Dover SAGD Progress Review Thermal Heavy Oil

Transcription

1 over SA Progress Review Thermal Heavy Oil by evon Canada Corporation (Project Project Operator) (AEUB Approvals 9044, 9045 & 9862)

2 Outline Introduction SA Performance Facilities Regulatory Future Plans

3 Introduction evon Canada Corporation has been operator of the over SA Facility since January 1, On February 28, 2005, evon s interest was sold, and operatorship was transferred to Petro-Canada Oil and as. evon continues to hold a working interest in the OVAP Vapex Pilot (reported separately). Confidentiality of all over SA data was removed ecember 31, This progress report covers the 14 month period from January 1, 2004 to February 28, Future Plans as per I will be presented by Petro- Canada.

4 over Project Area T93 over T92 MacKay T91 R13 R12W4

5 over SA Project

6 eology Typical Log of ood UTF Well R API North-South tidal channel sand deposit Channel width is about 500 to 800m FE Wabiskaw Main target reservoir is the McMurray Formation epth m R McMurray Best quality at the base of reservoir (high porosity and So) Lower quality near the top of reservoir (bioturbated interbedded shales) Limestone FE Ω -m No extensive bottom water and top gas/water

7 over Project Well Layout 500 m 1 PHASE 750 m 2 F& N OVAP 90 m 70 m Well Pair 750 m PHASE B 500 m m SCALE E1 PHASE E B3 B2 B1 Tunnels Well Pair PHASE A A3 A1 A2 25 m 60 m

8 Outline Introduction SA Performance Facilities Regulatory Future Plans

9 Overview Phase B 3 SA pairs, drilled from underground, started in Phase 2 surface-drilled SA pairs started in mid Added new facilities to handle the increased production. Phase E 1 surface-drilled SA pair started in late 1999.

10 Overview (cont d) Overview Produced Water Recycle (PWR) Plant Started up in Increased recycle rates have ultimately reduced available boiler feed water for steam generation. OVAP Vapex Pilot Started up in September 2003 (reported separately). Phases F & Each is a 750m long surface-drilled SA pair, started-up in mid-november Additional surface facilities installed.

11 Overview 2004 Summary Phase F and wells commenced SA production in March. Production from Phases B, and E was shut-in in August, though steam injection continued in an effort to increase steam chamber pressure. Limited production from November through February Abandoned 24 observation and 10 water disposal wells over Phases A and C. One cased well over each phase was retained for possible future use.

12 over Overall Performance 01Jan04-28Feb05 Oil Produced (m 3 ) Water Produced (m 3 ) Steam Injected (m 3 cwe) NC Injected (e 3 m 3 ) Oil Cut (%) SOR (m 3 /m 3 ) Phase B 10,552 24,135 11, Phase 16,628 52, , Phase E 13,872 44,638 79, Phases F & 45, , , TOTAL 86, , ,

13 over Overall Performance Cumulative to 28Feb05 Oil Produced (e 3 m 3 ) Water Produced (e 3 m 3 ) Steam Injected (e 3 m 3 ) NC Injected (e 3 m 3 ) Oil Cut (%) SOR (m 3 /m 3 ) OOIP (e 3 m 3 ) Oil Recovery (%) Phase B , , , , Phase , , Phase E , Phases F &

14 over Site Oil Production Oil Rate (m 3 /d) Jan-93 Jan-94 Jan-95 Jan-96 Jan-97 Jan-98 Jan-99 Jan-00 Jan-01 Jan-02 Jan-03 Jan-04 Jan-05 B B + B + + E B++E+F+

15 over Site Steam Injection 1,400 1,200 1,000 Steam Rate (m 3 /d) Jan-93 Jan-94 Jan-95 Jan-96 Jan-97 Jan-98 Jan-99 Jan-00 Jan-01 Jan-02 Jan-03 Jan-04 Jan-05 B B + B + + E B++E+F+

16 over Cumulative Bitumen Production 1,500,000 1,400,000 1,300,000 Phase B Phase Phase E Phases F+ 45,600 1,200,000 1,100, ,200 Cumulative Bitumen (m 3 ) 1,000, , , , , , , , , , , ,

17 Phase B Performance Production was shut-in in June 2004, as expected, due to insufficient steam available to maintain chamber pressure through 2003 and into Total days on production in 2004 was 136. Average producing day bitumen rate in 2004 was 77 m 3 /d at a 30% oil cut. Calendar day oil was 28.9 m 3 /d. Total 2004 days on steam injection was 176 at an average producing day rate of 70 T/d and a calendar day rate of 31.4 T/d. Steam shut-in in September. Overall 2004 SOR was 1.09.

18 Phase B Performance (cont d) (cont d) No methane injection in Steam chamber pressure fell to approximately 1,300 kpaa in August, but increased to about 1,400 kpaa by year end. Periodic steam injection could be used to maintain chamber pressure if desired.

