost below the pads.

Flow lines

Once the natural gas and natural gas liquids have been extracted, they would flow through above-ground flow lines from the wells to the gas conditioning facility on the north pad. The 16 kilometre long flow line from the south pad would rest on piled metal supports at least 2.2 metres above the ground, and run parallel to the Parsons Lake lateral of the Mackenzie Gathering System. Hydrocarbons from the south pad would be metered and heated before traveling to the north pad. The flow lines would be insulated to keep temperatures inside the flow lines between 30°C and 50°C. This would help prevent the natural gas, natural gas liquids and any produced water from freezing and plugging the lines.

Production from any satellite well pads would be transported in insulated above-ground flow lines to the north pad and the gas conditioning facility.

Gas conditioning facility

The gas conditioning facility would be able to handle a maximum volume of 9.0 Mm³/d (324 MMcf/d). It would process the reservoir fluids to meet the specifications of the gathering system and would include components to:

  • separate gas from free water and hydrocarbon liquids (natural gas liquids);
  • compress and dehydrate the gas;
  • chill and meter the hydrocarbons before they enter the gathering system; and
  • collect any water and send it to a disposal well.

The gas dehydration unit is designed to reduce the moisture content of the sales gas to 6 mg/m³ and to neutralize any potential for corrosion caused by the carbon dioxide in the gas stream. ConocoPhillips' design also incorporates a relief and blowdown system, including flare stacks, to handle any emergency relief and flaring at the north and south pads. Equipment to compress the gas so it would flow

through the gathering system would be added in stages as the wellhead pressure declines. Project facilities would be built from very large modules constructed offsite, shipped by barge to Tuktoyaktuk, and transported via winter road to Parsons Lake. Once the modules were onsite, they would be placed on steel piles and elevated about one to two metres above the gravel

Figure 4-13 Parsons Lake field map

Figure 4-13	Parsons Lake field map

surface. Buildings installed on the gravel pad would have insulated foundations, and thermosiphons. Views of the Board

Alternative production system

ConocoPhillips considered a number of alternative configurations for production such as locating the main gas conditioning facility at the south pad, housing only a minimal satellite facility on the north pad and using a flow line to transport gas from the north pad to the south pad. However, this alternative would require a larger flow line than the current proposal and would be costlier.

Another alternative configuration evaluated by ConocoPhillips was to construct gas conditioning facilities at both north and south pads. This would be costlier and the north pad gas conditioning facility would not be fully utilized.

Because the Parsons Lake north pool contains about three percent carbon dioxide and the south pool about five percent carbon dioxide, ConocoPhillips evaluated whether removal facilities for carbon dioxide would be required. Four different options for removing carbon dioxide were studied, and costs for these options ranged from $80 to $100 million. Rather than design the Parsons Lake facilities to extract the carbon dioxide, ConocoPhillips chose to rely on blending the gas from Parsons Lake with gas from Niglintgak and Taglu that

would have lower concentrations of carbon dioxide. Blending would allow ConocoPhillips to meet the Inuvik Area Facility's carbon dioxide content specification.

Winter transportation

ConocoPhillips plans to move the seven pre-assembled gas conditioning facility very large modules from Tuktoyaktuk to Parsons Lake on a purpose-built heavy load ice road the winter before commercial gas production begins. The proposed ice road would be specially prepared with a smooth ice surface and designed to accommodate the heavy-lift trailers carrying the oversized and heavy gas conditioning facility modules. Because of the load's size and weight, the road would need to about 20 metres wide with a 50 metre right of way, have a three percent gradient, contain no tight curves and avoid frozen bodies of water. The wide ice road would be completed late in the season and likely used for six to eight weeks. However, a shortened winter season would mean significant delays to the construction of the gas conditioning facility if the ice road could not be used to transport all seven modules.

Furthermore, ConocoPhillips is proposing to drill the south pool and satellite wells from ice pads. ConocoPhillips is aware that this drilling schedule could be delayed by an unseasonably warm winter. If that happened, the wells would not be drilled until the following winter.

Views of the Board

We are of the view that the general approach and the conceptual design and plan outlined by ConocoPhillips for the Parsons Lake field are reasonable. We note that ConocoPhillips will use new geological and reservoir data acquired from drilling and production to determine if additional faulting and compartmentalization exists and whether any contingent wells would be required. In this regard, Condition P17 requests ConocoPhillips submit an updated resource management plan with the National Energy Board within 18 months after production commences or prior to the drilling of contingent wells.

