Section 2 - Project Description

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List of Tables

Table 2.2.1 Open Hole Log to Core Comparison McMurray C Net Pay ... 8

Table 2.2.2 Criteria used to Estimate Bitumen Resources ... 9

Table 2.2.3 Average Values of Key RDA Reservoir Parameters ... 10

Table 2.2.4 Bitumen Resource Estimate for the Algar Lake RDA ... 10

Table 2.3.1 Pad Bitumen Resources & Recoveries - 5 Year Well Life Estimated ... 14

Table 2.3.2 Total Pad Bitumen Resources & Recoveries - 5 Year Well Life Estimated .... 14

Table 2.3.3 Typical Key Elevations ... 15

Table 2.3.4 Caprock Permeability Tests ... 16

Table 2.5.1 External Emission Sources - CPF ... 27

Table 2.5.2 Storage Tanks ... 27

Table 2.6.1 Typical Water Source and Users Listing ... 35

Table 2.6.2 Water Balance Streams and Measurement ... 36

Table 2.6.3 Bitumen Balance Streams and Measurement ... 37

Table 2.6.4 Gas Balance Streams and Measurement ... 37

Table 2.6.5 Energy Produced to Energy Input Ratio ... 38

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List of Figures

Figure 2.2.1 Project Index Map

Figure 2.2.2 McMurray Sand Isopach

Figure 2.2.3 Type Log AA/01-15-085-12W4M

Figure 2.2.4 Type Log AA/01-15-085-12W4M – McMurray Interval Detail

Figure 2.2.5 Type Log AA/01-15-085-12W4M – Sand Facies Examples from Core Photos Figure 2.2.6 Cross Section A-A’

Figure 2.2.7 Cross Section B-B’ Figure 2.2.8 Cross Section C-C’

Figure 2.2.9 Top of the 1st Paleo/Devonian/Base of McMurray Subsea Structure Figure 2.2.10 Top of McMurray Interval to 1st Paleo/Devonian Isopach

Figure 2.2.11 Top of the McMurray Subsea Structure Figure 2.2.12 Wabiskaw Shale to McMurray Isopach Figure 2.2.13 Clearwater to McMurray Isopach Figure 2.2.14 Wabiskaw Shale Marker Structure Figure 2.2.15 Clearwater Subsea Structure

Figure 2.2.16 Grand Rapids to Clearwater Isopach Figure 2.2.17 Grand Rapids (top of Mannville) Structure Figure 2.2.18 Lower Grand Rapids Marker Structure Figure 2.2.19 Example 3D Seismic Section

Figure 2.2.20 3D Seismic McMurray C to 1st Paleo

Figure 2.2.21 McMurray C Channel Sands – Net Sand Base Structure Figure 2.2.22 McMurray C Channel Sands – Net Sand Subsea Top Structure Figure 2.2.23 McMurray C Channel Sands - Bottom Water/Gas Zone Isopach Figure 2.2.24 McMurray B Channel Sands - Bottom Water/Gas Zone Isopach Figure 2.3.1 Well Pads and Well Bore Trajectories

Figure 2.3.2 Circulation Phase Figure 2.3.3 SAGD Process

Figure 2.3.4 Well Pads and Drainage

Figure 2.3.5 Drainage Areas and 6% Isopach

Figure 2.4.1 Well Pads A and B Well Pair Locations Cross Section A-A' Figure 2.4.2 Well Pads A and B Well Pair Locations Cross Section B-B' Figure 2.4.3 Typical 10 Pair Slant Pad Layout

Figure 2.4.4 Typical Well Completions Circulation Phase/Gas Lift Phase Figure 2.4.5 SAGD Producer Wellhead

Figure 2.4.6 SAGD Injector Wellhead Figure 2.4.7 Water Source Well Completion Figure 2.4.8 Observation Well (Temperature)

Figure 2.4.9 Observation Well (Temperature & Pressure) Figure 2.5.1 Central Processing Facility Plot Plan

Figure 2.5.2 Central Processing Facility Flow Diagram & Material Balance Figure 2.5.3 Energy Balance

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2. PROJECT

DESCRIPTION

2.1 PROJECT OVERVIEW

Grizzly Oil Sands (Grizzly) proposes to build an 1800 m3/d (11,300 bopd) SAGD Project approximately 45 km southwest of Fort McMurray (Figure 1.1.1). The Grizzly Algar Lake SAGD lease area consists of three oil sands leases OSL #7406080047, OSL #7406080049 and OSL #7407050182. The Algar Lake SAGD Project is located on OSL #49 with the first stage of development occurring in Sections 10, 11, 14, 15-85-12-W4M (Figure 1.3.1).

Grizzly intends to construct the central processing facilities (CPF) in two phases each having a capacity of 900 m3/d, as shown in Figure 1.8.1. The two CPF and four pads are identified as Stage 1 of the Algar Lake SAGD Project. With further delineation work, additional pads will be identified for future stages of production.

2.1.1 Overview - Bitumen Extraction and Processing Components

The Project is designed to produce 1800 m3/d of bitumen (11,300 bopd) with an expected project life of approximately 20 to 30 years. Stage 1 of the Project is expected to supply bitumen

through Phase 1 and 2 of the CPF construction. Additional pads will need to be identified and approved within 10 years of start-up. The estimated total bitumen to be recovered for Stage 1 ranges from 4 to 5 million m3 (25to31 million barrels). Grizzly is only seeking approval for the Stage 1 well pads and wells in this application.

The first stage of the Project consists of three major components:

 a central processing facility (CPF) consisting of two 900 m3/d (5,650 bopd) modules;

 well pads (4) and well pairs (40);

 access roads, powerlines and pipelines connecting well pads to the CPF; and

 associated facilities.

The CPF component is where the extracted bitumen is processed to meet sales oil specifications. Produced water and make-up water is treated and recycled as boiler feedwater (BFW) for steam generation. Steam from the CPF is transported by pipeline to the well pads and distributed to the various wells. Produced water and bitumen from the wells is measured at the facilities on the well pads and aggregated into a single pipeline for transportation to the CPF.

Sales oil (dilbit) is trucked to local markets for upgrading to synthetic crude oil or transportation into export markets.

Stage 1 of the bitumen extraction will consist of four well pads with 40 well pairs including steam injectors and bitumen producers, downhole pumps, access roads, power lines, and pipelines.

Several associated facilities are required to support the SAGD Project including an access road, water pipeline, water source wells and gas pipeline. The access road into the CPF will be constructed from an existing all-weather road in Section 19-84-11W4 north parallel to an

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existing powerline and pipeline corridor then west to the Algar plant site on the west side of Little Horse Creek (Figure 1.3.1). Where possible the other associated facilities will be constructed adjacent to the access road.

2.1.1.1 Well Pairs

Grizzly will be using the SAGD recovery process for the Project. Injectors will be drilled along a horizontal track that is 5 m above the producers. The horizontal sections of a well pair will be spaced 60 to 70 m laterally from the horizontal sections of the next pair. The horizontal length of the wells will average 800 m. The well pairs will be started up using a 90 day circulation phase on both the injectors and the producers. This involves injecting steam to the toe through a toe injection string, with the condensed hot water returning up a heel string. After sufficient bitumen mobility has been achieved between the injector and the producer, the well pair will be converted to SAGD operation using gas lift as the lift mechanism. Additional details on the recovery process can be found in Section 2.3.2.

2.1.1.2 Well Pads

Stage 1 of the Project will require four well pads each with ten well pairs. Wellheads will be spaced 10 to 15 m apart on the surface of the well pads. Detailed well pad information is provided in Section 2.4.1.

