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Chapter 6 Facilities

Chapter 6
Facilities

6.1 Overview of facilities

The proposed Mackenzie Gas Project extends from the three development fields in and adjacent to the Mackenzie Delta (see Chapter 4), south along the Mackenzie River Valley into the northwest corner of Alberta (see Figures 1-2 and 1-3). The land changes along the route from the water-dominated Mackenzie Delta and treeless tundra to boreal forest in Alberta. Design, construction and operation of the pipelines and associated facilities are directly influenced by the harsh northern climate, the presence of permafrost, a unique transportation infrastructure that relies on ice roads and the Mackenzie River and the potential effects of climate change. To address the unique conditions of the project, the Proponents proposed a number of design innovations, including very high pressures, high strength steel, strain-based design, the use of statistical techniques and a greater emphasis on monitoring and subsequent intervention. A fundamental issue was the level of detail required at the approval stage to support our decision on whether or not to approve the project.

 

The proposed Mackenzie Gathering System includes upstream gathering pipelines, the Inuvik Area Facility and a natural gas liquids pipeline from the Inuvik Area Facility to Norman Wells. The upstream gathering pipelines would bring a mixture of natural gas and natural gas liquids produced at the three development fields to the Inuvik Area Facility. At the Inuvik Area Facility the natural gas liquids would be separated from the natural gas and stabilized before being shipped south to Norman Wells in the NPS 10 (DN 250) natural gas liquids pipeline. At Norman Wells the natural gas liquids pipeline would connect to the Enbridge Pipelines (NW) Inc. Norman Wells Pipeline on which the natural gas liquids would be shipped in batches.

 

The proposed Mackenzie Valley Pipeline is an NPS 30 (DN 750) natural gas pipeline which would share the same right of way as the natural gas liquids pipeline from the Inuvik Area Facility to Norman Wells. It would then continue in a separate right of way into northern Alberta, where it would connect to facilities to be constructed by NOVA Gas Transmission Ltd1.

[1] NOVA Gas Transmission Ltd. filed an application with the Alberta Energy and Utilities Board on 27 June 2006 requesting a permit to construct the proposed Northwest Mainline (Dickins Lake Section), Northwest Mainline Loop (Vardie River Section) and the Northwest Territories Border Meter Station. The Alberta Energy and Utilities Board subsequently announced that it would postpone the establishment of a date for the hearing on these facilities pending the issuance of the Joint Review Panel Report. On 29 April 2009 the NOVA Gas Transmission Ltd. system became subject to the jurisdiction of the National Energy Board. As a result, NOVA Gas Transmission Ltd. must file a new application with the National Energy Board for these facilities.


The Mackenzie Valley Pipeline is designed to operate at a pressure of 18.7 MPa (2,710 psi).

6.2 Assessment of
engineering Issues

When assessing an application for proposed facilities, the National Energy Board considers the facilities' design and proposed operation to determine whether the project would be constructed and operated in a safe, reliable and environmentally responsible manner. As mentioned in Chapter 2, pipelines under National Energy Board jurisdiction must be designed in accordance with the National Energy Board's Onshore Pipeline Regulations, 1999 and the latest versions of relevant design codes, including Canadian Standards Association Z662, Oil and Gas Pipeline Systems.

A number of engineering issues were examined in our hearing, some unique to the northern climate, others typical of pipelines in Canada. These issues are grouped into the following categories and discussed in this chapter.

Overall design strategy:

  • design process;
  • cost estimate;
  • stress-based and strain-based design, including consideration of frost heave and thaw settlement; and
  • hydraulic design and proposed configuration of the Mackenzie Gathering System, the Mackenzie Valley Pipeline and station facilities.

Specific design issues:

  • pipeline operating temperatures;
  • pipeline materials;
  • joining (including welding and
    non-destructive examination);
  • seismic design;
  • slopes;
  • watercourse crossings;
  • pipeline control systems and leak detection;
  • settlement of backfill; and
  • geohazards.

Other technical considerations:

  • air emissions;
  • pressure testing;
  • support infrastructure;
  • northern logistics and construction;
  • right of way protection; and
  • monitoring and surveillance plans.

6.3 Overall design strategy

6.3.1 Design process

The Proponents presented a three-phase design process for the Mackenzie Gas Project: conceptual engineering; preliminary engineering; and detailed engineering design (see Figure 6-1). The Proponents stated that the applications submitted to the National Energy Board were based on conceptual engineering and that preliminary engineering started after the applications were filed.

The detailed engineering phase takes into account the information from the previous design phases, inputs from the regulatory phase and additional information collected through field investigation programs. Detailed engineering results in products which can be used to initiate contracting and construction activities and would not start without project approval.

 

Figure 6-1 Engineering design process

Figure 6-1 Engineering design process

6.3.2 Cost estimate

The initial cost estimate for the Mackenzie Gas Project was prepared by the Proponents based on the proposed scope of work at the completion of the conceptual design phase. After filing the application, the preliminary engineering phase began. This resulted in revised cost estimates, which were based on:

  • improved definition of project materials and labour;
  • designs for slope stability and watercourse crossings;
  • project construction plans;and
  • costs of the regulatory process.

These revisions were subsequently filed with us and are shown in Table 6-1 and Figure 6-2. The capital cost estimate included expenditures for engineering design, procurement, owners' costs and construction, but excluded an allowance for funds used during construction.

Table 6-1 Project expenditures 2007 update

Project component Estimated cost
(2006$
million)
Niglintgak 800
Taglu 1,750
Parsons Lake 1,200
Mackenzie Gathering System 3,500
Mackenzie Valley Pipeline 7,050
Total initial cost 14,300
Future Mackenzie Valley Pipeline facilities 800
Future anchor field investments 1,150
Total cost 16,250

Costs for various project components were derived from different sources. The Proponents submitted that materials and equipment costs were based on estimates from suppliers for larger items such as pipe and valves and from the Proponents' own data or manufacturers' price lists for smaller times. The capital costs for spares were estimated on the basis of manufacturers' recommendations. By comparison, construction cost estimates were based on detailed construction industry data for pipelines and infrastructure. Construction cost estimates included allowances for:

  • past experience;
  • contractor input;
  • northern conditions; and
  • proposed construction methods.

A specific set of allowances for specific project risks and a contingency allowance based on the level of definition for each major project component were also factored into the cost estimate. The Proponents submitted that the method used to prepare and revise the capital cost estimate is consistent with the Association for the Advancement of Cost Engineering International's recommended practice for process industries.

Did you know?

Definitions

Strain - the deformation or change in pipe dimensions resulting from the applied loads.

Stress - the force per unit area experienced by the pipe at any given location in response to the applied loads.

Frost heave - the upward or outward movement of the ground surface caused by the formation of ice in the soil.

Thaw settlement - the settlement of the ground under its own weight or applied stresses caused by the loss of ice due to melting.

Strain-based design - designing a pipe by setting the limit (or maximum amount) of deformation that it can safely sustain.

Stress-based design - designing a pipe that can safely accommodate the predicted combination of internal and external loads without permanent deformation.

Thermal load - changes in temperature result in expansion or contraction of the pipeline (strain) which in turn induces a stress on the pipeline.

6.3.3 Stress-based and
strain-based design

The Mackenzie Gas Project would be constructed and operated in Canada's harsh northern environment through terrain containing varying amounts of permafrost. The design of pipelines in permafrost terrain requires consideration of the thermal properties of the ground, the pipe and the product being shipped, and presents a number of unique geotechnical and structural engineering challenges. Freezing and thawing of the ground can cause frost heave, thaw settlement and slope instability.


These ground movements impose stresses and strains on the pipeline that need to be considered during design, construction and operation. Construction activities can disturb the permafrost and alter terrain conditions.

The conventional approach to pipeline design is based on allowable stresses. This approach measures or predicts the combination of internal and external loads a pipeline can safely withstand without deforming during operation. Information needed for stress-based design includes an understanding of the site-specific geotechnical properties of the soil around the pipe and its potential for interacting with pipe. These properties include soil type, presence of groundwater or permafrost, and the magnitude and likelihood of slope movements, seismic events or other geohazards.

An alternative approach is strain-based design, which focuses on the pipe's material and its behaviour. The pipeline designer sets boundaries or limits, referred to as limit states, which define the maximum amount of strain the pipe can safely tolerate. This approach, however, requires active monitoring to identify where and how fast the pipeline is changing or deforming.

The Proponents stated that they would use a lifespan engineering approach for the Mackenzie Gas Project that includes a combination of stress and strain -based design, construction mitigation and operational monitoring and interventions to ensure the integrity of the pipeline. The primary loads on the Mackenzie Valley Pipeline, such as internal pressure and dead weight, would be

designed to meet the stress limits in Canadian Standards Association Z662-07, Oil and Gas Pipeline Systems while secondary loads such as frost heave and thaw settlement would be designed using a strain-based limit state design methodology.

The Proponents stated that the overall design approach relies on strain monitoring and mitigation during operation. A Geopig® tool travelling inside the pipe is able to determine longitudinal strains. When the strain at a given location is approaching the serviceability strain limit, the Proponents would take action such as:

  • reducing the size and rate of frost bulb growth;
  • reducing resistance to pipe movement;
  • reducing settlement;
  • providing additional pipe support;
  • replacing the pipe; or
  • relocating the pipe.

The Proponents submitted that specific intervention criteria for pipeline strain would be developed.

Following from this approach to overall project design, two issues arose during the hearing:

  • the applicability of using a strain-based design for the Mackenzie Valley Pipeline and the Mackenzie Gathering System; and
  • the type, amount and timing of site-specific geotechnical information required by the applicant in the design and regulatory approval processes.

Did you know?

Stress-based and strain-based design

Pipelines are designed to withstand a number of different loads. Some loads are permanent or remain constant for long periods of time, such as the pipeline's weight or that of the soil over the pipe. Operational loads such as internal pressure occur during the pipeline's operation and can vary over time. Environmental loads such as frost heave and thaw settlement can be of short or long duration. These loads are grouped into primary or secondary loads for pipeline design purposes.

Primary loads create stresses or forces within the pipe as long as the load is applied. The loads can be permanent or operational and if the stress in the pipeline were allowed to exceed the peak strength of the steel, the pipe would fail. The pipeline's internal pressure is an example of a primary load. Canadian Standards Association Z662, Oil and Gas Pipeline Systems requires that stress combinations resulting from primary loads be limited to a certain percentage of the yield stress of the pipe. This is referred to as stress-based design, and most pipelines in Canada are designed using this method.

Secondary loads are generated within the pipe as it conforms to environmental loads. In order to design pipelines to resist secondary loads, it is necessary to determine the size of the secondary load and the amount of deformation the pipe can safely sustain (called strain capacity or allowable strain). Pipelines designed to resist secondary loads in this way are called strain-based design pipelines.


On the record

Pipeline design temperatures

The Proponents stated that the minimum design temperature for exposed, above ground high pressure piping on the Mackenzie Gathering System without heat tracing would be -53oC. With insulation and heat tracing the minimum design temperature for above ground piping would be -45oC. The Proponents reviewed 40 years of Environment Canada climate data for Inuvik, and the lowest minimum average daily air temperature recorded was -53oC.

Did you know?

Frost heave and thaw settlement

The Mackenzie Valley Pipeline and Mackenzie Gathering System would be buried in areas containing permafrost, giving rise to design issues related to frost heave or thaw settlement depending on local ground conditions. The resulting loads exerted on the pipe would vary depending on the presence of groundwater, the porosity of soil and the temperature of the ground relative to the pipe at a given location. Where the pipe temperature is below 0oC and the surrounding ground is initially unfrozen, such as in taliks beneath rivers, a frost bulb may grow around the pipe, applying uplift forces over the affected span of pipe. Where the pipe temperature is above 0oC and the ground is frozen, any thawing may cause the ground to settle, leaving unsupported spans of pipe. If a pipe crosses through ground with varying soil types and ice contents, differential settlement or heave may occur, causing localized stresses and strains on the pipe.


These issues are inter-related and are addressed below in the context of frost heave and thaw settlement along a northern pipeline. The availability of site-specific geotechnical information is also addressed in the context of the specific design issues related to watercourse crossings and geohazards such as seismic risks and slope stability.

The preliminary design phase, including engineering design calculations such as those for the combination of external forces that could be imposed on the pipe, was ongoing at the time of the hearing. Detailed design and the gathering of the necessary remaining site-specific route information would not start unless the project is approved, and would continue until construction begins on each facility or pipeline construction spread.

Frost heave and thaw settlement

The Mackenzie Gas Project pipelines would be subject to environmental loads, such as large temperature differentials between construction and operation, frost heave and thaw settlement, which are not commonly encountered by conventional onshore pipelines. The Proponents indicated that several factors contribute to the loading conditions, including the unfrozen span length and the number of unfrozen spans per kilometre. The Proponents stated that statistical distributions best characterized these factors, as well as the strain capacity of the pipe. This made probabilistic methods suitable for assessing design safety and estimating the number of operational interventions that may be required during the life of the pipeline. Various simulation programs including finite element analyses were used to determine serviceability strain limits.

 

Figure 6-2 Frost heave

Figure 6-2 Frost heave

Strain capacity

The limit state design methodology (Canadian Standards Association Z662-07, Annex C) considers all phases of the pipeline life span, the combination of loads and the properties of the materials to be used. The value of the compressive strain limit for the Mackenzie Gas Project pipes is expected to be 1.5 percent and the tensile strain limit is 2.0 percent. Although these strain limits were determined analytically, the resulting values were confirmed through several laboratory verification tests. The Proponents considered several combinations of internal and external forces during the iterative design process. The most significant forces were internal pressure, frost heave (see Figure 6-2) and thaw settlement (see Figure 6-3).

Strain demand

For the overland design, the Proponents submitted that they used pipeline route selection criteria to avoid design and

construction challenges (see Chapter 5), and that it was not practicable to collect new geotechnical and geothermal data to further optimize the route. The Proponents mapped geotechnical conditions by terrain class. The soil properties for each terrain class were established using statistical methods. The Proponents submitted that pipeline strain calculations based on this information would not take into account all areas of high frost heave and thaw settlement. As a result, the pipe may be installed in an area with soil properties that produce higher values of frost heave and thaw settlement than established for the terrain class. Limit states would be set for the ultimate tensile strain, within which the pipeline's integrity is maintained, and for serviceable compressive strain, whereby the pipeline would initially buckle but would not leak.

The Proponents submitted that it was not practical to collect detailed soil and temperature

 

Figure 6-3 Thaw settlement

Figure 6-3 Thaw settlement

Did you know?

Definitions

Geopig® - a brand of internal inspection tool that can be used to determine pipe location and deformation.

In-line inspection - the use of internal inspection tools, which travel inside the pipeline, to carry out an inspection.

Longitudinal strains - elongation or compression of the pipe along its length.

Span lengths - the length of pipeline over which the load or deformation occurs.

Probabilistic methods - pipe properties and loads used in design are not discrete numbers but are deemed to be a range of values, each with a certain probability of occurrence based on statistical data. Designers select the design load and pipe properties based on the desired degree of confidence and conservatism and determine the likelihood that a particular limit state will be exceeded.

Strain capacity - the amount of deformation the pipe can safely tolerate.

Strain demand - amount of deformation caused by internal and external forces.

Serviceability strain limit - the point at which a deformity will cause the pipeline to become inoperable, but not cause a loss of containment.

Ultimate strain limit - the point at which a pipeline deformity will cause a loss of containment.


