Cold Lake Approvals 8558 and 4510 2012 Annual Performance ...

1

Cold Lake Approvals 8558 and 4510 2012 Annual Performance Review

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................l 8558 Coml 4510 Comisposal andPerformancBalances bumen in ShFact Sheet

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ober 1st

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CLO C

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CI C

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GW G

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OV O

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STC S

ST S

SAGD S

SCVF S

TVD T

Definition

Benzene Tolu

Bitumen In Sh

Bottom Hole L

Buttress Thre

Clearwater (T

Cold Lake Op

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(High Pressur

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5

Cold Lake AnnualPerformance Review

2012

6

Development History

60’s-70’s Lease acquisitionSmall scale research pilots

1975 10 kbd commercial pilot

‘85-‘94 Phase 1-10 - Maskwa- Mahihkan

2002 Phase 11-13 Mahkeses- Cogeneration facility

2004 Approval area expanded- Nabiye, Mahihkan North

H62

H69

H65

H68

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T65

T66

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0 2.5 5

Approved

Development Area

T18

V13

Developed Pads - 2012

Background


2012

7

Wells required

Well type

Steam pressure

One

Deviated or horizontal

Above fracture pressure

• High pressure, high rate with multiple recovery mechanisms

• compaction drive

• solution gas drive

• gravity drainage

• Steam heats bitumen to allow flow (4 - 6 weeks)

• Soak (several weeks) allows heat to contact more bitumen

• Production period lengths increase from few months in early cycles to two years in last cycles

• Full Well life; 8 -17 cycles and up to 50 years including follow-up processes

CSS Process Overview


2012

8

0

1000

2000

3000

4000

0 2 4 6 8 10 12 14 16

Year

Flu

id R

ate

(m3/

d)

Steam

Water Bitumen

Injection/Production Rates for a Typical 4 Acre Cold Lake pad

CSS Process Overview


2012

9

Heated Channel Heated Channel

Cold Bit Cold Bit

Residual Oil Residual Oil

Horz. Infill Well Horz. Infill Well

POW POW POW

DrainageDrainageDrainage

Drainage

Heated Channel Heated Channel

Cold Bit Cold Bit

Residual Oil Residual Oil

Horz. Infill Well Horz. Infill Well

POW POW POW

DrainageDrainageDrainage

Drainage

Water

Bitumen

Cyclic Production

Cyclic Steam Injection

Time

Rat

e

Water

Bitumen

Cyclic Production

Cyclic Steam Injection

Time

Rat

e

Water

Bitumen

Continuous Steam Injection into Dedicated Wells

Continuous Production from Dedicated Wells

Time

Time

Ra

teR

ate

Water

Bitumen

Continuous Steam Injection into Dedicated Wells

Continuous Production from Dedicated Wells

Time

Time

Ra

teR

ate

Continuous Process

Cyclic Process

Steamflood Process Overview

• Continuous steam injection, at low rates has the potential to:

• Lower operating costs

• Improve well operability

• Reduced casing stress

• Target reservoir pressure between 0.5 to 1.5 MPa

• Continuous rather than cyclical steam injection through dedicated injection-only and production-only wells


2012

10

Pad Design

4 Acre Spacing Downhole well

locations

• Wells drilled directionally from central lease location

• Reduced environmental disturbance

• Improved development economics

• Increased operational efficiencies

• Original pad design 20 wells on 4 acre spacing

• Current pad designs

• Up to 35 wells on 4 or 8 acre spacing

• Mix of deviated and horizontal wells

Original Pad Design

Mega PadSubsurface area of original Cold Lake Pad design

Horizontal wells

Deviated wells

8 Acre Spacing


2012

Geoscience Overview


2012

Reservoir and Fluid Properties

Depth Clearwater @ 400MDepositional Facies Incised Valley Fill, Tidal / EstuarineSands Unconsolidated, reactive, clay clastsDiagenetic Cements Mixed-layer claysBitumen API Gravity 10.2Bitumen Viscosity 100,000 cp @ 13 C

8 cp @ 200C

Bitumen Saturation Average 70%

Range AveragePorosity 27 - 35% 32%Permeability 1 - 4 Darcies 1.5 DarciesBitumen Wt % 6 - 14% 10.5%Total Net Pay 0 - 60m 30m

CALCULATION METHOD

OBIP = A * H * V A = area (m2)H = Net pay (m)V = Volumetric Factor = W * (2.64 – (1.64 * P))

W = Saturation (avg Wt %)P = avg Porosity

Average Reservoir Properties and OBIP

Original-Bitumen-in-Place (OBIP)Clearwater Fm 8 Wt % 6 Wt %

(E6m3) (MBO) (E6M3) (MBO)

Entire Approval Area 2,250 14,150 2,609 16,410Operating Portion1 1,888 11,875 2,185 13,740

1 Volume of main approved development area (i.e. excluding Nabiye)

12


2012

13

Representative Type Log

Grand Rapids Fm

top Clearwater reservoir

Wabiskaw MbrMcMurray Fm

Shale

Bitumen Sand

Water Sand

Gas Sand

Carbonate

Schematic Cross-section through Clearwater Formation

3-10-66-4W4

Gra

nd R

apid

s F

m.

Cle

arw

ater

Fm

.M

cMur

ray

Fm

.

SW NE

Idealized SW-NE section across CL field

• Type well log through the Mannville Group, (Albian) of Cold Lake field, Alberta

• Primary reservoir is the Clearwater Fm, secondary targets comprise the Grand Rapids and McMurray formations

• The Clearwater Fm is comprised of at least 10 stacked incised valleys which form a complex reservoir architecture

• Development to date has focused on the Clearwater in the central axis of the valley complex

Clearwater

SPGR

Resistivity

SonicDensity

Neutron


2012

14

Top Bitumen Pay Structure C.I.=10m tvdss

PROPERTY OF IMPERIAL OIL LIMITED

Mapped Surface

• Top of bitumen pay is a smoothly varying surface which gently dips from a high of 220m above sea level (A.S.L.) in the NW to a low of 136m A.S.L. in the SE

• Top of bitumen structure varies more greatly in the Nabiye area

• Mapped surface is either a rock/bitumen or a gas/bitumen contact


2012

15

Base Bitumen Pay Structure C.I.=10m tvdss

PROPERTY OF IMPERIAL OIL LIMITEDCurrent to October 2009

• Map represents amalgamated incised valley fills associated with low-stand erosional events

• Different valley fills, depending on depositional environment are filled with varying amounts of sand and shale.

• Mapped surface is either a bitumen/rock, a bitumen/water transition zone or a bitumen/water contact

ClearwaterMapped Surface


2012

16

Isopach of Net Bitumen Pay (> 8 wt %) C.I=10m

• Map illustrates distribution of pay above 8 wt% saturation cut off

• Thin pay and pay immediately adjacent to water included in isopach calculation

• Thickness trend is consistent with orientation of main valley incision

PROPERTY OF IMPERIAL OIL LIMITED YE 2008

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43.5

24.633.4

35.629.6

21.9

26.5

30.3

30.2

31.131.8

29.532.9

42.1

43.240.7

40.4

33.8

36.2

39.5

35.9

34.834.4

40.6

34.2

41.6

37.3

25.5 43.5

31.1

41.3

29.834.4

34.133.8

33.3

30.8

31.8

28.1

35.5

35.1

30.625.6

33.3

38.7

38.8

42.540.6

49.4 32.8

36.4

56.3

51.851.1

27.5

21.241.1

21.4

16.4

40.7

14.824.6

39.4

45.249.1

48.2 49.750.1

47.1

43.2

49.8

46.548.4

50.1

31.9

24.4

30.221.3

33.828.8

38.6

26.4

26.427.9

28.9

26.1 26.9

24.8

30.629.8

30.723.7

29.7

25.1

29.430.7

24.228.3

16.3

18.216.2

21.513.5

19.128.6

17.1

15.9

15.7 16.9

20.620.7

24.8

17.5

15.315.5

16.924.7

19.623.6

23.1

21.820.4

18.8

14.8

19.5

16.8

15.4

13.9

25.8

28.1

27.821.2

34.328.4

15.9

20.2

23.4

15.2

17.4

26.5 24.2

25.4

25.4

20.1

28.3

31.8

14.6 18.9

28.6

31.8

31.1

26.7

39.3

40.6 43.3

28.5

35.5

34.7

43.3

24.728.9

27.432.2

36.3

16.4

17.3

15.1

29.1

24.821.3

17.4

14.4

14.3

14.4

12.4

13.4

14.313.8

23.5

20.3

21.5

23.2

23.7

18.318.8

21.218.7

12.414.7

11.511.5

16.6

15.9

25.1

14.6

12.7

15.2

16.4

20.3

20.8

20.712.2

15.2

15.5

12.9

16.8

21.5

18.2 16.2

16.6

19.6

20.8

15.1

14.8

22.521.2

19.814.2

14.722.7

13.3

12.9

23.112.9

13.7

29.3

19.3

13.3

26.1 17.9

24.421.4

15.4 13.521.8

20.5

25.5

28.3

39.361.9

55.5

60.1

60.5

57.6

50.550.3

35.1

22.145.8

38.8

34.5

33.5

36.3

31.3

41.2

23.4

36.7

34.7

43.742.4

30.3

49.9

23.6

33.3

24.9

24.7

26.5

21.2

27.9

28.824.8

22.2

24.1

41.6

49.848.4

46.5

45.7

40.539.9

53.9

45.7

42.2

41.4

46.2 40.240.6

25.1

33.3

39.534.8

39.6

45.3

17.5

44.942.433.5

43.8

38.7

48.7

34.6

39.943.1 47.4 49.6

50.551.5

45.5

42.648.9

42.646.9

45.2

40.9 52.7

49.1 49.9

46.243.5

39.8

23.6

25.1

21.8

38.8

38.8

39.236.3

40.5

39.4

39.635.645.8

38.338.6

35.5

46.836.4

44.7

37.1

45.239.6

38.5

33.231.6

35.6

31.3

34.631.4

45.2

36.3

36.6

39.1

41.6

45.2

42.341.2

41.8

33.4

40.4

38.6

33.9

38.2

39.9

40.6

39.9

39.238.5

30.535.5

38.340.4

41.335.4

34.1

0 2.5 5

k

/

Approved Development Area

IOL Oil Sands Leases

Net Bitumen Pay Isopach

(> 8wt Percent)

0.041 - 10

11 - 20

21 - 30

31 - 40

41 - 50

51 - 60

Lease 42

Lease 41

Lease 40

Lease 49(meters)

Top Surface used for net bitumen pay

Base Surface used for net bitumen pay


2012

17

Approved Development Boundary

Cold Lake Leases

Developed Pads

2012 CSP Pilot Wells

2012 Wellbore deviations(CSS and Infills)

Type Well 3-10-66-4W4M

Representative StructuralCross Sections (A-A’) (B-B’)

Map Illustrates:(a) Location and extent of

existing development

(b) Development wells drilled to date in 2012

(c) CSP Pilot Wells Drilled

(d) Location of representative structural cross sections

Approved Development Area Basemap with 2012 Drilled Wells


2012

18

A A’Northwest Southeast

top Clearwaterreservoir

Wabiskaw Mbr

McMurrayFm.

3-10-66-4W4

H03 – 13

J16 – 08 D04 – 08

5-32-64-3W44-35-64-3W4

Cross section represents stratigraphic and structural variability within the Clearwater formation.

Representative Structural Cross Section

Mapped Surface

Mapped Surface


2012

19

B B’Southwest Northeast

7-8-65-4 6-11-65-4

11-25-65-4 1-17-66-3

2-14-66-3

7-19-66-2

Cross section represents stratigraphic and structural variability within the Clearwater formation.

Representative Structural Cross Section

Mapped Surface

Wabiskaw Mbr

Mapped Surface

top Clearwaterreservoir

McMurrayFm.


2012

20

Cored Wells

• Map illustrates location of core within approved development area

• Sampling taken for reservoir quality in 2010 and 2011

• Core acquired in 2012

Approved Development Boundary

Cold Lake Leases

Developed Pads

Core Analysis

Year to Date 2012 Core Analysis


2012

21

2012 3D - 4D Seismic Location Map

• Map illustrates position of 3D and 4D seismic data acquired within the approved development area in the past 12 months

• 2012 3D Seismic acquired: Mahihkan West and H58/H59 (74 km2)

• 2012 4D Seismic acquired: U08 and U01/U03 (11 km2)

Depth slice middle of Clearwater Reservoir

AA A’A’

1 km+-

W-E Seismic Line

ClearwaterClearwater

McMurrayMcMurray

DevonianDevonian

500 m100

200D

epth

SS

(m

)

A’A’AA

+-


2012

22

Colorado Group Core

• Locations where core have been acquired in shales of the Colorado Group in 2012:

L09-27 sidewall cores currently being analyzed for BTEX content

• 4 cores from 2010 – 2011 OV program remain in freezer pending analysis for clay content


2012

Drilling and Completions


2012

24

Typical Deviated CSS Well Design

Surface Casing~ 150-200 m


2012Horizontal CSS Well Design

25

350-1200 m350-1200 m350-1200 m

– 177.8mm, 219mm or 244mm (size depends on required capacity)– L-80 type 1 grade

– metal-to-metal seal connections– cemented from FTD to surface w/thermal cement

– 89mm, 114mm or 140mm LTC


2012Horizontal Steam Injection Well Design

26


2012

Artificial Lift


2012

28

Artificial Lift Performance

PumpjackBottom Hole

Pump SpeedDesign

Rate

160 - 173 - 86 50.8 mm 7 SPM 38 m3/d

11 SPM 60 m3/d

16 SPM 87 m3/d

228 - 173 - 86 7 SPM 60 m3/d

or 63.5 mm 11 SPM 93 m3/d

320 - 213 - 86 16 SPM 135 m3/d

456 - 213 - 144 63.5 mm 4 SPM 55 m3/d

(long stroke) 7 SPM 100 m3/d

14 SPM 200 m3/d

912 - 305 - 192 82.6 mm 4 SPM 130 m3/d

7 SPM 225 m3/d

11 SPM 350 m3/d

1280 - 305 - 240 95.3 mm 4 SPM 210 m3/d

7 SPM 370 m3/d

10 SPM 530 m3/d

• Rod pumps used across field

• Size of lift system depends on:

• Offset to reservoir target

• Well deliverability: deviated versus horizontal wells

• Operating Conditions

• Pumping temperature 75 –220°C

• Pump Intake pressure 6 MPa to less than 500 kPa

• Average run life of rod pumps is between 300-400 days

• Corpac Variable Frequency Drive (VFD) Program ongoing

• Installing variable speed drives on all new producing wells.

• Program in place to retrofit many existing wells with VFD’s.

• Using VFD controllers for inferred measurement.


2012

Instrumentation in Wells


2012

30

geophones

Colorado Group top

Grand Rapids top

Clearwater top

2 geophones in Glacial Till as of 2007

• A passive seismic well with permanent omnidirectional geophones is installed at all new pads at Cold Lake since 1998

• Seismicity is monitored to detect fluid incursion and casing failures in uphole zones

Typical Passive Seismic Configuration

Instrumentation in Wells


2012Instrumentation in Wells

31

Hybrid Passive Seismic Well

• A hybrid Passive Seismic well design allows pressure monitoring in the Grand Rapids and passive seismic monitoring with cemented geophones in the same well.

Grand Rapids Pressure Monitoring Well

• There are several wells in the field used to monitor Grand Rapids pressure. These wells often monitor more than one interval. The configuration below provides pressure monitoring in one Grand Rapids interval and one Clearwater interval.

Clearwater Top

Grand Rapids Top

Colorado Top

Perforations

10 geophones, 5 each on two cables banded on 73 mm tubing.

Pressure / temperature sensor installed across from the perforations hung through tubing on wireline

Geophones are cemented in the well

2 Geophone cables, ran through the wellhead at surface to a junction box.

Pressure and temperature sensor cable run through the tubing hanger to a junction box

73 mm tubing for banding the geophones. Will allow for perf gun and pressure / temperature sensor to be run through.


2012

Scheme Performance


2012Cold Lake Recovery Determination

33

• Bitumen recovery from the CSS process in the Clearwater zone is a function of effective pay thickness and bitumen saturation

• Effective pay and bitumen saturations are determined from facies based descriptions of logs and cores obtained from the Clearwater zone at an 8 wt% cutoff

• Shale and clay content are considered in the determination of effective pay

• Recovery predictions are based on performance type curves derived from field performance and reservoir simulation

• Adjustments are made for other factors impacting recovery such as:• Bottom water

• Clearwater gas cap

• Split pay

• Adjacent reservoir depletion

• Well spacing


2012

Bitumen Production

Steam Injection

103 m3/d 103 m3/d OSR SOR

2011 25.5 88.4 0.30 3.4

2012 YTD Sep 24.5 86.8 0.30 3.4

Cumulative

Cold Lake Production Performance

Cold Lake Approval 8558 Area Production

• Maximum daily bitumen production under approval 8558 is 40,000 m3/d

• Development continues to increase production rates towards daily maximum

• Development is driven by many factors including technology and economics

• Increased 2011 and 2012 steam volumes related to steaming restrictions removal and improved plant reliability

* (Steam volumes prior to Oct 2004 not adjusted for meter correction)

*

34


2012Individual Site Performance

Steam Transfers (103 m3)

• Maskwa to Mahihkan: 121 D04 infills (Oct 2011 – Feb 2012)

• Mahihkan to Maskwa: 93 J10 infills (Oct 2011 – Sep 2012)

• Leming to Maskwa: 1,864 0FF / 00U infills (Oct 2011 – Sep 2012)

• Leming to Mahkeses: 0

• Mahkeses to Leming: 035

Steam restrictions

Water

Steam

Bitumen


2012

36

• 5 year outlook for pad abandonment• E07 pad abandoned to above the oil in

shale anomaly in 2012

• Q and S pads abandonments to be completed in 2013

• Pads with support from adjacent pads will continue operation

• Pads A01-A04 and H35-H37 received small amounts of steam in the last 48 months, and therefore were not included on the list

• Individual wells that are uneconomic will be zonally suspended to meet the conditions of Directive 13

Pads not steamed in prior 48 months

Abandonment Outlook

Pad Plans 00N Operating as water storage pad00U Operating with support from adjacent pads 00V Operating with support from adjacent pads 00W Operating with support from adjacent pads 0AA Operating with support from adjacent pads 0BB Operating with support from adjacent pads 0CC Operating with support from adjacent pads 0DD Shutin, evaluating future potential0FF Operating with support from adjacent pads 0GG Shutin, evaluating future potential0HH Operating with support from adjacent pads A05 Operating with support from adjacent pads B01 Operating with support from adjacent pads B03 Operating with support from adjacent pads C01 Operating with support from adjacent pads C03 Operating with support from adjacent pads C05 Operating with support from adjacent pads D01 Operating with support from adjacent pads D02 Operating with support from adjacent pads , steam planned for 2013D03 Operating with support from adjacent pads , steam planned for 2013D26 Operating with support from adjacent pads D27 Operating with support from adjacent pads D52 Operating with support from adjacent pads E07 Scheduled for steam in Oct /2012 through D29 Horz. wellsH03 Operating with support from adjacent pads H33 Operating with support from adjacent pads H34 Operating with support from adjacent pads J02 Operating with support from adjacent pads , steam planned for 2015J07 Operating with support from adjacent pads & infill steam planned in 2014 P02 Operating with support from adjacent pads D57 All wells zonally abandoned in 2008D66 3 rows zonally abandoned ‐ top row supported by E09 infill


2012

• Steam quality is measured at plant outlets only

• Calculations indicate a 2 to 5% decrease in quality at pad depending on distance from plant

• Maskwa average steam quality low since March 2012 due to several boilers awaiting maintenance

• Leming average steam quality low since June 2012 due to water treatment issues

Steam Quality

37


2012Cold Lake N-Pad – Approval 4510

• Approval 4510 is for utilization of Leming N pad as a temporary water storage scheme

• Annual N Pad Report to be submitted late November 2012

• Reservoir pressure continues to be below 7500 kPa limit

• Plan is to continue N Pad water injection and production as required

38


2012

39

1AB060506503W400

00NFT735MANUAL

1AN060506503W400

N-PAD7678 - Disposal

Prod Water From Leming

00NFT704MANUAL

LEMNDISPL_PWDISN

00NFT706MANUAL

00NFT708MANUAL

00NFT734MANUAL

1AG070506503W4000 1AH070506503W400 1AJ060506503W400

00NFT731MANUAL

1AM060506503W400

00NFT743MANUAL

1AU060506503W4001AB060506503W400

00NFT735MANUAL

1AN060506503W400

N-PAD7678 - Disposal

Prod Water From Leming

00NFT704MANUAL

LEMNDISPL_PWDISN

00NFT706MANUAL

00NFT708MANUAL

00NFT734MANUAL

1AG070506503W4000 1AH070506503W400 1AJ060506503W400

00NFT731MANUAL

1AM060506503W400

00NFT743MANUAL

1AU060506503W400

N-Pad Schematic

ERCB injection system #7678

Active Suspended

2006-01-01

Suspended

2006-01-01

N-Pad Disposal Volumes (m3)

Cold Lake N-Pad – Approval 4510

Month 00N04CLD 00N06CLD 00N31CLD 00N43CLD MonthlyTotalJan‐11 4073 5671 7910 9076 26731Feb‐11 8837 10122 12005 10900 41864Mar‐11 12698 15013 18093 14409 60213Apr‐11 0 0 31884 0 31884May‐11 9389 11769 11952 10667 43778Jun‐11 14379 23100 18718 14859 71055Jul‐11 12830 18236 16746 12738 60551Aug‐11 11726 16551 15050 10701 54028Sep‐11 7742 11595 10588 12158 42083Oct‐11 18406 18406 18406 18406 73624Nov‐11 14365 16653 16887 18767 66672Dec‐11 15412 18912 18551 21282 74157Jan‐12 16694 18750 18373 20969 74786Feb‐12 15623 16870 17007 19771 69271Mar‐12 17634 19007 19644 21968 78252Apr‐12 16792 17915 17997 20680 73384May‐12 16551 17372 17086 20294 71303Jun‐12 17712 18679 19193 6775 62359Jul‐12 17608 18543 19203 4245 59599Aug‐12 10561 13012 13111 15234 51917Sep‐12 10864 13315 12949 15263 52391


2012Cold Lake Water Management

40

Cold Lake Water Production

• Increasing water production driven by field development

• Water to steam ratio has increased as pads move into later cycle production

• Field water producibility currently in excess of facility water handling capacity, requiring production shut-in

- Actively managing district water balance to maximize throughput

- Example pad: D55 impacted by water constraints during cycle 11, resulting in bitumen production below forecast

Operational Strategies

• Production shut-ins prioritized based on water to oil ratio and other factors – typically impacts later cycle pads

• Maximize produced water recycling through:

- Projects to increase operational flexibility with inter-site produced water and steam transfer systems

- Implementing initiatives which reduce fresh water consumption which include:

• transfer of treated water from Mahkeses to Leming• debottlenecking water treatment systems to deliver more

treated water to Leming from Maskwa• vapor recovery compressor seal water recycle systems using

produced water

Cycle 10 Cycle 11

D55 pad

Production constrained due to water


2012

4141

Pad Performance Reviews

H62

H69

H65

H68

T15

H59

H58

E11

V10

H63

H57

H51

F08

U0

8

D57

D35

0MM

00G

00B

0MB

00Q00R

00A

0GG

0MD

0MA

0MC

00F

00J

SA-SAGD

0HF

00D

D29

T64

T65

T66

R2W4MR3R4R5

0 2.5 5

Approved

Development Area

T18

V13Reviewed Pad

Developed Pad


2012Maskwa E09 Pad

• Maskwa E09 is a regular 4 acre spacing / 20 well pad

• Extended steaming period utilizing 4 steam injectors at E09, as part of E08/E09/E10 steamflood operation

• Initial oil production during the steaming period ramped quicker than forecast and reached expected peak. Oil has since declined below expectations due to water constraints at Maskwa and production shut-ins.

• Injection at the E08/E09/E10 steamflood was interrupted in November 2011 due to limited steam availability.

Cycle 9 Cycle 10(CSD)

42


2012Maskwa E11 Pad

• Maskwa E11 is an 8 acre spacing / 42 well pad that is currently in cycle 5

• Pad is currently performing as expected despite adjacent to depletion challenges from the first row of horizontal wells

• CSS perforation stand off from bottom water zones is dependent upon the reservoir quality in the stand off interval

• Bottom water production is also reduced by not drilling within 5 m TVD of a projected water zone. Note that 8 -10 m MD sumps below the perforations are required in all wells for mechanical operating reasons

• 3 wells on the southeastern edge of the pad are likely connecting to bottom water

7-25-64-4W4 pad OV well

Perf. interval for most of pad

•Inc. shale beds

•Inc. water

bottom of core

top transition zone

top water

8-10m standoff

43


2012

44

Maskwa F08 Pad

• Maskwa F08 is a 11 acre spacing / 4 horizontal well pad

• Pad is a CSS trial in thin pay with average thickness 10-11 m

• Cycle lengths extended versus original forecast due to increased steam injection volume, expecting higher ultimate recovery

• Early cycle production on expectation

Cycle 1 Cycle 2

Pay interval


2012

45

Mahihkan H10 Pad

• Mahihkan H10 is an irregular-shaped 4 acre spacing / 21 well pad (32 bottom hole locations)

• Cycle 7 production produced slightly below expectation: horizontal well productivity, leak-off to adjacent depleted zones (testing issues late in cycle 7 resulting in erroneous water and oil)

• Cycle 8 production ramping lower than forecast – water shut-in impact, scale issues

• Pad bitumen recovery expectation remains at ~20%

Cycle 7 Cycle 8


2012

46

Mahihkan H47 Pad

• Mahihkan H47 is an irregular-shaped 8 acre spacing / 25 well pad / 30 bottom hole locations

• H47 pad surface location is co-located with H39

• Near end of cycle 6 steam, two producer-only wells failed while on soak (wells 12 and 20)

• Small impact to steam volumes as all wells were taken off steam following second failure

• Cycle 6 production volumes remain near expectation, partially supported by H57 steam push

• Cycle 7 steam strategy: shear stress modeling supported a number of slimholes around the H47 / H39 pad surface locations

• Primary benefit will be balance shear stresses by more evenly heaving the pad

• Additionally, slimholed wells return to HP CSS operation, resulting in higher recovery versus producer only status

H47

H39H46

H57

Cycle 6Cycles 1‐5


2012

47

Mahihkan H57 Pad

• Mahihkan H57 is an 8 acre mega-pad / 24 well pad / 54 bottom hole locations

• Pre-cycle 1 steam, six wells were identified as having poor primary cement bond; subsequent cement remediation and slimhole of each well occurred prior to cycle 1 steam

• Slimhole casing collapses occurred on three wells during cycle 1 steam (Hz 13, 20, 22)

• Wells have been abandoned and re-drills are planned

• Slimhole collapses occurred early in the steam cycle, resulting in reduced cycle 1 steam volumes for several wells and reduced pad production volumes

• Cycle 2 and 3 steam-in timing delayed to remediate collapses and align steam sweep with other Mahihkan North pads; production performance as expected.

Cycle 1 Cycle 3Cycle 2


2012

48

Mahihkan H63 Pad

• Mahihkan H63 is a mega-pad 8 acre spacing / 24 well pad / 80 bottom hole locations

• Pad required remediation prior to cycle 1 steam due to cement issues during initial development

• Included as part of the Grand Rapids monitoring program: H63-21 slimhole with downhole P/T sensors in Lower GR, H63-Hz12 with surface pressure monitoring of Lower GR formations)

• Additional surveillance includes passive seismic and select early cycle temperature logs / casing integrity checks

• No anomalous pressures / temperatures observed during H63 cycle 1 steam

• Early cycle production performance on expectation; steam schedule adjusted to align with other Mahihkan North pads

Cycle 1 Cycle 2


2012Mahihkan H69 Pad

• Mahihkan H69 is a mega-pad 8 acre spacing / 24 well pad / 80 bottom hole locations

• Lower early cycle production performance, expected to be the result of resource quality (lower bitumen weight %) at perforation location; fracture orientation may be a contributing factor

• Progressing recompletion opportunities to increase bitumen production and ultimate recovery; incorporating learnings into future pad development

Cycle 1 Cycle 2

49


2012

50

Mahihkan J08 Pad

• Mahihkan J08 is a regular shaped 4 acre spacing / 20 well pad

• J08 producers are steamed by the H01 and J07 infill only injectors

• Production performance slightly above expectation and leveling off with sustained steam injection; clear evidence of production push (increasing water) following periods of higher steam injection

• High ultimate recovery due to thick, clean resource


2012

51

Mahkeses T14 / T15 Pads

• Mahkeses T14 is an 8 acre spacing / 20 well pad (includes 5 horizontals and 43 total bottom hole locations)

• Mahkeses T15 is an 8 acre spacing / 36 well pad (includes 6 horizontals and 70 total bottom hole locations)

• Increase surveillance required for these pads due to T15-09 surface casing vent flow and bitumen to surface prior to cycle 1 steam

• T15-09 monitoring: surface pressure monitoring of Lower / Upper GR, surface casing vent monitoring

• T15-07 (low cement top, re-drilled): down hole pressure / temperature monitoring of Lower / Upper GR

• Sequential steaming of pads in area for early cycles

• GR monitoring observations

• Lower and Upper GR pressure responses observed at T15-07 and T15-09 during steaming of T14/T15 pads are consistent with poroelastic effects

• No fluid observed at T15-09 surface casing vent flow during steaming operations at T14/T15 pads

• Early cycle production performance meets expectation

Cycle 3 Cycle 4Cycle 1 Cycle 2

Cycle 3Cycle 1 Cycle 2

T14 pad

T15 pad


2012

52

Leming Y32 Pad

• Leming Y32 is a 4 acre spacing / 20 well pad

• Early cycle performance generally in line with expectation

• Performance impact by adjacent areas already depleted by steaming operations (as expected)

Cycle 3Cycle 1 Cycle 2


2012

Late Life SteamfloodPerformance


2012Late Life Steamflood Expansion

54

H01/H02 Area

D20’s Area

• Expanded beyond J01 infill area (H01/H02), 1st commercial application

• Currently 55 infills on steamflood into 34 producing pads (~700 wells)

Approved November 2011

Approved November 2010


2012Steamflood Trials: D20’s and H01/H02 Area

55

D20’s Pattern Injection/Production

Water Decline

Injection End

Vertical Well Steamflood

• D20’s vertical well steamflood injection ended October 2011, with ongoing production.