2.1.1.3 Central Processing Facility (CPF)

Grizzly plans to use proven technologies for bitumen/water separation, produced water treatment/reuse and steam generation.

In the reservoir, bitumen is heated by injection steam (which forms a steam chamber) to a temperature where its viscosity is reduced allowing it to flow to the producing well. Lift gas is injected into the well and provides the means for bringing the bitumen, produced gas and

produced water to the surface facility at the pad. The surface pad facility is described in detail in

Section 2.4. At the pad,the bitumen and produced water are separated from the produced gas (gas flashed off from the bitumen), lift gas and steam in the group separator. The produced gas/steam mixture and bitumen/produced water mixture are pipelined to the CPF in separate pipelines. A description of the CPF facilities is provided in Section 2.5.

At the CPF, produced gas from the group separator is used as fuel for the boiler. Production (bitumen/produced water mixture) from the group separator is cooled and mixed with diluent. Diluent reduces the viscosity of the bitumen prior to entering the inlet cooling and separation system. This system consists of inlet coolers, a desand vessel, a free water knock (FWKO) and a treater. After the treater, the product stream, known as dilbit (diluted bitumen) or sales oil, is stored in the dilbit storage tanks for shipment by truck.

At the CPF, produced water (PW) separated from the bitumen is treated and reused as boiler feedwater (BFW) for the steam boiler. Produced water and any required makeup water is cooled and sent to the induced gas floatation (IGF) and filter units for oil removal. After oil removal, the PW is flows to an evaporator where BFW quality water is produced by evaporation of

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There will be some waste materials generated from the CPF. These wastes consist of slop oil (rag layer), sand/reservoir solids and evaporator blowdown water. Slop oil consists of tight emulsions that cannot be recycled on site cost effectively. Rag layers form in the desand vessel, FWKO and treater. Sand and reservoir solids that accumulate in the desand vessel will be trucked out to approved waste disposal facilities when the vessel is taken offline for cleaning. Waste water from the water treatment plant will come in the form of evaporator blowdown. These wastes will be hauled offsite for third party disposal.

2.1.2 Overview - Utility and Transportation Components

Grizzly is currently evaluating a number of suppliers for natural gas and diluent for the plant site. As well, discussions are in progress with a number of potential purchasers of the sales oil.

Natural gas will be transported to site by pipeline. Electricity will be generated onsite using a gas turbine with cogeneration. Export of power is not being considered at this time. The diluent and sales oil will be hauled by truck.

The proposed access road to the plant site and from the CPF to the well pads, is shown on Figure 1.3.1.

2.1.3 Overview - Site Selection Project Facilities

For locating the Project facilities, Grizzly engaged in a process to identify the various site selection options where economic, environmental and social sensitivities or constraints would determine the most suitable locale. This process has been referred to as “constraints mapping” and is further explained in Section 4.12.

For locating the facilities, numerous site selection criteria were considered such as:

 the CPF be centrally located to the bitumen reservoir;

 the CPF be located in close proximity to existing utilities;

 the CPF be located on high ground for easier construction;

 the well pads be located to minimize operating distance between the pad site and the CPF, yet still optimize resource recovery; and

 the location of project facilities and infrastructure be optimized by incorporating key design and environmental features which encourage maximum resource utilization and minimize environmental impacts.

2.2 GEOLOGY AND RESOURCES

This section evaluates the geology and resources of the Algar Lake Project Area with both regional mapping and more detailed data within the initial SAGD Resource Development Area (RDA).

2.2.1 Geological Data and Control

Exploration activities conducted to date including exploratory wells and 3D seismic are shown on Figure 2.2.1. The Algar Lake Project Area covers the 100% owned Crown Oil Sand Lease #7406080049 (OSL #049). Grizzly has drilled a total of 58 core holes within the Project Area

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and there were three pre-existing oil sand evaluation wells. Grizzly acquired a high-resolution 3-D survey covering 2050 ha within the lease OSL #49 area in 2008. Grizzly also owns adjoining oil sand leases where they have drilled an additional six core holes in addition to eight pre-existing wells (Figure 2.2.1). The JACOS Hangingstone SAGD project is located 10 km to the southeast. Data from the JACOS Hangingstone project has been invaluable in assessing the potential of the Algar Lake project.

The proposed Resource Development Area (RDA) currently has 38 oil sand evaluation wells. It covers a large portion of a southwest to northeast oriented McMurray C channel trend that cuts through OSL #049 as shown by the McMurray net pay (>6% bulk mass bitumen) isopach in

Figure 2.2.2. The McMurray C sand comprises 100% of the expected recoverable resource in the Project Area.

2.2.1.1 Exploration Drill Hole Program Information

Grizzly has drilled the following oil sands evaluation wells in the Project Area and RDA:

 26 oil sands exploration holes in 2006-07 drilling season in the Project Area; 22 in the RDA

 24 oil sands exploration holes in 2007-08 drilling season in the Project Area; 9 in the RDA

 8 oil sands exploration holes in 2008-09 drilling season in the Project Area; all 6 in the RDA

 3 pre-existing wells in the Project Area: 1 pre-existing well in the RDA.

Open-hole electric logs were run to total depth (Array Induction, Neutron-Density-gamma Ray, and Sonic) and continuous core was taken over the McMurray in all Grizzly wells. All Grizzly cored wells were analyzed for Dean Stark Analysis of bitumen/water saturation and porosity. Permeability/overburden testing was performed on 15 wells in the Project Area, 13 of which are in the RDA. The core analysis lab performed a core to log correlation and a facies description for each well. Bitumen viscosity and density were obtained from fluids extracted from the AA/10-14-085-12W4 well. For purposes of net pay mapping, parameters using the weight-percent bitumen from core analysis and open log values were used. Effective porosities and bitumen saturations used in the mapping were derived from shale-volume corrected density-neutron logs and resistivity, calibrated to the core information. Thus, the log, core and seismic data provide sufficient information for characterizing bitumen distribution and resources. 2.2.1.2 Seismic Survey Program Information

In 2008, Grizzly conducted a 3D seismic program covering 2050 ha (5066 acres) within OSL #049, covering 95% of the RDA (Figure 2.2.1). The seismic was shot with a 60 m by 60 m shot and receiver grid, yielding 20 m by 20 m subsurface bins. The seismic data helps distinguish interfaces within the McMurray formation and strongly images the contact with the underlying Paleozoic carbonates. Interpretation of these seismic reflections can have a high degree of confidence in the mapping horizon structure and thickness, but the seismic records are not an ideal tool for mapping reservoir quality.

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2.2.1.3 Results of Exploration Program Information

The exploration conducted to date (Section 2.2.1.1) has led to the characterization of a SAGD bitumen resource within Project Area. An area with 15 to 20 m of clean bitumen pay was fully delineated in the areas covered by the first four pads. This pay has been mapped to the west and south of the initial four pads, however, some additional drilling will be done to completely delineate those bitumen resources. Additional areas of thick pay in the northern portion of the Project Area will be followed up with additional exploratory drilling.

2.2.2 Regional Geology

Grizzly Oil Sands evaluated the regional geology for the Algar Lake project centered in and adjoining Township 085 - Range 12W4.

