alkaline-surfactant-polymer flooding flooding - laboratory and single well chemical tracer test...
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Copyright of Royal Dutch Shell plc 3 November 2010 1
Alkaline-surfactant-polymer flooding
Laboratory and single well chemical tracer test (SWCT) results
Rien FaberShell International and Production BV
Fields for ASP single well tracer tests
Field A Field B Field C
Oil viscosity (mPa.s) 100 9 2
Total acid number (mg KOH/g oil)
0.77 0.08 0.04
Permeability (mD) 1000+ ~ 600200 - 1000
~ 10010 – 200
Make-up water salinity (TDS – mg/l))
4795 10860 Fresh water,< 1000
Temperature (oC) 46 54 83 (downhole)During SWCT (cooling): 70
Mineralogy (% clays ~ adsorption / consumption)
~ 570% Kaolinite
~ 8.580% Kaolinite
~ 1060% Kaolinite
20% Illite20% Chlorite
Design of ASP formulation for SWCT and learnings from SWCT
Phase behaviour studies to establish optimum salinity Flow experiments in Bentheim/Berea sandstone to determine
– Activity of ASP formulation – Mobility requirements
Flow experiments in reservoir core material to determine influence of mineralogy on
– Surfactant retention– Caustic consumption– Oil recovery efficiency
Single well chemical tracer tests (SWCT) to determine– Handling of chemicals – Preparation of ASP and polymer solutions on a larger scale– Injectivity– ASP formulation effectiveness in reducing the remaining oil saturation after
water flooding
Surfactant formulation design for Field A
Phase behaviour studies at University of Texas identified suitable surfactant formulation, based on two of Shell Chemical’s ENORDETTM surfactants
Solubilisation ratio = 10 ift = 3 x 10-3 mN/m
0
5
10
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0 10000 20000 30000 40000 50000 60000 70000 80000
Electrolyte Concentration, ppm Na2CO3
So
lub
iliz
ati
on
Rati
o, cc/c
c
Oil
Water
Minas Crude ( filt)
Temp = 46 C
After 58 days
Sodium Carbonate scan
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30
0 10000 20000 30000 40000 50000 60000 70000 80000
Electrolyte Concentration, ppm Na2CO3
So
lub
iliz
ati
on
Rati
o, cc/c
c
Oil
Water
Crude A
Temp = 46 C
After 58 days
Sodium Carbonate scan
0.3% ENORDET surfactants, 1% co-solventoil/water ratio = 1:1
Phase behaviour at 1% surfactantconcentration
Surfactant formulation design for Field A
Bentheim sandstone core0.3 PV ASP slug/polymer drive: 100 mPa.sROS = 46.4%Surfactant retention: 0.043 mg/g rock
0.0
0.2
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1.0
1.2
0.0 0.5 1.0 1.5 2.0 2.5 3.0 3.5 4.0
Injected fluid volume (PV)
Oil
re
co
ve
ry (
fra
cti
on
So
r),
C/C
o &
u/u
o
Viscosity produced polymer/viscosity injected polymer
Oil production (fraction Sor)
C/Co surfactant
C/Co Na2CO3
Reservoir core materialASP solution: 100 mPa.sROS = 21.8%Surfactant retention: 0.29 mg/g rock
0.0
0.1
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1.0
0.0 0.2 0.4 0.6 0.8 1.0 1.2 1.4 1.6 1.8 2.0
Injected fluid volume (PV)
Oil
re
co
ve
ry (
fra
cti
on
So
r),
C/C
o &
u/u
o
Oil production (fraction Sor)
C/Co surfactant
C/Co Na2CO3
Viscosity produced polymer / viscosity injected polymer
Single Well Tracer Theory
Figure 5
EtOH (Product) and EtAc (Cover) Tracers
Hypothetical 1-Layer Test Result
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0 100 200 300 400 500 600 700 800 900 1000
Produced Volume (barrels)
Co
nce
ntr
atio
n E
tOH
(p
pm
)
0
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Co
nce
ntr
atio
n E
tAc
(pp
m)
EtOH
Example Data
EtAc
Example Data
Injection: Ester (30 m3) + Push water (120 m3).Ester partially partitions in oil.