On the record

Iterative design process

The Proponents' pipeline design process for the conceptual and preliminary design phases includes the following steps:

  • Conduct hydraulic modeling (system design) to establish the pipe sizes, grade, wall thicknesses, operating temperatures and pressure profiles, and compression requirements.
  • Conduct thermal modeling to predict the potential for frost heave and thaw settlement using the temperature profile.
  • Conduct structural modeling to predict the potential for frost heave and thaw settlement effects over time. This is known as strain demand.
  • Model the capability of the pipe to sustain the tensile and compressive strains predicted by the structural modeling. This is known as strain capacity.
  • Compare the calculated strain demand as it varies over time to the design strain demand to ensure pipeline integrity.
  • Check the heave and settlement displacements and freeze and thaw bulb growth to assess environmental impacts.
  • Evaluate options for design and maintenance and make changes to the temperature limits, pipe sizes, pipe grades and pipe wall thicknesses
  • Repeat the above steps until the system design requirements are met, strain demand and strain capacity are balanced and the environmental impacts are acceptable.

data in sufficient detail to support site-specific design. To illustrate, the Proponents pointed out that changes between permafrost and unfrozen ground conditions can occur over tens of metres and changes in ice content can occur within metres. Consequently, the Proponents' design approach incorporated a requirement to monitor pipeline loads which accumulate slowly over several years, such as frost heave and thaw settlement loads. After several years, these loads may reach specific values that would require the Proponents to take action. The Proponents submitted that with this approach, detailed mapping of the geotechnical and geothermal conditions for most of the route would not be necessary for conceptual or preliminary design. Other loads, such as those which may be rapidly applied and those typical of most pipelines would be accounted for in the base design for the pipeline.

Indian and Northern Affairs Canada expressed the view that significant data on actual soil properties and ground temperatures along the pipeline route would be required to accurately model frost heave and thaw settlement on the pipeline. To delineate permafrost along the entire pipeline route, Indian and Northern Affairs Canada recommended that the Proponents use geophysics and additional boreholes, collect ground temperatures at more frequent intervals along the right of way than proposed by the Proponents and develop a detailed characterization of soils in support of frost heave and thaw settlement assessments. Indian and Northern Affairs Canada further

On the record

Effect of heat transfer

Heat transfer between the pipe and the soil will cause water in the soil to freeze or ice in the soil to thaw depending on the pipe temperature, the ground temperature and the time of year. The growth of frost or thaw bulbs around the pipeline over successive years can cause frost heave or thaw settlement forces, respectively, to develop on the pipeline. Disrupting the insulating vegetative mat during pipeline construction will also affect the rate of heat transfer between the air and the soil, further altering the permafrost regime beneath the right of way. In addition to displacement of the pipe by frost heave and thaw settlement, the span over which the displacement occurs also impacts the magnitude of the bending strains (strain demand) imparted to the pipe.

recommended that the geotechnical and thermal data be presented to the National Energy Board prior to pipeline construction.

The Proponents indicated that extensive airborne and ground-based geophysical surveys were planned before the start of construction to delineate the presence of permafrost along the entire route. Furthermore, an extensive borehole program would be undertaken during the geotechnical verification program to be carried out in the two-year period preceding pipe-laying operations. The data on permafrost distribution, ground temperature measurements and soil data would be used to revise the preliminary estimates of frost heave and thaw settlement during final engineering design. It would also be used by the Proponents to identify regions


of high heave and settlement potential and to refine monitoring and intervention programs during operations.

The Proponents stated that heavy wall pipe would be used for watercourse crossings but was not being considered as an option for frost heave and thaw settlement mitigation. It would be impractical to delineate all critical permafrost occurrences in time to procure heavy-wall pipe. The Proponents submitted that the approach adopted for the project was to design a pipeline with a tolerance for frost heave and thaw settlement and use monitoring and interventions during operations to detect and address local areas of high-strain demand as they actually occur.

 

Did you know?

Definitions

Heavy wall pipe - pipe with a greater wall thickness than the general design requirement is capable of tolerating greater stress and is more resistant to deformation (can absorb more strain energy).

LiDAR - a technology that employs an airborne scanning laser to measure the elevation of the ground.

Piezometers - instrumentation used to measure pore water pressure in soil.

Reduced pipe cover - reducing pipeline cover in areas where frost heave is anticipated allows the pipeline to displace more evenly over the entire span length, relieving the heave induced stress and reducing the total strain experienced by any one discrete pipe segment.

Thermistor - a device used to measure temperature, relying on the change in its electrical resistance with changing temperature.


Climate Change

The Proponents found that mean annual soil temperatures are typically about 4.5oC warmer than mean annual air temperatures and surface disturbance can increase the mean ground temperature by about 2oC. At the development fields the ground temperatures vary from about -4oC at Niglintgak to -7.6oC at Parsons Lake. Temperatures rise to the south, where the mean ground temperatures are about -3oC in Fort Good Hope and -2oC in Norman Wells in undisturbed areas.

Climate change data shows a warming trend in the Mackenzie Valley which may affect the distribution of permafrost over the life of the pipeline. The Proponents established values for climate warming for different regions within the project area for consideration in its design, shown in Table 6-2.

Table 6-2 Regional climate-warming rates selected by the Proponents

Region Climate warming rate
(°C/year)
Inuvik 0.094
Norman Wells 0.05
Fort Simpson 0.076
Northern Mackenzie Valley 0.072
Southern Mackenzie Valley 0.063

On the record

Data collection

The Proponents submitted that the conceptual design work required a significant amount of information about the route. Data collected using global positioning systems and light detection and ranging (LiDAR) and incorporated into geographic information systems made it unnecessary for the Proponents to clear the centreline of the route for land surveys before construction. The Proponents used the large volume of existing geotechnical and geothermal data from previous highway and pipeline studies, and incorporated some new project boreholes to populate its project borehole database. Information collected from the design and construction of the Enbridge Pipeline (NW) Inc. Norman Wells Pipeline, specifically the geophysical survey and ditch logs, provided nearly continuous profiles of the permafrost south of Norman Wells. Route temperature measurements collected during the 1970s and 1980s were available for conceptual engineering from a Geological Survey of Canada database. This information was supplemented by new information from the Geological Survey of Canada and the Proponents. The Proponents plan to collect additional geotechnical and geothermal information including probe holes, test pits, geotechnical boreholes with sampling and geophysics after the right of way is cleared.


The thermal modeling used in the development of frost heave and thaw settlement predictions was based on historical trends in air temperature warming rates at locations along the route (Inuvik, Norman Wells and Fort Simpson) rather than general climate models. Mr. Doug Ritchie raised concerns that the thermal modeling used did not include rigorous general climate models, as used by other organizations for predicting climate warming in the Arctic. The Proponents responded that historical trends for sites along the route represented the best information for pipeline design and resulted in a higher and therefore more conservative rate of climate warming than the rate predicted by available general climate models.

The Joint Review Panel was generally satisfied that the Proponents had taken climate change into account in their design. Nevertheless the Joint Review Panel recommended that we require the Proponents 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 should incorporate climate variability and, in particular, upper limit temperature scenarios to account for the range of future temperature conditions, including their 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 the 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 argued that the Proponents should consider how these upper limit scenarios influence their predictions regarding pipeline integrity in particular for those areas where permafrost may degrade over the life of the pipeline.

Views of the Board

We are of the view that the Proponents' use of a lifespan engineering approach for the Mackenzie Gas Project that includes a combination of stress and strain-based design, construction mitigation and operational monitoring and interventions to ensure the integrity of the pipeline is acceptable for the project.

As stated in Chapter 3, we are satisfied with the Proponents' climate change estimates used in the design. Given the uncertainty regarding climate change predictions, a prudent step would be to assess the design using upper limit temperature scenarios as recommended 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 the Proponents for the design of the project. Condition 6 requires the Proponents to submit a report which includes an analysis of the impacts of climate change and variability on permafrost and terrain stability for a series of representative locations and conditions using potential upper limit temperature scenarios which may occur along the pipeline. The analysis is to include potential impact on slope and water course crossing design. We have not specified how the study should be structured. We are of the view that, as part of this study, government departments such as Environment Canada, Indian and Northern Affairs Canada and Natural Resources Canada should be consulted to benefit from their expertise.


6.3.4-System design and configuration

To accomplish the stated project objective of delivering natural gas and natural gas liquids from the Mackenzie Delta to existing pipeline infrastructure in Alberta, the Proponents proposed a system of gas and liquids gathering pipelines, station facilities and a large diameter natural gas transmission pipeline. The proposed Mackenzie Gathering System will transport both natural gas and liquids from the anchor fields to the Inuvik Area Facility where receipts will be measured, separated and prepared for transmission south to interconnections with existing pipeline infrastructure. The separated natural gas liquids will be transported to Norman Wells in a dedicated liquids line while natural gas will be compressed and shipped south to an interconnection in Alberta via the Mackenzie Valley Pipeline.

A primary consideration of the system design is selecting an initial system capacity that meets the requirements for immediate hydrocarbon transportation commitments and takes into account requirements for future gas and liquid shipments. The final system design will specify the combination of pipeline diameter, fluid composition, temperature and pressure selected to achieve the desired system capacity. These parameters in turn are used to determine the pipeline materials that will be necessary. The throughput capacity of an existing pipeline can be increased by adding pumps, compressors or pipeline loops during the lifespan of the project.

Figure 6-4 Mackenzie Gathering System

Figure 6-4 Mackenzie Gathering System

On the record

Design considerations

When designing the Mackenzie Gathering System, the Proponents considered:

  • historical and existing pipeline routes;
  • potential locations for gas processing;
  • total costs over the life of the project;
  • potential locations of dehydration facilities;
  • minimization of the environmental footprint;
  • existing infrastructure; above-ground and buried pipeline alternatives;
  • input from community consultation;
  • field delivery pressures; delivery pressures entering the gas processing facility;
  • accommodation for gas volumes from 24 Mm³day (.85Bcf/d) to 34 Mm³day (1.2 Bcf/d);
  • pipeline operating temperatures in permafrost;
  • pipe sizes from NPS 12 to 36 (DN 300 to 900); and
  • pipeline material grades up to 483 MPa (X70).

Figures 6-4 and 6-5 illustrate the proposed configuration of the Mackenzie Gathering System and Mackenzie Valley Pipeline, described in greater detail in the following sections. The Proponents submitted that the proposed Mackenzie Gas Project system is expandable through the addition of laterals and facilities on the Mackenzie Gathering System and the addition of up to 11 compressor stations along the Mackenzie Valley Pipeline.

Design of the Mackenzie Gathering System

The Mackenzie Gathering System includes:

  • approximately 190 kilometres of NPS 16, 18, 26 and 32 (DN 400, 450, 650 and 800) gathering pipelines to transport production
  • from the Niglintgak, Taglu and Parsons Lake natural gas fields (development fields) and the volumes committed by MGM Energy Corp. to the Inuvik Area Facility;
  • the Inuvik Area Facility, which would process the gas produced;
  • an approximately 457-kilometre long NPS 10 (DN 250) pipeline to transport natural gas liquids from the Inuvik Area Facility to Norman Wells; and
  • block valves, pigging facilities, and meter stations for the gathering pipelines and the natural gas liquids pipeline.

The Mackenzie Gathering System would have the capacity to deliver about 30.9 Mm³/d (1.1 Bcf/d) of natural gas to the Mackenzie Valley Pipeline and to transport about 4000 m³/d (25,200 Bbl/d) of natural gas liquids from the Inuvik Area Facility to Norman Wells. The approximate capital cost of the Mackenzie Gathering System is $3.5 billion (2006$). It is scheduled to be in service in 2018.

Mackenzie Gathering System – upstream gathering pipelines

The gathering pipelines upstream of the Inuvik Area Facility (Figure 6-6) consist of:

  • the NPS 16 (DN 400) Niglintgak lateral which extends 14.7 kilometres from the outlet of the Niglintgak gas conditioning facility to the Taglu gas conditioning facility with a design pressure of 12.9 MPa (1,870 psi);
  • the NPS 26 (DN 650) Taglu lateral which extends 80.9 kilometres from the Taglu gas conditioning facility to the Storm Hills pigging facility with a design pressure of 12.2 MPa (1,770 psi);
  • the NPS 18 (DN 450) Parsons Lake lateral which extends 26.4 kilometres from the Parsons Lake gas conditioning facility to the Storm Hills pigging facility with a design pressure of 12.2 MPa (1,770 psi); and
  • the NPS 32 (DN 800) Storm Hills lateral which extends 67.2 kilometres from the Storm Hills pigging facility to the Inuvik Area Facility with a design pressure of 12.2 MPa (1,770 psi).

The design of the upstream gathering pipelines is based on natural gas production volumes from the three development fields and other potential sources in the Mackenzie Delta. The natural gas and natural gas liquids mixture would be dehydrated at the development fields and shipped to the Inuvik Area Facility for processing in lateral pipelines designed for two phase flow. The upstream gathering pipelines are designed to carry volumes of up to 30.9 Mm³/day (1.1 Bcf/d) in the summer. This could be expanded by looping portions of the lateral pipelines or by adding new laterals, additional compression or liquid handling facilities.

Mackenzie Gathering System – natural gas liquids pipeline

The Proponents determined that the best design for the pipelines south of the Inuvik Area Facility would be to use two single-phase pipelines. One pipeline would be for natural gas, as discussed in following sections, and the other would be for the natural gas liquids. The Proponents chose a buried NPS 10 (DN 250), Grade 359 (X52) pipe with a wall thickness of 7.8 millimetres and a maximum operating pressure of 9.93 MPa (1440 psi) for the liquids pipeline. The 457.2-kilometre


long natural gas liquids pipeline would terminate at the Enbridge Pipelines (NW) Inc. pump station in Norman Wells where a pig receiver and block valve would be installed. No pump stations would be required between the Inuvik Area Facility and Norman Wells for the initial operation. The line's initial capacity would be about 4000 m³day (25,200 Bbl/d), which could be increased to about 6700 m³day (42,150 Bbl/d) with two additional pump stations. From Norman Wells, the liquids would be carried further south in batches by the existing Enbridge Pipelines (NW) Inc. Norman Wells Pipeline.

Capacity and expansion of the Mackenzie Gathering System

During the hearing, intervenors questioned the design capacity of the upstream gathering pipelines and how it could be increased. However, no intervenors questioned the design adequacy of the natural gas liquids pipeline or its ability to transport present and future volumes of liquids.

Mackenzie Explorer Group expressed the view that the most likely expansion of the two phase design proposed by the Proponents would be through looping. Mackenzie Explorer Group believes this would probably not be the most cost effective approach especially if new natural gas production comes on line in small increments.

Mackenzie Explorer Group presented evidence which indicated that the nominal capacity of the system would be 30.4 Mm³day (1,075 MMcf/d). This would leave 8.65 Mm³day (305 MMcf/d) of available, non-contracted capacity of which 5.1 Mm³day (180 MMcf/d) is available at Taglu and the remainder is available south of the Storm Hills pigging facility. Mackenzie Explorer Group stated that the design philosophy upstream of the Inuvik Area Facility did not match the downstream design philosophy. Mackenzie Explorer Group noted in its evidence that while the upstream gathering pipelines had a maximum capacity of 30.4 Mm³day (1,075 MMcf/d), the Mackenzie Valley Pipeline could be expanded to 48 Mm³day (1,695 MMcf/d).

The Proponents and Mackenzie Explorer Group members Chevron Canada Resources and BP Canada Energy Company undertook a joint effort to evaluate alternatives that could increase the capacity on the gathering system north of the Inuvik Area Facility for new natural gas discoveries. Based on this study, Mackenzie Explorer Group supports an option that requires upgraded pipe and components to be pre-installed for future expandability. The Proponents estimated the cost of this pre- installation would be an additional $142 million.

In argument the Mackenzie Explorer Group expressed the view that the higher-pressure design of the two-phase system is superior in terms of total unit of capacity cost, avoiding lumpiness of expansion and minimizing incremental environmental impact.

