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Low Salinity Waterflooding
An Overview of Likely Mechanisms
Jill Buckley
EORI contractorAdjunct, Dept. of Chem. and Petroleum Eng.
15 January 2009
http://eori.uwyo.edu
• Additional oil recovered from some (but not all) sandstone cores.
• In studies with high permeability Berea sandstone cores, additional oil was recovered if and only if:
core contained connate water
oil phase was a crude oil
core was not “fired” to remove clays
Observations on Low Salinity Waterflooding
Recovery (% OOIP)Connate HS MS LS
Injected
HS 50 65 80
MS 50 71
LS 56 80
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0
20
40
60
80
100
0 5 10 15 20 25 30 35
Brine injected, PV
Rf,
%O
OIP
0
2
4
6
8
10
12
14
ΔP (p
si) o
r pH
Test A:R1/C1WP crude oil, Swi = 40.6%q = 2.6 ft/D
R
ΔP
pH
RIB(29,690 ppm)
LSB(1,480 ppm)
16.2%
Low Salinity Waterflooding
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Low Salinity Flooding MechanismsUniversity of Wyoming Mechanism Workshop
12 – 23 May 2008Laramie, WY
Outside Experts:
Geoff Mason U Loughborough
Koichi Takamura BASF
Andrew Fogden Australian Nat U
Norman Morrow, Xina Xie, Li Yu, Jill BuckleyNina Loahardjo, Wang Wei, Pu Hui, Xiuyu Wang
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Suggested Mechanisms• Osmotic pressure
• Limited release of mixed-wet particles
• Salinity shock
• Mineral dissolution
• Emulsification/snap-off
• Saponification
• Particle-stabilized interfaces/lamellae
• Multicomponent ion exchange
• Surfactant-like behavior
• Wettability alteration (more water-wet)
• Wettability alteration (less water-wet)
• Viscosity ratio
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In a porous medium, there are multiple solid and fluid phases.
Properties of interfaces between these phases change as brine composition changes.
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Proposed Mechanism
Description: Evidence for:
Evidence against: Experiments needed:
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Osmotic Pressure
Description: Evidence for:
Evidence against: Experiments needed:
Rock may act as a semi- permeable membrane.
+ΔP usually associated with low salinity injected brine and increased recovery.
Increase only observed for crude oils--no increase in recovery with mineral oil
Low salinity of both connate and injected water gives very high recovery even though there is no change in salinity.
high salinityoillow salinity
Tube with corners:
Flow of oil plug depends on whether water can flow around the oil drop or high salinity phase expands.
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Limited Release of Mixed-Wet Particles
Description: Evidence for:
Evidence against: Experiments needed:
Tang and Morrow (1999)p
oil
water
solid
clays
oil
clay
oil
oilwater
solid
Fines not seen in all experiments, especially BP reservoir conditions tests.
Tests to find and identify mixed-wet particles.
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Salinity Shock
Description: Evidence for:
Evidence against: Experiments needed:
Changes in flowing aqueous phase composition can be amplified by step changes in injected compositions.
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Vaiyda and Fogler, 1992
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Salinity Shock
Description: Evidence for:
Evidence against: Experiments needed:
Changes in flowing aqueous phase composition can be amplified by step changes in injected compositions.
Often see increase ΔP and recovery with step decrease in salinity.
Secondary recovery is better for low salinity, without salinity shock.
Additional investigation of salinity gradient effects.
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Mineral Dissolution
Description: Evidence for:
Evidence against: Experiments needed:
Reducing salinity increases solubility of some minerals.
Tensleep core, which does not contain clay, responds to low salinity waterflooding. Cement dissolution may release dolomite particles.
Micro CT visualization and AFM force measurements are in progress at ANU.
