Firebag Project Overview

Transcription

FIREBAG PROJECT
COMMERCIAL IN-SITU OIL SANDS PROJECT
APPROVAL NO. 8870
ANNUAL AEUB REVIEW PRESENTATION – APRIL 19, 2006
Presentation Overview

Project Overview
Performance to Date
Compliance
Current Development
Future Development
2
Firebag Project Location
3
Firebag Project Overview

The Firebag Project is Suncor Oil Sands in-situ supply
of bitumen for the Upgrader
The Firebag Project consists of an experimental solvent
injection pilot (ETS) and a commercial Steam Assisted
Gravity Drainage (SAGD) scheme
Includes integrated central plant facilities, wellpads and
gathering corridors
Ultimately, the Firebag Project will supply 360,000+
bbl/day (55,645 m³/day) of bitumen feed
4
Suncor’s Integrated Strategy
Vision
1/2 million barrels per day
5
Original Project Design

SAGD project approved to provide up to 140,000
bbl/day (22,258 m³/day) of bitumen to Oil Sands
Upgrader
Project to be constructed in 4 - 35,000 bbl/day (5,565
m³/day) stages
Design Steam to Oil Ratio 2.0
Water supply from Oil Sands
Firebag connected with Oil Sands plant via 4 pipelines
(water, gas, diluent, DB) and powerline
Firebag is a bitumen supply for Oil Sands Upgrader
6
Firebag SAGD Project Chronology

Application and EIA submitted to EUB/AENV in May 2000
Project received EUB approval 8870 (without public
hearing) in October 2001
Stage 2 approved in January 2003
First steam in September 2003
First oil to Upgrader in January 2004
Stage 3 approved in March 2004
C&E approved in May 2005
Pad 6 approved in May 2005
Pads 7 and 8 approved in March 2006
Revised Stage 3 approval expected in April 2006
7
Firebag Existing Operations
8
Firebag Site Layout
9
Firebag Reservoir Properties