2.2.2.1 Regional Stratigraphy

Figures 2.2.3 and 2.2.4 are type-logs from data in the 1AA/01-15-85-12-W4M well which is centrally located in the RDA. Figure 2.2.3 is a type log show the complete wellbore electric log with formation tops used in regional geologic study. Figure 2.2.4 is a more detailed type log of the well that shows additional core data along with facies descriptions used in the McMurray sands. Figures 2.2.5 are photo examples of McMurray sand facies types found in the Project Area. The position of the facies types are indicated by green bars on the core photo column of the detailed type log (Figure 2.2.4). Figures 2.2.6, 2.2.7, and 2.2.8 are cross sections constructed to illustrate the general stratigraphy in both the Project Area and RDA. The Mannville Group in north eastern Alberta is composed predominantly of unconsolidated sediments belonging to three formations. From oldest to youngest, these are the McMurray, the Clearwater, and the Grand Rapids. The bitumen resource is within the McMurray C Formation, the lowest unit in the Lower Cretaceous Mannville Group that is preserved in the Algar Lake Project Area.

The McMurray Formation unconformably overlies the Devonian Beaver Hill Lake Group. It was deposited subsequent to a prolonged period of subaerial exposure and erosion that created incised valleys controlling the distribution of McMurray reservoir sands. The lowermost sands are typically fluvial in origin, but estuarine or shoreface environments predominate higher in the section. In both fluvial and estuarine environments, multiple channel incision events resulted in thick, amalgamated channel sand deposits.

As shown on Figures 2.2.6 to 2.2.8, there is no known Tertiary Pre-Upper Cretaceous (La Biche/Joli Fou) erosion more than 20 to 35 meters below the surface. The consistently

developed Clearwater formations show competent caprock development throughout the Project Area and the overlying Grand Rapids formation exhibits no missing section due to later erosional events.

2.2.2.2 Beaverhill Lake Group

Wells in the area penetrate the upper part of the Devonian Beaverhill Lake Group, which is comprised of the argillaceous lime mudstones and of the Waterways Formation. These

limestones do not contain bitumen resources within the area and are an effective barrier to flow.

Figure 2.2.9 illustrates the regional structure of the top of the Beaverhill Lake Group and is also referred to as the 1st Paleo (Paleozoic) top.

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2.2.2.3 McMurray Formation

The thickness of the McMurray formation ranges from 22 to 40 m (Figure 2.2.10) within the Project Area. It is composed of unconsolidated sands and shales/muds. Its thickness is largely controlled by the eroded topography of the underlying 1st Paleo top (Figure 2.2.9). The lowermost sediments of the McMurray Formation are deposited in incised valleys. The formation indicates a gradual transition from sands deposited in high-energy fluvial environments to lower energy estuarine and shallow marine sands and shales at the top. The ERCB has standardized the nomenclature of several units in the McMurray Formation (EUB, 2003). From bottom to top, these are McMurray C Channel, McMurray B2, McMurray B1, McMurray A2, McMurray A1 and the Wabiskaw C Sequences. The most common

correlation in the Project Area from the study indicates the presence of the McMurray C,

McMurray B, and Wabiskaw C zones. For the mapping in this application the Wabiskaw C and McMurray B zones are combined with the top referred to as McMurray and the base the same as the McMurray C top. The McMurray interval is shown in higher detail on the type log from the 1AA/01-15-085-12W4 well (Figure 2.2.4).

The McMurray C channel is generally 10 to 25 m thick within the Project Area. The lower part of the channel is dominated by thick, well-sorted very fine to fine grained sands, often high angle cross bedding, with only minor laminated mudstone and shale clast breccia intervals. This typically grades upward into middle and upper point bar/tidal deposits that vary from sand dominated channel to sand dominated shale intervals with low angle cross bedding. The amount shale content and degree of bioturbation often increases upward. The sands within the C channel are bitumen saturated within the RDA.

Above the McMurray C channel is an approximately 5 to 9 m thick coarsening upward

succession referred to as the McMurray B Sand Sequence. The McMurray B grades from heavily bioturbated muds at the base to moderately bioturbated, silty sands upward. The upper 2 to 3 m of this succession is of reservoir quality in this area, but the underlying low energy, often bioturbated, muddy sands present a significant barrier to steam chamber development. As a result, no net pay has been assigned to this unit, although there is bitumen present.

Overlying the B Sand sequence is a regionally extensive 2 m thick blanket of glauconitic muddy sand that caps the McMurray, and may represent an amalgamation of the B1, A2 and A1

McMurray and possible basal Wabiskaw C sequences. The regional structure of the McMurray shows a gentle southward dip (Figure 2.2.11), with a slight localized high in the RDA. This is likely related to differential compaction over the preserved McMurray C sand deposits, with the sandy channel deposits compacting less than the mud-dominated sediments on either side. 2.2.2.4 Clearwater Formation

The Wabiskaw Shale member is the lowermost part of the Clearwater Formation. It comprises consistently developed 8 to 10 m thick (Figure 2.2.12) coarsening-upward marine succession of shales to sandy silts with a thin (<2 m thick) glauconitic silty sand at top (Figure 2.2.4). The remainder of the Clearwater consists of approximately 30 m of mud overlain by 25 m of muddy siltsones or sands with usually several thin low porosity limestone beds. The consistent nature of

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deposition in Clearwater shales and silts is shown on the cross sections (Figures 2.2.6 to 2.2.8). No Clearwater sand aquifers have been found in the Algar Lake Project Area. The Clearwater Formation regionally thickens slightly to the south, (Figure 2.2.13), and both the Wabiskaw structure top (Figure 2.2.14) and Clearwater structure top (Figure 2.2.15) closely mimics that of the McMurray (Figure 2.2.11). The Clearwater section has no apparent faulting or permeable zones making for excellent, competent caprock for SAGD projects.

2.2.2.5 Grand Rapids Formation

The Grand Rapids Formation is composed of two members, Lower and Upper. The Lower Grand Rapids member is a 30 to 45 m thick and often has a 2 to 12 m porous sand interval near the top that is water wet in the Project Area (Figure 2.2.3). The Upper Grand Rapids is 50 to 65 m thick and consists of stacked coarsening upward sand cycles separated by impermeable thin marine shales, giving the Grand Rapids a total thickness of 90 to 105 m, thinning southward (Figure 2.2.16). The Grand Rapids Formation has a gentle southward dip; the N-S high seen in the lower formations is still slightly expressed in the top of the Grand Rapids (top of the

Mannville) and Lower Grand Rapids structure maps (Figure 2.2.17 and Figure 2.2.18). 2.2.2.6 Joli Fou Formation

The Joli Fou Formation is tight Cretaceous marine shale overlying the Grand Rapids Formation. Its upper contact is usually an erosional truncation by the Quaternary usually occurring within 20 m below the surface. There are consistently developed marker beds that are sometimes referred to as the Viking at about 15 m and 35 m above the Grand Rapids but their exact age and

correlation is uncertain. 2.2.2.7 Quaternary

Quaternary glacial deposits in the area consist of gravel, sand and mud less than 20 to 30 m in thickness and lay uncomformably over the Joli Fou/Viking. No significant Quaternary channels appear to be present in the area.

2.2.3 Local Geology 2.2.3.1 Site Stratigraphy

Figure 2.2.4 shows the McMurray in the 1AA/01-15-85-12W4/00 oil sand evaluation well. It is a typical example of the McMurray sand stratigraphy within the Algar Lake RDA. Effective porosities and oil saturations calculated from logs show good correlation with the core analyses results. Figures 2.2.6, 2.2.7, and Figure 2.2.8 show the McMurray sand correlation through much of the RDA. A well summary report for wells within the RDA is included as Appendix 4

and includes the depth, subsea elevation and thickness of the McMurray sand pay. 2.2.3.2 Log and Core Characteristics

The RDA has 38 total wells (Grizzly drilled 37) of which Grizzly ran electric logs and cored the entire McMurray sand section. There is good agreement between electric log and core data throughout the RDA. The type log in Figure 2.2.4 shows close agreement to average E-log porosity and oil saturations and the corresponding core parameters. Table 2.2.1 shows a comparison of log and core data for all wells within the RDA.

