cnrl 2012 primrose, wolf lake, and burnt lake annual ... economizer tube failures at psp contributed...

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2012 Primrose, Wolf Lake, and Burnt Lake Annual Presentation to the ERCB

Surface Operations, Compliance and Issues Not Related to Resource Evaluation and Recovery

January 24, 2013

CNQSlide 2

Directive 54: Performance Presentations, Auditing, and Surveillance of In Situ Oil Sands Schemes

• January 23, 2013

3.1.1 Subsurface Issues Related to Resource Evaluation and Recovery

• January 24, 2013

3.1.2 Surface Operations, Compliance, and Issues Not Related toResource Evaluation and Recovery

Primrose, Wolf Lake, and Burnt LakeAnnual Presentation to the ERCB for 2011Primrose, Wolf Lake, and Burnt LakeAnnual Presentation to the ERCB for 2011

CNQSlide 3

• Facilities Plot Plans, Simplified Plant Schematic, Modifications and Updates

• Facility Performance Oil & Water Treatment, Steam & Power Generation Gas Usage, Greenhouse Gas Emissions

• Measurement & Reporting Well Production Estimates, Proration factors, Test Durations, New

Measurement Technology• Water Production, Injection, and Uses UWIs, Water Uses and Water Quality Fresh, Brackish, Steam and Produced Water Volumes & Forecasts Brackish Water Supply UWIs & Disposal Well Compliance Wolf Lake Disposal & Water Storage Volumes Wolf Lake Waste Disposal

• Sulphur Production Summary and Discussion of Emissions

Page5-9

10-1112-14

15-17

18-1920-2223-25

2627-32

33

34-38

Outline - Surface Operations, Compliance, and Issues Not Related to Resource Evaluation and RecoveryOutline - Surface Operations, Compliance, and Issues Not Related to Resource Evaluation and Recovery

CNQSlide 4

• Environmental Summary Compliance Issues & Amendments Monitoring Programs Reclamation Regional Initiatives Arsenic Monitoring Groundwater Monitoring at E14 Pad Primrose East Risk Management Plan Pad 75 Update

• Well & Formation Integrity• Abandonments• Approval Condition Compliance Approvals (9140P, 9108, 8186A, 8672A, 8673, 3929A, 4128D, 9792A)

• Discussion of Non-Compliance Items Self Disclosures

• Future Plans

Page39

40-444546

47-5051-52

5354

55-6364

65-72

73-74

75-76

Outline - Surface Operations, Compliance, and Issues Not Related to Resource Evaluation and RecoveryOutline - Surface Operations, Compliance, and Issues Not Related to Resource Evaluation and Recovery

CNQSlide 5

FacilitiesFacilities

• Detailed Site Survey Plans - refer to included drawings: Wolf Lake Plant Plot Plan Primrose Plant Plot Plans (South, North, East) Typical Pad Plot Plan (Primrose East)

• Simplified Plant Schematic - refer to included drawings: Wolf Lake / Primrose Simplified Plant Facilities Schematic

• Summary of Modifications Wolf Lake Brackish Water Expansion – Phase 1

– Completion of the project started in 2011. Project involved the addition of brackish water tank, VRU, pumps, piping, heater exchangers, pick heater

Wolf Lake Unit 8 DCS Upgrade– Replaced obsolete control system in Wolf Lake Plant Unit 8 (part of multi-year program)

Wolf Lake Slop Oil Treatment System– Added a centrifuge for slop oil treatment

Wolf Lake Unit 2 Separator Replacement– Replacement of an existing damaged inlet separator

CNQSlide 6

FacilitiesFacilities

• Summary of Modifications (cont’d) Wolf Lake Oil Debottlenecking

– Numerous upgrades to improve oil treating. Including a new ORF in unit 10, sales pump in Unit 8, various vessel control valve upsizing

Wolf Lake Salt Cavern Returns– Installed a salt cavern booster pump and made provisions for future filtration

CNQSlide 7

Specific Project UpdatesSpecific Project Updates

• Wolf Lake Slop Treatment Modifications Centrifuge construction complete to treat slop oil (ie oil, water, solids, rag

layers, emulsion) from all units Centrifuge to separate oil, water, slurry Slurry to be injected to existing salt caverns System currently involved in commissioning

• Brackish Water Expansion – Phase 1 Project to increase peak supply/treating/handling capacity to 35,000 m3/d Involves 3 new brackish water wells on existing locations tied into the

existing pipeline Plant upgrades include new 20,000 bbl tank, inlet skid and piping, pumps,

VRU, steam heating and inlet to Unit 3 WLS, inlet and exchanger to Unit 8 skim tank

Project completed and operational

CNQSlide 8

Primrose East Sulphur TreatmentPrimrose East Sulphur Treatment

• Temporary produced gas sweetening at Primrose East Steam plant was shutdown on June 2, 2011 and restarted on February 7,

2012 for reservoir management Produced gas was conserved by sending it to Primrose South as sweet

fuel gas A compressor, two phase separator, and liquid H2S scavenger system

were installed Flared for first 2 months of steam plant outage due to construction delays System started on July 28, 2011 and was commissioned with sweet gas Flared intermittently due to compressor issues/servicing, Primrose South

outages, pigging of the gas pipeline and start up/shutdown of the steam plant System shutdown on February 7, 2012 and decommissioned

CNQSlide 9

Primrose East Sulphur Treatment (con’t)Primrose East Sulphur Treatment (con’t)

• Prior to system start up (June 2, 2011 – July 27, 2011) Total sulphur flared: ~29 Tonnes

• System online (July 28, 2011 – February 6, 2012) Total sulphur removed: ~28 Tonnes Total sulphur flared: ~13 Tonnes

CNQSlide 10

Facility PerformanceFacility Performance

• Bitumen and Water Treatment Overall water quality and oil treating targets were generally met:

– Experienced some treating and produced water de-oiling challenges due to low inlet production temperatures (low produced water volumes and cooler Primrose East emulsion temperatures).

– Recycling of slop and skimmed oil is causing treating and rag layer issues. Problem is being mitigated by addition of slop oil treatment unit. Currently in commissioning phase. Slop oil treatment unit will be functional in Q1 2013.

Performance testing indicated additional available capacity in existing oil treating system. Wolf Lake debottlenecking project is nearing completion.

Successfully completed Unit 8 oil side turnaround this year.

• Steam Generation Overall steam generation targets were met:

– Primrose South & North achieved 98.1% of budget injected steam volumes– Primrose East steam plant was shut down for a total of 39 days at the beginning of 2012

to allow depletion of the area Corrosion and erosion issues in the steam piping systems caused production

losses due to maintenance and repair outages Six economizer tube failures at PSP contributed to unplanned downtime HRSG tube sheet failure at PSP contributed to power disruptions

CNQSlide 11


• Power Generation/Consumption on a monthly basis

CNQSlide 12


• Gas Usage on a monthly basis

Month

Total Purchased Gas

Total Solution Gas Conserved

Total Gas Vented

Total Solution Gas

FlaredSolution Gas

Conserved

e3m3 e3m3 E3m3 e3m3 %

January 92,882 24,942 13 246 99.0%

February 105,719 23,816 13 553 97.7%

March 138,352 25,227 611 32 99.9%

April 123,915 24,627 44.51 1,437 94.2%

May 130,400 23,231 8 1,042 95.5%

June 133,213 24,647 12 175 99.3%

July 129,780 25,551 6 165 99.3%

August 116,428 23,823 5 1,207 94.9%

September 114,584 27,414 1.5 105 99.5%

October 126,818 31,476 0.4 47 99.8%

November 122,500 22,741 9 125 97.7%

December 124,869 25,498 4 392 98.5%

*Total purchased gas does not include gas from site gas wells *Solution gas flared volumes are corrected to remove purchased gas to flare*Total gas vented includes brackish water associated vent gasNotes: 1) Brackish usage increased in March 2012. New VRU commissioned April 24, 2012.

CNQSlide 13

• Flaring & Solution Gas Conservation Compliance All Primrose and Wolf Lake facilities are equipped for gas conservation except one

pilot well, 15BM – granted exemption in 2004 New pads (since 2004) are built with VRUs or are linked to a neighboring pad’s

VRU

• Solution Gas Flare Volumes Conserved ~ 97.9% of total Primrose and Wolf Lake solution gas in 2012

• Facility Venting Compliance No routine venting in the field No routine venting at Primrose North, South or East plants Vapour recovery on all major sources of solution gas at Wolf Lake Plant


CNQSlide 14

Facilities – Greenhouse Gas EmissionsFacilities – Greenhouse Gas Emissions

• PAW Greenhouse Gas Emissions *2012 November and

December emission is estimated using the average of the previous 3 months

Month 2012(tCO2e)

Jan 240,863

Feb 248,972

Mar 313,518

Apr 286,850

May 297,670

Jun 302,987

Jul 299,681

Aug 271,505

Sep 274,301

Oct 302,522

Nov* 282,776

Dec* 286,533

Year Total 3,408,177

CNQSlide 15

• Measurement, Accounting & Reporting Plan (MARP) for Wolf Lake / Primrose Thermal Bitumen Scheme Approved May 1st, 2007. Annual updates in March.

• Methods for estimating well production and injection volumes reported to the Registry Produced emulsion from the scheme is commingled at the battery. Bitumen and water production

from the battery is prorated to each well using monthly proration test data and proration factors. – Total Battery Oil (Water) / Total Test Oil (Water) at Wells = Oil (Water) Proration Factor– Oil (Water) Proration Factor * Each Well Test Oil (Water) Volume = Oil (Water) Allocated to Each

Well Gas allocated to each well is determined by GOR (gas oil ratio) for the battery

– Total Solution Gas Produced / Total Battery Oil = Gas Oil Ratio– Gas Oil Ratio * Oil Allocated to Each Well = Gas Allocated to Each Well

Injected volumes of steam and water are not estimated, they are continuously measured at wellhead

Some pads have capability to take steam from Primrose South or Primrose North Steam Plant. Estimating steam transfer volume from combined proration factor for both plants.

• Test Durations Through experience, CNRL field operations has identified the test durations, gross fluid rates and

BS&W results required to obtain valid proration test data for each well. Most wells have 4 hour proration test durations; however some wells may be tested from 1 to 6 hours depending on their unique operating conditions and cycle maturity. Each well is tested each month and may be tested several times over the month.

Measurement and ReportingMeasurement and Reporting

CNQSlide 16

Measurement and Reporting – Proration FactorsMeasurement and Reporting – Proration Factors

CNQSlide 17

Measurement and ReportingMeasurement and Reporting

• New Measurement Technology– Installed multi-phase flow metering technology.

– Conducting field tests since mid-2012. Tests will be continued into 2013.

– Objective is to identify a multi-phase flow meter which provides adequate performance and accuracy to replace the traditional test separator system for multiple wells

– Installed a new nuclear level technology for interface control on one inlet separator vessel at Wolf Lake for improved interface level control. Proceeding with installation on other vessels.

– Installing low flow steam meters on new pads for improved measurement accuracy at low flows.

CNQSlide 18

• Primrose & Wolf Lake Project Water Well UWI Listing ESRD fresh water well license renewed in 2012 Primrose wells are utility use only

Fresh WSW Brackish WSW

Wolf Lake Primrose Grand Rapids McMurray

1F1/12-10-066-05W4M 1F1/10-05-67-04W4 102/10-08-66-5W4M 1F3/10-03-67-4W4M

1F2/12-10-066-05W4M 1F1/14-05-67-04W4 102/05-16-66-5W4M 1F1/11-06-67-3W4M

1F1/06-10-066-05W4M 1F2/15-05-67-04W4 104/05-16-66-5W4M 1F1/16-12-67-4W4M

1F2/06-10-066-05W4M 04-14-67-03W4 109/01-17-66-5W4M 1F1/11-05-67-3W4M

1F1/13-10-066-05W4M NW 08-068-04W4 107/02-17-66-5W4M 1F2/13-08-67-3W4M

1F2/13-10-066-05W4M NW 08-068-04W4 106/08-17-66-5W4M 1F1/14-08-67-3W4M

107/08-17-66-5W4M 1F1/12-09-67-3W4M

1F2/12-09-67-3W4M

1F1/10-08-67-3W4M

1F1/02-12-67-3W4M

1F1/07-06-67-3W4M

Water Production, Injection, and UsesWater Production, Injection, and Uses

CNQSlide 19


• Fresh water uses Utility water, utility steam, seal flush and gland water, slurry make-up, dilution water, filter

backwash, quench water, miscellaneous –ends up as boiler feed water Water softener regenerations – some of this water is recycled as boiler feed water and some is

used as cavern wash and then sent to disposal Fresh water may also be used for boiler feed water make-up as required

• Brackish water uses De-sand quench, filter backwash –ends up as boiler feed water Boiler feed water make-up supply

• Water Quality Assessment Quaternary Water Source Wells (6)

– Empress Unit 3 & Muriel Lake Formations– Average TDS = 609 mg/L, TDS ranges from 575 to 640 mg/L

Grand Rapids Fm. Water Source Wells (7)– Average TDS = 9,721 mg/L, TDS ranges from 8,900 to 10,300 mg/L

McMurray Fm. Water Source Wells (10)– Average TDS = 7,276 mg/L, TDS ranges from 6,470 to 8,570 mg/L

Produced Water Quality– Typical parameters: TDS = 7,102 mg/L, Cl = 3,700 mg/L, pH 7.3, hardness = 99 mg/L

CNQSlide 20


• Fresh, brackish, produced and steam injection volumes

CNQSlide 21

• Long term make-up yearly requirements approximately 35,000 m3/d• Reduction of fresh groundwater use – down to 3,000 m3/d in mid-2014

Excludes Surface Water and Cold Lake Fish Hatchery Effluent VolumesExcludes Surface Water and Cold Lake Fish Hatchery Effluent Volumes


CNQSlide 22

• PAW water volume summary for 2012 Wolf Lake Fresh Water - Average 9,427 m3/d Grand Rapids Brackish Water - Average 920 m3/d McMurray Brackish Water - Average 18,089 m3/d Burnt Lake Pilot Water – Cold Lake Fish Hatchery Effluent Diversion - Average 837 m3/d Plant Runoff Water – Average 352 m3/d


No runoff data before 2006No runoff data before 2006

CNQSlide 23

• Brackish to Fresh Groundwater Ratio Increase in brackish use compared to 2011 (19,065 vs. 13,512 m3/d) Average brackish to fresh groundwater ratio was 2.02 in 2012 (1.64 in

2011)

Excludes Cold Lake Fish Hatchery Effluent VolumesExcludes Cold Lake Fish Hatchery Effluent Volumes


CNQSlide 24

McMurray Fm Basal Aquifer Isopach Map - targeted due to prolific nature of aquifer

25 m Contour

IOR Pumping Centre

06-30 Obs Well

CNRL McMurray Wells

McMurray Brackish Water Supply – ExistingMcMurray Brackish Water Supply – Existing

• Producing wells 3 Horizontals and 7 Verticals 3 vertical wells brought online in Q1 2012

• 2012 production average – 18,089 m3/d maximum – 30,222 m3/d

• Drawdown of 69 m in obs well 6-30 (6 km from pumping centre)

14-02 Obs Well

CNQSlide 25

McMurray Brackish Water Supply – Phase 2 ExpansionMcMurray Brackish Water Supply – Phase 2 Expansion

• Phase 2 Expansion Develop new pumping centre in

NW67-3 and SW68-3– away from planned CSS

development– following basal aquifer fairway

north of existing pumping centre (PC1)

– add up to six water wells Refurbishment of old pipeline Construction of new pipeline and

roads in 2013/2014 Constraints

– Geology– Thermal development– Target circle– Mineral and surface rights

System operational by end of Q2 2014

CNRL McMurray Wells

August 2010

C-314 Target Circle

PC2

PC1

CNRL McMurray Wells

C-314 Target Circle

PC2

PC1

CNRL McMurray Wells

C-314 Target Circle

PC2

PC1

CNQSlide 26

Wolf Lake Primrose South Primrose East

WDW#1 - 100090806605W400 103100506704W400 100031106703W400

WDW#2 - 100100806605W400 1F1110206703W400

WDW#4 – 100050806605W400

WDW#5 - 100150706605W400

WDW#9 - 100140506605W400

• Primrose & Wolf Lake Project Disposal Water Well UWI Listing Wells shown in bold are active, (Wolf Lake - WDW#1 and WDW#9 are zonally abandoned)

• Wolf Lake (WDW #2, 4, & 5) Disposal scheme was amended on June 16/10 to allow injection into WDW #4 (Approval

8672A). Maximum wellhead injection pressures decreased from 17,500 kPa to 13,770 kPa; with the ability to inject at 17,500 kPa for a maximum time period of 24 hrs.– Injection pressures have not exceeded 13,770 kPa in WDW #2, 4, or 5 in 2012.