Condition P5 requires ConocoPhillips to provide adequate gas sampling and analyses during drilling and production operations as the Parsons Lake field is expected to have three to five percent carbon dioxide gas content.

We accept ConocoPhillips' conceptual commingled production strategy to effectively deplete reservoir compartments. The National Energy Board will consider commingled production on an individual well basis during drilling and production operations in accordance with section 66 of the Canada Oil and Gas Drilling and Production Regulations.

Condition P30 stipulates that the approval of the Development Plan under for the Parsons Lake field under subsection 5.1(4) of the Canada Oil and Gas Operations Actis subject to the Minister of Indian Affairs and Northern Development Canada providing confirmation that ConocoPhillips has satisfactorily met the Benefits Plan requirements of section 5.2 of the Canada Oil and Gas Operations Act.

4.4.2 Development plan issues

During the hearing, the issues raised included:

  • matters raised by adjacent rights holders;
  • geographic and design issues related to permafrost, climate change, subsidence and flooding;
  • air quality issues and greenhouse gas emissions; and drill cuttings disposal.

Matters raised by adjacent rights holders

The National Energy Board issued a Declaration of Commercial Discovery for the Parsons Lake field on 16 September 2004 which included lands held under Significant Discovery Licence 030, 032 and 062.

The Parsons Lake field is contained within Significant Discovery Licences SDL030 and SDL032. ConocoPhillips, the field operator, holds 75 percent of the working interest of these licences while ExxonMobil holds the other 25 percent. Exploration Licence EL4068, of which PetroCanada is the representative interest holder, borders Significant Discovery Licence SDL030 and SDL032 to the east and south. Crown land lies to the north and west of Significant Discovery Licence SDL032. Imperial9 is the registered interest holder and operator of Significant Discovery Licence SDL062 located on the northeast boundary with ConocoPhillips' Significant Discovery Licence SDL032. Other notable interest holders of Significant Discovery Licence SDL062 include ExxonMobil Canada,

[8] Exploration Licence EL406 was surrendered in 2007.

[9] In Exhibit MOL-3I, Imperial Oil Resources Limited,
Imperial Oil Resources Ventures Limited and Imperial
appear to have been used interchangeably.

ConocoPhillips and Mosbacher. ExxonMobil holds between four and eight percent interest in the south, central and north segments of Significant Discovery Licence SDL062. ConocoPhillips holds approximately 1.2 percent interest only in the central segment. Mosbacher holds an average 3.1 percent interest in the central and north segments (see Figure 4-14).

Mosbacher, which holds an interest in lands adjacent to the Parsons Lake field, expressed concern that the proposed development would drain its gas resources. According to Mosbacher, the Parsons Lake Development Plan should not be approved because ConocoPhillips has failed to present plans that would respect the rightful economic interest of holders of adjacent lands.

Mosbacher indicated that, although its estimate for gas-in-place for Significant Discovery Licence SDL062 is small compared to the gas-in-place for Significant Discovery Licences SDL030 and SDL032, it believes that approximately 5.4 percent of the total Parsons Lake original gas-in-place lies under Significant Discovery Licence SDL062. According to Mosbacher, the volumes under Significant Discovery Licence SDL062 are commercially producible. Mosbacher stated that the one grid unit buffer offered by ConocoPhillips would not adequately protect its resource from being drained by ConocoPhillips' operations on Significant Discovery Licences SDL030 and SDL032. Without a unitization agreement it is likely that the gas resource on Significant Discovery Licence SDL062 would be lost to the owners of Significant Discovery Licences SDL030 and SDL032.

Figure 4-14 Commercial discovery declaration area and significant discovery licences for Parsons Lake field as of 2006

Figure 4-14 Commercial discovery declaration area and significant discovery licences for Parsons Lake field as of 2006

Mosbacher indicated that it sought cooperative negotiation between the parties. Since its efforts in this regard were not successful, Mosbacher asked us to direct ConocoPhillips to make a comprehensive and compelling case that resources from adjacent lands will not be drained. Mosbacher stated that Imperial, the operator of Significant Discovery Licence SDL062, considered drilling a well, constructing facilities and tying into the proposed Parsons Lake development, but the stand-alone drilling project was not sufficiently robust to meet its internal hurdle rates. Mosbacher stated it then circulated an alternative cost-effective drilling scenario based on the cooperative use of the north pad by all partners of Significant Discovery Licence SDL062. The scenario proposes a single well with a horizontal reach10 of approximately 7500 metres from the north pad into section 54 of Significant Discovery Licence SDL062 which may be approaching the current theoretical technical limit for the reservoir.