On the record

Expansion study

For the purposes of the joint Mackenzie Explorers Group/Proponents study, it was assumed there would be three 7.1 Mm³day (~250 MMcf/d) expansions north of the Inuvik Area Facility and the fully expanded Mackenzie Gathering System would match the Mackenzie Valley Pipeline's capacity. The study did not consider the potential for gas entering the Mackenzie Valley Pipeline downstream of Inuvik which would use available Mackenzie Valley Pipeline expansion capacity at Inuvik.

The joint Mackenzie Explorers Group/Proponents study submitted by Mackenzie Explorers Group identified seven alternative designs for the gathering pipelines and two alternative designs for the Inuvik Area Facility. Of the seven pipeline alternatives, three allowed for expansion to match the capability of the Mackenzie Valley Pipeline. These alternatives are: installing NPS 36 (DN 900) pipelines between Taglu and the Inuvik Area Facility; increasing the operating pressure of the gathering pipelines to 18 MPa (2,610 psi) to match the design of the Mackenzie Valley Pipeline; and constructing a separate or looped pipeline. Of the three, Mackenzie Explorers Group favoured the 18 MPa (2,610 psi) design option requiring upgraded pipe and components to be pre-installed. As the pressure in the gathering pipelines increases to accommodate new volumes, additional compression would be required at each existing field for the natural gas and natural gas liquids to flow into the upstream gathering system.


Did you know?

Definitions

Batches - quantities of oil/oil products or condensate with particular properties owned by a particular shipper and transported in a pipeline between other batches.

Block valve - a valve that can completely block the flow in a pipeline in both directions.

Dense phase pipeline - under certain conditions of pressure and temperature natural gas liquids and natural gas can be transported in a pipeline in a single phase, referred to as dense phase, which has properties between those of a gas and a liquid. Dense phase pipelines may have higher wall thickness which makes them more resistant to bending stresses.

Lateral - a pipeline that connects a new supply or a new market to the main pipeline.

Looping - expansion of pipeline capacity by building another pipeline adjacent to the existing pipeline.

Mass flow rate - mass of fluid transported by the pipeline over a period of time.

Nominal capacity - the capacity that is available year round and is determined by using historical ambient temperatures in the warmest month (July) since pipeline capacity increases with decreasing air temperature due to the increased driver power of the gas turbines at cooler ambient temperatures.

Pig receiver - a piping arrangement that allows inline tools (pigs) to be removed from a pipeline without stopping the flow of the pipeline.

Pipe grade - the specified minimum yield strength of the steel used in making the pipe, typically expressed in mega Pascals (MPa).

Single phase pipeline - a pipeline that conveys either a liquid or gas but not both at the same time.

Slug catcher - a piping arrangement used in two phase pipelines to separate liquids from gas in the pipeline before it can enter a gas compressor.

Two phase pipeline - a pipeline that conveys both liquid and gas at the same time.

  • The Proponents rejected the assumption that the ultimate capacity of the Mackenzie Gathering System needed to match the ultimate capacity of the Mackenzie Valley Pipeline. The Proponents pointed to the possibility that gas could enter the Mackenzie Valley Pipeline at locations south of Inuvik from the Colville Hills. The Gilbert Laustsen and Jung Associates supply study forecasted that Colville Hills production could exceed 8.5 Mm³d (300 MMcf/d). The Proponents noted that MGM Energy Corp. had requested 5.7 Mm³d (200 MMcf/d) of capacity over the 23.5 Mm³d (830 MMcf/d) used by the Proponents which left 1.3 Mm³d (45 MMcf/d) of capacity for other shippers. The Proponents noted that another 10.6 Mm³d (375 MMcf/d) of capacity could be added with the construction of a compressor station at Storm Hills. The Proponents also stated that the capacity of the upstream gathering system could be further expanded by looping.

Design of the Mackenzie Valley Pipeline The Mackenzie Valley Pipeline includes:

  • approximately 1196 kilometres of NPS 30 (DN 750) pipeline from the Inuvik Area Facility to a point of interconnection with the NOVA Gas Transmission Ltd. system just south of the Alberta-Northwest Territories boundary;
  • three compressor stations, one at Great Bear River to be installed initially and two others at Loon River North and River Between Two Mountains to be installed when additional shipping commitments are received;
  • the Trout Lake heater station to be installed when additional shipping commitments are received;
  • a meter station located at the Inuvik Area Facility; and
  • a pig receiver and block valve just south of the Alberta-Northwest Territories boundary.

The Mackenzie Valley Pipeline has a design capacity of 27.3 Mm³d (0.96 Bcf) with one compressor station and 34.3 Mm³d (1.2 Bcf) with three compressors and heater station in operation. The capacity could be expanded to 49.8 Mm³d (1.8 Bcf/d) with a total of 14 compressor stations (see Figure 6-5). Only three compressor stations are included in the applications before us. The Mackenzie Valley Pipeline is scheduled to be in service in 2018.

The design selection of the Mackenzie Valley Pipeline was affected by several factors including:

  • gas composition;
  • operating temperatures in continuous and discontinuous permafrost;
  • initial and future volumes; and
  • the potential location of station facilities along the route.

The Proponents evaluated three potential design concepts for the Mackenzie Valley Pipeline: a dense phase design, a two phase design and a single phase design. The criteria used to evaluate the designs included:

  • flexibility with respect to changes in volume and gas composition caused by potential changes in supply;
  • costs over the life of the project;
  • constructability; and operability.

Figure 6-5 Mackenzie Valley Pipeline design capacity

Figure 6-5 Mackenzie Valley Pipeline design capacity

The Proponents selected a single phase pipeline with a maximum operating pressure of 18.7 MPa (2,710 psi) for the Mackenzie Valley Pipeline. This design was described by the Proponents to best accommodate potential variation and uncertainty in gas volumes, composition, timing and location. Cited advantages of the single phase, high pressure design include lower lifespan costs, simpler facilities and a more flexible operation. Most of the pipe would have a wall thickness of 16.2 millimetres while locations with the potential for higher external loads, such as road crossings and watercourse crossings, would have a wall thickness of 21.6 millimetres. The design parameters are shown in Table 6-3.

Table 6-3 Mackenzie Valley Pipeline design parameters

Pipe type NPS 30
(DN 750)
Line pipe
NPS 30 (DN 750)
Heavy wall pipe
Grade 550 MPa
(X80)
550 MPa
(X80)
Wall thickness 16.2 mm 21.6 mm
Design pressure 18.7 MPa
(2,710 psi)
18.7 MPa
(2,710 psi)
Estimated quantity 1185 km 19 km

The applied-for design includes three compressor stations and a heater station capable of delivering 34.3 Mm³d (1.2 Bcf/d) of natural gas in the summer and 38.4 Mm³d (1.35 Bcf/d) in the winter.


On the record

Dense phase, two phase and single phase designs

The Proponents considered a dense phase design where the operating pressures would be increased so the natural gas and natural gas liquids would behave as a single fluid. This concept would result in smaller pipe sizes and fewer compressor stations and would potentially eliminate the need for the natural gas liquids line. The Proponents found that operating pressures of about 40 MPa (5,800 psi) would be required to operate in a dense phase. At pressures less than this, natural gas liquids would be present. The Proponents estimated that it would be necessary to store, sell or dispose of approximately 150 m³day (940 Bbl/d) of liquids along the pipeline route, which would be impractical. Also, a processing plant would be required at the end of the Mackenzie Valley Pipeline to remove the liquids from the gas in order to meet downstream gas pipeline specifications. The Proponents chose not to use this design because its operation would be sensitive to gas composition, the presence of liquids at all but the highest operating pressures would increase the need for processing facilities, and the very high operating pressures would increase costs.

In a two phase pipeline, liquids and gas are shipped together. While a two phase pipeline can operate at pressures similar to a single phase pipeline, the liquids must be separated from the gas at compressor stations to prevent them from damaging the compressors. This requires the addition of slug catchers and pumps at each station to collect the liquids and re-inject the liquids into the pipeline after the gas is compressed. The Proponents rejected this design because it was less flexible than a single phase design.

With a single phase pipeline, liquids are separated from the gas and either trucked, flared, re-injected or shipped in a separate pipeline. The Proponents indicated that it selected the single phase gas pipeline option with a separate liquids pipeline because it best accommodated the potential variability between initial and future gas composition, had lower costs over the life of the project, required simpler facilities and allowed for more flexible operation.

Mackenzie Valley Pipeline expansion

No intervenors questioned the adequacy of the design of the Mackenzie Valley Pipeline or its ability to transport present and future volumes of gas. However, there were questions about the initial capacity of the pipeline, how it would be expanded in the future and the design implications of a phased expansion on the thermal regime of the pipeline route.

The development field owners have contracted for 23.5 Mm³day (0.83 Bcf/d) of the initial pipeline capacity and the remaining capacity of approximately 11 Mm³day (0.39 Bcf/d) is available for contracting. With one compressor station in operation near the Great Bear River, the pipeline is capable of delivering all the initial contracted capacity.

The approximate capital cost of the Mackenzie Valley Pipeline is $7,050 million (2006$) with one compressor station at the Great Bear River. The Loon River North and River Between Two Mountains compressor stations and the Trout Lake heater station would add approximately $800 million to the capital cost. While the Proponents have applied for approval of all of these facilities, they plan to delay construction of two of the three compressors and the heater station until the remaining capacity is contracted for.

The addition of 11 more compressor stations on the Mackenzie Valley Pipeline could increase the nominal capacity to about 49.8 Mm³day (1.8 Bcf/d). The Proponents have not applied for

approval for these 11 compressor stations in the applications before us.

Design of station facilities

The applied-for station facilities for the Mackenzie Gas Project include:

  • receipt metering facilities at each of the development fields where natural gas and natural gas liquids would be metered separately;
  • a pigging facility at the junction of the Taglu and Parsons Lake laterals (Storm Hills) consisting of pig receivers and launchers that could be remotely operated from the main control centre;
  • the Inuvik Area Facility which would remove natural gas liquids to meet the inlet gas specifications for the Mackenzie Valley Pipeline and natural gas liquids pipelines;
  • natural gas liquids and natural gas metering facilities located within the Inuvik Area Facility site;
  • compressors to deliver natural gas to the Mackenzie Valley Pipeline and pumps to deliver natural gas liquids to the natural gas liquids pipeline also located within the Inuvik Area Facility site;
  • three natural gas compressor stations near Fort Good Hope (Loon River North), the Great Bear River and the River Between Two Mountains; and
  • a heater station near Trout River to maintain the pipeline operating temperature within the design limits.

The Proponents state that Mackenzie Gas Project station facilities would be designed to Canadian Standards Association Z662, Oil and Gas Pipeline Systems with the exception of the Inuvik Area Facility which would be designed to American Society of Mechanical Engineers Code B31.3.

At the Inuvik Area Facility, the natural gas and natural gas liquids delivered by the upstream gathering pipelines must be separated and processed to meet the inlet gas specifications for the pipelines. The natural gas liquids contain components which vaporize when stored in a conventional oil storage tank. To make it easier to transport natural gas liquids in a pipeline, the unstable components would be removed at the Inuvik Area Facility in a process called stabilization. The removed

 

On the record

Design considerations

After determining that a single phase pipeline was the best design concept for the project, the Proponents considered the following factors:

  • historical and existing pipeline routes;
  • total costs over the life of the project;
  • operating temperatures in continuous and discontinuous permafrost;
  • volumes from 24 Mm³day to 56 Mm³day (0.8 Bcf/d to 2 Bcf/d);
  • facility locations along the route;
  • initial shipper requirements and potential future expansion;
  • input from community consultation; and
  • minimizing footprint by using existing infrastructure.

components would later be re-injected into the Mackenzie Valley Pipeline. The Inuvik Area Facility would use a flare system to burn gaseous streams produced during operational upsets. The design and performance standards would be consistent with Alberta's Energy and Utilities Board Guide G-40.

The natural gas would be compressed by two centrifugal compressors located within the Inuvik Area Facility. These compressors would be driven by two ISO 30 MW gas turbines fuelled by natural gas sourced from within the facility. The compressed natural gas would be cooled using aerial coolers and gas-to-gas heat exchangers. The gas turbines would be commercially available, dry, low nitrogen oxide units. The compressors would be manufactured according to American Petroleum Institute Standard 617. All compressor stations would have a design pressure of 19.8 MPa (2,870 psi) to allow for the maximum discharge pressure of the Mackenzie Valley Pipeline. Primary power production for the compressor stations would be generated by natural gas-fuelled reciprocating engines. Diesel reciprocating engines would be used for standby emergency power generation.

Although not required initially, the Trout River heater station would eventually be needed to maintain pipeline operating temperatures within the design limits established for the three compressor station configuration. The Proponents' preferred design option is to use

indirect-fired bath heaters fuelled by pipeline gas. The heater station would be designed for remote operation, with maintenance staff being flown to the station by helicopter. The facility would be designed to operate at a pressure of 19.8 MPa (2,870 psi). Natural gas-fuelled reciprocating engines would be used for primary power production at the heater station. Reciprocating engines would also be used for standby emergency power generation and would be fuelled by diesel.

The Proponents indicated they would select engines with a proven low-emission design and would meet or exceed Alberta Environment's Code of Practice for Compressor and Pumping Stations and Sweet Gas Processing Plants, 1996, which specifies maximum nitrogen oxide emissions of 6 g/kWh for engines over 600 kW.

On the record

Location of the Inuvik Area Facility

During the early stages of engineering design, the Proponents had planned to locate the Inuvik Area Facility 16 kilometres to the north of its currently applied-for location. The Proponents submitted that the new location is flatter, requires less imported gravel for the facility and shortens the access road by 14 kilometres. Early design work had established a requirement that all pipeline segments in the continuous permafrost zone should have a constant pipeline inlet gas temperature of -1°C to prevent thawing. To meet this operating requirement, the Inuvik Area Facility needed gas refrigeration units. At the new location of the Inuvik Area Facility, the Proponents found there was little evidence of thaw sensitive soils for some distance downstream. As part of this design refinement, the Proponents investigated the possibility of replacing the gas refrigeration units with heat exchangers which would cool the gas using the surrounding air.

Because of the low temperatures of the product entering the Inuvik Area Facility and the relatively low summertime air temperatures, the Proponents found that without the refrigeration units the Inuvik Area Facility could discharge gas at about 3°C in the summer and at or below 0°C the rest of the year. This would result in approximately 0.3 m of thaw settlement on the right of way at the outlet of the Inuvik Area Facility, decreasing to zero settlement 50 kilometres downstream of the Inuvik Area Facility.


Views of the Board

We are of the view that the system design undertaken by the Proponents for the single phase gas pipeline and the natural gas liquids line between the Inuvik Area Facility and Norman Wells is consistent with good design practice and provides sufficient expansion capability for future volumes. We are also of the view that there is uncertainty in regards to volume, composition, timing and location of future gas supplies. Because of this uncertainty, we do not share the view of Mackenzie Explorer Group that pre-investing in heavy wall pipe and other facilities to permit a future increase in operating pressure is warranted for the two-phase gathering system. We note that in the event that new capacity is required from the Mackenzie Delta, the option to construct compression facilities at Storm Hills is a viable potential alternative to looping. It also has the advantage of not requiring changes to compressor facilities at other receipt points.

6.4 Specific design issues

6.4.1 Overview

Specific issues arose as a result of the project's location in a northern environment and on the proposed engineering design approach. Our focus in the hearing was to ensure that the facilities could be designed and operated in a safe and environmentally responsible manner, while maintaining system reliability.

6.4.2 Geohazards

Geohazards are naturally occurring or project-induced geological, geotechnical, geothermal or hydrological phenomena that could lead to pipeline or other component failure, causing adverse environmental impacts, or that could affect the right of way, causing environmental concerns.

