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Low Salinity Waterflooding Fundamentals and Case Studies
Norman R. Morrow Chemical & Petroleum Engineering
University of Wyoming
and
Charlie Carlisle Chemical Tracers, Inc.
2012 IOR/EOR Conference Jackson, WY September 10 – 11, 2012
Enhanced Oil Recovery Technologies
The increase of ultimate recovery through injection of steam, chemicals or gas
to more effectively displace the oil bringing RFs to the 50-70% range.
In Situ Upgrading (catalytic)
Process Maturity
R&D
‘Discover’
‘Develop’ & ‘Demonstrate’ Optimisation
‘Deploy’ & Repeat
N 2 /CO 2 Foam
Thermal GOGD
Contaminated/Acid Gas
In - Situ Combustion / HPAI
Polymer Flooding
High Pressure Steam Injection
Alkaline Surfactant Polymer
Hybrid Processes Microbial
Time
Steam (SF, CSS)
Miscible Gas
Low Salinity Waterflooding
SAGD
Integrated Solutions • Mature Field Mgmt • Surface+Subsurface • Onshore/Offshore • Smart Surveillance • Wells & Resv Mgmt • Operations
Solvents
In - Situ Upgrading (heating)
From Shell EOR Academy, May, 2012
20,000
40,000
60,000
Oil
Pro
du
cti
on
Rate
, B
/D
1850 1900 1950 2000
Field Discovered
Year
Bradford Field, Pennsylvania
Primary Recovery
Secondary Recovery
From Waterflooding, Whillhite, 1986
Bradford Field, Pennsylvania
20,000
40,000
60,000
Oil
Pro
du
cti
on
Rate
, B
/D
1850 1900 1950 2000
Waterflooding
Legalized
Field Discovered
Year
Primary Recovery
Secondary Recovery
From Waterflooding, Whillhite, 1986
WATERFLOODING
• Highly successful for more than 75 years
• Accounts for more than 50% of current US
oil production
• Worldwide application (waterflooding is
usually implemented at the outset of
production).
•Technology involves handling very large
volumes of water
Co-produced water
Estimates of the decrease in
fractional flow of oil can be
obtained from production
statistics for oil and water
US (including Alaska)
Worldwide
0
.1
.2
.3
.4
US (lower 48 states)
Wyoming
Average fractional flow of produced oil
in the US lower 48 states is about 2%
From C. Carlisle
Dependence of Oil Recovery on
Injection Brine Composition
Conventional view
Injection brine composition was believed to have no
effect on efficiency of oil recovery by waterflooding
(apart from formation damage).
Brine Composition Effects • Change in brine composition at high salinity (1994)
• Low salinity waterflooding – secondary mode
(1997)
– tertiary mode (1999)
• Dissolution - especially anhydrite (2009, 2010)
• No change in brine composition (2008, 2009, 2012)
brine core
0
20
40
60
80
100
0 5
Injected Brine Volume (PV)
Oil
Reco
very
(%
OO
IP)
OIL RECOVERY BY WATERFLOOD
TARGET FOR
TERTIARY RECOVERY
Laboratory Measurement of Oil Recovery by Waterflooding for Outcrop Rock and Refined Oil
For an initial water
saturation of 25%:
residual oil = 37.5%
LSE starting at initial water saturation
From Tang and Morrow 1999
June 1995 – The British Petroleum Research Center sent their representative, Cliff Black, for a three day “think tank” session.