Depth
Pressure
Temperature
Average net pay
Permeability
Porosity
Bitumen saturation
Bitumen viscosity
320 m
800 kPa
8C
35 - 40 m
6 - 10 darcy
32 %
85 %
10 million cp
10
Firebag Net Pay Map
11
Firebag Approved Development Area
12
Volumetric and Reservoir Properties
Area
[m2]
Gross
Thickness
(H)
[m]
Gross
Rock
Volume
(Vr)
[e6 m3]
Net-toGross
Ratio*
Net Pay
Thickness (H)
[m]
Porosity
So
1/Bo
OBIP [e6
m3]
OBIP
[e6 bbl]
SAGD Pad 1
1,582,640
53.2
84.2
0.84
44.5
0.35
0.79
1
19.6
123.30
SAGD Pad 2
1,592,960
52.7
83.9
0.75
39.5
0.35
0.78
1
17.2
108.36
SAGD Pad 3
1,654,720
48.0
79.5
0.81
39.1
0.35
0.80
1
17.9
112.74
SAGD Pad 4
1,548,000
42.4
65.6
0.82
34.8
0.35
0.77
1
14.4
90.31
SAGD Pad 5
2,481,276
40.1
99.4
0.82
32.8
0.35
0.78
1
22.1
138.72
SAGD Pad 6
2,156,963
41.2
88.9
0.77
31.9
0.35
0.78
1
18.8
117.97
SAGD Pad 7
1,561,500
45.5
71.1
0.72
33.0
0.35
0.79
1
14.5
90.95
SAGD Pad 8
1,253,000
53.6
67.1
0.72
38.6
0.35
0.80
1
13.7
86.27
SAGD TOTAL
13,831,059
46.3
639.7
0.78
36.1
0.35
0.79
1
138.1
868.60
Approved
Development
Area
24,902,896
42.9
1,069
0.75
32.4
0.35
0.78
1.00
219.4
1,379.98
Approved
Project Area
194,354,523
36.4
7,072.2
0.68
24.6
0.34
0.78
1
1,278.7
8,043.17
*Net-to-Gross Ratio = Net pay cutoffs applied are GR>60 API, Porosity < 0.22, and Sw > 0.50.
13
Firebag Predicted Recovery
% of
Development
Area Total
Original BIP
Bitumen
Below
Producer
(% of BIP)
Bitumen on &
above Producer
(% of BIP)
Recovery
(% of Total BIP
on & above
Producer)
Recovery
(% of Total
BIP in area)
Development Plan
SAGD Pad 1
8.9%
12.0%
88.0%
91.5%
80.5%
On Production
SAGD Pad 2
7.9%
15.5%
84.5%
90.2%
76.2%
On Production
SAGD Pad 3
8.2%
11.4%
88.6%
90.7%
80.4%
On Production
SAGD Pad 4
6.5%
14.7%
85.3%
88.6%
75.6%
Production Ready
SAGD Pad 5
10.1%
11.8%
88.2%
83.1%
73.3%
Being developed
SAGD Pad 6
8.5%
19.8%
80.2%
85.7%
68.7%
Drilling planned - 2007
SAGD Pad 7
6.6%
15.4%
84.6%
71.8%
67.5%
SAGD Pad 8
6.3%
18.8%
81.2%
60.9%
56.1%
SAGD TOTAL
62.9%
*Net-to-Gross Ratio = Net pay cutoffs applied are GR>60 API, Porosity < 0.22, and Sw > 0.50.
14
Performance – Bitumen Production
Firebag Well Production
120,000
10
110,000
9
100,000
8
90,000
7
60,000
5
50,000
4
SOR (bbl/bbl)
6
70,000
40,000
3
30,000
2
20,000
1
10,000
Actual Daily Well Bitumen Production (bpd)
Actual Daily Steam (bpd)
3/14/06
1/14/06
11/14/05
9/14/05
7/14/05
5/14/05
3/14/05
1/14/05
11/14/04
9/14/04
7/14/04
5/14/04
3/14/04
1/14/04
0
11/14/03
0
9/14/03
Rate (bpd)
80,000
Actual Daily SOR (bbl/bbl)
15
1-Mar-06
1-Jan-06
1-Nov-05
1-Sep-05
1-Jul-05
1-May-05
1-Mar-05
1-Jan-05
1-Nov-04
1-Sep-04
1-Jul-04
1-May-04
1-Mar-04
1-Jan-04
1-Nov-03
1-Sep-03
Water Produced / Steam Injected (%)
Performance - Steam/Water Balance
Water Balance
150%
Ratio of Produced Water to Steam Injected
140%
130%
120%
110%
100%
90%
80%
70%
60%
50%
40%
30%
20%
10%
0%
16
2005/2006 Issues and Milestones
Problems with
steam generators
120,000
110,000
First steam
from Stage 2
Planned
turnaround
100,000
90,000
10
Full field
power
outage
9
8
7
6
First oil from
Stage 2
60,000
5
50,000
4
SOR (bbl/bbl)
70,000
40,000
3
30,000
2
20,000
Warm lime softener
problems, plant downtime
10,000
1
Actual Daily Well Bitumen Production (bpd)
Actual Daily Steam (bpd)
4/1/06
3/1/06
2/1/06
1/1/06
12/1/05
11/1/05
10/1/05
9/1/05
8/1/05
7/1/05
6/1/05
5/1/05
4/1/05
3/1/05
0
2/1/05
0
1/1/05
Rate (bpd)
80,000
Actual Daily SOR (bbl/bbl)
17
Performance – Reservoir Summary

