E N H A N C E D O I L R E C O V E R Y I N S T I T U T E
Improved Oil Recovery by Waterflooding
Nina LoahardjoPetrophysics and Surface Chemistry Group
Chemical and Petroleum Engineering
University of Wyoming
18 January 2011
E N H A N C E D O I L R E C O V E R Y I N S T I T U T E
Project Personal
• Norman Morrow
• Carol Robinson (administration)
• Winoto Winoto, Ph.D.
– Low salinity, removal of water blocks, rate effect, and core properties for screening cores
• Nina Loahardjo, Ph.D.
– Low salinity, sequential waterflooding, and interfacial properties
• Siluni Wickramatilaka, Ph.D.
– Spontaneous Imbibition – scaling of viscosity ratio etc., gravity dominated imbibition, MRI imaging of an imbibition front, low salinity imbibition at Sor, surfactant enhanced imbibition
• Pu Hui, Ph.D.
– Low salinity flooding of reservoir cores including CBM water, chemical analysis and in-line monitoring of pH and conductivity of effluent brine
• Behrooz Raeesi, Ph.D. Student
– Drainage/imbibition capillary pressure data, theory and experiments on surface energy, wetting and surface roughness
EORI staff
• Peugui Yin
– Petrophysics: thin section analysis and data acquisition: surface areas, clay analysis, cationexchange capacities (Susan Schwapp)
• Shaochang Wo
– Data analysis, modelling, simulation
Machine shop
• Ron Borgialli, George Twitchell, and Dean Twitchell
E N H A N C E D O I L R E C O V E R Y I N S T I T U T E
Adjunct Professors
• Jill Buckley
• Crude oil characterization, wetting, low salinity and sequential
waterflooding recovery mechanisms, adhesion, interfacial
tension, asphaltene phase behavior
• Koichi Takamura
• Recovery mechanisms, surfactants, emulsions, dispersions,
DLVO theory, fundamentals of interfacial tensions including
effect of pH and salinity for crude oils
• Geoff Mason
• Spontaneous imbibition, pressures at imbibition front and core
face, viscosity ratios – correlations and theory, bubble snap-off
and capillary back pressure for precise pore geometries, nuclear
tracer imaging and interpretation (with U Bergen)
E N H A N C E D O I L R E C O V E R Y I N S T I T U T E
Collaborations
•Australian National University
•Digital Core Consortium for Wettability : Mark Knackstedt, Andrew Fogden, Munish Kumar, Evgenia
Lebedevia and Tim Senden
Micro X-ray CT Imaging and Surface Chemical Techniques Related to Recovery Mechanisms for Crude Oil
and Core (Tensleep and Minnelusa) Which Complement UW Coreflood and Imbibition Studies
•University of Manitoba: Doug Ruth
Simulation and Theory of Imbibition
•University of Bergen: Arne Graue and Martin Fernø
Nuclear Tracer Imaging of Imbibition
•ConocoPhillips: James Howard and Jim Stevens
MRI Imaging of Sequential flooding, Spontaneous Imbibition, and Low Salinity Flooding
•University of Kyoto
Application of Molecular Simulation to Interpretation of the Interfacial and Surface Properties of Crude Oil
•University of Edmonton: David Potter
Tracking the Movement of Clay Particles Within Porous Media from Magnetic Properties
•Chevron: Guoqing Tang
Low Salinity Waterflooding – Industrial X-Ray Imaging
E N H A N C E D O I L R E C O V E R Y I N S T I T U T E
Presentations
July 2010 onward
• Morrow, N:” Interfacial Properties and Improved Oil Recovery by Waterflooding”, presented at Technical Advisory Board for
Enhanced Oil Recovery Institute, University of Wyoming, July 2010
• Loahardjo, N., Xie, X., Winoto, W., Buckley, J., and Morrow, N.R., “Improved Oil Recovery by Sequential Waterflooding”,
presented at the 14th Annual Gulf of Mexico Deepwater Technical Symposium, New Orleans, LA, Aug. 19-19, 2010.
• Xie, X., Pu, H., Buckley, J., Morrow, N.R., and Carlisle, C., “Low Salinity Waterflooding and Improved Oil Recovery”, presented
at the 14th Annual Gulf of Mexico Deepwater Technical Symposium, New Orleans, LA, Aug. 19-19, 2010.
