nexen / opti long lake sagd project 2007 performance

1

Nexen / OPTI Long Lake SAGD Project

2007 Performance Presentation

June 17, 2008

2

Background

3

Background

•

The Long Lake Project is a Steam Assisted Gravity Drainage (SAGD) scheme for the production of Bitumen from the Wabiskaw-McMurray deposit in the Athabasca Oil Sands area and for the upgrading of bitumen.

•

Estimated production capacity of the Long Lake Phase 1 SAGD is 60,000 bbl/d of Premium Synthetic Crude (PSC).

4

Nexen / OPTI Long Lake Lease

5

Nexen / OPTI Long Lake CPF

6

SAGD Layout

7

Wells at Long Lake Project

8

Integrated Plant Operation

9

Subsurface Issues Related to Resource Evaluation and Recovery

10

Geology / Geoscience

11

Original Bitumen in Place

Project Area P10 P50 P90Total OBIP

(109bbls) 4.284 4.024 3.657

Nexen Cutoffs: h > 15m or HPV > 4 m3/m2

Lease Area North of the Gregoire River

Minimum Pay Hydrocarbon Pore Volume

HPV = Σ

(So

*Φ)Min pay bs

Min pay tp

12

Pad by Pad OBIP

Pad Total OBIP Total OBIP E6 m3 E6 bbls

1

3.85

24.232NE

3.16

19.902SE

0.68

4.263

3.44

21.624

0.17

1.085

4.62

29.066N

5.51

34.646W

4.14

26.077N

5.37

33.807E

2.84

17.888

5.16

32.459NE

1.74

10.929W

3.27

20.5410N

5.04

31.7210W

3.91

24.5911

3.81

23.94TOTALS 56.71 356.71

13

Average Parameters Summary

Lease

•

Measured Depth 201.6 m MD•

Average Minimum Pay 30.6 m

•

Porosity 30.2%•

Water Saturation 28% (median 21.1%; mode 11.5%)

•

Temperature 6 - 8°C

14

Program Area Map

5 -

2007 wells

15

30 –

2008 wells

16

Representative Log 1AB/07-01-086-07W4/00

Pay Top

McMurrayWabiskaw C

Pay Base

17

Bitumen Pay Top Structure

Range in Values:

187 to 314 TVDSS

18

Bitumen Pay Top Structure

5 –

2007 Wells

19

Bitumen Pay Base Structure

Range in Values:

211 to 289 TVDSS

20

Bitumen Pay Base Structure

21

5 –

2007 wells

Minimum Pay Hydrocarbon Pore Volume

HPV = Σ

(So

*Φ)Min pay bs

Min pay tp

22

5 –

2007 wells

Minimum Pay Hydrocarbon Pore Volume Zoom

IDA

23

Drilling and Completions

No drilling or completions in 2007.

24

Drilling Highlights 2005 / 2006

•

No drilling in 2007.•

Three slant rigs utilized.•

Surface casing was cemented to surface.•

Intermediate casing was cemented to surface.•

One well abandoned due to lost returns during cementing operation.

•

One well out of 156 has a low cement top.•

One well abandoned due to suspected intermediate casing separation.

•

Two wells abandoned due to no pay.•

Tenaris Blue couplings used on all casing connections.

25

Completion Highlights 2005 / 2006

•

Cement Bond Log Waiver successfully obtained after demonstration of good cementing practices on Pads 9 and 2. A total of 91 wells were logged for cement bond.

•

Tubing connections are all Tenaris ER.•

Initial artificial lift will be gas lift.•

Low pressure artificial lift mechanism will be electric submersible pumps.

