Chemical Mechanism of Low Salinity Water Flooding in Sandstone Reservoirs...
Transcript of Chemical Mechanism of Low Salinity Water Flooding in Sandstone Reservoirs...
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Chemical Mechanism of Low Salinity Water
Flooding in Sandstone Reservoirs
Tor Austad, Alireza RezaeiDoust and Tina Puntervold,
University of Stavanger, 4036 Stavanger, Norway
IEA EOR Conference in Aberdeen,18-20. October 2010
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“Smart water” in carbonates
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Time (days)
Rec
over
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acto
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OO
IP)
Core SK#5 T.O.
Core SK#3 T.O.
Core SK#1 O.O.
Core SK#11 O.O.
VB
SW
Spontaneous imbibition into chalk at 110 oC
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“Smart water” in sandstones
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0 2 4 6 8 10PV Injection
Rec
ove
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)
B15-Cycle-2
High SalinityLow Salinity
HS: 100 000 ppm; LS: 750 ppm
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What is “Smart Water”?
• “Smart water” can improve wetting properties of
oil reservoirs and optimize fluid flow/oil recovery
in porous medium during production.
• “Smart water” can be made by modifying the ion
composition. No expensive chemicals are
added.
• Wetting condition dictates:
– Capillary pressure curve; Pc=f(Sw)
– Relative permeability; ko and kw = f(Sw)
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Outline: “Smart Water” in Sandstones
• Some experimental facts
• Suggested chemical mechanism • Experimental documentation
• Offshore case study • Why poor low salinity effect on the Snorre field ??
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Some experimental facts
• Porous medium
– Clay must be present
• Crude oil
– Must contain polar components (acids and/or
bases)
• Formation water
– Must contain active ions towards the clay
(Especially divalent ions like Ca2+ and Mg2+)
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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).
• Extension of the double layer (Shell)
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Presentation linked to:
SPE 129767-PP
Chemical Mechanism of Low Salinity Water
Flooding in Sandstone Reservoirs
Tor Austad, Alireza RezaeiDoust and Tina Puntervold, University of
Stavanger, 4036 Stavanger, Norway
This paper was prepared for presentation at the 2010 SPE Improved Oil Recovery Symposium held in
Tulsa, Oklahoma, USA, 24–28 April 2010.
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Local increase in pH important
NaCl
(mole/l)
CaCl2 .2H2O
(mole /l)
KCl (mole /l)
MgCl2 .2H2O
(mole /l)
Connate Brine 1.54 0.09 0.0 0.0
Low Salinity Brine-1 0.0171 0.0 0.0 0.0
Low Salinity Brine-2 0.0034 0.0046 0.0 0.0
Low Salinity Brine-3 0.0 0.0 0.0171 0.0
Low Salinity Brine-4 0.0034 0.0 0.0 0.0046
0
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PV Injected
Re
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%)
B15 - CaCl2 Brine
B14 - NaCl Brine
B16 - MgCl2 Brine
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pH
B15-SalinityB14-SalinityB16-SalinityB15-pHB14-pHB16-pH
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Suggested mechanism Initial situation Low salinity flooding Final situation
Fig. 1. Proposed mechanism for low salinity EOR effects. Upper: Desorption of
basic material. Lower: Desorption of acidic material. The initial pH at
reservoir conditions may be in the range of 5-6
Clay
NH Ca
2+O
H
H
Clay
NH Ca
2+
Clay
N
Ca2+
H+H
O
H
C H
OH
Clay
Ca2+H
+
R
HO
O H
O
H
Clay
Ca2+
H+
H+
R
O-
CO
Clay
Ca2+H
+
R
HO
O C
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Chemical equations
• Desorption of cations by low sal water
– Clay-Ca2+ + H2O = Clay-H+ + Ca2+ + OH-
• Wettability alteration
– Basic material
• Clay-NHR3+ + OH- = Clay + R3N + H2O
• Acidic material
• Clay-RCOOH + OH- = Clay + RCOO- + H2O
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Clay minerals
• Clays are chemically unique
– Permanent localised negative charges
– Act as cation exchangers
• General order of affinity:
Li+ < Na+ < K+ < Mg2+ < Ca2+ < H+
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Adsorption of basic material Quinoline
Kaolinite
Nonsweeling(1:1 Clay)
Montmorillonite
Swelling (2:1 clay,
similar in structure to
illite/mica)
Burgos et al.