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Tensleep rock
quartz
dolomite
Swi =20% φ=14% k=14md (HSB); 9.5 md (LSB)
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Registration[1]Size 762x460x573Dry: P=7.7%; Q=79.6%; D+A=12.6%Wet: P=7.6%; Q=79.6%; D+A=12.7%
[1] Latham, S, Varslot, T & Sheppard, A. P., 2008. Image registration in Micro-CT experiments, to be submitted to the Proceedings of the Society of Core Analysts
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Emulsifcation/Snap-off
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5
10
15
20
25
30
35
40
45
50
55
5 15 25 35 45 55
Predicted API
°API
1.4
1.42
1.44
1.46
1.48
1.5
1.52
1.54
1.56
1.58
1.6
5 15 25 35 45 55
RI@
20°C
0
2
4
6
8
10
12
0 10 20 30 40 50 60
API Gravity
mg
KO
H /
g oi
l
0
2
4
6
8
10
12
0 10 20 30 40 50 60
API Gravity
mg
KO
H /
g oi
l
Crude Oil Composition ~ 300 Samples
ACID NUMBER
BASE NUMBER
RI vs °API
SARA vs °API
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5
10
15
20
25
30
35
40
45
50
55
5 15 25 35 45 55
Predicted API
°API
1.4
1.42
1.44
1.46
1.48
1.5
1.52
1.54
1.56
1.58
1.6
5 15 25 35 45 55
°API
RI@
20°C
0
2
4
6
8
10
12
0 10 20 30 40 50 60
API Gravity
mg
KO
H /
g oi
l
0
2
4
6
8
10
12
0 10 20 30 40 50 60
API Gravity
mg
KO
H /
g oi
l
Wyoming Crude Oil Composition (20 samples)
ACID NUMBER
BASE NUMBER
RI vs °API
SARA vs °API
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The Way Forward
Can we find a model rock?Reservoir cores often respond to low salinity waterflooding, but are hard to obtain, limited in quantity, heterogeneous, and sometimes poorly consolidated.
Outcrop rocks have some advantages, but have been exposed to oxidation and to low salinity rainwater. Some Berea cores (higher permeability) respond to low salinity waterflooding, but the core material that is currently available from the quarry is lower in permeability and does not respond consistently.
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The Way Forward
Address baseline problem in reservoir cores
Response to low salinity my be greater in a secondary waterflood than in tertiary mode, but the baseline is shifting.
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The Way Forward
Fundamental studies
Can we create a micromodel that includes kaolinite?
Force measurements in low and high salinity environments.
Micro CT visualization of particle movement.
http://eori.uwyo.edu
The Way Forward
Suggestions for improved laboratory procedures
Add back pressure regulation
Add pressure measurements in imbibition tests
Low Salinity Waterflooding
An Overview of Likely Mechanisms
Jill Buckley
EORI contractorAdjunct, Dept. of Chem. and Petroleum Eng.
15 January 2009
http://eori.uwyo.edu
Viscosity Ratio
Description: Evidence for:
Evidence against: Experiments needed:
Is kaolin dispersed in brine or formation of emulsions increasing viscosity and sweep efficiency?
Use glycerol to viscosify brine or toluene to reduce oil viscosity.
Use a back pressure regulator to facilitate use of low viscosity oils.
http://eori.uwyo.edu
Saponification
Description: Evidence for:
Evidence against: Experiments needed:
If pH of flowing aqueous phase is high enough, saponification of esters from the oil phase can cause mass transfer from oil to water and decrease IFT.
We are not seeing consistent increases in pH and pH never gets high enough to release fines or reduce IFT significantly.
An increase in pH was observed in early low salinity tests.
ester + NaOH = alcohol + organic acid
Characterization of effluent brine composition.
Crude oil compositional information.
http://eori.uwyo.edu
Surfactant-like Behavior
Description: Evidence for:
Evidence against: Experiments needed:
Increasing temperature should have the same effect.
Tor Austad says adsorbed materials are surfactants, salted out by high salinity that comes off the surface in low salinity water, forms micelles or is transferred to the oil phase. Calls this “salting in.”
mixed wettingsolid
water
oil
decreasesalinity
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Multicomponent Ion Exchange
Description: Evidence for:
Evidence against: Experiments needed:
BP patent: [Ca2+]inj / [Ca2+]connate < 1
Lager et al., 2006; BP patent, 2007
Secondary results for Injected = Connate.Recovery is better with low salinity even though ion exchange has already taken place.
Evidence of Ca2+ in oil? Difficult to measure.
0
5000
10000
15000
20000
25000
0 1 2 3 4 5 6 7Pore volume
Chl
orid
e co
ncen
trat
ion
(ppm
)
0
10
20
30
40
50
60
70
Mag
nesi
um c
once
ntra
tion
(ppm
)
Chloride Mg
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0
5
1 0
1 5
2 0
2 5
3 0
3 5
4 0
bene
fit c
ompa
re to
w
ater
flood
resu
lts (%
)
1 2 3 4 5 6 8 9 10 11 12 13 14 15 16 17 18
Low Salinity WaterfloodingSlide Number 2Slide Number 3Slide Number 4Slide Number 5Slide Number 6Slide Number 7Slide Number 8Slide Number 9Slide Number 10Slide Number 11Slide Number 12Slide Number 13Tensleep rockRegistration[1]Slide Number 16Slide Number 17Slide Number 18Slide Number 19Slide Number 20Slide Number 21Slide Number 22Low Salinity WaterfloodingSlide Number 24Slide Number 25Slide Number 26Slide Number 27Slide Number 28