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Table 2.2.1 Open Hole Log to Core Comparison McMurray C Net Pay

Location

Datum

(KB) Net Pay Depth Net

Pay (m) Average Porosity Average Oil Saturation Elevation Top (m) Base (m) E-Log % Core % E-Log % Core % 1AA/06-10-085-12W4/00 536.6 237.7 256.4 19.5 35.5% 35.3% 83.2% 81.4% 1AA/09-10-085-12W4/00 534.9 233.6 250.8 17.2 34.9% 33.1% 81.7% 84.9% 1AA/14-10-085-12W4/00 535.2 233.9 253.5 19.8 35.7% 34.9% 78.9% 73.9% 1AA/15-10-085-12W4/00 534.7 233.3 253.0 19.3 35.7% 33.6% 80.6% 80.3% 1AA/16-10-085-12W4/00 533.0 231.1 250.2 17.0 36.6% 35.3% 83.2% 81.4% 1AA/10-11-085-12W4/00 531.7 246.9 249.5 1.8 32.3% 36.0% 64.6% 65.7% 1AA/13-11-085-12W4/00 531.3 230.5 247.7 18.5 35.4% 33.6% 70.9% 71.0% 1AA/14-11-085-12W4/00 530.0 231.7 246.9 14.8 35.5% 33.5% 75.3% 70.8% 1AA/15-11-085-12W4/00 531.6 240.7 249.4 1.0 31.3% 27.9% 42.7% 39.0% 1AA/16-11-085-12W4/00 534.5 241.2 250.8 4.8 32.1% 29.7% 60.0% 52.5% 1AA/01-14-085-12W4/00 533.1 246.0 249.1 0.0 32.8% 47.1% 1AA/02-14-085-12W4/00 532.8 232.4 251.9 19.8 35.2% 34.3% 79.4% 74.8% 1AA/06-14-085-12W4/00 531.5 229.1 252.3 21.8 36.9% 34.3% 73.9% 74.6% 1AA/07-14-085-12W4/00 532.1 232.0 253.0 17.3 36.2% 34.2% 76.0% 71.2% 1AA/08-14-085-12W4/00 532.6 234.0 248.2 2.0 33.0% 33.1% 57.7% 75.3% 1AA/09-14-085-12W4/00 532.5 239.5 249.6 5.9 33.0% 29.1% 54.5% 52.7% 1AA/10-14-085-12W4/00 531.0 228.9 252.7 22.1 35.0% 33.5% 77.9% 74.0% 1AA/11-14-085-12W4/00 531.0 227.7 249.6 21.3 36.5% 35.8% 84.3% 78.7% 1AA/14-14-85-12W4/00 527.4 226.8 248.3 19.3 35.1% 33.4% 76.2% 65.1% 1AA/15-14-085-12W4/00 529.8 228.1 249.1 19.0 35.6% 33.2% 67.6% 68.3% 1AA/16-14-085-12W4/00 531.0 233.0 249.9 7.4 39.4% 36.7% 74.3% 76.7% 1AA/01-15-085-12W4/00 531.0 229.6 249.0 19.0 35.6% 35.4% 74.8% 79.0% 1AA/02-15-085-12W4/00 530.5 230.4 248.9 17.2 35.3% 34.4% 79.9% 71.5% 1AA/03-15-085-12W4/00 533.7 232.9 251.4 19.6 36.0% 32.4% 77.4% 79.3% 1AA/07-15-085-12W4/00 532.5 230.9 249.0 18.0 35.7% 33.5% 75.7% 73.1% 1AA/08-15-085-12W4/00 531.2 230.0 246.8 15.8 34.6% 31.7% 75.4% 75.0% 1AA/11-15-085-12W4/00 534.0 233.5 244.8 8.0 33.0% 34.5% 70.0% 82.3% 1AA/16-15-085-12W4/00 528.0 226.7 245.0 15.8 35.7% 33.4% 71.5% 68.8% 1AA/01-22-085-12W4/00 525.2 226.2 244.1 14.8 32.9% 30.8% 65.3% 65.2% 1AA/07-22-085-12W4/00 523.3 224.8 244.7 9.3 35.0% 31.8% 67.7% 61.0% 1AA/01-23-085-12W4/00 531.8 232.9 250.4 7.4 34.3% 29.3% 55.9% 54.1% 1AA/02-23-085-12W4/00 529.3 227.7 249.1 18.3 36.1% 33.5% 74.4% 72.0% 1AA/03-23-085-12W4/00 528.3 226.7 247.0 15.8 34.8% 34.1% 74.8% 68.8% 1AA/04-23-085-12W/00 527.7 226.7 247.6 18.0 34.3% 31.0% 67.8% 66.6% 1AA/06-23-085-12W4/00 525.3 225.2 243.6 16.7 34.4% 31.9% 67.8% 60.5% 1AA/10-23-085-12W4/00 526.4 226.3 248.9 19.4 34.2% 30.5% 69.2% 64.1% 1AA/11-23-085-12W4/00 523.6 223.0 243.2 17.4 34.2% 31.7% 69.8% 69.0% 1AB/11-23-085-12W4/00 523.2 227.3 239.6 14.2 34.6% 30.6% 70.6% 66.4%

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2.2.3.3 Seismic Characterization of the McMurray Formation within the Project Area In 2008, Grizzly acquired a high quality 3D seismic program that covers all of the initial stages of development within the RDA. Employing closely spaced source and receiver lines Grizzly obtained excellent data sufficient to image the formations above and below the McMurray. Integrating the current well control with the seismic data has allowed for the imaging of the underlying 1st Paleo top erosional surface which forms the base of the McMurray SAGD pay and construction of maps which indicate the overall thickness of the McMurray sand. Figures 2.2.19 and 2.2.20 show some examples of the seismic data quality, formation picks tied to seismic horizon data, and a resulting map example showing an isotime of the interval that includes the McMurray C sand pay. The quality of the data that extends across the riparian areas, therefore not accessible to drilling core holes or seismic acquisition, is generally good but does create some areas with poor near surface anomalies that can be difficult to depth correct. Summary of 3D seismic survey acquisition parameters:

 60 m source and 60 m receiver line intervals with 20 m group intervals;

 resulting bin size of 20 m by 20 m;

 single hole dynamite source using 0.25 kg charges at 4.5 m depth;

 1 ms sample rate with ARAM 24 bit recording equipment; and

 survey processed by Calgary based Edge Technologies in April/May 2008. 2.2.4 Bitumen Reservoir Characterization

The oil sands pay zone was identified and characterized through integration of open-hole logs, cores, and seismic data into a resource model.

2.2.4.1 Bitumen Reservoir Modeling

Table 2.2.2 shows the criteria for the bitumen resource estimates. Based on the net pay maps and average reservoir properties within the pay zone from core analyses, resource values were

estimated using a minimum criterion of 6 weight-percent bitumen for pay, and a minimum thickness of 10 m for net pay.

Table 2.2.2 Criteria used to Estimate Bitumen Resources

Parameter Value

Bitumen Saturation (core) > 6%

Bitumen Saturation (log) RT > 20 Ohms Porosity (Sandstone matrix log density) > 27%

Gamma Ray (log) <75 API

Minimum Net pay >10m & >15m

2.2.4.2 Bitumen Reservoir Quality

Within the RDA, the reservoir’s oil sands pay zone thickness ranges between 0 and 22.8 m (Figure 2.2.2). Table 2.2.3 lists the average values of these reservoir properties within the area, based primarily on the core analysis and well data.

