Force workshop 6-7 Nov 2013 Competence... · Force workshop 6-7 Nov 2013. ... pressure maintenance...
Transcript of Force workshop 6-7 Nov 2013 Competence... · Force workshop 6-7 Nov 2013. ... pressure maintenance...
Polymer flooding - an option for NCS?
Arne Skauge
CIPR, Uni Research
14:30 – 15:15
CIPR – CENTRE FOR INTEGRATED PETROLEUM RESEARCHCIPR – CENTRE FOR INTEGRATED PETROLEUM RESEARCH
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OilOil RecoveryRecovery FactorFactor
Primary production
Primary and secondary recovery leads to an average RF of 35%
Secondary recovery
Natural flow and artificial lift techniques (pumps)
Water or Gas Injection ; pressure maintenance
80%RF
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40 to 50%
Wateror Gas
injection
40 to 50%
Waterinjection 20 to 30%
Waterinjection
5-20% Water injection
Worldwide Average RF ~35%
20
40
80
60
%RF
Oil viscosity (cp)0.1 1 10 100 103 104
OIL VISCOSITY (µµµµo) ����
%RF
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OilOil RecoveryRecovery FactorFactor
Primary production
Secondary recovery Tertiary recoveryChemical
Polymer Flooding:
� Improves initial sweep efficiency
� Prevents early fingering
� Water cut reduction compensates for the cost of chemicals
80%RF
Expectations on the efficiency of polymer based floods
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40 to 50%
Wateror Gas
injection
40 to 50%
Waterinjection 20 to 30%
Waterinjection
5-20% Water injection
RF ~70%
Oil viscosity (cp)
+5 to 15%Polymer only
+5 to10% Polymer only20
40
80
60
%RF
0.1 1 10 100 103 104
OIL VISCOSITY (µµµµo) ����
%RF
+ 5- 10%+ additional recovery by polymer from lower µµµµo
heterogeneous systems
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OilOil RecoveryRecovery FactorFactor
Primary production
Secondary recovery Tertiary recoveryChemical
Polymer Flooding:
� Improves initial sweep efficiency
� Prevents early fingering
� Water cut reduction compensates for the cost of chemicals
80%RF
Expectations on the efficiency of polymer based floods
CIPR – CENTRE FOR INTEGRATED PETROLEUM RESEARCH
40 to 50%
Wateror Gas
injection
40 to 50%
Waterinjection 20 to 30%
Waterinjection
5-20% Water injection
RF ~70%
Oil viscosity (cp)
+5 to 15%Polymer only
+5 to10% Polymer only20
40
80
60
%RF
0.1 1 10 100 103 104
OIL VISCOSITY (µµµµo) ����
%RF
+ 5- 10%+ additional recovery by polymer from VERY HIGH µµµµo
in Alberta+ - heavy oil
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Polymer Sweep Efficiency in Reservoirs
The profile of “incremental oil” in Polymer flooding
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Reservoir Screening CriteriaWhere Polymer Flooding Could be Applied (1991)
1991
ScreeningCriterion
Visc. controlpolymer flood
Het. controlpolymer flood Comment
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Reservoir Screening CriteriaWhere Polymer Flooding Could be Applied (1991)
1991
ScreeningCriterion
Visc. controlpolymer flood
Het. controlpolymer flood Comment
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Experiment E2000
Slab dimensions (cm) 30 x 29,8 x 2,55
x = 30 cm
y = 30 cm
z = 2 cm
injection
x x x
1 2 3
Polymers for heavy oil
Porosity 0,248
Pore Volume, PV (ml) 546
Swi 0,13
kw(Sw = 1) (Darcy) 2,3
Oil viscosity (cP) 2000
Injected Volumes (PV):
Water flood (PV) 2,3
Polymer flood (PV) 1,5
Polymer viscosity
58 cP at 10s-1
24 cP at 70s-1
Polymer 3630S
Skauge, A., Ormehaug, P.A., Vik, B.F., Fabbri, C., Bondino, I, and Hamon, G., Polymer Flood Design for Displacement of Heavy Oil analysed by 2D-imaging, EAGE 17th European Symposium on Improved Oil Recovery, St. Petersburg, Russia, 16 - 18 April 2013