• Primrose South Injected 0 m3 fluid in 2012

• Primrose East 11-2 out of service since August 2007. Abandonment work still outstanding. Ongoing

discussions with ERCB

Water & Waste Disposal Wells, Landfill Waste UWI List & Disposal ComplianceWater & Waste Disposal Wells, Landfill Waste UWI List & Disposal Compliance

CNQSlide 27

Water & Waste Disposal Wells, Landfill Waste Wolf Lake Disposal VolumesWater & Waste Disposal Wells, Landfill Waste Wolf Lake Disposal Volumes

2012 Average Monthly Disposal Rates, Temperature and Pressure

0

500

1000

1500

2000

2500

3000

3500

4000

4500

Jan-12 Feb-12 Mar-12 Apr-12 May-12 Jun-12 Jul-12 Aug-12 Sep-12 Oct-12 Nov-12 Dec-12

Pres

sure

(MPa

)x10

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olum

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3/d

0

10

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30

40

50

60Flow Pressure Temp

WDW #2: 2012 Average Monthly Disposal Rates, Temperature and Pressure

-500

0

500

1000

1500

2000

2500

3000

3500

4000

4500


Pres

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(MPa

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0

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2000

3000

4000

5000

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7000

8000


Pres

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CNQSlide 28

• Water is stored in the C3 Formation Converted two wells to injectors

in June 2003

• Injected 348,255 m3 total 189,085 m3 to M2-S 159,170 m3 to M2-E

• M2-E and M2-S are currently configured for short notice injection M2-S

M2-E

Water & Waste Disposal Wells, Landfill Waste Wolf Lake Water StorageWater & Waste Disposal Wells, Landfill Waste Wolf Lake Water Storage

CNQSlide 29

Water & Waste Disposal Wells, Landfill Waste Wolf Lake Water Storage VolumesWater & Waste Disposal Wells, Landfill Waste Wolf Lake Water Storage Volumes

Wolf Lake Water Storage Volumes

Year MonthGross (m3/d)

Oil (m3/d)

Water (m3/d)

Water Inj (m3/d)

Gross (m3/d)

Oil (m3/d)

Water (m3/d)

Water Inj (m3/d)

2003 21 2 20 243 40 1 39 2922004 0 0 21 28 0.2 28 492005 0.3 420062007 146 174200820092010 16 0.032011 5.39 0.142012 Jan 13.74 0

Feb 19.14 0Mar 0 0Apr 6.90 0.33May 0 0Jun 0 0Jul 0.32 0.32Aug 0 0Sep 0 0Oct 12.90 0Nov 9.33 0.33Dec 0 0

M2_E M2_S

CNQSlide 30

Water & Waste Disposal Wells, Landfill Waste Wolf Lake Water Storage ComplianceWater & Waste Disposal Wells, Landfill Waste Wolf Lake Water Storage Compliance

• Formation Integrity and Pressure Monitoring Offset well reservoir pressures never exceeded the 2.5 MPa allowable during

injection periods M2-E injection packer successfully passed packer isolation test in 2012 M2-S injection packer successfully passed packer isolation test in 2012 No wellbore integrity issues encountered

• Wolf Lake Water Storage – Reservoir M2 & N2 Cumulative DI = 1.26

– Cumulative Gross Production = 12,535,817 m3

– Cumulative Oil Production = 1,539,321 m3

– Cumulative Steam Injected = 9,915,737 m3 CWE– Cumulative Water Injected = 348,235 m3

M2 & N2 Remaining Voidage = 2,271,845 m3

(CWE) Injected Steam TotalWater)(Bitumen Produced Fluid Total DI

CNQSlide 31

• From the outlined area (M2 wells and N2-F) Total Injected Water = 348,235 m3

since Jan ’03 Total Produced Water = 592,374 m3

since Jan ’03 Difference = 244,139 m3

• Expected to have minimal water storage in 2013.

Water & Waste Disposal Wells, Landfill Waste Wolf Lake Water Storage BalanceWater & Waste Disposal Wells, Landfill Waste Wolf Lake Water Storage Balance

CNQSlide 32

• Injectors appear to communicate readily with offset wells

• No problems anticipated when pumping out injected water

• Intend to maintain two wells as short notice injectors

• Expect to have minimal produced water storage in 2013

• M2-E and M2-S are classified as disposal wells on S-4 forms

Water & Waste Disposal Wells, Landfill Waste Wolf Lake Water Storage SummaryWater & Waste Disposal Wells, Landfill Waste Wolf Lake Water Storage Summary

CNQSlide 33

• Waste to CCS Lindbergh Cavern 107,125 m3– liquid wastes including drilling wastes for PAW production

(new pads) and OSE

• Waste to CCS Bonnyville Landfill 4,918 m3 – contaminated soil 59,944 tonnes - lime sludge waste

• Waste to RBW 845 m3 solid waste – contaminated soils, plastics, filters inorganic

chemicals, asbestos, scrap metal, glycol, caustics

• Waste to NewAlta 3,178 m3 – sludges 822 m3 – coemulsion

Water & Waste Disposal Wells, Landfill Waste Waste Disposal SummaryWater & Waste Disposal Wells, Landfill Waste Waste Disposal Summary

CNQSlide 34

Sulphur ProductionSulphur Production

• EPEA approval limits for SO2: PSP + WLP = 6.7 t/d PNP = 2.0 t/d PEP = 2.0 t/d

• CEMS values are used for reporting at all steam plants PNP from September 1, 2010 onward PEP, PSP, and WLP from April 1, 2011 onward

• Quarterly averages for all steam plants < 1.0 t/d sulphur

• Contingency for compliance with ID 2001-3 is currently to restrict/delay production to maintain sulphur level below 1 t/d quarterly average

CNQSlide 35

Sulphur Recovery StudySulphur Recovery Study

• Objective Q4 2012 decision to proceed or not proceed with Sulphur Recovery at any

one or all Primrose Steam Plants• Requirements Selection of Optimal Technology

– Liquid Scavenger Economic Assessment of Delayed Oil vs. Sulphur Recovery

– Based on April 2012 10 Year Plan and Sulphur Model• Conclusion Do not proceed with Sulphur Recovery at any of the Primrose Plants at

this time

CNQSlide 36


CNQSlide 37


• To maintain sulphur levels below 1 t/d, production from the following wells/pads were held back in Q1 2012: Month of February:

– Last 2 weeks of February:• Primrose South Pad 28 S & N held back 4,590 m3 oil production• Primrose North Pads 62 & 66 held back 1,070 m3 oil production• Township 68 pads held back 5,660 m3 oil production

Month of March:– Week of March 1:

• Primrose South Phases 13, 14, 28 S & N held back production» Production held back: 5,100 m3 oil

• Township 68 south 3 pads held back production: 5,100 m3 oil Production limitations lifted March 9, 2012

CNQSlide 38


• To maintain sulphur levels below 1 t/d, production from the following wells/pads were held back in Q1 2012 (Cont): Production limitations reinstated for March 20 - 28, 2012 Pads affected are as follows:

– Primrose North Plant (excluding Township 68 pads) – Held back 175 m3 of oil– Primrose South Plant – Held back 800 m3 of oil– Primrose North Plant Township 68 pads – Held back 975 m3 of oil

CNQSlide 39

• Compliance Issues EPEA Approval: Air Related

– OTSG NOx exceedance later verified and followed up as non-exceedance (Primrose East June 2, 2012)

– Heat recovery steam generator Continuous Emissions Monitoring System availability uptime <90% (Primrose South Dec 19, 2012)

Water Related:– Runoff pond licensing discrepancies (April 19, 2012 Primrose North and East plant) – E-Pond high pH water discharge (July 22, 2012 Primrose East)– WSW daily limit exceedance (Sept 11, 2012 Wolf Lake Plant)– WSW daily limit exceedance (Dec 4, 2012, PRS)– WSW daily limit exceedance (x5) (Dec 13, 2012, PRS).

Notice of Investigation – Surface Runoff Ponds– Primrose North and East runoff ponds investigation – use of runoff water without Water

Act approval– Water Act Approval subsequently obtained for runoff ponds

Administrative Penalty – unauthorized installation (2008) and operation of the Wolf Lake 4 flare stack

Environmental SummaryCompliance & AmendmentsEnvironmental SummaryCompliance & Amendments

CNQSlide 40

• Environmental Monitoring Programs currently underway include: Wildlife Monitoring Program Wildlife Mitigation Plan Wildlife Habitat Enhancement Program Wetlands and Hydrology Monitoring Program

Environmental SummaryMonitoring ProgramsEnvironmental SummaryMonitoring Programs

CNQSlide 41


• Objectives of Wildlife Monitoring Program To determine if the PAW project has an influence on the abundance and

distribution of wildlife species; The effectiveness of crossing structures; and

Distribution and movement of caribou.

• Wildlife Monitoring Program activities for 2012: Breeding songbird surveys

– 58 transects surveyedWinter track surveys

– 36 transects surveyedWoodland caribou cameras

– 41 remote cameras deployed for 12 weeks along eastern and northern boundaries of Project Area to capture seasonal movement of caribou in the fall.

CNQSlide 42


• Wildlife Mitigation Plan activities in 2012 Remote Camera Monitoring of Above-Ground Pipeline

– 30 remote cameras deployed along AGP to record wildlife behaviour and confirm wildlife movement under the AGP

– 30 remote cameras deployed along game trails or cutlines near remote camera areas on the AGP to record wildlife occurrence and behaviour as animals approach the pipeline

Wildlife Winter Tracking Along AGP– 38.6 km of AGP surveyed, noting movement patterns and wildlife behavioural

responses near the AGP • Wildlife Habitat Enhancement Program Nest Box Program

– 20 nest boxes maintained to confirm bird use during the breeding season. 30% showed evidence of use.

Revegetation Program– No activities in 2012; activities planned for 2013

CNQSlide 43

• Hydrology, Wetlands and Water Quality Monitoring Program 2012 2012 was the 6th year of the Hydrology Monitoring component which

provides monitoring for lakes within the PAW development area.

Water quality program (started in 2009) continued surface water quality data collection from Burnt Lake and Sinclair Lake

– ESRD approved reduction of sampling events from 3 to 2– Sampling locations and depths did not change from 2011 to 2012


CNQSlide 44


• Preliminary Results Hydrology Program

– Looseman Lake and North Reference Lake experienced average lake levels lower than the August 1, 2007 reference level. This may be attributed to changing outlet conditions or lower seasonal inputs.

Wetland Monitoring Program– 2012 re-measurement of wetland sites indicates only small differences in

species richness among monitoring and reference sites.

Water Quality Program– To-date, no large deviation was observed for surface water quality samples from

Burnt Lake and Sinclair Lake.– Phenol concentrations at Burnt Lake were at or above guideline concentrations

in a majority of samples.– Total phosphorus at or above guideline concentrations at Sinclair Lake.– Continued monitoring will determine if these results are indicative of a trend.

CNQSlide 45

• Reclamation activities in 2012: Reforested 13.6 ha of borrows in Primrose South. Infill planting on 10

ha of borrows in Primrose South and East. Total of 23.60 ha using 11,305 Trees and Shrubs.

• Proposed activities in 2013: Reforestation of 32.70 ha of Borrows in Primrose East. Planting of 0.52 ha Linear disturbances and 0.8 ha of non-linear

disturbances as part of our Habitat Enhancement Program.

Environmental SummaryReclamation ProgramsEnvironmental SummaryReclamation Programs

CNQSlide 46

• LICA Airshed Zone LICA is responsible for monitoring regional air quality Currently four continuous monitoring sites (Cold Lake, Maskwa, St. Lina

and Portable), 26 passive stations, two VOC and PAH samplers, and two soil acidification monitoring plots distributed throughout the region.

• Beaver River Watershed Alliance (BRWA): The BRWA serves as the Watershed Planning and Advisory Council (as

set out by Alberta Environment) for the Beaver River Watershed The BRWA State of the Watershed Report to be published spring 2013

provides a snapshot of watershed health and will act as the guiding document for development of the upcoming Water Management Plan for the Beaver River watershed.

Environmental SummaryRegional InitiativesEnvironmental SummaryRegional Initiatives

CNQSlide 47

• Arsenic Liberation in Groundwater Evaluate liberation of arsenic associated

with elevated groundwater temperatures from steaming Z8 Investigation ongoing since 2001 Measure arsenic concentration and

temperature in 30 wells – focus on 10 Empress Fm Wells ~ 150 m depth Temporal assessments associated with

steaming

• Results - Empress Formation

Background 75 m down-

gradient

360 m down-

gradientTemp 5.2 deg C 30.4 deg C 9.4 deg C

As Conc

0.041 mg/L 0.131 mg/L 0.056 mg/L

Sept to Nov 2012Sept to Nov 2012

Environmental SummaryMonitoring - Dissolved Arsenic Z8 PadEnvironmental SummaryMonitoring - Dissolved Arsenic Z8 Pad

CNQSlide 48

• Groundwater In-Situ Temperatures - Empress Formation - Overall down-gradient thermal plume migration- Temperatures decrease with distance from the Pad- Temperatures are increasing over time


CNQSlide 49

Z8-03 E1

• Groundwater Dissolved Arsenic Concentrations – Empress Formation- Overall down-gradient dissolved arsenic plume migration- Concentrations increasing at down-gradient wells - Dissolved arsenic concentrations at Z8-23 (135m) and Z8-25 (160m) are greater than

Z8-21 (75m)


CNQSlide 50

• Summary of Z8 Pad Field Findings – Empress Formation Increasing temperatures and concentrations at wells show that thermal

and dissolved arsenic plumes are migrating down-gradient Dissolved arsenic concentration 135 m down-gradient of Pad is just

greater than approximately 4 times background Dissolved arsenic plume expected to eventually detach from Pad as

plume migrates down-gradient (no steaming since 2005) Arsenic plume leading-edge is likely greater than 360 m down-gradient

• Program for New Monitoring Wells Selected locations for two new Empress Formation monitoring wells

(downgradient and cross-gradient) – expect to undertake in 2013• Ongoing Work Continued temperature and arsenic monitoring Regional Quaternary geology review Ongoing monitoring of arsenic in CNRL regional monitoring network


CNQSlide 51

Groundwater Monitoring at E14 PadGroundwater Monitoring at E14 Pad

16-32a16-32a

• A groundwater monitoring well was installed at E14 Pad (16-32-065-05W4M) as per the amendment to the Commercial Scheme Approval 9140I for SIB Pad

– Installed on the south side of the pad in July 2010 to monitor for changes in the basal quaternary aquifer associated with SIB operation

– Completed into the basal aquifer identified as the Muriel Lake (121 to 127 metres below ground surface)

– Instrumented to monitor water levels and temperatures

– Sampled semi-annually as part of regional groundwater monitoring program

NN SIBSIB

E14E14

CNQSlide 52

Groundwater Monitoring at E14 PadGroundwater Monitoring at E14 Pad

• Groundwater Monitoring Results for 16-32a - Anomalous water levels not noted- In-situ groundwater temperature at 7°C- Anomalous groundwater chemistry not noted (comparable to regional results Muriel

Lake Formation chemistry)

CNQSlide 53

Primrose East Pad 74 Risk Management PlanPrimrose East Pad 74 Risk Management Plan• The Primrose East groundwater management is continuing• Ongoing application of the Pad 74 Risk Management Plan

including:• Ongoing daily pressure and temperature monitoring in 24 wells on site• Ongoing monthly and quarterly groundwater sampling• Monthly reporting of Primrose East Area 1 (including Pad 74)

groundwater chemical analytical results (ERCB and ESRD)

• Monitoring and sampling results are reported annually to ESRD via PAW EPEA Approval since March 2012.

• Elevated dissolved solids and dissolved hydrocarbons have been noted in the past but currently neither exceed Tier 1 criteria.