ConocoPhillips stated that Mosbacher has never been prevented from doing work and drilling wells like ConocoPhillips has done. No well has been drilled in Significant Discovery Licence SDL062 and ConocoPhillips believes there is a great deal of uncertainty as to what resources are included in Significant Discovery Licence SDL062. ConocoPhillips stated that serious and meaningful discussions on unitization cannot occur without a well. The gas

[10] Mosbacher stated in the hearing that the length of the drill was “7500 m reach measured depth distance.” Measured depth is not horizontal reach, but has been taken to mean horizontal reach because the distance between the north pad and section 54 is approximately 7500 metres.

conditioning facility is designed to process only the gas produced from the Parsons Lake field and offers no spare capacity. Currently, ConocoPhillips has no plans to expand the gas conditioning facility; however, the gas conditioning facility could be upgraded to accommodate third-party gas if the volume, delivery conditions and gas composition were known before detailed engineering plans are finalized. Upgrading would require expansion of the pad size. In addition, ConocoPhillips would consider allowing a third-party to drill a well from the north well pad as this pad was designed to accommodate more wells than ConocoPhillips plans to drill. If Mosbacher were to drill a well into Significant Discovery Licence 062 from the north pad and the well was determined to be commercial, the gas conditioning facility may have to be upgraded.

ConocoPhillips requested approval for a variance to the National Energy Board's 2009 Draft Spacing Requirements for Significant Discovery Licences SDL030 and SDL032 to allow the appropriate placement of wells to increase gas recovery.

Mosbacher submitted during final argument that the proposed Parsons Lake Development Plan was sub-optimal insofar as it does not address development of the whole field, and it encourages waste. In this regard, Mosbacher referenced sections 18 and 19 of the Canada Oil and Gas Operations Act. In the event there is no joint development, Mosbacher requested that we reject ConocoPhillips' applied-for spacing. Mosbacher asked us to consider a condition requiring ConocoPhillips to include all land in Significant Discovery Licence SDL062 within the commercial discovery declaration area as part of the Parsons Lake Development Plan. Another condition requested by Mosbacher would require ConocoPhillips to fully explore joint production arrangements with other interested parties. In addition, Mosbacher suggested a condition requiring ConocoPhillips to make available drilling pad space on reasonable commercial terms to allow Mosbacher and other interested parties the opportunity to drill additional wells on a timely basis.

Views of the Board

We consider joint development of the Parsons Lake field to be the desired approach if the interest holders of Significant Discovery Licence SDL062 agree to develop their lands. This would avoid duplication of facilities and would minimize the environmental footprint. It is also our view that joint development should be attained voluntarily through commercial negotiations and agreements between the interested parties. We note that the compulsory unitization provisions in the Canada Oil and Gas Operations Act require participation from ConocoPhillips as it holds a large portion of the lands comprising the Parsons Lake commercial discovery declaration area. ConocoPhillips stated that the first step that needs to be taken to begin meaningful talk on joint development or unitization is Mosbacher proving the extent of field by drilling a well on Significant Discovery Licence SDL062. Condition P2 requires both the north and south well pads to be designed for expansion allowing for the drilling of at least one well by adjacent interest holders. Contingent upon successful discussions between ConocoPhillips and Mosbacher to settle commercial terms including timing, the condition would provide Mosbacher the opportunity to drill directional wells to delineate the field on its lands with a minimal environmental footprint.

We consider there to be no basis for a condition directing ConocoPhillips to include all sections of land in Significant Discovery Licence SDL062 that are within the commercial discovery declaration area as part of the Parsons Lake Development Plan since there is currently no joint development agreement between the interest holders of Significant Discovery Licence SDL062 and ConocoPhillips and ExxonMobil. As the critical action that needs to occur before joint development discussions progress is that Mosbacher drills a well on its land, we are not persuaded to include the condition sought by Mosbacher requiring ConocoPhillips to fully explore joint production arrangements with other interested parties.

