Saleski Grosmont Project Phase 1 Alberta … 2008/03...10.4 ASSESSMENT OF FUTURE EXPANSION OR...

Saleski Grosmont Project Phase 1

Alberta Department of Energy Innovative Energy Technology Program

Approval 03-061

2008 – 2009 Annual Report

September 2009

Laricina Energy Ltd. Saleski Grosmont Project – Phase 1

IETP Approval 03-061 2008 Annual Report

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TABLE OF CONTENTS

1.0 REPORT ABSTRACT ......................................................................................................1

2.0 PROJECT STATUS...........................................................................................................2 2.1 PROJECT TEAM MEMBERS ...........................................................................................................................2 2.2 CHRONOLOGICAL ACTIVITIES AND OPERATIONS REPORT ...........................................................................3 2.3 TOTAL, PRODUCTION, MATERIAL AND ENERGY BALANCE FLOW SHEETS ..................................................4 2.4 RESERVES ESTIMATES .................................................................................................................................4

3.0 WELL INFORMATION ...................................................................................................5 3.1 WELL LAYOUT ............................................................................................................................................5 3.2 DRILLING, COMPLETIONS AND WORK-OVER OPERATIONS .........................................................................6

3.2.1 LEL ET AL SALESK 2-26-85-19........................................................................................................6 3.2.2 LEL ET AL P2 OBS1 SALESK 7-26-85-19........................................................................................6 3.2.3 LEL ET AL P1 OBS1 SALESK 7-26-85-19........................................................................................6 3.2.4 LEL ET AL P2 OBS3 SALES 10-26-85-19.........................................................................................7 3.2.5 LEL ET AL P1 OBS3 SALES 10-26-85-19.........................................................................................7 3.2.6 LEL ET AL 101-P1-HZ SAL 15-26-85-19..........................................................................................7 3.2.7 LEL ET AL 101-P2-HZ SAL 7-26-85-19............................................................................................8

3.3 WELL OPERATIONS .....................................................................................................................................8 3.3.1 Well List and Status ...........................................................................................................................8 3.3.2 Wellbore Schematics..........................................................................................................................9

3.4 SPACING AND PATTERN.............................................................................................................................16 4.0 SOLVENT INJECTION - PRODUCTION PERFORMANCE AND DATA ............17

4.1 INJECTION AND PRODUCTION HISTORY – FIRST AND SECOND CYCLE .......................................................17 4.1.1 Composition of Injected and Produced Fluids.................................................................................19 4.1.2 History of Injection, Production and Observation Well Pressures and Average Reservoir Pressure23

4.2 INJECTION AND PRODUCTION HISTORY – THIRD CYCLE............................................................................24 4.2.1 C3 Solubility and Viscosity Reduction..............................................................................................28

5.0 PILOT DATA ...................................................................................................................30 5.1 NON-PRODUCTION DATA ..........................................................................................................................30

5.1.1 Geological and Geophysical data....................................................................................................30 5.1.2 Laboratory Studies...........................................................................................................................38 5.1.3 Reservoir Data - Solvent Test ..........................................................................................................52

6.0 SOLVENT INJECTION AND WELL ECONOMICS.................................................53 6.1 CAPITAL COSTS – FIELD WORK.................................................................................................................53

6.1.1 Saleski Cross Well Seismic Capital Expenses..................................................................................53 6.1.2 Observation Well Capital Expenses.................................................................................................54 6.1.3 Horizontal Well Capital Expenses ...................................................................................................55

6.2 CAPITAL COSTS - GROSMONT STUDIES .....................................................................................................56 6.3 CAPITAL COSTS - COLD SOLVENT TESTS AND STUDIES.............................................................................56 6.4 CAPITAL COSTS - COLD SOLVENT FIELD TESTS ........................................................................................57 6.5 CUMULATIVE PROJECT COSTS...................................................................................................................59 6.6 MATERIAL DEVIATIONS FROM BUDGETED COSTS .....................................................................................59

7.0 FACILITIES.....................................................................................................................60 7.1 2008 INCURRED MAJOR CAPITAL ITEMS ...................................................................................................60



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7.2 CAPACITY LIMITATION AND EQUIPMENT INTEGRITY ................................................................................61 7.3 PROCESS FLOW AND SITE DIAGRAM..........................................................................................................61

8.0 ENVIRONMENT/REGULATORY/COMPLIANCE ..................................................62 8.1 PROJECT REGULATORY REQUIREMENTS AND COMPLIANCE STATUS.........................................................62 8.2 ENVIRONMENTAL AND SAFETY PROCEDURES ...........................................................................................62

8.2.1 Environmental Management............................................................................................................62 8.2.2 Plan for Shut-down and Environmental Clean-up...........................................................................63 8.2.3 Site Management .............................................................................................................................64 8.2.4 Health and Safety Standard Operating Procedures.........................................................................65 8.2.5 Emergency Response Plans .............................................................................................................66

9.0 FUTURE OPERATING PLAN ......................................................................................67 9.1 PROJECT SCHEDULE ..................................................................................................................................67 9.2 PILOT OPERATION CHANGES .....................................................................................................................67 9.3 SALVAGE UPDATE .....................................................................................................................................68

9.3.1 Reclamation Monitoring ..................................................................................................................68 10.0 INTERPRETATIONS AND CONCLUSIONS .............................................................69

10.1 DIFFICULTIES ENCOUNTERED AND RECOMMENDATIONS...........................................................................69 10.1.1 Cold Solvent – 3rd Cycle .................................................................................................................69 10.1.2 Lost Circulation in the Carbonates..................................................................................................69 10.1.3 Horizontal Well Drilling..................................................................................................................69

10.2 TECHNICAL AND ECONOMIC VIABILITY .....................................................................................................70 10.2.1 Cold Solvent.....................................................................................................................................70 10.2.2 Horizontal Well Drilling..................................................................................................................70

10.3 OVERALL EFFECT ON OVERALL BITUMEN RECOVERY ................................................................................70 10.4 ASSESSMENT OF FUTURE EXPANSION OR COMMERCIAL FIELD APPLICATION AND DISCUSSION OF REASONS70



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LIST OF FIGURES Figure 1: Well Layout Map............................................................................................................. 5 Figure 2: LEL ET AL SALESKI 2-26-85-19 Wellbore Schematic ............................................... 9 Figure 3: LEL ET AL P2 OBS1 SALESK 7-26-85-19 Wellbore Schematic............................... 10 Figure 4: LEL ET AL P1 OBS1 SALESK 7-26-85-19 Wellbore Schematic............................... 11 Figure 5: LEL ET AL P2 OBS3 SALES 10-26-85-19 Wellbore Schematic................................ 12 Figure 6: LEL ET AL P1 OBS3 SALES 10-26-85-19 Wellbore Schematic................................ 13 Figure 7: LEL ET AL 101-P1-HZ SAL 15-26-85-19 Wellbore Schematic ................................. 14 Figure 8: LEL ET AL 101-P2-HZ SAL 7-26-85-19 Wellbore Schematic ................................... 15 Figure 9: Saleski Spider Plot......................................................................................................... 16 Figure 10: Solvent Injection and Production Data........................................................................ 18 Figure 11: Prorated CANSUB Daily Production Rate ................................................................. 19 Figure 12: Composition of Casing Gas......................................................................................... 20 Figure 13: Density of Produced Dead Oil..................................................................................... 21 Figure 14: Viscosity of Produced Dead Oil.................................................................................. 21 Figure 15: First Solvent Injection Cycle Temperature and Pressure Data.................................... 23 Figure 16: Second Solvent Injection Cycle Temperature and Pressure Data ............................... 24 Figure 17: Injection Pressure and Temperature Profiles............................................................... 25 Figure 18: Production Pressure and Temperature Profiles ........................................................... 26 Figure 19: Cumulative Production................................................................................................ 28 Figure 20: Propane Solubility ....................................................................................................... 29 Figure 21: Viscosity of Live Oil Produced................................................................................... 30 Figure 22: Stratigraphy ................................................................................................................. 31 Figure 23: Saleski Cross Section NS-1......................................................................................... 32 Figure 24: Grosmont C Structure Map ......................................................................................... 34 Figure 25: Grosmont C Isopach Map............................................................................................ 35 Figure 26: Grosmont D Structure Map ......................................................................................... 36 Figure 27: Grosmont D Isopach Map ........................................................................................... 37 Figure 28: Capillary Pressure Curves ........................................................................................... 41 Figure 29: Pore Throat Distributions ............................................................................................ 42 Figure 30: Distribution of Micropores and Macropores ............................................................... 43 Figure 31: Oil Composition .......................................................................................................... 47 Figure 32: Asphaltene Precipitation at 10°C ................................................................................ 49 Figure 33: Asphaltene Precipitation at 50°C ................................................................................ 49 Figure 34: Viscosity vs. Temperature........................................................................................... 50 Figure 35: Viscosity Comparison ................................................................................................. 51 Figure 36: Project Schedule .......................................................................................................... 67



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LIST OF TABLES Table 1: Phase 1 Field Work and Studies Summary....................................................................... 2 Table 2: Project Team Members..................................................................................................... 2 Table 3: Chronological Activities and Operations Report.............................................................. 4 Table 4: Monthly and Total Year Production ................................................................................. 4 Table 5: Well List and Status.......................................................................................................... 8 Table 6: SARA Analysis of Produced Oil .................................................................................... 22 Table 7: Results of Live Oil Analysis........................................................................................... 22 Table 8: Results of Water Analysis .............................................................................................. 23 Table 9: Injection Rates ................................................................................................................ 25 Table 10: Production Rates........................................................................................................... 27 Table 11: Dean-Stark & Permeability Results.............................................................................. 40 Table 12: Results from Solubility Test (TIPM)............................................................................ 47 Table 13: Results from Dr. Moore's Group .................................................................................. 51 Table 14: Saleski Cross Well Seismic Costs ................................................................................ 53 Table 15: Observation Well Capital Expenses ............................................................................. 54 Table 16: Horizontal Well Capital Expenses............................................................................... 55 Table 17: Observation Well Capital Expenses ............................................................................. 56 Table 18: Cold Solvent Tests and Studies Capital Expenses........................................................ 56 Table 19: 2008 First and Second Cold Solvent Injection Capital Expenses................................. 58 Table 20: 2009 Third Cycle Cold Solvent Injection Capital Expenses ........................................ 59 Table 21: Third Cycle Cold Solvent Injection Incurred Capital Items......................................... 61



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1.0 Report Abstract The pilot proposed by Laricina Energy Ltd. (Laricina) will evaluate the commercial potential of SAGD within a karsted carbonate reservoir. SAGD within a carbonate environment presents different challenges and remains untested. This report is a summary of the results from field work, production tests, and studies undertaken in preparation of a pilot project within the Athabasca Grosmont formation.

Table 1: Phase 1 Field Work and Studies Summary summaries the field work, and studies that encompass Phase 1 of the project.

Field Work Scope

1 1 Section 3D Seismic Winter 2008 initial 3D seismic data for baseline data for Pilot 9 (2.5 by 2.5 km) & Interpretation Presentation.

2 Reservoir geophysics for 3D Alternate characterization of the 3D seismic data.

3 Observation Wells Drilled 4 observation wells, of which 3 were Cased and Completed and 1 was cored, needed for Drilling of Horizontal wells and Pilot.

4 2 Horizontal Wells Data Drilling and completion reports and logs for 2 horizontal wells (1 in each Grosmont D and Grosmont C)

Grosmont Studies 1 Grosmont PIA Study Petrographic image analysis of Grosmont thin sections 2 Grosmont Core Tomography Study Tomographic imaging of core samples from 6-34-85-19W4 3 Steam Soak Grosmont D Test Steam circulation in 7-4-85-19W4 Grosmont D core sample 4 Grosmont Fluid Analysis AGAT Grosmont bitumen property analysis 5 Grosmont Petrophysical Study Hitchner petrophysical study around township 85-19W4 6 Full Well CT Scan - 11-15 CT scanning of full length core in 11-15-85-19W4

7 ARC Geochemistry Study Analysis of Grosmont chemical reactivity under thermal conditions

8 GUSHOR Geochemical Characterization Geochemistry of steam soak oil recovery

9 Grosmont Steam Rise Study Steam rise recovery in Grosmont core sample 10 Capillary Pressure Study Capillary pressure on profile of Grosmont samples 11 Relative Permeability Study Relative permeability based on NMR technique 12 Steam Soak Grosmont C test Steam circulation in 7-26-85-19W4 Grosmont C core sample 13 Wettability Study Wettability alteration study in 11-15-85-19W4 core sample 14 Ireton Steaming Study Ireton steam rise study 15 GUSHOR Bitumen Profiling Study Bitumen viscosity/density profiling over vertical wellbore 16 Full Well CT Scan - 8-27 CT scanning of full length core in 8-27-85-19W4

17 Cross-well Seismic Cross well seismic tomogrophy at 100 m spacing between 2 obs. wells



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18 End-point saturation study End point sat. determination to steam in Breccia facies.

19 Rock Fluid study Wettability, IFT, oil changes distribution, solution kinetics for range of Grosmont Facies.

Cold Solvent Field Test Related. Scope

1 CO2 Solubility Study CO2 solubility in Grosmont oil 2 Solvent Soak Test Solvent circulation in 7-26-85-19W4 Grosmont C core sample 3 Solvent Solubility Study Solvent solubility in Grosmont oil 4 Asphaltene Precipitation Study Asphaltene precipitation for Grosmont oil to propane

5 3 Cold Solvent Tests (2008 & 2009) Cold Solvent Field test results from 2008 & 2009. (Rates, P & T, Fluid Analyses).

Table 1: Phase 1 Field Work and Studies Summary

2.0 Project Status 2.1 Project Team Members

1. Dave Theriault [email protected] Corporate Development 2. Sandeep Solanki [email protected] Asset Manager

2. Neil Edmunds [email protected] Reservoir

3. Mauro Cimolai [email protected] Reservoir

4. Derek Keller [email protected] Operations

5. Lane Becker [email protected] Drilling and Completions

5. George Brindle George. [email protected] Facilities

6. Kent Barrett [email protected] Carbonate Geology

Table 2: Project Team Members The persons in the bold text are additions to the team. Resumes for additional team members are included.

mailto:[email protected]






mailto:George.%[email protected]




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2.2 Chronological Activities and Operations Report Table 3: Chronological Activities and Operations Report lists each major operational activity chronologically. The activities are separated into Field Work, Grosmont Studies and Cold Solvent Field Test Related.

