East Tower, 5th Ave Place Suite 800, 425 1st Street SW Calgary, Alberta T2P 3L8 Tel: 403-750-0810 Fax: 403-263-0767 www.laricinaenergy.com Email: [email protected]

July 10, 2014

Martin Mader Alberta Energy Innovative Energy Technologies Program Research and Technology Branch 9th Floor Petroleum Plaza North 9945 - 108 Street Edmonton, Alberta T5K 2G6

Dear Mr. Mader:

Re: IETP - Approval 05-077 - Saleski Pilot Project Phase 2 Final Report 2013- Laricina Energy Ltd.

As required under the captioned project approval and intellectual property agreement please find the final project report for the 2013 calendar year. The report includes the technical report, the intellectual property form and the statutory declaration.

Sincerely, Laricina Energy Ltd.

Deepa Thomas, B.Sc. Director, Regulatory & Environmental Performance

Saleski Pilot Project Phase 2 FINAL REPORT

Alberta Department of Energy Innovative Energy Technology Program Approval 05-077

July 2014 Laricina Energy Ltd. Saleski Pilot Project IETP Approval 05-077 Final Report

TABLE OF CONTENTS

1.0 ABSTRACT ...... 1

2.0 SUMMARY PROJECT STATUS REPORT ...... 3

2.1 TEAM MEMBERS ...... 3 2.2 CHRONOLOGICAL ACTIVITIES AND OPERATIONS REPORT ...... 4 2.3 PRODUCTION, MATERIAL AND ENERGY BALANCE FLOW SHEETS ...... 11 2.4 RESERVE ESTIMATES ...... 13 3.0 WELL INFORMATION ...... 14

3.1 WELL LAYOUT ...... 14 3.2 DRILLING, COMPLETIONS, AND WORKOVER OPERATIONS ...... 15 3.3 WELL OPERATIONS ...... 19 3.3.1 Well List and Statuses ...... 19 3.3.2 Wellbore Schematics ...... 21 3.3.3 Spacing and Pattern...... 43 4.0 PRODUCTION PERFORMANCE AND DATA ...... 43

4.1 NEW PRODUCTION DATA ...... 43 4.1.1 Individual Well Injection and Production History ...... 43 4.1.2 Composition of Injected and Produced Fluids...... 54 4.2 SOLVENT INJECTION ...... 68 5.0 PILOT DATA ...... 68

5.1 LABORATORY STUDIES ...... 68 5.2 SIMULATIONS ...... 68 5.3 OBSERVATION WELL DATA ...... 68 5.4 INTERPRETATION ...... 71 5.4.1 1C Well Pair ...... 71 5.4.2 1D Well Pair ...... 73 5.4.3 2D Well Pair ...... 76 5.4.4 2C Well Pair ...... 78 6.0 PILOT ECONOMICS ...... 80

6.1 BITUMEN SALES VOLUMES ...... 80 6.2 REVENUE ...... 80 6.3 CAPITAL COSTS – FACILITIES ...... 81 6.4 CAPITAL COSTS – DRILLING & COMPLETIONS ...... 86 6.5 CAPITAL COSTS – REGULATORY ...... 86 6.6 CAPITAL COSTS – INFRASTRUCTURE ...... 87 6.7 OPERATING COSTS ...... 87 6.8 ROYALTIES ...... 88 6.9 CUMULATIVE PROJECT COSTS ...... 89 i Laricina Energy Ltd. Saleski Pilot Project IETP Approval 05-077 Final Report

6.10 MATERIAL DEVIATIONS FROM BUDGETED COSTS ...... 89 7.0 FACILITIES ...... 90

7.1 ADDITIONS AND MODIFICATIONS ...... 90 7.2 CAPACITY LIMITATIONS AND EQUIPMENT INTEGRITY ...... 90 7.3 SITE DIAGRAM ...... 90 8.0 ENVIRONMENTAL/REGULATORY/COMPLIANCE ...... 90

8.1 PROJECT REGULATORY REQUIREMENTS AND COMPLIANCE STATUS ...... 90 8.2 ENVIRONMENTAL AND SAFETY PROCEDURES ...... 91 8.2.1 Environmental Management ...... 91 8.2.1.1 Plan for Shut-down and Environmental Clean-up ...... 92 8.2.2 Site Management ...... 93 8.2.3 Health and Safety Standard Operating Procedures ...... 94 8.2.4 Emergency Response Plans ...... 94 9.0 FUTURE OPERATING PLANS ...... 95

9.1 PROJECT SCHEDULE ...... 95 9.2 CHANGES TO PILOT OPERATION ...... 95 9.3 SALVAGE UPDATE ...... 96 9.3.1 Site Management ...... 96 10.0 INTERPRETATIONS AND CONCLUSIONS ...... 96

10.1 LEARNING EXPERIENCE ...... 96 10.2 DIFFICULTIES ENCOUNTERED ...... 99 10.3 TECHNICAL AND ECONOMIC VIABILITY ...... 99 10.4 OVERALL EFFECT ON BITUMEN RECOVERY ...... 99 10.5 ASSESSMENT OF FUTURE EXPANSION AND COMMERCIAL FIELD APPLICATION ...... 100 11.0 APPENDIX ...... 101

PROCESS FLOW AND SITE DIAGRAMS ...... 102

INTELLECTUAL PROPERTY AGREEMENT DISCLOSURE FORM ...... 103

STATUTORY DECLARATION ...... 104

ii Laricina Energy Ltd. Saleski Pilot Project IETP Approval 05-077 Final Report

LIST OF FIGURES

Figure 1: Planar View of Well Layout ...... 14 Figure 2: Planar and Cross-Sectional Well Schematics ...... 15 Figure 3: LEL ET AL 101-I1C-HZ SALESKI 15-26-85-19 Wellbore Schematic ...... 23 Figure 4: LEL ET AL 101-I1D-HZ SALESKI 15-26-85-19 Wellbore Schematic ...... 24 Figure 5: LEL ET AL 101-I2D-HZ SALESKI 15-26-85-19 Wellbore Schematic ...... 25 Figure 6: LEL ET AL 101-I2C-HZ SALESKI 10-26-85-19 Wellbore Schematic ...... 26 Figure 7: LEL ET AL 101-P1C-HZ SALESKI 15-26-85-19 Wellbore Schematic...... 27 Figure 8: LEL ET AL 101-P1C-HZ SALESKI 10-26-85-19 (P1C Re-entry) Wellbore Schematic ...... 28 Figure 9: LEL ET AL 101-P1D-HZ SALESKI 15-26-85-19 Wellbore Schematic ...... 29 Figure 10: LEL ET AL 101-P2D-HZ SALESKI 15-26-85-19 Wellbore Schematic ...... 30 Figure 11: LEL ET AL 101-P2C-HZ SALESKI 15-26-85-19 Wellbore Schematic...... 31 Figure 12: LEL ET AL P1 OBS1 SALESKI 7-26-85-19 Wellbore Schematic ...... 32 Figure 13: LEL ET AL P2 OBS1 SALESKI 7-26-85-19 Wellbore Schematic ...... 33 Figure 14: LEL ET AL P1 OBS2 SALESKI 10-26-85-19 Wellbore Schematic ...... 34 Figure 15: LEL ET AL P1-2 OBS2 SALESKI 10-26-85-19 Wellbore Schematic ...... 35 Figure 16: LEL ET AL P2 OBS2 SALESKI 10-26-85-19 Wellbore Schematic ...... 36 Figure 17: LEL ET AL P1 OBS3 SALESKI 10-26-85-19 Wellbore Schematic ...... 37 Figure 18: LEL ET AL P2 OBS3 SALESKI 10-26-85-19 Wellbore Schematic ...... 38 Figure 19: Schematic of a Typical Saleski Water Source Well ...... 39 Figure 20: LEL ET AL 100 SALESKI 2-26-85-19 Wellbore Schematic ...... 40 Figure 21: LEL ET AL 100 SALESKI 5-23-85-20 Wellbore Schematic ...... 41 Figure 22: LEL ET AL 102 SALESKI 5-23-85-20 Wellbore Schematic ...... 42 Figure 23: Well Activities Summary for 2013 ...... 43 Figure 24: 1D Well Pair Injection and Production Rates ...... 46 Figure 25: 1D Well Pair Cumulative Production and Injection Volumes ...... 46 Figure 26: 1C Well Pair Injection and Production Rates ...... 48 Figure 27: 1C Well Pair Cumulative Production and Injection Volumes ...... 48 Figure 28: 2D Well Pair Injection and Production Rates ...... 50 Figure 29: 2D Well Pair Cumulative Production and Injection Volumes ...... 51 Figure 30: 2C Well Pair Injection and Production Rates ...... 52 Figure 31: 2C Well Pair Cumulative Production and Injection Volumes ...... 53 Figure 32: Total Production and Injection Rates from all Well Pairs...... 53 Figure 33: Total Cumulative Production and Injection Volumes from all Well Pairs ...... 54

iii Laricina Energy Ltd. Saleski Pilot Project IETP Approval 05-077 Final Report

Figure 34: Density of Bitumen ...... 55 Figure 35: Total Sulphur Content of Bitumen ...... 55 Figure 36: Bitumen Absolute Viscosity ...... 56 Figure 37: Produced Water Total Hardness ...... 57 Figure 38: Produced Water Chloride and Sodium Content ...... 57 Figure 39: Produced Water Salinity ...... 58 Figure 40: Produced Gas Content from Casing Gas Separator #1 ...... 59

Figure 41: Produced H2S Content from Casing Gas Separator #1 ...... 59 Figure 42: Produced Gas Content from Casing Gas Separator #2 ...... 60

Figure 43: Produced H2S Content from Casing Gas Separator #2 ...... 60 Figure 44: 1D Well Pair BHP Profile ...... 61 Figure 45: 1C Well Pair BHP Profile ...... 61 Figure 46: 2C Well Pair BHP Profile ...... 62 Figure 47: 2D Well Pair BHP Profile ...... 62 Figure 48: P1D Temperature Profile...... 64 Figure 49: P1C Temperature Profile ...... 65 Figure 50: P2C Temperature Profile ...... 66 Figure 51: I2D Temperature Profile ...... 67 Figure 52: P2D Temperature Profile...... 67 Figure 53: Observation Well Pressure Plots ...... 69 Figure 54: Observation Well Temperature Plots ...... 70 Figure 55: Production and Injection Rates for 1C Well Pair from Start-up to End of 2013 ...... 72 Figure 56: Production and Injection Rates for 1D Well Pair from Start-up to End of 2013 ...... 75 Figure 57: P1D Temperature Fibre (May –June Observation Period) ...... 76 Figure 58: Production and Injection Rates for 2D Well Pair from Start-up to End of 2013 ...... 77 Figure 59: Production and Injection Rates for 2C Well Pair from Start-up to End of 2013 ...... 79 Figure 60: Pilot Project Schedule ...... 95

iv Laricina Energy Ltd. Saleski Pilot Project IETP Approval 05-077 Final Report

LIST OF TABLES

Table 1: Saleski Pilot Project Team Members ...... 3 Table 2: Chronological List of all Activities and Operations Performed at the Saleski Pilot ...... 4 Table 3: Summary of 2013 Calendar Year Gross Balances ...... 11 Table 4: Monthly Boiler (OTSG) Related Values for the 2013 Calendar Year ...... 12 Table 5: Summary of all Produced Materials in 2013 ...... 13 Table 6: Summary of Workovers Associated with the 1D Well Pair ...... 15 Table 7: Summary of Workovers Associated with the 1C Well Pair ...... 16 Table 8: Summary of Workovers Associated with the 2D Well Pair ...... 17 Table 9: Summary of Workovers Associated with the 2C Well Pair ...... 18 Table 10: Well List and Statuses ...... 20 Table 11: Production Performance Indicators for 1C well pair ...... 71 Table 12: Production Performance Indicators for 1D Well Pair...... 75 Table 13: Production Performance Indicators for 1D Well Pair Cycle 4 Mini-Cycles ...... 75 Table 14: Production Performance Indicators for 2D Well Pair...... 77 Table 15: Production Performance Indicators for 2C Well Pair ...... 79 Table 16: Gross Production and Sales volumes for 2013 ...... 80 Table 17: Revenue - Bitumen Sales for 2013 ...... 80 Table 18: Summary of the Pilot Facility Costs ($) ...... 81 .Table 19: Detailed Costs of the Pilot Equipment ($) ...... 81 Table 20: Detailed Costs of the Pilot Fabrication and Construction ...... 83 Table 21: Costs of the Saleski Water Source and Disposal Pipelines ...... 84 Table 22: Detailed Costs of the Saleski Pilot Commissioning ...... 85 Table 23: Detailed Costs of the Pilot Regulatory ...... 87 Table 24: Detailed Costs - Pilot Infrastructure ...... 87 Table 25: Operating Costs for Saleski Pilot in 2010-2013 ...... 88 Table 26: Royalties Paid from Pilot in 2013 ...... 88 Table 27: Cumulative Project Cost Summary ...... 89 Table 28: AER Amendment Approvals ...... 90

v Laricina Energy Ltd. Saleski Pilot Project IETP Approval 05-077 Final Report

1.0 ABSTRACT Laricina Energy Ltd.’s (Laricina) Saleski Pilot Project (Pilot) is currently operating within the Athabasca Grosmont Formation to evaluate the commercial potential of thermal recovery within a karsted carbonate reservoir. While steam assisted gravity drainage (SAGD) has been demonstrated as a successful exploitation strategy within the McMurray clastics, the application of SAGD within a carbonate environment presents different challenges. A review of previous vertical well Cyclic Steam Stimulation (CSS) performance from the Union Oil Company Buffalo Creek Pilot, dating from the early 1980s, indicated that horizontal SAGD wells may prove to be an effective recovery process within the Grosmont Formation. Additionally, carbonate core analyses and lab testing undertaken by Laricina further validated SAGD as an effective recovery process within the Grosmont Formation.

The highly bitumen saturated Grosmont Formation consists of 50 m of pay at the Pilot and is a complex reservoir framework subdivided into the Grosmont C and D intervals by a regionally correlatable marlstone. The primary objective of the Pilot is to test SAGD performance within each zone. In addition to the synergy of operations within each zone, reservoir continuity between the Grosmont C and D intervals will also be evaluated.

Field testing SAGD technology to date within the Grosmont Formation has provided an understanding of carbonate depletion mechanisms similar to the understanding the AOSTRA (Alberta Oil Sands Technology and Research Authority) Underground Test Facility (UTF) Project’s advancement of SAGD recovery in clastics.

Laricina applied to the Innovative Energy Technology Program (IETP) for funding in two separate rounds as the Pilot was advanced in two phases. This report is the annual report for the Saleski Phase 2 IETP Report and covers the period January 1 to December 31, 2013.

The key deliverables of Phase 2 include:

1. Establish the base reservoir characterization dataset for fluid and rock properties, inclusive of initial reservoir conditions of pressure, temperature and fluid saturation profiles. 2. Identify the reservoir performance under SAGD, monitoring steam chamber conformance across regionally identified geological features. 3. Determine the levels of reservoir continuity through the bitumen saturated target zones. 4. Evaluate the synergy of potential combined thermal operations across two adjacent vertical commercial zones. 1 Laricina Energy Ltd. Saleski Pilot Project IETP Approval 05-077 Final Report

5. Establish a database of production performance for the application of SAGD in Athabasca carbonates that can be further analysed to innovate refinements and advancements in future exploitation strategies. 6. Identify drilling, reservoir and production issues specific to bitumen recovery within carbonates. 7. Innovation of alternatives and solutions to recovery issues as may arise over the course of the Pilot performance. 8. Develop an understanding of carbonate performance issues that can be generalized on a regional basis. 9. Establish the commercial exploitation potential of the Grosmont carbonate resource.

2 Laricina Energy Ltd. Saleski Pilot Project IETP Approval 05-077 Final Report

2.0 SUMMARY PROJECT STATUS REPORT

2.1 Team Members Table 1: Saleski Pilot Project Team Members Name Institution E-mail Expertise Added

1. Jim Hand Laricina [email protected] Chief Operating Officer 2. Daniel Yang Laricina [email protected] Reservoir 3. Darcy Ries Laricina [email protected] Asset Director 4. Derek Keller Laricina [email protected] VP, Operations 5. Darcy Riva Laricina [email protected] Asset Manager

6. Kent Barrett Laricina [email protected] Carbonate Geology

7. Rod Collins Laricina [email protected] Manager, Operations Saleski Pilot Asset Team 8. Steve Brand Laricina [email protected] Lead 9. Deepa Thomas Laricina [email protected] Regulatory Director

The following team members listed in the 2011 and/or 2012 Saleski Pilot Project IETP Approval 05-077 are no longer directly involved with the Saleski Pilot Project: Dave Theriault, Neil Edmunds, Sandeep Solanki, Mauro Cimolai, Kathleen Coffey, George Brindle, Allison Aherne, Jason Smith, and Martin Belanger.

3 Laricina Energy Ltd. Saleski Pilot Project IETP Approval 05-077 Final Report

2.2 Chronological Activities and Operations Report The table below is a chronological report of all activities and operations conducted since the project was initiated. The details are included in subsequent sections.

