encana christina lake in-situ oil scheme 2009 update

Cenovus Christina Lake In-situ Oil Scheme 2010 -2011 Update

ERCB Office | June 16, 2011

2

This Cenovus Christina Lake In-situ Oil Scheme 2011Update (“Update”) is prepared and submitted pursuant to regulatory requirements promulgated by the Energy Resources Conservation Board under its Directive 054 dated October 15, 2007. The contents of this Update are not intended to be, and may not be relied upon by any person, company, trust, partnership or other entity (“Person”) for the purpose of making any investment decision, including without limitation any decision to purchase, hold or sell any securities of Cenovus Energy Inc. or any of its affiliates (“Cenovus”).

Cenovus expressly disclaims, and makes no representation or warranty, express or implied, with respect to any of the information made available in this Update where such information is used by any Person for the purposes of making any investment decision as prohibited by this disclaimer, and none of Cenovus and its affiliates, and their respective officers, directors, employees, agents, advisors and contractors shall have any liability to any Person in respect thereof.

Disclaimer

Subsection 3.1.1 – 1 Brief Background

Everett Diamond, Development Engineer

4

Brief Background of Scheme

Q1 2000 EUB Project Approval

Q2 2002 First Steam of Phase 1A Pilot

Q4 2005 Approval of 1B Expansion

Q2 2008 1B Expansion First Steam

Q3 2008 Approval of Phase 1C/D Amendment

Q4 2009 Filing of Phase 1E/F/G EIA Application

Q1 2010 Approval of Large Gas Cap Air Repressurization

2011F 1C Expansion first Steam

Subsection 3.1.1 – 1)

5

Brief Description of Recovery Process


– high temperature steam injected into upper well heat the bitumen and allows gravity to drain

– oil and water emulsion pumped to the surface and treated

• the Christina Lake Thermal Project uses the dual-horizontal well SAGD (steam-assisted gravity drainage) process to recover bitumen from the McMurray formation

• two horizontal wells one above the other approximately 5 m apart

• steam injected into upper well heat the bitumen and allows gravity to drain

• oil and water emulsion pumped to the surface and treated

6

Area Map of Christina Lake


7Subsection 3.1.1 – 1)

Scheme Map

Current EIA

CL 1E/1F/1G EIA

Current ERCB ApprovedDevelopment Area

Proposed Development Expansion

Current EIA

CL 1E/1F/1G EIA

Previous ERCB ApprovedDevelopment Area

ERCB Approved Development Expansion


B02 Pad-4 well pairs


A02 Pad-A02-2 well pair

A01 Pad-6 well pairs

WA01-2_3 Wedge Well WA01-3_4 Wedge Well

-drilled from (B02 Pad)

Phase 1C/1D ApprovedDevelopment Area (Existing Development and Current Producers)

WA01_2 Wedge Well

WB02-1 Wedge Well






A01-3 Toe

9

Existing Source Water and Disposal wellsRD 1

15-35-76-4W4(6 well pad)

BW 210-3-75-6W4(2 well pad)

BW 110-34-75-6W4

(3 well pad)

RD 213-34-76-3W4

(3 obs well pad)

RD 313-03-77-3W4

(1 vertical obs well)Local McM

Disposal (3 well pad)

Quaternary Freshwater source (2 wells @

9-17-76-6W4)

Source Water WellWater Disposal Well

Future Water Disposal WellSubsection 3.1.1 – 1)

Section 3.1.2 SURFACE

11

3.1.2 (Surface) – AGENDA

Subsection 1 – Facilities Logan Popko

Subsection 2 – MARP Logan Popko

Subsection 3 – Water Management Logan Popko

Subsection 4 – Water Treating Logan Popko

Subsection 5 – Disposal Operations Logan Popko

Subsection 6 – Sulphur Production Logan Popko

Subsection 7 – Environmental Issues Renee Alessio

Subsection 8 – Statement of Compliance Renee Alessio

Subsection 9 – Statement of Non-Compliance Renee Alessio

Subsection 10 – Future Plans Everett Diamond

Subsection 3.1.2 – 1) Facilities

Logan Popko, Production Engineer

13

Site Survey Plan

Subsection 3.1.2 – 1a)

• No modifications to the A/B surface facilities in 2010

• Future phases (C/D) under construction and next years update will include these modifications

14Subsection 3.1.2 – 1b)

Process Schematic – Phase A/B

ABBT 0067303

ABIF 0009508

Iron Filter X3

FE 1102

FE 160/161

Brack Water104FE 1261 A/B/C/D

FE 155 A/B

FE 5044

Regen waste

Steaminjection

FE 422

FE 1409

Inlet DegasserV301

Test Sep

Treater V302 Flash V 303

Diluent V305

FE 302

FE 3014, 3011

Gas SepV304

FE 312

FE 366

FE 310

FE 307FE 261, 9003

FE 271, 9002

TCPLGas inletV500

FE 505

FE 530

Tanks blanket Gas

FE 508FE 551

Blanket Gas to SAP

V511

FE 541

V 502

Tank vapours

VRU

V503FE 503

FE 205 A/B/C/D/E/FFE 206 A/B/C/D/E/F

FE 9111-1&2, 9121- 1&2

FE 520

FE 304

FE 306

FE 403

FE 421

FE 1535 A/B/C FE 316_1/2

FE 1485 A/BFE 1540 A/B

FE 1400

Blowdown

FE 5043

ShowerOffice

Blowdown Well

FE 105

FE 305

FE 407

V 425

V 425

WLS1400

Micro bubbloer

M

M

M

MM

M

M M

M

M M

M

MM

MM

M

M

M

M

M

M

MM

M

M

M

M

M

M

MM

M

M

M

M

M

M

M

FE 169

FE 106 FE 423

FE 1205 A/B

FE 109

M

M

MM

MM

Z 1470

Brackish Source

Well

102A/B

SAC X2

WAC X2 Soft Water

101 106A/B

108A/B

FE 122

FE 1117

FE 124

M

M

M

FE 631, 670

Blow down 105

FE 651 A/B, 606 A/B/C/DE

MM

Steam Sep

111 110

Raw Water545

RawSource

Well

547A/B

M

Disposal

Regen Waste 102 105

FE 1785

FE 1726 A/B/C/D/E/F

FE 1720

FE 1750

M

M

M

FE 1731

Blow down 1715

FE 1726 A/B/C/D/E/F

MM

Steam Sep

1717 1720

BFW1700 1710

A/B

107 A

107B

Clear Well 1480

Afterfilter PK

1500

SAC PK

15301485A/B

FE 1724

FE 119

M

FE 115

1470 A/B

401402

403 A/B0

420A/B

De-Oiled 405

406

ORFMSkim 404

IGF406490

A/B/C

412A/B

407 A/B

408A/B

FE 400

411

FE 401

M

304A/B

Sales 401 A/B

Slop 402Off Spec

403Diluent

319Diluent

303

409

405

404

305 A?B

306A/B

M

301

303A/B

M

M FE 335

319A/B

Enbridge Diluent

M

FE M-11

Flare

Enbridge Blend

M FE 507

M FE 5105

Warehouse, Office Vessel make-up

Glycol heater V 501 Operations Camp

11-16-76-6W4Injection Facility & Heater

FE 515

NC

Steam Gen'sM

MFE 509

T 303 E-302

Truck-in

MFE 317

M

M

FE M-21

M

WLS

11800 m3

M

YTOTV010

Run Off Pond

MFE 101

FE 510

G C

Lift GasFE 203 A/B/C/D/E/F, 9322 A/B

FE 319

FE 225 A/B/C/D/E/F, 9312 A/B FE 226 A/B/C/D/E/F, 9302 A/BFE 236 E/F

M

M

SAGD Well

M

M FE 776

LEGEND:

Gas WaterEmulsionDiluentUtility Seal FlushRegen & Waste Fluid

Accounting Meter

Accounting Meter TBI

Operations Meter

NNU

NNU

DischargeM

M

M

Field HeatersM

FE 572A

M

A4I Compressor

M FE TBI

M

M

NNU

Schematic # 1 Christina Lake SAGD MARP Phase 1B

NNU

Access Pipeline CondensateM

15

Facility Modifications

• No major modifications of Christina Lake phase A/B facility in 2010

• Christina Lake’s future phases (C/D) are not discussed in this presentation; information will be provided in next years RMR update

Subsection 3.1.2 – 1c)

Subsection 3.1.2 – 2) Facility Performance


17

Plant Performance• Generally stable and predictable plant performance:

• Steam plant has achieved higher rates than nameplate design (106% >5450 m3/d CWE)

• Water treating (de-oiling) higher rates than nameplate design (115% > 6500 m3/d)

• Oil treating has achieved higher rates than nameplate design(107% >20,000 bbls/d)

• Minor Issues:• Cooling at high flow rates• Handling production swings

Subsection 3.1.2 -2)

18

Bitumen Treatment

• Bitumen Treatment:• Capacity of Phase 1A/B of 18,800 bopd• Have consistently achieved rates in excess of 19,000

bbls/d (high of 20,265 bbls or 107% of design achieved)• Minor issues with treating due to:

• Production swings

• High rates restricting hydraulics

• Cooling capacity at high rates

• No other major issues to report

Subsection 3.1.2 –2a)

19

Water Treatment

• De-Oiling• Capacity of phase A/B of 5,692 m3/d of water • Flowed up to 6500 m3/d of water

(115% of design)• Minor issues in de-oiling are:

– Water cooling at high flow rates

– Fouling of heat exchangers

– No other major issues to report

• Water Treatment• Produced Water treatment – commissioning completed in

October of 2008• Blowdown recycle into the produced water treatment trains

with no adverse impacts; have not been recycling blowdown recently due to excess produced water (high PWSR)

• No major issues to report

Subsection 3.1.2 – 2b)

20

Steam Generation• Phase 1A/B Steam Generation via 3 OTSGs

• Design capacity of 5144 m3/d CWE dry steam

• Have achieved rates in excess of 5450 m3/d CWE steam (106% of design)

• OTSG operation at qualities as low as 77% and high quality testing conducted as high as 85%


21

Power Usage

Subsection 3.1.2 –2d)

*Note – Plot represents monthly power imports. There is no power generation facilities at Christina Lake

7651

6052

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

9,000

Jan-1

0Feb

-10Mar-

10Apr-1

0May

-10Ju

n-10Ju

l-10

Aug-10Sep

-10Oct-

10Nov-10Dec-1

020

10 A

vgJa

n-11

Feb-11

Mar-11

2011

Avg

YTD

(MW

h)

22

Gas Usage

Subsection 3.1.2 –2e)

0

50

100

150

200

250

300

350

400

450Ja

n-10

Feb-

10M

ar-1

0Ap

r-10

May

-10

Jun-

10Ju

l-10

Aug-

10Se

p-10

Oct

-10

Nov-

10De

c-10

2010

Avg

.Ja

n-11

Feb-

11M

ar-1

120

11 A

vg Y

TD

Avg

. Gas

Vol

ume

(sE3

m3/

d)

Total Gas Used Purchased Produced Flared

23

Green House Gas Emissions

• Greenhouse gas emissions are reported to AENV on a yearly basis for review

• 2010 Stationary Combustion Emissions

– CO2 – 259,129 tonnes CO2 e

– CH4 – 103 tonnes CO2 e

– N2 O – 460 tonnes CO2 e• 2009 Flaring Emissions

– CO2 – 1,841 tonnes CO2 e

– CH4 – 184 tonnes CO2 e

– N2 O – 0.93 tonnes CO2 e

*Note – Values have been verified by and independent 3rd Party review and submitted to Alberta Environment for Approval and Issuance of Emission Performance Credits.

Subsection 3.1.2 –2f)

Subsection 3.1.2 – 3) Measurement and Reporting (MARP)


25

Measurement, Accounting, and Reporting Plan MARP (Directive 42)

• Phase A-D MARP Approved July 2010• Yearly update submitted in Feb 2011 Along with

Phase E addition to MARP• Recently submitted updated MARP for Phase A-G

• MARP Modifications:• No major changes to the MARP – updated lists to

reflect current operation • Hired 3rd party company “Eclipse” to assist us in

reviewing our MARP and assist us in preparing for our EPAP (directive 076) submission

• Hired a measurement specialist to aid us in compliance and assist in things such as meter selection types (ie. finding meters that have electronic verification capabilities)



Simplified MARP Schematic

Truck

Truck

LACT

BT

IFSteam to Field

Blow Down to Disp.

PW & Waste to Disp.

Fresh Source from Wells

Saline Source from Wells

PW to IF

Utility to BT

INV. INV.

SAGD Production

Domestic use

P/L Fuel

Lease fuel to IFLease Fuel

Lease Fuel

Cavern (future)

GasOil Water

Truck

Truck

LACT

BT

IFSteam to Field

Blow Down to Disp.

PW & Waste to Disp.

Fresh Source from Wells

Saline Source from Wells

PW to IF

Utility to BT

INV. INV.

SAGD Production

Domestic use

P/L Fuel

Lease fuel to IFLease FuelLease Fuel

Lease FuelLease Fuel

Cavern (future)

GasOil Water

GasOil Water

27

Production and Injection Volumes

• Measured Plant Bitumen• Blend (API 12.3) and bitumen inventory and trucking• Estimate by well tests (2 Phase test separators with H2O cut)

– ~8-10 wells per separator on ~12 hour cycles + purges

– Minimum of 4 tests per well per month

– Minimum of 48 hours of test time per well per month

• Steam Injection• Steam to wells measured by nozzles or V-cone (>95% quality)• Prorate well steam to plant steam (metered by flow nozzle off steam

seps, checked by BFW- BD)

• Gas Production• Plant measurement by balance (PG = burnt/inj – bought/received)• Measuring well GOR based off well test and prorate to plant measurement• Co-Injected gas monitored and reported on a well basis

Subsections 3.1.2 – 3a,c)

28

Proration Factors

• Overall water balance closure monitored on a monthly basis (< 5%)

• Steam proration typically <5%

•Oil Proration• Proration factor was high due to the BS&W probe (red-

eye) on the B02 pad separator reading incorrectly • Multiple attempts to re-calibrate the meter and troubleshoot

the situation but the meter was not reading accurately until the latest calibration in late February

• Since the meter has been fixed proration levels have returned to acceptable levels

Subsections 3.1.2 – 3b)

29

MARP – New Measurement Technology

• Cenovus continually focuses on evaluating new meter technologies; nothing has currently been trialed and tested in the last reporting period.

Subsection 3.1.2 – 3d)

Additional Section) Bottom Water Depressurization under A Pad


31

The Problem: High Bottom Water Pressure

• Historical disposal into the bottom water under A Pad caused high bottom water pressure


Local Disposal

Bottom Water Pressure

2,000

2,500

3,000

3,500

4,000

4,500

16-Dec-99 16-Mar-01 16-Jun-02 16-Sep-03 16-Dec-04 16-Mar-06 16-Jun-07 16-Sep-08 16-Dec-09 16-Mar-11

P (k

Pag)

100/06-16-076-06W4M 100/05-15-076-06W4M 100/09-13-076-06W4AA/06-02-076-06W4M AA/15-15-076-06W4M 102/03-08-076-06W4M

Disposal volume moved to 15-35 disposal site

32


0

200

400

600

800

1000

1200

1400

1600

1800

2000

600 700 800 900 1000 1100 1200A Pad Chamber Pressure - Bottom Water Pressure (kPag)

Wat

er P

rodu

ctio

n fr

om A

Pad

(m3/

d)• High bottom water pressure causes influx of water into A Pad wells causing high PW rates

• High produced water rates affect facility operation and affect water metrics (recycle ratio, blowdown recycle capability, disposal volumes, etc.)

dP between bottom water and A Pad (kPag)

33

The Solution: Dispose Remotely and Raise Chamber Pressure• Stopped disposing locally (under A Pad) and all

volumes sent out to 15-35 remote location

• Keep A Pad chamber as high as possible using steam and co-injection gas (increased chamber pressure ~400 kPa this year)

Local DisposalRemote Disposal

34

The Solution: De-Pressure Bottom Water

• 1F5/03-16-076-06W4 has been converted into a water production well:

• Completions work is completed• Currently finishing construction

Subsection 3.1.2 – 4) Water Management


36

Fresh and Brackish Sources

• Fresh wells:• Two Quaternary wells (Empress Formation) at

09-17-076-06W4M

• AENV - Licensed for up to 5,000 m3/day

• Total Dissolved Solids (TDS) 500-600 mg/L

• Brackish water source wells:• Three Clearwater B Aquifer source wells on same pad, two brought

online in September 2008, one brought online February 2011

• 1F1/13-34-75-6W4/00: TDS = 5350 mg/L

• 1F1/13-35-75-6W4/00: TDS = 7350 mg/L

• 1F1/15-27-075-06W4/00: TDS = 7590 mg/L


37

Fresh and Brackish SourcesClearwater Brackish (CW1) Currently Producing

Clearwater Brackish (CW 2) Drilled but not tied in

Clearwater Brackish (CW 3)

Expected spud date Q1 2012

CW 2

CW 1

2 Quaternary Fresh Water Source wells @ 9-17-76-6W4

McMurray Saline Water Source well @ 1F5/03-16-76-6W4 (former disposal well)

CW 3Subsection 3.1.2 – 4a)

Brackish Water TDS13-35A Well ~7,350 mg/L13-34B Well ~ 5,350 mg/L15-27 Well ~ 7,590 mg/L10-03-76-6 Pad Evaluation (CW2) ~5000 mg/L10-27-76-6 Pad evaluation (CW3) ~9700 mg/L

38

38

Fresh Water Use


Uses:• Primarily for utilities, seal flushes, etc. All attempts are made to minimize fresh water usage.