Date Field Work 05/02/2008 Spud LEL ET AL P1 OBS1 SALESK 7-26-85-19 13/02/2008 Spud LEL ET AL P2 OBS3 SALES 10-26-85-19 15/02/2008 Spud LEL ET AL 101-P2-HZ SAL 7-26-85-19 15/02/2008 Rig Release LEL ET AL P1 OBS1 SALESK 7-26-85-19 16/02/2008 Spud LEL ET AL P2 OBS1 SALESK 7-26-85-19 17/02/2008 Spud LEL ET AL 101-P1-HZ SAL 15-26-85-19 20/02/2008 Spud LEL ET AL P1 OBS3 SALES 10-26-85-19 27/02/2008 Rig Release LEL ET AL P2 OBS1 SALESK 7-26-85-19 04/03/2008 Rig Release LEL ET AL 101-P1-HZ SAL 15-26-85-19 15/03/2008 Rig Release LEL ET AL P2 OBS3 SALES 10-26-85-19 16/03/2008 Rig Release LEL ET AL 101-P2-HZ SAL 7-26-85-19 16/03/2008 Rig Release LEL ET AL P1 OBS3 SALES 10-26-85-19

Date Grosmont Studies

01/02/2007 Steam Soak Grosmont D Test 01/06/2007 ARC Geochemistry Study 01/09/2007 Grosmont PIA Study 15/09/2007 Grosmont Core Tomography Study 01/10/2007 Grosmont Petrophysical Study 01/01/2008 Grosmont Fluid Analysis 01/02/2008 Steam Soak Grosmont C test 01/02/2008 GUSHOR Geochemical Characterization 11/02/2008 Capillary Pressure Study 23/02/2008 Full Well CT Scan - 8-27 22/04/2008 Full Well CT Scan - 11-15 02/06/2008 GUSHOR Bitumen Profiling Study 22/09/2008 Ireton Steaming Study 03/11/2008 Rock Fluid study 26/01/2009 Cross-well Seismic 02/02/2009 End-point saturation study 02/03/2009 Grosmont Steam Rise Study 01/05/2009 Wettability Study



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15/06/2009 Relative Permeability Study 13/10/2009 Reservoir geophysics for 3D

Date Cold Solvent Field Test Related

27/01/2008 Spud LEL ET AL SALESKI 2-26-85-19 03/02/2008 End of First Solvent Injection Cycle 12/02/2008 Rig Release LEL ET AL SALESKI 2-26-85-19 17/02/2008 Start of First Solvent Injection Cycle 08/03/2008 Start of Second Solvent Injection Cycle 15/03/2008 End of Second Solvent Injection Cycle 20/06/2008 Solvent Soak Test 14/07/2008 Solvent Solubility Study 25/09/2008 2 Cold Solvent Tests (2008 & 2009) 01/10/2008 Asphaltene Precipitation Study 05/01/2009 Start of Third Solvent Cycle (Mob equipment to site) 01/02/2009 CO2 Solubility Study 04/03/2009 End of Third Solvent Cycle (Demob equipment from site)

Table 3: Chronological Activities and Operations Report

2.3 Total, Production, Material and Energy Balance Flow Sheets The monthly production and total year production are shown in the table below.

Oil production (m3)

Water production (m3)

February 2008 9.2 9.8March 2008 7.2 5.1

Total production for the year of 2008 (m3) 16.4 14.9January 2009 3.3 0.5February 2009 60.7 5.9

Total production for the year of 2009 (m3) 64.0 6.4Table 4: Monthly and Total Year Production

Material and energy balances are not applicable here because in the initial tests, cold solvents were injected into the formation where no external heat was injected.

2.4 Reserves Estimates Currently there are no reserves assigned to the Saleski property. GLJ’s best case estimate recoverable resources for the Saleski Lease are in the order of 2.3 billion barrels.



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3.0 Well Information 3.1 Well Layout

Figure 1: Well Layout Map

23 24

2526

35 36

Horizontal Wells

Observation Wells

Cold Solvent

T85

R19W4



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3.2 Drilling, Completions and Work-Over Operations

3.2.1 LEL ET AL SALESK 2-26-85-19 The 2-26 well was spudded on January 21, 2008. The surface hole was drilled to 325m with mud ring and bridging difficulties. Weatherford logged the surface hole on January 29 and subsequently ran and cemented 244.5mm surface casing. The well was cored from 325 to 377.96mKB with 76% core recovery from January 31 to February 5. Losses were encountered throughout the coring operation (from 5m3/hr to 12m3/hr). The 222mm main hole was drilled and logged from 378m to 408mKB (total depth) on February 6 with losses (2 cements plugs were run for loss circulation). On February 10, 177.8mm main hole casing was run in the hole with a piezometer and cable. While running in with casing the hole became very tight and 12m3/hr of fluid losses were experienced while circulating. Casing was circulated to avoid getting stuck in the hole which broke the piezometer cable. After the piezometer cable was repaired, 29 joints of 177.8mm Tenaris Blue main hole casing were run and cemented with 19.5 tonnes of thermal cement. The rig was released on February 12, 2008.

See section 4.1 Injection and Production History – First and Second Cycle for the first and second cycle cold solvent testing operations. See section 4.2 Injection and Production History – Third Cycle for the third cycle cold solvent testing operations.

3.2.2 LEL ET AL P2 OBS1 SALESK 7-26-85-19 The P2 OBS1 well was spudded on February 16, 2008. The surface hole was drilled to 306m with some difficulties with mud rings. Surface casing was run and cemented with thermal cement on February 18. The 159mm main hole was drilled to core point (346m) on February 19 and the well was cored from 346 to 366mKB with 100% core recovery. The main hole was drilled to Total Depth (TD) of 406mKB and cement plugs were run on February 20. While attempting to pump a cement plug, the drill pipe became stuck. Fishing operations continued until February 27 at which point the rig was torn out and released. The well was suspended on February 27, 2008.

3.2.3 LEL ET AL P1 OBS1 SALESK 7-26-85-19 The P1 OBS1 well was spudded on February 5, 2008. Surface hole was drilled to 331mKB with some difficulties with mud rings. 331.25m of 244.5mm surface casing was run and cemented with 31 tonnes of thermal cement. Operations were slowed due to extremely cold weather. The main hole was drilled to 405mKB on February 10. Difficulties with loss circulation and mud rings were experienced throughout drilling of the main hole section. Cement plugs were then run to heal the losses. Main hole was logged February 13 and casing was run and cemented with



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thermal cement. Piezometers were set at 374.27mKB, 362.27mKB and 339.27mKB. The rig was released on February 15, 2008.

3.2.4 LEL ET AL P2 OBS3 SALES 10-26-85-19 The P2 OBS3 well was spudded on February 13, 2008. The surface hole was drilled to 318m and logged. Twenty-four (24) joints of 244.5mm casing were run and cemented with 24 tonnes of thermal cement. Due to tight hole, loss circulation and bridging, it took three (3) attempts to land casing on bottom. The 159mm main hole was drilled to 343m on February 22. A LCM pill was mixed and the core barrel was tripped into the hole. Difficulties with loss circulation and tight hole were encountered throughout the main hole section. Smith Wireline Services was rigged in and shot string at 320m. Smith attempted to retrieve the fish from February 22 to 26 using various tools and techniques. The 159mm main hole drilling continued to 405m, and open hole logs were run on February 28. Several attempts were made to pump cement plugs from February 29 to March 12. Between March 6 and March 12 cement retainers were set and pressure tested with Halliburton. There were bridging difficulties while running the first cement plug and loss circulation difficulties throughout the operation. From March 14 to 15, 32 joints of Tenaris Blue casing were run and cemented with foam cement. The rig was released on March 15, 2008.

3.2.5 LEL ET AL P1 OBS3 SALES 10-26-85-19 The P1 OBS 3 well was spudded on February 20, 2008. The surface hole was drilled to 306m with some problems with mud rings. Twenty-four (24) joints of surface casing were run and cemented with 16.5 tonnes of thermal cement on February 22. Main hole was then drilled to 356m. Starting on February 24, the well was cored from 356m to 380m with 100% core recovery. Several cement plugs were pumped to heal losses from February 26 to March 03. Cement was drilled out and main hole wireline logging with Weatherford began. Cement plugs were pumped until March 6. The rig was released on March 16, 2008.

3.2.6 LEL ET AL 101-P1-HZ SAL 15-26-85-19 The rig was walked from the P2 horizontal well and the P1 horizontal well was spudded on February 17, 2008. The 444mm surface hole was drilled to 128m with mud ring problems. Ten (10) joints of surface casing were run and cemented with 21.3 tonnes of thermal cement. The intermediate section was drilled directionally from 128 m to a measured depth of 363m on March 3. 28 joints of 244.5mm Tenaris Blue intermediate casing were run and cemented with thermal cement. Rig released March 04, 2008 and was walked back to the P2 horizontal well to complete the horizontal section.



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3.2.7 LEL ET AL 101-P2-HZ SAL 7-26-85-19 The P2 horizontal well was spudded on February 15, 2008. Surface hole was drilled from 0-130m and surface casing was run and cemented with 22.3 tonnes of thermal cement. The intermediate section was drilled from 130m to a measured depth of 578m. Loss circulation was experienced in this section and 3 cement plugs were run. 29 joints of 244.5 Tenaris Blue casing were then run and cemented with 35 tonnes of thermal cement. The well was paused March 1 as the rig was walked to the P1 horizontal well to complete the surface and intermediate sections. The rig was walked back March 4 to drill the main hole/horizontal section from a measured depth of 578m to total measured depth 1379m on March 13. Throughout the horizontal section, there were challenges with tight hole, loss circulation and tool failure. The well was logged and the liner was run on March 15, and the rig was released March 16, 2008.

3.3 Well Operations

3.3.1 Well List and Status

Well Name ERCB Well Status Spud Date

Rig Release

Date License #

LEL ET AL SALESKI 2-26-85-19 Susp Cr-BITumen 27/01/2008 12/02/2008 392373 LEL ET AL P2 OBS1 SALESK 7-26-85-19 Drilled & Cased 16/02/2008 27/02/2008 392351 LEL ET AL P1 OBS1 SALESK 7-26-85-19 *Drilled & Cased 05/02/2008 15/02/2008 392352 LEL ET AL P2 OBS3 SALES 10-26-85-19 Drilled & Cased 13/02/2008 15/03/2008 392446 LEL ET AL P1 OBS3 SALES 10-26-85-19 Drilled & Cased 20/02/2008 16/03/2008 392447 LEL ET AL 101-P1-HZ SAL 15-26-85-19 Drilled & Cased 17/02/2008 04/03/2008 393303 LEL ET AL 101-P2-HZ SAL 7-26-85-19 Drilled & Cased 15/02/2008 16/03/2008 393306

* - see wellbore schematic 3.3.2.2 Table 5: Well List and Status



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3.3.2 Wellbore Schematics

3.3.2.1 Cold Solvent Well - LEL ET AL SALESKI 2-26-85-19

ELEV (masl) DEPTH (mKB)

587.8 4.20

PiezometerPCPTubing Pressure Borehole Diameter: 311 mm

Note: PCP removed Surface Casing: 244.5 mmonce production interval Thread: ST&Ccompleted, tubing in hole. Grade: H40

Viking 473.00 119 Thermal CementJoli Fou 460.00 132

Upper Grand Rap 444.20 147.8

Lower Grand Rap 420.20 171.8

Clearwater 362.10 229.9

Wabiskaw 298.30 293.7

Ireton Shale 274.80 317.2

Casing Shoe 271.9 320.10

Ireton Carbonate 267.20 324.8 Borehole Diameter: 222 mm

Grosmont D 258.00 334 9.2

Grosmont D Midd 250.00 342 8 Production Tubing

Grosmont D Lowe 239.30 352.7 10.7 89.0 mm J55 EUE

Grosmont CD Mar 228.00 364Grosmont C 226.40 365.6Piezometer #1 222.50 369.50 External Casing Packer

371.80 - 374.42 m

Perforations 374.75 - 383.0 m26 spm, 12 mm diameter

Tubing Pressure Recorder

Progressing Cavity Pump1300TP60 ~385.0m

Production Casing: 177.8 mmGrosmont C argill 206.00 386 Thread: Tenaris BlueGrosmont C 226.40 365.6 Grade: L80Grosmont B 192.80 399.2 Thermal CementTD 188.00 404.00

Borehole TD

Solvent Well Construction and Completion Details1AA/02-26-85-19W4 (Solvent Well)

As of July 2009

Figure 2: LEL ET AL SALESKI 2-26-85-19 Wellbore Schematic



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3.3.2.2 Observation Well - LEL ET AL P2 OBS1 SALESK 7-26-85-19 P2OBS 1 is currently suspended. There are 6.5 joints of 88.9mm drill pipe stuck in the main hole section of the well. The fish top is currently at 335mKB and the bottom is at 397mKB. The drill pipe became stuck while pumping cement plugs.