26

Typical Well Pair Schematic

339.7 mm Surface Hole

Surface Casing -339.85mm J-55, 81.1kg/m Tenaris ER

Thermal 40F Cement

104/01-06-086-06/W402S0102P01

100/01-06-086-06/W4

508mm Surface Hole

Surface Casing 406.4mm, H-40, 96.73 kg/m Tenaris ER

374.7mm, Intermediate Hole

Intermediate Casing 298.5mm, K-55, 80.36 kg/m, Tenaris Blue

Heel Inj. String 177.8mm, K-55, R2, 34.23 kg/m, Tenaris ER SC SB landed at 393.31 mKB

406 mKB 436.61 mKB / 236.7 mTVD 1231 mKB1219.84 mKB / 237 mTVD

0.010" slotted liner 219.1mm, K-55, 47.62 kg/m, Tenaris ER 269.9mm Hz Hole

0.0135" rolled on 0.018" slotted liner - 177.8mm, K-55, 34.23 kg/m, Tenaris ER222.3mm Hz Hole

1227.6 mKB

1219 mKB / 241.66 mTVD443.85 mKB / 242.55 mTVD

426.17 mKBPrim. Prod. String - 114.3 mm, J-55, 18.8 kg/m Tenaris ER SC SB, tapered to 88.9mm, J-55, 13.7 kg/m Tenaris ER SC SB at 386.68 mKB, landed at 1191.66 mKB

Intermediate Casing 244.5mm, K-55, 53.57 kg/m, Tenaris Blue

311 mm Int. Hole

Guide String 73.0mm J-55, AB STL Flush, landed at

416.21 mKB, with gas-lift pup at 242.8 mTVD

1 inch Gas-lift coil�at 360 mKB

Instrument Coil - 38.1mm, Toe bubble tube and T/C at 1163.5, 976.5, 789.5, 602.5,

415 5 mKB

Pad 02 Well Pair 01

Well Pair Architecture

Toe Inj String 114.3 mm, J-55, 17.3 kg/m Tenaris ER landed at 1205.14 mKB

87.09 mKB

85.06 mKB

27

SAGD Well Pair Instrumentation

28

SAGD Observation WellUW I 100/01-31-085-06W 4Status: Standing

CC #: Date:

Elevations:K B: 475.5 mGL: 474.0 m

KB - GL: 1.5 mSurface Equipment: W ellhead:

Surface Casing:

Volumes: OD ID m3/m m/m3

Tubing: 0.00000Casing: 114.30 101.60 0.00811 123.35

Annulus: 0.00811 123.3Production Casing:

Tubing String:# Size Description Length Top Set Comment

Casing Collars:

No tubing string.

Logs:

PBTD: 249.2 mKB TD: 249.7 mKB

11/28/2006

W ELLBORE SCHEM ATICNexen Opti OB1A Newby 1-31-85-6

2018096

6 jts 177.8mm, 29.76 kg/m, J-55, 8RD, ST&C IPSCO casing set at 83 mKB. Cemented with 6 tonnes of 0-1-0 "G" + 3% CaCl2.

15 jts 114.3mm, 17 kg/m, J-55, LT&C casing to 138.27 mKB crossed over to 9 jts 114.3mm, 17 kg/m, J-55, QB2 casing set at 249.7 mKB. Cemented with 5.4 tonnes thermal 40M thix mix + 0.4% FL-77 + 0.5% AF-1 + 2% CaCl2.

*Promore instrumentation installed with production casing.*

29

Reservoir Observation Well

30

Artificial Lift

31

Gas Lift

•

Initially all producer wells were completed with a gas lift production system.

•

With steam chamber operating pressures above 2 MPa, Gas lift will be effective.

32

Electric Submersible Pumps

•

If steam chambers are to be operated below 2 MPa, ESPs will be installed.

•

Long Lake is working with three high temperature ESP vendors.

33

Scheme Performance

34

Exploitable Bitumen In Place

35

Long Lake Phase 1 Recovery Factors

•

Initial Recovery Factor Estimate–

No Impairments 60%

–

With Top Impairments 45%–

Overall Average 56%

•

Once production is established for a longer period of time, will use modeling to history match production.

