Connacher Oil and Gas Limited

Transcription

Great Divide Oil Sands Project
(10587)
EUB Annual Performance
Presentation
Nov 2008
1
This presentation contains forward looking information including estimations of reserves and resources and
future net revenue associated therewith, expectations of future production, planned capital expenditures,
integrated netbacks per barrel of bitumen, development of additional oil sands resources (including receipt of
regulatory approvals in respect of Algar and timeline for construction of Algar) and expansion of current
conventional oil and gas and refining operations. Forward looking information is based on management’s
expectations regarding future growth, results of operation, production, future capital and other expenditures
(including the amount, nature and sources of funding thereof), plans for and results of drilling activity,
environmental matters, business prospects and opportunities involves significant known and unknown risks
and uncertainties, which could cause actual results to differ materially from those anticipated. These risks
include, but are not limited to: the risks associated with the oil and gas industry (e.g., operational risks in
development, exploration and production; delays or changes in plans with respect to exploration or
development projects or capital expenditures; the uncertainty of reserve and resource estimates; the
uncertainty of estimates and projections relating to production, costs and expenses, and health, safety and
environmental risks), and the risk of commodity price and foreign exchange rate fluctuations, and risks and
uncertainties associated with securing the necessary regulatory approvals and financing to proceed with the
continued expansion of the Great Divide Project at Algar and other regions and expansion of the company’s
refinery in Great Falls, Montana. These risks and uncertainties are described in detail in Connacher’s Annual
Information Form for the year ended December 31, 2007, which is available at www.sedar.com. The
Corporation assumes no obligation to update or revise the forward-looking information to reflect new events
or circumstances, except as required by law. All references to barrels of oil equivalent (boe) are calculated on
the basis of 6 mcf : 1 bbl. This conversion ratio is based on an energy equivalency conversion method
primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Boes may be
misleading, particularly if used in isolation.
Great Divide ERCB Presentation Nov 2008
2
Contents
• Introduction
• Project Status
• Project Reserves
• Geology
• Production/Injection
• Development Plans
• Facilities
• EH&S
Water
Emissions
Other
3
Connacher Oil & Gas
100% working interest in the Great Divide oil sands
SAGD projects and related properties
• 843 million barrels of 3P reserves and high estimate
contingent plus prospective resources (as at 30/06/08
per GLJ Petroleum Consultants) (1)
• Pre-tax PV10% of $4.1 billion (1)
• Great Divide On-stream, Algar Completion 2009
• Each project is a 10,000 bbl/d SAGD project
9,500 bbl/d heavy crude oil
refinery in Great Falls, Montana
Note:
(1) See Last Slide for Reserve
Definitions
