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
Subsection 3.1.1 – 1)
– 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
Subsection 3.1.1 – 1)
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
8Subsection 3.1.1 – 1)
B02 Pad-4 well pairs
B01 Pad-7 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
B05 Pad-9 well pairs
B05 Pad-9 well pairs
B04 Pad-8 well pairs
B07 Pad-8 well pairs
B03 Pad-8 well pairs
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
Logan Popko, Production Engineer
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%
Subsection 3.1.2 – 2c)
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)
Logan Popko, Production Engineer
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)
Subsection 3.1.2 – 3)
26Subsection 3.1.2 – 3)
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
Logan Popko, Production Engineer
31
The Problem: High Bottom Water Pressure
• Historical disposal into the bottom water under A Pad caused high bottom water pressure
Subsection 3.1.2 – 4a)
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
The Problem: High Bottom Water Pressure
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
Logan Popko, Production Engineer
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
Subsection 3.1.2 – 4a)
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
Subsection 3.1.2 – 4b)
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
Subsection 3.1.2 – 4b)
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
Subsection 3.1.2 4e)
*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
Existing Water Disposal102/15-35-76-4W4103/15-35-76-4W4104/15-35-76-4W4
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
Subsection 3.1.2 – 4g)
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
Subsection 3.1.2 – 4h)
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
Water Disposal Operations
Subsection 3.1.2 – 4h)
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
50
Water Disposal Operations Cont’d
Subsection 3.1.2 – 4h)
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
Subsection 3.1.2 – 4h)
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
Logan Popko, Production Engineer
54
Operations with Sulphur Recovery
•Christina Lake Operations does not currently have sulphur recovery capability
Subsection 3.1.2 – 5a)
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.
Subsection 3.1.2 – 6b)
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
Subsection 3.1.2 – 5d)
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 – 5d)
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
Subsection 3.1.2 – 7a)
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)
Subsection 3.1.2 – 7b)
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
Subsection 3.1.2 – 7c)
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
Subsection 3.1.2 – 7c)
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
Subsection 3.1.2 – 7d)
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
Renee Alessio, Environment
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 – 8)
Subsection 3.1.2 – 9) Non-Compliance
Renee Alessio, Environment
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 – 8)
Subsection 3.1.2 – 9) Future Plans
Everett Diamond, Development Engineer
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
Subsection 3.1.2 – 10a)
74
Filed Applications
Subsection 3.1.1 – 8a)*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)
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
Subsection 3.1.1 – 8a)
*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
Subsection 3.1.2 – 10c)
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
Subsection 3.1.2 – 10d)
Discussion and Questions
Cenovus Christina Lake In-situ Oil Scheme 2010 - 2011 Update
ERCB Office | June 15, 2011
Page 2
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
Page 3
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
Page 5
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
Everett Diamond, Development Engineer
Page 7
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)
Page 8
Brief Description of Recovery Process
Subsection 3.1.1 – 1)
– 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
Page 9
Area Map of Christina Lake
Subsection 3.1.1 – 1)