582.1 5.60

Borehole Diameter: 311 mm

Surface Casing: 244.5 mmThread: ST&C

Viking 473.20 114.5 Grade: H40

Thermal CementJoli Fou 464.70 123

Upper Grand Rapids 444.70 143

Lower Grand Rapids 421.70 166

Clearwater 363.70 224

Wabiskaw 299.10 288.6

Casing Shoe 281.70 306.00Borehole Diameter: 200 mm

Ireton Shale 274.20 313.5

Ireton Carbonate 271.30 316.4

Grosmont D 259.70 328Fish Top 335m

Grosmont D Middle Tite 250.00 337.7

Grosmont D Lower Porou 242.90 344.8

Grosmont CD Marl 231.10 356.6 6.5 joints of 88.9mm Drill Pipe

Grosmont C 229.70 358

Grosmont C argillaceous 209.70 378

Grosmont B 196.70 391Fish Bottom 397m

TD 187.7 400.00Borehole TD

Observation Well Construction Details100/07-26-85-19W4 (P2Obs1)

As of July 2009

Figure 3: LEL ET AL P2 OBS1 SALESK 7-26-85-19 Wellbore Schematic



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3.3.2.3 Observation Well -LEL ET AL P1 OBS1 SALESK 7-26-85-19


597.05 4.27

PiezometerBorehole Diameter: 311 mm

Viking 484.32 117 Surface Casing: 244.5 mmThread: ST&CGrade: H40

Joli Fou 470.32 131Thermal Cement

Upper Grand Rapids 455.22 146.1

Lower Grand Rapids 431.82 169.5


Wabiskaw 309.32 292

Ireton Carbonate 278.42 322.9

Casing Shoe 270.32 331.00Grosmont D 270.22 331.1 Borehole Diameter: 200 mm

Grosmont D Middle Tite 264.42 336.9 Thermocouple Spacing: 3.0m316m to 343m GL

Piezometer #3 262.05 339.27

Grosmont D Lower Poro

Thermocouple

u 252.52 348.8Thermocouple Spacing: 1m

Grosmont CD Marl 241.52 359.8 346m to 355m GL

Grosmont C 240.22 361.1 Thermocouple Spacing: 2m356m to 366m GL

Piezometer #2 239.05 362.27Grosmont C Porosity Str 233.02 368.3 Thermocouple Spacing: 1m

368m to 378m GLPiezometer #1 227.05 374.27 Production Casing: 114 mmGrosmont C argillaceous 220.32 381 Thread: Tenaris Blue

Grade: L80Grosmont B 206.82 394.5 Thermal CementTD 196.32 405.00 Borehole TD


As of July 2009

Figure 4: LEL ET AL P1 OBS1 SALESK 7-26-85-19 Wellbore Schematic



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3.3.2.4 Observation Well -LEL ET AL P2 OBS3 SALES 10-26-85-19


590.18 3.98


Viking 479.06 115.1 Surface Casing: 244.5 mmThread: ST&C

Joli Fou 463.36 130.8 Grade: H40

Upper Grand Rapids 449.16 145 Thermal Cement

Lower Grand Rapids 426.86 167.3


Wabiskaw Sand 304.16 290

Wabiskaw Shale 291.86 302.3


Piezometer #5 282.16 312.00Ireton Shale 281.86 312.3 Production Casing: 114 mmIreton Carbonate 275.46 318.7 Thread: Tenaris BluePiezometer #4 269.16 325.00 Grade: L80Grosmont D 268.56 325.6 Thermocouple Spacing: 3.0mGrosmont D Middle Tite 261.16 333 316m to 343m GLPiezometer #3 260.16 334.00Grosmont D Lower Poro

Thermocouple

u 251.16 343 Thermal Cement

Thermocouple Spacing: 1m346m to 355m GL

Piezometer #2 240.16 354.00Grosmont CD Marl 237.16 357Grosmont C 235.46 358.7 Thermocouple Spacing: 2mGrosmont C Porosity Strk 228.16 366 356m to 366m GLPiezometer #1 228.16 366.00

Grosmont C argillaceous 215.16 379 Thermocouple Spacing: 1m368m to 378m GL

Grosmont B 202.16 392TD 188.58 405.58 Borehole TD


As of July 2009

Figure 5: LEL ET AL P2 OBS3 SALES 10-26-85-19 Wellbore Schematic



13

3.3.2.5 Observation Well -LEL ET AL P1 OBS3 SALES 10-26-85-19


589.8 4.20


Surface Casing: 244.5 mmThread: ST&C

Viking 442.60 151.4 Grade: H40

Thermal CementJoli Fou 463.40 130.6

Upper Grand Rapids 449.10 144.9

Lower Grand Rapids 430.00 164

Clearwater 368.50 225.5

Wabiskaw 302.00 292


Piezometer #5 277.8 316.20

Grosmont D 267.00 327Piezometer #4 264.80 329.20 Thermocouple Spacing: 3.0m

316m to 343m GLGrosmont D Middle Tite 261.00 333Piezometer #3 255.8 338.20 Production Casing: 114 mm

Thread: Tenaris BlueGrosmont D Lower Poro

Thermocouple

u 250.00 344 Grade: L80Thermocouple Spacing: 1m346m to 355m GL

Grosmont CD Marl 237.00 357 Thermocouple Spacing: 2mPiezometer #2 235.80 358.20 356m to 366m GLGrosmont C 358.4Grosmont C Porosity Strk 228.20 365.8

Piezometer #1 223.8 370.20 Thermocouple Spacing: 1m368m to 378m GL

Grosmont C argillaceous 215.70 378.3Grosmont B 392 Thermal CementTD 188.2 405.80 Borehole TD


As of July 2009

Figure 6: LEL ET AL P1 OBS3 SALES 10-26-85-19 Wellbore Schematic



14

3.3.2.6 Saleski Horizontal – LEL ET AL 101-P1-HZ SAL 15-26-85-19 Saleski P1 Horizontal was only drilled, cased and cemented to the intermediate casing point in the Ireton Shale. The horizontal section will be drilled and completed winter 2010.

ELEV (masl) TVD (mKB) MD (mKB)

Ground Level 587.5 0 5.8

Surface Casing: 339 mmThread: ST&CGrade: H40

Thermal Cement

Viking 467.8 119.7 119.7

Intermediate Casing: 244.5 mmSCP 457.5 130 128 Thread: Tenaris BlueViking/KOP 467.8 119.7 134 Grade: K55

Upper Grand Ra 438.8 148.7 148.7 Thermal Foamed CementLower Grand Ra 415.9 171.6 171.7

Clearwater 357.2 230.3 233.7

Wabiskaw 292.9 294.6 311.7

Ireton Shale 270.5 317 344.2

ICP 257.5 330 363

Saleski Production Well P1100/15-26-085-19W4

Figure 7: LEL ET AL 101-P1-HZ SAL 15-26-85-19 Wellbore Schematic


IETP Approval 03-061 ort

15

2008 Annual Rep

3.3.2.7 Saleski Horizontal – LEL ET AL 101-P2-HZ SAL 7-26-85-19

ELEV (masl) TVD (mKB) MD (mKB)

Ground Level 589.8 0 5.6

Surface Casing: 339 mmThread: ST&CGrade: H40

Thermal Cement

ProRod 31.75mm114 mm Production tubing Hydril 503

Intermediate Casing: 244.5 mm (375m MD)SCP 459.8 130 130 Thread: Tenaris BlueViking/KOP 455.8 134 134 Grade: K55Upper Grand Ra 441.1 148.7 148.7Lower Grand Ra 418.1 171.7 171.7 Thermal Foamed CementClearwater 356.1 233.7 237.5Wabiskaw 295.8 294 308.8 Debris Packer Slotted Liner: 178 mmIreton Shale 272.8 317 347.9 Thread: Tenaris Blue SAGDGrosmont D 264.1 325.7 366.2 16 jtns Blank: 178 mm Grade: K55

Thread: Tenaris Blue SAGDGrosmont D Mid 249.8 340 398.6 Grade: K55Grosmont D Lo 238.8 351 435.3ICP 228.8 361 584Heel 228.8 361 584Toe 229.8 360 1280.61

Progressing Cavity Pump with 60.3 mm tail pipe

Saleski Production Well P2100/15-26-085-19W4

Figure 8: LEL ET AL 101-P2-HZ SAL 7-26-85-19 Wellbore Schematic



16

3.4 Spacing and Pattern The SAGD Pilot (Phase 2) will operate up to three (3) 800m SAGD injector/producer well pairs drilled south-north from a central pad at a 100m lateral spacing. The horizontal well pairs will each be immediately offset (within 5 to 10m) by vertical observation wells along the length of the horizontal wells forming a lattice around the pilot.

Figure 9: Saleski Spider Plot



17

4.0 Solvent Injection - Production Performance and Data 4.1 Injection and Production History – First and Second Cycle The first injection and production cycle was performed from February 16, 2008 to March 7, 2008. During this time approximately 60m3 (liquid volume) of liquid C3 and 90m3 (liquid volume) of gaseous CO2 were injected sequentially for about 8 hours. The well was then isolated and left to soak for 2 days before production. During this same cycle, other fluids were injected in many attempts to eradicate the plugging problem; these fluids were 20m3 of PWC-6 (Trican solvent), 25m3 of water, and 4.5m3 of acid. When production was resumed only some of these volumes were produced back. From the Core Lab analysis, one third of the injected PWC-6 was recovered during the first cycle production. In total, the well produced 15m3 of bitumen, 7m3 of PWC-6 and 16m3 of water.

The second cycle (from March 8, 2008 to March 15, 2008) was initialized to improve production via a different method of injection. During this cycle, 60m3 (liquid volume) of C3 and 1589 sm3 of N2 were injected simultaneously followed by a small volume of C3. The injection period was relatively short, lasting approximately 5 hours. The intent of the test was to inject a solvent mixture with a concentration of 50/50 mole % of C3 and N2, however, during the actual field test only 1/10th of the N2 was injected. After injection the well was immediately converted to production, as a result the soaking period was only 1 hour long. Over the production period of approximately 7 days, the well produced 10m3 of bitumen, 1m3 of PWC-6, and 6m3 of water. This cycle was cut short due to spring breakup. The results from the lab analysis indicated that about 2m3 (liquid volume) of C3 was produced during the 2nd cycle.

The cumulative injection of solvents and fluids production in both cycles can be seen in Figure 10: Solvent Injection and Production Data that follows.



18

Solvent Injection and Production Data

16/02 13:30 Injected 60m3 of propane

and 90m3 of liq

CO2

08/03 11:30Injected 60m3 of propane and 195

9sm3 of N2

0

20

40

60

80

100

120

140

160

180

February 12,2008

February 17,2008

February 22,2008

February 27,2008

March 3, 2008 March 8, 2008 March 13, 2008 March 18, 2008

Time

Inje

cted

Vol

umes

(m³)

0

10

20

30

40

50

60

Prod

uced

Vol

ume

(m³)

Fluid Injection (exclude CO2 &N2)Produced Total Fluid

Produced Bitumen

Produced Water

Produced PWC-6

19/02 20:30Injected 7m3 of

water

20/02 12:30 Injected 5m3 of

water and 10m3 of PWC-6

26/02 13:00Injected 5m3 of

PWC-6

27/02 9:00Acid Squeeze - Injected

4.5m3 of acid and 6.5 m3 of 70oC water

15/02 Injected 5m3 of PWC-

6 followed by 420sm3 of N2

07/03 3:30Injected 6m3 of Produced

water

Figure 10: Solvent Injection and Production Data



19

Detailed daily production rates can be seen in Figure 11: Prorated CANSUB Daily Production Rate. CANSUB was hired to operate the field test and the results reported within this reported are presented as recorded by CANSUB.

Prorated CANSUB Daily Production Rate

0

1

2

3

4

5

6

7

8

9

10

February 12,2008

February 17,2008

February 22,2008

February 27,2008

March 3, 2008 March 8, 2008 March 13, 2008 March 18, 2008

Time

Rat

e (m

3 /day

)

Daily BitumenDaily PWC-6Daily WaterDaily Total Fluid

Figure 11: Prorated CANSUB Daily Production Rate

4.1.1 Composition of Injected and Produced Fluids

4.1.1.1 Composition of Injected Solvents During the first cycle, the mole fraction of C3 was approximately 30%. As mentioned previously, for the second cycle, the intended composition of the injected solvents was 50mol% of C3. However, this was not achieved in the field, mostly due to a shortage of N2 in the area. The actual volume of N2 injected was much less than the designed volume. As a result, the solvent mixture injected during the second cycle consisted of 95mol% C3.



20

4.1.1.2 Composition of Produced Fluids Various samples were collected during the field test: casing gas, dead oil, live oil and water. Unfortunately, the majority of the samples collected from the first cycle were analyzed incorrectly. As a result, most of the data from the first cycle was dismissed.

The results from casing gas analysis showed that the produced gas contained a significant amount of C3, as can be seen in Figure 12: Composition of Casing Gas.

0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

N2 CO2 H2S C1 C2 C3

Mol

e fra

ctio

n

2008022920080309200803102008031120080312200803132008031420080315

Figure 12: Composition of Casing Gas

When oil was produced it still contained dissolved solvents, which was then flashed on-site to remove these components. The resulting dead oil was collected and analyzed for density and viscosity, as well as SARA analysis. Figure 13: Density of Produced Dead Oil shows that the produced oil was progressively heavier due to the lower content of dissolved solvent.



21

920

940

960

980

1000

1020

1040

1060

17/02/08 22/02/08 27/02/08 03/03/08 08/03/08 13/03/08 18/03/08

Dens

ity (k

g/m

3)

Figure 13: Density of Produced Dead Oil

The same behaviour was also observed with viscosity; as the test progressed the viscosity of the produced oil increased, as can be seen in Figure 14: Viscosity of Produced Dead Oil.

1

10

100

1000

10000

0 20 40 60 80 100

Temperature (°C)

Vis

cosi

ty (c

P)

20/02/200821/02/200822/02/200823/02/200826/02/200828/02/200802/03/200806/03/200807/03/200808/03/200809/03/2008

Figure 14: Viscosity of Produced Dead Oil



22

SARA (saturates, aromatics, resins and asphaltene) analysis was also performed on the dead oil samples. The results are shown in Table 6: SARA Analysis of Produced Oil. From the results that are summarized in the table below it was apparent that the produced oil exhibited increasing concentrations of asphaltene over time.

Date Volatile organic

comp Saturates Aromatics Resin Asphaltene 22/02/2008 12.5 24.4 16.9 26.9 19.3 26/02/2008 24.1 17.6 11.2 28.3 18.8 02/03/2008 45.2 15.6 6.0 20.2 13.0 07/03/2008 4.0 30.7 20.2 24.1 21.0 10/03/2008 23.4 20.0 9.0 21.8 25.8 11/03/2008 4.9 16.0 16.2 34.7 28.2 12/03/2008 2.8 20.3 13.4 35.6 27.9 13/03/2008 6.2 9.2 14.4 41.9 28.3 14/03/2008 8.0 26.9 19.5 25.5 20.1 20/03/2008 8.3 17.5 12.3 33.1 28.8

Table 6: SARA Analysis of Produced Oil

Live oil samples were collected during production. These samples were then flashed in the laboratory, where the liberated dissolved gas was collected and analyzed. This analysis is extremely important as the extent of viscosity reduction is governed by the volume of dissolved solvents in bitumen. The results of the live oil are shown in Table 7: Results of Live Oil Analysis.