CNQSlide 54

Pad 75 UpdatePad 75 Update• Elevated dissolved solids and dissolved hydrocarbons noted in

the Bonnyville Aquifer at Pad • Source believed to be release of BFW or produced water from

18A75 due to a casing breach• In 2012 remediation was initiated - pumped water from

Bonnyville Aquifer at three wells:• 05-12h July 11 through 24, 2012• 05-12g July 30 through October 22, 2012• 05-12f August 4 through October 22, 2012

• Recovered 235 m3 groundwater in total• Recovery system shut down for the winter on October 22, 2012• Pumping will resume in June 2013• Ongoing reporting to ESRD and ERCB

CNQSlide 55

• Out of Zone Casing Failures: There are 13 out of zone casing failures in PAW in 2012

Well Integrity- Summary of 2012 Casing FailuresWell Integrity- Summary of 2012 Casing Failures

Passive Seismic on Pad 66 damaged Jan 2012

CNQSlide 56

Well Integrity- Summary of 2012 Casing FailuresWell Integrity- Summary of 2012 Casing Failures• Out of Zone Casing Failures:Current status of 2012 out of zone casing failures

`

No high pressure well failures in 2012

All 2012 out of zone casing failures were at the connection

Well Primary/Slimhole

Tubular OD (mm) Failure In: Confirmation

DateCycle of Failure:

Well Phase During Failure Current Status

8C28 P 244.5 CONN 13-Feb-12 3 Pump Patched18A78 P 244.5 CONN 20-Feb-12 3 Pump Slimhole11A74 P 244.5 CONN 28-Feb-12 4 Pump On Production - Fluid Level Below Break14A77 P 244.5 CONN 28-Feb-12 3 Pump Slimhole4C28 P 244.5 CONN 23-Mar-12 3 Pump/WKO Patched8B51 P 244.5 CONN 17-May-12 3 Pump Zonally suspended6A66 P 244.5 CONN 30-May-12 5 Pump/WKO Slimhole

14A66 P 244.5 CONN 16-Jul-12 5 Pump Slimhole12A66 P 244.5 CONN 8-Aug-12 5 Pump/WKO Slimhole7A77 P 244.5 CONN 6-Sep-12 4 Pump On Production - Fluid Level Below Break

15A62 P 244.5 CONN 20-Sep-12 5 Pump Slimhole14A63 P 244.5 CONN 30-Sep-12 3 Pump Zonally suspended4B29 P 244.5 CONN 20-Dec-12 4 Pump Zonally suspended

CNQSlide 57

• In Zone Casing Failures: There are 18 confirmed in zone casing failures in 2012

Well Integrity- Summary of 2012 Casing FailuresWell Integrity- Summary of 2012 Casing Failures

Majority of the in zone failures were at TWP 68

CNQSlide 58

Well Integrity- Summary of 2012 Casing FailuresWell Integrity- Summary of 2012 Casing Failures• In Zone Casing Failures:Current status of 2012 in-zone casing failures

Well Primary/Slimhole

Tubular OD (mm) Failure In: Confirmation

DateCycle of Failure:

Well Phase During Failure Current Status

1A77 P 244.5 CONN 21-Mar-12 3 Pump/WKO Casing patch9C28 P 244.5 CONN 4-Apr-12 3 Pump Zonally suspended3A67 P 244.5 UNKNOWN 18-May-12 3 Pump/WKO Zonally suspended

11A62 P 244.5 UNKNOWN 19-May-12 5 Pump/WKO Zonally suspended1C27 P 244.5 CONN 8-Jun-12 4 Pump/WKO Casing patch

13A58 P 244.5 CONN 8-Jun-12 5 Pump/WKO Casing patch2C27 P 244.5 BODY 20-Jun-12 4 Pump Casing patch

13A62 P 244.5 CONN 10-Jul-12 5 Pump Initial mitigation was to slimhole2A67 P 244.5 Unknown 25-Jul-12 3 Steam Zonally suspended5A67 P 244.5 UNKNOWN 25-Jul-12 3 Pump Mech Plug9A63 P 244.5 CONN 22-Aug-12 3 Steam Casing patch

15A63 P 244.5 UNKNOWN 31-Aug-12 3 Trickle Steam Casing patch13A63 P 244.5 CONN 4-Oct-12 3 Steam On Production - Low Pressure16A63 P 244.5 UNKNOWN 10-Oct-12 3 Steam Casing patch10A63 P 244.5 CONN 2-Dec-12 3 Trickle Steam Casing patch10A59 P 244.5 CONN 13-Dec-12 3 Trickle Prod Casing patch12A63 P 244.5 CONN 14-Dec-12 3 Trickle Steam Casing patch6A63 P 244.5 CONN 17-Dec-12 3 Trickle Prod Casing patch

CNQSlide 59

Well and Formation IntegrityLogsWell and Formation IntegrityLogs

• Casing Pressure Monitoring No casing failures were detected via DFP (differential flow pressure)

• Corrosion Logs A Vertilog was run in Primrose East well 11A78 in response to

investigating a near surface casing failure at ~61m MD• No significant corrosion was observed from TD to surface

- A Vertilog was run on water source well 110 – Corrosion was found at ~450m at the pump landing depth

• Internal corrosion of the 273mm production casing occuring within the formation

– Design of future water source wells under review by the team to address this issue

CNQSlide 60

• Cement Bond Logs (CBL) 100% of all new wells in 2012 had cement bond logs run (160 total)

– 160 CSS down to the Clearwater Formation– Directive 51 applications were submitted for 9 pads

• 9 applications were approved by the ERCB 84 other wells had cement bond logs run in 2012 (All casing failures had a

cement bond log run for investigative and/or post repair purposes)– 13 post steam CBL’s were run for investigative purposes on well with up-hole

casing failures– CBL’s run at Primrose East:

• 17 CBL’s were run on observation wells • 43 CBL’s were run for investigative purposes on burnt lake primary wells

– CBL’s run at Primrose South:• 11 CBL’s were run on observation wells

Well and Formation IntegrityLogsWell and Formation IntegrityLogs

CNQSlide 61

Well and Formation IntegrityCasing and Cementing investigationsWell and Formation IntegrityCasing and Cementing investigations

• Review of casing failures at the BFS had indicated a correlation to collars placed within 4m of the BFS and failures of those collars. Drilling program has been modified to ensure a casing collar is not placed

within 4m of the BFS

• Review of casing failures at the CLWR top indicate that the connection closest to the shale/sand interface is most likely to fail

• Other drilling changes: Increased centralization through BFS and CLWR shale top

– BFS – to improve cement bond– CLWR – to decrease differential sticking to ensure rotation while cementing

CNQSlide 62

• Thermal fibre gives us the ability to monitor for fluid migration attributed to inferior cement jobs

• Thermal fibre is CNRL’s preferred method for fluid monitoring within the Colorado Shales

• Monitoring to date has shown no issues during steaming or production

• Data quality is acceptable, in that temperature profiles are repeatable

Formation IntegrityThermal FibreFormation IntegrityThermal Fibre

CNQSlide 63

Formation IntegrityB12 Pressure MonitoringFormation IntegrityB12 Pressure Monitoring

• B12 pressure monitoring has proven to be an effective addition to formation integrity surveillance during high pressure CSS Under certain circumstances it can be difficult to distinguish heave from

fluid invasion based on B12 pressure alone– Pressure anomalies in the B12 must be examined in conjunction with all

available data to determine pressure response sources:• Passive seismic, thermal fiber, injectivity plots, production data

Continue to obtain data to quantify the poro-elastic heave pressures in the B12 (Lower Grand Rapids) during high pressure CSS steaming

Primrose East, Township 68, Phase 28 and Phases 22-24 all are currently equipped with B12 monitoring equipment

– All new pads are equipped with B12 pressure monitoring

CNRL shall notify the ERCB if a B12 pressure increase/decrease is greater than 200 kPa/day

CNQSlide 64

• There were 3 wells abandoned in 2012 in the Primrose/Wolf Lake area.

• CNRL plans to review all suspended wells to determine which wells require abandonment in order to ensure compliance to ERCB Directive 13 requirements

Well and Pad AbandonmentsWell and Pad Abandonments

CNQSlide 65

ApprovalsApproval 9140P – Oil Sands Primrose Wolf Lake ApprovalsApproval 9140P – Oil Sands Primrose Wolf Lake

CNQSlide 66

• Original Approval – August 2002• Amendment A - Approved October 2003 Approval to conduct Gas and Gas Solvent enhanced

recovery pilot• Amendment B - Approved January 2004 Approval to develop PRN and decrease production

volume to 14,000 m3/d• Amendment C - Approved March 2007 Approval for PRE and increase production volume to

19,000 m3/d Approval for Orange Valley Sand Phases 41-50 and

Blue Valley Sand Phases 8, 9, 11, 12 (West)• Amendment D - Approved March 2007 Approval to expand the development area to include

67-5W4M Approval 6804 (Burnt Lake rescinded)

• Amendment E - Approved March 2008 Pads 58, 62, 66 modification to development plan

• Amendment F - Approved August 2008 Pads 59, 63, 7 modification to development plan

• Amendment G - Approved February 2010 Approval for McMurray MC1 SAGD Pad

Approval 9140P – Oil Sands Primrose Wolf Lake Approval 9140P – Oil Sands Primrose Wolf Lake

• Amendment H - Approved July 2010 Approval for Grand Rapids S1B SAGD Pad

• Amendment I - Approved September 2010 Approval for PRS Phases 22-24

• Amendment J - Approved November 2010 Approval for PRE Development Area 2

• Amendment K - Approved December 2010 Approval for Trim Treating during PEP Steam

Outage

• Amendment L - Approved August 2011 Approval for modification of PRE Phases 90/91

drainage boxes

• Amendment M - Approved October 2011 Approval for PRS Phases 25/26 Approval for PRN Phases 60, 61, 64, 65 & 68

• Amendment N - Approved February 2012 Approval for PRS D1 Steamflood Trial

• Amendment O - Approved May 2012 Approval for Wolf Lake Sparky B8 Trial

• Amendment P - Approved November 2012 Approval for Primrose South Phases 40-43

CNQSlide 67IN COMPLIANCE

• Annual Report(a) Summary of monthly injected and

produced volumes/well(b) Well/Formation Integrity(c) Reservoir Water Storage remaining(d) Water Balance, Bitumen Volumes

and Incremental Recovery(e) Overall performance and 2012 plans(f) Discussion of produced water

utilization & fresh water reductions

Approval 9108 – Wolf Lake Water StorageApproved July 2002 Approval 9108 – Wolf Lake Water StorageApproved July 2002

CNQSlide 68

• Approval Compliance Requirements Directive 51 Compliance Maximum Injection Pressures (kPa)

– F1/11-02-067-03W4/0 = 7800– 00/03-11-067-03W4/0 = 5500

• Injection packer isolation test failed on 11-2 in 2008 Well currently shut-in Work in progress

• No disposal in 2012 as water is now recovered and re-used

IN COMPLIANCE

Approval 8186A – Burnt Lake Water DisposalApproved February 1999 Approval 8186A – Burnt Lake Water DisposalApproved February 1999

CNQSlide 69

• Approval Compliance Requirements Directive 51 Compliance

• Operational injection pressure limit 13,770 kPa

• Maximum injection pressure 17,500 kPa for a 24 hour period

• Disposal wells are: WDW#1 - 00/09-08-066-05W4/0 WDW#2 - 00/10-08-066-05W4/0 WDW#4 - 00/05-08-066-05W4/0 WDW#5 - 00/15-07-066-05W4/0 WDW#9 - 00/14-05-066-05W4/0

IN COMPLIANCE

Approval 8672A – Wolf Lake Deep DisposalApproved June 2010 Approval 8672A – Wolf Lake Deep DisposalApproved June 2010

CNQSlide 70

• Approval Compliance Requirements Monitoring Maximum Injection Pressures Annual Report

– 2011 Report Submitted– 2012 Report will be prepared following annual cavern sounding

• Salt Cavern 1 – 118/12-8-66-5W4 Cavern volume (as of April 2012 sounding) 191,531 m3

Wash water 10,862 m3

Oily waste (bitumen) 25 m3

Solid waste 0 m3

Next Cavern sounding expected in April 2013 • Salt Cavern 2 - 119/12-8-66-5W4 – Washing Only Cavern volume (as of April 2012 sounding) 51,308 m3

Wash water 22,678 m3

Next Cavern sounding expected in April 2013

IN COMPLIANCE

Approval 8673 – Cavern DisposalApproved October 2000 Approval 8673 – Cavern DisposalApproved October 2000

CNQSlide 71

• Approval Compliance Requirements Originally approved 1983 Transferred to Canadian Natural from Dome Petroleum – September 2011 Directive 51 Compliance Maximum Wellhead Injection Pressures (kPa)

– 03/10-05-067-04W4/0 = 6,000

IN COMPLIANCE

Approval 3929A – Primrose Class 1b DisposalAmended September 2011 Approval 3929A – Primrose Class 1b DisposalAmended September 2011

CNQSlide 72

• Approval No. 4128D – Class II Disposal Transferred to Canadian Natural from Dome Petroleum – September 2011 Directive 51 Compliance 02/10-05-067-04W4/0 = 16,000 kPA

• Approval No. 9792A– Class II Disposal 00/14-02-065-08W4/0 has been abandoned and the approval was rescinded

September 2011

IN COMPLIANCE

Additional ERCB Disposal ApprovalsAdditional ERCB Disposal Approvals

CNQSlide 73

Compliance DisclosuresCompliance Disclosures

• Reportable spills 18 reportable spills were reported in 2012 including; 5

emulsion, 3 hydrochloric acid, 2 boiler feed, 1 hydrated lime, 1 oil, 1 sludge, 1 brackish water, 1 high pH, 1 produced water, 1 drilling mud and 1 diesel fuel.

• Digital Data Submissions (DDS) Notifications/Submissions were entered into the DDS as per Directives

in 2012.

CNQSlide 74

Non-ComplianceNon-Compliance

• ERCB Scheme Approval 9140 None

CNQSlide 75

Future PlansFuture Plans

• Wolf Lake Plant Control System & Electrical Upgrades Significant work ongoing to upgrade equipment and infrastructure

• Wolf Lake Unit 2 Improvements IGF Replacement, desand system upgrades

• Wolf Lake Salt Cavern Filtration Salt cavern return filtration and booster pumps

• Wolf Lake Oil Treating Capacity (9140 Approval 19,000 m3/d) Increasing plant capacity to ~ 23,000 m3/d

• Brackish Water System/Fresh Water Reduction Reduce fresh water usage to 3,000 m3/d: Additional supply wells,

pipelines, convert fresh water users to brackish water, glycol system expansion

Regulatory applications will be filed as required

CNQSlide 76

Future Plans Future Plans

• Wolf Lake Steam Generation Capacity Increase Reviewing addition of steam generation for future SAGD steam demand

and brackish heating

• Surface Facilities Associated with Field Development Primrose South/East/North Pads (PRS 25-26, PRS 40-43, PRN 60-68)

• Primrose East Heat Integration Re-piping inlet heat exchangers to optimize heat transfer

