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EnCana has been operating at CFB Suffield, and within the area now designated as the National Wildlife Area (NWA), since 1975.

As of November 2005, 1,145 shallow gas wells had been drilled in the NWA. The average well density ranges from four wells per section (wps) to a maximum of 16 wps. Individual wells are tied into a natural gas pipeline system through 50.8 millimetre (mm) inside diameter (I.D.) (2 in.) lines. The loop2-6lines consist of 101.6 mm, 152.4 mm, and 203.2 mm (4, 6, and 8 in.) I.D. lines. There are estimated to be about 760 kilometres (km) of pipelines in the NWA.

EnCana proposes to drill 1275 shallow infill wells over three drilling seasons to extract the remaining shallow sweet gas from the area. Infill drilling is drilling that occurs within the defined boundaries of an existing natural gas pool. The target formations are between 250 m and 650 m deep. The new wells will be tied in to existing and new local gathering system to transport the additional gas volumes to existing compressor stations outside the NWA. Additional infrastructure required for the Project will include pig launchers and receivers, meters and isolation valves. Existing access roads will be used; no new roads (with built-up roadbeds) will be constructed. However, access routes to each well site will be established. The locations of Project facilities are shown in Figure 2-1 (PDF: 1.1M) and Figure 2-2 (PDF: 1.4M).

The Project will comprise part of EnCana's ongoing shallow gas drilling in the Suffield area, and the infill drilling will displace other segments of EnCana's overall Suffield program in any given year. Therefore, overall activity levels in the area will not increase from existing activity levels.

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2.1 Reservoir Characteristics
2.1.1 Shallow Gas
2.1.1.1 Geology
The natural gas-bearing units in the Suffield Area of southeast Alberta include the Second White Speckled Shale, the Medicine Hat, and the Milk River formations (all as further described herein). The natural gas pools have blanket-like geometries, natural fractures, and are delimited by permeability barriers. The regional extent of these pools is measurable and extends over approximately 35,000 km² in southeast Alberta and southwest Saskatchewan (O'Connell 2005) (see Appendix B)

The Second White Speckled Shale Formation is approximately 600 metres (m) deep and 40 m thick in the Suffield area. Production is from a series of regionally extensive distal marine shoreline units that occur within the upper 5 to 10 m of the Upper Second White Speckled Shale Formation. Facies include interlaminated sand and mud, muddy bioturbated sands, and transgressive marine sands (Leckie et al. 1994).

The Medicine Hat Formation is approximately 375 m deep and 60 m thick. The Colorado Shale separates the Medicine Hat Formation from the Second White Speckled Shale Formation. The lowermost facies is dark grey mudstone to silty mudstone, grading upwards to interlaminated and thinly interbedded mudstone, siltstone, and fine-grained sandstone. The First White Speckled Shale Formation lies above the Medicine Hat Formation and was deposited during a maximum marine transgression (Leckie et al. 1994).

The Milk River Formation in southern Alberta forms a sandy clastic wedge that tapers northward, where the top of the Formation is approximately 275 m in depth. The natural gas-bearing unit, named the Alderson Member, is characterized by a thick succession (80 to 100 m) of shallow shelf, marine interlaminated shale, siltstone, and fine-grained bioturbated sandstone. The reservoir is rich in clay, and has high water saturation (ranging from 70 to 95 percent) and low permeability. The Milk River Formation is capped by a transgressive conglomeratic lag, which in turn is unconformably overlain by the Pakowki Formation (Braman and Hills 1990).

The reservoir parameters are summarized in Table 2-1.

Table 2-1 Summary of Reservoir Parameters
Summary of Reservoir Parameters
	Effective Porosity (%)	Density Porosity (%)	Resistivity (ohm·m)	Formation isopach (m)	39% Neutron net pay (m)	Sw (%)	Initial Reservoir Pressure (kPa)
Milk River (Alderson)	5–10	10–17	8–12	90	85	70–95	3300
Medicine Hat	6–12	15	>10	60	8	60–80	4300
Second White  Speckled Shale	6–12	15–17	>10	40	5	60–80	5700
NOTES: kPa = kilopascal Sw = water saturation

The geologic stratigraphy in the Proiect area is shown in Appendix C.

2.1.1.2 Gas Composition
The natural gas that has been produced within the NWA, and that which will be produced from this Project, is sweet gas, containing no hydrogen sulphide (H₂S). The sweet gas was created biogenetically by the bacterial breakdown of organic matter in the reservoir, resulting in its characteristically high methane (CH₄) composition. Typical gas composition from the Milk River, Medicine Hat, and Second White Speckled Shale formations ranges from 95 to 98 percent methane. The remaining percentage comprises mainly nitrogen (N₂) and carbon dioxide (COM₂). Minor amounts of helium (He), hydrogen (H₂), ethane (C₂H₆), and propane (C₃H₈) are also found in the gas produced within the NWA.

Figure 2-1 Proposed and Existing Infrastructure within the NWA North (PDF: 1.1M)

Figure 2-2 Proposed and Existing Infrastructure within the NWA South (PDF: 1.4M)

A typical breakdown of the natural gas produced in the NWA is presented in Table 2-2:

Table 2-2 Typical Composition of Natural Gas in the NWA
Typical Composition of  Natural Gas in the NWA	Percentage (%)
He	0.10
N2	3.05
CO2	0.76
H2S	0.00
H2	0.00
CH4	95.82
C2H6	0.24
C3H8+	0.03
Total	100.00
SOURCE: Gas Analysis 3-35-15-5 - Core Labs

2.1.1.3 Production
Natural gas production from wells currently producing within the NWA began in November 1976. As illustrated in the Figure 2-3 (PDF: 25k), development drilling continued until 1986, when production reached a maximum rate of 2,386.3·10³ m³ (84.7 million cubic feet per day (MMcfpd)). Production rates declined to 845.2·10³ m³ (30 MMcfpd) until 1997, when additional drilling added incremental volumes. Moderate drilling activity and production optimization efforts increased production rates to 1,155.1·10³ m³ (41 MMcfpd). In December 2006, production from the current wells averaged 853.7·10³ m³ (30.6 MMcfpd). Total cumulative production to the end of December 2006 was 12,190.9·10⁶ m³ (432.7 billion cubic feet (bcf)). EnCana expects the existing wells within the NWA will recover an additional 3,400·10⁶ m³ (120 bcf) over their remaining life of 20 to 25 years.

To evaluate the feasibility of the infill development, EnCana conducted a pilot project in the Riverbank and Middle Sandhill areas of the NWA, before the establishment of the NWA, involving well spacing of 16 wps. The pilot project evaluated, and confirmed, the geologic and economic suitability of the area for infill drilling. In addition, production from the pilot project confirmed that recovery of natural gas volumes with the infill wells increasing well density to 16 wps is incremental recovery over well density of 8 wps. These conclusions are also supported by reservoir modeling and simulation, based on EnCana's proprietary analysis methods.

The production and reserves performance observed in the pilot area (and from other areas where development is at 16 wps) were used to forecast the production from the Project. This forecast, which assumed development over a three-year period, is also shown in the figure above. This results in total incremental volumes of 3525·10⁶ m³ (125 bcf) that will be recovered over a period of 20 to 40 years.

Figure 2-3 Suffield Natural Gas Production (PDF: 25k)

EnCana is currently developing the majority of its lands outside the NWA with infill drilling to 16 wps, in accordance with down-spacing and commingling orders approved by the EUB. These orders acknowledge the need for increased well density and multi-zone commingling for best recovery of the natural gas and conservation of the resource.

As of January 2007, EnCana has drilled over 3500 wells in the Western Canadian Shallow Gas Complex to 16 wps density. Other companies including Apache Canada Ltd., Anadarko Canada Corporation and Nexen Inc. have drilled over 3500 wells at this increased density. In the surrounding areas to the NWA, EnCana has drilled 124 sections including the D6/D8 area of the NWA, Koomati area adjacent to the NWA and in the Military Training Area (MTA). The results of the drilling programs indicate significantly increased reserves can be recovered with minimal environmental effects.