The Proponents indicated that the principal geohazards to the project are well known from the previous studies and projects in the Mackenzie Valley. The Proponents were of the view that the initial consideration of geohazards did not require detailed information on the location or the quantification of risk associated with each specific geohazard occurrence. During the conceptual and preliminary design the Proponents used route selection approaches to avoid potentially difficult terrain and unstable slopes. The Proponents indicated that credible worst case scenarios had been used to develop conservative estimates of the effects of geohazards on the pipelines, pipeline ditch or pipeline right of way. These estimates were

used to develop a pipeline design that was relatively insensitive to ground conditions along the route, thus reducing the need for very detailed and precise data (i.e., the pipe wall thickness for overland portions of each pipeline is predominately one thickness). A monitoring and mitigation tool box was developed to address geohazards during construction and operation.

The Proponents stated that a more formalized geohazard assessment approach would be beneficial for the detailed design phase in terms of systematically organizing available information on geohazards, verifying preliminary design assumptions, and obtaining information about the distribution and potential effects of various individual and combined geohazards along the pipeline route.

The Proponents plan a three-phased approach consisting of: a geohazard inventory and assessment using terrain mapping and LiDAR; a field geotechnical program and detailed design engineering to develop mitigation; and a construction and operations monitoring phase where expected conditions would be further verified during ditch excavation and later upgraded based on in-line inspection and monitoring of the right of way.

In order to assess the geohazards which act alone or in combinations the Proponents propose to use a semi-quantitative index based approach to rank the susceptibility of individual geohazards along the route. As part of this approach the values and rankings associated


with each geohazard would be based on expert judgment. To facilitate the assessment of possible combined geohazards the route would be segmented based on the extent of each individual geohazard.

In undertaking their geohazard assessment the Proponents would consider only those geohazards within the pipeline corridor that may directly affect the pipe, the pipeline ditch, or the right of way. The Proponents referred to these as “credible probable geohazards.” The Proponents identified 31 geohazards which could result from:

  • the freezing of unfrozen ground;
  • the thawing of permafrost terrain;
  • landslides impacting the right of way;
  • tectonics/seismicity;
  • watercourse hydraulics resulting in exposed pipe;
  • erosion;
  • geochemical concerns such as the occurrence of acid-generating rock; and
  • soil structure issues such as the presence of large rocks which could damage the pipe.

The Proponents are of the view that these naturally occurring or project-induced geohazards could load the pipeline causing a pipeline integrity concern, could affect the pipeline or ditch causing an operational concern, or could affect the right of way causing an environmental concern. The Proponents assembled a Senior Advisory Team consisting of four external experts experienced in northern engineering and pipeline design to evaluate its proposed approach and made modifications in response to the comments received.

A workshop was held in Calgary on 10 and 11 July 2006 where the Proponents, the Senior Advisory Team and staff from Indian and Northern Affairs Canada and Natural Resources Canada met and discussed the Proponents' semi-quantitative geohazard assessment approach. Following the July workshop four more geohazards were identified by the Proponents. The results of these workshops were submitted in our hearing.

Indian and Northern Affairs Canada indicated that the success of any geohazard risk assessment will depend on the adequacy of the database and acknowledged the Proponents' efforts at organizing existing data and its preparations to accommodate anticipated data in a geographic information system. Indian and Northern Affairs Canada was of the view that the geohazard list was adequate for the preliminary stage of the assessment and that the Proponents' work may benefit from broader input by geoscientists with northern mapping experience. Indian and Northern Affairs Canada indicated that it was not possible to fully assess the Proponents' methodology at the July meeting because much of the presentation was conceptual. Indian and Northern Affairs Canada noted that the assessment approach outlined was adequately structured and in conformity with other semi-quantitative methodologies described in the literature but that in its view significant challenges remain. Indian and Northern Affairs Canada cautioned that

On the record

Inuvik Area Facility, compressor stations and heater station equipment

The Inuvik Area Facility includes:

  • a liquid slug catcher;
  • liquid stabilization;
  • pumping and storage facilities;
  • residue gas processing and compression equipment;
  • propane refrigerant equipment;
  • safety and control systems; and
  • utility systems.

Liquid processing and storage equipment includes:

  • stabilizer and associated equipment;
  • heat exchangers;
  • aerial coolers;
  • pumps;
  • storage tanks; and
  • a pressure vessel.

The liquid storage in the Inuvik Area Facility would be protected by a foam-based fire protection system and the tank farm would be designed to meet Alberta's Energy Resources Conservation Board's Guide G-55 requirements. The tanks would be constructed within a bermed containment area with an impermeable liner.

The three downstream compressor stations would all contain similar equipment, including:

  • pipe and pipeline components such as mainline block valve assemblies;
  • pig launcher and receiver;
  • inlet scrubber;
  • gas turbine compressor package;
  • aerial coolers;
  • gas-to-gas heat exchangers;
  • utility gas equipment;
  • fuel gas equipment; station power generating equipment;
  • controls and communication equipment; and
  • safety equipment.

The centrifugal compressor at each of the compressor stations would be driven by an ISO 15 MW gas turbine fuelled by natural gas sourced from the pipeline. The gas turbines would be commercially available, dry low nitrous oxide units. The compressor units would be manufactured according to API Standard 617.

Equipment at the heater station site includes:

  • line heaters;
  • fuel gas and metering equipment;
  • glycol storage tanks;
  • electrical power generating equipment;
  • controls and communication equipment; and
  • safety equipment.

As noted above, the heater station piping would comply with Canadian Standards Association Z662, Oil and Gas Pipeline Systems; however, the line heaters would be designed and manufactured in accordance with American Society of Mechanical Engineers Boiler and Pressure Vessel Code, Section VIII, Division 1, as permitted by Canadian Standards Association Z662.

a semi-quantitative approach, such as the one adopted by the Proponents could “easily stray from good science regardless of the best intentions of those involved” and that the individual geohazard scores obtained from the Proponents' methodology would be difficult to compare and sum, and thus integrate into risk assessment.

The Proponents are of the view that their semi-quantitative index-based geohazard assessment approach allows geohazards to be identified and ranked in terms of the associated susceptibility (i.e., high, medium, low, very low, or negligible) relative to specific pipeline elements. The Proponents stated that the spatial distribution and sorting of individual and combined geohazards by susceptibility provides sufficiently detailed information to guide decisions regarding design, field activities, specialized engineering analysis and testing, operations monitoring and operations mitigation maintenance. The Proponents characterized their approach as adaptable and well-suited to the abundance of regional data available to the project. The Proponents also noted that their approach allowed for more site specific information to be incorporated into it as the project progresses.

The Proponents stated that a quantitative risk assessment for all geohazards was neither required at the preliminary engineering stage of project nor meaningful, given the lack of site-specific information required to support the engineering judgment of probabilities required in a quantitative approach. The Proponents indicated that during operations, integrity management decisions for specific locations might be suited to the quantitative or probabilistic site-specific treatment of geohazards.

Indian and Northern Affairs Canada suggested that the geohazard risk assessment should be conducted using a quantitative risk assessment approach on a segment-by-segment basis and that the preferable approach would be a geohazard risk assessment which examined every segment of the pipeline route. Indian and Northern Affairs Canada was of the view that the segments should be small. Indian and Northern Affairs Canada stated that in the least, the assessment should include a relative risk rating and analyses of geohazards acting in combination where applicable. Indian and Northern Affairs Canada was of the view that we should consider a condition specifically listing the geohazards and specific combinations of geohazards which the Proponents would be required to analyze.

Views of the Board

We note that there was general agreement that a geohazard assessment of the project would be beneficial in providing useful information for the detailed design and the implementation of geohazard mitigation during construction. There was disagreement however on whether the semi-quantitative approach described by the Proponents is adequate or whether the quantitative approach suggested by Indian and Northern Affairs Canada is required. Both require a significant level of expertise to implement.

We are satisfied that the semi-quantitative geohazard approach described by the Proponents is a suitable design tool for the detailed design phase of the project. Therefore we will not require the Proponents to undertake a quantitative geohazard assessment. Condition 45 requires the Proponents to file a geohazard assessment of the project prior to pipe-laying operations. This report shall:

  • detail its geohazard assessment methodology and the specific and combined geohazards identified along the route;
  • describe specific measures to be implemented to mitigate individual and combined geohazards;
  • provide decision criteria for implementation of mitigation for geohazards identified during construction;

  • outline the qualifications of the staff making decisions regarding design and implementation; and
  • outline the ongoing monitoring requirements for geohazards identified during the detailed design and construction phases.

6.4.3-Pipeline operating temperatures

The operating temperature of a pipeline is an important design consideration as heat is exchanged between the pipeline and the surrounding ground. The difference in temperature of the pipeline compared to the surrounding ground could result in a change of temperature in the ground around the pipeline as well as how the surrounding ground exchanges heat with the atmosphere (the thermal regime). In permafrost environments the structural and physiographic properties of the ground are dependent on the thermal regime. A change in ground temperature could cause the formation of a frost or thaw bulb around the pipeline, a change in the depth of the active layer or a change in the timing of active layer freeze-thaw cycles, resulting in loading and, in some cases, deformation of the pipe.

Did you know?

Joule-Thompson effect

As natural gas moves downstream in a pipeline, energy is lost mostly due to friction and this causes a drop in pressure. When pressure decreases the gas expands and the temperature of the natural gas. decreases The decrease in temperature is referred to as the Joule-Thompson effect.

Mackenzie Gathering System – upstream gathering pipelines

The Proponents stated that the gathering pipelines north of the Inuvik Area Facility would be operated cold since they are located in continuous permafrost. These pipelines would be subject to frost heave where unfrozen pockets of ground referred to as taliks occur. The Proponents indicated that design mitigation would be used as required on a site-specific basis to limit the strain demand on the gathering pipelines to below 0.5 percent, so that common line pipes that comply with Canadian Standards Association Z245.1, Steel Pipe, can be used.

Mackenzie Gathering System – natural gas liquids pipeline

The temperature of a liquids pipeline is affected by the mass flow rate and the transfer of heat between the pipe and the soil. The Proponents determined that since the mass flow rate in the natural gas liquids pipeline is low, the pipe temperature would be close to the soil temperature anywhere along the pipeline. Natural gas liquids entering the liquids pipeline from the Inuvik Area Facility would be designed to have a constant inlet temperature of -1°C. The Proponents stated operating temperature guidelines are based on the criteria that the average annual temperature will not increase long-term thaw of the right of way compared to the effects of just clearing without pipeline operation.

Mackenzie Valley Pipeline The Proponents indicated that they intend to limit the compressor station discharge temperature to ensure that the pipeline temperature does not cause long-term thawing of the permafrost beyond that caused by clearing the right of way. The Proponents selected an average annual station discharge temperature of -1°C in continuous permafrost areas. Figure 6-6 shows the expected temperature profiles at different times of year for the one compressor station configuration and the three compressor stations plus a heater station configuration.

In their May 2007 updated evidence the Proponents indicated that the Mackenzie Valley Pipeline would begin operation with only one compressor station between the Inuvik Area Facility and the Alberta border, at Great Bear River. The full potential capacity of the Mackenzie Valley Pipeline could be reached in the future with a total of 14 compressor stations in operation. Figure 6-7 shows the different temperature profiles for the Mackenzie Valley Pipeline with different compressor arrangements. The variation in the temperature profile with added compressor stations is a consideration in the overall design of the pipeline. Areas which would begin operation with average pipeline temperatures well below 0°C could operate with temperatures above 0°C in the fully expanded case. For example, near kilometre 400, the annual average temperature with one station operating would be about -6°C but with 14 stations operating the annual average temperature would be 2°C.


To monitor the effects of changes in ground temperature on the pipeline, the Proponents stated that ground temperatures would be monitored with thermistors and pipeline strain would be monitored with high resolution in-line inspection tools (such as the Geopig®). The Proponents discussed several mitigation measures against thermally induced pipeline deformation including the use of heavy wall pipe, thermosiphons, pipe insulation, reduced pipe cover, and backfill of the trench with non frost-susceptible soils at locations of high frost heave and thaw settlement potential.

Views of the Board

The pipeline operating temperatures for the gas pipeline are significantly influenced by the system configuration. We are of the view that the Proponents' approach of developing a pipeline design which is relatively insensitive to pre-existing ground conditions is prudent. Nevertheless, we have added requirements to Conditions 46, 48 and 51 for further assessments of the potential impact of changing pipe operating temperatures associated with increases in compressor stations. Monitoring of pipeline strain will be important to maintaining pipeline integrity. Conditions regarding monitoring are discussed in Section 6.6.

Figure 6-6 Temperature profiles for configurations with one and three compressor stations

Figure 6-6 Temperature profiles for configurations with one and three compressor stations

Figure 6-7 Temperature profiles for various compressor configurations

Figure 6-7 Temperature profiles for various compressor configurations

6.4.4 Pipeline materials

The Proponents' approach to pipeline design for the project, as discussed in Section 6.3, includes using a strain-based design methodology for secondary loads such as ground movement. The Proponents would then use monitoring during operation to identify locations where loads are accumulating, and would intervene to repair or maintain the pipe at these locations. The materials selected for the project must be suitable for strain-based design and operation at high pressures in an environment with limited seasonal access for pipeline repair and maintenance. The materials must also be able to withstand cold temperatures during construction and potentially high external loads.

The line pipe, components and plant-applied external coating would be designed and manufactured in accordance with the Canadian Standards Association Z245 series requirements. Line pipe specifications are shown in Table 6-4. Qualified suppliers would be selected to produce the pipe and apply external coating in accordance with the Canadian Standards Association Z245.1 and Z245.20/Z245.21, and the Proponents' specification and quality assurance program.

Table 6-4 Line pipe specifications

Parameter Manufacturing specifications
Pipe material Low carbon, high strength, low alloy steel
Steel grade 550 (X80)
Skelp (plate) Thermo-mechanically rolled
Welds Longitudinally or helically double submerged arc
Notch toughness 160 Joules

The Proponents performed ductile fracture arrest analysis using the Battelle method and conducted a full-scale burst test. Based on the results of the analysis and verification test the Proponents would specify a notch toughness of 160 Joules to provide for a positive ductile fracture arrest in the Mackenzie Valley Pipeline.

Pipeline components such as valves, fittings, flanges, and induction bends would be manufactured in accordance with Canadian Standards Association Z245.15, Z245.11, Z245.12, and the Proponents' specification and quality assurance program. Components would be of Grade 483 (X70), PN250 and Category II to provide sufficient strength and fracture resistance for reliable operation in the northern environment.

Views of the Board

The design specifications will require material properties able to meet the requirements for operation in cold temperatures at high pressures and subjected to secondary loads such as ground movement. We are of the view that the current piping manufacturing technology exists to enable the Proponents to select and test the appropriate piping materials to ensure they meet the design specifications. The Proponents have indicated that they will be using a quality control and assurance process to ensure that the piping materials will be selected, manufactured, tested, transported and installed to ensure they continually meet the design specifications. Condition 18 requires the filing of specifications, mill joining programs and project-specific quality assurance programs to facilitate National Energy Board audits. Condition 58 requires summary reports of non-compliances with design, materials and construction specifications and the disposition of these non-conformances.


6.4.5 Joining - welding and non-destructive examination

Individual pipe sections are factory manufactured using either longitudinal welding or spiral welding techniques. Sections of pipe are then joined together at the pipe mill or the project site by welding the circumference joint using girth welds. The factory and field welding procedures are critical to ensuring pipeline integrity. To ensure quality control the welds are tested using non-destructive examination techniques.

Did you know?

Definitions

Arc weld - a welding process where metal is joined by using a power supply to create an electric arc between a consumable electrode and the base metal to melt the metals.