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Table 2.2.3 Average Values of Key RDA Reservoir Parameters

Parameter Value

Pay Zone Thickness (m) 18

Lateral Well Spacing (m) 66

Horizontal Well Length (m) 800

Porosity (%) 33

Oil Saturation (%) 75

Initial Reservoir Pressure (kPa) 2350

Initial Reservoir Temperature (ºC) 15

Bitumen Viscosity at TRES (cp) > 1,000,000

Horizontal Permeability (D) 1-5

Vertical Permeability (D) 0.5-4

2.2.4.3 Bitumen Reservoir Resource

Bitumen resources were calculated for the RDA of the project using the parameters described in

Tables 2.2.2 and 2.2.3 along with the McMurray Net Sand Isopach (Figure 2.2.2). The results are shown in Table 2.2.4. In addition, Figures 2.2.21 and 2.2.22 show the structural position of the top and base of the McMurray C sand net pay.

Table 2.2.4 Bitumen Resource Estimate for the Algar Lake RDA McMurray C Sand Bitumen Resource Estimates

Net Pay Cutoff >10m >15m

Total Area Hectares 911.67 636.06

Original Bitumen In Place OBIP – MM m3 36.01 26.96 Original Bitumen In Place OBIP – MM bbls 226.51 169.58 Recoverable Bitumen In Place OBIP – MM m3 18.0 13.48 Recoverable Bitumen In Place OBIP – MM bbls 113.25 84.79

Grizzly estimated the bitumen resource for the entire RDA areas of >10m and >15m thicknesses. Initial SAGD stages in the RDA will be in the >15m area. Based on computer simulations, analytical work and results from nearby SAGD projects, 40 to 60% of the original bitumen in place (OBIP) should be recoverable. Estimates provided in Table 2.2.4 are based on an

estimated 50% recovery of the total OBIP. Additional information related to bitumen recovery is provided in Section 2.3.3 Bitumen Production and Recovery Estimates.

2.2.4.4 Gas and Water Zones

There has been no bottom water found within the RDA in the McMurray C Channel (Figure 2.2.23). Thin zones of McMurray C sand bottom water were only seen in the lower 3.5 m of breccia beneath a mudstone bed in the 1AA/8-11-85-12W4/00 and in 3.75m in the 1AA/14-03-085-12W4. In both cases the thin bottom water zones appear to be localized and not present in within any current planned stages of the RDA. Some McMurray C sand bottom water is present on some wells to the north of RDA, but is not connected to exploitable sands within the RDA. No gas was identified within wells the Project Area in the McMurray C sand zones.

Traces of natural gas may be present in the McMurray B zone to the east of the SAGD project area in Section 13-85-12-W4M but none in the McMurray C zone (Figure 2.2.23). Wet to lean

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appearing sands were commonly encountered in the lower part of the McMurray B Sand Sequence (Figure 2.2.24), but these lean zones were typically no more than 3 to 4 m thick and overlain by bitumen-saturated sands of the upper part of the B sequence. It is unlikely the steam chamber will develop through the uppermost McMurray C into the overlying McMurray B muddy bioturbated sands and mudstones. Core permeability data taken from this zone shows less than 165 millidarceys in this zone. Grizzly does not currently assign any recoverable resources to the McMurray B sequence.

2.2.5 Hydrogeology

Source water for the Project will come from water wells drilled into the Lower Grand Rapids Formation. The hydrogeology of OSL #49 and the Project Area are described in detail in the Hydrogeology Report (Consultant’s Report #4). A summary of this report is provided in Section 4.4.

2.3 RESERVOIR RECOVERY PROCESS

2.3.1 Recovery Process Selection

Steam Assisted Gravity Drainage was chosen as the preferred reservoir recovery process as it has been demonstrated to be an efficient process for reserves recovery in analogous reservoirs. Oil pay at the Algar Lake SAGD Project is characterized by a clean base sand overlain by a layer of interbedded sand and mud. While it is uncertain if substantial reserves recovery will occur from the overlying material, the application of SAGD can be expected to recover in the order of 50% of the OBIP contained in the cleaner interval.

The McMurray Formation on the Algar Lake SAGD Project has an overburden thickness of about 250 m. At this depth, surface mining is not technically or economically viable. The bitumen viscosity is in excess of 1,000,000 cp at the initial reservoir temperature of approximately 15o C, and is essentially immobile. Due to this high initial bitumen viscosity, primary recovery processes will not be applicable.

Solvent assisted thermal processes may have potential. These processes involve the injection of a hydrocarbon solvent, either with the steam or heated by the steam, to reduce the bitumen’s viscosity, and thus permit gravity flow into horizontal wellbores. This technology could be applicable to the Algar Lake SAGD Project in the future, once the process is sufficiently proven in the field. Grizzly will continue to monitor the development of this technology.

2.3.2 Recovery Process Description

Grizzly plans to utilize the Steam Assisted Gravity Drainage (SAGD) process for the Algar Lake SAGD Project. Grizzly will drill and complete 40 horizontal well pairs from four surface pads (Stage 1), as shown in Figure 2.3.1.

Each well pair consists of a producer and an injector. The producer will be drilled first, with a flat trajectory at a vertical height of about 1m above the base of the McMurray Formation (see

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will be drilled along a horizontal track that lies directly over the producer’s horizontal track at a vertical separation of approximately 5 m. The horizontal section length will be approximately 800 m. Well pairs will be spaced 60 to 70 m apart laterally from each other in the reservoir. The horizontal well length and the lateral spacing were based on an analysis of the Stage 1 area geology, wellbore hydraulics studies, a review of analogs, and reservoir simulation. The values of key reservoir parameters are listed in Table 2.2.3.

The first step in the SAGD process (the circulation phase) is to develop bitumen mobility between the producer and the injector, as well as immediately above the injector (Figure 2.3.2). This will facilitate heated communication between the injector and the producer during the subsequent phase (the operating phase). The well pairs will be circulated for approximately three months. This will be accomplished in both the injector and the producer by injecting steam through the tubing to the toe, and circulating back up the heel string. The maximum bottomhole injection pressure will not exceed the formation fracture pressure, which is conservatively

estimated to be approximately 4,000 to 4,500 kPa (at a depth of 250 m). The operating plan calls for injecting steam at a bottomhole pressure of approximately 3000 kPa initially, and

progressively reducing the steam injection pressure as the steam chamber grows vertically. Bottomhole steam pressure readings will be monitored (and alarmed) on the control room board to prevent overpressure. Automated steam shutdown controls will intervene if the operators do not reduce the bottomhole steam injection pressure.

Once heated communication is established, the circulation of steam into the injector and the producer would be shut down and the operating phase of the SAGD process will then commence. Grizzly will inject steam on a continuous basis into the injector. Approximately 80% of the steam will be injected into the heel injection string, and the remainder will be injected down the toe injection string. The wellbore hydraulics study being conducted suggests that better steam distribution will result if the heel injection string is landed part way into the liner. The exact landing depth is still to be determined, but the work to date suggests that the heel string landing depth should be about 100 m into the liner for an 800 m long horizontal section injection. The injected steam rises. A steam chamber forms and gradually expands with time (Figure 2.3.3). The steam condenses at the edges of the steam chamber. This heats the bitumen and mobilizes it. The hot bitumen and condensed steam flow, due to gravity, down to the production well. The bitumen and condensed steam, plus some connate water, are lifted to surface, using gas lift. During the operating phase, Grizzly will initially target the injector pressure to be about 100 to 200 kPa greater than the producer pressure. The steam injection rate will be varied over the life of a well pair, depending on the reservoir performance around that well pair. Stage 1’s estimated Steam Oil Ratio (SOR) will be approximately 3.50 m3/m3, based on steam (100% steam quality). The actual field results of Stage 1 will be used by Grizzly to optimize the reservoir recovery process and to refine the estimated SOR’s for future Algar Lake stages.