• Vertical well steamfloods are not expected to achieve the same level of recovery as infill steamflood.

• No existing plans for vertical steamfloods as steam is being used in higher performing areas, but it remains an option for future implementation.

Infill Steamflood

• J01 infills completed a 3 year steamflood trial of the H01/H02 area in August 2011.

• Performance is consistent with initial predictions and results are encouraging.

• Implementation of additional late life infill steamflooding is desirable and has expanded into Mahihkan, Maskwa, and Leming in the J,D,F,G Trunk areas.

J01 H01-H03 off steam

J01 H04 continued to

steam



56

• Steamflood expansion into Mahihkan J trunk. Overall performance to date as expected.

• Getting IOI steam to consistent, target rates has resulted in declining water production and steady oil production

• Steamflood expansion into Maskwa D trunk. Overall performance to date as expected.

• Steamflood injection rates overall consistent and on target resulting in lower water production and steady oil production



• Steamflood expansion into F-Trunk started Q2-Q3 2011. Overall performance to date as expected

• Higher injection rates in the beginning to commence the steamflood. Rates have since declined and with it water production. Oil production has maintained at expected levels. F02 & F03 IOIs temporarily off steam due to a steam interruption and are expected to continue in the near future.

• Current strategy for F-trunk is to steamflood, however option to return to a higher injection rate and cyclic operation of the F-trunk IOI is still available and may be evaluated.

• Steamflood expansion into the rest of F-Trunk (F07) and Leming G01 and G02 pad via 00U & G02 IOI’s started Q4 2011. Overall performance to date is below expectations due to an imbalance between steam injection and fluid withdrawal.

• Steamflood injection rates overall consistent and on target

Ste

am I

nje

ctio

n &

Oil/

Wat

er P

rod

uct

ion

(m

3 /d

)

Ste

am I

nje

ctio

n &

Oil/

Wat

er P

rod

uct

ion

(m

3 /d

)

57


2012

58

Factors Impacting Recovery

• Individual pad recovery expectations range from less than 10% to over 60% of the original effective bitumen in place.

• The variation in recovery level is fundamentally a function of bitumen saturation and shale structure/distribution.

• Additional reservoir challenges include:• Bottom water

• Clearwater gas cap

• Split pay

• Adjacent reservoir depletion

• Well Spacing LOW PRESSURE

DEVELOPED LOWER RISK

BOTTOM WATER

GAS CAP

SPLIT PAY

THIN PAY

LOW BIT. SATURATION

ADJACENT DEPLETION

SHALE INTERBEDS

RECOVERY RISK


2012

59

CSS Performance - Bottom Water

• Performance issues:• Bottom water is a thief zone for steam injection

• High mobility water excludes bitumen production

• Mitigation• Basal Wabiskaw shale provides seal for much of

CLPP 1-13

• Perforation standoff from transition zone and thin bottom water

• Additional standoff required for thick bottom water in clean sand

• Uphole recompletions of wet wells can be effective if sufficient separation is left between old and new perforations

Developed Pads

Developed Pad – Bottom Water Issues

Future Area with Bottom Water Risk

D66D57

T10

D67


2012

60

CSS Performance - Gas Cap

• Two significant Clearwater gas cap areas• M&P Trunk – producing

• Bourque Lake gas cap - undeveloped

• M&P Trunk pads exhibited poorer performance due to pressure losses to the gas cap

• Steaming all pads under a gas cap together reduces steam losses and improves performance

• Recovery expectations at M&P Trunk pads are 30-40% lower due to presence of gas cap

Performance of Gas Cap Pads

M&P Trunk Gas Cap

P01

M06

M04M03

Developed Pads no gas cap

Developed Pad – gas cap present

Undeveloped gas cap area

–

Bourque Gas Cap

(Corrected steam volumes)


2012

61

Thin Split Pay

Interbedded sequence

ThickContinuous Pay

• Split pay occurs where an interbedded sequence has cut through lower reservoir sequences

• Interbedded sands and shales act as vertical permeability barrier between lower reservoir sequences and good quality sand in upper sequence

• Upper zone can be accessed through recompletion after lower zone depletion

• Concurrent depletion trials with limited entry perforations resulted in poor inflow performance

• Thin zones have substantially lower recovery due to heat losses to surrounding non-reservoir rock

• Split pay can be used to isolate effects of top fluids

CSS Performance - Split Pay

Split Pay


2012

62

• MM pad is adjacent to depletion in DD pad which acts as thief zone for steam

Adjacent to Depletion Example - MM Pad

LL

DD

NN

GG

HH

MM

F

280 m

210 m

Edge column wellEdge row wellInterior well

• Difficult to achieve high injection pressure after cycle 2 in edge row wells

• Low fluid production in edge row wells

0MM - OSR

0.0

0.1

0.2

0.3

0.4

0.5

0 1 2 3 4 5 6

Cycle

OS

R

IntER


2012

63

Well Spacing

• Commercial pads are developed on 4 acre, 8 acre or 11 acre well spacing

• 4 acre spacing in the thicker central area of the field

• 8 or 11 acre spacing in thinner resource areas

• Cycle steam injection volumes have been derived primarily from field operating experience with the objectives of:

• Achieving high levels of reservoir conformance to mobilize cold bitumen

• Managing inter-well communication

• Limiting casing damage caused by shear stress

• Current steaming practices employ the same early cycle injection volume strategy for both 4 and 8 acre well spacings:1

• Cycle 1 8,000 m3

• Cycle 2 7,000 m3

• Cycle 3 8,000 m3

• Cycle 2 volumes are reduced because injected fluids are typically not fully reproduced in cycle 1

• Subsequent cycle high pressure steam injection volumes range up to 10,000 m3 (volumes injected at dilation pressure)

• Actual injection performance from previous cycles is used to develop the steaming strategy for an individual pad

• Wells drilled on 8 acre spacing are expected to operate through more cycles than those on 4 acre spacing

• Expected recovery from 8 acre spacing is approximately 80% of 4 acre recovery based on reservoir simulation

• Existing 8 acre pads are not sufficiently mature to demonstrate lower recovery

Infilled Pads8 Acre Spacing

ApprovedDevelopment Area

4 Acre Spacing

Other Spacing (Pilots)

Infill Drilling

• Where economic, horizontal injector-only-infills are drilled between the rows of wells at mature pads

• Infill steam is directed to bypassed bitumen to increase recovery by 15 to 30% relative to CSS

• Infill steam injection volumes per pad are similar to CSS volumes

111 Acre Spacing steam strategy approved by the ERCB in July 2011 allowing for 12,000 m3 overfillup per cycle.


2012

64

Impact of Well Spacing on Recovery

• Simulation data suggests that pads on 8 acre spacing recover ~ 80% of the resource of a pad on 4 acre spacing

• 4 acre performance curve shown for equivalent resource to Mahkeses pads

• Most mature Mahkeses pads not sufficiently depleted to validate recovery expectations

4 Acre Reference is @ LRFS 0.863 curve

Most Mature Mahkeses pads


2012Pad Recovery

65

Effective OBIP Ultimate Recovery(e3 m3) (e3 m3) % EBIP % EBIP

00A 1184 152 13% EUR = Recovery to date00B 1772 126 7% EUR = Recovery to date00C 1559 216 14% EUR = Recovery to date00D 1236 212 17% EUR = Recovery to date00E 1257 150 12% EUR = Recovery to date00F 1079 233 22% EUR = Recovery to date00G 2097 358 17% EUR = Recovery to date00H 2010 291 14% EUR = Recovery to date00J 850 249 29% EUR = Recovery to date00K 1905 489 26% EUR = Recovery to date00L 2019 450 22% EUR = Recovery to date00M 982 68 7% EUR = Recovery to date00N 1648 489 30% 30% - 35%00P 2341 714 30% EUR = Recovery to date00Q 1988 342 17% EUR = Recovery to date00R 1764 116 7% EUR = Recovery to date00S 1174 136 12% EUR = Recovery to date00T 2644 846 32% EUR = Recovery to date00U 2636 982 37% 40% - 45%00V 2780 723 26% 30% - 36%00W 2488 1244 50% 50% -55%0AA 2533 1115 44% 44% - 45%0BB 2278 1504 66% 66% - 70%0CC 2369 941 40% 40% - 45%0DD 2890 884 31% 31% -35%0EE 1854 575 31% EUR = Recovery to date0FF 1976 986 50% 50% - 55%0GG 1365 511 37% 37% - 40%0HF 297 102 34% EUR = Recovery to date0HH 1337 612 46% 46% - 50%0LL 1715 698 41% 45% - 50%0MA 1454 126 9% EUR = Recovery to date0MB 1942 452 23% EUR = Recovery to date0MC 1087 496 46% EUR = Recovery to date0MD 816 496 61% EUR = Recovery to date0ME 2276 533 23% EUR = Recovery to date0MM 1879 614 33% 33% - 35%0NN 2549 907 36% 50% - 55%A01 2446 948 39% 40% - 45%A02 2330 1022 44% 45% - 50%A03 2159 959 44% 45% - 50%A04 2974 1337 45% 45% - 51%A05 2024 786 39% 39% - 42%A06 2615 894 34% 35% - 40%B01 2070 937 45% 45% - 50%B02 2131 1012 47% 47% - 50%

Recovery to Sept 2012Pad


2012Pad Recovery

66

Effective OBIP Ultimate Recovery(e3 m3) (e3 m3) % EBIP % EBIP

B03 2146 1029 48% 48% - 50%B04 1938 972 50% 50% - 55%B05 2110 1458 69% 70% - 75%B06 1937 1023 53% 53% - 55%C01 1695 834 49% 50% - 55%C02 1962 1086 55% 55% - 60%C03 2304 1539 67% 67% - 70%C04 2455 889 36% 40% - 48%C05 2055 794 39% 40% - 45%C08 4026 678 17% 46% - 55%D01 2138 914 43% 43% - 50%D02 2038 713 35% 50% - 55%D03 3459 1052 30% 35% - 40%D04 3307 1325 40% 50% - 60%D05 3075 1366 44% 50% - 60%D06 3422 2358 69% 75% - 80%D07 3521 1734 49% 50% - 60%D09 3331 1913 57% 70% - 80%D10 4056 1801 44% 50% - 55%D11 2431 80 3% EUR = Recovery to dateD12 2883 559 19% 25% - 30%D21 2132 644 30% 45% - 55%D22 2664 1117 42% 50% - 60%D23 2914 1158 40% 55% - 65%D24 2015 811 40% 45% - 55%D25 2640 1100 42% 44% - 50%D26 2990 1494 50% 55% - 65%D27 2717 920 34% 35% - 40%D28 2743 451 16% 30% - 35%D29 2287 148 6% 20% - 25%D31 5974 1362 23% 60% - 70%D33 5004 1289 26% 55% - 60%D35 3616 783 22% 45% - 55%D36 3115 1002 32% 60% - 70%D39 3582 563 16% 45% - 55%D51 2959 1046 35% 60% - 70%D52 3082 801 26% 26% - 30%D53 2704 1126 42% 60% - 65%D54 1688 645 38% 35% - 45%D55 1322 653 49% 49% - 55%D57 728 105 14% EUR = Recovery to dateD62 2390 1106 46% 60% - 70%D63 2703 928 34% 50% - 55%D64 2531 1083 43% 55% - 65%D65 2319 796 34% 55% - 60%D66 1498 187 12% 12% - 13%D67 1546 646 42% 45% - 55%

PadRecovery to Sept 2012


2012Pad Recovery

67

Effective OBIP Ultimate Recovery

(e3 m3) (e3 m3) % EBIP % EBIPE01 3765 729 19% 45% - 50%E02 2601 610 23% 45% - 50%E03 1799 656 36% 50% - 60%E04 2373 590 25% 45% - 55%E05 4256 812 19% 45% - 55%E07 2766 270 10% 20% - 25%E08 2151 589 27% 30% - 38%E09 2286 702 31% 35% - 40%E10 1899 619 33% 35% - 40%E11 7758 741 10% 35% - 40%F01 3266 837 26% 40% - 45%F02 2238 747 33% 35% - 40%F03 3605 1155 32% 55% - 60%F04 2091 931 45% 50% - 55%F05 3406 1205 35% 50% - 60%F06 2123 744 35% 40% - 45%F07 3251 947 29% 55% - 60%F08 2943 122 4% 25% - 35%G01 4764 1212 25% 45% - 50%G02 2664 775 29% 40% - 50%G03 2365 794 34% 40% - 45%H01 2583 1772 69% 75% - 80%H02 1663 1060 64% 65% - 70%H03 935 434 46% 46% - 50%H04 973 503 52% 52% - 55%H05 1402 317 23% 25% - 30%H06 2310 147 6% EUR = Recovery to dateH10 2979 495 17% 20% - 25%H11 2302 1119 49% 70% - 75%H14 2073 326 16% 20% - 25%H15 2809 994 35% 40% - 45%H16 2000 816 41% 50% - 55%H18 2422 754 31% 30% - 40%H19 2034 937 46% 50% - 55%H21 2719 992 36% 36% - 40%H22 2805 1119 40% 40% - 45%H23 3972 1670 42% 45% - 50%H24 2213 654 30% 30% - 35%H25 3716 1456 39% 40% - 45%H26 3878 994 26% 30% - 35%H27 3998 1155 29% 40% - 45%H31 2276 714 31% 35% - 40%H32 2244 595 26% 26% - 30%H33 2170 522 24% 24% - 25%H34 1423 311 22% 22% - 24%H35 1570 313 20% 20% - 22%H36 1629 336 21% 20% - 22%



2012Pad Recovery

68


(e3 m3) (e3 m3) % EBIP % EBIPH37 2139 463 22% 22% - 24%H39 4853 400 8% 35% - 40%H40 2484 572 23% 45% - 55%H41 7842 1314 17% 40% - 50%H42 3843 1035 27% 30% - 40%H45 4283 512 12% 30% - 35%H46 4460 1064 24% 45% - 50%H47 5407 857 16% 35% - 40%H51 6675 503 8% 30% - 40%H57 9705 394 4% 30% - 40%

H58 12793 1423 11% 30% - 35%

H59 10313 1259 12% 30% - 40%

H62 9188 428 5% 25% - 35%H63 8184 286 3% 25%- 35%H65 8499 471 6% 35%- 35%H68 8686 275 3% 30%- 35%H69 9606 140 1% 30%- 40%J01 3011 1976 66% 70% - 80%J02 1874 1165 62% 62% - 70%J03 2654 1539 58% 70% - 75%J04 2764 1572 57% 60% - 65%J05 1355 734 54% 55% - 60%J06 2500 847 34% 45% - 55%J07 3043 1567 51% 60% - 70%J08 3551 2339 66% 75% - 80%J10 3497 1903 54% 60% - 70%J11 3378 1206 36% 35% - 40%J12 3089 1602 52% 60% - 65%J13 3740 1982 53% 70% - 80%J14 3438 1394 41% 60% - 70%J15 4341 1952 45% 65% - 75%J16 3886 1647 42% 60% - 70%J21 3638 1230 34% 35% - 40%J25 3072 605 20% 25% - 30%J27 2531 344 14% 15% - 25%K22 1753 513 29% EUR = Recovery to dateK23 2587 615 24% 25% - 35%K24 2183 478 22% 22% - 25%K26 3154 230 7% 7% - 10%L05 2641 1021 39% 55% - 65%L06 2161 1298 60% 65% - 75%L07 2570 1133 44% 65% - 75%L08 927 428 46% 46% - 50%L11 4227 1140 27% 40% - 50%M03 2774 792 29% 29% - 30%M04 3238 785 24% 24% - 25%M05 2272 457 20% 20% - 25%



2012Pad Recovery

69


(e3 m3) (e3 m3) % EBIP % EBIPM06 2572 434 17% 17% - 18%M07 1762 270 15% 15% - 18%P01 3160 761 24% 24% - 25%P02 2436 329 14% 15% - 25%P03 2777 463 17% 17% - 18%R01 1903 850 45% 50% - 60%R02 1889 731 39% 50% - 60%R03 2359 715 30% 35% - 40%R04 2135 464 22% 25% - 30%R05 1829 579 32% 40% - 50%R06 1255 454 36% 40% - 45%R07 1751 620 35% 40% - 50%T01 4744 791 17% 40% - 50%T02 5084 695 14% 30% - 40%T03 3703 624 17% 30% - 40%T04 4167 591 14% 30% - 40%T05 4906 597 12% 30% - 35%T06 4150 610 15% 35% - 45%T07 4647 710 15% 40% - 45%T08 4877 661 14% 30% - 35%T09 4518 450 10% 30% - 40%T10 6371 515 8% 20% - 30%T11 3556 571 16% 30% - 35%T12 4139 523 13% 25% - 30%T14 5445 246 5% 30% - 40%T15 7171 234 3% 30% - 35%T18 4973 0 0% 30% - 35%U01 4644 856 18% 40% - 50%U02 4432 731 16% 40% - 50%U03 5239 847 16% 40% - 50%U04 4726 739 16% 35% - 45%U05 6818 723 11% 30% - 40%U06 3710 554 15% 25% - 35%U07 5542 382 7% 30% - 35%U08 4836 394 8% 30% - 40%U09 3657 346 9% 35% - 45%V01 5202 837 16% 35% - 45%V02 5073 635 13% 25% - 35%V03 4843 619 13% 25% - 30%V04 4861 774 16% 35% - 45%V05 4974 728 15% 35% - 45%V08 5090 726 14% 35% - 45%V09 4882 647 13% 35% - 45%V10 8201 669 8% 30% - 40%V13 7873 54 1% 25% - 30%Y16 2362 651 28% 30% - 40%Y31 2563 539 21% 40% - 45%Y32 2302 116 5% 40% - 45%Y34 2818 571 20% 40% - 45%Y36 3835 680 18% 35% - 40%



2012

Future Plans


2012Pad Steaming Priorities

• Long-term steam plans developed annually

• Targetted cycle timing based on historical performance and optimal cycle length

• Development plans tied to projected steam demand at each site to fully utilize installed steam capacity

• Earlier cycle pads receive priority during periods of steam demand higher than plant capacity and for scheduling considerations

• Pads are steamed less frequently as they mature (steam timing is less critical to performance)

• Individual pad steaming suspended at an economic limit

• Infill steamflood pads can operate effectively at a range of steaming rates, providing flexibility to steam scheduling

• Mega-row sweep strategy, intended to maximize recovery, dictates relative steam timing of pads within a steaming area

• Additional factors

• Setback requirements between drilling and steaming operations

• Pad remediation and steaming restrictions

71


2012

72

Steam Plans to End 2013

• Mahkeses• T14, T15, V13, T18

• T-Trunk sweep

• U07, U08, U09, V10

• U01 and T01 IOIs

• T13 SA-SAGD

• Leming• Y32

• FF/U/G02 and T05 Infills

• Maskwa• D, E and F-Trunk Infills and steamfloods

• Central Maskwa steam C08, D39

• F08, E11, D29 Hzs

• New IOIs: D02, D24, A06, D05

• Mahihkan• Mahihkan North sweep (H51, H57, H58,

H59, H62, H63, H65, H68, H69)

• LASER area pads (H21, H22, H23, H25, H24 infills)

• H40, H41, H45, H39, H46, H47

• L09 PM pad and Infills

• H11 and H15 Infills

• H and J Trunk steamfloods

•Steam Injection Volumes

•5 to 10 one cycle

•No steam this period

•30 Steam +

•0 •1 •2 •3 •4 •5•0.5•Km

•Abandoned




•10 to 20 multiple cycles

Steam Injection Volumes Oct ’12 to Dec ‘13

(103 m3/BHL)

5 to 9 one cycle

No steam this period

•0 •1 •2 •3 •4 •5•0.5•Km

•0 •1 •2 •3 •4 •5•0.5•Km

Abandoned

10 to 19 one cycle

20 to 29 one cycle

30+ one cycle

10 to 19 multiple cycles

5 to 9 multiple cycles

0 to 5 one cycle

Steam flood

Injector Only Infill

D02/D24 IOIs

H39/H46/H47

T05 IOIs

LASER area pads

U01 & T01 IOIs

Mah

ihka

n N

ort

h

T18

A06/D05 IOIs

L09 Pad& Infills


2012

73

Pad Development Program

Drilling and Steaming Schedule


Developed Pads

Developed - 1st Steam 2012

Future Pad - 1st Steam 2013



PadYear

Drilled 1st Steam

V13 2010 2012

T18 2011 2012

L09 2011 2013

N01 2012 2014

N02 2012 2014

N03 2012 2014

N04 2012 2014

N05 2013 2014

N06 2013 2014

N07 2013 2014

N08 2013 2015

T18

L09

V13

N01

N03N04

N05N06

N07

N02

N08


2012

74

Infill Drilling Program

Drilling and Steaming Schedule


Existing Infill Wells

Existing Infill - 1st Steam 2012

Future Infill - 1st Steam 2013

Future Infill - 1st Steam 2014

Infill PadYear

Drilled 1st Steam

D02 2010 2012

D24 2010 2012

H11 2011 2012

T05 2011 2013

D05 2011 2013

L09 2011 2013

A06 2012 2013

U01 2012 2013

T01 2012 2013

V01 2012 2014

V02 2013 2014

D22 2013 2014

U04 2013 2014

U05 2013 2014

HH 2013 2014

J08 2013 2014

L09 Infill

V01 & V02 Infills

U01 & T01 Infills

U04 & U05 Infills

D02 Infill

D24 InfillD05 Infill

H11 Infill

J08 Infill

A06 Infill

T05 Infill

HH Infill

D22 Infill


2012Cold Lake Expansion - Nabiye

75

Plant Status

• Nabiye Project approved by Imperial Oil in 1Q2012.

• Plant facility construction contractor mobilized 2Q2012.

• Deep underground and foundation installation underway.

• Major equipment procurement and deliveries progressing.

Field and Offsites Status

• Main access road complete.

• Field area north/south corridor road construction complete.

• Seven pad program. Three leases complete, three in construction.

• Two drilling rig program (N02, N03 underway) with common camp.

• Buried pipeline (fresh water, produced water, fuel gas, dilbit, diluent) construction underway.

• Grand Rapids monitoring plan approved as Condition 21 of Scheme Approval 8558V, 3 sites (N01, N05, off N07)

Public Engagement

• Communication with First Nations and other stakeholders is ongoing.

• Participated in Neighbour Night, November 2011.

• Nabiye Update newsletter distributed by mail drop. Posted on Imperial Oil Website.

• Local and Aboriginal suppliers engaged in contractor activity.


2012

Special Projects


2012

77

LASER Recovery ProcessIOR Cold Lake Special Projects


2012

78

Table of Contents

• LASER – Process Overview

• Pad Location Map

• LASER Geoscience Overview • Reservoir Properties and OBIP

• Pad by Pad Summary

• Representative Type Log

• Annotated Logs

• Resource Quality (core pictures)

• Casing Integrity

• LASER Performance Summary • Background / Diluent Injection

• Injection Pressures

• LASER Process Phase Behaviour

• Production Performance (area / pad)

• Measurement Methodology


2012

79

LASER - Process Overview

• LASER is a late-life technology• Follow-up process for CSS (cyclic steam stimulation)

• Implemented with 2-3 cyclic cycles remaining

• Alternative to purely thermal processes

• LASER is a cyclic steam process with the addition of a C5+ condensate to the steam during injection

• Enhances gravity drainage efficiency by reducing in-situ viscosity beyond thermal limit

• Potentially increases the recovery by >5% of EBIP

• Key process performance indicators• Incremental OSR over a purely thermal baseline

• Fractional recovery of injected solvent

Liquid Addition to Steam for Enhancing Recovery

CSS Thermal Process

BITUMEN

STEAM+Diluent

Diluent

Well

2

Well

1

STEAM

BITUMEN

STEAM+Diluent

Diluent

Well

2

Well

1

STEAM


2012

80

LASER Project Location

Developed Pads - 2012


2012

81

Reservoir and Fluid Properties

Depth Clearwater @ 400m

Depositional Facies Incised Valley Fill, Tidal / Estuarine

Sands Unconsolidated, reactive, clay clasts

Diagenetic Cements Mixed-layer clays

Bitumen API Gravity 10.2

Bitumen Viscosity 100,000 cp @ 13oC

8 cp @ 200oC

Bitumen Saturation Average 70%

Range AveragePorosity 27 - 35% 32%

Permeability 1 - 4 Darcies 1.5 Darcies

Bitumen Wt % 11.1 - 11.8% 11.5%

Total Net Pay 28 - 35m 31m

LASER Area Reservoir Properties and OBIP

Original-Bitumen-in-Place (OBIP)Clearwater Fm 8 Wt %

(E6m3) (MBO)

LASER Area 35 221


2012

82

LASER Pad Geology

Pad Net Pay(m)

Wt% OBIP(e3m3)

EBIP(e3m3)

H18 30.7 11.5 3245 2422

H19 26.4 11.1 3212 2034

H21 34.0 11.6 3091 2719

H22 35.2 11.6 3198 2805

H23 33.1 11.6 4617 3972

H24 27.9 11.4 2586 2213

H25 31.9 11.4 4503 3719

H26 32.5 11.4 3997 3878

H27 33.0 11.8 4131 3998

H32 28.8 11.5 2534 2244

• The LASER pads have pay mostly in tidal bar and tidal flat depositional facies with minor pay amounts in estuarine delta & fluvial facies

• These facies are bitumen-saturated, fine- to medium-grained sandstones that contain thin mud-beds and clasts

• The southeast part of the area (pads H18,19,21,22,32) has variable amounts of clay coatings on the sand grains


2012

83

• Regional sediment transport of quartzose/feldspathic sands from southwestern fold/thrust belts during Cretaceous time

• Deposition of Clearwater reservoirs in large NW-SE oriented incised valley complexes (up to 50-60m incision)

• Predominantly sandy, tide-dominated facies form the reservoir at Cold Lake

Clearwater Formation – Paleogeography

Clearwater Reservoir Isopach (C30-90 – Incised Valley Fill)5 m contours LASER Area Detail

1 mile5 miles

•H19

LASER type log

OV AA/3-3-66-4W4

H18

H27

H25

H26

H24

H23

H22

H32

H21

30m isopach

Annotated pad wells seen on a later slide

H19


2012

84

Representative LASER Type Log

Grand Rapids Fm

Clearwater Fm

McMurray Fm

Shale

Bitumen SandWater SandCarbonate

TOP OF ZONE UNDER EXPLOITATION

Gra

nd R

apid

s F

m.

Cle

arw

ater

Fm

.M

cMur

ray

Fm

.

