EOR in Fractured Carbonate Reservoirs
– low salinity low temperature conditions
By
Aparna Raju Sagi, Maura C. Puerto,
Clarence A. Miller, George J. Hirasaki
Rice University
Mehdi Salehi, Charles Thomas
TIORCO
April 26, 2011
Outline
• EOR strategy for fractured reservoirs
• Evaluation at room temperature (~25 °C)
o
o
o
o
Phase behavior studies – surfactant selection
Viscosity measurements
Imbibition experiments
Adsorption experiments
• Evaluation at 30 °C and live oil
o Phase behavior experiments
o Imbibition experiements
• Conclusions
2
EOR strategy
3
EOR strategy
• Reservoir description
o Fractures – high permeability paths
o Oil wet – oil trapped in matrix by capillarity
o Dolomite, low salinity, 30 °C
• Recover oil from matrix spontaneous imbibition
o IFT reduction
• Surfactants
o Wettability alteration
• Surfactants
• Alkali
Ref: Hirasaki et. al, 2003
4
Current focus – IFT reduction – surfactant flood
• Surfactant flood desirable characteristics
o Low IFT (order of 10-2 mN/m)
o Surfactant-oil-brine phase behavior stays underoptimum
o Low adsorption on reservoir rock (chemical cost)
o Avoid generation of viscous phases
o Tolerance to divalent ions
o Solubility in injection and reservoir brine
o Easy separation of oil from produced emulsion
5
Phase behavior studies
at ~ 25 °C
6
Procedure
Seal open
end
24 hr
Oil
Initial
interface
Brine +
surfactant
Parameter
• Salinity
• Surfactant blend ratio
• Soap/surfactant ratio
micro
Varying parameter
micro
Pipette
(bottom sealed)
Winsor Winsor Winsor
Type - I Type - III Type - II
Optimal parameter
7
𝜎mo
𝜎mw
middle
Vo/Vs
Vw/Vs
upper
Solubilization parameter
lower
IFT, mN/m
Phase behavior, IFT, solubilization parameter
Salinity, wt% NaCl
Reed et al. 1977
8
Phase behavior
• Purpose of phase behavior studies
o Determine optimal salinity, Cø
• transition from Winsor Type I to Winsor Type II
o Calculate solubilization ratio, Vo/Vs and Vw/Vs
o Detect viscous emulsions (undesirable)
• Parameters
o
o
o
o
o
Salinity – 11,000 ppm (incl Ca, Mg)
Surfactant type, Blend ratio (2 surfactants)
Oil type – dead oil vs. live oil
Water oil ratio (WOR)
Surfactant concentration
9
1
1.1
1.2 1.3 1.4 1.5 1.6 1.7 1.8
1.9
Brine2
4wt%
optimal salinity
S13D
Salinity scan
(Multiples of Brine2)
WOR ~ 1
Vo/Vs~ 10 at reservoir salinity
optimal salinity
0.5wt%
optimal salinity
0.25wt%
10
Viscosity studies
at ~ 25 °C
11
Viscosities of phases – function of salinity
0.5 wt% S13D
upper phase 16d
Viscosities of phases as function
of salinity for S13D 0.5 wt%
middle section 16d
reservoir salinity
Viscosity (cP)
Optimal salinity
1000
100
optimal salinity
lower phase 16d
0.4
cm
0.3
cm
0.1
cm
Oil
Oil
10
1
0.8
1
1.2
1.4
salinity (multiples of Brine 2)
0.84 0.94 1.05 1.15 1.26 1.36 1.47
Multiples of Brine 2
12
Imbibition studies
at ~ 25 °C
13
Imbibition results – S13D reservoir cores (1”)
80
S13D 0.5wt% 126md
70
Recovery (% OOIP)
60
50
40
S13D 0.25wt% 151md
30
20
10
0
0
20
40
60
80
100
Time (days)
Mehdi Salehi, TIORCO
14
S13D candidate for EOR
o under-optimum at reservoir salinity
o stays under-optimum upon dilution
o Vo/Vs~10 (at 4wt% surfactant concentration)
indicative of low IFT
o No high viscosity phases at reservoir salinity
o ~ 70% recovery in imbibition tests
15
Adsorption studies
at ~ 25 °C
16
Dynamic adsorption – procedure
• Sand pack
o Limestone sand ~ 20-40 mesh
o Washed to remove fines & dried in oven
• Core holder
o Core cleaned with Toluene, THF, Chloroform, methanol
