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Annual Surmont SAGD Performance Review Approvals 9426 and 11596

Surface Operations

April 11, 2013

Calgary, Alberta, Canada

Contents of Presentation

2

• Introduction• Surmont Overview and Highlights• Facilities & Facility Performance 3.1.2(1,2)• Measurement and Reporting 3.1.2 (3)• Water Production, Injection, and Uses 3.1.2(4)• Sulphur Production 3.1.2 (5)• Environmental Issues 3.1.2(6)• Compliance Confirmation 3.1.2(7)• Non-Compliance Issues 3.1.2(8)• Future Plans 3.1.2(9)

Introduction

Ownership and Approvals

• 50/50 joint venture between ConocoPhillips and TOTAL E&P Canada Ltd; Operated by ConocoPhillips

• Approval history: 1997 - ERCB Project Approval - Pilot 2003 - ERCB Project Approval - Commercial 2007 - First Steam at Phase1 2008 - Approval of Phase 2 2009 - Approval of Phase 2 Amendment 2010 - Construction Start at Phase 2 2011 - Approval of Phase 2 Expansion, E-SAGD and GT-OTSG Projects 2012 - Multiple Amendment Submissions for Scheme 9426

- Phase 1- Well pad 103 - approved

- Phase 2- Condition 9 – Well Pads 264-2 and 263-1 – approved- Condition 10 – Operating Strategy – approved- HWY 881 Steam Pipeline Crossing – approved

Subsection 3.1.2 (1) 4

Surmont Overview and Highlights

• Phase 1 is identifying optimization opportunities based on actual conditions

• Phase 1 and 2 combined approved capacity is 21, 624 m3/d (136,000 bbl/cd) (Ph 1 - 4,293 m3/d , Ph 2 - 17,331 m3/d )

Surmont Overview


7

2012 Highlights

• Operations Excellence: Focus on Integrated Operations to improve safety and productivity

• Leverage learning from others• Continued planning for sustaining pads and infill wells• Engineering work for major debottlenecking projects • Reached new records of steam injection and bitumen

production during 2012• Key improvements/successes:

- Achieved production proration factor compliance- Improved ESP conversion time. Started up two PCPs- Continue Circulation optimization- Achieve longer periods of CPF stability- Soda ash silo commissioned and operating- MPFM trial - Started solvent injection at E-SAGD pilot- Started MP reduced BD trial - Pilot turn around. GT-OTSG burner start up

• Key challenges:- Water treating OTSG Scale- Water balance and water recycle- E-502 fouling and required cleaning

Subsection 3.1.2 (1)

D ata as o f January 31 , 2013

0

5,000

10,000

15,000

20,000

25,000

30,000

35,000

Oct

-07

Jan-

08

Apr

-08

Jul-0

8

Oct

-08

Jan-

09

Apr

-09

Jul-0

9

Oct

-09

Jan-

10

Apr

-10

Jul-1

0

Oct

-10

Jan-

11

Apr

-11

Jul-1

1

Oct

-11

Jan-

12

Apr

-12

Jul-1

2

Oct

-12

Jan-

13

Gro

ss P

rodu

ctio

n (b

oepd

)

0

20,000

40,000

60,000

80,000

100,000

120,000

Stea

m In

ject

ion

(cw

ebpd

)

Daily produc tion P roduc tion record Daily S team S team record

8

Phase 1 Production

•2008 Key Issues• Freezing

• Off-spec product• Plant instability

•2009 Key Issues• OTSG integrity

• Front-end treatment• 1st turnaround

•2010 Key Issues• ESP installations

• OTSG maintenance

•Continued stable operationsSubsection 3.1.2 (1)

•2011 Key Issues• ESP installations

• OTSG maintenance • Turnaround

•2012 Key Issues•ESP installations /

Repair•OTSG maintenance

•Record production: 29,917 boepd

•Record Steam: 68,470 cwebpd

Key actions to reduce lost production: Optimize treating capacity and frequency of boiler pigging, optimize downtime for ESP installs, continue to optimize well conformance and subcool and reduce downtime for ESP replacement

2012 Lost Production Roll Up (2437 bbl/d)

Lost Production Rollup

9

bbl/d m3/d bbl/d m3/d bbl/d m3/d bbl/d m3/dTotal Losses 4979.0 791.6 1858.0 295.4 3376.1 536.7 2437.0 387.5

Wells 405.0 64.4 912.0 144.7 1354.5 215.3 1233.0 196.0Facility 4574.0 727.2 898.0 142.8 2021.6 321.4 1204.0 191.4Other 0.0 0.0 48.0 7.6 0.0 0.0 0.0 0.0

2009 2010 2011 2012

424378

339 325

201178

106 97 81 6642 38 26

-555

136

-600

-400

-200

0

200

400

01.02.04 Facility:Process Upsets:Unit 05 - Steam

Generation

02.02.05 Wells:Artificial Lift:

Planned ArtificialLift Replacement

01.11.03 Facility:Facility Capacity:Unit 04 - Water

Treatment


Failure /Replacement


Optimization /Troubleshooting

01.11.04 Facility:Facility Capacity:Unit 05 - Steam

Generation

02.04.02 Wells:Downhole

Optimization:Upgrade of lift

system


Impairment:Optimization /

Conformance /Troubleshooting

01.11.05 Facility:Facility Capacity:Unit 05 - Planned

SteamGeneration/OTSG

Pigging

01.02.03 Facility:Process Upsets:Unit 04 - Water

Treatment

01.07.01 Facility:Power and Fuel:

Third party powersupply failure


Impairment:Subcool control


Impairment:Downhole

obstruction

Flush Combined Misc

Loss

(bbl

/d)

Boiler Pigging

ALS Conversions

E502 Work

ESP Failures

Well Optimization

C-Gen Repairs

ALS Upgrades

Plugged GLUpgrades

Subcool Control on 101P02102P03 Liner

Issue

D-Gen Pigging

WLS Problems, Turbidity issues

ATCO Power Outage

Flush Production

Combined Miscellaneous

Subsection 3.1.2 (2a)

Surmont Oil Sands Commercial ProjectApproval 9426I

Subsection 3.1.2 (1) Facilities

Phase 1 Plot Plan 2012 Major Plant Facility Additions


Plant optimization focus for Phase 1 CPF in 2012

11

Soda Ash System

Raw Water Heater

Fuel Skid(Gas/Diesel Card Lock)

Phase 1 Plot Plan - Pad 101 - 2012 Major Plant Facility Additions


Artificial Lift Program added 6 new wells in 2012

12

- Infill Producer 11- Infill Producer 12

- Infill Pair 19- Infill Pair 20

Phase 1 Plot Plan - Pad 102 - 2012 Major Plant Facility Additions


Artificial Lift Program added 4 new units in 2012

13

- P15 ESP- P09 ESP- P16 ESP- P14 ESP

Plant Schematic

Subsection 3.1.2 (1b)

Raw WaterHeater Upgrade

14

BTU Analyzer

Automated Soda Ash

OTSG ConvectionBox Replacement

Belly Drain

Surmont Operations2012 Focus

• 2012 – Capital Projects– Fuel gas measurement: Btu analyzer installed in 2012 project, currently

online and measuring.– Spare OTSG Economizer with metallurgy improvements ordered.

• 2012 – Optimization Focus– Steam optimization

• Steam production and delivery development: boiler master control enhancements.

• Burner Management System (BMS) optimization: Minimize nuisance trips on low flow deviation and optimize flowrate for each pass maximizing steam quality.

• Steam production development: Complete CFD for S1 OTSGs.

2012 optimization and opportunity development focusSubsection 3.1.2 (1c) 15

Surmont Operations2012 Focus

• Water treatment optimization Raw Water Heater: Increase the heating capabilities of exchanger Automated Soda Ash Silo: Reduces alkalinity of the produced water

• Oil treatment optimization FWKO/Treaters Belly Drain: Remove sand near sand dams inside vessels

• Steam optimization OTSG Economizer Material Upgrade: Upgraded material type to withstand

high differential temperatures BTU Analyzer: Analyze fuel gas real-time

• Artificial lift 6 ESP installations complete 2 PCP infill producer installations complete 2 new infill pairs complete

• Technology E-SAGD Project: Solvent injection system completed and commissioned

2012 optimization and opportunity development focusSubsection 3.1.2 (1c) 16


Subsection 3.1.2 (2) Facility Performance

Plant PerformanceBitumen Treating

Zero off-spec bitumen production in 2010, 2011 and 2012Subsection 3.1.2 (2a)

Avg. Prod. in 2012 = 24,269 bbl/d (3883 m3/d)



Avg. BS&W 2012 = 0.20%

Avg. BS&W 2011 = 0.25%

Avg. BS&W 2010 = 0.20%

Bitu

men

Pro

d. /d

ay

BS&

W %

age

20112008 2009 2010 2012BS&W Target < 0.5%

18

Surmont FacilitiesModifications

1. 2012 – Capital Projects

• Front end vessels treating: Install belly drain system on FWKOs and treaters vessels (March 10, 2012 start-up)

2. 2012 – Production Increase

• Reduced <1% prod. loss to process and capacity

• Produced water cooling improvements:Increase PW coolers ASC to 580m3/hr combined

• Emulsion treating improvements:Increase emulsion ASC to 740 m3/hr combined

• Front end chemical injection optimization: EB (<400 ppm) and REB (<150 ppm) averagely

3. 2012 – Opex Reduction

• Prolonged PW coolers cleaning cycle time:Target 120 days (Q3/2012)

• Optimized de-sand cycle & trucking cost; • Target save ~$ 250K trucking cost by lowering

de-sand on treaters 3 times a week vs 5 times

2012 optimization and opportunity development focusSubsection 3.1.2 (2a)

LPO 40K BBL

Zero Prod. Loss

Prod

uctio

n w

eekl

y av

erag

e (b

bl/d

ay)

%ag

e fr

ont e

nd lo

ss

19

Plant PerformanceFront End Treatment

Continued increase of produced emulsion and water ratesSubsection 3.1.2 (2a) 20

Produced Emulsion Flow Rates

0

100

200

300

400

500

600

700

800

3/15/2012 5/4/2012 6/23/2012 8/12/2012 10/1/2012 11/20/2012 1/9/2013

Date

Flow

Rate (m

3 /hr)

Train 2Train 1

Combined Trains

Total Produced Water Flow Rate

0

100

200

300

400

500

600

3/15/2012 5/4/2012 6/23/2012 8/12/2012 10/1/2012 11/20/2012 1/9/2013

Date

Flow

Rate (m

3 /hr)

Plant PerformanceBitumen Treating

Front end vessels online cleaningKey Issue: Automated de-sand system is not able to remove solid near sand dams inside the vessels

Issue mitigated: Belly drain systems, manual, are installed

Key findings:- Optimized emulsion through put – Optimized to 770 m3/hr combined- PW trim coolers rune time increase to 120 days before offline cleaning- Lowered de-sand cycle and reduced de-sanding trucking cost- Treatment - oil in water <300 ppm 90 % of year- EB normal operating ranges lowered to (450 to 350ppm) and - REB normal operating ranges lowered to (150 to 100ppm)- Maintained BS&W <0.5


De-Sand Tank

Internal Sand Dam

FWKO’s/Treaters

Current De-Sand System

Existing Belly Drain Piping

Proposed Belly Drain Piping Additions

Camlock Truck Off Connection De-Sand Slurry Header

21

Plant PerformanceWater Treatment


Conductivity controlled in 2012. Experienced Significant Turbidity Upset in Summer 2012 due to WLS

0

2

4

6

8

10

12

14

16

18

20

1/31/2008 6/29/2008 11/26/2008 4/25/2009 9/22/2009 2/19/2010 7/19/2010 12/16/2010 5/15/2011 10/12/2011 3/10/2012 8/7/2012 1/4/2013

Date

NTU

, mic

ro S

Turbidity

Conductivity

2009 2010 2011 2012

22

0

1

2

3

4

5

6

11/18/2010 2/26/2011 6/6/2011 9/14/2011 12/23/2011 4/1/2012

Trea

tmen

t (pp

m)

New Chemical Plan Initiated

0

25

50

75

100

125

150

175

200

225

250

11/18/2010 2/26/2011 6/6/2011 9/14/2011 12/23/2011 4/1/2012

Trea

tmen

t (pp

m) New Coagulant

Implimented

Reduced Coagulant from ~90ppm to >10ppm

Reduced Flocculent from ~2.5 ppm to >1ppm


Subsection 3.1.2 (2b) 23

Coagulant Optimization



WLS Optimization Trial ResultsWLS Performance

0

100

200

300

400

500

600

700

11/18/2010 2/26/2011 6/6/2011 9/14/2011 12/23/2011 4/1/2012 7/10/2012 10/18/2012 1/26/2013 5/6/2013

Days

Turb

idity

(NTU

s)

Chemical Trial Period

Chemical Pump Failure

Soda Ash System

WLS

440 m3/hr PW

53 m3/hr RW @ 12%

80 m3/hr Super + BD

WLS PW Capacity Limited due to RW Minimum (Carbonate Deficient)

573 m3/hr BFW

Automated Soda Ash System

• Historically The WLS struggles below 12% RW factor, Study underway to “find” new RW Minimum for WLS

• Goal of Soda Ash system was to allow WLS to operate at lower raw water cuts and increase throughput through the facility

• System complete Dec, 2012 and online Jan, 2013

25Subsection 3.1.2 (2b)

Soda Ash System

• Able to sustain WLS performance during low raw water cuts –NO UPSETS

• Improvements on WRR during BD recycle Trial

Surmont WLS Inlet Raw Water Cut

0

0.05

0.1

0.15

0.2

0.25

0.3

0.35

11/3/2011 12/23/2011 2/11/2012 4/1/2012 5/21/2012 7/10/2012 8/29/2012 10/18/2012 12/7/2012 1/26/2013 3/17/2013

Raw

Wat

er K

-Fac

tor

Sustained Lower Raw Water Cuts at Full Rates--WITHOUT WLS UPSETS.

Soda Ash System Online


Plant PerformanceSteam Generation

Subsection 3.1.2 (2c) 27

0.0

10,000.0

20,000.0

30,000.0

40,000.0

50,000.0

60,000.0

70,000.0

80,000.01-

Jan-

11

31-J

an-1

1

2-M

ar-1

1

1-A

pr-1

1

1-M

ay-1

1

31-M

ay-1

1

30-J

un-1

1

30-J

ul-1

1

29-A

ug-1

1

28-S

ep-1

1

28-O

ct-1

1

27-N

ov-1

1

27-D

ec-1

1

26-J

an-1

2

25-F

eb-1

2

26-M

ar-1

2

25-A

pr-1

2

25-M

ay-1

2

24-J

un-1

2

24-J

ul-1

2

23-A

ug-1

2

22-S

ep-1

2

22-O

ct-1

2

21-N

ov-1

2

21-D

ec-1

2

20-J

an-1

3

19-F

eb-1

3

Stea

m in

ject

ion

(cw

e bp

d)

0

10

20

30

40

50

60

70

80

90

Qua

lity

(%)

2011 Issue:Steam Generator Fouling


Max rate 67,175 bpdDec 31, 2012


0.0

10,000.0

20,000.0

30,000.0

40,000.0

50,000.0

60,000.0

70,000.0

80,000.01-

Jan-

11

31-J

an-1

1

2-M

ar-1

1

1-A

pr-1

1

1-M

ay-1

1

31-M

ay-1

1

30-J

un-1

1

30-J

ul-1

1

29-A

ug-1

1

28-S

ep-1

1

28-O

ct-1

1

27-N

ov-1

1

27-D

ec-1

1

26-J

an-1

2

25-F

eb-1

2

26-M

ar-1

2

25-A

pr-1

2

25-M

ay-1

2

24-J

un-1

2

24-J

ul-1

2

23-A

ug-1

2

22-S

ep-1

2

22-O

ct-1

2

21-N

ov-1

2

21-D

ec-1

2

20-J

an-1

3

19-F

eb-1

3

Stea

m in

ject

ion

(cw

e bp

d)

0

10

20

30

40

50

60

70

80

90

Qua

lity

(%)





OTSG Pigging Frequency

28

Average OTSG Throughput and Days Between Pigging

75 days

41 days

40 days

59 days

65 days

62 days

61 days

60 days

75 days

58 days

65 days

76 days

74 days

84 days

52 days

43 days

41 days

91 days

27 days

30 days

37 days

67 days

43 days

59 days

50,000

75,000

100,000

125,000

150,000

175,000

200,000

225,000

250,000

275,000

300,000

1‐Jan‐10

1‐Feb‐10

1‐Mar‐10

1‐Ap

r‐10

1‐May‐10

1‐Jun‐10

1‐Jul‐1

01‐Au

g‐10

1‐Sep‐10

1‐Oct‐10

1‐Nov

‐10

1‐De

c‐10

1‐Jan‐11

1‐Feb‐11

1‐Mar‐11

1‐Ap

r‐11

1‐May‐11

1‐Jun‐11

1‐Jul‐1

11‐Au

g‐11

1‐Sep‐11

1‐Oc t‐11

1‐Nov

‐11

1‐De

c‐11

1‐Jan‐12

1‐Feb‐12

1‐Mar‐12

1‐Ap

r‐12

1‐May‐12

1‐Jun‐12

1‐Jul‐1

21‐Au

g‐12

1‐Sep‐12

1‐Oct‐12

1‐Nov

‐12

1‐De

c‐12

1‐Jan‐13

Date

Volume (m

3, days)

Subsection 3.1.2 (2c)

Electrical Consumption

0

2,000

4,000

6,000

8,000

10,000

12,000

14,000

0

2

4

6

8

10

12

1/20

092/

2009

3/20

094/

2009

5/20

096/

2009

7/20

098/

2009

9/20

0910

/200

911

/200

912

/200

91/

2010

2/20

103/

2010

4/20

105/

2010

6/20

107/

2010

8/20

109/

2010

10/2

010

11/2

010

12/2

010

1/20

112/

2011

3/20

114/

2011

5/20

116/

2011

7/20

118/

2011

9/20

1110

/201

111

/201

112

/201

11/

2012

2/20

123/

2012

4/20

125/

2012

6/20

127/

2012

8/20

129/

2012

10/2

012

11/2

012

12/2

012

Elec

tric

al Im

port

s (M

Wh/

mon

th)

Elec

tric

al In

tens

ity (k

Wh/

BB

L B

itum

en)

Electrical Energy Intensity Electrical Energy Import

Subsection 3.1.2 (2d) 29

Gas Conservation and Emissions

Gas recovery has been improving since 2007, achieving more than 98% in 2012.

