chemical enhanced oil recovery malcolm j. pitts surtek, inc
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SURTEK
Chemical Enhanced Oil Recovery
Malcolm J. Pitts Surtek, Inc.
SURTEK
SURTEK
Oil Bank
Waterflood Residual OilA
SP
Poly
mer
Wat
er
Chemical Flood Mechanism
Injection Production
Ultimate Residual Oil
Chemical Flood is Not like a waterfloodChemical Flood effects only reservoir contacted by chemicals
• Fluid is Injected at an Injection Well• Injected Fluid Moves through an Oil Reservoir• Mobilized Oil Produced at a Production Well
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o
poVIAD B
VSEEENp •=
Oil Recovery Equation
Capillary Number Mechanism –Pore to PoreDisplacement EfficiencyHow well does the injected fluid move oil?
Mobility Control Mechanism -Volumetric Displacement EfficiencyOil Recovery
Stock Tank Oil Saturation
SURTEK
• application objectives• recover 15 to 30% OOIP as incremental oil• cost of incremental oil is less than $20.00/bbl• rate of return 50% or greater
• two primary mechanisms• a mobility control mechanism • a capillary number mechanism
Chemical Floods
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σLP
ForcesSurfaceForcesViscousNca
/Δ==
Capillary Number Mechanism
Improves ED
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SURTEK
0.0 0.5 1.0 1.5 2.0 2.5Alkali Concentration (wt%)
1E-3
1E-2
1E-1
1E+0
1E+1
Inte
rfac
ial T
ensi
on (m
N/m
)
Na2CO
3+ Surfactant
NaOH + Surfactant
42 API
22 API
Alkali-Surfactant IFT Reduction
0.0 0.5 1.0 1.5 2.0 2.5Alkali Concentration (wt%)
1E-3
1E-2
1E-1
1E+0
1E+1
Inte
rfac
ial T
ensi
on (m
N/m
)
Na2CO
3
NaOH
42 API
22 API
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Interfacial Tension Criteria
interfacial tension reduction alone does not result in good oil recovery
150 oF Interfacial TensionInjected Solution (mN/m)- ASP Solution #1 <0.001 - ASP Solution #2 <0.001- ASP Solution #3 <0.001- ASP Solution #4 0.001
0.0 1.0 2.0 3.0 4.0 5.0Cumulative Produced Fluids (PV)
0
10
20
30
40
50
60
70
Cum
ulat
ive
Oil
Rec
over
y (%
OO
IP)
Primary and Waterflood Chemical Flood
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Alkali and Surfactant• alkali
• alters rock wettability• reacts with oil to form surfactants• adjusts pH and salinity• alters rock chemistry, reducing adsorption• acts as a mild biocide• stabilizes polyacrylamide to H2 S catalyzed
oxidative degradation• surfactant
• reduces oil-water interfacial tension• alkali plus surfactant
• synergistic interfacial tension reduction
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Alkaline Agents
Increase solution pH > 7
Most common alkalis used in chemical floods are:
• soda ash (Na2 CO3 )
• caustic soda (NaOH)
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Surfactant
Surfactant (surface active agent)
C7 – C10
C4 – C5
CH3
H3C
H3C SO-
3 Na+
Hydrophobic
Hydrophillic
AnionicCationicNon-ionicZwitterionic - Amphoteric
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oiloil
waterwater
kk
MobilityPhaseDisplacedMobilityPhaseDisplacingM
μμ
//
==
Mobility Control Mechanism
Improves EVI and EA
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Polymers
Macromolecules composed of repetitive units - monomers
Most common CEOR polymers are:
• hydrolyzed polyacrylamide (HPAM)
• xanthan gum (biopolymer)•Most important CEOR property
• changing mobility of injected fluid
• increase viscosity
• reduce effective water permeability
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Oil Displacement in 5-spotWaterflood, break through in 1 hour 19 minutes
Polymer flood, break through at 2 hours and 4 minutes, better sweep
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Alkali,Surfactant, and Polymer• Capillary Number Mechanism
• alkali• surfactant
• improve oil removal from pores
• Mobility Control Mechanism• polymer
• improve contact efficiency• improve displacement of oil to well
• Combining Mechanisms• synergistic oil recovery
SURTEK
Wilmington Crude Oil
Waterflooded to Sorw = 0.40 Vp
Flooded with 1 pore volume low IFT slug
Flushed with 2 pore volumes of water
Recovered 0.05 pore volume incremental oil
Sof = 0.352 “
dia.