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Technical data for measuring system
- X-ray adsorption
- Gamma adsorption
- X-ray camera
Saturation estimation methods
CIPR – CENTRE FOR INTEGRATED PETROLEUM RESEARCHCIPR – CENTRE FOR INTEGRATED PETROLEUM RESEARCHCentre for Integrated Petroleum Research, Bergen, Norway
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CIPR – CENTRE FOR INTEGRATED PETROLEUM RESEARCHCIPR – CENTRE FOR INTEGRATED PETROLEUM RESEARCHCentre for Integrated Petroleum Research, Bergen, Norway
Example viscous fingering at the model inlet
Pictures from X-ray camera
Slabs up to 1meter x 1meter
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2D-experiments using X-ray detection
Material: Bentheimer slabs 30cm x 30cm x 2 cm
Type of fingering observed during unstable displacement
Adverse mobility ratio floods
CIPR – CENTRE FOR INTEGRATED PETROLEUM RESEARCHCentre for Integrated Petroleum Research, Bergen, Norway
Sharpening (1) Spreading (2) Indifferent (3)
1. Sharpening fingers grow from the tip of the finger and established fingers is reinforced
(observed for miscible displacement when the mobility ratio was unfavourable [viscosity ratio 100 : 1])
2. Spreading fingers increase the area contacted with frontal displacement, thicker front)(observed when water was injected at 100% oil saturation and strong spontaneous water imbibition occur)
3. Indifferent process - no visible fingers appears even at very unfavourable mobility ratio (observed for waterflooding at Swi, both at high and low interfacial tensions)
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Waterflood E2000
Viscous water fingers develops into channels at later stage
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OBSERVATIONS
Fractal type fingers is formed at early stage of the
waterflood
Early breakthrough of water (0,04 PV)Early breakthrough of water (0,04 PV)
Fingers is broadened and the stronger fingers progress
Fingers collapse into channels at later stage
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Water- and polymer flood
40
50
60
70
Oil R
ec
ov
ery
(%
OO
IP)
Polymer both increase oil recovery and accelerate production
0
10
20
30
40
0 1 2 3 4 5 6 7 8 9
Injected Volume (PV)
Oil R
ec
ov
ery
(%
OO
IP)
E7000
E2000Force
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Oil mobilization during polymer flood
X-ray camera visualize change in oil and water saturation
2000 cP oil Change in saturations after end of waterflood
Red: increased oil saturation
Light blue: increased water saturation
Early oil mobilization through established water channels
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Change in local oil saturation during waterflood
Water channels reach low So early
Oil saturation at the end of waterflood
Sorw=0,25
Water channels reach low So early
No change in So
In unswept areas
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Oil saturations
in water channels
Position:
Border of a water
channel
Polymer flood 1,5 PV
Oil
bank
Polymer swept area
Position:
Center of a
water channel
Oil saturation at the end of polymer flood0,25 PV
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Effluent production
P C P C
First polymer slug (0.5 PV) seems sufficient slug size for maximizing oil production
Li tracer in chase water has a breakthrough around 0.5 PV
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“Polyacrylamide” or “HPAM” Polymers
[ - CH2 - CH - ]m - [ - CH2 - CH - ]n
C C
- O O O NH2
acrylate acrylamide
“Polyacrylamide” or “HPAM” Polymers
[ - CH2 - CH - ]m - [ - CH2 - CH - ]n
C C
- O O O NH2
acrylate acrylamide
Polymers
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XanthanPolysaccharide
Double helix, semi-rigid rod.