SW NE

•Idealized SW-NE section across CL field

• Type well log through the Manville Group (Albian), in the LASER area of the Cold Lake field, Alberta

• The primary reservoir is the Clearwater Formation

• The Clearwater formation is comprised of at least 10 stacked incised valleys which form a complex reservoir architecture

Clearwater

OV AA/3-3-66-4W4 on pad H27

50 m


2012

85

LASER Pad Annotated Logs (part 1)10 m

H18-13 H19 OV 15-27 H21-08 H22 OV 7-34 H23 OV 14-34


2012

86

LASER Pad Annotated Logs (part 2)10 m

H24-13 H25-15 H27 OV 3-3 H32-08 H26 OV 8-3


2012

87

LASER Area - Resource Quality

OV AA/3-3-66-4W4 on pad H27

Cap Rock – siltyshale typical across Cold Lake

Excellent quality reservoir

Excellent quality reservoir

Intermediate quality reservoir

Non-reservoir

2.5 feet ( 75 cm )

50 ft


2012

88

LASER Casing Integrity

• Pad Classification:

• Commercial New (started steaming post-1996): H18, H23, H24, H25, H26, H27, H32

• Environmental New (started steaming post-1996 and within 500 m of Bourque Lake): H19, H21, H22

• 100% Casing Integrity Checks on steaming wells completed prior to a cycle for all 10 LASER pads

• No Passive Seismic Well Coverage on any of the 10 LASER Pads

• For the first LASER cycle all 10 pads were in Cycle 8 or 9

• Reservoir Pressure must be < 4 MPa on adjacent wells to the LASER pads to ensure no additional casing integrity checks

• LASER has not caused a change in the failure frequency of intermediate casing failures on LASER pads or pads adjacent to LASER

• Several of the LASER pads have now advanced to the next cycle, with additional steam injection

• H26 and H27 entered the next IOI cycle in February 2012, with steam into the H24 infill wells

• H21 and H25 entered the next LASER CSS cycle in July 2012

• H22 and H23 entered the next LASER CSS cycle in August 2012


2012

89

Project location

LASER H-trunk pads

LASER H Trunk Project - Background

• Project Scope – H Trunk LASER• 10 pads in Mahihkan H-trunk – diluent injection complete

• First cycle diluent injection began in Q3 2007 and was completed April 2009

• Diluent management

• Distributed to pads via dedicated distribution pipeline

• Produced back to Mahihkan Plant as part of common production stream

• Produced diluent reduces future blend requirement

• Recovery equipment minimizes burning of flashed diluent in steam generators

• Started up August 2008

• Key Learning Initiatives• Effectiveness of solvent distribution through Injector-Only-Infill wells

• Impact of Producer-Only-Wells on solvent recovery

• Effect of solvent concentration on incremental bitumen production

• Sustainability of incremental bitumen production over 3 cycles (pilot H22 pad)

• Obtaining post-steam core was considered, but felt would provide little benefit in progressing the understanding of the LASER process

• Post-steam core is limited to one location at one point in time

• There is limited value in validating the process

• Surveillance efforts focused on acquiring high quality production measurements


2012

Key Learning Initiative# of Pads Location

Target (% v/v)

Actual (% v/v)

LASER POW 29 injectors H18 3% 3.2%8 injectors H19 3% 3.0%

LASER CSS 6Standard H21 4% 6.1%

3rd LASER Cycle H22 4% 4.5%High Diluent H23 8% 8.6%

Standard H25 4% 4.4%Potential Last Cycle H24 3.5% 3.9%Potential Last Cycle H32 3% 3.9%

LASER IOI 2After 1 IOI cycle completed H26 5% 4.4%After 1 IOI cycle completed H27 5% 4.6%

90

LASER H Trunk Project – Diluent Injection

Diluent Injection

Complete in all 10 pads

Injection Data for First LASER Cycle (10 pads)

Project area

H25 H23 H22

H19

H27 H26

H24

H32

H21

Producer Only Well

3 %

4 % Solvent in Steam (v/v)

8 %

H18Injector Only Infill

•LASER PILOT•LASER PILOT

Abandoned / Suspended well

6 %

• Original LASER Pilot at H22 pad had 6% v/v of diluent injected in 8 wells (equivalent to ~2.4% v/v across a 20-well pad)

• Based on successful results at H22 Pilot, increased diluent to nominal average of 5% v/v for commercial implementation in 2007

• 8% v/v injected at H23 to test theory of increased benefits with higher concentration

• Remaining pads received diluent concentrations between 3-6% v/v

• Lower diluent concentrations injected into pads with lower performance expectations

Cumulative (km3) to 09/30/2012Steam Injection 6,246Diluent Injection 297


2012

91

Injection Pressures during LASER Cycle


2012

92

• Liquid diluent is added to the steam and readily vaporizes

• Diluent is transported as vapor with steam into the reservoir (steam chamber)

• Steam tends to condense preferentially at high steam saturation temperatures closer to the wellbore

• Steam-solvent mixtures condense together at slightly lower dew point temperatures

• Solvent condenses near the periphery of surrounding steamed areas and overburden strata

• At higher pressures and temperatures, liquid diluent condensate fractions start to mix with surrounding bitumen

• Actual degree of mixing with surrounding bitumen remains theoretically unknown

• Pressure and temperatures fall steadily during the production phase and continuous steam and solvent flashing or refluxing convection takes place across the steam chambers

• Consistently observed a significant amount of reproduced diluent fractions via venting of producing well casings in ongoing LASER operations.

• Since the first pilot cycle started production at H22 pad in 2002, unusual or difficult emulsions have not been observed. The same standard CSS operating procedures have been implemented to ensure well test data accuracy.

LASER Process Phase Behaviour


2012

93

LASER H Trunk Project - Production Performance

• Steam injection cycle at the 10 pad H Trunk LASER implementation was completed in early 2009

• Oil production and diluent reproduction increased to peak rates in 2010 as expected

• Production has declined throughout the remainder of the cycle, through 2011 and into 2012

• With the first H Trunk LASER cycle now at an end, the performance is encouraging. The overall incremental oil production and diluent recovery are in line with expectations.

• H18 and H19 began the production cycle in Q2 2008

• Peak oil production rates were achieved in 2010 and wells on oil decline during 2011 & 2012

• H21, H22, H23, H25 began the production cycle in Q4 2008


• H24, H26, H27, H32 began the production cycle in Q1 2009


Production Data for First LASER Cycle (10 pads)

Cumulative (km3) to 09/30/2012Hydrocarbon Production 1,886

Diluent Production 174


2012

94

Mahihkan H21 Pad

• H21 is a standard 4 acre spacing / 20 well pad in the LASER H Trunk project

• H21 had completed 8 successful CSS cycles when the 2007 forecast was developed

• Cycle 9 steam injection was completed in September 2008 with the addition of 6.1% diluent to steam

• The oil production ramp up and decline in this cycle is on track with the initial LASER forecast, with total OSR uplift in the full cycle somewhat exceeding expectation

• The change in oil decline rate starting in late 2011 is the result of some steam influx from a CSS pad to the south


2012

95

Mahihkan H32 Pad



• Cycle 9 steam injection was completed in March 2009 with the addition of 3.9% diluent to steam

• The oil production ramp up in 2010 was on track with the initial forecast. The 2011 decline was faster than forecast, with total OSR uplift in the full cycle below expectation (due to steam and diluent fluid migration outside of this pad to the north)


2012

96

Mahihkan H19 Pad



• Cycle 9 steam injection was completed in late 2007 with the addition of 3.0% diluent to steam

• The oil production ramp up in this cycle is delayed from initial forecast• likely due to inter-well communication in 2009 from steaming wells to the north of H19 pad

• Total OSR uplift in the cycle is above expectation (due to steam migration into this pad)

• The change in oil decline rate in early 2012 is the result of some steam influx from a CSS pad to the west


2012

97

Current LASER Measurement Methodology

Diluent / Steam Injection• Injection rates set at HP pumps, which inject diluent into pad steam header

• Diluent measured through pad turbine prior to injection down well

• Injected steam and diluent calculations based on steam measurement at each well

• H24 infills only

• Steam measured at each well individually

• Diluent measured by coriolis meter on diluent supply header and allocated based on orifice meters at each well

• Meters to control concentration of diluent

Hydrocarbon Production (Bitumen & Diluent)• Well testing in compliance with Regulatory requirements

• Production of blend, gas & water based on well test results and production hours

• Diluent recovery volumes based on compositional analysis for each pad with allocated production volume

• Gas Composition (GC) Analyses performed on regularly taken samples

• Results combined with coriolis mass flow & density readings and vent gas orifice meter readings to calculate diluent volumes

• Daily calculated volumes pass through Process Control Systems into Production Accounting System (X-Stream)

• Tested production rate of the blend (bitumen and diluent) is used for production allocation to each well– As documented in MARP (March 28, 2008) reviewed and approved by ERCB on June 3, 2008– Updated MARP submitted to ERCB in February 2012


2012

98

LASER Cycle 1 Results and Future Plans• Overall first cycle LASER performance is in line with expectations

• on average a 0.10 OSR uplift was achieved compared to no LASER implementation, due to the 5% v/v diluent injected with the steam in this first LASER cycle. This is approximately a 50% improvement in oil production performance.

• LASER bitumen production uplift on the 10 H trunk pads ranges from 0.04 to 0.18 OSR uplift

• the recovery of diluent has reached 58% of the initial injected diluent volume, on average in line with the expectation for diluent recovery for this first LASER cycle

• LASER diluent production on the 10 H trunk pads ranges from 30% to 90% recovery of the injected diluent

• there was some fluid migration from the LASER pads, primarily to other pads in the north and east, with the most significant impact being reduced OSR uplift and lower diluent recovery at H26, H27, H24, and H32 pads

• LASER has been demonstrated to be effective in CSS, IOI, and CSS POW situations

• implementation of a higher diluent concentration at H23 pad (8.6%) compared to other pads resulted in an increase in incremental bitumen production and OSR uplift for the cycle, but with an apparent lower diluent recovery for LASER. An estimated 0.18 OSR uplift and 49% diluent recovery was achieved at H23 pad, but with uncertainty in the high concentration assessment due to fluid migration between pads.

• the LASER process has been demonstrated to be successful across a wide range of diluent concentrations at the H trunk project, but identification of an optimal diluent concentration for LASER from the field data is difficult due to the pad-to-pad fluid migration experienced in the cycle

• the sustainability of the LASER performance uplift has been demonstrated by the third cycle of LASER at H22 pad, with an estimated 0.14 OSR uplift in the cycle

• Next cycle of LASER began at H21, H22, H23, and H25 pads in July/August of 2012• steam injection is planned for the remainder of 2012 and into early 2013, with diluent injection in the 3% - 8% v/v range

• the production cycle is expected to continue until 2015

• Significant learnings on LASER cycle 2 will be communicated in future annual reviews when available, no longer as a Special Project but as part of the Scheme Performance section of the future Imperial Oil Cold Lake reviews


2012

Other Discussion Items


2012

0 2.5 5

Grand Rapids Monitoring Program

100

ObjectiveExpand the investigation of interzonal communication to other parts of the field and proactively identify additional instances of, or conditions that can lead to, interzonal communication.

Pad Basis Results

U07 Upper Grand Rapids Pressure

No re-activation of high pressure after 2 cycles of selective steaming

U09 Lower Grand Rapids Pressure

Pressure increase observed when U09-12/13 put back on steam

V10 Poor primary cement bond log

Pressure increase detected in offset gas well during annual GR pressure survey

T15 Potential cement channels

Only poro-elastic response observed (~ 250 kPaincrease in LGR)

L09 None - control pad (replaced V13 in Plan)

To be steamed in 2013

H62 Poor primary cement bond log

Only poro-elastic response observed (~100 kPaincrease in LGR)

H63 Poor primary cement bond log

Only poro-elastic response observed (<100 kPa increase in LGR)

H68 None - control pad Poro-elastic responses observed

Developed PadsMid-Life Pads (Cycle 4-6)New Pads (Cycles 1-3)

L09

H62

H63

H68

T15

V10

U07

U09


2012

101

U/V Trunk Grand Rapids MonitoringObjective

• Monitor specific pads on U/V Trunks for potential fluid excursions into Grand Rapids; if excursions exist, identify sources and pathways

Grand Rapids Monitoring Program• All Pads

- Standard Passive Seismic with thermal fibre optics- Steam injection rates and pressures- Post-steam temperature logs

• U07: 2 pressure/temperature monitoring wells in Lower and Upper Grand Rapids, with one Hybrid Passive Seismic well

• U02 and V10: Cycle steaming restrictions removed, but monitoring continuing on V10-05

Observations• Pressure responses into the Lower and Upper Grand Rapids observed at U07 in Cycle 2 and 3 could

not be re-activated by selective steaming of highest probability candidate wells• Pressure excursions into the Grand Rapids at U09 and V10 appear to diminish with cycle, but pressure

at U09-08 increased when U09-12/13 put back on steam

Conclusions• Conduits from the CW to GR generally close off after early cycles due to either:

- Plugging of the conduit with bitumen, or - The stress state changes to favour horizontal fracturing

• High pressures in Upper Grand Rapids bitumen zones can be highly localized

Plans• U07: Steam pad with high overlap• U09: Steam and monitor pad as in prior cycle to further assess trend when U09-12/13 are steamed

U08

U09

U07

V10

U02

Pressure/Temperature

Hybrid Passive Seismic

Standard Passive Seismic


2012Husky 4-1 & V10 Pad

• Anomalous pressure/fluid behavior was observed in the Husky Colony gas well 00/04-01-065-03W4 during the annual survey program and a subsequent wire line investigation.

• Further field diagnostics are required to confirm whether there are well integrity concerns in the 4-1 wellbore. However, because of the challenging surface conditions around the surface lease for this well, it is necessary to wait until winter ground conditions permit access for a more complete rig investigation to be conducted.

• The adjacent HW on V10 pad is not being steamed during the current cycle, and monitoring of surface pressures at the Husky well has not indicated any material change in pressure to date.

• Pending results of the rig investigation, it is anticipated that the well will be properly abandoned or converted to a pressure monitoring well before the next steam cycle.

102

V10 Pad

4-1 Gas Well


2012

103

T15 Grand Rapids Monitoring

T15

T15-07

T15-09

Monitoring Program• T15-09

• Surface tubing pressure from 2 sets of Lower Grand Rapids perforations• Surface casing pressure from 3 sets of Upper Grand Rapids perforations• Surface casing annulus (for possible vent flows)

• T15-07• Downhole pressures / temperatures in Lower Grand Rapids (tubing)• Downhole pressure / temperatures in Upper Grand Rapids (annulus)

Observations• Poro-elastic responses observed during steaming of T15 and adjacent pads

Conclusions• Caprock integrity maintained

Objective• Monitor Grand Rapids pressures at T15 for potential uphole fluid excursions (cement channel concerns)


2012Upper H-Trunk Grand Rapids Monitoring

H65

H68 HPSWH68

H63

H63-12

H63-21

H62

H62-04

Objective• Monitor Grand Rapids pressures for potential uphole fluid excursions (cement channel concerns)

Monitoring Program• H68 Hybrid Passive Seismic Well (HPSW)

• Pad selected as “control” pad, i.e. no prior wellbore integrity issues

• Installed to provide passive seismic data and Lower Grand Rapids pressures

• H62-04, H63-12 and H63-21 • Pads monitored due to cement integrity concerns • H62-04: Completed in Lower Grand Rapids and

Clearwater• H63-H12 and H63-21: Completed in Lower Grand

Rapids

Observations• H62 – Only poro-elastic responses observed during

steaming• H63 – Only Poro-elastic responses observed during

steaming• H68

• Perfs plugged during cycle 1 – subsequent workover established connectivity to formation

• High-quality GR water sand allowed responses from H69 steaming to be observed

Conclusions• Caprock integrity maintained in the three pads; H69

under investigation

104


2012

105

Investigation of BTEX in Deep Groundwater Monitoring WellsInvestigation initiated in 2011 to identify cause for levels of benzene, toluene, ethylbenzene, or xylene (BTEX) detected in groundwater evaluation wells that exceed Canadian Drinking Water Guidelines.

Diagnostic Purpose Results to Date

Continuous pressure monitoring in aquifers

Detect high-pressure excursions into the aquifers during steaming

Quantify the volume of mud lost to aquifers during drilling

No excursions were detected during steaming

1 - 2 m3 of drilling mud was typically lost to the aquifer during drilling.

Nitrogen soak analyses Detect any collar leakage or casing integrity issues No collar leakage or casing integrity issues were detected

Gas Migration and Surface Casing Vent Flow testing

Characterize flow behind casing• Gas concentrations and compositions• Carbon Isotope analyses• Gas rate and pressure build-up measurements

on surface cased wells

Low levels of non-serious gas flow were detected at approximately 60% of the wells

The majority of the gas appears to be biogenic; some evidence of gas flow from the Colorado/Grand Rapids formations

Tracers Identify pathways behind casing and/or leaking collars using Helium tracer in N2 soaks

Characterize transport of BTEX within the aquifer using Potassium bromide tracer in drilling mud

No casing leaks to surface, as witnessed by absence of any helium detections

Tracer was successfully emplaced into an aquifer during drilling

Noise logs Conducted after steaming to identify potential flow behind casing

None of the 10 wells that were noise-logged indicated a Clearwater gas source; interpret shale as a source

Hydrocarbon analyses Test for presence of BTEX in• surface gas samples• shale cores

BTEX detected in surface gas samples

BTEX was measure in all virgin core samples from the Clearwater Shale and Colorado Shales


2012

Delineation• Groundwater drilling completed mid-July 2012

‒ 6 delineation wells including a 6-inch that can act as a producer‒ Data loggers installed in 5 of 6 wells to monitor water levels

during V13-31 pumping and steaming

GEW 12-7 & GEW 12-8 - weekly analytics including BTEX F1, F2• Only GEW 12-7 initially showed evidence of produced fluids, but

BTEX, Cl and B now below guidelines

GEW 12-5, 12-9, GEW 12-10 - bi-weekly analytics including BTEX F1, F2 – no evidence of produced fluids

Remediation• V13-31 producing aquifer since June 23 2012 now at ~80 m3/day,

includes 3x per week sampling & weekly analytics‒ Chlorides decreasing below guidelines; benzene above

guidelines

• GEW 12-6 E3 ready for tie-in if required; currently sampling

V13 Pad Monitoring & Remediation

50 m

GEW 12-6

GEW 12-5

GEW 12-7

GEW 12-8

GEW 12-9GEW 12-10

Background• Casing failure at V13-31 occurred Apr 13 and was confirmed on Apr 14, 2012.

• Well control response team established and initial notice to AESRD and ERCB on Apr 14. Daily/regular communications continued.

• Nitrogen purge diagnostics and well flowbacks (to depressure the reservoir) occurred between Apr 14 and Apr 26, 2012.

• Groundwater level responses at REG-11-3 (ML) indicate hydraulic communication between V13-31 casing break and the aquifer (confirmed Apr 26 based on nitrogen diagnostics)

• Well killed by “bullheading” a 1375 kg/m3 CaCl2 solution with a freshwater head across the break on Apr 27

• IOR Cold Lake Incident Response Plan initiated, which includes aquifer delineation, evaluation and remediation (if necessary).

• Estimated 60-100m3 of produced fluids (80:20 produced water:bitumen) was released

• Service rig was moved on well on May 3, 2012 for diagnostics, production casing confirmed failed adjacent to an aquifer (ML/E3).

• Surface casing observed intact, but Log-inject-Log test indicated that surface casing leaked in the 100-107 mKb interval.

• V13-31 legally abandoned in Clearwater & Grand Rapids and recompleted as an aquifer remediation well (96-107 mKb)

V13-31

106


2012

107

V13-31 Root Cause Failure Analysis

Failure Summary• Trapped fluid pocket, initiated at 98.5mKB as indicated by low

quality bond, resulted in collapse of 7” production casing from 107.89-110.56mKB

• Trapped fluid had ability to seep along pipe wall until it reached very high quality bond at 111mKB

• Collapse likely initiated at 110.56mKB and moved upward and collapse stopped at production casing collar located at 107.4mKB

• Surface casing collar at 110.91mKB potential leak path to aquifer • 3 ½ “ tubing damaged from implosion of production casing• 10 ¾” surface casing appears to be intact from camera pictures• Moment of collapse likely occurred as well came off steam • Production casing likely remained intact or only small hole until

N2 purge occurred. Temperature changes from N2 may resulted in collapsed casing failing

• Surface casing began leaking after N2 purge due to temperature changes

Root Cause Summary

• 0.8m of low cement bond (1.8db/ft), partially filled with fluid -Adequate as per hydraulic isolation definition

• Very good bond quality above and below location of poor cement likely reduced trapped fluids ability to leak off as steaming continued and fluid expanded

• Drop in internal 7” casing pressure at end of steam cycle resulted in sufficient differential pressure to collapse production casing

Follow-up

• Review other recently drilled wells for similar bond log response and perform collapse test where observed

7” casing collapsed

into figure 8, tubing was in larger lobe

Surface casing & cement intact

V13-31 Bond Log

Downhole Camera View


2012

108

Gas Migration and Surface Casing Vent Flow Testing

Multiple Objectives• Characterize gas flows behind casing • Develop methods to meet intent of SCVF regulations• Examine potential relationship to BTEX concentrations measured in Groundwater Monitoring wells.

Continue testing program initiated in 2011• Tested 9 mid-cycle pads for GM and SCVF (230 wells)• Tested all 230 wells for GM

• Surface gas testing for methane and H2S concentrations• Gas composition and carbon isotope analysis performed from locations with highest concentrations• Source of GM was mainly biogenic, remainder from Colorado with possible Grand Rapids sources

• Developed temporary packoffs for SCVF testing• Gas rate and pressure buildup from surface casing annulus

• Tested 18 wells with temporary packoffs for SCVF as per ID 2003-01• Non-serious SCVF found on 5/18 wells tested. Gas flows < 1m3/d. No serious SCVF found.• Source of flow primarily Colorado.

2012 Program• Random sampling of 173 additional wells for GM

• Surface gas testing of methane and H2S concentrations with some isotope analyses• Range of operating parameters (cycle, operating status and temperature)

• 12 SC wells selected for pack-off build-up and bubble testing• 5 of 12 SCVF tests completed, analysis ongoing

2012 Interim Findings and Conclusions• Similar gas composition and carbon isotope results to 2011• No indications of serious gas flows: 60% of wells with methane reading >10 ppm, 25% with methane reading > 1000 ppm• Majority (69%) of surface gas is biogenic, near surface source and 28% is Colorado Shale source gas• Some instances of H2S exceeding 10 ppm (< 1% of wells) with limited repeatability, further monitoring and analysis is planned.• Weak correlation between surface gas measurements and operating parameters


2012

109

E07 Pad Testing

Objectives• Test hydraulic isolation in areas with low quality post steam cement bond log

response. • Examine responses from various commercially available logging tools• Select remedial cementing intervals as per current evaluation techniques

and gain ERCB approval for proposed work • Conduct tracer logging on a sample of the intervals• Conduct dual perforation tests on 2 wells in intervals with poor post steam

cement bond response• Feed rate tests on selected remedial intervals.

• Begin examination of potential aquifer crossflow impacts in areas with low quality post steam bond log response.

Testing Completed• Post steam bond logs taken on all 20 wells. Remedial intervals based on poor

post steam bond log response. ( 6-CWT, 4-GRT, 17-CT)• Acoustic cement bond logs run at varying pressures on two wells, also ran

nuclear logging tools (density and porosity)• Boron tracer tests conducted on three wells in the Clearwater, Grand Rapids and

Colorado• Dual perforation tests conducted in the mid- Grand Rapids (27m separation) and

Quaternary (23m separation) on E07-03• Feed rates recorded with water on all remedial intervals (rates and pressures)• Cement placement volumes recorded for all remedial intervals.• Observation water wells drilled on pad to help evaluate groundwater implications

Typical Post Steam Cement Bond Log


2012

110

E07 Pad Testing Test Results• Tracer tests at Clearwater top and Grand Rapids tests show no flow above injection intervals• Upper Colorado tests show low or no feed rates and no tracer movement upwards to the Quaternary• Dual perforation tests in the Grand Rapids show negligible flow capacity behind pipe, despite the

poor post-steam bond logs, even at 24 MPa• Low feed rates and cement volumes have been measured at all remedial intervals to date

• Quaternary dual perforation test shows limited communication between perforations • Aquifer definition and analysis of pressure/composition results initiated from new groundwater wells

Conclusions to Date• Hydraulic isolation at E07 pad is generally good over the intervals tested. Deeper intervals (CW and

GR) show negligible flow capacity behind casing• Quaternary tests indicate some flow behind casing over limited intervals. However, to date, testing

has not detected connection between aquifers• In a post steam environment, currently available logging tools do not reliably reflect the cement

quality or degree of hydraulic isolation behind casing.

• E07 test results are aligned with historical observations at Cold Lake:

• No significant fluid releases confirmed from flow behind pipe on a commercial well

• Many other measurements (ie. temp logs) rarely show anomalous uphole responses

• Remedial cementing experience from post steam log analysis on other pads is similar

Note: Additional work is planned to complete evaluation of uppermost intervals and provide recommendations for final E07 pad abandonment. Recommendation on general Cold Lake repair and abandonment work to follow

Interval

# of intervals tested

Water Feedrate

(l/min)

Feedrate Pressure (% of frac pressure)

Cement Placement

(liters)CWT 6 15 91% 4GRT 4 1 98% 10CT 17 34 93% 75 *

* CT cement results to date 10/17 intervals cemented

Average Results


2012T01 Infill Pad Fluid Losses

T01 Infill Pad Overview

• 6 horizontal well infill pad & 1 Passive Seismic Well

• Well paths offset due to Mahkeses plant • Increased anti-collision risk

• Longer intermediate hole sections 660 – 1030 m

• 5 of 6 wells successfully completed

• 6 intermediate sections successfully completed – 9 attempts• 2 successfully cased with standard practices (H29 &30)

• 4 successfully landed and cemented intermediates in CW shale (H28ST, 27A, 26ST & 25)

• 3 with CW losses preventing successful intermediate cementing (H27, 26 & 28)

• 5 lateral sections successfully completed – 7 attempts• H30 – Lost circulation challenges (H30ST successfully re-drilled)

• H26ST – Lost due to shale instability

• All wells completed in CW shale had some wellbore shale stability issues

111


2012T01 Resistivity Anomaly

112

• As reported to the ERCB a low resistivity anomaly was observed in the lower portion of the Colorado Group at T01-27A and H30 but not at other T01 infills

• Reduced resistivity linked to conductive heating from nearby CSS wells

• Recent investigation revealed similar low resistivity on other infill pads (ex. U01)

• Strong correlation between temperature (>20°C) from temperature logs and anomalously low resistivity

• Intervals showing temperature >20°C and corresponding low resistivity are also in close proximity to offset CSS wells (<30m)

• Infill wells located more distant from the CSS well did not have an anomalous resistivity

• Casing integrity checks will be performed before steaming T01

Infill

Infill

Colorado resistivity anomaly

CSS wells in close proximity to infill wells

Reduced resistivity linked to conductive heating from nearby CSS wells


2012

Facilities


2012

114

Facility Modifications

• Completed liner installation for existing 12” freshwater pipeline from Cold Lake Pump Station to Leming site in August 2012• Extends life of freshwater pipeline• Existing freshwater pipeline maximum operating pressure reduced from Cold Lake Pump Station to Leming

• Completing construction of replacement 1T5008 in 2012• Increases reliability and flexibility by centralizing produced water handling across district• Commissioning in Q4/2012• Existing 1T5008 has been decommissioned since 1991

• Completing the installation of field sulphur recovery at G01 pad• Field deployment supports SO2 emissions control• Commissioning in Q4/2012

• Completing construction of new Brackish Water Pipeline• Existing brackish water pipeline reached end of life• Maintains steam generation and reduces freshwater consumption; upsized to accommodate Nabiye• Construction in progress for 2013 start-up

• Completing fabrication and delivery of Mahkeses HRSG Modules• Replacement of (3) modules for each of the two HRSG’s to maintain integrity of units• Delivery to site Q4/2012 for installation during 2013 plant shutdown


2012

115

Site Interconnects – Bitumen, Blend and Diluent

Hardisty

Edmonton

IPFLacorey

Trim Blend

Trim Blend

EncanaFoster Creek

CNRLWolf Lake

Well Tests

Well Tests

Well Tests

WellTests

Diluent

Blend

Bitumen

Maskwa Battery - 51211

Mahihkan Battery - 51212

Mahkeses

Leming

MahkesesPads

LemingPads

Cold Lake OperationProduct Flow DiagramBitumen, Blend & Diluent

HuskyLloydminster

IPFPipeline

Leming Battery - 1330520

Updated: 2007-03-09

Site Interconnect Estimated Capacity: Emulsion

• Leming to Mahkeses 5,400 m3/d

• Mahkeses to Leming 6,000 m3/d


2012

116

Site Interconnects – Steam & Water

Site Interconnect Estimated Capacity: Steam

• Maskwa to Mahihkan 15,000 m3/d

• Mahihkan to Maskwa 14,000 m3/d

• Leming to Mahkeses 9,200 m3/d

• Mahkeses to Leming 6,000 m3/d

Site Interconnect Estimated Capacity: Produced Water

• Maskwa to Mahihkan 7,000 m3/d

• Mahihkan to Maskwa 3,500 m3/d

• Leming to Maskwa 6,000 m3/d

• Mahkeses to Maskwa 15,000 m3/d


2012CLO Process Overview

117


2012Process Flow Schematics

118



119



120



121



122



123



124



125


2012Facility Performance

126

Bitumen Treatment and Vapour Recovery

• Bitumen production remained within ERCB inlet license limits over reporting period

• Issues & Limitations• None

• Major Downtime• Mahihkan Plant 4 planned regulatory inspection of steam header, included hot lime softener

cleanout – 10 days: June/12 • Maskwa Plant shutdown, including planned regulatory inspections - 45 days: Sep - Oct/12

• Major Equipment Failures• None

• Vapour Recovery Performance - approximately 99.7% produced gas recovery Oct/11 to Sept/12• Recent activities to improve venting performance:

• Continued use of Forward Looking Infra-red (FLIR) camera• Stock-Tank Vapour Recovery (STVR) venting study progressed

ERCB Inlet License Maskwa Mahihkan Leming Mahkeses

Bitumen License (m3/d) 11,000 15,000 5,000 8,000

Actual Oct/11 – Sep/12 (m3/d monthly avg) 6,341 11,500 1,491 5,395



Water Treatment

• Water production remained within ERCB inlet license limits over reporting period

• Issues & Limitations• Continued focus on improving treated water transfer from Maskwa to Leming• Evaluating opportunities to increase produced water transfer from Mahihkan to Maskwa• Self-disclosure to ERCB that Scheme requirement for minimum 95% produced water

recycle will not be met for 2012 (July 26, 2012)• Evaluating increased throughput at Mahihkan and Maskwa in response to higher watercut

from late cycle wells

• Major Downtime• Maskwa Plant shutdown – 45 days (Sep-Oct/12), cleaning and inspection of 1 HLS unit

• Major Equipment Failures• None

127

ERCB Inlet License Maskwa Mahihkan Leming Mahkeses

Water License (m3/d) 38,000 41,000 13,500 22,000

Actual Oct/11 – Sep/12 (m3/d monthly avg) 27,143 33,120 8,546 17,917



Steam Generation

• Issues & Limitations• Steam quality is measured at plant outlets only

• Major Downtime • Mahkeses HRSG planned inspection – 15 days: Apr 2012• Maskwa Plant shutdown, planned inspection - 45 days:

Sep – Oct 2012

• Major Equipment Failures None

128

2006 2007 2008 2009 2010 2011 2012 YTD91,609 90,203 88,022 83,524 88,967 92,132 91,051

Cold Lake District HP Steam Generation (m3/d)



Electrical Power Generation and Consumption

• Mahkeses plant has two gas turbine electrical power generators within a co-generation steam plant that generates power for the district and exports power to the Alberta power grid

• Power is imported from the Alberta power grid when consumption exceeds generation

• Issues & Limitations

None

• Major Downtime

• Mahkeses Gas Turbine Generator planned inspection – 26 days: June 2011

• Mahkeses Gas Turbine Generator planned inspection – 15 days: April 2012

• Major Equipment Failures

None

129



Produced Gas Management

• All recovered produced gas used as fuel for high pressure steam generation

• Purchased sweet gas is used for steam generation (high and low pressure) and heater operation

• Issues and Limitations

None

• Major Downtime

As per bitumen and water summaries

• Major Equipment Failures

None

130


2012

Measurement and Reporting


2012Measurement & Reporting

• There were zero compliance issues with volume reporting for CLO in Q4 2011 & 2012 YTD

• Obtained exception approval from ERCB for Sections 10 and 12.4.4 of Directive 017 Measurement Requirements for Oil and Gas Operations (June 6, 2012)

• Section 10 Trucked Liquid Measurement - Exempt fluid truck volume reporting for all loads moved within Cold Lake Operations (e.g. load fluids moved inter-site, or plant to well site, etc.)