We are of the view that the National Energy Board's 2009 Draft Spacing Requirements are appropriate in the absence of joint development arrangements. The 2009 Draft Spacing Requirements are intended to provide a fair approach with respect to the optimization of gas recovery and the protection of the correlative rights of adjacent land interest holders. Condition P18 requires ConocoPhillips to comply with the 2009 Draft Spacing Requirements. The 2009 Draft Spacing Requirements establish a 250 metre off-target area from adjacent

lands of differing ownership for gas wells. Alberta, British Columbia, Saskatchewan and Yukon utilize a similar set-back.

ConocoPhillips would not require a variance for the proposed preliminary well locations for the Parsons Lake field in accordance with the 2009 Draft Spacing Requirements. The 2009 Draft Spacing Requirements set a limit of one producing well in spacing units adjacent to lands of differing ownership, but for spacing units not adjacent to lands of differing ownership, there is no off-target area and more than one producing well is permitted11. The National Energy Board will consider any future application for a variance at that time and assess it in accordance with the 2009 Draft Spacing Requirements or any orders dealing with spacing that may supersede it.

In our view, Mosbacher has not provided evidence to support a determination that the proposed Parsons Lake Development Plan encourages waste. We consider the proposed production scheme to be appropriate for a conventional gas field such as Parsons Lake. With Condition P19 in place requiring compliance with the 2009 Draft Spacing Requirements, Mosbacher has the opportunity to drill wells and develop lands in Significant Discovery Licence SDL06212.

[11] Part IV of the 2009 Draft Spacing Requirements.

[12] Those lands of Significant Discovery Licence SDL062 that were included in the National Energy Board's commercial discovery declaration dated 3 November 2004 are eligible for a production licence.

Geographic and design issues Permafrost and climate change

The Parsons Lake field lies within a zone of continuous permafrost. The permafrost thickness north and east of the lake ranges from 354 metres to 378 metres. Geotechnical drilling on the north pad and adjacent areas in 2004 identified massive ground ice throughout the north pad area. As with the other development fields, development could thaw the permafrost and significantly alter the northern landscape.

ConocoPhillips plans to use a number of measures to preserve the permafrost. These activities are divided into methods for protecting surface sites and methods for protecting the permafrost during drilling and production. ConocoPhillips plans to insulate the ground from heat sources, such as buildings and flow lines using methods such as:

  • piling 1.5 metres of gravel on all well pads and the airstrip to provide thermal stability and protect against contact pressure caused by vehicles. A layer of rigid insulation or geotextile may be incorporated in some areas to further protect the permafrost;
  • using adfreeze-type steel pipe piles to elevate the buildings about 1.5 metres above the gravel pads and allow for air flow between the building and the gravel pad;
  • using thermsiphons under any slab-on-grade foundations elevating and insulating the flow lines, as mentioned in section 4.4.1; and
  • where embankments are created, slopes would be angled to minimize thaw degradation.

Preservation of the permafrost at well sites would be accomplished by:

  • spacing all wells, including contingent wells, at least 25 metres apart. This exceeds the 15 metre interwell spacing suggested by the C-FER Technologies and EBA Engineering study of the effect of well spacing on permafrost, which predicted the coalescence of permafrost thaw bulbs in 20 years for wells spaced at 10 metre intervals;
  • installing thermosiphons close to each well;
  • placing an insulated conductor about 24 metres down each well; and
  • using cooled mud to drill the surface holes; using permafrost cement for the conductor and the surface casing on each well;
  • and using gelled diesel fuel in the tubing or casing annulus for insulation.

By using these methods, ConocoPhillips expects heat loss from conduction and convection of produced fluids would be reduced by at least 90 percent compared to using conventional packer fluids.

The Sierra Club of Canada raised questions about the projections of temperature change due to climate change over the life of the project used by ConocoPhillips in the design of the Parsons Lake field facilities.

ConocoPhillips evaluated the risk of surface subsidence caused by the extraction of natural gas and determined that no measurable subsidence is expected because of the nature of the reservoir and its depth (three kilometres). In addition, because ConocoPhillips plans to

use a combination of wellbore insulation and thermosiphons it does not expect measurable amounts of well permafrost thaw subsidence.