22 out of total 40 well pairs converted to SAGD production mode on Pads 101 – 104:
Pad 101
7 well pairs in SAGD
3 temporarily shut in due to steam availability
1,273,251 m3 of oil produced, Feb 28 2006
6.6% OBIP recovered
Pad 102
649,183 m3 of oil produced, Feb 28 2006
3.8% OBIP recovered
Pad 103 – First Oil November 2005
1 well pair on circulation
67,393 m3 of oil produced, Feb 28 2006
0.4% OBIP recovered
Pad 104 – Steaming not yet commenced.
18
Performance
– Recoveries
to Date
19
Performance – Reservoir Pad 101
Firebag Field
Pad 101 Production
Nov/Dec 2005:
10000
10.00
Pump Installation
April 2005:
Jan-Feb 2006:
Plant Turnaround
9000
9.00
Steam shortage
June 2005:
8000
8.00
caused by
Steam shortage caused
operational issues
by operational issues
7000
7.00
6000
6.00
5000
5.00
4000
4.00
3000
3.00
2000
2.00
1000
1.00
0
0.00
Jan-04 Apr-04 Jul-04 Oct-04 Jan-05 Apr-05 Jul-05 Oct-05 Jan-06 Apr-06
SOR (m3/m3)
Rate (m3/d)
August 2004:
Plant turnaround
1WP3, 1WP4, & 1WP5 shut
in due to steam limitations
Sept 2004:
High SOR - due to reservoir
repressurization
Date
Oil Rate (m3/CD)
Steam Rate (m3/CD)
SOR (m3/m3)
CSOR (m3/m3)
20
1WP1,
1WP2, 1WP6, 1WP7, 1WP8, 1WP9, &
1WP10 wellpairs currently on production
To date these wells are exhibiting similar behavior
At present, production ranges from 200 – 400 m3/d
per wellpair, with an SOR range of 1.5 – 4 m3/m3
A slow production ramp-up and high SORs were
observed after both the 2004 and 2005 turnarounds
Pump installs occurred in Q4 2005 in all wells but
1WP6, which is presently using gas lift
21
Rate (m3/d)
Firebag Pad 101
Individual Well Production Profiles
900
800
700
600
500
400
300
200
100
0
Jan-04
Apr-04
1WP1
Jul-04
1WP2
Oct-04
1WP6
Jan-05
Apr-05
Date 1WP8
1WP7
Jul-05
Oct-05
1WP9
Jan-06
Apr-06
1WP10
22
SOR (m3/m3)
Firebag Pad 101
Individual Well SOR Profiles
20.00
18.00
16.00
14.00
12.00
10.00
8.00
6.00
4.00
2.00
0.00
1WP1
1WP2
1WP6
1WP7
1WP8
1WP9
1WP10
23
Rate (m3/d)
All 10 wells circulated
Jan 2004:
2WP4, 2WP5 1st Prd.
April 2004:
2WP6 1st Prd.
Firebag Field
Pad 102 Production
Sept 2005:
2P3 1st Prd
Oct 2005:
Pump Installations
Nov 2005:
2P8 Started
Jan-Feb 2006:
Steam shortage
10000
10.00
Nov 2004:
9000
9.00
2WP6 1st Prd.
Apr 2005:
8000
8.00
Plant Turnaround
Jun 2005:
Aug 2004:
7000
7.00
Steam shortage
Plant
turnaround
6000
6.00
5000
5.00
4000
4.00
3000
3.00
2000
2.00
1000
1.00
0
0.00
SOR (m3/m3)
Date
Oil Rate (m3/CD)
Steam Rate (m3/CD)
SOR (m3/m3)
CSOR (m3/m3)
24