Page 10Subsection 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
Page 11Subsection 3.1.1 – 1)
B02 Pad-4 well pairs
B01 Pad-7 well pairs
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
B05 Pad-9 well pairs
B05 Pad-9 well pairs
B04 Pad-8 well pairs
B07 Pad-8 well pairs
B03 Pad-8 well pairs
A01-3 Toe
Page 12
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
Subsection 3.1.1 – 1)
Existing Source Water and Disposal wells
Subsection 3.1.1 – 2 Geology and Geophysics
James Newsome, Geologist; Lori Barth, Geophysicist
Page 14Subsection 3.1.1 – 2a)
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
Page 15Subsection 3.1.1 – 2a)
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)
Page 16
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
Subsection 3.1.1 – 2b)
Page 17Subsection 3.1.1 – 2b)
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
Page 18
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
Page 19
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
Page 20
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
Page 21
Producible Oil in Place (POIP) and % Recovery
Subsection 3.1.1 – 2b)
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
Page 22
SAGD Pay (net bitumen)
Isopach (with posted values)
Subsection 3.1.1 – 2c)
Page 23
Paleozoic Structure
Subsection 3.1.1 – 2d)
Page 24
McMurrayIsopach
Subsection 3.1.1 – 2d)
Page 25
SAGD Pay Base with posted values(SSTVD meters)
Subsection 3.1.1 – 2d)
Page 26
SAGD Pay Top with posted values(SSTVD meters)
Subsection 3.1.1 – 2d)
Page 27
McMurrayStructure
Subsection 3.1.1 – 2d)
Page 28
SAGD Gas Isopach
Subsection 3.1.1 – 2d)
Page 29
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
Subsection 3.1.1 – 2e)
- 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
Page 30
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
Subsection 3.1.1 – 2e)
- 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
Page 31
Christina Lake ‘A01 pad’ Pilot Cores
6-16 (A01-1)
12-16 (A01-3)
Subsection 3.1.1 – 2f)
Page 32
12-16-76-6W4
Average So from offsetting wells ~ 80%
Subsection 3.1.1 – 2f)
Page 33
6-16-76-6W4
Average So from offsetting wells is ~ 80%
Subsection 3.1.1 – 2f)
Page 34
McMurray Cored WellsTotal Cored Wells (Proper) - 1752011 Cored Wells - 242010 Cored Wells - 9
Analysis-routine core analysis-photos-caprock integrity
Subsection 3.1.1 – 2f)
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.
Page 35
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)
Page 36
B04-1 Cross-Section
Subsections 3.1.1 – 2h,i)
Page 37
B03-4 Cross-SectionJune 27, 2008
Proper
June 27, 2008
Comments:-elevated SAGD base on right-geostats indicates higher SAGD base
By-pass PayPotential
Subsections 3.1.1 – 2h,i)
Page 38
B05-7 Cross-Section
B05Well: 7Profile
June 27, 2008
Proper
June 27, 2008
Comments:-profile elevated on right toavoid perm barriers.
Subsections 3.1.1 – 2h,i)
Page 39
B07-5 Cross-Section
Proper
Subsections 3.1.1 – 2h,i)
Page 40
RepresentativeCross-Sections
Subsections 3.1.1 – 2h,i)
Page 41Subsections 3.1.1 – 2h,i)
Cross-Section A – A’ (Saturation)
Page 42Subsections 3.1.1 – 2h,i)
Cross-Section A – A’ (Lithology)
Sand Mud
Page 43
Cross-Section B-B’ (Saturation)
Subsections 3.1.1 – 2h,i)
Page 44Subsections 3.1.1 – 2h,i)
Cross-Section B-B’ (Lithology)
Sand Mud
B B’
Abd. Mud Channel
Abd. Mud Channel
Page 45
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
Page 46
Geomechanical and Surface Heave
Subsections 3.1.1 – 2j,k)
Corner ReflectorLocations
Page 47
Geomechanical and Surface Heave
Subsections 3.1.1 – 2j,k)
Cumulative deformation at the Corner Reflectorsfrom May 2008 to October 2010
(mm)
Page 48
Geomechanical and Surface Heave
Subsections 3.1.1 – 2j,k)
Cumulative deformation at the Corner Reflectorsfrom May 2008 to October 2010
5
4
1
3
6
7
18
17
9
(mm)
Page 49
Geomechanical and Surface Heave
Subsections 3.1.1 – 2j,k)
Cumulative deformation at the Corner Reflectorsfrom May 2008 to October 2010
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)
Page 50
Geomechanical and Surface Heave
Subsections 3.1.1 – 2j,k)
Cumulative deformation at the Corner Reflectorsfrom May 2008 to October 2010
CR 12
+ 30 mm
~ 1 year
(mm)
Page 51
Geomechanical and Surface Heave
Subsections 3.1.1 – 2j,k)
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.