Subsection 3.1.2 (2e)

2007 2008 2009 2010 2011 2012 units

Total Gas Imports (TCPL) 42,999 160,095 183,933 223,447 228,344 250,412 e3Sm3

Solution Gas 2,533.8 5,272.9 10,051.6 11,101.1 11,284.9 14,136.3 e3Sm3

Total Gas Vented 0.0 0.0 0.0 0.0 0.0 0.0 e3Sm3

Total Gas Flared 4,640.6 6,438.7 3,962.0 705.0 624.8 217.6 e3Sm3

Solution Gas Recovery -83.1 -22.1 60.6 93.6 94.5 98.5 %

30

0

20

40

60

80

100

120

1-20

092-

2009

3-20

094-

2009

5-20

096-

2009

7-20

098-

2009

9-20

0910

-200

911

-200

912

-200

91-

2010

2-20

103-

2010

4-20

105-

2010

6-20

107-

2010

8-20

109-

2010

10-2

010

11-2

010

12-2

010

1-20

112-

2011

3-20

114-

2011

5-20

116-

2011

7-20

118-

2011

9-20

1110

-201

111

-201

112

-201

11-

2012

2-20

123-

2012

4-20

125-

2012

6-20

127-

2012

8-20

129-

2012

10-2

012

11-2

012

12-2

012

1-20

13

Gre

enho

use

Gas

Em

issi

ons

(kg

CO

2e/B

OE)

Greenhouse Gas Emission Intensity Intensity

Performance Target

Greenhouse Gas Emissions

Subsection 3.1.2 (2f)

• 518,131 tonnes CO2e generated in 2012• 19% reduction in GHG emission intensity from 2009 to 2012 • 2% reduction in GHG emission intensity from 2011 to 2012

2009 2010 2011

31

2012


Subsection 3.1.2 (3) Measurement and Reporting

Well Allocated Oil Production


Well Allocation Oil ProductionEstimated Monthly Well Oil Production X Oil Proration Factor

Where:Estimated Production = Accepted well test / duration of test * on-stream hoursOil Proration Factor = Actual battery production / estimated battery productionActual Battery Production

Dispositions + Inventory – Receipts + Shrinkage + External Shipments + (Load Oil to Wells inventories)

Where:Dispositions = Dilbit shipped to Enbridge + Diluent send to pilotInventory = Dilbit tanks volume changes

+ Diluent tank volume changes + Slop tank oil inventory + Skim tank oil inventory

Receipts = Dilbit received from pilot + Diluent received from EnbridgeShrinkage = Shrinkage adjustmentExternal Shipment = Oil from slop trucked out to external facility

Changes for 2012:• Added Pilot Plant Diluent and Dilbit pipelines - January 2012.• Start to report eSAGD wells at independent facility ABBT0122487 - October 2012

Surmont MARP Rev 8 submitted in February 2013 (SUR2-A0A-00-OPM-OPN-0045) 33

Well Allocated Water Production


Well Allocation Water ProductionEstimated Monthly Well Water Production X Water Proration Factor

Where:Estimated Water Production = Accepted well test / duration of test * on -stream hoursWater Proration Factor = Produced water volume / estimated water productionProduced Water VolumeInlet Produced Water Meter – Recycled Plant Water + Inventory– Steam Condensate Traps – Enbridge Diluent BS&W + Pilot Diluent BS&W + Enbridge DilBit BS&W – Pilot Dilbit BS&W + external shipments + (Load Water to Wells inventories) – 03FIT1170BRecycled Plant Water = Water from plant use and plant utilities recycled upstream of inlet

produced water meter Pilot Dilbit BS&W = Water content in received pilot DilBitPilot Diluent BS&W = Water content in shipped Diluent to Pilot PlantExternal shipment = Any water trucked out of oil battery and delivered to other facilities

Changes for 2012:

• Start to report eSAGD wells at independent facility ABBT0122487 - October 2012

• Pilot Plant Blowdown Water shipped together with Produced Water – December 2012

• Reporting Receipts of Pilot Pipeline Water (Fresh and Produced) at Injection facility (ABIF0111818) only(Reported Battery Water Receipts from Injection Facility exclude portion of Pilot Water if shipped to Battery and metered by 03FIT1170)

ABIF0111818 WATER REC = 03FIT1143 - 03FIT1170B

34Surmont MARP Rev 8 submitted in February 2013 (SUR2-A0A-00-OPM-OPN-0045)

Well Allocated Gas Production


Well Allocated Oil Production X Calculated Gas-Oil RatioWhere:Calculated Gas-Oil Ratio = Total produced gas / actual battery productionTotal Produced Gas

Total Gas Consumed – Metered Purchased Fuel gas from TCPL

Where:Total Gas Consumed = Metered flared gas+ metered steam gen fuel gas + utilities fuel +

gas for purging system + metered purchased fuel gas for TCPL


Changes for 2012:

• Start to report eSAGD wells at independent facility ABBT0122487 - October 2012

• Added Flare Meter at Pad 101 ESAGD facility (61FIT3203) - October 2012

(eSAGD Flare Reported at ABBT0122487 and used in Total Gas Consumed calculation)

Well Allocated Steam Injection


Estimated Well Steam Injected Meter X Steam Proration Factor

Where:

Steam Proration Factor = Total injected steam volume / estimated well steam injected meters

Total Injected Steam VolumeTotal Steam Meter to Well Pads – Steam Condensate Dropped Out – Steam Recovered at Pipeline – Steam to eSAGD wells


Changes for 2012:

• Start to report eSAGD wells at independent facility ABIF0122488 - October 2012

• Steam Receipts from ABIF0111818 = 61FIT1120 + 61FIT1130

• Independent Steam Proration Factor for eSAGD wells

= (61FIT1120 + 61FIT1130) / (estimated steam injected to ESAGD wells)

Production Proration Factors


Remarkable improvement in water cut measurement during 2012. Calibration of Pad 102 WC analyzer in May 2012 and in October performed

preliminary calibration in Pad 101

•Proration Factors

37

Injection Proration Factors


Average steam Injection proration factor during 2012 = 0.964

38

Well Testing

Well Testing• Well test duration is optimized to 8 hours with 1 hour purge• Typical frequency is 4-5 per month per well on the pad test separartor• Method is test separator with Coriolis flow meter for total liquid measurement and water

cut meter based on multiple high frequency permittivity measurement• Since January 2012, eSAGD dedicated test separator online at Pad 101. Testing

continuously 4 solvent candidate wellpairs.

Production Sampling Program• Produced gas analysis for detailed composition every month (minimum3 wells)• Sampling for calibration purpose and adjustment of meters:

• In 2012, intensive well sampling at Pad 101 and 102 to recalibrate water cut analyzer • Since eSAGD test separator started-up, intensive sampling program to baseline SAGD performance: up to daily water cut, weekly oil composition, and produced gas samples to calibrate online gas chromatograph


New Technology

Improvements in WatercutMeasurement & Sampling • Significant work put into improving both oil and water

proration factors in 2012. Water cut calibrations performed on both Pad 102 and Pad 101. Significant improvement in proration factors after calibrations.

• Installed temporary sampling skid on Pad 102 and calibrated the water cut analyzer.

• Calibrated Pad 101 water cut analyzer utilizing manual (bomb) sampling.

• Kicked off engineering for a permanent automatic sampler on Pad 101.

Multi-phase Flow Meter Update• Selected vendor and location for MPFM trial. Received

approval for testing program in Application 173221.• Completed engineering and began construction on Pad

102.• Test ongoing with results expected by April 2013



Subsection 3.1.2 (4) Water Production, Injection, and Uses

Surmont Water Source WellsNon-Saline

Surmont Pilot

Source Well Observation Well Formation

1F1082508307W400 1AJ082508307W400 Lower Grand Rapids

1F1072508307W400 100072508307W400 Clearwater

Surmont Phase 1


1F1021808306W400 1F2021808306W400 Lower Grand Rapids

1F1041808306W400 102041808306W400 Lower Grand Rapids



Notes

• all water currently used at the Surmont project is non-saline and non-potable (i.e., waters not readily or economically treatable for potable, domestic, agricultural or livestock use)• Phase 2 source wells licenced on December 14, 2012, not yet operational

Subsection 3.1.2 (4a, 4b) 42

Surmont Phase 2









S1 Water Source WellsProduction Volumes


0

10,000

20,000

30,000

40,000

50,000

60,000

70,000

80,000

90,000

Jan-

10

Apr

-10

Jul-1

0

Oct

-10

Jan-

11

Apr

-11

Jul-1

1

Oct

-11

Jan-

12

Apr

-12

Jul-1

2

Oct

-12

Jan-

13

Volu

me

of W

ater

Pro

duce

d (m

3 ) per

Mon

th

1F1/01-19-083-06 W4M1F1/04-18-083-06 W4M1F1/02-18-083-06 W4M1F1/03-23-083-07 W4M

Water Production and Steam Injection Volumes


-

50,000

100,000

150,000

200,000

250,000

300,000

350,000

Jan-

11

Mar

-11

May

-11

Jul-1

1

Sep

-11

Nov

-11

Jan-

12

Mar

-12

May

-12

Jul-1

2

Sep

-12

Nov

-12

Jan-

13

Prod Water Steam Injection

Stea

m (C

WE

–m

3 ); P

rodu

ced

wat

er (m

3 )

Produced Water Recycle and Blowdown Recycle

Subsection 3.1.2 (4e, 4f) 45

0

10

20

30

40

50

60

70

80

90

100

Jan-

11

Mar

-11

May

-11

Jul-1

1

Sep-

11

Nov

-11

Jan-

12

Mar

-12

May

-12

Jul-1

2

Sep-

12

Nov

-12

Jan-

13

WRR BD Recycle

Reduced BD Recycle trial

Perc

enta

ge, %

Reduced BD Recycle trial

• Can pigging cycles be extended significantly by reducing BD recycle

• Formally initiated on Jan 01, 2013

Reduced Blowdown Recycle Test

Test days BD recycle, % T estimated end of step, ºC Expected WRR, %90 20 20 77150 30 35 78180 35 50 80

T,

ºC

0

10

20

30

40

50

0 50,000 100,000 150,000 200,000 250,000 300,000

Volume of processed water, m3

OTSG B

OTSG D

Current trial Baseline (2012)

0

10

20

30

40

50

0 50,000 100,000 150,000 200,000 250,000 300,000

OTSG C

OTSG AT,

ºC

Volume of processed water, m3

OTSG Days on service Average T, ºC Days to pig (estimated)A 52 5 232B 62 15 158C 50 11 62D 64 10 127

Est. 30 days Est. 60 days Est. 30 days Est. 60 days

46Subsection 3.1.2 (4e, 4f)

Water Disposal Wells

Subsection 3.1.2(4g)

Well

Zone Approved

for Disposal

Maximum Wellhead Injection Pressure

(kPa)

Well Status

ERCB DisposalApproval

No

102/03-31-083-06W4/0 McMurray 3600 Water,

Suspended 9573A

103/03-31-083-06W4/0 McMurray 3600 Water,

Suspended 9573A

103/10-31-083-06W4/0 McMurray 3600 Water,

Suspended 9573A

104/10-31-083-06W4/0 McMurray 9000 Observation

Well 9573A

100/09-25-083-07W4/0 Keg River 6000 Water,

Disposal 9573A

100/01-16-083-05W4/0 McMurray 2700 Water,

Disposal 10044B

100/07-22-083-05W4/0 McMurray 2500 Water,

Disposal 10044B

100/08-10-083-05W4/0 McMurray 2300 Water,

Disposal 10044B

100/01-04-083-05W4/0 McMurray 2500 Awaiting

Tie-in 10044B

100/01-11-083-05W4/0 McMurray 2500 Startup in

Feb 2013 10044B

47

INA

CTI

VE

102/01-16

102/08-10

100/01-04

100/01-11

100/01-16

100/07-22

100/08-10

083-05W4

Disposal Well

Observation Well

Notes

• Phase 1 Approval No. 10044B (December 5, 2012) rescinds 1044A, and includes addition of disposal wells 01-04 and 01-11• Disposal at 100/01-11-083-05W4 began February 17, 2013

Water Disposal WellsInjection Rates (McMurray)

Subsection 3.1.2 (4g, 4h) 48

0

5,000

10,000

15,000

20,000

25,000

30,000

35,000

40,000

45,000

50,000Ja

n-09

Jul-0

9

Jan-

10

Jul-1

0

Jan-

11

Jul-1

1

Jan-

12

Jul-1

2

Jan-

13

Volu

me

of W

ater

Inje

cted

(m3 ) p

er M

onth

00/01-16-083-05 W4M00/07-22-083-05 W4M00/08-10-083-05 W4M

Water Disposal WellsWell Head Pressure (McMurray)

Subsection 3.1.2 (4h)

• Based on Caprock study (Condition 10) disposal well operating pressures have been reduced • Pressure currently controlled using well head chokes

49

0

500

1,000

1,500

2,000

2,500

3,000

3,500

Jan-

09

Jul-0

9

Jan-

10

Jul-1

0

Jan-

11

Jul-1

1

Jan-

12

Jul-1

2

Jan-

13

Dis

posa

l Wel

l Hea

d Pr

essu

re (k

Pa)

00/01-16-083-05 W4M00/07-22-083-05 W4M00/08-10-083-05 W4M

Approval Max. WHP for 01-16: 2700 kPa

Opperating WHP Limit for 01-16: 1924 kPa





Water Disposal Well 100/01-16-083-05 W4MObservation Well Pressure

Subsection 3.1.2 (4h) 50

0

200

400

600

800

1,000

1,200

1,400

2007 2008 2009 2010 2011 2012 2013 2014

Pres

sure

(kPa

)

102/01-16 Piezo 3 (gas)102/01-16 Piezo 2 (water)102/01-16 Piezo 1 (water)

Water Disposal Well 100/08-10-083-05 W4MObservation Well Pressure


0

200

400

600

800

1,000

1,200

2007 2008 2009 2010 2011 2012 2013 2014

Pres

sure

(kPa

)

102/08-10 Piezo 3 (gas)102/08-10 Piezo 2 (water)102/08-10 Piezo 1 (water)