36

Long Lake Phase 1 Performance

Phase 1 Total Injection and Production Rates to March 31, 2008

0

400

800

1200

1600

2000

2400

2800

3200

3600

4000

4400

4800

5200

5600

6000

6400

6800

7200

7600

8000

09-Feb-07 20-Mar-07 29-Apr-07 08-Jun-07 17-Jul-07 26-Aug-07 04-Oct-07 13-Nov-07 23-Dec-07 31-Jan-08 11-Mar-08 19-Apr-08

Volum

etric

Rat

es C

WE (m

3/da

y)

0

4

8

12

16

20

24

28

32

36

40

44

48

52

56

60

64

68

72

76

80

SOR

Oil Steam Water SOR

37

Long Lake Phase 1 Overall Operating Philosophy

•

During steam circulation, the goal was to achieve returns on both the injector and producer with a projected average conversion time of 90 days.

•

Due to typical facility / start-up issues, steam rates and well returns were limited which delayed conversion to SAGD.

38

Long Lake Phase 1 SAGD Operating Philosophy

•

The target operating pressure is 2,750 –

3,000 kPa (Scheme approval is 3,000 kPa).

•

Operating pressure will be adjusted to control losses to the reservoir (we will not try to increase pressures if wells are experiencing high losses).

•

For wells operating at lower pressures, ESPs will be required to produce these wells.

39

Long Lake Phase 1 Pads

40

Pad 1

•

Test and group separators for Pads 1, 4 and 5 commissioned April 2007.

•

March 2007 began steam injection.•

June 2007 no steam injection.•

01P01 ESP restarted in January 2008.•

O1P02 ESP would not restart. New ESP installed January 2008, production in February and March Installed fibre optic cable in 01S02 in November 2007.

•

01P03 pump would not restart. New ESP installed in January 2008.•

All wells producing mainly water after being shut-in since August 2006.•

Cumulative production of 159,450 m3

by March 31 (4.9% recovery of exploitable BIP).

41

OB1A (Heel – 1.2 m From Injector)

•

Maximum temperature rose from 170°C in March 2007 to a maximum temperature of 210°C in January 2008 due to steam injection at the heel.

•

Top of steam still located at the top of a lean zone.

42

OB1B (Middle – 7.2 m From Injector)

•

Maximum temperature of 60°C in March 2007 dropping to 54°C indicating no fluid movement.

43

OB1C (Toe – 6.8 m From Injector)

•

Maximum temperature increased from 95°C in March 2007 to 154°C due to steam injection.

•

The position of maximum temperature appears to have risen 5 m.

44


•

Maximum temperature rose from 130°C in March 2007 to 181°C in January 2008 due to steam injection at the heel.

45


•

Maximum temperature rose from 132°C in March 2007 to a maximum temperature of 164°C indicating that there is some nearby heating.

46


•

Area of heated zone growing larger as maximum temperature increased from 132°C in March 2007 to a maximum temperature of 150°C.

47


•

Area appears to be cooling as maximum temperature has dropped from 114°C to 70°C.

•

Even though some steam injected at heel, observation well is too far away to detect any heat.

48


•

Area continues to cool with maximum temperature dropping from 146°C in March 2007 to 125°C.

49


•

Maximum temperature rose from 158°C in March 2007 to current maximum temperature of 186°C due to steam injection even though observation well not located near injector well.

50

Pads 2SE and 2NE

Pad 2SE•

Test and group separators commissioned November 16, 2007.•

Limited steam warm-up.•

No production to March 31.

Pad 2NE•

Test and group commissioned November 16, 2007.•

Steam circulation started November in 02P05 and 02P06.•

Limited steam to lower reservoir quality wells 02P01 –

02P04.•

Converted 02P05 to SAGD on March 29, 2008.•

Converted 02P06 to SAGD on March 18, 2008.•

First measurable production in February 2008.•

Maximum pressure of 2,300 kPa and 2,200 kPa in 50 m and 100 m offset monitoring wells respectively.

•

Cumulative production of 269 m3

to March 31 (0% recovery of exploitable BIP).