Page 52
Geomechanical and Surface Heave
Subsections 3.1.1 – 2j,k)
RADARSAT-2 CTM data acquired from July 2, 2008 to October 20, 2010
Subsidence
(mm)
Page 53
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)
Page 54
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
Logan Popko, Production Engineer
Page 56
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)
B03 Pad (8 prod/injectors)
-drilled Q1-2, 2010 (B03 Pad)
Subsection 3.1.1 – 3a)
B07 Pad (8 prod/injectors)
-drilled Q1 2011B05 Pad (9 prod/injectors)
-drilled Q3, 2010 (B03 Pad)
B04B04B07B07
B05B05
B03B03
B02B02
B01B01A01A01
A02A02
Page 57
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
Page 58
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
Subsections 3.1.1 – 3b,c)
Page 59
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-out Tailpipe
ESP
Subsections 3.1.1 – 3b,c)
Page 60
Sample Modified Injector Completion
339.7 mm 71.43 kg/mH-40 ST&C Surface Casing
244.5 mm 59.53 kg/mL-80 QB2 Casing
Liner Hanger
Steam Subs
Injection Tubing
Subsections 3.1.1 – 3b,c)
Page 61Subsection 3.1.1 – 3c)
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
Logan Popko, Production Engineer
Page 63
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
Subsection 3.1.1 – 4a)
Page 64
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
Subsection 3.1.1 – 4b)
Subsection 3.1.1 – 5) Instrumentation
Logan Popko, Production Engineer
Page 66
Hanging Wire Piezometer Temperature Observation Cemented Casing Piezometers
Instrumentation in Observation Wells – Typical Completions
45Subsections 3.1.1 – 5a,b)
Page 67
Map of Observation WellsPiezometer Wells
Thermocouple Wells
Subsection 3.1.1 – 5b,c)
(cemented)Piezometer Wells
(Hanging wire)
Page 68
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)
Subsection 3.1.1 – 6) 4D Seismic
Lori Barth, Geophysicist
Page 70
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
Page 71
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
Subsection 3.1.1 – 6b)
Page 72
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
Subsection 3.1.1 – 6b)
Subsection 3.1.1 – 7) Scheme Performance
Maliha Zaman, Reservoir Engineer
Page 74
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
Subsection 3.1.1 – 7)
Page 75
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
Subsection 3.1.1 – 7)
Page 76
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)
Subsection 3.1.1 – 7)
Page 77
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)
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
Subsection 3.1.1 – 7)
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
Page 78
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
Subsection 3.1.1 – 7)
Page 79
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
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
)
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)
Subsection 3.1.1 – 7)
A01W01 Start-Up
B01-5/B01-6 Start-Up
Page 80Subsection 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
Page 81
Christina Lake Cumulative % Recovery Based on Producible OOIP (POIP)
Subsection 3.1.1 – 7a)ii)
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
Page 82
Christina Lake Cumulative SOR
Subsection 3.1.1 – 7a)ii)
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
Page 83Subsection 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
Page 84
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)
Page 85
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)
Page 86
A01-2 Well Pair – High Recovery
A01-2A01-2
TO-02 obs well
TO-02 obs well
Subsections 3.1.1 – 7b),c)iii)
Page 87
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
Subsections 3.1.1 – 7b),c)iii)
Co-Injection
Page 88Subsections 3.1.1 – 7b),c)iii)
T0-02 (A01-2 Middle)
Page 89
B02-3 Well Pair – Medium Recovery
B02-3B02-3
Subsections 3.1.1 – 7b),c)iii)
Page 90
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
Subsections 3.1.1 – 7b),c)iii)
Page 91
B01-5 Well Pair – Low Recovery
B01-5B01-5
Subsections 3.1.1 – 7b),c)iii)
Page 92Subsections 3.1.1 – 7b),c)iii)
B01-5 Well Pair Performance
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
)
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)
• Well started up using steam dilation
• Modified Injector Completion Used from the start
Page 93
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
Subsection 3.1.1 – 7c)
Page 94
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)
Subsection 3.1.1 – 7c)
Page 95
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)
Subsection 3.1.1 – 7c)
High P (B01-5)
High P (B01-6)Low P (B01-6)
Started using water dilation; Connected to bottom-water;
Early conversion to ESP
Page 96
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)
Subsection 3.1.1 – 7c)
Circulation (B02-1 and B02-2)