19 Phase B Performance 1, Rate (t/d) Field Oil Field Steam ensim Oil ensim Steam Analytical Oil Analytical Steam

20 Phase B Performance Forecast 900 For 0.8 mole % of gas injection with steam and steam alone cases Steam 600 Rate (t/d) steam 2,000 kpa 300 Steam + 0.8mol% gas Oil 2,000 kpa 0.8mol% gas 0 Jan93 Jan94 Jan95 Jan96 Jan97 Jan98 Jan99 Jan00 Jan01 Jan02 Jan03 Jan04 Jan05

21 Phase B Steam-Oil Ratio Steam-Oil-Ratio Field Cumulative

22 Phase B Cumulative Oil Production 1,000, , , , Bitumen (m 3 ) 600, , , Recovery (%) 300, , , Bitumen Recovery

23 Phase Performance Overall Phase performance suffered from decreased steam chamber pressure due to insufficient steam available to maintain chamber pressure through 2003 and into and 2 production was shut-in in August, steam injection continued in an effort to increase chamber pressure. Limited production from November through to February Phase calendar day oil production in 2004 was 42.1 m 3 /d and steam injection was 250 T/d, for an overall SOR of 5.94.

24 Phase Performance (cont d) (cont d) Steam chamber pressure fell to about 1,250 kpaa in August, but increased to approximately 1,450 kpaa by year-end. Phase cumulative recovery of 51.7% is based on reserves calculated for two 750m long well pairs. Actual well lengths for 1I = 186m and 1P = 293m. Well lengths for 2I = 748m and 2P = 740m. Oil recovery from Phase equals that of Phase B when compared on a total effective production well length basis.

25 Phase Performance Effective Liner Length Cumulative Oil Produced to 31ec04 Oil Production per Metre (m) (m 3 ) (m 3 /m) 1P , P , Total Phase , Total Phase B 1, ,

26 Phase Performance Rate (m 3 /d) Field Oil Field Steam 97 Rev. Forecast Oil (High) 97 Rev. Forecast Steam (High) Original Forecast Oil (High) Original Forecast Steam (High)

27 Phase Steam-Oil Ratio Instantaneous Steam-Oil-Ratio Rev. Forecast (High) Original Forecast (High) Field Cumulative

28 Phase Cumulative Oil Production 500, , , , Bitumen (m 3 ) 300, , , Recovery (%) 150, , , Bitumen Recovery

29 Phase E Performance Initially drilled proximal to Phase B in order to observe new chamber development next to a mature steam chamber. Overall recovery is expected to be negatively impacted. Wells started up in 1999 with SAP. Phase E and B steam chambers believed to be in communication since early Steam chamber pressure negatively impacted by the drop in Phase B pressures.

30 Phase E Performance (cont d) Production shut-in in August but steam injection continued through the year. Limited production resumed in November and continued through February calendar day oil was 33.4 m 3 /d and calendar day steam injection was 187 T/d. Steam chamber pressure fell to a low of approximately 1,300 kpaa in September but increased to 1,400 kpaa by year-end.

31 Phase E Performance Rate (m 3 /d) Field Oil Field Steam SA Predicted Oil SA Predicted Steam

32 Phase E Steam-Oil-Ratio Steam-Oil Ratio Field forecast Cumulative

33 Phase E Cumulative Oil Production 160, , , Bitumen (m 3 ) 100,000 80,000 60, Recovery (%) 40, , Bitumen Recovery

34 Phases F & Each phase consists of a 750m horizontal well pair. Injectors completed with 219mm slotted liners, producers with 178mm slotted liners. Initial circulation commenced in November SA production commenced March Post-start-up average 2004 production: F1P 63 m 3 /d oil at 3.4 SOR 1P 73 m 3 /d oil at 3.1 SOR Steam chamber pressures of approximately 2000 kpaa.

35 Phases F & Jan-04 Feb-04 Mar-04 Apr-04 Rate (T/d) May-04 Jun-04 Jul-04 Aug-04 Sep-04 Oct-04 Nov-04 ec-04 Jan-05 Feb-05 SOR Oil Steam SOR

36 Outline Introduction SA Performance Facilities Regulatory Future Plans

37 over SA Process Schematic Raw Water Wells Raw Water Tank Water Treatment Water Filters Sodium Cation Softeners Produced Water Recycle Warm Caustic Softener Recarbonation Tank AfterFilter isposal Wells Natural as Pipeline Produced as Recycle Feed Water Storage Tank Steam eneration 175 mm BTUH Steam Separator Blowdown HT Bitumen / Water Separator Bitumen Treating Flash Separator Storage Tanks Produced Water Treating Skim Tank IF Oil Filter Truck Loading Produced Water Tank 3 Well Pairs Production P I Steam Production Heater Steam Liquid / Vapour Separator Natural as Lift Production Liquid / Vapour Separator UNERROUN FACILITIES Flare Stack I P 5 Surface Well Pairs