Conventional Properties.
~14 mmcf/d natural gas
and ~ 1,000 bbl/d Oil
4
Development History 2004 - 2008
• March 2004 - Started field
evaluation and delineation
From Wightman and Pemberton CSPG
Memoir 18, 1997
• 80 km south of Fort McMurray on
highway 63
Total Joslyn
Suncor
Firebag
PetroCan Dover
PetroCan
Mackay River
Fort McMurray
• August 2005 - Great Divide
application to ERCB
• July 2006 - Great Divide ERCB
approval
• October 2006 – First pile driven at
plant
• September 2007 – First steam into
15 well Pairs
JACOS
Hangingstone
63
TP 82 RG 11W4
Algar
MEG
Christina
Encana
Christina Lake
Devon
Jackfish
• December 2007 – Start conversion
to full time production
TP 82 RG 12W4
• September 2008 – First annual
plant turnaround & re-drill of one
producing horizontal well
Encana
Foster Creek
Expansion Area
30-60m McMurray Formation
>60m McMurray Formation
Great Divide Project Area
6 miles
CONNACHER’S OIL SAND LEASES
Great Divide
Conoco /Philips
Surmont
Connacher
Great Divide
• October 2007 – First bitumen sales
• November 2008 Algar (second
10,000 bopd project) approved
Nexen-OPTI
Long Lake
Great
Divide
Algar Project Area
Bitumen pods
5
2
Great Divide Area - Current Approvals
Great Divide Project
Approval 10587
10 - 15m
Algar Project
Approval 11253
32
33
34
35
36
31
32
33
29
28
27
26
25
30
29
28
15 - 20m
20 - 25m
25 - 30m
> 30m
Approved
Development
20
T 82
21
22
23
24
19
20
21
17
16
15
14
13
18
17
16
8
9
10
11
12
7
8
9
R 12
R 11
6
Great Divide Area - Current Development
Great Divide Project Approval 10587
32
33
34
29
28
27
21
22
17
16
15
8
9
10
Bitumen
Net Pay
10 - 15m
15 - 20m
20 - 25m
63
25 - 30m
> 30m
North
15 Well Pairs
3 Pads
20
West
South
7
OBIP & Reserves
Reserve Volumes Great Divide Approval Area
Reported by GLJ Petroleum Consultants, June 2008
Area (ha)
OOIP (e3m3)
Recovery
Factor
Ultimate
Reserves
(e3m3)
Net Pay > 15
613
32,436
42.1%
13,656
Net Pay < 15
336
11,716
34.2%
4,005
Total
949
44,152
40.0%
17,661
Proved Reserves (1)
Proved Plus Probable Reserves (1)
Net Pay > 15
629
33,133
54.3%
17,991
Net Pay < 15
501
16,650
44.4%
7,398
Total
1,130
49,782
51.0%
25,389
Net Pay > 15
629
33,133
62.4%
20,675
Net Pay < 15
501
17,103
52.4%
8,964
Total
1,130
50,235
59.0%
29,639
Average Porosity
33%
Average Sw%
15%
Average FVF
1.001
3P Reserves (1)
Compared to
17,000 e3m3
2P reserves reported
in the Great Divide
application
(1) See slide 61 for
reserve definitions
8
Geology
Geology
9
Geology Overview
100/05-21-082-12W4/00
686.8
1996/03/19
472.2
Oilsands_Bottom
D&C
DEV
GDOC DIVIDE 5-21-82-12
Type Well
NPHI (%)
60.00
GR (GAPI)
ILD (OHMM)
150.00
0.20
0.00
DPHI (%)
2000.00
60.00
SP (MV)
0.00 -75.00
75.00
100
0.00
Bedrock
200
Base Fish Scales
Viking
Joli Fou
Grand Rapids
300
Lower Grand
Rapids
Clearwater
400
Wabiskaw
McMurray
Oil Sands Top
McMurray c_ch
Palaeozoic
GR (GAPI)
0.00
ILD (OHMM)
150.00
0.20
DPHI (%)
2000.00
60.00
SP (MV)
0.00 -75.00
75.00
NPHI (%)
60.00
0.00
10
Delineation - 3D Seismic & Cores
Reservoir Defined by 3D Seismic,
Cores and Geophyscial logs
Cored Wells
3D Seismic
Bitumen
Net Pay
10 - 15m
15 - 20m
20 - 25m
25 - 30m
> 30m
11
Geology - Core vs Log Data
Typical Composite Log with Interpretation
Log vs Core Comparison
