Corporate Presentation

Transcription

2011 Confidential
Performance Presentation
Whitesands Pilot Project
April 2012
Table of Contents








2
Introduction
Surface Facilities
• Measurement and Reporting
• Water and Waste Disposal
• H2S and Sulphur Recovery
Drilling and Completions
Environmental Monitoring
Compliance
Subsurface
• Geology
• 4-D Seismic
• Scheme Performance
Observations and Conclusions
Future Plans
Whitesands Pilot Area – Petrobank Oil Sands Asset Base
Petrobank area

In-situ project
Mining project
3

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)
Whitesands THAI® Pilot Project
Production Pad &
Facility
P1B
(THAI™)
Injection Pad
4
P2B
(THAI™)
P3B
(CAPRI™)
Whitesands Project - 2011 Operational Update
THESE ARE 2010 POINTS - UPDATE
•
•
•
•
•
5
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
Facilities Plot Plan
6
Process Flow Diagram
Start and End of 2011
7
Key Facilities Additions and Status 2011
•
•
•
•
•
8
Repaired V-165 and removed V-160 from service
Installed rental pump to perform wet combustion test
Air injection rates were decreased September 16, 2011
Air injection rates on A1 and A2 were ceased on September 24,
2011
Facility operations were ceased on October 12, 2011
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.
9
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-11
Feb-11
Mar-11
Apr-11
May-11
Jun-11
Jul-11
Aug-11
Sep-11
Oct-11
Nov-11
Dec-11
Total
518.6
73.2
47.5
55.8
956.5
1104.3
1536.2
1492.9
482
18.8
205
22
6512.8
10
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)
Jan-11 Feb-11 Mar-11 Apr-11 May-11 Jun-11 Jul-11 Aug-11 Sep-11 Oct-11 Nov-11 Dec-11 Total
1AW - 15-12-077-09 W4M 28.1
0.0
5.5
0.0
50.2 556.8 805.4 1162.4 339.4 0.0
0.0
0.0 2947.83
Total
28.1
0.0
5.5
0.0
50.2 556.8 805.4 1162.4 339.4 0.0
0.0
0.0 2947.83
•
Power usage based on bills from Valeo Power
Corporation
Power Usage - MWh
11
Jan-11
Feb-11
Mar-11
Apr-11
May-11
Jun-11
Jul-11
Aug-11
Sep-11
Oct-11
Nov-11
Dec-11
Total
1242.3
1188.2
1046.3
1100.8
1013.7
1324.4
1649.2
1616.7
787.8
400.3
404.1
405.9
12179.7
Gas Production And Disposition
•
All volumes in e3m3
Total Gas
Gas Imported Production Gas Vented Gas Flared
Jan-11
257.7
733.7
0
991.4
Feb-11
214.1
578.5
0
792.6
Mar-11
211
578.5
0
789.5
Apr-11
157.8
253.7
0
411.5
May-11
170.9
232.7
0
403.6
Jun-11
196.5
336.6
0
533.1
Jul-11
191.5
528.3
0
719.8
Aug-11
133.5
569.7
0
703.2
Sep-11
97.8
633
0
730.8
Oct-11
39.2
98.9
0
138.1
Nov-11
131.7
0
0
131.7
Dec-11
130
0
0
130
Total
1931.7
4543.6
0
6475.3
12
Greenhouse Gases
•
•
CO2 Emissions (t)
Based on complete combustion of all gases
Jan-11
Feb-11
Mar-11
Apr-11
May-11
Jun-11
Jul-11
Aug-11
Sep-11
Oct-11
Nov-11
Dec-11
Total
13
Produced Gas
351.4
277.1
277.1
121.5
111.5
161.2
253.1
272.9
303.2
47.4
0.0
0.0
2176.3
Fuel Gas
500.9
416.2
410.2
306.7
332.2
382.0
372.3
259.5
190.1
76.2
256.0
252.7
3755.0
Total
852.4
693.3
687.3
428.3
443.7
543.2
625.3
532.4
493.3
123.6
256.0
252.7
5931.4
Reporting Methodology to Petroleum Registry