38 over PWR Process Schematic MgO NaOH Anti Foam CO 2 Produced Water Feed Tank Coagulant (Aluminium based) Cationic Flocculant Warm Caustic Softener Recarbonation Tank (not in service) Afterfilter Treated Water To SACs Sludge Recycle isposal Wells Sludge Pond

39 Facilities Continued improvements in produced water recycle (PWR) rates through Warm Caustic Softener process continued through All produced water is processed through PWR for silica removal and added filtration. Average water recycle rate in 2004 was 32% (up from 29% in 2003) based on AEUB formula: Recycle % = (Steam Injected Raw Water) Produced Water x 100

40 (cont d) Facilities (cont d) Theoretical maximum with existing equipment is about 60%. Recycle limited due to: Inability to recycle blowdown water (high TS); High TS fouling of SAC resin in boiler feed water conditioning. Increased produced water recycle volumes have caused a reduction in overall available boiler feed water due to incompatibility of recycled water and raw water when combined upstream at softeners. Consequently, about 40% of steam injection capacity was lost in 2003 and early 2004.

41 Facilities (cont d) A new raw water softener was installed and operational by April Mixing of re-cycled produced water with raw water downstream of softening has solved the softening problem. Raw water use increased in 2004 due to: Addition of dedicated raw water filter; Lower produced water volume available for re-use; Maximum steam generation demanded for ongoing operations, re-pressurization and OVAP.

42 over Source & isposal Water Raw Water isposal Water m 3 Raw Water (m 3 ) (m 3 ) m 3 Oil Produced , , , , , , , , ,900 98, , ,

43 over Water isposal & Fresh Water Withdrawal 2,000 1,800 1,600 1,400 Rate (m 3 /d) 1,200 1, Total Water isposal Raw Water Withdrawl Site Oil Production

44 over Fresh Water Use Ratio Raw Water/Steam Inj Raw Water/Oil Prod

45 Cumulative Water isposal into Wabiskaw 4,000,000 3,500,000 3,000,000 Cuml Injection Volume (m 3 ) 2,500,000 2,000,000 1,500,000 1,000, ,

46 Wabiskaw Monitoring Program Wabiskaw Wabiskaw Monitoring Program Monitoring Program AA/3-17/0 AA/6-17/0 AA/14-17/0 AB/11-8/0 C AA/6-8/0 AA/3-8/0 AA/11-8/0 AA/11-17/0 AA/13-8/0 AA/4-17/0 00/8-7/0 AB/9-7/0 AB/1-18/0 AA/8-18/0 AC/9-18/0 AB/16-7/0 H U 02/1-18/2 S V 00/1-18/0 AA/16-6/0 A 02/8-18/0 A/16-7/0 AC/1-18/0 AE/1-18/0 S U S U S U H V H V H V A/1-18/0,AH/1-18/0,AJ/1-18/0,AK/1-18/0,AL/1-18/0,AM/1-18/0 U S U 04/9-18/0,04/9-18/2 AA/16-18/0 AC/16-7/0 S U H U 05/9-18/0,03/9-18/0 AC/9-7/0 AB/8-18/0 AF/1-18/0 C 00/9-18/0 AA/9-7/0 A/1-18/0 AA/1-7/0 H U 02/9-18/0 AA/1-18/0 AA/9-18/0 AB/9-18/0 AA/8-7/0 AB/8-7/0 AA/16-7/0 C 02/7-18/0 00/7-7/0 02/7-7/0 AB/15-6/0 A/15-7/0 AB/2-18/0 AE/2-18/0 S V 03/10-18/0 H V 04/10-18/0 03/7-7/0 C 00/7-18/0 C AB/10-18/0 04/10-7/0 AC/15-7/0 AA/7-18/0 C 06/10-7/0 AF/2-18/0 H V 02/10-18/0 AA/15-18/0 S V 00/10-18/0 AA/10-18/0 03/10-7/0 AB/15-7/0 02/10-7/0 05/10-7/0 00/10-7/0 A 07/10-7/0 AB/15-18/0 A 04/7-7/0 C 00/2-18/0 A/2-18/0 AA/2-18/0 C 03/2-18/0 AC/7-18/0 AA/7-7/0 16/15-7/0 AB/7-18/0 10/15-7/0 15/15-7/0 02/15-7/0 08/15-7/0 A AB/2-7/0 05/15-7/0 AA/2-19/0 C 00/15-18/0 C U C U AE/10-18/0,AF/10-18/0 06/15-7/0 11/15-7/0 09/15-7/0 C A/10-18/0 07/15-7/0 AA/15-7/0 AC/2-18/0 03/15-7/0 04/15-7/0 13/15-7/0 U 02/2-18/0 12/15-7/0 AA/15-6/0 AA/2-7/0 14/15-7/0 AC/10-18/0 C U C U A/10-18/0,AH/10-18/0 AA/14-7/0 AA/3-18/0 AA/6-7/0 AA/3-19/0 C AB/11-18/0 00/14-7/0 A/3-18/0 AC/11-7/0 AA/14-18/0 AA/11-7/0 C 02/11-18/0 C AE/6-18/0 AB/6-18/0 00/6-18/0 00/11-7/0 A/11-7/0 C 00/3-18/0 03/11-7/0 02/11-7/0 C 03/11-18/0 C 04/11-7/0 AE/14-7/0 A/14-7/0 AB/3-18/0 AC/14-7/0 00/15-7/0 AB/14-7/0 AF/3-18/0 AC/6-7/0 AC/3-18/0 C 02/6-18/0 C AF/6-18/0 C A/6-18/0 00/11-18/0 AC/6-18/0 AF/14-7/0 C 03/6-18/0 AA/11-18/0 AB/11-7/0 C A/6-18/0 AB/14-18/0 AA/3-7/0 AE/3-18/0 AA/6-18/0 AB/6-7/0 AA/14-6/0 AB/13-7/0 AA/4-18/0 AA/13-7/0 AB/4-7/0 AA/5-7/0 AA/4-19/0 AA/13-6/0 AA/4-7/0 AB/5-7/0 AA/13-18/0 AA/12-18/0 AA/16-12/0 AA/9-12/0 AA/8-12/0 AA/1-13/0 AA/16-1/0 AA/1-12/0 A AB/16-12/0 A AB/8-12/0 A AB/9-12/0 A AB/1-13/0 A AA/8-13/0 A AA/16-13/0 A AA/9-13/0 AA/15-12/0 AA/15-1/0 AA/7-12/0 B HC BB1 ( W4) is exactly 1 mile east of AA/13-8/0 Shaft 1 O T93 T93 R12W4 R13 R12W4 R13