Typical Water Analysis


Phase 1 Typical Water Quality

Units Produced Water

Raw Water

Disposal Water

Oil content mg/L 82 0.2 40

pH 8 8.9 9.5Alkalinity as CaCO3 mg/L 257 812 2,680

Total dissolved solids mg/L 1,644 1,410 14,800

Salinity mg/L 1 0.99 17Hardness as CaCO3 mg/L 6 8 <1

Silica mg/L 273 7.5 150

Total organic carbon mg/L 548 17 1,360

52

Waste DisposalLocations and Volumes

Subsection 3.1.2 (4i) 53

Waste Description Volume (m3) Final Destination(volume in m3) Disposal Method

Contaminated Debris and Soil (Crude Oil/Condensate) 11 Tervita – Lindbergh Cavern

Crude Oil/Condensate Emulsions 565 Newalta – Elk Point Oilfield Processing

Sludge - Emulsion 1,789.5 Tervita – Lindbergh (1,710)Newalta – Elk Point (79.5)

CavernOilfield Processing

Sludge - Hydrocarbon 3,707.74 Tervita – Lindbergh (3,505.24)Newalta – Elk Point (202.5)

CavernOilfield Processing

Wash Fluids - Organic 942.5 Tervita – Lindbergh Cavern

Waste Water Non Reportable 18.7 Tervita – Lindbergh Cavern

Solid Waste Disposal


Waste Description Class Ia Disposal Well Landfill Class I Landfill Class II Swan Hills Facility

BATTERIES - ALKALINE (disposal) (cls 8) 114.00BATTERIES - DRY CELL 95.00

Contaminated Debris and Soil (Crude Oil/Condensate) 36,710.00CORROSIVE LIQUID - ORGANIC ACID (cls 8) 442.00

CORROSIVE LIQUID - ORGANIC BASIC (cls 8) 248.80DESICCANT MATERIALS - LEACHABLE (cls N/R) 250.00

FILTERS - LEACHABLE (cls N/R) 17,758.00GREASE - LEACHABLE (cls N/R) 60.00

GREASE - NONREG 744.00 5,234.00LEACHABLE WASTE LIQUIDS (cls N/R) 3,131.00LEACHABLE WASTE SOLIDS (cls N/R) 1,388.25

LP FLAM TOXIC LIQ (cls 3) 40.05LP PEROXIDE ORG SOLID TYPE E (cls 5.2) 15.00

NON-REGULATED LIQUIDS 355.60NON-REGULATED SOLIDS (LANDFILL) 7,310.30 34,594.23

RAGS - LEACHABLE (cls N/R) 15,775.00Sludge - Hydrocarbon 73,500.00

SLUDGE - HYDROCARBON LEACHABLE (cls N/R) 206.75Sludge - Lime 9,799,590.00

SOIL & DEBRIS - LEACHABLE HYDROCARBON (REFINED) (cls N/R) 20,175.00

SOIL & DEBRIS - NONREG HYDROCARBON (REFINED) 320,496.00SOLIDS WITH FLAMMABLE LIQUIDS (cls 4.1) 3,176.97

Total 3,486.60 67,053.27 10,270,124.23 745.85

The pond dredging accounted for most of the solid waste disposal in 2012

Recycling


Waste Description Recycled (kg)

Recycled (L)

AEROSOLS - FLAMMABLE (cls 2.1) 1,180BATTERIES - ALKALINE (recycle) (cls 8) 33

BATTERIES - LITHIUM (cls 9) 65BATTERIES - WET CELL (cls 8) 2,521COMPRESSED GAS (cls 2.2) 26

COMPRESSED GAS FLAMMABLE (cls 2.1) 2EMPTY CONTAINERS - METAL 679

EMPTY CONTAINERS - PLASTIC 1,908FLAMMABLE LIQUID (cls 3) 2,149

FLUORESCENT LIGHT TUBES, NON-REG 169LUBE OIL FILTERS - LEACHABLE (cls N/R) 172

NON PCB CONTAINING BALLASTS 5NON-REGULATED SOLIDS (RECYCLABLE) 82

OIL - LEACHABLE (cls N/R) 1,738 3,131SCRAP METAL 101

Total 10,830 3,131


Subsection 3.1.2 (5) Sulphur Production

0.0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

1.0

Sulp

hur E

mis

sion

s (to

nnes

/day

)

Average Peak Daily Limit

Daily Sulphur Emissions


Sulphur emissions have stabilized around 0.4 tonnes/day

2009 2010 2011

57

2012

0

5

10

15

20

25

Sulp

hur E

mis

sion

s (to

nnes

/mon

th)

Monthly Sulphur Emissions


2009 2010 2011

58

2012

0.0

0.5

1.0

1.5

2.0

2.5

SO2

Emis

sion

s (to

nnes

/day

)

Average Peak Daily Limit (AESRD)

Daily SO2 Emissions


SO2 Emissions are well below the EPEA approval limit of 2 tonnes/day

2009 2010 2011

59

2012

Ambient Air Quality Monitoring

Subsection 3.1.2 (5d)

•Passive ambient air monitoring - all Alberta Ambient Air Quality Objectives were met in 2012•Continuous ambient monitoring trailer October 2011-March 2012 – November & January

erroneous exceedances of the one-hour & 24-hour H2S limits due to a Mercaptan leak60

0.01

0.1

1

10

H2S

(ppb

v)

2012 Ambient Air Quality Results - H2S

North East South West Limit

0.01

0.1

1

10

100

SO2

(ppb

v)

2012 Ambient Air Quality Results - SO2

North East South West Limit


Subsection 3.1.2 (6) Environmental Issues

Environmental Compliance

Compliance• Alberta Environment inspection issues (September 19, 2012)

– Add flare stack at Surmont Phase I Pad 101 to AESRD Approval– Confirm all pressure and safety relief valves in sour service are connected to the

flare system]– Send details of tanks venting to atmosphere at testing– Updates to monthly and annual reports– Clarify requirements for storm water sampling

Environmental Approval Contraventions• January 16, 2012 - 1-hour limit for H2S exceeded – determined to be mercaptan

release from fuel gas skid that is odourizing the gas going to Phase 2• December 15, 2012 – failed hydrotest resulted in a propylene glycol/water spill to the

environment. Completed soil sampling in trench and installed 4 groundwater monitoring wells. Presence of ethylene glycol in the product means the soils exceed guidelines.

Subsection 3.1.2 (6a) 62

All the inspection items have been addressed to the satisfaction of AESRD

Groundwater Monitoring• 2012 results within historical/background concentrations

Soil Monitoring• Soil monitoring program completed in 2012

Integrated Wetlands Monitoring Program• 2012 results within historical/background concentrations

Reclamation Programs• No reclamation in 2012

Programs will be expanded in 2013 to collect background information before Phase II goes into operation.

Environmental Monitoring



Subsection 3.1.2 (7) Compliance Confirmation

Compliance Confirmation


ConocoPhillips is in compliance in all areas of the regulations for all of 2012 with the exception of the following:

• Water recycle• Self disclosure sent on January 2013

• Oil and Water Proration Factors between Jan-May • In compliance since July 2012

• Flaring• 2 low risk flaring events during 2012

• Standing wellbores in excess of 10 years of age without wellheads or pressure test

• Implementing a review process to ensure continued compliance• Steam chamber pressure on Well Pair 102-10 (UWI 102/01-01-083-

7W4 and 103/01-01-083-7W4) • Now in compliance

65


Subsection 3.1.2 (8) Noncompliance Issues

Compliance

Subsection 3.1.2 (7, 8)

Water Recycle:• Scheme requirement is 90%; annual water recycle rate for 2012 was 81.9%• Self disclosed non-compliance for 2012.

• Lower than anticipated produced water volumes from Pilot project driven by ESP failures, downtime to install casing vents, and post T/A ramp up

• WLS problems • Fouling problems in E-502 required the use of additional fresh water to

quench the disposal tank in summer • Replacement of Gen-C convection box and mechanical cleaning of E-502

67

Compliance


Metering and Reporting:• High Risk: Online BS&W analyzer did not exist at delivery point from Pilot facility (F 16885)

to Surmont Plant (F 30980)• Water cut analyzer was installed and commissioned during T/A; now in compliance

• Low Risk: Inaccurate reporting of fuel gas. • CPC created an administrative control to review flared volumes for accuracy between production

accounting and Operations on a monthly basis. Volumes that were inaccurately reported were corrected.

• Low Risk: Product analyzers for the well test separators were not being calibrated. The calibration had also expired for the gas reporting meters.

• Recurrent Preventive Maintenance work orders were implemented. WC analyzer in pad 101 and 102 were calibrated and sampling skid was adopted as permanent installation for yearly calibration.

• Low Risk: Calibration tags/labels had not been updated or were not attached.• Included instrumentation tag/labels verification and correction in PM program.

Flaring:• Low Risk: Two flaring events (December 24, 2011, for 6.5 hours and January 22, 2012 for 7

hours) and the ERCB was not notified of these events• Implemented an electronic Flare Log for Operations to track flare events and reduce manual data

entry errors. Implemented procedure to review log on a weekly basis and report to the Environmental Coordinator.

• Improved DCS alarms on events lasting greater than 4 hours in any 24 hour period (both CPF and well pad flares). Automatic creation of work notification of urgent priority alarm and warn of the need to enter an ERCB submission

68

Compliance


Standing wellbores:• High Risk Enforcement Action issue on June 27/2012. Improper well suspension,

Remedial Action:• Downhole suspension operation completed, DDS update for suspension operation.

• Self-disclosed inactive wells with respect Directive 013 non-compliance for 2012. Low and Medium Risk inactive well without proper suspension.

Remedial Action:• Executed well review to further verify and define steps to bring all Surmont wells in compliance with

Directive 013.• Incorrect well status within the petroleum registry for observation wells.• Low Risk inactive wells suspension that were not reported through the DDS• Inactive wells that have not undergone proper downhole suspension• Develop actions to prevent future Non-Compliance situations.

• Low Risk: Valve handles present on the suspended wellhead that were not chained/locked.• Chains and locks have been installed on the suspended wellhead valves.

Steam Chamber Pressure:• Self disclosure of steam chamber pressure exceedence on Well Pair 102-10 (UWI 102/01-

01-083-7W4 and 103/01-01-083-7W4) due to a manual monitoring pressure process during circulation mode.

Remedial Action:• Adjusted alarm management strategy• Piping surface modified to work for circulation and SAGD mode• Inclusion of a stand alone pressure monitoring system in the piping designs for future circulation wells

69

Surmont Oil Sands ProjectApproval 9426I

Subsection 3.1.2 (9) Future Plans

71

Future Plans – Phase 1

• Continued research into OTSG fouling and OTSG runtime improvements based on reduced MP blowdown recycle field trial and other studies

• Evaluation of GT-OTSG; collect/analyze data• Validate performance of lateral hook on two infill producers in Pad 101 South• Operate eSAGD Pilot with solvent injection commencing in Jan. 2013 • CPF Debottleneck including one OTSG addition • Pad 101 infill program: received approval in Jan. 2013. Rig is scheduled to

commence drilling in April 2013. • The alternative start-ups on Pad 101, the solvent soak and dilation, were

recently applied for in this Month. Current plans are to conduct these tests in 3Q 2013.

• Pad 102 infill program application was issued in November 2012. The current timeline is that we would spud on Pad 102 in June, 2013

• Engineering for Partial Condensate usage for S1 and S2• Automation of EB/REB Chemical Injection• Heat integration improvement on diluent injection

Subsection 3.1.2 (9a, 9b)

Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4

Milestones

Drilling & Completions

Engineering

Procurement & Fabrication

Construction

2013 2014 20152010 2011 2012

Rig Procure / Construct Drilling and Completions

Detailed Engineering

Procurement and Fabrication

Site Preparation Construction

90% Complete

AFEDec 2009

1st Oil

Commissioning Start

1st Steam

• Continued focus on achieving world class safety and environmental performance

• Drilling complete on first pad • Drilling started on next 2 pads• Completions started on first pad• Engineering is 96% complete• Central Processing Facility

Construction 27% complete• Phased commissioning strategy



72

Annual Surmont SAGD Performance Review Approval 9460

Surface Operations

April 11, 2013

Calgary, Alberta, Canada


2

• Introduction• Surmont Overview and Highlights• Facilities & Facility Performance 3.1.2(1,2)• Measurement and Reporting 3.1.2 (3)• Water Production, Injection, and Uses 3.1.2(4)• Sulphur Production 3.1.2 (5)• Environmental Issues 3.1.2(6)• Compliance Confirmation 3.1.2(7)• Non-Compliance Issues 3.1.2(8)• Future Plans 3.1.2(9)

Introduction



• Approval history: 1997 - ERCB Project Approval - Pilot 2003 - ERCB Project Approval - Commercial 2007 - First Steam at Phase1 2008 - Approval of Phase 2 2009 - Approval of Phase 2 Amendment 2010 - Multiple Amendment Submissions for Scheme 9426 2011 - Multiple Amendment Submissions for Scheme 9426

- Phase 1- E-SAGD - approved- Infill Wells - approved- Produced Water Heat Exchanger - approved- Well pad 103 - currently under review

- Phase 2- Production Capacity Increase - approved- Condition 9 - Well Pad 263-2 approved, Well Pad 264-2 and 263-1 currently under review- Condition 10 - currently under review


Surmont Oil Sands Pilot ProjectApproval 9460D

Subsection 3.1.2 (1) Facilities

Site Survey Plan

Rental Boiler & Original Control Room Removed, GT and SCV’s InstalledSubsection 3.1.2 (1a) 6

GT-OTSG Schematic

GT connected and commissioned Turn Around 2012 Subsection 3.1.2 (1b, 1c) 7

Site Survey Plan - Future


2013 Planned Work


Subsection 3.1.2 (2) Facility Performance

Pilot Plant PerformanceBitumen Production


Bitumen Production

0

100

200

300

400

500

600

700

800

900

1000

1/1/

2011

2/1/

2011

3/1/

2011

4/1/

2011

5/1/

2011

6/1/

2011

7/1/

2011

8/1/

2011

9/1/

2011

10/1

/201

1

11/1

/201

1

12/1

/201

1

1/1/

2012

2/1/

2012

3/1/

2012

4/1/

2012

5/1/

2012

6/1/

2012

7/1/

2012

8/1/

2012

9/1/

2012

10/1

/201

2

11/1

/201

2

12/1

/201

2

1/1/

2013

Bitu

men

Pro

duct

oin

bbl/d

2011 2012

Avg. Prod. in 2011 =747 bbl/d (119 m3/d)

Avg. Prod. in 2012 = 553 bbl/d (88 m3/d)

ESP Replacement

Planned Plant Outage

ESP Replacement

Surface Casing Vent installation

2012 Scheduled Turnaround

Pilot Plant PerformanceSteam Generation


Steam Injection

0

500

1000

1500

2000

2500

3000

3500

1/1/

2011

2/1/

2011

3/1/

2011

4/1/

2011

5/1/

2011

6/1/

2011

7/1/

2011

8/1/

2011

9/1/

2011

10/1

/201

1

11/1

/201

1

12/1

/201

1

1/1/

2012

2/1/

2012

3/1/

2012

4/1/

2012

5/1/

2012

6/1/

2012

7/1/

2012

8/1/

2012

9/1/

2012

10/1

/201

2

11/1

/201

2

12/1

/201

2

1/1/

2013

Stea

m In

ject

ed (b

pd C

WE)

2011 2012

ESP Replacement

Planned Plant Outage

2012 Scheduled Turnaround

ESP Replacement

Pilot Production Performance

Deviation from capacity due to:• Surface casing vent installation throughout the summer • ESP failure in P2 • 2012 turnaround

370 m3/d

200 m3/d

Subsection 3.1.2 (2a, 2c) 12

0

50

100

150

200

250

300

350

400

450

Jan-12 Feb-12 Mar-12 Apr-12 May-12 Jun-12 Jul-12 Aug-12 Sep-12 Oct-12 Nov-12 Dec-12 Jan-13

Stea

m R

ate

(m3/

d CW

E) /

Bitu

men

Rat

e (m

3/d)

Steam Steam Capacity Bitumen Bitumen Capacity

Surmont Thermal PilotElectricity Consumption


0

50

100

150

200

250

300

350

400

450

0

5

10

15

20

25

30

35

40

45

1/20

092/

2009

3/20

094/

2009

5/20

096/

2009

7/20

098/

2009

9/20

0910

/200

911

/200

912

/200

91/

2010

2/20

103/

2010

4/20

105/

2010

6/20

107/

2010

8/20

109/

2010

10/2

010

11/2

010

12/2

010

1/20

112/

2011

3/20

114/

2011

5/20

116/

2011

7/20

118/

2011

9/20

1110

/201

111

/201

112

/201

11/

2012

2/20

123/

2012

4/20

125/

2012

6/20

127/

2012

8/20

129/

2012

10/2

012

11/2

012

12/2

012

Elec

tric

al Im

port

s (M

Wh/

mon

th)