• High volumes used on February/April/Nov 2010 due to operational issues

• Original Phase A/B facility design has been modified to reduce fresh water, by changing services to softened brackish / produced

170188

050

100150200250300350400

Jan-1

0Feb

-10Mar-

10Apr-

10May

-10Ju

n-10

Jul-1

0Aug

-10Sep

-10Oct-

10Nov

-10Dec

-1020

10 A

vgJa

n-11

Feb-11

Mar-11

2011

Avg

YTD

Ave

rage

Mon

thly

Rat

e (m

3/d)

39

Brackish Water Use


Uses:• Make-up water for steam generation

• Softened water used for slurry make-up, seal flushes etc.

• High Volumes in March 2011 due to commissioning of Phase 1C

11781169

0200400600800

1000120014001600

Jan-1

0Feb

-10Mar-

10Apr-

10May

-10Ju

n-10

Jul-1

0Aug

-10Sep

-10Oct-

10Nov

-10Dec

-1020

10 A

vgJa

n-11

Feb-11

Mar-11

2011

Avg

YTD

Ave

rage

Mon

thly

Rat

e (m

3/d)

40

Produced Water Volumes

Subsection 3.1.2 4c)

56775369

0

1000

2000

3000

4000

5000

6000

7000

Jan-1

0Feb

-10Mar-

10Apr-

10May

-10Ju

n-10

Jul-1

0Aug

-10Sep

-10Oct-

10Nov

-10Dec

-1020

10 A

vgJa

n-11

Feb-11

Mar-11

2011

Avg

YTD

Prod

uced

Wat

er V

olum

e (s

m3/

d)

41

Steam Volumes

Subsection 3.1.2 4d)

50325082

0

1000

2000

3000

4000

5000

6000

Jan-1

0Feb

-10Mar-

10Apr-

10May

-10Ju

n-10

Jul-1

0Aug

-10Sep

-10Oct-

10Nov

-10Dec

-1020

10 A

vgJa

n-11

Feb-11

Mar-11

2011

Avg

YTD

Avg

. Dai

ly S

team

Inje

ctio

n (m

3/d

CW

E)

42

Produced Water Steam Ratio

Subsection 3.1.2 4e)

1.131.06

0.0

0.2

0.4

0.6

0.8

1.0

1.2

1.4

Jan-1

0Feb

-10Mar-

10Apr-

10May

-10Ju

n-10

Jul-1

0Aug

-10Sep

-10Oct-

10Nov

-10Dec

-1020

10 A

vgJa

n-11

Feb-11

Mar-11

2011

Avg

YTD

Ave

rage

Mon

thly

Rat

e (m

3/d)

43

Produced Water Recycle Percent


*Cenovus does not anticipate being below the regulated recycle percentage in the 2011 Calendar year. Currently low recycle percent number due to high water volumes (high PWSR), additional phase C steam capacity coming in the summer should allow for high water recycle numbers

86%91%

0%

20%

40%

60%

80%

100%

120%

Jan-1

0Feb

-10Mar-

10Apr-

10May

-10Ju

n-10

Jul-1

0Aug

-10Sep

-10Oct-

10Nov

-10Dec

-1020

10 A

vgJa

n-11

Feb-11

Mar-11

2011

Avg

YTD

Wat

er R

ecyc

led

%

44

Blowdown Recycle

Subsection 3.1.2 4f)

24%

0%

10%

20%

30%

40%

50%

60%

10-Ja

n10

-Feb

10-M

ar10

-Apr

10-M

ay10

-Jun

10-Ju

l10

-Aug

10-S

ep10

-Oct

10-N

ov10

-Dec

2010

Avg

11-Ja

n11

-Feb

11-M

ar

2011

Avg

YTD

(% R

ecyc

le)

0%

*Have not been able to recycle blowdown due to high produced water volumes in the facility

45

• Continue to inject into McMurray water sands at 15-35

• Approval No. 9712 and 10627 (Class 1b Disposal)

• Six disposal wells (all Class 1b)• Three disposal wells located near the facility (3-16); • One well located near the facility (3-16) has been converted for

disposal reversal• Three disposal wells in service located at 15-35. Currently utilizing two

wells with a third well as a spare (used periodically)• Three additional wells drilled this year at 15-35, not in operation yet

• Try to send all disposal volumes out to the remote sites at 15-35. When disposing locally we can adversely affect our bottom water pressure.

• Began commingling PW and Regen Waste in common disposal pipeline this year

Water Disposal Operations

Subsection 3.1.2 – 4g)

46

McMurray Water Disposal Wells

0 m

10 m

20 m

30 m

0 m

0 m

0 m

30 m

20 m

40 m 50 m60 m

70 m

80 m80 m

90 m

10 m

20 m

0 m

Existing Water Disposal100/04-16-76-6W4100/03-16-76-6W4102/07-16-76-6W4

Recently converted to water prod well1F5/03-16-76-6W4


Drilled (Q3 2010) but not in operation105/15-35-76-4W4106/15-35-76-4W4107/15-35-76-4W4

*All disposal streams always attempted to be minimized

*Disposal temperatures at remote locations is less 25oC.

*Disposal temperature at plant site is higher as there is no temperature restrictions on pipelines


47

Blowdown Disposal Volumes

1,351

921

0200400600800

1000120014001600

Jan-1

0Feb

-10Mar-

10Apr-

10May

-10Ju

n-10

Jul-1

0Aug

-10Sep

-10Oct-

10Nov

-10Dec

-1020

10 A

VGJa

n-11

Feb-11

Mar-11

2011

YTD A

VGB

low

dow

n D

ispo

sal V

olum

es (s

m3/

d)

Subsection 3.1.2 – 4h)

*Blowdown disposal volumes increased due to high PW volumes into facility

48

PW and RW Disposal Volumes


432549

0

200

400

600

800

1000

1200

Jan-1

0Feb

-10Mar-

10Apr-

10May

-10Ju

n-10

Jul-1

0Aug

-10Sep

-10Oct-

10Nov

-10Dec

-1020

10 A

VGJa

n-11

Feb-11

Mar-11

2011

YTD A

VGPW

+ R

W D

ispo

sal V

olum

es (s

m3/

d)

*High disposal months due to very high PWSR in facility

49




2,000

2,500

3,000

3,500

4,000

4,500


P (k

Pag)



50

Water Disposal Operations Cont’d


Remote Location

2200.0

2205.0

2210.0

2215.0

2220.0

2225.0

2230.0

2235.0

2240.0

2245.0

8-Mar-06 8-Nov-06 8-Jul-07 8-Mar-08 8-Nov-08 8-Jul-09 8-Mar-10 8-Nov-10 8-Jul-11

P(kP

ag)

100/08-34-076-06-04W4

Commencement of produced water treatment train commissioning

51

Disposal Well Head Pressures

0

500

1000

1500

2000

2500

3000

3500

4000

4500

5000No

v-09

Dec-

09

Jan-

10

Mar

-10

Apr-1

0M

ay-1

0

Jun-

10

Jul-1

0

Aug-

10

Sep-

10

Oct-

10

Nov-

10

Dec-

10

Jan-

11

Feb-

11

Mar

-11

Apr-1

1M

ay-1

1

Jun-

11

Jul-1

1

Dis

posa

l WH

P (k

Pag)

100/3-16 102/3-16 4-16 7-16 15A-35 15B-35 15C-35


52

Waste Disposal Site Location & Volumes

• Increased waste mainly due to high drilling activity in 2010

• Cenovus Christina Lake trucks all disposal waste to licensed third party facilities

2010 2009 2008Slop Oil (m3) 1,388 1,520 1,153

Drilling Waste (m3) 31,312 149 522

Lime Sludge (m3) 2,498 1,682 1,225

Contaminated Soils (m3) 139 282 223

Total 35,628 4,487 3,353

Subsection 3.1.2 –4i)

Facility Name TotalCCS Janvier Landfill 33,312

CCS Lindbergh Cavern 1,669

Newalta Edmonton Industrial Process 15

Newalta Elk Point 220

Newalta Hughenden 202

Newalta Redwater 39

R.B.W. Edmonton 167

Grand Total 35,628

Subsection 3.1.2 – 6) Sulphur Production


54

Operations with Sulphur Recovery

•Christina Lake Operations does not currently have sulphur recovery capability


55

Operations with no Sulphur Recovery

• Summary of conditions are as follows:

• Phase 1A & 1B• Sulphur emissions below 1.0 t/d limitation

(2.0 t/d sulphur dioxide)

• Scavenger unit to be installed as incremental production comes online. Cenovus continues to evaluate sulphur recovery technology.


56

SO2 Emissions

Subsection 3.1.2 – 5b)i)

Note: Calculated from gas flow rate to flare stack and H2S concentration of that gas

14.3

21.7

0

5

10

15

20

25

30

35

40

10-Ja

n10

-Feb10

-Mar

10-A

pr10

-May

10-Ju

n10

-Jul

10-A

ug10

-Sep

10-O

ct10

-Nov

10-D

ec20

10 A

vg.

11-Ja

n11

-Feb11

-Mar

2011

YTD Avg

.

(tonn

es)

Note: Calculated from fuel gas compositions sampled monthly

57

Monthly Sulphur Balance for Facility

• Cenovus’s Christina Lake Facility has not commenced with Sulphur Recovery at this time. The monthly air report does include a Sulphur Dioxide report that includes daily total Sulphur Dioxide emissions. There is no sulphur recovery and no produced sulphur to report.

Subsection 3.1.2 – 5b)ii)

58

Scavenger Unit Installation

• Phase 1C and 1D Scavenger Unit:• Application has been approved• Currently under construction• Required start date dependent on sulphur

production rate

Subsection 3.1.2 – 5b)iii)

59

Ambient Air Quality Monitoring

Passive Air Monitoring • Four passive station locations approved September 2010• Gathered and reported data on calculated Sulphur

Dioxide and calculated Hydrogen sulphide• 2010 monitoring and reporting satisfactory

Continuous Ambient Monitoring completed quarterly • Monitored parameters: sulphur dioxide, hydrogen

sulphide, nitrogen dioxide and wind speed and direction • 2010 monitoring and reporting requirements have been

completed

No criteria exceedances were noted in either monitoring program


60

Ambient Monitoring Trailer for 2010 Monthly Summary Results

( All Values in ppm)

Analyzer operational time did not fall below 90% each month

October November December

H2S

1 hour average 0.0085 0.0018 0.0080

24 hour average 0.0011 0.0006 0.0007

SO21 hour average 0.0035 0.0077 0.0114

24 hour average 0.0011 0.0022 0.0027

NO21 hour average 0.0802 0.0511 0.1104

24 hour average 0.3225 0.0131 0.4191


Subsection 3.1.2 – 7) Environmental Issues

Renee Alessio, Environment

62

2010 Compliance Issues AENV

• In compliance

•EPEA Approval 48522-00-00 (as amended) – 2010 contraventions discussed in section 3.1.2 9)

• Several Water Act Licences

DFO

• In compliance

• Continue to voluntarily monitor water quality in Sunday Creek and Monday Creek

ASRD

• In compliance

• B06 contractors did not follow survey flags and created trespass

•13-34 contractors did not follow survey flags and created trespass


63*A01 Pad Co-Injection Approvals Modified to increase operational flexibility

Category 2 Application filed ApprovedAir Injection, Sections 11 thru 14 10-Sep-2010 30-Mar-2010

B05_9 Well Pair 30-Nov-2009 8-Jun-2010

Xylene (Solvent) Enhanced Start-up 26-Feb-2010 8-Jun-2010

Dilation Start-up, B01-5 & B01_6 8-Jun-2010

Phase 1C/1D Scavenger & SRF Amendment Submitted 2009-07-15 Registered by ERCB July 22, 2009

8-Jun-2010

A01 PAD Wedge Wells (5), Drilled Off of B02 Pad 5-Jul-2010 20-Sep-2010

B01-7 & Rise Rate Control/ Dilation 9-Mar-2010 20-Sep-2010

Phase D-Pad Profiles 13-May-2010 20-Sep-2010

A01 Pad - Bottom Water Pressure 13-Oct-2010 Oct 27th, 2010

Pipeline Aerial Coolers to Support EnBridge Terminal 26-Jul-2009 1-Dec-2010

A01 Pad Temporary Gas Blowdown Appl. 4-Dec-2009 Not Approved

*A01 Pad Co-injection Request Amending *4-Dec-2009 11-Jan-2011

B01-05/06 Solvent Injection (CondenSAP)/ Dilation 28-Jul-2009 11-Feb-2011

Phase C Dilation Start up 4-Nov-2010 26-May-2011

Category 3 Application filed ApprovedPhases E/F/G EIA - Joint Appl. 1-Oct-2009 April 26, 2011 (ERCB)


Christina Lake Scheme Amendment Application Approvals to No.8591

64

EPEA Environmental Monitoring Programs

• Soil Monitoring Program completed in 2008 • no industrial impacts• program planned for 2012

• Annual groundwater monitoring completed in 2010 • expansion of MW network to include Phases C&D• no material change

• Annual groundwater monitoring for Arsenic completed 2010 • no material change• proposal for As monitoring will be submitted to AENV in 2011 for

review

• Annual conservation and reclamation plan submitted 2010 • commercial footprint 486 ha• continued focus on reduced footprint

• Voluntary water quality monitoring of Sunday Creek and Monday creek ongoing

• no facility related impacts noted in 2010


65

Environmental Monitoring Programs

• Wildlife and biodiversity monitoring completed in 2009

• Wildlife mitigation monitoring completed in 2009

• Wetland monitoring completed in 2009

• results submitted to AENV September 2010

• monitoring planned for 2011• monitoring on 2-year rotation

• Two fulltime onsite staff dedicated to environmental monitoring and sampling


66

Other Environmental Initiatives

• Christina Lake Regional Groundwater Water Management Committee (regional model collaboration with Devon, MEG and Cenovus)

• Alberta Biodiversity Monitoring Institute (ABMI)

• Member of Wood Buffalo Environmental Association (WEBA) as of May 2011

• Regional Aquatics Monitoring Program (RAMP)

• Cenovus is participating with Industry, AENV and WBEA • ambient air quality approval harmonization

• Chipewyan Prairie Dene First Nations Traditional Food Study


67

Reclamation

• Reclamation of disturbances related to Oil Sand Exploration (OSE) programs is ongoing

• new techniques employed in an attempt to accelerate reclamation

• Reclamation has begun on 2 borrow pits

• Interim reclamation and erosion control is ongoing

• Partnering with other industry players to support regional wetland research

Subsection 3.1.2 – 7e)

Subsection 3.1.2 – 8) Compliance


69

2010 Compliance Status

Cenovus FCCL Ltd. maintains and tracks compliance through:

• Incident Management System (IMS)

• Routine inspections

• Dedicated regulatory and environmental staff

Cenovus FCCL Ltd., believes its operations are in compliance

with ERCB approvals and regulatory requirements (i.e.

measurement, storage, flaring/venting, well placement).


Subsection 3.1.2 – 9) Non-Compliance


71

2010 Non-Compliances

• ERCB• Self disclosure on co-injection A01 PAD

• AENV• Measuring free chlorine instead of total chlorine residual at WTP

(March)• Not documenting daily dosage of chemicals added to WTP (March)• Annual analysis of required parameters not completed at WTP

(March)• Raw wastewater samples analyzed for CBOD not BOD5 (May) • Shut down WTP (June)• WWTP stopped discharging treated effluent at the discharge point

(July) • Chlorine pump at WTP shut down (July) • ~1 m3 of treated effluent overflow from WWTP holding tank

(August)• Missed daily analysis for TSS and CBOD from WTP (November)


Subsection 3.1.2 – 9) Future Plans


73

Continuation of Phased Development:Phase Regulatory

Regulatory Production Capacity ~ Bbl/day

Filing Approval First Steam Incremental Total

1A Q1 1998 Q1 2000 Q2 2002 10,000 10,000

1B Q2 2005 Q4 2005 Q2 2008 8,800 18,800

1C Q3 2007 Q2 2008 2011F 40,000 58,800

1D Q3 2007 Q2 2008 2013F 40,000 98,800

1E Q3 2009 2011 2014F 40,000 138,800

1F Q3 2009 2011 2016F 40,000 178,800

1G Q3 2009 2011 2017F 40,000 218,800

Notes: Future Plant facilities will be constructed at the existing plant site

Major Activities and Target Dates


74

Filed Applications

Subsection 3.1.1 – 8a)*A01 Pad Co-Injection Approvals Modified to increase operational flexibility






8-Jun-2010











75

Future ApplicationsSubject Potential

Filing DateCategory 1

B01, B03 – B07 Pad Group Test Separator Q2 2011

Category 2

B02, B11 Well Spacing Amendment Q2 2011

B09, B23 Well Spacing/Wedge Well Amendment Q3 2011

Discussion on Blowdown for B01, B02 Pads* TBD*

Natural Gas / Air Injection Amendment (Future Gas Caps) Q4 2011

Category 3

Phase 1H Scheme Approval Q4 2012


*Meet with ERCB first (Q3 2011) regarding Cenovus Blowdown Strategy

76

Major Plans Requiring Future Applications

•Baseline data gathering commencing in Q2 2011 for Phase 1H.

• Equivalent to CL Phase 1E of 1C/D/E• Additional Well Pads and Supporting

Infrastructure


77

Changes to Plant Design or Water Treatment Strategy

• Current plans are consistent with existing approvals and 1C/D SRF amendment, and 1E/F/G application

• Any future changes will be communicated via notifications or amendments as required

•Phase H application will continue to look for new improvements to plant design or water treatment strategy that was proposed in the EFG application


Discussion and Questions

Cenovus Christina Lake In-situ Oil Scheme 2010 - 2011 Update

ERCB Office | June 15, 2011

This Cenovus Christina Lake In-situ Oil Scheme 2011 Update (“Update”) is prepared and submitted pursuant to regulatory requirements promulgated by the Energy Resources Conservation Board under its Directive 054 dated October 15, 2007. The contents of this Update are not intended to be, and may not be relied upon by any person, company, trust, partnership or other entity (“Person”) for the purpose of making any investment decision, including without limitation any decision to purchase, hold or sell any securities of Cenovus Energy Inc. or any of its affiliates (“Cenovus”).