Analytical interpretation of geophysical logs
to determine bitumen saturations (wt%)
gives good correlation with core derived
bitumen wt%. Examples shown below.
12
McMurray Oil Sands Facies and Pay
Zones
Defined by Vshale
Z1
Z2
Z3
Z4
Z5
Z6
Connacher Cut-Offs
Z1 (Sand): 0-10% fines
Z2 (Sandy IHS): 10-20% fines
Z3 (IHS): 20-50% fines
Z4 (Muddy IHS): 50-80% fines
Z5 (Mud): 80-100% fines
Z6 (Breccia): >10% clasts
Pay Base Criteria
Minimum bitumen grade: 6 wt%
Minimum Net/Gross ratio: 80 %
Maximum included shale interval: 2m
Minimum zone thickness: 8 m
Clearwater
Wabiskaw
Devonian
Core displayed is from a number of separate wells
13
Geology – X Section
A
A’
100/16-17-082-12W4/00
102/05-21-082-12W4/00
699.4
2005/03/18
489.9
Dwoodbend
D&C
DSW
CONNACHER DIVIDE 16-17-82-12
A
GR (API)
0.00
697.9
2001/01/31
479.0
Dbvrhl_lk
AZN
DEV
<=751.8m=>
ILD (OHMM)
150.00
0.20
100/06-21-082-12W4/00
GR (GAPI)
2000.00
0.00
700.4
2007/03/05
510.0
Paleozoic
LCT
OV
CONNACHER DIVIDE 6-21-82-12
<=293.6m=>
ILD (OHMM)
150.00
0.20
100/15-21-082-12W4/00
GR (gAPI)
2000.00
687.3
2005/03/11
474.6
Paleozoic
D&A
DSW
<=971.5m=>
M2R9 (ohm.m)
0.00
150.00
0.20
GR (API)
2000.00
0.00
A'
ILD (OHMM)
150.00
0.20
2000.00
Kwabiskaw_Mrkr
Kwabiskaw_Mrkr
Kwabiskaw_Mrkr
Kwabiskaw_Mrkr
Kmcmurray
Kmcmurray
Kmcmurray
275
275
Oilsands_top
Oilsands_top
Paleozoic
Paleozoic
Oil32Sands Top
33
34
250
250
275
Oilsands_top
250
250
275
Kmcmurray
Paleozoic
225
Paleozoic
225
225
225
Oilsands_top
1:480
29
28
ELV 218.9m
GR (API)
0.00
ILD (OHMM)
150.00
0.20
GR (GAPI)
2000.00
0.00
ILD (OHMM)
150.00
0.20
GR (gAPI)
2000.00
150.00
0.20
A’
20
X SECTION
21.0
20
GR (API)
2000.00
A'
A
21
0.00
A’
21
13.6
A
19.5
T82
30 5
2 0
2 5
1 0
1
Licensed to : Connacher Oil and Gas Ltd
Date : 2008/12/03
By : Tim Lau
Datum : Sea Level
Scale = 1:480
Interval : From Kwabiskaw_Mrkr to Paleozoic
22
3.6 m
16
7.0
A
R12W4
17
2000.00
5.2 m
1 : 33798
0.20
Great Divide Pod1
McMurray
Structure Cross Section SW-NE
22
17.4
18.7
A
ILD (OHMM)
150.00
Connacher Oil and Gas Ltd
A’
2.5 m
17
27
M2R9 (ohm.m)
0.00
15
25
25
16
15
14
Top of Oil Structure for Great Divide Project Area
T83
254.3 m
251.2 m
262.7 m
32
240.5 m
33
265
247.6 m
248.5 m
31
.0
259.8 m
242.9 m
34
35
--- m
260.4 m
245.4 m
256.9 m
260.0
258.7 m
256.8 m
248.8 m
230
30
29
--- m
5.0
23
252.8 m
252.9 m
.0
231.6 m
26
0.0
241.1 m
230.2 m
27
28
248.9 m
236.3 m
250.1 m
257.5 m
255.0
236.9 m
241.3 m
250.0
235.0
238.0 m
21
249.8 m
25
0.0
244.6 m
22
245.0
.0
240
24
5.0
20
T 82
260.0 m
.0
19
256.0 m
257.8 m
240
231.9 m
260.2 m
256.3 m
238.5 m
25 256.8 m
0.
0
243.7 m
26
240
.0
251.3 m
240.3 m
0.0
24
259.1 m
264.4 m 258.3 m
260
.0
258.4 m
259.2 m
255.8 m
23
232.5 m
T82
229.9 m
265.7 m
248.8 m
259.7 m
255.4 m
248.4 m
234.2 m
NLA m
.0
240
244.6 m
254.4 m
240.7 m
246.9 m
.0
245
245.0
247.1 m
5.2 m
243.1 m
248.3 m
239.7 m
3.6 m
15
250.4 m
258.2 m
255.9 m
14
260
242.9 m
.0
1.0 m
253.3
m
251.8 m 261.4 m
255.0
24
0.0
228.9 m
241.5 m
1.0 m
243.9
m
244.1 m
5.0 m
233.8
m
237.2 m
234.9 m
9
8
10
243.9 m
249.3 m
1.5 m
251.0 m
256.0 m
11
253.2 m
--- m
26
0.0
7
260.7 m
249.3 m
248.3 m
254.6 m
246.1 m
247.3 m
262.3 m
265.0
261.8 m
249.8 m
244.3 m
2.5 m
263.7
m
16
240.7 m
26
0.0
245.5 m
17
250.0
18
261.6 m
24
0
0.