Elec

tric

al In

tens

ity (k

Wh/

BB

L B

itum

en)

Electrical Energy Intensity Electrical Energy Import

Surmont Thermal PilotProduced Gas

14Subsection 3.1.2 (2e)

Change from calculated to metered volumes

0

50

100

150

200

250

300

350

400

450

1/20

092/

2009

3/20

094/

2009

5/20

096/

2009

7/20

098/

2009

9/20

0910

/200

911

/200

912

/200

91/

2010

2/20

103/

2010

4/20

105/

2010

6/20

107/

2010

8/20

109/

2010

10/2

010

11/2

010

12/2

010

1/20

112/

2011

3/20

114/

2011

5/20

116/

2011

7/20

118/

2011

9/20

1110

/201

111

/201

112

/201

11/

2012

2/20

123/

2012

4/20

125/

2012

6/20

127/

2012

8/20

129/

2012

10/2

012

11/2

012

12/2

012

1/20

13

Prod

uced

Gas

(103 m

3 /mon

th)

Produced Gas

Pilot Plant PerformanceGas usage

Subsection 3.1.2 (2e) 15

2009 2010 2011 2012 units

Total Gas Imports (TCPL) 11,767 11,224 12,334 9,728 103m3

Solution Gas 41.20 53.20 1,347.30 2,961.60 103m3

Total Gas Vented 0 0 0 0 103m3

Total Gas Flared 2.70 0.9 2.8 2.45 103m3

Solution Gas Recovery 93.4 98.3 99.8 99.9 %

0

20

40

60

80

100

120

140

160

180

200

1/20

092/

2009

3/20

094/

2009

5/20

096/

2009

7/20

098/

2009

9/20

0910

/200

911

/200

912

/200

91/

2010

2/20

103/

2010

4/20

105/

2010

6/20

107/

2010

8/20

109/

2010

10/2

010

11/2

010

12/2

010

1/20

112/

2011

3/20

114/

2011

5/20

116/

2011

7/20

118/

2011

9/20

1110

/201

111

/201

112

/201

11/

2012

2/20

123/

2012

4/20

125/

2012

6/20

127/

2012

8/20

129/

2012

10/2

012

11/2

012

12/2

012

1/20

13

Gre

enho

use

Gas

Em

issi

on In

tens

ity

(kg

CO

2e/B

OE)

Greenhouse Gas Emission Intensity

2012

Greenhouse Gas Emissions

2009 2010 2011

Subsection 3.1.2 (2f) 16


Subsection 3.1.2 (3) Measurement and Reporting

Bitumen Measurement and Reporting


Bitumen Production = [Phase 1 meter Daily Total + Phase 1 Truck receipts + (Sales Tank finish level – Sales Tank start level) ] –[Diluent Pilot Receipt Meter Daily Total + Diluent Truck receipts +(Diluent Tank finish level – Diluent Tank start level)]

Well Bitumen production is calculated from well tests (pro-rated battery)

18

Prod Water Measurement and Reporting


Water Production = [Flash Tank, Skim Tank, Produced Water Tank and De-sand Tank finish levels - Flash Tank, Skim Tank, Produced Water Tank and De-sand Tank start levels] + [Phase 1 Receipt Meter Daily Total]

Well water production is calculated from well tests (pro-rated battery)

19

Production Gas• Total battery gas production estimated from total battery oil production and

GOR• Well test gas production calculated from well test oil production and GOR• Gas proration factor = total battery gas production / well test gas production

Steam• Steam injection metered individually at each well

Well Testing• One well on test at a time• Target at least two tests per well per month• All three well pairs tested regularly to meet minimum monthly target

Measurement and Reporting Methods

Subsection 3.1.2 (3a, 3c)

No modification in accounting formula

20


Subsection 3.1.2 (4) Water Production, Injection, and Uses

Water Source WellsNon-Saline

Surmont Pilot


1F1082508307W400 1AJ082508307W400 Lower Grand Rapids

1F1072508307W400 100072508307W400 Clearwater

Surmont Phase 1






Notes

• all water currently used at the Surmont project is non-saline and non-potable (i.e., waters not readily or economically treatable for potable, domestic, agricultural or livestock use)• Phase 2 source wells licenced December 14, 2012, not yet operational


Surmont Phase 2









Pilot Water Source WellsProduction Volumes


0

2,000

4,000

6,000

8,000

10,000

12,000

14,000

16,000

18,000

20,000

Jan-

10

Apr

-10

Jul-1

0

Oct

-10

Jan-

11

Apr

-11

Jul-1

1

Oct

-11

Jan-

12

Apr

-12

Jul-1

2

Oct

-12

Jan-

13

Volu

me

of W

ater

Pro

duce

d (m

3 ) per

Mon

th

1F1/08-25-083-07 W4M (Lower Grand Rapids)1F1/07-25-083-07 W4M (Clearwater)

Source Water and Steam Injection Volumes

Subsection 3.1.2 (4c; 4d) 24

0

2000

4000

6000

8000

10000

12000

14000

16000Ja

n-11

Feb-

11

Mar

-11

Apr

-11

May

-11

Jun-

11

Jul-1

1

Aug

-11

Sep

-11

Oct

-11

Nov

-11

Dec

-11

Jan-

12

Feb-

12

Mar

-12

Apr

-12

May

-12

Jun-

12

Jul-1

2

Aug

-12

Sep

-12

Oct

-12

Nov

-12

Dec

-12

Jan-

13

Stea

m (c

we

m3/

mnt

h), P

rod.

Wat

er (m

3/m

nth)

Steam Prod Wtr

Water Disposal Wells

Subsection 3.1.2 (4g)

Well

Zone Approved

for Disposal

Maximum Wellhead Injection Pressure

(kPa)

Well Status

ERCB DisposalApproval

No

102/03-31-083-06W4/0 McMurray 3600 Water,

Suspended 9573A

103/03-31-083-06W4/0 McMurray 3600 Water,

Suspended 9573A

103/10-31-083-06W4/0 McMurray 3600 Water,

Suspended 9573A

104/10-31-083-06W4/0 McMurray 9000 Observation

Well 9573A

100/09-25-083-07W4/0 Keg River 6000 Water,

Disposal 9573A

100/01-16-083-05W4/0 McMurray 2700 Water,

Disposal 10044B

100/07-22-083-05W4/0 McMurray 2500 Water,

Disposal 10044B

100/08-10-083-05W4/0 McMurray 2300 Water,

Disposal 10044B

100/01-04-083-05W4/0 McMurray 2500 10044B

100/01-11-083-05W4/0 McMurray 2500 10044B

25

INA

CTI

VE

Notes

• Disposal to 100/09-25-083-07W4/0 ended December 2011• As of December 2011, water transferred to Phase 1 via pipeline

102/01-16

102/03-31

102/08-10

104/10-31

1F1/08-32

100/01-04

100/01-11

100/01-16

100/07-22

100/08-10

103/03-31

103/10-31

100/09-25

083-05W4

Disposal Well

Observation Well

083-06W4

084-06W4 084-05W4

Water Disposal Rates

Subsection 3.1.2 (4h) 26Disposal waters transferred to Phase 1 via pipeline and truck as of December 2011

0

2,000

4,000

6,000

8,000

10,000

12,000

14,000

16,000

18,000

20,000

22,000

24,000Ja

n-11

Feb-

11

Mar

-11

Apr

-11

May

-11

Jun-

11

Jul-1

1

Aug

-11

Sep

-11

Oct

-11

Nov

-11

Dec

-11

Jan-

12

Feb-

12

Mar

-12

Apr

-12

May

-12

Jun-

12

Jul-1

2

Aug

-12

Sep

-12

Oct

-12

Nov

-12

Dec

-12

Jan-

13

Volu

me

of W

ater

Tra

nsfe

rred

(m3 )

per

Mon

th

Blow Down Water Transferred to Phase 1 via Pipeline

Blow Down Water Trucked to Pond

Produced Water Injected at 100/09-25-083-07 W4M (Keg River)

Produced Water Transferred to Phase 1 via Pipeline

Water Disposal WellWellhead Pressure (Keg River)


0

1,000

2,000

3,000

4,000

5,000

6,000

7,0001-

Jan-

10

2-Ju

l-10

1-Ja

n-11

3-Ju

l-11

1-Ja

n-12

2-Ju

l-12

1-Ja

n-13

Dis

posa

l Wel

l Hea

d Pr

essu

re (k

Pa)

Approval Max WHP for 09-25: 6000 kPa

Solid Waste Disposal

Data provided by Tervita

Subsection 3.1.2 (4i)

Waste Description Waste Weight (kg) Final Destination Facility Type

FILTERS - LEACHABLE (cls N/R) 356 Secure Energy – Pembina Area Landfill Landfill Class I

RAGS - LEACHABLE (cls N/R) 277 Secure Energy – Pembina Area Landfill Landfill Class I

SOIL & DEBRIS - LEACHABLE HYDROCARBON (REFINED) (cls N/R) 5,518 Secure Energy – Pembina Area Landfill Landfill Class I

ASBESTOS (TDG PIN UN2590 OR UN2212) (cls 9) 470 Beaver County Regional Landfill Landfill Class II

NON-REGULATED SOLIDS (LANDFILL) 135 Beaver County Regional Landfill Landfill Class II

28

Waste Description Waste Volume (m3)

Final Destination (Volume in m3) Facility Type

Contaminated Debris and Soil (Crude Oil/Condensate) 23 Newalta – Redwater (5)

Tervita – Lindbergh (18)Oilfield Processing

Cavern

Crude Oil/Condensate Emulsions 225 Newalta – Elk Point (153)Tervita – Lindbergh (72)

Oilfield ProcessingCavern

Sand - Produced 17.5 Tervita – Lindbergh Cavern

Sludge - Hydrocarbon 1124.5Newalta – Elk Point (21.5)Newalta – Hughendon (18)Tervita – Lindbergh (1085)

Oilfield ProcessingOilfield Processing

Cavern

Wash Fluids – Organic 20 Tervita – Lindbergh Cavern

Waste Water Non Reportable 18 Newalta – Hughendon Oilfield Processing

Well Workover Fluids 20 Newalta – Hughendon Oilfield Processing

Fluid Waste Disposal

Data provided by TervitaSubsection 3.1.2 (4i) 29


Subsection 3.1.2 (5) Sulphur Production

0

0.05

0.1

0.15

0.2

0.25

0.3

0.35

0.4

0.45

Sulp

hur E

mis

sion

s (to

nnes

/mon

th)

Monthly Sulphur Emissions


2012

31

Change to a more accurate Field Data Capture system starting May 2011

2009 2010 2011Unusually high field H2S concentration

0.000

0.010

0.020

0.030

0.040

0.050

0.060

0.070

0.080

0.090

SO2

Emis

sion

s (to

nnes

/day

)

Average Peak Daily Limit (AESRD)

Daily SO2 Emissions


SO2 emissions well below daily limit of 0.08 t/d32

2009 2010 2011 2012

Ambient Air Quality Monitoring


Alberta Ambient Air Quality Objectives were met in 201133

0.01

0.1

1

10

H2S

(ppb

v)

2012 Ambient Air Quality Results - H2S

Site 5 Site 6 Limit

0.1

1

10

100

SO2

(ppb

v)

2012 Ambient Air Quality Results - SO2

Site 5 Site 6 Limit


Subsection 3.1.2 (6) Environmental Issues

Compliance• No regulatory issues with Alberta Environment, SRD or DFO

Groundwater Monitoring• 2012 results within historical/background concentrations

Soil and Groundwater Monitoring• Soil monitoring program completed in 2012

Reclamation Programs• No reclamation in 2012

Environmental Compliance

Subsection 3.1.2 (6a, 6c, 6d) 35


Subsection 3.1.2 (7) Compliance Confirmation

Compliance Confirmation

ConocoPhillips is in compliance in all areas of the regulations for all of 2012 with the exception of the following:

• Inaccurate reporting of flared gas• Meter calibration/proving tag or detailed report does not meet

requirementsFollow-up items from audit

• Glycol surge drum blanketed with fuel gas• Pilot VRU• Raw water with no secondary containment• No surface casing vents• Water-cut meter



Subsection 3.1.2 (8) Noncompliance Issues

Compliance

Inaccurate Reporting of Flared Gas:• High risk noncompliance• (Complete) Administrative controls in place

Meter calibration/proving tag or detailed report does not meet requirements:

• Low risk noncompliance• (Complete) Recalibrated and re-tagged at Pilot turn around September 2012

Follow-up Items From Audit:• Glycol surge drum blanketed with fuel gas

– (Complete) Replaced fuel gas blanket with inert N2 during September 2012 turn around

• Pilot VRU – H2S release calculations submitted, ERCB meeting pending

• Raw water with no secondary containment– (Complete) Sampling and testing of the raw water meets the criteria of Directive 055 Section 3.4.1 and

therefore does not require secondary containment.

• No surface casing vents– (Complete) Installed during 2012 turn around

• Water-cut meter on sales oil – (Complete) Installed during 2012 turn around


Subsection 3.1.1 – 2) Geology and GeophysicsSurmont Oil Sands Pilot Project

Approval 9460DSubsection 3.1.2 (9)

Future Plans

• Potentially re-drill well pair C and reestablish total steam chamber coalescence with pairs A and B.

• Maintain a production strategy for well pairs A and B to achieve primary objective of the Pilot of understanding SAGD performance under thief zones.

• Gas cap monitoring• Thief zone and blowdown studies• Potentially install and test the operation of a rifled tube OTSG • Test the operation of the GT-OTSG


Future Plans

41

April 10, 2013

AnnualSurmont SAGD

Performance ReviewApprovals 9460, 9426 and 11596

Subsurface

2


• Introduction• Surmont Overview and Highlights• Geology and Geophysics 3.1.1(2)• Drilling and Completions 3.1.1(3)• Artificial Lift 3.1.1(4)• Instrumentation in Wells 3.1.1(5)• 4D Seismic 3.1.1(6)• Scheme Performance 3.1.1(7)• Future Plans 3.1.1(8)

Introduction



• Approval history: 1997 - ERCB Project Approval - Pilot 2003 - ERCB Project Approval - Commercial 2007 - First Steam at Phase1 2008 - Approval of Phase 2 2009 - Approval of Phase 2 Amendment 2010 - Construction Start at Phase 2 2011 - Approval of Phase 2 Expansion, GT-OTSG and E-SAGD Projects 2012 - Multiple Amendment Submissions for Scheme 9426

- Phase 1- Well pad 103 - approved

- Phase 2- Condition 9 – Well Pads 264-2 and 263-1 – approved- Condition 10 – Operating Strategy – approved- HWY 881 Steam Pipeline Crossing – approved


5

Surmont Overview and Highlights

6

• Phase 1 is identifying optimization opportunities based on actual conditions

• Phase 1 and 2 combined approved capacity is 21, 624 m3/d (136,000 bbl/cd) (Ph 1 - 4,293 m3/d , Ph 2 - 17,331 m3/d )

Surmont Overview


7

2012 Highlights

• Operations Excellence: Focus on Integrated Operations to improve safety and productivity

• Leverage learning from others• Continued planning for sustaining pads and infill wells• Engineering work for major debottlenecking projects • Reached new records of steam injection and bitumen

production during 2012• Key improvements/successes:

- Achieved production proration factor compliance- Improved ESP conversion time. Started up two PCPs- Continue Circulation optimization- Achieve longer periods of CPF stability- Soda ash silo commissioned and operating- MPFM trial - Started solvent injection at E-SAGD pilot- Started MP reduced BD trial - Pilot turn around. GT-OTSG burner start up

• Key challenges:- Water treating OTSG Scale- Water balance and water recycle- E-502 fouling and required cleaning


D ata as o f January 31 , 2013

0

5,000

10,000

15,000

20,000

25,000

30,000

35,000

Oct

-07

Jan-

08

Apr

-08

Jul-0

8

Oct

-08

Jan-

09

Apr

-09

Jul-0

9

Oct

-09

Jan-

10

Apr

-10

Jul-1

0

Oct

-10

Jan-

11

Apr

-11

Jul-1

1

Oct

-11

Jan-

12

Apr

-12

Jul-1

2

Oct

-12

Jan-

13

Gro

ss P

rodu

ctio

n (b

oepd

)

0

20,000

40,000

60,000

80,000

100,000

120,000

Stea

m In

ject

ion

(cw

ebpd

)

