University of Regina
Petroleum Systems Engineering
F. Torabi, A. Qazvini Firouz, University of Regina, Canada, IEA-EOR-2010 1
Increasing Temperature of Injection Water to
Improve Heavy Oil Recovery
Farshid Torabi, Ph.D., P. Eng., University of Regina
Alireza Qazvini Firouz, Graduate Student, University of Regina
University of Regina
Petroleum Systems Engineering
F. Torabi, A. Qazvini Firouz, University of Regina, Canada, IEA-EOR-2010 2
Outline
Objective
Introduction
Reservoir Properties
Fluid Properties
Reservoir Simulation Model
Results and Discussions
Effect of Well Spacing and Injection Rate
Conclusion
University of Regina
Petroleum Systems Engineering
F. Torabi, A. Qazvini Firouz, University of Regina, Canada, IEA-EOR-2010 3
To investigate the feasibility of hot waterflooding as an alternative to SAGD for oil recovery from thin heavy oil reservoirs
To compare the performance of hot waterflooding with the conventional waterflood
To find out the range of applicability of hot waterflooding from reservoir and fluid characteristic s, well spacing, and perhapsoperating conditions
Objectives
University of Regina
Petroleum Systems Engineering
F. Torabi, A. Qazvini Firouz, University of Regina, Canada, IEA-EOR-2010 4
Source: http://alneft.com/wp-content/uploads/2010/07/trends_graph_distribution_oil.gif
Introduction
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F. Torabi, A. Qazvini Firouz, University of Regina, Canada, IEA-EOR-2010 5
Source: http://www.petroleumequities.com/FigureIA.jpg
Introduction
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F. Torabi, A. Qazvini Firouz, University of Regina, Canada, IEA-EOR-2010 6
Reservoir and Fluid Properties
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F. Torabi, A. Qazvini Firouz, University of Regina, Canada, IEA-EOR-2010 7
Depth, m 600
Net pay, m 6
Porosity, % 33
Porosity reference pressure, kPa 1400
Permeability, mD 2000
Initial water saturation, % 19
Oil gravity, API 10.6
Tank oil viscosity (21 oC) 20550
Initial reservoir viscosity (22 oC, 3500 kPa) 13434
Initial reservoir temperature, oC 22
Initial reservoir pressure, kPa (psi) 3500 (500)
Bubble point pressure, kPa (psi) 3500 (500)
Formation compressibility, 1/kPa 5.00E-06
Initial formation volume factor,res m3/stock-tank m3 (res bbl/STB)
1.02 (1.02)
Relative Permeability end points Sw=0.18, Krow=0.86
Sw=0.67, Krw=0.25
Reservoir and Fluid Properties
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Petroleum Systems Engineering
F. Torabi, A. Qazvini Firouz, University of Regina, Canada, IEA-EOR-2010 8
T- Dependent coefficient, J/(m3×C×C) 2715
Thermal conductivity
Reservoir rock, J/(m×day×C) 43201
Oil phase , J/(m×day×C) 11319
Water phase, J/(m×day×C) 56161
Gas phase, J/(m×day×C) 1500
Overburden, J/(m×day×C) 224158
Underburden, J/(m×day×C) 224158
Volumetric heat capacity
Overburden, J/(m3×C) 2084322
Underburden, J/(m3×C) 2084322
Reservoir and Fluid Properties
University of Regina
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F. Torabi, A. Qazvini Firouz, University of Regina, Canada, IEA-EOR-2010 9
Experimental data for Oil-A: API=10
Temperature C Viscosity, cp Density, Kg/m3
15 60970 999.2
21 30510 996.2
31 8870 989.2
Experimental data for Oil B: API=10.6
Temperature C Viscosity, cp Density, Kg/m3
15 37070 995.1