Grizzly is utilizing gas lift as the artificial lift mechanism for the Algar Lake SAGD Project because the ability to independently produce or inject to the heel and toes of the wells should result in more even steam chamber development over the length of the well pairs and hence, improve overall bitumen recovery. The surface facilities design has taken into account the low wellhead pressures required to implement gas lift. Should Grizzly desire lower reservoir

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operating pressures later in the life of the SAGD well pairs, the producing wells and plant operations can easily be converted to bottomhole pumps from gas lift.

Operations personnel will be continuously monitoring bottomhole and surface data. Steam injection rates and pressures, and production rates will be adjusted to achieve optimum reservoir performance. The producer and the injector of any well pair will be operated such that live steam is not produced into the producer. Also, Grizzly will take care to ensure that hot water is not flashing to steam across the producer liner. This operating condition will be achieved through a combination of production rate and steam injection rate adjustments. This should ensure that the liners are not eroded.

2.3.3 Bitumen Production Rate and Recovery Estimates

Bitumen production profiles have been developed using a number of sources, including the following:

 Grizzly has examined the production performance of the JACOS Hangingstone SAGD project, which is located approximately 10 km southeast of the Algar Lake SAGD Project. This project is considered to be a good analog for the Grizzly Project.

 Fractical Solutions (Mike McCormack) conducted reservoir characterization studies of the Grizzly Algar Lake property and the JACOS Hangingstone property which provided insight into the relative production rate potential of the two properties.

 Grizzly commissioned the Taurus Reservoir Solutions to conduct a reservoir simulation study, primarily to determine a safe operating pressure for the project. A summary of the simulation study, done by Dr. Dale Walters of Taurus, is attached as Appendix 5. The report details the development of the base case bitumen production profile and steam injection requirements.

The bitumen recovery estimates shown in Table 2.3.1 and Table 2.3.2 were derived from the information provided in the reservoir characterization studies and the reservoir simulation study Original bitumen in place (OBIP) contained in the reservoir exploitation boxes is depicted on

Figure 2.3.4. The OBIP calculations assume that the horizontal well length is 800 m, and the width of the Pad areas is equivalent to the 65 m spacing between the 10 well pairs horizontal wells, or 650 m. The heights of the boxes are determined by the pay thicknesses, as mapped on the McMurray C net sand isopach (Figure 2.2.2) which uses a 6% bitumen by weight cut-off. The locations of the initial well pads, and the approximate drainage area for each well pad, and the Net McMurray Sand Isopach used to estimate the OBIP are shown Figure 2.3.4 and 2.3.5.

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Table 2.3.1 Pad Bitumen Resources & Recoveries - 5 Year Well Life Estimated ZONE No. of Well Pairs OBIP (E03m3) Bitumen Production (E03m3) Bitumen Recovery (%) PAD A

Total McMurray C Sand 2457.9 48

Total McM C Below Producers 142.8

Total McM C Sand Above Producers 2315.1 1190

Average Well 10 231.5 119 51

PAD B

Average Well 10 271.1 132 49

PAD C

Average Well 10 226.9 119 52

PAD D

Average Well 10 274.4 132 48

Table 2.3.2 Total Pad Bitumen Resources & Recoveries - 5 Year Well Life Estimated ZONE No. of Well Pairs OBIP (E03m3) Bitumen Production (E03m3) Bitumen Recovery (%)

PADS A+B+C+D TOTAL

Total McM C Sand Above Producers 10040.9 5020 50 Average Well 40 251.0 125.5 50

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Table 2.3.3 lists key elevations for the four pads – the McMurray C Sand top and base, the injectors, and the producers.

Table 2.3.3 Typical Key Elevations

Pad McMurray C Top (mASL) McMurray C Base (mASL) Injector (mASL) Producer (mASL) A 300 281 287 282 B 302 282 288 283 C 300 282 288 283 D 303 281 287 282

It is estimated that approximately 95% of the water injected as dry steam will be produced. This estimate is based on other operators’ applications, and some actual field performance data from other projects. Therefore, approximately 5% of the injected water may not be recovered from the reservoir. This retention of injected water in the reservoir necessitates a comparable water makeup volume, in addition to other makeup water requirements.

The gas oil ratio (GOR) is expected to range between 3 and 5 m3/m3. For the purposes of the facilities design and the environmental work, a GOR of 8 m3/m3 has been assumed in order to ensure that the design emissions have an adequate safety factor.

Sand production is expected to be minimal (< 0.1 % of the bitumen production rate). Grizzly engaged Hycal Energy Laboratories (Dr. Brant Bennion) to conduct laboratory sand control tests for both seamed slot liners and wire wrapped liners for the producers. The testing determines a straight cut slot/seamed slot width or a wire wrap spacing that will restrain all but the finest fraction of the formation sand/fines. At the same time, the pressure drop across the slot or wire wrap gap is measured to ensure that plugging is not occurring. The injector liners will use straight cut slots or slotted/seamed slots. The injector slot width may be moderately smaller than that used in the producer.

The Project Stage 1 total bitumen production rate will reach a plateau of approximately 1800 m3/d or 11,300 bopd. Prior to Stage 1 bitumen production declining, Grizzly will prepare an application to the ERCB and the AENV to request approval for additional stages, as required, to maintain the Project bitumen production rate at 1800 m3/day. Grizzly will utilize the facilities built for Stage 1 to handle all subsequent Stages’ production and steam requirements. It should be noted that, at this time, well pad locations for additional Stages are preliminary and do not have the requisite drilling density for approval. Stage 2 wells will be drilled and completed as required to offset the declining production near the end of the life of the Stage 1 wells. Grizzly’s belief is that there is sufficient resource in the Project Area to operate this project for 20 to 30 years.

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2.3.4 Caprock Integrity 2.3.4.1 Caprock Integrity Testing

The ultimate caprock for the project area are the thick muds and sandy marine silts of the Clearwater Formation (including Wabiskaw) to the top of the McMurray sands. Three cross sections have been constructed to show the location and thickness of the caprock group (Figures 2.2.6, 2.2.7, 2.2.8). As shown on the cross sections the Clearwater interval constitutes a

consistent development of predominately shale sediments that is 64 to 68 m thick, with only a few thin sand or limestone beds. The cross sections show that there are no identified Quaternary channels, karsting, or faults cutting into the Clearwater interval (or even the overlying Viking and Grand Rapid intervals) in this area ensuring an effective barrier to steam chamber growth. In most of the project area, the steam chamber will be constrained by the 8 to 12 m of low permeability, shale dominated, and bioturbated McMurray B2 sand/mudstone sequence. The overlying 8 to 10 m thick Wabiskaw shale interval which lies at the base of the Clearwater has a consistent thickness (Figure 2.2.12) and two preserved well cores had special high temperature caprock tests conducted in the Project Area.

Preserved state (unslabbed) refrigerated (not frozen) core material was supplied to Hycal Energy Research Laboratories from the caprock intervals overlying the McMurray formation in Algar lake wells 02-15-085-12W4M and 14-14-085-12 W4M. The entire caprock interval in both wells was subjected to x-ray analysis to select samples in the appropriate interval that were dense, homogeneous and free from any coring induced fracturing or disturbance. The final selection of the location of the caprock samples (214 m interval from well 02-15 and 214.45 m interval from well 14-14) was made jointly between Hycal and Grizzly.