241.3 m
259.7 m
243.5 m
260.0 m
R 12R12W4
W4
250
.0
245.0
15
Associated Gas
T83
32
33
34
35
63
29
28
27
26
T 82
20
2.3
21
22
23
2.5
T82
2.0
2.2
2.2
2.0
5.2 m
2.5
2.8
17
6.8
11.6
2.5 m
3.6 m
16
15
14
4.0
7.4
3.8
1.1
8.0
5.0
1.9 m
2.8 m
5.5
2.5
1.0 m
1.5
1.0 m
5.0 m
9
8
10
6.6
11
6.5
1.5 m
R 12 W4
16
Geo-statistical Model
•
3-D Geo-statistical model (Petrel) created for Project
Development Area
•
Inputs: 3D Seismic, Logs and Core
•
Paleo base is adequately defined and model is used to
place horizontal wells
•
Slides 18 - 22 show Great Divide model output for:
-
paleo mapping & well placement(18)
oil saturation (19 & 20)
facies descriptions (21 & 22)
17
Geology – Paleo Structure
226 Paleo Elevations
32
33
34
29
28
27
20
21
22
17
16
15
8
9
10
18
Oil Saturation E- W
Oil Saturation
32
33
34
29
28
27
20
21
22
17
16
15
8
9
10
19
Oil Saturation E- W
32
33
34
29
28
27
20
21
22
17
16
15
8
9
10
20
Geology Facies X Section E – W
32
33
29
28
20
21
17
16
1
8
9
1
21
Geology Facies X Section N – S
32
33
34
29
28
27
20
21
22
17
16
15
8
9
10
22
Production / Injection
Recovery Process
Production & Injection
Performance
23
Recovery Process
STEAM ASSISTED GRAVITY DRAINAGE (SAGD)
Process information
Steam Injected
~260 Dec C, 98% Quality
Steam injection Well
Producing Well
Lift - Gas Lift (one ESP pump
installed)
Steam Chamber
Steam Rises, gives up heat
Hot bitumen drops down
Hot bitumen produced from lower well
24
Circulation Phase
During the pre-heat or circulation phase, both the upper
horizontal injector wells and the lower horizontal producer
wells have steam injected through tubing into the “toe” of the
well. Steam is circulated back to the “heel” of the well and
returned through tubing to surface. The reservoir is exposed
to the steam along the horizontal liner but steam is not
injected directly into the formation. Temperatures along the
well-bores are monitored for thermal consistency. Even
heating at temperatures of approximately 260 degrees
Celsius is the objective of this process.
HORIZONTAL INJECTOR
Long String
Short String
Steam Circulation
Heel
Toe
HORIZONTAL PRODUCER
Long String
Short String
Steam Circulation
Heel
Toe
Due to the unique placement of the Great Divide reservoir,
directly on the flat Devonian carbonate basement,
Connacher was able to utilize an innovative process during
the circulation phase. Pressure in the horizontal producing
wells was maintained at a slightly higher level than in the
injection wells. This ensured that no hot spots or “short
circuits” were developed from the injector well to the
producer well, as such an occurrence would ultimately result
in poorer recoveries. Connacher was able to use this
technique, since there was no risk of heat losses to water or
thief zones below the producer, as they do not exist in the
Great Divide reservoir.
This phase is normally scheduled for approximately 90 days.
25
SAGD Phase with Steam Boost
Horizontal Injector
Long String
Injecting steam
into reservoir
Short String
Horizontal Producer
Bitumen Production
Steam Boost
During this phase, the upper injection well
commences steam injection into the reservoir as
it has been pre-heated and will accept steam
injection with minimal pressure increase. Both
the short tubing string at the heel and the long
tubing string near the toe of the well are
continuously injecting steam into the reservoir.
In the lower producing well, the steam circulation
is stopped except for a small amount of steam
injected out the long string (“boost”). Bitumen is
produced up the short string at the heel. This
steam boost keeps the toe of the producer well
warm enough during the initial stages of SAGD
production. This allows the bitumen produced in
the toe area to flow to the heel. This phase is
transitional and may last as little as two days or
as long as one month.
26
Optimized SAGD Producer
Steam Chamber
HORIZONTAL INJECTOR
Long String
During this phase, the injection well
continues as before, but in the producing
well the “boost” steam out the long string
tubing is shut off. This tubing string can
now also produce bitumen in conjunction
with the short string. The optimization of
the production from each string in the
producing horizontal well is essential.
Short String
HORIZONTAL PRODUCER
Bitumen Production
Long String
Short String
Bitumen
Flows to
Surface
27
Injector & Producer Well Completions
T
•
Pressure measurements made by using
annulus as bubble tube (see XL
appendix )
•
All production wells equipped with Gas Lift
(ESP pump installed in
(104/16-17-082-12W4/00 P8S)
•
Thermocouples used to maintain optimum
sub-cool
T
T
T
T
Three to five thermocouples placed at approximately equal distance along length
28
6-21-082-12W4 Observation Well



North
Pad
21
West






 
 


South









Purpose of this observation well was to measure rise of steam
and to determine if steam moved into any overlying gas caps.
The instruments have not performed as expected:
Pres 1 is not communicating
Pres 2 is not communicating
Pres 3 is reading a pressure of approximately 1480 kPa








Temp 4 and Temp 2 are not working.















