RDS Aberdeen. Thursday, May-05-11

Transcription

1 Heavy Oil Presentation for RDS Aberdeen Thursday, May-05-11

2 Heavy Oil Presentation for RDS Aberdeen Conclusions Overview of Heavy Oil Growth Reserves Growth in Heavy Oil What is applicable to North Sea Development?

3 Conclusions Heavy Oil Reserves Growth is Critical Worldwide Heavy Oil reserve growth critically depends upon technology as well as price Heavy Oil Waterfloods and Polymer floods have been very successful (above initial expections) but reservoir managtement is key North Sea Development with depend upon adaptation of technology for off shore environments such as ; ICD (profile control, well intervention) Waterfloods at higher water cuts Polymer

4 World Reserves rels billion bar b Sources: Oil and Gas Journal Dec 2002, AEUB

5 Canadian Oil Production >50% of Canada s oil production 5

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7 Development Areas, Alberta/Saskatchewan Alberta Saskatchewan CSS, CHOPS Athabasca Peace River Oilsands Oilsands CHOPS CP Wabiskaw deposits Edmonton Lloydminster Mining API 8-11 Cold Lake Oilsands CSS(see cold lake) SAGD WATERFLOOD/CHOPS API API Saskatoon Heavy Oil: API Cold Lake area: <10 API Major Cities Approximate Oil Viscosity Examples Cold Lake Lloydminster mpa.s Athabasca mpa.s Calgary The Heavy Oil Belt Regina 7

8 Athabasca Oil Sands Over 20 projects Over 20 projects in Athabasca Area Alone

9 SPE Paris 2004, 66th EAGE Conference & Exhibition, Paris, France Reserves Growth: Enigma, Expectation, or Fact? Richard Baker and Dennis Beliveau June 8th, 2004

10 Reserves Growth: Enigma, Expectation, or Fact? Growth in reserves from existing reservoirs has been the prime contributor to reserve additions in most mature basins. Out of 202 heavy oil fields 88% of those fields have reserve growth. The average reserves growth is 1,083% This reserve growth can be attributed to: a) advances in technology, b) multi-disciplinary reservoir studies,

11 Focus on Heavy Oil (examined 38 pools) Heavy Oil - Average Growth Function for Oil Pools Discovered Prior to Heavy oil fields are very 18 technology dependent; Screw 16 pumps + hz wells te Initial Estima Multiple of (10 pools) 1977 (8 pools) 1978 (10 pools) 1979 (10 pools) US light oil fields US gas fields Heavy Oil Averge Growth functions for USA oil and gas fields Years Since Discovery 11 Attanasi, E.D. and Root, D.H., The Enigma of Oil and Gas Field Growth, AAPG Bulletin, V. 78, No. 3, March 1994.

12 TECHNOLOGY LEVERAGES

13 Heavy Oil Technical Influences Horizontal/multilateral drilling EOR (thermal/non thermal) Screw pumps/pumping systems are tied to heavy oil reserves growth Most reserve growth is not thermal in the last 15 years

14 Horizontal Wells, Worldwide (In More horizontal wells drilled in Canada thanin anyother country) 6000 Est Worldwide Wells Well over hz wells currently Courtesy of George Stosur

15 Heavy Oil Primary Production o Cold Heavy Oil Production(CHOPS), foamy oil production

16 Reservoir Mechanisms: Geo-mechanical Effects Sand Production enlarged drainage radius wormholes dilated zones cavities sand grain flow liberation of pore blocking materials clean up of drilling damage Up to 400 m in length Vertical wellbore

17 Cold Production - An Example High density perforation 26shots/m, high explosive charge Progress cavity (Screw) pumps high fluid rates Cold Production Conventional Operating Practices

18 Development Areas, Canada Alberta Saskatchewan CSS, CHOPS Peace River oilsands Wabiskaw deposits Edmonton Athabasca oilsands CHOPS CP Mining SAGD Cold Lake oilsands CSS SAGD CHOPS >2000 chops wells Lloydminster Calgary The Heavy Oil Belt Saskatoon Regina

19 Sand production field horizontal wells example SPE 52636, Huang et al., SPE Res. Eng. & Eval., Dec. 1998

20 HEAVY OIL WATERFLOODS/HORIZONTAL WELLS/HZ INJECTORS + POLYMER APPLICATION

21 Field Development Plan; Pelican Lake (Canada) Horizontal well development 2900 multilateral hz wells Primary with waterflood OOIP= 0.6 Bbbl 14 API oil gravity variation across field ~600 cp No substantial ti sand production 12 ft sand thickness Sw~15-30% φ>30% K=500 to 1000mD