Cenovus expressly disclaims, and makes no representation or warranty, express or implied, with respect to any of the information made available in this Update where such information is used by any Person for the purposes of making any investment decision as prohibited by this disclaimer, and none of Cenovus and its affiliates, and their respective officers, directors, employees, agents, advisors and contractors shall have any liability to any Person in respect thereof.

Disclaimer

Presenter

Presentation Notes

Disclaimer needs to be updated to reflect Cenovus

Contents of Presentation

Section 3.1.1 – SUBSURFACE (June 16, 2011)

Appendix 1 – as per requirements of Subsection 3.1.1 (5d)

Appendix 2 – as per requirements of Subsection 3.1.1 (7h)

Section 3.1.1 SUBSURFACE

3.1.1 (Subsurface) – AGENDA

Subsection 1 - Brief Background Everett Diamond

Subsection 2 - Geology and Geophysics James Newsome

Subsection 3 – Drilling and Completions Logan Popko

Subsection 4 – Artificial Lift Logan Popko

Subsection 5 – Instrumentation Logan Popko

Subsection 6 – 4D Seismic Lori Barth

Subsection 7 – Scheme Performance Maliha Zaman

Subsection 8 – Future Plans Everett Diamond

Subsection 3.1.1 – 1 Brief Background


Brief Background of Scheme

Q1 2000 EUB Project Approval

Q2 2002 First Steam of Phase 1A Pilot

Q4 2005 Approval of 1B Expansion

Q2 2008 1B Expansion First Steam

Q3 2008 Approval of Phase 1C/D Amendment

Q4 2009 Filing of Phase 1E/F/G EIA Application

Q1 2010 Approval of Large Gas Cap Air Repressurization

2011F 1C Expansion first Steam


Presenter

Presentation Notes

NOTE: All text on slide should be aligned on left hand side with the Title. (thus in the above example the “E” from the title and the two “H”s from the Headings are all aligned from top to bottom.

Brief Description of Recovery Process


– high temperature steam injected into upper well heat the bitumen and allows gravity to drain

– oil and water emulsion pumped to the surface and treated

• the Christina Lake Thermal Project uses the dual-horizontal well SAGD (steam-assisted gravity drainage) process to recover bitumen from the McMurray formation

• two horizontal wells one above the other approximately 5 m apart

• steam injected into upper well heat the bitumen and allows gravity to drain

• oil and water emulsion pumped to the surface and treated

Area Map of Christina Lake



Scheme Map

Current EIA

CL 1E/1F/1G EIA



Current EIA

CL 1E/1F/1G EIA






A01 Pad-6 well pairs

WA01-2_3 Wedge Well WA01-3_4 Wedge Well

-drilled from (B02 Pad)

Phase 1C/1D ERCB ApprovedDevelopment Area (Existing Development and Current Producers)

WA01_2 Wedge Well

WB02-1 Wedge Well






A01-3 Toe

RD 115-35-76-4W4

(6 well pad)

BW 210-3-75-6W4(2 well pad)

BW 110-34-75-6W4

(3 well pad)

RD 213-34-76-3W4

(3 obs well pad)

RD 313-03-77-3W4

(1 vertical obs well)Local McM

Disposal (3 well pad)

Quaternary Freshwater source (2 wells @

9-17-76-6W4)

Source Water WellWater Disposal WellFuture Water Disposal Well


Existing Source Water and Disposal wells

Subsection 3.1.1 – 2 Geology and Geophysics

James Newsome, Geologist; Lori Barth, Geophysicist


Scheme Map

Current EIA

CL 1E/1F/1G EIA



Current EIA

CL 1E/1F/1G EIA




Phase 1C/1D ApprovedDevelopment Area

Reservoir Properties (Approved Area)Average SAGD Pay: 27.7 metersAverage Porosity (Ø): .34 fractionAverage Oil Saturation: .79 fractionRock Volume: 1,013 x 106 m3

SOIP= 1,712 MbblsNote:SOIP = Rock Volume in Development area x phi (.34) x So (.79)

SAGDable vs. Producible OIP

We are presenting two tables• SAGDable OIP and Producible OIP

We define SAGDable OIP as:• (Planned Length) x (Spacing) x (Net SAGD Pay: Base to Top SAGD) x (So ) x (Ø)

– Note have used drilled length for existing well pairs but will use planned length for all future pairs• a “before-drilling” OOIP, used during planning phase • doesn’t change after well pair plans finalized• used to plan additional wells (wedge wells, bypassed pay producers, re-drills, new pairs)• this is essentially a “planned” OOIP, as we would aim to drill the full planned length

(typically 800m), and drill the producer well as low as possible in relation to Base SAGD

We define Producible OIP as:• (Effective Length) x (Spacing) x (Effective Pay: Producer to Top SAGD) x (So ) x (Ø)• an “after-drilling” OOIP, based on well pair potential• changes with time and interpretation (obs. wells, 4D seismic, MWD error, etc.)• used to plan blowdown strategy• this reflects actual well pair performance

– incorporates actual overlapping slotted liner lengths initially (including blank sections <100m)

– incorporates actual location of the producing well

Producible OIP is always < SAGDable OIP



Liner Hanger 4-1/2" Outer

2-7/8" Inner2-3/8" Inner

7" Slotted Liner

5-1/2" Outer

2-7/8" Inner

Injector

Producer

Liner Hanger

5-1/2" Outer

7" Slotted Liner

1" Thermocouple String

2-7/8" Inner

Total (ICP to TD)

Effective (Slotted Liner Overlap)

Tota

l (SA

GD

Top

to S

AG

D B

ASE

)

Effe

ctiv

e (S

AG

D T

opto

Pro

duce

r)

SAGDable vs. Producible OIP (Definition)

Vertical Horizontal

Presenter

Presentation Notes

These numbers are from Phas1AB_OOIP_June11 (2).xls and are calculated in worksheet (Sheet2) in CL AEUB Volumes_Char.xls

SAGDable Oil in Place (SOIP) and % Recovery – A01 Pad

* up to March 31, 2011 Subsection 3.1.1 – 2b)

Producible Oil in Place (POIP) and % Recovery – A01 Pad

A01A01

A02A02

B02B02

B01B01

Presenter

Presentation Notes

DOne

SAGDable Oil in Place (SOIP) and % Recovery – B01 Pads

* up to March 31, 2011Subsection 3.1.1 – 2b)

Producible Oil in Place (POIP) and % Recovery – B01 Pads

A01A01

A02A02

B02B02

B01B01

Presenter

Presentation Notes

Done

Producible Oil in Place (POIP) and % Recovery – B02 Pads

* up to March 31, 2011Subsection 3.1.1 – 2b)

SAGDable Oil in Place (SOIP) and % Recovery – B02 Pads

A01A01

A02A02

B02B02

B01B01

Presenter

Presentation Notes

Done

Producible Oil in Place (POIP) and % Recovery


SAGDable Oil in Place (SOIP) and % Recovery

0 20 40 60 80 100

1

2

3

4

Year

Percent Recovery (SOIP)

A01 PadB02 PadB01 PadA02 Pad

2008

2009

2010

2011

0 20 40 60 80 100

1

2

3

4

Yea

r

Percent Recovery (POIP)

A01 PadB02 PadB01 PadA02 Pad

2008

2009

2010

2011

Presenter

Presentation Notes

new

SAGD Pay (net bitumen)

Isopach (with posted values)


Paleozoic Structure


McMurrayIsopach


SAGD Pay Base with posted values(SSTVD meters)


SAGD Pay Top with posted values(SSTVD meters)


McMurrayStructure


SAGD Gas Isopach


Representative Composite Log Pad B01 102\06-15-76-6 W4

SAGD GAS

SAGDPay

WaterZone

SAG

D In

terv

al

Lithology

Mud

PaleoLmst

WabiskawMcMurrayShales

Brackish BayGas

Mud


- pervasive basal mud layer often separates bitumen andMcMurray water

- Basal mud is discontinuous and ranges from 0-4 metersin thickness

- provides a good marker during SAGD operations

Location

Representative Composite Log Pad B04 (Phase C Wells)102\06-15-76-6 W4

SAGDPay

WaterZone

SAG

D In

terv

al

Lithology

Mud

PaleoLmst

WabiskawMcMurrayShales

Mud


- pervasive basal mud layer often separates bitumen andMcMurray water

- Basal mud is discontinuous and ranges from 0-4 metersin thickness

- provides a good marker during SAGD operations

LocationSAGD GAS

Christina Lake ‘A01 pad’ Pilot Cores

6-16 (A01-1)

12-16 (A01-3)

Subsection 3.1.1 – 2f)

12-16-76-6W4

Average So from offsetting wells ~ 80%


6-16-76-6W4

Average So from offsetting wells is ~ 80%


McMurray Cored WellsTotal Cored Wells (Proper) - 1752011 Cored Wells - 242010 Cored Wells - 9

Analysis-routine core analysis-photos-caprock integrity


2011 Strat

2010 WellsCored

2011 Obs

-strat and strat/cored wells are generally abandoned.-some strat and strat/cored wells are cased if theyare further used for SAGD observation wells.

-all abandoned and cased wells are examined for integrityby the completions department prior to SAGD

startup.

Representative SAGD Well Pairs (B01 Pad)

Proper

Depth (m)TVD SS Well ID

& KB

Toe & HeelLocation

Tops atWell Location

Rt Log

Lithology

GR Log

Paleozoicon ProfileWater Zone

on Profile

Well Offset fromProfile (meters)

ProducerProfile

InjectorProfile

SAGD BaseGeological

SAGD Base3D Seismic/Geological

SAGD TopOil Zone

SAGDGas Top

SAGD GAS

Well ProfileHorizon Identification and Nomenclature

Subsections 3.1.1 – 2h,i)

B04-1 Cross-Section


B03-4 Cross-SectionJune 27, 2008

Proper

June 27, 2008

Comments:-elevated SAGD base on right-geostats indicates higher SAGD base

By-pass PayPotential


B05-7 Cross-Section

B05Well: 7Profile

June 27, 2008

Proper

June 27, 2008

Comments:-profile elevated on right toavoid perm barriers.


B07-5 Cross-Section

Proper


RepresentativeCross-Sections



Cross-Section A – A’ (Saturation)


Cross-Section A – A’ (Lithology)

Sand Mud

Cross-Section B-B’ (Saturation)



Cross-Section B-B’ (Lithology)

Sand Mud

B B’

Abd. Mud Channel

Abd. Mud Channel

Subsections 3.1.1 2j) and 2k) – Geomechanical and Surface Heave

• Integrated InSar (Synthetic Aperture Radar) Land Deformation Monitoring took place between May-October 2009 by MDA Geospatial Services Inc

• The measurements were successfully made on 22 corner reflector locations installed on April 2008

• In addition to the Corner Reflectors, the deformation profiles at 4837 hard targets were estimated (Coherent Target Monitoring-CTM). The location of these points coincides in general with pad, pipeline and plant structures.

Subsections 3.1.1 – 2j,k)

Study Area

Geomechanical and Surface Heave


Corner ReflectorLocations



Cumulative deformation at the Corner Reflectorsfrom May 2008 to October 2010

(mm)




5

4

1

3

6

7

18

17

9

(mm)




CR 21

CR 22

CR 13

CR 12

CR 10

CR 19

CR 11

CR 14

CR 15

CR 16

CR 20

Highest at 70 mm

(mm)




CR 12

+ 30 mm

~ 1 year

(mm)



Cumulative deformation at the Corner Reflectorsfrom May 2008 to May 2009

A

A’

McM

Wab

CLWThere are no obvious geologicalreasons for the increased heavein the CR# 12/13 area.

Overall this pad has been subjectedto extended gas lift prior to ESPconversion in comparison to Pad A.

Overall the heave is negligible.



RADARSAT-2 CTM data acquired from July 2, 2008 to October 20, 2010

Subsidence

(mm)

Stratigraphic Wells 501(461-Cenovus/40 Others)-2011

- 2D Seismic - 155 km- 3D Seismic - 80 km2

(entire project area now covered by 3D)

•2011 4D - 2.95 km2

•2011 3D – 6.29 km2

•2011 – 33 Strat Wells, 22 Obs wells

•2010 4D – 2.36 km2

•2010 Baseline 4D –16.52 km2

•2010 – 24 Strat Wells

McMurrayGeologicalDatabase

2010 & 2011 4D Seismic

2010 Strat Wells

2011 Strat Wells

Subsection 3.1.1 – 2l)

2011 3D Seismic acquisition (Q1

2011)

Reservoir Fracture Pressure and Cap Rock Monitoring

•No new learnings since last presentation

•Cored cap rock interval in 1AB/15-10-076-06W4 in Feb 2011

• Core samples sent to rocks mechanics lab in Houston for compressive strength testing

• Results expected early 2012

Subsections 3.1.1 – 2j,m)

Subsection 3.1.1 – 3) Drilling and Completions


Recent Commercial ActivityB02 Wedge wells

-drilled Q4, 2010

-2 A01 pad wedge wells

-1 wedge b/t B01 and B02

B01-7

-drilled Q4, 2010

B04 Pad (8 prod/injectors)

-drilled Q1-2, 2010 (B04 Pad)





-drilled Q1 2011B05 Pad (9 prod/injectors)

-drilled Q3, 2010 (B03 Pad)

B04B04B07B07

B05B05

B03B03

B02B02

B01B01A01A01

A02A02

SAGD Completions – Circulation and Gas Lift

Liner Hanger 4-1/2" Outer

2-7/8" Inner2-3/8" Inner

7" Slotted Liner

5-1/2" Outer

2-7/8" Inner

Injector

Producer

Liner Hanger

5-1/2" Outer

7" Slotted Liner

1" Thermocouple String

2-7/8" Inner

Subsections 3.1.1 – 3b,c)

1.25” Thermocouple String

Presenter

Presentation Notes

Presenter: Jason Owner: Updated: Final: Final – last year Question: Notes: No Changes – May 14 2009

339.7 mm 71.4 kg/mH-40 ST&C Surface Casing

244.5 mm 59.5 kg/mL-80 QB2 Production casing

Liner Hanger

Production Tubing:114.3 mm tubing

Bubble Tube and Thermocouple:48.3 mm IJ tbg

Sample ESP Producer Completion with Tailpipe

Tail Pipe

ESP


Presenter

Presentation Notes

Presenter: Simon Owner: Jason Updated: Final: Questions: Notes: Reflects majority of new ESP completions – No Change. May 14 2009


244.5 mm 59.5 kg/mL-80 QB2 Production casing

Liner Hanger

Production Tubing:114.3 mm tubing

Bubble Tube and Thermocouple:48.3 mm IJ tbg

Sample ESP Producer Completion with-out Tailpipe

ESP


Presenter

Presentation Notes

Presenter: Jason Owner: Jason Updated: Final: Questions: Notes: Reflects A Pad ESP completions

Sample Modified Injector Completion


244.5 mm 59.53 kg/mL-80 QB2 Casing

Liner Hanger

Steam Subs

Injection Tubing



B02 Pad-B02-1 well pair-B02-2 well pair-B02-3 well pair-B02-4 well pair

B01 Pad-B01-1 well pair-B01-2 well pair-B01-3 well pair-B01-4 well pair-B01-5 well pair-B01-6 well pair

A01-3 ToeA01 Pad-A01-1 thruA01-6 wellpairs

WA1_2 Wedge Well

-drilled Q1, 2010 (A01 Pad)

2010 ERCB ApprovedDevelopment Area (Operating Producers)

A4

A3A2

A5

A6

A1WA1_2

Subsection 3.1.1 – 4) Artificial Lift


Review of Artificial Lift By Well

• Summary: 19 producing wells on 4 pads to date • Sixteen 220oC ESPs, Two 250oC ESP’s and one gas lift

• A01 Pad Wells (8) • All six original A01 Pad producers are operating on ESP• Also, the A01-3 toe producer and the A01 Wedge well are

operating on ESP

• B01 Pad Wells (6)• B01-1,2,3,6 operating on 220oC ESP• B01-4 operating on 250oC ESP• B01-5 operated on gas lift until the intersection with the

overlying Section 15 gas cap

• B02 Pad Wells (4)• B02-1,2,3 are operating on 220oC ESP• B02-4 is operating on 250oC ESP


Presenter

Presentation Notes

Presenter: Jason Owner: Jason Updated: Final: Questions: Notes: Updated May 14 2009

Artificial Lift Performance

• Gas Lift (currently B01-5):• Typical operating pressure 3,500 – 5,000 kPag• No temperature limitations, go as hot as ~250oC• Average emulsion flow rate ~ 600-1200 m3/d

• 220 °C ESP (16 current wells):• Typical operating pressure 1,800 – 3,000 kPag• Downhole temperature limitation of ~220oC• Average emulsion flow rate ~ 200-1000 m3/d

• Piloted 250 °C ESP (currently in B01-4 and B02-4):• Typical operating pressure 1,800 – 4,500 kPag• Downhole temperature limitation of ~250oC• Average emulsion flow rate ~200-1200 m3/d


Presenter

Presentation Notes

Presenter: Jason Owner: Jason Updated: Final: Questions: Notes: Updated May 14 2009

Subsection 3.1.1 – 5) Instrumentation


Hanging Wire Piezometer Temperature Observation Cemented Casing Piezometers

Instrumentation in Observation Wells – Typical Completions

45Subsections 3.1.1 – 5a,b)

