Transcript Tertiary Oil Recovery by Water Flooding: A Comparison of

“Smart Water” for Enhanced Oil Recovery:
A Comparison of Mechanism in Carbonates
and Sandstones
Tor Austad
University of Stavanger, Norway
Force seminar on Low Salinity, NPD, 15. May, 2008.
Definition
• Primary recovery
– Use the energy stored in the reservoir
• Pressure depletion
• Secondary recovery
– Pressure support by injection fluids already present in
the reservoir
• Gas injection
• Water injection (formation water or water available)
• Tertiary recovery
– Injection of fluids/chemicals not initially present in the
reservoir.
• Chemicals: Polymers; Surfactants; Alkaline; etc.
• “Smart water” to impose wettability alteration
“Smart Water” to obtain
improved wetting conditions
• Carbonates
– Often neutral to preferential oil wet
– Water injection difficult without wettability
modification.
• Sandstones
– Optimal water flood at weakly water-wet
condition (Morrow)
– Mixed wet (oil-wetness linked to clays)
Chalk: SW as “smart water”
Oil Recovery, %OOIP
50
40
30
C#4 at 110°C
20
C#5 at 110°C
SI FW
10
SI SW
VF FW
VF SW
0
0
20
40
60
80
100
Time, days
Fig. 3. Oil recovery from the cores C#4 and C#5 at 110 °C by successive spontaneous
imbibition and forced displacement. The injection rate was in the range of 0.06-0.10 PV/day,
and the P across the core varied from 6 psi at the start to 3 psi at the end. Swi ~0.1 and
AN=1.9 mgKOH/g.
Sandstone: Low Salinity flooding
Oil Production (Total Pore Volume)
0.7
0.6
0.5
0.61 PV
0.4
0.535 PV
Oil
0.3
0.2
0.1
(15,000 ppm)
(1,500 ppm)
High Salinity
Low Salinity
0
0
5
10
15
20
25
30
Water Throughput (Pore Volumes)
By: Webb et al. 2005.
Low Salinity effect well documented by BP
(By: Lager et al. 2007)
Outline
• What is the chemical mechanism for
enhanced oil recovery by “Smart Water”??
– Carbonates
– Sandstones
– Are there any similarities??
Wetting properties for carbonates
• Carboxylylic acids, R-COOH
– AN (mgKOH/g)
• Bases (minor importance)
– BN (mgKOH/g)
• Charge on interfaces
– Oil-Water
• R-COO– Water-Rock
• Potential determining ions
– Ca2+, Mg2+, SO42-,
CO32-, pH
-
-
Ca2+
Ca2+
Ca2+
+ + + + + + +
SO42-
-
- -
SO42-
- -
SO42-
-
Model composition of FB and SW
Comp.
Ekofisk
(mole/l)
Seawater
(mole/l)
Na+
K+
Mg2+
Ca2+
ClHCO3-0
0.685
0
0.025
0.231
1.197
0.450
0.010
0.045
0.013
0.528
SO42-
0
0.002
0.024
•
Seawater: [SO42-]~2 [Ca2+]; [Mg2+]~ 2 [SO42-] ; [Mg2+]~4 [Ca2+]
•
[Mg2+..SO42-]aq = Mg2+ + SO42– Stronger interaction as T increases.