2 foot length©
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Capillary Number Mechanism
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Wilmington Crude OilWaterflooded to Sorw = 0.40 Vp
Sof = 0.35
Sof = 0.36
Flooded with 1 pore volume polymer = oil viscosityFlushed with 2 pore volume of water
Recovered 0.04 pore volume incremental oil
©
SURTEK
Mobility Control Mechanism
Capillary Number Mechanism
2 foot length
2 “
dia.
SURTEK
Flooded with 1 pore volume ASP Solution Viscosity of ASP Solution = oil viscosity
Recovered 0.37 pore volume incremental oil
Sof = 0.03
Sof = 0.36
Sof = 0.35
©
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Capillary Number Mechanism
Mobility Control Mechanism
Combined Capillary Number and Mobility Control Mechanisms
2 foot length
2 “
dia.
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0.0 0.5 1.0 1.5 2.0 2.5 3.0Normalized Cumulative Produced Fluids (PV / PV Waterflood)
0.0
0.5
1.0
1.5
2.0
N
orm
aliz
ed C
umul
ativ
e O
il R
ecov
ery
(%O
OIP
Rec
over
y / %
OO
IP W
ater
flood
)
Alkaline-Surfactant-Polymer FloodWaterflood
Berea
J Sand
Muddy
Sand Type Effect on Recovery
reservoir rock is critical for a successful design
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Tanner Field
Mellott Ranch
Cambridge
Timing of Floods• Cambridge
secondary flood• Tanner
waterflood to40% oil cut
• Mellott Ranch35 yearswaterflood to5% oil cut
Alkaline-Surfactant-Polymer Floods
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Secondary Alkaline-Surfactant-Polymer Flood Net Pay Isopach
Alkaline- Surfactant- Polymer Flood InjectionWell
Cambridge FieldASP area = 5,684 MBBL PV
Mobility Ratio = 2.2 to 5.8
Permeability = 845 md
Oil API Gravity = 20o
Oil Viscosity = 31 cpAlkaline-Surfactant-Polymer flooding beginning 1993
SPE Res. Eng., Dec. 2000
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Cambridge Alkaline-Surfactant-Polymer Flood Production
1989 1993 1997 2001 2005
1,000
10,000
100,000O
il (b
bl/m
onth
)
1
10
100
% O
il C
ut
ActualActualSimulatedOil Cut
Oil Production
HistoryMatchPrimary
ForecastSecondaryASP Flood
Primary
Alkaline-Surfactant-Polymer Flood
SURTEK
Cambridge Federal 23-28
1989
1994
1999
2004
2009
100
1,000
10,000
100,000
Oil
(bbl
/mon
th) -
Wat
er (b
bl/m
onth
)
0.1
1.0
10.0
100.0
% O
il C
ut
Oil Cut
Oil
Water
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Cambridge Alkaline-Surfactant-Polymer Flood Recovery Summary
Ultimate Oil Recovery 73.2 %OOIPPrimary and Waterflood 39.8 %OOIP
ASP Incremental Recovery 33.4 %OOIP
Cost per Incremental Barrel 2.95 $/bblcost includes chemicals and plant
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Cambridge Comparison Alkaline-Surfactant-Polymer Flood
0.00 0.05 0.10 0.15 0.20 0.25 0.30 0.35 0.40 0.45 0.50Cumulative Oil after Injection Begins
Cumulative Waterflood or ASP Oil (Vp)
1
10
100%
Oil
Cut
Field ComparisonsCamridgeMellott Ranch ASP floodAverage Waterflood
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Alkaline- Surfactant- Polymer Flood InjectionWell