Date Time GOR C3 mol frac Vol%C312/03/2008 12:00 73 0.91 19.7812/03/2008 16:00 90.6 0.88 22.8113/03/2008 0:00 68.2 0.86 17.9013/03/2008 16:00 68.6 0.85 17.6914/03/2008 12:00 69.4 0.80 17.0815/03/2008 0:00 95.5 0.84 22.84

Table 7: Results of Live Oil Analysis

The data from live oil was scarce due to the fact that most live oil samples were mistakenly identified as conventional live oil. Thus, during the laboratory analysis most of these samples were destroyed.



23

The results of the water analysis are shown in Table 8: Results of Water Analysis.

Date Time Cations Anions pH2008 02 20 7:30 952 2042 82008 02 21 12:00 2207 4562 8.12008 02 22 8:15 1841 3486 82008 02 26 2:00 3455 7070 8.12008 02 26 20:00 2748 4024 7.62008 02 27 14:15 3152 3500 7.62008 02 28 15:15 8496 16873 5.22008 03 04 14:00 17094 38610 4.72008 03 06 2:15 1209 6195 5.32008 03 07 19:00 16684 35962 6.62008 03 08 19:20 5272 10241 7.52008 03 09 0:00 6708 13493 7.32008 03 09 13:00 10235 22809 7.5

Table 8: Results of Water Analysis

4.1.2 History of Injection, Production and Observation Well Pressures and Average Reservoir Pressure

Over the course of the test, the bottom hole pressure and temperature were logged along with the piezometer pressure in Grosmont “D” formation. The logged responses are shown in Figure 15: First Solvent Injection Cycle Temperature and Pressure Data and Figure 16: Second Solvent Injection Cycle Temperature and Pressure Data. Casing and tubing pressures were also logged.

0

10

20

30

40

50

60

70

16/02/2008 18/02/2008 20/02/2008 22/02/2008 24/02/2008 26/02/2008 28/02/2008 01/03/2008

Tem

pera

ture

(C)

-

1,000

2,000

3,000

4,000

5,000

6,000

7,000

Pres

sure

(kPa

)

Piezometer D TempBottom Hole TempPiezometer Pressure (kpag)Casing Pressure (kpag)

Tubing Pressue (kpag)Bottom Hole Pressure (kpaa)

Figure 15: First Solvent Injection Cycle Temperature and Pressure Data



24

0

10

20

30

40

50

60

70

80

90

100

08/03/2008 09/03/2008 10/03/2008 11/03/2008 12/03/2008 13/03/2008

Tem

pera

ture

(C)

-

1,000

2,000

3,000

4,000

5,000

6,000

7,000

Pres

sure

(kPa

)

Piezometer D TempBottom Hole TempPiezometer D Pressure (kpag)Trican Inj. PressureCasing Pressure (kpag)Tubing Pressue (kpag)Bottom Hole Pressure (kpaa)

Figure 16: Second Solvent Injection Cycle Temperature and Pressure Data

4.2 Injection and Production History – Third Cycle

The third cycle began by injecting solvents on January 21, 2009 and lasted until January 28, 2009. Over this injection period the total volume of solvents injected were 549m3 of liquid C3

(291 tonnes) and 155,000sm3 N2 (180 tonnes). The total C3 volume injected was calculated based on C3 tank levels, whereas the total volume of N2 injected were provided by Praxair. Both solvents were injected simultaneously with a C3 mole fraction of approximately 50%. During injection the bottom hole pressure peaked at about 4600kPa, as can be seen in Figure 17: Injection Pressure and Temperature Profiles.



25

0

1000

2000

3000

4000

5000

Jan-210:00

Jan-2112:00

Jan-220:00

Jan-2212:00

Jan-230:00

Jan-2312:00

Jan-240:00

Jan-2412:00

Jan-250:00

Jan-2512:00

Jan-260:00

Jan-2612:00

Jan-270:00

Jan-2712:00

Jan-280:00

Jan-2812:00

Jan-290:00

Pres

sure

(kPa

g)

0

5

10

15

20

25

30

35

40

Tem

p (°

C),

C3

rate

(m3/

hr)

"D" Pressure

"C" Pressure

"D " Temp.

"C" Temp.

C3 rate

Figure 17: Injection Pressure and Temperature Profiles

During injection the bottom hole pressure and temperature (BHP, BHT), piezometer pressure and temperature in Grosmont “D” and the C3 injection rate was logged. The N2 injection rate could not be logged due to communication issues between the ultrasonic meter and the datalogger.

A log book was kept on-site to record associated activities during the test. Based on the information recorded in the book the injection rates and the corresponding cumulative injection are compiled and shown in Table 9: Injection Rates.

Date Time N2 (sm3/min) N2 (tonne/hr) C3 (m3/hr) C3 (tonne/hr) Cum N2 (sm3) Cum C3 (tonne)21/01/2009 19:28 10 0.699 3.8 2.0391 0 022/01/2009 14:30 12 0.8388 3.8 2.0968 11420 38.811322/01/2009 22:06 13 0.9087 3.8 2.0024 16892 54.746622/01/2009 22:12 14 0.9786 3.8 2.0024 16970 54.946823/01/2009 00:02 16 1.1184 3.8 2.1072 18510 58.618023/01/2009 01:15 18 1.2582 3.8 2.1072 19678 61.181823/01/2009 21:00 20 1.398 4 2.2347 41008 102.799623/01/2009 23:00 22 1.5378 4.2 2.3522 43408 107.268923/01/2009 23:30 20 1.398 4 2.2402 44068 108.445024/01/2009 04:20 18 1.2582 3.8 2.1491 49868 119.272624/01/2009 08:45 12 0.8388 3.3 1.8664 54638 128.764724/01/2009 11:30 18 1.2582 2.8 1.5878 56618 133.897228/01/2009 04:00 10 0.699 3.5 1.8974 152198 274.4128/01/2009 06:00 0 0 0 0 153398 278.21

Table 9: Injection Rates



26

The total volume injected into the formation was slightly different than the values quoted earlier on page 24 in section 4.2(291 tonnes of C3 and 180 tonnes of N2). The total value of N2 injected provided by Praxair included all the N2 that was used during testing to fix leaks, thus it is slightly higher than the value calculated directly from the rates. The volume of C3 injected based on the C3 tank level calculations was likely not as accurate.

It should be noted that during the period of injection from January 24 to 28 there were various instances where the C3 pump was down (approximately 17 hours). During this 4 day period, the injection rate for C3 was set at 3.5m3/hr. Assuming that C3 injection was continuous over this period the injection rate was lowered to 2.8m3/hr to yield the proper cumulative C3 injection.

The well was converted to production on January 28, 2009. Oil was not produced until January 29, 2009. On January 30, 2009 the well was shut-in to facilitate automatic control of the tubing pressure (to keep produced live oil in a single phase), during which the pump motor was burned out. Production resumed on February 2 and lasted until February 28, 2009. The pressure profiles are shown in Figure 18: Production Pressure and Temperature Profiles.

During the last 14 days of production it was necessary to produce at intermittent intervals, because shut-in was required to build up fluid level in the wellbore to prevent gas production.

Overall, the total fluids produced are approximately 70m3. The oil and water production rates are shown in Table 10: Production Rates.

0

500

1000

1500

2000

2500

3000

3500

Jan-29 0:00 Feb-3 0:00 Feb-8 0:00 Feb-13 0:00 Feb-18 0:00 Feb-23 0:00

Pres

sure

(kPa

g); D

ensi

ty (k

g/m

3); F

low

(kg/

hr)

0

5

10

15

20

25

30

35

Tem

pera

ture

(°C

)

"D" Piezo Pressure

BHP

Density

Mass flow

BHT

T of D

Figure 18: Production Pressure and Temperature Profiles



27

Date Total Fluid (m3/d) Qo (m3/d) Qw (m3) Cum Fluid (m3) Cum Oil (m3) Cum Water (m3)30/01/09 0 0 0 0 0 031/01/09 3.76 3.1 0.7 3.8 3.1 0.701/02/09 0 0.0 0.0 3.8 3.1 0.702/02/09 0 0.0 0.0 3.8 3.1 0.703/02/09 5.34 4.4 1.0 9.1 7.5 1.604/02/09 5.34 4.4 1.0 14.4 11.8 2.605/02/09 4.61 3.8 0.8 19.1 15.6 3.406/02/09 3.47 2.8 0.6 22.5 18.5 4.107/02/09 4.09 3.4 0.7 26.6 21.8 4.808/02/09 4.1 3.4 0.7 30.7 25.2 5.509/02/09 3.49 2.9 0.6 34.2 28.0 6.210/02/09 2.57 2.1 0.5 36.8 30.2 6.611/02/09 0.95 0.8 0.2 37.7 30.9 6.812/02/09 1.84 1.5 0.3 39.6 32.4 7.113/02/09 3.2 2.6 0.6 42.8 35.1 7.714/02/09 2.58 2.1 0.5 45.3 37.2 8.215/02/09 1.22 1.0 0.2 46.6 38.2 8.416/02/09 1.46 1.2 0.3 48.0 39.4 8.617/02/09 3.52 2.9 0.6 51.5 42.3 9.318/02/09 2.05 1.7 0.4 53.6 43.9 9.619/02/09 1.76 1.4 0.3 55.4 45.4 10.020/02/09 2.16 1.8 0.4 57.5 47.2 10.421/02/09 2.28 1.9 0.4 59.8 49.0 10.822/02/09 1.73 1.4 0.3 61.5 50.4 11.123/02/09 1.98 1.6 0.4 63.5 52.1 11.424/02/09 1.4 1.1 0.3 64.9 53.2 11.725/02/09 1.14 0.9 0.2 66.0 54.2 11.926/02/09 1.73 1.4 0.3 67.8 55.6 12.227/02/09 1.75 1.4 0.3 69.5 57.0 12.528/02/09 0.83 0.7 0.1 70.4 57.7 12.7

Table 10: Production Rates

The volume of total fluids produced was reported by the operators everyday by observing the change in the level of the P-tank and calculating the corresponding volumes.

The water content was difficult to determine due to conflicting numbers. The trucking company (CCS) reported water-cuts for the 3 trucks delivered to be 12%, 1% and 21%, respectively. TIPM measured the water content of the pails delivered to them, and they found that the water cut was fairly consistent at about 18%. The numbers above were derived by assigning a fix water cut of 18%.

Gas production was not logged due to the same problem that was encountered with the ultrasonic meter. However, this value was manually recorded at 1 hour intervals. The cumulative production (including gas) is plotted in Figure 19: Cumulative Production.



28

0

50

100

150

200

29/01/09 03/02/09 08/02/09 13/02/09 18/02/09 23/02/09 28/02/09

Cum

ulat

ive

prod

uctio

n (to

nne,

m3)

, GLR

0

2000

4000

6000

8000

10000

12000

14000

16000

18000

Cum

gas

(am

3)

Cum mass Cum vol GLR Cum gas P tank

GLR

Cum gas

Cum vol

Cum mass

Figure 19: Cumulative Production

It should be noted that the oil rate for the last two weeks of production was fairly consistent. It would have been useful to continue producing in order to observe the production rate fall off, but the test was cut short due to spring break-up. Incidentally, the gas to liquid ration (GLR) is also fairly consistent over this same period of production.

4.2.1 C3 Solubility and Viscosity Reduction Various data were recorded during this test. The density of the produced fluids was logged. This is a great source for extrapolating the solubility information. C3 solubility can also be extracted from live oil viscosity information (determined from viscometer loop) and production (oil and gas) information. The solubility of C3 was calculated based on mixing rules and plotted in Figure 20: Propane Solubility.



29

0

10

20

30

40

50

27/01/09 01/02/09 06/02/09 11/02/09 16/02/09 21/02/09 26/02/09 03/03/09

Volu

me

% o

f C3

in b

itum

en m

ixtu

re

vol%C3 from dens vol%C3 from PGvol%C3 from visc from Lab

Figure 20: Propane Solubility

Live oil samples were collected from the test and sent to Core Lab to determine composition and live oil viscosity. The C3 fractions reported by Core Lab are also compared against the calculated values in Figure 20: Propane Solubility. The results measured by Core Lab agree quite well with the values extracted from live oil density and production data.

As mentioned previously, the live oil viscosity can be extracted from information gathered from the viscometer loop. The produced live oil travelled through two different loops of known length and diameter with the pressure drop being recorded. The live oil viscosity was then calculated from Hagen-Poiseuille’s equation and is shown in Figure 21: Viscosity of Live Oil Produced.



30

0

1

10

100

1000

10000

27/01/09 01/02/09 06/02/09 11/02/09 16/02/09 21/02/09 26/02/09 03/03/09

Visc

osity

(cP)

0

20

40

60

80

100

120

140

160

180

200

T (°

C)

cold hot from Lab T cold

Figure 21: Viscosity of Live Oil Produced

So far the live oil viscosity values measured by Core Lab are in agreement with the values calculated from the “cold” viscometer loop.

5.0 Pilot Data 5.1 Non-Production Data

5.1.1 Geological and Geophysical data

Figure 22: Stratigraphy shows the typical stratigraphy of the zones in the region. The Grosmont Formation is an Upper Devonian carbonate succession that is part of the Woodbend Group. It is underlain by the Lower Ireton Formation, an approximately 100 to 120m thick nonporous shale sequence that is a very good basal seal. It is capped by a 20 to 25m thick Upper Ireton succession of argillaceous dolomites and shale which is in turn overlain by the vuggy dolomites of the Nisku Formation (where it has not been eroded). The Grosmont is approximately 120m thick and consists of four subdivisions, designated A, B, C and D in ascending order, that are separated by thin argillaceous markers. The basal three units, A, B and C, are shallowing upwards cycles. The D unit that caps the Grosmont Formation is an agradational unit. Northeast of Laricina’s Saleski



31

lands the Grosmont Formation has been erosionally bevelled to the northeast. The regional dip on the top of the Grosmont C is approximately 4.25m per kilometre where its upper surface is not erosional. The bitumen resource within the Grosmont Formation in the Saleski area is confined to the Grosmont C and D zones. The gross porous interval is approximately 50m thick. A thin marl unit at the top of the Grosmont C separates the porosity developments within the Grosmont C and D units.