The techniques utilized to drill, complete and tie-in the wells for the Project are essentially the same techniques utilized for the surrounding areas since 2003. The wells are drilled utilizing coil-tubing or single drilling rigs and spider plough or chain ditchers are utilized to tie-in the wells. The primary differences between the Project and other 16 wps projects are:

1. Timing of the activities - Winter construction only in the NWA. Outside of the NWA, EnCana conducts activities in appropriate field conditions year round. To minimize the effects on the environment, EnCana attempts to conduct activities in dry or frozen conditions in all projects;
2. Use of caissons - Current practices outside of the NWA, where military activities (including training) may occur, EnCana places the wells underground in caissons. Caisson installation has not been proposed as part of the Project. Caissons increase soil and vegetation disturbance thus increasing the footprint of the wells;
3. Reclamation practices - EnCana adapts its practices based on site conditions and the disturbance levels. In general, EnCana does not seed disturbed areas such as bellholes and tie-in points immediately after the disturbance as is proposed for this Project. The timing of reclamation activities is dependent on military schedules and site conditions so there may be a delay in reclamation timing compared to the proposed schedule for the Project;
4. Reduced potential well sites - EnCana has committed to not drilling on the floodplain of the South Saskatchewan River, near to wetlands or water bodies and other sensitive environments for this Project;
5. Additional Project specific training - EnCana conducts some training sessions for all projects. This Project includes more detailed training including specific training on species identification, environmental practices, etc.; and
6. Additional monitoring and follow-up activities - EnCana follows regulatory requirements on monitoring and follow-up activities. For this Project, EnCana has developed additional practices including additional construction phase monitoring

2.1.2 Other Hydrocarbon Production (Deep Rights)
EnCana recognizes there is a possibility of both Bow Island and Basal Colorado gas reserves underlying the Project area. The Bow Island Formation is approximately 675 m deep and 100 m thick in the NWA. The Bow Island Formation consists of six major coarsening upwards successions from distal marine to shore face and barrier bar facies. Production is generally from the three uppermost sand packages and the lowermost sand package. The Basal Colorado Formation is approximately 775 m deep and 5 m thick in the NWA.

However, the NWA was precluded from deep rights access for petroleum and natural gas development by the DND-Alberta Deep Rights Agreement of 1999; therefore, at this time EnCana does not foresee the deep gas being developed.

The Taber Coals are approximately 130 m deep while the McKay coals have pinched out and are not present in the NWA. Where they occur in the NWA, the Taber coal seams are thin and in proximity to the groundwater aquifers (above the base of groundwater protection). EnCana does not view these coals as having any potential for gas production in the reasonably foreseeable future. The deeper Mannville coal seams (approximately 825 m deep) are also thin in the NWA.

EnCana has no current plans to develop any deep gas, coalbed methane or oil in the NWA.

The Project phases include wells, gathering pipelines and associated above ground facilities, access, and other infrastructure.

2.1.3 Project Components
The Project components include wells, gathering pipelines and associated above ground facilities, access, and other infrastructure.

2.1.4 Wells
The locations of the proposed wells are shown in Figure 2-2 (PDF: 1.4M) and Figure 2-1 (PDF: 25k). [Updated from original report.] Typical well site layout is shown in Figure 2-4 (PDF: 108k). A typical well schematic is shown in Figure 2-5 (PDF: 19k).

2.1.5 Gathering System
The majority of wells will be tied into the existing local gathering system (laterals) using 50.8 mm (2 in.) I.D. high-density polyethylene plastic (HDPE) pipe. In some cases, new gathering systems (back end loop lines) may be required. To tie in the new wells into the gathering system, approximately 180 km of HDPE is expected to be required. Approximately 40 km of 101.6 mm, 152.4 mm, or 203.2 mm (4, 6, or 8 in.) I.D. steel pipe will be required for loop lines to transport the gas to existing compressor stations outside the NWA. Backend loop lines may be required where there is insufficient capacity to transport the gas in existing laterals. While working areas during construction will typically be 15 m wide, the width of the linear disturbance (i.e., topsoil stripping for ditching installation of steel pipe) will be limited 2 to 4 m.

The gathering system will also include aboveground group meters, pig launchers and receivers for pipeline integrity inspection, and isolation valve stations. Typically, each battery of 12 sections will require one group meter, one pigging facility, and one to three isolation valves.

2.1.6 Access
Existing access roads will be utilized whenever possible and where appropriate. Each well site will have an access route (i.e., prairie trail without a built-up road base) for construction and operations.

2.1.7 Other Infrastructure
Other infrastructure required for the Project will include remote sumps.

Containment sumps for drilling fluids will be designed to improve the separation of liquids and solids via gravity or settling out of the solids, reducing the amount of water used for drilling by up to 10 percent. Remote sumps will be outside the NWA on previously disturbed areas of CFB Suffield, and will be reclaimed following the construction season using mix-bury-cover methods.

For fast communication, "spread spectrum" radios will be used at each group meter site. The radios have low energy requirements, can use low profile antennas and the configuration settings can allow for repeaters to access low lying areas without additional towers or infrastructure. Transnet, 900 MHz radios will be used for communication to the Supervisory Control and Data Acquisition (SCADA) host from Remote Terminal Units (RTUs) installed at group meter sites; this will reduce the need for and frequency of site visits. The transmitter output power of these radios is 1 Watt (W). A Yagi directional antenna mounted on an aluminum 50.8 mm schedule 40 mast will be required for each radio. The mast height, including antenna, will range between 0.9 and 1.5 m.

Figure 2-4 Typical Well Layout (PDF: 108k)

Figure 2-5 Typical Well Schematic (PDF: 19k)

No temporary power lines will be needed. Direct current batteries with a solar panel (60 cm X 60 cm) will be used to supply permanent power to the group meter site transmitters, RTU, and radio. These solar panels will be mounted on the radio transmission antennae with a 22.5 degree angle to maximize solar cell exposure to the sun. Based on power requirement calculations at previously installed metering setups and polling frequency of sites in the area, each meter site will require one 30 W solar panel and two batteries (100 Amp-hours). Based on past experience, the life cycle of these batteries is expected to be three years.

Existing infrastructure to be used for the Project but which will not require any changes to accommodate the incremental Project production includes the existing produced water treatment facility at 04-03-015-06 W4 and compressor stations (see Figure 2-6 (PDF: 977k)). No new compression capacity is required for the Project, as the production from the infill wells will offset declining production from existing wells. Moreover, peak production rates experienced during the initial start-up of past infill projects demonstrates that the compression horsepower currently in service is ample for the infill development.

Figure 2-6 Existing Compressor Stations (PDF: 977k)

No new lay down or temporary storage areas will be required during construction. Existing lay down and storage areas will be used as required for storage of equipment and materials.

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2.2 Project Phases
The phases of the Project will include preconstruction activities, construction, operations, and decommissioning and abandonment.

2.2.1 Preconstruction Activities
Preconstruction activities include baseline mapping, site selection, and an ordinance sweep done by Suffield Industry Range Control (SIRC). Careful preparation and pre-construction planning is the first and most important aspect of minimal disturbance practices.

Since 2005, EnCana has been developing its baseline mapping tool for the Suffield area to support effective decision-making regarding site and route location. EnCana's baseline mapping process uses an environmental database for the predisturbance assessment (PDA), and is complemented using additional data compiled from a search of available provincial and federal data sources, as well as information gathered during desktop studies or from prior fieldwork undertaken in relation to other EnCana projects at CFB Suffield.

The baseline mapping layers include:

• palaeontological resources and potential (including regional stratigraphy);
• archaeological resources and potential;
• terrain (landscape, slope, and sand dunes);
• soils;
• vegetation;
• wetlands and riparian areas (permanent, temporary, and intermittent);
• wildlife; and
• existing infrastructure (roads, pipelines, well sites, remote metering).

The information compiled through the baseline mapping process will be used to identify ecologically and culturally sensitive areas and to determine the least disruptive locations for well sites, access routes, pipelines, and associated infrastructure.