Essential to the success of a SAGD operation is the presence of a continuous confining shale caprock over top of the target formation to act as a containment seal for high pressure steam that would be used for a cyclic or SAGD injection operation. Two tests were conducted on the provided core material (one from each well) to quantify low and high temperature permeability to water as well as estimate steam phase intrusion pressure into the caprock. For this test

program, brine permeability was measured (using fresh water to approximate steam condensate) at both ambient (25˚ C) and elevated (230˚C to simulate expected average steam chamber operating temperature in the Algar Lake project) to determine low and high temperature caprock sealing capacity. These tests ranged in duration from 200 to 400 hr to allow long term exposure to occur. A summary and the low and high temperature stabilized permeability data for each phase of the test on the caprock samples from the two wells is contained in the Table 2.3.4. Table 2.3.4 Caprock Permeability Tests

Well Location Depth (m) Brine Permeability at

25 deg C - mD

Brine Permeability at 230 deg C - mD

02-15-085-12 W4M 214 0.0055 0.0008

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For acceptable thermal caprock an effective low and high temperature permeability to brine of less than 0.001 mD (1 microDarcy) is desirable. Although the values are slightly higher than this at low temperature for the 02-15 sample, at high temperature permeability values appear to be within the tolerance limit, indicating the caprock with acceptably low permeability appears to be present in the samples evaluated in the study.

Threshold intrusion tests were also conducted on both samples at 230˚C (using nitrogen to simulate steam intruding into the hot, water saturated matrix of the caprock). The samples had steam intrusion pressures in the range of 35 to 140 kPa, but very low measured effective gas perm (<1 microDarcy) at all intrusion levels tested, once again indicating what would be considered to be acceptable caprock containment performance.

2.3.4.2 Caprock Integrity Modeling

A coupled reservoir and geomechanical modeling study was completed using Geosim to evaluate the structural stability of the caprock under the current design constraints (Appendix 5). The main objective of the study was to evaluate the caprock integrity at a SAGD operating pressure of 3000 kPa. The study evaluated a 3D element of symmetry model including two pads with three well pairs per pad. Also, two cross-sectional models were used for more detailed modeling and represented an "average" cross-section and a "worst case" cross-section positioned under Little Horse Creek (which contained the thinnest overburden). The pay zone in the

reservoir simulation model consisted of the McMurray C zone, which averaged 15 to 20 m in thickness. However, the grid consisted of all zones in the overburden and underburden

(specifically Clearwater shale, Wabiskaw shale, McMurray B zone, McMurray C zone and the Devonian). This was required to accurately model temperature and pore pressure changes outside of the reservoir zone. These changes in the overburden and underburden in turn cause stress and strain changes which impact the shear stress in the caprock. The main parameter evaluated in the geomechanical modeling process is the shear stress level of the caprock. The caprock possesses a certain shear strength, which is dependent on the effective stress. In order to maintain structural integrity the maximum shear stress in the caprock should not exceed the shear strength.

The main geomechanical input parameters affecting the results of the coupled modeling are the rock mechanical parameters and the initial stress state. The rock mechanical properties of the geomechanical model were based on publicly available data. The key data was the shear

strength criterion of the caprock. The data used was based on caprock shales present at the UTF site (Chalaturnyk, 1996). Residual shear strength parameters were used both for the Wabiskaw shale and the Clearwater shales. The initial stress state was based on UTF minifrac test results for three zones (shale, sand-shale and sand) ranging from 21.5 kPa/m to 23 kPa/m (Collins, 2002).

The simulation results showed that the shear stress level exceeded the shear strength only in the McMurray C zone and the lower portion of the McMurray B zone. Directly above the

McMurray C zone shaley layers exist separating the reservoir zone and upper permeable zones in the McMurray B, which restrict steam chamber growth. These layers showed some shear failure as the steam chamber grew to the top of the McMurray C zone. The highest induced shear stresses exist on the shoulder of the steam chamber and when the steam chamber is relatively

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isolated. At this point in the simulations some shear failure of the lower McMurray B was observed. However, the McMurray B zone is up to 10 m thick and provides a significant buffer zone shielding the Wabiskaw and Clearwater shales from significant shear stress loading. Only the bottom 2 m of the McMurray B zone showed any shear failure. The shear stress level in the Wabiskaw and Clearwater shales remained well below the shear strength of those zones.

The JACOS Hangingstone property to the southeast of Grizzly Algar Lake also provides some historical evidence of safe operating pressure. The earliest SAGD well pairs, which have been operating for about 10 years now, were operated at about 5000 kPa. The depth of the reservoir zone at Hangingstone is about 40 to 80 m deeper than that at Algar Lake. This depth difference converts into a stress difference of about 800 to 1600 kPa. This suggests, based on the past JACOS Hangingstone performance, that the shallowest portions of Algar Lake could safely operate at steam pressures of about 3400 kPa.

In summary, coupled reservoir and geomechanical modeling of SAGD at Algar Lake indicates that 3000 kPa is a safe operating pressure to maintain caprock integrity. The induced shear stress levels in the Wabiskaw and Clearwater shales are relatively low due in part to a large buffer zone of poor quality McMurray above the reservoir zone. The simulations showed that for a 10 year operating period the shear strength of the Wabiskaw and Clearwater caprocks was not

compromised.

2.3.5 Reservoir Process Monitoring

Grizzly will be utilizing some vertical observation wells to assist in the monitoring of the reservoir recovery process in Stage 1. These wells will be equipped with instrumentation (thermocouple bundles or fibre optic cables) to monitor reservoir temperatures so that the shape and rate of advance of the steam chamber can be approximately determined. Selected vertical observation wells in Stage 1 could be equipped with high temperature/pressure piezometers to measure bottomhole pressures. Grizzly is evaluating the number of vertical observation wells that would be required for the commercial development. Grizzly is also investigating the use of various temperature and pressure measurement devices for use in the injectors and the producers (e.g. thermocouples and bubble tubes in instrumentation coil tubing strings). The results of these evaluations, coupled with the results obtained from other operators’ field experience will

determine which equipment (and how much of it) is utilized in Stage 1. Grizzly will also be using produced water analyses as another technique to determine if steam breakthrough is occurring between the injector and the producer. Consideration will also be given to using 4-D seismic to track the progress of the SAGD process.

2.3.6 Potential Follow-up Processes for Improved Recovery

Grizzly has been monitoring a number of potential processes that may become applicable to the Algar Lake SAGD Project in the future. One potential group of processes are the solvent assisted thermal processes. These processes involve the injection of a hydrocarbon solvent, either with the steam or heated by the steam, to reduce the bitumen’s viscosity, and thus permit gravity flow into horizontal wellbores. Grizzly will continue to monitor technology

developments to determine if another recovery process would be superior to the SAGD process. Grizzly will also be monitoring and/or investigating potential follow-up processes (e.g., reservoir

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pressurization with flue gases or other gases) to decrease the steam required and improve the recovery efficiency in the late life of the recovery process.

2.4 WELL PADS AND WELLS

Grizzly is planning to produce 1800 m3/d (11,300 bopd) of bitumen at the Algar Lake SAGD Project. Current planning requires the drilling of 40 horizontal well pairs in Stage 1 of the project, on four well pads (Figure 2.3.1). Each SAGD well pair will consist of a producer and a steam injector. The SAGD well pairs are planned to have a completed horizontal section length of approximately 800 m at a true vertical depth (TVD) of about 250 m.