14
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
14
Air injection Wells


15
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.
Well Flow Measurement



16
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 2011 and
will be completed next in April 2012.
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-11
1.00
1.00
Feb-11
1.28
0.32
Mar-11
0.50
1.00
Apr-11
1.00
1.00
May-11
1.00
1.00
Jun-11
1.00
1.00
Jul-11
1.00
1.00
Aug-11
1.00
1.00
Sep-11
1.00
1.00
Oct-11
1.00
1.00
Nov-11
N/A
N/A
Dec-11
N/A
N/A
2011
Average
0.98
0.93
17
Water Disposal Wells

Two disposal wells:
•
•



00/08-12-77-09 W4 (UWI 100081207709W400) (McMurray formation)
─ This well was abandoned in 2011 and never used
00/15-12-77-09 W4 (UWI 100151207709W400) (McMurray formation)
Produced water volumes are metered by orifice meters at the
facility and using turbine meters at the wellhead.
Boiler blowdown water is metered by truck gauge
Disposal injection pressure at pump discharge and wellhead is
monitored on DCS
•
•
Pump discharge pressure was recorded and would trip the pump at 3500 kPag. Wellhead
pressure was continuously monitored and would trip the pump at 3500 kPag.
There were 25 incidents where the pump discharge pressure exceeded 3500 kPag in 2011.
Each time, the pump tripped immediately and the excedences were never longer than 5
seconds.
Disposal Volumes (m3)
15-12-77-09 W4M
19
Jan-11 Feb-11 Mar-11 Apr-11 May-11 Jun-11 Jul-11 Aug-11 Sep-11 Oct-11 Nov-11 Dec-11
751.3
60.8
446
431.8 1107.3 571.5 1304.9 1160.1 899.5 131.7
Total
6864.9
Water Disposal Pressures (kPag)
20
Water Disposal Flows (m3)
21
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
Company
AB CT 0000457/557 CCS
AB WP 0000556
Palko Environmental
22
Volume
194.0
1083.4
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)
10-12-77-09 W4M
Jan-11
2.79
Feb-11
3.06
Sulphur Balance (t)
Quarter
Q1
Q2
Q3
Q4
23
S Emissions SO2 Emissions
2.93
5.85
2.63
5.26
5.11
10.22
1.59
3.18
Mar-11 Apr-11 May-11 Jun-11 Jul-11 Aug-11 Sep-11 Oct-11 Nov-11 Dec-11
0.0562
2.5
2.7
3.62
2.304
4.3
2.74
0.435
0
0
Total
24.5
Drilling and Completions Well Status
P1B
(THAI™)
Shut in
24
P2B
(THAI™)
Abandoned
P3B
(CAPRI™)
Suspended
Drilling, Completions and Workover 2011 Update
•
Production Wells:
•
P1B (1AW/16-12-77-9W4/00) Licence # 0410828:
No workovers in 2011. Well remained active & producing up until October 12, 2011
•
Well is currently shut in
•
P2B (1AX/16-12-77-9W4/00) Licence # 0411485 :
• 2010 workover to replace coiled tubing instrument string resulted in parted tubing
and extensive fishing job. Decision made then to abandon well.