• Morrow, N. and Mason, G:”Areas of Crude Oil/Rock Contact That Govern The Development of Mixed Wet Rocks”, presented at
11th International Symposium on Reservoir Wettability Calgary, AB, Canada, September 2010
• Loahardjo, N., Xie, X., Winoto, W., Buckley, J. and Morrow, N.:”Mechanism of Improved Oil Recovery by Sequential
Waterflooding”, ”, presented at 11th International Symposium on Reservoir Wettability Calgary, AB, Canada, September 2010
• Buckley, J. and Morrow, N.:”Improved Oil Recovery by Low Salinity Waterflooding: A Mechanistic Review”, presented at 11th
International Symposium on Reservoir Wettability Calgary, AB, Canada, September 2010
• Morrow, N. and Mason, G:”Spontaneous Imbibition Into Cores with Different Boundary Conditions”, presented at 11th
International Symposium on Reservoir Wettability Calgary, AB, Canada, September 2010
• Wickramatilaka, S., Mason, G., Morrow, N., Howard, J. and Stevens.:” Magnetic Resonance Imaging of Oil Recovery during
Spontaneous Imbibitions”, presented at 11th International Symposium on Reservoir Wettability Calgary, AB, Canada, September
2010
• Loahardjo, N.: “Mechanism of Improved Oil Recovery by Sequential Waterflooding” Chemical & Petroleum Engineering Graduate
seminar, Nov. 8, 2010.
• Takamura, K., Loahardjo, N., Buckley, J., Morrow, N, Kunieda, M., Liang, Y. and Matsuoka, T.:” Preferential Accumulation of
Light End Alkanes and Aromatics at The Crude Oil/Air and Crude Oil/Water Interfaces: Potential Mechanism of Accelerated Tar
Ball Formation from Spilled Crude Oil”, be presented at the Annual SME Meeting, Denver, February 27 – March 2, 2011
E N H A N C E D O I L R E C O V E R Y I N S T I T U T E
Publications
July 2010 onward
• Mason, G., Fisher, H., Morrow, N.R., and Ruth, D.W.: “Correlation for the Effect of Fluid Viscosities on Counter-Current
Spontaneous Imbibition”, JPSE. 72, (August) 2010, 195-205.
• Loahardjo, N., Xie, X., and Morrow, N.R., “Oil Recovery by Sequential Waterflooding of Mixed-Wet Sandstone and Limestone”,
Energy Fuels 24 (9) 5073-5080, Web published August 30, 2010.
• Pu, H., Xie, X., Yin, P. and Morrow, N.:”Low Salinity Waterflooding and Mineral Dissolution”, SPE 134042, SPE Annual Meeting
Technical Conference and Exhibition, Florence, Italy, September 2010
• Pu, H., “Recovery of Crude Oil from Outcrop and Reservoir Sandstone by Low Salinity Waterflooding”, PhD Defense, Sept. 27,
2010
• Wickramatilaka, S., G., Morrow, N. and Howard, J.:”Effect of Salinity on Oil Recovery by Spontaneous Imbibition”, 24th
International Symposium on the Core Analysts, Halifax, Nova Scotia, Canada, October 2010
• Kumar, K., Fodgen, A., Morrow N. and Buckley J.:”Mechanisms of Improved oil Recovery from sandstone by Low Salinity
Flooding”, 24th International Symposium on the Core Analysts, Halifax, Nova Scotia, Canada, October 2010
• Loahardjo, N., Morrow, N., Stevens, J. and Howard, J.:”Nuclear Magnetic Resonance Imaging: Application to Determination of
Saturation Changes in a Sandstone Core by Sequential Waterflooding”, 24th International Symposium on the Core Analysts,
Halifax, Nova Scotia, Canada, October 2010
• Morrow, N., and Buckley, J. ” Improved Oil Recovery by Low Salinity Waterflooding”, SPE Distinguished Author Series, October
2010
• Morrow, N.:” Low salinity Waterflooding”, EORI Newsletter, Wyoming, October 2010
• Fogden, A., Kumar, M., Morrow, N.R., Buckley, J.S.: “Mobilization of Fine Particles during Flooding of Sandstones, and Possible
Relations to Enhanced Oil Recovery”, Energy Fuels, submitted November, 2010.