Page 97
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)
Page 98
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)
Page 99
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 – 7d)
Subsection 3.1.1 – 7e) Steam Chamber Development at A01 Pad
Lori Barth, Geophysicist
Page 101
Christina Proper Area Data Map
R10
R RST
Thermocouples
Piezometers
Subsection 3.1.1 – 7e)
Page 102
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
Subsection 3.1.1 – 7e)
Page 103
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
Subsection 3.1.1 – 7e)
Page 104
Gas Top
Steam Top
GR
Sg Temperature
A3 Profile: 4D Seismic Amplitude Difference(2001/2007) Subsection 3.1.1 – 7e)
Page 105
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
Subsection 3.1.1 – 7e)
Page 106
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
Subsection 3.1.1 – 7e)
Page 107
A1 Profile: 4D Seismic Amplitude Difference(2001/2007)
Steam Top
Gas Top
GR
Sg Temperature
Subsection 3.1.1 – 7e)
Subsection 3.1.1 – 7e) Co-Injection at A01 Pad
Maliha Zaman, Reservoir Engineer
Page 109
• 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
Subsection 3.1.1 – 7e)
Page 110
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
Subsection 3.1.1 – 7e)
Page 111
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
Subsection 3.1.1 – 7e)
Page 112
A01-2 Co-Injection Performance
A01-2 phases of operation
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
Subsection 3.1.1 – 7e)
Page 113
A01-3 Co-Injection Performance
A01-3 phases of operation
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
Subsection 3.1.1 – 7e)
Page 114
A01-4 Co-Injection Performance
A01-4 phases of operation
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
Subsection 3.1.1 – 7e)
Page 115
A01-5 Co-Injection Performance
A01-5 phases of operation
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
Subsection 3.1.1 – 7e)
Page 116
A01-6 Co-Injection Performance
A01-6 phases of operation
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
Subsection 3.1.1 – 7e)
Page 117
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
Subsection 3.1.1 – 7e)
Page 118
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
Subsection 3.1.1 – 7e)
Additional Section) Bottom Water Depressurization under A01 Pad
Logan Popko, Production Engineer
Page 120
The Problem: High Bottom Water Pressure
• Historical disposal into the bottom water under A01 Pad caused high bottom water pressure
Subsection 3.1.2 – 4a)
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
Page 121
The Problem: High Bottom Water Pressure
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)
Subsection 3.1.2 – 4a)
Page 122
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
Subsection 3.1.2 – 4a)
Page 123
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 – 4a)
Subsection 3.1.2 – 4) Water Management
Logan Popko, Production Engineer
Page 125
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
Subsection 3.1.2 – 4a)
Page 126
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
Page 127
Fresh Water Use
Subsection 3.1.2 – 4b)
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)
Page 128
Brackish Water Use
Subsection 3.1.2 – 4b)
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)
Page 129
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)
Page 130
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)
Page 131
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)
Page 132
Produced Water Recycle Percent
Subsection 3.1.2 4e)
*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
%
Page 133
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
Page 134
• 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
Water Disposal Operations
Subsection 3.1.2 – 4g)
Page 135
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
Existing Water Disposal102/15-35-76-4W4103/15-35-76-4W4104/15-35-76-4W4
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
Subsection 3.1.2 – 4g)
Page 136
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
Page 137
PW and RW Disposal Volumes
Subsection 3.1.2 – 4h)
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
Page 138
Water Disposal Operations
Subsection 3.1.2 – 4h)
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
Page 139
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
Subsection 3.1.2 – 4h)
Page 140
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
Subsection 3.1.2 – 4h)
Page 141
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
Maliha Zaman, Reservoir Engineer
Page 143
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
Subsection 3.1.1 – 7e)
Page 144
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
Subsection 3.1.1 – 7e)
Christina Lake - gas cap re-pressuring
Page 145
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.