EFFECT OF DILUTION OF BOTH CONNATE
AND INVADING BRINES ON OIL RECOVERY
BY WATERFLOODING
0
10
20
30
40
50
60
70
80
90
100
0 5 10 15
Injected Water Volume (PV)
Rw
f (%
OO
IP)
0.01CSRB
0.1CSRB
CSRB
CS Crude Oil/CS Brine/Berea
Sw i=23-27 %
Ta=55 °C
ta=7.0 days
Td=55 °C
Flood rate=10 ft/d
connate=invading
From Tang and Morrow 1999
0
10
20
30
40
50
60
70
80
90
100
0 1 2 3 4 5 6 7 8 9 10 11Injected Brine Volume (PV)
Rw
f (%
OO
IP)
CSRB
0.01 CSRB
CS Crude Oil/CS Brine/CS Sandstone
Swi=25%
Ta=55 oC
ta=10 days
Td=55 oC
flood rate=6ft/d
invading brine
EFFECT OF THE CONCENTRATION OF INJECTION
BRINE ON WATERFLOOD RECOVERY FOR
RESERVOIR CORE
CSRB=connate
From Tang and Morrow 1999
Application of LSW to recovery of oil from
watered-out reservoirs at residual oil saturation
after high salinity waterflooding
Tertiary response to low salinity brine
0
20
40
60
80
100
0 5 10 15 20 25
Brine injected, PV
Rw
f ,
%O
OIP
0
5
10
15
D P
, p
si
LC crude oil, Swi = 10.6%
R
D P
RIB (29,690 ppm)
LSB (1,480 ppm)
12.6%
R3:C3
Zhang, et al 2007 (SPE 109849)
Pilot tests of low salinity waterflooding
BP: All clastic reservoir systems reported have shown
an average of 12% incremental oil recovery through
mobilization of residual oil
100%o Hisal o Losal
ot
o initial o Hisal
S SS
S S
D
Injection of low salinity water at the outset of reservoir
development
(especially when membrane separation infrastructure
is needed for removal of sulfate)
Application of LSW – secondary mode
19
Low Salinity Waterflooding - Mechanism
NECESSARY CONDITIONS FOR SENSITIITY OF OIL RECOVERY TO BRINE
COMPOSITION
•Adsorption of polar components from crude oil
•the presence of connate water
•The presence of clay (kaolinite)
NO SENSITIVITY TO SALINITY WAS OBSERVED IF:
• the oil phase was a refined oil
• if the core did not contain an initial water saturation
• if the core was fired and acidized in order to destroy the
kaolinite clay structure.
(Tang & Morrow, 1999)
adsorbed polar oil components
Adsorption of Polar Components from Crude Oil and
Mobilized Clay Particles at Brine/Oil Interface
oil
water
solid
clays
a. adsorption onto clay surface
oil
b. clay particle
clay
oil
water
From Tang and Morrow 1999
Effect of Clay Wettability on Retained Oil
mobilized mixed-wet clay particles
oil
water-wet clay particles
water
solid
transition towards
increased water-wet
From Tang and Morrow 1999
oil
retained oil
a. retained oil before dilute brine flooding
b. retained oils become mobilizeed due to detached clay particles
solid
water
Detachment of Mixed-Wet Clay Particles and Mobilization of Oil Drops
water
From Tang and Morrow 1999
Mechanism - Limited Mobilization
of Fine Particles (Kaolinite) Tang and Morrow, JPSE, 1999
There are now numerous examples of LSW for which
production of fine particles is not observed.
However, the number of submicron particles in sandstone that
change location during waterflooding has been demonstrated
to increase with decrease in salinity (Fogden, Kumar, Morrow,
Buckley, Energy & Fuels 2011).
Berea B1 “Before”: 97x73 mm2, scale bar 10 mm
SEM imaging: Single-phase flooding
From Kumar, et al. Petrophysics 2011
Berea B1 “After”: 97x73 mm2, scale bar 10 mm
From Kumar, et al. Petrophysics 2011
Many laboratories and organizations have
grappled with identifying, reproducing, and
explaining LSE
Low Salinity Effect (LSE)
Morrow and Buckley, 2011
Interest in LSW has increased as indicated by the number of
publications and presentations focused on the low salinity effect (LSE).
Updated from Morrow and Buckley, JPT, 2011
Year
Num
be
r o
f p
ap
ers
McGuire et al. 2005
Lager et al. 2006
Mechanism?
