Corporate Presentation

Transcription

technology
diversity
We deliver
energy
2011 Confidential Performance Presentation
Whitesands Pilot Project
February 22, 2010
TSX : PBG
Table of Contents

Introduction
Surface Facilities
Measurement and Reporting
Water and Waste Disposal H2S and Sulphur Recovery
Drilling and Completions
Environmental Monitoring
Compliance
Subsurface issues
Introduction
Geology
4‐D Seismic
Scheme Performance
Observations and Conclusions
Future Plans
TSX : PBG
2
Conklin Pilot Area‐ Oil sands asset base
62 sections of oil sands leases (46,240 acres ‐ 100%)
3P reserves of 77.7 mmbbls & contingent recoverable resource of up to 737.1 mmbbls (NPV 8% ‐ $3.6 billion)
TSX : PBG
3
Conklin THAI® Pilot Project
Production Pad & Facility
P1B
(THAI™)
P2B
(THAI™)
P3B
(CAPRI™)
Injection Pad
Injection Pad
TSX : PBG
4
Whitesands THAI®
Integrated injection & production facilities
Air
Toe
Combustion
Zone
Mobile Oil
Coke Zone
Zone
Cold Bitumen
Heel
TSX : PBG
5
THAI® technology benefits
Current operations demonstrate key THAI® benefits

Minimal natural gas and water use
Higher recovery rates: 70‐80% of oil in place

Improved economics

The 70‐80% recovery factor comes from lab work and numerical modeling. Approximately 9% of the hydrocarbon (the heavy ends) is used to make coke which is ultimately the fuel for the combustion process. Combustion gases (see Slide 106), upgraded oil and water are produced. The rest of the hydrocarbon is left behind.
Lower capital cost: 1 horizontal well, no steam or water handling facilities
Lower operating cost: negligible natural gas & minimal water handling
Higher netbacks for partially upgraded product
Faster project execution time
Able to generate power from produced gas
Lower environmental impact

50% less greenhouse gas emissions Partially upgraded oil requires less refining
CO2 capture‐ready
Net useable water production
Smaller surface footprint
TSX : PBG
6
THAI® oil initial upgrading

Native bitumen 8o API, 550,000 centipoise
Consistent THAI®
upgrading since start up
Confirmed CAPRITM
catalyst upgrading
Recent P3B “CAPRITM oil”
quality is up to 15º API
In‐situ upgraded THAI® oil 12o
API, 1,225 centipoise

Produced THAI®
condensate 36 O API
TSX : PBG
7
Oil and water samples from the plant
Sales Oil
Condensate
Sales Oil + Produced Water
Produced
Water
Treater Oil
TSX : PBG
8
Whitesands Project
Operational status
The wells have demonstrated the feasibility of THAI® (Toe‐to‐Heal Air Injection) and of the CAPRI™ catalyst enhancement
Key expectations of the THAI® and CAPRI™ processes have been demonstrated
Initiating communication of P1B continues to be challenging due to wellbore placement in the reservoir
Abandoning P2B due to inability to replace instrumentation string Assessing options for Conklin pilot as a test facility for further technology enhancements
TSX : PBG
9
Plot Plan
TSX : PBG
10
Process Flow Diagram
Start and End of 2010
TSX : PBG
11
Key Facilities Additions 2010
Sand knock‐out vessel modifications for V‐170 (P3‐B)
Completed construction and commissioning of new incinerator (IS‐380)
TSX : PBG
12
Water Withdrawal and Treatment
Our process only requires treatment of fresh water that is softened through a conventional sodium zeolite system
This boiler feed water (BFW) is only required if the wells are being steamed
No other water treatment is required
No brackish water is used
No withdrawal from natural bodies of fresh water
Source water well: 10‐12‐77‐09 W4
Water from source well is used for steam generation and utility water
Source water is drawn from the Empress Channel Aquifer which occurs at the base of the buried Christina Channel
The Empress Channel Aquifer occurs from 160.9 – 186.5 mbgs (meters below ground surface)*
*Reference: Westwater Environmental Ltd., Annual Water Use Report – Whitesands Pilot Project. February 2011.
TSX : PBG
13
Water Balance
Total raw water flow is measured by a turbine meter with totalizer.
The accuracy of the meter is +/‐ 0.5 % of rate. The meter is changed out annually with a new meter or a recalibrated meter.
BFW flow is measured by a Vortex meter Injected steam is measured at each production well using a Vortex meter