• Well was abandoned, (cut & capped) in 2011.
•
P1 (1AH/16-12-77-9W4/00) Licence # 0325005 :
•
25
•
•
Well previously shut in due to excessive sand production.
•
Well abandoned in 2011, awaiting cut & cap.
107/16-12-77-9W4/00 (Drilled and Cased) Licence # 0432326 :
•
Well drilled to test for seismic gas anomaly in the bottom water
•
Well will be used to test for combustion gas in Wabaskaw/McMurray “A” &
Clearwater formations related to our gas migration discussion with Devon Canada.
P1-B (With FacsRITE)
26
26
P1
1AH/16-12-77-09W4
• Well previously shut in due
to excessive sand
production.
• Well abandoned in 2011,
awaiting cut & cap.
27
FacsRiteTM Liner Design
• Stronger liner integrity
• Improved sand control with screens
• Greater flow area (4 to 10%)
• 2 wells at Whitesands (P1B & P2B)
28
CAPRITM Liner (P3-B)
29
Air Injector and Disposal Well Workover Update
•
Water Disposal Well (100/15-12-077-09W4/03)
• Found obstruction in casing above injection perforations.
Bottom of well abandoned, (filled with cement) and wellbore
sidetracked in 2011. Perforated sidetrack casing and
established injectivity
•
Water Disposal Well (100/08-12-077-09W4/00)
• During 2010 packer replacement, packer would not unset and
parted tubing while trying to shear packer. Washover mill
wedged on fish top and exited casing. Decision made to
abandon well
• Wellbore abandonment completed in March 2011, (cut &
capped)
30
Disposal Well
100/15-12-77-09W4/03
is now
100/15-12-77-09W4/04
• Side tracked in 2011 due to
casing obstruction above
injection perforations.
• Ran & cemented 114.3mm
casing in place.
• Perforated well. Injectivity
obtained.
31
Disposal Well
100/08-12-77-09W4
• During 2010 packer
replacement, packer would
not unset. Parted tubing
while trying to shear packer.
Washover mill wedged on
fish top and exited casing.
Decision made to abandon
well.
• Wellbore abandonment
completed in 2011, (cut &
capped).
32
Artificial Lift
Prior to suspension of project, producer wells relied on
gas lift from combustion gas to provide lift to surface.
• Water flashing to steam also helped to generate lift.
• Steam circulation was sometimes required to initiate
inflow of combustion gas.
•
33
Well Instrumentation
TC’s along the length of the horizontal sections of the
production wells, approximately 25 m spacing
• 20 TC’s in P1B
• 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
• Pressure observation well (POB well) with piezometer
pressure sensors in Wabiskaw and in Clearwater
•
34
Pressure Observation
Well (POB1)
35
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