Subsection 3.1.1 – 7e)
Page 146
PipelinesInstalled Injection Wells Tied in March 2011 Projected Contingent Wells
Subsection 3.1.1 – 7e)
Page 147
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
Subsection 3.1.1 – 7e)
Total Injected Gas Volume (Bcf)
Total Injected Gas Volume (e3m3)
Average Pressure in Gas Cap (kPa)
1.39 39,301 1,175
Page 148
Large Gas Pool (Phase 3) con’t
Subsection 3.1.1 – 7e)
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
Page 149
Large Gas Pool (Phase 3) Zoomed in
Subsection 3.1.1 – 7e)
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
Page 150
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
Subsection 3.1.1 – 7e)
Page 151
Section 15 Gas Cap Pressure
Subsection 3.1.1 – 7e)
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
Page 152
Section 15 Gas Cap Pressure
Subsection 3.1.1 – 7e)
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
Maliha Zaman, Reservoir Engineer
Page 154
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
Subsection 3.1.1 – 7e)
Subsection 3.1.1 – 7f) Dilation Startup at B01 Pad
Maliha Zaman, Reservoir Engineer
Page 156
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
Subsection 3.1.1 – 7f)
Page 157
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
Subsection 3.1.1 – 7f)
Page 158
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
Subsection 3.1.1 – 7f)
Subsection 3.1.1 – 7f)
Maliha Zaman , Reservoir Engineer
Page 160
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
Subsection 3.1.1 – 7f)
Page 161
Follow-up from previous presentations
• There are no outstanding issues to follow up from any previous ERCB presentation
Subsection 3.1.1 – 7g)
Page 162
Subsection 3.1.1 – 7h), well production plots
• Requirements under Subsection 3.1.1 7h) are located in the Appendix
Subsection 3.1.1 – 7h)
Subsection 3.1.1 – 8) Future Plans
Everett Diamond, Development Engineer
Page 164
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
Subsection 3.1.1 – 8a)
Page 165
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
Subsection 3.1.1 – 8a)
Page 166
Resource Recovery Strategy
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
Subsection 3.1.1 – 8a)
Page 167
Resource Recovery Strategy
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)
Subsection 3.1.1 – 8a)
Page 168
Filed Applications
Subsection 3.1.1 – 8a)*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)
Page 169
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
Subsection 3.1.1 – 8a)
*Meet with ERCB first (Q3 2011) regarding Cenovus Blowdown Strategy
Page 170
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
Subsection 3.1.1 – 8b)
Page 171
Drilling Plans – 2012F
Subsection 3.1.1 – 8b)
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
Page 172
Drilling Plans Source and Disposal– 2011F-2012F
Subsection 3.1.1 – 8b)
2011 Future:
No Plans
2012 Future:
Source:• Drill CW3 Pad (10-27-075-06), 3 Hz wells in Clearwater
Disposal• No Plans
Page 173
B07 Pad (8 prod/injectors)
-drilled Q1-2, 2011 (B07 Pad)
- will be completed ~June
Drilling Plans – 2011 Complete
Subsection 3.1.1 – 8b)
Page 174
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
B11 Pad (2012)12 Well pairs
B08 Pad (2012)8 Well pairs
B06 Pad (2011)
8 Well pairs
Subsection 3.1.1 – 8b)
Page 175
Future Strat Well Drilling Plans 2012F
2012 Cased Obs
2012 Strat Wells
Subsection 3.1.1 – 8b)
Page 176
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)
Subsection 3.1.1 – 8c)
Page 177
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
Subsection 3.1.1 – 8c)
Page 178
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)
Subsection 3.1.1 – 8c)
Page 179
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
Subsection 3.1.1 – 8c)
APPENDIX 1 Subsection 3.1.1 7h)
Page 181
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
Subsection 3.1.1 – 5c)
Page 182
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
Subsection 3.1.1 – 5c)
Page 183
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
Subsection 3.1.1 – 5c)
Page 184
Thermocouples in Observation Wells
Subsection 3.1.1 – 5c)
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
Page 185
Thermocouples in Observation Wells - Relative Positions
Subsection 3.1.1 – 5c)
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
Page 186
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)
Page 187
Piezometer Data
Subsection 3.1.1 – 5d)i)
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)
334 mKb 349 mKb 366 mKb 378 mKb 395 mKb
Instrumentation Issues from January 1st – March 2011
Page 188
Piezometer Data
Subsection 3.1.1 – 5d)i)
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)
334 mKb 344 mKb 375 mKb 398 mKb 405 mKb
Page 189
Piezometer Data
Subsection 3.1.1 – 5d)i)
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)
322 mKb 332 mKb 345 mKb 360 mKb 386 mKb
Page 190
Piezometer Data
Subsection 3.1.1 – 5d)i)
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
Page 191
Piezometer Data
Subsection 3.1.1 – 5d)i)
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)
379.0 mKb 357.0 mKb 350.0 mKb 337.3 mKb 330.0 mKb
Page 192
Piezometer Data
Subsection 3.1.1 – 5d)i)