Daily produc tion P roduc tion record Daily S team S team record

8

Phase 1 Production

2008 Key Issues• Freezing

• Off-spec product• Plant instability

2009 Key Issues• OTSG integrity

• Front-end treatment• 1st turnaround

2010 Key Issues• ESP installations

• OTSG maintenance

Continued stable operationsSubsection 3.1.1 (1)

2011 Key Issues• ESP installations

• OTSG maintenance • Turnaround

2012 Key Issues•ESP installations /

Repair•OTSG maintenance

Record Production: 29,917 boepd

Record Steam: 68,470 cwebpd

9

Subsection 3.1.1 (2) Geology and Geophysics

1010

2012-2013 Delineation Campaign and Well Density

Subsection 3.1.1 (2a,b)

Phase 1 and Phase 2 Development Area

Phase 2 drainage areas

Surmont lease

1146 existing wells – 139 new

139 new vertical wells (as of Jan 31, 2013)

Delineation Wells – Surmont Lease

11



Focus on Phase 2 Initial Drainage Areas and Initial Surmont 1 sustaining pad

locations as well as delineation of Phase 3

Existing wells

New vertical wells (as of Jan 31, 2013)



Surmont lease

Delineation Wells – Development Area

(only includes wells that penetrate the McMurray)

1212



Delineation focused on Phase 2 AreaDelineation across Phase 1, 2, and 3

Delineation Well Density Map - Jan 2013Delineation Well Density Map - Jan 2012

1313

2012-2013 Delineation Campaign and Core Density


McMurray Cored Wells – Surmont Lease

1146 wells total

403 existing core wells

23 new core wells (as of Jan 31, 2013)



Surmont lease

14Subsection 3.1.1 (2a,b)


McMurray Cored Wells– Development Area

Existing wells

Existing cored wells

New core wells (as of Jan 31, 2013)



Surmont lease

1515

Increased core density with latest drilling


Cored Wells Density Map - Jan 2012

McMurray penetrated Wells only

Cored Wells Density Map - Jan 2013


1616

2012-2013 Delineation Campaign and FMI Logs


1146 wells total

657 existing FMI wells

139 new FMI wells (as of Jan 31, 2013)



Surmont lease

McMurray FMI Logs – Surmont Lease 100% Coverage of FMI Data in 2012/2013 program

• Important for breccia identification

1717Subsection 3.1.1 (2f)

2012-2013 Delineation Campaign and FMI Logs

McMurray FMI Logs – Development Area 100% Coverage of FMI Data in 2012/2013 program

• Important for breccia identification

Existing wells

Existing FMI wells

New FMI wells (as of Jan 31, 2013)



Surmont lease

McMurray penetrated Wells only

FMI Well Log Density Map – Jan 2012

Increased Formation Micro Imaging density with latest drilling

FMI Well Log Density Map – Jan 2013

2012-2013 Delineation Campaign and FMI Density

18Subsection 3.1.1 (2a,b)

TopResSeis: was a composite surface interpreted from seismic and well picks to represent the top of the McMurray reservoir. It could be top bitumen, top water or top gas, and it was a challenged seismic pick.• Decision: discontinue this interpretation in

favor of clear stratigraphic interpretations: Top McMurray and Base Channel.

Top McMurray (MCMR): distinct geologic and seismic pick, a stratigraphic boundary.• McMurray fluid boundary interpretations

remain based on well data

McMurray Channels (MCMR_CH_SH_Base): distinct geologic and seismic pick, stratigraphic feature that erodes into McMurray reservoir.

2012 Geological Updates

Updated Geological Schematic 2012

19Subsection 3.1.1 (2i)

Refined Channel Interpretation

20

Surmont 3D Seismic Surveys

KW KE

Subsection 3.1.1 (2l)

KNW

3D Km2 Shots S-R Line S-R

103 1.9 1,700 60x80 20x20

104 2.9 1,103 60x80 20x20

KW 58.2 24,690 120X80 20X20

KNW 21.5 9,543 120x80 20x20

2012-2013 Seismic

21Subsection 3.1.1 (2c)

McMurray Gross Isopach

McMurray Gross Isopach

28‐40 m

40‐50 m

50‐60 m

60‐75 m

75‐110 m

Phase 1 and Phase 2 development


3D seismic areas used for mapping (all 12 volumes)

Surmont lease

2012/2013 delineation program update: December 2012 – minor changes due to

• Re-evaluated/unified geologic picks

• Improved Seismic Interpretation

2222

McMurray Net Gas Isopach


McMurray Net Gas Isopach


Phase 2 drainage area


Surmont lease

• Net top gas thickness = Sands have deep resistivity >10 Ω-m and Vsh <65%




2323

McMurray Net Top Water Isopach



Surmont lease

• Net top water thickness = Sands have deep resistivity <10 Ω-m and Vsh <45%




McMurray Net Top Water Isopach



2424

Top Cont Bitumen Structure



Surmont lease




Top Continuous Bitumen Structure



2525

Base Cont Bitumen Structure





Surmont lease




Base Continuous Bitumen Structure

2626

Net Cont Bitumen Pay


McMurray Net Continuous Bitumen Pay


Surmont lease



• Net continuous bitumen = sands have deep resistivity >40 Ω-m and Vsh <33%, and no shale greater than 3 m thick

18-30 m>30 m

2-18 m




27

Surmont Lease OBIP

Subsection 3.1.1 (2a, 2b, 2c)

Surmont Lease OBIP

Surmont lease



OBIP = Thickness x Phie x So x Area

2012/2013 Delineation Program Update: December 2012 – no major change to

OBIP per square mile (enlarged Development Area)

18-30m

>30m

2-18m

Properties Development Area

NCBThickness Range

0 to Greater than 30 m

Phie in NCB 33%

So in NCB 79%

OOIP in NCB > 18m

2761 MMbblsDeterministic

28

Example Log 100161408307w400

Phase 1 Area

Phase 1 Type Log (Pad 101)


Type LogPad 101

Core

WTAR

0-0.2

Calc

WTAR

0-0.2

DT

600-200

Res

0.2-2000

Neut-Den

0.6-0Cor

eVSh

0-1

GR

0-150Faci

es

Dips Flag

s

Devonian

McMurray

Continuous Bitumen

High Sw

High Sw

No changes In 2012

29

Example Log 100162208306w400

Phase 2 Area

Phase 2 Type Log (Pad 264-2)


Type Log

Core

WTAR

0-0.2

Calc

WTAR

0-0.2

DT

600-200

Res

0.2-2000

Neut-Den

0.6-0Cor

eVSh

0-1

GR

0-150Faci

es

Dips Flag

s

Devonian

McMurray

Continuous Bitumen

High Sw

Top Gas

No changes In 2012

30

Special Core Analyses BitumenViscosity Sampling


Objectives• Characterize vertical and lateral variance in

viscosity at different temperatures

• Model the variance in bitumen properties and its implications for bitumen production rates during SAGD

• Characterize relationship between viscosity, density and geochemical composition

No changes. Viscosity increases with depth in the

McMurray Formation.

8 viscosity sample wells (Jan 31, 2013 )

38 existing viscosity sample wells

2012 – 2013 DelineationDelineated Wells - Surmont

31

Representative Structural Cross Section

Subsection 3.1.1 (2i)

A

A’

A A’

No changes In 2012

3232

Pad 262-1 VariableBitumen-Water Contact

The presence of basal water becomes a risk on Pad 262-1


Existing 13-34 04-03

270m

TopContBit

DevUnc

Small gas accumulation

BitumenWater

McMurray Net Continuous Bitumen (NCB)

13-344-3

• Well 4-3-84-6w4 intersected a raised bitumen/water contact. Contact is ~ 12 m higher than the nearest offset.

• Well also intersected a small gas pool under the bitumen.

No changes In 2012

33

INSAR Surface Deformation Monitoring

Subsection 3.1.1 (2k; 2j)

Cumulative Deformation April to Dec 2012Cumulative Deformation Jan to Dec 2012

Interferometric Synthetic Aperture Radar Images:• Data is collected every 24 days

Data acquisition initiated after first steam in 2008 • Input used for Geomechanical Model Calibration• CRs 1 to 20 March 2008• CRs 21 to 47 March 2010• CRs 48 to 72 March 2012

50 New CR March 2012Frost heave affect CR

Maximum deformation at CR 14

Deformation currently in line with expectations

During 2013 focus on area near CR 14

34Subsection 3.1.1 (2m)

Caprock Integrity

Conclusions from the study

1. The results of the cap rock integrity study indicate that Wabiskaw and Clearwater shales at Surmont constitute a robust and laterally continuous cap rock.

2. Generally, similar lithologies and thus seal characteristics will be distributed over substantial distances (typically of greater areal extent than the Surmont lease area).

3. Seismic structural analysis indicated that no through-going faults or other discontinuities break the cap rock interval at Surmont

•Seismic structural analysis, coherency and a fault enhanced volume has been studied on the Devonian and Wabiskaw surfaces to look for through-going faults.

Coherence Seismic Attribute Wabiskaw Formation and Devonian Unconformity Overlain Fault-enhanced Extraction at Wabiskaw Formation

No changes In 2012

Subsection 3.1.1 (2m)

Caprock Integrity

Conclusion from the study:

•The best seals within the cap rock interval are the deeper water deposits occurring on maximum flooding surfaces.

•These muds can be over 80% clay and are correlated throughout and beyond the Surmont lease.

•9 new cap rock cores in 2011

•The cap rock interval was investigated by:•core description and analyses•log interpretation and correlation•seismic interpretation and correlation.

•Analytical methods included •visual core examination,•reflected light microscopy, •laser particle size analysis, •biostratigraphic analyses, •X-ray diffraction for clay species, •QEMSCAN (quantitative mineralogy),•chemostratigraphy (bulk geochemistry) and •MICP (mercury injection capillary pressure) analyses to determine seal capacity

35

No changes In 2012

36Subsection 3.1.1 (2m)

Maximum Operating Pressure

Conclusion from the study:

In the 2011 testing, despite the varying conditions tested, the retained minimum stress gradient of the cap rock at 18.4 kPa/m was further validated The recommended MOP gradient is 15 kPa/m (@SF=1.2) which is lower than previous by applying a higher factor of safety.

•3 mini-frac tests targeted the most structurally complex features currently identifiable across the lease based on mapped structures of the Devonian, McMurray, cap rock, and overburden.

•All of the 2011 test locations were proposed to and reviewed with the ERCB prior to the execution of the tests and include variability in other features such as proximity to gas depletion, overburden, karsting and other structural variability.

•Other MOP supporting data, includes cap rock core samples subjected to tri-axial testing, log data, FMI interpretations, seismic, etc., combined with the overall cap rock characterization, reservoir simulation and geomechanical modeling.

Pre-Cretaceous Unconformity and 2011 Mini-Frac Locations

No changes In 2012

37

Operating Strategy

• Based on the cap rock integrity studies, ConocoPhillips has proposed a maximum pressure of 15kpa/m

• Circulation optimization including dilation is an area of ongoing study and ConocoPhillips submitted an application to the ERCB in Q1 of 2013

• Pace of pressure drops will be largely driven by:– Specific, local reservoir properties– Thief zone interactions– Economics– ESP installations– Plant capacity– Global steam optimization

Subsection 3.1.1 (2m)

ConocoPhillips continues to propose a flexible tapered strategy envelope bound by the cap rock integrity study and the associated MOP on one side and economic achievable pressures on the low side

38

Subsection 3.1.1 (3)Drilling and Completions

39

6 new delineation wells

Well Summary

• 5 drainage areas– Pilot– 101 North– 101 South– 102 North– 102 South

• 41 well pairs, 2 infill producers Pilot (3 well pairs) Phase 1A (21 drilled – 20 completed) Phase 1A redrills (3 wells) Phase 1B (7 drilled – 7 completed) Phase 1C (8 drilled well pairs – 8 completed) Pad 101 South 2011-2012 Infills

Subsection 3.1.1 (3a)GOB – Gas Over Bitumen

2011/2012 Infills

GOB MonitoringObservation WellsPilotPhase 1A ProgramPhase 1B ProgramPhase 1C ProgramRedrills

40

Pad 101 Plot Plan


Phase 1C

Infill program in 2012

Infill Pairs

Infill Producers

Surface Well Name

Downhole Well Name

101-01 101-10101-02 101-11101-03 101-12101-04 101-13101-05 101-14101-06 101-17101-07 101-18101-08 101-02101-09 101-01101-10 101-03101-11 101-04101-12 101-05101-13 101-06101-14 101-16101-15 101-15101-16 101-07101-17 101-08101-18 101-09101S10INF1 101S10INF1101S11INF1 101S11INF1101S16INF1 101S16INF1101S17INF1 101S17INF1

2012 Infill Drilling Campaign

• Completed all wells• 101P10INF, P11INF and

101WP16INF are in operation


N

101-WP17-INF

101-WP16-INF

101-P11-INF1

101-P10-INF1

101S Infill Well Locations

WP18

WP17

WP16

WP15

WP14

WP13

WP12

WP11

WP10

41

42

Pad 102 Plot Plan


No changes In 2012Pad 102 well naming is the same

surface and downhole wells

43

All Phase 1A wells completed with ESPs,

Infill producers with metal-to-metal PCPs,

Infill Pair 101-16INF Completed Circulation Process

Pad 101 Completions

Subsection 3.1.1 (3b)• Wellpair 18 Executed cement squeeze and completed with tie-back.

P01

I01 I02

P02 P18

I18 I17

P17

I09

P09P08

I08I07

P07

I15

P15

I16

P16

P06

I06

P05

I05I04

P03

I03

I10 P10

I11P11

I12P12

I13

P13

I14

P14

P04

Phase 1C

Phase 1A

Concentric Completion Well

Parallel Completion Well

Drilled and to be completed 2012

~ ~~ ~ ~

~

~ ~~ ~ ~

Mechanical Lift Completion Well

~~

~ ~P10INFP11INF

I17INF

P17INF P16INF

I16INF

I01

P01

44

Pad 102 Completions


P18I18 I17

P17 P16

I16 I15

P15I09

P09P08

I08I07

P07 I06

P06

I05

P05

P04

I04

P03

I03

P02

I02

P01

I01

I10P10P11P11I12P12I13P13I14P14

A A

AP11-R I10-RI11-R

A

Phase 1A are parallel completions while Phase 1B are mostly concentric

Phase 1B

Phase 1B

~ ~~ ~~ ~

~ ~~ ~

Concentric Completion Well

Parallel Completion Well

~ Mechanical Lift Completion Well

~~

~

~

~~

45

• ESP change – Dec 2012• Depths (mKB)

– Surface Casing: 55– Intermediate Casing: 535 – Production Tubing: 447.2– Wire-Wrapped Screen: 504-935 – Reda 538 Series ESP: 455.1

• Diameters (mm)– Surface Casing: 406.4 (16 in)– Intermediate Casing: 273.1 (10.75 in)– Wire-Wrapped Screen: 177.8 (7 in)– Production Tubing: 88.9 (3.5 in)

• Measurement– Schlumberger P/T gauge– ESP motor temperature RTD– Bubble Tube

Pilot A Wellpair Producer Example

ESP replaced Jun 2011

Pump Intake

ESP Motor

Wire‐Wrapped Screen

Surface Casing

Intermediate Casing

Tubing Hanger


46

Surface Casing

Intermediate Casing

Toe Injection Tubing

Heel injection Tubing

Promore Thermocouple Instrument String

Wire‐Wrapped Screen

Pilot A Wellpair Parallel Injector Example

• Depths (mKB)– Surface Casing: 64– Intermediate Casing: 545– Toe Tubing: 905– Heel Tubing: 501– Instrument String: 905– Wire-Wrapped Screen: 518-920

• Diameters (mm)– Surface Casing: 339.7 (13.4 in)– Intermediate Casing: 244.5 (9.625 in)– Wire-Wrapped Screen: 177.8 (7 in)– Heel Tubing: 60.3 (2.4 in)– Toe Tubing: 60.3 (2.4 in)