Once the baseline information for the PDA is compiled, a series of team planning meetings will be held to discuss siting or routing issues and select preliminary sites and routes. These team planning-meetings will typically include personnel involved in the Project, such as geologists, project engineers, construction personnel, and environmental professionals. This process reduces the number of visits to, and the number of crews visiting, each of the sites.

Once preliminary locations are chosen and any outstanding potential environmental issues are identified, then all locations will be field-checked. The field component allows any outstanding issues to be confirmed and addressed at the field level.

A field crew consisting of environmental specialists (e.g., biologists, archaeologists, and botanists), surveyors, and construction staff will visit each location to collect additional site-specific data and to ensure each location is suitable, with respect to terrain, wildlife, vegetation, and other environmental concerns, before construction. Adjustments to locations (or relocations) will be made accordingly. Site-specific mitigation measures will be developed for any potential issues identified in the field, before construction.

In selecting site and route locations, the following criteria will be considered:

• minimization of ground disturbance;
• shortest distance between facilities;
• provincially and federally designated wildlife species at risk;
• sensitive wildlife species;
• critical or sensitive habitat;
• rare plants and rare plant communities;
• wetlands, waterbodies and riparian areas;
• historical, archaeological, and palaeontological resources;
• research locations (e.g., sampling or data collection sites); and
• sensitive and unstable soils and terrain.

EnCana does not anticipate that the Project will require crossing permanent watercourses, and no well sites will be on the floodplain of the South Saskatchewan River.

The existing and potential future access needs of other users of lands in the NWA typically are taken into consideration during access planning, through consultation with the Department of National Defence (DND) and SIRC who are responsible for managing oil and gas personnel access within CFB Suffield. However, no new roads will be constructed for the Project. Well site access routes are not expected to be used by other parties. EnCana is the only active operator within the NWA. No other Project infrastructure is suited to any other user's needs.

2.2.2 Construction
The construction phase includes drilling, completion, tie-in of the wells, and post-construction cleanup.

Once drilling locations have been finalized, access to each well site will be determined. To minimize disturbance to the prairie environment, no new roads (i.e., with built-up roadbeds) will be constructed, and all access routes will be marked in the field to ensure all traffic is restricted to specified routes. Whenever possible, EnCana will use existing access routes. If gravel is required to improve the existing road conditions and reduce rutting, clean gravel will be brought in from existing sources outside the NWA.

EnCana will contractually require that all equipment will arrive in a clean condition (i.e., free of weeds) to minimize the risk of weed introduction, and will be in good working condition to minimize emissions and noise. Weed management is discussed in the Environmental Protection Plan (EPP) in Appendix I.

All wells will be drilled using minimal disturbance techniques to minimize soil disturbance, preserve the soil regime, and maintain the existing seed bed. . Full stripping and topsoil removal is not required during drilling; the only topsoil that is removed is at the wellhead itself. Topsoil will be removed at points of connection (bell holes) between wellheads and tie-in pipelines, and between tie-in pipelines and steel gathering pipelines. Normally topsoil stripping will not be required for the 50.8 mm (2 in.) I.D. HDPE pipelines, but minimal stripping will occur for steel gathering pipelines installed by trenching techniques. Rock and frozen conditions may require the salvage of topsoil from the anticipated disturbance width. Where feasible, soil handling activities will be completed during unfrozen soil conditions to minimize the environmental effects on vegetation and soils.

EnCana will suspend construction activity when site and weather conditions are such that the soil resource may be adversely affected (e.g., by compaction, rutting, remoulding, mixing, or erosion). All construction activities will comply with EnCana's Environmental Protection Plan (EPP) for the Project.

There is no public access to the NWA. Access to CFB Suffield, including the NWA, is restricted by fencing and gates. EnCana employees and contractors muster at existing gates and facilities outside the NWA and all movements within the NWA are coordinated with SIRC.

Construction figures are available in Appendix O.

2.2.2.1 Drilling
The drilling of the shallow gas wells will involve the following steps.

• A small conductor rig will be moved in and will drill until a 177.8 mm (7 in.) I.D. conductor pipe (or casing) can be cemented in place at depth of approximately 27 m.
• After the conductor pipe has been set, the drilling rig and associated equipment will move onto the lease (approximately five truck loads) and continue drilling. The drilling rigs used to drill the shallow gas wells will be either "single rigs" or coil tubing rigs which have a continuous coil of 60.3 mm (2 3/8 in.) tubing (with 159 mm (6 ¼ in.) bit) which serves as the drill pipe. It will take between 14 and 20 hours to drill each well to the total depth of 450 to 650 m, depending on location.
• A string of 114.3 mm (4 ½ in.) casing will then be run into and along the total length of the well and cemented in place. Cementing the production casing will hydraulically isolate groundwater from the wellbore.
• All drill cuttings and drilling fluid (water) will be collected in on-site tanks while drilling, and removed from the NWA for disposal.

2.2.2.2 Completions
Well completion will follow drilling and allows the gas encountered during drilling to be produced. Well completion will involve the following steps.

• A well logging truck and crew will run an electronic well log from the total depth to surface.
• The wellhead will be installed.
• The well will be pressure-tested to ensure hydraulic isolation.
• A swabbing unit, typically a five-ton truck, will remove the water in the wellbore and collect it in a truck-mounted tank for use at the next wellsite as completion fluid.
• A perforating unit will place perforations in the casing at the appropriate depths as determined through interpretation of the well log.
• A blowback tank (skid unit) will be placed on location for the duration of the completion.
• The well will be fracture (frac) stimulated. This activity involves pumping sand and friction-reduced water down the wellbore at high pressure. The pressure forces the producing formations downhole to fracture and the sand fills these fractures. This operation allows the wells to flow at commercial rates. Fracturing requires 10 to 15 trucks on location and typically takes 4 to 6 hours.
• The well will be flowed back to the blowback tank to remove as much of the water used in the fracture process as possible. There is typically a small amount of sand in the water that is flowed back. The recovered fluid and sand will be contained in the blowback tanks and taken off-site to the next site, where the fluids will be clarified for re-use and the solids transported to an existing sand recycling facility outside the NWA.
• The well will be cleaned, with air, using a small coil tubing unit to remove any remaining fluid.
• The well will be shut in until it is tied into the gathering system.
• The well will be swabbed and turned on when the pipeline is attached.

2.2.2.3 Well Tie-ins
Well tie-in will follow well completion, and will involve the following steps.

• Wells will be tied into the existing or new gathering system using 50.8 mm (2 in.) I.D. HDPE pipe. The HDPE pipe is a continuous pipe that will be brought to location on a large roll.
• In the NWA, it is anticipated that, based on operating experience, all HDPE pipelines can be buried (ditched) using low impact ploughing equipment (such as the spider plough). An assessment of the feasibility of ploughing in pipelines will be done before the initiation of construction and be re-evaluated continuously throughout the activity. Factors which may preclude ploughing include: surface and subsurface stones, frozen soils, adverse topography, heavy clay soils, and wet conditions. Using the spider plough, the roll of pipe will be ploughed into the ground at a depth of 1.5 m (5 feet). This technique results in minimal disturbance to the ground; no topsoil would be stripped. In addition, the width of the pipeline ROW is kept as narrow as possible. Conventional techniques (chain ditcher) will be used if ploughing is not feasible or if it is determined that ploughing in will result in excessive damage to soils and vegetation. The total pipeline length used will depend on the proximity of the existing gathering system to the wellbore. Lengths of tie-ins will typically range between 200 and 400 m.
• Once the pipeline is buried, reclamation activities will take place. Post construction and cleanup activities will occur.
• Once the well is tied-in, the well will be brought on-stream.
• Where back-end loop lines are required, 101.6 mm to 203.2 mm (4 to 8 in.) I.D. steel pipelines will be required to allow for effective transport of the gas to an existing gathering system. These pipelines are expected to average 3 to 6 km in length and will be installed using conventional ditching techniques. Typically stripping of topsoil along these ROWs will be restricted to 1 or 2 m, depending on soil conditions.
• Pipelines will be integrity tested before commissioning.
• Working space for pipeline installation typically will be 15 m, and up to 30 m where required (e.g., curves).