o Core holder with 400 – 800psi overburden pressure
• Vacuum saturation (~ -27 to -29 in Hg)
o measure pore volume
• Permeability measurement
17
Dynamic adsorption - setup
Syringe pump/
ISCO pump
Core holder/ Sand pack
Bromide
electrode
Bromide
concentration
reading
Pressure
monitoring
Pressure
transducer
Sample
collection
18
Limestone sandpack ~ 102D
• Injection solution: Brine 2 with 1000ppm Br - + 0.5wt% S13D
• Flow rate: 12.24ml/h
• Pore volume: 72 ml, Time for 1PV ~ 6hrs
1PV
2PV
• 1PV = .38 ft3/ft2
• Lag ~ 0.14 PV
• Adsorption
0.26 mg/g sand
0.12 mg/g reservoir
rock
19
Reservoir core – 6mD
• Injection solution: Brine 2 with 1000ppm Br - + 0.5wt% S13D
• Flow rate: 2ml/h
• Pore volume: ~12 ml, Time for 1PV ~ 6hrs
3PV
4PV
day 3
2PV
day 1
1PV
• 1PV = .035 ft3/ft2
• Effective pore size
= 26.8𝜇m
• Lag ~ 0.54PV to
1.25PV
• Adsorption
0.12 mg/g rock to
0.28 mg/g rock
20
Reservoir core – 6mD plugging
1PV
9
2PV
3PV
4PV
5PV
Expected pressure drop @ 15ml/hr
8
Absence of
surfactant
pressure (psi)
7
6
5
Presence of surfactant – dyn ads exp
4
day 1
3
2
day 3 – no data
day 11
Expected pressure drop @ 2ml/hr
1
0
0
10
20
30
40
volume produced (ml)
50
60
21
HPLC analysis of effluent
1PV
1PV
2PV
2PV
3PV
3PV
4PV
4PV
HPLC sample
day 3
day 1
diff in area ~ 21 %
By Yu Bian
22
Reservoir core – 15mD
• 2 micron filter @ inlet – pressure monitored
• Injection solution: Brine 2 with 1000ppm Br - + 0.5wt% S13D
• Flow rate: 1ml/h, Pore volume: ~30 ml, Time for 1PV ~ 1.25 days
1PV
2PV
3PV
4PV
5PV
HPLC sample
Bromide
Surfactant
• 1PV = .103 ft3/ft2
• Effective pore size
= 11.8𝜇m
• Lag ~ 0.67PV
• Adsorption
0.29 mg/g rock
16
15
14
10
9
8
7
6
3
4
2
day1
Pressure
23
HPLC analysis of effluent
diff in area ~ 25 %
By Yu Bian
24
Adsorption results comparison
Experiment
Material
Equivalent
adsorption on
reservoir rock
(mg/g)
Residence time
(hrs)
Dynamic
Limestone sand
0.12
6
Dynamic
Dolomite core
6mD
0.12 – 0.28
6 - overnight
Dynamic
Dolomite core
15mD
0.29
30
Static
(by Yu Bian)
Dolomite powder
0.34
24
25
Phase behavior studies
at ~ 30 °C
26
S13D phase behavior
S13D 1wt% @ 25 °C
S13D 1wt% @ 30 °C
Type I microemulsion
Type II microemulsion
S13D 1wt% @ 30 °C
with live oil (600 psi)
Type II microemulsion
27
S13D/S13B blend scan 30°C
Optimal blend
Brine 2 salinity; 2 wt% aq; WOR = 1
10/0
S13D
9/1
8/2
7/3
6/4 5/5
4/6
S13D/S13B ratio
3/7
2/8
1/9 0/10
S13B
28
5
5
4
4
3
3
2
2
1
1
0
0
Phase behavior
S13D/S13B blend
With dead oil @ 30 °C
% Cs
S13D 10 9
S13B 0 1
8
2
7
3
6
4
Aqueous stability test of
S13D/S13B blend
5
5
4
6
3
7
50
2
8
1
9
0
10
50
40
40
°C 30
30
20
20
10
10
0
S13D 10 9
S13B 0 1
0
8
2
7
3
6
4
5
5
4
6
3
7
2
8
1
9
0
10
29
S13D/S13B (70/30) – dead vs live crude @ 30 °C
Dead oil – UNDER-OPTIMUM
After mixing &
settling for 1 day
Live oil – OVER-OPTIMUM
Before mixing
After mixing &
settling for 1 day
30
Imbibition studies
at ~ 30 °C
31
Imbibition results –reservoir cores (1”)
S13D 0.5wt% 126mD, 25 °C
S13D/S13B 70/30 1wt% 575mD, 30 °C
S13D 0.25wt% 151mD 25 °C
S13D/S13B 60/40 1wt% 221mD, 30 °C
Mehdi Salehi, TIORCO
32
Conclusions
33
Conclusions
• Dynamic adsorption experiments (absence of oil)
o Effluent surfactant concentration plateaus at ~80%
injected concentration
o Higher PO components are deficient in the effluent
sample (in plateau region)
o Increase in pressure drop with volume throughput
• Sensitivity of phase behavior to temperature and oil
(dead vs. live)
• S13D/S13B 70/30 @ 30 °C performance poor
compared to S13D @ 25 °C
34
Questions
35