The north pad sits approximately 45 metres above sea level and there is no evidence the site has been flooded. Accordingly, flooding is not expected at the north pad or, similarly, the south pad.

The Joint Review Panel was generally satisfied that ConocoPhillips had taken climate change into account in its design. Nevertheless the Joint Review Panel recommended that the National Energy Board require ConocoPhillips to file final design plans that incorporate further design analysis of the impacts of climate change on permafrost and terrain stability over the design life of the project and post-abandonment. The Joint Review Panel was of the view that this analysis should be conducted for a series of representative locations, conditions and terrain types and should incorporate climate variability, in particular, upper limit temperature scenarios to account for the range of future temperature conditions, including variability and extremes, and the impact of this variability on stream flow regimes. The Joint Review Panel added that the results should be incorporated into monitoring, mitigation and adaptive management plans. The Joint Review Panel thought that this analysis should be provided to other appropriate regulators in sufficient time for review and to provide input to the National Energy Board.

Indian and Northern Affairs Canada suggested in final argument that the Proponents should

demonstrate how upper limit temperature scenarios have been considered in their design.

Further specific discussion on climate change regarding project design is found in Chapter 6.

Views of the Board

Warming of the global and regional climate could raise sea levels and affect weather patterns. Parsons Lake is located on higher ground and further from the sea, so its facilities would be less exposed to possible effects of climate change.

We are satisfied with ConocoPhillips' general approach to addressing permafrost integrity with respect to the Parsons Lake development. As warm fluids will flow through those wellbores during drilling and production operations, it is important for safety and environmental protection reasons that the permafrost thaw bulbs around wellbores do not coalesce. Condition P3 requires the interwell spacing on the Parsons Lake well pads to be no less than 15 metres unless ConocoPhillips utilizes mitigation measures approved by the National Energy Board.

Condition P8 requires ConocoPhillips to provide final detailed design information which incorporates an analysis of the impacts of climate change and variability on permafrost and terrain stability for the Parsons Lake facility using potential upper

limit temperature scenarios which may occur during the operational life of the facilities. ConocoPhillips will also provide information about how upper limit temperature scenarios may impact precipitation and water levels of Parsons Lake and other nearby lakes. We are of the view that government departments such as Environment Canada. Indian and Northern Affairs Canada and Natural Resources Canada should be consulted to benefit from their expertise.

Air quality issues

Air quality in the North is considered to be of high quality and Northerners are very concerned that it remains that way. Both Environment Canada and the Proponents agreed that existing air quality in the proposed project area is good and, along with other government regulators, emphasized the need to “keep clean areas clean.” This principle requires new industrial development to be “planned, constructed and operated in a manner that minimizes the degradation of air quality in these areas.”

Air quality issues for the project included project emissions for the pipeline and development fields, monitoring, and greenhouse gases in the context of monitoring climate change. The Joint Review Panel noted that the National Energy Board would be the prime regulator of air emissions from the project and that Environment Canada and the Government of the Northwest Territories would play advisory roles. The Joint Review Panel recognized

the National Energy Board's expertise and experience in regulating interprovincial aspects of the oil, gas and electric utility industries, including environmental matters. The Joint Review Panel also recognized the extensive environmental and local knowledge that Environment Canada and the Government of the Northwest Territories can provide.

Air emissions can be related to the project-specific effects of construction, operations, and waste incineration. Air quality impacts can be local to regional in the case of particulate matter and sulphur dioxide, or global in the case of greenhouse gases. Emissions would occur during the construction phase through intermittent flaring during well testing at the Parsons Lake field.

Further specific details pertaining to emissions for the pipeline are discussed in Chapter 3 and discussion on air emissions pertaining to facility design is found in Chapter 6.

The Joint Review Panel report indicated that the Proponents' baseline information was compiled from historical data and results of air quality monitoring that was carried out over one year near the communities of Inuvik and Norman Wells, and periodically at the Parsons Lake and Taglu gas fields. The Proponents' monitoring data and other sources indicated that background concentrations of air contaminants are generally below detection levels or applicable guidelines. The one exception that is not below detection levels is ozone; relatively high background levels were monitored in Inuvik

and Norman Wells. The Proponents indicated that elevated ozone levels at high latitudes in the northern hemisphere are thought to result from the intrusion of stratospheric ozone. The Proponents stated that all ground-level concentrations of compounds released by the project during operations at the gas fields, the Inuvik Area Facility, and compressor and heater station sites would increase, but would be below those outlined in applicable federal and territorial guidelines at all locations in the production area and along the pipeline corridor.

