Heavy Oil Presentation for ea y O ese tat o o

RDS Aberdeen

Thursday, May-05-11y, y

Heavy Oil Presentation for RDS Aberdeen

• Conclusions

• Overview of Heavy Oil Growth

• Reserves Growth in Heavy Oil

• What is applicable to North Sea Development?

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 keyy

• North Sea Development with depend upon adaptation of technology for off shore environments such as ;

– ICD (profile control, well intervention)

– Waterfloods at higher water cutsWaterfloods at higher water cuts

– Polymer

World Reserves

300

200

250

rels

100

150

billion

 bar

50

100b

0

Sources: Oil and Gas Journal – Dec 2002, AEUB

Canadian Oil Production

>50% of Canada’s oil production50% of Canada s oil production

5

Development Areas, Alberta/Saskatchewan

Alberta Saskatchewan

P RiAthabasca Oilsands

MiningCSS

Heavy Oil: 10-18°API

Cold Lake area:Peace River Oilsands

Oilsands

Cold Lake Oilsands

CSS, CHOPS

CSS(see cold lake)

API 8-11CHOPSCP

Cold Lake area: <10°APIMajor Cities

Edmonton

Wabiskawdeposits

SAGDCSS(see cold lake)

WATERFLOOD/CHOPSEdmonton

SaskatoonLloydminster

The Heavy

API 13-25 API

Calgary Regina

The Heavy Oil BeltApproximate Oil Viscosity Examples

Cold Lake Lloydminster10-1000 mPa.sAthabasca120-4000 mPa.s

7

Athabasca Oil SandsOver 20 projectsOver 20 projectsin Athabasca Area Alone

Paris 2004 66th EAGE Conference & Exhibition Paris 2004, 66th EAGE Conference & Exhibition, Paris, France

SPE 84144Reserves Growth: Enigma, g ,Expectation, or Fact?

• Richard Baker and Dennis Beliveau

• June 8th, 2004June 8th, 2004

Reserves Growth: Enigma, Expectation, or Fact?Fact?

• Growth in reserves from existing reservoirs has been the prime contributor to reserve additions in most mature basinscontributor 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%growth. The average reserves growth is 1,083%

• This reserve growth can be attributed to:

a) advances in technologya) advances in technology, b) multi-disciplinary reservoir studies,

Focus on Heavy Oil (examined 38 pools)

Heavy Oil - Average Growth Function for Oil Pools Discovered Prior to 1980

18

20

1973 (10 pools)

1977 (8 pools)

Heavy oil fields are very Heavy oil fields are very technology dependent;technology dependent;

14

16

te

1977 (8 pools)

1978 (10 pools)

1979 (10 pools)

US light oil fields

Growth functions

technology dependent;technology dependent;Screw pumps + Screw pumps + hzhz wellswells

10

12

Initi

al E

stim

a US light oil fields

US gas fields

Heavy Oil Averge

functions for USA oil and gas

4

6

8

Mul

tiple

of g

fields

0

2

4

11

0 5 10 15 20 25 30 35 40 45 50Years Since Discovery

Attanasi, E.D. and Root, D.H., “The Enigma of Oil and Gas Field Growth”, AAPG Bulletin, V. 78, No. 3, March 1994.

TECHNOLOGY LEVERAGES

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

Horizontal Wells, Worldwide

(In 1994‐1997 ‐More horizontal wells drilled in Canada than in any other

5000

6000 Est.

drilled in Canada than in any other country)

e

Well over 12000 hz wells tl

4000

5000

Worldwide

currently2000

3000

Wells ‐

0

1000

0

86 88 1990 92 94 96 98 2000Courtesy of

George Stosur

Heavy Oil Primary Productionea y O a y oduct o

Cold Heavy Oil Production(CHOPS), foamy oil y ( ), y

production

Reservoir Mechanisms: Geo-mechanical Effects

Sand Production•enlarged drainage radius

h l–wormholes–dilated zones–cavities

•sand grain flow•liberation of pore blocking materials•clean up of drilling damage•clean up of drilling damage

Up to 400 m in length

Vertical wellbore

Cold Production - An Example

High density perforation 26shots/m,

Cold Production

high explosive chargeProgress cavity (Screw) pumps high fluid rates

Conventional

Production

Conventional Operating Practices

Development Areas, Canada

Alberta          Saskatchewan

Peace River oilsands

Athabasca oilsands

Mining

CSS, CHOPSSAGDoilsands

Wabiskaw 

Cold Lake oilsands

SAGDCSS

SAGDCHOPSCP

Edmonton

depositsSAGD

CHOPS>2000 chops wells

SaskatoonLloydminster

The Heavy Oil Belt

CalgaryRegina

Sand production – field horizontal wells example

SPE 52636, Huang et al., SPE Res. Eng. & Eval., Dec. 1998

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

Field Development Plan; Pelican Lake (Canada)