Mid-Waterflood Alkaline-Surfactant-Polymer Flood Net Pay Isopach
SPE 100004
Tanner FieldASP area = 2,528 MBBL PV
Mobility Ratio = 3.2
Permeability = 200 md
Temperature 175oF
Oil API Gravity = 21o
Oil Viscosity = 11 cp
Waterflood beginning November 1997
Alkaline-Surfactant-Polymer flooding beginning March 2000
SURTEK
Tanner, Wyoming Alkaline-Surfactant-Polymer Flood
1991 1993 1995 1997 1999 2001 2003 2005 2007 20091
10
100
% O
il C
ut
1,000
10,000
100,000
Mon
thly
Oil
Prod
uctio
n (b
bls)
Primary
Waterflood
Alkaline-Surfactant-PolymerFlood
Oil Cut
Oil Production
CalculatedContinuedWaterfloodOil Cut
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Tanner Alkaline-Surfactant-Polymer Flood Recovery Summary
Ultimate Oil Recovery 65.0 %OOIP
Primary and Waterflood 48.0 %OOIPto 3% oil cut
ASP Incremental Recovery 17.0 %OOIP
Cost per Incremental Barrel $4.49 (estimated)Includes Chemical and Facilities
Primary and Waterflood 31.3 %OOIPto 3/2000 – 40% oil cut
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Tanner Alkaline-Surfactant-Polymer Flood Production Compared to Eight Minnelusa Waterfloods
Tanner
0.00 0.05 0.10 0.15 0.20 0.25 0.30 0.35 0.40 0.45 0.50Cumulative Oil Produced After Injection Begins (PV)
1
10
100
% O
il C
ut
Field ComparisonsCamridgeTotal Tanner FieldTanner 24-30Tanner 22-31Tanner Calculated WaterfloodAverage Waterflood
arrows incicate start of ASP for TannerMay 2000
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Alkaline- Surfactant- Polymer Flood InjectionWells
Tertiary Alkaline-Surfactant-Polymer Flood Net Pay Isopach
`H
Water Injection Well
Mellott Ranch FieldASP area = 12,200 MBBL PV
Mobility Ratio = 7.6
Permeability = 640 md
Temperature 133oF
Oil API Gravity = 21o
Oil Viscosity = 23 cp
Waterflood beginning December 1965
Alkaline- Surfactant- Polymer flooding beginning August 2000
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Mellott Ranch Northeast Sand, Northern Wells 34-02, 41-11, and 11-12H Producing
21-11 and 32-1 Injecting
1961 1966 1971 1976 1981 1986 1991 1996 2001 20061.0
10.0
100.0
% O
il C
ut
1,000
10,000
100,000
Mon
thly
Oil
and
Wat
er P
rodu
ctio
n (b
bls)
Oil CutOilWater Injection
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Mellott Ranch Northeast Sand, Northern Wells 34-02, 41-11, and 11-12H Producing
21-11 and 32-1 Injecting
1991 1995 1999 2003 2007 20111.0
10.0
100.0
% O
il C
ut
1,000
10,000
100,000
Mon
thly
Oil
and
Wat
er P
rodu
ctio
n (b
bls)
Oil CutOilWater Injection
ASP Injection August 2000
Polymer DriveJune 2004
WaterMay 2006
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Mellott Ranch Northeast Sand Waterflood Comparison Alkaline-Surfactant-Polymer Flood
0.00 0.05 0.10 0.15 0.20 0.25 0.30 0.35 0.40 0.45 0.50Cumulative Oil Produced After Injection Begins (PV)
1
10
100
% O
il C
ut
Field ComparisonsCamridgeMellott Ranch ASP floodAverage Waterflood
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Secondary Alkaline-Polymer Flood Net Pay Isopach
Thompson Creek FieldAP area = 26,000 MBBL PV
Mobility Ratio = 13.6
Permeability = 1,400 md
Temperature 88oF