21 20550 992.5
31 6105 985.5
Experimental data for Oil C: API=11.4
Temperature C Viscosity, cp Density, Kg/m3
15 21400 989.3
21 11620 986.3
31 3760 979.4
Fluid Properties
University of Regina
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F. Torabi, A. Qazvini Firouz, University of Regina, Canada, IEA-EOR-2010 10
Regression Results, API=10
0
10000
20000
30000
40000
50000
60000
70000
0 10 20 30 40
Temperature, C
Vis
cosi
ty, c
p
Viscosity Calculated
Viscosity Experimental
Regression Reults, API=10
988
990
992
994
996
998
1000
0 10 20 30 40
Temperature, C
Den
sity
, Kg/
m3
Density Calculated
Density Experimental
Fluid Properties Comparison between simulation (CMG-winprop) and
experimental results for oil viscosity and density
University of Regina
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F. Torabi, A. Qazvini Firouz, University of Regina, Canada, IEA-EOR-2010 11
Phase Properties, API= 10
0
2,000
4,000
6,000
8,000
10,000
12,000
0 50 100 150 200 250
Temperature (deg C)
Liqu
id V
isco
sity
(cP)
Phase Properties, API=10.6
0
2000
4000
6000
8000
10000
0 50 100 150 200 250
Temperature (deg C)
Liqu
id V
isco
sity
(cP)
Fluid Properties Predicted values of oil viscosity as a function of
temperature for 3 oil samples.
Phase Properties, API=11.4
0
1000
2000
3000
4000
5000
0 50 100 150 200 250
Temperature (deg C)
Liq
uid
Vis
cosi
ty (
cP)
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Petroleum Systems Engineering
F. Torabi, A. Qazvini Firouz, University of Regina, Canada, IEA-EOR-2010 12
Five-Spot Pattern as a base case:
(3 base cases for 3 oil samples)
The size of area modeled is
500m x 500m x 6m.
grid block size was
16.7m x16.7m x 1m
Nine point fluid flow
Simulation Model
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F. Torabi, A. Qazvini Firouz, University of Regina, Canada, IEA-EOR-2010 13
Five-Spot Pattern as a base
case:
Nine point fluid flow
Simulation Model
University of Regina
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F. Torabi, A. Qazvini Firouz, University of Regina, Canada, IEA-EOR-2010 14
Simulation Model
Injection rate was set as the main constraint.
considering shallow reservoirs of unconsolidated sands
at a depth of about 600m, a low fracturing pressure is
often associated.
For this case, fracturing pressure was estimated to be
more than 7500kPa.
To avoid damaging the reservoir particularly at higher
temperature, bottom hole pressure was set to a
maximum of 7000kPa as the secondary constraint.
University of Regina
Petroleum Systems Engineering
F. Torabi, A. Qazvini Firouz, University of Regina, Canada, IEA-EOR-2010 15
Simulation ModelFor all three base cases:
homogenous reservoir
identical reservoir characteristics
injection rate of 25 m3/day
injection temperature of 22oC
higher production rate and recovery for 11.4 API
oil sample as lighter oil
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Petroleum Systems Engineering
F. Torabi, A. Qazvini Firouz, University of Regina, Canada, IEA-EOR-2010 16
Results and DiscussionsConventional Waterflooding (22oC)
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F. Torabi, A. Qazvini Firouz, University of Regina, Canada, IEA-EOR-2010 17
Well-1 Well-2
Well-3Well-4
Well-5
0 100 200 300 400 500
0 100 200 300 400 500
-400-300
-200-100
-500
-400
-300