Imbibition of modified SW
• Effects of SO42-
• Effcets of Ca2+
•
•
•
•
•
•
•
•
Crude oil: AN=2.0 mgKOH/g
Initial brine: EF-water
Imbibing fluid: Modified SSW
T = 100 oC
Crude oil: AN=0.55 mgKOH/g
Swi = 0;
Imbibing fluid: Modified SSW
Temperature: 70 oC
70.0
Oil recovery (%OOIP)
Recovery (%OOIP)
50.0
CS100-5 - SSW*4S
40.0
CS100-2 - SSW*3S
CS100-4 - SSW*2S
30.0
60.0
50.0
40.0
CS100-1 - SSW
30.0
20.0
CS100-1 - SSW*4Ca
CS100-3 - SSW/2S
CS100-2 - SSW*3Ca
20.0
CS100-3 - SSW
CS100-6 - SSW/US
10.0
CS100-4 - SSW/2Ca
10.0
CS100-5 - SSW/UCa
0.0
0
5
10
15
20
25
30
35
40
45
0.0
0.0
Tim e (days)
10.0
20.0
30.0
40.0
50.0
Tim e (day)
60.0
Affinity of Ca2+ and Mg2+ towards chalk
•
•
•
•
•
•
•
•
NaCl-brine,
T= 23 oC,
[Ca2+]= [Mg2+]= 0.013 mole/l
SCN- as tracer
1,00
NaCl-brine,
T= 130 oC,
[Ca2+]= [Mg2+]= 0.013 mole/l
SCN- as tracer
2.00
1.75
0,75
1.50
C/Co SCN (Brine with Mg and Ca2+) at 23C
[Magnesium] A=0,084
1.25
C/Co
C/Co
C/Co Mg2+ (Brine with Mg2+ and Ca2+) at
23°C
0,50
C/Co Ca2+ (Brine with Mg2+ and Ca2+) at
23°C
1.00
C/Co SCN (Brine with Mg and Ca2+) at 23C
[Calsium] A=0,31
0.75
C/Co SCN (Brine with Mg and Ca2+)
at 130°C
0,25
0.50
C/Co Mg2+ (Brine with Mg2+ and
Ca2+) at 130°C
0.25
C/Co Ca2+ (Brine with Mg2+ and
Ca2+) at 130°C
0,00
0.00
0,6
0,8
1,0
1,2
1,4
1,6 PV
1,8
2,0
2,2
2,4
2,6
0.6
0.8
1.0
1.2
1.4
1.6
1.8 PV
2.0
2.2
2.4
2.6
2.8
3.0
Substitution of Ca2+ by Mg2+
• Slow injection of SW without
Mg2+
– 1 PV/D
C/Co
– 1 PV/D
C/Co Ca2+ SW at 130°C
C/Co Ca2+ SW at100°C
1.6
C/Co Ca2+ SW at 70°C
C/Co
• Slow injection of SW
C/Co Ca2+ SW at 23°C
C/Co SO4 SW at 130°C
1.4
1.0
C/Co Ca2+ SW0Mg at 23°C
C/Co Ca2+ SW0Mg at130°C
1.2
C/Co SO4 SW0Mg at 130°C
0.8
1.0
0.8
0.0
1.0
2.0
3.0
4.0
0.6
PV
0.0
1.0
2.0
3.0
PV
Effects of potential determining ions and
temperature on spontaneous imbibition
Imbibition at 70 & 100oC (with/without Ca & Mg)
Recovery, %OIIP
25:SWx0CaMg(+Mg@43days)
26:SWx0Sx0CaMg(+Mg@ 53 days)
60
27:SWx2Sx0CaMg(+Ca@43 days)
28:SWx4Sx0CaMg(+Mg@53 days)
40
70°C
20
100°C
130°C
0
0
20
40
60
80
Time, days
100
120
Suggested wettability mechanism
Conditions for LoW Salinity effects
(Morrow et al. 2006)
• Porous medium
– Sandstones (not documented in carbonates)
– Clay must be present
• Oil
– Must contain polar components (acids and bases)
• Water
– FW must contain divalent cations (i. e. Ca2+, Mg2+ …Lager et al. 2007)
• Initial FW must be present
• Efficiencyn related to Swi
– Low Salinity fluid (Salinity: 1000-2000 ppm)
• Appears to be sensitive to ion composition (Ca2+ vs. Na+)
– pH of effluent water usually increases a little, but also decrease in pH
has been observed. In both cases, Low Salinity effects were observed.
• Are small changes in pH important for Low Salinity effects ??
Suggested mechanisms
• Wettability modification towards more
water-wet condition, generally accepted.
• Migration of fines (Tang and Morrow 1999).
• Increase in pH lower IFT; type of alkaline flooding
(Mcguri et al. 2005).
• Multicomponent Ion Exchange (MIE) (Lager et al.
2006).
• Small changes in bulk pH can impose great
changes in Zeta-potential of the rock (StatoilHydro)
Migration of fines
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Clay particles are released and transported at the oil-water
interface, creating water-wet surface spots.
Can improve sweep efficiency by blocking pores in already water
flooded area.