• Primrose South Steam Generator Economizer Upgrades Replace damaged equipment and improve efficiency, 2 OTSG’s targeted

for 2013 Replace damaged HRSG evap modules

Regulatory applications will be filed as required

CNQSlide 77

Certain statements in this document or documents incorporated herein by reference constitute forward-looking statements or information (collectivelyCertain statements relating to the Company in this document or documents incorporated herein by reference constitute forward-looking statements orinformation (collectively referred to herein as “forward-looking statements”) within the meaning of applicable securities legislation. Forward-lookingstatements can be identified by the words “believe”, “anticipate”, “expect”, “plan”, “estimate”, “target”, “continue”, “could” “intend”, “may”, “potential”, “predict”,“should”, “will”, “objective”, “project”, “forecast”, “goal”, “guidance”, “outlook”, “effort” “seeks”, “schedule” or expressions of a similar nature suggesting futureoutcome or statements regarding an outlook. Disclosure related to expected future commodity pricing, production volumes, royalties, operating costs, capitalexpenditures, and other guidance provided in the 2010 outlook section and throughout this document and the documents incorporated herein by referenceconstitute forward looking statements. Disclosure of plans relating to existing and future developments including but not limited to Horizon, Primrose East,Pelican Lake, Olowi Field (Offshore Gabon), and the Kirby Thermal Oil Sands Project also constitute forward-looking statements. This forward-lookinginformation is based on annual budgets and multi-year forecasts and is reviewed and revised throughout the year if necessary in the context of targetedfinancial ratios, project returns, product pricing expectations and balance in project risk and time horizons. These statements are not guarantees of futureperformance and are subject to certain risks. The reader should not place undue reliance on these forward looking statements as there can be noassurances that the plans, initiatives or expectations upon which they are based will occur.In addition, statements relating to “reserves” are deemed to be forward-looking statements as they involve the implied assessment based on certainestimates and assumptions that the reserves described can be profitably produced in the future. There are numerous uncertainties inherent in estimatingquantities of proved crude oil and natural gas reserves and in projecting future rates of production and the timing of development expenditures. The totalamount or timing of actual future production may vary significantly from reserve and production estimates.The forward-looking statements are based on current expectations, estimates and projections about the Company and the industry in which the Companyoperates, which speak only as of the date such statements were made or as of the date of the report or document in which they are contained and aresubject to known and unknown risks, uncertainties and other factors that could cause the actual results, performance or achievements of the Company to bematerially different from any future results, performance or achievements expressed or implied by such forward-looking statements. Such risks anduncertainties include, among others: general economic and business conditions which will, among other things, impact demand for and market prices of theCompany’s products; volatility of and assumptions regarding crude oil and natural gas prices; fluctuations in currency and interest rates; assumptions onwhich the Company’s current guidance is based; economic conditions in the countries and regions in which the Company conducts business; politicaluncertainty, including actions of or against terrorists, insurgent groups or other conflict including conflict between states; industry capacity; ability of theCompany to implement its business strategy, including exploration and development activities; impact of competition; the Company’s defense of lawsuits;availability and cost of seismic, drilling and other equipment; ability of the Company and its subsidiaries to complete its capital programs; the Company’s andits subsidiaries’ ability to secure adequate transportation for its products; unexpected difficulties in mining, extracting or upgrading the Company’s bitumenproducts; potential delays or changes in plans with respect to exploration or development projects or capital expenditures; ability of the Company to attractthe necessary labour required to build its thermal and oil sands mining projects; operating hazards and other difficulties inherent in the exploration for andproduction and sale of crude oil and natural gas; availability and cost of financing; the Company’s and its subsidiaries’ success of exploration anddevelopment activities and their ability to replace and expand crude oil and natural gas reserves; timing and success of integrating the business andoperations of acquired companies; production levels; imprecision of reserve estimates and estimates of recoverable quantities of crude oil, bitumen, naturalgas and liquids not currently classified as proved; actions by governmental authorities; government regulations and the expenditures required to comply withthem (especially safety and environmental laws and regulations and the impact of climate change initiatives on capital and operating costs); asset retirementobligations; the adequacy of the Company’s provision for taxes; and other circumstances affecting revenues and expenses. Certain of these factors arediscussed in more detail under the heading “Risk Factors”. The Company’s operations have been, and at times in the future may be affected by politicaldevelopments and by federal, provincial and local laws and regulations such as restrictions on production, changes in taxes, royalties and other amountspayable to governments or governmental agencies, price or gathering rate controls and environmental protection regulations. Should one or more of theserisks or uncertainties materialize, or should any of the Company’s assumptions prove incorrect, actual results may vary in material respects from thoseprojected in the forward-looking statements. The impact of any one factor on a particular forward-looking statement is not determinable with certainty as suchfactors are dependent upon other factors, and the Company’s course of action would depend upon its assessment of the future considering all informationthen available.Readers are cautioned that the foregoing list of important factors is not exhaustive. Unpredictable or unknown factors not discussed in this report could alsohave material adverse effects on forward-looking statements. Although the Company believes that the expectations conveyed by the forward-lookingstatements are reasonable based on information available to it on the date such forward-looking statements are made, no assurances can be given as tofuture results, levels of activity and achievements. All subsequent forward-looking statements, whether written or oral, attributable to the Company orpersons acting on its behalf are expressly qualified in their entirety by these cautionary statements. Except as required by law, the Company assumes noobligation to update forward-looking statements should circumstances or Management’s estimates or opinions change.

Forward Looking StatementsForward Looking Statements

CNQSlide 78

Special Note Regarding Currency, Production and ReservesIn this document, all references to dollars refer to Canadian dollars unless otherwise stated. Production data is presented on a before royalties basis unlessotherwise stated. In addition, reference is made to oil and gas in common units called barrel of oil equivalent (“boe”). A boe is derived by converting sixthousand cubic feet of natural gas to one barrel of crude oil (6 mcf:1 bbl). This conversion may be misleading, particularly if used in isolation, since the6mcf:1bbl ratio is based on an energy equivalency at the burner tip and does not represent the value equivalency at the well head.

ReservesFor the year ended December 31, 2010 the Company retained Independent Qualified Reserves Evaluators (”Evaluators”), Sproule Associates Limited andSproule International Limited (together as “Sproule”) and GLJ Petroleum Consultants Ltd. (“GLJ”), to evaluate and review all of the Company’s proved andproved plus probable reserves with an effective date of December 31, 2010 and a preparation date of February 14, 2011. Sproule evaluated the NorthAmerica and International crude oil, NGL and natural gas reserves. GLJ evaluated the Horizon SCO reserves. The evaluation and review was conducted inaccordance with the standards contained in the Canadian Oil and Gas Evaluation Handbook (“COGE Handbook”) and disclosed in accordance with NationalInstrument 51-101 – Standards of Disclosure for Oil and Gas Activities (“NI 51-101”) requirements. In previous years, Canadian Natural had been grantedan exemption order from the securities regulators in Canada that allowed substitution of U.S. Securities Exchange Commission (“SEC”) requirements forcertain NI 51-101 reserves disclosures. This exemption expired on December 31, 2010. As a result, the 2010 reserves disclosure is presented inaccordance with Canadian reporting requirements using forecast prices and escalated costs. The recovery and reserves estimates of crude oil, NGL andnatural gas reserves provided in this presentation are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual crudeoil, NGL and natural gas reserves may be greater than or less than the estimates provided.

Reserves estimates provided in this presentation are company gross, before royalties.

Resources Other Than ReservesThe contingent resources other than reserves (“resources”) estimates provided in this presentation are internally evaluated by qualified reserves evaluatorsin accordance with the COGE Handbook as directed by NI 51-101. No independent third party evaluation or audit was completed. Resources provided arebest estimates as of December 31, 2010. The resources are evaluated using deterministic methods which represent the expected outcome with nooptimism or conservatism.

Resources, as per the COGE Handbook definition, are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from knowaccumulations using established technology or technology under development, but are not currently considered commercially viable due to one or morecontingencies. There is no certainty that it will be commercially viable to produce any portion of these resources.

Due to the inherent differences in standards and requirements employed in the evaluation of reserves and contingent resources, the total volumes ofreserves or resources are not to be considered indicative of total volumes that may actually be recovered and are provided for illustrative purposes only.

Petroleum, bitumen or natural gas initially-in-place volumes provided are discovered resources which include: production, reserves, contingent resourcesand unrecoverable volumes.

Special Note Regarding non-GAAP Financial MeasuresManagement's discussion and analysis includes references to financial measures commonly used in the oil and gas industry, such as cash flow, cash flowper share and EBITDA (net earnings before interest, taxes, depreciation depletion and amortization, asset retirement obligation accretion, unrealized foreignexchange, stock-based compensation expense and unrealized risk management activity). These financial measures are not defined by generally acceptedaccounting principles (“GAAP”) and therefore are referred to as non-GAAP measures. The non-GAAP measures used by the Company may not becomparable to similar measures presented by other companies. The Company uses these non-GAAP measures to evaluate the performance of theCompany and of its business segments. The non-GAAP measures should not be considered an alternative to or more meaningful than net earnings, asdetermined in accordance with Canadian GAAP, as an indication of the Company's performance.

Volumes shown are Company share before royalties unless otherwise stated.

Reporting DisclosuresReporting Disclosures


Canadian Natural Resources Limited2500, 855 - 2 Street SW

Calgary Alberta T2P 4J8phone: 403.517.6700

fax: 403.517.7350email: [email protected]

www.cnrl.com

THE FUTURE CLEARLY DEFINED


2012 Primrose, Wolf Lake, and Burnt Lake Annual Presentation to the ERCB

Subsurface Issues Related to Resource Evaluation and Recovery

January 23, 2013

CNQSlide 2

Directive 54: Performance Presentations, Auditing, and Surveillance of In Situ Oil Sands Schemes

January 23, 2013

3.1.1 Subsurface Issues Related to Resource Evaluation and Recovery

January 24, 2013

3.1.2 Surface Operations, Compliance, and Issues Not Related to Resource Evaluation and Recovery

Primrose, Wolf Lake, and Burnt LakeAnnual Presentation to the ERCB for 2012Primrose, Wolf Lake, and Burnt LakeAnnual Presentation to the ERCB for 2012

CNQSlide 3

Page(s)• Geology and Seismic 4-29• PAW Artificial Lift Summary 31• Various Thermal Subsurface Well Design 32-33• PAW Steam Quality 34• SAGD Scheme Description 35-37• SAGD Reservoir Detail and Performance

• Burnt Lake SAGD Pilot 38-41• Wolf Lake SAGD 42-67

• CSS Scheme Description 68-80• CSS Reservoir Detail and Performance

• Primrose/Wolf Lake: Clearwater 81-101• 2013 Steam Schedules 102• Primrose East 2012 Update 103-114• Investigation Updates 115-120• Key Learning's 121-125• Primrose Next Developments 126-130• CSS Summary 131• Follow Up Process to CSS 132-138

Outline - Subsurface Issues Related to Resource Evaluation and RecoveryOutline - Subsurface Issues Related to Resource Evaluation and Recovery

CNQSlide 4

Primrose and Wolf Lake (PAW) Index MapPrimrose and Wolf Lake (PAW) Index MapDevelopment History for PAW

Orange/Blue Sand (Primrose South and North)1981-1983 (Dome): Moore Pilot Vertical Well CSS1992 (Amoco): CDD Pilot Phase 5 Horizontal Well Steam Drive1993-1999 (Amoco): Phase 1-20 Horizontal Well CSS1996 (Amoco): Phase 2-3 MWSDD Steam Drive Drainage Pilot1998 (Amoco): BD-18 SAGD Pilot2000 (CNRL): Phase 21 Horizontal Well HPCSS2003-2004: Phase 29-31 Horizontal Well HPCSS2004-2006: Phase 51-55 Horizontal Well HPCSS2003: Phase 14 Surfactant in Steam CSS2003: Phase A1-A2 Cyclic Gas2004: Phase A1 Cyclic Rich Gas2005: Phase B2 Solvent in Steam CSS2005-2007: Phase 27, 17 in-fill, 28 (80m spacing) Horizontal HPCSS2006: Phase BD-18 VAPEX2008-2009: Phase 58, 59, 62, 63, 66, 67 Horizontal Well HPCSS2010-2011: Phase 22-24 Horizontal Well HPCSS2011-2012: Phase 25-26 Horizontal Well HPCSS2011-2012: Phase 60,61,64,65,68 Horizontal Well HPCSSYellow Sand (Primrose East)1986-1988 (Suncor): Phase 14A-14B Slant Pads1996 (Suncor): Burnt Lake Pilot SAGD2007-2008 (CNRL): Phase 74, 75, 77, 78 Horizontal Well HPCSS2011-2012: Phase 90-95 Horizontal Well HPCSSValley Fill (Wolf Lake)1988 (BP): Z8 Vertical Well CSS1989 (Amoco): HWP1 SAGD Pilot2005 (CNRL): Z13 Vertical Well CSSC3 Sand (Wolf Lake)1966 (BP): Phase A Vertical Well Steam and Combustion Pilots1980-1985 (BP): Wolf Lake 1 West Vertical Well CSS1980-1985 (BP): Wolf Lake 1 East Vertical Well CSS1987-1988 (BP): Wolf Lake 2 Vertical Well CSS1994 (Amoco): Wolf Lake 1 East Horizontal MWSDD1996 (Amoco): Wolf Lake 1 West Horizontal MWSDD1999-2000 (CNRL): Phase E2 and N Horizontal CSSB10 Sand (Wolf Lake)1978-1988 (BP): Marguerite Lake Combustion Pilot1989 (BP): E14 Vertical Well CSS Pilot1997 (Amoco): D2 Pair 1 SAGD2000 (CNRL): D2 Pair 2-6 SAGD2000-2001: SD9 SAGD2001: S1A SAGD2004: S1A SAGD re-drill2010: S1B SAGDMcMurray Sand (Wolf Lake)2010 (CNRL): MC1 SAGD

CNQSlide 5

Primrose and Wolf Lake (PAW) OBIP within Approval Area 9140MPrimrose and Wolf Lake (PAW) OBIP within Approval Area 9140M

• OBIP numbers include McMurray, Clearwater and Grand Rapids pay

Total PAW OBIP :911 Million m3

• Pay criteria for each area and formation shown in subsequent slides

152 Million m3

(956 Million bbls)

230 Million m3

(1441 Million bbls)

80 Million m3

(502 Million bbls)

449 Million m3

(2800 Million bbls)

Average PAW Clearwater Reservoir Characteristics

• Oil saturation: 0.6• Bitumen weight: 9%• Pay thickness: 11m• Porosity: 32%• Horizontal permeability: 3,000mD• Vertical permeability: 900mD• Viscosity: 100,000cP (at 15oC)

CNQSlide 6

McMurray: Estuarine to shoreface deposits

Clearwater Formation:

• Compound incised valley system

• Estuarine deposit vary from valley to valley

• Valley specific reservoir facies assemblages

Grand Rapids B10: Shoreface deposits

Regional StratigraphyRegional Stratigraphy

CNQSlide 7

Representative Stratigraphic Cross SectionRepresentative Stratigraphic Cross Section

CNQSlide 8

PrimroseBlue Valley: bitwt >6%, >7m, (FAA has no Berthierine and <10% mud)

Orange Valley: bitwt >6%, >7m(O30 <10% mud)

Primrose EastYellow Valley: bitwt >6%, >7m(FA3 <10% mud, vertically continuous)

Wolf Lake C3 sand: bitwt >6%, (>10m, >8 ohm)Valley Fill: bitwt >6%

Clearwater Net Pay IsopachClearwater Net Pay Isopach

Regional Clearwater Net Pay Isopach

Contour Interval = 2mMinimum contour = 0m

CNQSlide 9

Clearwater Formation StructureClearwater Formation Structure

Reservoir Top Structure Reservoir Base Structure

• Clearwater reservoir base is the start of continuous deposits with bitwt >6% and <10% mud beds

• Clearwater reservoir top is the termination of continuous deposits with bitwt >6% and <10% mud beds

Contour Interval = 5m Contour Interval = 5m

CNQSlide 10

Reservoir Characteristics

• Reservoir: FAB & FAA• Avg. oil saturation: 0.62• Avg. bitumen weight: 9.3%• Max. net pay thickness: 23 m• Avg. porosity: 32%• Avg. horizontal permeability:

3,000mD• Avg. vertical permeability: 900mD• Avg. viscosity: 100,000cP (at 15oC)

1AA060406804W400

FAEFAD

FAC

FAB

FAA

Blue Sand (Primrose South and North)Blue Sand (Primrose South and North)

CNQSlide 11

1AA010506704W400

O10

O30

Orange Sand (Primrose South)Orange Sand (Primrose South)


• Reservoir: O10• Avg. oil saturation: 0.65• Avg. bitumen weight: 9.8%• Max. net pay thickness: 20m• Avg. porosity: 32%• Avg. horizontal permeability:


CNQSlide 12

1AA060106703W400

FA9

FA8

FA7

FA3

Yellow Sand (Primrose East)Yellow Sand (Primrose East)


• Reservoir: FA7, FA8 & FA9• Avg. oil saturation: 0.63• Avg. bitumen weight: 9.5%• Max. net pay thickness: 29 m• Avg. porosity: 32%• Avg. horizontal permeability:


CNQSlide 13

1AA102106605W400

VF30

VF20

VF10

Valley Fill (Wolf Lake)Valley Fill (Wolf Lake)


• Reservoir: VF20 & VF10• Avg. oil saturation: 0.57• Avg. bitumen weight: 8.9%• Max. net pay thickness: 42 m• Avg. porosity: 33%• Avg. horizontal permeability:

3,000mD• Avg. vertical permeability: 200 mD• Avg. viscosity: 100,000 cP (at 15oC)

CNQSlide 14

100160306605W400

VF30

C2

C3-10

C3-20

C3-30

C3 Sand (Wolf Lake)C3 Sand (Wolf Lake)


• Reservoir: C3-10 & C3-20• Avg. oil saturation: 0.50• Avg. bitumen weight: 7.8%• Max. net pay thickness: 17 m• Avg. porosity: 33%• Avg. horizontal permeability:

2,000mD• Avg. vertical permeability: 200 mD• Avg. viscosity: 100,000 cP (at 15oC)

CNQSlide 15

Grand Rapids B10Shoreface Sand

• Laterally continuous sandin FA4 & FA5, >30 ohm·m (Net Pay >10m for development)

• All 4 B10 SAGD Pads highlighted as black wells.