• Section 12.4.4 Steam Measurement - Allow IOR to use non-destructive radiographic testing instead of visual testing to perform inspection of primary steam measurement elements

• New edition of Directive 017 issued September 11, 2012• IOR intends to meet requirements of Section 12.3.6 (Water/Steam Primary & Secondary

Measurement) of new edition• List of primary meters for produced water measurement at all plants• Provision(s) which allow each produced water meter to be promptly inspected and

maintained/repaired when necessary • Secondary measurement device(s) for each produced water meter whose metering

system does not allow for prompt inspection and maintenance/repair

132


2012Proration Factors

133

• Revised Proration factor tolerance range for produced oil and water from 0.75/1.25 to 0.85/1.15 effective April 1, 2012

• Facility proration factors reviewed daily at Production Review meetings with Field, Plant, Well Servicing, Maintenance, Management representatives

• Monthly proration factors documented, reviewed, and approved with action plans assigned and stewarded for deviations

• Improvements in proration factors realized in recent months through focused approach above

Profacs which are over Deviation LimitBattery Code (1330520) Oct Nov Dec Jan Feb Mar Apr May June July Aug Sep AVG

LEMING OIL 0.85-1.15% 1.21 1.02 1.10 1.06 0.97 1.22 1.07 1.21 1.19 1.17 1.00 1.11 1.10

WATER 0.85-1.15% 1.41 1.21 1.23 1.32 1.22 1.19 1.19 1.04 1.02 1.02 0.88 0.98 1.13

GAS 1.18 1.20 1.15 1.25 1.15 1.26 1.13 1.08 1.05 1.06 1.00 0.95 1.11

Oct Nov Dec Jan Feb Mar Apr May June July Aug Sep AVG

Leming Steam Inj IF:0007678 STEAM 0.82 0.78 0.72 0.75 0.80 0.81 0.84 0.83 0.89 0.90 0.86 0.84 0.82

Lower Limit Lower Limit 85% 85% 85% 85% 85% 85% 85% 85% 85% 85%

Battery Code (0111783) Oct Nov Dec Jan Feb Mar Apr May June July Aug Sep AVG

MAHKESES OIL 0.85-1.15% 0.81 0.84 0.86 0.88 0.73 0.87 0.91 0.91 0.86 0.87 1.00 0.84 0.87

WATER 0.85-1.15% 1.14 1.22 1.23 1.25 1.34 1.24 1.16 1.13 1.09 1.14 1.11 1.11 1.17

GAS 0.72 0.77 0.84 0.80 0.72 0.81 0.89 0.89 0.89 0.90 1.06 0.95 0.86

Mahkeses Steam Inj Oct Nov Dec Jan Feb Mar Apr May June July Aug Sep AVG

IF:0111784 STEAM 0.90 0.93 0.96 0.97 0.93 0.93 0.99 1.01 0.95 0.96 1.01 1.03 0.98

Upper Limit Upper Limit 1.15 1.15 1.15 1.15 1.15 1.15 1.15 1.15 1.15

Lower Limit Lower Limit 85% 85% 85% 85% 85% 85% 85% 85% 85%


MASKWA OIL 0.85-1.15% 0.79 0.78 0.77 0.87 0.91 0.90 0.96 0.90 0.86 0.86 0.88 0.85 0.86

WATER 0.85-1.15% 1.25 1.27 1.18 1.24 1.27 1.34 1.21 1.12 1.00 1.07 1.06 1.01 1.15

GAS 0.71 0.74 0.71 0.79 0.83 0.93 0.95 0.88 0.78 0.78 0.77 0.72 0.79

Maskwa Steam Inj Oct Nov Dec Jan Feb Mar Apr May June July Aug Sep AVG

IF:0000797 STEAM 1.06 0.89 0.94 1.00 0.96 0.98 1.07 1.03 1.01 1.03 1.01 0.97 1.01

Upper Limit Upper Limit 1.15 1.15 1.15 1.15 1.15 1.15 1.15 1.15 1.15

Lower Limit Lower Limit 85% 85% 85% 85% 85% 85% 85% 85% 85%


MAHIHKAN OIL 0.85-1.15% 0.87 0.94 0.93 0.92 0.94 0.92 0.82 0.87 0.86 0.89 0.87 0.92 0.89

WATER 0.85-1.15% 1.01 0.98 0.93 0.85 0.85 0.90 0.94 0.96 0.89 0.86 0.93 0.95 0.93

GAS 0.76 0.75 0.84 0.89 0.90 0.80 0.75 0.78 0.80 0.80 0.82 0.85 0.83

Mahihkan Steam Inj Oct Nov Dec Jan Feb Mar Apr May June July Aug Sep AVG

IF:0008798 STEAM 1.05 1.02 1.03 1.05 0.97 0.97 0.98 0.96 0.98 0.98 0.94 0.94 0.99Upper Limit Upper Limit 1.15 1.15 1.15 1.15 1.15 1.15 1.15 1.15 1.15Lower Limit Lower Limit 85% 85% 85% 85% 85% 85% 85% 85% 85%

SaltWater Disposal Steam Inj Oct Nov Dec Jan Feb Mar Apr May June July Aug Sep AVG

IF:00008036 STEAM 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00

2011 2012


2012Sulphur Measurement & Reporting

134

Sulphur (H2S) Sampling Process• Manual gas samples taken on a weekly basis to monitor H2S concentration• Additional gas samples may be taken if increased frequency is desired (e.g.

approaching licence limits and/or increased variability in samples expected or performance control improvements)

• Sulphur measurement process accuracy is within the requirements of ID 2001-03 for reporting (+/- 0.1 tonnes S and +/- 0.1 km3 gas)

• Sulphur emissions are documented on a daily basis and monitored against the quarterly limits for each plant

Gas sample locations

Maskwa plant Inlet gas P1 & P3

Mahihkan plant Inlet gas P2 & P4, P4 SRU inlet and outlet

Leming plant Inlet gas

Mahkeses plant Inlet gas, SRU inlet and outlet, combined gas


2012

Water Sources and Use


2012Cold Lake Water Use

136

0.0

0.5

1.0

1.5

2.0

2.5

3.0

3.5

4.0

4.5

5.0

19

75

19

76

19

77

19

78

19

79

19

80

19

81

19

82

19

83

19

84

19

85

19

86

19

87

19

88

19

89

19

90

19

91

19

92

19

93

19

94

19

95

19

96

19

97

19

98

19

99

20

00

20

01

20

02

20

03

20

04

20

05

20

06

20

07

20

08

20

09

20

10

20

11

20

12

m3

Fre

sh W

ater

pe

r m

3 B

itu

men

Fresh Water Use per Unit of Bitumen Produced

Annual 5 yr Rolling Avg

Leming Pilot

CLPP1-6

CLPP7-8

CLPP9-10

CLPP11-13

2012 Forecast YE

80%

85%

90%

95%

100%

105%

110%

115%

1990

1991

1992

1993

1994

1995

1996

1997

1998

1999

2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

2010

2011

2012

Re

cycl

e %

Percentage of Produced Water Recycled for Steam Generation

Annual 5 yr Rolling Avg

ERCB Produced Water Recycle % = Steam Injected - Cold Lake Water - Ground WaterProduced Water

2012 Forecast YE


2012Cold Lake Water Use (cont’d)

137

Water Conservation & Improvements• Early 90’s developed capability to utilize

brackish water to supplement produced water• Inter-site produced water transfer systems

reduce make-up water requirements and limit disposal of produced water

• Mahkeses freshwater consumption significantly lower than other plants (~100 m3/d); Nabiye will be similar

• Treated water transferred from Maskwa to Leming reduces freshwater usage

• Brackish water deliverability not an issue to date• All plants use treated boiler feed water

(produced water) as the source for blending with acid for WAC regeneration

• Inter-site steam transfer provide additional water use flexibility

• Progressing fresh water reduction initiatives which will reduce freshwater consumption on site by 30% by 2014

Cold Lake Fresh Water Uses:

• Leming HP steam boiler feed water

• Leming Plant production inlet cooling

• Domestic use and safety showers/eyewashes

• Utility boiler feed water for low-pressure steam

• Utility water, sample cooling, heat tracing

• Flush and seal water for pump seals and compressors

• Water treatment processes

• Field and well activities

• Emergency firewater

Cold Lake Operations Water Management Strategy

• Maximize produced water recycling

• Minimize the need for non-saline water, by first using produced water and brackish water resources within existing plant equipment capability

• Use the non-saline groundwater withdrawal license for Cold Lake water system maintenance or as a contingency source in the event of lower water levels in Cold Lake



138

• Produced water and Brackish water both contain TDS (Total Dissolved Solids) or salt

• Produced water contains silica (requires Mg treatment)

• Natural waters do not contain silica

• Produced water contains tannin (helps mitigate Caustic Stress Corrosion Cracking)

• Natural waters, i.e. BW, FW, GW, contain no tannin

• Produced water pH is a function of CO2

• Natural waters have much higher levels of magnesium

Parameter Produced Water Brackish Water Cold Lake Water Ground Water

pH ~6 to 7.5 ~7.5 ~7.5 ~8

Ca as CaCO3 150 - 300 ppm 85 ppm 90 ppm 200 ppm

Mg as CaCO3 5–25 ppm 95 ppm 40 ppm 150 ppm

Total Hardness as CaCO3 155–325 ppm 180 ppm 130 ppm 350 ppm

Alkalinity “M”

Alkalinity “TIC”

450 ppm

300 ppm

1000 ppm

1000 ppm

150 ppm

150 ppm

550 ppm

550 ppm

Silica 150–350 ppm < 10 ppm < 5 ppm < 15 ppm

Chloride 5000–8000 ppm 4000 ppm < 5 ppm < 20 ppm

TDS ~12000 ppm ~7000 ppm ~300 ppm ~800 ppm

Tannin 100–200 ppm 0 ppm 0 ppm 0 ppm

Dissolved Gases CH4, CO2, H2S CH4, CO2 Dissolved Oxygen CO2

Well ID UWI Regulatory Name

Brackish water (1-05-65-02-W4M)

BRAK1CLD 1F1010506502W 400 BRAKISH WATER WELL #1

BRAK2CLD 1F2010506502W 400 BRAKISH WATER WELL #2

BRAK3CLD 1F3010506502W 400 IMP MARIE 3 COLDLK 1-5-65-2

Groundwater (5-22-65-04-W4M) – License 00148301-00-00

FW1-1 CLD 1F1052206504W 400 ESSO FW E1-1 COLD LAKE WW 5-22-65-4

FW1-2 CLD 1F3052206504W 400 ESSO FW E1-2 COLD LAKE WW 5-22-65-4

Cold Lake water (14-02-65-02-W4M) – License 00079923-00-00

LEMFWCLD 1L1140206502W 400 COLD LAKE FRESH WATER SOURCE

Brackish and Fresh water well summary:

Water properties summary:



139

Fresh Water Use & Produced Water Recycle in 2012

• Lower PW recycle due to increasing water-steam ratio due to maturing reservoir leading to excess produced water

• Ground water was used between Oct/11 through Aug/12 while project was executed to internally line a portion of the Cold Lake water pipeline – project completed Aug/12

• Produced water recycle improvements in 2012• Continued focus on treated water processing and transfer from Maskwa to Leming to offset Leming freshwater

consumption• Proceeding with prioritized list of district freshwater reduction projects

• Self-disclosed to ERCB that Scheme requirement for minimum 95% produced water recycle will not be met for 2012 (July 26, 2012)

2011 Produced Water RecycleMonthly Cumulative

Jan 96.5% 96.5%Feb 96.8% 96.6%Mar 96.2% 96.5%Apr 93.7% 95.8%May 95.7% 95.8%Jun 92.8% 95.3%Jul 90.5% 94.5%Aug 84.1% 93.1%Sep 84.2% 92.0%Oct 85.9% 91.4%Nov 84.1% 90.7%Dec 85.2% 90.2%YE 90.2% 90.2%

2012 Produced Water RecycleMonthly Cumulative

Jan 85.2% 85.2%Feb 86.3% 85.7%Mar 84.1% 85.2%Apr 86.8% 85.6%May 90.9% 86.6%Jun 92.9% 87.6%Jul 93.1% 88.4%Aug 92.7% 89.0%Sep 94.8% 89.5%Oct* 84.1% 89.0%Nov* 86.7% 88.8%Dec* 87.1% 88.6%YE* 88.6% 88.6%*Forecast

0

2000

4000

6000

8000

10000

12000

Jan‐11

Feb‐11

Mar‐11

Apr‐11

May‐11

Jun‐11

Jul‐1

1Au

g‐11

Sep‐11

Oct‐11

Nov‐11

Dec‐11

Jan‐12

Feb‐12

Mar‐12

Apr‐12

May‐12

Jun‐12

Jul‐1

2Au

g‐12

Sep‐12

Oct‐12

Nov‐12

Dec‐12

Mon

thly Avg. m

3/d

District Fresh Water and Brackish Water

Cold Lake Water Ground Water Brackish Water2012 Forecast YE



140

Freshwater Reduction Initiatives

• Freshwater reduction initiatives aligned with Alberta ESRD Water Act renewal commitments

• Initiatives focused on existing operation

• 2012 initiatives:

• Sustain or increase produced treated water transfer from Maskwa to Leming

• Execute 2012 activities and scoping of 2013 activities on-going:

• Initiated surveillance for all items

Freshwater Reduction Item Timing Expected Volume (m3/d)

Current Status

Utility steam condensate capture to HLS clean backwash compartment (Maskwa & Leming)

4Q12/ 1Q13

400 Commissioning expected 4Q12/1Q13; weekly surveillance in place

Truck loading facility upgrades at Mah/Mas

4Q12 300 Maskwa operational; Mahihkan upgrades to be commissioned 4Q12; weekly surveillance in place

Use of produced water for seal cooling in vapor recovery compressors at P1-P4 & Leming

4Q12/ 4Q13

1400 P1-P3 commissioned; Leming commissioning expected 4Q12; Mahihkan in scoping & detailed design; weekly surveillance in place

Maskwa chemical slurry tank dilution water change from FW to supernatant

4Q12 180 System operational; weekly surveillance in place

Reduce Maskwa HLS feedwater piping pressure drop by removing unused flowmeters/installing bypasses

TBD 300 Not complete; project postponed to pursue larger FW reduction opportunities


2012

Water Disposal and Waste Management


2012Produced Water Disposal to Cambrian – Approval 4510

142

Monthly Injection Volumes and Average Wellhead Injection Pressures

WELL Disposal NOVEMBER DECEMBER JANUARY FEBRUARY MARCH APRIL MAY JUNE JULY AUGUST SEPTEMBERIDENTIFIER Zone (KPA) (m3) (KPA) (m3) (KPA) (m3) (KPA) (m3) (KPA) (m3) (KPA) (m3) (KPA) (m3) (KPA) (m3) (KPA) (m3) (KPA) (m3) (KPA) (m3)

00 01 19 064 03 4 00 (SWDFT701) Cambrian 12.0 49,649 12.1 52,183 12.2 51,011 12.2 49,409 11.9 56,547 12.0 52,460 12.1 56,482 12.0 53,962 12.2 53,963 12.2 52,347 12.1 13,610

00 01 32 064 03 4 00 (SWDFT702) Cambrian 12.7 50,514 12.2 51,448 13.1 51,817 12.9 47,973 13.2 53,666 13.2 46,789 13.2 53,007 13.2 52,159 13.1 52,001 13.1 51,999 13.0 12,816

02 02 03 064 03 4 00 (SWDFT703) Cambrian 12.1 36,840 12.1 36,558 12.6 36,112 12.4 33,986 12.5 34,358 12.3 26,126 12.3 34,079 12.5 32,757 12.4 32,619 12.5 32,389 12.4 8,006

00 03 04 065 03 4 00 Abandoned Cambrian





00 07 18 064 03 4 00 (SWDFT705) Cambrian 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0


TOTAL DISPOSAL (m3) 137,002 140,189 138,941 131,368 144,571 125,375 143,568 138,878 138,584 136,735 34,432DAILY AVERAGE(m 3) 4,567 4,522 4,482 4,530 4,664 4,179 4,631 4,629 4,470 4,411 1,148

Monthly Injection Volumes and Average Wellhead Injection Pressures

2011 2012

• Water disposal required due to high field produced water levels (high water to steam ratios)

• Efforts to improve water recycle include reduced fresh water usage, improved steam generation and water reuse service factors, and improved water inter-plant transfer capability

• See Facilities Performance Section for additional details


2012Cold Lake Waste Management

143

Volumes (m3)On-Site Disposal 2011 2012 (End of Q3)

Class III Waste Volumes (industrial garbage) 10,734 8,778

Class II Lime Sludge 63,622* 29,739*

Class II Oily Wastes (non-DOW) 31,057** 2,224**

Landfill Leachate Collection and Recycle at Mahkeses Plant 31,897 15,435

* Annual volume of lime sludge disposed depends on timing of pond cleaning. Lime sludge generation does not significantly differ from year to year.** Oily waste generation is dependent on amount of abandonment and reclamation work undertaken each year

Off-Site Disposal 2011 2012 (End of Q3)

Solid Wastes (asbestos, batteries, oily rags, soils) 8,850 m³ 1,965 m³

Liquid Wastes (lube-oil, paint, etc.) 4,212 m³ 2,252 m³

Recycled steel 0 t 1438 t

Note: All off-site disposal wastes manifested as per Directive 58 requirements


2012Cold Lake Waste Management

144

C-203L (constructed in 2008,

operational)

Scrap metal (operational)

C-313L (to be

capped in 2013)

C-101L (capped)

C-102L (capped)

C-202L (to be capped

in 2013)

C-103L (capped)

C-201L (capped)

Future Landfill Development• Closure of class II cell C-202L and class III C-313L • Long term waste strategy being developed to evaluate future waste disposal options


2012

Environmental Summary


2012Approval Renewals and Amendments

Approvals under the Environmental Protection and Enhancement Act (EPEA)• Received EPEA Renewal in March 2011 (Approval No. 73534-01-00)• Existing EPEA Approval 73534-00-04 (as amended) is cancelled • Will be submitting an EPEA amendment application to add a line heater and adjoining pressure letdown station at Mahihkan Plant (Q4 2012)

Approvals under the Water Act• Received Cold Lake Water Act license renewal for surface water diversion in October 2011 (Approval No. 79923-01-00)• Received Water Act license renewal for back-up groundwater wells in October 2011 (Approval No. 148301-01-00)

146


2012Monitoring Programs – Wildlife

Relevant data are submitted electronically to the Fisheries and Wildlife Information System (FWMIS) and supplement existing provincial records

Wildlife Monitoring and Mitigation Plan and Caribou Mitigation and Monitoring Plan have been submitted to the Director as per EPEA approval for Cold Lake Operations for review and authorization

Cold Lake Operations made a financial contribution to the Alberta Biodiversity Monitoring Institute (ABMI) to support a regional approach to biomonitoring

147


2012

• T18 GEW 12-1 (ML)• F08 GEW 11-9 (E1)• L05 GEW 11-2 (E1)• L05 11-3 (E1)• L05 11-4 (CS)• Y32 GEW 11-5 (ML)• H68 GEW 11-1 (BNV)• H11 GEW 11-7 (E1)• V13 GEW 12-5 (E3)• V13 GEW 12-6 (E3)

• V13 GEW 12-7 (E3)• V13 GEW 12-8 (E3)• V13 GEW 12-9 (E3)• V13 GEW 12-10 (E3)• E07 GEW 12-2 (EL)• E07 GEW 12-3 (BNV)• E07 GEW 12-4 (ML)

GEW Drill LocationsV13

Monitoring Programs – Groundwater

Currently monitoring approximately 400 deep groundwater wells and over 350 shallow groundwater wells, including domestic wells:

Monitoring includes both chemistry and water levels

2011/2012 Regional drilling program: T14 Regionals 11-4 (ML, CS, BNV, EL. E1, E3,WT,SR) T15 Regionals 11-2 (BNV, WT, ML, E3) V13 Regionals 11-3 (ML, BNV, WT) V12 South Mahkeses (tentatively planned) Winter 2012

Wells abandoned (2011/2012 to-date): None

Groundwater Evaluation Wells (GEW) Drilled (2011/2012 to-date):

L05

H11

Y32

H68

F08

T18

E07

148

Developed Pads


2012Bitumen In Shale Code of Practice Update

149

Groundwater Well Requirements

The management practice describes two principal activities designed to investigate the potential impact to groundwater aquifers due to B-I-S occurrences:

• Install and monitor groundwater evaluation well(s) downgradient of observed locations of B-I-S B-I-S Management Practices – Procedure #2. Development and implementation of a delineation program within 2 months of the detection date, or such later date as the Board may approved, to investigate and define the extent of the incident. This includes groundwater evaluation well(s) (GEW) drilled downgradientfrom the observed bitumen show location and Colorado Shales evaluation well(s) (CEW) drilled to 20 m below the depth of the source but perforated at the source depth as a pressure monitoring well.

• Install and monitor a groundwater well at all new productivity maintenance pads B-I-S Management Practices – Procedure #8. A groundwater monitoring well will be drilled into the lower most Quaternary aquifer at each new pad, prior to commencement of steam injection, to monitoring groundwater quality and aquifer pressure (head) on a periodic basis.

Performance under B-I-S Code of Practice

• 3 groundwater wells installed at new pads in 2011 (H68, Y32, F08)

• 2 groundwater wells installed at new pads in 2012 YTD (T18, V13)

• All groundwater wells drilled under the B-I-S code of practice are included in the Cold Lake deep groundwater monitoring program

No Bitumen In Shale (B-I-S) events in 2011 or YTD (September 30, 2012)


2012Monitoring Programs – Arsenic

150

Key Regulatory Review and Public Consultation Dates

• Submission of Technical Update Report to ERCB and AENV Dec, 2009• Technical Report Review with AENV and ERCB Jul, 2010• 2011 Cold Lake Operations Neighbor Night Nov 15, 2011• 2011 Annual Performance Review with ERCB Nov 23-24, 2011 • 2012 Annual GW review meeting with ESRD Jul 9, 2012• 2012 Cold Lake Operations Neighbor Night Nov 14, 2012• 2012 Annual Performance Review with ERCB Nov 28-29, 2012

Technical Update

• In 2006, Health Canada lowered the maximum acceptable concentration for arsenic in drinking water from 25 µg/L to 10 µg/L.

• Using this standard, 50% of domestic wells in the Lakeland area have naturally high arsenic concentrations above guidelines. (Alberta Health andWellness Data: Arsenic in Groundwater from Domestic Wells in Three Areas of Northern Alberta, October, 2000).

• In 2010, Imperial conducted a review of arsenic in its regional groundwater wells and reconfirmed that arsenic concentrations are similar to the AHW(2000) study and do not display increasing trends over time. Imperial will repeat this study as part of its 2013 Deep Groundwater Report to ESRD.

• Imperial continues to monitor thermally mobilized arsenic at D55, D57, and L08 Pad.

• Field observations confirm that heat convection cells play a significant role in the release and transport of arsenic when the GW velocity is low.

• Laboratory experiments indicate that arsenic released by conductive heating is re-adsorbed when the GW is exposed to unheated sediments.

• Field study results to date indicate that peak arsenic concentrations and arsenic mass at D55 and D57 pads have declined as the arsenic plumes migrate down gradient. The average velocity of the dissolved arsenic is retarded relative to GW flow velocity. These observations are an indication that arsenic attenuates as it moves downgradient.

• Additional downgradient monitoring wells are positioned to further examine the rate and extent of attenuation. These remain as key objectives ofongoing work.

• Because groundwater moves very slowly and requires a long time to move even short distances, the field study will continue for many years.Imperial has an AEPEA requirement to complete an additional technical update report in 2015.

• Imperial has an extensive groundwater monitoring program to aid in the detection of mobilized arsenic. Based on groundwater monitoring to date,there is no evidence that any released arsenic has impacted any domestic or stock groundwater wells.

A comparison of arsenic concentrations in wells tested by Alberta Health and Wellness (2000) and wells in Imperial’s Regional Groundwater Monitoring Network (2010)


2012Monitoring Programs – Surface Water

• Comprises the following components:

• Surface Water Quality Sampling (Regional, Infield, wetlands)

• Annual Drainage Assessment

• Level Monitoring (Lake, creeks, wetland piezometers)

• Long-term Wetland Monitoring Plots

151


2012Monitoring Programs – Surface Water

• Spring and fall sampling of water bodies (routine water quality parameters (pH, alkalinity, hardness etc), major cations and anions, forms of nitrogen, phosphorous, hydrocarbons, and trace elements)

• Flow measurements at selected creek sites

• Depth composite samples from canoe for both regional and infield lakes where depths are greater than 2 metres

• In 2011, sediment samples were taken at five pre-determined locations in the Marie Creek Watershed (on a 5-year rotating schedule)

• Biomonitoring (zooplankton & benthic invertebrates) of regional lakes on a rotational basis (biomonitoring conducted in Bourque Lake and May Lake in 2012)

• Results to date do not indicate any significant impact or apparent trends from Cold Lake Operations on the regional surface water quality

152

Marie Creek Upstream of Nabiye Stream Crossing – Spring 2011

Marie Creek Upstream of Nabiye Stream Crossing – Fall 2011


2012

Monitoring Programs – Surface Water Regional

153

• Regional Program included spring and fall sampling at 25 sites

• Includes sites within the Jackfish Creek, Marie Creek, & Medley River Watersheds:

Data from this program is shared with BRWA, ALMS and MLAWS, as well as some landowners.