• Measurement– Promore Thermocouple string installed


No change in 2012

47

Phase 1 Parallel Injector Example

11 3/4” Intermediate Casing

4 1/2” Heel String

8 5/8” slotted liner2 7/8” Toe String

16” Conductor


No change in 2012

48

Phase 1 Parallel Producer Example


4 1/2” Heel String 7” Slotted Liner

3 1/2” Toe String

1 1/4” G/L Bubble Tube Coil

1/4” Bubble Tube

1” G/L Coil

13 3/8” Conductor


1.66” IJ String With Instrumentation Coil

No change in 2012

49


7” Heel String8 5/8” Slotted Liner

4” Toe String

16” Conductor Pipe

Phase 1 Concentric Injector Example


No change in 2012

50

1” G/L Coil

Phase 1 Concentric Producer Example

9 5/8” Intermediate casing

7” Heel String

7” Slotted Liner4” Toe String

5/8” TC Bubble Tube Instrument Control Line Clamped to the Outside of Toe Tubing

¼” Bubble Tube

13 3/8” Conductor Pipe


No change in 2012

51

Phase 1 VIT Concentric Injector Example



7” Heel (Short) Tubing

8 5/8” Slotted Liner

4” Toe (Long) Tubing

16” Conductor Pipe

4.5” Toe (Long) VIT Tubing

No change in 2012

52

1” G/L Coil

Phase 1 VIT Concentric Producer Example


7” Heel String

7” Slotted Liner

4” Toe String

5/8” TC Bubble Tube Instrument Control Line Clamped to the Outside of Toe Tubing

¼” Bubble Tube

13 3/8” Conductor Pipe


4.5” Toe VIT String

No change in 2012

53

Phase 1 VIT Completions


Vacuum insulated tubing (VIT):• Consists of concentric inner and outer

standard oil field tubing welded at each end • Vacuum is applied to the annular space• Coupling further insulated with a covering

Applications:• Minimize heat transfer to permafrost zones to

prevent subsidence• Minimize annular pressure build-up• Hydrate prevention• Paraffin prevention• Heat retention for heavy oil and steam

flooding projectsCourtesy of V&M Tubing Alloy

No change in 2012

54

Phase 1 ESP Producer Completion


Typical ESP Bottomhole Configuration


88.9mm EU 9.3ppf production string

7” slotted liner f/743m to 1,616m

1-1/4” IJ InstrumentString

1/4” Bubble Tube Coil (clamped)3/8” Instrumentation in power cable (clamped)¼” encapsulated instrumentation line for Opsens P/T sensor (clamped)

ESP – REDAHotline III

13 3/8” Conductor

P/T Senso Bottom @715m

Tail pipe thermal packer

114.3mm Hydrill tail pipe top: above liner hanger bottom @ 1,461m

All depths indicated are GRD

Temperature monitoring Instrumentation (Thermocouple/Fiber Optics inside of 1.25” Coil)5 thermocouples from 705m to 730m, equally spaced6th thermocouple @ 743m40th thermocouple @ 1,616m. Equally spaced

Liner hanger top @741m MD

ESP

No change in 2012

Phase 1 PCP Producer Completion

55

101-P21 (10INF) • Rod String: Sucker Rods with spin

through centralizers• Lined to toe with sidetrack “hook” towards

P01 (10) toe, taking-off at 1404MD • Guide/steam injection string: 2 3/8” by

3½” to toe• Instrumentation consisting of:

Intake/Discharge P/T + 40 pts Lxdata + Toe P/T gauge

101-P22 (11INF) • Rod String: Continuous Rod• Lined and “hooked” towards P02 (11)

at toe• Guide/steam injection string: 2 3/8”

by 3 ½” to toe• Instrumentation consisting of:

Intake/Discharge P/T + 40 pts Lxdata + Toe P/T gauge


Flow Control Device Update102-06 Equalizer Completion

4 ½” Heel String

Injector Equalizer SAGD

Liner hanger:WFT packer

1/4” Bubble Tube

SteamEmulsionBlanket Gas

Steam Injection

Slotted liner6-5/8” Equalizer

Intermediate casing9 5/8” Producer

Thermocouples Downhole Temperature Measurement:1-1/4” coil deployed TC inside toe tubing

Downhole Pressure Measurement: Bubble tube banded to heel string

4 ½” Heel String

Producer Equalizer SAGD

Liner hanger:WFT packer

1/4” Bubble Tube

EmulsionBlanket Gas

Emulsion

Slotted liner6-5/8” Equalizer

Intermediate casing9 5/8” Producer

Thermocouples Downhole Temperature Measurement:1-1/4” coil deployed TC inside toe tubing

Downhole Pressure Measurement: Gas lift pressureand/or bubble tube banded to heel string

Look at scale of injection points

SPE 153706 J Stalder


101-07(18) Well Pair Status

• Several issues identified during CBL review with ERCB

• Remedial jobs executed:– Injector: Cement squeezes and 8-5/8” liner install. – Producer: Cement squeezes and 7” liner install.

• Current Status and Path Forward– Injector and Producer: Circulation completion is

installed and ready for operation.


58

Subsection 3.1.1 (4) Artificial Lift

59

• Gas lift will remain effective to bottomhole producer operating pressures of ~>3,000 kPa after which the wells will be required to be converted to other forms of artificial lift

• Current production rates range from 200 m3/d to 500 m3/d of emulsion targeting 3,500 kPa and 2200 injector bottomhole pressure for gas lift and ESP/PCP wells, respectively

• By end of 2012 the total Gas Lifted wells population added to 7 wells

• Total 28 wells had ESPs and PCPs installed at Phase 1 due to reservoir management strategy guidelines:

• 7 in 2010• 14 in 2011• 9 in 2012 (includes 2 infill producers)

Artificial Lift at Phase 1


Gas lift operations for high-pressure period followed by conversion to ESP or PCP for low pressure

60

• Wellpair A – ESP replaced in December 2012

• Wellpair B – ESP replaced in August 2012

• Wellpair C – Operating with hydraulic gas pump.Limited optimization due to steam limitation andinjection being 100% at the toe.

Artificial Lift at Surmont Pilot


2012 ALS Performance

• 20 failures total• 16 ESP pulls and 4 cable repairs• Average Runtime All = 9.5 months (oldest

is 29.4months)• Average Runtime failed = 9.4months• MTTF: 21.3 months


Population:• 27 Wells converted and started to

production – all ESPs• 2 Infill PCPs• 6 Wells on Gas LiftKey Decisions:• Resume ALS technology evaluation plan

with Technology Team and Global Production Engineering Team

• Selected ALS Specialist – hiring process ongoing

• Optimized 101P08 and 101P06 GLsUpdate:• Recurrent power cable failures RCA

finished• Planning ESP peer review by Q1-2013

Workover – Heel GL• 101-06(17):

– Workover done in July 2012– Heel pulled and landed at optimum depth– Currently in subcool target

• 101-08(02)– Workover done in Aug/Sept 2012– Gas Lift impairment fixed, modified and

reinstalled.– Currently in subcool target

• Provided critical information for S2 GL completion optimization

Set at 10m above liner TVD

Set at 20m above Heel TVD

101-06(17) - O il / W a te r / S te a m pe rform a nce s

0

500

1 ,000

1 ,500

2 ,000

2 ,500

16-J

un-1

2

30-J

un-1

2

14-J

ul-1

2

28-J

ul-1

2

11-A

ug-1

2

25-A

ug-1

2

8-Se

p-12

22-S

ep-1

2

6-O

ct-1

2

20-O

ct-1

2

3-N

ov-1

2

Rat

e [b

pd]

Oil [bpd] Water [bpd]

101-08(02) - O il / W a te r / S te a m pe rform a nce s

0

500

1 ,000

1 ,500

2 ,000

2 ,500

3 ,000

16-J

un-1

2

30-J

un-1

2

14-J

ul-1

2

28-J

ul-1

2

11-A

ug-1

2

25-A

ug-1

2

8-S

ep-1

2

22-S

ep-1

2

6-O

ct-1

2

20-O

ct-1

2

3-N

ov-1

2

Rat

e [b

pd]

Oil [bpd] Water [bpd]


ESP Service/Intervention


64

Artificial Lift Commercial Production


Example ESP performance curve

65



No change in 2012

66



No change in 2012

New Technology Field TrialPCP Performance

• Positive displacement pump– Improved efficiency (compared to

other ALS)• Handles wide fluid viscosity range• More cost effective for maintenance

(pump changes), especially in the lower production range wells

• The All Metal PCP, also can:– Produce fluids up to 250C– Steam into the well without removing

the production tubing– Eventual steam flashes cause lesser

impact on runlife than ESPs

Advantages of a PCP system

• Infill producers (2) Jun 2012 -Significant challenges:

– Uncertainty about well productivity

– Wide temperature, water cut and viscosity range

Field Trial Scope


New Technology Field TrialPCP Performance


400MET1000 Nominal Performance Curve

101-P21 and 101-P22 Operating at ~50% Volumetric Efficiency

New Technology Field TrialPCP Operating Conditions


101-P21 Operating Conditions: 101-P22 Operating Conditions:

Average Production: 740 bpd fluid, 205 bpd oil at 260RPM, Overall System efficiency ~30%

Average Production: 380 bpd fluid, 190 bpd oil at 140RPM, Overall System efficiency ~ 24%

70

Subsection 3.1.1 (5) Instrumentation in Wells

71

SAGD Well Instrumentation


6 Thermocouples

8 Thermocouples

3-5 Thermocouples

40 Point Fibre Optic

Newly converted wells in 2012

Well Layout on Pad 102

102-14102-16

102-09

102-15• Phase 1C wells are equipped with 40 Point fibre optic– One additional phase 1C well to be completed and equipped

• All ESP/PCPs are equipped with 40 point fibre optic– 101-03 and 101-05 are the only ESP conversions equipped with

thermocouples (first ESP completions)• Note: 102-14 and 102-16 only has 1 LxData Fiber:

– Unable to complete the guide string due to casing deformation.

72

• Example thermocouple and piezometer layout (101-07-OBA)

• Typically 30 TC (1.5 m spacing)• 2-3 piezometers placed at varying intervals


225 mASL

268.5 mASL

Prod 227 mASL

Inj 232 mASL

West of prod 21 m

30 TC

Piezo 1: 256.1 mASL

Piezo 2: 241.4 mASL

Piezo 3: 231.5 mASL

MetersMD TVDSS

350

375

400

225

250

275

0.2 2000AF900.2 2000RXOZ

0 150APIAR_GRrsc 1 0v/v decimal

AR_PHIE1 0SURM-PhieSW0 1v/v decimal

AR_VSH

AnalysisCoreSoft cable TC strings were replaced by hard cable TC strings for improved well integrity

Typical Observation Well Measurement

73

Producer Well P/T Instrumentation


Typical ESP Bottomhole Configuration


88.9mm EU 9.3ppf production string

7” slotted liner f/743m to 1,616m

1-1/4” IJ InstrumentString

1/4” Bubble Tube Coil (clamped)3/8” Instrumentation in power cable (clamped)¼” encapsulated instrumentation line for Opsens P/T sensor (clamped)

ESP – REDAHotline III

13 3/8” Conductor

P/T Senso Bottom @715m

Tail pipe thermal packer

114.3mm Hydrill tail pipe top: above liner hanger bottom @ 1,461m

All depths indicated are GRD

Temperature monitoring Instrumentation (Thermocouple/Fiber Optics inside of 1.25” Coil)5 thermocouples from 705m to 730m, equally spaced6th thermocouple @ 743m40th thermocouple @ 1,616m. Equally spaced

Liner hanger top @741m MD

ESP

• Current standard system

configuration utilizes one P/T gauge

(fiber optics) and a bubble tube

74

Instrumentation Program 2012 Summary

• Lateral instrumentation is key to ensure proper well performance monitoring and integrity (for slotted liners)

• Pressure monitoring redundancy/backup in ESP wells is needed to avoid significant production losses or unnecessary ESP pulls

• Fiber Optics Pressure gauges proven not as reliable (downtime) as 3/8” bubble tubes


No change in 2012

75

Subsection 3.1.1 (6) 4-D Seismic

• Pilot– Buried analog single component geophones– Cased dynamite shots (1/4 Kg) @ 9 m– 11th monitor acquired in September 2012

• Pad 101N– Buried analog single component geophones– Cased dynamite shots (1/8 Kg) @ 6 m– 2nd and 3rd monitor acquired in March and

September 2012• Pad 101S

– Buried analog single component geophones– Cased dynamite shots (1/8 Kg) @ 6 m– 6th monitor acquired in March 2012

• Pad 102N– Buried analog single component geophones– Cased dynamite shots (1/8 Kg) @ 6 m– 6th monitor acquired in April 2012

• Pad 102S– Buried analog single component geophones– Cased dynamite shots (1/8 Kg) @ 6 m– 4th monitor acquired in April 2012

• Pads 103 and 104– Buried analog single component geophones– Cased dynamite shots (1/8 Kg) @ 6 m– Baseline acquired in April 2012


Phase 1 Area

4D Seismic Location Map

76

101N

1998

October

SAGD Start-up

2007 2008 2009 2010

101S

102N

102S

B M

MB

B M

M

Pilot M M

M

M

M

B

March September March March

March

March September

MAugust January

JanuaryJanuaryMarch

August August

SAGD Start-up

SAGD Start-up

SAGD Start-up

SAGD Start-up

M

M

October

October

2011

MOctober

MMarch

M

M

April

April

M

2012

MMarch

MApril

MApril

MMarch

103

104

BMarch

BMarch

2013

MMarch

MApril

MApril

MOctober

October

M

P,A

P

P

P

MSept

MSept

Phase 1 4D Seismic Program

77Subsection 3.1.1 (6a)

78

4D Seismic Workflow

4D Volumetrics (Allocations)

0

100000

200000

300000

400000

500000

600000

700000

0 50000 100000 150000 200000Cum. Oil Prod. (m³)

4D V

olum

e (m

³) 101S - Sept 08

102N - Mar. 08

102N - Sept. 08

102S M1-B Jan 09

101S- Mar. 09

102N_M2-B Sept 09

102S-M2 Jan10

102N-Mar10

101S-M3-Mar10

101N-SM-M1-Mar10

102 North M4 Oct. 10

101 South M4 Oct. 10

Cross-plot of 4D anomaly volumes versus allocated SAGD oil production volumes from select Phase 1 well pairs.

TemperatureConceptual models for SAGD 4D Response

4D Observation

= 4D anomaly

Not resolved by seismic

Because of seismic resolution there are some discrepancies between the total oil produced and the volume of 4D anomalies


= 4D anomaly~60 deg C Isotherm


WP 07/08/09, without a true baseline. For the rest of Well Pairs the 4D anomaly volumes have increased. Good conformance, especially at the heel. WP 03 an ESAGD pilot

4D anomaly volumes have increased. Continued conformance improvement along WP 10, 11.

Infill wells drilled between WP 10, 11, 12. 16, 17 and 18 to optimize production in a geological more complex zone.

2012 4D Seismic Results Pad 101


2012 4D Seismic Results Pad 102


4D anomaly volumes have increased. Improve conformance along well pairs 1 to 8 (no changes in 7).

4D anomaly volumes have increased. Good conformance along well pair 12 to 18.


2012 4D Seismic Results Pilot


4D anomaly volumes have increased for WP A and B.

Poor SAGD conformance in middle of well pair “C”

Coalescence between WPB/A and C


Problem:

Well pair 101-P16 lacking good conformance along well pair

Action:

Increase pressure of steam injection at toe

Results:

Conformance improved at toe

M4-Oct/2010

M5-Apr/2011

M6-Mar/2012

Amp GR

Top Bottom Water (Thief Zone)

Seismic Examples: 101-P16 Conformance (Toe)

Seismic Examples: 102-04 OBA Baffle Breakthrough (Heel)

2009 2008

RST

2009 RST and 4D surveys confirmed recovery above mudstone

Operating pressure reduced to manage thief zone interactions

April 2012 4D survey with RST showing steam breakthrough through mudstone

M4-Oct/2010

M5-Apr/2011

M6-Apr/2012

Amp GR

Mud Abandon Channel

Mud Abandon Channel

Mud Abandon Channel

1 m baffle

1 m baffle


Pilot 4D Seismic 11th Monitor

Objectives: Top water and gas thief zone interaction.