Presenter

Presentation Notes

Presenter: Chris/Jason Owner: Updated: Final: Questions: Notes: No Changes Required

Map of Observation WellsPiezometer Wells

Thermocouple Wells

Subsection 3.1.1 – 5b,c)

(cemented)Piezometer Wells

(Hanging wire)

Presenter

Presentation Notes

Presenter: Chris/Jason Owner: Updated: Final: Questions: Notes: Graphic has been updated. May 19 2009

Subsection 3.1.1 – 5c) and d) – Instrumentation Data

• Requirements under Subsection 3.1.1 5c) and d) are located in the Appendix

Subsections 3.1.1 – 5c,d)

Presenter

Presentation Notes

Presenter: Chris/Jason Owner: Updated: Final: Questions: Notes: Maliha to update data in Appendix

Subsection 3.1.1 – 6) 4D Seismic

Lori Barth, Geophysicist

3D/4D Locations and 2011 Program Survey: CL-094D-001

Subsections 3.1.1 – 2l), 6a)

2011 4D and

CL-104D-001Location

2011 RST logging program

CL South2011 3D

4D Seismic in 2010 for Steam Chamber of B-padSteam Chamber (Top of Structure)

Cold OBWell

Hot OBWell

B02-4

B02-3

B02-2

B02-1

B01-1

B01-2

B01-3

B01-4

B01-5

B01-6

Low High

Structure


Presenter

Presentation Notes

Aerial extension of steam growth after: Approximately 36 months steam injection into B021 and B022 (on circulation Oct 2006, steam winter 2007) Approximately 24 months into B024 (on circulation Dec 2007 steam Feb 2008) Approximately 21 months into B023 (on circulation Feb 2008, steam May 2008) Approximately 18 months into B011, B012 and B013 and 17 months into B014 (on circulation May 2008, steam Aug 2008 and Sept 2008)

T11

Paleo

Top Steam

gamma

temp (thermocouples)

temp (RST log)

Sg (RST)

4D Seismic Profile of B02-4 in 2010

Heel Middle Toe

Steam zone

B01-1

B01-2


Presenter

Presentation Notes

The Seismic profile of B02-4 horizontal well path showing the amplitude difference between 2006 and 2009; heel to toe is 900 m long; GR (dark green) and Temp. log (white), the scales of temp. log is 0 to 250 degrees; - top of the steam is mapped based on the large amplitude difference which ties to the temperature log in observation well 100/11-15-76-07W4

Subsection 3.1.1 – 7) Scheme Performance

Maliha Zaman, Reservoir Engineer

SAGD Summary to Date• 19 total production wells in operation to date

• 17 standard well pairs- 16 ESPs; 1 gas lift

• 1 offset toe producer well

– Increase recovery from A01-3 well pair • 1 wedge well

– Increase recovery from A01-1 and A01-2 well pairs

• 8 producers on A01 Pad• All 8 are operating on ESP

– 6 standard well pairs, currently operating on natural gas co-injection

• Co-injection: Up to 60.0 e3m3/d natural gas; 600 m3/d steam per pad

• Operating at ~2,200 kPag

– 1 offset toe producer

– 1 wedge well


Presenter

Presentation Notes

Presenter: Chris/Jason Owner: Updated: Final: Questions: Notes: Update May 19

SAGD Summary to Date (cont’d)• 4 producers on B02 Pad

• All 4 are standard well pairs operating ~ 2,400 kPag• All 4 are operating on ESP

• 6 producers on B01 Pad• All 6 are standard well pairs operating• 1 is operating on gas lift (B01-5) ~ 4,500 kPag• 5 is operating on ESP (B01-1 to B01-4 and B01-6) ~ 2,400 kPag


Presenter

Presentation Notes

Presenter: Chris/Jason Owner: Updated: Final: Questions: Notes: Update May 19

Christina Lake Performance

0

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

4,500

5,000

5,500

6,000

6,500

May-02

Nov-02

May-03

Nov-03

May-04

Nov-04

May-05

Nov-05

May-06

Nov-06

May-07

Nov-07

May-08

Nov-08

May-09

Nov-09

May-10

Nov-10

Rat

e (m

3/da

y)

0.0

5.0

10.0

15.0

20.0

25.0

30.0

35.0

40.0

45.0

50.0

55.0

60.0

65.0

Rat

e (e

3m3/

d), S

team

-Oil

Rat

io,

Pres

sure

(mPa

)

Oil Rate (m3/d) Water Rate (m3/d ) Steam Inj Rate (m3/d)Inst SOR Cum SOR Monthly Average Pressure (mPa)Produced Gas Rate (e3m3/d) Gas Co-Injection Rate (e3m3/d)


Presenter

Presentation Notes

Done


0

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

4,500

5,000

5,500

6,000

6,500

May-02

Nov-02

May-03

Nov-03

May-04

Nov-04

May-05

Nov-05

May-06

Nov-06

May-07

Nov-07

May-08

Nov-08

May-09

Nov-09

May-10

Nov-10

Rat

e (m

3/da

y)

0.0

5.0

10.0

15.0

20.0

25.0

30.0

35.0

40.0

45.0

50.0

55.0

60.0

65.0

Rat

e (e

3m3/

d), S

team

-Oil

Rat

io,

Pres

sure

(mPa

)


Start-up A01-1 through A01-3

Start-up B02-3, B02-4

Plant Turn around Plant Turn around

Start-up A01-4

Start-up A01-5, A01-6


Start-up B02-1, B02-2

Start-up B01-5 B01-6

Start-up B01-1, B01-2, B01-3,

B01-4

Start-up A01W01

Presenter

Presentation Notes

LOGAN

Christina Lake Project SOR

0.00

0.50

1.00

1.50

2.00

2.50

3.00

3.50

4.00

May-02

Nov-02

May-03

Nov-03

May-04

Nov-04

May-05

Nov-05

May-06

Nov-06

May-07

Nov-07

May-08

Nov-08

May-09

Nov-09

May-10

Nov-10

Rat

e (m

3/da

y)

Inst SOR Cum SOR



0

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

4,500

5,000

5,500

6,000

6,500

Jan-10 Mar-10 May-10 Jul-10 Sep-10 Nov-10 Jan-11 Mar-11

Rat

e (m

3/da

y)

0.0

5.0

10.0

15.0

20.0

25.0

30.0

35.0

40.0

45.0

50.0

55.0

60.0

65.0

Rat

e (e

3m3/

d), S

team

-Oil

Rat

io,

Pres

sure

(mPa

)



A01W01 Start-Up

B01-5/B01-6 Start-Up

Presenter

Presentation Notes

New

Subsection 3.1.1 – 7a)ii)

Christina Lake Cumulative % Recovery Based on SAGDable OOIP (SOIP)

0

10

20

30

40

50

60

70

80

May-02Aug-02Nov-02Feb-03May-03Aug-03Nov-03Feb-04May-04Aug-04Nov-04Feb-05May-05Aug-05Nov-05Feb-06May-06Aug-06Nov-06Feb-07May-07Aug-07Nov-07Feb-08May-08Aug-08Nov-08Feb-09May-09Aug-09Nov-09Feb-10May-10Aug-10Nov-10Feb-11

Date

Rec

over

y (%

)

A01-1 A01-2 A01-01+A01-02+WA012A01-3 A01-3 + A01-3 TP A01-4A01-5 A01-6 B02-1B02-2 B02-3 B02-4B01-1 B01-2 B01-3B01-4 B01-5 B01-6A01-01+A01-02

Presenter

Presentation Notes

New

Christina Lake Cumulative % Recovery Based on Producible OOIP (POIP)


0

10

20

30

40

50

60

70

80

May-02

Aug-02

Nov-02

Feb-03

May-03

Aug-03

Nov-03

Feb-04

May-04

Aug-04

Nov-04

Feb-05

May-05

Aug-05

Nov-05

Feb-06

May-06

Aug-06

Nov-06

Feb-07

May-07

Aug-07

Nov-07

Feb-08

May-08

Aug-08

Nov-08

Feb-09

May-09

Aug-09

Nov-09

Feb-10

May-10

Aug-10

Nov-10

Feb-11Date

Rec

over

y (%

)

A01-1 A01-2 A01-01+A01-02+WA012A01-3 A01-3 + A01-3 TP A01-4A01-5 A01-6 B02-1B02-2 B02-3 B02-4B01-1 B01-2 B01-3B01-4 B01-5 B01-6A01-01 + A01-02

Presenter

Presentation Notes

New

Christina Lake Cumulative SOR


1

1.5

2

2.5

3

3.5

4

May-02

Aug-02

Nov-02

Feb-03

May-03

Aug-03

Nov-03

Feb-04

May-04

Aug-04

Nov-04

Feb-05

May-05

Aug-05

Nov-05

Feb-06

May-06

Aug-06

Nov-06

Feb-07

May-07

Aug-07

Nov-07

Feb-08

May-08

Aug-08

Nov-08

Feb-09

May-09

Aug-09

Nov-09

Feb-10

May-10

Date

CSO

R

A01-1 A01-2 A01-3 A01-4 A01-5 A01-6 B02-1 B02-2B02-3 B02-4 B01-1 B01-2 B01-3 B01-4 Project

Presenter

Presentation Notes

New

Subsection 3.1.1 – 7a)i)

A01-1, A01-02, and WA12 Well Pair Performance

1.00

1.20

1.40

1.60

1.80

2.00

2.20

2.40

2.60

2.80

3.00Ja

n-10

Feb-

10

Mar

-10

Apr-

10

May

-10

Jun-

10

Jul-1

0

Aug-

10

Sep-

10

Oct

-10

Nov

-10

Dec

-10

Jan-

11

Feb-

11

Mar

-11

Date

CSO

R

CSOR A01-1 CSOR A01-2 CSOR A01-1+A01-2+WA12 CSOR A01-1 + A01-2

Presenter

Presentation Notes

Presenter: Chris/Jason Owner: Updated: Final: Questions: Notes: Talk to Chris about this slide. JPA

Scheme Performance Prediction

• Predict well pair performance based on modified Butler’s equation

• Predict well pair CSOR using published CSOR correlations (Edmunds & Chhina 2002)

• Generate overall scheme production performance by adding individual well forecasts over time to honour predicted plant steam capacity

Subsection 3.1.1 – 7a)i)

Presenter

Presentation Notes

Presenter: Chris/Jason Owner: Updated: Final: Questions: Notes: Talk to Chris about this slide. JPA

Low, Medium, High Recovery Pads / Patterns

• The three example well pairs provided in Subsection 3.1.1 – 7b) illustrate:

• High recovery (A01-2) • Medium recovery (B02-3), and • Low recovery (B01-5) patterns

Subsection 3.1.1 – 7c)iii)

A01-2 Well Pair – High Recovery

A01-2A01-2

TO-02 obs well

TO-02 obs well

Subsections 3.1.1 – 7b),c)iii)

A01-2 Well Pair Performance

0

100

200

300

400

500

600

700

800

900

May

-02

Sep-

02

Jan-

03

May

-03

Sep-

03

Jan-

04

May

-04

Sep-

04

Jan-

05

May

-05

Sep-

05

Jan-

06

May

-06

Sep-

06

Jan-

07

May

-07

Sep-

07

Jan-

08

May

-08

Sep-

08

Jan-

09

May

-09

Sep-

09

Jan-

10

May

-10

Sep-

10

Jan-

11

Date

Rat

e (m

3/d)

0.00

1.00

2.00

3.00

4.00

5.00

6.00

7.00

8.00

9.00

10.00

Stea

m-O

il R

atio

, G

as R

ate

(e3m

3/d)

Pres

sure

(MPa

)

Oil Rate (CD) m3/d Water Rate (CD) m3/d Steam Inj Rate m3/d Instantaneous Steam-Oil Ratio (Monthly) m3/m3 Cumulative Steam-Oil Ratio m3/m3 Natural Gas Co-Inj Rate E3m3/dProd Gas Rate E3m3/d Monthly Average Pressure (MPa)

Co-Injection

Plant Turnaround ESP Deployed

Plant Turnaround


Co-Injection

Presenter

Presentation Notes

LOGAN -check


T0-02 (A01-2 Middle)

B02-3 Well Pair – Medium Recovery

B02-3B02-3


B02-3 Well Pair Performance

0

100

200

300

400

500

600

700

Jan-

08

Mar

-08

May

-08

Jul-0

8

Sep

-08

Nov

-08

Jan-

09

Mar

-09

May

-09

Jul-0

9

Sep

-09

Nov

-09

Jan-

10

Mar

-10

May

-10

Jul-1

0

Sep

-10

Nov

-10

Jan-

11

Mar

-11

Date

Rat

e (m

3/d)

0.00

2.00

4.00

6.00

8.00

10.00

12.00

Stea

m-O

il R

atio

, G

as R

ate

(e3m

3/d)

Pres

sure

(MPa

)

Oil Rate (CD) m3/d Water Rate (CD) m3/d Steam Inj Rate m3/d Instantaneous Steam-Oil Ratio (Monthly) m3/m3 Cumulative Steam-Oil Ratio m3/m3 Prod Gas Rate E3m3/dMonthly Average Pressure (MPa)

Plant Turn aroundESP Deployed

Plant Turn around


Presenter

Presentation Notes

LOGAN-check

B01-5 Well Pair – Low Recovery

B01-5B01-5




0

100

200

300

400

500

600

700

800

900

Jan-

10

Feb-

10

Mar

-10

Apr

-10

May

-10

Jun-

10

Jul-1

0

Aug

-10

Sep

-10

Oct

-10

Nov

-10

Dec

-10

Jan-

11

Feb-

11

Mar

-11

Date

Rat

e (m

3/d)

0.00

2.00

4.00

6.00

8.00

10.00

12.00

Stea

m-O

il R

atio

, G

as R

ate

(e3m

3/d)

Pres

sure

(MPa

)


• Well started up using steam dilation

• Modified Injector Completion Used from the start

Presenter

Presentation Notes

LOGAN to add annotations

0

1000

2000

3000

4000

5000

6000

7000

8000

01-Sep-02

30-Dec-02

29-Apr-03

27-Aug-03

25-Dec-03

23-Apr-04

21-Aug-04

19-Dec-04

18-Apr-05

16-Aug-05

14-Dec-05

13-Apr-06

11-Aug-06

09-Dec-06

08-Apr-07

06-Aug-07

04-Dec-07

02-Apr-08

31-Jul-08

28-Nov-08

28-Mar-09

26-Jul-09

23-Nov-09

23-Mar-10

21-Jul-10

18-Nov-10

18-Mar-11

Date

Pres

sure

, kPa

g

A01-1 A01-2 A01-3 A01-4 A01-5 A01-6

A01 Pad Chamber Pressures - RAW


Presenter

Presentation Notes

NEW

0

1000

2000

3000

4000

5000

6000

01-Sep-02

03-Mar-03

02-Sep-03

03-Mar-04

02-Sep-04

04-Mar-05

03-Sep-05

05-Mar-06

04-Sep-06

06-Mar-07

05-Sep-07

06-Mar-08

05-Sep-08

07-Mar-09

06-Sep-09

08-Mar-10

07-Sep-10

09-Mar-11

Date

Pres

sure

, kPa

g

A01-1 A01-2 A01-3 A01-4 A01-5 A01-6

A01 Pad Chamber Pressures – ‘Sanitized’

Circulation Phases

Low Pressure ESP operations (all)High Pressure gas lift (all)


Presenter

Presentation Notes

NEW

0

1000

2000

3000

4000

5000

6000

01-May-0830-Jun-0829-Aug-0828-Oct-0827-Dec-0825-Feb-0926-Apr-0925-Jun-0924-Aug-0923-Oct-0922-Dec-0920-Feb-1021-Apr-1020-Jun-1019-Aug-1018-Oct-1017-Dec-1015-Feb-11

Date

Pres

sure

, kPa

g

B01-1 B01-2 B01-3 B01-4 B01-5 B01-6

B01 Pad Chamber Pressures

High P (B01-2 and B01-3)Circulation (all wells)

Low Pressure ESP operations (B01-4)

Low P (B01-1) Chamber initially coalesced with B02-1;

Followed by communication with gas cap

High Pressure operations (B01-4)

High P (B01-1)


High P (B01-5)

High P (B01-6)Low P (B01-6)

Started using water dilation; Connected to bottom-water;

Early conversion to ESP

Presenter

Presentation Notes

LOGAN-check

0

1000

2000

3000

4000

5000

6000

01-Dec-06 31-Mar-07 29-Jul-07 26-Nov-07 25-Mar-08 23-Jul-08 20-Nov-08 20-Mar-09 18-Jul-09 15-Nov-09 15-Mar-10 13-Jul-10 10-Nov-10 10-Mar-11

Date

Pres

sure

, kPa

g

B02-1 B02-2 B02-3 B02-4

B02 Pad Chamber Pressures

High Pressure gas lift (B02-1 and B02-2)

High Pressure gas lift (B02-3 and B02-4)

Low Pressure ESP operations (B02-1 and B02-2) Low P ESP (B02-1, B02-2, B02-3

and B02-4)

Circulation (B02-3 and B02-4)


Circulation (B02-1 and B02-2)

Presenter

Presentation Notes

LOGAN-check

SOIP, % Recovery, and Ultimate Recovery by Pad

PadNet

SAGD Pay (m)

Drilled Length

(m)

Spacing (m)

Average ϕ Average So

CumulativeOil Production

(e3m3)*

SOIP(e3m3)

%Recovery

UltimateRecovery (e3m3)