• Li, Y., Mason, G., Morrow, N. and Ruth D.:” Capillary Pressure at A Saturation Front during Restricted Counter-Current
Spontaneous Imbibition with Liquid Displacing Air”, Transport in Porous Media, November, 2010
• Siluni Wickramathilaka, “Oil Recovery by Spontaneous Imbibition,” Dec. 1, 2010, PhD. Defense
15 Manuscripts in Preparation for 2011
E N H A N C E D O I L R E C O V E R Y I N S T I T U T E
TOPICS
• Screening outcrop cores for model rocks for low
salinity waterflooding
• Low salinity waterflooding with mineral dissolution
– Eolian sandstones containing dolomite and anhydrites
but without clays (Tensleep, Minnelusa, and Phosphoria)
• Sequential waterflooding
– Mechanisms of Sequential waterflooding
– Field test applications
E N H A N C E D O I L R E C O V E R Y I N S T I T U T E
Oil Recovery: Waterflooding
Single 5-Spot Well Pattern
E N H A N C E D O I L R E C O V E R Y I N S T I T U T E
Laboratory Measurement of
Oil Recovery by Waterflooding
brinecore
0
20
40
60
80
100
0 2 4 6 8 10 12
Oil
Re
cove
ry, %
OO
IP
Brine Injected, PV
Target for Tertiary Recovery
Oil Recovery by Waterflood
E N H A N C E D O I L R E C O V E R Y I N S T I T U T E
Definitions
• Low Salinity Waterflooding (LSW) at Sor
– Low salinity waterflooding of watered-out reservoir, nominally at residual oil saturation, Sor, after High Salinity Waterflooding (HSW) (common approach)
0
20
40
60
80
100
0 2 4 6 8 10 12
Rw
f(%
OO
IP)
Brine Injected, PV
HSW
LSE
LSW
Core U : R1/C1
LC Crude Oil
Loahardjo et al., 2007
E N H A N C E D O I L R E C O V E R Y I N S T I T U T E
Definitions (cont’d)
• Low Salinity Waterflooding (LSW) at Swi
– secondary mode low salinity waterflooding that begins at initial water saturation, Swi (growing interest)
Loahardjo et al., 2010
E N H A N C E D O I L R E C O V E R Y I N S T I T U T E
Low Salinity Waterflooding
0
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Figure 3. Histogram of Low Salinity Papers and Presentations
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Figure 3. Histogram of Low Salinity Papers and Presentations
EORI Newsletter Fall 2010
Mechanism of Low Salinity Waterflooding ?SPE Distinguished Author article on LSE (Morrow and Buckley, 2010)
E N H A N C E D O I L R E C O V E R Y I N S T I T U T E
Main Hindrances to Systematic Investigation of Low Salinity Flooding
• The type of Berea sandstone which
responded to low salinity waterflooding is
no longer available
• Currently available Berea shows little
(< 2% OOIP increase) if there is any
response to low salinity flooding
E N H A N C E D O I L R E C O V E R Y I N S T I T U T E
Solutions/work in progress
A. Work with reservoir crude oil/brine/rockReservoir cores are generally more responsive than outcrop
cores but :• coring are expensive
• duplicate core plugs are not usually available because of heterogeneity
• core quality, history, cleaning and re-use of cores are problematic.
• quality of crude oil samples can be uncertain
Papers on reservoir sandstone and carbonate results are in
preparation, covering:• Step changes in salinity
• Injection flow rate
• Intermissions in flow
• Effluent brine analysis
• Etc.
E N H A N C E D O I L R E C O V E R Y I N S T I T U T E
Solutions/work in progress
B. Total has identified a responsive outcropThree groups have reported response (U. of Wyoming, U.
Bordeaux, and U. of Stavanger)• Cost, heterogeneity, and logistics of supply are still a problem
E N H A N C E D O I L R E C O V E R Y I N S T I T U T E
C. Screening Outcrop Cores