Reservoir units within the Grosmont C and D are stratigraphically continuous within the Saleski area. Porosity is largely secondary but its distribution is controlled by depositional facies which is crudely layercake in its distribution. Figure 23: Saleski Cross Section NS-1 demonstrates the continuity of reservoir and non-reservoir units in the vicinity of the proposed cold solvent well.

The Devonian is unconformably overlain by the Cretaceous shales and sands of the Manville Group. These strata are water bearing. Where the shales overlie the Grosmont Formation, they provided a seal during oil migration.

Figure 22: Stratigraphy



32

Figure 23: Saleski Cross Section NS-1



33

Structure and isopach maps of the Grosmont C for the immediate vicinity of the proposed Saleski pilot in section 26 (T85, R 19W4) are shown in Figure 24: Grosmont C Structure Map and Figure 25: Grosmont C Isopach Map. The Grosmont C isopach shows little variation within the Saleski area supporting the thesis that it is a monotonous and predictable stratigraphic unit in the Saleski area. The structure map demonstrates that it dips gently to the southwest with some gentle flexuring on this planar surface.

The Grosmont D structure, shown in Figure 26: Grosmont D Structure Map, mimics the gentle southwest dip of the Grosmont C except in the northeast corner of the map where the influence of erosional thinning of the Grosmont D is evident. The fully preserved Grosmont D thickness varies between 30 and 32.8m in the Saleski area as is evident from the Grosmont D Isopach Map shown in Figure 27: Grosmont D Isopach Map. East of the test well located in section 26, the thickness of the Grosmont D thins to less than 20m due to erosion during the pre-Cretaceous erosional event.



34

5.1.1.1 Grosmont C Structure Map

Figure 24: Grosmont C Structure Map



35

5.1.1.2 Grosmont C Isopach Map

Figure 25: Grosmont C Isopach Map



36

5.1.1.3 Grosmont D Structure Map

Figure 26: Grosmont D Structure Map



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5.1.1.4 Grosmont D Isopach Map

Figure 27: Grosmont D Isopach Map



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5.1.2 Laboratory Studies

5.1.2.1 Grosmont PIA Study A petrographic image analysis study was been performed on a core sample suite from the 6-34-85-19W4 well. Some SEM samples have been processed for key lithologies identified.

5.1.2.2 Grosmont Core Tomography Studies Cat Scanning of core material from two wells was conducted at TIPM labs. The primary objective of the tomography studies was to identify the internal rock framework, providing both direct visual and quantifiable information on the vug, fracture and matrix porosities and flow networks at a core scale. Tomography studies have been conducted on approximately 0.75m of core from the Grosmont C unit from the 6-34-85-19W4 well, 2m of core from the 7-4-85-19W4 well and 1m of core from the 7-26-85-19W4 well from the Grosmont C unit is in progress.

5.1.2.3 Steam Soak Grosmont D Test A 1m sample of full diameter core from the Grosmont D was steam soaked within a specially designed apparatus with stringent controls on fluid recovery. Primary objective of this test was to demonstrate the magnitude of hydrocarbon recovery accompanied by an understanding of the drive mechanisms and scale at which recovered fluids were obtained i.e. levels of secondary porosity, matrix porosity and micro porosity recoveries. The tested core was CT scanned over three stages:

1. as received, frozen from the well site; 2. after dry heating to 90ºC and; 3. following steaming for a 10 day period.

Density overlays at each stage revealed the scale of bitumen movement internal to the rock fabric accompanying the recovered fluids.

5.1.2.4 Grosmont Fluid Analysis The native Grosmont bitumen was analysed across a range of tests including molecular composition, elemental analysis, aromatic spectrum, asphaltene content, density, API gravity, carbon residue, sulphur content, viscosity, SARA, water content, high temperature distillation and TAN.

5.1.2.5 Grosmont Petrophysical Study Well log data from 22 wells from the Saleski area (Twp. 84-85, Rge. 18-19 W4) were analyzed to provide an independent, reasonable and consistent estimation of the reservoir parameters and analyze the apparent hydrocarbon zones within the Grosmont formation.



39

5.1.2.6 Full Well CT Scan – 11-15 A program to develop quantitative analysis of secondary and primary porosity from CT density scans was refined and extended specific to the Grosmont application.

5.1.2.7 ARC Geochemistry Study Using the geochemical computer modelling software, GAMSPath, a mineralogy representing the Grosmont formation and 3 different fluids representing a condensed steam, a mixture of condensed steam and formation water, and a boiler condensate were made to react. The results of the modelling included the changes in mineralogy, partial pressure of carbon dioxide and aqueous species over time.

Although the rate of reactions varied between the different zones, the reactions themselves were remarkable similar. Two major reactions were observed; one - the dissolution of some of the dolomite to form calcite, and two - the dissolution of the clays to form chlorite. The initial rates were fast due to the re-equilibrium of the initial solution and the minerals, then relatively fast due to the presence of illite. Once the illite had more or less completely reacted out, the reactions were much slower.

The reactions were quite limited in extent, thus formation damage would not be expected. There would probably be a slight increase in porosity and permeability due to the dolomite dissolution and calcite precipitation.

The limited nature of these reactions was due to the nearly mono-mineralic nature of the Grosmont formation (∼95% dolomite) and the relatively dilute nature of the Grosmont formation fluid.

All of the zones (with their different fluids) resulted in an increase of the partial pressure of carbon dioxide to between 1 and 2 bars, with Zone 1 the highest and Zone 3 the lowest. Considering the approximations in these calculations, the differences are not large. There certainly was no indication that high partial pressures of carbon dioxide were ever reached.

5.1.2.8 GUSHOR Geochemical Characterization

The fluid characterization of bitumen from a reservoir vug from the Grosmont formation, and from a core steaming experiment on a related core carried out by TIPM was conducted to better understand the changes in bitumen properties effected by core steaming. The samples all contained severely biodegraded oils reaching levels of 6 – 8 on the Peters and Moldowan scale and levels of 800 to 1100 on the GUSHOR scale. The most biodegraded oil was the well sample (from reservoir vug), which showed extensive alteration of hopanes and production of 25 nor hopanes. It was also clearly seen that the bitumen samples collected from core steaming were



40

enriched in lower molecular weight compared to the bitumen Dean-Starked from the core after steaming. In addition, the bitumen produced from top of the core was enriched in saturated hydrocarbons and in lower molecular weight components compared to the bitumen produced from the bottom of the core. The enrichment of low molecular weight and hydrocarbon fractions suggested a distillation process rather an aqueous extraction process was dominantly active through some chemical fractionation was evident during the process. The vertical fractionation seen in the top versus the bottom produced bitumen indicated a simple vapour liquid equilibrium process and the top sample was interpreted as a condensate from a hot vapour phase material with the bottom sample being the liquid in equilibrium with the vapour.

5.1.2.9 Grosmont Steam Rise Study This study remains in progress at TIPM laboratory.

5.1.2.10 Capillary Pressure Study Eighteen samples were selected from intact portions of core from well 7-26-85-19W4, thus representing the tightest pore structure. The samples were cleaned via Dean-Stark, after which the gas permeability was determined. The samples were then subjected to mercury injection to extract capillary information. The Dean-Stark and permeability results are shown in Table 11: Dean-Stark & Permeability Results.

Routine @ NOBP 6000 kPa Dean-Stark resultsSample Grain Helium Gas Helium Gas

ID Depth Density Porosity Permeability Porosity Permeability Comments Sw So (m) (kg/m3) (%) (mD) (%) (mD)

SP-01 320.3 2832 27.31 6.1329 26.67 5.9306 0.049 0.951SP-02 334.4 2795 28.05 2005.7 27.75 1877.8 Vuggy 0.102 0.898SP-03 337.5 2778 30.14 409.18 29.39 380.15SP-04 338.8 2781 17.83 1.356 15.51 1.0192 0.14 0.86SP-05 340.1 2804 11.49 10.134 10.52 8.82379 FractureSP-06 342.6 2809 9.58 73.86 Fracture 0.773 0.227SP-07 344.7 2785 5.82 0.19021 5.43 0.1796 Vuggy 0.163 0.837SP-08 345.8 2798 15.52 16.0024 14.94 15.7679 0.016 0.0984SP-09 347.1 2800 10.85 0.67105 9.62 0.417SP-10 353.8 2791 36.03 44.75 30.79 35.4228 Fracture 0.031 0.969SP-11 357.6 2822 43.62 53.23 41.03 50.53 Fracture 0.045 0.955SP-12 360.9 2746 21.13 40.21 19.48 37.264 Fracture 0.435 0.565SP-13 365.6 2805 8.62 42.05 7.5 39.23 Vuggy, FractureSP-14 367.4 2799 14.5 26.2666 12.09 25.031 Vuggy, Fracture 0.125 0.875SP-15 373.4 2807 20.17 382.119 18.05 345.95 Vuggy, Fracture 0.082 0.918SP-16 374.4 2788 22.95 157.3644 22.17 149.19 Vuggy, FractureSP-17 381.5 2802 12.08 57.528 10.53 42.3964 Vuggy, Fracture 0.055 0.945SP-18 386.3 2800 10.9 45.869 9.49 22.43 Vuggy, Fracture 0.218 0.782

Table 11: Dean-Stark & Permeability Results



41

Capillary data of all samples are compared in Figure 28: Capillary Pressure Curves. In general, the higher the permeability the lower the capillary curve.

0

1

10

100

1,000

10,000

100,000

1,000,000

0 10 20 30 40 50 60 70 80 90 100

Wetting Phase Saturation (%)

Cap

illar

y Pr

essu

re (k

Pa)

SP1 6mDSP2 2000mDSP3 409mDSP4 1mDSP5 10mDSP6 74mDSP7 .2mDSP8 16mDSP9 .7mDSP10 45mDSP11 53mDSP12 40mDSP13 42mDSP14 26mDSP15 382mDSP16 157mDSP17 58mDSP18 46mD

Figure 28: Capillary Pressure Curves

The pore throat distributions of the same samples are plotted in Figure 29: Pore Throat Distributions. This figure shows that generally the sample with high permeability has a higher fraction of large pore throats.



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0

5

10

15

20

0.001 0.01 0.1 1 10 100Pore Throat Radius (microns)

Incr

emen

tal N

onw

ettin

g Ph

ase

Satu

ratio

nSP1 6mDSP2 2000mDSP3 409mDSP4 1mDSP5 10mDSP6 74mDSP7 .2mDSP8 16mDSP9 .7mDSP10 45mDSP11 53mDSP12 40mDSP13 42mDSP14 29mDSP15 382mDSP16 157mDSP17 58mDSP18 46mD

Figure 29: Pore Throat Distributions

Figure 30: Distribution of Micropores and Macropores plots the wetting saturations in micro and macro pores against permeability. This figure shows that samples with higher permeability tend to have a higher wetting saturation in the macropores and lesser wetting saturation in micropores.



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0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

1

0.1 1 10 100 1000 10000

Gas perm (mD)

Sw

from

DS

(frac

tion)

0

10

20

30

40

50

60

70

80

90

100

Satu

ratio

n of

wet

ting

phas

e (%

)

Sw Sw in micropores Sw in macropores

Figure 30: Distribution of Micropores and Macropores

This figure shows that samples with high permeability have relatively low wetting phase saturation in micropores and a much larger saturation in macropores. This implied that samples with high permeability had a significant number of large pores.

5.1.2.11 Relative Perm Study

5.1.2.12 Steam Soak Grosmont C test The principal objective of this experiment was to evaluate the effect of steam heating on the mobilization of bitumen within a Grosmont C carbonate core sample. The production response of the Grosmont C test demonstrated a rapid initial drainage profile, consistent with the depletion of a continuous secondary porosity network (vugs and fractures) throughout the core. Oil recovery was 41% by weight from Dean-stark, indicating drainage from both the primary and secondary core porosity.

CT scanning revealed that mobilized bitumen was uniformly evident throughout the full core length, despite wide variations in porosity across the sample.

5.1.2.13 Wettability Study Experiment in progress.



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5.1.2.14 Ireton Steaming Study A steam rise experiment was conducted on a bitumen saturated core samples from well 2-26-85-19W4 from the Ireton formation. The Ireton core demonstrated a marked lithology change at the Grosmont-Ireton contact, where the Ireton brecciated dolomitic grainstone framework commonly carried a higher clay content. The principal objective of this experiment was to investigate the Ireton recovery potential from underlying SAGD operations in the Grosmont D.

The core was vertically mounted over an underlying sandpack. Steam was subsequently injected in the center of the underlying sandpack. During the course of the experiment, it was expected that the vertical steam rise through the core sample would mobilize oil in countercurrent flow to the exit at the base of the core holder, where all recovered fluids, oil, water and steam were collected.

Oil recovery from this experiment was approximately 30% of the original oil in place.

5.1.2.15 GUSHOR Bitumen Profiling Study Fifteen (15) frozen core samples were collected from well 11-15-085-19W4. Solvent and mechanically extracted bitumen from core samples in the Grosmont formation were geochemically characterized and analyzed for viscosity and API gravity. All oils appeared to be derived from a common source and are equally mature. The variations in molecular composition and physical properties of these coils could be explained by variable levels of biodegradation and charge mixing processes.

The dead oil viscosity was measured on mechanically recovered bitumen at 20, 30, 50, 80, 149 and 185°C. The viscosity values of bitumen range from 1.5 to 6.1 million cP and all bitumen samples had low API gravity ranging from 6.1 to 7.4°. The viscosity variations are more typical of carbonate reservoirs, showing a classical decrease in viscosity down the oil column, quite unlike the variations seen in McMurray oil sand reservoirs, which invariable increase in viscosity down reservoir.