51

Pad 3

•

Test and group separator commissioned November 13, 2007.•

Three wells converted to SAGD–

03P01 March 30, 2008–

03P04 March 30, 2008–

03P05 March 17, 2008•

First measurable production in February 2008.•

Maximum pressure of 2,230 kPa and 2,220 kPa in 50 m and 100 m offset monitoring wells.

•

Maximum pressure of 2,500 kPa in 100/09-31 monitoring well adjacent to 03P01.

•



52

Pad 4

•

Steam injection started April 2007 in one well (04P01).•

No steam June 2007.

•

No steam since November 2007 as steam used in better quality reservoir areas.

•

Pressure back to original pressure, high loss area.•

No bitumen production.

53

Pad 5

•

Test and group separator commissioned April 2007.•


05P02 March 4, 2008–

05P03 March 6, 2008–

05P04 March 14, 2008•

One well shut-in 05P05.•

First production allocated starting in November 2007.•

Wells operating at higher operating pressures with small fluid losses despite being next to Pad 1.

•

Muted pressure response seen in 50 m and 100 m offset monitoring

wells with maximum pressure of 1,650 kPa.

•


to March 31 (0.1% recovery of exploitable BIP).

54

Pad 6N and 6W

Pad 6N•

Test and group separator commissioned in September 2007.•

First steam injected in October 2007.•

All six wells converted to SAGD06P01 March 16/08

06P04 March 13/0806P02 March 11/08

06P05 March 31/0806P03 March 4/08

06P13 March 31/08•

First production in December 2007 allocated to 06P02, 06P04 and 06P13.•

All wells except 06P04 appear to have fluid losses so will require an ESP to operate at lower pressure.

•


to March 31 (0 % recovery of exploitable BIP).

Pad 6W•

Limited steam circulation as lower reservoir quality area anticipated to operate at lower pressure.

•

All wells still on steam warm-up. No production.

55

Pad 7N and 7E

Pad 7N•

Test and group separators commissioned September 3, 2007.•

First steam injected in October 2007.•

First production allocated to 07P01, 07P03 and 07P05 in December

2007.•


07P03 March 12/08–

07P04 March 12/08–

07P05 March 5/08•

Wells operating at higher pressures with small fluid losses.•


to March 31 (0.1% recovery of exploitable BIP).

Pad 7E•

Limited steam injection as lower reservoir quality area anticipated to operate at lower pressures.

•

All wells still on steam warm-up. No production.

56

Pad 8

•

Test and group separator commissioned August 19, 2007.•

Steam injection started in October 2007.

•


08P03 March 16/08

–

08P05 March 14/08–

08P06 March 16/08

•

First measurable production starting in February 2008.•

Wells 08P01 and 08P02 operate at lower pressure and are ESP candidates in future.

•


(0% recovery of exploitable BIP).

57

Pad 9W and 9NE

Pad 9W•

Test and group separator commissioned in September 2007.•

First steam injection in August 2007 unable to circulate steam with returns until September 24, 2008.

•

First production allocated to all five wells starting in December 2007.•

09P01 was the first commercial well converted to SAGD on February 5, 2008.•

All wells converted to SAGD09P01 February 5/08

09P04 March 31/0809P02 March 6/08

09P05 March 16/0809P03 March 10/08

•

All wells operating at higher pressures with small fluid losses.•


(0.4% recovery of exploitable BIP).

Pad 9NE•

Limited steam injection into 09P06, 09P08 and 09P10 began in August 2007. •

Maximum pressure of 1,900 kPa in offset monitoring wells.•

No production.

58

Pad 10W and 10N

Pad 10W•

Test and group separators commissioned November 16, 2007.•

Steam injection began in November 2007.•

High pressure area had trouble lifting fluid out of injectors at

pressures of 3,000 kPa, temporary approval to go to 3,500 kPa received in order to circulate wells with returns.

•

Due to steam capacity limitations unable to circulate steam on full-time basis so four wells still on steam circulation.