2.2.2.4 Post-construction and cleanup activities
EnCana will commence initial cleanup immediately after construction activities. The final cleanup schedule will vary depending on conditions, time of construction, and any military lockouts. If construction is complete during frozen conditions, final cleanup will typically occur after spring breakup. If construction is completed during nonfrozen conditions, final cleanup will be undertaken as quickly as practical and before freeze-up.

Well leases and pipeline ROWs will be constructed using minimal disturbance and no-strip techniques where possible. No new roads will be constructed. Therefore, it is not anticipated any additional fill or soil will be required for reclamation. In the unlikely event additional fill or soil is required for reclamation of lease areas, ROWs, or access routes, such material will be sourced from an existing borrow pit or stockpile outside the NWA. Once construction is complete, bell holes (i.e., at connections between wellheads and tie-in pipelines and between HDPE tie-in and steel gathering lines) will be immediately backfilled using native subsoil and topsoil.

Disturbed ground will be recontoured, where necessary, and reseeded or left to recover naturally, depending on site conditions. Reclamation of disturbed ground will be described in the Conceptual Reclamation Plan (Appendix H) and the Soil Loss Mitigation Plan (Appendix N). As sites will be on level ground, erosion control or storm water management is expected to be minimal.

All remaining equipment, garbage, and debris will be removed from the well site and ROW.

2.2.3 Operations
The main activities done during the operations phase are well testing, well and pipeline inspection, swabbing (if necessary), refracturing (if necessary), and reclamation maintenance (if necessary). As during construction, access to sites within the NWA will be coordinated with SIRC.

2.2.3.1 Well Testing
Wells will be regularly tested and evaluated. Well site visits in the NWA will average one visit per month in the first year of production and annually thereafter. These visits will involve the use of a ¾-ton truck. Typically, one truck can visit approximately 15 to 20 wells in a day. A yearly test of the well's performance is required by EUB regulations. Wells will only be visited during dry or frozen conditions for this annual test.

2.2.3.2 Swabbing and Well Site Visits
Well site visits, after the first year of production, will average one visit per year providing no water is produced in the wellbore. In the event water is produced at any time in the wellbore, well site visits will average four visits per year. If there is water produced, well site visits would involve the use of a swabbing unit and tank truck. Swabbing, if necessary, will only occur in dry or frozen conditions. The water produced into the wellbore would be removed. All water swabbed out of the wells would be contained in a tank truck and transported to the existing produced water treatment facility. The management of produced water from the Project will not require any new infrastructure.

Siphon strings for produced water removal may be considered for wells that have measurable water production and are in areas difficult to access.

2.2.3.3 Pipeline Protection
Work done to protect the integrity of EnCana's pipeline system is important to shareholders and the environment. For shareholders, this work extends the useful life of a valuable asset; and for the environment, this work minimizes environmental effects associated with pipeline leaks. The root cause of nearly all pipeline leaks in Suffield is associated with metal corrosion. Because of this, EnCana has implemented a number of strategies aimed at preventing corrosion of metal pipelines:

• Use of HDPE (High Density Polyurethane) pipe.
  HDPE pipe is not subject to metal corrosion. As a result, HDPE is the material of choice when the expected capacity of a well or wells falls into the capacity range of pipe made with HPDE.
• Cathodic Protection Program
  This program is a strategy used to prevent external corrosion. All metal pipelines are cathodically protected and regularly monitored.
• Biocide and Inhibition Program
  This program is a strategy used to prevent internal corrosion. The root cause of nearly all internal corrosion is a result of water introduced to the pipeline system from the wellbore. Key contributors to this type of corrosion is the presence of bacteria in water produced from the wellbore and the composition of the water produced from the wellbore. Only wells equipped with a siphon string have the ability to introduce water to the pipeline system from the wellbore. As a result, all wells equipped with a siphon string are placed on the biocide/inhibition program.

To combat corrosion related to bacteria, biocide (Nalco/Exxon EC6222A) is injected into the wellbore through the casing annulas. This allows the biocide to contact and mix with water in the wellbore thus killing the bacteria. Enough biocide is injected to not only kill the bacteria in the wellbore but to also kill bacteria in the pipeline when wellbore water is produced up the siphon string and into the pipeline system. This treatment is performed 2 times per year and each treatment requires 4 litres of biocide mixed with 4 litres of water.

To combat corrosion related to the composition of the wellbore water, corrosion inhibitor (Brentagg T-8084) is injected into the pipeline at the well site pig senders. Corrosion inhibitor coats the internal metal surface of the pipeline thereby preventing water and metal contact. This treatment is performed 2 times per year and each treatment requires 2 litres of inhibitor and 2 litres of water.

Pipeline pigging is an important element of this program as it is used to move the biocide, inhibitor and wellbore water through the entire pipeline system (from the wellhead to the produced water tanks at the production facilities). Once in the produced water tanks, fluids are trucked to a water disposal well for downhole injection.

Because the biocide and inhibitor in combination with wellbore fluid can foam in the pipeline, diesel fuel is sometimes used as a defoamer. It is only used when the pipeline pressure differential (well site to production facility) causes gas production from the wells to be limited. When diesel fuel is used it is injected into the pipeline system through a pig sender. Each treatment usually requires 20 litres and is only performed when required (see Table 2-3).

Table 2-3 Annual Volume Summary of the Products used in the Biocide and Inhibitor Program
Product	Volume
Biocide (Nalco/Exxon EC6222A)	36,400 litres
Corrosion Inhibitor (Brentagg T-8084)	18,200 litres
Diesel Fuel	2,500 litres
Water	54,600 litres

Biocide, corrosion inhibitor and diesel fuel are stored in bulk tanks meeting EUB G-55 requirements. No fuel or chemicals will be stored within the NWA. The following table is a summary of the locations used for storage of products used in the biocide and inhibitor program:

2.2.3.4 Well Inspections and Pipeline Integrity Checks
Pipelines and wellheads will be inspected yearly for leaks and damage. Any leaks detected will be immediately repaired pursuant to EUB regulations. Additionally, EnCana periodically monitors its pipeline ROWs during the operational phase. EnCana's operators are trained to identify issues including subsidence, erosion, and weeds, and will monitor conditions during routine operational activities to ensure integrity. No ROW maintenance is normally required, based on operating experience in the area.

Road and access and lease conditions are one of the primary factors when planning and scheduling operational activities. EnCana's practice is to defer operational site visits and activities when conditions are excessively wet and when site and weather conditions are such that the soil resource may be adversely affected (e.g., by compaction, rutting, remoulding, mixing, or erosion). Where it is necessary to access a site during wet conditions, EnCana will consider the use of all-terrain vehicles to reduce damage to the environment.

2.2.3.5 Refracturing
Although not typically required, for some wells, it may be necessary to refracture the producing formation. This activity is essentially a repeat of the completion process described above. If required, refracturing would take place 15 to 25 years after the initial completion.

2.2.4 Decommissioning and Abandonment
Decommissioning and abandonment of both production and pipeline facilities will be undertaken at the end of the life of each well and in accordance with all regulatory requirements applicable at the time of such activities. Although regulatory requirements may change before the time of decommissioning and abandonment, current practices would require the producing zones to be isolated with bridge plugs and topped with eight linear metres of cement. The well would then be filled with inhibited fluid. Finally, the well would be cut and capped at least 1 m below the surface. Pipelines will be purged, capped and tagged.

EnCana will employ effective conservation and reclamation measures to ensure land disturbed by the Project is reclaimed to meet the goal of equivalent land capability. Disturbed land will be reclaimed using appropriate site-specific methods (i.e., seed mixes or natural recovery) determined in consultation with regulators. A Conceptual Reclamation Plan is discussed in Appendix H.