Regional Program

B1Unnamed Creek upstream of Bourque Lake

Stream

B1a Unnamed Creek upsteam of B1 Stream

B2-N Bourque Lake (North Basin) Lake

B2-S Bourque Lake (South Basin) Lake

B3Jackfish Creek downstream of Bourque Lake

Stream

B4Jackfish Creek downstream of Mahihkan Plant

Stream

B5 Unnamed Tributary #4 Stream

B6 Unnamed Tributary #5 Stream

LM1 Hilda Lake Lake

LM2 Ethel Lake Lake

LM3 Marie Creek downstream at Hwy 897 Stream

M1 Marie Creek inlet to May Lake Stream

M2 May Lake Lake

M3 Marie Creek outlet of May Lake Stream

M4 Marie Creek inlet to Marie Lake Stream

M5 Unnamed Tributary #1 Stream


M7 Marie Lake Lake

M8a Marie Creek outlet of Marie Lake Stream

M8b Marie Creek inlet to Ethel Lake Stream

M8c Marie Creek near Nabiye field Stream

M9 Medley River Stream


M11A Upstream of Marie Creek Bridge Stream

M11B Downstream of Marie Creek Bridge Stream


2012

Monitoring Programs – Surface WaterRegional Cont’d

154

Chemistry Observed in the Regional Program

• Generally, pH, turbidity, DO, phenols, iron & manganese (total) fell outside of the guideline values (normal for area).

• Concentrations of dissolved metals (bioavailable form) are typically low at all monitoring sites.

Consultant (AMEC) Conclusion:

• Overall, water levels for streams and lakes during 2011 were higher than previous years in all watersheds.

• The water quality in 2011 for the streams and lakes surveyed were generally similar to the water quality observed in previous years of the monitoring program.

• The results presented in this report do not suggest any significant impact from human activities on the aquatic environment of the lakes and streams selected for this monitoring.


2012

Monitoring Programs – Surface Water Infield

155

Infield Program

Bufflehead Pond Bufflehead PondPond

D53 Pond D53 PondPond

Fire Training Pond Fire Training PondPond

H31 Pond H31 PondPond

H38 SW Pond H38 SW PondPond

H58/59 Access Road Pond H58/59 Access Road PondPond

Lake C Lake CLake

Lake F6 Lake F6Lake

LEEB Slough LEEB SloughSlough

Leming Lake Leming Lake Lake

Lower E Wetlands Lower E WetlandsWetland

MAH W Wetlands MAH W WetlandsWetland

May Ethel Creek 1 (DS) May Ethel Creek 1 (DS)Creek

May Ethel Creek 2 (US) May Ethel Creek 2 (US)Creek

McDougall Lake McDougall Lake Lake

T Pad Pond T Pad PondPond

Y34 Pond Y34 PondPond

Infield Surface Water:• 18 Sites sampled bi-annually for field parameters, total and dissolved metals, nutrients and

hydrocarbons

• Generally, the 2011 results were within the range of historical results and parameters of concern, such as Chlorides, were well below Surface Water Quality Guidelines.


2012

Monitoring Programs – Surface Water Drainage

156

• Completed on an annual basis since 2002

• Assessments entail a qualitative examination of drainage impediments, vegetation stress, rutting, erosion, and/or sedimentation

• A total of 101 sites were assessed in 2012: Leming Field (12),

Mahkeses Field (24),

Mahihkan Field (39); and

Maskwa Field (26).

• The sites are ranked as high, medium/high, medium, low and for information only and sites are compared year after year to assess improvements

• High and medium/high sites are addressed to prevent further impacts

Examples of drainage assessment study sites

Example of culvert assessment study site


2012

Monitoring Programs – Surface Water Drainage cont’d

157

• Area wide assessment of culverts commenced in 2006 and was completed for Leming, Mahkeses and Maskwa Fields in 2012

• Mahahikan Field is proposed for assessment in 2013

• All dyke drains were capped in fall 2009 and complete removal started in 2010 and was completed in 2012

Example of capped dyke drain


2012

Monitoring Programs – Surface Water Wetland Level Monitoring

158

• In 2011, piezometers were sampled 3 times during the open water season (May to October).

• Level monitoring was conducted once per month during the open water season

• Program continued in 2012 and will continue into the future with an expansion planned for the Nabiye area. In 2011 staff gauges were placed in the Grand Coulee Crossing along the Nabiye Main Trunk Road to begin wetland level monitoring. Two more staff gauges are planned for the Nabiye South Fen Crossing by year-end 2012.

2011 Water Levels at the U07/U08 Wetland Piezometers


2012

Monitoring Programs – Surface WaterLong-term Wetland Monitoring Plots

159

• Established in August 2006, as per EPEA 73534-00-04 Section 4.9.2a

• Purpose: Monitor long-term effects of groundwater withdrawals on wetland health, extent and distribution Establishment of 11 plots Baseline data collection

• Ongoing monitoring program Conducted every 5 years (last completed in 2010, next survey will be completed in 2015)

• The 2010 program focused on vegetation data and aerial photo interpretation and aligned with false color infrared survey (FCIR)

• 100 m2 plots for vegetation cover used in the 2006 program were replicated in 2010- 2010 program established 1 m2 subplots

• Based on aerial photos and vegetation data collected, vegetation stress was not identified in any of the 11 plots

• Vegetation stress was identified in proximity to 3 plots and appears to be from beaver activity adjacent to the plots

• 2013 will see the addition of paired piezometers associated with each wetland monitoring plot


2012Monitoring Programs – Vegetation

160

Overview

• In 2006 a long-term vegetation monitoring program was established, per the commitments made in Section 9, Subject 10 of the IOR Nabiye and Mahihkan North EIA

• The monitoring program was revised and improved in 2009

• The extent of the program is expected to increase as monitoring plots are identified and established in the Nabiye Operating Area

Pitcher Plant (Sarracenia purpurea)

2011 Monitoring Results:• 6 of the 14 sensitive species recommended for

monitoring were observed during the summer rare plant survey

• Northern bur-reed (Sparganium hyperboreum)• Tall blue lettuce (Lactuca biennis )• Pitcher plant (Sarracenia purpurea)• Beaked sedge (Carex rostrata Marsh)• Crested shield fern (Dryopteris cristata)• Umbellate sedge (Carex umbellate)

• Overall results from the monitoring indicate that known rare plant populations within CLO are persisting over time


2012

Monitoring Programs – Air Leak Detection and Repair

161

Overview Leak Detection and Repair (LDAR) program is implemented to detect unintentional hydrocarbon

emissions (seals, valves, flanges, etc.)

These emissions arise from issues such as normal wear and tear, corrosion, damage, environmental effects

The LDAR program is focused on components in sweet hydrocarbon service, particularly stock tank vapour recovery systems and vent gas compressors and piping

IOR has purchased a FLIR GasFindIR HSX camera and trained operations and environmental staff in its use. The camera will be utilized to monitor for gas leaks on tanks and equipment in the district

2012 Progress Consultant was on-site with leak finder camera and gas flow sampler in August/September 2012 Tested Mahkeses and Leming plant and sample of field pads (older and newer pads) Plan to test 1/3 of operations every year. Mahihkan plant and field is scheduled for surveying in 2013

Year Area Tested Approximate # of Sample Points # of Leaking Points Leak Rate

2007 Mahihkan Plant and sample of field (older and newer pads) 8,875 12 0.14%

2008 Maskwa Plant and sample of field (older and newer pads) 25,824 12 0.05%

2009 Mahkeses and Leming Plants and sample of field (older and newer pads) 8,700 4 0.05%

2010 Mahihkan Plant and sample of field (older and newer pads) 8,250 3 0.04%

2011 Maskwa Plant and sample of field (older and newer pads) 6250 10 0.16%


2012

Monitoring Programs – Air Flare and Vent

162

Historical Annual Averages

38.7 39.0

13.6

3.3 3.7 2.8 3.42.4 1.8 2.2 1.6

4.15.1 5.1

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Average Flare and Vent Volumes (10³m³/day)


2012

Monitoring Programs – Air Flare and Vent cont’d

163

2012 Flaring events:

January

Mahihkan plant boiler trip (74.7 km³)

Maskwa plant shutdown for maintenance (16.6 km³)

May

Mahihkan planned shutdown for maintenance (109.9 km³)

June

Mahihkan plant startup flaring (35.5 km³)

Maskwa plant upset (34.6 km³)

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2012

Monitoring Programs – Air GHG Emissions

164

As reported to Alberta Environment under the Specified Gas Emitters Regulation

GHG Emissions 2007 2008 2009 2010 2011

Carbon Dioxide (CO2) (tonnes CO2e) 4,502,694 4,497,260 4,201,016 4,465,633 4,551,849

Methane (CH4) (tonnes CO2e) 10,493 11,219 11,600 11,764 12,777

Nitrous Oxide (N2O) (tonnesCO2e) 24,089 24,008 22,697 23,209 23,564

Total Annual Emissions (tonnesCO2e) rounded 4,537,275 4,532,487 4,235,313 4,500,607 4,588,190

Emissions Intensity 2007 2008 2009 2010 2011

Total Annual Emissions (tonnes CO2e) rounded less Deemed GHG Emissions from Electricity Generation 3,958,225 4,010,797 3,700,235 3,940,533 4,032,204

Total Production (m3) 8,908,549 8,535,446 8,199,284 8,420,509 9,309,664

Emissions Intensity (tonnes CO2e/m3) 0.4443 0.4699 0.4513 0.4680 0.4331


2012Monitoring – Reclamation

• Schedule IX of EPEA Approval 73534-01-00 requires ongoing, progressive reclamation of the Cold Lake area lease

• Goal is to restore disturbed areas back to an equivalent land capability upon decommissioning, remediation and reclamation At the end of 2011, ~ 57% of the disturbed area within the CLO lease was undergoing progressive reclamation

and ~ 20% of the disturbed area was permanently reclaimed

• In 2012, approximately 89,000 tree seedlings and 14,000 shrubs were planted. The predominant species planted were white spruce, aspen, jack pine, birch, willow and alder – all indigenous to the region

165


2012Monitoring – Reclamation (cont’d)

166

Comprises the following components:

• Soil and Terrain

• Site stability - annual observations for the first 5 years

• Soil sampling first year following reclamation to demonstrate replacement of soils to an appropriate depth

• Most sites have adequate topsoil replaced

• Revegetation

• Focused on competition, tree seedling survival, agronomic species and weeds

• Historic practices of establishing native grasses can result in heavy competition with planted trees

• Wildlife and Vegetation Stress Monitoring

• Conducted at 5 year intervals

• Last completed in 2010, next monitoring scheduled for 2015


2012Environmental Initiatives

• Imperial Oil continues to be involved with LICA (Lakeland Industry and Community Association). Currently IOR Cold Lake Operations holds the following industry seats:• LICA Board of Directors

• co-chair position on the LICA Airshed

• alternate position on the Beaver River Watershed Alliance (BRWA)

• In October 2007 Imperial entered into a partnership with Ducks Unlimited for collaboration on a Wetland Reclamation Trial. In 2008, we joined other in-situ operators as part of the 5 year "Removing the Wellsite Footprint" research agreement signed with the University of Alberta.

• In October 2012, completed removal of pad materials for 2nd wetland trial at J10 pad

• Imperial meets with the Marie Lake Air and Watershed Society (MLAWS) annually and offers to meet one-on-one with domestic well owners

• Hosted a MLAWS Nabiye tour in addition to the annual IOR-MLAWS review meeting in September 2012

• Imperial Oil’s annual Neighbour Night was held November 14, 2012 (Energy Centre, Cold Lake)

167


2012

Monitoring Programs – Air Ambient Monitoring

168

• Imperial has transitioned our “fence line” ambient monitoring network to the LICA Airshed. The Maskwa station located within our operating area is now maintained and operated by LICA.

• Hourly averages for NO2 and SO2 well below Alberta Ambient Air Quality Objectives (AAAQO)

• In May 2011, two exceedances of the 1-hour AAAQO for H2S were detected

• Meteorological conditions put the potential source downwind from the monitoring station in the hours leading up to and at the time that the exceedance was detected

00.020.040.060.080.1

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NO2 Hourly Average January 1, 2011 – September 30, 2012 Maskwa Air Trailer (operated by LICA)

LICA Maskwa Air Trailer Alberta Air Quality Objectives

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SO2 Hourly Average January 1, 2011 - September 30, 2012 Maskwa Air Trailer (operated by LICA)

LICA Maskwa Air Trailer Alberta Air Quality Objectives

00.0020.0040.0060.008

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H2S Hourly Average January 1, 2011 - September 30, 2012 Maskwa Air Trailer (operated by LICA)

LICA Maskwa Air Trailer Alberta Air Quality Objective


2012

Sulphur


2012Sulphur Removal

Mahihkan Site – Plant Sulphur Removal• Start-up of Mahihkan Plant 4 solid scavenging sulphur removal facility Jun/07, to remove 69.7%

(calendar quarter-year) of sulphur for the Mahihkan site, SO2 emissions (ESRD) limited to < 1.8 t/d (calendar quarter-year daily average)

• Sustained reliability achieved over reporting period, with additional performance improvements on-going:

• Achieved greater than 69.7% recovery in all quarters of 4Q11, 1/2/3Q12 and was continuously below emissions limit

• Achieved 100% uptime in 4Q11, 1/2/3Q12 due to better tower operation and media handling

Mahkeses Site – Plant Sulphur Removal • Start-up Mahkeses liquid scavenging sulphur removal facility Oct 10/08 to remove 69.7% (calendar

quarter-year) of sulphur for the Mahkeses site, SO2 emissions (ESRD) limited to < 1.08 t/d (calendar quarter-year daily average)

• Improvements to scavenger performance, and system performance were achieved:• Achieved greater than 69.7% recovery in all quarters of 4Q11, 1/2/3Q12 and was below

emissions limit• Unit continues to demonstrate reliable performance quarter over quarter• Achieved 98.9% uptime in 4Q11, 1/2/3Q12; sulphur removal facility was down for 4 days in July (24-

27); other downtime for maintenance activities

Leming Site – No Plant Sulphur Removal• Sulphur emissions limited to < 1.00 t/d (calendar quarter-year daily average) and SO2 emissions

limited to < 2.10 t/d (daily) by means of production curtailment, no plans for plant sulphur removal facilities

• Leming was less than the limits in all quarters of 4Q11, 1/2/3Q12 and was continuously below daily emission limits

170


2012Sulphur Removal & SO2 Emissions

• Maskwa Site – No Plant Sulphur Removal• Sulphur emissions limited to < 1.00 t/d (calendar quarter-year daily average) and SO2 emissions

(ESRD) limited to < 4.00 t/d (daily) by means of production curtailment

• Maskwa was less than the limits in all quarters of 4Q11, 1/2/3/Q12 and was continuously below daily emissions limit.

• Field Sulphur Removal• Field trial of pad-based sulphur removal at Maskwa F03 pad was successful in 2011.

• Two pad-based sulphur removal units have been constructed and will be installed at Leming Field

• Sulphur Operating Practice• Re-submitted application for Directive 78, Category 3 amendment to Scheme 8558W, Section

24.3 on July 26, 2012

• Received ERCB approval of Sulfur Operating Practice as part of Scheme Approval Amendment 8558X on August 22, 2012

171


2012Cold Lake Sulphur

172

• 2012 Leming sulphur ranged between 0.4 and 1.0 t/d

• Leming site sulphur concentration consistent with other sites

• Periods of higher sulphur production driven by:

• G-trunk infill areas (generally higher sulphur content) produced back in 2012

• Production transfer from Mahkeses T-trunk

• Y32 pad entering cycles of expected higher sulphur production (currently cycle 3)

• Field sulphur skids were not operational in 2012, but are expected to remove 0.05 – 0.1 t/d


2012Sulphur Removal & SO2 Emissions

173

Calendar Quarter Average Sulphur Emission By Plant (tonnes/day)

Maskwa PlantsCalendar Quarter Sulphur SO2 Sulphur SO2 Sulphur SO2 Removal Sulphur SO2 Removal Sulphur SO2Q4 2011 0.50 1.00 0.91 1.81 0.26 0.53 71.3% 0.43 0.86 79.7% 2.10 4.20Q1 2012 0.53 1.05 0.75 1.49 0.35 0.70 70.1% 0.33 0.65 71.3% 1.95 3.89Q2 2012 0.62 1.23 0.97 1.94 0.31 0.62 70.8% 0.44 0.87 72.7% 2.34 4.67Q3 2012 0.76 1.51 0.77 1.54 0.35 0.70 71.3% 0.51 1.01 70.0% 2.38 4.76

Calendar Quarter Peak Day Sulphur Emission By Plant (tonnes/day)

Maskwa Plants Mahihkan Plants Mahkeses PlantCalendar Quarter Sulphur SO2 Sulphur SO2 Sulphur SO2 Sulphur SO2 Sulphur SO2Q4 2011 0.99 1.99 1.18 2.35 0.46 0.92 0.53 1.07 2.68 5.36Q1 2012 0.90 1.79 0.87 1.74 0.82 1.63 0.50 1.01 3.02 6.03Q2 2012 1.01 2.01 1.38 2.75 0.84 1.68 0.54 1.07 3.02 6.03Q3 2012 1.00 2.00 1.07 2.13 1.06 2.11 1.65 3.30 3.55 7.09*Mahkeses SRU was shutdown July 24-27/12 for maintenance activities - exception obtained from ERCB

District

District

Leming Plant Mahihkan Plants Mahkeses Plant

Leming Plant


2012

Compliance


2012Plant License Limits

175

AgencyMaximum Daily Inlet

LimitsUnits Maskwa Mahihkan Mahkeses Leming District

ERCB Bitumen Inlet m3/d 11,000 15,000 8,000 5,000 40,000

ERCB Gas Inlet km3/d 600 600,000 330 250 --

ERCB Water Inlet m3/d 38,000 41,000 22,000 13,500 --

ERCB H2S Inlet Composition mol/kmol 9.99 10.00 9.99 9.99 --

ERCB Sulphur Inlet t/d 8.13 3.00 4.43 3.39 --

AgencyMaximum Daily Emission

LimitsUnits Maskwa Mahihkan Mahkeses Leming District

ERCB Sulphur t/d 2.00 3.00 0.54 1.05 --

ERCB NOx (kg/hr) kg/hr 196.66 167.3 135.00 80.24 --

ERCB CO2 (t/d) t/d 4,532.00 4,500.00 3,307.00 1,596.40 --

ERCB Continuous Flaring (km3/d) km3/d 0 0 0 0 --

ERCB Continuous Venting (km3/d) km3/d 0 0 0.02 0 --

AENV Sulphur Dioxide (SO2) t/d 4.00 -- -- 2.10 13.15

AENV NOx kg/hr -- -- 126.00 -- --

Agency Calendar Quarter-Year Daily AVERAGE Emission

Limits

Units Maskwa Mahihkan Mahkeses Leming District

ERCB Sulphur t/d 1.00 -- -- 1.00 --

ERCB Inlet Produced Gas Sulphur Recovery

% -- 69.7% 69.7% -- --

AENV Sulphur Dioxide (SO2) t/d -- 1.80 1.08 -- --

Cold Lake Operations – Operating Plant License Limits


2012ERCB Compliance

Incident Investigations

• Facilities failure investigations• None

• Pipeline failure investigations• ERCB Incident 20111997

• Pipeline 20434 Line 20 fresh water line from Cold Lake pump station – liner repair

• Status: Closed

• ERCB Incident 20120588

• Pipeline 20885 Line 278 H68/H69 Pad

• Status: Closed


• Pipeline 20885 Line 23 H03 pinhole leak

• Status: Closed


• Pipeline 20885 Line 7 Maskwa A Trunk

• Status: Closed

Inspections • 94 inspections performed Jan - Oct 15th 2012:

• Six low risks identified (calibration, pipeline license amendment, staining)

• Prior history:

• 2011: 3 identified low-risks

• 2010: 0 identified low-risks

• 2009: 26 identified low-risks (staining, signage) 176


2012ERCB Compliance

Other Matters

• July 2011 Measurement Audit - High Risk Enforcement Action 1 High risk enforcement action issued by ERCB to IOR on Oct 3, 2011

IOR to issue response by Nov 16, 2012

Alternative well testing methodologies used for conventional test separators out of service

• Temporary exceedance of daily sulphur emissions for Mahkeses Facility F22779• Two requests submitted (July, October 2012) for 7 day planned outages for maintenance –

approved by ERCB

177


2012

Future Plans

178


2012Future Plans

• Continue to pursue fresh make-up water reduction opportunities and execute existing fresh water reduction projects

• Continue industry sharing and participation

• Install and commission second field sulphur recovery skid at Leming field pad

• Complete installation of new HRSG modules during 2013 plant turnaround at Mahkeses

179


2012ERCB Approvals 8558 and 4510

• Imperial is in compliance with all conditions of Approval 8558 with the exception of Clause 5

• Imperial has satisfied the requirements of Condition 5 of the Mahkeses development approval (enhanced seismicity monitoring in the Colorado group) and ERCB approval to retire this condition was received on April 16, 2012

• Imperial is in compliance with all conditions of Amendment F to Approval 4510 (details are enclosed in Attachment 2)

180


2012

Attachments


2012

Attachment 1

Approval 8558Y Compliance Conditions


2012

183

ERCB Approval 8558

Clause Requirement Summary - Responsibility 2012 Status/Comments2 The Operator shall notify the ERCB of any proposed

alteration or modification of the scheme or to any equipment proposed for use therein, prior to effecting the alteration or modification.

Susan Stark (CLRE), Hsao-Hsien Chio (CLOT)

8558W – removal of Mahkeses Colorado seismicity clause8558X - modification of sulphur recovery clause 238558Y – expansion of the approved infill area

3 Where, in the opinion of the ERCB, any alteration or modification of any equipment proposed for use thereina) is not of a minor nature,b) is not compatible with the scheme approved herein, orc) may not result in an improved or more efficient scheme or operation,the alteration or modification shall not be proceeded with or effected without the further authorization of the ERCB.

Susan Stark (CLRE), Hsao-Hsien Chio (CLOT)

See above

4 Unless otherwise stipulated by the ERCB, the production from the project area outlined in Appendix A shall not exceed 40 000 cubic metres per day (m

3/d) on

annual average basis.

Paul Leonard (CLO) No plan to exceed 40,000 m3

5 The Operator shall conduct all operations to the satisfaction of the ERCB and in a manner that, under normal operating conditions, will permita) the recovery of the practical maximum amount of crude bitumen,b) the conservation of the practical maximum volume of produced gas at the well pads and central facilities,c) the practical minimum use of off-site gas for project fuel,d) the practical minimum use of fresh make-up water subject to the Water Act and the practical minimum disposal of water,e) the practical maximum reuse of produced water, with the minimum recycle rate being 95 per cent on an annual basis, unless otherwise stipulated by the ERCB, andf) the efficient transportation of crude bitumen to market.

Paul Leonard (CLO) e) Self disclosed inability to meet the 95% recycle

6.1 The Operator shall measure and record, to the satisfaction of the ERCB, the volumes and other pertinent characteristics of all fluids injected and produced and other streams as may be required by the ERCB.

Matt Fuller (CLO) Zero reporting compliance issues to date in 2012. Cold Lake Operations review their Operational M.A.R.P. annually to ensure metering and accounting revisions are kept current. A significant effort has been completed reviewing the ERCB Directive - 17 to ensure compliance in 2012, worked closely with ERCB representative on specific produced water reporting requirements. Developing specific tools and performance indicators to track well test frequencies, quality of data and alternative testing methods (Task Force).

6.2 The measurements referred to in paragraph (1) shall be made with sufficient frequency and accuracy as to allow calculation, to the satisfaction of the ERCB, of mass balances, energy balances and recovery efficiencies for the production processes.

Ron Martens (CLO) IOR has not made any changes to mass balances, energy balances and recovery efficiencies at the present time.


2012

184

Clause Requirement Summary - Responsibility 2012 Status/Comments7.1 The Operator shall log all wells from total depth to

surface by means of a spontaneous potential - resistivity or gamma ray-resistivity log and such other logs as may be required to ensure sufficient depth and directional control.

Glen McCrimmon (CLOTG) One or more wells per pad and all OV wells were logged by LWD, wireline or pipe conveyed methods. Exceptions received for Passive Seismic wells and the horizontal sections of Injection-Only-Infill wells. ERCB logging waivers obtained for any wells unable to achieve TD due to mechanical issues.

7.2 The Operator, unless otherwise authorized by the ERCB, shall take full diameter cores of the entire bitumen bearing section of the Clearwater Formation from not less than four vertical evenly-spaced wells per section, and take fill diameter cores of the remaining bitumen bearing sections of the Mannville Group from at least one vertical well per section, and at the ERCB’s request

a) analyze portions of such cores, andb) provide suitable photographs of the clean-cut surface of each core slabbed.

Glen McCrimmon (CLOTG) All OV wells cored through the Cleawater Formation. On average four wells per section drilled prior to development. One well per section cored in Grand Rapids in hydrocarbon zones >8m not encumbered by gas.

7.3 Each of the wells referred to in paragraph 2 and one other well per pad shall be loggedover the entire Mannville Group by means of a gamma ray-neutron density log.

Glen McCrimmon (CLOTG) All OV wells and one well per pad were logged using wireline or pipe conveyed Gamma Ray - Neutron-Density tools

8 The Operator shall conduct all drilling operations using a water-based mud and not introduce any toxic or potentially toxic additives to any muds or fluids used directly in the drilling of wells associated with the scheme.

Sebastien Morin (D&C) Only non-toxic water-based mud systems were used in all drilling activities conducted in 2012

9.1 Prior to the commencement of steam injection operations at all newly-drilled wells, the Operator shall comply with the hydraulic logging requirements of the ERCB Directive 051: Injection and Disposal Wells – Well Classifications, Completions, Logging, and Testing Requirements.

Kelly Wiebe (CLSSE) Directive 051 approvals received for all newly-drilled wells prior to commencement of steam.

9.2 The Operator shall submit an annual summary report on casing integrity and remedial efforts to the ERCB by March 31 the following year.

Kelly Wiebe (CLSSE) Annual casing integrity report submitted March 23, 2012, followed by review on April 30, 2012, and supplemental information submission June 1, 2012.

ERCB Approval 8558


2012ERCB Approval 8558

185

Clause Requirement Summary - Responsibility 2012 Status/Comments10 The Operator shall take such steps and effect such

measures as may be necessary in the completing and operation of wells to prevent production-casing failures.

Paul Leonard (CLO) Well construction and casing failure prevention / detection practices discussed with ERCB through quarterly drilling/cementing reviews and annual casing integrity submission (Mar 30/2012).

11.1 The Operator shall conduct additional sampling, testing, and studies to help assess formation integrity and to provide baseline geological and geotechnical information and further knowledge on properties that can influence groundwater flow, water quality, and corrosion of casing and degradation of cement.

John Elliott (OSDR) Ongoing data collection and analysis in multiple areas: groundwater, passive seismic, gas composition, purge compliance, post steam cement quality and quantification, casing shroud installations, bentonitetop ups.

11.2 The Operator shall design and implement monitoring programs to specifically address the potential that its operations may have on liberating or introducing arsenic into the groundwater.

Stuart Lunn (SHE) Current activity is focused on the rate and extent of natural attenuation of arsenic in long term field tests. A technical update report was submitted in late 2009 and reviewed with AENV and ERCB on July 8, 2010. As per AEPEA requirements, Imperial's next detailed technical report will be completed in 2015. Imperial conducts periodic reviews of arsenic in its regional groundwater network to confirm that arsenic concentrations are not increasing over time. The next analysis will be conducted in 2013.

12 The Operator shall install surface casing, in a manner satisfactory to the ERCB, through the glacial drift on all disposal wells.

Sebastien Morin (D&C) With the exception of wells that have had an ERCB approved surface casing depth reduction waiver, surface casing has been installed on all wells consistent with ERCB Directive 008: Surface Casing Depth Requirements.

13 The Operator, unless given the express written consent of the ERCB to do otherwise, shall maintain between the location of steamed wells and wells being drilled, a separation adequate to ensure that zones pressured by injected steam are not encountered by wells being drilled.

Adam Coutee (CLRS) Drilling program coordinated with steaming schedule to ensure adequate separation.

14 The Operator shall conduct pressure surveys prior to the commencement of steaming and thereafter in any Grand Rapids gas wells that it operates within the expansion area.

Susan Stark (CLRE) IOR submitted the annual pressure survey to the ERCB on May 15, 2012.

15 The Operator, subject to such terms and conditions as may be described by the ERCB upon considering an application therefore, shall undertake extensive field investigations of an alternate or follow-up recovery method that the Operator believes may have potential application in the Clearwater Formation.

John Elliott (OSDR) Multiple field investigations underway: infills, LASER, steamflood, SAGD, SA-SAGD, and CSP.



186

Clause Requirement Summary - Responsibility 2012 Status/Comments16 The Operator shall conduct recovery tests, satisfactory

to the ERCB, in the McMurray and Grand Rapids Formations in the project area to determine the practicality of recovering bitumen from these formations and provide the results of such tests to the ERCB.