•

10P05 was shut-in on January 8, 2008 until drilling of Pad 11 completed.•



Pad 10N•

Limited steam circulation commenced in November 2007 as this area has poor reservoir quality.

•

All wells still on steam circulation.•


(0% recovery of exploitable BIP).

59

Initial Key Learnings

•

Early results have been in line with expected simulation results.

•

Operating pressures in the field have, in the most part, been what was expected.

•

Pressure communication between wells, in the same pair and in the adjoining pair, have been noted early after initiation of steam injection.

•

Too early to determine any changes in strategy.

60

Long Lake Phase 1 Other Well Tests

•

Temperature logging on five injectors November 2007–

Since there is no instrumentation other than blanket gas heel pressure on the injectors, temperature logs were run to determine if injector steam rates were sufficient to provide uniform heating along injector length.

•

Results–

Unable to run temperature log to end of 04S01 due to cold wellbore (bitumen plug).

–

Other wells showed uniform heating with two wells showing a small heated zone.

61

Long Lake Phase 1 Other Well Tests

•

Fracture gradient test 0n 14-25-85-7W4–

As a follow-up to previous testing, testing was conducted on the upper two perforation intervals in an attempt to measure the fracture gradient.

–

Testing was inconclusive. Long Lake is using results from previous testing which used the ISIP method to provide a fracture gradient estimate of 19.7 kPa/m.

–

At the depth of the highest injector for each pad, the fracture pressure ranges from 4,000 to 4,675 kPa, well above the project approved operating pressure limit of 3,000 kPa.

–

At the top of pay, the fracture gradient ranges from 3,350 kPa to 4,175 kPa.

62

Long Lake Phase 1 Quaternary (Q) Channel Monitoring

•

Q-Channel is a fresh water source that follows a normal water gradient.

•

Located on the east portion of the Long Lake lease.

–

Cuts through the cretaceous sediments down to a maximum depth of 220 m close to 4-5-86-6W4 (NE of Pad 2 NE).

•

Q-Channel trends mostly north to south.•

Average pressure of the Q-Channel is approximately 2,200 kPa at a depth of ~220 m.

•

The commercial SAGD well pairs adjacent to the Q-Channel have been oriented perpendicular to the Q-Channel and terminated 150 meters away.

63

Long Lake Phase 1 Quaternary (Q) Channel Monitoring

•

Monthly Q-Channel Status Reports are now being submitted to the ERCB which includes plots and tabulated data of daily fluid rates from all wells adjacent to the Q-Channel, plots and data from all observation wells and interpretation of the data.

•

Long Lake has seen no evidence that we are adversely affecting the Q-Channel.

•

All the above data is contained in the Appendix.

64

Future Plans

•

Continue with production of existing locations.•

Additional development planned, first pad (Pad 11) to be on production by early 2010.

•

Well spacing and length will be changed in Pad 11 to provide a test of these factors for future development.

•

Additional pads, for 2010 drilling, are being worked on for approvals.

•

To date no information has been gained that would change our go forward strategy.

65

Surface Heave

•

Test done in 2006 to determine if INSAR could see our location.

•

Results showed that INSAR was effective with results as expected.

•

Going forward with plan to install additional corner reflectors and do monitoring.

66

Wind-down Strategy

•

Final wind-down strategy of the field will have to be determined.

•

Operating strategy throughout the project life could effect wind-down.

•

Starting with simulation to determine what the wind-down may look like.

•

Next step will be to look at differing operating scenarios and what impact they have on final wind-down.

•

Wind-down not expected for 8 to 10 years.

67

Surface Operations and Compliance

68

Facilities

71

Facility Performance

•

Plant is currently in start-up / ramp up mode.•

Challenges to date have been:–

Increasing water production with cold make up water to a Hot Lime Softener.

–

Plate style heat exchanger failures due to low flows and slugging in the vapor system.

–

Chemical system failures due to initial design.–

Lift gas compressor was commissioned in March.