36
Full operational environmental compliance achieved in
2011
Sampling Points
37
Passive monitors (4)
Source Wells (2)
Groundwater wells (18)
Ambient Air Quality Results 2011
Reporting Month
H2S Max (ppb)
AAOQO = 3
SO2 Max (ppb)
AAOQO =23
January
0.53
1.9
February
1.85
1.8
March
0.25
1.0
April
0.27
0.7
May
0.15
0.4
June
0.46
0.4
July
0.32
0.2
August
0.59
0.6
September
0.2
0.8
October
0.09
0.3
November
0.15
0.5
December
0.14
0.5
The results Aug are from data collected between Aug 1 – Sept 26
The results from Sept are from data collected between Sept 26
and Oct 1
38
All 2011 monitoring
results are below
the AAAQO
Environmental Monitoring Regional Initiatives



39
Lower Athabasca Regional Plan (LARP)
• NOx /SOx emission thresholds
• Groundwater project
• Regional monitoring programs (IMERF)
Southern Athabasca Oil Sands Producers (SAOP)
• None
Insitu Oil Sands Association (IOSA)
• None
2011 Regulatory Compliance Summary
•
ERCB 2011
•
•
•
•
40
Self Disclosure - Disposal Well Pressure Exceedance (Mar 11)
Self Disclosure - PRA Water Metering Difference (Jun 11)
Request - Maximum Operating Pressure Re-assessment (Jun 11)
Combustion Gas Migration to Devon 8-13-77-9W4M (Aug 11)
Non Compliance Issues
•
Disposal Well Pressure Exceedance 15-12-77-9 W4M
• We exceeded the permitted operable pressure on this well.
•
PRA Water Metering Difference Non Compliance for BA
Code A514
• Petroleum registry reporting issue where PBG is reporting injected
water to a facility that should not accept it
•
Maximum Operating Pressure Re-assessment
• We requested a reduction in our MOP from 8000 to 6000kPa
•
Combustion Gas Migration to Devon 8-13-77-9W4M
• Devon encountered a gas composition at their well that resembles
THAI® combustion gas.
41
Non Compliance Issues - Gas Migration
•
•
•
•
42
No definitive
conclusion of
cause or method
of migration.
No evidence of
caprock breach.
Poor cement job
on 8-13.
Well testing
should be done to
explore inter
wellbore
communication as
cause.
Original Bitumen In Place (OBIP)
THAITM pilot area
Drainage Area
Length Width
(m)
(m)
43
450
300
Area (m2)
Average
Net Pay
Thickness
(m)
Rock
Volume
(m3)
Porosity
(%)
Pore
Volume
(m3)
Average
Bitumen
Saturation
(%)
Bitumen
Volume In
Place (m3)
135,000
11.5
1,552,500
34
527,850
80
422,280
OBIP = Area * pay thickness * porosity * bitumen saturation
Bitumen
Volume In
Place (mmbbl)
2.7
McMurray Basal Net Bitumen Pay Isopach
Contour Interval = 1m
44
Structure of Basal Bitumen Pay Top
45
Structure of Bitumen Pay Base
46
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
47
Paleozoic
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
48
Log-Core Correlation
OB1 Well
Core
Gamma
Gamma
Top
Resistivity
Wabiskaw C
McMurray A2
Sequence
C
Shale
McMurray
B Channel
IHS
McMurray
C Shale
49
Paleozoic
Mudstone
Clast
Breccia
Paleozoic
Limestone
Bottom
Basal
B
Sand
B Silty
Mudstone
A
Shale
A
Sand
Petrographic Analysis
50
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®.
51
Structural Cross-Section Along P1B Well
52
HEEL
TOE
P1B Trajectory
OB1
OB2
OB3
P1B
A Sand
IHS
Basal
Sand
53
54
HEEL
TOE
P2B Trajectory
OB4
P2B
OB5
OB6
A Sand
IHS
Basal
Sand
55
56
HEEL
TOE
P3-B Trajectory
OB7
OB8
OB9
A Sand
P3B
IHS
Basal
Sand
57
Greater May River Seismic
8
9
10
11
12
13
25
15
2010 3D merged seismic
(2003, 2005, 2010 shoots)
20
20
15
1102
10
8 5
High-Res 4D-3C seismic
2003, 2008, 2009, 2010, 2011
0
77-09W4
12
8
15
0
12
5
5
5
G
1
0
15
1292
72
10
3
526740915832661646194649472972497
9889788931797684753281967987864557423319879660475311880365046258359037185460181335467501813056461342694974922
2
999 7166556452597452394412
0
G
G
5
25
8
McMurray channel
continuous net
bitumen
(contours)
existing 3Ds and
4Ds in green and
orange
1
15
8
12
5
20
1
0
5
10
0
10
8
0
8
25
5
0
5
12
5 8
12
0
15
12
12
20
15
2
12
15
8
10
5
10
0
0
985
1,970
METERS
58
PETRA 12/8/2011 9:51:33 AM
2,955
TWT (ms)
Paleozoic Regional Time Structure- 2011 reprocessing
= Well with compressional sonic
= Well with shear sonic
= 2011 OSE wells
59
Regional cross section- 2011 reprocess
CLRWTR
Sand
Wabisakw
MRKR
Paleozoi
c
Prairie
Evaporite
Ernestina Lake
60
What is time lapse seismic?
Repeat seismic over time –
like timelapse photography….
Monitors – 5X5m bins
Baseline Interpolated to
5X5m bins
….then difference the
Monitor Surveys from
the Baseline
61
What drives the time lapse response?
62
Time lapse- past interpretation
Technical Data