Table 2: Chronological List of all Activities and Operations Performed at the Saleski Pilot Date Activity Dec 23, 2010 1st steam injected to 1D well pair Jan 12, 2011 Temperature log run on P1D – confirm steam to toe Fully commission the Once Through Steam Generator (OTSG) and available steam capacity Jan 24-28 increased Jan. 30 1st steam injected into 1C well pair Feb 15 Bubble tube installed in P1D 1D pair pressure communication test – 10 kPa response Feb 23 P1C temperature log – corrupted data 1C well pair pressure communication test – 50 kPa response Feb 28 2nd 1D pair pressure communication test – 10 kPa response 2nd P1C temperature log Mar 10 2nd 1C well pair pressure communication test – 50 kPa response Mar 13 Install temperature fibre in P1D Mar 14 Production test on the 1D pair – production flows into rig tank. Mar 14-22 Workover on P1C to install bubble tube and pump Mar 23 Production from P1D transferred into plant Mar. 24 Install temperature fibre in P1C Mar 25 Production test on the 1C pair – production flows into rig tank Determine that P1C bubble tube not functioning properly due to a blockage – workover Mar 27 required Mar 30 Stopped P1C production until bubble tube is replaced Replace 1C and 1D producer current pump rod (torque of 1000 ft*lb) with a new pump rod Apr 3-4 (torque of 1500 ft*lb) Apr 4-10 Replace damaged/plugged P1C bubble tube Apr 16-20 2nd production test on the 1D pair Apr 23-May 20 2nd production test on the 1C pair Apr 28-May 5 3rd production test on the 1D pair Apr 30 A big slug of oil caused treating difficulties in the FWKO and treater Surface piping modifications completed to direct 1C production through the line heater and May 5 allow individual metering and sampling May 18 Brief steam outage due to shutdown of the natural gas generator May 9-16 4th production test on the 1D pair May 20-25 5th production test on the 1D pair (short production test due to turnaround) Turnaround completed successfully. Installed three inline static mixers, solvent injection May 26 and recovery Motor Control Center (MCC) tie-in, OTSG pigging, Pressure Safety Valve (PSV) replacements and other plant routine maintenance 4 Laricina Energy Ltd. Saleski Pilot Project IETP Approval 05-077 Final Report

Date Activity Uninterrupted power supply (UPS) batteries were depleted. Programming in the control May 27 system was disrupted and had to be reloaded 3rd 1C Production Test (Variable Frequency Drive (VFD) board issues caused ~18 hour Jun 2-10 delay) Jun 10-16 6th 1D Production Test Jun 27-Sep13 4th 1C Production Test Fluid inversion in plant vessels due to insufficient diluent injection into the 1C production Jun 29 emulsion. 1C pump was slowed down and plant took ~2 days to recover Jul 5-24 7th 1D Production Test 1D pump stopped for two hours to test for communication with the 1D and 1C injector. No Jul 13 conclusive result from test to show communication with the 1C injector Jul 16 NMR operational, require ongoing calibration and testing Jul 24 P1D Pump failure, work over needed to diagnose cause of failure July 27 Service rig arrived for P1D workover Aug 7, 10, 15, 16 Natural gas generator causing steam to stop (less than 3 hours) Aug 11-12 Finished P1D workover to replace pump and return to steaming Aug 17 AGAR meter becomes operational Boiler Feed Water (BFW) valve closed caused OTSG to stop for a day. Distributed Control Aug 22-23 System (DCS) programming adjustments required on the mixed fuel burner management system. Aug 25 OTSG shutdown to install sampling ports Sep 12-13 OTSG shutdown to repair BFW pump Sep 12-16 8th 1D Production Test (stopped because of inability to pump fluid, require workover) Sep 13 End of 4th 1C Production Test Sep 22-Oct 10 9th 1D Production Test (Ended due to stimulation) Oct 11 1D injector and producer stimulation Oct 12-16 10th 1D Production Test (Ended due to pump rod failure) Oct 17-22 1D Pump Rod Workover Oct 17-Nov 11 5th 1C Production Test Scheduled plant shutdown for steam addition project tie-ins (stop both steam and emulsion Oct 25-27 treatment) Oct 28-Nov 2 11th 1D Production Test P1D pump shutdown and workover to replace the pump. Subsequently decided to perform Nov 2 another stimulation. Nov 11-18 1C and 1D Stimulations Nov 18-Jan 13, 2012 6th 1C Production Test Dec 3-4 Steam plant shutdown for final steam-addition project tie-ins project work (1 day) Dec 9 Start-up of new OTSG Dec 12-16 12th 1D production test Dec 16 P1D pump shutdown due to pump inefficiency Dec 28 - Jan 8, 2012 P1D pump workover (crack in production tubing) Jan 22 Steam header tie-in completed; OTSG shutdown for the day 5 Laricina Energy Ltd. Saleski Pilot Project IETP Approval 05-077 Final Report

Date Activity Feb 12 P1D pump shutdown due to pump inefficiency Feb 12-20 1D well pair workover due to crack in pipe near pump Feb 22 P2C drilling completed Feb 15 HP disposal pump module installed Mar 4 I2C drilling completed Mar 5 - Apr 30 7th 1C production test Mar 16-22 Metal PCP pump installed in I1C Source wells’ pumps upgraded to provide water to both OTSGs so they can run at full Mar 18 - May 6 capacity Mar 30 Plant shutdown to allow for I1C VFD tie in to the electrical system Apr 2 - 5 I1C production test. Terminated due to low flow rate Apr 11-12 Second OTSG fully commissioned Apr 16 Workover of I1C to prepare for steaming Apr 17 - May 7 13th P1D production test Apr 17-22 Workover of I1D for production test Apr 12 - May 12 P2C module construction and additional preparation for first steam Apr 26 Disposal Well 102/5-23 tied into the plant April 27 - May 1 Production test of I1D. Terminated due to low flow rate. May 6 PIC starts steam cycle May 7 - 9 New diluent pump installed at P1D P1D shut in due to inconsistent/gassy flow rate. Not enough steam generation to start May 10 steaming. May 13 First steam into 2C well pair Jun 10-15 Emulsion line for P2C and new source water pump installed in preparation for production Jun 16 - Aug 4 P1C production phase Jun 17 P2C 1st production test Jun 21 - 27 Minor leak in disposal water line. Promptly fixed and returned to service. Jun 29 - Aug 9 P2C steam injection phase Jul 24 - Aug 4 P1D steam injection phase Aug 4 Scheduled steam outage so that I2D piping could be tied in P1C workover to install new pump and pressure gauge. Damage to production tubing is Aug 4 - 9 what caused low pump efficiency near end of cycle. Aug 5 - Sept 25 P1D production phase Aug 9 - Sept 28 P1C steam injection phase Aug 10 - Oct 4 P2C production phase Aug 11 - Oct 4 1st steam injection phase at I2D P1D wellhead emulsion leak causes production at P1D to stop. Promptly cleaned, repaired Aug 14 - 15 and restarted Sept 5 - 23 1st Solvent injection phase at P1C Sept 25 - Oct 5 P1D shut down to observe temperature response from P1C steam Sept 29 P1C production phase Oct 7 - 13 Replacement of casing bowl at P2C to improve steam injection rate 6 Laricina Energy Ltd. Saleski Pilot Project IETP Approval 05-077 Final Report

Date Activity Oct 5 - Oct 21 P1D steam injection phase Oct 6 - 28 I2D production phase Oct 20 - Dec 6 P2C steam injection phase Oct 22 P1D production phase Oct 28 FWKO water dump was maximized and decided to stop production from I2D Nov 22-27 Decreased production at P1C due to rod failure Dec 7 P2C production phase Rod string and pump removed at P1C because of crack in tubing. Replaced string and added Dec 18-20 rod centralizers. Turned out to be issue with hole is stator. Dec 23- Jan 23, 2013 1D well-pair SAGD test Service rig pulled PCP out of P2C so that a gas separator could be installed on the intake. Jan 5 – 7 Replaced old pump as well because of damage. Jan 21 – 27 I2D cycle 2 production phase Jan 24 P1D cycle 4 steam injection begins Jan 28 – Feb 8 I2D cycle 3 steam injection. Feb 9 I2D cycle 3 production begins P1C cycle 4 truncated by ~15 days to avoid potential steam limitation conflicts in future. Casing bowl being upsized to 4” diameter and steam casing piping upsized from 3” Feb 15 – Mar 10 diameter to 4” diameter to allow for ~800 m3/d cold water equivalent (CWE) steam injection. Feb 17 – 19 Service rig on P2C because of rod string backing off just above rotor Feb 19 P2C casing gas redirect to Boreal vessel Feb 26 – Mar 2 P1C rod string breakage, replaced with Prorod Mar 7 P1C Cycle 5 steam injection begins Mar 12 P1D Cycle 4 production begins Mar 11 – 16 Elastomer pump installed at P2C to test efficiency late in cycle Mar 19 – 20 P1D/I2D master valve bonnet failure, flange separated from top. Mar 24 I2D pump failure. Attempted pressure test, but failed. Mar 27 Isotope tracer injected into P1C to test inter-well communication New Disposal Line Apr 2 - 5 P1D pump failure, service rig on to replace pump Apr 3 HP disposal pump replaced with new one, scale found in old pump. Apr 8-9 Elastomer pump placed in I2D. Apr 23 First use of quench water, at P1D, to attempt to handle steam conditions at the pump. Apr 26-27 P2C elastomer pump replaced with a larger elastomer pump. May 6 P1D quench water injection surface piping completed and ready for use. May 22 Oilflow Solutions Inc. injected 3 volumes of Proflux into P2C. Plant and wells tripped because of faulty deltaV card. P1D, I2D, and P2C restarted. P1C May 28 injection target already complete so only one boiler restarted and therefore decreased injection rates used.

7 Laricina Energy Ltd. Saleski Pilot Project IETP Approval 05-077 Final Report

Date Activity Planned turnaround, which included the following major projects:  Installed P2C elastomer pump pulled and metal PCP so that it can return to steam injection after turnaround.  Installed steam trap at end of steam header to reduce condensate to condensate tank  Modified I2D piping so that the emulsion line is separate from P1D emulsion line.  Installed Jet Shear isolation valves.  Replaced BFW seal flush tubing .  Installed fuel gas lineheater control valve and PSV. May 30 – Jun 10  Replaced IGF discharge pump and water system control valves to improve discharge rate from roughly 30 m3/hr to roughly 40 m3/hr.  Tied-in new disposal pipeline.  Modified sample tap levels in Skim Tank to monitor level at desand jet pump suction.  Modified sample tap levels in FWKO to sample the produced water outlet.  Cleaned out asphaltene from diluent tank.  Replaced slop oil pump. Jun 11 OTSGs started up and running. Jun 12 Quench water line installed for P1D and P1C. Jun 14 – Jul 3 SAGD test of 2C well pair. Jun 17 P1C Cycle 5 production begins. First time quench water utilized at this well. June 23 P1C pressure fibre failure. P1C pump went down on high torque. Pieces of metal found in gas anchor. Workover to Jun 24 – Jul 2 replace pump and remove metal pieces. Pressure fibre response returns shortly after. Jul 3 P1C returns to production. Jul 3 2C SAGD test ends and P2C joins I2C in Cycle 4 injection. Jul 6 - 7 Workover on P1D to replace Oryx seal and drive head. Jul 27 Natural gas generator #2 went down and plant lost power temporarily. Pressure gauge and temperature sensor at pump failed. Began to use temperature point on instrumentation string near heel for bottomhole temperature (BHT) and subcool Aug 3 calculations. Began using P1Obs1 and P1Obs2 for pressure as they were trending closely to P1C bottomhole pressure (BHP) prior to failure. Aug 11 Natural gas generators tripped on low exhaust temperature. Aug 13 -23 Steam production down to clean blowdown water cooler. Aug 14 P2C begins production phase of Cycle 4. Aug 19 - 21 P1D shut in an attempt to increase BHP and improve production; limited success. Aug 22 I2D Cycle 4 injection begins. Injected 5 m3 of diluent down casing and 2 m3 down long string of P1D in attempt to clean Aug 24 wellbore and improve production. Aug 25 P1D Mini-slug 4a injected; total steam injected 60 m3. Sept 5 Both OTSGs and natural gas generators tripped. Sept 6 – 8 P1D Mini-slug 4b injected; total steam injected was 510 m3. Sept 21 Plant tripped due to natural gas generator trip. 8 Laricina Energy Ltd. Saleski Pilot Project IETP Approval 05-077 Final Report

Date Activity Sept 28 Plant tripped due to natural gas generator #1 high exhaust temperature. P1D Mini-slug 4c injected; total steam injected was 1,129 m3. Plant tripped twice because Oct 1 – 6 steam rate injected into P1D was too fast. Oct 4 Isotope tracer injected into P1D to test inter-well communication. Oct 5 Larger control valve installed on I2D steam line to allow for higher steam rates. P1C having issues with high drive head seal pressure and torque. On Oct 25 P1C was shut- Oct 18 - 25 in. Began injecting steam into I1C to prepare reservoir for P1C sidetrack drilling. Injection stopped when fuel gas was shut off so that pressure control valve and mercaptans Oct 24 skid could be installed on fuel gas line. I2D Cycle 4 steam injection complete. Workover to install pump and temperature fibre Oct 29 begins. Nov 2 P1C steam injection begins to help prepare reservoir for P1C sidetrack drilling. I2D Cycle 4 production begins. Difficulty with getting fluid to surface tried injecting blowdown to prove pump is operational; passed test. Also injected steam to promote Nov 4 connectivity, and quench water to create subcool near pump. Casing began to pull a vacuum. Steaming of I1C and P1C halted to replace a level indicator on the high pressure steam Nov 5 - 7 separator. Nov 5 P1C steam injection ceases, still steaming I1C though. Nov 10 I2D shut-in to allow injected quench to soak. Nov 10 Permanent quench line tied-in. Nov 11 I2D begins production again. Stopped later this day because of unsustainable flow. Nov 14 - 15 I2D begins production again. Stopped on 15th because of unsustainable flow. I1C steaming ceased to test pressure decline and so that completions could be removed prior Nov 15 to drilling. P2C Cycle 4 production truncated to help prepare reservoir for P1C sidetrack drilling. Nov 16 Immediately switched to P2C Cycle 5 production. P1D pump failure; could not perform workover because of P1C sidetrack service and Nov 18 drilling rigs. Nov 19 – 20 I2D steamed for a few days to test connectivity of horizontal. Nov 20-22 I2D production test. Nov 22 Draining of certain vessels to prepare for down time during P1C sidetrack drilling. I2D shut in. Workover performed Nov 28-29 to install coiled tubing down guide string to Nov 23 - 30 inject steam further into the horizontal section. To do this the temperature fibre was removed.

Nov 24 – 27 OTSG issues with O2 analyzers. Injection rates into P2C decreased. Nov 27 Bridge plug installed at P1C original. Nov 28 I1C steam injection for final pressure preparation before P1C sidetrack drilling begins. Water dump clogged on the Free Water Knock Out (FWKO) due to irregular operation. Nov 30 Vacuum truck brought to site and removed oil blockage. Dec 1 P1C and I1C handed over to drilling for P1C sidetrack. Dec 1 I2D restarted production.

9 Laricina Energy Ltd. Saleski Pilot Project IETP Approval 05-077 Final Report

Date Activity Underground piping cathodic protection system rectifier energized for the first time. Dec 17 Construction took place in fall of 2013. Dec 17 – 19 Began to remove drilling equipment allowing room for P1D pump replacement to begin. Dec 17 Construction began reinstalling surface piping for P1C-sidetrack. Dec 18 P1C-sidetrack casing bowl welded on. Dec 20 Service rig moved to P1C to remove bridge plug and reinstall the rest of wellhead. Dec 21 P1D returns to production. I2D tripped as a result due to a programming artifact. Dec 23 P1C sidetrack steaming begins. Two plant trips after reducing OTSG outputs because of disposal tank levels due to scale Dec 28 build up at strainers. Strainers cleaned and disposal rates improved.

10 Laricina Energy Ltd. Saleski Pilot Project IETP Approval 05-077 Final Report

2.3 Production, Material and Energy Balance Flow Sheets The month and calendar year total, production, and material and energy balance as per operations in the reporting year are summarized in the Table 3 to Table 5. For this reporting period, the tables presented include volumes from January 1 to December 31, 2013.

Table 3: Summary of 2013 Calendar Year Gross Balances

Gross Balances Electricity Consumed (KWh) N/A Source Natural Gas and Diesel Generation

Steam (Per Boiler) Rating (lbs) 1,500 Pressure (kPag) 11,200 Capacity (tonnes/hr) 23 Firing Rate 73% Quality 79%

Boiler Feed Water Salinity (mg/mL) 158 Fresh Water Composition 100%

In-Situ Combustion N/A

Process Air - Flotation N/A

Fresh Water Total (m3) 333,438 Dry Steam (m3) 193,766 Blow Down (m3) 51,672

11 Laricina Energy Ltd. Saleski Pilot Project IETP Approval 05-077 Final Report

Table 4: Monthly Boiler (OTSG) Related Values for the 2013 Calendar Year Cumulative Cumulative Average BFW Average OTSG Cumulative BFW OTSG Fuel Month Temperature Boiler Pressure Produced Steam Consumption Consumption (ºC) (kPag) Energy (GJ) (Tonnes) (GJ) January 102.3 9,009 9,823 26,638 21,202 February 112.5 9,142 15,408 39,683 33,867 March 93.2 9,118 23,705 61,683 52,469 April 95.1 9,145 24,506 62,588 54,327 May 103.6 9,114 21,639 57,387 48,445 June 120.7 9,152 8,576 18,947 19,030 July 91.6 9,258 29,230 54,512 65,129 August 126.2 9,229 17,536 42,058 38,907 September 120.5 9,128 20,075 51,186 44,646 October 121.1 9,158 25,043 63,058 55,865 November 98.0 9,047 20,178 51,766 44,329 December 102.3 9,022 29,720 73,951 64,716 Annual 107.2 9,127 245,438 603,457 542,932

12 Laricina Energy Ltd. Saleski Pilot Project IETP Approval 05-077 Final Report

Table 5: Summary of all Produced Materials in 2013

Produced Materials Produced Water (m3) 115,840

Total Volume disposed (m3) 253,155 Well 100/2-26-085-19W4 (m3) 1,977 Well 100/5-23-085-20W4 (m3) 164,319 Well 102/5-23-085-20W4 (m3) 86,859

Produced Oil (m3) 22,669 API 6-7

Diluent Purchased (m3) 5,630.9 Mean Density (kg/m3) 669.9

Sales Oil (m3) 27,622.5 Blend Density (kg/m3) 959.6 Diluent Percentage 17%

Produced Sand (m3) 277.5

Produced Gas (m3) 768,800 Natural Gas (m3) 768,800 Combustion Gas (m3) N/A

2.4 Reserve Estimates There are no reserve estimates for the Saleski Pilot Project. However, the best estimate of contingent resources for the Saleski lease is 2.5 billion barrels (Gross).

13 Laricina Energy Ltd. Saleski Pilot Project IETP Approval 05-077 Final Report

3.0 WELL INFORMATION 3.1 Well Layout

Figure 1: Planar View of Well Layout 14 Laricina Energy Ltd. Saleski Pilot Project IETP Approval 05-077 Final Report

Figure 2: Planar and Cross-Sectional Well Schematics

3.2 Drilling, Completions, and Workover Operations Workover operations performed during the reporting period for each well pair are presented below.

Table 6: Summary of Workovers Associated with the 1D Well Pair

Date Workover

Jan 13, 2013 Changed out wellhead Oryx Seal and emulsion line valve.

A leak formed at master valve on wellhead causing a spill. Switched out so that failure can be analyzed. Included killing well, Mar 19 - 21 removing drive head, lowering rod string onto tag bar, stripping off old composite pumping tree (CPT) installing refurbished and

15 Laricina Energy Ltd. Saleski Pilot Project IETP Approval 05-077 Final Report

Date Workover

serviced CPT. Installed a new Oryx seal on drive head and reinstall on wellhead.