Ultimate % Recovery

A01 31.13 696.7 115 0.33 0.80 1,878.5 3,979 47.2 1,927 48

B01 34.79 835.6 100 0.34 0.85 930.0 5,377 17.3 2,654 49

B02 35.11 834.4 100 0.33 0.84 990.7 3,089 32.1 1,594 52

Total 3,799 12,445 30.5 6,176 49.6

Pad Effective SAGD (m)

Effective Length (m)

Spacing (m)

Average ϕ Average So

CumulativeOil Production

(e3m3)*

POIP(e3m3)

%Recovery

UltimateRecovery (e3m3)

Ultimate % Recovery

A01 27.24 550.13 100 0.35 0.80 1,878.5 2,965 63.4 1,927 65

B01 27.85 790.3 100 0.34 0.85 930.0 4,083 22.8 2,654 65

B02 29.72 778.2 100 0.33 0.84 990.7 2,453 40.4 1,594 65

Total 3,799 9,501 40.0 6,176 65.0

POIP, % Recovery, and Ultimate Recovery by Pad

* up to March 31, 2011

Subsection 3.1.1 – 7c)i,ii)

Presenter

Presentation Notes

New

5 Yr Outlook – Pad Abandonments

• There are no anticipated pad abandonments for any of the Christina Lake wells at this time

Subsection 3.1.1 – 7c)iv)

Wellhead Steam Quality

• Current steam quality injected into A01 Pad is 98- 99%

• Quality is high due to the location of A01 Pad relative to steam generation

• Quality at B01 Pad and B02 Pad is calculated to be ~96%

• Currently steam head pressure is operated at 8.9MPag with a corresponding steam temperature of 303oC


Subsection 3.1.1 – 7e) Steam Chamber Development at A01 Pad

Lori Barth, Geophysicist

Christina Proper Area Data Map

R10

R RST

Thermocouples

Piezometers


Wabiskaw Shale Mark

T11 BB Gas Top McMurray top

BB Gas Base

UM Gas Top

UM Gas Base

SAGD Top Pay SAGD Top

SAGD Top Rich

SAGD Base Paleo

300

310

320

330

340

350

360

370

380

180

190

200

210

220

230

240

250

260

310

320

330

340

350

360

370

380

UWI: 103121607606W400Name: PCP PCR 12A2 LEISMER 12-16-76-ELEV: KB 568.2 METERSTD: 508.0 METERS MD

200 C

R.R. Aug., 2001Start-up June, 2002First prod. Oct., 2002Steam SI Feb, Mar/04Co-injection Aug.,2004Prod SI Dec/04-Mar/05Coinjection July, 2005

Note: Gas top in 2007 4Dand RSTsMinor changes in 2009 RST

Gas Top

Steam Top

RST Logs2009 2007


200 C

Steam Top

R.R. Aug., 2001Start-up June, 2002First prod. Oct., 2002Steam SI Feb, Mar/04Co-injection Aug.,2004Prod SI Dec/04-Mar/05Coinjection July, 2005

Note: A-3PT drilled in 2008New P is 30m+ to NorthOriginal P&I are 4-5m lower

Initial steam in 2004

RST Logs2010 2009


Gas Top

Steam Top

GR

Sg Temperature

A3 Profile: 4D Seismic Amplitude Difference(2001/2007) Subsection 3.1.1 – 7e)

MeterTVD

0 150APIGR

-400 1200mVSP

0.2 2000ohm.mILD

0.2 2000ohm.mAT60

0.2 2000ohm.mAT30

0.45 -0.15DPSS

Meters

TVD TVDSS

Wabiskaw Shale Mark

T11 BB Gas Top McMurray top

BB Gas Base

UM Gas Top UM Gas Base

SAGD Top Pay SAGD Top

SAGD Top Rich

SAGD Base SHBreak Top

Water Top

SHBreak Base

Paleo

310

320

330

340

350

360

370

380

390

400

410

170

180

190

200

210

220

230

240

250

260

310

320

330

340

350

360

370

380

390

400

410

UWI: 100061607606W400

Name: PCP PCR 6C LEISMER 6-16-76-6ELEV: KB 571.7 METERSTD: 518.0 METERS MD

R.R. Sept., 2001Start-up May, 2002First prod. Sept., 2002SAP starts Aug., 2004Co-inj start Aug., 2006

Note: Good steam chamberP, I are in clean sandsGas in 4D seismic (2007)

Gas Top

No major changes between 2007 and 2009Gas present in IHS above steam top

RST Logs2009 2007

Steam Top

200 C


200 C

Steam Top

Gas Top 2007

R.R. Sept., 2001Start-up May, 2002First prod. Sept., 2002SAP starts Aug., 2004Co-inj start Aug., 2006

Note: Fully developed steam chamberGas present above steam topIn 2007 4D


A1 Profile: 4D Seismic Amplitude Difference(2001/2007)

Steam Top

Gas Top

GR

Sg Temperature


Subsection 3.1.1 – 7e) Co-Injection at A01 Pad


• Co-injection of methane with steam in SAGD has been demonstrated in the field to consistently improve SOR

• High percentage of injected methane appears to get produced preventing excessive accumulation in the steam chamber

• Starting to understand how gas behaves in reservoir. • Simulations being conducted to investigate how gas is moved

around in the chamber • Intend to present results of a simulation study (with gas) to

ERCB once complete

Methane Co-injection Experience


Co-Injection of Methane at A01 Pad• Natural gas is currently co-injected with steam into A01-1 thru A01-6

• The composition of this gas is ~99% pure methane as it is delivered to the wells from our main gas pipeline

• Average concentrations for Jan 2010 – March 2011• A01-1 – 32.1 m3 C1 / m3 steam (C.W.E.)• A01-2 – 27.4 m3 C1 / m3 steam (C.W.E.)• A01-3 – 25.9 m3 C1 / m3 steam (C.W.E.)• A01-4 – 25.3 m3 C1 / m3 steam (C.W.E.)• A01-5 – 41.3 m3 C1 / m3 steam (C.W.E.)• A01-6 – 33.2 m3 C1 / m3 steam (C.W.E.)

• Average current operating conditions (based on new co-injection approvals)

• Up to 60 e3m3/d natural gas, 600 m3/d steam for the entire pad• Operating pressure ~ 2,200 kPag and rising


A01-1 Co-Injection Performance

A01-1 phases of operation

Period RF (%)

(SOIP)

RF (%)

(POIP)

CSOR

(v/v)

Aug ’05 – Aug ’06 (SAGD – 12 mo.)

26.3 – 32.7 (0.53%/mo)

37.8 – 47.1 (0.78%/mo)

2.46 – 2.45

Aug ‘06 – Dec ’06 (co-inj – 4 mo.)

32.7 – 34.7 (0.50%/mo)

47.1 – 49.9 (0.70%/mo)

2.45 – 2.43

Dec ’06 – Dec ’07 (SAGD – 12 mo.)

34.7 – 39.9 (0.43%/mo)

49.9 – 57.3 (0.62%/mo)

2.43 – 2.32

Dec ’07 – Mar ‘11 (co-inj – 39 mo.)

39.9 – 54.6 (0.38%/mo)

57.3 – 78.5 (0.54%/mo)

2.32 – 2.23


Presenter

Presentation Notes

New



Period RF (%)

(SOIP)

RF (%)

(POIP)

CSOR

(v/v)

Jul ’04 – Jul -05 (SAGD – 12 mo.)

16.2 – 19.7 (0.29%/mo)

21.9 – 26.6 (0.39%/mo)

2.55 – 2.95

Jul ’05 – Dec ’06 (co-inj – 17 mo.)

19.7 – 28.5 (0.52%/mo)

26.6 – 38.4 (0.69%/mo)

2.95 – 2.86

Dec ’06 – Dec ’07 (SAGD – 12 mo.)

28.5 – 31.9 (0.28%/mo)

38.4 – 43.0 (0.38%/mo)

2.86 – 2.79

Dec ’07 – Mar ‘11 (co-inj – 39 mo.)

31.9 – 42.3 (0.27%/mo)

43.0 – 57.0 (0.36%/mo)

2.79 – 2.61


Presenter

Presentation Notes

new



Period RF (%)

(SOIP)

RF (%)

(POIP)*

CSOR

(v/v)

Aug ’03 – Aug ‘04 (SAGD – 12 mo.)

8.5 – 18.1 (0.80%/mo)

10.9 – 23.1 (1.02%/mo)

2.46 – 2.41

Aug ‘04 – Dec ’06 (co-inj – 28 mo.)

18.1 – 35.6 (0.63%/mo)

23.1 – 45.4 (0.80%/mo)

2.41 – 1.58

Dec ’06 – Dec ’07 (SAGD – 12 mo.)

35.6 – 39.1 (0.29%/mo)

45.4 – 49.9 (0.38%/mo)

1.58 – 1.65

Dec ’07 – Mar ‘11 (co-inj – 39 mo.)

39.1 – 54.1 (0.38%/mo)

49.9 – 69.2 (0.49%/mo)

1.65 – 1.63

* - includes POIP of A01-3 and A01-3 toe producer


Presenter

Presentation Notes

new



Period RF (%)

(SOIP)

RF (%)

(POIP)

CSOR

(v/v)

Jul ’04 – Jul -05 (SAGD – 12 mo.)

6.1 – 13.2 (0.59%/mo)

7.4 – 16.1 (0.73%/mo)

2.90 – 2.89

Jul ’05 – Dec ’06 (co-inj – 17 mo.)

13.2 – 24.3 (0.65%/mo)

16.1 – 29.6 (0.79%/mo)

2.89 – 2.70

Dec ’06 – Dec ’07 (SAGD – 12 mo.)

24.3 – 29.0 (0.39%/mo)

29.6 – 35.4 (0.48%/mo)

2.70 – 2.53

Dec ’07 – Mar ’11 (co-inj – 39 mo.)

29.0 – 41.9 (0.33%/mo)

35.4 – 51.1 (0.40%/mo)

2.53 – 2.28


Presenter

Presentation Notes

new



Period RF (%)

(SOIP)

RF (%)

(POIP)

CSOR

(v/v)

Jun ’05 – Jun ‘06 (SAGD – 12 mo.)

7.2 – 17.6 (0.87%/mo)

10.4 – 25.4 (1.25%/mo)

2.72 – 2.71

Jun ’06 – Dec ’06 (co-inj – 6 mo.)

17.6 – 23.3 (0.95%/mo)

25.4 – 33.6 (1.37%/mo)

2.71 – 2.70

Dec ’06 – Dec ’07 (SAGD – 12 mo.)

23.3 – 29.0 (0.48%/mo)

33.6 – 41.8 (0.68%/mo)

2.70 – 2.78

Dec ’07 – Mar ‘11 (co-inj – 39 mo.)

29.0 – 39.4 (0.27%/mo)

41.8 – 56.8 (0.38%/mo)

2.78 – 2.68


Presenter

Presentation Notes

new



Period RF (%)

(SOIP)

RF (%)

(POIP)

CSOR

(v/v)

Dec ’06 – Dec ’07 (SAGD – 12 mo.)

27.6 – 35.2 (0.63%/mo)

39.4 – 50.4 (0.92%/mo)

2.47 – 2.58

Dec ’07 – Mar ‘11 (co-inj – 39 mo.)

35.2 – 44.3 (0.23%/mo)

50.4 – 63.3 (0.33%/mo)

2.58 – 2.74


Presenter

Presentation Notes

new

A01 Pad General Co-Injection Performance

A01 Pad phases of operation

Period RF (%)

(SOIP)

RF (%)

(POIP)

CSOR

(v/v)

Dec ’05 – Dec ’06 (co-inj – 12 mo.)

20.7 – 29.4 (0.73%/mo)

27.8 – 39.5 (0.98%/mo)

2.47 – 2.37

Dec ’06 – Dec ’07 (SAGD – 12 mo.)

29.4 – 34.2 (0.40%/mo)

39.5 – 45.9 (0.53%/mo)

2.37 – 2.36

Dec ’07 – Mar ’11 (co-inj – 39 mo.)

34.2 – 47.2 (0.33%/mo)

45.9 – 63.4 (0.45%/mo)

2.36 – 2.24


Presenter

Presentation Notes

new

Co-Injection Experience to Date• To date, co-injection has not demonstrated a negative impact on production or recovery

• After first phase of co-injection (shut-in on Dec 2006), steam- only SAGD operations resumed with no negative impacts

• Second phase of co-injection is proceeding, with encouraging results

• CSOR appears steady, and in most cases is decreasing with time• Rate of recovery is about 0.45% POIP per month

(0.33% SOIP per month) for the pad• Similar recovery rate as last cycle of SAGD in 2007


Additional Section) Bottom Water Depressurization under A01 Pad



• Historical disposal into the bottom water under A01 Pad caused high bottom water pressure


Local Disposal


2,000

2,500

3,000

3,500

4,000

4,500


P (k

Pag)




0

200

400

600

800

1000

1200

1400

1600

1800

2000

600 700 800 900 1000 1100 1200A Pad Chamber Pressure - Bottom Water Pressure (kPag)

Wat

er P

rodu

ctio

n fr

om A

Pad

(m3/

d)• High bottom water pressure causes influx of water into A01 Pad wells causing high PW rates

• High produced water rates affect facility operation and affect water metrics (recycle ratio, blowdown recycle capability, disposal volumes, etc.)

dP between bottom water and A Pad (kPag)


The Solution: Dispose Remotely and Raise Chamber Pressure• Stopped disposing locally (under A01 Pad) and all

volumes sent out to 15-35 remote location

• Keep A01 Pad chamber as high as possible using steam and co-injection gas (increased chamber pressure ~400 kPa this year)

Local DisposalRemote Disposal


The Solution: De-Pressure Bottom Water

• 1F5/3-16-076-06W4 has been converted into a water production well

• Completions work is completed• Currently finishing construction


Subsection 3.1.2 – 4) Water Management


Fresh and Brackish Sources

• Fresh wells:• Two Quaternary wells (Empress Formation) at

09-17-076-06W4M

• AENV - Licensed for up to 5,000 m3/day

• Total Dissolved Solids (TDS) 500-600 mg/L

• Brackish water source wells:• Three Clearwater B Aquifer source wells on same pad, two brought

online in September 2008, one brought online February 2011

• 1F1/13-34-75-6W4/00: TDS = 5350 mg/L

• 1F1/13-35-75-6W4/00: TDS = 7350 mg/L

• 1F1/15-27-075-06W4/00: TDS = 7590 mg/L


Fresh and Brackish SourcesClearwater Brackish (CW1) Currently Producing

Clearwater Brackish (CW 2) Drilled but not tied in

Clearwater Brackish (CW 3)

Expected spud date Q1 2012

CW 2

CW 1

2 Quaternary Fresh Water Source wells @ 9-17-76-6W4

McMurray Saline Water Source well @ 1F5/03-16-76-6W4 (former disposal well)

CW 3Subsection 3.1.2 – 4a)

Brackish Water TDS13-35A Well ~7,350 mg/L13-34B Well ~ 5,350 mg/L15-27 Well ~ 7,590 mg/L10-03-76-6 Pad Evaluation (CW2) ~5000 mg/L10-27-76-6 Pad evaluation (CW3) ~9700 mg/L

Fresh Water Use


Uses:• Primarily for utilities, seal flushes, etc. All attempts are made to minimize fresh water usage.

• High volumes used on February/April/Nov 2010 due to operational issues

• Original Phase A/B facility design has been modified to reduce fresh water, by changing services to softened brackish / produced

170188

050

100150200250300350400

Jan-1

0Feb

-10Mar-

10Apr-

10May

-10Ju

n-10

Jul-1

0Aug

-10Sep

-10Oct-

10Nov

-10Dec

-1020

10 A

vgJa

n-11

Feb-11

Mar-11

2011

Avg

YTD

Ave

rage

Mon

thly

Rat

e (m

3/d)

Presenter

Presentation Notes

Presenter: Jason Owner: Rebecca / Jason Updated: May 18, 2010 Final: Yes Question:

Brackish Water Use


Uses:• Make-up water for steam generation

• Softened water used for slurry make-up, seal flushes etc.