-.25 s

2003-2008
All dedicated monitor surveys shot with similar
parameters (2008/2009/2010) and similar ground
conditions
 125 g dynamite @ 3m depth, 60 x100m receiver
line spacing, Sercel 428 acquisition system, 5x5
binning
 All processed concurrently for time lapse analysis
at CGGVeritas Calgary
All data shown below is PP time lapse analysis cross
correlated from 350-450ms to remove near surface static
changes
0s
.25 s
Summed time shifts at the Paleozoic horizon +25ms and 35ms to capture the McMurray formation and any delayed
shifts
2003-2009
OB9
Related
to gas
at the
O/W
contact
OB9
A3
A2
OB6
OB8
A1
OB5
OB3
2003-2010
OB9
A3
A3
A2
A2
OB6
OB6
OB8
OB8
A1
A1
OB5
63
OB3
OB5
OB3
Bottom water test well: OB17
OB17
64
OB17
No density
neutron cross
over in the McM
A/Wab C
65
Tested
combustion gas
from this log
signature
2011-2003 time lapse results
-.25 s
0s
.25 s
McMurray THAI
combustion gas
in the bottom
water (OBS 17
analogue)
McMurray THAI
heat/combustion
gas and bottom
water
66
Time lapse
2003-2008
2003-2009
-.25 s
OB9
OB9
A3
A3
A2
A2
OB6
OB6
OB8
OB8
A1
A1
OB5
OB3
OB5
OB3
OB9
2003-2011
OB17
OB9
A3
A3
A2
A2
OB6
OB6
OB8
OB8
OB5
OB3
A1
OB5
OB3
.25 s
A1
67
0s
2003-2010
Discrete InSAR
2007-2008
2007-2010
68
2007-2009
Discrete InSAR
2008-2009
2009-2010
69
2008-2010
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
•
•
70
POB well with pressure sensor in Wabiskaw and in
Clearwater
OBS well map
71
TOB1 temperature profile
72
TOB2 temperature profile
73
OB3 temperature profile
74
OB3 temperature profile (2011)
75
76
77
78
79
80
81
P1 temperature profile
82
P1 temperature profile (2011)
83
P1B temperature profile
84
P1B temperature profile (2011)
85
86
P2 temperature profile (2011)
87
•
88
No update from 2010
•
89
No update from 2010
•
90
No update from 2010
POB1 pressure data: 2011 daily average
2006- June 2011 MOP
June 2011- present MOP
Data historian
malfunction…missing
data
Conklin shut in
Piezometers in Wabiskaw C sand and
Clearwater Sandstone (above cap rock)
91
POB1 pressure profile (Wabiskaw piezometer raw data)
92
POB1 pressure profile (Clearwater piezometer raw data)
93
POB1 pressure profile (raw daily average)
2006-June 2011 MOP
Pre 2008 data
using faulty
surface module:
erroneous low
signal strength
readings
94
Observation well
workover with tubing
open to surface.
Data should be
omitted
Conklin shut in
POB1 pressure profile (edited for bad data: daily average)
2006-June 2011 MOP
Pre 2008 data
using faulty
surface module:
erroneous low
signal strength
readings
Conklin shut in
95
Combustion Gas Analyses
WHITESANDS COMBUSTION GAS COMPOSITION & VOLUMES
2011
AVERAGE FROM DAILY GAS ANALYSES