29
Production & Injection
First Steam:
First Sales Oil:
September 2007
October 2007
As of September 30th, 2008
Cumulative Bitumen Production m3:
Cumulative Steam Injection m3:
235,267
1,007,756
Cumulative SOR:
4.3
Number of Producing Well Pairs:
14
Number of Circulating Well Pairs:
1
Operating Pressure:
4300 kpa
Max Injection Pressure:
6300 kpa
Average depth
475 m
Net pay
20 m
Fracture Gradient
17 Kpa/m
(Source SPE CIM paper 79208 patrick collins 2002)
30
Performance - Injection & Production by Pad
Plant 5 day Shut Down
4000
Steam Injection
North
Pad
Steam Injection m3/cd
3500
3000
2500
South
West
North
Total Steam
2000
1500
1000
21
West
500
0
1200
South
Oil Production m3/cd
Oil Production
1000
800
South
West
North
Total Oil
600
400
200
0
3000
South
West
North
Total Water
2000
1000
Ju
l-0
8
A
ug
-0
8
Se
p08
Ju
n08
M
ay
-0
8
08
08
A
pr
-
M
ar
-
Fe
b08
Ja
n08
0
O
ct
-0
7
N
ov
-0
7
D
ec
-0
7
14 well pairs Producing.
One well re-drilled out of 30. Production ramp up better than expected. Production climbing and SOR’s dropping as wells mature.
Plant turnaround in Sept 2008
Produced Water
4000
Se
p07
•
•
•
•
•
Produced Water m3/cd
5000
31
Performance - SOR & Production by Pad
8.0
Cum Steam / Oil Ratio
Steam / Oil Ratio
7.0
North
Pad
South
West
North
Cum SOR All Pads
6.0
5.0
4.0
3.0
21
West
2.0
250,000
Oil Production m3
South
Cum Produced Water m3
Cum Oil Production
200,000
1,000,000
South
West
North
Cum Oil All Pads
150,000
100,000
50,000
0
South
West
North
Cum Prd Water All Pads
600,000
400,000
200,000
08
pSe
-0
8
ug
A
l-0
8
Ju
n08
Ju
-0
8
ay
M
-0
8
pr
A
-0
8
ar
M
08
07
b08
Fe
Ja
n-
ec
-
7
D
7
ov
-0
N
ct
-0
Se
p-
07
0
O
Detailed Production data in
appendix XL
Cum Produced Water
800,000
32
Performance - Pad Recovery & Production
12%
% Recovery BIP
% Recovery BIP
10%
North
Pad
21
West
South
West
North
Recovery % All Pads
8%
6%
4%
2%
0%
250,000
225,000
South
Cum Oil Production
South
West
North
Cum Oil All Pads
Oil Production m3
200,000
175,000
150,000
125,000
100,000
75,000
50,000
25,000
p08
Se
g08
Au
8
l-0
8
Ju
n0
Ju
-0
8
ay
M
8
pr
-0
8
A
8
ar
-0
M
b0
Fe
n08
Ja
-0
7
ec
D
v07
No
ct
-0
7
O
Se
p07
0
33
Performance - % Recovery Bitumen in Place
Great Divide Bitumen Drainage Area (Pads) Volumes & Estimated Recoveries
Developed
Pads OBIP
e3m3
(2)
Developable
OBIP e3m3
(3)
Estimated
recoverable
volumes
20.4
2,300
1,587
1,254
5.8%
85%
18.7
1,784
1,231
973
9.4%
33%
85%
19.5
1,908
1,317
1,040
6.9%
33%
85%
19.5
5,993
4,135
3,267
7.2%
Pad
(1)
Area
ha
Average
Porosity
%
Average Oil
Average
Saturation Hydrocarbon
%
Thickness %
North
40
33%
85%
West
34
33%
South
35
109
%
Recovery
Sept 30
2008
Notes
(1)
Drainage area extends 50m beyond wells in all directions
(2)
Estimated Losses within the SAGD Interval
Heel
Toe
Below Producer
Inter-Well
Total
(3)
North
21
3%
3%
5% (assumes producer 2m above Paleo)
20%
31%
Recovery excluding end losses
79%
West
South
34
Individual Well Pair Performance - 10S
WELL PAIR 10S
400
350
100/12-16-082-12W4/00 (P10S) Bitumen m3/cd
100/12-16-082-12W4/00 (P10S) Prod Water m3/cd
102/12-16-082-12W4/00 (I10S) Steam m3/cd
Volume m3/cd
300
North
21
West
100/12-16-082-12W4/00 (P10S) Steam m3/cd
250
Circulation Phase
200
150
100
50
0
South
80,000
100/12-16-082-12W4/00 (P10S) Cum Bitumen m3
100/12-16-082-12W4/00 (P10S) Cum Prod Water m3
70,000
102/12-16-082-12W4/00 (I10S) Cum Steam m3
10S
Volume m3
Comments:
• circulation phase extended because of
early plant limitations.