2WP1, 2WP2, 2WP3, 2WP4, 2WP5, 2WP6, 2WP7, & 2WP8 wellpairs are
currently on production
For the wells on production in 2004 (2WP4, 2WP5, 2WP6, & 2WP7), current
production ranges from 150 – 350 m3/d per wellpair, with an SOR range of 2-4
m3/m3
2WP1 has a lower production rate than the other wells. Explanations for this
include:
A pump was installed in 2WP1 after the steam circulation period, and has
had 2 pump changes since its start-up in Dec 2004
2WP1 is on the edge of the pattern
The toe of the well is shalier than the average reservoir on Pad 102
2WP2, 2WP3, & 2WP8 started production in Aug, Sept, & Nov 2005
respectively are on trend with the first 4 wells
A slow production ramp-up and high SORs were observed after both the 2004
and 2005 turnarounds
Pump installs occurred in Q4 2005 in all wells but 2WP3 and 2WP8
25
Rate (m3/d)
Firebag Pad 102
500
450
400
350
300
250
200
150
100
50
0
2W P1
2W P2
2W P3
2W P4
2W P5
2W P6
2W P7
2W P8
26
Firebag Pad 102
14.00
SOR (m3/m3)
12.00
10.00
8.00
6.00
4.00
2.00
0.00
Jun-03
2WP1
Jan-04
2WP2
2WP3
Aug-04
2WP4
Feb-05
2WP5
2WP6
Sep-05
2WP7
Mar-06
2WP8
27
Jan-Feb 2006:
10000
20.00
Steam shortage
3WP4, 3WP7,
Aug 2005:
Nov 2005:
9000
18.00
3WP8, 3WP10
1st Steam
3WP6 1st Prd
8000
16.00
Shut-in as a result
Dec 2005:
3WP4, 3WP5, 3WP6, 3WP7,
7000
14.00
3WP8, & 3WP10 1st Prd
6000
12.00
5000
10.00
4000
8.00
3000
6.00
2000
4.00
1000
2.00
0
0.00
Jul-05 Aug-05 Sep-05 Oct-05 Nov-05 Dec-05 Jan-06 Feb-06 Mar-06
SOR (m3/m3)
Rate (m3/d)
Firebag Field
Pad 103 Production
Date
Oil Rate (m3/CD)
Steam Rate (m3/CD)
SOR (m3/m3)
CSOR (m3/m3)
28
3WP4,
3WP5, 3WP6, 3WP7, 3WP8, & 3WP10
began producing in Q4 2005
3WP9 is presently on steam circulation – production
delay was the result of surface facility issues
3WP4, 3WP7, 3WP8, & 3WP10 were shut-in in Jan
& Feb 2006 in response to steam shortages
resulting from facility upsets, these wells have been
returned to production
29
Firebag Pad 103
400
Rate (m3/d)
350
300
250
200
150
100
50
0
Sep-05
Oct-05
3WP4
3WP5
Dec-05
3WP6
3WP7
Jan-06
3WP8
3WP9
Mar-06
3WP10
30
SOR (m3/m3)
Firebag Pad 103
14.00
12.00
10.00
8.00
6.00
4.00
2.00
0.00
Sep-05
Oct-05
Dec-05
Jan-06
Mar-06
Date
3WP4
3WP5
3WP6
3WP7
3WP8
3WP10
31
Performance – Observation Wells

There are 3 active temperature observation wells OB3,
OB4, OB5 located alongside the heel, mid and toe of
wellpair 1WP6
Steam Temperature was observed at these wells in:

OB3
OB4
OB5
January 2005
May 2004
Mar 2006
32
Observation Wells 3,4 and 5
P1P6
Observation
Wells 3, 4
and 5
OB 3
OB 4
OB 5
33
Temperature in OB3 Observation Well
0
20
40
60
80
100
Temperature, C
5m from 1WP6
120
140
160
180
200
220
240
260
270
Injector Depth: 314.5m
(from down-hole trajectories)
Producer Depth: 321.5m
TVD: 321m
P1P6 MD: 592.6m
Measured Fiber Length, m
280
Note: Well depths shown on plot have approximately a ±2m error.
290
300
Injector
Producer
310
1-Jan-04
15-May-04
10-Jan-05
5-May-05
5-Jan-06
27-Mar-06
34
0
20
40
60
80
100
Temperature, C
12m from 1WP6
120
140
160
180
200
220
240
260
1440
Injector Depth: 315.5m
Producer Depth: 321m
TVD: 322m
P1P6 MD: 1146.5m
1450
Note: Well depths shown on plot have approximately a
±2m error.
1460
1470
Injector
Producer
1480
1490
1-Jan-04
15-May-04
10-Jan-05
5-May-05
5-Jan-06
27-Mar-06
35
Temperature, C
7m from 1WP6
0
20
40
60
80
100
120
140
160
180
200
220
240
260
2400
Injector Depth: 315m
Producer Depth: 321m
TVD: 321m
P1P6 MD: 1435.0m
2410
2420
Injector
2430
Producer
2440
Note: Well depths shown on plot have approximately a
±2m error.
2450
1-Jan-04
15-May-04
10-Jan-05
5-May-05
5-Jan-06
27-Mar-06
36
Interwell
Communication