Ductile fracture arrest - the ability of pipe, which fails in a ductile manner, to resist or arrest crack propagation.

Full-scale burst test - burst testing of sections pipe to validate material behaviour models, such as crack propagation.

Girth weld - the circumferential weld used to join two pipe joints together.

Helically double submerged weld - the welding process used to join spiral pipe; the pipe is manufactured from steel coils formed helically into cylinders.

Longitudinal weld - the weld used to join U and O formed pipe; the pipe is manufactured from steel coils or plate formed into a cylinder and then the length of the joint is welded.

Notch toughness - the ability of pipe steel to resist crack initiation and propagation.

Skelp - a piece or strip of metal produced to a specified thickness and width during the pipe manufacturing process.

The Proponents indicated that a combination of stress and strain-based design would be used on the pipeline portion of the project and a conventional stress-based design would be used for the station and facility construction. The specific components identified in the welding and non-destructive examination programs are related and form part of an overall joining program. The successful implementation of an effective joining program is necessary to provide the required weld quality.

Welding

Strain-based design calls for a higher degree of weld quality and more stringent mechanical properties than stress-based design. The integrity and strain bearing capacity of the weld and the area adjacent to the weld, known as the heat affected zone, are important factors. In addition to any flaws which may be introduced during the welding process, heat from this process may change the micro-structure of the parent metal adjacent to the welding material in the heat affected zone. This in turn may affect the strength and ductility of the original parent metal. Therefore, it is important that the welding procedure minimizes the potential for flaws and ensures any changes in the parent material properties are still within the design parameters. The welding procedure design should not only consider flaws and mechanical property requirements, but also balance the need for acceptable construction productivity in the challenging northern environment. Verification that a welding procedure can achieve the predicted and desired results is critical when the

project involves the use of unconventional design methods or state of the art joining techniques.

The Proponents have developed a framework for weld qualification requirements which they would use to develop final girth weld procedure specifications. The Proponents stated that all welding procedure specifications would meet Canadian Standards Association Z662, Oil and Gas Pipeline Systems requirements and any additional project-specific requirements.

The objective for the Proponents' strategy for developing welding procedures for the project is to achieve weld properties critical to a strain-based design. These welding procedures relate to:

  • weld strength overmatch;
  • appropriate consumable selection;
  • bevel design; and
  • the appropriate welding process selection.

The Proponents indicated that all circumferential field and pipe mill welds would be required to meet the same weld performance criteria, based on their intended application in either a stress or strain-based design. The identified performance criteria include mechanical properties and maximum allowable flaw sizes. In addition, the Proponents indicated that the target weld overmatch yield strength value is five percent higher than the yield strength of the parent metal.

The Proponents indicated that they would use a combination of stress and strain-based design for all pipeline applications on the Mackenzie


Gas Project and a stress-based design for the Inuvik Area Facility, compressor station and the facility construction. The weld quality requirements for these two design approaches are different due to the different operating and loading regimes. The Proponents submitted that the Canadian Standards Association Z662 flaw acceptance criterion is very conservative and would be impractical to use on the strain-based design piping, due to the high cost associated with repairing defects which may have excess stress and strain capacity for the intended loading regime. Canadian Standards Association Z662 provides the option of using fracture mechanic principles to develop alternative acceptance criteria. Therefore, the Proponents developed a curved wide plate test program to perform large-scale proof testing to determine the critical flaw sizes for the various proposed pipe sizes and to verify the preliminary estimates of tensile strain capacity of the welds.

Under the curved wide plate test program, a total of 60 curved wide plate tests were performed on UOE (longitudinally welded pipe) and spiral welded pipe which had undergone a simulated coating heat treatment to represent the aged heat condition. The Proponents indicated that additional curved wide plate tests may be considered during detailed design to further enhance the design and to identify areas which could reduce construction costs. Some of the identified follow-up testing may include confirmation of weld procedure strain capacity and critical flaw size. In addition, the Proponents would consider additional

testing on buried flaws or interacting flaws to determine if the acceptable flaw criteria could be expanded to accommodate actual field production welding.

The Proponents stated that they are attempting to leverage new technology or process initiatives they are involved in. Welding related improvements contemplated on the project, such as dual torch metal arc weld or single torch tandem (dual wire) welding process, may enable the Proponents to find efficiencies during pipeline production and to complete more, higher quality welds in a shorter time frame.

Non-destructive examination

Once welding procedures and flaw acceptance criteria that meet the design requirements have been established, the next step is to choose a reliable method for identifying and fully characterizing any flaws. The weld inspection method must be able to non-destructively examine the finished weld to determine whether the weld integrity meets specified flaw acceptance criteria requirements. The chosen non-destructive examination technique must be proven to accurately characterize potential flaws in terms of vertical height, depth and circumferential location.

A solid understanding of the types of potential flaws associated with the welding process, and their anticipated size, location and orientation is required when choosing and proving the effectiveness of the non-destructive examination technique. In addition, knowledge of the potential weld flaw characteristics is also required

Did you know?

Testing of welds

Since the early 1980s considerable work has gone into testing and analysis to determine the tensile strain capacity of pipe and girth welds. The driver for this work was the potentially high strains associated with offshore piping installation and operation. A reliable means to analyze strain capacity of a pipeline weld and the associated heat affected zone was required because traditional fracture mechanics methods have not been fully validated for higher strain demands.

The mechanical properties required to achieve high tensile strain capacity in pipeline girth welds include weld metal yield strength overmatch (where the weld metal has higher strength properties than the parent metal) yield to tensile strength ratio and uniform elongation in both the pipe and weld metal and, in addition, adequate toughness in both the heat affected zone and the weld metal. Currently, the only method to obtain these properties accurately is through empirical testing with methods such as curved wide plate testing. The curved wide plate test (a large-scale tensile test of a piece of pipe which may include a girth weld) has been used within both the offshore and onshore pipeline industry to better represent actual pipe behaviour under strain conditions compared to transverse tensile testing.

when developing non-destructive examination procedures and related quality checks.

To aid in the preparation of a joining program, the Proponents developed a non-destructive examination strategy framework to inspect the estimated 80,000 circumferential girth and facility welds. The main purpose of the non-destructive examination strategy is to identify any flaws in the weld metal which


would reduce the strength of the weld joint during the anticipated loading.

The Proponents are planning to use a zonal discrimination approach to determine the flaw sizes using either focused probes or phased array technology. Prior to detailed engineering, the Proponents would implement an automated ultrasonic testing vendor qualification program along with an automated ultrasonic testing flaw size verification program to determine the accuracy of the automated ultrasonic testing system under cold climate conditions.

The stress-based design used for station and facility construction would employ flaw acceptance criteria specified in either the applicable Canadian Standards Association Z662 or American Society of Mechanical Engineers B31.3 standards. The Proponents confirmed that they would comply with Onshore Pipeline Regulations, 1999 requirements which stipulate 100 percent non-destructive examination inspection of all welds. However, the Proponents stated that they intend to request an exemption from the Onshore Pipeline Regulations, 1999 non-destructive examination requirement for welds in the auxiliary systems of the Mackenzie Valley Pipeline.

The Proponents plan to develop a project-wide data management system designed specifically for the Mackenzie Gas Project to manage the large amount of data resulting from over 80,000 pipeline welds. The Proponents indicated that a weld management and materials system would be developed during

detailed engineering to ensure each weld is uniquely identified and traceable during all stages of construction and over the operating life of the pipeline.

Views of the Board

Due to the anticipated strain-based design and the associated loads we are of the view that joining of the piping is an important consideration in meeting the material design specifications. Instances of localized low fracture toughness properties are known to have occurred in or adjacent to the weld. Currently there is no requirement in the piping manufacturing standard to perform testing such as crack tip opening displacement that would identify areas of localized low fracture toughness. Instances of localized low fracture toughness could affect the integrity of the weld or the base metal adjacent to the weld during any pipeline deformation associated with a strain-based design at low operating temperatures. Therefore, in addition to determining the crack tip opening displace-

ment values for the alternative flaw acceptance criteria we are of the view that it would be prudent to determine the crack tip opening displacement values for the heat affected zone and the weld metal of the pipe mill circumferential, helical and longitudinal welds. Condition 17 requires the Proponents to undertake testing to determine the susceptibility to areas of localized low fracture toughness associated with welds.

Pursuant to the Onshore Pipeline Regulations, 1999 the Proponents must file a joining program with the National Energy Board prior to conducting welding procedure qualification tests for the field circumferential production, tie-in and repair pipeline welds and welding of project facilities. In addition, the Proponents must file the non-destructive examination procedure qualification records shortly after the completion of qualification tests. Conditions 52, 53 and 54 address these requirements.


6.4.6 Seismic design

Indian and Northern Affairs submitted that the occurrence of earthquakes could impose significant environmental loads and subsequent strain on the pipeline. A recommendation was made that the Proponents should satisfy us that seismic related hazards had been incorporated into the design of the pipelines and associated facilities. The Proponents submitted that earthquakes and other seismic related geohazards were to be considered as part of the final design and would be addressed during detailed engineering.

6.4.7 Slopes

If the soil surrounding a pipeline moves after a pipeline is built, as in the case of an unstable slope, the movement can cause stresses and strains in the pipe, expose the line, damage the pipe coating, or possibly cause the pipe to fail. The Proponents submitted that the structural integrity of the proposed pipelines is such that rupture and leakage would be unlikely

 

Did you know?

Definitions

Cross slopes - slopes that dip perpendicular to the pipeline.

Longitudinal slopes - slopes that dip roughly parallel to the pipeline.

Pore water pressure 0 the pressure of groundwater at a given location within the soil

On the record

Threshold slope angles

The Proponents define threshold slope angles as the angles below which a particular slope will be stable regardless of surface disturbance and permafrost thaw. The method was adopted based on its successful utilization for the Norman Wells to Zama Pipeline.

 

in the case of soil movement. The Proponents expressed the view that the objective for slope design for the project is essentially one of environmental protection and, in particular, one of protecting watercourses from the ingress of soils from slope movement or soil erosion caused by pipeline construction and operation.

The Proponents submitted that the Mackenzie Valley is very active in terms of slope movement and the pipeline route would cross terrain susceptible to slope movement and other geological hazards. Permafrost has a significant influence on slope stability design in northern regions. When permafrost thaws, the ice in the ground melts, causing the pore water pressure to rise until the water is able to drain. The Proponents' goal is to manage pore water pressures in the slopes so that thawing permafrost does not cause the calculated factor of safety for the slope to fall below a predetermined value, and the slope to become potentially unstable.

Slopes were categorized on the basis of slope angle and orientation in relation to the pipeline. The Proponents estimated that the Mackenzie

Gathering System and Mackenzie Valley Pipeline would cross 372 and 822 longitudinal slopes, respectively, as well as 64 kilometres and 339 kilometres of cross slopes, respectively. Of these slopes, the Proponents identified 246 that required stability mitigation. Based on preliminary geothermal and pore water pressure modeling and preliminary soil data, the Proponents developed threshold slope angles for three types of frost susceptible soils and four geographical regions. The Proponents plan to update the threshold angles during final design.

Slope design

Where LiDAR measurements of slope angle exceed the threshold angle, the Proponents propose the use of slope stability mitigation techniques. The primary methods proposed to increase slope stability and reduce the rate of permafrost thaw are:

  • installing pipe insulation;
  • using right of way passive cooling systems such as thermosiphons;
  • employing surface erosion control measures; and
  • using surface insulation.

Other proposed slope stability mitigation methods include re-grading the slope to a lesser angle or installing friction-reducing wrap on the pipeline to prevent damage during slope movement. Studies to determine the suitability of carbon dioxide versus ammonia refrigerant thermosiphons and the available types of surface insulation (flax straw, wood chips and synthetic


sheeting) were ongoing during the hearing. The Proponents submitted preliminary analysis of data from the surface insulation field trials indicating that straw bales provided the best thermal protection of materials tested, but were subject to shrinkage and would require further study to determine if the effects were material.

The Proponents submitted that the risk of potentially rapid events such as slope movements would be reduced in design and construction by identifying rapid loading mechanisms and then avoiding these areas

 

(rerouting and directional drilling) or stabilizing the site using secondary mitigation measures such as slope grading or thermosiphons. The Proponents described the buildup of strain due to earth movement from frost heave, thaw settlement and soil creep as a gradual process that could be identified prior to reaching threshold intervention values for pipeline strain. In addition, the Proponents plan to install slope monitoring equipment, including piezometers and thermistor cables on the right of way. Slope movement indicators would be installed at sites with stability concerns such as ice rich slopes,

Figure 6-8 Thermosiphon (left) and wood chips used as surface insulation (right)

Figure 6-8 Thermosiphon (left) and wood chips used as surface insulation (right)

slopes with evidence of soil movement or slopes where large toe excavations are required. The Proponents stated that intervention criteria other than pipeline strain, such as thaw depth or slope movement, would not be developed for monitored slope parameters.

To address the expected variation in ground conditions along the proposed route, the Proponents' preliminary slope design method incorporates a field change manual with contemplated design responses to foreseeable changes in ground conditions from those assumed in final design.

replacement slope


Indian and Northern Affairs Canada reviewed preliminary documents submitted by the Proponents and made several recommendations as outlined in Section 6.4.8. Indian and Northern Affairs Canada and the Proponents participated in a series of meetings and technical workshops and reached a general agreement on a design approach for slopes and geohazards.

Indian and Northern Affairs Canada was of the view that the Proponents should assess the effects of changes in ground thermal regime due to the addition of compressor stations or selected slopes where those effects could occur. Indian and Northern Affairs Canada also suggested that the Proponents prepare a complete inventory of all slopes along the right of way, especially lesser slopes, and not just those requiring site-specific slope designs.

Indian and Northern Affairs Canada indicated that further detail was required regarding the remedial actions the Proponents would take should monitoring indicate that the factor of safety for a slope falls below the design factor of safety. Indian and Northern Affairs Canada was concerned over who would make this determination and what kind of training or expertise they would have. Indian and Northern Affairs Canada suggested that there needs to be specific requirements for the technical ability and skills of the individuals making this determination and suggested that this should be specified in a condition.

Views of the Board

We find the Proponents' preliminary design methodology for slopes to be satisfactory. We note however that there appears to be

On the record

Thermosiphons

The Proponents filed an April 2006 report entitled Slope Design Methodology Report – Preliminary Engineering Design which described the use of thermosiphons. Thermosiphons are passive devices (require no power source) designed to remove heat from the ground during winter when the air temperature is lower than both the ground temperature and the boiling point of the heat exchange agent. The thermosiphons considered for the project are sealed systems containing a pressurized heat transfer agent. This agent would be either pressurized carbon dioxide or ammonia. Heat is removed from the ground in winter, when the heat transfer agent boils within the buried portion of the thermosiphon and the gas rises and condenses in the radiator segment above ground. The heat exchange process stops in summer when the air temperature is warmer than the ground

temperature. The Proponents indicated that manufacturers currently favour carbon dioxide as the heat transfer agent but that ammonia had not been ruled out.

The Proponents indicated that ammonia had been used in the 120,000 thermosiphons, called heat pipes, installed on the Alyeska Pipeline which carries crude oil from Prudhoe Bay, Alaska. Ammonia was found to have the best thermal performance and a lower working pressure, meaning that thinner-walled pipe could be used for the thermosiphons. The Proponents noted, however, that these thermosiphons had operational problems due to non-condensing gas accumulating within the pipes, and the company was converting these pipes to carbon dioxide. During preliminary engineering the Proponents had not yet considered the corrosion protection requirements for thermosiphons but acknowledged that the loss of containment of the heat transfer agent due to corrosion would be undesirable.

an exhaustive inventory of slopes on the project in the report submitted in evidence which will require revision when the final route is determined. We also note that the Proponents have proposed a field change manual for slopes in anticipation of the need for changes during construction. We are of the view that such a manual should be approved by the National Energy Board prior to use so that changes made in accordance with the manual would not require amendments to submitted final designs. Indian and Northern Affairs Canada's concern regarding the effects of changes in ground thermal regime due to the addition of compressor stations is valid and should be considered by the Proponents during the final design phase to preserve their ability to safely add compression in the future.