72

2007/2008 Performance Summary and Issues

March 2007 Restarted steam injection into three Pad 1 (Pilot) wells that had been shut-in August 2006.

April 2007 Began steam injection into one Pad 4 well.

June 2007 No steam injection due to facility construction.

August 2007 Started one OTSG. Steam injection into 12 wells.

September 2007 Plant inlet accepted steam returns September 24. Tube failure in one OTSG. Steam injection limited.

October 2007 Commissioned two more OTSGs. Increased number wells on steam warm-up to 59.

73

2007 / 2008 Performance Summary and Issues - Continued

November 2007 No steam returns due to inlet heat exchanger problems.

December 2007 All four OTSGs in operation December 22.

January 2008 Water treatment problems in HLS restricted steam injection. Priority given to top 25 wells.

February 2008 Better volume measurements attained for daily bitumen and water volumes. First well (09P01) converted to SAGD Operation.

March 2008 Lift gas compressor in operation. Total of 28 wells converted to SAGD. Start-up on HRSG No. 1.

74

Measurement and Reporting

75

SAGD Well Production Measurement

•

Eight two-phase test separators with up to 13 well pairs.•

Currently testing two wells per day per pad, 12 hour duration.

•

Allows one test per week per well.•

Bitumen cuts are based on an inline water cut analyzer, AGAR meter, and manual cuts are taken for confirmation.

•

Bitumen and water are prorated to total battery production.

76

Diesel Soaks

•

During initial well circulation the return of any diesel used as load fluid was not trackable.

•

Therefore Long Lake has not reported any load fluid recovery.

77

Water Balance

•

Being managed under following Alberta Registry facilities:–

AB BT 0094109•

SAGD Production Wells and Related Treating Facility.–

AB BT 0096995•

Saline Water Source System and tied in AENV Fresh Water Source.

–

AB IF 0094110•

Water Treatment, Steam Generation, Steam Injection Wells.•

AENV Fresh Water Source System and Water Disposal Wells.•

ERCB Bulletin 2006-11 is guidance for reporting water related activity.

78

Compliance

•

Meter calibration, accuracy and location:–

All metering is being reviewed.

–

Where issues are identified, they are being documented and addressed, where / when possible.

–

Directive 17 compliance is guideline.

79

Fresh and Saline Water

80

Water Usage

•

Water sources include–

Grand Rapids B–

Gregoire Channel–

Clearwater B•

Combination of fresh and saline water.

81

Water Source Wells Already Tied-In

UWI or Pseudo-UWI Formation Saline?

ERCB License (drilling)

AENV License (production)

Maximum Rate (m3/d)

Nominal Rate (m3/d)

Cum Annual Diversion to

March 31, 2008

Maximum Annual

(m3)

Freshwater Network: 16 wells 13,930 11,590

1WS/13-31-085-06W4/00 Quaternary N n/a 00191355-00-04 1,100 1,100 34286 401,500

1WS/02-12-086-07W4/00 Quaternary N n/a 00226884-00-00 1,050 1,050 32778 383,250

1WS/07-36-085-07W4/00 Lower Grand Rapids N n/a 00191355-00-04 1,220 960 40873 350,000

1WS/01-21-085-06W4/00 Lower Grand Rapids N n/a 00226884-00-00 400 400 21715 146,000


1WS/01-27-085-06W4/00 Lower Grand Rapids N n/a 00226884-00-00 1,100 1,100 37177 401,500





1WS/08-01-086-07W4/00 Lower Grand Rapids N n/a - 360 210

1WS/02-32-085-06W4/00 Gregoire Channel N n/a 00191355-00-04 650 410 4782 150,050

1F1/10-29-085-06W4/00 Gregoire Channel N 281564 00226884-00-00 1,000 800 44231 292,000