Oil API Gravity = 19o
Oil Viscosity = 300 - 515cp
Waterflood beginning July 2002
Alkaline- Polymer flooding beginning May 2004
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10
100
1000
STB
/day
Jul-87 Jul-92 Jul-97 Jul-02 Jul-07 Jul-12 Jul-17 Jul-22
020406080
100
Oil
Cut
%
Thompson Cr. – Wyoming USABegin AP Injection
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Thompson Cr. – Wyoming
Additional Recovery
Less Injection
0.0 0.5 1.0 1.5 2.0 2.5Cumulative Injection, PV
0
1,000
2,000
3,000
4,000
5,000
6,000
Cum
ulat
ive
Oil,
MB
BL
Alkaline-Polymer ForecastWaterflood ForecastActual
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Alkaline-Polymer FloodEtzikomAP area = 21,500 MBBL PV
Mobility Ratio = 17.2
Permeability = 1000 md
Temperature 86oF
Oil API Gravity = 19o
Oil Viscosity = 100 cp
Waterflood beginning 1971
Alkaline- Polymer flooding beginning December 2000
SURTEK1967 1972 1977 1982 1987 1992 1997 2002 2007 2012
0
10
20
30
% O
il C
ut
0
10,000
20,000
30,000
Mon
thly
Oil
and
Wat
er P
rodu
ctio
n (b
bls)
Field Oil CutField Oil Rate
APDec 2000
Polymer DriveMarch 2003
WaterMay 2005
Chemical Flood oil productionmatches historical maximum rate
Oil CutIncrease2.5 to 17.0%
Oil Rate Increase10,200 bbl/m to29,100 bbl/m
Alkaline-Polymer Flood Etzikom C Pool 22,000,000 bbl Full Field
SURTEKSURTEK1967 1972 1977 1982 1987 1992 1997 2002 2007 2012
0.1
1.0
10.0
100.0
% O
il C
ut
100
1,000
10,000
100,000
Mon
thly
Oil
and
Wat
er P
rodu
ctio
n (b
bls)
Oil CutOilWater Production
Etzikom Alkaline-Polymer FloodWell 03-24 of C Pool
33 years primary and waterflood
7.5 years alkali-polymer flood
SURTEKSURTEK
0 50,000 100,000 150,000 200,000 250,000 300,000Cumulative Oil (bbls)
0.1
1.0
10.0
100.0
% O
il C
ut
100
1,000
10,000
100,000
Mon
thly
Oil
and
Wat
er P
rodu
ctio
n (b
bls)
Oil CutOilWater Production
Etzikom Alkaline-Polymer FloodWell 03-24 of C Pool
33 years primary and waterflood140,000 bbls
7.5 years alkali-polymer flood140,000 bbls additional
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Alkaline-Surfactant-Polymer FloodWarnerASP area = 50,000 MBBL PV
Mobility Ratio = 10.9 – 12.4
Permeability = 2100 md
Temperature 95oF
Oil API Gravity = 19o
Oil Viscosity = 58 cp
Polymer Flood beginning 19672 injection wells
Water beginning 1972
Alkaline-Surfactant-Polymer flooding beginning May 2006
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1963 1968 1973 1978 1983 1988 1993 1998 2003 2008 2013
0
2
4
6
8
10
% O
il C
ut
0
20,000
40,000
60,000
80,000
100,000
Mon
thly
Oil
Prod
uctio
n (b
bl)
Oil CutOil Rate
ASP InjectionMay 2006
Oil Rate Increasedfrom 9,000 bbl/m to49,600 bbl/m
Oil Cut Increasedfrom 1.7 to 8.4%
Alkaline-Surfactant-Polymer Flood Warner 50,000,000 bbl Full Field
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What Makes a Successful Flood?
• reservoir engineering and geology• laboratory evaluation• numerical simulation• facilities design• careful field operations• monitoring flood performance
SURTEK
Thank You!
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