Evir. Eng. Sci.,
19, (2002) 59-68.
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Kaolinite: Adsorption reversibility by pH
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Ad
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Sample no.
Adsorption pH 5
Desorption pH 8-9
Readsorption pH 5.5
Desorption pH 2.5
Quinoline
Samples 1-6: 1000 ppm brine.
Samples 7-12: 25000 ppm brine
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Adsorption/desorption onto illite
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3,00
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8,00
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Adsorption
[mg base/g illite]
Test
number
Step 1: pH 5
Step 2: pH 9
Step 3: pH 5
Step 4: pH 2,5
25000 ppm 1000 ppm
Average step 1: 6,28±0,03 Average step 1: 6,45±0,05
Average step 3: 7,40±0,05 Average step 3: 7,69±0,02
Average step 4: 4,47±0,06 Average step 4: 4,54±0,02
Average step 2: 3,93±0,09 Average step 2: 2,78±0,10
Figure 4.2: Adsorption of quinoline onto illite at room temperature in 25000
ppm and 1000 ppm brine. The uncertainties are based on the standard deviation
of mean of every series. The pH in the samples was stable for at least 24 hours,
and the reproducibility are good in both high and low salinity series.
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Quinoline: Adsorption/desorption
onto montmorillonite
Figure 18: Adsorption of quinoline onto Ca2+
- montmorillonite
dictated by pH in 15000ppm brine solution at room temperature.
140,00
160,00
180,00
200,00
220,00
240,00
260,00
280,00
0 1 2 3 4
Ad
so
rpti
on
(m
g/g
)
Sample no.
Step 1: Adsorption pH 5
Step 2: Desorption pH 9
Step 3: Readsorption pH 5
Step 4: Desorption pH 2.5
Average step 1: 233 3 mg/g
Average step 2: 205 2 mg/g
Average step 4: 168 1 mg/g
Average step 3: 238 2 mg/g
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Adsorption of acidic components onto
Kaolinite
• Adsorption of benzoic acid onto
kaolinite at 32 °C in a NaCl brine
(Madsen and Lind, 1998)
pHinitial max
mole/m2
5.3 3.7
6.0 1.2
8.1 0.1
Increase in pH increases water wetness.
No correlation between AN and LowSal effects has
been detected (Larger et al.)
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Oil: Acidic or Basic
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PV Injection
Reco
very
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B-15 TOATL Oil
B-11 Res-40 Oil
Total oil: AN=0.1 and BN=1.8 mgKOH/g
Res 40: AN=1.9 and BN=0.47 mgKOH/g
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Optimal condition for LowSal effect
• Initial reservoir condition
– Balanced adsorption onto clay by
• Organic material
• Active cations
• Key process
– Local increase in pH close to the clay-water
interface promoted by desorption of cations.
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Lower initial pH by CO2
Core No.
Swi %
TAging ° C
TFloodin
g ° C
Oil Low Salinity
Flood Formation
Brine
B18 19.7
6 60 40
TOTAL Oil
Saturated With CO2
at 6 Bars
Low Salinity-1
NaCl 1000
ppm
TOTAL FW
B14 19.4 60 40 TOTAL Oil Low Salinity-
1 NaCl 1000
ppm
TOTAL FW
0
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50
60
70
80
0 2 4 6 8 10 12 14 16
Oil R
ec
ove
ry F
ac
tor
(% O
OIP
)
PV Injection
B18-Cycle-1 CO2 Saturated Oil
B14-Cycle-1 Reference Curve
High Salinity
Low Salinity
High Rate
4
5
6
7
8
9
10
0 2 4 6 8 10 12 14
Brine PV Injected
pH
B18-Cycle-1 CO2 Saturated Oi
B14-Cycle-1 Reference Test
High Salinity
Low Salinity
HCO3- + OH- ↔ CO3
2- + H20
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Solubility of Mg(OH)2 and Ca(OH)2 vs. pH
1E-11
1E-10
1E-09
1E-08
1E-07
1E-06
1E-05
0.0001
0.001
0.01
0.1
1
5 6 7 8 9 10 11 12 13 14
pH
mo
l M
g2
+ o
r C
a2
+
Mg2+ 50 °C
Mg2+ 100 °C
Ca2+ 50 °C
Ca2+ 100 °C
Fig. 10. Solubility of Mg(OH)2 and Ca(OH)2 versus pH at 50 and
100 oC in a 50 000 ppm NaCl brine and 6 bars.