KUDU PCP failure and replacement. Pulled flush rods, bottom two showed signs of wear and five coupling showed minor thread damage. Tubing hanger and damaged threads replaced with spare hanger. Pulled tubing from well and replaced with new one. Installed new all metal KUDU PCP and horizontal intake sub. Apr 3 - 11 Installed new flush rod string.

Stator not cracked but both rotor and stator showed signs of even wearing throughout. Crack was discovered at one tubing joint, 39 m from top of pump. Oryx seal replaced. Removed existing KUDU drive head and Jul 6 replaced with refurbished fully serviced one.

Oryx seal replaced. Bitumen found plugging the purging hoses on August 15 drive head, indicating that wellbore fluids contaminated purging system due to seal failure. KUDU PCP failed to lift fluids to surface. Pulled PCP hollow rods; rods were in good condition, but damaged threads. Rotor pulled and showed excessive amount of chrome had worn off evenly from Dec 14 - 20 top to bottom. Tubing pulled and no holes or cracks found. Ran in hole a new KUDU PCP (same type), same tubing with hardened joints above the pump, and Pro-rod. Very tight fitting rotor and stator.

Table 7: Summary of Workovers Associated with the 1C Well Pair

Date Workover

Replaced casing bowl with new bowl, equipped with a 2” and 4” valve. Pulled out instrumentation coil (line bent at surface so landed 15 m shallower on reinstallation). Pulled rods and tubing which showed no significant wear or damage. Pulled 13 joints of long string, installed packer and suspended long string. Cut off casing Feb 15 - 23, 2013 bowl installed new bowl, 0.5 m lower with larger valves to improve steam rates. Heat treated welds, pulled packer, and re-ran long string. Ran in same KUDU stator and rotor with new production tubing and with hardened joints above the pump. Ran in PCP flush rods and centralizers

16 Laricina Energy Ltd. Saleski Pilot Project IETP Approval 05-077 Final Report

Date Workover

Fished rod string. Rod string failure occurred while increasing pump speed. Spin through centralizer had stripped coupling, rod failure 20 m above the pump. Centralizer could not be retrieved. Pulled Feb 26 – Mar 3 production tubing and instrumentation cable. Cable, damaged 14 m above carrier, sensor still working. Ran in same KUDU PCP, production tubing, and new instrumentation. Ran in new coiled rod string. Troubleshot PCP lift system which had difficulties with over torqueing. Pulled up rotor to flush tubing. Pumped water to kill the well. Picked up rods no back spin on pump pressure seen while pumping 1.5 x tubing volume. Picked up rods again, rotor wouldn’t go down into stator. Removed drive head and pulled out coiled rod and KUDU Rotor, which showed some wear but still in good condition. Rods were in good condition. Removed wellhead, Jun 26 – Jul 3 installed BOP and pulled tubing and heel gauge which had failed prior to beginning of workover. Several damaged Cannon clamps found. Installed perforated pup in guide string and ran back in with long string. Perforated pup landed at heel, long string landed at toe. Ran in magnet to pull any debris, nothing recovered. Ran in instrumentation coil. Ran in KUDU pump and pressure temperature gauge. Ran in tubing with 6 hardened joints above pump. Ran in new rotor and re-ran coiled rod. Preparing for P1C sidetrack drilling. Pulled all completions tubing from well, set permanent bridge plug and pressure tested. Logged Nov 20 – Dec 22 intermediate casing prior to drilling sidetrack. Removed completion casing bowl and installed drilling bowl. Drilled a new lateral section parallel to original P1C horizontal but laterally offset 15m to the east. Drilling rig, rigged up, set Nov 30 – Dec 19 whipstock, milled window, and drilled 216 mm lateral section from 448 m MD to 1,251 m MD. Set bridge plug and drilling rig moved off. (Note: completions for sidetrack performed in 2014).

Table 8: Summary of Workovers Associated with the 2D Well Pair

Date Workover

Replaced worn Oryx seal on KUDU drive head. Original Oryx seal showed signs of wear (pressure gauges monitoring seal pressure Mar 10 -11, 2013 were reading the same as the emulsion flow line pressure). A properly functioning seal would read much lower (50 - 300 kPa).

17 Laricina Energy Ltd. Saleski Pilot Project IETP Approval 05-077 Final Report

Date Workover

Repair master valve that was starting to separate at bonnet connection on CPT. Locked out well, killed well by pumping 5 m3 Mar 21 down tubing. Unbolted master valve body and removed CPT. Studs were visibly stretched. Installed new gasket, new studs and greased master valve. Pulled rods, KUDU PCP, production tubing and instrumentation cable. Six PCP rods had to be changed out due to thread wear. Six rods changed out due to body wear. Instrumentation cable showed Apr 7-9 no signs of damage. Ran in high temperature elastomer KUDU PCP, new production tubing and rods, did not run in instrumentation with pump. Old metal KUDU stator found to be cracked throughout.

Replaced faulty Oryx seal on KUDU drive head. Oryx seal pressure Apr 24 gauges rose above normal levels indicating primary seal was failing.

Completion work to install guide string, instrumentation and new all-metal NOV PCP into well. Pulled pump rods, and KUDU elastomer PCP which showed minimal wear. Ran flush joint tubing in hole. Difficulty installing tubing, at 1,100 m MD noticed that Jul 3 - 12 tubing joints were starting to bend. Pulled two joints briefly steamed well to help with tubing installation, got to 1,210 m MD. Suspected immobile bitumen holding up string. Pulled out tubing string, with 16 joints bent and un-usable. Ran to toe, landed tubing hanger and installed wellhead. Pulled instrumentation coil, pumped fluid to TD to clean out guide string. Pulled the guide string back to 800m MD and Ran in hole Nov 11 with open ended coil string for quench water injection. Installed fitting and valve as well.

Table 9: Summary of Workovers Associated with the 2C Well Pair

Date Workover

Pump swapped out due to low productivity. Pulled coil rod, production tubing, instrumentation and KUDU PCP. Stator had several cracks. Pressure and temperature gauge did not have Jan 5 – 8, 2013 significant damage but the cable was damaged. New cable and gauge run. Replaced pump with new KUDU PCP with gas anchor at intake, with new production tubing string. New rotor and ran in the same coiled rod string. Fished out backed off rod string. Pulled coiled rod, found it had backed off at the shear coupling. Fished out shear coupling and rotor Feb 18 – 19 with coiled rod. Replaced all damaged rod components and re-ran the coiled rod and rotor.

18 Laricina Energy Ltd. Saleski Pilot Project IETP Approval 05-077 Final Report

Date Workover

Difficulty operating well due to unusually high torque. Lifted rod string, and flushed tubing string. Attempted to re-land rotor but unsuccessful. Pulled coiled rods and rotor. Minor scarring on but did not appear to have significant damage. Pulled instrumentation string, and KUDU PCP. Lost several pieces of instrumentation Cannon Mar 12 - 18 clamps down the well due to breakage. Capillary line destroyed. Broken pieces of broken stator inside gas anchor. Ran in perforated tubing with bull plug below pump. Ran in hole with new elastomer KUDU rotor and new coiled rod string (broke during spooling off site). Replaced Oryx seal because gauge reading higher than normal values indicating primary seal has failed. After change the pump began to experience high torque and drive head belts would slip. Apr 23 Tried to pump water into production tubing to flush rotor, could only pump at low rates and high pressures. Rotor seems to be seized in stator. Continuation of last workover:

Pulled rods with no issue and no significant damaged visible. Rotor pulled but difficult to unseat from stator. Production tubing pulled Apr 25 - 27 and only one joint had damage, replaced. Several chunks of elastomer were found in perforated pups below pump indicating pump was damaged. New larger elastomer KUDU PCP pump installed. Same production tubing with hardened joints installed above the pump. New rotor ran in on the same coiled rod string. Remove elastomer PCP and install metal PCP prior to steaming well. Wrong crosser was welded to bottom of new PCP (KUDU May 30 – Jun 3 error). KUDU corrected issue and provided credit for lost time. Ran in hole the metal KUDU PCP and heel pressure gauge. Ran in coiled rod string and KUDU rotor.

3.3 Well Operations 3.3.1 Well List and Statuses The following table summarizes all of the wells at the Pilot, and the status of each individual well at the end of 2013.

19 Laricina Energy Ltd. Saleski Pilot Project IETP Approval 05-077 Final Report

Table 10: Well List and Statuses

RIG WELL AER WELL SPUD LICENS WELL NAME RELEASE TYPE STATUS DATE E # DATE Injector LEL et al 101 I1C Saleski 15-26-85-19 SAGD 17/02/2008 21/08/2010 0393303 Injector LEL et al 101 I1D Saleski 15-26-85-19 SAGD 21/01/2010 13/02/2010 0416475 Injector LEL et al 101 I2D Saleski 15-26-85-19 SAGD 21/01/2010 14/09/2010 0416474 Injector LEL et al 101 I2C Saleski 10-26-85-19 SAGD 05/02/2012 04/03/2012 0441563 Producer LEL et al 101 P1C Saleski 15-26-85-19 SAGD 03/02/2010 08/08/2010 0418037 Producer LEL et al 101 P1D Saleski 15-26-85-19 SAGD 18/01/2010 05/03/2010 0416473 Producer LEL et al 101 P2D Saleski 15-26-85-19 Drilled and 15/02/2008 16/03/2008 0393306 Cased Producer LEL et al 101 P2C Saleski 10-26-85-19 SAGD 06/01/2012 23/02/2012 0441564 Producer LEL et al 101 P1C Saleski 10-26-85-19 SAGD 03/12/2013 16/12/2013 0418037 Re-entry Observation LEL et al P1 OBS1 Saleski 7-26-85-19 Drilled and 05/02/2008 15/02/2008 0392352 Cased Observation LEL et al P2 OBS1 Saleski 7-26-85-19 Drilled and 18/01/2010 04/02/2010 0392351 Cased Observation LEL et al P1 OBS2 Saleski 10-26-85-19 Drilled and 05/01/2010 17/01/2010 0416334 Cased Observation LEL et al P1-2 OBS2 Saleski 10-26-85-19 Drilled and 19/02/2010 03/03/2010 0416335 Cased Observation LEL et al P2 OBS2 Saleski 10-26-85-19 Drilled and 05/02/2010 18/02/2010 0416456 Cased Observation LEL et al P1 OBS3 Saleski 10-26-85-19 Drilled and 20/02/2008 16/03/2008 0392447 Cased Observation LEL et al P2 OBS3 Saleski 10-26-85-19 Drilled and 13/02/2008 15/03/2008 0392446 Cased Water Source LEL et al Saleski 10-26-85-20 Water Source 02/03/2010 04/03/2010 0417932 Water Source LEL et al WS Saleski 13-23-85-20 Water Source 19/01/2010 27/01/2010 0416397 Water Source LEL et al 1F1 Saleski 5-23-85-20 Water Source 27/01/2010 02/02/2010 0415965 Water Source LEL et al 1F1 Saleski 14-24-85-20 Water Source 02/02/2010 06/02/2010 0416408 Water Source LEL et al WSW1 Saleski 2-26-85-19 Suspended 08/02/2008 12/02/2008 0393094 Water Source LEL et al WSW2 Saleski 2-26-85-19 Suspended 13/02/2008 17/02/2008 0393129 Water LEL et al 100 Saleski 2-26-85-19 Water 17/02/2008 27/02/2008 0393483 Disposal Disposal Water LEL et al 100 Saleski 5-23-85-20 Water 06/02/2009 22/02/2009 0406826 Disposal Disposal Water LEL et al 102 Saleski 5-23-85-20 Water 14/10/2010 01/11/2010 0424415 Disposal Disposal

20 Laricina Energy Ltd. Saleski Pilot Project IETP Approval 05-077 Final Report

3.3.2 Wellbore Schematics The wellbore schematics for each well listed in

21 Laricina Energy Ltd. Saleski Pilot Project IETP Approval 05-077 Final Report

Table 10 are included below in the same order as they appear in the table. Since all five water source wells are very similar, a single schematic diagram of a typical water source well completion was included.

22 Laricina Energy Ltd. Saleski Pilot Project IETP Approval 05-077 Final Report

Figure 3: LEL ET AL 101-I1C-HZ SALESKI 15-26-85-19 Wellbore Schematic

23 Laricina Energy Ltd. Saleski Pilot Project IETP Approval 05-077 Final Report

Figure 4: LEL ET AL 101-I1D-HZ SALESKI 15-26-85-19 Wellbore Schematic

24 Laricina Energy Ltd. Saleski Pilot Project IETP Approval 05-077 Final Report

Figure 5: LEL ET AL 101-I2D-HZ SALESKI 15-26-85-19 Wellbore Schematic

25 Laricina Energy Ltd. Saleski Pilot Project IETP Approval 05-077 Final Report

Figure 6: LEL ET AL 101-I2C-HZ SALESKI 10-26-85-19 Wellbore Schematic

26 Laricina Energy Ltd. Saleski Pilot Project IETP Approval 05-077 Final Report

LEL et al 101 P1C Salesk 15-26-085-19 UWI: 106/15-26-085-19W4/0

ELEV (masl) TVD (mKB) MD (mKB) K.B. 593.17 0 0 Ground Level 588.82 4.35 4.35

Viking 474.4 118.5 118.7 Joli Fou 463.6 129.3 131.0 Upper Grand Rapids 445.9 147.0 147.5 Lower Grand Rapids 421.7 171.2 172.7 Clearwater 374.2 218.7 224.0 BGWP 345.0 248.2 258.0 Wabiskaw 294.7 298.2 323.5 Wabiskaw Shale 287.2 305.7 334.0 Ireton 281.1 311.8 350.0 Grosmont D 257.9 335.0 381.0 CD Marl 230.6 362.3 439.2 Grosmont C 229.1 363.8 442.8

Figure 7: LEL ET AL 101-P1C-HZ SALESKI 15-26-85-19 Wellbore Schematic

27 Laricina Energy Ltd. Saleski Pilot Project IETP Approval 05-077 Final Report

LEL et al 101 P1C Salesk 10-26-085-19 (P1C Re-entry) UWI: 109/10-26-085-19W4/02

ELEV (masl) TVD (mKB) MD (mKB) K.B. 593.17 0 0 Ground Level 588.82 4.35 4.35

Viking 474.4 118.5 118.7 Joli Fou 463.6 129.3 131.0 Upper Grand Rapids 445.9 147.0 147.5 Lower Grand Rapids 421.7 171.2 172.7 Clearwater 374.2 218.7 224.0 BGWP 345.0 248.2 258.0 Wabiskaw 294.7 298.2 323.5 Wabiskaw Shale 287.2 305.7 334.0 Ireton 281.1 311.8 350.0 Grosmont D 257.9 335.0 381.0 CD Marl 230.6 362.3 439.2 Grosmont C 229.1 363.8 442.8

Figure 8: LEL ET AL 101-P1C-HZ SALESKI 10-26-85-19 (P1C Re-entry) Wellbore Schematic

28 Laricina Energy Ltd. Saleski Pilot Project IETP Approval 05-077 Final Report

Figure 9: LEL ET AL 101-P1D-HZ SALESKI 15-26-85-19 Wellbore Schematic

29 Laricina Energy Ltd. Saleski Pilot Project IETP Approval 05-077 Final Report

Figure 10: LEL ET AL 101-P2D-HZ SALESKI 15-26-85-19 Wellbore Schematic

30 Laricina Energy Ltd. Saleski Pilot Project IETP Approval 05-077 Final Report

Figure 11: LEL ET AL 101-P2C-HZ SALESKI 15-26-85-19 Wellbore Schematic

31 Laricina Energy Ltd. Saleski Pilot Project IETP Approval 05-077 Final Report

Observation Well Construction Details 102/07-26-85-19W4 (P1Obs1) As of July 2009 ELEV (masl) DEPTH (mKB)

597.05 4.27

Piezometer Thermocouple Borehole Diameter: 311 mm

Viking 484.32 117 Surface Casing: 244.5 mm Thread: ST&C Grade: H40 Joli Fou 470.32 131 Thermal Cement Upper Grand Rapids 455.22 146.1

Lower Grand Rapids 431.82 169.5

Clearwater 373.32 228

Wabiskaw 309.32 292

Ireton Carbonate 278.42 322.9

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

Grosmont D Middle Tite 264.42 336.9 Thermocouple Spacing: 3.0m 316m to 343m GL Piezometer #3 262.05 339.27

Grosmont D Lower Porous 252.52 348.8 Thermocouple Spacing: 1m Grosmont CD Marl 241.52 359.8 346m to 355m GL

Grosmont C 240.22 361.1 Thermocouple Spacing: 2m 356m to 366m GL Piezometer #2 239.05 362.27 Grosmont C Porosity Strk 233.02 368.3 Thermocouple Spacing: 1m 368m to 378m GL Piezometer #1 227.05 374.27 Production Casing: 114 mm Grosmont C argillaceous Zone 220.32 381 Thread: Tenaris Blue Grade: L80 Grosmont B 206.82 394.5 Thermal Cement TD 196.32 405.00 Borehole TD

Figure 12: LEL ET AL P1 OBS1 SALESKI 7-26-85-19 Wellbore Schematic

32 Laricina Energy Ltd. Saleski Pilot Project IETP Approval 05-077 Final Report

Figure 13: LEL ET AL P2 OBS1 SALESKI 7-26-85-19 Wellbore Schematic

33 Laricina Energy Ltd. Saleski Pilot Project IETP Approval 05-077 Final Report

Figure 14: LEL ET AL P1 OBS2 SALESKI 10-26-85-19 Wellbore Schematic

34 Laricina Energy Ltd. Saleski Pilot Project IETP Approval 05-077 Final Report

Figure 15: LEL ET AL P1-2 OBS2 SALESKI 10-26-85-19 Wellbore Schematic

35 Laricina Energy Ltd. Saleski Pilot Project IETP Approval 05-077 Final Report

Figure 16: LEL ET AL P2 OBS2 SALESKI 10-26-85-19 Wellbore Schematic

36 Laricina Energy Ltd. Saleski Pilot Project IETP Approval 05-077 Final Report

Observation Well Construction Details 103/10-26-85-19W4 (P1Obs3) As of July 2009 ELEV (masl) DEPTH (mKB)