-200
-100
0
0.00 255.00 510.00 feet
0.00 80.00 160.00 meters
21.91
22.03
22.15
22.28
22.40
22.52
22.65
22.77
22.89
23.02
23.14
Temperature (C) 2020-01-01 K layer: 1
Well-1 Well-2
Well-3Well-4
Well-5
0 100 200 300 400 500
0 100 200 300 400 500
-400-300
-200-100
-500
-400
-300
-200
-100
0
0.00 255.00 510.00 feet
0.00 80.00 160.00 meters
10,095
10,128
10,160
10,192
10,225
10,257
10,290
10,322
10,355
10,387
10,419
Oil Viscosity (cp) 2020-01-01 K layer: 1
Results and DiscussionsConventional Waterflooding (22oC)
University of Regina
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F. Torabi, A. Qazvini Firouz, University of Regina, Canada, IEA-EOR-2010 18
Results and DiscussionsHot Waterflooding (up to 150oC)
University of Regina
Petroleum Systems Engineering
F. Torabi, A. Qazvini Firouz, University of Regina, Canada, IEA-EOR-2010 19
Injection Rate,
m3/d
Injection
Temperature, oCRecovery factor, %
Cumulative Oil
Produced, m3
25
22
Less than 1% About 310080
150
Results and DiscussionsHot Waterflooding of base case models with injection
water temperature of up to 150oC
University of Regina
Petroleum Systems Engineering
F. Torabi, A. Qazvini Firouz, University of Regina, Canada, IEA-EOR-2010 20
Well Configuration Injection
Rate, m3/d
Injection
Temperature, oC
Recovery
Factor, %
4 Vertical Injector & 1Horizontal
Producer25 150 5.0
4 Vertical Prod. & 1 Horizontal Inj. 25 150 0.46
9 Vertical Producer & 4 Vertical Injector 25 150 2.3
3 Horizontal Produce & 2 Horizontal
Injector25 150 7.8
3 Horizontal Producer & 2 Horizontal
Injector50 150 9.2
3 Horizontal Producer & 2 Horizontal
Injector100 150 13.0
3 Horizontal Prod. & 2 Horizontal Inj. 200 150 24.0
Results and DiscussionsHot Waterflooding of different well arrangements with
injection water temperature of 150oC-To find the best case
University of Regina
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F. Torabi, A. Qazvini Firouz, University of Regina, Canada, IEA-EOR-2010 21
Well-1
Well-10 Well-11
Well-12Well-13
Well-2
Well-3Well-4
Well-5
Well-6
Well-7
Well-8 Well-9
0 100 200 300 400 500
0 100 200 300 400 500
-40
0-3
00
-20
0-1
00
-50
0-4
00
-30
0-2
00
-10
00
0.00 255.00 510.00 feet
0.00 80.00 160.00 meters
22
35
47
60
73
85
98
111
123
136
149
Temperature (C) 2020-01-01 K layer: 1
Well-1
Well-10 Well-11
Well-12Well-13
Well-2
Well-3Well-4
Well-5
Well-6
Well-7
Well-8 Well-9
0 100 200 300 400 500
0 100 200 300 400 500
-40
0-3
00
-20
0-1
00
-50
0-4
00
-30
0-2
00
-10
00
0.00 255.00 510.00 feet
0.00 80.00 160.00 meters
10
1,035
2,060
3,085
4,110
5,135
6,160
7,185
8,210
9,235
10,260
Oil Viscosity (cp) 2020-01-01 K layer: 1
Hot Waterflooding of different well arrangements with
injection water temperature of 150oC-To find the best case
Results and Discussions
University of Regina
Petroleum Systems Engineering
F. Torabi, A. Qazvini Firouz, University of Regina, Canada, IEA-EOR-2010 22
Well-1 Well-2Well-3Well-4 Well-5
0 100 200 300 400 500
0 100 200 300 400 500
-40
0-3
00
-20
0-1
00
-50
0-4
00
-30
0-2
00
-10
00
0.00 255.00 510.00 feet
0.00 80.00 160.00 meters
22
35
47
60
73
86
98
111
124
137
149
Temperature (C) 2020-01-01 K layer: 3
Well-1 Well-2Well-3Well-4 Well-5
0 100 200 300 400 500
0 100 200 300 400 500
-40
0-3
00
-20
0-1
00
-50
0-4
00
-30
0-2
00
-10
00
0.00 255.00 510.00 feet
0.00 80.00 160.00 meters