Signs of
communication
were seen
between P2P1 and
P2P2 (the two
most north western
wells on the figure
to the right)
through the last
half of 2005
2P1
2P2
37
Interwell Communication –
Injection/Production Data for P2P2 and P2P1
Steam (m3/d)
Water (m3/d)
P2P2 was converted to
mechanical lift, water
returns became more
balanced in both well
pairs
Oil (m3/d)
1400
P2P1 Rate (m3/d)
1200
1000
800
Steam injection and
water production
balanced (P2P1 on
mechanical lift)
600
400
200
0
10/1/2004
12/1/2004
2/1/2005
4/1/2005
6/1/2005
8/1/2005
10/1/2005
12/1/2005
2/1/2006
4/1/2006
8/1/2005
10/1/2005
12/1/2005
2/1/2006
4/1/2006
38
1400
P2P2 Rate (m3/d)
1200
1000
800
600
400
Almost immediately, water production out
of P2P1 increased (well above the steam
injection rate), steam injectivity fell off, and
oil rate remained relatively constant
High rate steam injection began
on P2P2 (P2P2 on natural lift)
200
0
10/1/2004
12/1/2004
2/1/2005
4/1/2005
6/1/2005
Note: Daily testing does not match exactly with monthly reporting numbers
ES-SAGD Testing

y
ES-SAGD is being implemented on a limited basis initially.
Diluent co-injection with steam began on Nov 16, 2005 into all of the
wells on Pad 102.
Diluent injection volumes are metered prior to mixing with steam, the
diluent production is calculated from bitumen and gas samples taken
from the wells from the test separator, where possible taken on a monthly
basis.
As expected this early in the test, there has not yet been observable
changes to the bitumen production rates or SOR of these wells when
compared to the wells on Pad 101
There has been some indication of produced diluent in the gas samples.
Solvent injection is continuing on Pad 102, and plans are in place to
expand solvent injection to additional pads pending the results of this
project.
Solvent targets as follows:
y 2% of the steam volume into 2P1, 2P2, 2P3, 2P4, 2P5, 2P7, and 2P8
y 15% to 2P6
39
Lean Zones

In the Firebag reservoir, lean zones exist to the east of
the developed area
There are no significant lean zones in the active areas
of the reservoir
The initial water loss is believed to be the result of
water mobility in high bitumen (>85%) saturation zones
40
Steam – Oil Ratio (SOR)

As of Feb 2006, the cumulative SOR at Firebag is
3.99 m3/m3
Cumulative SOR was 4.60 m3/m3 in Feb 2005
The higher than expected SOR is largely the result of:
Circulating
new wells that were not immediately produced
Starting new wells to support the Stage 2 central plant.
High steam injection rates required to restart the wells
after prolonged shut downs in August 2004, April and
June 2005
41
SOR Discussion

Estimated impacts of these events on the CSOR are:
Firebag CSOR Feb 2006: 3.99 m3/m3
Less:
Additional circulation
0.38 m3/m3
Stage 2 start-up
0.24 m3/m3
Recovery from shut downs 0.13 m3/m3
Estimated CSOR
3.24 m3/m3
When looking at the production and the SOR on a time
normalized basis for these wells the production is trending
towards 360m3/d (2,300bbls/d) and the SOR towards 2.2m3/m3 at
23 months.
This is above expected performance in terms of rate and on trend
with the expected SOR delivery.
42
Firebag Phase 1 SOR History, Time Normalized
10
9
8
7
SOR
6
5
4
3
2
1
0
0
1
2
3
4
5
6
7
8
9
10 11
12 13 14
15
Production Time (months)
16
17
18
19
20
21
P1P1
P1P2
P1P6
P1P7
P1P8
P1P9
P1P10
P2P1
P2P4
P2P5
P2P6
P2P7
Fitted Trendline
22
23
43
24
Firebag Phase 1 Production History, Time Normalized
6000
5000
Oil Rate (bpd)
4000
3000
2000
1000
0
0
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
Production Time (months)
P1P1
P1P9
P2P6
P1P2
P1P10
P2P7
P1P6
P2P1
Fitted Trendline
P1P7
P2P4
P1P8
P2P5
44
Low - Pressure SAGD (LP-SAGD) Pilot