• Horizontal well development 2900 multilateral hz wells

• Primary with waterflood

• OOIP= 0.6 Bbbl

14 API il i i i fi ld• 14 API oil gravity variation across field

• ~600 cp

N b t ti l d d ti• No substantial sand production

• 12 ft sand thickness

S 15 30%• Sw~15-30%

• φ>30%

• K=500 to 1000mD• K=500 to 1000mD

Pelican Lake 2006

EnCana: Primary then WaterfloodCNRL: Primary

1 mile 

Map of Pelican Lake Field 2008 Data

Encana:1023wells1 mile

2900 mulitlaterals

AnalyzingAnalyzing area:585wells

CNRL:1906wells

miles

6 miles

6 m

• Concept

Horizontal well developmentinjector

with waterflood

14 API oil viscosity~600 cp

Producer lateral

Map of Pelican Lake Field

Encana:1023wells

AnalyzingAnalyzing area:585wells

CNRL:1906wells

miles

6 miles

6 m

Pelican Lake Field Development Time Lapse

UNTITLED PROJECTDATE 1999-1

pJan 1999

Jan 2003

Zoom in to a portion of field

Jan 2006 Nov 2008

Zoom in to a portion of field

Jan 2006 Nov 2008

Pelican Lake Section Production and Injection

60000

70000 250Oil Rate

Water Rate

Water Injection Rate

50000

60000

(Bbl

s/da

y) 200

Wel

l Cou

nt

a e jec o a e

Oil Producer Well Count

Water Injector Well Count

30000

40000

nd In

ject

ion 150

d In

ject

or W

Initial simulationwork

20000

30000

oduc

tion

an

50

100

rodu

cer a

ndwork

0

10000Pro

0

50 P

Dec-95 Dec-97 Dec-99 Dec-01 Dec-03 Dec-05 Dec-07 Dec-09

Date 19000 STBO/d= q(oil) maximum82 bbl/d/well 

Production Composite Plot for Pelican Lake Field20000

2800

LIQUID RATE (P) [m3/day] OIL RATE (P) [m3/day]

540 12

GOR (P) [m3/m3] WOR (P) [m3/m3]

12500

15000

17500

1750

2100

2450

2800

300

360

420

480

540

8

10

12

2500

5000

7500

10000

350

700

1050

1400

60

120

180

240

300

2

4

6

1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 20090

2500

0

350

_TIME_ [Years]1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 20090

60

0

_TIME_ [Years]

25000 X10E3 OIL CUM (P) [mX10E3 WATER CUM X10E3 WC_OIL (P)

15000 1 WATER RATE (I) [m3/day]

15000

17500

20000

22500

175

210

245

280

9000

10500

12000

13500

5000

7500

10000

12500

15000

70

105

140

175

3000

4500

6000

7500

9000

1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 20091/10000

2500

5000

0

35

1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 20090

1500

3000

0

UNTITLED PROJECTDATE 1999-1 OIL CUM (P)MAX: 100/03-24-082-21W4/00 (5815.7 m3)Multiplier=1

Time Lapse Cum Oil Production Bubble Plots

J 1999Jan 2003

Jan 1999

Jan 2006 Nov 2008Nov 2008

UNTITLED PROJECTDATE 1999-1 WATER CUM (P)MAX: 100/16-14-082-21W4/00 (431.5 m3)Multiplier=1

Time Lapse Water Production Bubble Plots

J 1999Jan 2003

Multiplier=1Jan 1999

Jan 2006 Nov 2008Nov 2008

UNTITLED PROJECTDATE 1999-1 WATER CUM (I)

Time Lapse Water Injection Bubble Plots

J 1999Jan 2003

Multiplier=1Jan 1999

Jan 2006 Nov 2008Nov 2008

Chauvin South-Mannville MU #1R3 R2 R1W4

T43

T42

Pool Data for Dina PP pool not Chauvin

• OOIP = 2 09 e6m3 (from ERCB)

Reservoir Properties Area = 350 ha h = 3.2 mOOIP 2.09 e6m3 (from ERCB)

• OGIP (soln’) = 71 e6m3

• Production

h 3.2 m = 25% Swi = 23% Boi = 1.031Production

– Oil: 1.27 e6m3

– Water: 24 94 e6m3

oi Pi = 5778 kPa Pb = 3116 kPa (Standing

correlation)Oil it 29 3 °APIWater: 24.94 e6m3

– Gas : 42.87 e6m3

• Current Oil RF = 60.8%

Oil gravity = 29.3 °API µoil = 15.1 mpa.s Rsi = 20 m3/m3 Fm Temp = 28 °CCurrent Oil RF 60.8%

• Injection

– Water injection: 25.66 e6m3

Fm. Temp = 28 C First production: 1988 Total production wells: 63 Currently active wells : 48Varies

i fi tlWater injection: 25.66 e6m3 Currently active wells : 48signficantlyacross field

With horizontal wells

Without horizontal wells

Historical Production Profile Historical Production Profile for for Chauvin South-Mannville MU #1

Polymerflood of heavy oilPolymerflood of heavy oil• In 1994 IFP recommended the application ofIn 1994, IFP recommended the application of

polymerflood in the Pelican Lake heavy oil field (12 API 900 to 40 000 cp) operated by CS(12 API, 900 to 40,000 cp) operated by CS Resources

• Horizontal wells

Fi t il t i l t d i 1996 97 f il d b• First pilot implemented in 1996-97 failed because of field operational issues

• New pilot implemented in 2005 by CNRL highly successful

From PoweltecPoweltec

Second polymer pilotSecond polymer pilot

1500 m long horizontals200 m spacing

From PoweltecPoweltec

Oil rate

Geowebworks From PoweltecPoweltec

Oil rate

Geowebworks From PoweltecPoweltec

Polymer Flood in Pelican Lake: F ll Fi ld I l t tiFull Field Implementation

HTLP 6 Polymer Pilot Schematic

• 2 injectors, 3 producers

• 1400m long lined horizontals

• 175m inter-well spacing

• Injection commenced May 2005

HTLP 6 Total Pilot Production

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%

Approval 10147 – Expansion of Pilot

Approval 10147 Flood Area

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 keyy

• North Sea Development with depend upon adaptation of technology for off shore environments such as ;

– ICD (profile control, well intervention)

– Waterfloods at higher water cutsWaterfloods at higher water cuts

– Polymer