4,543.600
VOLUME
P1B
COMBINED
103m3
H2
HYDROGEN
0.83
0.83
37.8
O2
OXYGEN
0.10
0.10
4.7
N2
NITROGEN
76.37
76.37
3,470.2
CO
CARBON MONOXIDE
0.02
0.02
0.8
CH4
METHANE
5.23
5.23
237.6
CO2
CARBON DIOXIDE
15.51
15.51
704.6
C2H6
ETHANE
0.91
0.91
41.5
C3H8
PROPANE
0.41
0.41
18.7
C4
NORMAL-BUTANE
0.20
0.20
9.1
C5
NORMAL-PENTANE
0.01
0.01
0.3
H2S
HYDROGEN SULFIDE
0.40
0.40
18.4
100.00
100.00
4,543.6
TOTAL
96
MOLE %
C1-C5 (HYDROCARBONS)
6.76
97
H2
O2
CO
DATE
CO2
Jan 2012
Nov 2011
Sep 2011
Jul 2011
May 2011
Mar 2011
Jan 2011
Nov 2010
Sep 2010
Jul 2010
May 2010
Mar 2010
Jan 2010
Nov 2009
Sep 2009
Jul 2009
May 2009
Mar 2009
Jan 2009
Nov 2008
Sep 2008
Jul 2008
May 2008
Mar 2008
Jan 2008
Nov 2007
Sep 2007
Jul 2007
May 2007
Mar 2007
Jan 2007
Nov 2006
Sep 2006
Jul 2006
MOLE %
P1/P1B Well Combustion Gas Analyses
P1 / P1B GAS
20
18
16
14
12
10
8
6
4
2
0
98
H2
O2
CO
DATE
CO2
Mar 2011
Jan 2011
Nov 2010
Sep 2010
Jul 2010
May 2010
Mar 2010
Jan 2010
Nov 2009
Sep 2009
Jul 2009
May 2009
Mar 2009
Jan 2009
Nov 2008
Sep 2008
Jul 2008
May 2008
Mar 2008
Jan 2008
Nov 2007
Sep 2007
Jul 2007
May 2007
Mar 2007
Jan 2007
Nov 2006
Sep 2006
20
20
18
18
16
16
14
14
12
12
10
10
8
8
6
6
4
4
2
2
0
0
MOLE %
Jul 2006
MOLE %
P2 / P2B GAS
99
H2
O2
CO
DATE
CO2
Mar 2011
Jan 2011
Nov 2010
Sep 2010
Jul 2010
May 2010
Mar 2010
Jan 2010
Nov 2009
Sep 2009
Jul 2009
May 2009
8
Mar 2009
Jan 2009
Nov 2008
Sep 2008
Jul 2008
May 2008
Mar 2008
Jan 2008
Nov 2007
Sep 2007
Jul 2007
May 2007
Mar 2007
Jan 2007
Nov 2006
Sep 2006
20
20
18
18
16
16
14
14
12
12
10
10
P3B Start-up
8
6
6
4
4
2
2
0
0
MOLE %
Jul 2006
MOLE %
P3 / P3B GAS
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:
100
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)
Water Quality
Whitesands Produced Water
Calculated Parameters Units
Total Dissolved Solids
mg/L
pH
11,000
8.3
50
8.2
Anions
Bicarbonate (HCO3)
Carbonate (CO3)
Dissolved Sulphate (SO4)
Dissolved Chloride (Cl)
1610
<0.5
<0.5
5800
1600
N/D
N/D
45
3800
17
55
30
10
0.5
0.4
0.1
mg/L
mg/L
mg/L
mg/L
Elements
Dissolved Sodium (Na) mg/L
Dissolved Potassium (K) mg/L
Dissolved Calcium (Ca) mg/L
Dissolved Magnesium (Mg) mg/L
101
Whitesands Condensed Water
A1-P1 Well Pair Production & Injection History
800
3 200
750
3 000
700
2 800
650
2 600
600
2 400
550
2 200
500
2 000
450
1 800
400
1 600
350
1 400
300
1 200
250
1 000
200
800
150
600
100
400
50
200
0
0
PROD. OIL M3
102
PROD. GAS 103M3
INJ. AIR 103M3
MONTHLY INJ AIR / PROD. GAS, 103M3
MONTHLY PROD. OIL, M3
1AH/16-12-077-09 W4/00
A1-P1 Well Pair Liquids Production & Injection History
800
4 800
750
4 500
700
4 200
650
3 900
600
3 600
550
3 300
500
3 000
450
2 700
400
2 400
350
2 100
300