589.8 4.20

Piezometer Thermocouple Borehole Diameter: 311 mm

Surface Casing: 244.5 mm Thread: ST&C Viking 442.60 151.4 Grade: H40

Thermal Cement Joli 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

Casing Shoe 284.80 309.20 Borehole Diameter: 200 mm Piezometer #5 277.8 316.20

Grosmont D 267.00 327 Piezometer #4 264.80 329.20 Thermocouple Spacing: 3.0m 316m to 343m GL Grosmont D Middle Tite 261.00 333 Piezometer #3 255.8 338.20 Production Casing: 114 mm Thread: Tenaris Blue Grosmont D Lower Porous 250.00 344 Grade: L80 Thermocouple Spacing: 1m 346m to 355m GL

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

Piezometer #1 223.8 370.20 Thermocouple Spacing: 1m 368m to 378m GL Grosmont C argillaceous Zone 215.70 378.3 Grosmont B 392 Thermal Cement TD 188.2 405.80 Borehole TD

Figure 17: LEL ET AL P1 OBS3 SALESKI 10-26-85-19 Wellbore Schematic

37 Laricina Energy Ltd. Saleski Pilot Project IETP Approval 05-077 Final Report

Observation Well Construction Details 102/10-26-85-19W4 (P2Obs3) As of July 2009 ELEV (masl) DEPTH (mKB)

590.18 3.98

Piezometer Thermocouple Borehole Diameter: 311 mm

Viking 479.06 115.1 Surface Casing: 244.5 mm Thread: 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

Clearwater 368.16 226

Wabiskaw Sand 304.16 290

Wabiskaw Shale 291.86 302.3

Casing Shoe 285.18 308.98 Borehole Diameter: 200 mm Piezometer #5 282.16 312.00 Ireton Shale 281.86 312.3 Production Casing: 114 mm Ireton Carbonate 275.46 318.7 Thread: Tenaris Blue Piezometer #4 269.16 325.00 Grade: L80 Grosmont D 268.56 325.6 Thermocouple Spacing: 3.0m Grosmont D Middle Tite 261.16 333 316m to 343m GL Piezometer #3 260.16 334.00 Grosmont D Lower Porous 251.16 343 Thermal Cement

Thermocouple Spacing: 1m 346m to 355m GL Piezometer #2 240.16 354.00 Grosmont CD Marl 237.16 357 Grosmont C 235.46 358.7 Thermocouple Spacing: 2m Grosmont C Porosity Strk 228.16 366 356m to 366m GL Piezometer #1 228.16 366.00

Grosmont C argillaceous Zone 215.16 379 Thermocouple Spacing: 1m 368m to 378m GL Grosmont B 202.16 392 TD 188.58 405.58 Borehole TD

Figure 18: LEL ET AL P2 OBS3 SALESKI 10-26-85-19 Wellbore Schematic

38 Laricina Energy Ltd. Saleski Pilot Project IETP Approval 05-077 Final Report

Figure 19: Schematic of a Typical Saleski Water Source Well

39 Laricina Energy Ltd. Saleski Pilot Project IETP Approval 05-077 Final Report

Figure 20: LEL ET AL 100 SALESKI 2-26-85-19 Wellbore Schematic

40 Laricina Energy Ltd. Saleski Pilot Project IETP Approval 05-077 Final Report

Figure 21: LEL ET AL 100 SALESKI 5-23-85-20 Wellbore Schematic

41 Laricina Energy Ltd. Saleski Pilot Project IETP Approval 05-077 Final Report

Figure 22: LEL ET AL 102 SALESKI 5-23-85-20 Wellbore Schematic

42 Laricina Energy Ltd. Saleski Pilot Project IETP Approval 05-077 Final Report

3.3.3 Spacing and Pattern The Pilot operates up to four cyclic SAGD injector/producer well pairs. The horizontal well length (1C, 1D, 2D = 800 m; 2C = 450 m) are drilled south-north from a central pad with 90 m lateral spacing. In late 2013, the horizontal section of the 1C producer (P1C) was abandoned and a sidetrack (referred to as P1Cs or P1C-sidetrack) drilled by milling a window in the original P1C intermediate casing. Thereby allowing the casing located above the milled window to be utilized. The original P1C horizontal section was plugged back with a bridge plug. The P1C- sidetrack is located roughly 15 m east and parallel to the original P1C horizontal section. The horizontal well pairs are immediately offset (within 4-10 m) by vertical observation wells along the length of the horizontal wells forming a lattice.. Refer back to Figure 1and Figure 2.

4.0 Production Performance and Data 4.1 New Production Data

4.1.1 Individual Well Injection and Production History

Shown below is a summary of well activities to the end of 2013

I2D

P2D

I2C

P2C

I1D

P1D

I1C

P1C

P1Cs

1-Jan-13 1-Feb-13 1-Mar-13 1-Apr-13 1-May-13 1-Jun-13 1-Jul-13 1-Aug-13 1-Sep-13 1-Oct-13 1-Nov-13 1-Dec-13 1-Jan-14

Production Injection Solvent Injection Idle

Figure 23: Well Activities Summary for 2013

43 Laricina Energy Ltd. Saleski Pilot Project IETP Approval 05-077 Final Report

4.1.1.1 1D Well Pair (LEL ETAL 101 I1D and P1D Saleski 15-26-85-19)

The 1D well pair began 2013 in the middle of a SAGD test. This test was implemented to determine if SAGD production was possible in the D reservoir with advanced communication between the wells and significant production from P1D. Communication between the wells during SAGD operation after the two acid jobs in 2011 was fairly good with roughly 100- 200 kPa drawdown between injector and producer. After roughly one month of attempting SAGD operation it was determined in late January that steam breakthrough at certain points was evident even at low injection and production rates resulting in poor production and unsustainable SAGD operation.

After the conclusion of the SAGD test, injection was switched from I1D to P1D to perform the injection phase of Cycle 4. A total of 14,000 m3 CWE was injected at an average rate of approximately 320 m3/d. When the well was put on production, issues with regards to low or no subcool resulted in poor production and difficult pump operation. A failure of the master valve bonnet on the wellhead resulted in a brief idle period. The well was then brought on production with high water cuts but the issues with subcool had been temporarily resolved. After two weeks of steady production and manageable downhole temperatures, subcool began to cause operational difficulties once again. After a pump failure in early-April and an idle period shortly after to allow steam to soak and subsurface temperatures to cool, production was attempted and subcool issues remained. It was decided to inject source water down the long string during production to improve subcool conditions; this idea is referred to as quench water injection. The first quench water test was successful and improved oil and net emulsion rates were achieved. Both the issues with subcool and the high water cuts were likely associated with P1C steaming. Although quench helped to improve subcool conditions and allowed for more consistent operation; Cycle 4 continued production with similar water cuts around 90% and oil rates around 15 m3/d for the next few months until the June turnaround. After the turnaround oil and emulsion rates were much higher (roughly 35 m3/d and 260 m3/d respectively) and more consistent. Temperature and pressure had been maintained due to P1C steaming during the turnover, and by P2C steaming afterwards.

This increased production continued until mid-August when bottomhole pressure (BHP) became too low to operate the pump effectively. The temperature of the well was still fairly high (around 120˚C) and it seemed as if connectivity to the reservoir was the problem. To help clean out the wellbore and regain connectivity, the decision was made to use a very small slug (7m3) of diluent followed by a small steam slug (60 m3) at roughly 10 m3/hour. This short steam slug is referred to as mini-slug 4a. The well responded fairly well resulting in operable conditions although both oil and emulsion production was not as high as few months prior (likely due to the C wells

44 Laricina Energy Ltd. Saleski Pilot Project IETP Approval 05-077 Final Report having finished their injection phases). Although the prior rates could not be achieved, the productivity index (PI) had increased compared to just before the slug. The mini-cycle resulted in an improvement of the overall cycle metrics of calendar day oil rate (CDOR) and cycle steam to oil ratio (CSOR). The production lasted 11 days until a similar situation where BHP became too low to operate effectively.

Overall mini-cycle 4a was seen as a successful test resulting in a second test (mini-cycle 4b). The second test used similar injection rates but with a larger steam slug in the order of 510 m3 and no diluent injected prior. This test was even more successful leading to improved PI, CSOR, and CDOR. The oil rates seen from mini-cycle 4b were approximately 30 m3/d. Mini-cycle 4b lasted about a month until the BHP was too low to operate.

An even larger steam slug (mini-cycle 4c) of 1,100 m3 was injected at similar rates as the two previous mini-slugs. In late November, a pump failure occurred at P1D. It was not possible, due to well pad spacing limitations, to have a service rig change the pump with the drilling rig performing the sidetrack of P1C. P1D remained idle until drilling of the sidetrack was complete and the drilling rig could be demobilized. Pump replacement was performed after rig demobilization. After this idle period, it was observed that the temperature and pressure were maintained around the 1D reservoir due to 2C and 1C injection. The well was switched directly to production where it continued mini-cycle 4c. Mini-cycle 4c continued the trend with even better production metrics, although being somewhat aided by steaming in the C wells. Oil rates observed during the 4c production phase were the highest up to that point in time in Cycle 4. Cycle 4 continued into 2014 with over 340 total cycle days by the end of 2013. The use of mini- cycles will continue to optimize and understand the recovery process of the Grosmont D.

The production and injection rates maintained for the 1D well pair, as well as cumulative production and injection numbers, are illustrated in Figure 24 and Figure 25 respectively.

45 Laricina Energy Ltd. Saleski Pilot Project IETP Approval 05-077 Final Report

Figure 24: 1D Well Pair Injection and Production Rates

Figure 25: 1D Well Pair Cumulative Production and Injection Volumes

46 Laricina Energy Ltd. Saleski Pilot Project IETP Approval 05-077 Final Report

4.1.1.2 1C Well Pair (LEL ETAL 101 I1C and P1C Saleski 15-26-85-19)

At the beginning of 2013, P1C was three months into Cycle 4 production. Oil rates were between 40 to 50 m3/d and production continued for the first month. As the cycle’s pressure and temperature continued to decline, oil rates started to drop off as well. To avoid a steam conflict with P2C, Cycle 4 was truncated by an estimated 15 days. To enable plant maximum steam injection rates the piping and valves were upsized. An attempt to produce the well after the steam line upsizing resulted in a rod string breakage. The rod was replaced and steaming of Cycle 5 began shortly thereafter.

Steam rates of up to 770 m3/d were achieved and a total of 52,000 m3 CWE of steam was injected into P1C, until the June turnaround. The well soaked during the turnaround and Cycle 5 production began mid-June. Low and/or no subcool was observed and quench injection was used to improve pumping conditions. Eight (8) days into the production cycle the pump failed due to high torque and metal pieces were found in the gas anchor. The pump began production again on July 3, and required quench water again to handle subcool avoiding steam flashing. Production rates were poor resulting in the decision to change operating conditions to achieve more consistent flows. The changes included minimizing casing gas pressure and removing quench water. This had a positive effect on both oil and emulsion production which successfully connected the well to the reservoir. Quench water was added a few weeks later without negatively impacting operating conditions. Strong oil rates continued and water cuts declined as mid-October approached.

With observed steam flashing in P1C and higher well productivity in P2C, a recommendation and work plan to sidetrack P1C was completed. This was done in order to attempt to replicate the production performance of P2C. Cycle 5 was truncated to begin preparing the reservoir for the sidetrack.

To achieve acceptable drilling conditions, in a hot reservoir with depleted pressure (<1,500 kPa) complicated operations were required. For drilling to be successful the downhole temperature could be no higher than 125˚C and pressure had to be maintained close to 1,000 kPa. This required pressurizing the reservoir by steaming I1C for a time and then P2C when temperatures became too hot at the 1C reservoir. P2C continued to be steamed during sidetrack drilling of P1C to maintain pressure. This strategy resulted in successfully drilling of the P1C sidetrack 15 m to the East of the initial P1C lateral wellbore (which was abandoned).

The first steam slug for the sidetrack, Cycle 6 (continuation of P1C original cycle numbers), began in December with a total of 10,000 m3 CWE injected. This was a smaller steam volume

47 Laricina Energy Ltd. Saleski Pilot Project IETP Approval 05-077 Final Report than Cycle 5 (52,000 m3) since the sidetrack could take advantage of existing heat in the 1C reservoir.

The production and injection rates for the 1C well pair, as well as cumulative production and injection volumes, are illustrated in Figure 26 and Figure 27 respectively.

Figure 26: 1C Well Pair Injection and Production Rates

Figure 27: 1C Well Pair Cumulative Production and Injection Volumes

48 Laricina Energy Ltd. Saleski Pilot Project IETP Approval 05-077 Final Report

4.1.1.3 2D Well Pair (LEL ETAL 101 I2D and P2D Saleski 15-26-85-19)

In early 2013, I2D was still in the Cycle 2 injection phase. The low Cycle 2 steam rates and the inconsistency of these rates are due to I2D having a lower priority for steam compared to the other wells. I2D was used as a well where steam could be injected when no other wells required steam, to maintain boiler(s) operation and surface emulsion temperature. Steam during January was being focused on I1D steaming as the well pair was in the middle of a SAGD test, the excess steam during this time was injected into I2D. In February the well was transitioned to production for a week resulting in fairly good oil rates up to 30 m3/d but the temperature and pressure quickly dropped making practical pump operation difficult. The quick decline in temperature and pressure are likely due to the low, sporadic injection rates during Cycle 2 injection.

I2D Cycle 3 steam slug size was designed to emulate the P1D Cycle 2 steam volume of roughly 4,000 m3 with more consistent steaming than previous cycles. The well came off of Cycle 3 steam injection in early February and immediately began production. The well had high casing gas flow rates and difficulty maintaining pump efficiency. Once I2D casing pressure was reduced by allowing the well to produce to its own casing gas separator, production began to stabilize. Oil rates of approximately 15 m3/d were observed for several weeks. Pressure and temperature began to drop off resulting in declining production. Several brief shutdowns occurred and pressure quickly increased to 900 kPa. These increases in pressure briefly improved rates but it was not sustainable, as it quickly dropped off again. In late March the metal to metal PCP failed and a workover was performed to replace it with an elastomer PCP. In April, production resumed but the bottomhole temperature (BHT) and BHP readings were no longer available since this was not installed on the elastomer PCP. After the well stabilized the rates were similar to before for roughly a week until they began dropping off. The well continued to produce at low oil rates until the June turnaround. The production cycle was at an end and steam was unavailable as it was being utilized at the higher priority wells. I2D remained shut-in until late August when steam became available again.

For Cycle 4 a much larger steam slug of 35,000 m3 CWE was injected at rates as high as 630 m3/d. Cycle 4 production began in early November but steam flashing up the production string became an issue. Quench water was utilized as a strategy to try and combat the steam flashing issue. As the design of the long string included perforations near the pump intake the quench water only added to steam flashing and did not improve operating conditions. A workover was completed to install a temperature fibre along the horizontal. It was observed that fluid was only being produced from the first 250 m of the well (heel) and that the remaining portion of the well (toe) was cooling due to immobile fluid. Attempts were made to gain access to the toe half of the well with no success. One attempt included inserting coil tubing down the

49 Laricina Energy Ltd. Saleski Pilot Project IETP Approval 05-077 Final Report long string to bypass the perforations, by the pump intake, and inject quench water farther along in the horizontal where the interface between the mobile and immobile fluid was located. This did not result in significant improvement.

It was concluded that the trajectory of the well and the location of the pump contributed to the inability to effectively produce fluids. The pump intake was moved to a more optimized location (below a potential gas/liquid interface in the horizontal) and this improved production from the well in early 2014.

The production and injection rates for the 2D well pair, as well as cumulative production and injection volumes, are illustrated in Figure 28 and Figure 29 respectively.

Figure 28: 2D Well Pair Injection and Production Rates

50 Laricina Energy Ltd. Saleski Pilot Project IETP Approval 05-077 Final Report

Figure 29: 2D Well Pair Cumulative Production and Injection Volumes

4.1.1.4 2C Well Pair (LEL ETAL 101 I2C and P2C Saleski 10-26-85-19)

P2C was one month into Cycle 3 production at the start of 2013. The well had produced at very strong rates to the end of 2012 (peak of 151 m3/d and average of 100 m3/d) with rates gradually declining. In early January, a gas separator was installed at the intake of a newly installed metal PCP pump. After this brief three (3) day workover rates peaked again at 142 m3/d and followed a similar decline as that of the beginning of Cycle 3 production. Production continued to decline gradually until mid-March when the metal PCP was replaced with an elastomer PCP to test the effectiveness of elastomer PCPs in the later portion of cycle production.

Although the elastomer pump operated at a high efficiency with high emulsion rates, steaming of the offsetting P1C well resulted in drastically increased water cuts (averaging 98%) and therefore little oil production. Production operations continued until late April when the first elastomer PCP was replaced with an upsized elastomer PCP to improve the fluid removal rate. The larger elastomer pump continued to produce at high water cuts and emulsion rates. Oil cuts began to improve as more fluid was drained from the reservoir. Production was continued until the June turnaround.

After the June turnaround, a SAGD test was performed with the 2C well pair to better understand SAGD operation once cyclic operation and partial depletion had been performed. The test was also used to understand how the differences in completion, compared to the other well pairs, would affect SAGD performance. The test lasted roughly a month. The well pair however was

51 Laricina Energy Ltd. Saleski Pilot Project IETP Approval 05-077 Final Report producing at high water cuts (+90%) and the resulting oil rates were too low to justify further SAGD operation.

Immediately after the SAGD test, Cycle 4 injection began. Both I2C and P2C were utilized to inject steam as quickly as possible. Early production rates were very strong with a peak of 142 m3/d, and average of roughly 80 m3/d. The use of quench water to reduce flashing, and fairly consistent pump rates resulted in consistent performance during Cycle 4 with no required workovers. The production metrics for this cycle once again provided ample evidence that commercial production is possible from the Grosmont. Cycle 4 was truncated in order to prepare the reservoir for P1C sidetrack drilling.

Cycle 5 injection began in late November, first to pressure up the reservoir (as mentioned in the 1C section above), then concurrent injection along with the newly drilled P1C sidetrack well. Injection in both P2C and the P1C sidetrack continued through the end of 2013.

The production and injection rates for the 2C well pair, as well as cumulative production and injection volumes, are illustrated in Figure 30 and Figure 31 respectively.

Figure 30: 2C Well Pair Injection and Production Rates

52 Laricina Energy Ltd. Saleski Pilot Project IETP Approval 05-077 Final Report

Figure 31: 2C Well Pair Cumulative Production and Injection Volumes

The composite injection and production data is also included in Figure 32 and Figure 33 shown below, which illustrate the combined production and injection from the 1C (both original and sidetrack), 1D, 2C and 2D well pairs throughout the year. The first graph illustrates the production/injection rates, while the second figure illustrates cumulative production/injection to date.