Susan Stark (CLRE) Identified candidates for potential Grand Rapids trial. Brought forward an application in Q2 2009 to conduct recovery tests. Based on ERCB feedback, IOR is going to retest size and scope of a potential trial.

17.1 Unless otherwise permitted by the ERCB, cyclic steam stimulation (CSS) operations, having commenced at a well pad, shall continue until the well pad has produced a minimum of 20 per cent of the in-place volume of crude bitumen assigned to that well pad by the ERCB.

Susan Stark (CLRE) Where required, IOR will review proposed pad abandonments OBIP with the ERCB

17.2 Where the Operator proposes to cease CSS operations at a well pad that has produced less than 20 per cent of the in-place volume of crude bitumen, and the ERCB's consent therefore is sought, the Operator shall advise the ERCB as to the following:a) the reason for proposing to cease CSS operations,b) details of individual well workovers and recompletions attempted,c) details of any infill drilling attempted,d) the effect of ceasing CSS operations on the bitumen recovery ultimately achievable from that part of the reservoir associated with the pad and immediately offsetting pads,e) detailed economics of continuing operations, andf) future plans for the well pad with reference to possible follow-up recovery techniques that could be applied and other zones that could be exploited.

Susan Stark (CLRE) Amendment 8558Q received March 4 2011 for E07 pad abandonmentNonroutine Abandonment applied for each individual well approved on March 22, 2012

18 The Operator is permitted to implement late lifeperformance optimization using continuous steam injection (steam flooding) in wells at pads A02, A03, A04, A05, A06, B04, D04, D06, D07, D21, D23, D24, D25, D51, D53, D62, D63, D64, D65, D67, E08, E09, E10, F02, F03, F07, G01, G02, G03, H01, H02, H31, H34, H35, H36, J01, J07, J10, J16, M03, M04, M05, M06, M07, 0FF, P01, P02, P03, R01, R02, R03, R04, R05, R06, and R07. Steam injection will be targeted at low rates (150 m3/day/well to 750 m3/day/well) and pressures (700 kPa to 2000 kPa); the Operator is permitted to steam these wells at rates above or below the targeted ranges in order to accommodate steam schedule flexibility as required, but will not exceedpeak reservoir pressures of 6 MPa..

Adam Coutee (CLRS) Steamflood operations continue at these pads, with target low steam injection rates and low reservoir pressures. Higher steam injection rate periods did occur at some wells to accommodate steam plant requirements, but peak reservoir pressure always remained below 6 MPa.



187

Clause Requirement Summary - Responsibility 2012 Status/Comments19.1 A well shall not be abandoned without prior written

ERCB approval.Kelly Wiebe (CLSSE) Well specific non-routine approvals sought prior to

abandonment.19.2 Where the Operator proposes to abandon a well and

the ERCB's consent therefore is sought, the Operator shall advise the ERCB as to the following:a) the reason for the proposed abandonment,b) the effect of abandoning the well on the bitumen recovery ultimately achievable from that part of the reservoir associated with the well,c) plans for recovering any portion of the remaining bitumen in place, andd) plans for recovering bitumen from other zones penetrated by the well.

Kelly Wiebe (CLSSE) Pad abandonment approvals are sought prior to commencement of well abandonment on the pad, in accordance with the requirements.

20.1 The Operator shall implement an enhanced regional monitoring network at its existing operation and in the expansion area to monitor groundwater flow directions and groundwater chemistry.

Lili Goncalves (SHE) Over 120 regional wells and approximately 15 domestic wells sampled in regional groundwater monitoring network. Monitoring is ongoing as required by Schedule VI of ESRD Approval No. 73534-01-00 and Water Diversion License 148301-01-00.

20.2 The Operator shall set up an enhanced groundwater-monitoring network within its existing operation and in the expansion area to provide information on any water level responses to steam injection.

Lili Goncalves (SHE) Regularly scheduled water level monitoring is completed on deep groundwater wells. Levels are monitored 3x per week at wells within 2 km radius of steaming wells. Monitoring outside the 2 km radius is generally done weekly.

Except for poroelastic response, steam injection has not been observed to cause water level changes.

Several groundwater evaluation wells (GEW) installed in 2011 and 2012.

21 The Operator shall implement a monitoring program for the Grand Rapids Formation in the Nabiye area, as per Application No. 1703441. This will include, but is not limited to, passive seismic monitoring wells located on each pad, a dual completed Grand Rapids pressure monitoring well on Pad N01 and Pad N05, a hybrid passive seismic and Upper Grand Rapidsmonitoring well on Pad N07 near the fault.

Pam Heatherington (OSDR) Imperial’s proposal for monitoring of Grand Rapids formation in the Nabiye area approved and incorporated into Scheme Approval 8558V as Condition 21 in December 2011. Currently plan to drill Grand Rapids monitoring wells in 2013 prior to steaming in 2014. The N07 Grand Rapids hybrid monitoring well site will be located off -pad N07 to be closer to assessed faulting.



188

Clause Requirement Summary - Responsibility 2012 Status/Comments22 Describe the Operator participation in regional

multistakeholders initiatives. Discuss recommendations that have been generated from these regional initiatives and how these recommendations have been incorporated into the project.

Paul Leonard (CLO) Imperial Oil continues to support and participate in regional monitoring programs and initiatives such as the Lakeland Industry and Community Association (LICA), Beaver River Watershed Alliance (BRWA) and Alberta Biodiversity Monitoring Institute (ABMI). Key duties of the LICA airshed is to identify regional environmental air quality issues and respond as required. The BRWA assists and /or supports regional water monitoring in the Beaver River watershed (surface water, groundwater, wetlands, and aquatic ecosystem health). Recommendations are incorporated into the regional monitoring programs and/or projects that are carried out by LICA/BRWA. ABMI conducts biodiversity monitoring and data collected by ABMI is provided to management agencies to help support decision-making with scientific knowledge about provincial biodiversity. IOR will implement any new regulatory requirements that are developed by government as a result of the information gathered through ABMI.

23 The Operator shall ensure that sulphur recovery will be operational at the Leming, Maskwa, Mahihkan, Mahkeses, and Nabiye sites before total sulphuremissions from flaring and combustion of gas containing hydrogen sulphide (H2S) reach one tonne/day per site on a calendar quarter-year average basis, unless otherwise stipulated by the ERCB. The calendar quarter-year sulphur recovery shall not be less than set out in Table 1 of ERCB Interim Directive (ID) 2001-03: SulphurRecovery Guidelines for the Province of Alberta on the basis of the calendar quarter-year daily average sulphurcontent of produced gas streams flared and used as fuel at each central processing facility.

Paul Leonard (CLO) Part of design basis for Nabiye - not operational in 2012.

24 The bottomhole location of a scheme well shall not be closer than 100 metres to the offset owner's oil sands lease boundary unless, upon application by the Operator, the drilling and operation of such a closer well is approved by the ERCB.

Susan Stark (CLRE) No scheme wells have been drilled within 100m of a lease

25.1 Steam injection into the D29 pad wells must not commence until all E07 pad wells have been properly abandoned. Cement bond logs must be run over the entire intermediate casing interval in all E07 pad wells to confirm hydraulic isolation and determine the need for remediation. A non-routine well abandonment plan must be submitted for all E07 pad wells to the Well Operations Section of the ERCB’s Technical Operations Group for review and approval in accordance with Section 2 of Directive 020: Well Abandonment. The non-routine well abandonment plan must include the interpreted cement bond logs and plans to ensure hydraulic isolation of all primary formation interfaces and across all non-salineaquifers.

Kelly Wiebe (CLSSE) Non-routine abandonment application for each specific well submitted to ERCB Feb 16/12 and approved Mar 22/12. The submission included cement bond logs for each well and plans to ensure hydraulic isolation. An update was provided Jun 4/12 regarding Clearwater top remediation and this plan was approved Jun 5/12. All wells have now been properly abandoned with a thermal cement plug to a minimum of 15 meters above the depth of the oil-in-shale anomaly, which now allows steaming of the D29 horizontal wells beneath E07 pad.



189

Clause Requirement Summary - Responsibility 2012 Status/Comments25.2 Any E07 pad wells that are already zonally abandoned

only require review below the cement top if the ERCB identifies issues of concern on those wells not yet zonallyabandoned. The Operator must, for any wells zonally abandoned across the Clearwater Formation where plugs have not been placed at the correct depth, drill out the existing plug and abandon the well properly as per Directive 020.

Kelly Wiebe (CLSSE) Wells already zonally abandoned were properly addressed in the applications noted in item 25.1, withabandonments executed as per the non-routine abandonment approval.

26 The Operator is permitted to abandon the Q and S Pads as described in Application No. 1684454. For the abandonment of wells on these pads a non-routine well abandonment plan must be submitted for each well to the Well Operations Section of the ERCB’s TechnicalOperations Group for review and approval in accordance with Section 2 of Directive 020: Well Abandonment. The ERCB notes many wells on the Q and S Pads have been zonally abandoned; any wells which were previously zonally abandoned across the Clearwater Formation that do not have plugs set at the appropriate depth must be drilled out and reabandoned as per Directive 020. Additionally, cement bond logs must be run over the entire intermediate casing interval, to the depth of the zonal abandonment plug in all wells where present, to confirm hydraulic isolation and determine the need for remediation. The nonroutine well abandonment plan must include the interpreted cement bond logs and discussion on how hydraulic isolation of all primary formation interfaces and across all non-saline aquifers will be maintained.

Kelly Wiebe (CLSSE) Bond logging is complete. Well specific non-routine abandonment plans are being developed and will be submitted as per the approval.


2012

Attachment 2

Approval 4510Compliance Conditions



191

Clause Requirement Summary - Responsibility 2012 Status/Comments

4510_2 The disposal of fluids...in the wells...which have satisfied Guide 51 requirements, may commence or continue.

Kelly Wiebe (CLSSE) Injection follows the conditions of the Directive 051 approvals.

4510_3 The reservoir pressure at the observation wells must be monitored on a minimum of an annual basis.

Mike Warner (CLO) In compliance

4510_4 If the reservoir pressure increases to 7500 kPa (ga), all of the following disposal wells must be re-logged to ensure there is no migration of the disposal fluid out of the zone via micro-annuli:

Mike Warner (CLO) In compliance. Average reservoir pressure did not exceed 7500 kPa.

AB/06-05-065-03W4/0 AU/06-05-065-03W4/0AJ/06-05-065-03W4/0 AG/07-05-065-03W4/0AM/06-05-065-03W4/0 AH/07-05-065-03W4/0

4510 Submit an annual report for Approval 4510 Adam Coutee (CLRS) 2012 Report to be submitted November 2012.


2012

Attachment 3

Water Disposal and Storage


2012Water Disposal and Storage

193

PW Disposal & StorageDistrict Summary

Dispositions (m 3) Nov Dec Jan Feb Mar Apr May June July Aug Sept

Water Disposal

Produced to SWD 148231.5 160581.5 148861.3 147536.1 168880.1 129522.0 146430.3 141512.7 142154.7 140550.3 34714.4

N Pad Storage 66672.0 74156.9 74786.2 69271.2 78252.3 73384.1 71302.6 62358.4 59599.0 51917.2 52391.4

Total Water Disp 214903.5 234738.4 223647.5 216807.3 247132.4 202906.1 217732.9 203871.1 201753.7 192467.5 87105.8

2011 2012


2012

Attachment 4

Facility Performance by Plant


2012Cold Lake Facility Performance

195

Facility Performance

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 10/1/2011 11/1/2011 12/1/2011 1/1/2012 2/1/2012 3/1/2012 4/1/2012 5/1/2012 6/1/2012 7/1/2012 8/1/2012 9/1/2012Maskwa Plant

Bitumen Production m3 203924.7 192562.9 228308.0 239099.8 254160.7 230651.6 232093.2 228719.4 217486.3 225043.5 216543.8 210004.8 211274.5 188796.6 186197.1 184461.9 185859.0 190950.0 193179.4 192680.0 135888.0

Produced Water m3 793835.7 795189.4 926567.2 864090.2 851073.3 822777.7 880720.5 1025195.1 961128.9 949081.3 928841.2 870950 930820.1 859278.4 928716.1 805031.4 845035.3 763564.5 793071.6 816615.8 443362.1

HP Steam Generation m3 764706.6 720089.3 804565.2 794393.2 809649.2 760539.4 814323.3 786416.9 766094.3 721707.3 677910.6 718209.0 729649.6 686025.7 766061.3 760997.7 821241.5 770734.7 765557.5 808180.4 456117.1

HP Steam Injection m3 720552.0 675881.4 762273.5 753437.8 774355.7 717731.9 763035.6 737203.7 706338.2 651901.0 604364.9 639901.7 652965.1 614021.0 694331.3 690144.8 753527.4 712934.0 712552.0 759725.2 436071.6Steam Quality % 72.5 70.0 72.8 73.7 72.8 71.5 72.8 71.1 71.6 70.9 70.8 70.0 71.7 72.8 72.0 68.5 67.6 66.2 62.3 62.4 64.1

Produced Gas km3 12296.8 11903.0 13810.5 13331.8 13754.3 12281.4 12494.5 12349.9 11881.5 11811.3 11804.9 11219.2 10768.5 9436.8 10742.6 10228.9 10164.6 9414.0 9534.8 9341.7 6243.7

Purchased Gas km3 40651.0 36879.9 41829.1 41443.9 42451.4 39651.6 42318.1 40147.9 39084.1 36056.6 32265.8 34704.5 36601.9 35596.6 38901.6 37436.9 40271.6 37121.9 35319.5 37684.8 22013.5

Mahihkan PlantBitumen Production m3 370397.8 344785.8 378854.9 355689.2 362363.5 347829.6 346310.3 364229.8 351061.6 360566.9 370801.0 359835.2 327746.0 318003.0 363330.7 343048.5 341778.6 332457.3 361064.7 355333.1 374898.9

Produced Water m3 1038169.4 916880.3 1009160.0 957216.3 993851.3 935770.1 1061920.3 1108480.8 1044883.4 1082300.0 1017994.7 1011846.9 953660.9 1001464.7 1022883.1 977108.1 959078.7 972807.6 1062779.2 1013725.6 1046394.8


HP Steam Injection m3 1079439.1 992556.3 1102576.3 1046158.9 1122156.6 1089310.7 1098272.2 1084510.5 1057282.5 1078249.6 1002860.9 1028571.1 989485.6 1026286.8 1054514.1 1055435.3 1051781.4 1021903.8 1119876.4 1070653.1 1109800.7Steam Quality % 68.0 68.1 69.3 69.9 70.3 69.6 67.0 69.5 70.7 66.2 69.1 69.0 66.5 70.2 70.8 71.3 70.4 71.6 71.2 71.5 70.0

Produced Gas km3 13928.4 12951.1 14170.7 13371.2 13510.2 12573.9 13098.3 12639.1 12081 12810.5 11548.1 12819.3 12303.5 11884.7 12281.7 12143.8 12169.9 12207.6 12866.1 13139 13701.9

Purchased Gas km3 58282.7 53105.2 58505.2 55004 59007.1 57300.6 56724.7 55151 53822.2 53551.9 51413.4 52423.2 49664.6 53120 54534.7 54156.3 53611.8 51331.1 55992.6 54175.1 55551.3

Mahkeses PlantBitumen Production m3 145445.8 125513 152294.6 143798 139523 115111.7 154693 172982.2 156541.7 162297.4 162991.3 178145 187653.8 173429.2 182671.3 169111.4 157617.2 157263.4 155555.8 146911.4 140861.4

Produced Water m3 462292.7 439706.5 504350.8 511932.2 568884.2 412342.5 589842.3 545783.5 526357.1 550658.8 540002.4 552579.3 524256.5 530406.9 552517.1 560829.1 587291.3 544040.4 524029 542790 548198.2


HP Steam Injection m3 735530.5 646341.1 747398.3 639686.6 664198.8 397557.4 649493.2 672792.8 624377.5 666366.2 618940 647660.2 640209.7 607294.8 573157.6 479931.6 636196 644906 653546.2 658821.5 647622.8Steam Quality % 69.3 68.5 69.2 70.0 70.0 69.9 69.6 70.1 70.0 69.3 69.8 69.8 70.0 70.0 70.0 69.6 69.6 69.8 70.0 69.5 69.7

Produced Gas km3 7253.2 5886.4 6797.9 6574.4 6664 4996.4 6268.1 6113.3 5730.5 6257.9 6640.3 7567.1 7136.9 6663.9 7038.7 7003.6 6820 7089.3 7099.9 7060.7 7197.3

Purchased Gas km3 48672.7 42263.2 48227.5 48011.5 49324.1 28156.1 47039.4 48493.7 45583.2 49687.5 48397.1 51111.4 52053 48249.9 46249.4 35191.7 47453.7 45652.5 46167.7 47389 46020.3

Leming PlantBitumen Production m3 36668.3 29517.6 38475.7 30164.2 29288.4 37442 52669.4 51446.1 45252.5 47198.2 34570.8 41474.5 45264.5 40241.7 50721.1 42136.9 45239.3 44134.5 48236.6 47869.3 58435.7

Produced Water m3 288225.1 199136.8 239098.6 190608.4 189088.7 210555 255439.3 263408.3 260585.2 261748.8 212146.3 274807.3 249120.3 253196.8 282683.7 253830 266805.8 263244.2 273416.3 264525.1 272290.3

HP Steam Generation m3 276630.4 267056.5 287561 186213.5 157745.3 271305.2 308226.6 317122.6 296222.3 292500.8 268649.3 197236.9 203503.3 231925.8 250045 248314.1 211848 219252.3 251176.6 258510.3 257040.2

HP Steam Injection m3 142886.6 124627.4 169805 200927 195782.1 332534.3 355335.5 355759.4 325466.2 358164.6 325566.9 265173.5 270154.4 297478.3 317164.9 317750.9 270897.9 267486.6 296414.3 294363 300751.2Steam Quality % 72.0 71.6 72.5 72.3 53.6 58.6 70.1 72.2 69.5 68.2 67.2 67.8 68.5 68.4 70.4 69.8 71.9 72.0 67.1 64.3 60.4

Produced Gas km3 4814.2 4560.1 5392.8 4140.6 3368.9 4809.8 4979.3 5280.2 5104.5 5354.3 5073.2 4993.8 5029 4554.7 5085.5 4746.9 4934.2 5022 5350.5 5473.7 5356.6

Purchased Gas km3 16604.6 16329.2 17601.2 10927.6 8083.8 15642.8 17739.1 19088.7 17423.7 16830.3 15559.8 10372.2 10664.8 12839.9 13328.5 13629.5 11160.3 11729.5 12355 12254.7 13580.4

DistrictFresh Water m3 278487.1 239668.9 275153.2 226795.9 213718.6 240438.4 267383.3 305981.1 301807.2 39538.2 0 0 0 0 0 0 3035.2 527.9 113114.7 229211.2 243699.7

Brackish Water m3 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

Ground Water m3 323.3 659.1 277.8 0 604.4 372.8 312.7 4188.5 1041.4 19032.1 204915.4 183395.7 193439 178666.6 199155.5 199555.5 213866 208100 124509.2 40316.5 688.6

Disposal Water m3 189935.8 188067.7 189157 151261.1 151340.1 200874.4 202303.6 190371.7 167714.3 195378.2 214903.5 234738.4 223647.5 216807.3 247132.4 202906.1 217732.9 203871.1 201753.7 192467.5 87105.8PW Recycle % 96.5 96.8 96.2 93.7 95.7 92.8 90.5 84.1 84.2 85.9 84.1 85.1 85.2 86.3 84.1 86.8 90.9 92.9 93.1 92.7 94.8

Power Generation MWh 127833 113950 119041 114676 113347 64116 106237 109832 108748 117122 121621 121821 123444 115890 112872 86617 112326 107935 108171 106908 108903Power Import from Grid MWh 646 585 649 561 530 562 580 591 587 132 88 97 96 85 76 64 100 190 305 589 736Power Export from Grid MWh 33233 27807 26646 25590 28848 5101 22503 22935 24780 28012 29582 29820 32057 28329 23653 13536 29663 29384 26162 26756 33873

Power Consumption MWh 95245 86728 93044 89647 85029 59577 84314 87488 84555 89242 92128 92098 91483 87646 89295 73146 82763 78742 82314 80741 75765

Produced Gas km3 38358 35354 40220 37458 37345 34693 36850 36389 34813 36404 35072 36608 35244 32546 35156 34132 34095 33737 34856 35021 32512

Flare Gas km3 379.8 23.8 141.8 66.7 101.2 52.2 136.2 133.7 18.1 14.4 118.6 66.6 164.4 102.3 52.7 29.8 257.5 138.6 76.8 95.8 56.6

Vent Gas km3 17.5 16.8 14.5 14.9 18.1 13.8 6 5 7.6 26.5 11.5 12.8 8.7 7.1 12.3 8.4 7 14.7 10.2 9.3 7.5Produced Gas Recovery % 99.0 99.9 99.6 99.8 99.7 99.8 99.6 99.6 99.9 99.9 99.6 99.8 99.5 99.7 99.8 99.9 99.2 99.5 99.8 99.7 99.8


2012

Attachment 5

Sulphur Balances by Plant


2012Cold Lake Plant Sulphur Balances

197

tonnes average Month Oct-11 Nov-11 Dec-11 Jan-12 Feb-12 Mar-12 Apr-12 May-12 Jun-12 Jul-12 Aug-12 Sep-12

District Sulphur Inlet 164.98 117.39 126.13 108.18 105.13 111.84 115.18 137.72 134.02 142.49 140.80 124.47Sulphur Removed 96.59 64.76 53.91 51.13 48.57 48.23 46.30 62.91 64.96 68.59 64.47 55.57Sulphur Emissions 81.61 88.25 88.17 57.05 56.56 63.60 68.88 74.81 69.06 73.90 76.33 68.90SO2 Emissions 163.05 176.31 176.14 113.98 112.99 127.07 137.62 149.45 137.98 147.63 152.50 137.65Sulphur Recovery 58.5% 55.2% 42.7% 47.3% 46.2% 43.1% 40.2% 45.7% 48.5% 48.1% 45.8% 44.6%

Leming Sulphur Inlet 22.46 8.47 14.92 11.79 14.53 21.63 21.02 18.64 16.57 20.83 24.82 23.94Sulphur Removed 0 0 0 0 0 0 0 0 0 0 0 0Sulphur Emissions 22.46 8.47 14.92 11.79 14.53 21.63 21.02 18.64 16.57 20.83 24.82 23.94SO2 Emissions 44.88 16.92 29.80 23.55 29.02 43.21 41.99 37.25 33.11 41.62 49.59 47.82

Maskwa Sulphur Inlet 27.42 24.14 31.97 24.15 21.32 22.53 24.48 35.35 28.72 30.98 26.56 13.27Sulphur Removed 0 0 0 0 0 0 0 0 0 0 0 0Sulphur Emissions 27.42 24.14 31.97 24.15 21.32 22.53 24.48 35.35 28.72 30.98 26.56 13.27SO2 Emissions 54.78 48.22 63.87 48.24 42.59 45.01 48.92 70.61 57.37 61.89 53.06 26.51

Mahihkan Sulphur Inlet 32.79 24.45 27.32 33.25 36.92 35.90 32.72 32.95 31.13 38.38 34.16 39.31Sulphur Removed 24.86 17.18 18.25 23.62 25.76 24.99 18.79 26.44 23.26 32.59 24.75 22.45Sulphur Emissions 7.93 7.28 9.07 9.62 11.16 10.91 13.93 6.51 7.87 5.79 9.41 16.87SO2 Emissions 15.85 14.54 18.11 19.22 22.29 21.80 27.82 13.00 15.73 11.57 18.81 33.70Sulphur Recovery 75.8% 70.2% 66.8% 71.1% 69.8% 69.6% 57.4% 80.2% 74.7% 84.9% 72.4% 57.1%

Mahkeses Sulphur Inlet 82.30 60.33 51.92 39.01 32.36 31.78 36.96 50.78 57.60 52.30 55.27 47.95Sulphur Removed 71.73 47.59 35.66 27.51 22.81 23.25 27.51 36.47 41.70 36.00 39.73 33.12Sulphur Emissions 10.57 12.75 16.26 11.50 9.55 8.53 9.45 14.31 15.90 16.29 15.54 14.83SO2 Emissions 21.12 25.47 32.48 22.97 19.08 17.05 18.89 28.59 31.77 32.55 31.05 29.62Sulphur Recovery 87.2% 78.9% 68.7% 70.5% 70.5% 73.1% 74.4% 71.8% 72.4% 68.8% 71.9% 69.1%

As per EUB approval 8558 clause 24.2, IOR Cold Lake is required to report monthly sulphur and comply on a calendar quarter year average basis for each plant.


2012

Attachment 6

2012 Bitumen in Shale Report


2012

199

Oil-in-Shale Anomaly

P02 Pad (1996)

F Trunk (2001)

H38 Pad(2003)

L08 Pad (2003)

H11 Pad(2003)

J01 Infill Pad(2003)

D28 Pad(2003)

E07, D51, D62, D63, D64 Pads (1996)

Uphole Issues Summary


2012

200

Location Issue Date of Discovery

Current Restriction?

Comments/ Commitments/ Results Next Scheduled Steam Date

E07 Oil in Shale found during drilling at E07 pad

1997 No Steaming pattern and volumes adjusted to minimize shear stresses. Shale pressure monitored while steaming.

Q4 2012

(via D29)

F trunk Oil in Shale found during re-drill at F03-16A

2001 No Steaming restrictions lifted Sept 10, 2003. Anomaly area steamed 2006, including new infill wells. Shale pressure monitored and steam pattern adjusted to minimize shear stresses. One GEW shows <1 ppb benzene and below Canadian drinking water guidelines (CDWG).

Steam Flood Ongoing

(via infills)

L08 Oil reported during drilling of L08-01 and PS well on pad.

2003 No Steaming restriction lifted June 13, 2003. Steamed 8 cycles with no abnormal pressures in CEW. Closest GEW well has shown BTEX levels over CDWG in the past but are now below detection limits

Q2 2015

H38/H39 Oil reported during drilling of H38-12 and H38-22.

2003 No Steaming restriction lifted Nov 25, 2004. Shale pressure and ground water monitoring wells monitored through 5 cycles. No abnormal pressures observed. Since Feb 2011 groundwater has shown benzene concentrations above CDWG.

Q1 2013

H11 Oil reported during drilling of H11-02 and H11-05

2003 No No abnormal pressures at CEW during 7 steam cycles. Benzene observed in 2004 and 2005 but was subsequently below detection limit.

A new GEW was drilled as part of the BTEX investigation; BTEX was observed at the new well, and was attributed to the original H11 CSS wells.

Q3 2013

J01 Infills

Oil reported during drilling of J01-H1 2003 No No abnormal pressures at CEW during 3 infill well cycles. Groundwater shows no abnormal hydrocarbons.

Steam Flood Operations Ongoing

D28 Oil reported during drilling of D28-07 and D28-09.

2003 No Steam volumes reduced and pattern adjusted to minimize shear stress in four cycles based on anomaly pressure response at CEW. Shale pressure correlates well with net steam volume injected. Groundwater shows no abnormal hydrocarbons.

Q1 2012

Oil In Shale Issues Summary


2012D/E Oil In Shale Anomaly

201

Background• October 1996 – Oil discovered in lower portion of the

Colorado Shales during drilling of E07 Pad

• A number of SEW wells were drilled to determine the areal extent of the oil-in-shale anomaly

• The SEWs identified that the anomaly is present at D51, D62, D63, D64 and E07 pads.

Current Status• No high pressure steaming operation has occurred

on D51, D62, D63, D64 and E07 since 2006

• D51, D62, D63 and D64 pads are currently being steamed by low pressure infill wells

• Application submitted to ERCB in Sept 2011 to convert D51, D62, D63, D64 to steamflood

• E07 resource is scheduled to be steamed by D29 horizontal wells in 2013.

• E07 vertical wells will be abandoned prior to the steaming of the E07 resource from D29 horizontal wells.

Forward Actions• Continue to steam D51, D62, D63 and D64 pads

using low pressure infills

• Steaming practices will be modified as necessary to minimize shear stress when steaming D29

•"•)

•"•)

•"•)

•E11

•D53

•E07

•E08

•D63

•D51

•D65

•D64

•Y32•D62

•D66

•D52

•E09

•E06•D26 •D27

•D67

•D57

•E05•D35 •D29


2012

202

F Trunk Oil in Shale Anomaly

Background• F Trunk first steamed in 1999• Oil observed at 248 m in Colorado Shales while

drilling F03-16A redrill in Nov 2001• 1000 m steaming restriction imposed in

January 2002• Anomaly delineated by drilling CEW wells and

logging existing CSS wells.• Approval received in July 2002 to steam one

cycle • Investigation report submitted to EUB in April

2003.• Steaming restriction lifted Sept 10, 2003• F Trunk steamed in 2006, along with new infill

wells with monitoring at CEW and GEW wells

Current Status• F Trunk infills have been approved by the

ERCB for steamflood operation (F02/F03/FF)• 12 infill wells currently on steamflood • F03 03-5 (E3) has benzene near 1 ppb which is

below Canadian Drinking Water Guidelines.