• High Volumes in March 2011 due to commissioning of Phase 1C

11781169

0200400600800

1000120014001600

Jan-1

0Feb

-10Mar-

10Apr-

10May

-10Ju

n-10

Jul-1

0Aug

-10Sep

-10Oct-

10Nov

-10Dec

-1020

10 A

vgJa

n-11

Feb-11

Mar-11

2011

Avg

YTD

Ave

rage

Mon

thly

Rat

e (m

3/d)

Presenter

Presentation Notes

Presenter: Jason Owner: Rebecca / Jason Updated: May 18, 2010 Final: Yes Question:

Produced Water Volumes

Subsection 3.1.2 4c)

56775369

0

1000

2000

3000

4000

5000

6000

7000

Jan-1

0Feb

-10Mar-

10Apr-

10May

-10Ju

n-10

Jul-1

0Aug

-10Sep

-10Oct-

10Nov

-10Dec

-1020

10 A

vgJa

n-11

Feb-11

Mar-11

2011

Avg

YTD

Prod

uced

Wat

er V

olum

e (s

m3/

d)

Presenter

Presentation Notes

Presenter: Jason Owner: Jason Updated: May 18, 2010 Final: Yes Question:

Steam Volumes

Subsection 3.1.2 4d)

50325082

0

1000

2000

3000

4000

5000

6000

Jan-1

0Feb

-10Mar-

10Apr-

10May

-10Ju

n-10

Jul-1

0Aug

-10Sep

-10Oct-

10Nov

-10Dec

-1020

10 A

vgJa

n-11

Feb-11

Mar-11

2011

Avg

YTD

Avg

. Dai

ly S

team

Inje

ctio

n (m

3/d

CW

E)

Produced Water Steam Ratio


1.131.06

0.0

0.2

0.4

0.6

0.8

1.0

1.2

1.4

Jan-1

0Feb

-10Mar-

10Apr-

10May

-10Ju

n-10

Jul-1

0Aug

-10Sep

-10Oct-

10Nov

-10Dec

-1020

10 A

vgJa

n-11

Feb-11

Mar-11

2011

Avg

YTD

Ave

rage

Mon

thly

Rat

e (m

3/d)

Presenter

Presentation Notes


Produced Water Recycle Percent


*Cenovus does not anticipate being below the regulated recycle percentage in the 2011 Calendar year. Currently low recycle percent number due to high water volumes (high PWSR), additional phase C steam capacity coming in the summer should allow for high water recycle numbers

86%91%

0%

20%

40%

60%

80%

100%

120%

Jan-1

0Feb

-10Mar-

10Apr-

10May

-10Ju

n-10

Jul-1

0Aug

-10Sep

-10Oct-

10Nov

-10Dec

-1020

10 A

vgJa

n-11

Feb-11

Mar-11

2011

Avg

YTD

Wat

er R

ecyc

led

%

Presenter

Presentation Notes


Blowdown Recycle

Subsection 3.1.2 4f)

24%

0%

10%

20%

30%

40%

50%

60%

10-Ja

n10

-Feb

10-M

ar10

-Apr

10-M

ay10

-Jun

10-Ju

l10

-Aug

10-S

ep10

-Oct

10-N

ov10

-Dec

2010

Avg

11-Ja

n11

-Feb

11-M

ar

2011

Avg

YTD

(% R

ecyc

le)

0%

*Have not been able to recycle blowdown due to high produced water volumes in the facility

Presenter

Presentation Notes

Presenter: Jason Owner: Jason Updated: Updated plot to reflect 2009 Avg Final: Yes Question:

• Continue to inject into McMurray water sands at 15-35

• Approval No. 9712 and 10627 (Class 1b Disposal)

• Six disposal wells (all Class 1b)• Three disposal wells located near the facility (3-16); • One well located near the facility (1F5/3-16) has been converted for

disposal reversal• Three disposal wells in service located at 15-35. Currently utilizing two

wells with a third well as a spare (used periodically)• Three additional wells drilled this year at 15-35, not in operation yet

• Try to send all disposal volumes out to the remote sites at 15-35. When disposing locally we can adversely affect our bottom water pressure.

• Began commingling PW and Regen Waste in common disposal pipeline this year



Presenter

Presentation Notes


McMurray Water Disposal Wells

0 m

10 m

20 m

30 m

0 m

0 m

0 m

30 m

20 m

40 m 50 m60 m

70 m

80 m80 m

90 m

10 m

20 m

0 m


Recently converted to water prod well1F5/03-16-76-6W4


Drilled (Q3 2010) but not in operation105/15-35-76-4W4106/15-35-76-4W4107/15-35-76-4W4

*All disposal streams always attempted to be minimized

*Disposal temperatures at remote locations is less 25oC.

*Disposal temperature at plant site is higher as there is no temperature restrictions on pipelines


Blowdown Disposal Volumes

1,351

921

0200400600800

1000120014001600

Jan-1

0Feb

-10Mar-

10Apr-

10May

-10Ju

n-10

Jul-1

0Aug

-10Sep

-10Oct-

10Nov

-10Dec

-1020

10 A

VGJa

n-11

Feb-11

Mar-11

2011

YTD A

VGB

low

dow

n D

ispo

sal V

olum

es (s

m3/

d)


*Blowdown disposal volumes increased due to high PW volumes into facility

PW and RW Disposal Volumes


432549

0

200

400

600

800

1000

1200

Jan-1

0Feb

-10Mar-

10Apr-

10May

-10Ju

n-10

Jul-1

0Aug

-10Sep

-10Oct-

10Nov

-10Dec

-1020

10 A

VGJa

n-11

Feb-11

Mar-11

2011

YTD A

VGPW

+ R

W D

ispo

sal V

olum

es (s

m3/

d)

*High disposal months due to very high PWSR in facility




2,000

2,500

3,000

3,500

4,000

4,500


P (k

Pag)



Presenter

Presentation Notes


Remote Location

2200

2205

2210

2215

2220

2225

2230

2235

2240

2245

24-Mar-06 10-Oct-06 28-Apr-07 14-Nov-07 01-Jun-08 18-Dec-08 06-Jul-09 22-Jan-10 10-Aug-10

P (k

Pag)

100/08-34-076-06-04W4

Water Disposal Operations Cont’d

Commencement of produced water treatment train commissioning


Presenter

Presentation Notes


Disposal Well Head Pressures

0

500

1000

1500

2000

2500

3000

3500

4000

4500

5000No

v-09

Dec-

09

Jan-

10

Mar

-10

Apr-1

0M

ay-1

0

Jun-

10

Jul-1

0

Aug-

10

Sep-

10

Oct-

10

Nov-

10

Dec-

10

Jan-

11

Feb-

11

Mar

-11

Apr-1

1M

ay-1

1

Jun-

11

Jul-1

1

Dis

posa

l WH

P (k

Pag)

100/3-16 102/3-16 4-16 7-16 15A-35 15B-35 15C-35


Waste Disposal Site Location & Volumes

• Increased waste mainly due to high drilling activity in 2010

• Cenovus Christina Lake trucks all disposal waste to licensed third party facilities

2010 2009 2008Slop Oil (m3) 1,388 1,520 1,153

Drilling Waste (m3) 31,312 149 522

Lime Sludge (m3) 2,498 1,682 1,225

Contaminated Soils (m3) 139 282 223

Total 35,628 4,487 3,353

Subsection 3.1.2 –4i)

Facility Name TotalCCS Janvier Landfill 33,312

CCS Lindbergh Cavern 1,669

Newalta Edmonton Industrial Process 15

Newalta Elk Point 220

Newalta Hughenden 202

Newalta Redwater 39

R.B.W. Edmonton 167

Grand Total 35,628

Subsection 3.1.1 – 7e) Gas-Over-Bitumen


GOB Issue

Depleted Gas Pools Over Bitumen

Shutin pressure was ~500 to 1,600 kPa

Need to re-pressure to equilibrate between water, bitumen and gas zones Water Influx

SAGD CHAMBER

Bitumen Zone

SAGD CHAMBER

Bottom Water connected to an aquiferPressure estimated at 3,000 kPa

Depleted Top Gas Zone (500-2000 kPa)Initial Pressure of 2000 kPa

3000

500

2500

2500

Pressure (kPa)

OperatingAt Shutin


Phase 111-16 Brackish Bay Gas Pools;

OGIP ~1.1BcfPhase 2Section 15 SAGD Gas Pools;

OGIP ~1.0Bcf

Phase 3Section 11,12,13,14 SAGD Gas Pools;

OGIP ~8.0Bcf

Piezometer WellsPotential Gas Injector


Christina Lake - gas cap re-pressuring

Producer : 6-14

Injector : 7-14

Producer : 6-12Producer : 6-11

Injector : 10-11

Injector : 14-12

Injector : 6-11

Tied in March 2011

Piezo : 1-14

Piezo : 13-11

Piezo : 15-11

Piezo : 13-12

Piezo: 6-12

Piezo: 5-13

piezo : 9-13Piezo : 11-14

Producer

Injector

Piezometer

LEGEND

Map of Gas Cap with Producers, Injectors and Piezometers Locations.


PipelinesInstalled Injection Wells Tied in March 2011 Projected Contingent Wells


Presenter

Presentation Notes

Presenter: Jason Owner: Updated: Final: Questions: Notes: Asked Hollis for and updated graphic. May 19 2009

Large Gas Pool (Phase 3) con’t

Q1 2010• Received approval to repressure Large Gas Pool with air - #8591K• No air injection has occurred through March 31, 2010• Pressure ~ 500-600 kPag

Q2 2010• Air injection was started on April 2010• Summary of the injection and pressure till March 31st, 2011 can be

found in the table below


Total Injected Gas Volume (Bcf)

Total Injected Gas Volume (e3m3)

Average Pressure in Gas Cap (kPa)

1.39 39,301 1,175

Presenter

Presentation Notes

Presenter: Jason Owner: Updated: Final: Questions: Notes: Slide updated May 19 2009

Large Gas Pool (Phase 3) con’t


0.0

100.0

200.0

300.0

400.0

2010‐01‐01

2010‐01‐31

2010‐03‐02

2010‐04‐01

2010‐05‐01

2010‐05‐31

2010‐06‐30

2010‐07‐30

2010‐08‐29

2010‐09‐28

Time. days

Air

Rat

es, E

3m3

0.0

200.0

400.0

600.0

800.0

1000.0

1200.0

1400.0

1600.0

Pres

sure

, kPa

Flow 10-11 Flow 7-14 Flow 14-12 Total Flow PZO_1_14_P

PZO_13_11_P PZO_05_13_P PZO_13_12_P PZO_15_11_P

Response in Peizo correlates with start of

injection

See slight pressure drop off when injection was stopped; Peizo located

close to gas injection point

Presenter

Presentation Notes


Large Gas Pool (Phase 3) Zoomed in


0.0

100.0

200.0

300.0

400.0

2010‐01‐01

2010‐01‐31

2010‐03‐02

2010‐04‐01

2010‐05‐01

2010‐05‐31

2010‐06‐30

2010‐07‐30

2010‐08‐29

2010‐09‐28

2010‐10‐28

2010‐11‐27

2010‐12‐27

2011‐01‐26

2011‐02‐25

2011‐03‐27

Time. days

Air

Rat

es, E

3m3

0.0

200.0

400.0

600.0

800.0

1000.0

1200.0

1400.0

1600.0

Pres

sure

, kPa

Flow 10-11 Flow 7-14 Flow 14-12 Total Flow PZO_1_14_P

PZO_13_11_P PZO_05_13_P PZO_13_12_P PZO_15_11_P

Pressures are tracking each each other

Presenter

Presentation Notes


Experience with Gas Cap Intersection to Date

• B02-1 and B02-2 intersected Section 15 gas cap in May-June ‘08

• Neither well experienced any operational difficulties subsequent to intersection

– produced gas composition changed substantially

• B01 and B02 pad all in communication with the gas cap

– Except 2 new wells: B01-5 and B01-6

• Pressure in gas cap has continually increased after intersection

– ~250 kPa to date

– has reached 2,500 kPag; current 2,475 kPag


Section 15 Gas Cap Pressure


Phase 2 (Section 15) Monitoring Well Pressures at 5-15 and 8-15

1400145015001550160016501700175018001850190019502000205021002150220022502300235024002450250025502600

Jan 2

007

Mar 20

07May

2007

Jul 2

007

Sep 20

07Nov

2007

Jan 2

008

Mar 20

08May

2008

Jul 2

008

Sep 20

08Nov

2008

Jan 2

009

Mar 20

09May

2009

Jul 2

009

Sep 20

09Nov

2009

Jan 2

010

Mar 20

10May

2010

Jul 2

010

Sep 20

10Nov

2010

Month

Pres

sure

(kPa

)

5-15 8-15

Approximate intersection time of the B02-1 and B02-2 steam chambers with the Phase 2 gas cap

Plant turnaround October 2009

Section 15 Gas Cap Pressure


B01/B02 Chamber Pressures

0

1000

2000

3000

4000

5000

6000

1-Jan-10 20-Feb-10 11-Apr-10 31-May-10 20-Jul-10 8-Sep-10 28-Oct-10 17-Dec-10 5-Feb-11 27-Mar-11

Time

Pres

sure

(kPa

g)

B01-1B01-2B01-3B01-4B02-1B02-2B02-3B02-45/15 (Gas Cap)

B01-2, B01-3 and B01-4 intersects gas cap

B01-1 to B01-4 and B02-1 to B02-4 have all intersected with gascap; chambers are coalesced

Steam chamber pressures ~ 100-200 kPa higher than

gas cap; Maintain slight influx of steam into steam

h b

Steam chamber pressures ~ 50kPa higher than gas

cap pressure

Subsection 3.1.1 – 7e) Solvent Soak Start-Ups


Solvent Soak Start-Up

• As of March 31st 2011, two wells at Christina Lake are on solvent soak:

– B04-1

– B04-3

• These wells should be started up in Q3 2011


Presenter

Presentation Notes

B041Xylene in Inj & Prod-completed Aug 2010 B043Xylene in Inj -completed Aug 2010 Find out actual volumes

Subsection 3.1.1 – 7f) Dilation Startup at B01 Pad


Dilation Startup: Objective

• To create a high-porosity dilation zone between the SAGD wells via controlled high-pressure injection.

• The injection is managed so that NO excessive propagation is caused elsewhere except between the wells.

To promote To prevent


Presenter

Presentation Notes

Controlled with proper review of rates

Key Results

• Dilation startup can effectively be conducted in field in a controlled manner.

• Pressures required to allow for the dilation zone to be developed ranged from 6900 kPa to 8200 kPa

• Monitoring fluid losses helped understand how dilation zone was being developed

• B01-6 had higher net injection rates; communicated with the bottom-water

– Early conversion to low-pressure ESP operations, to maintain pressure balance with bottom-water zone

– Water balance restored; operating as expected (no impact from bottom water)

Wellpair Start-up Maximum BHP Net Rate InjectedMethod (kPag) (m3)

B01-5 Steam Dilation 6900 70

B01-6 Water Dilation 7600 350

B01-7 Water Dilation 8200 29


Microseismic monitoring of B01-7 Dilation start-up

Geophones were placed down two observation wells, OB16 and OB12, to passively monitor the dilation start-up of the B01-7 well pair over the two days of dilation

All events large enough to be recorded were within the SAGD zone

OB16(obs. well)

OB12(obs. well)

B01I07 (injection well)B01P07(producer well)

Visible Range

SAGD Top

B01I07

OB12

B01P07

OB16

SAGD Base

Paleo

Plan View, chronology of events Side View, magnitude of events



Maliha Zaman , Reservoir Engineer

Key Learnings at Christina Lake for 2010• Steam dilation, modified injector completion successful on B01-5

• B01-6 first pilot well with water dilation– Communicated with bottom-water zone; converted early to ESP to maintain pressure

balance with bottom-water zone

– Important to monitor fluid losses to understand how dilation zone being developed• Monitor fluid losses to determine when dilation startup will be stopped

• Optimizing injector hydraulics helps:– Improve steam chamber development

• Starting to understand gas movement in reservoir further– Simulation work being conducted to test out ideas currently

– Will provide further information to ERCB once conclusions are drawn

• A01 Pad bottom water influx via:– Increased gas injection into pad

– Gas injection has helped increase bitumen recovery from pad


Follow-up from previous presentations

• There are no outstanding issues to follow up from any previous ERCB presentation


Subsection 3.1.1 – 7h), well production plots

• Requirements under Subsection 3.1.1 7h) are located in the Appendix


Subsection 3.1.1 – 8) Future Plans


Resource Recovery Strategy

Well/Pad Placement:• 2011/2012 well pairs will be drilled as per

the existing (or future) applications and approvals

– Basis for well trajectories are laid out in each trajectory filing

– Continue to drill Phase 1C/D well pads

• B06, B08, B11 trajectories approved

– B02 sustaining wells

• B02 well pairs 5,6,7 trajectories filed Q1 2011 as part of Phase 1C Wedge Well application


Presenter

Presentation Notes


Resource Recovery Strategy, con’t

Well/Pad Placement:

• Up to 6 more wedge wells (B01(3) and B02(3) Pads)

– Application (including trajectories) expected to be filed in Q1 2011 as part of Phase 1C Wedge Well Application

• Downspacing Pilot• B02B pad – 6 well pairs @ 50m spacing

• B11 pad – 12 well pairs @ 67m spacing

• Will provide 1 representative well pair trajectory per pad as part of application (waiver will be provided)

» Reduce workload for both Cenovus and ERCB» Cenovus has well-established and efficient drilling

strategy


Presenter

Presentation Notes



Operating Pressure:

• Continue with dilation (where approved), steam circulation, gas lift, ESP

• Present Cenovus high level steam ramp- down / blowdown strategy to ERCB Q3 2011


Presenter

Presentation Notes



Composition of Injected Fluid

• composition of injected fluid will be consistent with existing (or future) applications and approvals

• Deviations applied for as amendments i.e. :• steam + solvent injection

• steam + air or natural gas injection

• air or natural gas injection (future application)


Presenter

Presentation Notes


Filed Applications

Subsection 3.1.1 – 8a)*A01 Pad Co-Injection Approvals Modified to increase operational flexibility






8-Jun-2010











Presenter

Presentation Notes


Future ApplicationsSubject Potential

Filing DateCategory 1

B01, B03-B07 Pad Test Separators Q2 2011

Category 2

B02, B11 Well Spacing Amendment Q2 2011

B09, B23 Well Spacing/Wedge Well Amendment Q3 2011

Discussion on Blowdown for B01, B02 Pads* TBD*

Natural Gas / Air Injection Amendment (Future Gas Caps) Q4 2011

Category 3

Phase 1H Scheme Approval Q4 2012


*Meet with ERCB first (Q3 2011) regarding Cenovus Blowdown Strategy

Presenter

Presentation Notes


Drilling Plans – 2011F

Complete:

Well Pads• B07 (8 well pairs)

In Progress:

No drilling in progress

Future:

Well Pads:• B06 (8 well pairs) drilling start Q2 2011• B11 (12 well pairs)* drilling start Q4 2011

* 67m well spacing, pending on ERCB approval


Presenter

Presentation Notes


Drilling Plans – 2012F


Future:

Well Pads:• B02 (6 well pairs)* drilling start Q2 2012• B08 (7 well pairs) drilling start Q3 2012

Wedges• B01 (3 wedges) drilling start Q1 2012• B02 (3 wedges) drilling start Q1 2012