Figure 32: Total Production and Injection Rates from all Well Pairs

53 Laricina Energy Ltd. Saleski Pilot Project IETP Approval 05-077 Final Report

Figure 33: Total Cumulative Production and Injection Volumes from all Well Pairs

4.1.2 Composition of Injected and Produced Fluids

4.1.2.1 Bitumen Analysis

As of December 31st 2012, the density of bitumen produced from all wells ranged from 6-7° API (Figure 34). Figure 35 shows that the total sulphur content of the produced bitumen from both Grosmont C and D Formations range between 3 to 5 wt.%. These fluid properties remained consistent with the results obtained in 2012.

Figure 36 illustrates that there is minimal variation between the Grosmont C and Grosmont D bitumen viscosity.

54 Laricina Energy Ltd. Saleski Pilot Project IETP Approval 05-077 Final Report

Figure 34: Density of Bitumen

Figure 35: Total Sulphur Content of Bitumen

55 Laricina Energy Ltd. Saleski Pilot Project IETP Approval 05-077 Final Report

Figure 36: Bitumen Absolute Viscosity

4.1.2.2 Produced Water Analysis

The sample taken from the Free Water Knock Out (FWKO) stream showed that produced water hardness averaged between approximately 50 and 300 mg/L (

Figure 37), with a few outliers within 600 mg/L. All wells showed hardness below 300 mg/L for the most part, with a few outliers within 500 mg/L.

Figure 38 shows the chloride and sodium content off of the FWKO stream ranges between 200 - 1,800 mg/L, which followed a downward trend. Figure 39 shows that this higher salinity water at the FWKO early on came from the C wells.

56 Laricina Energy Ltd. Saleski Pilot Project IETP Approval 05-077 Final Report

Figure 37: Produced Water Total Hardness

Figure 38: Produced Water Chloride and Sodium Content

57 Laricina Energy Ltd. Saleski Pilot Project IETP Approval 05-077 Final Report

Figure 39: Produced Water Salinity

4.1.2.3 Produced Gas Analysis

The produced gas from casing gas separator #1 that was methane (CH4) varied between 20 and

80 mol% usually around 50 mol%. Carbon dioxide (CO2) often made up most of the rest of the gas (in terms of mol %) ranging between 15 and 75 mol% carbon dioxide (

Figure 40), typically around 45 mol%. The hydrogen sulfide (H2S) content of the produced gas from separator #1 ranged from 1,000 to 3,000 ppm in 2013 (Figure 41).

58 Laricina Energy Ltd. Saleski Pilot Project IETP Approval 05-077 Final Report

Figure 40: Produced Gas Content from Casing Gas Separator #1

Figure 41: Produced H2S Content from Casing Gas Separator #1

Until May 2013 produced gas from casing gas separator #2 was composed mainly of methane (60 to 80 mol%) and carbon dioxide (15 to 30 mol%) as shown in

59 Laricina Energy Ltd. Saleski Pilot Project IETP Approval 05-077 Final Report

Figure 42. This trend began to vary later in the year with methane dropping as low as 25 mol% and carbon dioxide reaching as high as 65 mol%. The hydrogen sulfide content of the produced gas from separator #2 was below 2,000 ppm in 2013 (Figure 43).

Figure 42: Produced Gas Content from Casing Gas Separator #2

Figure 43: Produced H2S Content from Casing Gas Separator #2

60 Laricina Energy Ltd. Saleski Pilot Project IETP Approval 05-077 Final Report

4.1.2.4 Bottomhole Pressure History

The surface equipment and steam piping (300# ANSI rating) have a maximum pressure limit of 3,500 kPag at the well modules. The BHP at the injection wells is measured with the use of blanket gas, while the BHP of the production wells is measured with the use of a bubble tube or pressure gauge either located at the heel or toe. The BHP profiles for 2013 for the 1D, 1C, 2D, and 2C well pairs are included below.

Figure 44: 1D Well Pair BHP Profile

Figure 45: 1C Well Pair BHP Profile

61 Laricina Energy Ltd. Saleski Pilot Project IETP Approval 05-077 Final Report

Figure 46: 2C Well Pair BHP Profile

Figure 47: 2D Well Pair BHP Profile

There is a significant difference between how pressure increases and peaks during injection for the C and D well pairs (See

Figure 44 - Figure 47). During injection at the C well pairs pressure increases quickly and then gradually levels off. When injection is complete the pressure drops quickly at first and then gradually declines. In contrast the BHP of the D well pairs tends to level off and plateau at a nearly constant pressure for an extended time and then drops abruptly.

The pressure communication between I1D and P1D seems to have decreased since the acid jobs performed in 2011. During the SAGD test in January it can be seen that the drawdown was much

62 Laricina Energy Ltd. Saleski Pilot Project IETP Approval 05-077 Final Report too large for sustainable SAGD operation to occur. It is important to keep in mind that both these wells use bubble tubes for pressure measurement and at times they could have been reading incorrectly and thus needed to be purged.

The 1C well pair experienced similar pressure incline and decline as previous years. A comparison between I1C and P1C injection is not possible because the pressure sensors were not operational for a large portion of the year (I1C was incorrect between February and July, and P1C was incorrect between august and end of year 2013). I1C is actually reading casing head pressure and is not an indicator of BHP due to potential variances in liquid level in the well.

P2C continued to show strong pressure communication with I2C throughout the year. The drawdown during the SAGD test in July was between 30 and 70 kPa which allowed for SAGD operation.

I2D showed similar pressure response to switching from injection to production compared to P1D. This includes steep increases and decreases in pressure. Pressure was only recorded during one injection phase in 2013 which was for Cycle 2 injection (only 4,000 m3). Since this injection volume was so small it was not possible to determine if I2D pressure plateaus like P1D. The BHP gauge readings were unavailable from April to November. Connectivity with the reservoir was questionable during Cycle 4 production and thus the pressure decline is not fully indicative of cyclic production in the D.

4.1.2.5 Temperature Measurement

The producers of all four well pairs (P1C, P1D, P2C and P2D) are equipped with a fibre optic sting to measure temperature and one was installed in I2D in November. There are 39 different temperature measurement points along the length of the fibre optic string, with 100 m spacing between the first four points below a true vertical depth of 100 m, and 25-27 m spacing between all the points thereafter. The initial reservoir temperature of the formation was determined to be approximately 15˚C.

Having real time temperature monitoring capabilities along the entire length of a well assists in determining the location of potential hot spots, where steam or hot fluid may preferentially be entering or leaving the wellbore. Access to temperature data also enables the production team to forecast the end of a production cycle, based on the observation of a temperature decline along the well horizontal. During a production cycle, operators will calculate and monitor the downhole subcool (the difference between the actual downhole temperature and the saturation temperature at the downhole pressure) at the pump intake. This ensures that steam is not flashing (water reaching its saturation temperature and rapidly vaporizing into steam) across the pump.

63 Laricina Energy Ltd. Saleski Pilot Project IETP Approval 05-077 Final Report

For the P1D temperature profile presented in Figure 48 the blue line represents January 10, a time in which the 1D well pair was performing a SAGD test. During this time much of the horizontal was at saturated conditions indicating steam breakthrough, resulting in poor rates and a less than successful SAGD test. The red line (April 7) represents early operation during Cycle 4. The toe half of the well was significantly hotter and at saturated conditions, resulting in poor production because only the heel half contributed. The green curve (July 31) shows Cycle 4 a few weeks before the first mini-slug was used. At this point in time the temperature conformance had greatly improved and the well was just below saturation conditions, which resulted in improved production. The orange line (October 13) shows the temperature response shortly after mini-slug 4c. Note the temperature profile is similar to the green line (July 31, before the mini- slugs) but roughly 15˚C hotter.

Figure 48: P1D Temperature Profile

The blue line presented in Figure 49 (February 13) on the P1C temperature profile represents when P1C was near the end of Cycle 4 production. The temperature was still fairly hot (roughly 130˚C) and this cycle was estimated to be capable of production for several weeks longer. The red line (June 17) shows the soak period after Cycle 5 injection. The temperature conformance is strong and the well is very hot (+200˚C) with portions of the toe near or at saturated conditions. The green line (August 4) represents when oil production from P1C began to improve during Cycle 5. Temperature along the horizontal held good conformance, whereas the toe cooled quicker than the rest of the well. The bottomhole pressure and temperature were below saturated conditions which allowed for most of the well to contribute to production. The orange curve

64 Laricina Energy Ltd. Saleski Pilot Project IETP Approval 05-077 Final Report

(November 15) shows the temperature profile just prior to the instrumentation fibre being removed from P1C in preparation for sidetrack drilling. The well became hot (+190˚C) and steam was directed shortly after toward P2C so that pressure would continue to rise but temperature was allowed to cool.

Figure 49: P1C Temperature Profile

P2C temperature response is presented in Figure 50. The blue curve (January 1) shows early Cycle 3 production where it was observed that several cold spots along the horizontal existed. The red line (May 28) represents temperature near the end of Cycle 3 production, temperature conformance has improved from the beginning. Interestingly even at a low of 95˚C P2C was capable of producing at fairly strong rates and may have continued Cycle 3 production had it not been shut-in for the June turnaround. The green curve (June 23) shows the temperature profile during the SAGD test, varying temperature points can be seen with the highest temperature points likely being where steam communication occurs. The orange line (November 1) represents the temperature near the end of Cycle 4. It can be seen the temperature along the well is much higher than that seen in the red line (which was the end temperature profile for Cycle 3). Therefore P2C may have produced for several more months had it not been required to begin Cycle 5 injection prematurely to support reservoir pressure during drilling of the P1C sidetrack.

65 Laricina Energy Ltd. Saleski Pilot Project IETP Approval 05-077 Final Report

Figure 50: P2C Temperature Profile

I2D temperature fibre was installed in November 2013 so there is limited data shown in Figure 51. In the two months that the fibre was installed a steep temperature gradient was observed, roughly 250 m into the horizontal (around 800 m MD). This temperature gradient becomes worse as I2D production continues. It is suspected, with supporting evidence that only the 250 m of I2D contribute significantly to production. The rest of the well experiences temperature decrease early in production which indicates fluid pooling at the middle and toe portions of the well, cooling, and ultimately becoming immobile.

Since P2D has not been operated, its temperature profile is significantly colder than the other producers. An exception was observed at a hot spot (up to a 130˚C) in between the middle and toe section which indicates that at 1,000 m MD P2D is exposed to convective heat transfer as a result of direct contact with fluid. A similar hot spot has begun developing closer to the heel around 650 m MD. This temperature response has been somewhat linked to P2C and I2D steaming.

66 Laricina Energy Ltd. Saleski Pilot Project IETP Approval 05-077 Final Report

Figure 51: I2D Temperature Profile

Figure 52: P2D Temperature Profile

67 Laricina Energy Ltd. Saleski Pilot Project IETP Approval 05-077 Final Report

4.2 Solvent Injection

There were no solvent injection tests during 2013. The testing of solvent injection and production enhancement was not covered in this phase of IETP funding.

For an overview of the solvent injection that has been performed at the Saleski Cold Solvent test, please refer back to Section 4.0 in the 2009 IETP Report under Approval 03-061.

5.0 Pilot Data 5.1 Laboratory Studies

No additional studies were performed in 2012 or 2013 associated with Saleski Pilot Project IETP Phase 2 Approval 05-077. Please refer to the 2011 Saleski Pilot Project IETP Phase 2 Approval 05-077 for details regarding studies previously summarized.

5.2 Simulations

Numerical simulation studies have been conducted applying a range of reservoir descriptions, from single porosity through to dual porosity models, providing valuable insights into the nature of the Grosmont reservoir and recovery processes. History matching has not determined a unique reservoir description with confidence, such that this work remains in progress. Current activities are underway to narrow the range of uncertainty in a number of key reservoir parameters, which will be incorporated in future studies.

5.3 Observation Well Data

The plots of temperature and pressure data collected from each of the 7 observation wells over the course of 2013 are included in the figures below.

It should be noted that the 2C well pair is only 450 m long. Therefore, there is limited temperature and pressure response from P2Obs3 which is located near the toe of the 800 m long 2D well pair and is too far to have been impacted by steam into the 2C well pair. In addition the lower steam volume injected into the 2D well pair also limited the temperature and pressure response at P2Obs3.

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P2Obs3 01/01/2013 P1Obs3 01/01/2013 01/05/2013 01/05/2013 pressure (kPag) 01/09/2013 pressure (kPag) 01/09/2013 290 31/12/2013 290 31/12/2013 wells wells 280 280

270 270

upper D 260 260 upper D

middle D

250 250 middle D mASL mASL 240 lower D 240 lower D

230 230

C 220 220 C

210 210

200 200 0 500 1000 1500 2000 2500 3000 3500 0 500 1000 1500 2000 2500 3000 3500 P2Obs2 01/01/2013 P12Obs2 01/01/2013 P1Obs2 01/01/2013 01/05/2013 01/05/2013 01/05/2013 pressure (kPag) 01/09/2013 pressure (kPag) 01/09/2013 pressure (kPag) 01/09/2013 290 31/12/2013 290 31/12/2013 290 31/12/2013 wells wells wells 280 280 280

270 270 270

260 260 260 upper D upper D upper D

250 middle D 250 middle D 250 middle D

mASL mASL mASL 240 lower D 240 240 lower D lower D

230 230 230

C 220 220 C 220 C

210 210 210

200 200 200 0 500 1000 1500 2000 2500 3000 3500 0 500 1000 1500 2000 2500 3000 3500 0 500 1000 1500 2000 2500 3000 3500 P2Obs1 01/01/2013 P1Obs1 01/01/2013 01/05/2013 01/05/2013 pressure (kPag) 01/09/2013 pressure (kPag) 01/09/2013 290 31/12/2013 290 31/12/2013 wells wells 280 280

270 270

260 260 upper D upper D 250 250 middle D

middle D mASL mASL 240 240 lower D lower D 230 230

C 220 220 C

210 210

200 200 0 500 1000 1500 2000 2500 3000 3500 0 500 1000 1500 2000 2500 3000 3500

Figure 53: Observation Well Pressure Plots

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P2Obs3 P1Obs3 Temp (˚C) Temp (˚C) 290 290 01-Jan-13 01-Jun-13 01-Jun-13 31-Dec-13 280 31-Dec-13 280 01-Jan-13 litho litho wells wells 270 270

upper D 260 260 upper D

middle D middle D

250 250 mASL 240 mASL lower D 240 lower D

230 230

C C 220 220

210 210

200 200 0 50 100 150 200 250 0 50 100 150 200 250

P2Obs2 P12Obs2 P1Obs2 Temp (˚C) Temp (˚C) Temp (˚C)

290 290 290 01-Jan-13 01-Jan-13 01-Jan-13 01-Jun-13 01-Jun-13 01-Jun-13 280 280 280 31-Dec-13 31-Dec-13 31-Dec-13 litho litho litho wells 270 270 wells 270 wells

260 260 260 upper D upper D upper D middle D

250 middle D 250 middle D 250

mASL mASL mASL 240 lower D 240 240 lower D lower D

230 230 230

C C 220 220 220 C

210 210 210

200 200 200 0 50 100 150 200 250 0 50 100 150 200 250 0 50 100 150 200 250

P2Obs1 P1Obs1 Temp (˚C) Temp (˚C) 290 290 01-Jan-13 01-Jan-13 01-Jun-13 01-Jun-13 280 31-Dec-13 280 31-Dec-13 litho litho wells wells 270 270

260 260 upper D upper D middle D 250 250

middle D

mASL mASL 240 240 lower D lower D

230 230 C C 220 220 C

210 210

200 200 0 50 100 150 200 250 0 50 100 150 200 250

Figure 54: Observation Well Temperature Plots

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5.4 Interpretation

5.4.1 1C Well Pair The first steam into the 1C well pair (both injector and producer) commenced on January 30, 2011. Throughout 2011, there were a total of six (6) traditional SAGD production cycles, where steam injection was maintained through the injector while the producer was on production.

Overall, the 1C well pair had very few equipment issues resulting in the well having long production cycles. The longest uninterrupted 1C well production cycle lasted from late June to September, 2011. The steam injection rate for that period ranged between 200-250 m3/d and the oil production rate ranged from 20-50 m3/d.

During the third quarter of 2011, the emulsion and oil rate being produced from the P1C well was observed to increase after the injector steam was decreased or shut off. This led to the first cyclic test (Cycle 1) where no steam was injected. Cycle 1 started in November and ended in December, 2011. The results from Cycle 1 were then compared to the traditional dual well SAGD production cycles that had occurred up to that point. In the traditional SAGD production cycles, the 1C well produced 13 m3/d of oil compared to approximately 70 m3/d of oil under cyclic operation. The favorable results from this single well test lead to the testing of the 1D well pair under cyclic operation. All wells have now been switched to cyclic operations.

Table 11: Production Performance Indicators for 1C well pair 1C Performance CDOR (m3/d) Peak Rate (m3/d) CSOR Cum. Oil (m3) Steam (m3) SAGD Warm-up and Production Jan - Nov 2011 13 94 12 3,773 44,326 SAGD/Cycle #1 Nov - Dec 2011 71 129 0.8 2,195 1,685 SAGD Dec 2011 - Jan 2012 5 24 45 170 7,570 Cycle #2 Jan - May 2012 33 128 4.4 3,680 16,319 Cycle #3 May - Aug 2012 14 41 9.5 1,286 12,276 Cycle #4 Aug 2012 - Mar 2013 23 73 5.0 4,831 24,319 Cycle #5 Mar - Oct 2013 17 89 13 4,016 52,307 Cycle #6 (P1Cs) Dec 2013 - Present 24 76 2.5 4,126 10,502 Three additional cycles took place in 2012, where steam was injected and oil produced from the same well. Cycle 2 yielded a peak oil rate of 128 m3/d and a CSOR of 4.4. For Cycle 3, the steam volume injected was sized to test matrix productivity which resulted in an insufficient steam volume to expand the heat affected zone. This resulted in a production cycle that underperformed previous cycles. Furthermore, Cycle 3 production was terminated prematurely due to a hole in the production tubing. Following tubing replacement, steam injection for Cycle 4 was started with a much larger steam volume and followed up with solvent co-injection later in the injection cycle (September 5, 2012) to evaluate its impact. Production for Cycle 4

71 Laricina Energy Ltd. Saleski Pilot Project IETP Approval 05-077 Final Report commenced on September 29, 2012. Cycle 4 production was prematurely ended on February 14, 2013 to manage steam scheduling, and resulted in a cycle 4 SOR of 5.1 and a CDOR of 25 m3/d. The CSOR was forecasted to be 4.6 when extrapolated to the predicted cycle end. Evaluation of the impact of diluent injection in the Grosmont is ongoing; however, cyclic operation continues to establish baseline data prior to advancing diluent injection at the Pilot.