2.2.5 Malfunctions and Accidents
EnCana has an Environmental, Health and Safety Risk Matrix to analyze the probability and impact of failure on personnel, the public, the facility, the environment and/or EnCana's reputation. The process EnCana utilizes to determine the risk is:

1. Identify the risk or concern;
2. Estimate the Project effects on four factors: People, Environment, Assets and Reputation;
3. Estimate the probability of the risk/concern occurring;
4. Determine the risk potential; and
5. Determine the risk level and appropriate actions, if necessary.

Risk is categorized in terms of:

• Extreme - the activities must stop until risk controls have been implemented to reduce the risk to a lower level;
• High - extensive risk controls must be implemented immediately;
• Medium - risk controls are required; and
• Low - some risk controls are justified.

EnCana's extensive experience with shallow gas construction, operations and decommissioning and abandonment provides a high degree of certainty in the evaluation of the risk. EnCana's evaluation of the Project is that there is low level of risk due to minor to moderate potential effects on people, environment, assets and reputation with a remote probability.

As part of reducing the risk, EnCana has an emergency response plan (ERP). The emergency response plan is designed to maximize public safety. As part of the emergency response plan, EnCana has identified an emergency planning zone as required by the EUB.

EnCana has considered how the security conditions in the region could be affected by the Project and concluded that there will be no change in the security conditions as EnCana continues to operate under the direction of the military through Range Standing Orders (RSOs) and industry access to the Base is controlled by SIRC. All personnel active in the NWA undergo training by SIRC regarding the specific procedures necessary for CFB Suffield.

This section provides an overview of potential malfunctions and accidental events that, while unlikely, may occur during the Project and may result in potential environmental effects. These include collisions and releases from vehicles, pipeline accidental releases, blowouts and surface casing vent flow, and grassland fires. Design, inspection, maintenance, and integrity assurance programs, as well as proven engineering techniques, will be in place to prevent such events from occurring. All safety procedures will be documented and in place before the commencement of routine operations.

Given the low pressure of the natural gas, any event (including exploding ordinance or human error) that resulted in a large hole in the pipeline or destruction of a wellhead would be remedied by the shut-in of the production until the damage could be fixed. It is extremely unlikely that the release of natural gas would result in a flashfire. In 30 years of operations in the NWA, there has never been significant damage to a pipeline or wellhead as a result of human error, military activities or extreme weather (i.e., tornados).

All fuel, chemicals, and wastes will be handled in a manner that minimizes or eliminates routine spillage and accidents. EnCana's Environmental Protection Plan (EPP) and Emergency Response Plan (ERP) include safe chemical handling and storage procedures, as well as accidental release response measures, such as the use of cleanup equipment, training of personnel, and identification of personnel to direct cleanup efforts, lines of communications, and organizations that could assist cleanup operations.

2.2.5.1 Collisions and Releases from Vehicles
The risk of collisions between vehicles is anticipated to be extremely low, based on compliance with standard procedures and motor vehicle regulations and speed limits. On average, 288 industry vehicles enter CFB Suffield each day. On average, two industry (EnCana) vehicles enter the NWA each day, so the chances of collision and resulting releases are less in the NWA than in other parts of CFB Suffield. In the unlikely event a collision occurs, EnCana's ERP would address response procedures.

Pursuant to EnCana's Environment, Health, and Safety Best Practices (described below), EPP, and ERP, all vehicles will be inspected regularly and kept in good working order. In the unlikely event there is an accidental release from a vehicle, it will be small in magnitude and extent. Accidental release cleanup will be undertaken pursuant to EnCana's EPP. Vehicle-related accidental releases may comprise hydraulic fluid, diesel fuel, gasoline, waste products, fresh water, produced water, transmission fluid, and methanol.

2.2.5.2 Pipeline Releases
The gas gathering system will be designed and maintained in a manner that minimizes the frequency and extent of any releases. Table 2-4 presents the results of EnCana's ongoing efforts to minimize risks for personnel and the environment. In 30 years of operation in the NWA, pipeline releases have been small enough to be undetectable via conventional gas production measurement equipment. The primary detection devices used to detect pipeline releases are gas ionization equipment used during pipeline integrity inspections and gas detection equipment used by all personnel working on the Suffield Block. For these reasons, release volumes associated with pipeline leaks are estimated to be no more than those volumes released by a surface casing vent leak and deemed non-serious by the EUB.

Table 2-4 Pipeline Releases
Time Period	Releases	Releases per Year
1991-1999	33	3.7
2000-2004	9	2.3
2005-2006	1	0.5

 

The observed performance improvement can be primarily attributed to the change to HDPE pipe and the implementation of a corrosion inhibition program to combat internal corrosion. As the gas gathering system will comprise primarily HDPE pipe and a corrosion inhibition program is and will be implemented, it is anticipated releases will not exceed one or two per year (due to internal corrosion).

Because the pipelines and wells contain primarily methane, there will be no pipeline releases of hydrocarbon liquids that could pool and adversely affect ecosystem components such as wetlands and wildlife.

Dispersion of natural gas from pipeline or well casing leaks without ignition poses no immediate hazard to humans or the environment. Due to the low pressure of shallow gas reserves in the NWA, safety and environmental risks associated with the dispersion of natural gas from pipeline or well casing leaks are considered low. To further mitigate safety and environmental risks, all personnel working for EnCana are trained in the detection of leaks and in safe work practices where the potential for leaks exists.

The small amount of released natural gas can become hazardous in the event it is ignited. Based on the level of activity near the wells and pipelines, it is extremely unlikely releases will be ignited outside auto-ignition from the energy released and possible sparks generated in the occurrence of the leak.

The risk to public and worker safety is considered extremely low at the pipeline or wellhead and insignificant more than 25 m from the pipeline or wellhead, given the low likelihood of the occurrence of an initiating accident combined with extremely low ignition probability and a correspondingly low likelihood of people being exposed. Routine inspection and maintenance serves to minimize potential risks. In over 30 years of operations at CFB Suffield, there has never been an injury related to a flash fire.

2.2.5.3 Blowouts and Surface Casing Vent Flow
As the wellhead pressures in the NWA are low (average pressure is approximately 350 kPa), especially after the first year of production, it is extremely unlikely any well blowout will occur. In over 30 years of operations at CFB Suffield, there has never been a gas well blowout.

EnCana utilizes gate valves at the wellhead, two ball valves in the gas gathering system and where necessary a check valve to ensure the gas pressure is controlled. Given the low pressures in the NWA, pressure safety valves are not necessary.

Surface Casing Vent Flow (SCVF) is the flow of gas and liquid or any combination out of the surface casing and casing annulus (often referred to as internal migration). Gas Migration (GM) is a flow of gas that is detectable at surface outside the outermost casing string (often referred to as external migration or seepage). A SCFV or GM that is considered serious will be repaired as soon as possible pursuant to EUB Interim Directive 2003-01.

SCVF/GM problems that are not considered serious will be addressed at the time of well abandonment. SCVF/GM instances are rare and historically EnCana has had 56 SCVF out of more than 9000 wells at CFB Suffield.

2.2.5.4 Water Contamination
Information available to date has shown that contamination of underground water aquifers from shallow gas wells has not occurred. EnCana has operated at CFB Suffield for 30 years without contaminating the underground aquifers. EnCana complies with all regulatory requirements including drilling and cementing practices which greatly reduces the potential of groundwater contamination.

The EUB has comprehensive regulations and requirements that are designed to maximize safety during the exploration for, and production of, oil and gas resources. Regulation serves not only to ensure efficient development to maximize resource recovery in the interests of all Albertans, but also to ensure a safe and reliable infrastructure of energy facilities (ERCB website: http://www.ercb.ca/portal/server.pt?open=512&objID=248&PageID=0&cached=true&mode=2)

Based on the distances to the nearest drinking water supply, even if, in the extremely unlikely event, there was a potential problem with communication between the gas formation and the underground aquifer or a casing leak, there is no risk to nearby community or private water supplies. In the extremely unlikely event that there is contamination of the groundwater, EnCana will comply with EUB regulatory requirements and remedy the situation as quickly as possible and alert all affected persons.