for Model Rocks for Low
Salinity Waterflooding
Solutions/work in progress
E N H A N C E D O I L R E C O V E R Y I N S T I T U T E
0.1
1
10
100
1000
10000
0 5 10 15 20 25 30 35 40 45
Klin
ke
nb
erg
Pe
rme
ab
ility,
mD
Porosity, %
Torrey Buff
Idaho Gray
Edwards
Georgetown
Cordova Cream
Austin Chalk
ParkerBandera Brown
Bandera GrayKirby
Idaho HardBerea Edwards Brown
Sister Gray
Berea Stripe
Berea Buff
Silurian Dolomite
Leopard
Castle Gate
Boise
Bentheimer
Briar Hill
Stephen Xtra
Wisconsin
Screening of commercially available outcrop
0.1
1
10
100
1000
10000
0 5 10 15 20 25 30 35 40 45
Klin
ke
nb
erg
Pe
rme
ab
ility,
mD
Porosity, %
Torrey Buff
Idaho Gray
Edwards
Georgetown
Cordova Cream
Austin Chalk
ParkerBandera Brown
Bandera GrayKirby
Idaho HardBerea Edwards Brown
Sister Gray
Berea Stripe
Berea Buff
Silurian Dolomite
Leopard
Castle Gate
Boise
Bentheimer
Briar Hill
Stephen Xtra
Wisconsin
E N H A N C E D O I L R E C O V E R Y I N S T I T U T E
Castle Gate, Kklink=1,140–1,300 mD, f=25.0–25.6%
Berea Stripe,Kklink=382–457 mD, f=20.1–20.5%
Briar Hill, Kklink=5,500–5,900 mD, f=23.7–24.2%
Idaho Gray, Kklink=5,600–7,200 mD, f=28.6–29.7%
E N H A N C E D O I L R E C O V E R Y I N S T I T U T E
0 5 10 15 20 25 30 35 400
20
40
60
80
100
0 5 10 15 20 25 30 35 400
2
4
6
8
10
12
14
20x Dilution of Seawater
pH
P (psi)
pH
an
d
P (
psi
)
Rw
f (%
OO
IP)
Berea Stripe (WP Crude Oil)
Ta = 60
oC ; T
d = 60
oC
kg = 463 mD ; kb = 282 mD
Swi
= 23%
Injected Brine, PV
Seawater
2.3% OOIP
Low Salinity Waterflooding for Berea Stripe Outcrop
E N H A N C E D O I L R E C O V E R Y I N S T I T U T E
Low Salinity Waterflooding for Idaho Gray Outcrop
0 5 10 15 20 25 300
20
40
60
80
100
0 5 10 15 20 25 300
2
4
6
8
10
12
14
16
p
20x Dilution of Seawater
P (psi)
pH
an
d
P (
psi
)
Rw
f (%
OO
IP)
Idaho Gray (WP Crude Oil)
Ta = 60
oC ; T
d = 60
oC
kg = 7.2 D ; kb = 700 mD
Swi
= 22%
Injected Brine, PV
Seawater
3.3% OOIP
E N H A N C E D O I L R E C O V E R Y I N S T I T U T E
Low Salinity Waterflooding for Briar Hill Outcrop
0 5 10 15 20 25 300
20
40
60
80
100
0 5 10 15 20 25 300
2
4
6
8
10
12
14
20x Dilution of Seawater
pH
P (psi)
pH
an
d
P (
psi
)
Rw
f (%
OO
IP)
Briar Hill (WP Crude Oil)
Ta = 60
oC ; T
d = 60
oC
kg = 5.6 D ; kb = 700 mD
Swi
= 27%
Injected Brine, PV
Seawater
3.7% OOIP
E N H A N C E D O I L R E C O V E R Y I N S T I T U T E
Low Salinity Waterflooding for Castle Gate Outcrop
0 5 10 15 20 250
20
40
60
80
100
0 5 10 15 20 250
2
4
6
8
10
12
14
pH
20x Dilution of Seawater
P (psi) pH
an
d
P (
psi
)
Rw
f (%
OO
IP)
Castle Gate (WP Crude Oil)
Ta = 60
oC ; T
d = 60
oC
kg = 1.3 D ; kb = 460 mD
Swi
= 24%
Injected Brine, PV
Seawater
4.6% OOIP
E N H A N C E D O I L R E C O V E R Y I N S T I T U T E
Low salinity Effect
0
5
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30
35
40
be
ne
fit
co
mp
are
to
w
ate
rflo
od
re
su
lts
(%
)
1 2 3 4 5 6Endicott core
8 9 10 11
Endicott field average
12 13 14 15 16 17 18
Reservoir cores
(Lager et al., 2006)
0
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20
25
30
35
40
Berea Stripe
Idaho Gray
Briar Hill
Castle gate
Outcrop
cores
% 100%or HSW or LSW
oi or LSW
S Sbenefit
S S
(Seccombe et al., 2008)
E N H A N C E D O I L R E C O V E R Y I N S T I T U T E
LSW from LC Reservoir Core
0
10
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40
0
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40
60
80
100
0 2 4 6 8 10 12
Pre
ssu
re D
rop
(p
si)
an
d p
H
Rw
f(%
OO
IP)
Brine Injected, PV
HSW 14% OOIP
LSW
Core U : R1/C1
LC Crude Oil
P