Poor SAGD conformance in middle of well pair “C”

Coalescence between WPB/A and C




Top Bottom Water (Thief Zone) Top Bottom Water (Thief Zone)

M6-Apr/2012

85

4D Seismic Program 2012

• 4D seismic has proven very useful in monitoring and optimizing conformance and pressure strategy

• 4D correlates with observation well data• Continuing to optimize heel/toe production/injection

splits using 4D results• Ongoing efforts to history match reservoir models using

4D seismic


86

Subsection 3.1.1 (7) Scheme Performance

87

Scheme Performance

• Pilot performances impacted by TA and well workovers in 2012• Phase 1 production increase thanks to stable operations and no

turnaround in 2012• Phase 1 Reservoir Water Retention (RWR) keeps decreasing as

a result of operating pressure reductions

Pilot

Phase 1


Bitumen production Steam injection ISOR WOR RWRbbl/d bbl/d

(m3/d) (m3/d) v/v v/v %748 2,308119 367519 1,65182 262

Bitumen production Steam injection ISOR WOR RWR Water Opp. bbl/d bbl/d Recycle Efficiency

(m3/d) (m3/d) v/v v/v % % %21,673 53,6763,446 8,53424,251 59,4423,856 9,450

2012 3.18 4.44 -40%

2011 3.08 3.20 -3%

80.0%

81.6%

2.48

2.45

2.38

2.43

2011

2012

4%

1%

87%

93%

88

Scheme Performance Prediction

• Surmont Pilot instrumental in establishing SAGD performance in presence of low-pressure thief zones

• Pilot and Phase 1 data together now being used to calibrate (simulation models used in the forecasting and planning for Phase 1)

• Well pair specific forecasts rolled up to composite profile

Subsection 3.1.1 (7a,i)

Single WP Profiles

Composite Profile

-

50,000

100,000

150,000

200,000

250,000

201320

15201720

1920

21202320

2520

2720

2920

3120

3320

3520

3720

3920

4120

43204520

4720

49205120

53205520

5720

5920

6120

63

Rate

(bbl

s/da

y)

-

5

10

15

20

25

30

35

40

45

50

Wel

lpai

r Sta

rtups

Startups Bitumen RateSteam Rate Drilling Rate

Composite Profiles Plant constraints, downtime, turnovers

0 10 20 30 40 50 60 70 80 90 1000

0.005

0.01

0.015

0.02

0.025

0.03

0.035

X

PD

F

0 10 20 30 40 50 60 70 80 90 1000

0.005

0.01

0.015

0.02

0.025

0.03

0.035

X

PD

F

0 10 20 30 40 50 60 70 80 90 1000

0.005

0.01

0.015

0.02

0.025

0.03

0.035

X

PD

F

Reservoir UncertaintyProxy tool – 2DProbability Uncertainty Modeling Application•Modified Butler’s theory•Analogues – Pilot Performance•Declination curve analysis•Heat balance for CSOR

Numerical Simulation

Forecasting Tools

No changes in 2012

Plant performance

0

100

200

300

400

500

600

700

800

Jan-

97

Jan-

98

Jan-

99

Jan-

00

Jan-

01

Jan-

02

Jan-

03

Jan-

04

Jan-

05

Jan-

06

Jan-

07

Jan-

08

Jan-

09

Jan-

10

Jan-

11

Jan-

12

Jan-

13

Time (years)

Rat

e (m

3/d)

0.00

1.00

2.00

3.00

4.00

5.00

6.00

7.00

8.00

SOR

(m3/

m3)

Oil ProductionSteam InjectionWater ProductioncSOR

89

Pilot Performance History

Subsection 3.1.1 (7a,ii)

Moderate performance in 2012 due to a turn around and extended well work-overs

Data through Dec 31, 2012:Plant cSOR: 3.46Plant cWSR: 0.98Well Count: 32012 avg. iSOR = 3.18

A Wellpair

0

50

100

150

200

250

300

350

400

Jan-97 Jan-98 Jan-99 Jan-00 Jan-01 Jan-02 Jan-03 Jan-04 Jan-05 Jan-06 Jan-07 Jan-08 Jan-09 Jan-10 Jan-11 Jan-12 Jan-13

Time (years)

Rat

e (m

3/d)

0.00

1.00

2.00

3.00

4.00

5.00

6.00

7.00

8.00

SOR


B Wellpair

0

50

100

150

200

250

300

350

400

450

Jan-97 Jan-98 Jan-99 Jan-00 Jan-01 Jan-02 Jan-03 Jan-04 Jan-05 Jan-06 Jan-07 Jan-08 Jan-09 Jan-10 Jan-11 Jan-12 Jan-13

Time (years)

Rate (m

3/d)

0.00

1.00

2.00

3.00

4.00

5.00

6.00

7.00

8.00

SOR


C Wellpair

0

50

100

150

200

250

300

350

400

Jan-00 Dec-00 Dec-01 Dec-02 Jan-04 Dec-04 Dec-05 Dec-06 Jan-08 Dec-08 Dec-09 Dec-10 Jan-12 Dec-12

Time (years)

Rate (m

3/d)

0.00

1.00

2.00

3.00

4.00

5.00

6.00

7.00

8.00

SOR


90

Pilot Performance History


Data through Jan. 31, 2012• Wellpair A cSOR = 3.14• Wellpair A cWSR = 1.08• Recovery Factor: 36.6%

• Wellpair B cSOR = 3.25• Wellpair B cWSR = 1.03• Recovery Factor: 44.3%

• Wellpair C cSOR = 4.83• Wellpair C cWSR = 0.73• Recovery Factor: 7.7%

Maps were updated in 2012 and yielded greater OOIP values

Pilot Production Capacity

Deviation from capacity due to:• BFW pump limitation• P3 liner damage preventing steam injection / production• 2012 turnaround – and data spikes due to emptying treaters

– Multiple complications with new control system post turn around• Extended outage for P2 due complications during SCV install after ESP failure and replacement (June -

Aug)• Extended outage for P1 due to rig availability (November & December)Subsection 3.1.1 (7a,iii) 91

S urm ont T herm al P ilo t Actua ls vs . C apac ities

-

50

100

150

200

250

300

350

400

450

500

Jan-12 Fe b-12 M ar-12 Apr-12 M ay-12 Jun-12 Jul-12 Aug-12 Se p-12 O ct-12 N ov -12 D e c-12 Jan-13

Stea

m (m

3/d

CW

E), B

itum

en (m

3/d)

Rat

es

S team To W ells S team C apacity B itum en B itum en C apacity

200 m3/d

432 m3/d

92

Well Status

Status on January 31, 2013

• Pilot: – 3 well pairs on SAGD

• Phase 1:– 35 well pairs on SAGD– 2 Infill producers online– 1 well pair in eSAGD– 2 Cold well pairs

• Infill drilling– 2012: 2 infill well pairs and 2 infill producers

drilled– 2013: New infill drilling campaign

• Planning underway for first sustaining pad drainage areas and more Phase 1 infill wellpairs

• No expected pad abandonments in 5 year outlook


Continuing to bring wells online

3

3

3

3

3

3

Delineation WellsGOB Monitoring WellsObservation Wellsin SAGDUnder SAGD conversionNGL steam co-injectionCold

Pad 101

Pad 102

Pilot

Phase 1 - P lant perform ance

0

2,000

4,000

6,000

8,000

10,000

12,000

Jul-0

7

Oct

-07

Jan-

08

Apr-0

8

Jul-0

8

Oct

-08

Jan-

09

Apr-0

9

Jul-0

9

Oct

-09

Jan-

10

Apr-1

0

Jul-1

0

Oct

-10

Jan-

11

Apr-1

1

Jul-1

1

Oct

-11

Jan-

12

Apr-1

2

Jul-1

2

Oct

-12

Jan-

13

Rat

e (m

3/d)

0

0.5

1

1.5

2

2.5

3

3.5

4

4.5

5

SOR

(v/v

), #

Wel

l pai

rs s

tarte

d / 1

0

Bitum e n production S te a m in je ction W a te r production CS OR IS OR # W e ll pa ir sta rte d

93

Phase 1 Performance History


Plant CSOR 2.65

Plant CWSR 0.93# Well pairs started (incl. infill producers) 38

2012 iSOR avg. (v/v) 2.45

Data through January 31, 2013

• Good performances due to stable operations and well availability• Stable ISOR for the past 3 years around 2.5

Phase 1 Production Capacity

Deviation from capacity due to:• Steam generator pigging every 2 months and other maintenance• Exchanger E502 maintenance in December 2012• Planned / Unplanned power outages• Wells availability:

– 8 ESP conversions + 20 ESP Failures– 5 SAGD conversions– Workover for heel gas lift relocation

10445 m3/d

4290 m3/d

Subsection 3.1.1 (7a,iii) 94

P hase 1 - M onth ly P roduction / In jec tion

0

2,000

4,000

6,000

8,000

10,000

12,000

Jan-

12

Feb-

12

Mar

-12

Apr

-12

May

-12

Jun-

12

Jul-1

2

Aug

-12

Sep-

12

Oct

-12

Nov

-12

Dec

-12

Jan-

13

Feb-

13

Rat

e (m

3/d)

B itumen S team B itumen capacity S team capacity OTS G maintenance

May-98 Mar-99 Dec-99 Sep-00 Jun-01 Apr-02 Jan-03 Oct-03 Jul-04 May-05 Feb-06 Nov-06 Aug-07 May-08 Mar-09 Dec-09 Sep-10 Jun-11 Apr-12 Jan-13

276273270267264261257254251248245242239236233230227224221217

225-250 200-225 175-200 150-175 125-150 100-125 75-100 50-75 25-50 0-25

95

Pilot Wellpair A: OBS36 (Mid)


MetersMD TVDSS

325

350

375

400

200

225

250

275

0.2 2000N-RD0.2 2000N-RS


AR_PHIE1 0SURM-PhieSW0 1v/v decimalAR_VSH

AnalysisCore

OBS36 A well pair (mid)

Piezo 1: 287 mASL

Piezo 2: 265 mASL

Piezo 3: 247 mASL

Piezo 4: 227 mASL

276 mASLTC

Prod depth 216 mASL

Inj depth 222 mASL

Offset : X m

TZPF = 2.5 m

TZPF = 2.5 m

MetersMD TVDSS

325

350

375

400

200

225

250

275

0.2 2000N-RD0.2 2000N-RS



AnalysisCore


Piezo 1: 287 mASL

Piezo 2: 265 mASL

Piezo 3: 247 mASL

Piezo 4: 227 mASL

276 mASLTC

Prod depth 216 mASL

Inj depth 222 mASL

Offset : X m

MetersMD TVDSS

325

350

375

400

200

225

250

275

0.2 2000N-RD0.2 2000N-RS



AnalysisCore


Piezo 1: 287 mASL

Piezo 2: 265 mASL

Piezo 3: 247 mASL

Piezo 4: 227 mASL

276 mASLTC

Prod depth 216 mASL

Inj depth 222 mASL

Offset : X m

TZPF = 2.5 m

TZPF = 2.5 m

OBS 36: Heat keeps progressing above breccia

96

Pilot Chamber and Thief Zone Pressures .


• Operated at 1600 kPa for 4-5 years with significant surface area of contact of chamber with thief zone

• Saturated steam temperatures observed in thief zone at OBS22 since 2009• Gas pressure zones still 500kPa below steam chamber pressure

Pilot A&B well pair chamber vs. Thief Zone Pressures

500

1000

1500

2000

2500

3000

3500

4000

Jan-98 Jan-00 Jan-02 Jan-04 Jan-06 Jan-08 Jan-10 Jan-12

Pres

sure

(kPa

)

OBS24 Channel Gas ZoneOBS36 Marine Gas ZoneA Well BHFPB Well BHFP OBS25 Top Water

97

Top Gas Monitoring

• OBS23– Tested 2 samples in early 2010 from McMR Gas Cap– Lab gas chromatography with thermal conductivity detector (TCD GC)

indicated H2S conc. ~ 1.09% and 0.28% – Well currently abandoned due to well integrity issues

• OBS41– Onsite field test on 6 samples in 2011 and 2 samples in 2012 – H2S con. measured (highest values): 0.61% (2011) and 0.42% (2012)– Considered representative sample and closest analog for Pad 101

• H2S Surveillance & Monitoring Plans (S1 Pads)– Conduct periodic field and gas chromatograph test on SCVG (ensure

standard test procedure)– Continue to reinforce safety measures on site in case of unexpected

release: ensure designated Muster Points allow for upwind/crosswind evacuation in the event of a release.


98

Piezos in:Bitumen

Top water

Bitumen and top water

Top gas

Top gas, bitumen and top water

E-SAGD observation wells with 10 piezometers per well monitoring:

- bitumen zones- high water saturation zones- thief zone (water / gas)- cap rock

No piezometer installed

Reservoir Monitoring

Thermocouple string installed

Horizontal observation well with fiber optic

No temperature monitoring

Temperature Measurement Pressure Measurement(as planned after hard cable TC string installation)


No changes in 2012

Pad 101

Pilot

Steam Chamber Development


• Well pair 101-03 (Pad 101 North)– Start-up in Feb 2011

Delineation WellsGOB Monitoring WellsObservation Wellsin SAGD

101-03 Well Pair

101-03 OBC Obs well

101-03 OBC Obs well

Steam Chamber DevelopmentWell Pair 101-03


• Temperature monitoring

101-I03

101-P03

101-03 OBB 101-03 OBC

Steam Chamber DevelopmentWell pair 101-03


• 4D seismic monitoring

101-03

Mc Murray

101-03-OBC101-03-OBB


• Pressure Monitoring– Lower piezometers follow exactly 101-I03 BHP injection trend– Pressure response ahead of the temperature front – Most likely through mobile initial

water

101-03 O B B P ressu re

0

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

4,500

5,000

M ar-11 M ay-11 Ju l-11 Se p -11 No v -11 Jan -12 M ar-12 M ay-12 Ju l-12 Se p -12 No v -12

Pres

sure

[kPa

]

P1 - 23 7 .58 m ASLP2 - 24 2 .04 m ASLP3 - 24 6 .13 m ASLP4 - 25 2 .18 m ASLP5 - 25 6 .65 m ASLP6 - 26 6 .94 m ASLP7 - 27 2 .41 m ASLP8 - 28 4 .04 m ASLP9 - 29 3 .05 m ASLP10 - 3 22 .04 m ASL101-I03 - Injec tion BHP

Pressure response in cold area

Steam Chamber DevelopmentWell pair 101-03

103

OBIP and Recovery Factor

Subsection 3.1.1 (7c,i)

No change in 2012

NCB = producer to Vsh cutoff of 33%

Average porosity = 33%

Average So = 80%

OBIP = bulk volume x Φ x So

125 m

40 m

Minimized resource below producer

104

Recovery Factor vs Thief Zone Type

Top GasTop Water

Top Cont Bitumen

1 = No thief zone, highest recovery, 45%+

2 = Limited thief zone, medium recovery, 40%+

3 = Thief zone, lowest recovery, 30%+

Type 2 Type 1 Type 1Type 3

Pri = 1400-1800 kpa

Pri = 1000-1200 kpa

* Recoveries based on simulations and in-house proxy tool

Mud

Continuous Bitumen

Subsection 3.1.1 (7c,i)

No change in 2012

105

Pilot

Pad 101

Pad 102

Pilot and Phase 1 Polygons

OBIP = Thickness x Phi x So x AreaThickness = Calculated from the top of continuous bitumen to the producer depthArea = Polygons around each well pair of 125 m x length of lateral section

• Expected ultimate recovery dependent on blow down timing and operating strategy

OBIP and Recovery Factor Jan 31, 2013

Subsection 3.1.1 (7c,ii)

OBIP Avg Phi Avg So Expected Rf Cum Prod Current Rf(e3m3) % % % (e3m3) %

101N 7,856 32.8% 81.8% 45% 770 9.8%101S 8,853 33.6% 83.0% 45% 1,479 16.7%102N 7,058 33.1% 81.6% 45% 1,321 18.7%102S 7,296 31.7% 73.5% 45% 1,915 26.3%Pilot A 615 32.6% 82.2% 45% 225 36.6%Pilot B 592 32.5% 82.8% 55% 263 44.5%Pilot C 1,183 33.6% 85.8% N/A 91 7.7%Pilot A&B 1,207 32.6% 82.5% 50% 488 40.4%

Drainage area

106


Subsection 3.1.1 (7c,iii)

• Low recovery pad example – Pad 101 North– 9 well pairs drilled– Low recovery essentially due to late start-up:

• 3 well pairs started in 2007• 6 well pairs started end 2010 / beginning 2011

P ad 101 North p erform ance

0

500

1,000

1,500

2,000

2,500

3,000

3,500

Jul-0

7

Oct

-07

Jan-

08

Apr-0

8

Jul-0

8

Oct

-08

Jan-

09

Apr-0

9

Jul-0

9

Oct

-09

Jan-

10

Apr-1

0

Jul-1

0

Oct

-10

Jan-

11

Apr-1

1

Jul-1

1

Oct

-11

Jan-

12

Apr-1

2

Jul-1

2

Oct

-12

Jan-

13

Rat

e (m

3/d)

0

1

2

3

4

5

6

7

8

9

10

SOR

(v/v

), #

Act

ive

wel

l pai

rs /

10

B itum e n production S te a m in je ction W a te r production CS OR IS OR # Active w e ll pa irs

107



• Low recovery pad example – Pad 101 North– 4D seismic monitoring– Low recovery to date but still in the early time– Fairly good steam chamber development despite recent start-up

Well pairs started in 2011

108



• High recovery pad example – Pad 102 South– 9 well pairs drilled– High performance despite two well pairs have been converted to SAGD in 2012 only

(102-10 and 102-11)

P ad 102 S outh perfo rm ance

0

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

Jul-0

7

Oct

-07

Jan-

08

Apr

-08

Jul-0

8

Oct

-08

Jan-

09

Apr

-09

Jul-0

9

Oct

-09

Jan-

10

Apr

-10

Jul-1

0

Oct

-10

Jan-

11

Apr

-11

Jul-1

1

Oct

-11

Jan-

12

Apr

-12

Jul-1

2

Oct

-12

Jan-

13

Rat

e (m

3/d)

0

1

2

3

4

5

6

7

8

9

10

SOR

(v/v

), #

Act

ive

wel

l pai

rs /

10

B itum e n production S te a m in je ction W a te r production CS OR IS OR # W e ll pa irs sta rte d

109



• High recovery pad example – Pad 102 South– 4D seismic monitoring – March 2012 monitor– Good steam chamber development over mature wells

Well pairs converted into

SAGD in 2012 –102-10 & 102-11

110

All mature steam chambers have been depleted to

2,400 – 2,500 kPaLatest available Phase 1 4D ~60°C isocontours


• Pad 101 North

ESP / PCP Converted

To be converted to ESP in 2013→

Top Steam Chamber Monitoring 4D Isocontours

111Latest available Phase 1 4D ~60°C isocontours



2,000 – 2,500 kPa

• Pad 101 South

ESP / PCP Converted



112

Latest available Phase 1 4D ~60°C isocontours



2,400 – 2,500 kPa

• Pad 102 North

ESP / PCP Converted



113




2,400 – 2,500 kPa

• Pad 102 South

ESP / PCP Converted



114



Pilot operating pressure decreased at 1600kPa for

the last 4 years.