We are of the view that the Proponents understand the importance of ensuring competent design staff for the final slope design and we are not persuaded that this needs to be specified in a condition. However we will make adequate training a requirement of the field changes manual since the presence of qualified geoscientists on each pipeline spread is not a typical requirement.

Conditions 48 and 49 require the submission of a slope design methodology final report and a field changes manual for slopes.

Figure 6-9 Watercourse crossing – open trench

Figure 6-9 Watercourse crossing – open trench

6.4.8 Watercourse crossings

Where a pipeline crosses a watercourse, there is a possibility that the water quality, aquatic habitat and navigable waterways could be degraded. Watercourses are a dynamic component of the physical environment and are subject to floods, debris flows, ice jams, erosion, and changing banks which can damage or trigger slope instability or expose the pipe. In permafrost regions, taliks present the potential for very large frost bulbs to form around the pipe which could cause frost heave and disrupt the surface and groundwater flow patterns at watercourse crossings.

The Proponents submitted that the Mackenzie Gathering System and Mackenzie Valley Pipeline would cross 643 water bodies. The shorter natural gas liquids pipeline would cross 260 water bodies. These watercourses range from unmapped, vegetated drainage features to named, navigable corridors including the Mackenzie River. The project route also crosses bodies of standing water and peatlands, which are typically areas of significant shallow groundwater flow. The Proponents anticipate taliks to be present beneath perennial watercourses in areas of continuous or


discontinuous permafrost. With the exception of the major watercourses, there is limited flow data from northern regions for use in the hydrologic design of watercourse crossings.

The Proponents selected the proposed crossing locations to minimize the number and width of crossings and to avoid areas prone to channel migration, local scour and ice jams. The Proponents plan to use a generic design template based on company best practices and a minimum burial depth of two metres for the majority of crossings. Site-specific designs for all large watercourse crossings would be based on local stream characteristics, the 1:100 year flood event, or the 1:200 year flood event where hydraulic data is limited.

Generally, watercourse crossings would be constructed using an open trench method when the watercourses are frozen (see Figure 6-9). Where winter flows occur, the flows would be controlled and watercourse crossings would be constructed using isolation methods (see Figure 6-10). The Proponents intend to install the pipe in horizontal directionally drilled bores (see Figure 6-12) to cross 17 perennial watercourses where fish habitat is present and isolation methods are not feasible.

Figure 6-10 Watercourse crossing – isolated method

Figure 6-10 Watercourse crossing – isolated method

Figure 6-11 Diversion berms and ditch plugs

Figure 6-10 Watercourse crossing – isolated method

 

The Proponents propose to control groundwater flow and seepage along the pipelines using ditch plugs and diversion berms for overland areas (see Figure 6-11). In areas of high groundwater flow, such as watercourse crossings and fens, the Proponents expect pipe strain related to frost bulb growth to be manageable, and intend to monitor frost bulb growth at these locations using aerial patrols and in-line inspection tools.

Did you know?

Definitions

Ditch plug - a section of ditch filled with a material intended to prevent the flow of ground water in the backfill along the ditch.

Diversion berm - a berm constructed on the surface of a slope which is intended to direct surface water off the right of way in order to minimize erosion.


Horizontal directionally drilled crossings

Feasibility assessments were carried out for all proposed horizontal directionally drilled crossings based on subsurface data from existing boreholes in the vicinity of the crossings. Additional field work is planned for each horizontal directional drill location before drilling begins to confirm soil types, ice content and the presence of any ice lenses.

Drilling muds are used during directional drill operations to remove drill cuttings, cool and lubricate the drill bit, provide fluid loss control and create pressure on the walls of the borehole for stability. The Proponents stated that muds with freezing temperature depressant additives have a lasting impact on the environment and increase the complexity of the horizontal directional drill operation compared to using chilled muds without freezing temperature depressant additives. Therefore, using temperature controlled (5°C) drilling fluids without freezing temperature depressant additives is preferable due to restrictions placed on the disposal of freezing temperature depressant muds. The Proponents stated that using freezing temperature depressant additives would be assessed further during detailed design and would only be considered where there is significant concern about hole instability during drilling. While freezing temperature depressant muds remain an option, the Proponents expressed confidence that the directional drill operations can be successfully completed using drilling muds chilled to within a few degrees above freezing.

Figure 6-12 Watercourse crossing – horizontal directional drill using backreaming method

Figure 6-12 Watercourse crossing – horizontal directional drill using backreaming method

On the record

Horizontal directional drilling in Arctic environments

The Proponents indicated that there is little precedent for horizontal directional drilling operations in permafrost and Arctic environments. A horizontal directional drilling comprehensive review undertaken by the Proponents identified several key issues which could affect the success of the overall horizontal directional drilling operations including:

  • limited numbers of horizontal directional drilling contractors with Arctic experience;
  • logistical planning;
  • continuous operation in an extreme cold environment; and
  • the need for tight control of drilling fluid properties.

A significant challenge identified by the Proponents is the development of a drilling mud that will not freeze when used in permafrost environments, yet will remain viscous enough to remove drill cuttings, provide lubrication and prevent hole collapse. In ice rich soils the circulation of warm drilling muds will cause the permafrost to thaw, which could lead to the collapse of the borehole, surface subsidence or slope instability.

The horizontal directional drilling study made a number of recommendations including:

  • investigating the use of non-toxic, biodegradable methyl glucoside as a freezing temperature depressant mud additive;
  • use of temperature controlled (cooled) drilling fluids;
  • investigating mud disposal requirements;
  • the calculation of frost heave at crossings; and
  • the completion of an extensive geotechnical field investigation to identify and delineate horizontal directional drilling unfavourable substrates, high ice content soils and taliks.

Additional mitigative measures proposed by the Proponents to prevent the degradation or thaw of unstable or ice rich permafrost include insulated work pads, temporary surface drill casing and auxiliary mud chilling systems.

During the course of the hearing Indian and Northern Affairs Canada reviewed the watercourse crossing conceptual designs and recommended that the Proponents collect and incorporate into the design additional data on:

  • distribution of ground ice;
  • thermal regime of river sediments;
  • extent of taliks;
  • soil properties; and
  • slope characterization at stream crossings.

Indian and Northern Affairs Canada further recommended that prior to construction, the Proponents should submit to the National Energy Board:

  • detailed stream crossing designs for the Mackenzie Valley Pipeline and natural gas liquids pipeline;
  • a comprehensive river engineering analysis;
  • revised frost bulb predictions; and
  • a typical crossing design for an ice rich slope.

The Proponents submitted that the proposed field investigations and final design requirements would address the recommendations made by Indian and Northern Affairs Canada during the oral hearing.

The Joint Review Panel expressed concerns regarding the potential release of sediments at stream crossings during construction and the post-construction phase and the potential negative effects of the formation of frost bulbs and aufeis at stream crossings. The Joint Review Panel recommended that measures must be in place to avoid the creation of frost bulbs and aufeis at stream crossings through effective design and mitigation. Frost bulbs in streams could have an impact on the physical environment if the flow in certain streams is blocked. The biological community in these streams, particularly fish and their habitat could be negatively affected. The Joint Review Panel heard that frost bulb formation can be reduced by using pipe insulation however the effectiveness of that insulation could degrade over time. Impacts at stream crossings can be further reduced by deeper burial of pipe but that burial by itself requires substantial depth to be effective.

The Joint Review Panel was generally satisfied that the Proponents have adequately addressed potential impacts of the Project on groundwater flow, subject to a number of recommendations.

Views of the Board

We are satisfied with the design approach adopted by the Proponents. The design approach and construction techniques, for the most part, are conventional and have been used on other projects successfully. We note that horizontal directional drilling 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 majority of the horizontal directional drilling crossings. 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 drilling must be carefully considered before implementation. Condition 47 requires the Proponents to undertake a hazard analysis and prepare contingency plans for each horizontal directional drilling crossing.

Condition 51 requires an inventory of all watercourse and water body crossings, design information, drawings, information regarding frost bulb analysis, evidence demonstrating the prevention of aufeis and unacceptable pipe strains, information regarding thermal, erosion, scour control and ground water flow mitigation measures, and evidence of consultation with the Department of Fisheries and Oceans.

Surveillance and monitoring is a requirement of the Onshore Pipeline Regulations, 1999 and all pipeline monitoring and surveillance programs incorporate the monitoring of watercourse crossings and their approach slopes. Condition 39, which is discussed later, requires the monitoring of water course crossings for scour, aufeis, drainage impedance and erosion issues.

6.4.9 Pipeline control systems and leak detection

Project facilities would be remotely monitored and operated using Supervisory Control and Data Acquisition Systems (SCADA) from a main control centre in Calgary. Emergency shutdown systems capable of being initiated remotely or locally would be installed. A leak detection system is an important complement to SCADA because it uses the information SCADA collects to help detect leaks earlier than surveillance programs such as aerial patrols. According to the Proponents, the leak detection system's performance is important to the integrity of the entire system. Therefore, they would develop a leak detection quality program to annually review the system's performance. The Proponents added that a typical quality program would use direct methods, such as liquid withdrawals, and inferred methods, such as inputting false data into the system, to evaluate both the system's performance and the response of operating personnel. The Proponents indicated that as part of the quality program alarm statistics, actual leak data and system performance information would be reviewed annually to improve system performance.

The Proponents plan to use computational pipeline monitoring with statistical process control technology on the Mackenzie Valley Pipeline and Mackenzie Gathering System pipelines. The Proponents noted that this technology would not be able to detect leaks as effectively in multi-phase lines such

Did you know?

Leak detection systems

Leak detection capabilities depend on the accuracy of the measurement devices, the design and location and capabilities of the SCADA. At the time of the hearing, the overall system design had not progressed to the point where the Proponents could accurately determine the necessary leak detection system capabilities. The Proponents' decision criteria would be based on API 1155 Evaluation Methodology for Software-based Leak Detection Systems. The Proponents confirmed that its leak detection system for the natural gas liquids pipeline would comply with Canadian Standards Association Z662-03, Annex E Recommended Practice for Liquid Hydrocarbon Pipeline System Leak Detection; however, it would test the leak detection system's effectiveness annually by inferred methods and not by annually removing the liquids.

as the gathering system upstream of the Inuvik Area Facility; however, potential performance improvements were possible with additional operational experience. The Proponents would also develop a project-specific plan to address the full implications of process control network security.

Views of the Board

In order to minimize potential damage from spills during operation, early detection of leaks and breaks is paramount. Given the remoteness of the pipeline we are of the view that it is important to ensure the system can be adequately controlled and the leak detection capability is sensitive but not prone to false alarms. Conditions 63 and 64 require the submission of data regarding the expected capabilities of the system and reports detailing the actual performance of the system and how the Proponents have addressed performance issues.


6.4.10 Settlement of backfill

After a pipeline is built, the earth along the right of way and ditch line may settle. This settlement can disrupt drainage and promote erosion if not addressed. Furthermore, if the backfill thickness and strength decreases, the pipe may become buoyant. Experience from the construction of other northern pipelines demonstrates that localized settlement occurs primarily in the first spring and summer after winter construction.

In planning their mitigation for ditch settlement, the Proponents drew on the knowledge gained by others during the construction of the Ikhil Pipeline. They plan to import thaw stable fill to supplement or replace the local backfill at the time of construction. The Proponents stated that granular fill material (e.g., sand or gravel) would be best; however, they recognized that granular material is in short supply along the pipeline route. The Proponents indicated that the only quality requirement for replacement backfill was that it be of low ice content so that thaw

 

On the record

Ditch settlement

Localized ditch settlement is primarily the result of three factors. First, excavated material tends to increase in volume to the extent that it cannot all be graded back into the ditch. Inevitably some of this excavated soil remains along the ditch. Second, in areas of permafrost the soil immediately below the active layer can be ice rich, and this material will lose some volume after it has melted. Third, freshly exposed earth will absorb more solar radiation and would tend to thaw faster than the adjacent less disturbed soil.

settlement would be limited. The Proponents intend to mine the material at borrow sites, and deliver and backfill the pipe trench soon after the pipe is placed in the trench. They would use equipment which could process the backfill into smaller lumps at the borrow site and on the right of way so that large lumps would not be placed over top of the pipe.

To help protect the pipe, the Proponents indicated that the three millimetre, three-layer pipeline coating would protect against the expected backfill conditions. In addition to the pipeline coating, foam pillows and imported fill for bedding and padding purposes would be used. Pipe protection products such as Rockshield and wood lagging (i.e., lumber strapped around the circumference of the pipe) might also be used to protect the pipe as required.

The requirement for slope trench backfill is more stringent than the requirement for overland replacement backfill due to the potential for slope instability during thawing. The Proponents identified the need to replace or improve trench backfill as a function of slope angle, soil type and method of excavation in their preliminary slope design.

The Joint Review Panel considered the Proponents' plans for remediating ditch fill settlement satisfactory for most of the terrain likely to be encountered but remained concerned about the effectiveness of the ditch fill settlement remediation for areas of massive ice. The Joint Review Panel recommended that we require the Proponents to file:

  • methods for determining the quality and quantity of imported fill requirements;
  • the timing and methods for hauling and stockpiling those fill requirements;
  • the methods for monitoring for and remediating ditch subsidence; and
  • the methods for disposal of excavated material not required for backfill.

Views of the Board

We note that the Proponents filed a report during our hearing which presented the method used to estimate the settlement of backfill material that might be required. The ditch settlement values calculated were used as the basis for the preliminary designs and estimates of replacement backfill. The imported backfill quantities were based on route soil information obtained from geotechnical information available to the Proponents during preliminary design. We are confident that these estimates will improve as a result of the planned Geotechnical Verification Program. However, measures are required to ensure that the Proponents' efforts to remediate backfill settlement do not lead to other impacts which may be caused by excess backfill material being left on the right of way. Condition 44 addresses these concerns and implements the Joint Review Panel's recommendations. The condition requires the Proponents to consult with land managers and the appropriate regulators to ensure they are aware of the project backfill requirements for the project and


the need for potential disposal sites for unused material.

Condition 43 requires the approval of backfill and padding specifications. The purpose of this requirement is to ensure that this material is not injurious to the pipe and its coating. There is a potential that some of this material will be sourced from areas where acid-bearing rock may be present. It is our expectation that the specification will contain a requirement that quarried material be screened for this possibility.

6.4.11 Right of way protection during construction

Thaw-sensitive terrain along the pipeline route may be affected by thaw-induced erosion, slope instability, or excessive settlement. Disturbance of the vegetative cover specifically on thaw- sensitive overland areas could lead to ponding and possible sustained thawing.

Based on expected terrain conditions developed from available data, the Proponents plan to build snow-ice pads, where practical, north of the tree line, and at specific locations along about 50 kilometres of sensitive terrain between

the Inuvik Area Facility and Fort Good Hope. The Proponents are of the view that available borehole and terrain mapping data from previous ground disturbances in the Mackenzie Valley as well as experience gained from building earlier northern pipelines, suggests a combination of conventional surface leveling and cut and fill techniques can be used successfully south of Inuvik.