All with electronic verifications completed annually, and physical inspections pending shutdowns. The accuracy of the meters is +/‐ 1.35 % of rate.
Utility water is estimated as ~2 m3/day
10‐12‐77‐09 W4M
Jan‐10 Feb‐10 Mar‐10 Apr‐10 May‐10 Jun‐10 Jul‐10 Aug‐10 Sep‐10 Oct‐10 Nov‐10 Dec‐10 Total
4218.8 4217.5 4426 4882 4658.5 3435.3 174.3 2070 4347.4 3705 1574.1 3872.4 41581.1
TSX : PBG
14
Steam Generation and Power Consumption
Steam is injected during the initial well start‐up and may be used periodically for assisting production in the wells
Steam is generated onsite utilizing a 25 MMBTU/HR OTSG
Steam Injection (m3)
1AW ‐ 15‐12‐077‐09 W4M
1 AV ‐ 15‐12‐077‐09 W4M
1 AX ‐ 15‐12‐077‐09 W4M
Total
Jan‐10
2017.2
1376.7
402.2
3796.1
Feb‐10 Mar‐10 Apr‐10 May‐10 Jun‐10 Jul‐10 Aug‐10 Sep‐10 Oct‐10 Nov‐10 Dec‐10
Total
1858.5 2425.3 2104.7 1773.3 1153.2 0.7
236.8 988.4 880.0 589.5 441.1 14468.7
1304.5 534.4 1413.9 1324.4 680.5
0.5
719.9 1271.4 634.9
0.0
0.0
9261.1
830.4 640.0 55.6
0.0
53.2
18.0
0.0
5.5
7.2
0.0
0.0
2012.1
3993.4 3599.7 3574.2 3097.7 1886.9 19.2 956.7 2265.3 1522.1 589.5 441.1 25741.9
Power usage based on bills from Valeo Power Corporation
Power Usage ‐ MWh
2029.3 1641 1587.7 1303 1432.2 1803.6 2160 2300.1 1722.1 1457 830.5 1188 19454.6
TSX : PBG
15
Gas Production And Disposition
All volumes in e3m3
Gas Imported Total Gas Production Gas Vented Gas Flared
Jan‐10
766.7
4484.8
1356.6
3128.2
Feb‐10
799.5
1965.6
96.091 1869.509
Mar‐10
654.5
568.5
0
568.5
Apr‐10
694.1
1061
0
1061
May‐10
458.2
1371
0
1371
Jun‐10
465.4
2960.1
0
2960.1
Jul‐10
292.5
3858.6
0
3858.6
Aug‐10
334.1
3172.7
0
3172.7
Sep‐10
647.8
1107
0
1107
Oct‐10
546.8
863.4
0
863.4
Nov‐10
374.4
649.4
0
649.4
Dec‐10
464.6
520.3
0
520.3
Total
6498.6
22582.4
1452.691 21129.709
TSX : PBG
16
Greenhouse Gases
CO2 Emissions (t)
Based on complete combustion of all gases
Produced Gas
Fuel Gas
Jan‐10
2416.7
1490.4
Feb‐10
1032.9
1554.2
Mar‐10
293.3
1272.3
Apr‐10
571.2
1349.3
May‐10
719.3
890.7
Jun‐10
1541.3
904.7
Jul‐10
2051.3
568.6
Aug‐10
1727.4
649.5
Sep‐10
598.5
1259.3
Oct‐10
460.0
1062.9
Nov‐10
360.3
727.8
Dec‐10
290.0
903.1
Total
3907.1
2587.1
1565.5
1920.5
1610.0
2445.9
2619.9
2376.8
1857.7
1522.9
1088.1
1193.1
TSX : PBG
17
Reporting Methodology to Petroleum Registry

Each well has its own desand, separation and metering
Produced oil for each well is prorated based on the individual well meters and oil cuts and reconciled against sales and tank inventory changes
Produced water for each well is prorated based on the individual well meters and water cuts and reconciled against the disposal meter, water shipments to disposal facilities, and tank inventory changes
Produced gas is metered individually per well train and reconciled against the total gas metered and measured through incineration / flaring.
Injected steam is metered on a per well basis, total steam is measured via BFW consumption and results are reconciled with the disposal volumes from the blowdown tank and utility water usage.
Injected air is metered on a per well basis
MARP Discussions / Revisions
TSX : PBG
18
Air injection wells