pH
The result shows benefit to LSW compared to HSW is 43%
Loahardjo et al., 2007
E N H A N C E D O I L R E C O V E R Y I N S T I T U T E
Importance of Laboratory Coreflood
Tests on Reservoir for LSW
• For any positive LSW effect, tests on reservoir core show substantial response (averaged at 14%) as opposed to low response (0-9.6%) on tested outcrop core to date
• Single well chemical tracer tests showed 13% OOIP reduction in residual oil, consistent with laboratory core test (McGuire et al. 2005)
• A candidate North Sea field that met the necessary condition for low salinity effect did not respond to LSW in either laboratory or pilot test (Skrettingland et al. 2010)
• The correlation between laboratory coreflood test and field test results confirms the need for individual laboratory tests for screening low salinity candidate;
The variability in response demonstrates the value of laboratory tests in screening candidate reservoirs
E N H A N C E D O I L R E C O V E R Y I N S T I T U T E
2. Low Salinity Waterflooding
with Mineral Dissolution
Studies on Wyoming Reservoirs using
Low Salinity - Coal Bed Methane Water
E N H A N C E D O I L R E C O V E R Y I N S T I T U T E
Target Formations
• Minnelusa (Gibbs) and Tensleep (Teapot Dome) eolian
sandstones
One half of Wyoming’s oil production
Abundant dolomite & anhydrite cement
Formation water salinity: 3,300 – 38,650 ppm
Low salinity water: Coalbed Methane Water (1,316 ppm)
• Phosphoria (Cottonwood) dolomite formation
Recovery factor as low as 10%
Patchy anhydrite
Formation water salinity: 30,755 ppm
Low salinity water: Diluted formation water (1,537 ppm)
E N H A N C E D O I L R E C O V E R Y I N S T I T U T E
Crude Oils
Oil samplen-C6 Asph
[%wt]Acid #
[mg KOH/g oil]Base #
[mg KOH/g oil]
Tensleep 3.2 0.16 0.96
Minnelusa 9.0 0.17 2.29
Phosphoria 2.9 0.56 1.83
E N H A N C E D O I L R E C O V E R Y I N S T I T U T E
Minnelusa Rock from Oil Zone
100 mm
Dolomite
Anhydrite
Dolomite
• Mineralogy: sandstone with abundance dolomite and anhydrites cements
• Porosity: 12.2 -18.1%
• Permeability: 63.7 – 174.2 mDPu et al., 2010
E N H A N C E D O I L R E C O V E R Y I N S T I T U T E
0
5
10
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25
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0 2 4 6 8 10 12 14 16 18
Pre
ssu
re d
rop
, p
si
Oil
reco
very
, %
OO
IP
Brine injected, PV
M1
Kg = 78.4 md, f = 14.6%
Swi = 8.2%,
MW (38,651ppm) CBMW (1,316ppm)
+5.8%
Pu et al., 2010
Low Salinity Waterflooding for Minnelusa Rock from Oil Zone
E N H A N C E D O I L R E C O V E R Y I N S T I T U T E
Phosphoria Rock from Cottonwood Creek Field
100 mm
DolomiteVugDolomite
Mineralogy: Crystallin dolomite and patchy anhydrites
Porosity: 9.5 -19.6%
Permeability: 0.25 – 294 mdPu et al., 2010
E N H A N C E D O I L R E C O V E R Y I N S T I T U T E
0
5
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25
30
0
10
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50
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70
80
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100
0 5 10 15 20 25 30 35 40 45 50
Pre
ssure
dro
p,
psi
Oil
reco
very
, %
OO
IP
Brine injected, PV
PW30,755ppm
5% PW dilute1,537ppm
P1
Kg = 6.8 md, f = 9.5%Swi = 22.7%
+8.1%
Kwe1 = 2.1 md
Kwe2 = 1.1 md
Low Salinity Waterflooding for Phosphoria Rock
Pu et al., 2010
E N H A N C E D O I L R E C O V E R Y I N S T I T U T E
Tensleep Rock from Oil Zone
100 mm
Dolomite
quartz
dolomite
anhydrite
• Mineralogy: sandstone with dolomite and anhydrites cements