The Proponents indicated that existing borehole data is sufficient to determine the expected average amount of thaw settlement for a terrain group. The average settlement for each terrain

 

Fiqure 6-13 Anticipated right of way settlement for different clearing techniques

Fiqure 6-13 Anticipated right of way settlement for different clearing techniques

group between Inuvik and Norman Wells is predicted to be less than about 0.5 metres after five years. Figure 6-13 shows the anticipated right of way settlement between Inuvik and the Nova Gas Transmission Ltd. interconnection in Northern Alberta for three different clearing and right of way preparation techniques in areas of thick peat. The Proponents added that long-term terrain effects would be acceptable provided the necessary rehabilitation and re-vegetation is carried out. Where grading is necessary and high-ice content soil is exposed, special protective measures would be applied before the construction season ends.

Mitigative measures being considered by the Proponents include:

  • using surface insulation, such as a layer of stripped organics, wood chips or board stock insulation under a layer of soil, to limit seasonal thaw;
  • installing berms and breakers for erosion control; and
  • stabilizing the right of way through re-vegetation.

Views of the Board

Based on the successful use of conventional surface leveling techniques on the Norman Wells Pipeline we are satisfied with the Proponents' proposed right of way preparation plans south of the tree line. North of the tree line and in limited areas north of Fort Good Hope, where construction from snow pads is required,

pursuant to Condition 44(d), we will verify that the Proponents' plans to remove excess replacement backfill from the right of way will incorporate measures to limit disturbance of the surface organics.

6.5 Other technical considerations

6.5.1 Overview

In addition to the design issues discussed above, a number of technical issues were raised during the hearing related to construction and operation. The following issues are included in this section:

  • air emissions;
  • pressure testing;
  • northern logistics and construction;
  • right of way protection during construction; and
  • preliminary plans for integrity monitoring and surveillance

6.5.2 Air emissions

During operation the project would emit greenhouse gases including carbon dioxide from combustion-related sources such as compressors, along with methane gas released through normal venting procedures and minor leaks (fugitive emissions). Annual equivalent carbon dioxide emissions during operation are estimated at 812.8 kt/a. Construction activities are expected to generate up to 487.6 kt/a of equivalent carbon dioxides. Other air contaminants which may be emitted, such

as oxides of nitrogen, fine particulate matter, carbon monoxide and volatile organic compounds could have a direct impact on human health, wildlife and vegetation. Oxides of nitrogen and volatile organic compounds are precursors to the formation of secondary particulate matter and ozone. Oxides of nitrogen also contribute to acid rain.

Environment Canada noted that air quality in the project area is good and recommended pollution prevention measures to minimize negative effects on air quality. Recommendations were made for both the pipeline and the facilities and included ways to reduce methane emissions during operation including:

  • reducing oxides of nitrogen and sulphur oxide emissions from gas turbines;
  • minimizing greenhouse gas emissions; and
  • reducing benzene and other emissions.

Methane emissions

Environment Canada provided examples of pipeline best management practices that address operational methane emissions. These examples included:

  • dry gas seals on compressors;
  • unit isolation valve systems;
  • electric or air starting systems for gas turbines;
  • optimized maintenance and pigging schedules;
  • regular leak detection and aerial surveys;
  • line break controls;
  • computational leak detection;
  • pre-installed connecting tees for future gathering pipelines and compressor stations;

  • hot tapping;
  • operator training; and
  • an emergency response plan.

The Proponents stated they would implement the best management practices that are currently being developed by the Canadian Association of Petroleum Producers, Environment Canada, the Canadian Energy Partnerships for Environmental Innovation and the Canadian Gas Association, once these are adopted by Alberta's Energy Resources Conservation Board Directive 60. This document is called Best Management Practice: Management of Fugitive Emissions at Upstream Oil and Gas Facilities and is expected to:

  • identify large versus small fugitive emission sources, to allow operators to focus on sources with larger volume emissions; provide a tiered approach for developing leak detection and repair programs;
  • recommend a framework for establishing guidelines, such as leak definition, sampling protocols, leak detection frequency, repair and maintenance and other monitoring methods;
  • describe methods of flow indication to determine leakage, and to determine how this information would be used to guide repair and maintenance decisions; and
  • provide a method for collecting and benchmarking fugitive emissions information resulting from any leak detection and repair program implemented.

Environment Canada supported the implementation of these best management practices by the Proponents, but added that it was not necessary as a prerequisite that the best management practices be adopted by Alberta's Energy Resources Conservation Board.

Oxides of nitrogen and sulphur oxides emissions

Environment Canada stated that using dry low oxides of nitrogen gas turbines that meet the 1992 Canadian Council of Ministers of the Environment National Emission Guidelines for Stationary Combustion Turbines along with reciprocating engines that meet or exceed the requirements for such engines in Alberta's Energy Resources Conservation Board Directive 56 would meet Environment Canada's recommendations regarding the appropriate application of best available technology and best management practices in order to reduce the project's oxides of nitrogen and sulphur oxide emissions. Alberta's Energy Resources Conservation Board Directive 56 requires compliance with Alberta Environment's Code of Practice for Compressor and Pumping Stations and Sweet Gas Processing Plants, 1996.

The Proponents intend to specify the requirement that gas turbines meet or exceed Canadian Council of Ministers of the Environment guidelines in the purchase agreements. The Proponents added that vendors would be required to guarantee emissions performance and fuel efficiency. The Proponents indicated that natural gas fuelled reciprocating engines

would be used as primary power production for the Storm Hills pigging facility, compressor stations, and the Trout Lake heater station. Diesel engines would be used for standby emergency power generation. Engines would be selected using proven low emission design criteria and would meet or exceed the requirements of Alberta Environment's Code of Practice for Compressor and Pumping Stations and Sweet Gas Processing Plants, 1996, which specify a maximum oxides of nitrogen level of 6 grams/kilowatt-hour for engines over 600 kW.

Greenhouse gas emissions

Environment Canada stated that maintaining an efficient gas processing and pipeline system is important factor in minimizing greenhouse gas emissions and conserving natural gas. Environment Canada cited waste heat recovery as a method of achieving this goal. The Proponents' preliminary designs incorporate waste heat recovery in the Inuvik Area Facility. Environment Canada recommended that the Proponents provide details concerning the design choices for waste heat recovery at the Inuvik Area Facility prior to construction.

Benzene emissions

Natural gas produced at the development fields would be dehydrated before entering the gathering pipelines. Glycol dehydrators typically used in the upstream oil and gas industry have the potential to emit benzene gas. Benzene can cause harmful effects at any level of exposure and available evidence indicates that it is a carcinogen. Accordingly, benzene emissions


On the record

Best available technologies and best management practices

Environment Canada stated that the intent of the phrase “best available technology” varies according to the specific application. For the Mackenzie Gas Project, Environment Canada understood the phrase to refer to the continuous improvement of pipeline safety and environmental protection and would expect any best available technology to achieve that intent. In addition, Environment Canada pointed to certain criteria guiding its assessment of whether a particular proposed technology is best available technology. These criteria are that:

  • it must be a technology with superior emissions performance;
  • it must be commercially available at the time it is required for the project;
  • the cost for the technology must be reasonable; and
  • the best available technology includes the goals of pollution prevention and energy efficiency.

Environment Canada expressed the view that best management practices are innovative, dynamic, and improved environmental protection practices that help ensure development is conducted in an environmentally responsible manner. Environment Canada indicated that best management practices may exist as formal guidelines or generally accepted procedures recognized by regulators and industry associations as best practices. Best management practices for this project refer to both system design and operating practice for all activities and operations from the wellhead to the product's final destination, using overall system optimization, energy efficiency, reliability and air emissions prevention.

 

were a concern for Environment Canada. The Proponents indicated that molecular sieve dehydration units would be used where required. Environment Canada expressed the view that glycol dehydrators could be specified during final design and suggested implementing a condition requiring glycol dehydrators be designed, installed and operated in accordance with recommended practice Control of Benzene Emissions from Glycol Dehydrators (Canadian Association of Petroleum Producers, 2000) and comply with Alberta's Energy Resources Conservation Board Directive 39: Revised program to Reduce Benzene Emissions from Glycol Dehydrators.

Other emissions

Environment Canada noted that incinerators operating at work camps and other project-related facilities could emit mercury, dioxins and furans. Environment Canada recommended that all incinerators be required to meet emission limits in the Canada-wide Standards for Mercury Emissions and the Canada-wide Standards for Dioxins and Furans. Environment Canada stated that using best available incineration technologies and best management practices would also minimize emissions of particulate matter and precursors to pollution management and ozone. Environment Canada added that best management practices for incineration focus on waste segregation, reducing the amount of waste to be incinerated and proper operation and maintenance of incineration equipment. Dual chamber and controlled air technologies are considered best available technology for incineration.

Views of the Board

Addressing emissions issues begins with making appropriate design decisions to minimize energy use, implementing best available technologies and using best available management practices. The Proponents made undertakings during our hearing which indicate their intention to implement these measures. Conditions 11 and 13 require the Proponents to submit reports that will confirm the implementation of their undertakings. Condition 67 requires the Proponents to minimize and reduce emissions from flaring.

We agree with the measures proposed by Environment Canada to limit mercury, dioxin and furan emissions. Condition 12 requires the submission of a report evaluating technologies and practices the Proponent will implement to reduce these emissions from camps and station facilities. These technologies and practices must be reflected in the waste management plans required by Conditions 16 and 59.


6.5.3 Pressure testing

Prior to final commissioning, testing is conducted on the assembled pipeline to verify at the outset that the pipeline does not have undetected leaks and that the pipeline is capable of containing its design pressure plus an appropriate safety margin. While water is generally considered to be the most acceptable testing medium, freezing temperature depressants must be added to prevent freezing in the pipeline or test facilities in cold climates. For alternative test mediums such as air, operators may need to address additional safety risks and demonstrate that an equivalent degree of accuracy, as compared to hydrostatic fluids, can be achieved.

The Proponents stated that the installed pipelines and facilities would be pressure tested in segments to confirm the strength and to check for leaks in accordance with Canadian Standards Association Z662 requirements. Potential test media evaluated by the Proponents include:

  • heated water;
  • water with freeze depressants;
  • air;
  • nitrogen; and
  • hydrocarbons.

The Proponents indicated that their plan is to use a mixture of water and methanol to pressure test the natural gas liquids pipeline and Mackenzie Valley Pipeline. The mixture of water with freeze depressants could be reused to minimize the volume of fluid required for testing and for eventual disposal. For the upstream gathering pipelines, water mixed

with freeze depressants and air are both being assessed. The Proponents indicated that air testing was also being considered as an option because of difficulties with water testing such as drying pipelines and managing the different volumes required by each test section (with varying pipeline lengths and diameters), as well as cost and schedule considerations. In order to compensate for the air test's lack of sensitivity, it was suggested that test section volumes and hold period durations could be adjusted. Further, odorant could be added to increase the ability to detect small leaks. If a leak occurs, the segment identified by the test would be uncovered and repaired or replaced.

Views of the Board

Due to its ability to detect leaks and for safety reasons we consider hydrostatic testing to be the preferred method of ensuring pipeline integrity prior to operation. We recognize that there may be circumstances where air testing may be necessary. Condition 57 requires the filing of the Pressure Testing Program required by section 23 of the Onshore Pipeline Regulations, 1999 which specifies additional requirements for air testing should its use be necessary.

6.5.4 Support infrastructure

The Proponents submitted that construction of the project facilities will involve the construction of extensive off right of way support infrastructure including roads, borrow sources, camps, barge landings and staging areas. The project would require new roads to transport materials, equipment and personnel to and from camps, facility and pipeline construction sites. The Proponents estimate they would need 60 kilometres of all-weather roads and 820 kilometres of winter roads for the project. Of the 820 kilometres of winter, roads 235 kilometres would be ice roads over rivers and lakes. Approximately 80 percent of the winter roads would be needed to access water and borrow sources for the project.

The borrow requirements for the project are estimated at 7.6 Mm³ and would be sourced from 68 primary sites in the Mackenzie Delta and Mackenzie Valley. This material is required for development field facility sites, the Inuvik Area Facility, pipeline facilities, infrastructure development and pipeline backfill.

Winter roads for the project must be durable enough to support the expected construction equipment needed to transport 7.6 Mm³ of borrow material, as well as project equipment and materials. The Proponents indicated this

would require developing similar, but more stringent, design specifications than the Government of the Northwest Territories winter road construction standards. The Proponents stated that maintenance would comply with local regulatory approvals and would generally conform to Environmental Guidelines for the Construction, Maintenance and Closure of Winter roads in the NWT, a handbook used by the Northwest Territories Department of Transportation. The Proponents also indicated that ice thickness requirements for ice crossings would be similar to the Government of the Northwest Territories ice bearing assessments.

Views of the Board

The construction, operation and closure of winter roads require regulatory measures to reduce the off right of way impacts of the project. There are also safety concerns since 235 kilometres of these winter roads would be over lakes and rivers. The Northwest Territories Department of Highways has experience constructing and operating these roads and the handbook used by the Northwest Territories Department of Transportation is sufficient for their needs. However, is likely that most of the workers constructing, operating, using and closing the project's winter roads, many of whom will come from outside of the Northwest Territories, will not have the benefit of this experience. We are of the view that a single manual encompassing both safety and environmental requirements of winter road management is required for the project to minimize off right of way environmental impacts and promote safety. Conditions 9 and 10 require the filing of winter road manual as well as the permits, authorizations and letters of advice issued by governments and regulators which have a bearing on winter road construction, operation and closure.

6.5.5 Northern logistics and construction

Logistics

The Mackenzie River would be the primary transportation corridor for the project. Most of the material required to build the pipeline would be shipped by rail from the south to Hay River where it would be transferred to barges for travel north in the summer. Pipeline construction would take place mostly in winter when the ground surface is sufficiently frozen to support the movement of vehicles. Trucks would use existing highways, winter roads and new project roads. Construction crews would travel to the camps by aircraft, which would limit private vehicle use by the workforce. Substantial improvements to existing infrastructure and new project-specific infrastructure such as barge landings, camps and temporary winter roads would be required to accommodate construction activities. Some very large processing and compressor modules for the Inuvik Area Facility would be shipped by sea to Inuvik where specialized carriers would transport them to the site on purpose-built gravel and winter roads.

Schedule

The Proponents' construction plan assumes four years of construction for infrastructure, pipelines, and associated facilities. To address potential issues related to the availability of labour and increased costs, the construction plan distributed pipeline construction activities over three full winter seasons.


Construction Activities by Season

First Summer

  • Mobilize some equipment, small camps and fuel for initial site development.
  • Develop borrow sites and stockpile borrow material.
  • Begin to develop barge landing sites.
  • Begin to install main construction camp pads and stockpile pads.
  • Mobilize equipment, small camps and fuel for right of way clearing.
  • Transport fuel by barge and truck to support future construction.

First Winter

  • Continue borrow site development work.
  • Develop barge landing sites.
  • Install main construction camp pads, stockpile pads and facilities pads.
  • Begin installing main infrastructure, including camps and field-erected tanks.
  • Survey, clear and, potentially, grade the right of way and facility sites.
  • Geotechnical Verification Program.

Second Summer

  • Mobilize pipe, equipment, camps and fuel to support main construction.
  • Install construction camps. Clear pipeline right of way, where practical.
  • Continue developing and operating borrow sites.
  • Continue installing infrastructure and facility pads.

Second Winter

  • (First pipe-laying season) Construct pipeline sections with multiple construction spreads.
  • Continue surveying and clearing right of way and facility sites.
  • Continue developing and operating borrow sites and installing infrastructure, including camps and field-erected tanks.
  • Install pile foundations at facility sites. Begin pipeline right of way construction cleanup.
  • Geotechnical Verification Program.