BP observed Low Salinity effects without detecting fines in the
produced fluid
Chemical reactions affecting pH
• Clay acts as cation exchanger
– Cation replacing order
• Li+<Na+<K+<Mg2+<Ca2+<H+
• pH change in solution
– Increase in pH by dilution
• Ca2+ + H2O = (Ca2+..OH-) + H+
• Clay..Ca2+ + H+ = clay..H+ + Ca2+
– Decrease in pH by ion exchange
• Clay..Ca2+ + Na+ = clay..Na+ + Ca2+
• Ca2+ + H2O = (Ca2+..OH-) + H+
– Great buffering effects in real systems
Multicomp. Ion Exchange (MIE)
clay
clay
Difficult to write a model chemical reaction illustrating MIE
Low Salinity effects non-linear with salinity
•
•
Webb, Black, Edmond (2005)
Dead oil
•
Appears to be an upper critical
value for Low Salinity effects
0.6
Low Salinity (1000 ppm)
Oil Production (Total PV)
0.5
Sea Water Equivalent (30,000 ppm)
Reservoir Brine (80,000 ppm)
0.4
0.3
Reservoir Brine
Sea Water Equivalent
Low Salinity (1000 ppm)
0.2
0.1
0
0
5
10
15
20
25
30
Water Throughput (Pore Volumes)
It appears to be an upper critical salinity, which the Low Salinity
fluid must stay below, to observe the Low Salinity effect
Chemical Facts
• Wettability modification caused by changes in the
aqueous phase.
• The thermodynamic equilibrium between the phases
(water/oil/rock), which has been established during
geological time, is disturbed by changing the salinity of
the water.
• The solubility of polar organic component in water is
affected by ion composition and salinity
– Salting Out / Salting In effects
• Salinity gradients to optimize conditions for surfactant
flooding (oil in water, three-phase, water in oil)
• CMC related to salt effects
• Adsorption at interfaces (oil-water, water-rock)
Salting Out and Salting In effects
• Organic material in water is solvated by formation of
water structure around the hydrophobic part due to
hydrogen bonds between water molecules. (structure
makers)
• Inorganic ions (Ca2+, Mg2+, Na+) break up the water
structure around the organic molecule, and decreases
the solubility (structure breakers, Salting Out).
– The relative strength of cations as structure breakers is reflected
in the hydration energy
• Decrease in salinity below a critical ionic strength will
increase the solubility of organic materials in the
aqueous phase. This is called Sating In effect.
Hypothesis
• The main mechanism for Low Salinity
effects is related to changes in the
solubility of polar organic components in
the aqueous phase, described as a
“Salting In” effect.
(1) Experiments to verify the hypothesis
• Low Salinity fluid should be characterized
in terms of Ionic strength rather than
salinity
– Compare Low Salinity effects using NaCl and
CaCl2 ( [CaCl2] = ½ [NaCl] )
– If the Low Salinity effect is quite similar for the
two fluids, the Low Salinity mechanism is
more linked to solubility properties rather than
MIE at the rock surface.
(2) Experiments to verify the hypothesis
•
No correlation between AN and
Low Salinity effect (Lager et al.
2006)
• Test Low Salinity effects for
oils with and without water
extractable acids and bases
present.
• Is there a correlation between
AN and BN of extractable
acids and bases and Low
Salinity effect ???
•
According to the hypothesis,
the desorbed organic material
must be partly soluble in water
(3) Experiments to verify the hypothesis
• Test the difference in hysteresis for the adsorption and desorption of
substituted benzoic acid onto kaolinite using FW and Low Salinity
fluid.
– Difference in hysteresis will reflect difference in solubility properties for
FW and Low Salinity water
– Temperature effects ?
– Effects of Low Salinity fluid composition ??
+ Kaolinite
Conclusion on “Smart Water”
• Carbonate
– The chemistry of fluid-rock interaction is well
characterized
• Wetting agent: Carboxylic materials, difficult to remove
• Wettability modifiers: Ca2+, Mg2+, SO42-, Temp.
• Wetting modification at SW-salinity, which is not regarded as a Low
salinity fluid.
• Sandstone
– The chemistry of fluid–rock interaction is more complicated
• The organic material adsorbs differently onto clay minerals, but it is
more easily removed compared to carbonates.
• So fare, no single proposed mechanism has been clearly accepted
for the observed Low Salinity effect.
• A hypothesis involving “Salting In” effects has been suggested, and
actual experiments are proposed to verify the hypothesis.
Conclusion on “Smart Water”
• The chemical mechanism for using “Smart
Water” for wettability alteration to enhance
oil recovery is different for Carbonates and
Sandstones.