• Porosity: 8.6 -15.7%
• Permeability: 7.0 – 42.7 mdPu et al., 2010
E N H A N C E D O I L R E C O V E R Y I N S T I T U T E
0
10
20
30
40
50
60
70
80
90
0
10
20
30
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50
60
70
80
90
100
0 10 20 30 40 50 60 70
Pre
ssure
dro
p,
psi
Oil
reco
very
, %
OO
IP
Brine injected, PV
T4
Kg = 22.9 md, f = 12.5%Swi = 15.3%
MW38,651ppm
CBMW1,316ppm
Kwe2 = 0.55 mdKwe1 = 0.53 md
+5.2%
Low Salinity Waterflooding for Tensleep Rock from Oil Zone
Pu et al., 2010
E N H A N C E D O I L R E C O V E R Y I N S T I T U T E
Anhydrates dissolution in Tensleep rock – the green regions show the region
of cement dissolutions after flooding with CBM water (Lebedeva et al., 2009)
E N H A N C E D O I L R E C O V E R Y I N S T I T U T E
Tensleep Rock from Aquifer
100 mm
Dolomite
Dolomite
Mineralogy: sandstone with interstitial dolomite crystals and minimal anhydrates
Porosity: 17 -18.7%
Permeability: 50.8 – 228.5 mdPu et al., 2010
E N H A N C E D O I L R E C O V E R Y I N S T I T U T E
0
5
10
15
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25
30
0
10
20
30
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0 5 10 15 20 25 30
Pre
ssure
dro
p,
psi
Oil
reco
very
, %
OO
IP
Brine injected, PV
MW38,651ppm
CBMW1,316ppm
Core# Kg (md) f Swi (%)TA1 228.5 18.7 22.4TA2 50.8 18.1 20.4
RTA1
RTA2
PTA2
PTA1
Kwe = 10.4 md
Kwe = 1.1md
Low Salinity Waterflooding for Tensleep Rock from Aquifer
Pu et al., 2010
E N H A N C E D O I L R E C O V E R Y I N S T I T U T E
Silurian Dolomite Outcrop
Mineralogy: interstitial dolomite and no anhydrates
Porosity: 17 – 20%
Permeability: 100 mD – 1,000 md
E N H A N C E D O I L R E C O V E R Y I N S T I T U T E
0 5 10 15 20 25 30 350
20
40
60
80
100
0 5 10 15 20 25 30 350
5
10
15
20
25
30
35
20x Dilution
of Seawater
pH
P (psi)
pH
an
d
P (
psi
)
Rw
f (%
OO
IP)
Silurian Dolomite (WP Crude Oil)
Ta = 60
oC ; T
d = 60
oC
kg = 102 mD ; kb = 19 mD
Swi
= 24%
Injected Brine, PV
Seawater
Low Salinity Waterflooding for Silurian Dolomite Outcrop
E N H A N C E D O I L R E C O V E R Y I N S T I T U T E
Summary
• Tensleep and Minnelusa sandstones, and
Phosphoria dolomite all contained
anhydrites and all responded to low
salinity waterflooding
• Tensleep sandstone from an aquifer and
Silurian dolomite outcrop did not contain
any noticeable anhydrites and did not
respond to low salinity waterflooding
E N H A N C E D O I L R E C O V E R Y I N S T I T U T E
3. Sequential Waterflooding
Morrow, Xie, and Loahardjo, US Patent No. WO 2009/12663 A2, October 2009
Morrow, Xie, and Loahardjo, Pending Provisional Patent No. 61/226,709, July 2009
E N H A N C E D O I L R E C O V E R Y I N S T I T U T E
Effect aging at Sor and/or Swi
on sequential waterflooding
E N H A N C E D O I L R E C O V E R Y I N S T I T U T E
Recovery of Crude Oil
Medium Permeability Berea Sandstone
Aging at Sor after 3 cycles
Ta = 75 oC
Td = 60 oC
E N H A N C E D O I L R E C O V E R Y I N S T I T U T E
0 1 2 3 4 5 6 70
20
40
60
80
100
kg = 604 mD PH 2L H 02 (WP Crude Oil)
Ta = 75
oC ; t
a = 6 months
Td = 60
oC (m = 28.8 cP)
R1/C1 : Swi
= 26% : Sor = 44%
Rw
f (%
OO
IP)
PV Brine Injected0 1 2 3 4 5 6 7
0
20
40
60
80
100
kg = 604 mD PH 2L H 02 (WP Crude Oil)
Ta = 75
oC ; t
a = 6 months
Td = 60
oC (m = 28.8 cP)
R1/C1 : Swi
= 26% : Sor = 44%
R1/C2 : Swi
= 36% : Sor = 28%
Rw
f (%
OO
IP)
PV Brine Injected0 1 2 3 4 5 6 7
0
20
40
60
80
100
kg = 604 mD PH 2L H 02 (WP Crude Oil)
Ta = 75
oC ; t
a = 6 months
Td = 60
oC (m = 28.8 cP)
R1/C1 : Swi
= 26% : Sor = 44%