Third Summer

  • Mobilize pipe, equipment, camps and fuel to support main construction.
  • Install construction camps.
  • Clear pipeline right of way, where practical.
  • Transport facility modules from Hay River.
  • Install pile foundations at facility sites.
  • Begin facility assembly at sites and continue construction.
  • Continue developing and operating borrow sites and installing infrastructure.

Third Winter

  • (Second pipe-laying season) Construct pipeline sections with multiple construction spreads.
  • Continue surveying and clearing right of way and facility sites, where required.
  • Continue developing and operating borrow sites and installing infrastructure, including camps and field-erected tanks.
  • Install pile foundations at facility sites.
  • Continue pipeline right of way construction cleanup and reclamation.

Fourth Summer

  • Mobilize pipe, equipment, camps and fuel to support main construction.
  • Install construction camps.
  • Clear pipeline right of way, where practical.
  • Transport facility modules from Hay River and offshore locations.
  • Continue installing facility modules and construction.
  • Continue developing and operating borrow sites and installing infrastructure.

Fourth Winter

  • (Third pipe-laying season) Complete surveying and clearing right of way and facility sites, where required.
  • Construct remaining pipeline sections with multiple construction spreads.
  • Transport facility modules to remote sites.
  • Complete pipeline construction. Continue operating borrow sites.
  • Continue facility construction.
  • Continue pipeline right of way construction cleanup and reclamation.
  • Begin demobilizing camps and equipment.

Fifth Summer

  • Complete facility construction.
  • Begin commissioning and start-up activities for pipelines and facilities.
  • Begin infrastructure and borrow site reclamation.
  • Continue pipeline right of way construction cleanup and reclamation.
  • Continue demobilizing camps and equipment.

Fifth Winter

  • Complete commissioning and start-up activities.
  • Start up and begin operating facilities and pipelines in Q4 2018.
  • Continue pipeline right of way construction cleanup and reclamation.
  • Continue demobilizing camps and equipment.

Sixth Summer

  • Complete pipeline right of way construction cleanup and reclamation.
  • Complete reclamation of infrastructure sites not required for operations.
  • Complete demobilization.
 


Construction Safety

Pipeline construction projects in winter conditions similar to those in the project area have been successfully completed in the past. To ensure the Mackenzie Gas Project is equally successful, the Proponents have incorporated the following mitigation measures in construction planning:

  • providing shelters for welding, horizontal directional drilling and pressure testing;
  • using electric resistance and propane flame heating to meet preheat, inter-pass and post heating requirements for welding and the field application of weld joint coatings;
  • fitting construction machinery for arctic service;
  • installing cooling and lubricating system heater devices to allow equipment to be shut down for extended periods;
  • developing activity shutdown criteria; and
  • sizing crews and equipment to allow work to continue during warm-up breaks.

The Proponents' planning assumes pipeline construction crews would work seven days a week, 12 hours per day. Some activities such as directional drilling and ditching may be carried out around the clock. The Proponents estimated that 15 to 20 percent of scheduled working days may end up being weather days, resulting in little or no productivity.

The Proponents stated that one of the primary project priorities is to provide an injury-free, incident-free, healthy workplace and that, regardless of the labour supply and demand

situation, contractors participating in project construction must meet safety requirements. The Proponents added that safety training must be completed before workers are assigned to a work site and that supplemental safety training would also be provided, both before and during construction, to ensure workers have the required safety related qualifications.

In order to maintain worker safety in northern working conditions, the Proponents indicated that the personal protective equipment provided for each worker would be appropriate for their work assignments. This equipment would typically include a hooded arctic parka, insulated coveralls, lined leather mitts, insulated arctic work boots, face protection and headgear. In addition, the Proponents stated it would provide crew transportation buses and emergency shelters with heaters so that warm-up breaks could be taken depending on working conditions.

Views of the Board

Conditions 3, 4, 7, 8, 9, 10, 15, 16, 19, 20, 21, 29 to 36, 39, 42, 49 and 56 require the Proponents to construct the Mackenzie Gas Project with due consideration of safety, the environment, and logistical and scheduling difficulties in the North. Some of these conditions have been elaborated elsewhere in this volume. Implementation of these conditions during construction of the

project will promote worker safety, protect the environment and help maintain the project schedule.

These conditions include the filing of:

  • Environmental Protection Plans (EPP) and corresponding environmental alignment sheets;
  • a waste management plan;
  • an emergency response plan;
  • a construction safety manual;
  • construction schedules;
  • a manual for the construction operation, maintenance and closure of winter roads;
  • permits, authorizations and letters of advice from federal departments, the Government of the Northwest Territories and local regulatory organizations;
  • project organization details of the Proponent;
  • engineering alignment sheets;
  • field change manual for slope design;
  • heritage resources management plans;
  • wildlife management plans; air quality monitoring program; and
  • project progress reports.

There is also a requirement to provide logistical support to the National Energy Board staff undertaking construction inspection and reclamation.


Did you know?

Integrity management program

An Integrity Management Program is a proactive program which typically incorporates the tools, technologies, procedures and strategies needed to ensure pipelines are safe, reliable and environmentally responsible. The included management system defines the scope of the program, organizational lines of responsibility, personnel training and qualification requirements, change management and program monitoring. An Integrity Management Program incorporates a records management system to provide timely access to important integrity information. The program would also typically include hazard identification and condition monitoring using methods such as in-line inspection tools (pigs) and a mitigation program to correct integrity issues identified. The monitoring of pipeline strain, corrosion and geotechnical hazards is within the scope of an Integrity Management Program.

6.6 Preliminary plans for integrity monitoring and surveillance

The Proponents outlined preliminary plans for monitoring and surveillance as well as its proposed frequency of inspection. These preliminary plans are listed in Table 6-5.

The Proponents expressed the view that strain accumulation from frost heave and thaw settlement would occur over several years before they would approach critical strain levels. During the operating phase, inline strain monitoring would be required so that the Proponents can undertake appropriate maintenance before the onset of the limiting strains. Therefore it is particularly important to the project to construct a suitable in-line inspection tool or tools that can detect strain accumulation in the Mackenzie Gas Project pipelines and would work under the anticipated conditions. Also required is a detailed survey of as-constructed base line conditions in order to measure strain that develops following construction. The Proponents indicated that the baseline survey of the pipe would be undertaken during construction instead of running the inspection tool immediately after the start of pipeline operation.

The Proponents assessed the pipeline operating parameters of temperature, pressure, fluid speed, fluid composition and multiphase flow against the operating capabilities of currently available in-line inspection tools and discovered challenges that would limit pipeline inspection capability. The most difficult challenge is overcoming low operating temperatures,

although high operating pressures and long inspection lengths would also limit certain tools. In-line inspection tools perform better within certain speed ranges. Another challenge is developing speed control that would minimize impacts on throughput while allowing accurate inspection of the pipeline. The Proponents were of the view that, although these constraints would pose challenges for in-line inspection tool vendors, these are not vastly different from other challenges that have been solved in the past with enough lead time and planning.

Because the pipelines will be buried for approximately two years prior to operation and in-line inspection monitoring can only be done in the first year of operation, Indian and Northern Affairs Canada suggested that the Proponents be required to survey the location of the pipe after it is lowered into the trench to determine its precise location prior to line fill. Indian and Northern Affairs Canada suggested that In-line inspection monitoring of the pipeline be conducted twice in the first year of pipeline operation, with the frequency thereafter based on those results and as directed by the National Energy Board, with a minimum of one In-line inspection per year.

The Joint Review Panel recommended that we require the Proponents to implement an effects monitoring plan that includes, in addition to pipeline integrity monitoring, monitoring of permafrost, terrain and geotechnical parameters relevant to thaw and frost bulb impact assessment.


Table 6-5 Proponents' preliminary plans for monitoring and surveillance

Mechanism

Preliminary monitoring
method options

Indicator

Preliminary monitoring frequency

Frost heave

Curvature in-line

inspection (ILI)

Strain accumulation

Baseline is the construction as-built survey.

Annual in-line inspection runs for the first three years of operation.

Frequency of subsequent runs based on projected strain accumulation.

Remote sensing methods

Ground deformation

Quarterly, at identified sites.

Thaw settlement

Inertial ILI

Strain accumulation

Baseline is the construction as-built survey.

Annual in-line inspection runs for the first three years of operation.

Frequency of subsequent runs based on projected strain accumulation.

Aerial patrol

Ground deformation

Monthly.

Remote sensing methods

Ground deformation

Quarterly, at identified sites.

Upheaval displacement

Inertial ILI

Strain accumulation

Baseline is the construction as-built survey.

Annual in-line inspection runs for the first three years of operation.

Frequency of subsequent runs based on in-line inspection trends.

Aerial patrol

Ground deformation

Monthly.

Slope instability

Inertial ILI

Strain accumulation

Baseline is the construction as-built survey.

Annual in-line inspection runs for the first three years of operation.

Frequency of subsequent runs based on projected strain accumulation.

Aerial patrol

Ground deformation

Monthly.

Slope monitored by inclinometers, thermistors, piezometers

Ground deformation

As required.

Remote sensing

Ground deformation

Quarterly, at identified sites.

Frost bulb growth-crossings

Aerial patrol

Icings

Monthly.

Frost bulb growth-general

Aerial patrol

Drainage impedance

Monthly.

Buoyancy

Aerial patrol

Loss of cover

Monthly.

River scour-lateral

Aerial patrol

Loss of cover

Monthly.

River scour-vertical

Diver survey

Loss of cover

As required.

Right of way performance

Aerial patrol

Drainage and erosion integrity

Monthly.

Corrosion

Magnetic flux leakage or ultrasonic ILI

Metal loss

Initial run in years 5 to 7 of operations.

Frequency of subsequent runs based on in-line inspection trends.

Investigative digs

Cracking

As required.

Third party damage

Aerial patrol

Encroachment on rights of way

Monthly.

Seismicity

Aerial patrol

Slope movement

Monthly.

 

Loss of support

 

Views of the Board

Given the importance of strain monitoring in the current design, Condition 60 requires the Proponents to have the necessary in-line inspection tools available to inspect the pipeline during operation.

We agree with Indian and Northern Affairs Canada that establishing a base line for future in-line inspection monitoring of a pipeline's position is important. Condition 70 requires the Proponents to survey the position of the pipelines after they are lowered in the trench. We are not persuaded that Indian and Northern Affairs Canada's suggestion of running the in-line inspection twice in the first year is warranted given the pipelines will be in the ground two seasons prior to operation; however we are of the view that requiring a high resolution in-line inspection to determine their position within one month of operation has merit. Condition 70 requires that the Proponents monitor geotechnical and thermal effects on the Mackenzie Gathering System and Mackenzie Valley Pipeline with respect to thaw subsidence, frost heave and slope stability using inertial in-line inspection within one month of the start of operation and on an annual basis thereafter.

Condition 39 requires the development of an effects monitoring program. We have specified that the program's scope, objectives, monitoring methodologies, frequencies and criteria for the selection of instrumented sites be determined prior to the first of the pipe-laying activities to facilitate the early selection of sites to be monitored, the acquisition of detailed data on pre-disturbance/ pipeline operation conditions, and early installation of instrumentation.

To facilitate effects monitoring, and adaptive management during operation Conditions 66 and 68 to 72 require the submission of as-built slope information, post-construction environmental reports, ditch wall logs and the stream flow, ice thickness and ground temperature data used for project planning and design. Condition 37 which requires the filing of the Geotechnical Verification Program data and Condition 45 which requires the filing of the Proponents' geohazard assessments would also inform the effects monitoring program. In keeping with the National Energy Board's usual practice, these submissions will be available to the public by way of the National Energy Board's regulatory repository.

6.7 Emergency response

The Onshore Pipeline Regulations, 1999 requires pipeline companies to develop, regularly review and update, as required, an emergency procedures manual. A company must take all reasonable steps to inform all persons who may be associated with an emergency response activity on the pipeline of the practices and procedures to be followed, and make available to them the relevant information that is consistent with that which is specified in the emergency procedures manual. A company must also develop a continuing educational program for the police, fire departments, medical facilities, other appropriate organizations and agencies and the public residing adjacent to the pipeline to inform them of the location of the pipeline, potential emergency situations involving the pipeline and the safety procedures to be followed in the case of an emergency.

The Joint Review Panel recommended that we require the Proponents to provide, prior to the commencement of construction, and as part of the an emergency preparedness and response plan for all forms of transportation associated with the Mackenzie Gas Project, an assessment of the potential for the establishment of local, community-based spill response teams. This assessment would include their commitment to build community spill response and a discussion of the opportunities and constraints in establishing local spill response teams.

Views of the Board

Safely responding to a transportation emergency or spill requires coordination, training, knowledge of the products involved, the appropriate personal protective equipment and spill response equipment.

To address worker and public safety and environmental protection during construction, Condition 4 requires the Proponents to file an Emergency Response Plan at least 60 days prior to pre-construction. During construction, the Proponents and their contractors will be on the scene for incidents on the right of way, on project winter roads and at camps and they will be required to have the necessary resources to respond appropriately. We have therefore decided local, community-based spill response teams are not necessary for the construction phase of the project.

To ensure that the Proponents are prepared for an emergency on the first day of operation Condition 61 requires the submission of emergency procedures manuals at least 30 days prior to operation. We believe that local communities could be involved in pipeline emergencies occurring during operation as they may be the closest to the incident. Condition 61 requires an assessment of the potential for local community-based spill response teams,

opportunities and constraints of establishing these teams and a commitment to work with local communities to build and maintain capacity. Condition 62 requires the Proponents to confirm that they have completed an emergency response exercise to evaluate the effectiveness of their response plans prior to operation.

Government departments have responsibility for emergencies occurring on territorial highways, winter roads and on the Mackenzie River. They will have the responsibility for emergency response training and equipment needs at these locations.


6.8 Other requirements specific to the Mackenzie Gathering System

Views of the Board

We are of the view that the requirements for the Mackenzie Gathering System, regulated under the Canada Oil and Gas Operations Act, should be consistent with the requirements for the Mackenzie Valley Pipeline, regulated under the National Energy Board Act. In this regard, for the Mackenzie Gathering System, Condition 77 requires the Proponents to comply with the Onshore Pipelines Regulations, 1999, as amended from time to time; the National Energy Board Processing Plant Regulations, as amended from time to time; and those sections of the National Energy Board Pipeline Crossing Regulations Part I and Part II as amended from time to time. Similarly, Condition 78 requires the Proponents to file for approval the information referred to in the National Energy Board Filing Manual, 2004, for opening the pipeline for operation.

There are also requirements under the Canada Oil and Gas Operations Actthat apply to the Mackenzie Gathering System.

Condition 76 requires the Proponents to provide financial responsibility pursuant to the Canada Oil and Gas Spills and

Debris Liability Regulations and pursuant to subsection 27(1) of the Canada Oil and Gas Operations Act in the amount of $25,000,000 in a form satisfactory to the National Energy Board prior to commencement of pre-construction activities and that will remain in place until all facilities are abandoned in accordance with National Energy Board requirements.

Condition 79 stipulates that the authorization for the Mackenzie Gathering System under paragraph 5(1)(b) of the Canada Oil and Gas Operations Actis subject to the Minister of Indian Affairs and Northern Development Canada providing confirmation that the Proponents have satisfactorily met the Benefits Plan requirements of section 5.2 of the Canada Oil and Gas Operations Act.

Condition 80 requires the Proponents to provide a declaration pursuant to subsection 5.11(1) of the Canada Oil and Gas Operations Act in a form satisfactory to the National Energy Board prior to commencement of pre-construction activities.

Condition 81 requires the Proponents to provide any necessary certificates pursuant to subsection 5.12(1) of the Canada Oil and Gas Operations Actin a form satisfactory to the National Energy Board prior to commencement of the related activities.



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Date Modified:
2014-02-19