Forward Actions• Continue to monitor pressures at CEW and

water chemistry at GEW. • Continue low pressure steamflood

F02 - CEW6

F01 - CEW8

8-18 - CEW2

F04 - CEW7F06 - CEW10

F07 - CEW13

No oil

No oil

No oil

No oil

No oil

FF - CEW4

No oilNo oil

14-17 - CEW1213-17 - CEW9

Oil at 282 m

Oil at 266 m

Oil at 248 m

F03-16A

Oil at 250 m

2-18 - CEW1


2012

203

L08 Pad Bitumen in Shale

Background• Jan 4, 2003 - Oil observed at L08-01 while drilling in

Empress 1 aquifer at a depth of 165 m. Recovered ~ 900 litres emulsion (50-60 wt% bitumen)

• Feb 12, 2003 - Oil observed while drilling L08-PSW at 220 m in Colorado Shales. Recovered 25 litres of emulsion (8 wt% bitumen)

• Three GEW wells drilled to Empress 1 aquifer (GEW3-3 deepened to Colorado Shale) and two CEW wells drilled to base of Colorado Shale. No bitumen observed.

• Steaming restriction of Jan. 14, 2003 lifted by EUB on June 13, 2003

Current Status• Pad steamed 8 cycles with pressure monitoring at CEW-

19 and GEW wells. No abnormal pressure responses.

• New wells installed in 2005, 2007 at L08 pad (L08 GEW 05-9, L08 GEW 07-2, GEW 07-3, GEW 07-4, and GEW 07-5) did not observe bitumen in Empress 1 Aquifer

• L08 GEW 03-1, L08 GEW 03-2, L08 05-9, and L08 07-3 (on pad wells) show intermittent BTEX values below CDWG in the past but were below detection limits in 2012 (Data to August 2012)

Forward Actions• Water chemistry at GEW continues to be monitored and

reviewed with AENV.

• Ongoing monitoring of CEW pressures

-75

-50

-25

0

25

50

75

-75 -50 -25 0 25 50 75

-100

178 m

L08-01 well centre

10-29 OV well

GEW3-2

(metres)

GEW3-3

CEW-20

CEW-19

L08-1 trajectory

L08 Pad BoundaryL08 wellheads

10-29 OV well

GEW wells

CEW wells

Depth of Empress 1at L08-01

Passive Seismic Well

165 m GEW3-1

L08 Surface Pad

GEW07-3


2012

204

H38 Pad Bitumen in ShaleBackground• Oil influx occurred at a depth of 220 m at H38-12 and at H38-22.

• Pressure in shale estimated at 4 MPa (2 MPa overpressure)

• Steaming restriction imposed.

• RST logs at H27 and H26 wells showed no evidence of oil in shale

• CEW wells at H26, H27 and H37 showed no evidence of oil in shale

• Interim investigation report submitted to EUB August 28, 2003

• Bitumen encountered at H38 CEW-24 on Jan 10, 2004

• No reportable bitumen or pressure at H47 CEW 23 or H39 CEW-25. CEW’s converted to passive seismic wells.

• Final report submitted to EUB in August 4, 2004.

• H47 pad wells drilled with no bitumen in shale occurrences.

• Steaming restriction lifted Nov 25, 2004

• H38 resource drilled from new surface location (H39) with no B-I-S incidents

Current Status• Shale pressure monitoring wells in place at H38-CEW24,

H38-12 and H38-22.

• Ground water monitoring wells located on H38 and H47 pads

• H39 pad instrumented with 2nd generation passive seismic system

• Monitored pressures at CEWs and GEW while steaming through 4 cycles. No abnormal pressures observed.

• GEW well shows infrequent and sporadic detections of BTEX considered to be false positives

H47

H39

H37 CEW-18

H26 CEW-16

H27 CEW-17

H39 CEW-25

H38 CEW-24

H38-12 & H38-22

H47 CEW-23

H39 SurfacePad

H38/H39Bottomhole Outline

GEW04-4

Forward Actions

• Ongoing monitoring at CEW and GEW wells


2012

205

H11 Pad

Background• Oil observed at H11-03 on March 16, 2003 while

drilling at 204 m. Recovered ~150 litres of emulsion.

• No oil show at adjacent well, H11-04 Hz.

• Very small oil show at wells H11-02 & H11-05 at 204 m. Too small to measure.

• No uphole oil shows at subsequent wells

• Cold Eyes review of drilling showed small amounts of oil can be entrained in drilling mud.

• CEW and GEW wells drilled in Oct. 2003 - no bitumen observed

• Core obtained from Empress 2 and top of Colorado Shales at the GEW well. No evidence of bitumen in natural fractures in shale.

• H11 GEW 03-7 showed benzene and toluene below Canadian Drinking Water Guidelines in 2004-2005 followed by non-detection levels to present

GEW 03-7

GEW 11-7

CEW 22

CSS

WellsInfill

Wells

Source Well

(1.25 km)

Groundwater

Flow Direction

H11 Pad

Current Status• Pad has steamed 7 cycles with no abnormal pressures observed at monitoring wells.

• GEW03-7 had no hydrocarbon detections in 2012.

• GEW 11-7 showed 2 BTEX detections above CDWG in 2012, attributed to BTEX transport from H11 CSS pad to GEW due to use of Cold Lake groundwater source wells (1.25 km to SE). Currently below detection limit.

Forward Actions• GEW continues to be monitored and reviewed with ESRD

• Ongoing monitoring of CEW pressures


2012

206

J01 Infill Pad

Background• Oil influx occurred June 9, 2003 while drilling intermediate section of J01-H1 at a depth of 202 m. Mud weight

increased to control influx. Reduced mud weight and drilled ahead with no further issues.• J01-H1 was fourth intermediate section drilled on infill pad. No oil observed at other 3 wells.• Shale pressure monitoring well drilled north of J01-H1. Core obtained from Upper Colorado Shale - no

evidence of bitumen in natural fractures in shale. • Ground water well drilled down-gradient of J01-H1.

Current Status• Infill wells steamed through 3 cycles with no abnormal pressures observed at monitoring well.• J01 infill wells are part of an on-going steam flood trial.• No hydrocarbon impacts have been detected in groundwater monitoring well

Forward Actions• Continue to monitor pressures at CEW and water chemistry at GEW.

H11

J01-H1 -30

-20

-10

0

10

20

-30 -20 -10 0 10 20

E-W Distance from J01-H1 Wellhead (m)

N-S

Dis

tan

ce f

rom

J01

-H1

Wel

lhea

d (

m)

Ground Water Flow Direction

J01-H1

J01-H2

J01-H3

J01-H4

J01-CEW-21

J01-GEW19m 10m


2012

207

D28 Pad

Background• Passive seismic well drilled prior to pad

development at D28 pad

• Sheen of oil observed April 14 at depth of 175 m

• Oil droplets observed at 230 m. 1/3 litre of oil recovered on bottoms up after 2 hr shut down

• Oil influx at D28-09 on Dec 11, 2003 at ~242 m TVD, approx. 0.5 m3 of emulsion recovered

• Oil influx at D28-07 on Dec 19 at ~256m TVD, approx. 0.75 m3 of emulsion recovered

• CEW well and GEW drilled for pressure monitoring of shales and basal aquifer.

Current Status

• Steamed four cycles. Steam volumes and steaming pattern adjusted to minimize shear stresses based on anomaly pressure response.

• No hydrocarbon impacts have been detected in groundwater monitoring well

Forward Actions• Continue to monitor pressures at CEW and water

chemistry at GEW.

• Steaming practices will be modified as necessary to minimize shear stress.

D28 PadBottomhole Outline

D28-07 & D28-09 Oil Shows

D28 Surface Pad


2012

Attachment 7

Arsenic Fact Sheet

208

Slide

Paul L

eon

ard

paul.m.leonard@

exxonmobil.com

Novem

ber 2012

Property of Imperial Oil

2012 Annual Summary Report on Casing Integrity

Submitted: March 4, 2013

Property of Imperial Oil Page 2 of 29

EXECUTIVE SUMMARY

Casing Failures

• Total number of casing failures (all depths) of 46 wells, lowest level since 1993. Near Surface

• 7 failures in 2012 versus 13 failures in 2011. • All 7 near surface failures detected operationally. • None in 2012 were assessed above a level zero environmental consequence.

Intermediate Depth

• 31 failures in 2012 (31 primary failures & 0 secondary failures) versus 34 failures in 2011. The number of failures is down slightly from 2010 and 2011.

• Failure frequency of 0.64%, lowest level since 2006 • 19 detected with casing integrity checks, 12 detected operationally which includes 9 with passive

seismic and 3 wells detected by the nitrogen soak/nitrogen fluid monitoring programs. 7 of the 19 wells detected by casing integrity checks were detected by regulatory pressure testing requirements on previously suspended wells.

• No multi-well failures occurred in 2012. • One well failure (V13-31) had an environmental consequence above Level 0. • 16% of failures were high pressure, a significant decrease from 2011, and was the lowest level

since this metric has been tracked • Only 1 confirmed case with fluid loss from the casing break (V13-31). Total fluid loss volumes

from breaks at lowest level in last 7 years • 8 wells in 2012 proactively taken out of high pressure steam service due to impairment or

deformation. Clearwater

• 8 failures in 2012. • No adverse environmental impact identified.

Casing Failure Detection Initiatives Alarm Management

• A new method of filtering Delta Flow and Pressure (DFP) alarms was developed in 2009. Prototype testing progressed through 2010 and was completed in 2011. Full implementation was undertaken in 2012 and completed in January 2013.

Casing Integrity Check Process

• Imperial Oil qualified and implemented the use of Through Tubing Electro-Magnetic (EM) Logging as a method for performing a casing integrity check. This technology will be used for specific applications where determining if the casing has a failure is the only function of the integrity check.

Near Surface Casing Integrity Initiatives Alternative Corrosion Measurement Technologies

• Bench testing of a surface piping corrosion inspection technology retro-fit for well inspection was completed in 2011. Field trials were completed 2012 and a final decision if the technology is viable for full commercial use will be made in 2013.


Alternative Casing Repair Technologies • A near surface casing patch for low pressure steam operations or producer only wells was

successfully trialed in 2011 and the technology has been approved by the ERCB as a standard repair technology suitable for producer only or low pressure steam operations. The repair option was fully incorporated into best practices in 2012 as an alternative repair method to surface dig outs.

Intermediate Depth Casing Integrity Initiatives Wellbore Environment Control

• Near 100% compliance of N2 purge practices – reduces risk of supplied stress corrosion failures • 16 wells shut in and purged with nitrogen in 2012 due to cold production and H2S concentrations

above the H2S concentration limit of 3kPaa Casing Connection Design

• A new fatigue resistant connection has been designed using finite element analysis. The connection has been built and physical testing to determine fatigue properties and seal-ability began in 2011 and will continue through 2013

Material Testing • 2010 test results indicated T95 has a slightly higher sulfide stress cracking resistance compared

to L80 under monotonic conditions. • 2011 testing program performed to compare fatigue characteristics of T95 vs. L80 at elevated

temperatures. Final decision after analysis of testing program will be made 2013. Fault Reactivation Research

• Preliminary research completed to identify conditions that could induce fault reactivation and resulting casing deformation in specific geological horizons.

• The study investigated a single well and looked at the effect of fault friction and horizontal stress conditions to determine the faulting potential.

• Study will be extended in 2013 to look at a full pad model and to determine if steaming strategies aimed to reduce shear slip along weak bentonite layers in the Fish Scales will have the same desired affects for reducing fault re-activation in other geological horizons.


INTRODUCTION 1.0

Pursuant to the requirements of AEUB Decision 99-22, condition #9 and clause 6.2 of AEUB Approval 8558, Imperial Oil Resources hereby submits the 2012 Annual Summary Report on Casing Integrity and remediation efforts. This report has been submitted annually since 2000, and as such builds on information that was included in previous reports, with focus on 2012 performance. For the purpose of this report, a casing failure is defined as a break or crack in the production casing that results in the well’s inability to contain pressure. A primary failure is defined as being limited to a single well; a secondary (or multi-well) failure occurs when fluid loss from a primary failure results in immediate adjacent well failures. Casing failures have been classified according to the following three depth intervals:

• Near surface (0 to ~25 mTVD). • Intermediate depth including the Quaternary, Colorado group, and Grand Rapids formations. • Clearwater, at the interface between the Clearwater formation and the Grand Rapids formation or

lower. Undetected, high pressure, near surface and intermediate well failures in the upper part of the wellbore have potential for environmental consequence due to aquifer contamination or breach to surface. Clearwater failures only affect the operability of the well. The existing casing integrity program for Cold Lake was designed to address the concerns associated with the near surface and intermediate depth intervals, and was not intended to deal with failures within the production zone. Near surface and intermediate depth casing failures with potential for adverse environmental impact are assigned an environmental consequence level. Clearwater failures do not have an adverse environmental impact, and therefore are not assigned one. Casing failures that occur within the Glacial Till or within 75 meters of the Bedrock top, and have produced fluid loss are Alberta Environment reportable; the response follows the Cold Lake Operations Incident Response Plan. Consequence levels are assigned jointly by environmental and engineering personnel utilizing the descriptions provided in Table 1.


Table 1: Environmental Consequence Matrix for Casing Failures Consequence

Level Environmental Consequence

Description

Level 0

Level 1

Level 2

- Failure occurred within the bedrock with fluid loss below the typical

threshold required to cause a multi-well failure (approximately 1000 – 5000 m³ produced fluid, dependent on proximity of wellbores at failure depth)

- Failure occurred within the Glacial Till, but only released inert fluid (e.g. N2 gas) or minimal produced fluid not requiring remediation

- Failure occurred within the bedrock with fluid loss above the typical

threshold required to cause a multi-well failure (approximately 1000 – 5000 m³ produced fluid, dependent on proximity of wellbores at failure depth)

- Failure released fluid into the Glacial Till and there is low potential of the fluid migrating to a freshwater aquifer (i.e. volume released from failure is low, or the aquitard layer is thick)

- Failure with fluid release to surface or fresh water aquifer requiring

longer term remediation efforts

Note: Bedrock is defined as solid rock that underlies unconsolidated surface material (i.e. Bedrock includes the Lea Park and/or Colorado Group and lower formations).

For the purpose of the report, failures are defined as being detected either operationally, or through a casing integrity (CI) check. An operational detection is defined as a failure detected with the differential flow & pressure (DFP), nitrogen soak, or passive seismic (PS) systems, or detected by visual means. A casing integrity check detection is defined as a failure detected as part of the pre-steam casing integrity process (identified through a service rig based casing integrity check, or Electro-Magnetic logging casing integrity check) The failures detected as part of the five year pressure testing requirement of a suspended well are also considered as detected through a CI check.


CASING INTEGRITY DATA 2.0

A historical summary of casing failures by depth interval at Cold Lake is provided in Table 2. The total number of failures, all depths, was the lowest since 1993. All 31 of the intermediate depth casing failures detected in 2012 were classified as primary commercial intermediate failures (no early casing design failures). One of the 39 near surface or intermediate failures in 2012 were assessed an environmental consequence above level 0. Well V13-31 had an environmental consequence level 2 failure, which is discussed in detail in section 3.3.1. Of the 38 surface and intermediate failures detected in 2012, 19 were detected operationally and 19 were detected through casing integrity checks. Table 2: Historical Failure Summary by Depth Interval

2.1 Near Surface Casing Integrity Data

Since 1996, 110 commercial wells have failed near surface, including 7 near surface failures detected in 2012. Details describing these failures (including primary cement tops) are provided in Table 3. In addition to failed wells, since 1996, a further 121 wells have either been proactively repaired or taken out of steam service due to excessive wall loss. Table 3: 2012 Surface Depth Failures Summary

2004 2005 2006 2007 2008 2009 2010 2011 2012Surface 0 1 1 5 5 16 11 13 7

Intermediate 21 16 26 36 39 30 34 34 31Clearwater 57 51 70 71 81 56 17 19 8

Total 78 68 97 112 125 102 62 66 46

Depth Classification

Year

Well License UWI Primary Cement

Top

Detection Date

Cycle Environmental Consequence

LevelmGL mm/dd/yy mKB mGL

1 H26-24 179194 111/16-34-065-04W4 2.9 03/11/12 Operational CI Check 5.6 1.5 9 02 J05-18 112733 108/07-22-065-04W4 9.0 04/07/12 Operational CI Check 4.0 -0.3 10 03 K24-22 197969 100/15-08-065-04W4 0.5 04/11/12 Operational Visual 3.9 -0.4 10 04 R02-01 134593 102/05-23-065-04W4 9.6 06/16/12 Operational CI Check 6.0 1.4 9 05 J01-02 109489 107/05-22-065-04W4 7.8 06/18/12 Operational CI Check 4.0 -0.4 13 06 T04-20 236979 102/01-05-065-03W4 0.0 07/19/12 Operational Other 6.2 1.1 9 07 00W-09 098062 1AF/09-07-065-03W4 10.7 12/27/12 Operational Visual 4.7 0.9 11 0

FAILURE INFORMATIONWELL INFORMATIONNo.DepthDetection Method


Historic consequence levels associated with near surface casing failures since 1996 are displayed in Figure 1. All near surface failures, except H01-03 in 1996, were assessed at a level 0 environmental consequence, including the 7 near surface failures detected in 2012.

Figure 1: Cold Lake Surface Failures by Consequence Level

0

5

10

15

20

25

3019

96

1997

1998

1999

2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

2010

2011

2012

Failu

re C

oun

t

Year

Level 0 Level 1 Level 2


The number and frequency of near surface casing failures for the commercial casing design in Cold Lake are summarized in Figure 2. Failure frequency is the number of failures divided by the total number of wells operating. The peak failure rate observed in 1996 marks the inception of the Casing Integrity Operating Practices, at which time the cement and bentonite top-up program was initiated to mitigate the occurrence of surface failures. Positive results were observed and the surface failure frequency declined; however, failure frequency increased between 2006 and 2009. Many of the failures occurred on 'old' wells (steamed prior to 1996 before the implementation of the Casing Integrity Operating Practices). The bentonite top-up program, casing shroud installation program, and production casing inspection practices were further upgraded in 2010 and were targeted to mitigate the risk associated with external corrosion. 2011 was the first year with modified operating practices triggering casing inspection logs based on well age instead of well cycle for all ‘New/Upgraded’ well casings. This practice was developed to help identify wells with high external corrosion and result in more proactive repairs before a well reaches failure. In 2012, 4 of 7 failures occurred on ‘old’ wells. The three failures ‘New/Upgraded’ casing wells were of age consistent with the new operating practice, and were proactively identified and taken out of service prior to steaming.

Figure 2: Commercial Surface Failures and Failure Frequency

In total 153 ‘New/Upgraded’ wells have been logged as triggered by well age. The average wall loss on ‘New/Upgraded’ wells is 2.8%/year versus 3.5%/year on ‘Old’ wells. Data will continue to be analyzed to monitor the potential performance improvement provided by Imperial Oil’s bentonite top up and shroud installation program.

0.0%

0.2%

0.4%

0.6%

0.8%

1.0%

1.2%

1.4%

0

5

10

15

20

25

30

35

1996

1997

1998

1999

2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

2010

2011

2012

Failu

re F

req

uen

cy

Failu

re C

oun

t

Year

Failure Count Failure Frequency


In 2012, all 7 near surface failures were detected operationally.

Figure 3: Commercial Surface Failures by Detection Method

The 7 near surface failures in 2012 were managed the following way:

• 4 wells had a near surface patch installed • 2 wells were temporarily suspended • 1 well had a near surface patch installed, but is currently temporally suspended due to a

intermediate depth failure

2.2 Intermediate Depth Casing Integrity Data

The scope of this document includes intermediate depth failures that have occurred in wells with L-80 or IK-55 casing (also referred to as ‘commercial’ design), and does not include early casing designs, such as SOO-95. There were no failures in wells of earlier casing design in cyclic steam stimulation (CSS) operation in 2012. Since the implementation of the Casing Integrity Operating Practices in 1996, a total of 408 primary intermediate casing failures have been detected in wells with the L-80 or IK-55 casing designs. Approximately 62% of these failures were identified during pre-steam casing integrity checks. In addition, 534 wells have been taken out of steam service or repaired due to intermediate impairments or excessive deformation. There have been three intermediate failures which have required aquifer remediation (H15-10 in 1999, H39-H04 in 2006 and V13-31 in 2012). There have been two multi-well failure events since 1996:

• T09-01 primary intermediate casing failure in 2006 with one secondary failure on T09-07 in 2006. • H33-06 primary intermediate casing failure in 2007 with secondary failures on H33-08 and H33-

10 in 2007, as well as H33-01, H33-12, and H33-15 in 2008. Details on the 31 primary intermediate failures, which occurred in 2012, are provided in Table 4.

0

2

4

6

8

10

12

14

1996

1997

1998

1999

2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

2010

2011

2012

Cas

ing

Fai

lure

s

Year

CI Check Operational


Table 4: 2012 Intermediate Depth Failures Summary

*E11-15 failure occurred during swaging operations while rig was on the well. V13-31 failure discussed in more detail in section 3.3.1

Wel

l

Lic

ense

Un

iqu

e W

ell

Iden

tifi

er

Det

ecti

on

Dat

e

Dep

th C

lass

Pip

e B

od

y/C

on

nec

tio

n

Co

nn

ecti

on

Typ

e

Pri

mar

y/S

eco

nd

ary

/S

lim

ho

le

Cyc

le

En

viro

nm

enta

l C

on

seq

uen

ce L

evel

mm/dd/yy mKB mTVD

1 U01-05 253492 106/14-33-064-03W4 01/11/12 314.7 311.5 Fish Scale Fm C NSCC P 8 02 U05-15 253324 107/06-09-065-03W4 02/01/12 248.8 247.9 Fish Scale Fm Pipe QB2 P 8 03 V04-13 291589 100/08-34-064-03W4 02/02/12 250.0 250.0 Fish Scale Fm Pipe NSCC P 8 04 D55-13 127639 104/06-35-064-04W4 02/16/12 287.7 286.4 Fish Scale Fm C OBTC P 13 05 E11-15 376016 102/16-25-064-04W4 03/28/12 98.0 98.0 Glacial Till Pipe NSCC P 5 06 T05-06 236679 103/02-31-064-03W4 04/03/12 346.2 329.2 Joli Fou Fm C NSCC P 9 07 J05-18 112733 108/07-22-065-04W4 04/13/12 285.6 278.2 Viking Fm C OBTC P 10 08 J05-18 112733 108/07-22-065-04W4 04/13/12 311.5 301.7 Joli Fou Fm C OBTC P 10 09 V13-31 419112 100/16-21-064-03W4 04/14/12 107.9 107.9 Glacial Till N/A NSCC P 1 210 H16-10 176418 100/07-27-065-04W4 05/06/12 291.7 283.5 Joli Fou Fm Unknown QB2 P 9 011 E11-17 376011 102/12-30-064-03W4 05/13/12 318.0 312.6 Joli Fou Fm C NSCC P 5 012 H21-09 178692 103/01-34-065-04W4 05/19/12 215.2 210.0 Second White Specks Fm C QB2 P 9 013 D62-01 157792 105/13-36-064-04W4 05/28/12 263.9 251.1 Fish Scale Fm C OBTC P 8 014 T03-14 237000 104/10-32-064-03W4 06/01/12 265.3 262.7 Fish Scale Fm Pipe NSCC P 9 015 T11-09 268184 102/09-29-064-03W4 06/18/12 235.0 234.4 Upper Colorado Shale C QB2 P 8 016 E11-13 376018 104/15-25-064-04W4 06/23/12 225.5 225.4 Fish Scale Fm C NSCC P 5 017 E11-21 376014 103/09-25-064-04W4 07/14/12 230.5 230.5 Fish Scale Fm C NSCC P 5 018 E10-09 189366 104/11-25-064-04W4 08/10/12 263.0 260.0 Fish Scale Fm Unknown OBTC P 10 019 T10-16 248827 105/16-30-064-03W4 09/15/12 342.0 337.8 Belle Fourche Fm C NSCC P 8 020 A01-15 104280 107/04-13-065-04W4 09/30/12 276.7 255.0 Fish Scale Fm C OBTC P 10 021 T10-17 248828 102/09-30-064-03W4 09/30/12 253.4 250.5 Belle Fourche Fm C NSCC P 8 022 U03-23 253384 1W0/05-03-065-03W4 10/19/12 323.3 318.2 Joli Fou Fm C QB2 P 8 023 D63-15 158390 100/07-36-064-04W4 10/19/12 254.6 246.9 Fish Scale Fm C OBTC P 8 024 V04-02 291570 103/06-34-064-03W4 11/06/12 325.9 318.8 Fish Scale Fm C NSCC P 8 025 E05-H19 287874 1W0/04-06-065-03W4 11/19/12 206.7 206.7 Belle Fourche Fm QB2 P 7 026 H69-16 413044 104/03-33-066-04W4 11/22/12 275.0 275.0 Westgate Fm NSCC P 3 027 H69-15 413151 107/03-33-066-04W4 11/22/12 266.0 266.0 Fish Scale Fm NSCC P 3 028 Y32-17 412384 108/09-36-064-04W4 11/30/12 243.8 243.6 Fish Scale Fm C VAM P 3 029 V04-04 291572 104/03-33-064-03W4 12/07/12 255.6 255.3 Belle Fourche Fm C NSCC P 8 030 E10-14 189359 107/11-25-064-04W4 12/12/12 273.0 269.4 Fish Scale Fm OBTC P 10 031 T07-04 248841 102/14-28-064-03W4 12/13/12 370.0 361.1 Joli Fou Fm NSCC P 8 0

FALURE INFORMATION

Dep

th

No

.

WELL INFORMATION


A summary of the connection type for primary intermediate connection failures detected in 2012 is provided in Table 5. Note that NSCC, VAM & QB2 thread designs have a metal-to-metal seal. It is difficult to draw any conclusions from the data presented due to the varying installation phases with the different connection types, and limited sample size with the QB2 design. Table 5: 2011 Primary Intermediate Connection Failures by Connection Design

Note: excludes U05-15, V04-13, E11-15, T03-14, (pipe body failures), V13-31 (casing collapse) and H16-10, E10-09, E05-H19, H69-16, H69-15, E10-14, and T07-04(investigation not complete) Historic consequence levels associated with intermediate casing failures since 1996 are displayed in Figure 4. One of the 31 intermediate failures (V13-31) that occurred in 2012 was assessed higher than a level 0 environmental consequence, however, the volume release was very low relative to other Level 1or 2 events.

Figure 4: Cold Lake Intermediate Failures by Consequence Level

1 2 3 4 5 6 7 8 9 10 11 12 13 TotalOBTC 0 0 0 0 0 0 0 2 0 3 0 0 1 6NSCC 0 0 0 0 3 0 0 5 1 0 0 0 0 9QB2 0 0 0 0 0 0 0 2 1 0 0 0 0 3VAM 0 0 1 0 0 0 0 0 0 0 0 0 0 1

Total 0 0 1 0 3 0 0 9 2 3 0 0 1 19

Cycle NumberConnection Type

0

5

10

15

20

25

30

35

40

1996

1997

1998

1999

2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

2010

2011

2012

Failu

re C

oun

t

Year

Level 0 Level 1 Level 2


Many enhancements in Imperial’s casing integrity processes, as discussed in section 3.0, have led to a reduction in the percentage of high pressure casing failures as shown in Figure 5. These enhancements, in addition to the improvements in other detection systems has demonstrated success in reducing higher pressure failures that have more potential for loss of liquids through the casing break and resulting consequences. In 2012 16% of failures occurred at high pressure, lowest since initially tracking this metric in 2006. Section 3.3 outlines ongoing work targeted to continually improve casing integrity performance and further reduce high pressure failures. In 2012, there were 7 new failures identified during pressure tests on suspended/zonally abandoned wells that had no potential for loss of liquids. Excluding these wells, the number of failures was the lowest since 2005.

Figure 5: Intermediate Casing Failures by Pressure Category

0.0%

5.0%

10.0%

15.0%

20.0%

25.0%

30.0%

35.0%

40.0%

45.0%

0

5

10

15

20

25

30

35

40

45

2006 2007 2008 2009 2010 2011 2012

Fai

lure

Co

un

t

Year

HP LP No Pressure %HP


The primary response to a high pressure intermediate casing failure is to control the fluid level below the casing break depth with nitrogen on the annulus and flow back up the tubing to avoid liquid losses out through the break, followed by immediate de-pressuring of the area. Imperial also maintains all necessary kill fluid additives in order to perform a high pressure fluid or mud well kill if the primary response is not possible. In 2012, the number of wells that experienced liquid loss to the break (blue line) and the volume of liquids lost out of the break (blue bar) remained low as shown in Figure 6. V13-31 was the only well that experienced a fluid loss out the break, estimated at 60-100m3. There were two mud kills required in 2012: U05-15 (barite kill), H69-16 (hematite kill).