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
Page 193
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)
396.5 mKb 364.4 mKb 348.8 mKb 340.6 mKb 323.8 mKb
Piezometer Data
Subsection 3.1.1 – 5d)i)
Page 194
Piezometer Data
Subsection 3.1.1 – 5d)i)
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
Page 195
Piezometer Data
Subsection 3.1.1 – 5d)i)
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)
374.2 mKb 356.3 mKb 342.5 mKb 335.3 mKb 325.3 mKb
Page 196
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)
403.0 mKb 370.0 mKb 358.0 mKb 347.0 mKb 330.0 mKb
Piezometer Data
Subsection 3.1.1 – 5d)i)
Instrumentation Issues from April 2010– March 2011
Page 197
Piezometer Data
Subsection 3.1.1 – 5d)i)
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
Page 198
Piezometer Data
Subsection 3.1.1 – 5d)i)
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
Page 199
Piezometer Data
Subsection 3.1.1 – 5d)i)
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
Page 200
Piezometer Data
Subsection 3.1.1 – 5d)i)
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
Page 201
Piezometer Data
Subsection 3.1.1 – 5d)i)
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
Page 202
Piezometer Data
Subsection 3.1.1 – 5d)i)
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)
323 mKb 345 mKb 355 mKb 372 mKb 402 mKb
Page 203
Piezometer Data
Subsection 3.1.1 – 5d)i)
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
Page 204Subsection 3.1.1 – 5d)ii-iv)
OB-2 Observation Well (B02-4 Toe)
Page 205Subsection 3.1.1 – 5d)ii-iv)
OB-3 Observation Well (B02-2 Heel)
Page 206Subsection 3.1.1 – 5d)ii-iv)
OB-4 Observation Well (B01-3 Toe)
Page 207Subsection 3.1.1 – 5d)ii-iv)
OB-5 Observation Well (B01-3 Heel)
Page 208Subsection 3.1.1 – 5d)ii-iv)
OB-6 Observation Well (B01-4 Mid)
Page 209Subsection 3.1.1 – 5d)ii-iv)
GP-5 Observation Well (B02-1 Mid)
APPENDIX 2 Subsection 3.1.1 7h)
Page 211Subsection 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)
Page 212Subsection 3.1.1 – 7h)
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)
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)
Page 213Subsection 3.1.1 – 7h)
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)
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)
Page 214Subsection 3.1.1 – 7h)
A01-1 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
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)
Page 215Subsection 3.1.1 – 7h)
A01-2 Well Pair Performance
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
)
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)
Page 216Subsection 3.1.1 – 7h)
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
)
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)
Page 217Subsection 3.1.1 – 7h)
A01-3 Well Pair Performance
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
)
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)
Page 218Subsection 3.1.1 – 7h)
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
Page 219Subsection 3.1.1 – 7h)
A01-4 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
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)
Page 220Subsection 3.1.1 – 7h)
A01-5 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
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)
Page 221Subsection 3.1.1 – 7h)
A01-6 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
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)
Page 222Subsection 3.1.1 – 7h)
B01-1 Well Pair Performance
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
)
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)
Page 223Subsection 3.1.1 – 7h)
B01-2 Well Pair Performance
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
)
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)
Page 224Subsection 3.1.1 – 7h)
B01-3 Well Pair Performance
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
)
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)
Page 225Subsection 3.1.1 – 7h)
B01-4 Well Pair Performance
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
)
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)
Page 226Subsection 3.1.1 – 7h)
B01-5 Well Pair Performance
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
)
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)
Page 227Subsection 3.1.1 – 7h)
B01-6 Well Pair Performance
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
)
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)
Page 228Subsection 3.1.1 – 7h)
B02-1 Well Pair Performance
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
)
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)
Page 229Subsection 3.1.1 – 7h)
B02-2 Well Pair Performance
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
)
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)
Page 230Subsection 3.1.1 – 7h)
B02-3 Well Pair Performance
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
)
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)
Page 231Subsection 3.1.1 – 7h)
B02-4 Well Pair Performance
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
)
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)
Discussion and Questions