Shut-in: 2 days. Ester partially hydrolyses to ethanol. Ethanol in water phase.
Back production:Ethanol travels faster than ester.
Result:Ethanol and ester return as separate peaks.Peak distance is used to calculate Sor.
Field A – Well completion and injection schedule
Injection schedule ASP flood• 420 m3 ASP solution overdisplaced with 420 m3
water• 150 m3 tracer injection of which the first 30 m3
contained the tracer (ethyl formate)
845 – 875 m
Field A – SWCT operation
Polymer slicing unit
3 x 32 m3 tanks for preparing chemical EOR fluids
Chemical storage
Field A - Tracer test response after water and ASP flooding
EtOH (Product) and NPA (Cover) Tracers
Best-Fit 3-Layer Model (CFSIM)
0
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0 100 200 300 400 500 600 700 800 900 1000 1100 1200 1300 1400 1500 1600 1700 1800 1900
Produced Volume (barrels)
Co
nc
en
tra
tio
n E
tOH
(p
pm
)
0
100
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600
Co
nc
en
tra
tio
n N
PA
(p
pm
)
EtOH (Product) and NPA (Cover) Tracers
Best-Fit 2-Layer Model (CFSIM)
0
100
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300
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600
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0 100 200 300 400 500 600 700 800 900 1000 1100 1200 1300 1400 1500 1600
Produced Volume (barrels)
Co
nc
en
tra
tio
n E
tOH
(p
pm
)
0
100
200
300
400
500
600
700
800
900
Co
nc
en
tra
tio
n N
PA
(p
pm
)Best-Fit 2-Layer Model
Sor = 0.01
Best-Fit 3-Layer
Model
Sor = 0.25
IPA tracer in the ASP fluidcontained ethanol and thisaffected the tracer profile
Sor after water flooding
Sor after ASP flooding
CTI performed tracer test and history matching of the tracer response
Fields for ASP single well tracer tests
Field A Field B Field C
Oil viscosity (mPa.s) 100 9 2
Total acid number (mg KOH/g oil)
0.77 0.08 0.04
Permeability (mD) 1000+ ~ 600
200 - 1000
~ 100
10 – 200
Make-up water salinity (TDS – mg/l))
4795 10860 Fresh water,
< 1000
Temperature (oC) 46 54 83 (downhole)
During SWCT (cooling): 70
Mineralogy (% clays ~ adsorption / consumption)
~ 570%
Kaolinite
~ 8.580% Kaolinite
~ 1060% Kaolinite
20% Illite20% Chlorite
Surfactant formulation design for Field BPhase behaviour with surfactant formulation: 0.3% ENORDET surfactants (two components), 1% co-solvent
Flow experiments in Bentheim sandstoneASP solution/polymer drive – 20 mPa.s 60% recovery ASP solution/polymer drive – 30 mPa.s 92% recovery
0.0
0.1
0.2
0.3
0.4
0.5
0.6
0.7
0.8
0.9
1.0
0.0 0.5 1.0 1.5 2.0 2.5 3.0
Injected fluid volume (PV)
Oil
reco
very
(fr
acti
on
Sor),
C/C
o &
u/u
o
Viscosity produced polymer/viscosity injected polymer
Oil production (fraction Sor)
C/Co surfactant
C/Co Na2CO3
0.0
0.1
0.2
0.3
0.4
0.5
0.6
0.7
0.8
0.9
1.0
0.0 0.5 1.0 1.5 2.0 2.5 3.0
Injected fluid volume (PV)
Oil
reco
very
(fr
acti
on
Sor),
C/C
o &
u/u
o
Viscosity produced polymer/viscosity injected polymer
Oil production (fraction Sor)
C/C0 surfactant
C/C0 Na2CO3
Surfactant formulation design for Field B
Injection side
Production side
Injection side Production side
Injection side
Production side
Injection side Production side
Improved mobility
20 mPa.s at 6 s-1 30 mPa.s at 6 s-1
Field B - Tracer test response after water and ASP flooding
EtOH (Product) and NPA (Cover) Tracers
Best-Fit 3-Layer Model (CFSIM)
0
200
400
600
800
1000
1200
1400
1600