R1/C2 : Swi
= 36% : Sor = 28%
R1/C3 : Swi
= 46% : Sor = 19%
Rw
f (%
OO
IP)
PV Brine Injected
20 days at Sor
0 1 2 3 4 5 6 70
20
40
60
80
100
kg = 604 mD PH 2L H 02 (WP Crude Oil)
Ta = 75
oC ; t
a = 6 months
Td = 60
oC (m = 28.8 cP)
R1/C1 : Swi
= 26% : Sor = 44%
R1/C2 : Swi
= 36% : Sor = 28%
R1/C3 : Swi
= 46% : Sor = 19%
R1/C4 : Swi
= 42% : Sor = 15%
Rw
f (%
OO
IP)
PV Brine Injected
Sequential waterflooding with wettability control
for medium permeability Berea sandstone
E N H A N C E D O I L R E C O V E R Y I N S T I T U T E
Recovery of Crude Oil
Low Permeability Berea Sandstone
Aging at Swi after 4 cycles
followed by aging at Sor
Ta = 75 oC
Td = 60 oC
E N H A N C E D O I L R E C O V E R Y I N S T I T U T E
0 1 2 3 4 5 6 70
20
40
60
80
100k
g = 84 mD k
g = 84 mD Ev 2L 02 (WP Crude Oil)
Ta = 75
oC ; t
a = 6 months
Td = 60
oC (m = 28.8 cP)
R1/C1 : Swi = 28% : S
or = 49%
Rw
f (%
OO
IP)
PV Brine Injected0 1 2 3 4 5 6 7
0
20
40
60
80
100k
g = 84 mD Ev 2L 02 (WP Crude Oil)
Ta = 75
oC ; t
a = 6 months
Td = 60
oC (m = 28.8 cP)
R1/C1 : Swi = 28% : S
or = 49%
R1/C2 : Swi = 28% : S
or = 43%
Rw
f (%
OO
IP)
PV Brine Injected0 1 2 3 4 5 6 7
0
20
40
60
80
100k
g = 84 mD Ev 2L 02 (WP Crude Oil)
Ta = 75
oC ; t
a = 6 months
Td = 60
oC (m = 28.8 cP)
R1/C1 : Swi = 28% : S
or = 49%
R1/C2 : Swi = 28% : S
or = 43%
R1/C3 : Swi = 31% : S
or = 38%
Rw
f (%
OO
IP)
PV Brine Injected0 1 2 3 4 5 6 7
0
20
40
60
80
100k
g = 84 mD Ev 2L 02 (WP Crude Oil)
Ta = 75
oC ; t
a = 6 months
Td = 60
oC (m = 28.8 cP)
R1/C1 : Swi = 28% : S
or = 49%
R1/C2 : Swi = 28% : S
or = 43%
R1/C3 : Swi = 31% : S
or = 38%
R1/C4 : Swi = 38% : S
or = 29%
Rw
f (%
OO
IP)
PV Brine Injected
30 days at Swi
0 1 2 3 4 5 6 70
20
40
60
80
100k
g = 84 mD Ev 2L 02 (WP Crude Oil)
Ta = 75
oC ; t
a = 6 months
Td = 60
oC (m = 28.8 cP)
R1/C1 : Swi = 28% : S
or = 49%
R1/C2 : Swi = 28% : S
or = 43%
R1/C3 : Swi = 31% : S
or = 38%
R1/C4 : Swi = 38% : S
or = 29%
R1/C5 : Swi = 34% : S
or = 38%
Rw
f (%
OO
IP)
PV Brine Injected
20 days at Sor
0 1 2 3 4 5 6 70
20
40
60
80
100k
g = 84 mD Ev 2L 02 (WP Crude Oil)
Ta = 75
oC ; t
a = 6 months
Td = 60
oC (m = 28.8 cP)
R1/C1 : Swi = 28% : S
or = 49%
R1/C2 : Swi = 28% : S
or = 43%
R1/C3 : Swi = 31% : S
or = 38%
R1/C4 : Swi = 38% : S
or = 29%
R1/C5 : Swi = 34% : S
or = 38%
R1/C6 : Swi = 37% : S
or = 22%
Rw
f (%
OO
IP)
PV Brine Injected
Sequential waterflooding with wettability control
for low permeability Berea sandstone
E N H A N C E D O I L R E C O V E R Y I N S T I T U T E
Recovery of Crude Oil
High Permeability Berea Sandstone – BS 4
Aging at Sor after 4 cycles
followed by aging at Swi, Sor , Sor and Sor
Restoration 2
Ta = 75 oC; ta = 1 year
Td = 60 oC
E N H A N C E D O I L R E C O V E R Y I N S T I T U T E
17 days at Sor
25 days at Swi24 days at Sor
21 days at Sor3 months at Sor
Sequential waterflooding with wettability control
for high permeability Berea sandstone – Restoration 2
E N H A N C E D O I L R E C O V E R Y I N S T I T U T E
Summary
• Further investigation of oil recovery by sequential
waterflooding is needed, particularly for different types of
crude oil, because wettability, and changes in wettability,
depend on specific crude oil/brine/rock interactions
• Aging at high water saturation usually gave increase in
oil recovery, whereas aging at low water saturation
resulted in decreased oil recovery
• Sequential waterflooding without change in salinity and
without cleaning or re-aging between cycles usually
showed sequential reductions in residual oil saturation.