Figure 6: Intermediate Failure Fluid Loss by Year

0

2

4

6

8

10

12

0

2000

4000

6000

8000

10000

12000

2006 2007 2008 2009 2010 2011 2012

# W

ells

wit

h L

iqu

id L

oss

Vo

lum

e (m

3)

Year

Nitrogen

Liquids

# Wells w/ Liquid Loss


The frequency of primary intermediate casing failures for commercial casing designs in Cold Lake is summarized in Figure 7. The frequency of failures in 2012 improved to the lowest level since 2006. Excluding failures on suspended wells, which have no chance of fluid loss, failure frequency would be 0.49%, the lowest since 2005.

Figure 7: Primary Intermediate Commercial Failure Frequency and Well Count

In Figure 8, the primary intermediate casing failures for the commercial casing design in Cold Lake data is stacked into early (1-4), mid (5-7), and late (8-12) cycle classifications. The number of early cycle failures has historically been lower than mid and late cycle failures and continues to be so. However there were 3 failures on early cycle wells in late 2012. Investigation work is ongoing to understand the cause of these failures. Mid cycle failures have generally been increasing since 1996; however, a significant decrease was observed in 2009 through 2012.

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Figure 8: Primary Intermediate Commercial Failures by Cycle Range

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In Figure 9, the primary intermediate failure frequency for the commercial casing design the data is, again, divided into early (1-4), mid (5-7), and late (8-12) cycle classifications. Early cycle failure frequency peaked in 2006 and has continued to decrease since. Mid cycle failure frequency steadily increased between 2004 and 2008; however, 2009 saw a marked reduction which is believed to be the result of many casing integrity initiatives underway since 2006. 2012 demonstrated a further improvement in mid cycle failure frequency, with offsetting increase in late cycle failures. The number of wells is each of the three categories breaks down as follows:

• Early (1-4) – 631 wells • Mid (5-7) – 1472 wells • Late (8+) – 2710 wells • Total – 4813 - wells

Figure 9: Primary Intermediate Commercial Failure Frequency by Cycle Range

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Primary intermediate failure detection method is displayed in Figure 10. The pre-steam casing integrity process has detected a significant portion (approximately 62%) of the casing failures at Cold Lake since its inception in 1996. The percentage of operationally detected casing failures has generally increased since 2002, primarily due to the increased detection capabilities and enhancements with passive seismic and the nitrogen soak monitoring program. Of the 19 failures detected by casing integrity check, 7 were pressure tests on suspended/zonally abandoned wells, and 12 were on wells in service at the time of the check. .

Figure 10: Primary Commercial Intermediate Failures by Detection Method

The 31 intermediate casing failures in 2012 were managed the following way:

• 9 wells were repaired using casing patch technology • 1 well repaired using slimhole technology • 4 wells were zonal abandonments • 8 wells were suspended with future plans to repair with casing patch, slimhole or abandon • 5 wells were on already zonally abandoned wells, no action was taken • 2 wells were already suspended and have plans to repair • 2 wells waiting for reservoir pressure/temperature to decrease before taking action

A breakdown of the management of each intermediate casing failure is found in Table 6. There are a number of wells that have been suspended with future plans to repair.

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Table 6: 2012 Primary Intermediate Repair Techniques

As mentioned, in 2012, 7 failures were identified on wells that were zonally abandoned or temporarily suspended and had a 5 year pressure test conducted. In total, 87 pressure tests were performed. The percentage of pressure tests that identified a new failure is higher than previous years, however, tracking failures identified on suspended wells has only been done since 2009 and the overall sample size is too small to distinguish if 2012 is statistically different from previous years. As previously mentioned, the ‘No Pressure’ failures found on zonally abandoned/suspended wells have no environmental consequence as the well is already plugged down hole.

Failure Managament

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1 U01-05 253492 106/14-33-064-03W4 01/11/12 314.7 311.5 Fish Scale Fm 8 Suspended

2 U05-15 253324 107/06-09-065-03W4 02/01/12 248.8 247.9 Fish Scale Fm 8 Repaired - Slimhole

3 V04-13 291589 100/08-34-064-03W4 02/02/12 250.0 250.0 Fish Scale Fm 8 Zonal Abandonment

4 D55-13 127639 104/06-35-064-04W4 02/16/12 287.7 286.4 Fish Scale Fm 13 Well Already Zonally Abandoned

5 E11-15 376016 102/16-25-064-04W4 03/28/12 98.0 98.0 Glacial Till 5 Suspended - Slimhole Planned

6 T05-06 236679 103/02-31-064-03W4 04/03/12 346.2 329.2 Joli Fou Fm 9 Suspended

7 J05-18 112733 108/07-22-065-04W4 04/13/12 285.6 278.2 Viking Fm 10 Repaired - Retrievable Casing Patch

8 J05-18 112733 108/07-22-065-04W4 04/13/12 311.5 301.7 Joli Fou Fm 10 Repaired - Retrievable Casing Patch

9 V13-31 419112 100/16-21-064-03W4 04/14/12 107.9 107.9 Glacial Till 1 Zonal Abandonment

10 H16-10 176418 100/07-27-065-04W4 05/06/12 291.7 283.5 Joli Fou Fm 9 Well Already Zonally Abandoned

11 E11-17 376011 102/12-30-064-03W4 05/13/12 318.0 312.6 Joli Fou Fm 5 Suspended - Slimhole Planned

12 H21-09 178692 103/01-34-065-04W4 05/19/12 215.2 210.0 Second White Specks Fm 9 Repaired - Retrievable Casing Patch

13 D62-01 157792 105/13-36-064-04W4 05/28/12 263.9 251.1 Fish Scale Fm 8 Repaired - Retrievable Casing Patch

14 T03-14 237000 104/10-32-064-03W4 06/01/12 265.3 262.7 Fish Scale Fm 9 Repaired - Retrievable Casing Patch

15 T11-09 268184 102/09-29-064-03W4 06/18/12 235.0 234.4 Upper Colorado Shale 8 Well Already Zonally Abandoned

16 E11-13 376018 104/15-25-064-04W4 06/23/12 225.5 225.4 Fish Scale Fm 5 Zonal Abandonment

17 E11-21 376014 103/09-25-064-04W4 07/14/12 230.5 230.5 Fish Scale Fm 5 Suspended - Slimhole Planned

18 E10-09 189366 104/11-25-064-04W4 08/10/12 263.0 260.0 Fish Scale Fm 10 Repaired - Retrievable Casing Patch

19 T10-16 248827 105/16-30-064-03W4 09/15/12 342.0 337.8 Belle Fourche Fm 8 Repaired - Retrievable Casing Patch

20 A01-15 104280 107/04-13-065-04W4 09/30/12 276.7 255.0 Fish Scale Fm 10 Well Already Zonally Abandoned

21 T10-17 248828 102/09-30-064-03W4 09/30/12 253.4 250.5 Belle Fourche Fm 8 Zonal Abandonment

22 U03-23 253384 1W0/05-03-065-03W4 10/19/12 323.3 318.2 Joli Fou Fm 8 Well Already Suspended - Slimhole Planned

23 D63-15 158390 100/07-36-064-04W4 10/19/12 254.6 246.9 Fish Scale Fm 8 Well Already Zonally Abandoned

24 V04-02 291570 103/06-34-064-03W4 11/06/12 325.9 318.8 Fish Scale Fm 8 Suspended

25 E05-H19 287874 1W0/04-06-065-03W4 11/19/12 206.7 206.7 Belle Fourche Fm 7 Suspended

26 H69-16 413044 104/03-33-066-04W4 11/22/12 275.0 275.0 Westgate Fm 3 HP Failure - Waiting for Pressure to Decrease

27 H69-15 413151 107/03-33-066-04W4 11/22/12 266.0 266.0 Fish Scale Fm 3 HP Failure - Waiting for Pressure to Decrease

28 Y32-17 412384 108/09-36-064-04W4 11/30/12 243.8 243.6 Fish Scale Fm 3 Suspended

29 V04-04 291572 104/03-33-064-03W4 12/07/12 255.6 255.3 Belle Fourche Fm 8 Repaired - Retrievable Casing Patch

30 E10-14 189359 107/11-25-064-04W4 12/12/12 273.0 269.4 Fish Scale Fm 10 Suspended - Retrievable Casing Patch Planned

31 T07-04 248841 102/14-28-064-03W4 12/13/12 370.0 361.1 Joli Fou Fm 8 Repaired - Retrievable Casing Patch

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Figure #11: Suspended Well Five Year Pressure Test Performance

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In 2012 3 intermediate depth casing failures were repaired by slimholing. Slimholing remains a common repair technology for Imperial Oil. In total 21 slimholes were performed in 2012, 11 of which were performed on impaired wells to return them from Producer only status to High Pressure steam capable. There are currently 246 slimhole wells within Cold Lake, representing just over 4% of the total well count. To date, 12 slimhole wells have failed (5.1% of all slimhole wells), 4 of which were near surface failures and repaired using the surface dig out technique. The 8 remaining slimhole failures were either suspended or abandoned after failure as there is currently no repair technology available for 4.5" intermediate failures.

Figure 12: Slimhole Failures

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2.3 Clearwater Casing Integrity Data

In 2012, 8 Clearwater casing failures were detected. Details of these failures are provided in Table 7. Table 7: 2012 Clearwater Failures Summary

The number and frequency of Clearwater casing failures for the commercial casing design in Cold Lake are summarized in Figure 13. The frequency of 2012 remained similar to 2009 and 2010, which was a large improvement from previous years. The reduced failure frequency is likely attributed to a large portion of the field moving to low pressure operations, an increased in use of horizontal wells, and enhanced intermediate depth shear stress management with also has an effect on Clearwater top formation movement.

Figure 13: Commercial Clearwater Failures and Failure Frequency

Well License UWI Detection Date Cycle

mm/dd/yy mKB mTVD

1 T14-06 384143 102/13-20-064-03W4 03/18/12 3 550.8 437.6

2 H65-09 409536 102/03-28-066-04W4 05/07/12 2 468.0 431.7

3 H65-16 409563 106/02-28-066-04W4 05/27/12 2 454.0 432.0

4 E11-18 376010 100/12-30-064-03W4 08/02/12 5 619.8 431.9

5 U09-14 356852 107/14-35-064-03W4 08/23/12 5 507.5 478.4

6 E11-25 376025 103/10-25-064-04W4 09/01/12 5 570.4 428.3

7 V03-15 253951 100/12-27-064-03W4 09/07/12 8 544.7 457.2

8 V03-15 253951 100/12-27-064-03W4 09/07/12 8 565.0 471.3

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COLD LAKE CASING INTEGRITY MANAGEMENT

Casing integrity is a critical component of the Operations Integrity Management System in Cold Lake. Continuous improvement with respect to casing integrity has been made throughout the history of Cold Lake Operations. Failure mechanisms that have been identified in Cold Lake wells are external corrosion (near surface failures), stress corrosion cracking (SCC), and sulphide stress cracking (SSC) with contributing factors such as metal fatigue (high strain – low cycle) and formation movement. The Cold Lake Casing Integrity Operating Practices were formally introduced in 1996 providing improvements in three major areas – prevention, detection of, and response to casing failures. Through a continuous improvement approach, the Casing Integrity Operating Practices have been enhanced, modified, and updated with new learnings since their implementation. The Casing Integrity Operating Practices are reviewed and updated annually. Improvements and initiatives in detection and prevention of (with respect to the three depth classifications), and response to casing failures relevant to 2012 and the future will be discussed in the following sections.

2.4 Casing Failure Detection

The manner in which casing failures are detected at Cold Lake has evolved through time. Imperial continues to rely on several complimentary and overlapping detection systems including:

• Differential Flow and Pressure (DFP) alarms during steam injection • Nitrogen Soak pressure and fluid level monitoring during soak and shut-in • Steam trend analysis • Passive seismic monitoring • Groundwater monitoring • Casing integrity check process

Current initiatives and recent improvements in detection methods will be discussed in the following subsections.

2.4.1 Alarm Management The monitoring system used during the steam injection portion of the cycle is known as the Delta Flow and Pressure (DFP) program. Steam injection and pressure trends are analyzed on a 15 minute frequency to detect pressure drops and corresponding flow increases. Varying levels of alarms are generated for pressure drops between 25 kPa and 250 kPa. All alarms are investigated and potential casing failure events are cross referenced to passive seismic alarms and responded to immediately in order to confirm the potential casing failure. A new method of filtering DFP events to reduce the number of false alarms and streamline casing failure detection was developed in 2009; a prototype test was completed in 2011 that validated the new systems method. The DFP algorithm has since been re-written and full implementation was initiated in 2012 and completed in January 2013.

2.4.2 Casing Integrity Check Process Since the inception of the Casing Integrity Operating Practices in 1996, casing integrity checks have been conducted pro-actively to detect casing failures. A basic casing integrity check consists of both a 21 MPa pressure test and a gauge ring/scraper run to at least the top of the Clearwater formation. If the gauge ring/scraper combination identifies a new impairment or casing deformation, or there is a previously identified severe impairment requiring follow-up, a multi-sensor caliper is run to determine the extent of the deformation. Although a well may pass a 21 MPa pressure test, the information from the gauge


ring/scraper combination can trigger additional diagnostics, which are used to confirm whether or not the wells integrity is adequate for steaming operations. Corrosion inspection logs in the top 50 meters of the wellbore are performed on wells at a prescribed age or cycle depending on vintage of well. The number of casing integrity checks performed on a pad prior to steaming is defined as part of the Casing Integrity Operating Practices, and is provided as Attachment 1. The casing integrity check frequencies were increased in 2007 for wells with metal-to-metal connections (called “upgraded” commercial casing) and for pads without passive seismic wells to enhance pre-steam confirmation of well integrity. Certain circumstances (e.g. known impairments, passive seismic events, unusual fluid levels and nitrogen soak trends) can trigger additional checks incremental to this minimum standard. A risk-based decision process is used to select wells that should be checked prior to being placed on steam. In 2007 the Targeted Selection process was implemented to select which wells should receive casing integrity checks, as well as to identify wells that should be checked incremental to the minimum standard. Targeted Selection is aimed at reviewing data indicating a potential casing failure and includes a mandatory review and close-out of passive seismic casing events, suspect nitrogen soak trends and fluid levels, DFP alarms, and suspect steam trends. There are defined standards describing when Targeted Selection requirements are to be completed and closed out prior to steam injection. The number of wells in Cold Lake has generally increased over time and the frequency of casing integrity checks increases over time with cycle number. However, the continuously changing mix of early, mid and late cycle wells and the variety of depletion methods will cause fluctuations in the total number of casing integrity checks each year. Figure 14 shows the number of casing integrity checks performed each year since 2001 as well as the percentage of casing integrity checks that found near surface or intermediate depth failures. The peak in 2007 through 2009 was primarily due to numerous Mahkeses wells reaching their first round of casing integrity checks. 2010-2012, the total number of casing integrity checks have been reducing due to a higher number of early cycle wells being steamed, an increase of injector only infill wells being steamed, and an increase in low pressure steam flood operations. Improved targeted selection and focus on specific problem pads in 2012 lead to the increased percentage of casing integrity checks that detected a failure.

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Figure 14: Casing Integrity Check History

In 2012 Imperial Oil qualified the use of Through Tubing Electro-Magnetic (EM) Logging as a method for performing a casing integrity check. Through Tubing logging and specifically the Schlumberger EM Pipe Scanner Inspection Tool was field trialed and qualified in Cold Lake. The through tubing logging technique is a less invasive method of evaluating the current condition of a casing string and does not require a service rig. The tool uses existing technology developed to evaluate corrosion of casing behind tubing or evaluation of corrosion in multiple casing strings. Based on the results of the qualification field trial, Imperial Oil has implemented the use of the Schlumberger EM Pipe Scanner as a method of casing integrity check for specific applications where determining if the casing has a failure is the only function of the integrity check.

2.5 Near Surface Casing Integrity Management

The mechanism for near surface casing failures is external corrosion. Minor wellhead packing leaks and surface water run-off collect in the conductor pipe or surface casing - production casing annulus forming a corrosion cell. Water typically accumulates in the conductor annulus due to cement slumping (after primary cementing) or cement degradation over time. Corrosion inspection logs (electromagnetic flux leakage) and casing pressure tests are completed as part of the Casing Integrity Operating Practices. Wells identified with corrosion concerns are either pressure tested to ensure suitability for service, repaired, or taken out of steam service. Improved primary cementing practices for new wells enhance the ability to achieve and maintain cement tops at or near surface. However, if the cement quality is not adequate in the production casing, the well will be repaired or taken out of steam service. Wells that have cement tops near surface are topped up with bentonite after the first steam cycle and the protective shrouds installed above the annulus. The bentonite top-ups and shrouds are maintained throughout the life of the wellbore on a prescribed frequency Imperial Oil’s bentonite top-up program and production casing inspection practices have been utilized since 1996 to manage near surface depth corrosion and confirm well integrity prior to steam. The practices have been targeted to mitigate the risk associated with a high pressure (capable of flow to surface) casing failure where there is the potential for environmental impact. Since the implementation of the Casing Integrity Operating Practices in 1996 there have been no surface depth casing failures of consequence, and Imperial Oil is confident that current practices will continue to confirm well integrity prior to steam. The majority of failures in 2012 occurred on older, late cycle, low pressure wells. The consequence associated with a near surface casing failure is low as these wells are not capable of flow to surface. In order to reduce the number of near surface failures and maintain operability of wells, several initiatives have been implemented or are being progressed, as described in the following subsections.

2.5.1 Alternative Corrosion Measurement Technologies Imperial Oil has used the Digital Vertilog (DVRT) for conducting corrosion assessments since the mid 1990’sIt an effective technology at identifying external corrosion near surface, however, changes in metal thickness, interference from the top of the conductor pipe, and changes in logging speed near surface affect the complexity and accuracy of the interpretation. In 2011, Imperial Oil conducted initial bench testing of a surface pipeline corrosion inspection technology, retro-fit for well inspection. This technology is expected to have a higher accuracy, reducing the uncertainty around corrosion measurement. Early and accurate detection will lead to fewer wells being prematurely taken out of service and more wells being proactively identified for repair, leading to fewer failures. This technology was field trialed in 2012 and plans are underway to determine if full commercial development is viable.


2.5.2 Alternative Casing Repair Technologies Imperial Oil’s original repair practice for wells with near surface failures is a surface dig out repair. This work involves suspending the well, excavating to below the failure depth, replacing the failed section of casing with new casing, and reactivating the well. The surface dig out is a proven repair method, but is complex, expensive and cannot be economically justified for all wells. In 2011, Imperial Oil tested a new near surface casing patch technology. The patch utilizes a MH patch set below the failure, L80 patch pipe, and a threaded wellhead connection. This new patch was tested in July, 2011 and after successful implementation the ERCB approved this technology as a standard repair option for future use, subject to individual well, non-routine approvals. The near surface patch can operate up to 343˚C, 10MPa and is suitable for either lower pressure steaming or POW candidates that cannot justify a surface dig out repair to return the well to high pressure CSS. In 2012 the near surface repair method was officially incorporated into Imperial Oil’s best practices.

2.6 Intermediate Depth Casing Integrity Management

The majority of intermediate depth casing failures are caused by a combination of SSC and high strain, low-cycle fatigue. Beginning in 2006 Imperial implemented a number of changes to its wellbore design and operations to improve performance, including:

• Connection spacing offset away from known weak layers • Enhanced shear stress management • Adjusted steam strategy • Targeted selection criteria for casing integrity checks • Improved nitrogen purge management • Producing well annulus gas testing environment control

The nitrogen purge management and producing well environment control are both aimed at reducing the risk of SSC. Nitrogen purging is used to reduce the presence of H2S in the casing - tubing annulus during shut-in periods. Nitrogen purge compliance for 2012 is displayed in Figure 18. Performance was at or near 100% throughout the year. Wells not achieving the purge within the 48 hour requirement were typically only exceeding the requirement by a few hours.


Figure 15: Weekly Nitrogen Purge Compliance Producing well annulus gas testing is aimed at reducing risk of SSC while producing due to temperatures below 60 oC and a corrected H2S partial pressure above 3kPaa. These wells were shut-in and purged with nitrogen until either the next steam cycle or until a warm-up is performed. In 2012, 16 wells were identified to be at risk of SSC while producing due to temperatures below 60 oC and a corrected H2S partial pressure above 3kPaa and were shut in and purged with nitrogen. In addition to these implemented initiatives, Imperial has an ongoing research program to investigate root causes and develop changes to operating practices and well construction techniques to reduce the number of intermediate depth casing failures. These initiatives are discussed in the following subsections.

2.6.1 V13-31 Casing Failure Root Cause Analysis A casing failure at V13-31 occurred on April 13, 2012 and was confirmed on April 14, 2012. A well control response team was established and initial notice to ESRD and ERCB was delivered on April 14, 2012. Daily/regular communications continued throughout the entire process. Nitrogen purge diagnostics and well flow backs were performed to de-pressure the reservoir until the well was killed by bull heading a 1375kg/m3 CaCl2 solution with freshwater across the break on April 27, 2012. Groundwater level responses at the nearby REG-11-3 monitoring well indicated hydraulic communication between V13-31 casing break and the Empress Formation-Unit 3. This was confirmed on April 26, 2012 based on nitrogen purge diagnostics. An estimated 60-100m3 of produced fluids (80:20 produced water: bitumen) was released to the Empress Formation-Unit 3 Aquifer. Imperial Oil initiated the Cold Lake Incident Response Plan and delineated, evaluated and quantified the release. V13-31 was legally abandoned in the Clearwater and Grand Rapids and recompleted as an Empress Formation-Unit 3 remediation well (96-107mKB).

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As part of the delineation phase, six delineation wells, including a 6-inch well that can be used as a remediation well were drilled in July 2012. Data loggers were installed on 5 of the 6 wells to monitor water levels. Initially, weekly analytics including BTEX were collected with evidence of produced fluids only detected at the closest monitoring well to V13-31 (~7 m). To-date, there is no evidence of produced fluids in the down-gradient monitoring well and BTEX, Chloride and Boron levels are below Canada Drinking Water Guidelines at all delineation wells being sampled. Accordingly, sampling has moved to monthly frequency. These results suggest that the relatively small release is contained to a limited area under V13 pad. A full investigation was completed to determine the root cause of the failure. It was determined that a 0.8m section of low cement bond within the production casing/surface casing annulus that was likely partially filled with fluid. Very good quality bond above and below the area of poor cement likely impeded the fluids ability to leak off as steaming occurred and the fluid expanded. The production casing collapsed due to the high pressure of the trapped fluid. The introduction of cooler nitrogen as part of the N2 purge program caused the production casing to pull apart and result in the failure. The N2 purging and change in temperature also likely caused the surface casing connection to leak, resulting in fluid loss to the aquifer. As a follow up to this failure incident, recently drilled wells’ cement bond logs were analyzed to look for responses similar to V13-31. If a similar response is found, a collapse test will be performed to ensure the well is safe for high pressure steaming. Also, Imperial Oil is evaluating alternative surface casing designs that would preferentially favor surface casing burst prior to production casing collapse occurring.

2.6.2 Well Design - Casing Connection Design In 2010, ExxonMobil Upstream Research Company (URC) completed detailed Finite Element Modeling of a new Fatigue Resistant connection that introduces modified connection geometry from the baseline connection to yield superior fatigue properties. In 2011, this connection model was built to perform physical testing of both the fatigue properties as well as seal-ability testing during thermal cycling. Testing began in mid-2011 and will continue through 2013.

2.6.3 Well Design - Material Testing Imperial began evaluating higher strength casing material for use in Cold Lake as a means of reducing casing failures. In 2010, a series of tests using T95 grade material were completed to determine the onset of SSC as a function of temperature and H2S partial pressure. The tests were based on a modified version of the NACE TM0198 slow strain rate test (SSRT) to better simulate the thermal well casing environment. The objective is to quantify performance of higher strength material in sour well environments. Based on the SSRT program for T95, the following observations were made:

• T95 exhibited superior SSC resistance compared to L80 under standard loading conditions, • T95 performance was similar to L80 in the cyclical loading environment.

In 2011, further testing was conducted to compare the low cycle fatigue characteristics of T95 vs. L80 as well as some elevated temperature characteristics of T95. The physical lab testing was completed in late 2011 and the results were analyzed in 2012 to understand the potential performance of the higher strength material. A final decision will be made in 2013. In addition to performing in-house modeling studies, Imperial is participating in a joint industry project (JIP) led by Noetic Engineering to study synergistic thermo-mechanical and environmental loads on casing. Project work is currently underway and Imperial has provided input to the scope of the project.


2.6.4 Well Operability – Fault Reactivation Research On behalf of and working closely with Imperial, ExxonMobil Upstream Research Company (URC) conducted some preliminary research looking to identify conditions that could induce fault reactivation and resulting casing deformation in specific geological horizons. The study investigated a single well model and looked to predict fault slip along a pre-existing fault and looked at the effect of fault friction and horizontal stress conditions to determine the faulting potential. This study will be extended in 2013 to look at a full pad model and to determine if steaming strategies aimed to reduce shear slip along weak bentonite layers in the Fish Scales will have the same desired affects for reducing fault re-activation in other geological horizons.

2.7 Clearwater Casing Integrity Management

Formation movement is the primary mechanism for Clearwater casing failures. As a result of the CSS process, shear stresses develop which results in slip along structurally weak planes existing at the Clearwater - Grand Rapids interface. As this shear is localized, there is no impact on intermediate casing integrity. There is no evidence that Clearwater failures cause, or are related to other intermediate depth or near surface casing failures. Although there is no adverse environmental impact, operability of the well can be restricted. The existing casing integrity program for Cold Lake was designed to address the concerns associated with the near surface and intermediate depth intervals, and was not intended to deal with the Clearwater failures. When Clearwater casing failures are detected the well is steamed below fracture pressure, unless the failure is repaired or the location of the failure is such that steam will not encroach on the Clearwater/Grand Rapids interface. Occasionally, Clearwater failures (or larger Clearwater impairments) are mitigated through the installation of shear liners for structural support or cemented patches. .

2.8 Casing Integrity Response

Currently, Imperial maintains the following equipment and materials on-site: 2 pre-mix tanks, a return tank, 280 tonnes of barite, 295 tonnes of hematite, 140m3 of 1370kg/m3 CaCl2 fluid, 156m3 of 1500kg/m3 CaCl2 fluid and all necessary kill fluid additives in order to respond to high pressure casing failures quickly. In 2012, emergency response was initiated 5 times due to high pressure casing failures and one barite mud kill and one hematite kill was required.


ATTACHMENT 1: CASING INTEGRITY CHECK FREQUENCY Casing Checks by Cycle and Design Beginning

Cycle # Commercial

Old Commercial

New/Upgraded w/o PS

Commercial New/Upgraded

w/ PS

Environmental Old

Environmental New/Upgraded

% % % % % % 1 0 0 0 0 0 2 0 0 0 0 0 3 0 0 0 0 0 4 0 0 0 0 0 5 33 33 0 100 50 6 33 33 33 100 50 7 33 33 33 100 100 8 1001 100 33 1001 100 9 1002 100 50 1002 100

10 1002 100 50 1002 100 11 1002 100 100 1002 100 12 1002 100 100 1002 100

12+ 1002 100 100 1002 100

Near Surface Corrosion Management Notes:

1. Old wells require a Vertilog at or before this cycle

2. Corrosion assessment (incremental 3.5%/yr from last Vertilog to projected steam in date) to be applied to determine operating strategy unless a current Vertilog is run to confirm.

3. New/Upgraded wells require Vertilogs as part of required CI checks based on the number of years following the first cycle’s steam in date to the planned steam date.

o Year 10 for wells with maximum expected annular pressure >6 MPa

o Year 12 for wells with maximum expected annular pressure >4 MPa and <6 MPa Additional Notes:

If a surface failure is detected all remaining wells in the current or next CI check require Vertilogs or a corrosion assessment to assess pad condition.

Horizontals and Infill wells are included in the above designs.

Commercial: L/MN-80 or IK-55 casing design with OBTC,NKEL or QB2 connections Non-Commercial: All casing designs prior to Commercial. 'Old' Wells: Wells beginning steam prior to OP#9 inception, improved steam

quality and lower volume steam injection (Jan 96). 'New' Wells: Wells beginning steam after OP#9 inception, improved steam quality

and lower volume steam injection (Jan 96). Environmental: Pads or wells within 500m of the historical high water level of a

designated water body. Water Bodies: Leming Lake, McDougal Lake, Bourque Lake, Un-named Lake in sec

35-64-04W4. Upgraded Commercial: New casing design coming out in 1998 with NSCC-M phosphate

coated 'metal-to-metal’ connections (VAM SWNA, Tenaris Blue, NSCCM, NSCC, QB2).

Known Surface Failures: Wells located on a pad which have had corrosion related surface failures (0-25m).

Cold Lake Approvals 8558 and 4510 2012 Annual Performance ...

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