0 200 400 600 800 1000 1200 1400 1600 1800 2000 2200 2400 2600 2800 3000 3200 3400 3600 3800
Produced Volume (barrels)
Co
nc
en
tra
tio
n E
tOH
(p
pm
)
0
100
200
300
400
500
600
700
800
900
1000
Co
nc
en
tra
tio
n N
PA
(p
pm
)
Best-Fit 3-Layer
Model
Sor = 0.20
EtOH (Product) and NPA (Cover) Tracers
Best-Fit 3-Layer Model (CFSIM)
0
200
400
600
800
1000
0 200 400 600 800 1000 1200 1400 1600 1800 2000 2200 2400 2600 2800 3000 3200 3400 3600 3800
Produced Volume (barrels)
Co
nc
en
tra
tio
n E
tOH
(p
pm
)
0
100
200
300
400
500
600
700
Co
nc
en
tra
tio
n N
PA
(p
pm
)
Best-Fit 3-Layer
Model
Sor = 0.04
Injection schedule ASP flood• 320 m3 ASP solution overdisplaced with 290 m3 polymer drive and 640 m3 water• 320 m3 tracer injection of which the first 64 m3 contained the tracer (ethyl formate)• 36 m interval
Sor after water flooding
Sor after ASP flooding
Fields for ASP single well tracer tests
Field A Field B Field C
Oil viscosity (mPa.s) 100 9 2
Total acid number (mg KOH/g oil)
0.77 0.08 0.04
Permeability (mD) 1000+ ~ 600
200 - 1000
~ 100
10 – 200
Make-up water salinity (TDS – mg/l))
4795 10860 Fresh water,
< 1000
Temperature (oC) 46 54 83 (downhole)
During SWCT (cooling): 70
Mineralogy (% clays ~ adsorption / consumption)
~ 570%
Kaolinite
~ 8.580% Kaolinite
~ 1060% Kaolinite
20% Illite20% Chlorite
Surfactant formulation design for Field CPhase behaviour tests
% KCl: 0.7 0.8 0.9 1.0 1.1 1.2 1.3 1.4 1.5%
Phase behaviour results with Field C crude after 3 days at 70C.WOR = 70/30, KCl salt was added to increase salinity.
ASP formulation
0.7% ENORDET surfactants (two
components)
1.0% SBA
1.0% Na2CO3
1500 ppm Flopaam 3230S
Optimum
Surfactant formulation design for Field CCore flow tests (Berea)
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
0.0 0.5 1.0 1.5 2.0 2.5 3.0
Pore Volumes Produced
% O
il or
Surf
acta
nt
start of
emulsionSurfactant
Oil cut
Cumulative oil
ASP core flow tests with Field C crude in Berea core. 1 PV ASP injected. Temperature = 70oC
Observations
95% of remaining oil recovered
Relative early oil breakthrough
Most surfactant in water phase (under-optimum)
Field C – Tracer test response after water and ASP flooding
0
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100
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250
0 20 40 60 80 100 120 140Produced Volume (m
3)
Co
nc
en
tra
tio
n E
tOH
(p
pm
)
0
100
200
300
400
500
600
700
800
Co
ncen
tra
tio
n N
PA
(p
pm
)
Layer 2 accepted 18% of the
tracer-carrying fluid.
Best-Fit 3-Layer
Model: Sor = 0.23
Layer 3 accepted 60% of
the tracer-carrying fluid.
NPA tracerEtOH
Layer 1 accepted
22% of the tracer-
carrying fluid.
Total tracer volume injected: 200 m3. Total ASP volume: 70 m3
(equivalent to 0.35 PV in core flow test)
Complex tracer response due to crossflow during
shut-in.
Tracer response modeled with 3 layers (solid lines)
Before ASP injection: remaining oil = 23 %
After ASP injection: remaining oil = 2%
Conclusions/further plans
Single well tracer tests showed that the ASP formulations were successful in reducing the oil saturation to very low values
Moving to pattern pilot tests in Field A and C Objectives:
Evaluation effectiveness ASP formulation(s), e.g. surfactant retention/propagation and caustic consumption
Fast oil recovery responseEvaluation of scaling and emulsion problems
When technical and economical issues are satisfactory resolved then further upscaling