Environment Canada recommended that the Proponents design and implement suitable air quality monitoring programs with its help. Environment Canada focused its recommendations on pollution prevention and the use of best available technology and best management practices to minimize the degradation of air quality. Further discussion around application of these principles may be found in Chapter 6.

The Dehcho Elders and Harvesters indicated that the project needs to be designed to minimize air quality impacts, with monitoring plans in place to verify the predicted emissions and impacts. Corrective action needs to be taken quickly to avoid impacts upon the land and wildlife from degraded air quality.

Greenhouse gas emissions

Parties were concerned about the impacts of the project on climate change, especially in light of Canada's international efforts under the United Nations Framework Convention on Climate Change and the Kyoto Protocol.

Greenhouse gas emissions arising from the project include carbon dioxide, methane and nitrous oxides with each compound having a different climate change potential. During operation, the project would emit greenhouse gases from burning natural gas at combustion related sources such as compressors and methane gas released through normal venting procedures and minor leaks (fugitive emissions). Further specific discussion on air emissions pertaining to facility design is found in Chapter 6.

Alternatives North submitted that the National Energy Board and the Government of Canada have a public interest mandate that requires consideration of greenhouse gas emissions.

Ecology North deemed that high project-specific standards for greenhouse gas emissions based on a robust and strong definition of best available technology and accompanied by penalties in the cases where they do not meet those project standards or targets, would provide the best possible protection in terms of minimizing upstream greenhouse gas emissions associated with the project.

Sierra Club of Canada submitted that we need to specify an actual target and it is not enough to just leave it up to the Proponents. Sierra Club of Canada indicated that the target should at least match the general recommended target in Joint Review Panel recommendation 8-8.

Views of the Board

We understand the importance of clean air in the North and that air quality must be considered in a cumulative manner. We also recognize the need to minimize greenhouse gas emissions resulting from the project. The Joint Review Panel directed several recommendations to us relating to air quality and air emissions. We have addressed air issues through several conditions for the Mackenzie Gas Project. These conditions are focused on the Proponents taking appropriate measures to minimize air emissions and address air quality. We are committed to working collaboratively with Environment Canada and the Government of the Northwest Territories to protect air quality in the North, recognizing the extensive environmental and local knowledge that these agencies can provide.

Conditions P13 and P14 address technologies for reducing emissions, incorporation of best management practices and best available technologies, and facility design. Condition P14 requires the submission of a report evaluating incinerator emissions from camps and station facilities and technologies and practices must be reflected in the waste management plans required by Condition P11. Condition P16 requires the ConocoPhillips to minimize and reduce emissions from flaring. Further specific

discussion for these conditions regarding air emissions pertaining to facility design is found in Chapter 6.

Air quality monitoring is part of comprehensive environmental monitoring under an environmental management system. Through environmental management, systems are established to address effects of the project on the environment and of the environment on the project, with the overall goal of minimizing negative impacts. Adaptive management is a systematic process for continually improving management practices by learning from their outcomes.

Environmental monitoring is an important part of environmental management that directly supports adaptive management by observing and evaluating the effects that occur, then changing or adding mitigative measures as appropriate to limit or reverse the environmental effects. Environmental monitoring can include:

  • compliance monitoring, to verify that all environmental mitigation is implemented as presented in the Environmental Protection Plan and environmental alignment sheets and that work is in compliance with environmental regulations; and
  • effects monitoring, to assess the effects resulting from project-environment interactions and evaluate the effectiveness of approved mitigation measures

This is further discussed in section 3.3.6.

ConocoPhillips is expected to implement Environmental Protection and Monitoring and Surveillance Programs which include protection of the environment as one of the main goals. A monitoring program may:

  • identify any issues or potential concerns that may compromise the protection of the environment;
  • include methods for developing measures to prevent or mitigate the impact of the identified issues;
  • provide for continued monitoring of sites to evaluate success of mitigative measures undertaken;
  • provide a system for implementing additional mitigative measures as necessary; and
  • provide a feedback system that allows for adaptation of successful mitigation to future pipeline projects.