Immediately after the end of Cycle 4, steam line piping and valves were upsized to allow for plant maximum steam rates to be injected during Cycle 5 injection. The steam slug volume for Cycle 5 was targeted to be 52,000 m3 (115% increase from Cycle 4). This volume was based on latent heat required to reheat the partially depleted zone. Steaming was continued until the June turnaround in P1C. The well soaked for 16 days (during the plant turnaround) and production began in mid-June 2013. Production was poor early on due to subcool issues and communication with P2C steaming. Rates eventually improved in August and significant production was achieved. A total of 4,000 m3 (CSOR of 13 and a CDOR or 17 m3/d) of oil was produced by late October 2013. The cycle was truncated at this point and P1C and I1C were put on steam injection to prepare the reservoir for the sidetrack drilling.

The decision to sidetrack the P1C well was based on the desire to replicate the production performance of P2C.

Figure 55 below presents the 1C well pair steaming and production profile from the start of operations to the end of 2013. The steam rate presented is the combined injector and producer rates.

Figure 55: Production and Injection Rates for 1C Well Pair from Start-up to End of 2013

72 Laricina Energy Ltd. Saleski Pilot Project IETP Approval 05-077 Final Report

5.4.2 1D Well Pair Steam injection into the 1D well pair commenced on December 24, 2010. Steam was injected down both the injector and producer wells with no circulation. Several SAGD tests were performed with limited success, poor conformance and steam breakthrough at times.

The pressure difference between the 1D well pair led to two acid stimulations in October and November of 2011. Immediately following the stimulations the pressure difference was reduced between the injector and producer but the fluid rate did not improve.

Over the course of 2011, P1D experienced many difficulties related to downhole equipment and tubing, which required a number of workovers. In contrast P1C, which had a very similar completion design to the P1D, required only one workover in 2011. In February 2012, following the successful cyclic operation of P1C, P1D was converted.

The 1D well pair in SAGD operations achieved an average oil rate of approximately 10 m3/d during the SAGD production tests. Cycle 1 production for the P1D well achieved a peak oil rate of 67 m3/d, a CDOR of 13 m3/d and a CSOR of 18.8. This demonstrated an improvement over SAGD operation but not as drastic as that observed in the C zone. As a result the well was shut- in for an observation period to determine the extent of communication with the underlying C zone.

During the P1C Cycle 3 steam injection, when P1D was under an observation period, a temperature response was observed at the toe of P1D (Figure 56 below). This was the first confirmed identification of localized temperature communication between the C and D reservoirs. After a two month observation period, a small steam volume for Cycle 2 was injected. Cycle 2 achieved a CSOR of 1.6, demonstrating significantly higher production rates (up to 111 m3/d) and a CDOR of 28 m3/d and provided the line of sight to exploitation of the Grosmont D Formation through cyclic operations.

P1D Cycle 3 steam injection started October 5, 2012 with a steam injection volume of 5,227 m3. Production resumed immediately following the injection period and continued for 62 days. During the cyclic production period, peak oil rate of 89 m3/d was achieved along with a CDOR of 34 m3/d and a CSOR of 1.9. These results demonstrated the repeatability of exploiting the Grosmont D under cyclic conditions and provided confidence that this interval can also be economically produced under cyclic operations.

At the conclusion of the cyclic production period, a brief SAGD test was conducted. The purpose of this test was to determine if a partially depleted reservoir and increased reservoir maturity would result in improved conformance and drawdown. Steam injection into I1D commenced on

73 Laricina Energy Ltd. Saleski Pilot Project IETP Approval 05-077 Final Report

December 23 and within hours, direct steam communication with the P1D well was established. Efforts were made to reduce steam breakthrough but this was not achieved and consequently resulted in poor production. The test was terminated in January 2013. This test indicated that the current well spacing is not adequate for SAGD operation in the Grosmont D.

After the SAGD test, P1D was put back on steam injection for Cycle 4. The total steam volume injected was roughly 14,000 m3; pressure began to plateau at around 2,000 kPag when the injection volume reached roughly 5,000 m3. This was the first indication that pressure in the D zone responds differently than the C. Production began in mid-March 2013 but suffered from low and or no subcool. P1C was on Cycle 5 injection during this time helping to maintain the hot temperature at P1D. This helped to extend the cycle in the long run but resulted in poor production, early on. Quench water was utilized for the first time at the Pilot in April in an attempt to manage subcool with limited success. The well continued with poor performance and subcool issues until the June turnaround. After the turnaround P1C had switched to production and shortly after P1D began to see lower water cuts, less issues with subcool and improved oil production. For the next few months P1D was able to produce at significant rates as temperature and pressure gradually declined. In August 2013, production began to decline and it appeared that subcool issues had reappeared, fluid column was running low, and P1D was losing communication with the reservoir.

To reconnect the well with the reservoir the well was shut in to build pressure and fluid level. A small amount of diluent (7 m3) was injected to help clean out the near wellbore followed by steam (60 m3) to ensure the diluent was pushed to the entire horizontal length. The well was turned back to production improving both rates and BHP. This lasted for 11 days before low BHP caused operational difficulties. Overall this test, mini-cycle 4a, was deemed successful at reconnecting the well with the reservoir and helped to improve productivity index. Another mini- slug (4b) was injected immediately after, this slug was 500 m3 injected at the same rate as 4a. Productivity index and CDOR continued to improve while CSOR continued to decline. Subsequent mini-cycles were performed at the same rate but with larger volumes helping to improve the overall CSOR, CDOR, productivity index, and longevity of the cycle. During mini- cycle 4c both P2C and the 1C well pair were steamed to prepare for P1C sidetrack drilling. P1D benefitted from this operation in terms of both heat and pressure, helping to extend the mini- cycle. Mini-cycle operation continued to the end of 2013. Due to the success of the mini-cycles further optimization and understanding of them has continued into 2014.

74 Laricina Energy Ltd. Saleski Pilot Project IETP Approval 05-077 Final Report

Table 12: Production Performance Indicators for 1D Well Pair 1D Performance CDOR (m3/d) Peak Rate (m3/d) CSOR Cum. Oil (m3) Steam (m3) SAGD Warm-up and Production Dec 2010 - Feb 2012 3 37 36 1,418 50,779 Cycle #1 Feb - July 2012 6 67 19 930 17,411 Cycle #2 Jul - Oct 2012 25 111 1.6 1,796 2,892 Cycle #3/SAGD Test Oct 2012 - Jan 2013 28 89 2.9 3,130 8,922 Cycle #4 Jan 2013 - Present 18 61 2.1 8,957 19,074

Table 13: Production Performance Indicators for 1D Well Pair Cycle 4 Mini-Cycles

1D Cycle 4 Mini-Cycle Performance CDOR (m3/d) Peak Rate (m3/d) CSOR Cum. Oil (m3) Steam (m3) 4a Aug. 25 - Sept. 5 11 21 0.5 123 60 4b Sept. 6 - Oct. 1 23 40 1 577 510 4c Oct. 2 - Mar. 18 25 60 0.3 4,237 1,136

Figure 56 presents the 1D well pair steaming and production profile from the start of operations to the end of 2013. The total steam rate presented is the combined injector and producer rates.

Figure 56: Production and Injection Rates for 1D Well Pair from Start-up to End of 2013

75 Laricina Energy Ltd. Saleski Pilot Project IETP Approval 05-077 Final Report

Figure 57: P1D Temperature Fibre (May –June Observation Period) 5.4.3 2D Well Pair

The first steam into the I2D well commenced on August 11, 2012 with injection continuing until the end of August. The objective of the test was to observe cyclic potential in an undisturbed area of the Grosmont D Formation. The P2D well was used as the observation well for this test. The I2D well received approximately 16,000 m3 of steam and produced daily volumes with high water cuts for a production period of 22 days. Due to a lack of steam availability the well was left idle for two weeks until injection operations could resume. I2D was used as a well where steam could be injected when no other wells required steam, to maintain boiler(s) operation and surface emulsion temperature. Because of the low volumetric steam rates and subsequent reduced heating efficiency, the first cycle of I 2D produced for only 3 weeks.

Cycle 2 produced for 7 days and exhibited similar characteristics to the previous cycle with fluid volumes reaching approximately 40 m3/d with a high water cut ratio. Temperature and pressure quickly dropped off and operation of the well became too difficult to continue.

After this brief production period, I2D was placed back on steam injection for Cycle 3. Injection rates were approximately 350 m3/d for a total steam slug volume of approximately 4,000 m3. This volume was similar to P1D Cycle 2, which resulted in a successful cycle in the same formation. When the well returned to production oil rates were initially better than the previous two cycles reaching up to 35 m3/d early on. After an idle period of two week in late March early April an elastomer PCP was installed at I2D. This pump operated at high efficiencies, improved emulsion rates, but high water cuts (>95%) at low pump speeds. The rates did decline back to

76 Laricina Energy Ltd. Saleski Pilot Project IETP Approval 05-077 Final Report those seen during the first two cycles. Operation continued for roughly two months until the June turnaround at which time 2D reservoir conditions indicated the end of its cycle. After the June turnaround I2D remained idle until late August due to steam being allocated to other wells. At this time a dedicated steam volume of 35,000 m3 was injected for Cycle 4 at rates of 540 m3/d in an attempt to drastically increase the steam chamber and heat affected zones. When the well was brought onto production in November subcool issues were immediately apparent. Quench water was injected at several locations and a temperature fibre was installed to try and diagnose what was occurring downhole. The quench water did not help to correct the issues but the temperature fibre helped to identify that the first 250 m MD were contributing to production and that the remaining portion of the well (toe) was cooling due to immobile fluid. I2D operated similarly until the end of 2013. With further troubleshooting in 2014 it was discovered that placement of the pump contributed to poor performance of the well during Cycle 4. Moving the pump intake location to a slightly lower TVD and eliminating the use of quench water has helped to improve rates in 2014.

Table 14: Production Performance Indicators for 2D Well Pair 2D Performance CDOR (m3/d) Peak Rate (m3/d) CSOR Cum. Oil (m3) Steam (m3) Cycle #1/Warm-Up Aug 2012 - Nov 2012 1 15 124 128 15,844 Cycle #2 Nov - Jan 2013 1 34 183 86 15,806 Cycle #3 Jan 2013 - Aug 2013 4 35 5.2 758 3,958 Cycle #4 Aug 2013 - Jan 2014 2 22 144 249 35,935

Figure 58presents the 2D well pair steaming and production profile from the start of operations to the end of 2013. The total steam rate presented is the combined injector and producer rates.

Figure 58: Production and Injection Rates for 2D Well Pair from Start-up to End of 2013

77 Laricina Energy Ltd. Saleski Pilot Project IETP Approval 05-077 Final Report

5.4.4 2C Well Pair

The 2C well pair was drilled in early 2012 at a shorter horizontal well length of 450 m versus the traditional 800 m (SAGD well pairs). This shorter well length was to accommodate the limited steam capacity at the plant. The well pair was drilled at balanced pressure and acid stimulated immediately after drilling and completed without a liner (i.e. open hole).

The first steam into the 2C well pair (both injector and producer) commenced on May 14, 2012. Steam Cycle 1 ended after 7,500 m3 of steam was injected and was immediately followed by production. Cycle 1 achieved peak rates greater than 200 m3/d, a CDOR of 24 m3/d and a cycle SOR of 6.5. This was followed by injection Cycle 2 which had a steam volume of 14,200 m3; nearly a 90% increase to the previous steam cycle. Cycle 2 injection was completed on August 10, 2012 and production Cycle 2 ended in early October 2012. Cycle 2 achieved an SOR of 3.4 and peak oil rate of 200 m³/d. These results further provide confidence in the commercial development plan of the Grosmont Formation at Saleski.

Cycle 3 steam injection began October 20, 2012 following de-bottlenecking efforts to increase the diameter of the steam injection piping thus increasing the steam capacity to greater than 700 m3/d. Steam injection continued for 48 days for a total injection volume of approximately 30,000 m3. The de-bottlenecking efforts have provided significant line of sight to the high injectivity potential of the Grosmont C. Early production from Cycle 3 produced strong rates yet again, averaging roughly 90 m3/d for the first 40 days. In February an elastomer PCP was installed to test this form of artificial lift later in the life of the cycle. The elastomer pump operated with very good efficiencies and improved emulsion production but drastically reduced oil cuts (from 50% to 5%). The drop in oil cuts also corresponded to P1C steaming, indicating that water was communicating between wells approximately 90m apart. The first elastomer pump was replaced with an upsized elastomer pump to help increase fluid removal (BHP was still rising even with 500+ m3/d of emulsion being produced). The larger elastomer PCP increased emulsion production briefly and did not have to operate at nearly the same speed as the smaller one and oil cuts improved slightly. P2C continued operation in this way until the June turnaround.

Following the June turnaround a SAGD test was performed on the 2C well pair. The test indicated SAGD operation was sustainable, although with high water cuts and low oil rates when compared to what was achieved through cyclic operation.

After the SAGD test 40,000 m3 of steam was injected into both P2C and I2C to maximize steam heat transfer efficiency and CDOR. Oil rates out of P2C peaked early (142 m3/d) indicating production from the fractures may initially dominate flow. Oil production on average remained over 90 m3/d for 53 days indicating that early production can remain very strong even after the

78 Laricina Energy Ltd. Saleski Pilot Project IETP Approval 05-077 Final Report oil from the fractures is produced. Gradual production decline continued until November when the cycle was truncate to help prepare the C reservoir for P1C sidetrack drilling. The cycle ended with temperatures around 130˚C. P2C could have likely continued to produce until it reached the temperature of the previous cycles (90˚C). Meaning that P2C could have produced for several more months according to temperature decline analysis.

P2C ended 2013 in the middle of Cycle 5 injection at varying rates to help manage the complex temperature and pressure requirements for sidetrack drilling.

Table 15: Production Performance Indicators for 2C Well Pair 2C Performance CDOR (m3/d) Peak Rate (m3/d) CSOR Cum. Oil (m3) Steam (m3) Cycle #1/Warm-Up May - June 2012 25 201 6.6 1,160 7,633 Cycle #2 June - Oct 2012 38 200 3.4 4,211 14,229 Cycle #3 Oct 2012 - May 2013 30 151 4.3 6,932 29,918 SAGD Test Jun - July 2013 16 31 21 358 7,641 Cycle #4 July - Nov 2013 49 142 4.8 6,531 31,630 Cycle #5 Nov 2013 - Present 31 94 5.4 6,391 34,747 Figure 59 presents the 2C well pair steaming and production profile from the start of operations to the end of 2013. The total steam rate presented is the combined injector and producer rates.

Figure 59: Production and Injection Rates for 2C Well Pair from Start-up to End of 2013

79 Laricina Energy Ltd. Saleski Pilot Project IETP Approval 05-077 Final Report

6.0 PILOT ECONOMICS

6.1 Bitumen Sales Volumes

Table 16 summarizes the gross bitumen and diluted bitumen volumes from the Pilot.

Table 16: Gross Production and Sales volumes for 2013 Crude Bitumen Crude Bitumen Blended Diluted Month Production (m3) Sales (m3) Bitumen Sales (m3) January 3518.0 3,486 4,215.2 February 1742.0 1,777.2 2,208.2 March 872.0 987.7 1,224.5 April 483.7 488 611.8 May 999.0 1,414.7 1,741.3 June 806 334.8 427.3 July 1520.3 1,651.9 2,080.5 August 3532.2 3,366.2 4,051.9 September 4774.8 4,846.6 5,798.5 October 3453.0 3,596.5 4,369.8 November 455.4 456.7 566.7 December 513.2 261.5 326.8 Total 22,669.6 22,667.8 27,622.5

6.2 Revenue

Table 17 displays revenue from bitumen sales from the Pilot. Please note that the below numbers have been adjusted for handling charges (i.e. sales value – handling cost = blended dilbit bitumen revenue).

Table 17: Revenue - Bitumen Sales for 2013

Crude Bitumen Blended Diluted Month Revenue ($) Bitumen Revenue ($) January 528,923 1,090,767 February 264,088 600,630 March 163,898 343,680 April 98,573 192,876 May 348,913 598,589 June 63,008 131,121 July 521,130 855,023 August 1,298,246 1,810,227 September 1,423,562 2,105,377

80 Laricina Energy Ltd. Saleski Pilot Project IETP Approval 05-077 Final Report

Crude Bitumen Blended Diluted Month Revenue ($) Bitumen Revenue ($) October 881,137 1,423,943 November 74,007 145,421 December 40,894 87,602 Total 5,706,379 9,385,256 6.3 Capital Costs – Facilities See Table 18 - Table 24 below for the capital costs associated with the Pilot facility.

This IETP approval does not include the solvent (SC-SAGD) portion of the project. The cost of the solvent equipment was estimated to be approximately $4 million in the application.

After reviewing the actual project costs, it was determined that the solvent equipment costs were approximately 14% of the total equipment costs. The CPF was constructed as a single plant and the cost of the solvent portion cannot be directly applied, as such the 14% was used to estimate the total cost of the facility without the solvent, as described below:

 Equipment, engineering and construction were reduced by 14%;  Supervision/inspection and camp use charges were reduced by 7%;  Commissioning costs were not required to be reduced as the commissioning costs for the solvent equipment were tracked separately.

Table 18: Summary of the Pilot Facility Costs ($) Gross Pilot Gross Prior Years Project with Year of 2011 Total Pilot Pilot Facility Costs 2007-2010 Cost of Solvent Project Removed ($) ($) ($) ($) Engineering 14,346,506 1,045,639 15,392,146 13,228,570 Supervision/Inspection 1,295,024 399,188 1,694,212 1,575,140 Equipment 18,379,577 1,451,062 19,830,639 17,043,172 Fabrication & Construction 25,913,261 14,158,064 40,071,325 34,438,754 Commissioning 686,372 3,991,906 4,678,278 4,678,278 Camp Use Charges 3,009,899 4,516,026 7,525,924 6,996,989 Total ($) 63,630,639 25,561,885 89,192,524 77,960,903

No additional facility costs in 2012 or 2013 associated with Saleski Pilot Project IETP Phase 2 Approval 05-077 .