22 Pelican Lake 2006 EnCana: Primary then Waterflood CNRL: Primary 1 mile

23 Map of Pelican Lake Field 2008 Data 1 mile Encana:1023wells 2900 mulitlaterals Analyzing area:585wells CNRL:1906wells 6 miles 6 miles

24 Concept Horizontal well development injector with waterflood 14 API oil viscosity~600 cp Producer lateral

25 Map of Pelican Lake Field Encana:1023wells Analyzing area:585wells CNRL:1906wells 6 miles 6 miles

26 Pelican Lake Field Development Time Lapse Jan 1999 UNTITLED PROJECT DATE Jan 2003 Zoom in to a portion of field Jan 2006 Nov2008

27 Pelican Lake Section Production and Injection Oil Rate 250 Water Rate an30000 Pro oduction nd Injection (Bbls/day) Water ae Injection Rate ae Oil Producer Well Count Water Injector Well Count Initial simulation work P50 roducer and Injector Well Count 0 Dec-95 Dec-97 Dec-99 Dec-01 Dec-03 Dec-05 Dec-07 Dec-09 Date STBO/d= q(oil) maximum 82 bbl/d/well 0

28 Production Composite Plot for Pelican Lake Field LIQUID RATE (P) [m3/day] OIL RATE (P) [m3/day] GOR (P) [m3/m3] WOR (P) [m3/m3] _TIME_ [Years] _TIME_ [Years] 0 X10E3 OIL CUM (P) [m WATER CUM WC_OIL (P) WATER RATE (I) [m3/day] /

29 Time Lapse Cum Oil Production Bubble Plots Jan 1999 UNTITLED PROJECT DATE OIL CUM (P) MAX: 100/ W4/00 ( m3) Multiplier=1 Jan 2003 Jan 2006 Nov2008

30 Time Lapse Water Production Bubble Plots Jan 1999 UNTITLED PROJECT DATE WATER CUM (P) MAX: 100/ W4/00 (431.5 m3) Multiplier=1 Jan 2003 Jan 2006 Nov2008

31 Time Lapse Water Injection Bubble Plots Jan 1999 UNTITLED PROJECT DATE WATER CUM (I) Multiplier=1 Jan 2003 Jan 2006 Nov2008

32 Chauvin South-Mannville MU #1 R3 R2 R1W4 T43 T42

33 Pool Data for Dina PP pool not Chauvin Reservoir Properties Area = 350 ha OOIP = 2.09 e6m3 (from ERCB) h = 3.2 m = 25% OGIP (soln ) = 71 e6m3 S wi = 23% Production B oi = P i = 5778 kpa Oil: 1.27 e6m3 P b = 3116 kpa (Standing correlation) Water: e6m3 Oil gravity = 29.3 API Gas : e6m3 µ oil = 15.1 mpa.s R si = 20 m3/m3 Current Oil RF = 60.8% Fm. Temp = 28 C First production: 1988 Injection Total production wells: 63 Varies Water injection: e6m3 Currently active wells :48 signficantly across field

34 With horizontal wells Without horizontal wells Historical Production Profile for Chauvin South-Mannville MU #1

35 Polymerflood of heavy oil In 1994, IFP recommended the application of polymerflood in the Pelican Lake heavy oil field (12 API, 900 to 40, cp) operated by CS Resources Horizontal wells First pilot implemented in failed because of field operational issues New pilot implemented in 2005 by CNRL highly successful From Poweltec

36 Second polymer pilot 1500 m long horizontals 200 m spacing From Poweltec

37 Oil rate Geowebworks From Poweltec

38 Oil rate Geowebworks From Poweltec

39 Polymer Flood in Pelican Lake: Full llfield Implementation ti

40 HTLP 6 Polymer Pilot Schematic 2 injectors, 3 producers 1400m long lined horizontals 175m inter-well spacing Injection commenced May 2005

41 HTLP 6 Total Pilot Production

42 HTLP 6 Pilot Discussion First Polymer Injection in May 2005 Polymer Response March 2006 Average watercuts increased, but remain less than 60% All previous simulation work had predicted substantial polymer breakthrough by now Primary recovery factor was 7.5%, latest incremental polymer flood recovery factor estimate is 15-21%

43 Approval Expansion of Pilot

44 Approval Flood Area

45 Conclusions Heavy Oil Reserves Growth is Critical Worldwide Heavy Oil reserve growth critically depends upon technology as well as price Heavy Oil Waterfloods and Polymer floods have been very successful (above initial expections) but reservoir managtement is key North Sea Development with depend upon adaptation of technology for off shore environments such as ; ICD (profile control, well intervention) Waterfloods at higher water cuts Polymer