Grizzly is currently applying for Stage 1 development and plans to apply for approval of the additional wells and well pads for Stage 2 of the Project, at a later date. Stage 2 wells will be drilled as Stage 1 wells production declines, in order to maintain a Project bitumen production rate of approximately 1800 m3/d (11,300 bopd). The structural position of the McMurray C sand and the anticipated position of the producing and injector wellbores for the well pads are shown on Figures 2.4.1 (cross-section A-A) and 2.4.2 (cross-section B-B).

2.4.1 Well Pads

The proposed well pads have been located with consideration of operability, capital costs and environmental impacts. The pads have been located outside of the high water line and have attempted to maintain a minimum of 100 m buffer zone from watercourses with defined channels. Grizzly has located all of the surface Pads on the west side of Little Horse Creek to minimize disturbance in the creek valley.

2.4.2 Drilling and Completions

2.4.2.1 SAGD Producers and Injectors Drilling

The producer wellhead and the steam injector wellhead of each well pair will be spaced 10 to 15 m apart on the surface of the well pad. Figure 2.4.3 shows a plan view of a typical ten well pair well pad. There will be a space of 10 to15 m between the outside wellhead of one pair and the outside wellhead of the adjacent well pair.

Grizzly’s plan is to drill the wells’ horizontal sections as flat as possible in order to have good wellbore hydraulics. This will facilitate reasonably even steam distribution along the length of the injectors. Good wellbore hydraulics will also assist in maximizing fluid production and recoveries.

The producer of each pair will be drilled first using directional drilling technology, such as measurement while drilling (MWD). Prior to drilling the horizontal SAGD wells, Grizzly may elect to drill one or more vertical targeting wells along the horizontal tracks of selected producers in order to increase the accuracy of the horizontal well’s trajectory. An electromagnetic source is hung in the targeting well at the same depth as the producer’s targeted horizontal track. The producer’s drilling assembly can pick up the electromagnetic signal when it is in range. The producer’s trajectory can then be adjusted depending on the strength of the detected signals. The targeting well can later be used as a temperature or a temperature/pressure observation well

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during the SAGD operations. The total depth (TD) of a typical horizontal well with a 800 m long liner is expected to average about 1300 m (Measured Depth (MD)).

Grizzly will drill the injector so that the horizontal section of the injector overlays that of the producer at a target distance of separation of 5 m. The injector drilling operation uses MWD technology also. During the injector’s horizontal section drilling, an electromagnetic source will be progressively moved along the length of the producer. A ranging system will be incorporated into the injector’s drilling assembly. The ranging system will detect the source in the producer. Measurements from the ranging system will aid in steering the injector so that it tracks the path of the producer at a vertical separation of 5 m above the producer.

The trajectories have been designed to minimize the rate of deviation which will assist in

ensuring that the intermediate casing can be run in to the intermediate casing point (ICP). Lower build rate trajectories also aid in ensuring that liners can be run to total depth (TD) with less chance of damage to the liner slots or wire wrap spacing. Similarly, lower build rate trajectories make the installation of a number of artificial lift systems feasible if required. The horizontal sections of the wells will be drilled on average 850 meters in length with 800 meter sections lined with slotted pipe or wire wrapped screens. The lateral spacing between adjacent well pairs will be 60 to 70 m.

Grizzly retained a wellbore hydraulics expert to optimize the hydraulics of the well design. Based on this work, Grizzly plans to utilize 219.1 mm liners in both the injectors and the producers as a base case. It is possible that, for shorter wells (e.g. 600 m), Grizzly may use a production or an injection well completion that uses 177.8 mm liners. The option(s) chosen for various well pairs will be based on the results of the wellbore hydraulics modeling.

Grizzly will be using contractors and service suppliers that are experienced in supplying, drilling, and completing SAGD well pairs, including the drilling rig contractor, directional drilling service company, cementing company, tubular supplier, wellhead supplier, etc. If, during the course of drilling operations, Grizzly abandons a ghost hole or has any other non-standard drilling events, Grizzly will report these events to the ERCB as per the required reporting procedures.

The following sections describe the drilling of the various sections of the wellbore, and are based on Grizzly’s base case well design of using 219.1 mm liners (Figures 2.4.4).

Surface Hole and Casing

The Project SAGD wells will require approximately 42 m of surface casing. A 508 mm surface hole will be drilled. A water based gel slurry mud system will be used for drilling the surface hole. Grizzly will run 406.4 mm, K-55 (or L-80), 96.7 kg/m, buttress thread & coupling (BT&C) surface casing. Grizzly will use thermal cement to cement the surface casing with sufficient excess to ensure good returns to surface.

Intermediate Hole and Casing

As Grizzly plans to utilize a pad drilling rig system, the intermediate section of the wells will be drilled using a combined build and turn section to reach the horizontal target. The producer intermediate hole will be 375 mm and will be drilled to a depth of approximately 250 m TVD

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(about 500 m MD). The injector intermediate hole will also be 375 mm, and will be drilled to a TVD of approximately 245 m in order to place the injector’s horizontal track about 5 m above the producer’s horizontal track.

Grizzly will be using a low density fresh water gel polymer mud system in this section of the wellbore to the top of the McMurray Formation. At this point, the mud system will be switched to fresh water polymer with additional additives to ensure down-hole stability, cleaning and reduce the accretion of bitumen on the drill string and drilling assembly.

Grizzly will utilize 298.5 mm, 89.3 kg/m, L-80 casing with premium connections suitable for steam service (with the appropriate thermal thread compound) for the intermediate casing strings for both the injectors and the producers. Grizzly will cement the intermediate casing with sufficient excess thermal grade cement to provide good returns to surface.

Grizzly will utilize best industry practices using thermal grade cement, and the casing will be properly centralized to ensure a good cement sheath. The well will be circulated with a pre-flush solution to ensure good mud cake removal. Cement will be pumped with sufficient excess to ensure good cement returns to surface. The casing string may be reciprocated or rotated

throughout the cement job if it is viewed that this can be done without damaging the hole or the casing. In addition, Grizzly will run cement bond logs on at least one producer per well pad to monitor the quality of cement jobs, and take corrective action if necessary. All injectors will have cement bond logs run as part of the requirements of ERCB Directive 51.

Horizontal Hole and Liner

The horizontal liner section will average 800 m in length for both steam injection and production wells. The production well will be drilled first, and then the injection well will be drilled from 4 to 6 m (average 5 m) above the production well (Figure 2.4.4). Both wells are to be drilled as flat as possible with vertical deviations of less than 1 m. There will be 60 to 70 m lateral spacing between adjacent well pairs. Measurement while drilling (MWD) technology, incorporating magnetic guidance, will be used to ensure that the injector and producer horizontal sections have appropriate lateral and vertical spacing.

Grizzly will drill 270 mm holes for both the injection and the production well horizontal sections. The average well length, with an 800 m long liner section, will be approximately 1300 m MD to total depth.

Grizzly is planning on using a fresh water, polymer mud system to ensure hole stability and cleaning, and reduce frictional torque and drag. There will also be additives to reduce the accretion of bitumen on the drill string and the drilling assembly.

Grizzly will install either slotted liners or wire wrapped liners. Hycal Energy Laboratories is currently conducting a comprehensive sand control study for Grizzly which should provide a good basis for picking the liner type and the gauge opening for optimum sand control without causing high pressure drops or plugging. Sand production is expected to be minimal (< 0.1 % of the bitumen production rate) due to the use of liner gauge openings which should retain all but the smallest of fines. Grizzly will use liners that are 219.1 mm OD, 47.6 kg/m, L-80 or K-55,