A1/A3 are measured by differential pressure transmitter calibrated annually
A2 is measured by a vortex meter that has had an electronic verification done annually.
TSX : PBG
19
Well Flow Measurement
Produced liquid measurement is taken at the outlet of the desand
separator vessels through mass flow meters. The accuracy of these meters is +/‐ 0.2 % of rate.
Produced gas measurement is done by vortex meters after cooling and secondary separation of condensed liquids.
These meters are scheduled to be proven beginning of second quarter every year. This calibration was done in April 2010 and will be completed next in April 2011.
TSX : PBG
20
Proration Factors
Proration factors are based on the volumes measured in the plant versus the volumes as reconciled with inventory and shipments
Proration Factors
Oil
Water
Jan‐10
0.67
0.18
Feb‐10
0.64
0.30
Mar‐10
0.74
0.23
Apr‐10
1.00
0.43
May‐10
1.42
0.26
Jun‐10
0.91
0.44
Jul‐10
0.68
2.76
Aug‐10
2.18
1.00
Sep‐10
0.84
0.65
Oct‐10
1.03
1.04
Nov‐10
0.63
0.90
Dec‐10
0.88
1.32
2010 Average
0.97
0.79
TSX : PBG
21
Water Disposal Wells
Two disposal wells:

00/08‐12‐77‐09 W4 (UWI 100081207709W400) (McMurray formation) 00/15‐12‐77‐09 W4 (UWI 100151207709W400) (McMurray formation)
Produced water volumes are metered by orifice meters at the facility. Turbine meters were installed at both wellheads late in 2010.
Boiler blowdown water is metered by truck gauge
Disposal injection pressure at pump discharge is monitored on DCS Disposal injection pressure readings at the wellheads were not recorded in 2010
Disposal Pressure and Rates: 3000‐3500kPa at 150‐250 m³/d Disposal Volumes (m3)
8‐12‐77‐09 W4M
15‐12‐77‐09 W4M
Injection Pressure
Temperature (°C)
4194.4 4453.5 3530.6 4205 6004.5 5353.7 1351 2833.7 3589.8 2622 1006.2 0.8 39144.9
158.3
1723.3 1881.6
3178.2
3080.4
3101.8
3103
3270
3285.5
1893
3307.2
3079.9
3143.6
2808.3
2911.9
80
80
80
80
80
80
80
80
80
80
80
80
TSX : PBG
23
Water Disposal Pressures and Flows
TSX : PBG
24
Offsite Waste Management
Solid waste is disposed at CCS Janvier landfill (S1/2‐03‐81‐06 W4), volume is recorded on an ERCB Waste Manifest.
Produced and blowdown water is trucked off‐site when we do not have disposal capacity. Locations of offsite disposal are:
Facility Code
AB CT 0000457/557
AB WP 0000671
AB WP 0000677
AB CT 0000458
AB WP 0000556
Company
CCS
Newalta
Cancen
CNRL Beartrap
Palko Environmental
Volume
4383.1
255.0
1047.8
0.4
2772.2
TSX : PBG
25
Quarterly Sulphur Emissions

We manage our produced gas via well production to ensure we do not exceed 1.0 tonne per day of sulphur emissions
A monthly sulphur balance is not included as we combust all of our produced gas so our sulphur inlet is equal to our sulphur outlet. The exception is January and the first few days of February of last year which are shown in the Q1 balance below.
SO2 Emissions (t)
Jan‐10
29.77
Feb‐10
12
Mar‐10
8.21
Apr‐10
16.61
May‐10
12.93
Jun‐10 Jul‐10 Aug‐10 Sep‐10 Oct‐10 Nov‐10 Dec‐10 Total
19.45 24.43 17.75
5.16
3.45 0.889
1.14 151.789
Sulphur Balance (t)
S Removed by Total Quarter S Emissions SO2 Emissions Sweetener
Sulphur
Q1
24.99
49.98
7.30
32.29
Q2
24.50
48.99
24.50
Q3
23.67
47.34
23.67
Q4
2.74
5.48
2.74
TSX : PBG
26
2010 Chronology of events at the Whitesands Pilot
P1B showing response and THAI® quality oil (up to 10o API oil) in late‐June to mid‐August and continually produced combustion gas that is associated with THAI® combustion
P2B established communication with the combustion zone and later encountered instrument string failure
P3B required to shut‐in for a minor casing vent flow and the remedial work is in progress
Experimented with elevated air rates from July‐August to establish communication (maintain high air on A1 up to today)
P2B and P3B down from October‐December TSX : PBG
27
Drilling and Completions 2010 OSE Drilling Program
TSX : PBG
28
Drilling, Completions and Workover Update
Producer Wells
P1B (1AW/16‐12‐77‐9W4/00): no workovers
P2B (1AX/16‐12‐77‐9W4/00): 4 workovers