Geochemical data analyzed by GC-MS indicated that the well contained severely biodegraded oils reaching levels of 6 to 8 on the Peters and Moldowan scale. In general, the C0-C4 alkylnapthalenes, C0-C1 phenapthrene and C0-C1 dibenzothiophene had been largely removed by biodegradation. C2 alkylphenanthrenes were the most sensitive components to biodegradation in aromatic fractions. In the saturated hydrocarbon fractions, all normal alkanes and isoprenoid alkanes were completely removed. Terpane biodegradation mainly occured in bicyclic sesquiterpanes and pentacyclic trepans (mainly hopanes), tricyclic terpanes were left intact. Sterane biodegradation occured with regular steranes and some diasteranes being removed but pregnanes (short chained steranes) were left intact. The best proxy for the level of oil alteration



45

in this suite was the absolute concentration of pentacyclic terpanes which intensified downward to the oil water contact. While the general systematics of biodegradation in carbonate reservoirs are similar to those in clastic reservoirs, the mass transport systematics and rates of degradation in carbonate reservoirs are likely different, due to different loading of nutrients in each reservoir type and the access of water to the bitumen may occur more variably in carbonate reservoirs resulting in more variable viscosity gradients.

5.1.2.16 Full Well CT Scan 8-27 The full core interval of approximately 50m from well 8-27-85-19W4 was CAT scanned. This information was then converted to density and porosity maps to showcase the pore structure.

5.1.2.17 Cross-Well Seismic The objective of the cross well seismic was to provide high resolution seismic imaging of the Grosmont formation over the proposed Pilot Project Area at Saleski. The cross well seismic program will be performed in several stages. The first stage seismic program concluded in February 2009, at the toes of the first two SAGD wellpairs.

This program will:

• Provide a detailed image of the Grosmont D and Grosmont C zones.

• Allow Laricina to evaluate the quality and structure of the reservoir and the continuity of the layer between the two zones.

• Provide baseline velocity and structural models for future time lapse images tomography to accurately monitor changes in the reservoir from the SAGD operation.

The project included planning, acquisition and processing for one crosswell profile.

5.1.2.18 End-Point Saturation Study Experiment in progress.

5.1.2.19 Rock Fluid Study Experiment in progress.

5.1.2.20 CO2 Solubility Study The main objective of this study was to evaluate the solubility of CO2 into the bitumen under two different temperatures and various vapour pressures. Since the CO2 solubility data may advance potential recovery strategies for the Grosmont reservoir, the experiments were conducted to evaluate the solubility of CO2 at reservoir temperature and at an elevated temperature of 50°C.



46

Under the experimental procedure, approximately 4L of bitumen was placed into a 6L mixing cylinder to measure gas oil ratio and live oil viscosity at different pressures. Before the solubility measurement, the native bitumen properties, such as API gravity and viscosity, were determined.

The solubility tests demonstrated that at either temperature, the solubility of CO2 in bitumen depended on the saturation (bubble point) pressure. For all test results, the dissolved CO2 reduced the viscosity of the live oil significantly, indicating that CO2 might be a potential carrying media for bitumen recovery within a carbonate.

5.1.2.21 Solvent Soak Test Since the mechanisms of bitumen recovery within a carbonate rock are not well understood and just emerging as an area of study, this experiment was conducted to evaluate the mobilization of bitumen under solvent injection at a core scale.

A core from the Grosmont C was mounted vertically and a mixture of C3 and CO2 was injected. Over a period of 10 days, the following observations were made:

• Grosmont bitumen was mobilized by the injected mixture of carbon dioxide and C3.

• Oil expulsion occurred within the rock matrix as well as the highly developed secondary fracture/vug system.

• Although the Grosmont core was thought to be initially saturated with only oil and water, evidence of initial gas saturation was assessed based on the porosity calculated from CT numbers and Dean-Stark cleaning of the core after the solvent flood.

• The average API gravity of produced oil was 6.54°API, while the gravity of Dean-Starked oil was 5.61°API.

• Bench oil recovery totalled 54% by volume and 54% by weight after solvent injection.

• CT scanning revealed a highly heterogeneous rock framework with a dense, continuous fissure/vug network through the core sample.

5.1.2.22 Solvent Solubility Study

TIPM was commissioned to evaluate the solubitlity of C3 in the Grosmont bitumen at various pressures. The oil provided to TIPM was previously spun by AGAT to remove water and fines. A request was made to AGAT to determine the oil composition and measure the dead oil viscosity as well as the oil composition after the oil was cleaned. The dead oil viscosity was measured at 40°C, 50°C and 60°C. The oil composition is shown in Figure 31: Oil Composition.



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0

0.02

0.04

0.06

0.08

0.1

0.12

C9C11

C13C15

C17C19

C21C23

C25C27

C29

Mol

e fra

ctio

n

Figure 31: Oil Composition

When the oil arrived at TIPM, the dead oil viscosity was re-measured and was found to be about 56 million cP (at 15°C). There was a significant difference in the oil viscosity measured between the two labs, especially at high temperature. TIPM re-measured the dead oil viscosity by a utilizing a different technologist but a similar result was obtained. TIPM attributed the difference either to the usage of different equipment or method of evaluation.

TIPM mixed C3 into dead oil at various fixed pressures. After a certain period of mixing the GOR was evaluated 3 times to establish consistency. If the GOR did not change with time then the live oil mixture was allowed to flow through a loop (with known diameter and length), where the pressure drop was measured. The live oil viscosity was then calculated through the Hagen-Poiseuille’s equation.

The results from the solubility test with C3 at 15°C are shown in Table 12: Results from Solubility Test (TIPM). From GOR values, the mass% and vol% of C3 was calculated.

P (kPaa) GOR mass % vol% C3 visc (cP)343 30 5.235 10.020 650000653 72 11.707 21.090 8400750 144 20.959 34.834 475940 188 25.717 41.102 444

Table 12: Results from Solubility Test (TIPM)

The results at 940 kPaa were unexpected. Since the GOR was higher it was expected that the magnitude of viscosity reduction would be greater. The live oil was further mixed at this



48

condition and its live oil viscosity was re-measured to be 473 cP. The value reported in the table is an average of all values measured at this pressure.

It is possible that at this condition asphaltene was starting to precipitate, thus the degree of viscosity reduction was only marginal.

5.1.2.23 Asphaltene Precipitation Study Dr. Moore’s laboratory at the University of Calgary was investigating asphaltene precipitation in mixtures of C3 and Grosmont bitumen. The oil produced from the 2nd cycle (2008) was shipped to the lab and was cleaned. The dead oil viscosity was then evaluated and found to be about 8 million cP (at 15°C). It should be noted that this dead oil viscosity was significantly lower than the dead oil viscosity measured by TIPM and AGAT. The dead oil used in the solubility study (by TIPM) and the asphaltene precipitation study (by Dr. Moore’s laboratory) was the oil produced from the 2nd cycle.

Asphaltene fraction was evaluated by adding a certain amount of pentane. The asphaltene of dead oil was evaluated first as a benchmark. A fixed amount of C3 was then mixed with bitumen. A live oil sample was then extracted and its viscosity is measured via a Cambridge viscometer. The live oil was then allowed to flow through a filter to investigate asphaltene precipitation. The live oil that was collected on the other side of the filter was then collected and its asphaltene content was measured. The material collected on the filter was also measured for asphaltene content. For the live oil that had flown through the filter, if its asphaltene content was similar to that of the dead oil then it could be concluded that no incremental asphaltene was formed due to C3 addition. However, if it reduced and there were materials collected in the filter, it could indicate that extra asphaltene must have formed due to C3. Figure 32: Asphaltene Precipitation at 10°C and Figure 33: Asphaltene Precipitation at 50°C shows the asphaltene content for various concentration of C3 at 10°C and 50°C, respectively.



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10°C

0

5

10

15

20

25

30

0 10 20 30 4

C3 mass %

Asph

alte

ne c

onte

nt (m

ass%

)

0

products collected after filter products collected from filter

Figure 32: Asphaltene Precipitation at 10°C

50°C

0

5

10

15

20

25

30

0 10 20 30 4

C3 mass %

Asp

halte

ne c

onte

nt (m

ass%

)

0

products collected after filter products collected from filter

Figure 33: Asphaltene Precipitation at 50°C

From the asphaltene precipitation tests at 10°C it was found that additional asphaltene was formed when mass percent reaches 27 (g C3/ g bitumen mixture). The test at 50°C showed incremental asphaltene precipitation at approximately 25 mass percent. It was not clear whether



50

the reduction in mass percent was a direct result of the higher temperature since the difference in mass percent was not significant. Regardless, it was safe to conclude that further asphaltene precipitation could be expected when mass percent of C3 exceeds 25%. Incidentally, this weight percent was reached when TIPM mixed C3 with bitumen at 940kPaa.

5.1.2.24 Comparison of results from both labs After the generation of live oil (with a fixed amount of C3 dissolved), Dr. Moore’s group also measured viscosity for a range of temperatures. The results are shown in Figure 34: Viscosity vs. Temperature.

1

10

100

1000

10000

100000

0 10 20 30 40 50 60

Temperature (°C)

Visc

osity

(cP)

10m%15m%20m%24m%

Figure 34: Viscosity vs. Temperature

The data from this figure was interpolated to 15°C in order to allow for a direct comparison with results obtained by TIPM. The interpolated results are shown in Table 13: Results from Dr. Moore's Group.



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mass % vol% C3 visc (cP)10 18.231 9257.2515 26.167 168920 33.439 517.624 38.809 240.9

Table 13: Results from Dr. Moore's Group

The results from both labs are compared in Figure 35: Viscosity Comparison.

100

1000

10000

100000

1000000

0 5 10 15 20 25 30

Mass %

Vis

cosi

ty (c

P)

TIPM Dr. Moore's Lab

Figure 35: Viscosity Comparison

Both labs produced comparable results, however Dr. Moore’s results were slightly lower in live oil viscosity (at similar mass %). This could be due to the fact that TIPM worked with higher viscosity dead oil.



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5.1.3 Reservoir Data - Solvent Test The stimulation interval was the 10m within the Grosmont C. Th interval is a fractured vuggy dolomite with up to 35% porosity (based on neutron-density log reading of neighbouring well at 370m). Due to the brecciated nature of the core it was difficult to obtain an accurate permeability but it is thought to exceed 10 Darcies in the high porosity zones. Porosity and permeability is quite variable due to the huge range in the degree of leaching that has created the cavernous, vuggy and fracture meso and mega porosity. It also is responsible for the pinpoint vug and intercrystalline meso and microporosity. The oil saturation in the test zone was estimated to be approximately 90% based on core oil saturations. This was supported by the off-scale (>2000 ohm-m) log resistivity. This data supported the belief that the Grosmont is oil (bitumen) wet rather than water-wet.

The bottom seal to the Grosmont C porosity is the basal Grosmont C argillaceous dolomitic unit. It is the interval from 382.0-395.0m at the 7-26-85-19W4M well. The marl at the top of the Grosmont C (359.5-361.0m) is an interlaminated siliciclastic shale and porous dolomite mud. It could have acted as a barrier to fluid flow between the Grosmont C and D if natural fracturing of the marl did not create good vertical permeability.

There is no direct top or bottom water. The bitumen/water contact is down dip to the southwest. There is no direct gas cap at the proposed pilot site. A Grosmont D gas pool is present northeast of the Laricina Saleski land block (Saleski Grosmont ‘A’ Gas Pool) in Township 86 Ranges 18 and 19W4M and has a gas/water contact is at approximately +270m Sea Level. There is no known gas pool in the Grosmont C within 10 km of the proposed cold solvent injection test.

Formation pressure of 1,400 kPaa was anticipated at the top of the Grosmont ‘C’ zone. Samples obtained in the 2006-2007 drilling program indicated 8° API oil. The solution GOR was estimated to range from 2 to 4m3/m3.



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6.0 Solvent Injection and Well Economics 6.1 Capital Costs – Field Work

6.1.1 Saleski Cross Well Seismic Capital Expenses Table 14: Saleski Cross Well Seismic Costs outlines the capital expenses for the Winter 2008 and the 3D seismic data for baseline data for the Pilot (2.5 by 2.5km) & interpretation presentation.

Life-To-DateCAPITAL EXPENSES

STUDIES 95,800.00SERVICE RIG CONTRACTOR 7,162.00FUEL 476.63

CAPITAL EXPENSES Totals: 121,428.11Table 14: Saleski Cross Well Seismic Costs



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6.1.2 Observation Well Capital Expenses Table 15: Observation Well C outlines the capital expenses for the drilling of 4 observation wells, of which 3 were cased and completed and 1 was cored. These wells are needed for the drilling of horizontal wells and pilot.


ROAD & LEASE CONSTRUCTION/ MAINTENANCE 46,624.00SURVEYING / SCOUTING 5,176.75SURFACE LAND SERVICES 256.19RECOVERABLE DOWNHOLE EQUIPMENT 15,834.00UNRECOVERABLE DOWNHOLE EQUIPMENT 231,030.00DRILL BITS 63,534.50RIG LABOUR & CREW TRAVEL 70,045.54DRILLING RIG CONTRACTOR 1,349,458.63WATER TRUCK 103,057.52CORING & ANALYSIS 69,799.28MUD, CHEMICALS AND SUPERVISION 79,960.13FUEL 253,392.25POWER TONGS 15,742.50ENVIRONMENTAL SUPERVISION 25,125.91EQUIPMENT RENTALS 104,957.28WELLSITE TRAILER 700.29CASING & ACCESSORIES 363,997.37CONDUCTOR HOLE 23,130.00CEMENTING 512,106.41WELL HEAD CASING BOWL 9,519.71WELL TESTING/ PRODUCTION TEST 1,865.00FISHING 211,094.56LINER, HANGER & WIRE WRAP CASING 24,840.00LOGGING & PERFORATING 285,731.67WASTE DISPOSAL 9,111.02VACUUM TRUCK 121,231.96TRUCKING 109,113.72RIG MOB/ DEMOB 234,907.46INSPECTION & REPAIR SERVICES 20,300.54SUPERVISION/ CONSULTANTS/ TRAVEL/ AUTO 164,823.07CAMP COSTS 495,161.23COMMUNICATION 55,754.40HEALTH/ SAFETY & SECURITY 43,067.21ENGINEERING/ DESIGN & DRAFTING 13,415.00MISC CORE HOLE PRGM/ DRILLING/ COMPLETIONS 1,520.72OVERHEAD 21,141.54

CAPITAL EXPENSES Totals: 5,156,527.36Table 15: Observation Well Capital Expenses



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6.1.3 Horizontal Well Capital Expenses Table 16: Horizontal Well Capital Expenses outlines the capital expenses for the drilling and completion of 1.5 horizontal wells (1 in Grosmont D and Grosmont C).