Monitoring programs may have specific goals and targets and could include methods for evaluating and interpreting collected data such as air quality or emissions data. Monitoring may include any relevant environmental practices (e.g., vegetation establishment, water quality sampling, waste disposal).

Responsibilities of the National Energy Board regarding monitoring include:

  • conducting environmental inspections of facilities, verifying compliance with terms and conditions, and assessing the effectiveness of mitigation;
  • monitoring ongoing operation, verifying reclamation and maintenance of the project site to acceptable standards; and
  • conducting environmental audits, evaluating environmental management systems and environmental programs.

We generally require the filing of environmental post-construction monitoring reports as a condition of an authorization. The information in monitoring reports should include:

  • confirmation of proper implementation of mitigation and reclamation measures used;
  • identification of the outstanding environmental issues; and
  • discussion of the company’s plans for how outstanding issues will be resolved.

Condition P10 requires ConocoPhillips to submit an Environmental Protection Plan which includes monitoring of activities. Condition P13 includes the requirement for monitoring incinerator emissions.

A commitment to continuous improvement, outlined in Joint Review Panel recommendation 8-6, is expected to be a component of an operator's Management system pursuant to paragraph 5(2)(b) of the Canada Oil and Gas Drilling and Production Regulations. This is addressed in Condition P10. We are of the view that the commitment to continuous improvement is not limited

to greenhouse gas emissions but should apply to all discharges to the environment, which in this case is the atmosphere. Condition P10 also covers the requirements for methods and locations of monitoring.

Condition P15 requires the Proponents to file a report outlining the use of best available technology for station facility construction. Selection of best available technology is the most significant factor in determining achievable air emissions targets. Condition P10 outlines the requirements for an Environmental Protection Plan. The condition requires the Proponents to submit maximum proposed greenhouse gas targets and reduction strategies for air emissions including particulate matter, NOx and greenhouse gases. Condition P10 also addresses other matters from the Joint Review Panel recommendations including employee training, monitoring, public communication, and required consultation with Environment Canada and the Government of the Northwest Territories. With these conditions, we find it acceptable for the Proponents to develop greenhouse gas targets for the project consistent with use of best management practices and in consultation with appropriate government agencies.

Drill cutting disposal

Like the operators of the Taglu field, ConocoPhillips plans to dispose of drill cuttings from the Parsons Lake field into a dedicated disposal well. Drill cuttings would be collected and transported to the cuttings processing station. At the station, the cuttings would be mixed with water, milled and sheared to create slurry. The slurry would then be pumped into the proposed D-20 dedicated cuttings disposal well (see Figure 4-13). Disposal would usually be done in batches at low pump rates. ConocoPhillips is planning a comprehensive program of testing and monitoring of subsurface containment during cuttings injection operations. Annular cuttings injection may be used as a back-up if ConocoPhillips was not able to use the dedicated cuttings injection well.

As mentioned for Taglu, subsurface slurry injection has not been used in the Northwest Territories at this scale before. If cuttings injection is not viable, ConocoPhillips' alternative method for the disposal of drill cuttings would be to stabilize, store and subsequently transport the cuttings to an approved disposal site.

Noise

The Parsons Lake anchor field is located outside of Kendall Island Bird Sanctuary. The physical footprint of the facility, particularly the north pad, is an area of relatively low numbers and diversity of migratory birds compared to the nearby Mackenzie Delta. ConocoPhillips believes

that it is appropriate for the Parsons Lake production facility to follow Alberta's Energy Resources Conservation Board Directive 038 “business as usual” Permissible Sound Level.

Views of the Board

We are of the view that the conceptual plan by ConocoPhillips to dispose its drill cuttings by subsurface slurry injection is satisfactory as it avoids the use of sumps and minimizes the environmental footprint. However, as down-hole slurry injection of this scale and extent has not been utilized in the Mackenzie Delta before, Condition P4 requires ConocoPhillips to submit a drill cuttings slurry injection management program. The National Energy Board would assess such a program with respect to subsurface containment as well as safety, protection of the environment and conservation of resources.

Condition P9 requires meeting requirements of Alberta's Energy Resources Conservation Board Directive 038 for noise regulation and filing a post construction noise assessment report 90 days following the start of operation.