Two cleanouts

Workover to inspect long string integrity

Workover to replace coil tubing instrument string resulted in parted tubing and decision to abandon the well
P3B (CAPRI™ liner) (1AV/16‐12‐77‐9W4/00)

Three Cleanouts

Remediating low‐flow surface casing vent flow (SCVF)
TSX : PBG
29
Cleanout Details
Cleanouts are done with coil tubing and nitrogen
A P‐tank is used to collect the liquids, solids and gases
Sources of plugged liner includes solids and bitumen
Production tubing also suffers from bitumen plugs
Cleanouts are complete when production is restored
Range in duration from a few hours to several days TSX : PBG
30
P3B Surface Casing Vent Flow
•Total volume released
<100m3
•Composition consistent with
combustion gas
•Leak source is likely through
ST&C casing connections
•SCVF ceased when well was
killed and has not resumed
•Will remediate by cementing in
a new full length slimhole casing
string with premium connections
TSX : PBG
31
P1‐B (With FacsRITE)
TSX : PBG
32
P2‐B (With FacsRITE)
TSX : PBG
33
P3‐B (With CAPRITM)
TSX : PBG
34
FacsRiteTM Liner Design
• Stronger liner integrity
• Improved sand control with screens
• Greater flow area (4 to 10%)
• 2 wells at Whitesands (P1B & P2B)
TSX : PBG
35
CAPRITM Liner (P3B)
TSX : PBG
36
Drilling, Completions and Workover Update Air Injectors & Disposal Wells
P1 (1AH/16‐12‐77‐9W4/00)

Pumped viscous oil to stop cross‐flow to P1B
A3 (1AQ) at 16‐12‐77‐9W4

Recompleted with packerless completion

Monthly fluid shots have always shown annulus is completely purged
Water Disposal Well (100/15‐12‐077‐09W4/03)

Unsuccessful attempt to run a tracer log

Granted temporary operation until April 30, 2011
Water Disposal Well (100/08‐12‐077‐09W4/00)

During packer replacement, packer would not unset and parted tubing while trying to shear packer