1 800
250
1 500
200
1 200
150
900
100
600
50
300
0
0
PROD. OIL M3
103
PROD. WATER M3
INJ. STEAM M3
MONTHLY INJ STEAM / PROD. WATER, M3
1AH/16-12-077-09 W4/00
A1-P1 Well Pair Cumulative Oil Production & Air-Oil Ratio
10 000
10 000
9 000
9 000
8 000
8 000
7 000
7 000
6 000
6 000
5 000
5 000
4 000
4 000
3 000
3 000
2 000
2 000
1 000
1 000
0
0
CUM. PROD. OIL M3
104
CAOR M3/M3
CAOR, M3/M3
CUM. PROD. OIL, M3
1AH/16-12-077-09 W4/00
600
3 000
550
2 750
500
2 500
450
2 250
400
2 000
350
1 750
300
1 500
250
1 250
200
1 000
150
750
100
500
50
250
0
0
PROD. OIL M3
105
PROD. GAS 103M3
INJ. AIR 103M3
1AJ/16-12- 077-09 W4/00
600
3 000
550
2 750
500
2 500
450
2 250
400
2 000
350
1 750
300
1 500
250
1 250
200
1 000
150
750
100
500
50
250
0
0
PROD. OIL M3
106
PROD. WATER M3
INJ. STEAM M3
1AJ/16-12- 077-09 W4/00
10 000
10 000
9 000
9 000
8 000
8 000
7 000
7 000
6 000
6 000
5 000
5 000
4 000
4 000
3 000
3 000
2 000
2 000
1 000
1 000
0
0
CUM. PROD. OIL M3
107
CAOR M3/M3
CAOR, M3/M3
CUM. PROD. OIL, M3
1AJ/16-12- 077-09 W4/00
600
3 000
550
2 750
500
2 500
450
2 250
400
2 000
350
1 750
300
1 500
250
1 250
200
1 000
150
750
100
500
50
250
0
0
PROD. OIL M3
108
PROD. GAS 103M3
INJ. AIR 103M3
1AK/16-12-077-09 W4/00
600
3 000
550
2 750
500
2 500
450
2 250
400
2 000
350
1 750
300
1 500
250
1 250
200
1 000
150
750
100
500
50
250
0
0
PROD. OIL M3
109
PROD. WATER M3
INJ. STEAM M3
1AK/16-12-077-09 W4/00
10 000
10 000
9 000
9 000
8 000
8 000
7 000
7 000
6 000
6 000
5 000
5 000
4 000
4 000
3 000
3 000
2 000
2 000
1 000
1 000
0
0
CUM. PROD. OIL M3
110
CAOR M3/M3
CAOR, M3/M3
CUM. PROD. OIL, M3
1AK/16-12-077-09 W4/00
A1-P1B Well Pair Production & Injection History
600
3 000
550
2 750
500
2 500
450
2 250
400
2 000
350
1 750
300
1 500
250
1 250
200
1 000
150
750
100
500
50
250
0
0
PROD. OIL M3
111
PROD. GAS 103M3
INJ. AIR 103M3
1AW/16-12-077-09 W4/00
A1-P1B Well Pair Liquids Production & Injection History
1AW/16-12-077-09 W4/00
3 600
550
3 300
500
3 000
450
2 700
400
2 400
350
2 100
300
1 800
250
1 500
200
1 200
150
900
100
600
50
300
0
0
PROD. OIL M3
112
PROD. WATER M3
INJ. STEAM M3
600
A1-P1B Well Pair Cumulative Oil Production & Air-Oil Ratio
12 000
12 000
11 000
11 000
10 000
10 000
9 000
9 000
8 000
8 000
7 000
7 000
6 000
6 000
5 000
5 000
4 000
4 000
3 000
3 000
2 000
2 000
1 000
1 000
0
0
CUM. PROD. OIL M3
113
CAOR M3/M3
CAOR, M3/M3
CUM. PROD. OIL, M3
1AW/16-12-077-09 W4/00
600
3 000
550
2 750
500
2 500
450
2 250
400
2 000
350
1 750
300
1 500
250
1 250
200
1 000
150
750
100
500
50
250
0
0
PROD. OIL M3
114
PROD. GAS 103M3
INJ. AIR 103M3
1AX/16-12-077-09W4/00
600
3 600
550
3 300
500
3 000
450
2 700
400
2 400
350
2 100
300