1WS/06-18-085-05W4/00 Lower Grand Rapids N n/a - 1,350 1,140

1WS/12-19-085-05W4/00 Lower Grand Rapids N n/a - 1,100 910

1WS/10-11-085-06W4/00 Lower Grand Rapids N n/a - 1,100 1,010

82

Water Source Wells Already Tied-In

UWI or Pseudo-UWI Formation Saline?ERCB License

(drilling)AENV License(production)

Maximum Rate(m3/d)

Nominal Rate(m3/d)

Saline Water Network: 17 wells 9,170 8,0001F1/11-28-084-06W4/00 Clearwater A N 302343 00240342-00-00 630 600

1F1/11-29-084-06W4/00 Clearwater A Y 302406 - 390 320

1F2/03-30-084-06W4/00 Clearwater A Y 302456 - 340 280

1F1/16-30-084-06W4/00 Clearwater A Y 303164 - 250 200

1F1/06-31-084-06W4/00 Clearwater A Y 302400 - 250 200

1F1/05-33-084-06W4/00 Clearwater A Y 302442 - 280 230

1F1/16-25-084-07W4/00 Clearwater A Y 302367 - 330 260

1F1/07-26-084-07W4/00 Clearwater A Y 302386 - 340 280

1F1/16-27-084-07W4/00 Clearwater A Y 302377 - 390 320

1F2/14-35-084-07W4/00 Clearwater A Y 304327 - 250 200

1WS/11-29-084-06W4/00 Lower Grand Rapids Y n/a - 490 390

1WS/11-32-084-06W4/00 Lower Grand Rapids N n/a 00240342-00-00 1,000 1,000

1WS/16-25-084-07W4/00 Lower Grand Rapids N n/a 00240342-00-00 680 680



1WS/07-23-085-06W4/00 Lower Grand Rapids Y n/a - 1,190 950

1WS/09-25-085-06W4/00 Lower Grand Rapids Y n/a - 620 500

Potable Water: 1 well shared with SAGD (WS Q 13-31-85-6)

83

Water Disposal

84

Disposal Well Summary (January – December 2007)

Disposal Well Avg. Vol. Inj., m3/dayAvg. WHP,

kPaAvg. BHP,

kPa BHT, oC

09-28-85-06W4 MCM 81.63 (avg. of 4 days) 1927 - -

09-28-85-06W4 KR 349.01 0 2486 15

01-21-85-06W4 MCM 0 - - -

04-22-85-06W4 MCM 0 - - -

•

9-28 MCM had disposal fluids only on September 3, October 16, October 17 and December 1, 2007.

•

9-28 KR is under vacuum.•

No disposal occurred down 1-21 MCM and 4-22 MCM in 2007. WHP data were very unreliable.

•

BHP and BHT are monitored only on 9-28 KR.

85

Disposal Well Summary (January - March 2008)

Disposal Well Avg. Vol. Inj., m3/dayAvg. WHP,

kPa Avg. BHP, kPa BHT, oC

09-28-85-06W4 MCM 22 (avg. of 13 days) 847 - -

09-28-85-06W4 KR 849 0Instrumentation

issuen/a

01-21-85-06W4 MCM 0 - - -

04-22-85-06W4 MCM 0 - - -

•

9-28 MCM had disposal fluids on 13 days from January to March 2008.•

9-28 KR is on vacuum.•

No disposal occurred down 1-21 MCM and 4-22 MCM from January to March 2008.

•

BHP and BHT are monitored only on 9-28 KR.

86

Sulphur Production

87

Sulphur Production

•

Sulphur recovery will begin once Upgrader comes on-line.•

No SO2

emitted from the Long Lake SAGD facility as natural gas was being used in fired equipment.