Based on EnCana's experience at CFB Suffield and in the NWA, EnCana has determined that a permanent leak detection system is not necessary. EnCana is confident that the existing biocide program and the conversion to HDPE pipelines for the laterals combined with the pipeline integrity testing program is sufficient to reduce the risk of pipeline leaks.

2.2.5.5 Water Requirements
For each well drilled, approximately 75 m³ of water will be required for drilling and drilling products and approximately 100 m³ of fluid will be required for well completions. To reduce water use during shallow well drilling, EnCana will recycle water. For drilling, containment sumps will be designed to improve the separation of liquids and solids via gravity or settling out of the solids, reducing the amount of make-up water required by up to 10 percent. For completions, the fluid will be recovered and separated out in temporary storage tanks, reducing the amount of water required by up to 25 percent.

Consequently, for each well, the net demand for drilling water is approximately 67.5 m³ and the net demand for completion water is approximately 75 m³. The total fresh water requirement for each well is, therefore, approximately 142.5 m³. Therefore, total water demand for construction is approximately 181,687 m³, which will be spread out over three construction seasons, primarily between October and April.

During operations, water requirements will be intermittent, but will occur primarily between October and April. Routine corrosion protection treatment of water-producing wells will require approximately six litres of water twice yearly per treated well. This water is typically supplied by the pigging contractor from municipal water supply in Medicine Hat. The number of wells that will require treatment is unknown at this time, but is expected to be low, based on past operating experience in the area. Refracturing typically requires approximately 75 m³ per well, of which up to 25 percent may be recycled. If all wells are assumed to be refractured, approximately 71,719 m³ of water will be required; refracturing water demands will occur, and be spread out over, 15 to 25 years after initial completion.

EnCana holds a temporary licence for the withdrawal of 18,000 m³ of water from the South Saskatchewan River at NE 23-17-5 W4. The licence stipulates conditions to protect fish and water quality and quantity in the river, including minimum passing flow, screen mesh size, and diversion rate, among other conditions. Water will be withdrawn from the South Saskatchewan River in accordance with the licence conditions.

Groundwater and surface water allocations are determined by the Alberta Government as such any issues with the allocation of water will be resolved by the Alberta Government. As the amount of water withdrawn from the South Saskatchewan River Basin is relatively small, it is not anticipated to have any negative environmental effects on surface water users who have existing approvals, permits or licenses. It has been proposed by the Alberta Government that conflicts between water users will be resolved by allocating water based on a "first in, first out" principle. Therefore, users who have been allocated water for a longer time period will be allocated water preferentially over new water users.

Any local water issues involving the use of dugouts will be resolved in consultation with the Prairie Farm Rehabilitation Administration (PFRA) and the DND as necessary. PFRA and EnCana have different water sources allocated; therefore, it is not anticipated that there will be any conflicts over water use.

In the event of drought conditions, EnCana will develop contingency plans to obtain the required water from alternative sources. In extreme drought conditions, it may be necessary to stop/avoid certain activities that require water.

Water will be withdrawn from the South Saskatchewan River in accordance with licence conditions, using a water truck equipped with pump and a screened hose.

Water also will be sourced from existing water wells and spring-fed dugouts within CFB Suffield, at 12-6-17-5 W4 (20,000 m³/yr licensed), 4-4-16-6 W4 (73,000 m³/yr licensed), 5-2-20-7 W4 (well and dugout), 10-16-20-7 W4 (well and dugout), and 10 16 20 8 W4 (well and dugout), all located within the NWA.

In addition, water has been and will continue to be sourced from the South Saskatchewan River, obtained via purchase from the Municipality of Medicine Hat.

All water for drilling will be sourced locally, from the licensed withdrawal point on the South Saskatchewan River, existing water wells, and dugouts within CFB Suffield. About half of the completion water demands will be met with water sourced from the South Saskatchewan River, obtained via purchase from the Municipality of Medicine Hat, and half will be met with recycled water and locally sourced water. Water to meet operational requirements likely will be sourced locally aside from re-completion requirements, which are anticipated to be sourced the same as completion requirements.

The location of existing water sources is shown on Figure 2-7 (PDF: 838k).

2.2.5.6 Grassland Fires
Wildfires could result from military activities, lightning, oil and gas operations, vehicles, and accidents. In the unlikely event of a wildfire, environmental damage would likely result in the form of ignition and burning of vegetation. Depending upon the timing of the fire, wildlife may be affected during the breeding and nesting season.

EnCana's ERP includes a plan for responding to wildfires that are frequent in the summer and fall at CFB Suffield. Wildfires are rare in the NWA and emergency response in the NWA has been prioritized to limit the damage in the NWA from fires arising in the Military Training Area (MTA). When conditions require, extra care is taken to limit ignition sources at CFB Suffield including in the NWA.

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2.3 Chemicals and Hazardous Materials
Approved drilling mud additives may be used. During well completion, a polyacrylamide friction-reducing agent may be used by the contractor. This would be transported to the site in a truck-mounted plastic bulk tank.

Biocide (Nalco/Exxon EC6222A) and corrosion inhibitor (Brentagg T-8084 or a heterocyclic amine-based inhibitor) will be used to control corrosion in the gathering system. These chemicals will be stored in two 1000-gallon tanks at E Station and two 500-gallon tanks at outside the NWA. These tanks are above ground farm-style tanks within a berm enclosure. Material Safety Data Sheets (MSDS) for these chemicals are provided in Appendix D. Accidental release kits are available at these locations outside the NWA.

Diesel may be used periodically as a defoamer in steel pipe. Diesel is stored in above ground tanks with secondary containment at existing compressor stations outside the NWA. Defoamer (Guardian Chemicals NOFOME 25106) is periodically used at the existing produced water treatment facility (outside the NWA) at a rate of approximately 40 litres (L) per year. Defoamer is stored outside the NWA, in the line heater shack, in a 20 L pail.

There will be no fuel storage within the NWA. Vehicles and equipment will be refuelled as required by a fuel truck equipped with standard accidental release prevention and cleanup equipment.

Pigging trucks are equipped with compressed natural gas (CNG) tanks for use in pigging operations.

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2.4 Emissions, Discharges, and Wastes
EnCana will adhere to all applicable regulations for emissions and waste management. Where no standards exist, EnCana will follow industry best practices, if feasible. EnCana will minimize, to the extent practical, wastes and emissions from the Project.

2.4.1 Air Emissions
The sources and types of air emissions expected during the life of the Project include:

• exhaust from vehicles and rigs;
• short-term venting during completions, tie-in, and maintenance operations; and
• fugitive emissions.

The primary activities associated with air emissions are the combustion of diesel fuel by construction equipment for construction activities, with the main products being water vapour (H₂O) and carbon dioxide (CO₂). Trace amounts of sulphur dioxide (SO₂), nitrogen oxides (NO_x) (comprising nitric oxide (NO) and nitrogen dioxide (NO₂)), carbon monoxide (CO), fine particulate matter (PM), and volatile organic compounds (VOCs) are typically emitted during diesel fuel combustion.

2.4.1.1 Greenhouse Gas
Greenhouse gas emissions from the Project will primarily be the result of diesel fuel combustion and venting of CO₂ and methane (CH₄) during the construction and operations phases. A small amount of CH₄ may be lost through fugitive emissions of natural gas.

EnCana minimizes air emissions (including GHG emissions) related to well testing by conducting in-line testing. In-line testing means that the existing gas gathering system is utilized to conserve the gas. In-line testing is possible in the NWA as there is suitable infrastructure and productivity information.

A significant portion of EnCana's air emissions for the Project are caused by vehicles/engines, EnCana utilizes standard practices/equipment to minimize its emissions. The vehicles/engines have all industry standard emission reduction technologies. EnCana's practices minimize the use of vehicles (including reduced idling times) to further reduce emissions.

The natural gas in the NWA contains no natural gas liquids (being greater than 96% methane and less than 0.01% pentanes or higher carbon chains); therefore, no technologies are utilized for vapour recovery.

Based on 30 years of operational experience at CFB Suffield, EnCana does not anticipate flaring gas including in emergency conditions. The reason that EnCana does not flare gas is that there are insufficient volumes to sustain stable combustion. There are insufficient volumes released to flare as EnCana shuts in at the compressor inlet and no process vessels are required for the Project.