Washover mill wedged on fish top and exited casing

Applying for abandonment
TSX : PBG
37
A3 Injector
Packer Removed
Annulus Purged with N2
Monthly fluid shots confirm successfully purged casing annulus
TSX : PBG
38
15‐12 Disposal Well 100/15-12-077-09W4/00
ERCB approved a packer setting depth
between 350.0 – 355.0 (October 2009)
Packer relocated to top of McMurray B
because of casing distortion
After workover to run tracer log, packer
re-set at 355.36 mKB with same
completion configuration
TSX : PBG
39
100/15‐12 Disposal Well
Video shows why tracer log tools could not enter the zone of interest
TSX : PBG
40
Artificial Lift
All producer wells rely on gas lift from combustion gas to provide lift to surface
Water flashing to steam also helps to generate lift
Steam circulation is sometimes required to initiate inflow of combustion gas
TSX : PBG
41
Well Instrumentation
18 thermocouples (TC’s) per observation well (OB and TOB wells) cemented in place. From Clearwater shale to base of McMurray Approximately every 2.5 m through the McMurray
TC’s along the length of the horizontal sections of the production wells, approximately 25 m spacing
20 TC’s in P1B
10 TC’s in P2B
18 TC’s in P3B
Pressure observation well (POB well) with piezometer
pressure sensors in Wabiskaw and in Clearwater
TSX : PBG
42
Pressure Observation Well (POB)
TSX : PBG
43
Environmental Monitoring
Air Quality Passive and produced gas analysis of H2S and SO2 Run off Containment Ponds
Regular monitoring, testing and pump off
Groundwater monitoring
18 shallow groundwater monitoring wells (early detection of subsurface contamination)
2 source water wells
Interim Reclamation
Erosion, sedimentation and dust control; revegetation
Full operational environmental compliance achieved in 2010
TSX : PBG
44
Sampling Points
Passive monitors (4)
Source Wells (2)
Groundwater wells (18)
TSX : PBG
45
Environment
Ambient Air Quality Results 2010
Reporting
Month
H2S Max (ppb)
AAOQO = 3
SO2 Max (ppb)
AAOQO =23
January
0.66
2.5
February
0.66
2.4
March
0.46
1.6
April
0.97
1.1
May
0.73
0.7
June
0.82
0.9
July
2.36
0.9
August
0.84
1.0
September
0.31
0.8
October
0.31
1.0
November
0.38
1.3
December
0.68
1.8
All 2010 monitoring results are below the AAAQO
TSX : PBG
46
Environmental Monitoring Regional Initiatives
Lower Athabasca Regional Plan (LARP)
NOx /SOx emission thresholds
Groundwater project Regional monitoring programs (IMERF)
Southern Athabasca Oil Sands Producers (SAOP)
Regional wildlife project
Insitu Oil Sands Association (IOSA)
Regulatory reform discussions with AENV
TSX : PBG
47
2010 Regulatory Compliance Summary ERCB
Self disclosure - Cased hole blowout/master valve failure (Apr)
ERCB Application Audit (Aug)
Site inspections (Jul, Sept)
Low Risk Non Compliance – Operational Inspection (Oct)
AENV
No compliance issues
ASRD
1 winter drilling inspection (construction and creek crossings)
1 seismic field inspection (construction and creek crossings)
1 OSE aerial reclamation inspection
ABSA
No compliance issues
TSX : PBG
48
Non‐Compliance Issues
Cased hole blowout/Master valve failure
ERCB received a self disclosure about a surface casing vent flow and requested additional information by May 10, 2010