Contour Interval = 1m, Minimum 5m shown

Grand Rapids B10 Pay IsopachGrand Rapids B10 Pay Isopach

CNQSlide 16

Reservoir Top Structure

Contour Interval = 1mContour Interval = 1m

Grand Rapids B10 StructureGrand Rapids B10 Structure

Reservoir Base Structure

• SAGD pay defined as clean sand in FA4 and FA5 Average bitumen weight 11.5%

CNQSlide 17


• Reservoir: FA5 & FA4• Average oil saturation: 0.75• Average bitumen weight: 11.5%• Maximum net pay thickness: 16 m• Average porosity: 33%• Average HZ permeability: 3,200 mD• Average Vertical Permeability:

2,500 mD• No connected bottom water

100040406605W400

FA5

FA4

FA3

FA2

Wolf Lake SAGD B10 Sand Reservoir CharacteristicsWolf Lake SAGD B10 Sand Reservoir Characteristics

CNQSlide 18

McMurray Sand

• Laterally continuous sandBitwt >10%, >6 ohm·m, >5 m

• Net Pay >10 m for development

• 2012 strat wells in blue

Contour Interval = 1 m

Wolf Lake McMurray SAGD Pay IsopachWolf Lake McMurray SAGD Pay Isopach

CNQSlide 19

Reservoir Top Structure Reservoir Base Structure

Contour Interval = 1mContour Interval = 1m

• SAGD Pay defined by continuous clean sand and breccia. IHS is not included. • Base of reservoir, above bottom water, corresponds to bitumen weight 10% and 6 ohm·m.

Wolf Lake McMurray SAGD Pay StructureWolf Lake McMurray SAGD Pay Structure

CNQSlide 20


• Reservoir: FA5• Average oil saturation: 0.73• Average bitumen weight: 11.9%• Maximum net pay thickness: 19 m• Average porosity: 34%• Average HZ permeability: 7,000 mD• Average Vertical Permeability: 6,000 mD• Cut-off for pay: 6 ohm·m

Reservoir Characteristics- WL McMurrayReservoir Characteristics- WL McMurray

FA5

FA6

FA7

CNQSlide 21

Wolf Lake McMurray Bottom Water IospachWolf Lake McMurray Bottom Water Iospach

Contour Interval = .05 m

McMurray Bottom Water Isopach

• cut-offs are less than 6 ohm·m

• isopach represents a gross water interval

CNQSlide 22

Progress in 2012 Plans for 2013Progress in 2012 Plans for 2013

2012• 107 stratigraphic wells drilled

• 2 off pad observation wells drilled

• 134 CSS production wells drilled

2013• 55 stratigraphic wells planned

• 13 off pad observation wells planned

• 135 CSS production wells planned

CNQSlide 23

Cored Wells Within PAWCored Wells Within PAW

Total wells cored: 953

2012 wells cored: 106

2013 wells cored: 57

Wells with caprock core: 769

CNQSlide 24

Wolf Lake Seismic

- 2009 Wolf Lake I

- 2009 Wolf Lake II

- 2011Wolf Lake III

- 2012 Wolf Lake IV

- 2012 Primrose North XIII

3-D Seismic Wolf Lake - TWP 65/66 R 5/63-D Seismic Wolf Lake - TWP 65/66 R 5/6

CNQSlide 25

2012 3D Coverage

2011 3D Coverage

2010 4D Coverage

2010 3D Coverage

2009 4D Coverage

2008 3D Coverage

2004 3D Coverage

**All pre-steam seismic has been merged in 2012

3-D Seismic: Primrose East3-D Seismic: Primrose East

CNQSlide 26

3D Seismic: Primrose North and SouthTownship 67 & 68-04W43D Seismic: Primrose North and SouthTownship 67 & 68-04W4

• Primrose North & South 06-II-3D 09-IV-3D 09-V-3D 10-VIII 10-VI-3D 10-VII 12-XIV-3D 12- XIII-3D

• Primrose East (Adjacent) 12-XVII-3D

– (Merged Volume)

CNQSlide 27

• Showing a portion of 12- XIII-3D

• Pad 1-9 A column depleted reservoir

PRS Post Steam 3D SeismicPRS Post Steam 3D Seismic

• RMS amplitude map used to highlight Clearwater gas. (High RMS values indicative of gas) Both naturally occurring (pool at top and base of image) and solution gas due to steaming operations.(darker colors along eastern edge of image)

• The location of the gas is used for drainage box design as well as steam chamber conformance evaluation.

CNQSlide 28

• Spectral Decomposition attribute showing steam chamber development. Hot colors are indicative of greater presence of solution gas due to depletion or gas phase due to steam. When correlated with reservoir pressures, it is used to indicate relative distribution of steam chamber along each well bore.

• Reservoir pressures vary greatly North to South and affect the seismic response. Low pressures in the very North allow much gas to come out of solution. High pressures slightly south of top 4 rows and then decreasing pressures further south. These dynamic reservoir conditions allow chamber analysis comparisons only of wells at similar pressures.

• Appropriate buffers to other pads are also supported by this image.

PRN TWP 68 Post Steam 3D SeismicPRN TWP 68 Post Steam 3D Seismic• Showing a 12-

XIV-3D• Map shows

steam chamber development conformance on large portion of wells

CNQSlide 29

• Showing a portion of 12- XIII-3D• Paleozoic time structure map shows push down effect due to steam chamber development /depletion. Values are in Milliseconds.• Pushdown effect shows that degree of steam chamber development of wells in north pad are smaller (less depleted) than south pad. This

steam chamber development assessment will assist in further depletion planning

Wolf Lake Post Steam 3D SeismicWolf Lake Post Steam 3D Seismic

CNQSlide 30

Reservoir PerformanceReservoir Performance

• Artificial Lift Summary• Thermal Subsurface Well Design• Steam Quality• SAGD Recovery Process Basics• SAGD Typical Well Schematics• Burnt Lake SAGD Pilot• Wolf Lake SAGD• CSS Recovery Process Basics• CSS Typical Well Schematics• Wolf Lake CSS• Primrose Clearwater

CNQSlide 31

Artificial Lift Type & Distribution as at Dec. 31, 2012

Operating temperature range :50 C to 330 COperating differential pressure range : 1 kPa to 6500 kPa

Pump Size

Pump Jack

Stroke Length Efficiency SPM m3/d

2" 160 86" 80% 9 45

2.5" 456 120" 80% 9 100

2.5" 456 144" 80% 9 120

3.25" 456 120" 80% 9 170

3.25" 456 144" 80% 9 200

3.25" 1280 240" 80% 9 340

3.75" Rotoflex 288" 80% 5 300

4.75" Rotoflex 288" 80% 5 480

5.5" Rotoflex 288" 80% 5 650

Rod Pump Lift Capacity Range

Artificial Lift SummaryArtificial Lift Summary

Operating Area Rod Insert Pump Tubing Pump PCP ESP

Primrose South 538 2

Primrose North 164

Primrose East 193

Burnt Lake 3

Wolf Lake CSS 35 2 1

Wolf Lake SAGD 5 19 4

ESP Capacity Range

CNQSlide 32

• CSS– Phase 1-21: Dual pad layout, 160m spacing, 600m length, 16-20 horizontals per pad– Phase 29-31, 51-55: Superpad, 188m spacing, 1200m length, 16-20 hz’s, 8-10 deviated– Phase 27: Single pad, 160m spacing, 1400m length, 9 horizontals per pad– Phase 28N/S: Single pad, 75m spacing, 1000m length, 10 horizontals per pad– Phase 74-75, 77-78: Single pad, 60m spacing, 900m length, 20 horizontals per pad– Phase 22-24, 58-68: 80m spacing, 1200-1700m length, 18-20 horizontals per pad– Phase 90-95: Single pad, 60&80m spacing, 800-1600m length, 10-25 horizontals per pad – Phase 25-26; Single pad, 60&80m spacing, 600-1700m length, 15-20 horizontals per pad

• SAGD– Lateral Spacing ranges from 75-140m Spacing– Lateral lengths range from 650-1000m– Number of well pairs per pad range from 3-8

Thermal Subsurface Well DesignThermal Subsurface Well Design

CNQSlide 33

Well Spacing Throughout PAWWell Spacing Throughout PAW

• Phase 1-21, 27: 160 m spacing– Old standard spacing

• Phase 29-31, 51-55: 188 m– Super pad standard spacing

• Phase 28: 75 m spacing– Reduced to test increased recovery factor

• Phase 58,59,62,63,66,67: 80 m spacing– Reduced to increase recovery factor

• Phase 74-75, 77-78, 90-95: 60&80 m spacing– Reduced to implement future gravity drainage and increase recovery factor

• Phase 22-24, 60-61,64-65, 68: 80 m spacing– Current standard spacing

• Phase 25A/B,26, 60&80 m spacing– Current standard spacing and reduced for thin pay trial

CNQSlide 34

• The steam quality at most pads is between 0.5 and 1.0 percent lower than the quality at the plant (the furthest pads may be up to 4 percent lower)

• Quality change varies depending on the operating pressure, operating flow rates, line size and distance between the plant and the pad

Steam Quality - 2012Steam Quality - 2012

CNQSlide 35

SAGD Basics – Well Warm UpSAGD Basics – Well Warm Up

• For both wells of SAGD pair Inject steam down tbg. string to toe Produce water and steam via 2nd tbg. string from heel

• Continue steam circulation for 2 to 4 months Duration determined by temp. and performance observations Typical wellhead pressures of 1 to 8 MPa

• Measure and monitor injection and returned volumes, pressures and temperature

CNQSlide 36

SAGD Basics – Injection / ProductionSAGD Basics – Injection / Production

• Inject steam into upper well Balance between toe and heel Control based on reservoir response and temperature

observations in producer

• Pump fluid from lower well with artificial lift Monitor bottomhole pressure data for both injection and

production wells Bottomhole temperature observations influence how wells are

operated Generally withdrawal rates exceed steam injection rates Typical fluid production rates vary from 250 m3/d to 600 m3/d

CNQSlide 37

APPROX. 750 m TO 1000 m

APPROX. 1050 m TO 1900 m

• Surface casing vent assemblies to be installed after warm up• Where ESP’s are used, the ESP is attached to the end of the tubing string• Typical thermocouple spacing ~110 m (50m at MC1)

WL SAGD SchematicWL SAGD Schematic

CNQSlide 38

Burnt Lake SAGD Performance SummaryBurnt Lake SAGD Performance Summary

2012 Performance

2012 Optimization Highlights:

• Continued the LP SAGD operation at ~ 1,600 kPa

• Replaced 14CS1 steam control valves in January

• Operated with steam relatively evenly distributed between injectors until August. (~ 165 m3/d per injector)

• Redistributed steam in August dropping 100m3/d in less productive well pair 3 and increased steam to the better performing well pairs 1 and 2

well pair 1

well pair 2well pair 3

CNQSlide 39

Cum

ulat

ive

SOR

Burnt Lake SAGD PerformanceBurnt Lake SAGD Performance

CNQSlide 40

Burnt Lake Observation Well temperature Profiles (CS2/CP2: Horizontal length 1000 m)Burnt Lake Observation Well temperature Profiles (CS2/CP2: Horizontal length 1000 m)

CNQSlide 41

Burnt Lake SAGD Pilot - 2013 PlanBurnt Lake SAGD Pilot - 2013 Plan

• Continue SAGD optimization• Continue to incorporate LP SAGD operation with the Primrose

East development plan• Maintain current reservoir pressure• Continue to monitor SAGD performance and CSS steam

injection

CNQSlide 42

Wolf Lake SAGD Location MapWolf Lake SAGD Location Map

CNQSlide 43

Wolf Lake SAGDWolf Lake SAGD

• Current production is from B10 Grand rapids & MCMR

• S1A-2L: Re-circulated for 6 months and converted to SAGD production in Sept. 2012

• S1B: All well pairs on production as of Mar. 2012. S1B-4L was put back on circulation in July 2012.

D2(B10)

SD9(B10)

S1A(B10)

S1B(B10)

B10 Total

MC1(MCM)

Active Wellpairs 1 6 8 6 21 6

2012 Bit Prod, e3m3 3.9 67.9 75.8 62.9 210.5 140.3

2012 Avg. SOR (*dry steam) 5.9 3.8 4.3 4.1 4.5 3.4

Cumm Bit, e3m3 327.2 821.3 899.1 76.7 2,124.3 192.9

Cumm SOR (*dry steam) 4.6 3.7 3.8 4.9 3.9 3.5

OBIP, e3m3 1,877 1,819 2,682 1,971 8,349 1,443

2012 YE RF, % 17.4 45.2 33.5 3.9 25.4 13.4

CNQSlide 44

D2 P2~P6 Oct/2000

SD9 Jul/2001

B10 Grand Rapids SAGD Active PadsB10 Grand Rapids SAGD Active Pads

S1B Aug/2011

D2 P1 1997

D2 & SD9 perforated late

2003/early 2004

S1A Aug/2004

CNQSlide 45

Wolf Lake SAGDOperational StrategyWolf Lake SAGDOperational Strategy

• Operate wells based on a target steam chamber pressure and target sub-cool

• Steam chamber pressure is measured by annulus gas pressure in the injector and is controlled by the steam injection rate Target pressure for SD9 is 2200kPa Target pressure for S1A is 2500kPa Target pressure for S1B is 3500kPa Target pressure for MC1 is approximately 3400kPa (to maintain steam chambers at

or slightly above the bottom water pressure)– Weekly chloride samples and longer term water retention is monitored regularly

• Sub-cool is determined based on the difference between the saturated temperature of the steam chamber pressure and the highest temperature along the producer lateral Target to maintain a minimum 15-30oC sub-cool

CNQSlide 46

Wolf Lake SAGDSD9 Pad Total RatesWolf Lake SAGDSD9 Pad Total Rates

Perforated SD9

CNQSlide 47

Wolf Lake SAGDSD9-4 (Best Well)Wolf Lake SAGDSD9-4 (Best Well)

SD9-4 has the best performance on the pad with very few operational issues.

CNQSlide 48

Wolf Lake SAGDSD9-6 (Worst Well)Wolf Lake SAGDSD9-6 (Worst Well)

SD9-6 has the worst performance on the pad as it has a high water cut and required many workovers over the past year.

CNQSlide 49

Wolf Lake SAGDS1A Pad Total RatesWolf Lake SAGDS1A Pad Total Rates

CNQSlide 50

Wolf Lake SAGDS1A-8 (Best Well)Wolf Lake SAGDS1A-8 (Best Well)

S1A-8 has the best performance on the pad as it steadily produces at good oil rates.

CNQSlide 51

Wolf Lake SAGDS1A-4 (Worst Well)Wolf Lake SAGDS1A-4 (Worst Well)

S1A-4 has the worst performance on the pad as production is limited by steam breakthrough at the heel.

CNQSlide 52

• SAGD well pair: 6

• ERCB Approval: Jul 08, 2010

• Completed Drilling: Oct. 2010

• First Steam: Aug. 2011

• Hz section length: 900 m

• Inter- well-pair spacing: 100 m

• Avg. net pay: 12 m

• Avg. So: 75%

• Avg. porosity: 36%

• Est. RF: 45%

Wolf Lake SAGDB10 Pad S1BWolf Lake SAGDB10 Pad S1B

D2D2

SD9SD9

S1AS1A

S1BS1B

CNQSlide 53

Wolf Lake SAGDS1B Pad Total RatesWolf Lake SAGDS1B Pad Total Rates

CNQSlide 54

Wolf Lake SAGDS1B Circulation Summary TableWolf Lake SAGDS1B Circulation Summary Table

• S1B 3-6 on production in 2011. S1B-2 completed circulation in Jan. 2012. S1B-1 completed circulation in Mar. 2012.