Figure 2-7 Existing Water Sources (PDF: 838k)

In the event of maintenance operations, process upsets or emergencies, EnCana will either shut-in the well(s) or vent the gas for the minimum time period necessary to remedy the situation. EnCana's first option is to shut-in the well(s). Situations resulting in venting or shut-in are rare and generally of short duration. EnCana will comply with all EUB regulations concerning the venting of gas including Directive 060: Upstream Petroleum Industry Flaring, Incinerating and Venting. Pursuant to EUB Directive 060, any vented gas is sweet, free of hydrocarbon liquids, will not be vented for more than 24 hours, and will not constitute an unacceptable fire hazard.

2.4.1.2 EnCana's Approach to Greenhouse Gas Management
Regulatory Context
The Canadian Federal Government (the "Federal Government") has announced its intention to regulate greenhouse gases (GHG) and other air pollutants. In late April 2007, the Federal Government announced its regulatory framework (the "Framework") that outlines its clean air and climate change action plan, including a target to reduce GHG emissions and a commitment to regulate industry on an emissions intensity basis in the short term. The regulations to achieve these objectives will be enacted under the Canadian Environmental Protection Act, 1999 and will be introduced starting in spring 2008. For GHG, the Framework sets a 2010 implementation date for emissions intensity reduction targets.

The government of Alberta (the "Alberta Government") has also passed legislation that will regulate GHG emissions from certain facilities located in the province. The Alberta Government's legislation is called the Climate Change and Emissions Management Act (CCEMA). In March 2007, the Alberta Government circulated draft regulations pursuant to the CCEMA that, starting on July 1, 2007, will require facilities that emit more than 100,000 tonnes of GHG per year to reduce their emissions intensity by 12%.

The Project is not a large emitting facility and therefore the draft Alberta regulations would not apply. As the federal regime is as yet unclear, EnCana is unable to predict the impact to its business. EnCana will continue current activities to reduce emissions intensity and improve energy efficiency. Efforts with respect to emissions management are founded on the following key elements:

• significant weighting in natural gas;
• recognition as an industry leader in CO₂ sequestration;
• focus on the development of technology to reduce GHG emissions;
• involvement in the creation of industry best practices; and
• industry-leading oil sands steam-oil ratio, which translates directly into lower emissions intensity.

Greenhouse Gas Management Policy
EnCana is keenly aware of the growing concern of society that energy is used efficiently and that emissions are managed to reduce greenhouse gas contributions and improve air quality. EnCana recognizes that true sustainability requires the foresight to steward resources so that it is possible to maintain and grow not only economic capital but also environmental and social capital.

EnCana acknowledges that climate change is occurring and it is a growing public concern. EnCana will do its part by reducing GHG emissions through improvements in energy use, investments in technology, sequestration and innovation. Central to the environmental practice of the organization, EnCana strives to employ capital and energy efficient methods to minimize footprint and to maximize recovery of the resources extracted by employing and advancing technologies and methodologies that reduce environmental effects and minimize waste.

EnCana understands the provincial and federal governments' increasing attention toward this important issue as they develop an appropriate regulatory framework. EnCana will continue to provide advice and assistance to government in this regard, as well as persevere with internal actions to contribute to these efforts and to work within the emerging regulatory requirements.

EnCana's focus on emission reduction is through reducing energy intensity and improving energy efficiency. In this regard, EnCana has developed an energy efficiency built around three mutually reinforcing pillars: operations, employees and community investment.

• Operations will maintain a strong focus on reducing emissions and energy use across the Company and further developing EnCana's existing culture of energy efficiency within the Divisions. Energy assessments are being launched at a small number of facilities to measure environmental performance against best practices and target improvements, and there is a budget that will be allocated through a specific Energy Efficiency Project Approval Request process. This program will start in 2007 with energy audits of major facilities for the purposes of identifying opportunities for improvement.
• EnCana employees will be provided with tools and incentives to make changes in consumer and lifestyle choices. EnCana is developing a rebate program for North American employees that will be linked to the Energy Star program that labels energy efficient products. In addition, employees and contractors have been asked to develop ideas on ways to reduce energy consumption.
• Community investment will serve to further solidify EnCana as a corporate leader on energy efficiency. EnCana is in the process of developing a new partnership to support a community-based effort to enable each household touched by EnCana's North American business to make a change to become more energy conscious.

EnCana believes there is a real need to reduce emission intensity and improve energy efficiency from wellhead production through to the consumer. The best solutions will be those that harness technology and provide timely incremental improvements to ultimate resource recovery.

Corporate Management of Greenhouse Gases
EnCana has tracked the Greenhouse Gas emissions due to its operations in Canada since 2003. The following Greenhouse Gas emissions data has been extracted from EnCana's 2006 Corporate Responsibility Report [http://www.encana.com/responsibility/reporting/index.htm].

EnCana's methodology to measure emissions is based on the specifications outlined in the American Petroleum Institute's "Compendium of Greenhouse Gas Emissions Methodologies for the Oil and Gas Industry" along with additional guidance provided by Canadian Association of Petroleum Producers (CAPP) and the Global Reporting Initiative (GRI).

As a result of increasing production and the addition of U.S. data, EnCana's 2006 direct CO₂ emissions have increased since 2003 (see Table 2-5). Emissions per unit of production, which represents emissions intensity, have also increased. Emissions intensity is measured on a "tonnes of CO₂e per m³ of oil equivalent production" basis. Compared to the best available information for the Canadian oil and gas industry from the 2006 CAPP Stewardship Progress Report, EnCana's Canadian emissions intensity is approximately 22 percent below the national industry benchmark. EnCana's Canadian operations direct GHG emissions are 5,924 kilotonnes CO₂ equivalent. (Direct GHG emissions include total direct emissions from combustion, flaring, formation CO₂ and other venting and fugitive leaks from equipment.)

Table 2-5 EnCana Greenhouse Gas Emissions
EnCana Greenhouse Gas Emissions 1,2	2003	2004	2005	2006
Direct CO2 emissions (ktonnes CO2e) 2,3	4,489	5,239	5,469	7,890
CO2 sequestered at Weyburn (ktonnes)	1,544	1,594	1,842	1,800
Direct greenhouse gas emissions intensity (tonnes CO2e/m3OE) 4	0.145	0.152	0.161	0.160
Canada				0.170
U.S.				0.137
Adjusted direct CO2 intensity	0.095	0.106	0.107	0.118

NOTES:
1	Figures for 2003, 2004, 2005 are for Canada only. Figures for 2006 include both Canada and U.S.
2	Estimates of direct CO2 emissions for 2003 and 2004 have been recalculated and restated as a result of a change in the interpretation of the definition of "covered emissions" in the Alberta Environment and Statistics Canada reporting protocols.
3	Includes total direct emissions from combustion, flaring, formation CO2 venting, fugitive equipment leaks and other reported venting consistent with Statistics Canada/Alberta Environment reporting protocols.
4	Direct emissions include all emissions generated during oil and natural gas exploration and production, except emissions associated with transportation activities. Direct emissions include fuels burned to generate onsite heat and electricity.

Project Greenhouse Gases
The expected Project greenhouse gas (GHG) emissions were developed by assessing several activities that will be incremental to current operations. These values are calculated as per the descriptions in the section above.

The Project will use the methods for reducing flaring and venting that EnCana has developed for its shallow gas operations in Southeast Alberta. The primary feature of these methods is EnCana's practice of having pipeline installed to the wellhead before the completion phase of the well. This allows EnCana to take gas from the well into the gas gathering system as soon as the gas quality is sufficient for the gas to be sold. Facility shut down systems are designed to contain gas, except in instances where a significant combustion risk is detected in which case the facility is depressured for safety purposes.

Methods and Assumptions
The Koomati Compressor Station
The increase in production of 9 mmscfd handled by this facility will increase the loading on the main compressor engines. Auxiliary equipment such as generators or office boilers will not be affected. The 2006 GHG emissions calculated from EnCana's Emission Manager database, were apportioned across each engine according to the 2005 fuel usage per engine which was in turn estimated according to the rated horsepower capacity of each engine and the fuel usage of the other fired equipment on site.