Petrobank provided all requested information to the ERCB
preliminary investigation identified human error as the cause of the incident
physical evidence indicates that the valve was partially closed during operation, causing it to fail
operating procedures had been amended and the procedures reviewed with all applicable personnel
Well Licensing
The new OB wells are currently licensed incorrectly, we are in the process of addressing this non‐compliance
Detailed Operational Inspection
The requirements outlined by the ERCB were successfully addressed
TSX : PBG
49
Original Bitumen In Place (OBIP)
THAITM pilot area
30
m
0
45
0
m
Drainage Area
Length Width
(m)
(m)
450
300
Area (m2)
135,000
Average Net
Rock
Pay
Volume
Thickness
(m3)
(m)
11.5
1,552,500
Porosity
(%)
Pore
Volume
(m3)
Average
Bitumen
Saturation
(%)
Bitumen
Volume In
Place (m3)
34
527,850
80
422,280
Bitumen
Volume In
Place (mmbbl)
2.7
OBIP = Area * pay thickness * porosity * bitumen saturation
TSX : PBG
50
McMurray net Basal bitumen pay isopach
Contour Interval = 1m
TSX : PBG
51
Structure of Basal bitumen pay top
TSX : PBG
52
Structure of bitumen pay base
TSX : PBG
53
Whitesands type log
Clearwater Shale
Wabiskaw Marker
Approximate 20m of
shale as the cap rock
Wabiskaw C
McMurray A
McMurray A Shale
McMurray B
IHS top
Basal Sand top
Main target
bitumen zone
Oil/WaterContact
McMurray C
Paleozoic
TSX : PBG
54
Whitesands Pilot: Well layout and cored wells
Section 12 T77 R9 W4
Cored
Cored
Cored
Cored
Cored
Legend
Observation well
Air injection well
Cored
Production well
Exploration well
TSX : PBG
55
Log‐core correlation
Top
OB1 Well
Core
Gamma
Gamma
Resistivity
Wabiskaw C
McMurray
A2
Sequence
C
Shale
McMurray
B Channel
IHS
McMurray
C Shale
Paleozoic
Mudstone
Clast
Breccia
Basal
B
Sand
B Silty
Mudstone
A
Shale
A
Sand
Paleozoic
Limestone
Bottom
TSX : PBG
56
Petrographic analysis
TSX : PBG
57
Petrographic analysis
383.46m
Sample taken from 383.46m –
383.75m
3C
3E
Q
Z
Clay
383.75m
3B
3D
Burrows and bioturbation enhance the porosity and permeability in the IHS interval and make IHS exploitable with THAI®.
TSX : PBG
58
Structural cross‐section along P1B well
HEEL
TOE
TSX : PBG
59
P1B trajectory
OB1
OB2
OB3
P1B
A Sand
IHS
Basal Sand
TSX : PBG
60
HEEL
TOE
TSX : PBG
61
P2B trajectory
OB4
P2B
OB5
OB6
A Sand
IHS
Basal Sand
TSX : PBG
62
HEEL
TOE
TSX : PBG
63
P3B trajectory
OB7
OB8
OB9
A Sand
P3B
IHS
Basal Sand
TSX : PBG
64
Geomechanical analysis
= Has sonic log
= Has density log
8-12-77-9-W4 Water
Injection
TSX : PBG
65
Geomechanical data analysis
Where:
z = vertical depth
g = acceleration due to gravity
ρ = density
TSX : PBG
67
Geomechanical data analysis
TSX : PBG
68
Geomechanical data analysis: density profiles
TSX : PBG
69
Regional overburden analysis
TSX : PBG
70
Greater May River area seismic
McMurray channel continuous net bitumen (contours) existing 3Ds and 4Ds in green and orange
2010 3D merged seismic (2003, 2005, 2010 shoots)
High‐Res 4D‐3C seismic
2003, 2008, 2009, 2010, 2011
TSX : PBG
71
time (ms)
Paleozoic regional time structure
= Well with compressional sonic
= Well with shear sonic
= 2011 OSE wells
TSX : PBG
72
Seismic cross section through merged 3D
Clearwater
Wabiskaw
Paleozoic
TSX : PBG
73
What is time lapse seismic?
Repeat seismic over time –
like timelapse photography….
Monitors – 5X5m bins
Baseline Interpolated to 5X5m bins
Baseline – 15X20m bins
….then difference the Monitor Surveys from the Baseline
TSX : PBG
74
Seismic velocities
Temperature dependent
Han et al., 2007
TSX : PBG
75
03‐10 Time lapse
OB9
A3
A2
OB6
OB8
A1
OB5
OB3
TSX : PBG
76
Well instrumentation
18 thermocouples (TC’s) per observation well (OB and TOB wells) cemented in place. From Clearwater shale to base of McMurray Approximately every 2.5 m through the McMurray
TC’s along the length of the horizontal sections of the production wells, approximately 25 m spacing
20 TC’s in P1B
10 TC’s in P2B
18 TC’s in P3B
POB well with pressure sensor in Wabiskaw and in Clearwater
TSX : PBG
77
Observation well map
TSX : PBG
78
TOB1 temperature profile
TSX : PBG
79
TOB1 temperature profile (2010)
TSX : PBG
80
TOB2 temperature profile
TSX : PBG
81
TOB2 temperature profile (2010)
TSX : PBG
82
OB3 temperature profile
TSX : PBG
83
OB3 temperature profile (2010)
TSX : PBG
84
TSX : PBG
85
TSX : PBG
86
TSX : PBG
87
TSX : PBG
88
TSX : PBG
89
TSX : PBG
90
Air injection timelines
Steam Injection
(PIHC)
Air Injection
A2 air injector timeline
October 2010
June 2006
March 2006
Steam Injection
(PIHC)
December 2010
April 2007
November 2006
Steam Injection
(PIHC)
Air Injection
Air Injection
October 2010
January 2007
September 2006
A2 and A3 shut down air for well operations in October
TSX : PBG
91
McMurray A sand heating
TSX : PBG
92
McMurray A gas production
TSX : PBG
93
McMurray A sand isopach
TSX : PBG
94
McMurray A sand temperature discussion
This temporary heating of the McMurray A sand during start‐up at TOB1/2 and was due to the high injection pressures for steam injection.