47 Wabiskaw Pressure & isposal Volume 1,800 1,600 Pressure (kpag) & isposal Vol (m 3 /d) 1,400 1,200 1, Jan93 01Jan94 01Jan95 01Jan96 01Jan97 01Jan98 01Jan99 01Jan00 01Jan01 01Jan02 01Jan03 01Jan04 01Jan05 Shaft 1 Pressure aily isposal BB1 Pressure 102/ / /11-18

48 Outline Introduction SA Performance Facilities Regulatory Future Plans

49 AEUB Approvals Approval A 6809B 6809C E 6809F Expiry 31ec ec ec ec ec Jun Jun Jun Jun2004 Purpose Construct Phase B Extend expiry to 31Jul99 Add Phase & facilities Add Phase E & PWR Inject NC into Phase B Interim extension Continue piloting - rescinded Commercial operating - experimental status removed. Add 3 SA well pairs (Phases F, & H) Removal of confidential status of Phase B & E data on 30Jun2004

50 AEUB Approvals Approval Expiry Rescinded Rescinded Rescinded 30Jun2007 Purpose Water disposal into Wabiskaw. Water disposal into Wabiskaw. Water disposal into Wabiskaw. Water disposal into Wabiskaw. Well WW 26 added in 2004

51 over Regulatory Alberta Environment Reporting over AEPEA Approval No over AEPEA Approval No Air Emissions Reports filed monthly Licensed maximums never exceeded Annual reporting for: Air emissions round water monitoring expanded in 2003 to include annual water sampling and pressure monitoring of the Wabiskaw Industrial waste water and run-off Temporary raw water diversion permit renewed in 2004

52 Regulatory Compliance evon Canada Corporation, to the best of it s knowledge, was compliant with all applicable regulations and approvals pertaining to the over SA Facility in 2004.

53 Outline Introduction SA Performance Facilities Regulatory Future Plans

54 OVER Operator Transition oing Forward April 28, April , 2005

55 over Plans - eneral Transitional Period Smooth transfer of operatorship Maintain status quo in 2005 Minor facility upgrades Regulatory and safety compliance Oil Sands R&

56 over Future evelopment Coordinated resource development plan for combined MacKay River/over area Evaluate technology options Oil Sands R&

57 over Future evelopment Phases B,, and E evelop and test pressure maintenance methods that do not rely on methane or steam injection Abandon Phase B wells and mine in 2006 Operate and E wells to logical end Retain most observation wells to monitor pressure maintenance schemes Oil Sands R&

58 over Future evelopment F & Well-Pairs Options Priority for steam in 2005 Pilot Options Low-pressure SA In situ processes Pump technology Solvent co-injection Oil Sands R&

59 over Future evelopment Solvent Co-Injection Pilot Options F& well pairs, or New well pairs Oil Sands R&