chemical mechanism of low salinity water flooding in sandstone reservoirs...

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

“Smart water” in carbonates

0

10

20

30

40

50

60

70

0 10 20 30 40 50 60 70 80

Time (days)

Rec

over

y F

acto

r (%

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

“Smart water” in sandstones

0

10

20

30

40

50

60

0 2 4 6 8 10PV Injection

Rec

ove

ry (%

)

B15-Cycle-2

High SalinityLow Salinity

HS: 100 000 ppm; LS: 750 ppm

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)

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 ??

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+)

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)

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.

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




0

10

20

30

40

50

60

0 2 4 6 8 10 12 14

PV Injected

Re

co

ve

ry (

%)

B15 - CaCl2 Brine

B14 - NaCl Brine

B16 - MgCl2 Brine

0

20

40

60

80

100

0 2 4 6 8 10 12

Th

ou

san

ds

Brine PV Injected

Sali

nit

y (

pp

m)

4

5

6

7

8

9

10

pH

B15-SalinityB14-SalinityB16-SalinityB15-pHB14-pHB16-pH

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

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

Clay minerals

• Clays are chemically unique

– Permanent localised negative charges

– Act as cation exchangers

• General order of affinity:

Li+ < Na+ < K+ < Mg2+ < Ca2+ < H+

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.

Kaolinite: Adsorption reversibility by pH

0,00

1,00

2,00

3,00

4,00

5,00

6,00

0 5 10 15

Ad

so

rpti

on

(m

g/g

)

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

Adsorption/desorption onto illite

2,00

3,00

4,00

5,00

6,00

7,00

8,00

0 1 2 3 4 5 6 7 8 9

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




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.

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




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.)

Oil: Acidic or Basic

0

10

20

30

40

50

60

0 2 4 6 8 10 12 14

PV Injection

Reco

very

(%

)

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

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.

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

10

20

30

40

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

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.

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

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 )

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

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

Lab flooding test (SINTEF)

Question:

• Why such a small Low Salinity effect

after flooding Snorre cores with SW

???

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

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

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

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.

chemical mechanism of low salinity water flooding in sandstone reservoirs...

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