Suncor has completed testing the use of low pressure
steam injection and artificial lift systems in the SAGD
wells
Primary LP-SAGD Pilot Objectives:
Quantify the SOR reduction potential of LP-SAGD;
and,
Evaluate artificial lift techniques including a multiphase pump and gas lift.
12 wells on mechanical lift (i.e. pumps)
1 well on gas lift
45
LP-SAGD Pilot Project Results
Mechanical Lift:
stabilizes well production, and minimizes the production impacts of
plant upsets
reliable pump operations
allows operation at reservoir operating pressures below those possible
with gas lift
higher water returns at lower operating pressures
Initial indications are that the operation at lower pressures using
mechanical lift results in a lower SOR and a slight reduced bitumen
production rate, there is still insufficient data to fully quantify these
effects
Gas Lift:
stabilizes well production
allows operation at reduced reservoir operating pressures over
natural, but does not provide lift at very low operating pressures
46
LP-SAGD Installations

Mechanical lift installed in wells as follows:

P1P1
P1P2
P1P7
P1P8
P1P9
P1P10
P2P1
P2P2
P2P4
P2P5
P2P6
P2P7
December 9, 2005
November 16, 2005
December 14, 2005
November 20, 2005
November 9, 2005
November 24, 2005
January 29, 2005
January 23, 2006
October 20, 2005
October 15, 2005
October 12, 2005
October 18, 2005
47
Lessons Learned

Individual wells producing oil at higher than expected
rates when steam is available
High operating pressure decreases water returns –
the wells on pump have shown water returns of
greater than 100%
H2S production is higher than expected – remains
under investigation
LP-SAGD is effective at stabilizing well operation and
improving water returns
48
Heave Monitoring

Monitoring surveys conducted in March 2003,
February 2004, February 2005 and March 2006
Surveys done using GPS real-time technology and
object monuments
44 object monuments installed
Majority of monuments above Pad 101 and 102 wells
4 object monuments showed some movement within
the accuracy of the measurement technique
No conclusions drawn at this time
49
Water Recycle
Mar-06
Feb-06
Jan-06
Dec-05
Nov-05
Oct-05
Sep-05
Aug-05
Jul-05
20
Jun-05
May-05
Apr-05
Mar-05
Feb-05
Jan-05
Dec-04
Nov-04
Oct-04
Sep-04
Aug-04
Jul-04
Jun-04
May-04
Apr-04
Mar-04
Feb-04
Jan-04
Dec-03
Nov-03
Oct-03
Sep-03
Recycle Rate (%)
Water Recycle Rate - To Date
140
PRELIMINARY
120
100
80
60
40
EUB Recycle Rate Formula:
RR% = SI – (FW In – Other Uses) x 100%
PW
0
90% Target
50
Water Recycle Rate - 2006
100
95
90
85
80
75
EUB Recycle Rate Formula:
70
RR% = SI – (FW In – Other Uses) x 100%
PW
65
PRELIMINARY
Water Recycle
16-Apr
9-Apr
2-Apr
26-Mar
19-Mar
12-Mar
5-Mar
26-Feb
19-Feb
12-Feb
5-Feb
29-Jan
22-Jan
15-Jan
8-Jan
1-Jan
60
90% Target
51
Firebag Produced Gas