• All steam values are dry steam.• S1B-4 back on circulation in July, 2012 (not included in table

above).

Totals by pairPair 1 2 3 4 5 6 Pad totalDays on circulation 185 156 96 106 98 104Average pressure (kPa) 4000 4000 4000 4000 4000 4000Cumul oil (m3) 2,435 1,986 1,486 1,740 1,511 1,905 11,064Cumul water (m3) 28,184 24,153 15,121 16,781 15,101 18,030 117,371Cumul steam injected (CWE, m3) 30,552 26,050 16,027 18,090 16,636 18,646 126,000% retention 7.7% 7.3% 5.6% 7.2% 9.2% 3.3% 6.8%

CNQSlide 55

Historical E14 CSS ProductionHistorical E14 CSS Production

• S1B pad affected by old E14 CSS production Perforated in Grand Rapids formation Abandoned CSS wells prior to drilling

S1B

• Enhanced mobility pathway from the injector to producer resulting in hot heels and cold toes

• S1B-1 is not affected by E14 wells

• Installed tailpipes to the toe of the producer laterals in S1B pairs 2, 3, 5, & 6 Effective in heating up producer toes

• S1B pair 4 back on circulation due to poor success with tailpipe

CNQSlide 56

73.0 mm (2 7/8”) Tailpipe New pump intake point (at toe)

Well Producer Schematic with TailpipeWell Producer Schematic with Tailpipe

Rod pump

CNQSlide 57

Temperature Profile Before & After TailpipeTemperature Profile Before & After Tailpipe

Before tailpipe

After tailpipe

CNQSlide 58

Wolf Lake SAGDS1B – 2 (Best Well)Wolf Lake SAGDS1B – 2 (Best Well)

S1B-2 has the best performance on the pad as it has performed smoothly since the tailpipe installation and is least affected by the E14 wells.

CNQSlide 59

Wolf Lake SAGDS1B – 5 (Worst Well)Wolf Lake SAGDS1B – 5 (Worst Well)

S1B-5 has the worst performance on the pad (other than pair 4 which was put back on circulation) as it shows the most affect by the E14 wells.

CNQSlide 60

• SAGD well pair: 6

• ERCB Approval: Feb 16, 2010

• Completed Drilling: Aug. 2010

• First Steam: May 2011

• Hz section length: 900 m

• Inter- well-pair spacing: 70 m

• Avg. net pay: 12 m

• Avg. So: 80%

• Avg. porosity: 34%

• Est. RF: 40%

Wolf Lake McMurray SAGD Pad MC1Wolf Lake McMurray SAGD Pad MC1

105

5

5

6

6

6

6

7

7

7

8

8

8

9

9

9

9

9

10

10

10

11

11

11

12

12

12

31

31

13

41

41

14

51

1551

16

17181

8.87.4

6.4

1012.9

14.3

11.4

11.4

11.5

14.5

19.3

9.4

7.1

0.9

8

3

10

16.6

16.6

8

18.017.517.016.516.015.515.014.514.013.513.012.512.011.511.010.510.09.59.08.58.07.57.06.56.05.55.04.54.0

METERS

0 102 204 306

CNQSlide 61

Wolf Lake McMurray SAGDMC1 Pad Total RatesWolf Lake McMurray SAGDMC1 Pad Total Rates

CNQSlide 62

Wolf Lake McMurray SAGDMC1 – 4 (Best Well)Wolf Lake McMurray SAGDMC1 – 4 (Best Well)

MC1–4 has the best performance on the pad. Although 4U has a steam splitter, this performance is mostly attributed to better geology at this location.

CNQSlide 63

Wolf Lake McMurray SAGDMC1 – 5 (Worst Well)Wolf Lake McMurray SAGDMC1 – 5 (Worst Well)

MC1–5 has the worst performance on the pad (other than PRS 1 & 2 which have had liner problems). This is attributed to poor geology at this location.

CNQSlide 64

Wolf Lake McMurray SAGDMC1 Observation Wells – TWP 066-05W4Wolf Lake McMurray SAGDMC1 Observation Wells – TWP 066-05W4

CNQSlide 65

Wolf Lake McMurray SAGDObs Wells LearningsWolf Lake McMurray SAGDObs Wells Learnings

MC1 OBS Well 1 Temperature profile (111/03-10-66-5W4)16.2 m from MC1-6 laterals (between MC1-5 and MC1-6)

495

505

515

525

535

545

0 25 50 75 100 125 150 175 200 225 250

Temperature (deg C)

Dep

th (m

KB

)

7/1/20118/1/20119/1/201110/2/201111/2/201112/2/20111/2/20122/2/20123/4/20124/5/20125/6/20126/6/20127/7/20128/7/20129/7/201210/8/201211/7/201212/8/2012CLEARWATERGRAND RAPIDSWABISKAWVIKINGJOLI FOUPALEOZOICMCMURRAYSAGD+UPSIDE TOPSAGD PAY BASESAGD PAY TOPMCMR NET BOT H20 TOPInjector depth (MC1-6)Producer depth (MC1-6)saturated steam temperature

Slowly heating up

CNQSlide 66

Wolf Lake McMurray SAGDMC1 LearningsWolf Lake McMurray SAGDMC1 Learnings• Successfully ran ESPs (4/6 wells currently on ESP)

• MC1-1L Re-drill planned for 2013 (2 patches were installed in 2012 but sand problems continued)

• MC1-2L Slimhole successfully installed in Nov 2012. Ramping up production rates on this well

• MC1-4L direct injection learnings Initial production temperatures were coolerWell performance is similar to offsetting well pairs Does not appear to have had any negative impacts compared with

circulation

• All wells impacted by low quality reservoir at the heels High temperatures seen in heel regions of producers – some are

production limiting

CNQSlide 67

Wolf Lake SAGD - 2013 PlanWolf Lake SAGD - 2013 Plan

• Continue operation and evaluation of SAGD performance

• Convert S1B-4L back to SAGD production in Q1 2013

• Re-drill MC1-1L in Q2 2013

• Investigate the possibility of installing scab liners in MC1 producers to mitigate hot spots at the heel

CNQSlide 68

Cyclic Steam Stimulation OverviewCyclic Steam Stimulation Overview

• CSS Basics Steaming Geomechanics Depletion Well Design OBIP Recovery

• Wolf Lake Update Valley Fill C3 Sands

• Primrose Update Oil, Water, Steam Current and Potential Recoveries Performance Variation 2013 Steam Schedule Investigation Updates Key Learning's 2012 2013 Development

CNQSlide 69

CSS Basics - SteamingCSS Basics - Steaming

• Steam Generation - Quality of ~75%, ~15 MPa.

• Inject high pressure steam to fracture reservoir Typical fracture gradient is 21 kPa/m. (@500 m TVD, fracture at 10.5 MPa) Dilate reservoir

• Steam is waved through a series of wells

• Rate and volumes are dependent on well geometry and cycle number Recent first cycle volumes are ~30-50,000 m3 for 1200 m laterals

– Historically 80-100,000 m3

Volumes are increased in subsequent cycles– Aim to have a minimum of 50% injected at fracture pressure to ensure contact with cold

reservoir

• Reservoir pressure management Starts with fill up volumes to increase reservoir pressure ahead of fracturing wells

2-5 wells ahead of steam Soak wells 3+ rows behind steam injection

CNQSlide 70

CSS Basics – SteamingRelationship of Cycle Volumes to Cycle and Ultimate RecoveryCSS Basics – SteamingRelationship of Cycle Volumes to Cycle and Ultimate Recovery

• First cycle steam volumes have little to no impact on the thermal efficiency of the cycle Performance is dependent on near well bore reservoir quality

• Mid to late life reduced cycle steam volume Increases number of cycles a well receives during its life

– Increasing casing integrity risk– Reduces thermal efficiency (reheating water within reservoir)– Increases risk of inter-well communication with multiple pressure cycles through a given

area (reducing thermal efficiency)

• Ultimate recovery is believed to be improved by increased cycle volumes due to improved thermal efficiencies

CNQSlide 71

CSS Basics - SteamingCycle 1 Low Volume Steam InjectionCSS Basics - SteamingCycle 1 Low Volume Steam Injection• CNRL believes in continuous improvement to steam strategies to maximize

recovery and reduce risk, and continues to examine cycle performance

• Low cycle 1 steam volume More difficult to manage field CDSR’s with small volumes and routine growth

– Too low a CDSR results in production issues and liner plugging/failing• Observed in TWP 68 experience

– Time to perform well maintenance is negligible

• A 10,000m3 steam slug was used in Phase 91 in Nov, 2012 Determined to be a prudent steam volume considering the fault location

• Goal of initial steam injection is to increase the horizontal stress by increasing poro-elastic and thermal elastic stresses which leads to horizontal fractures Whether a pause/production is necessary between a low 1st cycle volume and a

larger 2nd cycle volume is still under investigation

CNQSlide 72

CSS Basics - SteamingProactive Reservoir Pressure ManagementCSS Basics - SteamingProactive Reservoir Pressure Management• Inter-well communication has been shown to reduce reservoir performance.

Risk managed by controlling pressure gradients around wave.

• Front of Wave Design for a fill-up steam bank ahead of wave which establishes a controllable

pressure gradient ahead of the wave

• Behind Wave Soaking wells

– Use stress to confine steam injection

Flow back wells– Design a flow back rate

that balances production while keeping reasonable pressure differentials (dPs) between wells

DI = ‘Depletion Index’ = Total Fluid Produce/Steam Injected

Reservoir Depressurization with Produced Fluids

y = - 14.8 x + 10.0

y = - 17.4 x + 10.0

0

2

4

6

8

10

12

0 0.1 0.2 0.3 0.4 0.5

DI

Rese

rvoi

r Pre

ssur

e (k

Pa) Cycle 1

Cycle 2

CNQSlide 73

CSS Basics - SteamingFlow back RateCSS Basics - SteamingFlow back Rate• Flow back rate affected by: Steam slug size

– Larger steam slugs will have smaller dP’s at the same flow back rate Design maximum dP’s between rows

– Larger maximum dP’s between rows allows for a higher flow back rate– Approximately 1MPa between rows has been targeted

Wave speed– The faster the wave, the higher the flow back rate can be without going over the

max dP between rows Cycle number

• Optimized flow back rate is not a constant

CNQSlide 74

Geomechanics Horizontal Fractures DominateGeomechanics Horizontal Fractures Dominate

• Initial Clearwater stress state favours vertical fracturing• Initial, vertical > horizontal,min• Injection of steam increases the horizontal stresses such that horizontal

fractures are induced, vertical < horizontal

0

100

200

300

400

500

6000 2,000 4,000 6,000 8,000 10,000 12,000 14,000 16,000

In situ Stress, kPa

TVD Depth, mKB

Grand Rapids

v = 21.0 kPa/m

Clearwater Shale Cap

Horizontal Fractures Favoredh > v

Joli Fou Shale

Westgate Shale

Upper Colorado Shale

Lea Park

11-11-67-3W411-12-67-3W4

Clearwater SandClearwater Shale Cap

h min = 24-30 kPa/m

h min = 17-21 kPa/m

Vertical Fractures Favoredv > h

Belle Fourche ShaleSecond White Speckled Shale

Primrose East In Situ Stress Test Data

• Clearwater shale has been proven to be a competent barrier for HPCSS

• Colorado Group is considered the regional seal in the Cold Lake region protecting the Quaternary aquifers

• Stress state is affected by Temperature and Pressure

CNQSlide 75

Geomechanical Stress Test Results Geomechanical Stress Test Results

Well alias UWI MPP Pclosure Pisip Gradient CommentsTVD kPa kPa kPa/m

WL 05-15 100/05-15-66-5W4 244.0 N/A 6,300 25.8 Test Performed Sep 2000WL 05-15 100/05-15-66-5W4 284.0 N/A 8,600 30.3 Test Performed Sep 2000WL 05-15 100/05-15-66-5W4 325.0 N/A 8,300 25.5 Test Performed Sep 2000WL 05-15 100/05-15-66-5W4 386.0 N/A 6,300 16.3 Test Performed Sep 2000WL 05-15 100/05-15-66-5W4 408.5 N/A 7,500 18.4 Test Performed Sep 2000WL 05-15 100/05-15-66-5W4 439.8 N/A 8,100 18.4 Test Performed Sep 2000

PRE 11-11 100/11-11-67-3W4 172.0 3,517 N/A 20.4 Test Performed Mar 2009PRE 11-11 100/11-11-67-3W4 221.4 3,966 N/A 17.9 Test Performed Mar 2009PRE 11-11 100/11-11-67-3W4 271.5 6,730 N/A 24.8 Test Performed Mar 2009PRE 11-11 100/11-11-67-3W4 313.5 8,647 N/A 27.6 Test Performed Mar 2009PRE 11-11 100/11-11-67-3W4 336.5 10,660 N/A 31.7 Test Performed Mar 2009PRE 11-11 100/11-11-67-3W4 473.6 11,313 N/A 23.9 Test Performed Mar 2009PRE 11-11 100/11-11-67-3W4 481.7 9,753 N/A 20.2 Test Performed Mar 2009

PRE 11-12 100/11-12-67-3W4 317.5 8,523 N/A 26.8 Test Performed Mar 2009PRE 11-12 100/11-12-67-3W4 385.0 6,553 N/A 17.0 Test Performed Mar 2009PRE 11-12 100/11-12-67-3W4 414.5 8,602 N/A 20.8 Test Performed Mar 2009PRE 11-12 100/11-12-67-3W4 495.7 13,760 N/A 27.8 Test Performed Mar 2009

PRN 11-14 100/11-14-68-4W4 231.5 6,317 N/A 27.3 Test Performed Jan 2010PRN 11-14 100/11-14-68-4W4 287.0 8,767 N/A 30.5 Test Performed Jan 2010PRN 11-14 100/11-14-68-4W4 463.0 9,533 N/A 20.6 Test Performed Jan 2010PRN 11-14 100/11-14-68-4W4 481.0 10,800 N/A 22.5 Test Performed Jan 2010

CNQSlide 76

CSS Basics - DepletionCSS Basics - Depletion

• CSS consists of 3 depletion stages 1) Trickle Producing/Steaming

– Keeps casing hot without depleting reservoir pressure 2) Flow back – reservoir pressure > static head of fluid + group line pressure 3) Pumping – reservoir pressure <= (static head of fluid + group line pressure)

– Rate is initially limited by pump capacity1 2 3

CNQSlide 77

CSS Basics – Well DesignCSS Basics – Well Design

Typical Horizontal CSS WellMETRES

TVD0

100

200

300

400

500

QUATERNARY

COLORADOSHALES

GRANDRAPIDS FM.

CLEARWATER FM.

McMURRAY FM.

Surface Casing, Thermally Cemented, 340mmSet Between 30m and 120m Depending On Surrounding Area

Kick-Off Point ~130m TO 220m

Intermediate Casing, Thermally Cemented244.5mm, 59.5kg/m, Metal To Metal Seal Connections, L80 Or PS80

Centralizers

Pump Slotted Liner177.8mm, 34.2kg/m or 168.3mm, 29.76kg/m

Burst Pup Joint

Production Tubing114.3mm

Continuous Rod

ThermalCement

Casing Vent Or Steam InjectionFluid Production

Approx. 800-1600m

Approx. 1100-2000m

CNQSlide 78

CSS Basics – Observation WellsCSS Basics – Observation Wells

Passive Seismic Monitoring

Grand Rapids Top (B8 or B10) Pressure and Temperature Sensor

Grand Rapids Top (B12) Pressure and Temperature Sensor

Ground Level

Thermal Fibre Cable Geophones: Cemented into place

Spacers

Grand Rapids Monitoring

CNQSlide 79

CSS Basics - OBIP AssumptionsCSS Basics - OBIP Assumptions

• Area is 1 well spacing wide by length of well plus ½ spacing on each end• Net pay is as previously defined in the Geology section• Oil saturation is determined from Bitumen Weight percentage assuming a

sand/shale density of 2650 kg/m3, water/oil density of 1000 kg/m3, and 32% porosity

Saturation Oil Porosity Pay Net AreaOBIP

CNQSlide 80

CSS Basics - RecoveryCSS Basics - Recovery

• CSS life is dictated by the economic limits (SOR)

• Typical economic SOR limit 6-10– Oil/Gas price ratio dependant– Current SOR economic limit is >14

• Forecasting is based on a type curve• Recovery is a function of amount of

steam injected• Goal of steam scheduling is to

maximize rates and recovery• Type curve uncertainty exists for

greater than 15% recovery at 160m spacing

Type Curve - Recovery as a function of steam volume injected.