81 Laricina Energy Ltd. Saleski Pilot Project IETP Approval 05-077 Final Report

Table 19: Detailed Costs of the Pilot Equipment ($) GROSS ($) Pilot Equipment Costs 2008-2010 2011 Total Tanks 1,740,683 2,390 1,743,073 Building - Office 543,240 0 543,240 Equip Setting 81,752 11,004 92,756 Survey 8,294 0 8,294 MCC 16,803 65,944 82,747 Mechanical Equipment 2,462,764 0 2,462,764 Filtration Equipment 695,135 20,300 715,435 Power Generators 2,155,118 291,720 2,446,838 Instrumentation - Control Valves 121,397 178 121,575 Electrical Equipment - Cable 212,273 3,390 215,663 Piping - Fittings 125,288 0 125,288 IGF (Includes Gas Floatation) 21,809 0 21,809 Packaged Equipment 0 220,029 220,029 Equipment Rentals 205 0 205 Heat Exchangers - Shell & Tube 1,366,067 0 1,366,067 Pumps - Ansi 1,068,939 35,053 1,103,992 Flare Stacks 54,535 0 54,535 Heater 2,737,685 -60,710 2,676,975 Separators 2,542,718 99,157 2,641,875 Instrumentation Instruments 0 6,902 6,902 Compressors 793,294 608,765 1,402,059 Treater 878,992 95,480 974,472 Inspection & Quality Control 40,367 7,335 47,702 Rotating Equipment 428,169 1,088 429,257 Health & Safety 17,931 0 17,931 Trucking Heavy Haul 0 28,190 28,190 Regulatory Fees / Licences 348 3,293 3,641 Building - Process 191,327 0 191,327 Air Handling 0 5,771 5,771 Overhead 74,445 5,784 80,228 Total ($) 18,379,577 1,451,062 19,830,639

No additional equipment costs in 2012 or 2013 associated with Saleski Pilot Project IETP Phase 2 Approval 05-077.

82 Laricina Energy Ltd. Saleski Pilot Project IETP Approval 05-077 Final Report

Table 20: Detailed Costs of the Pilot Fabrication and Construction GROSS ($) Pilot Fabrication & Construction 2009-2010 2011 Total Garbage Disposal 14,290 32,241 46,531 Fuel 18,873 90,668 109,541 Trucking - Legal Loads 235,590 175,310 410,899 Piping - Pipe 0 4,090 4,090 Aviation Support 15,212 15,025 30,238 Construction Office 225,298 293,712 519,009 Propane Bullets 0 952 952 Insulation Contractor 0 674,653 674,653 Liner Contractor 4,525 112,257 116,782 Piling 739,198 121,696 860,894 Tanks 0 -2,425 -2,425 Structural 0 8,777 8,777 Earthworks -Rd 9,324 5,136 14,459 Mechanical Contractor 18,259,217 8,401,996 26,661,213 Electrical Contractor 52,164 2,044,483 2,096,647 Building - Office 0 12,483 12,483 Instrumentation Contractor 0 29,153 29,153 Equipment Setting 1,361,887 342,388 1,704,274 Survey 47,840 37,220 85,060 Hydro Vac 0 71,935 71,935 Civil Labour 207,146 0 207,146 Mechanical Equipment 503,238 271 503,509 Filtration Equipment 0 9,652 9,652 Steam Generators 0 10,255 10,255 Brokerage Fees 0 227 227 Instrumentation - Control Valves 2,130,494 142,165 2,272,659 Line Location 700 0 700 Electrical Equipment - Cable 98,069 31,777 129,846 Specialty Items 0 2,314 2,314 Piping - Fittings 362,107 300,404 662,511 Communication Equipment 14,997 6,655 21,652 Equipment Rentals 16,900 89,268 106,168 Consumables 1,187 8,906 10,093 Heater 0 9,108 9,108 Instrumentation Instruments 441,780 78,771 520,550 Compressors 0 11,749 11,749 Inspection & Quality Control 453,591 514,875 968,466 Earthworks - Site Prep / Geotextile 29,190 48,553 77,743 Tools, Equipment & Machinery 2,000 0 2,000 Health & Safety 3,579 45,038 48,617

83 Laricina Energy Ltd. Saleski Pilot Project IETP Approval 05-077 Final Report

GROSS ($) Pilot Fabrication & Construction 2009-2010 2011 Total Trucking Heavy Haul 508,551 216,088 724,638 Trucking - Hot Shot 1,750 0 1,750 Building - Warehouse 0 0 0 Building - Process 0 81,898 81,898 Piping - Manual Valves 33,529 1,300 34,828 Miscellaneous 595 0 595 Overhead 120,442 77,043 197,485

Total ($) 25,913,261 14,158,064 40,071,325

There were no additional fabrication or construction costs in 2012 associated with the Saleski Pilot Project IETP Phase 2 Approval 05-077.

Table 21: Costs of the Saleski Water Source and Disposal Pipelines Source and Disposal Pipeline Costs Cost ($) Aviation Support 3,674 Building Construction / Materials 115,306 Camp Costs 934,738 Communication 3,069 Crane Transportation 115,624 Earthworks 8,969 Electrical Equipment 173,338 Electrical Labour 526,348 Engineering / Design & Drafting 291,952 Equipment Rentals 9,088 Health & Safety 6,021 Inspection & Quality Control 12,915 Instrumentation 90,187 Lease Construction 140,867 Line Pipe 1,180,803 Matting 40,545 Mechanical Labour 23,009 Overhead 25,878 Pipeline Installation 859,472 Piping & Valve Materials 89,008 Regulatory Costs Fees/ Licences 27,973 Road Construction 485,715 Supervision / Consultant / Travel / Auto 361,538 Surface Land Services 4,947

84 Laricina Energy Ltd. Saleski Pilot Project IETP Approval 05-077 Final Report

Source and Disposal Pipeline Costs Cost ($) Surveying / Scouting 130,883 Total ($) 5,661,864

There were no additional source and disposal pipeline costs in 2012 or 2013 associated with the Saleski Pilot Project IETP Phase 2 Approval 05-077.

Table 22: Detailed Costs of the Saleski Pilot Commissioning GROSS ($) Pilot Commissioning 2009-2010 2011 Total Garbage Disposal 0 539 539 Fuel 0 214,154 214,154 Trucking - Legal Loads 0 167,798 167,798 Piping - Pipe 0 43,848 43,848 Aviation Support 29,805 40,597 70,402 Steam Generator Rentals 9,600 20,200 29,800 Earthworks -Rd 0 0 0 Mechanical Contractor 89,383 513,458 602,841 Electrical Contractor 61,222 449,012 510,234 Contractors 198,601 149,880 348,481 Building - Office 398 1,032 1,430 Instrumentation Contractor 3,317 0 3,317 Equip Setting 1,500 1,210 2,710 Mechanical Equipment 0 16,443 16,443 Filtration Equipment 0 0 0 Power Generators 0 9,280 9,280 Instrumentation - Control Valves 4,267 47,483 51,750 Electrical Equipment - Cable 203 26,268 26,471 Specialty Items 0 128,210 128,210 Piping - Fittings 0 6,803 6,803 Communication Equipment 7,779 -370 7,409 Equipment Rentals 55,360 347,404 402,764 Consumables 50 8,395 8,445 Inspection & Quality Control 57,227 383,377 440,604 Rotating Equipment 0 46,906 46,906 Tools, Equipment & Machinery 151,822 158,865 310,687 Health & Safety 6,151 176,609 182,759 Camp Costs 0 733,563 733,563 Engineering/ Design & Drafting 1,670 272,259 273,929 Supervision / Consultants / Travel /Auto 4,088 12,778 16,866 Overhead 3,930 15,904 19,834 Total ($) 686,372 3,991,906 4,678,278

85 Laricina Energy Ltd. Saleski Pilot Project IETP Approval 05-077 Final Report

There were no additional commissioning costs in 2012 or 2013 associated with the Saleski Pilot Project IETP Phase 2 Approval 05-077.

6.4 Capital Costs – Drilling & Completions

The Phase 1 portion of the IETP approval 05-077 included the costs for the following wells at the Pilot:

 P1Obs1 (102/07-26-085-19W4/00)  P2Obs3 (102/10-26-085-19W4/00)  P1Obs3 (103/10-26-085-19W4/00)  I1C horizontal well (100/15-26-085-19W4/00)  P2D horizontal well (102/15-26-085-19W4/00)

The 2011 Phase 2 portion of the IETP approval 05-077 included the costs for the following wells at the Pilot:

 P1Obs2 (104/10-26-085-19W4/00)  P2Obs1 (100/07-26-085-19W4/00)  P2Obs2 (106/10-26-085-19W4/00)  P1-2Obs2 (105/10-26-085-19W4/00)  P1C horizontal well (106/15-26-085-19W4/00)  I2D horizontal well (104/15-26-085-19W4/00)  7 Water source wells (refer to Table 10)  2 Disposal wells (refer to Table 10)

Any additional wells drilled are not associated with the Saleski Pilot Project IETP Phase 2 Approval 05-077, therefore costs are not reported. Associated costs for the above wells may be found in 2011 Phase 2 IETP Report.

6.5 Capital Costs – Regulatory

86 Laricina Energy Ltd. Saleski Pilot Project IETP Approval 05-077 Final Report

Table 23 below summarizes the Regulatory costs for the Pilot. These funds were used for consultants to complete the environmental assessment work and prepare the regulatory application.

Table 23: Detailed Costs of the Pilot Regulatory GROSS Pilot Regulatory 2007-2010 2011 2012 2013 Total Project Management 19,047 5,896 - - 24,943 Consulting Cost 139,061 10,611 - - 149,673

Total ($) 158,108 16,507 - - 174,616

6.6 Capital Costs – Infrastructure

Table 24 displays the Infrastructure costs for the Pilot. These funds were used to construct a high grade road to the Pilot and a natural gas pipeline.

Table 24: Detailed Costs - Pilot Infrastructure GROSS Saleski Pilot Infrastructure 2007-2010 2011 2012 2013 Total High Grade Road 28,329,755 86,750 - - 28,416,505 Fuel Gas Pipeline 413,868 - - - 413,868 Transportation Consulting 134,308 -6,667 - - 127,642

Total ($) 28,743,624 86,750 - - 28,830,374 No additional infrastructure costs in 2012 or 2013 associated with Saleski Pilot Project IETP Phase 2 Approval 05-077.

6.7 Operating Costs

Table 25 displays the gross operating costs from the Pilot for the period December 2010 to December, 31, 2013. These reported costs are accurate to +/- 5% and do not include road maintenance, taxes or insurance.

87 Laricina Energy Ltd. Saleski Pilot Project IETP Approval 05-077 Final Report

Table 25: Operating Costs for Saleski Pilot in 2010-2013 GROSS Operating Cost 2010 2011 2012 2013 Total Staff Costs 1,453,153 5,515,155 5,773,127 5,976,963 18,718,398 Office & Camp 53,659 3,966,812 3,155,475 5,026,337 12,202,283 OTSG Fuel 9,137 1,582,669 1,802,163 2,976,649 6,370,618 Waste Management - 225,134 171,089 222,548 618,771 Power 54,000 905,802 1,007,070 934,981 2,901,853 Repairs & Maintenance - 735,553 329,150 676,975 1,741,678 Staff Transportation 218,578 954,089 361,694 273,762 1,808,123 Well Workovers - 4,605,486 3,396,993 4,943,536 12,946,015 Chemicals - 304,557 50,267 504,409 859,233 EH&S 105,615 485,087 662,607 596,242 1,849,551 Instrument & Electrical 65,439 225,214 339,842 357,077 987,572 Freight - 180,312 110,666 129,913 420,891 Lab & Inspection - 434,543 498,987 1,617,533 2,551,063 Pressure, Vac, Steam Trucks - 290,517 839,799 603,343 1,733,659 Rentals - 652,867 1,605,503 1,307,050 3,565,420 Reservoir Solvents - - 746,598 - 746,598 Total ($) 1,959,581 21,063,797 20,851,030 26,147,318 70,021,726

6.8 Royalties

Table 26 summarizes the royalties paid in relation to the Pilot for the reporting period. These reported costs do not include road maintenance, taxes or insurance.

Table 26: Royalties Paid from Pilot in 2013 Gross Monthly Month Royalty ($) January 26,485 February 15,889 March 10,248 April 5,802 May 20,194 June 3,948 July 33,856 August 99,234 September 110,933 October 68,566 November 5,340 December 2,670 Total ($) 403,165

88 Laricina Energy Ltd. Saleski Pilot Project IETP Approval 05-077 Final Report

6.9 Cumulative Project Costs

Table 27 below has the gross cumulative costs of the Pilot at $230 million. Note that the estimated costs in the application were reported as net costs to Laricina (60%). In order to have a direct comparison of the original costs quoted in the application, the costs below would have to be multiplied by 0.6.

Table 27: Cumulative Project Cost Summary Actuals to Dec. 31, Pilot Cost 2013 (Gross) Facilities 89,192,524 Drilling & Completions 42,150,967 Regulatory 174,616 Infrastructure 28,830,374 Operating Costs 70,021,726

TOTAL ($) 230,370,107 There were no additional facilities, drilling & completions, or infrastructure costs in 2012 or 2013 associated with the Saleski Pilot Project IETP Phase 2 Approval 05-077. Operating and regulatory costs were adjusted to include costs from 2013.

6.10 Material Deviations from Budgeted Costs

There were no additional capital costs in 2013 associated with the Saleski Pilot Project IETP Phase 2 approval 05-077.

The Saleski Pilot is forecast to be $29.3 million over its original budget. The largest budget deviation was linked to the Facility portion of the project, which accounted for $21.5 million dollars. This significant deviation arose from lost productivity in the summer due to wet weather, estimate errors, and construction cost over-runs associated due to weak supervision by sub- contractors.

Drilling and completions also contributed $7.8 million dollars of over budget deviation, which was caused by drilling complications (i.e. significant fluid losses) and an under estimated budget that did not account for additional logging and testing.

The only major piece of the budget that is forecast to come in under budget is the Infrastructure, which was under budget by $3.6 million.

89 Laricina Energy Ltd. Saleski Pilot Project IETP Approval 05-077 Final Report

7.0 FACILITIES

7.1 Additions and Modifications No additions under approval 05-077 were made to the base facilities in 2013.

7.2 Capacity Limitations and Equipment Integrity

The capacity and equipment integrity are outlined on the process flow diagrams (PFDs) attached in the Appendix of this report.

7.3 Site Diagram

A detailed design layout of the Pilot Plant is included as Figure A1 in the Appendix of this report.

8.0 ENVIRONMENTAL/REGULATORY/COMPLIANCE

8.1 Project Regulatory Requirements and Compliance Status

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

Application No. 1625469 Laricina Energy Ltd. Saleski SC-SAGD Pilot Project was submitted to the AER in September 2009 to incorporate solvents to the SAGD process. Approval No.11337B was received April 30, 2010.

Since 2010, Laricina has filed a number of amendments to the AER concerning the project. A brief description of all the amendments filed and approval numbers and dates are summarized in Table 28 below.

Table 28: AER Amendment Approvals Approval Approval Brief Application Description No. Date 11377A Mar. 5, 2010 Change in well configuration. 11377B Apr. 30,2010 Add solvent to the SAGD process and associated surface recovery and handling facilities. 11377C Oct. 11, 2011 Addition of a second Once Through Steam Generator for increased steam capacity.

90 Laricina Energy Ltd. Saleski Pilot Project IETP Approval 05-077 Final Report

11377D Nov. 24, 2011 Addition of a new well pair (C2) to the project. 11377E Feb. 22, 2012 Change to C2 well pair to an open hole completion configuration. 11377F Mar. 26, 2012 Change all thermal wells in the project to be able to inject or produce. 11377G Jul. 27, 2012 Amendment to increase the number of cycles for injection/production. 11377H June 11, 2013 Amendment to add pressure tanks and incinerator at the well pad. 11377I Sept. 12, 2013 Amendment to drill a top injector well. 11377J Nov. 5, 2013 P1C Sidetrack The Pilot is currently operating in compliance within the various regulatory approvals for the project. In 2013, Laricina had six reported non-compliance issues that related to releases of various substances. All releases were over the reportable thresholds for reporting but were contained and remediated. All non-compliance issues were reported to the applicable regulatory agencies as they were identified. Corrective actions and required correspondences were completed to bring these items into compliance.

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 well sites. We also strive to meet or exceed all regulatory requirements as they pertain to environmental protection.

Laricina’s 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 move forward with our facility/production phase.

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

91 Laricina Energy Ltd. Saleski Pilot Project IETP Approval 05-077 Final Report

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

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 a membership to the Spill Co-op 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 has committed to the implementation of the greater Environmental Management System and Environmental Committee to further assess and monitor Laricina’s goals, performance and education - currently and prior to facilities and production.

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

8.2.1.1 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 eventual 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,

92 Laricina Energy Ltd. Saleski Pilot Project IETP Approval 05-077 Final Report whenever possible, endeavour to reduce working areas at facilities and well sites 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 above-ground and below-ground 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 on-site.

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. Register any contaminants, wastes, or structures that restrict future land use and/or that require periodic monitoring to ensure continued integrity on the property tile.

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.

8.2.2 Site Management

No activities took place in 2013 under Approval 05-077.

93 Laricina Energy Ltd. Saleski Pilot Project IETP Approval 05-077 Final Report

8.2.3 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

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

8.2.4 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 the case of an emergency situation; and

94 Laricina Energy Ltd. Saleski Pilot Project IETP Approval 05-077 Final Report

• maximize the 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 continually improving their Corporate HS&E Management system on an annual basis.

9.0 Future Operating Plans

9.1 Project Schedule

2010 2011 2012 2013 2014 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 SC_SAGD Pilot Development Facilities Engineering Central Processing Facility Construction Pad/Lateral Construction Pipeline (WS/WD) Construction Drilling & Completions Horizontals Water source/disposal Infrastructure Road Gas Supply Commisioning WP1D WP1C WP2C WP2D WP1C Sidetrack Figure 60: Pilot Project Schedule

9.2 Changes to Pilot Operation The Pilot was originally planned as a SAGD operation, utilizing constant steam injection to establish sustained bitumen production. Based on the production performance achieved from SAGD operations in the Grosmont C and D zones SAGD was established at the Pilot. However, early in development of the steam chamber, cyclic steam production cycles increased bitumen production and appeared to be a more promising recovery technology.

Although the focus has been turned to cyclic production, Laricina’s main focus is to optimize thermal recovery in the Grosmont. Various recovery methods will be analyzed and tested based upon field results, meaning that no thermal recovery method will be ruled out. There will also be more testing on post-cyclic production methods. Laricina will continue to advance its knowledge, to optimize future production.