• Cleanest, thickest pay
• Limiting factor on reservoir performance
is plant steam capacity
60,000
100/12-16-082-12W4/00 (P10S) Cum Steam m3
50,000
40,000
30,000
20,000
10,000
07
pe
S
7
-0
ct
O
07
vo
N
07
ce
D
08
na
J
08
be
F
8
-0
ar
M
8
r-0
Ap
8
-0
ay
M
08
nu
J
8
l-0
Ju
08
gu
A
08
pe
S
35
Individual Well Pair Performance - 4W
WELL PAIR 4W
400
107/05-21-082-12W4/00 (P4W) Bitumen m3/cd
107/05-21-082-12W4/00 (P4W) Prod Water m3/cd
350
110/05-21-082-12W4/00 (I4W) Steam m3/cd
300
Volume m3/cd
North
Pad
21
West
4W
107/05-21-082-12W4/00 (P4W) Steam m3/cd
Plant
250
Circulation Phase
200
150
100
50
0
South
80,000
107/05-21-082-12W4/00 (P4W) Cum Bitumen m3
107/05-21-082-12W4/00 (P4W) Cum Prod Water m3
70,000
110/05-21-082-12W4/00 (I4W) Cum Steam m3
Comments:
• circulation phase extended because
of early plant limitations.
• Average well in average pay
Volume m3
60,000
107/05-21-082-12W4/00 (P4W) Cum Steam m3
50,000
40,000
30,000
20,000
10,000
-
07
pe
S
7
-0
ct
O
07
vo
N
07
ce
D
08
na
J
08
be
F
8
-0
ar
M
8
r-0
p
A
8
-0
ay
M
08
nu
J
8
l-0
Ju
08
gu
A
08
pe
S
36
Individual Well Pair Performance - 3N
WELL PAIR 3N
400
3N
106/15-21-082-12W4/00 (P3N) Bitumen m3/cd
106/15-21-082-12W4/00 (P3N) Prod Water m3/cd
350
106/15-21-082-12W4/00 (P3N) Steam m3/cd
300
Volume m3/cd
North
21
West
102/15-21-082-12W4/00 (I3N) Steam m3/cd
250
Circulation Phase
200
150
100
50
0
South
80,000
106/15-21-082-12W4/00 (P3N) Cum Bitumen m3
106/15-21-082-12W4/00 (P3N) Cum Prod Water m3
70,000
106/15-21-082-12W4/00 (P3N) Cum Steam m3
Comments:
• circulation phase extended because of
early plant limitations.
• Thinner pay to north (toe)
• Sub-cool control harder towards toe
Volume m3
60,000
102/15-21-082-12W4/00 (I3N) Cum Steam m3
50,000
40,000
30,000
20,000
10,000
07
pe
S
O
-0
ct
7
vNo
07
c
De
7
-0
08
na
J
0
bFe
8
-0
ar
M
8
8
08
r -0
yp
a
A
M
0
nJu
8
l-0
Ju
8
08
08
gpe
u
S
A
37
Reservoir Performance Summary
•
•
•
•
Overall Reservoir Performance Excellent.
•
•
Production is climbing and SOR’s dropping as wells mature.
•
•
Downtime associated with this well for ESP install and optimization.
Better than expected production ramp up. At September 30, 2008, 14 wells are producing.
One (1) well re-drilled (102/09-17-082-12W4/00) out of 30. New
production well (104/09-17-082-12W4/00) in circulation phase as of
September 30 2008.
Installed ESP in well (104/16-17-082-12W4/00 P8S) in September 2008 in
order to lower SOR. Three (3) plant shutdowns in 2008 effected reservoir performance. •
•
May (de-bottlenecking),
June (vessel clean out),
September (mandated boiler and psv inspections). Plant optimization continues.
Plan to drill 2 new well pairs in 2009. Drilled from existing pads and within
the current development area. Great Divide ERCB Presentation Nov 2008
38
Performance - % Recovery Bitumen in Place
39
Development Plans – Existing Pads
New Well Pairs
Purpose: Maintain Plant Throughput
40
Development Plans – Future
Connacher’s Proposed Development
Only the “existing” pads approved for
development.
Future pad groupings 2, 3, 4 are within the
approval project but require future development
approvals from ERCB and AE.