* 50m well spacing, pending on ERCB approval

Presenter

Presentation Notes


Drilling Plans Source and Disposal– 2011F-2012F


2011 Future:

No Plans

2012 Future:

Source:• Drill CW3 Pad (10-27-075-06), 3 Hz wells in Clearwater

Disposal• No Plans

Presenter

Presentation Notes




- will be completed ~June

Drilling Plans – 2011 Complete


Drilling Plans 2011F – 2012F

CW3 (2012) Clearwater Brackish

Source Water

B02 Pad (2012)6 Well pairs

3 Wedge Wells

B01 Pad (2012)3 Wedge Wells



B06 Pad (2011)

8 Well pairs


Future Strat Well Drilling Plans 2012F

2012 Cased Obs

2012 Strat Wells


Steam Strategy – Q1 2011

• the current cumulative dry steam capacity at CL Phase 1A/1B is 5,140 t/d

• currently generating ~ 100-110% of capacity as required

• Steam continued to be injected into A01 Pad with increased gas injection rates

– minimum 600 t/d for the pad on a quarterly basis

• Production fully ramped up on all Phase 1B wells

– Remaining 4,540+ t/d steam on pads other than A01 (when at full capacity)


Presenter

Presentation Notes


Steam Strategy – 2011 and 2012

• Continue to generate 100-110% of steam capacity as required in Phase 1A/1B

• Use Phase 1A/1B steam in addition to Phase 1C steam (as required) to feed B04 Pad circulation/dilation

• Bring Phase 1C online Q2 2011 and ramp to full steam volumes by year end 2011

– 10,960 t/d incremental steam to be injected in Phase 1C Pads (B04, B03, B05 in order of steaming)

– Steam on B07 Pad in Q1 2012


Presenter

Presentation Notes


Steam Strategy – 2011 and 2012 con’t

• 2012 Use steam from Phases 1A/1B/1C plant as available to begin circulation/dilation for Phase 1D Pads

• Use piezometer in Section 15 gas cap to control total steam injection from ‘intersected’ well pairs

– keep the pressure constant, or slightly increasing, over time (small influx of steam into gas cap)


Presenter

Presentation Notes


Steam Shortages – 2010 and 2011

Cenovus does not anticipate a shortage of steam for the remainder of 2010

Cenovus does not anticipate a shortage of steam for 2011


APPENDIX 1 Subsection 3.1.1 7h)

Piezometer SummaryAA/06-02-076-06W4M

Piezo Formation Comments 401.5 mKb Bottom water Batteries died on Aug/06. Back online Dec/06 390.0 mKb Bitumen/Bottom

Water Batteries died on Aug/06. Back online Dec/06

382.5 mKb Bitumen Batteries died on Aug/06. Back online Dec/06 366.0 mKb Bitumen Batteries died on Aug/06. Back online Dec/06 342.5 mKb Gas –U.McM Batteries died on Aug/06. Back online Dec/06

AA/13-11-076-06W4M

Piezo Formation Comments 379.0 mKb Bitumen 357.0 mKb Bitumen 350.0 mKb Bitumen 337.3 mKb Gas –U.McM 330.0 mKb Gas

100/15-11-076-06W4M

Piezo Formation Comments 401.0 mKb Bottom Water Piezometer appears to have failed on February/06 372.0 mKb Bitumen Piezometer appears to have failed on March/06 348.0 mKb SAGD Gas 342.0 mKb SAGD Gas Piezometer appears to failed on February/06 332.0 mKb Gas – U.McM. Piezometer appears to failed on March/06

102/06-12-076-06W4M

Piezo Formation Comments 395.0 mKb Bitumen 378.0 mKb Bitumen 366.0 mKb SAGD Gas 348.0 mKb Upper -SAGD

Gas

332.0 mKb Gas – U.McM.

AA/05-13-076-06W4M

Piezo Formation Comments 383.0 mKb Bitumen Loss of communication Nov/06. Back online Dec/06 368.0 mKb Bitumen Loss of communication Nov/06. Back online Dec/06 358.0 mKb Bitumen Loss of communication Nov/06. Back online Dec/06 346.0 mKb SAGD Gas Loss of communication Nov/06. Back online Dec/06 335.0 mKb Gas – U.McM. Loss of communication Nov/06. Back online Dec/06


Piezometer Summary, con’t100/09-13-076-06W4M

Piezo Formation Comments 405.0 mKb Bottom Water -

OWC

398.0 mKb Low Bitumen – Below SAGD base

375.0 mKb Bitumen 344.0 mKb SAGD Gas 334.0 mKb BB Gas – U.McM.

102/11-14-076-06W4M

Piezo Formation Comments 386.0 mKb Bitumen Loss of communication Mar 07 360.0 mKb Bitumen Loss of communication Mar 07 345.0 mKb SAGD Gas Loss of communication Mar 07 332.0 mKb Gas – U.McM. Loss of communication Mar 07 322.0 mKb BB Gas Loss of communication Mar 07

100/05-15-076-06W4M

Piezo Formation Comments 396.5 mKb Bottom Water 364.4 mKb Bitumen 348.8 mKb Bitumen 340.6 mKb SAGD Gas 323.8 mKb BB Gas

100/08-15-076-06W4M

Piezo Formation Comments 374.2 mKb Bitumen 356.3 mKb Bitumen 342.5 mKb SAGD Gas 335.3 mKb UM no gas 325.3 mKb UM no gas

AA/15-15-076-06W4M

Piezo Formation Comments 403.0 mKb Bottom Water Loss of communication Jan/07. Back online Mar/07 370.0 mKb Bitumen Loss of communication Jan/07. Back online Mar/07 358.0 mKb Bitumen Loss of communication Jan/07. Back online Mar/07 347.0 mKb UM Bitumen – no

thermal Loss of communication Jan/07. Back online Mar/07

330.0 mKb UM no gas Loss of communication Jan/07. Back online Mar/07


Piezometer Summary, con’t

100/05-16-076-06W4M Piezo Formation Comments

391.0 mKb Bottom Water 377.0 mKb Bitumen It appears that the piezometer failed in 2005 338.0 mKb Bitumen Pressure increased and stabilized after BB Gas re-

pressurization with air pilot. Slight pressure decline. 318.5 mKb BB Gas Pressure increased and stabilized after BB Gas re-

pressurization with air pilot. Slight pressure decline. 100/06-16-076-06W4M

Piezo Formation Comments 400.0 mKb Bottom Water Appears that the Piezometer failed in May/06 350.0 mKb Bitumen Pressure increased after BB Gas re-pressurization with air

pilot. It appears that the piezometer failed on July/05 323.5 mKb BB Gas Pressure increased and stabilized after BB Gas re-

pressurization with air pilot. Appears that the Piezometer failed in May/06

AB/14-16-076-06W4M

Piezo Formation Comments 279.0 mKb Clearwater Appears that the Piezometer failed Aug/06 277.0 mKb Clearwater Appears that the Piezometer failed Aug/06

100/08-34-076-04W4M

Piezo Formation Comments 404.0 mKb McMurray Water


Thermocouples in Observation Wells


Thermocouple UWIs and Associated SAGD Positions

UWI SAGD Location

103/05-16-076-06W4M A01-1 Heel

100/06-16-076-06W4M A01-1 Middle

100/11-16-076-06W4M A01-1 Offset

106/11-16-076-06W4M A01-1 Toe

100/05-16-076-06W4M A01-2 Middle

102/11-16-076-06W4M A01-2 Toe

104/05-16-076-06W4M A01-3 Heel

103/12-16-076-06W4M A01-3 Middle

105/11-16-076-06W4M A01-3 Toe

1AB/12-16-076-06W4M A01-4 Middle

103/11-16-076-06W4M A01-4 Toe

103/06-16-076-06W4M A01-5 Toe

102/06-16-076-06W4M A01-6 Toe

103/05-15-076-06W4M B02-1 Mid

102/12-15-076-06W4M B02-2 Heel

100/11-15-076-06W4M B02-4 Mid

102/05-15-076-06W4M B01-3 Heel

102/06-15-076-06W4M B01-3 Mid

104/06-15-076-06W4 B01-4 Mid

104/03-16-076-06W4M A02-2 Heel

Thermocouples in Observation Wells - Relative Positions


Estimated Instrumentation Positions Relative to SAGD Wellbores

Well

Instrumentation

TVD of SAGD

Producer

(mKb)

Instrumentation

TVD of SAGD

Injector

(mKb)

Lateral Offset to

SAGD Producer

(m)

Lateral Offset to

SAGD Injector

(m)

103/05-16 379 373 1 4

100/06-16 381 376 1 5

106/11-16 378 374 9 5

100/11-16 378 372 3 1

100/05-16 378 373 3 2

102/11-16 378 372 3 3

104/05-16 379 373 3 2

103/12-16 380 375 4 3

105/11-16 380 375 n/a 8

1AB/12-16 374 369 3 2

103/11-16 375 370 4 3

103/06-16 382 377 3 3

102/06-16 385 381 3 3

103/05-15 377 371 1 1

102/12-15 381 376 30 30

100/11-15 381 376 5 5

102/05-15 380 374 15 15

102/06-15 378 372 1 1

104/06-15 378 372 0 0

104/03-16 389 384 4 4

100/15-11-076-06W4M

0.00

500.00

1000.00

1500.00

2000.00

2500.00

3000.00

3500.00

Jan-

10

Jan-

10

Jan-

10

Feb-

10

Feb-

10

Mar

-10

Mar

-10

Apr

-10

Apr

-10

May

-10

May

-10

Jun-

10

Jun-

10

Jul-1

0

Jul-1

0

Jul-1

0

Aug

-10

Aug

-10

Sep

-10

Sep

-10

Oct

-10

Oct

-10

Nov

-10

Nov

-10

Dec

-10

Dec

-10

Dec

-10

Jan-

11

Jan-

11

Feb-

11

Feb-

11

Mar

-11

Mar

-11

P (k

Pa)

332 mKb 342 mKb 348 mKb 372 mKb 401 mKb

Piezometer Data

Subsection 3.1.1 – 5d)i)

Presenter

Presentation Notes

NEW

Piezometer Data


102/06-12-076-06W4M

0.00

500.00

1000.00

1500.00

2000.00

2500.00

3000.00

3500.00

Jan-

10

Feb-

10

Mar

-10

Apr

-10

May

-10

Jun-

10

Jul-1

0

Aug

-10

Sep

-10

Oct

-10

Nov

-10

Dec

-10

Jan-

11

Feb-

11

Mar

-11

Apr

-11

P (k

Pa)


Instrumentation Issues from January 1st – March 2011

Presenter

Presentation Notes

Dead Battery

Piezometer Data


100/09-13-076-06W4M

0.00

500.00

1000.00

1500.00

2000.00

2500.00

3000.00

3500.00

Jan-

10

Jan-

10

Jan-

10

Feb-

10

Feb-

10

Mar

-10

Mar

-10

Apr

-10

Apr

-10

May

-10

May

-10

Jun-

10

Jun-

10

Jul-1

0

Jul-1

0

Jul-1

0

Aug

-10

Aug

-10

Sep

-10

Sep

-10

Oct

-10

Oct

-10

Nov

-10

Nov

-10

Dec

-10

Dec

-10

Dec

-10

Jan-

11

Jan-

11

Feb-

11

Feb-

11

Mar

-11

Mar

-11

P (k

Pa)


Presenter

Presentation Notes

NEW

Piezometer Data


102/11-14-076-06W4M

0.00

500.00

1000.00

1500.00

2000.00

2500.00

3000.00

3500.00

Jan-

10

Jan-

10

Jan-

10

Feb-

10

Feb-

10

Mar

-10

Mar

-10

Apr

-10

Apr

-10

May

-10

May

-10

Jun-

10

Jun-

10

Jul-1

0

Jul-1

0

Jul-1

0

Aug

-10

Aug

-10

Sep

-10

Sep

-10

Oct

-10

Oct

-10

Nov

-10

Nov

-10

Dec

-10

Dec

-10

Dec

-10

Jan-

11

Jan-

11

Feb-

11

Feb-

11

Mar

-11

Mar

-11

P (k

Pa)


Presenter

Presentation Notes

NEW

Piezometer Data


AA/06-02-076-06W4M

0.0

500.0

1000.0

1500.0

2000.0

2500.0

3000.0

3500.0

Jan-

10

Jan-

10

Jan-

10

Feb-

10

Feb-

10

Mar

-10

Mar

-10

Apr-1

0

Apr-1

0

May

-10

May

-10

Jun-

10

Jun-

10

Jul-1

0

Jul-1

0

Jul-1

0

Aug

-10

Aug

-10

Sep

-10

Sep

-10

Oct

-10

Oct

-10

Nov

-10

Nov

-10

Dec

-10

Dec

-10

Dec

-10

Jan-

11

Jan-

11

Feb-

11

Feb-

11

Mar

-11

Mar

-11

P (k

Pa)

401.5 mKb 390.0 mKb 382.5 mKb 366.0 mKb 342.5 mKb

Piezometer Data


AA/13-11-076-06W4M

0.0

500.0

1000.0

1500.0

2000.0

2500.0

3000.0

3500.0

Jan-

10

Jan-

10

Jan-

10

Feb-

10

Feb-

10

Mar

-10

Mar

-10

Apr

-10

Apr

-10

May

-10

May

-10

Jun-

10

Jun-

10

Jul-1

0

Jul-1

0

Jul-1

0

Aug

-10

Aug

-10

Sep

-10

Sep

-10

Oct

-10

Oct

-10

Nov

-10

Nov

-10

Dec

-10

Dec

-10

Dec

-10

Jan-

11

Jan-

11

Feb-

11

Feb-

11

Mar

-11

Mar

-11

P (k

Pa)


Piezometer Data


AA/05-13-076-06W4M

0.0

500.0

1000.0

1500.0

2000.0

2500.0

3000.0

3500.0

Jan-

10

Jan-

10

Jan-

10

Feb-

10

Feb-

10

Mar

-10

Mar

-10

Apr

-10

Apr

-10

May

-10

May

-10

Jun-

10

Jun-

10

Jul-1

0

Jul-1

0

Jul-1

0

Aug

-10

Aug

-10

Sep

-10

Sep

-10

Oct

-10

Oct

-10

Nov

-10

Nov

-10

Dec

-10

Dec

-10

Dec

-10

Jan-

11

Jan-

11

Feb-

11

Feb-

11

Mar

-11

Mar

-11

P (k

Pa)

383.0 m 368.0 m 358.0 m 346.0 m 335.0 m

Presenter

Presentation Notes

NeW

100/05-15-076-06W4M

0.0

500.0

1000.0

1500.0

2000.0

2500.0

3000.0

3500.0

4000.0

4500.0

5000.0

Jan-

10

Jan-

10

Jan-

10

Feb-

10

Feb-

10

Mar

-10

Mar

-10

Apr

-10

Apr

-10

May

-10

May

-10

Jun-

10

Jun-

10

Jul-1

0

Jul-1

0

Jul-1

0

Aug

-10

Aug

-10

Sep

-10

Sep

-10

Oct

-10

Oct

-10

Nov

-10

Nov

-10

Dec

-10

Dec

-10

Dec

-10

Jan-

11

Jan-

11

Feb-

11

Feb-

11

Mar

-11

Mar

-11

P (k

Pa)


Piezometer Data


Presenter

Presentation Notes

NEW

Piezometer Data


02-23-076-04W4

0

1000

2000

3000

4000

5000

6000

Jan-

10

Jan-

10

Jan-

10

Feb-

10

Feb-

10

Mar

-10

Mar

-10

Apr

-10

Apr

-10

May

-10

May

-10

Jun-

10

Jun-

10

Jul-1

0

Jul-1

0

Jul-1

0

Aug

-10

Aug

-10

Sep

-10

Sep

-10

Oct

-10

Oct

-10

Nov

-10

Nov

-10

Dec

-10

Dec

-10

Dec

-10

Jan-

11

Jan-

11

Feb-

11

Feb-

11

Mar

-11

Mar

-11

P (k

Pa)

447.5 mKb 410 mKb 393 mKb 382.5 mKb

Presenter

Presentation Notes

NEW

Piezometer Data


100/08-15-076-06W4M

0.0

500.0

1000.0

1500.0

2000.0

2500.0

3000.0

3500.0

Jan-

10

Jan-

10

Jan-

10

Feb-

10

Feb-

10

Mar

-10

Mar

-10

Apr

-10

Apr

-10

May

-10

May

-10

Jun-

10

Jun-

10

Jul-1

0

Jul-1

0

Jul-1

0

Aug

-10

Aug

-10

Sep

-10

Sep

-10

Oct

-10

Oct

-10

Nov

-10

Nov

-10

Dec

-10

Dec

-10

Dec

-10

Jan-

11

Jan-

11

Feb-

11

Feb-

11

Mar

-11

Mar

-11

P (k

Pa)


Presenter

Presentation Notes

New

AA/15-15-076-06W4M

0.0

500.0

1000.0

1500.0

2000.0

2500.0

3000.0

3500.0

4000.0

4500.0

5000.0

Jan-

10

Jan-

10

Jan-

10

Feb-

10

Feb-

10

Mar

-10

Mar

-10

Apr

-10

Apr

-10

May

-10

May

-10

Jun-

10

Jun-

10

Jul-1

0

Jul-1

0

Jul-1

0

Aug

-10

Aug

-10

Sep

-10

Sep

-10

Oct

-10

Oct

-10

Nov

-10

Nov

-10

Dec

-10

Dec

-10

Dec

-10

Jan-

11

Jan-

11

Feb-

11

Feb-

11

Mar

-11

Mar

-11

P (k

Pa)