11
1,550
3,089
4,627
6,166
7,705
9,244
10,783
12,322
13,861
15,400
Oil Viscosity (cp) 2020-01-01 K layer: 3
Results and Discussions2 Horiz. Prod. & 2 Horiz. Inj. (Injection rate of 200 m3/day
and temperature at 150°C)
3 Horiz. Prod. & 2 Horiz. Inj. (Injection rate of 200 m3/day
and temperature at 150°C)
University of Regina
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F. Torabi, A. Qazvini Firouz, University of Regina, Canada, IEA-EOR-2010 23
Well ConfigurationWells
Spacing, m
Maximum
Injection pressure , kPa
Recovery
Factor, %
2 Horizontal Producers & 1
Horizontal Injectors250 7000 7.0
3 Horizontal Producers & 2
Horizontal Injectors117 7000 54.0
4 Horizontal Producers & 4
Horizontal Injectors67 7000 60.0
2 Horizontal Producers & 1
Horizontal Injectors250 7000 3.74
3 Horizontal Producers & 2
Horizontal Injectors117 7000 8.98
4 Horizontal Producers & 4
Horizontal Injectors67 7000 16.96
Hot Waterflooding
Conventional Waterflooding
Results and Discussions
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F. Torabi, A. Qazvini Firouz, University of Regina, Canada, IEA-EOR-2010 24
Results and Discussions3 Horiz. Prod. & 2 Horiz. Inj. (Injection rate of 200 m3/day
and temperature at 150°C)
University of Regina
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F. Torabi, A. Qazvini Firouz, University of Regina, Canada, IEA-EOR-2010 25
3 Horiz. Prod. & 2 Horiz. Inj. (Effect of Well Spacing)
Results and Discussions
117m Spacing Injecting 400m3/day
0%
2%
4%
6%
8%
10%
12%
14%
16%
18%
20%
2009 2010 2011 2012 2013 2014 2015 2016 2017 2018
Time
Rec
over
y Fa
ctor 22 C
40 C
60 C
80 C
100 C
100m Spacing Injecting 400m3/day
0%
5%
10%
15%
20%
25%
30%
2009 2010 2011 2012 2013 2014 2015 2016 2017 2018
Time
Rec
ov
ery
Fac
tor
22 C
40 C
60 C
80 C
100 C
67m Spacing Injecting 400m3/day
0%
5%
10%
15%
20%
25%
30%
35%
40%
2009 2010 2011 2012 2013 2014 2015 2016 2017 2018
Time
Rec
over
y F
acto
r
22 C
40 C
60 C
80 C
100 C
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F. Torabi, A. Qazvini Firouz, University of Regina, Canada, IEA-EOR-2010 26
Results and Discussions3 Horiz. Prod. & 2 Horiz. Inj. (Effect of Injection Rate)
University of Regina
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F. Torabi, A. Qazvini Firouz, University of Regina, Canada, IEA-EOR-2010 27
Simulation results showed that hot waterflooding can be
promissing if implemented correctly
Water injectivity was considerably higher for hot
waterflooding (without exceeding fracturing press.)
Higher rates swept the reservoir producible oil in a
shorter time
Through the application of horizontal wells, higher
recovery factor can be obtained
Well spacing, and injection rate are key parameters in the
success of hot waterflooding and must be optimized
Conclusion
University of Regina
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F. Torabi, A. Qazvini Firouz, University of Regina, Canada, IEA-EOR-2010 28
The financial support provided for this research
was provided by the Petroleum Technology
Research Center (PTRC), Regina, and the
Faculty of Graduate Studies and Research at the
University of Regina.
Acknowledgement
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F. Torabi, A. Qazvini Firouz, University of Regina, Canada, IEA-EOR-2010 29
Thank You For Your Attention