0%

5%

10%

15%

20%

25%

30%

0 0.2 0.4 0.6 0.8

PV Stm

% O

BIP

Reco

very

CNQSlide 81

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File: SAGD-B10.MAP Datum: NAD27 Projection: Stereographic Center: N54.70586 W110.70604 Created in AccuMap™, a product of IHS

Z13

Z8

2012 Performance Summary

CNQSlide 82

Z13 Nov/2005

Z8 Nov/1988

HWP1 Oct/1993

Wolf Lake Valley Fill CSS, All PadsWolf Lake Valley Fill CSS, All Pads

CNQSlide 83

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N

E2N2

M2

2012 Performance Summary

Wolf Lake C3 Sand CSSWolf Lake C3 Sand CSS

• No steam available in 2012

• Cycle 6 planned for E2 in 2013

CNQSlide 84

E2 Oct/2000

N Nov/2000

Wolf Lake C3 Sand CSS – Phases E2, D2D & NWolf Lake C3 Sand CSS – Phases E2, D2D & N

CNQSlide 85

Wolf Lake 2012 / Potential RecoveriesWolf Lake 2012 / Potential Recoveries

CNQSlide 86

Primrose Oil, Water, Steam, and SORPrimrose Oil, Water, Steam, and SOR

CNQSlide 87

Wolf Lake Oil, Water, Steam, and SORWolf Lake Oil, Water, Steam, and SOR

CNQSlide 88

Primrose & WL Oil, Water, Steam, and SORPrimrose & WL Oil, Water, Steam, and SOR

CNQSlide 89

Primrose Current Recoveries - 2012Primrose Current Recoveries - 2012

CNQSlide 90

Primrose Current / Potential RecoveriesPrimrose Current / Potential Recoveries

• Using existing well performance to 31 Dec 2012

CNQSlide 91

Primrose Performance VariationPrimrose Performance Variation

Predictable performance up to 15% recovery factor

CNQSlide 92

Below Average Performance - Phase 74Below Average Performance - Phase 74

• Average Reservoir Parameters Net Pay 23 m Oil Saturation 73% Porosity 32%

• Below Average Performance• Increased interwell

communication• Well placement

• 20 horizontal wells at 55 m spacing (average)

• Forecasting 45% actual recovery at 40% PV steam

Recovery shown for normalized 160m well spacing

CNQSlide 93

Average Performance – Phase 58, 62 and 66Average Performance – Phase 58, 62 and 66

• 13.0 m height, 9.8% Bitumen Weight

• Average Primrose CSS Performance Average thickness, average

quality reservoir

• 20 horizontal wells per phase at 80 m spacing

• 30% actual recovery at 43% PV Stm by end of next 2 CSS cycles

Recovery shown for normalized 160m well spacing (actual recovery is twice what is shown)

CNQSlide 94

Above Average Performance - Pad 22-24Above Average Performance - Pad 22-24

• 13.4 m height, 9.1% bitumen weight

• Performance is above average• 28% actual recovery at a 0.4

pore volume steam• 54 horizontal wells with 2 high

pressure cycles and 80 m spacing

Phase 24 Estimated Volumes

0%

2%

4%

6%

8%

10%

12%

14%

16%

18%

20%

0 0.2 0.4 0.6PV Stm

% R

ecov

ery

% Recovery ActualsForecast Type Curve End Point% Recovery Forecast% Recovery Type Curve

Recovery shown for normalized 160m well spacing (actual recovery is twice what is shown)

CNQSlide 95

Tight Spacing Well PerformanceType Curves for T68,Pad 28 and Primrose East (PRE) Phase 1Tight Spacing Well PerformanceType Curves for T68,Pad 28 and Primrose East (PRE) Phase 1

Tight Spacing Wells Type Curves Normalized to 160m SpacingT68 Phase Factor 160/80 =2.0

Pad 28 Phase Factor 160/75 = 2.1Primrose East Phase Factor 160/60 = 2.67

0.000

0.020

0.040

0.060

0.080

0.100

0.120

0.140

0.160

0.180

0.000 0.050 0.100 0.150 0.200 0.250 0.300 0.350 0.400 0.450 0.500

Pore Volume Steam (dec)

Rec

over

y Fa

ctor

Nor

mal

ized

(dec

)(m

ultip

ly b

y Ph

ase

Fact

or to

get

ac

tual

reco

very

)

T68 Phase 58, 62, 66 T68 Phase 59, 63, 67 Type Curve Phase 59,63,67 = 0.88Type Curve Phase 58, 62, 66= 0.77 Pad 28 Type Curve Pad 28 = 0.84Primrose East Area 1 Type Curve PRE= 0.82

* Actual data points are solid, Forecast data Points are outlines

•These type curves are the same as an average 160 m spaced well

•The down spaced performance is on the type curve

•Therefore the recovery is incremental

CNQSlide 96

Tight Spacing Well PerformanceCSS Well Spacing ConceptTight Spacing Well PerformanceCSS Well Spacing Concept

• Steam can travel to a certain distance before its efficiency drops below the economic limit

• Optimum well spacing will yield maximum recovery, reserves and NPV

• Affected by reservoir quality and commodity prices

• Field examples Canadian Natural’s Primrose South

– 80 m vs. 160 m Spacing

Imperial Oil’s Cold Lake– 2, 4 and 8 Acre spacing– Infill from 4 Acre to 2 Acre Spacing

CNQSlide 97

D1 80 m C1 & B1 160 m

Pads that are in the same reservoir but at different well spacing

Tight Spacing Well PerformanceField Example: Canadian Natural’s Primrose SouthTight Spacing Well PerformanceField Example: Canadian Natural’s Primrose South

CNQSlide 98

Comparison of D1 (80 m spacing) with C1 and B1 (160 m Spacing ) Wells

-

50,000

100,000

150,000

200,000

250,000

300,000

- 200,000 400,000 600,000 800,000 1,000,000 1,200,000

Cum. Steam (m3)

Cum

. Oil

(m3)

C1 Wells (160 m)D1 Low Wells (80 m)D1 High Wells (80 m)B1 Wells (160 m)

Production data indicates wells have a similar performance profile regardless of spacing

Tight Spacing Well PerformanceField Example: Canadian Natural’s Primrose SouthTight Spacing Well PerformanceField Example: Canadian Natural’s Primrose South

CNQSlide 99

B3: 4 Acres

C3: 4 Acres

FF: 2 Acres

F5: 4 Acres

EE: 2.6 Acres

L: 4 Acres

T4,T2,U1,U4: 8 Acres

Tight Spacing Well PerformanceField Example: Imperial Oil’s Cold LakeTight Spacing Well PerformanceField Example: Imperial Oil’s Cold Lake

CNQSlide 100

Cum. Steam and Cum. Oil for Diffferent Well Spacing in IOL's Cold Lake

-

100,000

200,000

300,000

400,000

500,000

600,000

700,000

800,000

900,000

- 500,000 1,000,000 1,500,000 2,000,000 2,500,000Cum. Steam (m3)

Cum

. Oil

(m3)

FF Pad (2.0 Acre)FF03 Pad (4.0 Acre)FF05 (4.0 Acre)EE Pad (2.0 Acre)B03 Pad (4.0 Acre)C03 Pad (4.0 Acre)U1 (8 Acre)T4 (8 Acre)L (4 Acre)U4 (8 Acre)T2 (8 Acre)

IOL’s wells at various spacing shows similar performance profiles regardless of well spacing

Tight Spacing Well PerformanceField Example: Imperial Oil’s Cold LakeTight Spacing Well PerformanceField Example: Imperial Oil’s Cold Lake

CNQSlide 101

Tight Spacing Well Performance ConclusionsTight Spacing Well Performance Conclusions

• Tighter spacing wells perform with similar normalized thermal efficiency as larger spacing wells

• Similar cumulative oil volume vs steam volume performance per well regardless of spacing

• This results in a higher actual recovery for a densely spaced pad of the same area

• Currently on track to approximately double the recovery

• Tighter well spacing will increase ultimate oil recovery for CSS

• 60-80 m (or 2 Acre) spacing is currently standard for CNRL’s PAW area

CNQSlide 102

2013 Steam Schedules2013 Steam Schedules

Primrose South

Primrose East

Primrose North

CNQSlide 103

• Current Cycle Steamed West to East from February through October 2012 There were two material pauses in the steam wave

– March 2012 following a B12 pressure response in 108/09-02-067-03W4– April 2012 following a B12 pressure response in 100/11-01-067-03W4/2

In both cases steam injection rates were reduced, wells monitored and data analyzed until it was determined the steam wave could continue Continually monitoring and analyzing current cycle performance to

optimize next cycle

• Next Cycle Next steam cycle for Primrose East Area 1 scheduled for Q1, 2014 Current plan is to continue high pressure CSS in next cycle and evaluate

low pressure gravity drainage or other follow-up processes

Primrose East Area 1 – 2012 UpdatePrimrose East Area 1 – 2012 Update

CNQSlide 104

Primrose East Area 1 – Current Cycle PerformancePrimrose East Area 1 – Current Cycle Performance

*Actual performance data as of December 31st, 2012

CNQSlide 105

Primrose East Area 2 - 2012 UpdatePrimrose East Area 2 - 2012 Update

• HPCSS Cycle 1 through PRE A2 Started June 2012 on Pad 93 West to East Steam Wave across 93,95,92

– Connected to Pad 93 CLWTR Gas Cap, fill-up required– Delayed C1 steam on Pad 94 to 2013 to further understand Pad 93 Gas Cap

performance before steaming Pad 94 CLWTR Gas Cap

Started October 2012 on Pad 91, 92 (Fault above liners) Block Steam Started November 2012 on Pad 90 East to West Steam Wave

• HPCSS Cycle 2 through PRE A2 Started December 2012 on Pad 91, 92 (Fault above liners) Block Steam Started December 2012 on Pad 92 Mini 17,000 m3 steam per well Started December 2012 on Pad 93 Gas Cap Fill-Up

CNQSlide 106

N

PRE Area 2 Features & Steam StrategyPRE Area 2 Features & Steam StrategyPRE A2 Features• Varying well

spacing/lengths 60-86.5m spacing 500m-1450m liner lengths

• Burnt Lake Proximity• P93,94,95 Gas Caps• P91 Fault• Salt Dissolution Edge3 PAD ALIGNED

WAVE

SINGLE PAD WAVE

SALT DISSOLUTION EDGE

BLOCK

CNQSlide 107

PRE Area 2 Cycle 1 Steam InjectionPRE Area 2 Cycle 1 Steam Injection

• Successful Cycle 1 steam injection in Primrose East Area 2 Cycle 1 for Pad 94 to start Jan. 2013

Pad 93 Gas Cap Fill-Up

CNQSlide 108

PRE Area 2 Cycle 1 - Performance to DatePRE Area 2 Cycle 1 - Performance to Date

• Performance variances from forecast due to interwell communication and CLWTR gas cap connection Interwell communication observed on all wave-steamed pads regardless

of well spacing (60m and 80m) Wells on Pad 93 connected to gas cap show high SOR’s due to steam

gas cap fill-up

ALL P95 P93 P92 Wave P91,92 Block P90

SOR 6.3 4.6 7.2 4.2 3.8 11.8

WDI 0.25 0.34 0.35 0.20 0.24 0.10

DI 0.41 0.56 0.49 0.44 0.50 0.18

Cycle 1 Completed No No No No Yes No

*Performance data as of December 31st, 2012

CNQSlide 109

PRE Area 2 Cycle 1Gas Cap Update - BackgroundPRE Area 2 Cycle 1Gas Cap Update - Background

Gas Cap Estimated Pore Volumes1. Pad 93: 215,000 m3

2. Pad 94: 130,000 m3

3. Pad 95: 375,000 m3

•Connected to Pad 93 Gas Cap

•Did not steam Pad 94 in 2012

•Did not connect to Pad 95 Gas Cap

1.

2.

3.

CNQSlide 110

PRE Area 2 Cycle 1 Pad 93 Gas Cap – Monitoring Fill-UpPRE Area 2 Cycle 1 Pad 93 Gas Cap – Monitoring Fill-Up

• 8 wells connected to gas cap Injected targeted volume after reaching fill-up pressure in gas cap

• Delayed steam wave by 1 month to fill-up• Evidence of horizontal fracturing on Pad 93 gas cap wells once fill-up achieved• Unknown performance impacts on Pad 93

Postponed Pad 94 Cycle 1 to 2013

CNQSlide 111

PRE Area 2 Cycle 1 Pad 93 Gas Cap – Performance to DatePRE Area 2 Cycle 1 Pad 93 Gas Cap – Performance to Date

• Reduced performance on Pad 93 due to gas cap connection

• Lower final oil cuts than non-gas cap affected wells ~30% lower

• Delayed oil cut ramp up due to producing gas cap fill-up water preferentially early in cycle

WELL SOR DI

20A93 4.4 0.63

19A93 11.5 0.44

18A93 11.0 0.40

17A93 18.0 0.46

16A93 15.3 0.42

15A93 10.7 0.67

14A93 5.9 0.65

13A93 6.0 0.55

12A93 5.0 0.56

11A93 4.2 0.68

CNQSlide 112

PRE Area 2 Gas Caps – Cycle 2 PlanPRE Area 2 Gas Caps – Cycle 2 Plan

• Perforated single well on Pad 93 (17A93) and Pad 94 (11A94) to improve connection to gas cap for faster fill-upReduce steam volumes connected through multiple wellsPerforation location at minimum distance to gas cap

• Plan to fill-up using single well (11A94) on Pad 94 then wave through after filled Initial reservoir conditions and no adjacent pumping wells allow for

single well fill-up

CNQSlide 113

PRE Area 2 Pad 91 Fault – Block Steam Cycle 1 and 2PRE Area 2 Pad 91 Fault – Block Steam Cycle 1 and 2

• 10k m³ steam slug into P91 in Cycle 1 Smaller steam slug successfully

confirmed cap rock integrity for CSS operation under a fault 1-26 and 13-24 monitoring wells near

fault showed similar response to steam injection throughout PRE A2

– Pressure increases during initial cycle injection

• 30k m³ steam slug into P91 in Cycle 2 In addition to B12 surveillance, passive

seismic and thermal fiber was added to 1-26 and 13-24 observation wells No anomalies detected

Two steam cycles and 40k m3 per well total injected into Pad 91

CNQSlide 114

PRE Area 2ERCB B12 CommunicationsPRE Area 2ERCB B12 Communications

Date Wells/Pad Event

Aug. 22nd, 20122-27 B12 & 16-22 B12 &

Pad 93 B12 pressure at 2-27 in the morning and 16-22 in the afternoon. Both B12 wells near the leading edge

of the steam wave . No injectivity events correlated. Proceeded with steam.

Aug. 20th, 2012 4-22 B12 & 20A95

Injectivity event correlating to 4-22 B12 pressure increase. B12 well at edge of steam wave on Pad 95. Reduced rates and observed reduction on B12, continued to monitor and proceeded with reduced rate steam on 20A95.

Sept. 11th -12th, 2012 16-22 B12 & 24A92

Injectivity Event correlating to B12 pressure alarms at 16-22 B12. B12 well located at front of steam wave on Pad 92. Changed dilation profile/steam wave and proceeded with steam.

Oct. 22nd, 2012 14-23 B12 & 9-10A92

Injectivity events on wells at leading edge of steam wave. No injectivity events correlated. Reduced rates to 9-10A92 and observed 14-23 pressure decreases. Reservoir stress built over time to initiate fracturing. Proceeded with steam.

Oct. 25th - 29th, 2012

P92 Steam, 12-23 Strat, PS well

PS events detected in mid GDPD to lower CLRD (Joli Fou). 12-23 strat near PS events. No injectivity events near strat, no direct correlation to B12 pressures. Proceeded with steam.