88

SO2 Continuous Monitoring

24-hour SO2

AAAQO = 57 ppb

Daily SO2 Concentrations Measured at the Anzac Air Monitoring Trailer

0.00

2.00

4.00

6.00

8.00

10.00

12.00

1/1/07

2/1/07

3/1/07

4/1/07

5/1/07

6/1/07

7/1/07

8/1/07

9/1/07

10/1/

07

11/1/

07

12/1/

07

1/1/08

2/1/08

3/1/08

SO

2 (p

pb)

89

SO2 Passive Monitoring

0.0

0.5

1.0

1.5

2.0

2.5

3.0

Jan-07 Mar-07 May-07 Jul-07 Sep-07 Nov-07 Jan-08 Mar-08

SO2 (

ppb)

SAGD Pilot Site SE

SAGD Pilot Site NW

02-32-085-06 W4M

01-21-085-06 W4M

13-31-085-06 W4M

Nexen Tower

Well Pad 9

Well Pad 7

Electrical Substation

Beside Tankyard

Near Drilling Camp

Anzac

24-hour SO2

AAAQO = 57 ppb

90

H2 S Passive Monitoring

24-hour H2

S AAAQO = 3 ppb

0.0

0.2

0.4

0.6

0.8

1.0

1.2

Jan-07 Mar-07 May-07 Jul-07 Sep-07 Nov-07 Jan-08 Mar-08

H2S

(ppb

)

SAGD Pilot Site SE

SAGD Pilot Site NW

02-32-085-06 W4M

01-21-085-06 W4M

13-31-085-06 W4M

Nexen Tower

Well Pad 9

Well Pad 7

Electrical Substation

Beside Tankyard

Near Drilling Camp

Anzac

91

Environmental Issues

92


•

Approval Amendments–

No amendments required for existing approvals.

93


•

Monitoring Programs–

Wetland Monitoring Program–

Ambient Air Quality Monitoring Program (Passive and Continuous)–

Shallow Groundwater Monitoring–

Surface Water Monitoring–

Groundwater Monitoring Program–

LDAR underway

•

Monitoring Outcomes–

Monitoring Reports Submitted as per AENV Approval.–

No Significant Issues Identified in 2007.

94


•

Other Initiatives–

CEMA, RAMP, WBEA, RIWG, ATC.–

Piloting Hydrogeological Mapping Program (Southern SAGD Region).

–

Isotope Mapping Project.–

Leak detection for Building Sumps and Drains as per Directive 55

completed.

•

Reclamation Programs–

No reclamation activities have commenced.•

Site still under construction.

95

Compliance

96

Compliance

•

The Long Lake Commercial Project is currently operating in accordance with operating ERCB approval and AENV Approval 137467-00-00 as amended.

•

Non-Compliance in 2007–

ERCB File #4004•

Cold mix application on the Long Lake project.•

Geotextile material within excavated soil stockpiles.•

Concrete and hydrovac washout storage.•

Storage and disposal of wood waste.

97

Compliance

•

Operational Exceedences January 2007- March 2008–

Source well exceedences: 7 in 2007 and 3 in 2008.

•

Operational Reportable Spills January 2007- March 2008–

7 reportable spills in 2007 and 4 in 2008 including:•

560 m3

recycle water pond overflow February 14, 2008. 1500 m3

recovered.

•

120 m3

disposal tank overflow February 25, 2008. 120 m3

recovered.•

30 m3

skim tank overflow March 16, 2008. 30 m3

recovered.

•

Construction Reportable Spills January 2007- March 2008–

11 Sewage Spills, 1 Glycol Spill, and 1 Diesel Spill.

98

Compliance

•

Compliance Issues•

No Other Federal or Provincial Compliance Issues.

99

Future Plans

100

Future Plans

•

Major Activities–

SAGD ramping up to 70,000 bbl/d.

–

Debottlenecking construction underway. Expected completion November 2008.

–

Anticipate commissioning and start-up of Upgrader Phase 1.

•

Lime Sludge Pond–

Review option of including centrifuge or dredging to increase water recycle instead of land fill and cap.

101

Future Plans

•

Corporate Expansion Plans–

Plans to increase production to 360,000 bbl/d PSC.

–

Have current leases in place.

•

Plant Design–

No major changes to the Long Lake Phase 1 facility are anticipated.

nexen / opti long lake sagd project 2007 performance

Documents