1 800
250
1 500
200
1 200
150
900
100
600
50
300
0
0
PROD. OIL M3
115
PROD. WATER M3
INJ. STEAM M3
1AX/16-12-077-09W4/00
24 000
24 000
22 000
22 000
20 000
20 000
18 000
18 000
16 000
16 000
14 000
14 000
12 000
12 000
10 000
10 000
8 000
8 000
6 000
6 000
4 000
4 000
2 000
2 000
0
0
CUM. PROD. OIL M3
116
CAOR M3/M3
CAOR, M3/M3
CUM. PROD. OIL, M3
1AX/16-12-077-09W4/00
1000
950
900
850
800
750
700
650
600
550
500
450
400
350
300
250
200
150
100
50
0
3 000
2 700
2 400
2 100
1 800
1 500
1 200
900
600
300
0
PROD. OIL M3
117
PROD. GAS 103M3
INJ. AIR 103M3
1AV/16-12-077-09 W4/00
1000
950
900
850
800
750
700
650
600
550
500
450
400
350
300
250
200
150
100
50
0
3 000
2 700
2 400
2 100
1 800
1 500
1 200
900
600
300
0
PROD. OIL M3
118
PROD. WATER M3
INJ. STEAM M3
1AV/16-12-077-09 W4/00
10 000
10 000
9 000
9 000
8 000
8 000
7 000
7 000
6 000
6 000
5 000
5 000
4 000
4 000
3 000
3 000
2 000
2 000
1 000
1 000
0
0
CUM. PROD. OIL M3
119
CAOR M3/M3
CAOR, M3/M3
CUM. PROD. OIL, M3
1AV/16-12-077-09 W4/00
Field Gas Production & Injection History
1 500
7 500
1 400
7 000
1 300
6 500
1 200
6 000
1 100
5 500
1 000
5 000
900
4 500
800
4 000
700
3 500
600
3 000
500
2 500
400
2 000
300
1 500
200
1 000
100
500
0
0
PROD. OIL M3
120
PROD. GAS 103M3
INJ. AIR 103M3
PROJECT-TOTAL
Field Liquid Production & Steam Injection History
1500
7 500
1400
7 000
1300
6 500
1200
6 000
1100
5 500
1000
5 000
900
4 500
800
4 000
700
3 500
600
3 000
500
2 500
400
2 000
300
1 500
200
1 000
100
500
0
0
PROD. OIL M3
121
PROD. WATER M3
INJ. STEAM M3
PROJECT-TOTAL
Field Cumulative Oil Production and Air-Oil Ratio
30 000
15 000
28 000
14 000
26 000
13 000
24 000
12 000
22 000
11 000
20 000
10 000
18 000
9 000
16 000
8 000
14 000
7 000
12 000
6 000
10 000
5 000
8 000
4 000
6 000
3 000
4 000
2 000
2 000
1 000
0
0
CUM. PROD. OIL M3
122
CAOR M3/M3
CAOR, M3/M3
CUM. PROD. OIL, M3
PROJECT-TOTAL
Observations & Conclusions
Fluid Quality Summary

Oil
•
•
•
•
•
•

Gas
•
•
•
•
•
123
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
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 85120 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
Observations and Conclusions





124
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%)
Key Learnings to date
•
•
•
•
125
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
Future Plans
In early 2012, the Whitesands Project along with Petrobank’s
associated oil sands leases was divested to Grizzly Oilsands ULC
126
Petrobank Energy & Resources
1900, 111 – 5th Avenue SW
Calgary, AB, T2P 3Y6
403.750.4400
www.petrobank.com
TSX: PBG
www.petrobank.com
Version 1.

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