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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
Recommended