ROAD & LEASE CONSTRUCTION/ MAINTENANCE 19,660.00RECOVERABLE DOWNHOLE EQUIPMENT 23,353.02DRILL BITS 98,157.50DIRECTIONAL DRILLING SERVICES 650,511.20RIG LABOUR & CREW TRAVEL 41,393.77DRILLING RIG CONTRACTOR 947,731.16WATER TRUCK 78,346.22MUD, CHEMICALS AND SUPERVISION 342,238.64FUEL 108,997.16EQUIPMENT OPERATION & MAINTENANCE 62,788.82POWER TONGS 20,874.00REGULATORY/ STAKEHOLDER 40.00EQUIPMENT RENTALS 322,874.20WELLSITE TRAILER 19,505.00CASING & ACCESSORIES 379,302.30CEMENTING 121,701.57WELL HEAD CASING BOWL 11,036.60WELL TESTING/ PRODUCTION TEST 2,040.00LINER, HANGER & WIRE WRAP CASING 276,940.80WASTE DISPOSAL 1,803.00VACUUM TRUCK 97,946.66TRUCKING 402,738.94RIG MOB/ DEMOB 143,901.00INSPECTION & REPAIR SERVICES 44,261.57SUPERVISION/ CONSULTANTS/ TRAVEL/ AUTO 155,572.52COMMUNICATION 50,739.90HEALTH/ SAFETY & SECURITY 36,980.00ENGINEERING/ DESIGN & DRAFTING 4,777.77INSURANCE 48,032.00MISC CORE HOLE PRGM/ DRILLING/ COMPLETIONS 427.36OVERHEAD 18,658.69

CAPITAL EXPENSES Totals: 4,533,331.37Table 16: Horizontal Well Capital Expenses



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6.2 Capital Costs - Grosmont Studies Table 17: Observation Well Capital Expenses outlines the capital expenses for the Grosmont Studies conducted.


Grosmont PIA Study 9,198.00Grosmont Core Tomography Study 22,755.00Steam Soak Grosmont D Test 139,336.14Grosmont Fluid Analysis 32,137.00Grosmont Petrophysical Study 30,720.00Full Well CT Scan - 11-15 61,235.00ARC Geochemistry Study 5,000.00GUSHOR Geochemical Characterization 0.00Grosmont Steam Rise Study 51,976.00Capillary Pressure Study 0.00Relative Permeability Study 0.00Steam Soak Grosmont C test 102,840.00Wettability Study 0.00Ireton Steaming Study 103,656.00GUSHOR Bitumen Profiling Study 55,350.00Full Well CT Scan - 8-27 46,837.46Cross-well Seismic 0.00End-point saturation study 67,076.00Rock Fluid study 0.00

CAPITAL EXPENSES Totals: 728,116.60Table 17: Observation Well Capital Expenses

6.3 Capital Costs - Cold Solvent Tests and Studies Table 18: Cold Solvent Tests and Studies Capital Expenses outlines the capital expenses for the Cold Solvent related tests and studies.


CO2 Solubility Study 131,190.50Solvent Soak Test 91,970.66Solvent Solubility Study 17,252.97Asphaltene Precipitation Study 22,000.00

CAPITAL EXPENSES Totals: 262,414.13

Table 18: Cold Solvent Tests and Studies Capital Expenses



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6.4 Capital Costs - Cold Solvent Field Tests Table 19: 2008 First and Second Cold Solvent Injection outlines the capital expenses for the drilling, completion and testing operations for the 2008 first and second solvent injection cycles.

CAPITAL EXPENSES EXP & DEV- CORE HOLE PRGM/ DRILLING/ COMPLETIONS Life-To-Date

ROAD & LEASE CONSTRUCTION/ MAINTENANCE 30,735.50SURVEYING / SCOUTING 2,319.40SURFACE LAND SERVICES 2,250.00RECOVERABLE DOWNHOLE EQUIPMENT 25,281.60UNRECOVERABLE DOWNHOLE EQUIPMENT 99,217.18DRILL BITS 11,950.00RIG LABOUR & CREW TRAVEL 17,318.54SERVICE RIG CONTRACTOR 27,640.00DRILLING RIG CONTRACTOR 273,728.64WATER TRUCK 35,915.62GAS & FLUID ANALYSIS 33,309.00CORING & ANALYSIS 118,064.65MUD, CHEMICALS AND SUPERVISION 108,885.83LUBRICANTS & FLUIDS 22,766.50FUEL 28,394.20POWER TONGS 9,555.00ENVIRONMENTAL SUPERVISION 5,574.12REGULATORY/ STAKEHOLDER 256.00EQUIPMENT RENTALS 74,352.43WELLSITE TRAILER 175.08CASING & ACCESSORIES 58,507.20CEMENTING 65,555.00WELL HEAD CASING BOWL 37,273.76WELL TESTING/ PRODUCTION TEST 359,625.48WELL TREATMENT & STIMULATION 391,753.88LOGGING & PERFORATING 24,722.85WASTE DISPOSAL 28,303.52VACUUM TRUCK 29,536.60TRUCKING 100,711.09RIG MOB/ DEMOB 55,454.99INSPECTION & REPAIR SERVICES 14,704.76SUPERVISION/ CONSULTANTS/ TRAVEL/ AUTO 81,398.96WELL LICENCE & SURFACE LEASE 595.00CAMP COSTS 103,158.59COMMUNICATION 20,740.98HEALTH/ SAFETY & SECURITY 20,680.91ENGINEERING/ DESIGN & DRAFTING 4,430.00MISC CORE HOLE PRGM/ DRILLING/ COMPLETIONS 380.20OVERHEAD 11,442.27

EXP & DEV- CORE HOLE PRGM/ DRILLING/ COMPLETIONS Totals: 2,336,665.33



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FAC ENGINEERING & DEV-GATHER SYSTEM/ PRDN FACILITY MECHANICAL EQUIPMENT 81,817.56INSTRUMENTATION & CONTROL EQUIPMENT 671.62ENGINEERING/ DESIGN & DRAFTING 29,759.04SUPERVISION/ CONSULTANTS/ TRAVEL/ AUTO 1,916.57

FAC ENGINEERING & DEV-GATHER SYSTEM/ PRDN FACILITY Totals: 114,164.79

CAPITAL EXPENSES Totals: 2,450,830.12Table 19: 2008 First and Second Cold Solvent Injection Capital Expenses Table 20: 2009 Third Cycle Cold Solvent Injection Capital Expenses outlines the capital expenses for the testing operations for the 2009 third solvent injection cycle.

EXP & DEV- CORE HOLE PRGM/ DRILLING/ COMPLETIONS Life-To-Date ROAD & LEASE CONSTRUCTION/ MAINTENANCE 6,538.00GARBAGE DISPOSAL 2,859.14RECOVERABLE DOWNHOLE EQUIPMENT 138,787.13CAMP MOB/ DEMOB 5,436.15SERVICE RIG CONTRACTOR 40,199.55POTABLE WATER 16,292.10LUBRICANTS & FLUIDS 782,303.11FUEL 17,364.10CAMP FUEL 22,546.75EQUIPMENT OPERATION & MAINTENANCE 2,980.00REGULATORY/ STAKEHOLDER 7,272.75EQUIPMENT RENTALS 16,190.50WELLSITE TRAILER 12,552.66WELL HEAD CASING BOWL 4,759.00WELL TESTING/ PRODUCTION TEST 399,972.46WELL TREATMENT & STIMULATION 942.92LOGGING & PERFORATING 17,674.92WASTE DISPOSAL 47,395.21VACUUM TRUCK 8,377.55TRUCKING 81,605.17HOTSHOT 7,050.00INSPECTION & REPAIR SERVICES 18,855.26SUPERVISION/ CONSULTANTS/ TRAVEL/ AUTO 209,248.51CAMP COSTS 342,987.70CAMP SEWAGE 35,347.47COMMUNICATION 19,460.20HEALTH/ SAFETY & SECURITY 195,044.07OVERHEAD 14,861.02

EXP & DEV- CORE HOLE PRGM/ DRILLING/ COMPLETIONS Totals: 1,105,211.62 FAC ENGINEERING & DEV-GATHER SYSTEM/ PRDN FACILITY

CONTRACTORS 107,588.45INSTRUMENTATION & CONTROL EQUIPMENT 223,105.82ELECTRICAL EQUIPMENT 26,280.46



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EQUIPMENT RENTALS 35,803.50ANALYZERS & LABORATORY EQUIPMENT 190,106.96TOOLS, EQUIPMENT & MACHINERY 267.00ENVIRONMENTAL & REMEDIAL 2,221.47ENGINEERING/ DESIGN & DRAFTING 11,233.12SUPERVISION/ CONSULTANTS/ TRAVEL/ AUTO 51,819.31MISC GATHERING SYSTEM & PRODUCTION FACILITY 456,785.53

FAC ENGINEERING & DEV-GATHER SYSTEM/ PRDN FACILITY Totals: 2,474,903.40

CAPITAL EXPENSES Totals: 3,580,115.02Table 20: 2009 Third Cycle Cold Solvent Injection Capital Expenses

6.5 Cumulative Project Costs The cumulative project costs are $16.8MM.

Phase 1 Forecast ActualItem Notes 2007-2008 Notes 2007-2008Core evaluation Lab testing, studies and simulations 1.0 Numerous Studies 1.03D seismic 1 section 0.2 3D 1 section 0.1Core holes 6 core holes (3 to be converted to OBS wells) 6.0 Drilled 4, Complted 2 obs wells 5.2Pad preparation Gravel, grating and levelling 0.3 na1 Horizontal well pair 1 well in C; 1 well in D 4.0 Completed 1D and intermed for C 4.5Solvent cold solvent injection 2.0 2 tests 6.0

13.5 16.84.3 5.1Requested IETP funding

Total ($MM)

6.6 Material Deviations from Budgeted Costs The horizontal well pair cost $4.5MM versus the forecasted $4.0MM. Loss circulation, sloughing formations, and hole cleaning difficulties resulted in more time spent on the well than originally anticipated.

The actual cost for the first year of solvent injection was $2.5 MM versus the forecasted $2.0 MM. An unplanned second injection cycle was initiated (starting on March 8 and finishing March 15, 2008) due to quick oil production decline after the first injection. Another 30 tonnes of C3 and 2.5 tonnes of N2 were injected. The oil production was improved and stable for the majority of the production period.

A third injection cycle was planned for the following year (2009). The third cycle was proposed in order to provide clean data to compare with/adjust simulator predictions:

• injection rates, compositions (improved sampling) • bottomhole & piezometer pressures and temperatures (real time) • oil rate (constrained to a nominal GOR)

• C3 content in oil.



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The third injection was a much larger scale operation than the first and second to provide longer-term reservoir characterization via injectivity/piezo interface/falloff (horizontal & vertical permeability vs. compressibility). The data collected was used for the pilot design. The final cost of the operation was $3.8 MM.

7.0 Facilities 7.1 2008 Incurred Major Capital Items Table 21: Third Cycle Cold Solvent Injection Incurred Capital Items summarizes the equipment that was purchased for the 2009 Third Cycle Cold Solvent Injection. The equipment is currently stored at the Laricina Germain Campsite in a seacan container.

Equipment Vendor Total-Amount 23000 L of Triethylene Glycol DIV GLY SER INC 60,276.00 4 L Sample Cylinders PRO SYS INC 20,656.00 Actuator for ESD MID SUP ULC 1,125.00 Additional PIT's CB ENG LTD 2,120.00 Additional PIT's CB ENG LTD 5,129.00 Air Compressor Install WAB HOM HAR 28.98 Air Compressor Install WAB HOM HAR 410.57 Air Compressor, Varsol etc. DANIEL LASTIWKA 4,859.94 Bitumen Skid Structural Steel MID SUP ULC 6,086.55 Misc. Parts WEA CAN PAR 615.04 Misc. Parts WEA CAN PAR 1,287.64 Misc. Parts WEA CAN PAR 1,397.64 Cable THE CAT REN STO 698.12 Datalogger PET ENG LTD 14,000.00 Gas Detectors PRO SYS INC 6,585.00 Gas Flow Meter and DPT's CB ENG LTD 2,444.00 Gas Flow Meter and DPT's CB ENG LTD 24,729.39 Heat Tracing CAN SUB-SUR ENE 7,000.00 Heat Tracing CAN SUB-SUR ENE 21,291.85 Heat Tracing DRE COR 12,302.00 Instrumentation GRI ELE & INS 3,105.00 Instrumentation GRI ELE & INS 3,704.07 Instrumentation GRI ELE & INS 3,782.00 Instrumentation GRI ELE & INS 11,349.81 Mass Meter MIC CON DEV LTD 11,288.00 Meter Skid Costs MID SUP ULC 5,656.91 Pipe Fittings APE DIS INC 18.53 Pipine and Fabrication EOS PIP & FAC 87.25 Pipine and Fabrication EOS PIP & FAC 275.25 Pipine and Fabrication EOS PIP & FAC 785.00 Pipine and Fabrication EOS PIP & FAC 2,328.73 Pipine and Fabrication EOS PIP & FAC 2,720.00 Pipine and Fabrication EOS PIP & FAC 2,930.00



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Pipine and Fabrication EOS PIP & FAC 4,479.00 Pipine and Fabrication EOS PIP & FAC 4,735.00 Pipine and Fabrication EOS PIP & FAC 5,440.00 Pipine and Fabrication EOS PIP & FAC 5,725.00 Pipine and Fabrication EOS PIP & FAC 6,500.00 Pipine and Fabrication EOS PIP & FAC 7,983.20 Pipine and Fabrication EOS PIP & FAC 8,660.00 Pipine and Fabrication EOS PIP & FAC 8,830.00 Pipine and Fabrication EOS PIP & FAC 9,581.60 Pipine and Fabrication EOS PIP & FAC 11,630.00 Pipine and Fabrication EOS PIP & FAC 750.00 Pipine and Fabrication EOS PIP & FAC 2,175.00 Propane and Bitumen Skid Piping MID SUP ULC 10,769.65 Propane Pumps and Dampners PLA GRO INT INC 68,460.00 Propane Skid Repair MID SUP ULC 4,295.96 Propane Skid Structural Steel MID SUP ULC 8,017.25 Propane Turbine Meter ROBIN WICENTOVI 3,200.00 PSVs SPA CON LTD 471.06 PSVs SPA CON LTD 1,311.44 Seacan ROBIN WICENTOVI 3,500.00 Steel Drum GRE WES CON 501.96 Suction/Discharge Valves NAT PRO EQU 2,232.70 Tank BEN REN 45,590.00 Thermostats DANIEL LASTIWKA 2,980.00 Thermostats ROBIN WICENTOVI 5,960.00 VFD for Propane Pump WES DIS CAN LP 8,867.00 Windsocks APE DIS INC 387.56

Total: 484,106.65

Table 21: Third Cycle Cold Solvent Injection Incurred Capital Items

7.2 Capacity Limitation and Equipment Integrity Capacity and Equipment Integrity outlined on PFD drawings. Attached is a PFD drawing for both cold solvent programs.