Nov. 1st - 8th, 2012 1-26,13-24 B12/Fault

B12 pressure increases correlated to initial ramp-up of block steam. Data supported horizontal fracturing in the CLWTR. Proceeded with steam.

Nov. 8th - 10th, 2012 15-13 B12 & 5A90

B12 pressure alarms and correlating injectivity events on 5A90 and 12A90. Ramp downs on 5A90 and 12A90 did not show any interference with B12 responses. Ramped 5 and 12A90 back up and proceeded with steam.

Dec. 3rd - 8th, 2012 10-14 B12 & 20-25A90

B12 pressure alarms at 10-14 B12 during initial ramp up of west wells on Pad 90. Conducted interference tests to determine if single well influence exists. Determine as reservoir stress increased, B12 changes reduced. Proceeded with steam and reduced injected volumes on 20-25A90.

Dec. 22nd -23rd, 2012 1-26 B12/Fault & Pad 91

B12 pressure alarms on both B12/Fault monitoring wells. No correlating injectivity events observed. B12 pressure increase correlated to block steam started on Pad 91. No responses correlating on other fault obs systems (PS,TF). Proceeded with steam.

CNQSlide 115

Pad 51 Investigation - ResolvedPad 51 Investigation - Resolved

• A series of passive seismic events in the Grand Rapids during prior cycle 3 steam launched a Pad 51 investigation

• An analysis of all Pad 51 wellbores revealed 5C51 had potential flow behind pipe

• 5C51 became the source of a larger flow behind pipe investigation altering the understanding of logs and wellbore behavior Convection cells within wellbore caused difficult interpretation on

temperature logs and hydrologs Thermal fiber data with wellbore filled with drilling mud reduced

convective effects and shows behind pipe fluid movement isolated to Grand Rapids

• Investigation concluded. 5C51 slimholed as precaution.

• Cycle 4 steam completed successfully

CNQSlide 116

Pad 52 Investigation - ResolvedPad 52 Investigation - Resolved

• Elevated Grand Rapids pressure at 3B52 obs wells in prior steam cycle initiated a Pad 52 investigation

• Clearwater oil in B8 at 3B52 was found to have been placed by previously milled hole in casing during a prior workoverElevated observation pressure during steam caused by heave

response amplified by lower mobility of near wellbore emulsion

• Pad 52 temperature logs revealed possible flow behind pipe in Grand Rapids at 3A52 well Zonal isolation across Clearwater, but cross flow in Grand Rapids 3A52 remediated and slimhole casing installed prior to steam cycle

CNQSlide 117

• Pad 51 steam completed• Steam wave currently in Pad 52

Pads 51, 52 Steam Cycle 4 (in progress)Pads 51, 52 Steam Cycle 4 (in progress)

Pad 51: 203,000 m3

average per well

Pad 52: 210,000 m3 average per well

Fill‐up steam injection

Fracture Pressure Steam

Low‐Rate Trickle Steam

Low‐Rate Trickle Production

Flowing Production

Pumping Production

Wave direction

CNQSlide 118

• Multi-well injectivity event occurred on P59 and P63 on April 3, 2012 Injectivity observed with corresponding pressure increase south of steam

wave due to fracture propagation within Clearwater from high pressure steaming wells to trickle producing wells Fluid movement within Clearwater triggers heave response on multiple

pressure observation wells

• All wells on P59 and P63 reduced to trickle steam rates

• Observation well response indicates heave response followed by a limited duration fluid migration into the Lower Grand Rapids

• Pressure containment within the Clearwater net pay was restored within 24hrs and wells built back to fracture pressure on trickle steam

• High rate fracture steam was then re-initiated on P59 and P63 Completed the execution of the HPCSS steam wave without further

incident

Pad 59/63 Multi-Well Injectivity Event - UpdatePad 59/63 Multi-Well Injectivity Event - Update

CNQSlide 119

Cenovus 12-14-068-04-W4 - UpdateCenovus 12-14-068-04-W4 - Update

• Oil found in Cenovus’ 12-14-68-4W4 Colony gas well on March 1, 2012 Oil sample analysis identified as steam affected Clearwater oil

• Investigation conclusions: Small release into the Grand Rapids likely during earlier cycle Potential flow behind pipe on 12-14 and into the Colony perforations Flow path now likely filled with cooled bitumen

• CNRL acquired and converted the well into a pressure and temperature observation well to monitor Colony No abnormal pressure response observed during HPCSS under well

• Follow-Up Diagnostics: CNRL plans to mobilize a

rig in early 2013 to perform further diagnostic and investigative work (location is winter-access only)

CNQSlide 120

Phase 28 UpdatePhase 28 Update

• Effects of large cycle 1 volumes First close spacing development – before current steaming SOP’s were

developed– Lots of inter-well and inter-phase communication reducing thermal efficiencies– Inter well fracture events caused liner failures

Phase 28 Estimated VolumesType Curve Factor: 0.8 OPIB Factor: 1

0%

2%

4%

6%

8%

10%

12%

14%

16%

18%

20%

0 0.1 0.2 0.3 0.4 0.5 0.6

PV Stm

% R

ecov

ery

(@16

0m)

0

0.04

0.08

0.12

0.16

0.2

0.24

0.28

0.32

0.36

0.4

% A

ctua

l Rec

over

y

• Recovery is similar to other 80m spacing developments Recovery on 28b (Northern wells)

is lower than expected– Liner failure issues– Interwell communication

Recovery on 28 (Southern wells) is higher than expected

CNQSlide 121

Key Learning - Stimulation UpdateKey Learning - Stimulation Update

Pad 58

0

100

200

300

400

500

600

700

800

900

1000

0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1

DI

Gro

ss F

luid

12A 13A14A 15ABudget

Steep declines after flow back

Low gross rates and DI compared with offset wells

• Certain areas have a higher tendency to precipitate scale near wellbore during flow back in mature cycles of HPCSS

– Wells with relative low gross rate and low DI’s were considered for stimulation candidates– Cycle recovery’s were not expected to achieve the target type curve – Full liner access was verified prior to stimulation to rule out liner damage or sand for possible

poor performance

CNQSlide 122

Key Learning - Stimulation UpdateKey Learning - Stimulation Update

• Acid stimulations and liner perforations were implemented to accelerate recovery

– 25 stimulations were performed in 2012– Stimulations resulted in improved gross rates, cycle DI’s, and cycle recovery

Pad 58

0

100

200

300

400

500

600

700

800

900

1000

0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1DI

Gro

ss F

luid

12A 13A14A 15ABudget

Increase in gross rates and return to expected profile

CNQSlide 123

Key Learning - Phases 58, 66Liner Re-Drill SuccessKey Learning - Phases 58, 66Liner Re-Drill Success

• Three re-entries drilled 2011 after cycle 4 to overcome lost horizontal liner access due to prior liner impairments. 4A58, 7A58 (1200m horizontal liner length) 8A66 (1400m horizontal liner length)

• All laterals successfully re-drilled, laterally offset from original liner by 5-7 m.

• Cycle 5 performance indicates effective steam stimulation of reservoir beyond location of prior liner impairments

Laterals re-drilled

Performance back to type curve

CNQSlide 124

• Inter-well communication on tight spaced wells was observed behind the steam wave Pressure support caused slower pressure declines during flowback Initial start cuts lower than expected with small number of soak row strategy Oil ramp up variances between wells at start and end of wave

– Wells at end of wave have smaller exposure time to inter-well communication resulting in better thermal efficiency with less inter-well communication

• Soak strategy changed by increasing soak rows minimizing inter-well communication

Key Learning – Inter-well communication and Soaking StrategyKey Learning – Inter-well communication and Soaking Strategy

CNQSlide 125

• Original standard soak strategy included six wells 3 trickle steam and 3 trickle produce

• Phases 22-24 Cycle 2 used a more conservative soaking strategy 11 wells between fracture steam and full flow back

– 3 trickle steam wells, 4 trickle production wells and 4 reduced flow back wells

• Phases 22-24 Cycle 2 performance exceeding expectations Surpassing type curve suggests conservative soak strategy maximized thermal efficiency

• Primrose East Area 2 increased up to 18 row soak 3 trickle steam and 15 trickle produce to prevent inter-well communication and impacts

– Pseudo-block flowback ideal to reduce differential pressure between drainage boxes and reduce thermal efficiency impacts

• Larger soak affects cycle lengths Wells that start wave see larger amount of trickle produce days and require longer production

periods (i.e. lower average CDSR)

• Avoid stalling the steam wave; stalling the wave has a negative effect on the thermal efficiency

Key Learning – Inter-well communication and Soaking StrategyKey Learning – Inter-well communication and Soaking Strategy

FB 3/4 FB 1/2 FB 1/2 FB 1/4 FB TP TP TP TP TS TS TS Frac

Cycle 2 Soaking/Flowback Strategy

CNQSlide 126

Primrose Next DevelopmentPrimrose Next Development

CNQSlide 127

Primrose North DevelopmentPrimrose North Development

• Phases 60-68 5 Pads with 20 wells/pad

– 100 wells total – 80 m well spacing

895 - 1700 m laterals Steam in date scheduled for

Q4 2013 Steam wave injection volumes

(nominal)– ~ 35,000-45,000 m3/well

Steam injection rates– 2,100 m3/day (targeted

nominal)– ~2,500 m3/day (max)

Currently drilling, ~60% complete

CNQSlide 128

Primrose South DevelopmentPrimrose South Development

• Phase 25A/B &26 Pads 25A/B

– 15 wells at 80 m spacing Pad 26

– 20 wells at 60 m spacing Total of 50 wells 650-1650m laterals Steam-in date: Q2 2013 Steam wave injection volumes

(nominal)– ~30,000-40,000 m3/well

Steam injection rates (nominal)– ~2,100 m3/day– 2,500 m3/day (max)

Drilling complete, facility construction ongoing

Phase 27

Phase 17

Phase 18

Phase 16

Phase 19

Phase 25BPhase 25A

Phase 26

CNQSlide 129

Primrose South DevelopmentPrimrose South Development

• Phases 40-43CNRL’s first development in

Orange Sand Valley 4 Pads with 24 wells, 74m spacing

– Total of 96 wells 700-1700m lateralsDrilling scheduled for Q1 2013Steam-in date Q4, 2014Steam wave injection volumes

(nominal)– ~ 35,000-45,000 m3/well

Steam injection rates –2,100 m3/day (targeted nominal)–~2,500 m3/day (max)

CNQSlide 130

Other Development PlansOther Development Plans

• PRE Area 3 Development – Proposed Application Date Q1 2013 CNRL plans to apply for new pads with ~130-160 horizontal CSS wells in the

Clearwater Formation; wells in Primrose East (67-3W4) – Drilling in Q3 2013 – Steam in 2015

• PRN Development – Proposed Application Date Q2 2013 CNRL plans to apply for new pads with ~100-120 horizontal CSS wells in the

Clearwater Formation; wells in Primrose North (68-4W4) or Primrose West (67-5W4) (would be steamed from PRN Plant)

– Drilling in Q2-Q3 2014– Steam in 2016

• TWP 67-3 West Boundary Lands – Proposed Application Date Q3 2013 Finalize development plans for area between Primrose East and South

• WL Evaluating D2 re-drills – Responding to SIR’s Q2 2013 SIR responses being worked on Reviewing inter-well spacing within D2 drainage box

• WL Evaluating Grand Rapids – Proposed Application Date 2013 Technology development of long horizontal SAGD (1000-1600m horizontals) Optimization to liner design with fine grain sand

CNQSlide 131

CSS SummaryCSS Summary

• Re-entries look to be an excellent way to capture reserves stranded by early cycle liner problems

• For a given drainage area, the use of smaller spaced wells achieves a higher ultimate recovery

• Normalized type curves are the same for a more densely spaced pad

• Managing communication between tighter spacing horizontal wells will increase thermal efficiency and reduce liner damage

• Fill-up profile ahead of the steam wave and soak strategy behind the steam wave essential in achieving optimal performance

CNQSlide 132

FUP – Follow Up Process to CSSFUP – Follow Up Process to CSS

• The proposed FUP strategy is based on infill wells operated as dedicated injectors and mature wells operated as dedicated producers

• Repeated Cyclic Drive (CD) cycles required to establish good inter-well communication, followed by Steamflood (SF) once developed

repe

atcy

clic

driv

est

eam

flood

Mature Mature MatureInfill Infill

repe

atcy

clic

driv

est

eam

flood

Mature Mature MatureInfill Infill

CNQSlide 133

FUP – Potential Scope and TimelineFUP – Potential Scope and Timeline

PR-NPh 51-55

Ph 01-21

A-column

C-column

PR-S

D01

C17

• FUP requires infill drilling to reduce well spacing from current 160-190 m to 80-95 m

• Planning & execution of potential infill program depends on success of field trials- C17: cyclic drive (CD)- D01: steamflood (SF)

• Targeting commercial ready technology by 2017-2019

• The OBIP of PR-S Phase 1-21 reservoir is ~675 MMbbl- current average CSS RF ~16%

• Significant incremental recovery potential based on preliminary CD/SF performance forecasts- ultimate Ph1-21 CSS RF = 26%- ultimate Ph1-21 CD/SF RF >35%

CNQSlide 134

FUP – Infill Program or Continued CSS?FUP – Infill Program or Continued CSS?

• Need to pressure up mature wells prior to first infill cycle to control infill fracture orientation• Another CSS cycle would increase steam volumes required to change stress state, recommend no

further CSS cycles due to negative impact on economics of first infill cycle

CNQSlide 135

FUP – Status of Cyclic Drive Trial at C17FUP – Status of Cyclic Drive Trial at C17

C17 Bitumen Production History since Infills Drilled (m3/d)

0

50

100

150

200

250

300

Sep-07 Mar-08 Sep-08 Mar-09 Sep-09 Mar-10 Sep-10 Mar-11 Sep-11 Mar-12 Sep-12 Mar-13

HPCSS - 7 Producers LPCSS - 7 Producers

LPCD - 4 Producers HPCD - 4 Producers

• 2011 CD cycle operated below fracture pressure; while significant interwell communication observed, performance only marginally better than 2007 HPCSS

• 2012 CD cycle operated at fracture pressure; performance to date is encouraging due to significantly improved SOR and CDOR trends compared to 2011 LPCD and 2007 HPCSS

C17 CD Trial Performance based on 2/3/4/5/7/8/9C17

0

10

20

30

40

50

60

70

80

0.00 0.10 0.20 0.30 0.40 0.50 0.60 0.70 0.80

WDI (-)

Full

Col

umn

SOR

(-)

| CD

OR

(m3/

d)

2007 HPCSS SOR

2011 LPCD SOR

2012 HPCD SOR

2007 HPCSS CDOR

2011 LPCD CDOR

2012 HPCD CDOR

378k m3158k m3

206k m3206k m3

378k m3

158k m3

CNQSlide 136

FUP – Status of Steamflood Trial at D01FUP – Status of Steamflood Trial at D01

D1 SF Trial - Daily Rates (m3/d)

0

200

400

600

800

1000

1200

1400

1600

May-12 Nov-12 May-13 Nov-13 May-14 Nov-14 May-15

ACT STM ACT GRS ACT BIT

SIM STM SIM GRS SIM BIT

• Injection into upper wells since June 04 2012, in-line with simulation targets

• Production from lower wells since June 19 2012, slight gross fluid deficit compared to simulation forecast related to artificial lift

• Performance to date is encouraging as bitumen production exceeds forecast despite gross fluid deficiency

CNQSlide 137

0.0

1.0

2.0

3.0

4.0

5.0

6.0

7.0

8.0

9.0

10.0

0

500

1,000

1,500

2,000

2,500

May‐95 Sep‐96 Jan‐98 Jun‐99 Oct‐00 Mar‐02 Jul‐03 Nov‐04 Apr‐06 Aug‐07 Jan‐09 May‐10 Oct‐11 Feb‐13

Cumulative SO

R

Daily Rate (m

3/d)

D1 Pad History ‐ Daily Rates, 1‐8D1 & 1C2

ACT STM ACT BIT ACT WTR Cum SOR

Well Count = 9 wells (including 1C2)

D01 Historical RatesD01 Historical Rates

CNQSlide 138

FUP – Request For Early ConclusionsFUP – Request For Early Conclusions

• CNRL views it too early to draw any conclusions• D01 trial is currently 6 months into the 36+ month trial periodSection 3.5 of the Steamflood Trial at D01


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