• Single-well field testing of sequential waterflooding is
justified
E N H A N C E D O I L R E C O V E R Y I N S T I T U T E
Single-Well Tests of Sequential Floods
Calculations are based on a simple
piston-like displacement model
f =20.9%, 30 ft reservoir oil-zone thickness
E N H A N C E D O I L R E C O V E R Y I N S T I T U T E
Reservoir at residual oil saturation after waterflood
(WF1)
SOR (WF1)=36.2%
target zone radius = 45 ft
0 10 20 30 40 50 ft
Day 0
E N H A N C E D O I L R E C O V E R Y I N S T I T U T E
Injection of oil into the target zone
SOR (WF1)=36.2%
target zone radius = 45 ft
SOR (WF1)=36.2%
oil injected = 100 bbl
Day 1
SO=64.9%
0 10 20 30 40 50 ft
E N H A N C E D O I L R E C O V E R Y I N S T I T U T E
START WATER INJECTION
SOR (WF1)=36.2%
oil bank minimum radial length= 4.5 ft
oil bank volume = 406 bbl
Displacement of injected oil by injection of brine
(WF2)
inner radial distance
oil bank radial length
Day 1Day 2
Radial length of oil reaches minimum before
growing upon more injection of brine
0 10 20 30 40 50 ft
E N H A N C E D O I L R E C O V E R Y I N S T I T U T E
SOR (WF1)=36.2%
Continuation of oil bank displacement by
injection of brine (WF2)
oil bank radial length= 5.9 ft oil bank volume = 1,149 bbl
SO=64.9%
SOR (WF2)=28.8%
Day 2Day 3Day 4Day 5Day 6
0 10 20 30 40 50 ft
E N H A N C E D O I L R E C O V E R Y I N S T I T U T E
The well is put on production and the oil bank
grows in volume and radial length
SOR (WF1)=36.2%
Day 6Day 8Day 9Day 10
0 10 20 30 40 50 ft
E N H A N C E D O I L R E C O V E R Y I N S T I T U T E
SOR (WF1)=36.2%SOR (WF2)=28.8%SOR (WF3)=24.0%
Day 10Day 11Day 12Day 13Day 14
0 10 20 30 40 50 ft
The well is put on production and the oil bank
grows in volume and radial length
E N H A N C E D O I L R E C O V E R Y I N S T I T U T E
Single Well Field Test
4,000 bbl oil in 62 days(as high as 15,000 bbl optimistically)
900 bbl oil in 14 days(as high as 3200 bbl optimistically)
2,000 bbl brine
100 bbl oil
10,000 bbl brine 100 bbl
oil
E N H A N C E D O I L R E C O V E R Y I N S T I T U T E
Single Well Field Tests
• Low cost: Injected brine and oil are directly available: Required oil volume is small
• Test should first be applied to reservoirs with flow conformance (responded well to waterflooding), oil viscosity close to that of the injected brine and low gas/oil ratio
• Single well tracer tests can be used to determine residual oil saturations before and after the process
E N H A N C E D O I L R E C O V E R Y I N S T I T U T E
Field Test ? 2011 ?
Discussion of potential field test
with James Seccombe and Scott Digert (BP Alaska) Laramie, Wyoming, October 13, 2010
E N H A N C E D O I L R E C O V E R Y I N S T I T U T E
Further Application of Sequential Waterflood
Improved Recovery by Injection of Small Volumes of Oil
1. Inject multiple oil banks
(single well or well to well)
2. Reversing production and injection well before breakthrough to avoid sand production, especially for less consolidated reservoir
3. Convert a tertiary mode low salinity flood into a more favorable/effective secondary mode low salinity waterfloodby pre-injection of oil
4. Establishing initial oil bank for other recovery methods, e.g. before flooding natural residual oil zone
E N H A N C E D O I L R E C O V E R Y I N S T I T U T E
Ongoing Topics and Future Work
1. Low Salinity Waterflooding
a. Tests on reservoir rocks
b. Screening outcrop cores, at Swi and Sor
c. Attempt to identify a mechanism for LSW
2. Sequential Waterflooding
a. Further laboratory tests
b. Field tests of Sequential Waterflooding
3. Waterblock Treatment
E N H A N C E D O I L R E C O V E R Y I N S T I T U T E
Acknowledgments• EORI, University of Wyoming
• Wold Chair
• Industry:
Saudi Aramco*, BP*,Chevron, ConocoPhillips, Shell,
StatoilHydro*, Total* (enquiries from Oxy, Kuwait, Maersk)
* includes provision of reservoir rock and/or crude oil
Thank You !
E N H A N C E D O I L R E C O V E R Y I N S T I T U T E
Improved Oil Recovery by Waterflooding
Nina LoahardjoPetrophysics and Surface Chemistry Group
Chemical and Petroleum Engineering
University of Wyoming
18 January 2011
E N H A N C E D O I L R E C O V E R Y I N S T I T U T E
E N H A N C E D O I L R E C O V E R Y I N S T I T U T E
E N H A N C E D O I L R E C O V E R Y I N S T I T U T E