Despite growing interest in LSE, and consensus that
improved recovery can be obtained by Low Salinity
Waterflooding (LSW), a consistent mechanistic explanation
has not yet emerged
(Tang and Morrow 1999)
•a significant clay fraction,
•the presence of connate water, and
•exposure to crude oil to create mixed-wet
conditions.
Problem! In many instances these
conditions are not sufficient.
Further investigation is needed but the type of
Berea sandstone used in the original
mechanistic studies has been unavailable for
over ten years.
Necessary conditions for LSE
Quest for Responsive Outcrop
17 outcrop sandstones and
6 outcrop carbonates
have been tested for LS response
From Winoto, et al. 2012 SPE 154209
Tests of low salinity response of
outcrop sandstones
• Tertiary mode tests on all 17 cores for
mobilization of residual oil by LSW.
Tertiary mode recovery is readily tested in
the laboratory because response is
observed directly as additional recovery
after change in injection brine
From Winoto, et al. 2012 SPE 154209
brine core at Swi
Laboratory Measurement of Tertiary
Mode Oil Recovery by Waterflooding
0
20
40
60
80
100
0 2 4 6 8 10 12
Oil
Re
co
ve
ry, %
OO
IP
Brine Injected, PV
Oil Recovery
by Waterflood
Tertiary Recovery
by Injection
of Diluted Brine
LSE at Sor for 17 outcrop sandstones
From Winoto, et al. 2012 SPE 154209
avg DSot
= 12.1%
Comparison of LSE at Sor for outcrop
and reservoir sandstones
avg DSot
= 3.9%
From Winoto, et al. 2012 SPE 154209
37
Data have also been obtained at UW for
11 sandstone reservoir crude oil/brine/rock
combinations
Comparison of LSE at Sor for outcrop
and reservoir sandstones
avg DSot
= 3.9%
avg DSot
= 11.1%
avg DSot
= 12.1%
From Winoto, et al. 2012 SPE 154209
Summary • Overall, reservoir rocks respond better to LS flooding
than outcrop rocks
• Identification of the sufficient conditions for LSE remains
as an outstanding challenge.
• The search for outcrop sandstones that show LS
response comparable to the magnitude observed for
reservoirs is being continued
• Field wide application of LS flooding is being
implemented
FIELD APPLICATIONS
•Injection of selected brine at the beginning of a waterflood
•Change injection brine during the course of a mature waterflood
•Decide if produced brine (initially the reservoir connate brine composition) should be reinjected
Each situation should be carefully tested in the laboratory at reservoir conditions. The type of results that have been shown provide guidance in selection of brine composition, but recovery efficiency may depend on competing interactions for specific situations.
Application of Coalbed Methane Water to Low Salinity Waterflooding of Three Wyoming Formations
Targeted Formations
Tensleep and Minnelusa aeolian sandstones
One half of Wyoming’s oil production
Abundant dolomite & anhydrite cement
No measurable clay
Formation water salinity: 3,300 – 38,650 ppm
Phosphoria dolomite formation
Recovery factor as low as 10%
Patchy anhydrite
No measurable clay
Formation water salinity: 30,755 ppm
From Pu et al., 2010 SPE 134042
Low Salinity Water
• WY coalbed methane water (CBMW):
300 – 2,000 ppm
CBMW used in this study: 1,316 ppm
• Diluted Phosphoria formation water: 1,537 ppm
From Pu et al., 2010 SPE 134042
Teton
Park
Natrona W
ashakie
Uinta
Lin
coln
Carbon
Albany
Converse
Platte
Laramie
Niobrara
100 mm
Tensleep Rock from Oil Reservoir
quartz
dolomite
anhydrite
Mineralogy: sandstone with dolomite and anhydrite cements