The current throughput per engine was then determined by the percentage of fuel used by each engine. The incremental 9 mmscfd was also split in the same manner to identify a new total throughput of 60 mmscfd. The 2006 total GHG emissions were also apportioned across each piece of fired equipment and a current GHG emission per throughput was determined. This value was multiplied by the incremental throughput to get the incremental GHG emissions per machine. These incremental emissions per machine were summed to get the Project incremental value of 13,845.6 tonnes CO₂e/year.

Flaring
Flaring will increase GHG emissions by another 18.5 tonnes due to the incremental throughput. Flaring happens for several reasons, primarily:

• A section of the plant must be depressurized for maintenance and is then purged to put back on stream. This is not dependent on throughput.
• During an emergency, the plant shuts down and depressurizes to flare. This is a fixed volume and not dependent on throughput.
• Safety valves lift due to excessive internal pressures. This is not dependent on throughput and is of short duration.
• Short-term shutdowns of part or all of the plant before the well sites can be cut back. Short-term flaring constitutes most of the flaring, and it will increase in proportion to the number of wells.

Drilling, Completions, and Tie-in of New Wells
Minimal information is available to estimate emissions from a diesel engine operating in a stationary situation at a site. An estimate of the number of gallons of diesel used per hour while stationary was made based on an operating unit's mile per gallon fuel efficiency on the road even thought this number is dependent on speed, type of road surface, weight being hauled, etc. The GHG factor used for diesel fuel is 10.1 kg CO₂e/gallon based on U.S. EPA calculations.

The distance estimated to get on and off the NWA was derived by checking access to the NWA. There is a northwest access to the northeast section of the NWA and there is a Gate C access to the southwest section of the NWA. A worst case scenario for accessing to the wells was assumed to require an average of approximately 20 km of driving through the NWA.

There will not be a camp on the NWA, therefore the highway trucks bringing in the rig will not stay on the site. For water and vacuum trucks, it has been assumed that trucks would haul loads from or to the NWA each day they were required. Trucks used for infrequent efforts such as logging, pressure testing, swabbing and perforating were also assumed to leave the NWA at the end of a day, in addition to well-to-well travel. The plough truck, excavator and backhoe loader we assumed to go from well to well, staying on site overnight. This necessitates that crews will exit the NWA each night in smaller vehicle(s). The emissions from those vehicles are considered minimal and were not included.

New Well Clean-Out
Emissions during cleanout were estimated from data provided by experienced completions personnel. After the completion operation, the completion fluids are flowed back from the well to a blowback tank. For the first 0 to 5 hours, flowback consists of water mixed with carbon dioxide, with the carbon dioxide vented at rates of approximately 200 Mcf/d. For the next 5 - 18 hrs, the flowback changes to a gas that is a blend of an average 50% CO₂ and 50% methane flowing at rate of approximately 150 Mcf/d, and for the final 18 - 24 hrs a gas consistency of 90% methane and 10% CO₂, flowing at approximately 150 Mcf/d.

Operations Activities
For swabbing activities, truck travel was calculated using the same assumptions as for the drilling and completions work. Swabbing and blowdown volumes were based on depressurization of the casing from known operating pressures. The number of wells undergoing each operation was based on the known number of current wells that require swabbing each year. Blowdown operations are required between swabbing operations.

Summary of Project GHG Emissions
Estimated GHG emissions and emission intensity over the duration of the Project is provided in Table 2-6. The Project is expected to result in an increase of approximately 15,000 tonnes CO₂e per year. This Project represents an increase of approximately 0.002 % and 0.006 % of the GHG estimates for Canada and Alberta in 2004, respectively (Environment Canada 2006).

References
Environment Canada National Inventory Report, 1990 - 2004 - Greenhouse Gas Sources and Sinks in Canada http://www.ec.gc.ca/pdb/ghg/inventory_report/2004_report/toc_e.cfm [Updated from original report)

Table 2-6 Project Greenhouse Gas Emissions
Project Summary, Incremental GHG Emissions:	CO2e, tonnes
Installation:
Drilling, completions, Tie-in:	10,166	for the Construction Phase
Well Cleanout:	57,092	for the Construction Phase
Installation total per year:	22,419	tonnes per year
Operating:
Operations, Swabbing vehicle:	823	per year
Operations, Swabbing Depressurize:	146	per year
Blowdown to remove water:	210	per year
Koomati incremental emissions	13,864	tonnes per year
Operating total CO2e:	15,042	tonnes per year

Incremental gas production:	9	mmscfd
With oil at 38.5 GJ/m3:	96,271	m3 OE

Project Annual Intensity:	Year 1	Year 2	Year 3	Annually Thereafter
% wells on stream:	15.7%	52.9%	90.2%	100%
GHG Intensity	1.485	0.735	0.431	0.156

2.4.2 Noise
Noise emissions from the Project will be generated mainly from equipment in use during the construction phase, and, to a much lesser extent, from vehicles and equipment in use during routine operational activities. It is anticipated the highest noise emissions will occur during the construction phase of the Project. Sound levels from the Project are anticipated to range from 10 to 32 dBA at 1500 m. Predicted noise levels from typical construction phase activities are summarized in the table below.

All activities will comply with EUB Directive 038 (see Appendix E). Directive 038 permits specified sound levels attributable to the facilities at designated receptor points. The EUB Directive does not apply to noise from construction activities, as these activities are typically short in duration.

The potential environmental effects of noise emissions from the Project are assessed in Table 2-7).

Table 2-7 Predicted Noise Levels From Typical Equipment Operations for the Project Operations
Predicted Noise Levels From Typical Equipment Operations for the Project Operations at Theoretical Receiver Distances in the NWA
Noise Source *	Predicted Level (dBA Leq) Wind Directed to Theoretical Receiver Locations
	50 m	100 m	250 m	500 m	1000 m	1500 m
One Typical Fracturing Operation	72	61	57	49	39	33
One Traditional Drill Rig Operation	70	61	55	44	33	27
One Typical Coil Rig Operation	70	61	55	44	34	29
One Chain Trencher Operation	64	55	48	38	28	27
Pipe Laying Operation	57	47	40	32	24	20
Pipe Alignment And Welding Activity	58	49	42	31	22	17
Backhoe Trenching in Soft Ground	57	47	40	31	21	15
Pressure testing valve release of pressure	48	39	31	23	16	12
Total Predicted Level with wind conditions (with all listed activities operating continuously at the same location)	76	67	61	51	41	36
Total Predicted Level under calm conditions (with all listed activities operating continuously at the same location)	78	67	60	50	40	34
NOTE: * Drilling, fracturing, and pipelining activities do not necessarily take place simultaneously at a given site or within proximity to each other. However, each operation could occur at the same distance to a given theoretical receiver location.

2.4.3 Wastes
Wastes produced from the Project will be generated primarily during the construction phase, and, to a lesser extent, from maintenance activities during operations. The sources of waste from the Project include drilling and completion fluids and solids, produced water, and routine pigging and well treatment wastes. All waste storage systems do and will comply with applicable EUB guidelines.

2.4.3.1 Drilling and Completion Wastes
It is anticipated the drill mud systems will be fresh and water-based, using approved mud products to provide viscosity, control fluid loss, lubricate the drill bit, control formation pressure, and flocculate drilled solids. All drilling mud additives will be specified as non-toxic (as defined by the Petroleum Services Association of Canada, see Appendix F). Individual drilling wastes will vary in composition and volume for each well under construction. The characteristics of the formations drilled through will influence what wastes are produced.

Drilling each well will require approximately 75 m³ of water. The water necessary for drilling will be transported to the well site via a truck-mounted tank. Approximately 68 m³ will be returned as drilling waste, of which 56 m³ will comprise recovered water (approximately 80 percent of the water used to drill the well). Drilling waste will be stored in containment sumps outside the NWA, on previously disturbed sites. These su