Existing
2009 from existing Pads
Future 2
Future 3
Future 4
Oil sands showing no wells are the results of
recent exploration and require completion of
company’s internal planing process.
2 New Wells 2009
41
Facilities
Facilities
42
Facilities
Pad 101
•September 2007 – First steam into 15 well Pairs
Pad 102
•October 2007 – First bitumen sales
•December 2007 – Start conversion to full time
production
Steam Boilers
Evaporators
•October 2006 – First pile driven at plant
•September 2008 – First plant turnaround & redrill of one producing Horizontal well
43
Facilities
Key Points
Capacity ~ 1,600 m3 / day bitumen
Steam Generation: Drum boilers.
Maximum pressure rating 6300 kpa
Deliver 4,300 m3 /day steam @ 95% + Quality
Treating: Condensate addition
Water Recycle: IGF, WS Filter, Two vertical tube falling film evaporator towers
Waste Water: All water from shipped from facility to approved disposal sites
Source water: 4 groundwater wells in the Grand Rapids formation
44
Facilities - Process SchematicTreating
(Zoom to read)
45
Facilities - Plant Layout
Significant Changes 2008
Modifications to Trucking
Terminal to facilitate more
efficient truck loading
(Zoom to read)
46
Measurement, Accounting & Reporting (MARP)
MARP
(Zoom to read)
Last MARP audit October 7, 2008. Great Divide MARP was approved October 20, 2008
(appendix B)
Well Testing
The plant was designed to allow for two tests per well per month with a well test durations of 24
hours including stabilization and purge times. SInce August the plant has been using 12 hour
test. The results of this change are still being evaluated. As information is gathered testing
durations and frequencies will be modified to obtain representative well test information. It is
anticipated that operators will use a tolerance band of +/-10% for flagging test results. Any test
results outside this band, when compared to the most recent test, must be reviewed and
accepted or rejected by the operator. The 10% band is used for volumetric comparisons as well
as for water cut comparisons. The data is analyzed in accordance with calculations and
procedures laid out in the MARP
47
Water Recycle
Water Recycle Rate = (Steam Injected – Fresh Water) * 100
Produced Water
Source Water from Grand Rapids ( ~1900 ppm TDS)
Water Source Wells
1F1/08-17-082-12W4
1F1/09-17-082-12W4
1F1/16-17-082-12W4
48
Facility Observations
Observations
•
Initial high chemical usage and treater upsets at well
startups. Situation improves over time as a steady
state evolves.
•
Loads on the VRU higher than designs but corrected at
plant turnaround
•
Upgraded VRU seals
•
Increased Heat Exchanger capacity
•
Upsized the inlet separator line
•
Water cleanup process (IGF, WS Filter) worked as
designed
•
Evaporator system worked as designed
•
Recycle train not performed as designed (investigating)
49
EH&S & Compliance
EH&S & Compliance
50
Water Usage
2008
Divide
Water
Source
Well
2008Great
Great
Divide
Water
Source
Well
Usage
Usage
Number of Daily Exceedances/Month (2008)
10000
9153
15000
15907
21943
19089
22327
21899
11420
20000
3
(m )
25000
18390
21052
30000
Jan
3
Apr
8
July
0
Oct
Feb
3
May
0
Aug
0
Nov
Mar
21
June
0
Sep
0
Dec
0
Water Source Wells
1F1/08-17-082-12W4
1F1/09-17-082-12W4
1F1/16-17-082-12W4
5000
0
Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
Annual Allowable Water Use
292,000 m3
Total Annual Water Use (YTD)
161,180 m3
• June 2008, CLL obtained verbal confirmation in regards to increasing annual groundwater allowable.
• 129,000 cubic metres (annual) was added to the original 163,000 cubic metres (annual) allowable.
• Official increase effective July 2nd, 2008 expires one year later on June 30th, 2009 concurrent with License
00240458-00-00.
51
Facility Flaring
Facility License # 36853
13 16 082 12 W4
All DDS notifications submitted to ERCB Bonnyville field office.
Two way communication was held during all events.
Date
Volume (103m3) Duration (hrs)
04 Oct. 2007
13 Nov. 2007
21 Nov. 2008
21 Dec. 2007
31 Jan. 2008
14 May 2008
12 June 2008
13 June 2008
8.2
40
40
4
6.3
5.3
3
15.5
27.5
23
4.2
5.25
4.9
4.5
5.1
23.25
52
Sulphur Dioxide Emissions
2008 YTD Sulphur dioxide total:
102 t/yr
70
2008 Sulphur dioxide YTD:
60
Q1 – 10.48 tonnes
Q2 – 30.10 tonnes
50
Q3 – 61.42 tonnes
Two highest months of emissions (July & August 2008)
Due to high H2S content of gas analysis.