Flexible coil
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Polymer Structure
Conformation of HPAM in high and low salinity
HPAM is a polyelectrolyte - polyanionic
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AM: acrylamide
Code name type AM/AA AMPS n-VP
Superpusher SAV 522 n-VP Polymer 4 25-45% 20-25% 35-50%
Superpusher SAV 301 n-VP Polymer 3 50-65% 20-25% 15-25%
DP/GC 2878-6 n-VP Polymer 2 60-70% 20-25% 10-15%
DP/GC 2878-3 n-VP Polymer 1 65-75% 20-25% 5-10%
AN 125 SH AMPS Polymer 75-80% 20-25%
Flopaam 3630S F3P HPAM Polymer+ 100 %
Examples of high temperature and high salinity polymers
Salttolerance
Tempstability
New polymers
Best choice of polymer
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AA: acrylate
AMPS: 2-Acrylamido-2-Methylpropane Sulfonate
n_VP: n-Vinyl Pyrrolidone
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Viscosity as a function of aging time for HPAM and AN132Conditions: 80ºC, 5 wt. % NaCl included 3 wt. % IBA, Viscosity at a shear rate of 100 s-1
Best choice of polymer
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Sulfonation degree increase thermal stability
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Some positive news about salinity tolerant polymers
Effect of sulfonationdegree on viscosity and retention in saline brine
Retention
AN132 ~ 1/10 HPAM
Best choice of polymer
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•
Hydrolysed PolyAcrylaMide
different sulfonationdegrees
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Polymer retention – influence onpolymer flow in porous media
Straining
Bridging adsorption
Flow-induced adsorption
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Hydrodynamic retention
Depleted layer
Inaccessible pore volume (IPV)
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Polymer retention – influence onpolymer flow in porous media
Straining
Bridging adsorption
Flow-induced adsorption
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Hydrodynamic retention
Depleted layer
Inaccessible pore volume (IPV)
May lead to:
- Blocking of pore space (IPV)
- Early break-through
- Plugging / pressure increase
- Varying polymer concentration in effluent
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Polymer retention – influence onpolymer flow in porous media
Straining
Bridging adsorption
Flow-induced adsorption
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Hydrodynamic retention
Depleted layer
Inaccessible pore volume (IPV)During extensional flow – bridging or multilayeradsorption (Chauveteau and co-workers)
May lead to:
- Blocking of pore space (IPV)
- Early break-through
- Face plugging / injectivity reduction
- Increased loss of polymer
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Polymer retention – influence onpolymer flow in porous media
Straining
Bridging adsorption
Flow-induced adsorption
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Hydrodynamic retention
Depleted layer
Inaccessible pore volume (IPV)«Slip effect» -mixed effect, depends on severalfactors
May lead to:
- Early break-through
- Poor sweep
- Decreased viscosity at Newtonian flow
- Increased effective shear rate
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Polymer retention – influence onpolymer flow in porous media
No adsorption, No IPV 20 % PV adsorption, No IPV
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0 % PV adsorption, 25 % PV IPV 20 % PV adsorption, 25 % PV IPV
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Fluid models for viscoelasticity
η
a b c d e f g
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Fluid models for viscoelasticity
UVM
η
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Power law Ellis
Carreau
Stavland
γ
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Fluid models for viscoelasticity
� Power law
� Ellis model
� Carreau equation
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� Carreau equation
� UVM
� Stavland
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Low salinity polymer
Viscosities: Oil: 2,4cP LS brine: 1,03cP Polymer: 2,6cP
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Source: Behruz Shiran and Arne Skauge, 2012
High salinity WF
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Example – nano particle polymersSandstone reservoir core (fresh core), K=900 mD
0.5
0.6
0.7
0.8
0.9
Oil R
eco
very
(H
CP
V)
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0
0.1
0.2
0.3
0.4
0.00 5.00 10.00 15.00 20.00 25.00 30.00
Volume injected (PV)
Oil R
eco
very
(H
CP
V)
waterflood LPSForce
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In Out
Micro channel
Velocity vectors in a rectangular micro channel
Polymer particle trackingMicromodels and m-PIV (particle image velocimetry)
CIPR – CENTRE FOR INTEGRATED PETROLEUM RESEARCHCIPR – CENTRE FOR INTEGRATED PETROLEUM RESEARCH
z1
z2
Z …
zN
plane 1
plane 2
plane …
plane N
(Xi,j, yi,j)
In
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Polymer Sweep Efficiency in Reservoirs
Linear displacement efficiency (Buckley-Leverett)DO POLYMERS REDUCE RESIDUAL OIL below Sor ???Chinese school of thought on this also ….
Xia et al, SPE 114335 claim in Exptl. + Modelling Study Mechanism of the Effect of Microforces on Residual Oil in Chemical Flooding
Sor reduction as function of Weissenberg No., We = xxx
CIPR – CENTRE FOR INTEGRATED PETROLEUM RESEARCH 38
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Example of game changer
Polymer floodingTraditionally polymer is injected for sweep improvement
Old rules of tumbs
Poor injectivity (a lot of positive results on injectivity are now available)
Little effect after extensive waterflooding (new results disprove this statement)
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this statement)
Have to modify the viscosity ratio extensively (new results disprove this statement)
Additional news
Effect on microscopic displacement (lower Sor)
(viscoelastic effects, etc)
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