95 Laricina Energy Ltd. Saleski Pilot Project IETP Approval 05-077 Final Report

Laricina also plans to continue testing solvent injection as an enhancement to the recovery method. It is important that baseline thermal production is established and understood prior to initializing solvents. Solvents have the potential to greatly reduce SOR and optimize production.

Finally, the Passive Heat Assisted Recovery Method (PHARM) will enable harvesting of heat across the Grosmont CD marl (if there exists a physical barrier between the Grosmont C and D) and will also be further explored. This technique, patented by Laricina, has unique applications to the Grosmont geology and has the potential to reduce production costs by taking advantage of downhole heat conduction across the CD marl.

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

9.3.1 Site Management

No changes took place in 2013 under Approval 05-077.

10.0 INTERPRETATIONS AND CONCLUSIONS

10.1 Learning Experience The following information summarizes the insights amassed from Pilot operations:

 SAGD Start-up in the Grosmont Laricina attempted to start-up and produce both the Grosmont C and D units by using both the injector and producer wells to inject steam, warm up the reservoir and produce oil under gravity drainage to the producer well. Laricina did not achieve the expected production rates under SAGD operations. However, when a Grosmont C injector was shut-in, the production rates increased significantly. Based on this experience, Laricina began testing single horizontal well cyclic operations in the Grosmont C unit in early 2012.

The ability to inject steam into the reservoir during the warm-up period without circulating fluids back to surface had a significant impact on cyclic development. The reservoir was able to readily accept steam injection, the pressure in the wells would increase, but not to a point where fluid returns were possible. This data demonstrates the injectivity of the reservoir and the pressure build-up in the wells confirms that the fluid is contained near the wells.

96 Laricina Energy Ltd. Saleski Pilot Project IETP Approval 05-077 Final Report

 SAGD and SC-SAGD Production and Performance in the Grosmont. Laricina has not tested solvent assisted SAGD in the Grosmont C or D units based on the performance of SAGD in the Grosmont. Laricina completed its first diluent injection under cyclic operation on October 9, 2012 in the P1C well (see Section A6.1.3) and is continuing to evaluate the impact and future uses of solvent in the Grosmont.

 Drilling and Completion Methods The 1C, 1D and 2D well pairs were drilled using over-balanced drilling method which resulted in significant drilling losses into the formation. The three (3) well pairs have a horizontal lateral length of 800 m and were completed using slotted liners to mitigate the risk of solids production and maintain wellbore stability.

The 2C well pair was drilled in the first quarter of 2012 to a horizontal lateral length of 450 m due to limited steam availability. This well pair was drilled at close to balanced pressure to minimize fluid losses and improve drill cuttings removal from the well. The well pair was completed without a liner in the horizontal lateral sections to confirm whether solids production in a carbonate reservoir is an issue. Both wells were also stimulated with acid prior to the first steam injection cycle in May 2012.

To date, there have been negligible solids production into the plant and there is no evidence of well stability issues. The production rate from this 450 m well has been significantly better than the 800m long over balanced drilled wells indicating the positive potential of balanced drilling in the Grosmont reservoir.

 Cyclic Performance in the Grosmont D The P1D well had only one full production cycle in early 2012 and was shut-in as an observation well from May to June of 2012. The P1D well toe temperature responded to P1C steam Cycle 3. A small steam injection volume was completed at the end of July 2012 and the well was converted to production August 5, 2012. Production continued to the end of September 2012 with a cycle SOR of 1.6. This cycle demonstrates the potential cyclic exploitation of the D in conjunction with the C benefitting from passive heating below the C/D marl. Subsequently, the P1D well performed a third cycle achieving cycle SOR of 2.0. The I2D well has completed three (3) production and injection cycles over the past eight (8) months. This well has received approximately half the cumulative steam volume when compared to 1D, yet has achieved better cyclic SOR than 1D did early on.

97 Laricina Energy Ltd. Saleski Pilot Project IETP Approval 05-077 Final Report

Evaluation of the 2D well as a baseline for cyclic development of the D will remain ongoing.

At the conclusion of 2013 Laricina is exploring the potential to drill an additional Grosmont D well with balanced drilling and a staged acid job, similar to the strategy successfully executed in the P2C well.

 Proven Commercial Cyclic Performance in the Grosmont C Laricina has carried out one (1) hybrid cyclic cycle (i.e. where production started under SAGD but then was switched to cyclic when the injector was shut-in) and three full cyclic cycles in the P1C well. Each progressive cycle in P1C has demonstrated positive effects of cyclic operation. Cycle 2 was the first successful cycle in the Grosmont C, Cycle 3 demonstrated the productivity of the primary porosity to the overall production and Cycle 4 has demonstrated improved bitumen mobility at lower operating temperatures with the addition of diluent.

Laricina has completed two (2) full cyclic cycles in the P2C well. Cycle 1 achieved an SOR of 6.5. The P2C well cycle 2 achieved an SOR of 3.4 and a CDOR of 44 m3/d for the 450 m long horizontal well. The P2C completed producing cycle 3 in May 2013. The performance metrics achieved are comparative with other cyclic projects in the Province.

Cyclic steam injection and bitumen production at the Saleski Pilot have proven commercially viable injectivity and productivity from the Grosmont C Formation. Cyclic exploitation of bitumen from horizontal wells is not a new approach. Laricina intends to capitalize on the higher permeability in the Grosmont C by injecting steam below fracture pressure and relying on gravity drainage for production of bitumen. On a commercial scale, addition of solvents to the injected steam may improve the mobility of bitumen within the reservoir and lead to improved recovery.

Improvements in drilling and completions, facility design and optimizing steam and production cycles will lead to improved economic recovery of this resource. The strategy Laricina is proposing for exploitation of the Grosmont C has been supported by the recognition of 2P reserves from an independent reserves evaluator.

Laricina is proceeding with the Project using cyclic operations based on the SOR and CDOR from the Grosmont C unit wells.

98 Laricina Energy Ltd. Saleski Pilot Project IETP Approval 05-077 Final Report

10.2 Difficulties Encountered The difficulties encountered were primarily those related to the unsteady production related to the ramp up of a pilot. These included:

 Water treatment: The pH of the water was lower than initially anticipated, causing unexpected scaling. Changes to the water treatment process have reduced this issue. However, complete separation of the once through steam generators (OTSG) blowdown water and produced water is required to completely mitigate this issue. Further problem solving is required to determine if less capital intensive solutions exist.

 Pump runtime: The issues with the pumps were both mechanical and operational. The mechanical issues were largely the result of inexperience with this application in the geographical area. With increased experience and with re-enforcement, much more reliability has been achieved. The operational issues centered on understanding how the pumps behaved in the wellbores, by running them less aggressively Laricina has experienced longer runtimes. Laricina continues to monitor for technological opportunities to improve this issue.

 Steam venting: Early in production cycles in the P1C well, large volumes of steam are vented from the well. Due to the volume, additional piping and p-tanks were required to relieve the back pressure from the reservoir. Recently, Laricina operations have been successfully using a quench water injection strategy to reduce the steam flashing in the casing. This is reasonable at the pilot, but larger pipe diameters to vent to the plant will be incorporated at a commercial project.

10.3 Technical and Economic Viability SAGD operating conditions were established in the Grosmont but the rates did not meet performance expectations. The application of a cyclic thermal process has demonstrated better commercial potential. As a result, Laricina has elected to focus the near term activities of the Pilot on reinforcing cyclic thermal recoveries.

10.4 Overall Effect on Bitumen Recovery Moving forward with the Pilot, the change in production methodology from SAGD to cyclic production is not expected to change the overall bitumen recovery of the Grosmont. In both SAGD and cyclic operations, recovery is dominated by gravity drainage. At similar spacing, SAGD and cyclic recoveries are shown to be similar. At Primrose, recoveries at 160-190 m inter- well spacing range from 20-40%, whereas recent pads at 60-80 m inter-well spacing demonstrate

99 Laricina Energy Ltd. Saleski Pilot Project IETP Approval 05-077 Final Report recoveries of up to 50%, matching those seen with SAGD. For a more technical understanding of these conclusions, please refer to Paper 2007-027 from the 2007 Canadian International Petroleum Conference, “A Unified Model for Prediction of CSOR in Steam-Based Bitumen Recover” by Neil Edmunds and Jeff Peterson of Laricina Energy.

10.5 Assessment of Future Expansion and Commercial Field Application The Pilot is the cornerstone of Laricina’s development in the carbonates. Laricina’s Saleski Grosmont reservoir has a best estimate of contingent resources at 2.9 billion barrels (gross) and a potential of 282,500 bbl/d (gross). This resource is sufficient to support six (6) phases of commercial development. In July 2013 Laricina received approval from the AER for Saleski Phase 1 which will provide an additional 10,700 bbl/d of production. Start-up is expected to occur in Q3 of 2017.

100 Laricina Energy Ltd. Saleski Pilot Project IETP Approval 05-077 Final Report

11.0 APPENDIX

101 Laricina Energy Ltd. Saleski Pilot Project IETP Approval 05-077 Final Report

Process Flow and Site Diagrams

102

Laricina Energy Ltd. Saleski SC-SAGD Pilot Plant Block Flow Diagram Created by: Ali Farzaneh Created On: September 1, 2011 Created For: Laricina Energy Ltd. Job # 06210 Rev: Revision B

Disposal Water from Disposal Pump to Pipeline

Dirty Backwash Dirty (Stream 361) Source Water (Stream 300) 45,014 kg/hr & Spent Backwash Cooled De-Oiled 43,321 kg/hr From Water Wells Regenrant from Source Water from PW from SACS to Water Filters Trim Cooler to Disposal Water to Disposal Disposal Water Tank Water Tank Tank Liquid Hydrocarbon from (Stream 308) (Stream 305) (Stream 210) Combined Vent Gases from Suction Scrubber (V-6010) 133 kg/hr 1,232 kg/hr 32,794 kg/hr Vented Gases from Skim Tank & IGF to VRU Tanks to Vent Gas Separator (Stream 159b) (Stream 205+206) 2,364 kg/hr (Stream 710) 2,660 kg/hr 5 kg/hr Vent Gases from Source Other Fuel Gas to VRU Blowcases Cooled WATER TREATMENT Water Tank & Slop Tank to VRU VRU Vents (Stream 722) 14 kg/hr Produced (Stream 310+212) 33 kg/hr Water from FWKO & Vent Gas Treater to from Diluent Tank Recovered Liquids from Vent Gases Skim Tank Backwash Combined (Stream 704) to Skim Tank via Blowcases (Stream 113) Supply from Water from 262 kg/hr (Stream 713) 2,364 kg/hr 32,598 kg/hr BRW Tank to Casing Gas & Source Water Produced Gas Filters & Separators to SACS Skim Tank (Stream 304) (Stream 164) 1,330 kg/hr 388 kg/hr

Compressed Skimmed Oil Vent Gases from Skim Slop Oil from to Produced Tank to Slop Tank to Blowdown from BFW from Utility Water Pump to Utility Users Gas Cooler FWKO FWKO Combined BFW Blowdown Tank (Pump Seal Flush, Cooling Water) (Stream 712) (Stream 203) (Stream 250) from Exchangers to Disposal (Stream 419) 1,612 kg/hr 310 kg/hr 110 kg/hr 498 kg/hr to BFW Tank Water Tank (Stream 337) (Stream 418) Fuel Gas from 44,533 kg/hr RESERVOIR 7,549 kg/hr Fuel Gas Line SOR = 2.45 Cooled Dilbit from Heater to Wells Combined Emulsion Production to Plant (Stream 6) 49,450 kg/hr Fuel Gas (Stream 900) WOR = 2.31 Dilbit Cooler to (Stream 901) 1,755 kg/hr GOR = 10 Dilbit Tank STEAM GENERATION 30 kg/hr Casing Gas from Well #1 to Plant (Stream 8) 1,375 kg/hr BITUMEN TREATMENT STEAM GENERATION Mass Fraction of Propane Returned 0.09 From Supply Pipeline FUEL GAS HP Steam from HP Steam (Stream 132) Separator to Wells Mass Fraction of Diluent Returned 0.64 16,590 kg/hr Casing Gas from Well #2 to Plant (Stream 9) 1,375 kg/hr Mixed Fuel Gas (Stream 501) Fraction of Total Solvent Returned 0.45 to Steam 34,042 kg/hr Generators Note 1, 2, 3 (Stream 908) 1,790 kg/hr Heated Mixed Heated Mixed Injection Diluent & Injection Diluent & Diluent from Recycled Combined Casing, Diluent from Propane from the Propane from the Diluent Injection Diluent from VRU & Produced Diluent Pumps to Fuel Gases Diluent/Propane Diluent/Propane Pump to Casing Gas & PG Gases from FWKO & Treater (Stream 168) Heated Fuel to Emulsion/BFW (Stream 701) Fuel Gas Heater to Well #1 Heater to Well #2 Separator to Produced Gas 398 kg/hr Utilities (Power Exchanger 1,405 kg/hr to Inlet Vessels (Stream 720) (Stream 721) Diluent Tank Separator to From Discharge Gens, Camp) (Stream 119) (Stream 905) 4,754 kg/hr 4,754 kg/hr (Stream 702) Solvent Recovery Scrubber (Stream 903) 0 kg/hr 117 kg/hr 3,134 kg/hr (Stream 159) 216 kg/hr 1,815 kg/hr Fresh Diluent from Trucks to Diluent Tank (Stream 707) 4,140 kg/hr FUEL GAS TO UTILITY SOLVENT/DILUENT MAKE-UP & Note 4, 5 RECOVERY Fresh Propane from LP & HP Propane Pumps to Diluent/ Propane Line Heater (Stream 714) NOTES: 1) Produced Gas is retained solution gas (on a dry basis) in Emulsion as per in Stream 6. 2,489 kg/hr 2) To calculate ratios, use std volume flow of bitumen of 286 m3/d and std density of water of 1000 kg/m3. 3) GOR = 10 sm3/m3 4) Fuel Gas to Utility Stream 903 is for Streams (904, 906, 910, 911, 912) 3) Fuel Gas to VRU Blowcase (Stream 722) is included to (Stream 906) Fuel Gas for tank, VRU & IGF.

Laricina Energy Ltd. Saleski Pilot Project IETP Approval 05-077 Final Report

Intellectual Property Agreement Disclosure Form

103 Innovative Energy Technologies Program Intellectual Property Agreement Intitial Disclosure Form (Section 3) Name Type Owner Description Operator Use (Legal Terms and Licensee Use (Legal Terms and Developer Statutory Protection Conditions) Conditions) (name of the specific Technology) (Background Technology, New (name of the owner of the Technology (description of the Technology) (i.e. if the Operator is a licensee, or is (i.e. if a third party licensee wishes to (name of the person who developed the (if known, indicate whether Statutory Technology or Commercial Technology) i.e. the name of the Operator if the restricted in the use of the Technology, retain a license to that Technology, set Technology) Protection will be sought for the Operator is the owner or the name of any legal terms or conditions which may out the significant terms and conditions Technology i.e. patenting) the licensor of the Operator is a restrict the Operator's use of the of that license) licensee) Technology)

1. Application of cold solvent for New technology Laricina Energy Ltd. First field trial of bitumen recovery utilizing a Not applicable Not yet developed Neil Edmunds; An Mai Not yet. bitumen recovery in a mixture of propane and non-condensable gas carbonate reservoir mixture from the Grosmont carbonate reservoir 2. Bitumen recovery based on Patented Quarter One in the Laricina Energy Ltd. While steam forms an effective working fluid Not applicable Not yet developed Mauro Cimolai Patented Quarter One in the Passive Heating Assisted US and Quarter Two in Canada for heat transfer within the formation, the US and Quarter Two in Canada Recovery Methods(PHARM) overall energy inefficiency of steaming from a carbonate reservoir processes presents a continuing challenge for improvement. Specific to SAGD, substantial heat is lost to the rock bounding the reservoir over the producing life of a pattern, commonly representing the largest component of the overall thermal inefficiency. However, for layered bitumen reservoirs separated by a permeability restriction, this passive heat loss to an adjacent zone can provide a significant advantage for overall improved recovery. The preheated reservoir permits the application of alternate recovery strategies where the effectiveness of solvents, in the absence of water introduced by steam injection, is patently improved. PHARM is a patent pending recovery method which teaches the methods of using passive heat to recover bitumen.

3. Advanced Solvent-Additive New technology Laricina Energy Ltd. Laricina is developing solvent Additive SAGD Not applicable Not yet developed Neil Edmunds; Behdad Moini, Patenting. SAGD Processes processes tailored specifically to each unique Jeff Peterson. reservoirs. The solutions developed show Solvent application to SAGD with time variations in both rate and composition of the solvent.

4.

5.

THIS FORM IS INTENDED ONLY AS A GUIDE AND ANY ADDITIONAL INFORMATION REQUIRED TO COMPLY WITH SECTION 3 OF THE AGREEMENT 04/2008 (E.G. SCHEDULE "A") MAY BE ATTACHED IN A SEPARATE FORM AND DOCUMENT Laricina Energy Ltd. Saleski Pilot Project IETP Approval 05-077 Final Report

Statutory Declaration

104 MINES AND MINERALS ACT INNOVATIVE ENERGY TECHNOLOGIES REGULATION STATUTORY DECLARATION

Definitions

In this Statutory Declaration,

(a) “Allocable Costs” means allocable costs as defined in the Regulation;

(b) “Approval” means Approval No. 05 - 077 granted pursuant to the Regulation;

(c) “Operator” has the same meaning as in the Approval;

(d) “Project” has the same meaning as in the Approval;

(e) “Regulation” means the Innovative Energy Technologies Regulation (AR 250/2004);

(f) “Period of Time” means from January 1, 2013 to December 31, 2013.

Declaration

I, Jim Hand of the City of Calgary in the Province of Alberta,

DO SOLEMNLY DECLARE THAT:

1. I am an authorized signing officer of the Operator.

2. The Project commenced in accordance with the commencement provision of the Approval.

3. In respect to the Period of Time,

(a) Allocable Costs have not been applied for and established in relation to

(i) equipment or facilities located outside of the Province of Alberta;

(ii) the cost of borrowed money that has been or will be deducted from income under section 21 of the Income Tax Act (Canada);

(iii) an amount deducted as a capital cost allowance or as amortization of eligible capital property under the Income Tax Act (Canada) or the Income Tax Regulations under that Act;

(iv) any item or service obtained from a person who is connected to the Operator or any owner of the Project, pursuant to the definition of a connected person under section 6 of the Regulation;

(v) materials or capital items that have not been used in the Project; and

1 of 2