The steam injection pressure likely fractured the McMurray A2 shale and provided a communication conduit for steam heat at first and then hot combustion gas from the advancing front after the PIHC. From the profile at TOB1 and TOB2 this communication was decreasing dramatically before the thermocouples were lost in August of 2008. There is no evidence that these thermocouples failed due to excessively high temperatures. The following reasons could be the cause of the thermocouple failure:

Surface lead issues – Rain, snow, and hot/cold thermal cycling. This also extends to any surface cable that may have been moved or cycled.
Corrosion – if the metal sheath corrodes moisture gets in and shorts the thermocouple. This is the second most common problem after the surface problems
Strain – in places where the thermocouple is spliced together, you can pull apart the splice. This often happens during installation but can also occur downhole.
In addition, the heating of the McMurray A appears to be an extremely localized effect as OB6, which is only 42 meters away, shows very little heating in the time period of this apparent communication.
OB3 more than likely had a similar scenario with steam heat being transferred during the PIHC at A1.
There is no evidence that combustion gas, due to the time of the temperature increase, affected the McMurray A sand temperature at OB3.
The OB3 profile shows that the McMurray A sand is now at native temp and has been for some time. In all of these profiles there is no evidence of a negative impact of the resource in the McMurray A sand. TSX : PBG
95
P1 temperature profile
TSX : PBG
96
P1 temperature profile (2010)
TSX : PBG
97
P1B temperature profile
TSX : PBG
98
P2 temperature profile
TSX : PBG
99
P2 temperature profile (2010)
TSX : PBG
100
Thermocouple string down and pulled October 2010‐present
TSX : PBG
101
TSX : PBG
102
P3B temperature profile (2010)
TSX : PBG
103
POB1 pressure profile
Clearwater Shale
CAPROCK
Wabiskaw Marker
Wabiskaw C sand piezometer
Wabiskaw C Sand top
Clearwater sand piezometer
Piezometers in Wabiskaw C sand and Clearwater Sandstone (above cap rock)
TSX : PBG
104
Air injection wellhead pressures
TSX : PBG
105
Combustion Gas Analyses
TSX : PBG
106
H2
O2
CO
Mar 2011
Jan2011
Nov 2010
Sep2010
Jul 2010
May 2010
Mar 2010
Jan2010
Nov 2009
Sep2009
Jul 2009
May 2009
Mar 2009
Jan2009
Nov 2008
Sep2008
Jul 2008
May 2008
Mar 2008
Jan2008
Nov 2007
Sep2007
Jul 2007
May 2007
Mar 2007
Jan2007
Nov 2006
Sep2006
20
20
18
18
16
16
14
14
12
12
10
10
8
8
6
6
4
4
2
2
0
0
TSX : PBG
MOLE %
Jul 2006
MOLE
P1/P1B Well Combustion Gas Analyses
P1 / P1B GAS
DATE
CO2
107
H2
O2
CO
Mar 2011
Jan2011
Nov 2010
Sep2010
Jul 2010
May 2010
Mar 2010
Jan2010
Nov 2009
Sep2009
Jul 2009
May 2009
Mar 2009
Jan2009
Nov 2008
Sep2008
Jul 2008
May 2008
Mar 2008
Jan2008
Nov 2007
Sep2007
Jul 2007
May 2007
Mar 2007
Jan2007
Nov 2006
Sep2006
20
20
18
18
16
16
14
14
12
12
10
10
8
8
6
6
4
4
2
2
0
0
TSX : PBG
MOLE %
Jul 2006
MOLE
P2 / P2B GAS
DATE
CO2
108
H2
O2
CO
Mar 2011
Jan2011
Nov 2010
Sep2010
Jul 2010
May 2010
Mar 2010
Jan2010
Nov 2009
Sep2009
Jul 2009
May 2009
8
Mar 2009
Jan2009
Nov 2008
Sep2008
Jul 2008
May 2008
Mar 2008
Jan2008
Nov 2007
Sep2007
Jul 2007
May 2007
Mar 2007
Jan2007
Nov 2006
Sep2006
20
20
18
18
16
16
14
14
12
12
10
10
P3BStart-up
6
6
4
4
2
2
0
0
TSX : PBG
MOLE %
Jul 2006
MOLE
P3 / P3B GAS
8
DATE
CO2
109
THAI® Oil Partial Upgrading
Bitumen
Viscosity at 20 ºC, cP
Oil sulphur content, wt % API Gravity “SARA ” ANALYSIS Volatile organics, 40 ºC, mass %
Saturates Aromatics Resins Asphaltenes
Source:
Partially Upgraded Production
550,000 3.2 7.9 1225
2.6
12.3
21.1 12.7
30.3 19.0 16.9
25.5
23.5
22.6
17.2
11.2
Whitesands Bitumen & P1 Upgraded Oil
Archon Technologies Ltd. Oil Analysis 2007 (Archon, a wholly owned technology subsidiary of Petrobank)
TSX : PBG
110
Water Quality
Whitesands Produced Water
Whitesands Condensed Water
Calculated Parameters Units
Total Dissolved Solids mg/L
pH
11,000
8.3
50
8.2
Anions
Bicarbonate (HCO3)
mg/L
mg/L
Carbonate (CO3)
Dissolved Sulphate (SO4) mg/L
Dissolved Chloride (Cl) mg/L
1610
<0.5
<0.5
5800
1600
N/D
N/D
45
Elements
Dissolved Sodium (Na) mg/L
Dissolved Potassium (K) mg/L
Dissolved Calcium (Ca) mg/L
Dissolved Magnesium (Mg) mg/L
3800
17
55
30
10
0.5
0.4
0.1
TSX : PBG
111
A1‐P1 Well Pair Production & Injection History
TSX : PBG
112
A1‐P1 Well Pair Liquids Production & Injection History
TSX : PBG
113
A1‐P1 Well Pair Cumulative Oil Production & Air‐Oil Ratio
TSX : PBG
114
TSX : PBG
115
TSX : PBG
116
TSX : PBG
117
TSX : PBG
118
TSX : PBG
119
TSX : PBG
120
A1‐P1B Well Pair Production & Injection History
TSX : PBG
121
A1‐P1B Well Pair Liquids Production & Injection History
TSX : PBG
122
A1‐P1B Well Pair Cumulative Oil Production & Air‐Oil Ratio
TSX : PBG
123
TSX : PBG
124
TSX : PBG
125
TSX : PBG
126
TSX : PBG
127
TSX : PBG
128
TSX : PBG
129
Field Oil Production & Steam – Air Injection History
TSX : PBG
130
Field Gas Production & Injection History
TSX : PBG
131
Field Liquids Production & Injection History
TSX : PBG
132
Field Oil Production & Air‐Oil Ratio (AOR) trends
TSX : PBG
133
Field Cumulative Oil Production and Air‐Oil Ratio
TSX : PBG
134
Well On‐Stream Factor: P1, P2 & P3
TSX : PBG
135
Well On‐Stream Factor: P1B, P2B & P3B
TSX : PBG
136
Observations & Conclusions
Fluid Quality Summary
Oil