• Pilot


2,000

2,500

3,000

3,500

4,000

4,500

5,000

Jul-0

7

Oct

-07

Jan-

08

Apr

-08

Jul-0

8

Oct

-08

Jan-

09

Apr

-09

Jul-0

9

Oct

-09

Jan-

10

Apr

-10

Jul-1

0

Oct

-10

Jan-

11

Apr

-11

Jul-1

1

Oct

-11

Jan-

12

Apr

-12

Jul-1

2

Oct

-12

Jan-

13

101 N orth101 South102 N orth102 South

Average B ottom H ole In jection P ressure (kP a)

Phase 1: Operating Pressure


• Operating pressure– Operating pressure progressively decreased to manage interaction with top

reservoir / thief zones– Well pairs converted to ESP to operate at lower pressure– 101 North at higher pressure because of recent well pairs start-up

1st ESP conversion

115

Phase 1: Pad 101 Top Abandoned Mud Channel


• Pad 101: Abandoned mud channel overlaying bitumen intervalA B

Abandoned mud channel

AB

116

Phase 1: Pad 101 North Top Water


• Top water: Extension of pilot top water above Pad 101 north but limited

117

• Top water: Extension of pilot top water above Pad 101 north but limited


Subsection 3.1.1 (7g) 118


• Pad 101 North - Top water: • Development of the steam chamber towards top of reservoir

119





• Pad 101 North - Top water:

• Operating pressure decreased to manage interaction with top water and coalescence between well pairs

• Well performances not impaired by top water

Pad 101 North - 101-06 /07 /08 /09

0

200

400

600

800

1,000

1,200

1,400

1,600

1,800

Jul-0

7

Oct

-07

Jan-

08

Apr-0

8

Jul-0

8

Oct

-08

Jan-

09

Apr-0

9

Jul-0

9

Oct

-09

Jan-

10

Apr-1

0

Jul-1

0

Oct

-10

Jan-

11

Apr-1

1

Jul-1

1

Oct

-11

Jan-

12

Apr-1

2

Jul-1

2

Oct

-12

Jan-

13

Rat

e (m

3/d)

0

1

2

3

4

5

6

7

8

SOR

(v/v

), #

Wel

l pai

rs s

tarte

d / 1

0

B itum e n production S te a m inje ction W a te r production CS OR IS OR # Active W e ll pa irs

P ad 101 North - 101-06 /07 /08 /09

1,500

2,000

2,500

3,000

3,500

4,000

4,500

5,000

Jul-0

7

Oct

-07

Jan-

08

Apr

-08

Jul-0

8

Oct

-08

Jan-

09

Apr

-09

Jul-0

9

Oct

-09

Jan-

10

Apr

-10

Jul-1

0

Oct

-10

Jan-

11

Apr

-11

Jul-1

1

Oct

-11

Jan-

12

Apr

-12

Jul-1

2

Oct

-12

Jan-

13

BH

P In

ject

ion

(kPa

)

101-P 06 101-P 07 101-P 08 101-P 09

Flush production after 07/08/09 ESP

conversion

101-06 ESP conversion after steam chamber

coalescence

120

Subsection 3.1.1 (7g) 121M4 Oct 2010 M6 April 2012

Base Top Water

• Pad 101 South - Top abandoned mud channel: • Development of the steam chamber towards top of reservoir

Phase 1: Pad 101 South Top Abandoned Mud Channel


P ad 101 S ou th - 101-10 /11 /12 /13 /14

0

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

4,500

5,000

Jul-0

7

Oct

-07

Jan-

08

Apr-0

8

Jul-0

8

Oct

-08

Jan-

09

Apr-0

9

Jul-0

9

Oct

-09

Jan-

10

Apr-1

0

Jul-1

0

Oct

-10

Jan-

11

Apr-1

1

Jul-1

1

Oct

-11

Jan-

12

Apr-1

2

Jul-1

2

Oct

-12

Jan-

13

BH

P In

ject

ion

(kPa

)

101-P 10 101-P 11 101-P 12 101-P 13 101-P 14

Phase 1: Pad 101 SouthTop Abandoned Mud Channel


• Pad 101 South (101-10/11/12/13/14) - Performances

• June 2009: 101-12 steam chamber development up to the top reservoir. WP shut down.

• 101-12/13/14: ESP conversion on Aug/Sept 2010. Operating pressure decreased to manage interaction with top reservoir

• Stable performances since after ESP conversion.

101-12: Quick vertical development of steam

chamber – WP shut down101-12/13/14: ESP

conversion – Operating pressure decreased

101-10/11: ESP conversion – Operating pressure

decreased

P ad 101 S outh - 101-10 /11 /12 /13 /14 /21 /22

0

500

1,000

1,500

2,000

2,500

3,000

Jul-0

7

Oct

-07

Jan-

08

Apr-0

8

Jul-0

8

Oct

-08

Jan-

09

Apr-0

9

Jul-0

9

Oct

-09

Jan-

10

Apr-1

0

Jul-1

0

Oct

-10

Jan-

11

Apr-1

1

Jul-1

1

Oct

-11

Jan-

12

Apr-1

2

Jul-1

2

Oct

-12

Jan-

13

Rat

e (m

3/d)

0

1

2

3

4

5

6

7

8

SOR

(v/v

), #

Wel

l pai

rs s

tarte

d / 1

0

B itum e n production S te a m in je ction W a te r production CS OR IS OR # Active W e ll pa irs

122

Phase 1: Pad 101 SouthInfill Producer Performance


• Infill producers 101-P21 and 101-P22• Drilled in 2012• Open-hole hook in P21 and cased-hole hook in P22• Completed with PCP and started in Sept 2012• Both wells produce about 30-45m3/d bitumen

In fill p rodu cers perform ances

0

100

200

300

400

500

600

Jan-

12

Feb-

12

Mar

-12

Apr-1

2

May

-12

Jun-

12

Jul-1

2

Aug-

12

Sep-

12

Oct

-12

Nov-

12

Dec-

12

Jan-

13

Bitu

men

rate

(m3/

d)

0

1

2

3

4

5

6

7

ISO

R (v

/v)

W e ll pa irs 101-01 & 101-02 Infill produce rs 101-P 21 & 101-P 22 IS OR

21

13

2017

1916

15

14

13

12

2211

108

07

03

0405

06

0201

2

1615

1413

1718

2019

22

21

18

21

13

2017

1916

15

14

13

12

2211

108

07

03

0405

06

0201

2

1615

1413

1718

2019

22

21

21

13

2017

1916

15

14

13

12

2211

108

07

03

0405

06

0201

2

1615

1413

1718

2019

22

21

21

13

2017

1916

15

14

13

12

2211

108

07

03

0405

06

0201

2

1615

1413

1718

2019

2019

22

21

22

21

18

Pad 101 South

21

13

2017

1916

15

14

13

12

2211

108

07

03

0405

06

0201

2

1615

1413

1718

2019

22

21

18

21

13

2017

1916

15

14

13

12

2211

108

07

03

0405

06

0201

2

1615

1413

1718

2019

22

21

21

13

2017

1916

15

14

13

12

2211

108

07

03

0405

06

0201

2

1615

1413

1718

2019

22

21

21

13

2017

1916

15

14

13

12

2211

108

07

03

0405

06

0201

2

1615

1413

1718

2019

2019

22

21

22

21

18

Pad 101 South

Sept 2012: Infill producers start-up

123

Oil production reduced for plant

curtailment

124

• Record well performances in 2012.

• Thief zone impact on scheme performance have been very limited so far. Progressive decrease of operating pressure enabled to minimize interaction with thief zones and to operate at stable SOR. This has been observed on Pilot and S1 (Pad 101 North especially).

• 4D seismic has been a key input for reservoir management:– To anticipate operating pressure decrease based on distance of the steam chamber

to the thief zone. Needed for ESP conversion plan.– To refine steam allocation toe / heel– To identify infill drilling opportunities

• Pilot and Phase 1 performances are continuously used to calibrate geological and reservoir models for production forecasts.

Key Reservoir and Operational Learnings Summary


Subcool Monitoring

Subsection 3.1.1 (7,g)

• Subcool monitored in SAGD producer to avoid steam flashing through the liner and preserved its integrity

• Wellbore subcool:• Saturated temperature at producer BHP – Hottest Temperature in Prod• Used in ESP / PCP wells• Target is 8°C

• Reservoir subcool:• Saturated temperature at injector BHP – Hottest Temperature in Prod• Used in Gas Lift wells• Target is increased to 20°C to take into account uncertain ∆P between the injector and

the producer

125

Zero Sub-Cool Live steam produced

High Sub-Cool Loosing potential head &

steam distribution

Optimum Sub-CoolInterface as low as possiblewithout producing steam

Phase 1: Pad 101 North Performance

126Subsection 3.1.1 (7h)

101-

01 c

ircul

atio

n

101-

02 h

eel G

L re

loca

tion

101-

04 E

SP c

onv.

101-

06 E

SP c

onv.

101-

07 E

SP re

pair

101-

08 E

SP re

pair

101-

08 E

SP re

pair

OTS

G m

aint

enan

ce

0

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

4,500

Jan-

12

Feb-

12

Mar

-12

Apr

-12

May

-12

Jun-

12

Jul-1

2

Aug

-12

Sep-

12

Oct

-12

Nov

-12

Dec

-12

Jan-

13

Feb-

13

Rat

e (m

3/d)

-

2

4

6

8

10

12

SOR

(v/v

), #

Wel

l pai

rs s

tart

ed

B itumen production S team injection W ater production C S OR IS OR # W ell pair started

Imbalance between pads is affected by water-cut calibration

Phase 1: Pad 101 South Performance


101-

10 E

SP re

pair

101-

10 E

SP re

pair

101-

11 S

I -

Low

sub

cool

101-

11 E

SP R

epai

r

101-

13 E

SP re

pair

101-

14 E

SP re

pair

101-

17 H

eel G

L re

loca

tion

OTS

G m

aint

enan

ce

101-

17 c

ircul

atio

n

101-

17 E

SP c

onv.

101-

19 c

ircul

atio

n

0

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

4,500

Jan-

12

Feb-

12

Mar

-12

Apr

-12

May

-12

Jun-

12

Jul-1

2

Aug

-12

Sep-

12

Oct

-12

Nov

-12

Dec

-12

Jan-

13

Feb-

13

Rat

e (m

3/d)

0

2

4

6

8

10

12

SOR

(v/v

), #

Wel

l pai

rs s

tart

ed



Phase 1: Pad 102 North Performance


102-

02 E

SP re

pair

102-

02 E

SP re

pair

102-

02 E

SP re

pair

102-

05 E

SP re

pair

102-

05 E

SP re

pair

102-

06 E

SP re

pair

102-

09 E

SP c

onv.

OTS

G m

aint

enan

ce

0

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

4,500

Jan-

12

Feb-

12

Mar

-12

Apr

-12

May

-12

Jun-

12

Jul-1

2

Aug

-12

Sep-

12

Oct

-12

Nov

-12

Dec

-12

Jan-

13

Feb-

13

Rat

e (m

3/d)

0

2

4

6

8

10

12

SOR

(v/v

), #

Wel

l pai

rs s

tart

ed

B itumen production S team injection W ater production C S OR IS OR # W ell pa ir started


Phase 1: Pad 102 SouthPerformance


102-

10 c

ircul

atio

n

102-

11 c

ircul

atio

n

102-

11 E

SP c

onve

rsio

n

102-

12 E

SP re

pair

102-

13 E

SP re

pair

OTS

G m

aint

enan

ce

102-

14 E

SP c

onv.

102-

15 E

SP c

onv.

102-

15 E

SP re

pair

102-

16 E

SP c

onv.

102-

18 E

SP re

pair

0

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

4,500

5,000

Jan-

12

Feb-

12

Mar

-12

Apr

-12

May

-12

Jun-

12

Jul-1

2

Aug

-12

Sep-

12

Oct

-12

Nov

-12

Dec

-12

Jan-

13

Feb-

13

Rat

e (m

3/d)

0

2

4

6

8

10

12

SOR

(v/v

), #

Wel

l pai

rs s

tarte

d



Pad Performance Proration

• Pad production plots were affected by issues with the proration factor in 2012• The oil production from May - October on 101N was arbitrarily low due to overestimations in oil at

pad 102 South. • The field was corrected to this throwing off the Oil production and SOR values (SOR at Pad 102

less than 1.0 for April and May 2012).

• The effect on the field measured SOR was caused by the water cut analyzer calibrations performed in pads 101 and 102.

• These calibrations affected subsequent well tests and secondary calibration targets improved water cut on some of the large and small error wells.

11.5

22.5

3

3.54

4.55

Jul-0

7

Oct

-07

Jan-

08

Apr

-08

Jul-0

8

Oct

-08

Jan-

09

Apr

-09

Jul-0

9

Oct

-09

Jan-

10

Apr

-10

Jul-1

0

Oct

-10

Jan-

11

Apr

-11

Jul-1

1

Oct

-11

Jan-

12

Apr

-12

Jul-1

2

Oct

-12

Jan-

13

iSO R T otaliSO R Pad 101iSO R Pad 102

iS OR

May 2012 Sept 2012


131

Subsection 3.1.1 (8) Future Plans

132


• Continued research into OTSG fouling and OTSG runtime improvements based on reduced MP blowdown recycle field trial and other studies

• Evaluation of GT-OTSG; collect/analyze data• Validate performance of lateral hook on two infill producers in Pad 101 South• Operate eSAGD Pilot with solvent injection commencing in Jan. 2013 • CPF Debottleneck including one OTSG addition • Pad 101 infill program: received approval in Jan. 2013. Rig is scheduled to

commence drilling in April 2013. • The alternative start-ups on Pad 101, the solvent soak and dilation, were

recently applied for in this Month. Current plans are to conduct these tests in 3Q 2013.

• Pad 102 infill program application was issued in November 2012. The current timeline is that we would spud on Pad 102 in June, 2013

• Engineering for Partial Condensate usage for S1 and S2• Automation of EB/REB Chemical Injection• Heat integration improvement on diluent injection


Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4

Milestones

Drilling & Completions

Engineering

Procurement & Fabrication

Construction

2013 2014 20152010 2011 2012

Rig Procure / Construct Drilling and Completions

Detailed Engineering

Procurement and Fabrication

Site Preparation Construction

90% Complete

AFEDec 2009 1st Oil

Commissioning Start

1st Steam

• Continued focus on achieving world class safety and environmental performance

• Drilling complete on first pad • Drilling started on next 2 pads• Completions started on first pad• Engineering is 96% complete• Central Processing Facility

Construction 27% complete• Phased commissioning strategy



133

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