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Change in Mg2+ can be related to
precipitation of Mg(OH)2
Fig. 11. Schematically change in Mg2+
concentration in the produced
water during a low salinity flood. The concentration of Mg2+
is
suggested to be quite similar for the initial FW and low saline brine.
pH>9
pH≤ 8 pH≤ 8
Low Salinity
[Mg2+]
mol/l
10-3
Lager et al. SPE 113976
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BP: Endicott field tests SPE 129692
• Increase in HCO3-
– CO2 + H2O ↔ [H2CO3] ↔ H+ + HCO3
2-
- Equilibrium is moved to right as pH is increase
• Increased concentration of Iron, Fe2+.
•Suppose the formation is containing some FeS. Due to hydrolysis of
Fe2+ in alkaline solution, the solubility of FeS can increase by a factor
of 105 or more.
• Fe2+ + OH- ↔ [ Fe- OH]+ K1 = 105.7
( Reference: J. N. Butler )
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Snorre field:
• Lab work by SINTEF
– Negligible tertiary low salinity effects after
flooding with SW, <2% extra oil.
• Single well test
– Confirmed the lab experiments
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Properties: Lower Statfjord
Oil
Brine
Rock clay content
(wt%)
• Kaolinite: 14.1
• Mica/Illite: 1.4
• Chlorite 0.1
Other minerals (wt%)
• Quartz: 50.9
•K-Feldspar 11.7
•Plagioclase 20.9
•Albite NaAlSi3O8
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Lab flooding test (SINTEF)
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Question:
• Why such a small Low Salinity effect
after flooding Snorre cores with SW
???
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New study at UoS: Lunde formation
Table 5. Properties of the oil.
AN
[mgKOH/g oil]
BN
[mgKOH/g oil]
Density (20˚C)
[g/cm3]
Viscosity (30˚C)
[cP]
Viscosity (40˚C)
[cP]
0.07 1.23 0.83653 5.6 4.0
Table 1. Mineral composition
Core Quartz
Plagioclase
Calcite Kaolinite Illite/mica Chlorite
[wt%] [wt%] [wt%] [wt%] [wt%] [wt%]
13 28.2 32.1 1.4 2.6 9.3 3.6
14 36.0 35.2 2.4 3.9 7.4 2.9
PS!! The oil was saturated with CO2 at 6 bar.
The core was flooded FW diluted 5x and the pH of the effluent stayed
above 10.
Plagioclase gives alkaline solution: pH: 7.5 to 9.5
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Snorre (Lunde) Core 13
Fig. 3. Recovery vs. injected PVs for Core 13.
Flooding rate of 2 PV/D; Tres = 90 oC.
Low salinity effect of about 3-4 % of OOIP with SW as low salinity fluid
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Snorre (Lunde) Core 14
Fig. 6. Recovery vs. injected PVs for Core 14.
Flooding rate of 2 PV/D; Tres = 90 oC.
Negligible low salinity effect
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Learning from Snorre cores
• The pH during aging even in the presence of CO2 is
relative high, >7. Low adsorption of polar components
onto clay. Material with buffer effects ( More than 30 wt%
Plagioclase)
• Due to the gradient in the Ca2+ concentration between
FW and SW, SW appeared to act as a low salinity fluid
compared to FW.
• Negligible low salinity effects after flooding with SW.