Piezometer Data


Instrumentation Issues from April 2010– March 2011

Presenter

Presentation Notes

Dead Battery

Piezometer Data


100/05-16-076-06W4M

0.0

1000.0

2000.0

3000.0

4000.0

5000.0

6000.0

7000.0

8000.0

Jan-

10

Jan-

10

Jan-

10

Feb-

10

Feb-

10

Mar

-10

Mar

-10

Apr

-10

Apr

-10

May

-10

May

-10

Jun-

10

Jun-

10

Jul-1

0

Jul-1

0

Jul-1

0

Aug-

10

Aug-

10

Sep-

10

Sep-

10

Oct

-10

Oct

-10

Nov

-10

Nov

-10

Dec

-10

Dec

-10

Dec

-10

Jan-

11

Jan-

11

Feb-

11

Feb-

11

Mar

-11

Mar

-11

P (k

Pa)

391 mKb 377 mKb 338 mKb 318.5 mKb

Presenter

Presentation Notes

NEW- 377m no longer working

Piezometer Data


100/06-16-076-06W4M

0.0

1000.0

2000.0

3000.0

4000.0

5000.0

6000.0

Jan-

07

Mar

-07

May

-07

Jul-0

7

Sep

-07

Nov

-07

Jan-

08

Mar

-08

May

-08

Jul-0

8

Sep

-08

Nov

-08

Jan-

09

Mar

-09

May

-09

Jul-0

9

Sep

-09

Nov

-09

Jan-

10

Mar

-10

May

-10

Jul-1

0

Sep

-10

Nov

-10

Jan-

11

Mar

-11

P (k

Pa)

323.5 mKb 350 mKb 400 mKb

Piezometer no longer working

Presenter

Presentation Notes


Piezometer Data


AB/14-16-076-06W4M

0.0

200.0

400.0

600.0

800.0

1000.0

1200.0

1400.0

1600.0

1800.0

2000.0Ja

n-10

Jan-

10

Jan-

10

Feb-

10

Feb-

10

Mar

-10

Mar

-10

Apr

-10

Apr

-10

May

-10

May

-10

Jun-

10

Jun-

10

Jul-1

0

Jul-1

0

Jul-1

0

Aug

-10

Aug

-10

Sep

-10

Sep

-10

Oct

-10

Oct

-10

Nov

-10

Nov

-10

Dec

-10

Dec

-10

Dec

-10

Jan-

11

Jan-

11

Feb-

11

Feb-

11

Mar

-11

Mar

-11

P (k

Pa)

277 mKb 279 mKb

Presenter

Presentation Notes


Piezometer Data


100/08-34-076-04W4

2000.0

2050.0

2100.0

2150.0

2200.0

2250.0

2300.0

Jan-

10

Jan-

10

Jan-

10

Feb-

10

Feb-

10

Mar

-10

Mar

-10

Apr

-10

Apr

-10

May

-10

May

-10

Jun-

10

Jun-

10

Jul-1

0

Jul-1

0

Jul-1

0

Aug

-10

Aug

-10

Sep

-10

Sep

-10

Oct

-10

Oct

-10

Nov

-10

Nov

-10

Dec

-10

Dec

-10

Dec

-10

Jan-

11

Jan-

11

Feb-

11

Feb-

11

Mar

-11

Mar

-11

P (k

Pa)

404 mKb

Presenter

Presentation Notes


Piezometer Data


100/12-11-76-6W4/00

0.0

1000.0

2000.0

3000.0

4000.0

5000.0

6000.0

7000.0

8000.0

Jan-

10

Jan-

10

Jan-

10

Feb-

10

Feb-

10

Mar

-10

Mar

-10

Apr-1

0

Apr-1

0

May

-10

May

-10

Jun-

10

Jun-

10

Jul-1

0

Jul-1

0

Jul-1

0

Aug-

10

Aug-

10

Sep-

10

Sep-

10

Oct

-10

Oct

-10

Nov

-10

Nov

-10

Dec

-10

Dec

-10

Dec

-10

Jan-

11

Jan-

11

Feb-

11

Feb-

11

Mar

-11

Mar

-11

P (k

Pa)

340 mKb 345 mKb 362 mKb 385 mKb

Callibration Issue

Piezometer Data


100/01-14-76-6W4/00

0

500

1000

1500

2000

2500

3000

3500

Jan-

10

Jan-

10

Jan-

10

Feb-

10

Feb-

10

Mar

-10

Mar

-10

Apr-1

0

Apr-1

0

May

-10

May

-10

Jun-

10

Jun-

10

Jul-1

0

Jul-1

0

Jul-1

0

Aug-

10

Aug-

10

Sep-

10

Sep-

10

Oct

-10

Oct

-10

Nov

-10

Nov

-10

Dec

-10

Dec

-10

Dec

-10

Jan-

11

Jan-

11

Feb-

11

Feb-

11

Mar

-11

Mar

-11

P (k

Pa)


Presenter

Presentation Notes

new

Piezometer Data


100/13-12-76-6W4/00

0

1000

2000

3000

4000

5000

6000

7000

8000

Jan-

10

Jan-

10

Jan-

10

Feb-

10

Feb-

10

Mar

-10

Mar

-10

Apr-1

0

Apr-1

0

May

-10

May

-10

Jun-

10

Jun-

10

Jul-1

0

Jul-1

0

Jul-1

0

Aug

-10

Aug

-10

Sep

-10

Sep

-10

Oct

-10

Oct

-10

Nov

-10

Nov

-10

Dec

-10

Dec

-10

Dec

-10

Jan-

11

Jan-

11

Feb-

11

Feb-

11

Mar

-11

Mar

-11

P (k

Pa)

331 mKb 349 mKb 360 mKb 380 mKb

Presenter

Presentation Notes

new

Subsection 3.1.1 – 5d)ii-iv)

OB-2 Observation Well (B02-4 Toe)


OB-3 Observation Well (B02-2 Heel)


OB-4 Observation Well (B01-3 Toe)


OB-5 Observation Well (B01-3 Heel)


OB-6 Observation Well (B01-4 Mid)


GP-5 Observation Well (B02-1 Mid)

APPENDIX 2 Subsection 3.1.1 7h)


Christina LakeA01 Pad Performance

0

500

1,000

1,500

2,000

Jan-10

Feb-10

Mar-10

Apr-10

May-10

Jun-10

Jul-10

Aug-10

Sep-10

Oct-10

Nov-10

Dec-10

Jan-11

Feb-11

Mar-11

Rat

e (m

3/da

y), P

ress

ure

(kPa

)

0.0

5.0

10.0

15.0

20.0

25.0

30.0

35.0

40.0

45.0

50.0

Rat

e (e

3m3/

d), S

team

-Oil

Rat

io

Pre

ssur

e (m

Pa)

Oil Rate (m3/d) Water Rate (m3/d ) Steam Inj Rate (m3/d)Inst SOR Cum SOR Pad Pressure (mPa)Gas Co-Injection Rate (e3m3/d) Produced Gas Rate (e3m3/d)

Presenter

Presentation Notes

NEW


Christina LakeB01 Pad Performance

0

500

1,000

1,500

2,000

2,500

3,000

Jan-10

Feb-10

Mar-10

Apr-10

May-10

Jun-10

Jul-10

Aug-10

Sep-10

Oct-10

Nov-10

Dec-10

Jan-11

Feb-11

Mar-11

Rat

e (m

3/da

y), P

ress

ure

(kPa

)

0.0

5.0

10.0

15.0

20.0

25.0

30.0

Rat

e (e

3m3/

d), S

team

-Oil

Rat

io

Pre

ssur

e (m

Pa)


Presenter

Presentation Notes

NEW


Christina LakeB02 Pad Performance

0

500

1,000

1,500

2,000

2,500

3,000

Jan-10

Feb-10

Mar-10

Apr-10

May-10

Jun-10

Jul-10

Aug-10

Sep-10

Oct-10

Nov-10

Dec-10

Jan-11

Feb-11

Mar-11

Rat

e (m

3/da

y), P

ress

ure

(kPa

)

0.0

5.0

10.0

15.0

20.0

25.0

30.0

Rat

e (e

3m3/

d), S

team

-Oil

Rat

io

Pre

ssur

e (m

Pa)


Presenter

Presentation Notes

NEW



0

50

100

150

200

250

300

350

Jan-

10

Feb-

10

Mar

-10

Apr-

10

May

-10

Jun-

10

Jul-1

0

Aug-

10

Sep-

10

Oct

-10

Nov

-10

Dec

-10

Jan-

11

Feb-

11

Mar

-11

Date

Rat

e (m

3/d)

0.00

2.00

4.00

6.00

8.00

10.00

12.00

14.00

Stea

m-O

il R

atio

, G

as R

ate

(e3m

3/d)

Pres

sure

(MPa

)


Presenter

Presentation Notes

NEW



0

50

100

150

200

250

300

350

400

450

500

550

Jan-

10

Feb-

10

Mar

-10

Apr-

10

May

-10

Jun-

10

Jul-1

0

Aug

-10

Sep

-10

Oct

-10

Nov

-10

Dec

-10

Jan-

11

Feb-

11

Mar

-11

Date

Rat

e (m

3/d)

0.00

1.00

2.00

3.00

4.00

5.00

6.00

7.00

8.00

9.00

10.00

11.00

Stea

m-O

il R

atio

, G

as R

ate

(e3m

3/d)

Pres

sure

(MPa

)


Presenter

Presentation Notes

NEW


WA01-2 Well Pair Performance

0

50

100

150

200

250

300

350

Jan-

10

Feb-

10

Mar

-10

Apr-

10

May

-10

Jun-

10

Jul-1

0

Aug-

10

Sep-

10

Oct

-10

Nov

-10

Dec

-10

Jan-

11

Feb-

11

Mar

-11

Date

Rat

e (m

3/d)

0.00

2.00

4.00

6.00

8.00

10.00

12.00

14.00

16.00

Stea

m-O

il R

atio

, G

as R

ate

(e3m

3/d)

Pres

sure

(MPa

)


Presenter

Presentation Notes

NEW



0

50

100

150

200

250

300

Jan-

10

Feb-

10

Mar

-10

Apr-

10

May

-10

Jun-

10

Jul-1

0

Aug

-10

Sep

-10

Oct

-10

Nov

-10

Dec

-10

Jan-

11

Feb-

11

Mar

-11

Date

Rat

e (m

3/d)

0.00

1.00

2.00

3.00

4.00

5.00

6.00

7.00

8.00

9.00

10.00

Stea

m-O

il R

atio

, G

as R

ate

(e3m

3/d)

Pres

sure

(MPa

)


Presenter

Presentation Notes

NEW


A01-3 Toe Well Pair Performance

0

50

100

150

200

250

Jan-

10

Feb-

10

Mar

-10

Apr-

10

May

-10

Jun-

10

Jul-1

0

Aug

-10

Sep

-10

Oct

-10

Nov

-10

Dec

-10

Jan-

11

Feb-

11

Mar

-11

Date

Rat

e (m

3/d)

0.00

1.00

2.00

3.00

4.00

5.00

6.00

7.00

8.00

9.00

10.00

Stea

m-O

il R

atio

, G

as R

ate

(e3m

3/d)

Oil Rate (CD) m3/d Water Rate (CD) m3/d Steam Inj Rate m3/d Instantaneous Steam-Oil Ratio (Monthly) m3/m3 Cumulative Steam-Oil Ratio m3/m3 Natural Gas Co-Inj Rate E3m3/dProd Gas Rate E3m3/d

Presenter

Presentation Notes

NEW



0

50

100

150

200

250

300

350

Jan-

10

Feb-

10

Mar

-10

Apr

-10

May

-10

Jun-

10

Jul-1

0

Aug

-10

Sep

-10

Oct

-10

Nov

-10

Dec

-10

Jan-

11

Feb-

11

Mar

-11

Date

Rat

e (m

3/d)

0.00

2.00

4.00

6.00

8.00

10.00

12.00

14.00

Stea

m-O

il R

atio

, G

as R

ate

(e3m

3/d)

Pres

sure

(MPa

)


Presenter

Presentation Notes

New



0

50

100

150

200

250

300

350

Jan-

10

Feb-

10

Mar

-10

Apr-

10

May

-10

Jun-

10

Jul-1

0

Aug

-10

Sep

-10

Oct

-10

Nov

-10

Dec

-10

Jan-

11

Feb-

11

Mar

-11

Date

Rat

e (m

3/d)

0.00

1.00

2.00

3.00

4.00

5.00

6.00

7.00

8.00

9.00

10.00

Stea

m-O

il R

atio

, G

as R

ate

(e3m

3/d)

Pres

sure

(MPa

)


Presenter

Presentation Notes

New



0

100

200

300

400

500

600

Jan-

10

Feb-

10

Mar

-10

Apr

-10

May

-10

Jun-

10

Jul-1

0

Aug

-10

Sep

-10

Oct

-10

Nov

-10

Dec

-10

Jan-

11

Feb-

11

Mar

-11

Date

Rat

e (m

3/d)

0.00

2.00

4.00

6.00

8.00

10.00

12.00

Stea

m-O

il R

atio

, G

as R

ate

(e3m

3/d)

Pres

sure

(MPa

)


Presenter

Presentation Notes

New



0

100

200

300

400

500

600

700

800

Jan-

10

Feb-

10

Mar

-10

Apr

-10

May

-10

Jun-

10

Jul-1

0

Aug

-10

Sep

-10

Oct

-10

Nov

-10

Dec

-10

Jan-

11

Feb-

11

Mar

-11

Date

Rat

e (m

3/d)

0.00

2.00

4.00

6.00

8.00

10.00

12.00

Stea

m-O

il R

atio

, G

as R

ate

(e3m

3/d)

Pres

sure

(MPa

)


Presenter

Presentation Notes

New



0

100

200

300

400

500

600

700

800

900

1000

Jan-

10

Feb-

10

Mar

-10

Apr

-10

May

-10

Jun-

10

Jul-1

0

Aug

-10

Sep

-10

Oct

-10

Nov

-10

Dec

-10

Jan-

11

Feb-

11

Mar

-11

Date

Rat

e (m

3/d)

0.00

2.00

4.00

6.00

8.00

10.00

12.00

Stea

m-O

il R

atio

, G

as R

ate

(e3m

3/d)

Pres

sure

(MPa

)


Presenter

Presentation Notes

New



0

100

200

300

400

500

600

700

800

Jan-

10

Feb-

10

Mar

-10

Apr

-10

May

-10

Jun-

10

Jul-1

0

Aug

-10

Sep

-10

Oct

-10

Nov

-10

Dec

-10

Jan-

11

Feb-

11

Mar

-11

Date

Rat

e (m

3/d)

0.00

2.00

4.00

6.00

8.00

10.00

12.00

Stea

m-O

il R

atio

, G

as R

ate

(e3m

3/d)

Pres

sure

(MPa

)


Presenter

Presentation Notes

New



0

100

200

300

400

500

600

700

800

900

Jan-

10

Feb-

10

Mar

-10

Apr

-10

May

-10

Jun-

10

Jul-1

0

Aug

-10

Sep

-10

Oct

-10

Nov

-10

Dec

-10

Jan-

11

Feb-

11

Mar

-11

Date

Rat

e (m

3/d)

0.00

2.00

4.00

6.00

8.00

10.00

12.00

Stea

m-O

il R

atio

, G

as R

ate

(e3m

3/d)

Pres

sure

(MPa

)


Presenter

Presentation Notes

New



0

50

100

150

200

250

300

350

400

450

500

Jan-

10

Feb-

10

Mar

-10

Apr

-10

May

-10

Jun-

10

Jul-1

0

Aug

-10

Sep

-10

Oct

-10

Nov

-10

Dec

-10

Jan-

11

Feb-

11

Mar

-11

Date

Rat

e (m

3/d)

0.00

2.00

4.00

6.00

8.00

10.00

12.00

Stea

m-O

il R

atio

, G

as R

ate

(e3m

3/d)

Pres

sure

(MPa

)


Presenter

Presentation Notes

New



0

100

200

300

400

500

600

Jan-

10

Feb-

10

Mar

-10

Apr

-10

May

-10

Jun-

10

Jul-1

0

Aug

-10

Sep

-10

Oct

-10

Nov

-10

Dec

-10

Jan-

11

Feb-

11

Mar

-11

Date

Rat

e (m

3/d)

0.00

2.00

4.00

6.00

8.00

10.00

12.00

Stea

m-O

il R

atio

, G

as R

ate

(e3m

3/d)

Pres

sure

(MPa

)


Presenter

Presentation Notes

New



0

100

200

300

400

500

600

700

Sep

-06

Nov

-06

Jan-

07

Mar

-07

May

-07

Jul-0

7

Sep

-07

Nov

-07

Jan-

08

Mar

-08

May

-08

Jul-0

8

Sep

-08

Nov

-08

Jan-

09

Mar

-09

May

-09

Jul-0

9

Sep

-09

Nov

-09

Jan-

10

Mar

-10

May

-10

Jul-1

0

Sep

-10

Nov

-10

Jan-

11

Mar

-11

Date

Rat

e (m

3/d)

0.00

2.00

4.00

6.00

8.00

10.00

12.00

Stea

m-O

il R

atio

, G

as R

ate

(e3m

3/d)

Pres

sure

(MPa

)


Presenter

Presentation Notes

New



0

100

200

300

400

500

600

700

Jan-

10

Feb-

10

Mar

-10

Apr

-10

May

-10

Jun-

10

Jul-1

0

Aug

-10

Sep

-10

Oct

-10

Nov

-10

Dec

-10

Jan-

11

Feb-

11

Mar

-11

Date

Rat

e (m

3/d)

0.00

2.00

4.00

6.00

8.00

10.00

12.00

Stea

m-O

il R

atio

, G

as R

ate

(e3m

3/d)

Pres

sure

(MPa

)


Presenter

Presentation Notes

New

Discussion and Questions

encana christina lake in-situ oil scheme 2009 update

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