Porosity: 8.6 -15.7%
Permeability: 7.0 – 42.7 md
Dolomite
From Pu et al., 2010 SPE 134042
0
10
20
30
40
50
60
70
80
90
0
10
20
30
40
50
60
70
80
90
100
0 10 20 30 40 50 60 70
Pre
ssure
dro
p,
psi
Oil
recovery
, %
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%
Waterflooding: Tensleep Core from Oil Zone
From Pu et al., 2010 SPE 134042
Minnelusa Rock from Oil Reservoir
100 mm
Mineralogy: sandstone with dolomite and anhydrite cements
Porosity: 12.2 -18.1%
Permeability: 63.7 – 174.2 md
Dolomite
Anhydrite
Dolomite
From Pu et al., 2010 SPE 134042
Minnelusa Core Waterflooding
0
5
10
15
20
25
0
10
20
30
40
50
60
70
80
90
100
0 2 4 6 8 10 12 14 16 18
Pre
ssu
re d
rop
, psi
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%
From Pu et al., 2010 SPE 134042
Phosphoria Rock from Cottonwood Creek Field
100 mm
Mineralogy: Crystaline dolomite and patchy anhydrite
Porosity: 9.5 -19.6%
Permeability: 0.25 – 294 md
Dolomite Vug Dolomite
From Pu et al., 2010 SPE 134042
0
5
10
15
20
25
30
0
10
20
30
40
50
60
70
80
90
100
0 5 10 15 20 25 30 35 40 45 50
Pre
ssure
dro
p,
psi
Oil
recovery
, %
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
Phosphoria Rock Waterflooding
From Pu et al., 2010 SPE 134042
0
1
2
3
4
0
10
20
30
40
50
60
70
80
90
100
0 5 10 15 20 25 30
Pre
ssu
re d
rop
, psi
Oil
reco
very
, %O
OIP
Brine injected, PV
P2
Kg = 293.9 md, f = 19.6%
Swi = 23.1%
+5.5
%
PW
30,755ppm 5% PW dilute
1,537ppm
Kwe = 9.4 md
Phosphoria Rock Waterflooding
From Pu et al., 2010 SPE 134042
100 mm
Tensleep Rock from Aquifer – Minimal Anhydrite
Mineralogy: sandstone with interstitial dolomite crystals
Porosity: 17 -18.7%
Permeability: 50.8 – 228.5 md
Dolomite
Dolomite
From Pu et al., 2010 SPE 134042
0
5
10
15
20
25
30
0
10
20
30
40
50
60
70
80
90
100
0 5 10 15 20 25 30
Pre
ssure
dro
p,
psi
Oil
recovery
, %
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
DPTA2
DPTA1
Kwe = 10.4 md
Kwe = 1.1md
Waterflooding: Tensleep Core from Aquifer
From Pu et al., 2010 SPE 134042
Tensleep: 31 PV of 15% HCl
Wt reduction: - 5.1 wt%; f: - 5%, Kw: 18 md 90 md
0
1
2
3
4
5
6
7
8
0
10
20
30
40
50
60
70
80
90
100
0 5 10 15 20 25
DP, p
si
Reco
very
, %
OO
IP
Brine Injected, PV
R
Core T3
K w = 90md, S wi =35.39%
Formation water CBM water
DP
From Pu et al., 2010 SPE 134042
Micro - CT on Tensleep Rock:
Dissolution by CBM Waterflooding
Lebedeva, Senden, Knackstedt and Morrow, 2009
• Tensleep and Minnelusa sandstones, and
Phosphoria dolomite all contained
anhydrite and all responded to low
salinity waterflooding
• Increase in pressure drop was usually
observed before and after injection of low
salinity water for cores containing
anhydrite.
Summary
• After flushing with acid, Tensleep
sandstone no longer responded to low
salinity waterflooding
• Tensleep sandstone from an aquifer
did not contain anhydrite and did not
respond to low salinity waterflooding
Summary
Optimization of injection brine compositions (both low and high salinity)
Much improved engineering of waterfloods will result from development of broad understanding of the factors that determine waterflood recoveries for crude oil/brine/rock combinations for wide ranges of ionic strength and composition.
“smart water” “designer brines” “optimized brines”
Funding for this research was provided by: Enhanced Oil Recovery Institute and the Wold Chair Endowment at the University of Wyoming, BP, Chevron, Saudi Aramco, Statoil, and Total
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