Sulphur content of produced gas has ranged from 02.41 t/day
Exceeded 1 te/day inlet sulphur quarterly-average for
Q1, Q3 and Q4 2005
Produced gas tied into fuel gas system to allow
combustion in OTSGs
52
1-Mar-06
1-Feb-06
1-Jan-06
1-Dec-05
1-Nov-05
1-Oct-05
1-Sep-05
1-Aug-05
1-Jul-05
1-Jun-05
1-May-05
1-Apr-05
1-Mar-05
1-Feb-05
1-Jan-05
1-Dec-04
1-Nov-04
1-Oct-04
1-Sep-04
1-Aug-04
1-Jul-04
1-Jun-04
1-May-04
1-Apr-04
1-Mar-04
1-Feb-04
1-Jan-04
Sulphur Rate (Tonnes/day)
Sulphur Production Profile
2.5
2.0
1.5
1.0
0.5
0.0
53
Local Area Off-Set

EUB Approval for local area off-set in place allowing
Firebag inlet sulphur to be off-set by excess recovery
at Oil Sands Base Plant
Suncor has committed to:
Have
sulphur recovery fully commissioned and
operational at Firebag by the end of 2008 or before
production to Stage 3 facilities.
Submit progress reports on sulphur recovery unit in June
2006 and June 2007.
Monitor and report on inlet sulphur volumes, gas
compositions and recoveries at Firebag and the Oil
Sands Base Plant
54
Firebag Compliance Issues

The Firebag SAGD Project has been operating within
the terms and conditions of Approval No. 8870 with the
exception of:
Inlet sulphur exceeded 1 te/day in Q1, Q3 and Q4
2005 – Local area off-set now in place
Other compliance issues:
Facility Licence obtained for Stage 1-3 facilities and
Pads 1-8
55
Current Development
Co-gen and Expansion Project (C&E)

Stages 1/2 water and oil treating facilities are being
expanded for production of 25,000 bbl/day (3,975
m³/day) bitumen
85 MW co-generation plant included to produce
electricity and steam for use at Firebag
Co-gen construction commenced in August 2005
Commissioning planned for early 2007
57
Revised Stage 3

Suncor has elected to increase Stage 3 production to
62,500 BPCD (9,930 m3/day) (previously 52,500
BPCD – 8,350 m3/day)
Revised Stage 3 project includes majority of plantsite
and equipment from previous Stage 3 Update
Application plus additional footprint area, equipment,
production and emissions
Approval expected in late April 2006
58
Stage 3 Utilities

Stage 3 includes additional electrical infrastructure:
2 – 85 MW co-generation units
260 kV transmission line
260 kV substation
Power and steam to be used at Firebag
EUB Utilities Application submitted in August 2005
Approval expected in May 2006
59
Utility Corridor

Currently includes:
144 kV Transmission Line
Diluent, Make-up water, Dilbit and Natural Gas
Pipelines
Suncor installing 3 new pipelines in the utility corridor
between OS and FB:
Make-up water
Rich Fuel Gas (RFG)
Hot Bitumen
260 kV Transmission line
60
Future Development
Future Artificial Lift Installations

Current well design makes mechanical lift best option
for Pad 101-104 wells
3 additional pump installations are scheduled for June
2006
Pad 103 & 104 wells will start on natural lift to allow
production ramp up, and then convert to artificial lift
Gas lift will continue to be evaluated at 3WP9 on Pad
103
Still evaluating lift options for Pad 105+
Re-design of wells for new pads may allow for use of
other lift options
62
Stages 4-6 Development

Firebag will be a key bitumen supply for Suncor’s
Voyageur project
Stages 4-6 planning is currently underway
Suncor expects to submit an application for Stages 4-6
in May 2006
Constructed on same plantsite as Stage 3 and
integrated with Stage 3
Additional electrical generation in Stages 5 and 6
Ultimately, Firebag will produce 368,000+ bbl/day
(58,500 m³/day) of bitumen for the Oil Sands Upgrader
63
Firebag Regulatory Schedule
Q1
2006
Q2 Q3
Q4
Q1
2007
Q2 Q3
Q4
Q1
2008
Q2 Q3
Q4
Q1
2009
Q2 Q3
Q4
Revised Stage 3
Stage 3 Utilities
Stages 4-6
Hot Bitumen Pipeline
Sulphur Recovery Unit
Regulatory Process
Construction
Operation
64

Firebag Project Overview

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