Consistent API upgrade and viscosity reduction
Significant increase in volatiles and saturates
Notable reduction of resins and asphaltenes
Increased carry over of lighter ends to the secondary separators as surface temperatures increase
Early production from new wells does not show significant upgrading
Overall a higher quality produced oil than SAGD
Gas

No issues with O2 in produced gas
Free H2 production up to 8% Up to 9% of hydrocarbons (C1–C5) in the produced gas with a heating value 85‐120 Btu/scf, suitable for use in Low‐Btu steam generators
CO2 and CO levels and ratios consistent with high temperature combustion
H2S levels are stable in produced gas, off‐set by reduction of sulphur in produced oil TSX : PBG
137
Observations and Conclusions
Successfully ran the CAPRITM well at temperatures between 350 to 450oC at the toe for catalytic cracking
Bitumen upgrading was increased by an additional 3oAPI with CAPRITM
Reservoir thickness and quality are the major contributors, along with low plant on‐stream times early on in the project, to the difference in approval capacity and actual production
Wellbore trajectory also has a large impact on well performance and establishment of injector communication
On stream factors are still problematic (cumulative on‐stream for all three wells is 55%)
TSX : PBG
138
Key Learnings to date
Conklin Pilot
Reservoir quality constrains the initial production rates
THAI® is the only known process that can produce in this quality of reservoir
Wellbore placement toward bottom of the reservoir is optimal
On stream factor of facilities is critical to advance production
TSX : PBG
139
Future Plans
Conklin plant will be used as a field testing site for:

Enriched oxygen injection
Sulphur removal (catalytic and chemical)
Multi‐THAI® well configuration
The following activities are proposed for 2011

Abandonment 8‐12 water disposal well
Redrill water disposal well on the 15‐12 pad
Evaluate existing 15‐12 disposal well
Abandon P2B/Re‐drill
Evaluate P3B

Remediate or re‐drill
Potential new injection well (Multi‐THAI® candidate)
Evaluate P1B to potentially re‐drill the A1 closer to the heel
Evaluate potential new producing wells
TSX : PBG
140
technology
diversity
We deliver
energy
TSX: PBG
www.petrobank.com
TSX : PBG