7.3 Process Flow and Site Diagram Process Flow and Site Diagrams are attached for both cold solvent programs.



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8.0 Environment/Regulatory/Compliance 8.1 Project Regulatory Requirements and Compliance Status Application No. 1547911 Laricina Energy Ltd. Saleski Non-thermal Stimulation Well Test was submitted November 12, 2007. Approval No. 11112 in was received on January 18, 2008.

Application No. 1585811 Extension to Experimental Scheme Approval 11112 Saleski Non-thermal Stimulation Well Test (by 18 months in order to perform additional cold solvent cyclic operations) was submitted September 3, 2008. Approval No. 11112A was received January 5, 2009.

Application No. 1574946 and Application 001-245592 Laricina Energy Ltd. Saleski SAGD Pilot Project was submitted to the ERCB and Alberta Environment (AENV), respectively, in December 2007. Approval No. 11337 from the ERCB was received June 17, 2009 and Approval No. 245592-00-00 from AENV was received July 22, 2009.

8.2 Environmental and Safety Procedures

8.2.1 Environmental Management

Laricina has developed an Environmental Policy which affirms our commitment to environmental preservation and protection. The Laricina Energy Ltd. Corporate Environmental Policies and Procedures Manual puts Laricina’s policy into practice and establishes Laricina’s commitment to environmental stewardship.

Laricina has a continued commitment to involve and train company personnel in the environmental aspects of our operations. It is our policy that the company’s employees and contractors will take every reasonable measure to protect the environment in all facets of our activities from planning through to final abandonment of facilities and wellsites. We also strive to meet or exceed all regulatory requirements as they pertain to environmental protection.

Laricina’s IMS Global HSE Management System plan begins with Leadership, Policy, and Communication Goals, along with the necessary Legal Requirements and Operating Standards as the drivers of the System. Controls are in place for all hazards and effects and environmental aspects are evaluated and managed in accordance with current regulatory requirements and industry standards. Asset/Integrity management tools ensure that all of our equipment is monitored and maintained as we plan our facility/production phase.

Social and Environmental data is entered into an on-line databases for on-going reporting capabilities and impact assessment (Consultation Manager).



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Laricina is committed to abide by all Industry Best Practices, industry standards, all regulatory and applicable legislation, and corporate policy (ERCB/AENV/CAPP/ASRD).

Laricina contracts several environmental companies to monitor such areas as vegetation, wildlife, waterways etc. on our leases and project areas to ensure we minimize our environmental impact.

Laricina. has an associate membership to the Spill Co-op (non-producer requires only associate membership) to manage spill response in an emergency. Laricina employees will be participating in the “Spill Response” training exercises. Online spill training is also made available for employee training. Laricina Energy Ltd. is also committed to providing and supporting further access to environmental and social awareness training for employees (Enform/Global Training Center/Fountainhead-Leadership Training).

Laricina had committed to the implementation of greater Environmental Management System and Environmental Committee to further assess and monitor Laricina’s goals, performance and education currently & prior to facilities & production.

Risk Reduction Plans are conducted on contractors prior to work being conducted to ensure their systems meet Laricina’s standards in Health, Safety & Environment. WCB & Insurance Documentation is also verified. Inspections of equipment & leases are also conducted on contractors active on Laricina locations.

8.2.2 Plan for Shut-down and Environmental Clean-up.

Laricina will take appropriate action in the prevention, limitation, or repair of environmental damage arising from its operations. Environmental repair or decontamination will comply with all applicable laws and will occur according to the following priorities:

• protection of public and employee health and safety; • mitigation of further environmental damage; • protection of public/private property; and • protection of company property.

During the abandonment of a facility or production site, Laricina. will ensure that the quality of soil, water, and vegetation will meet regulatory health, safety, and environmental standards. To improve the success of reclamation and to minimize overall environmental impact at the site Laricina will endeavour to incorporate prudent reclamation pre-planning practices that include the use of sound vegetation and soil management procedures. To this end, Laricina will,



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whenever possible, endeavour to reduce working areas at facilities and wellsites as much, and as soon as practical.

The basic methodology that Laricina will use when decommissioning a facility is as follows:

1. Develop a decommissioning plan in conjunction with the landowner and/or applicable regulatory agencies. Depending on future land use and certain site specific factors (i.e. surrounding land use, the nature and mobility of contaminants on site, available pathways/transport modes, proximity to receptors, etc.) certain “Risk Management” strategies may be adopted in order to reduce the amount of reclamation work necessary.

2. Survey and establish reference points prior to the removal of equipment and buildings so that areas of interest (i.e. contamination hot spots) associated with those structures (i.e. treater buildings, storage tanks, pig traps, etc.) can be located after the buildings and equipment have been removed. Non-intrusive geophysical methods may be used to locate and map contaminated areas prior to or after the removal of buildings and equipment.

3. Remove all aboveground and belowground structures.

4. Conduct a preliminary intrusive sampling program.

5. Remove, treat, and/or dispose of all contaminated materials to attain clean-up criteria.

6. Ensure any structures remaining on site are safe for humans and animals.

7. Monitor any contaminant containment control or treatment systems remaining onsite.

8. Remediate any pits or mounds to original contour.

9. Clean up the site to a level that is acceptable for the intended land use.

10. Any contaminants, wastes, or structures that restrict future land use and/or that require periodic monitoring to ensure continued integrity should be registered on the property title.

11. Submit a report to the regulatory agencies confirming that decommissioning and clean up have been completed. Applications for reclamation certificates may also be submitted to AENV at this time.

8.2.3 Site Management Site preparation provided adequate drainage away from storage tanks, equipment, skids, and buildings. Site preparation activities included the following:



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• cleared the site by removing trees and plant roots;

• contoured the site to ensure proper site drainage;

• where required and deemed appropriate remove unsuitable or excess material including muskeg;

• apply (where necessary) appropriate sub-base material and compact bases for facilities complete with geotextile as required; and

• ensure appropriate (where necessary) secondary containment around facilities complete with geotextile as required.

All storage tanks, except boiler feed water and source water tanks, will be equipped with secondary containment and leak detection to minimize the occurrence of product leaks and subsequent contamination to the environment.

All well pads and roads will be constructed in a manner in which erosion from surface water runoff will be minimized. This will be achieved utilizing appropriate collection areas and flow barriers where necessary. Ditches will be designed to avoid ponding of water along the road surface.

8.2.4 Health and Safety Standard Operating Procedures

Laricina’s Health and Safety Manual reflects the latest interpretation of the federal, provincial, and municipal regulations, codes and industry accepted practices. Laricina’s Standard Operating Procedures are detailed in the Health and Safety manual and include the following:

• Building Entry

• Exemption Standard

• Management of Change Program

• Right to Refuse Unsafe Work

• Sour Lease Entry

• Standards of Business Conduct Policy

• Substance Abuse

• Workers’ Compensation Board

• Working Alone



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Laricina’s Health and Safety Manual will be provided upon request.

8.2.5 Emergency Response Plans Laricina’s Corporate Emergency Response Plan (CERP) has been developed to facilitate an effective response by Laricina operations, management and support personnel to an emergency occurrence affecting the company. To ensure a state of emergency preparedness throughout the company, Laricina has developed these emergency procedures to protect the public, employees, contract employees, property and the environment.

With the development of the Corporate Emergency Response Plan, the Laricina is prepared to:

• ensure immediate competent responses to, and handling of an emergency occurrence;

• minimize danger to the public, employees, contractors and environment;

• establish and maintain effective communications with all parties in an emergency; and

• make maximum use of the combined resources of Laricina Energy Ltd., Government agencies and other services.

In the event of a spill, soil sampling programs and water sampling programs will be initiated and site assessments will be completed.

Laricina is in the process of implementing an upgraded Corporate HS&E Management system and is working further to updating the ERP to be site specific. These plans will be in place and submitted prior to the commencement of construction of the Saleski Project.

Laricina has received the CAPP Silver designation for ERP, Health and Safety for 2007.



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9.0 Future Operating Plan 9.1 Project Schedule

Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4SC-SAGD Pilot 1st Well Development

FacilitiesEngineering FEEDCentral Processing Facility ConstructionPad/lateral ConstructionPipeline (WS/WD) Construction

Drilling & CompletionsHorizontalsWater Source/Disposal

InfrastructureRoad (Saleski portion) - baseRoad (Saleski portion) - rework & finalGas Supply

CommissioningSaleski Start 1st WP

SC-SAGD Pilot 2nd WellSaleski Start 2nd WP

Detailed

201220112009 2010

Figure 36: Project Schedule

9.2 Pilot Operation Changes The Saleski SAGD Pilot Project was originally planned as a thermal process, where steam will be used to heat up the formation, thereby reducing the bitumen’s viscosity and thus enabling it to flow. In comparison to solvent based recovery method, SAGD has an advantage of high production rate, however, it consumes a significantly amount of energy and has costly post-production water treatment. These drawbacks provided incentives for the industry to develop new processes to improve the energy efficiency of SAGD. One of these new processes is SC-SAGD, where steam and solvent are co-injected to improve oil production rates and lower the steam consumption. From internal studies, where the process was studied through extensive simulation, it was seen that the SAGD process will be as effective, if not more effective, with the addition of solvents. As demonstrated by the cold solvent tests, solvents can significantly reduce the oil viscosity. With the addition of solvent along with steam injection, solvent will travels ahead the steam front, where the temperature is significantly lower than the stream temperature. This allows the solvent to reduce oil viscosity in regions of low temperature.

The addition of solvents will have a significant impact on the facility design, costs and most important of all, reducing the amount of water usage. On the facility side, this process has the potential to significantly reduce the cost due to the smaller equipment, insulation, pipe designs, and the obvious reduction in the water treatment costs. On the environmental aspects, lower



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energy consumption will definitely lead to lower CO2 emissions. In addition, lower water usage will definitely lower the extent of water use.

9.3 Salvage Update Laricina will ensure that environmental impacts are kept to a minimum and end land use objectives and goals are attained.

9.3.1 Reclamation Monitoring Laricina will monitor results of the reclamation program in accordance with the requirements outlined in the EPEA operating approval.



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10.0 Interpretations and Conclusions 10.1 Difficulties Encountered and Recommendations

10.1.1 Cold Solvent – 3rd Cycle

The flare line was accumulating vapour liquids causing operational difficulties and environmental infractions. This issue was not anticipated during the design water production was expected to be near zero (as documented in the DBM). The flare system should incorporate a knock out drum with truck out connections. Water production with bitumen should be assumed for all future Saleski production wells.

10.1.2 Lost Circulation in the Carbonates

During the drilling of the cold solvent well large volumes of water were lost to the carbonate formations. In applications where solvent is being injected, there is the potential for hydrates to form. As such, drilling operations must try to minimize losses. With a 3.5MPa pressure limit at 400m, the maximum mud weight was calculated at 750kg/m3. An investigation into the options for a fluid of this density should be conducted so that drilling operations have insight into the options. Any light weight drilling fluid will have to possess good hole cleaning characteristics, and for extended reach horizontals in bitumen, possess anti-accretion properties.

This past season, a great deal was learned with respect to the nature of the losses in the carbonates. It seemed that the pressure at which fluids leak off was consistently around 3.5MPa in a bitumen saturated carbonate. This was consistent with the hydrostatic pressure (depth) at which there was a tendency to lose circulation. When drilling these formations, typically using a mud weight around 1000 – 1050 kg/m3, circulation is lost between 325m and 350m (in the Grosmont). At the mud weights listed above, 3.5MPa is reached between 340m and 355m (a potential correlation). 3.5MPa was also the number that the PWD sensor on the directional tools indicated was the maximum pressure at which the reservoir could hold a column of fluid, and was also consistent with the stable feed pressure on the cold solvent well injection.

10.1.3 Horizontal Well Drilling

When planning the logging on the initial carbonate horizontal wells, Laricina wanted to run the Azimuthal Deep Resistivity tool offered by Halliburton because it was believed that it would provide a good interpretation of the reservoir structure near wellbore. Unfortunately the technology was new and the tools were being piloted elsewhere in the world. As such, it was decided to run the Azimuthal Litho-Density tool instead. This tool was budgeted on both holes, but only one was TD’d before breakup. Halliburton is offering the trial of the Azimuthal



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Focused Resistivity tool that will give an interpretation of the structure of the wellbore wall. Laricina plans to look into the benefits of the information given by this tool as it may be used on future wells.

On the carbonate horizontals, there was no circulation for the majority of the lateral section. It was deemed unnecessarily expensive to drill the section with PolyTar (the emulsifying polymer). Instead the recommendation is to drill the intermediate section with floc water/water until bitumen contamination of fluid or shaker screen blinding occurs. If this does not occur, the recommendation is to continue to casing point/TD, blind (with no returns to surface). If additional hole cleaning is required, add viscosity with xanthan gum. On the first horizontal, a light viscosity was added but was likely unnecessary. If anti-accretion is required, add PolyTar. If there are losses do not add PolyTar.

10.2 Technical and economic viability

10.2.1 Cold Solvent

See section 9.2.

10.2.2 Horizontal Well Drilling

The drilling of the observation and horizontal wells enabled Laricina to determine that horizontal wells are technically and economically viable in the carbonate formations such as the Grosmont formation in Alberta. Laricina was able to assess the risks and challenges of drilling in the carbonates and has gained the experience necessary to drill the remaining SAGD wells approved for piloting.

10.3 Overall effect on overall bitumen recovery

See section 9.2.

10.4 Assessment of future expansion or commercial field application and discussion of reasons

See section 9.2.

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