40
Note: Calculated from gas flow rate and H2S
concentration
30
EPEA Approval No 223216-00-00 Emission Limits:
0.40 tonnes per day Sulphur Dioxide
20
Sulphur
Dioxide
Emissions t/q
10
0
Q1
Q2
Q3
53
Peak and Average Sulphur Dioxide Emissions
Summary:
2008 Sulphur Dioxide Emission Peak (monthly)
 August
– 30.60 t/m
2008 Sulphur Dioxide Emission Average (monthly)
 11.33
t/m
Monthly air reports are submitted to Alberta Environment
54
Self Disclosures – ERCB
ERCB Self Disclosure to
Bonnyville District Office
May 14th, 2008
Self Disclosure letter submitted to ERCB (9 items to address)
May 15th, 2008
Self Disclosure action plan submitted to ERCB
June 30th, 2008
Internal complete licensing and operations audit on the facility,
associated pipelines and well pads provided to ERCB with
identification of non compliances and action plan
July 31st, 2008
Submitted internal audit action plan required by ERCB
August 6th, 2008
Received ERCB approval of action plan to correct noncompliances by September 30th, 2008
August 6th, 2008
* Low risk (5 items) approved by the ERCB
Sept 8th, 2008
** High risk (3 items) approved by ERCB
Oct 8th, 2008
Extension on final item granted by ERCB. Due December 18th,
2008.
* Meter calibration, meter markings, facility license revision
** Secondary containment
55
Self Disclosures –AENV
AENV self disclosure to Ft McMurray Division
Current EPEA approval allows for emission of 0.4 t/d SO2
November 10th, 2008 - Request submitted to AENV for increase to 1.98 t/d SO2
56
Regulatory & HSE Summary
Connacher has developed a network of groundwater wells at various
depths consistent with EPEA requirements and monitoring to date has
indicated no contamination issues.
The network of four ambient air monitors measuring SO2 and H2S
within the development area has not exceeded the Alberta Ambient
Air Quality Objectives issued by Alberta Environment.
Fugitive emissions plan has been completed and submitted to AENV.
Soils monitoring program under development for submission to
Alberta Environment in 2009.
57
Compliance Summary
Connacher believes that the Great Divide project is in full compliance
with ERCB approvals and regulatory requirements
58
Support Documents
Support Documents
59
Bitumen Reserves and Resources
Per GLJ Petroleum Consultants (“GLJ”) as at June 30, 2008 pursuant
to NI51-101 and Canadian Oil & Gas Evaluation Handbook
1)
2)
3)
4)
5)
6)
7)
8)
9)
10)
Proved reserves are those reserves that can be estimated with a high degree of certainty to be recoverable. It is 90% likely that the actual remaining quantities recovered will exceed the estimated
proved reserves.
Probable reserves are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less
than the sum of the estimated proved plus probable reserves.
Possible reserves are those additional reserves that are less certain to be recovered than probable reserves. There is only a 10% probability that the quantities actually recovered will equal or
exceed the sum of proved plus probable plus possible reserves. Possible reserves were 72.3 million barrels as at Jun 30, 2008 per GLJ.
Contingent resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using established technology under development, but
which are not currently considered to be commercially recoverable due to one or more contingencies.
Prospective Resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from undiscovered accumulations by application of future development projects.
Low Estimate is considered to be a conservative estimate of the quantity that will actually be recovered from the accumulation. If probabilistic methods are used, this term reflects P90 confidence
level.
Best Estimate is considered to be the best estimate of the quantity that will actually be recovered from the accumulation. If probabilistic methods are used, this term is a measure of central
tendency of the uncertainty distribution (P50).
High Estimate is considered to be an optimistic estimate of the quantity that will actually be recovered from the accumulation. If probabilistic methods are used, the term reflects a P10 confidence
level.
Contingent resources and prospective resources are additive only for purposes of economic calculations, but are distinct categories with different risks.
10% Present Value of future net revenue, calculated after deduction of forecast royalties (royalty regime in effect as at June 30, 2008), operating expenses, capital expenditures and abandonment
costs but before corporate overhead or other indirect costs, including interest and income taxes using GLJ July 1, 2008 price forecast. Future Net Revenue does not necessarily represent fair
market value. Based on 211 million common shares outstanding as at June 30, 2008.
60
Additional Slides
Appendicies
61

Connacher Oil and Gas Limited

Transcription

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