Primary funding is provided by

The SPE Foundation through member donations and a contribution from Offshore Europe

1

The Society is grateful to those companies that allow their

professionals to serve as lecturers

Additional support provided by AIME

Society of Petroleum Engineers

Distinguished Lecturer Programwww.spe.org/dl

“Smart Water” Flooding in Carbonates and Sandstones:A New Chemical Understanding of the EOR-potential

Tor Austad(tor.austad@uis.no)

University of Stavanger, Norway

2

Example: “Smart Water” in Chalk

Spontaneous imbibition: Tres=90 oC; Crude oil AN=0.5; Swi=10%

Chalk: 1-2 mD

•Formation water: VB

•Seawater: SW

•Seawater depleted in NaCl

•Seawater depleted in NaCl and spiked with 4x sulfate3

Example: ”Smart Water” in Limestone

Spontaneous imbibition at 130°C of FW and SW into

Res# 4-12 using crude oil with AN=0.50 mgKOH/g. Low

perm. 0.1-1 mD.

4

Example: “Smart Water” in Sandstone

40

50

60

Low Salinity EOR-effect under forced displacement

0

10

20

30

0 2 4 6 8 10PV Injection

Reco

very

(%

)

B15-Cycle-2

High SalinityLow Salinity

HS: 100 000 ppm; LS: 750 ppm

5

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 • “Smart water” can be made by modifying the ion

composition.

– No expensive chemicals are added.

– Environmental friendly.

• Wetting condition dictates:

– Capillary pressure curve; Pc=f(Sw)

– Relative permeability; kro and krw = f(Sw)

6

Water flooding

• Water flooding of oil reservoirs has been performed for a century with the purpose of:

– Pressure support

– Oil displacement

• Question:

– Do we know the secret of water flooding of oil reservoirs??– Do we know the secret of water flooding of oil reservoirs??

– If YES, then we must be able to explain why a “Smart Water” sometimes increases oil recovery and sometimes not.

• If we know the chemical mechanism, then the injected water can be optimized for oil recovery.

• Injection of the “Smartest” water should be done from day 1.

7

Outline

• Discuss the conditions for observing EOR-effecets by «Smart Water» in:

– Carbonates

– Sandstones– Sandstones

• A very simplified chemical explanation

8

Wetting properties in carbonates

• Carboxylic acids, R-COOH

– AN (mgKOH/g)

• Bases (minor importance)

– BN (mgKOH/g)

• Charge on interfaces

- - - -

+ + + + + + +

- - - -

+ + + + + + +

Ca2+ Ca2+ Ca2+

• Charge on interfaces

– Oil-Water

• R-COO-

– Water-Rock

• Potential determining ions

– Ca2+, Mg2+,

– (SO42-, CO3

2-, pH)

- - - -

- - - - -SO4

2- SO42- SO4

2-

9

Ekofisk

• Why is injection of seawater such a tremendous success in the Ekofisk field?

– Highly fractured

– High temperature, 130 oC.

– Low matrix permeability, 1-2 mD

• Wettability:• Wettability:– Tor-formation: Preferential water-wet

– Lower Ekofisk: Low water-wetness

– Upper Ekofisk: Neutral to oil-wet

• Estimated recoveries– 1976: 18%

– 2001: Goal: 46%

– NPD; 2002: 50%

– 2007: Goal 55 %0

400

19

72

19

76

19

80

19

84

19

88

19

92

19

96

20

00

20

04

20

08

20

12

20

16

20

20

20

24

20

28

OIL

RA

TE

, M

ST

BD

(G

RO

SS

)

10

Brine composition

Comp. Ekofisk Seawater

(mole/l) (mole/l)

Na+ 0.685 0.450

K+ 0 0.010

Mg2+ 0.025 0.045

Ca2+ 0.231 0.013Ca 0.231 0.013

Cl- 1.197 0.528

HCO3- 0 0.002

SO42- 0 0.024

Seawater: [SO42-]~2 [Ca2+] and [Mg2+]~ 2 [SO4

2-]

[Mg2+]~4 [Ca2+]

11

Effect of Sulfate in SW

•Crude oil: AN=2.0 mgKOH/g

•Initial brine: EF-water

•Imbibing fluid: Modified SSW

•Spontaneous imbibition at 100 oC

50

60

0

10

20

30

40

50

0 10 20 30 40

Oil

Re

cov

ery

, %

OO

IP

Time, days

SW4S at 100°C

SW3S at 100°C

SW2S at 100°C

SW at 100°C

SW½S at 100°C

SW0S at 100°C

12

Is Ca2+ active in the wettability alteration?

• Crude oil: AN=0.55 mgKOH/g

• Swi = 0; Imbibing fluid: Modified SSW

• Spontaneous imbibition at 70 oC

50

60

0

10

20

30

40

50

0 10 20 30 40 50 60

Oil

Re

cov

ery

, %

OO

IP

Time, days

SW4Ca at 70°C

SW3Ca at 70°C

SW at 70°C

SW½Ca at 70°C

SW0Ca at 70°C

13

Co-Adsorption of SO42- and Ca2+ vs.

Temperature

0.25

0.50

0.75

1.00

C/C

o

C/Co SCN FL#7-1 SSW-M at 21°C A=0.174

C/Co SO4 FL#7-1 SSW-M at 21°C

C/Co SCN FL#7-2 SSW-M at 40°C A=0.199

C/Co SO4 FL#7-2 SSW-M at 40°C

C/Co SCN FL#7-3 at 70°C A=0.297

C/Co SO4 FL#7-3 at 70°C

C/Co SCN FL#7-4 at 100°C A=0.402

C/Co SO4 FL#7-4 at 100°C

C/Co SCN FL#7-5 at 130°C A=0.547*(Extrapolert

Method:

1. Core saturated with SW without SO4

2-

2. Core flooded with SW spiked with SCN- (Chromatographic separation of SCN- and SO 2-)0.00

0.6 0.8 1.0 1.2 1.4 1.6 1.8 2.0 2.2PV

C/Co SCN FL#7-5 at 130°C A=0.547*(Extrapolert

2.6PV)C/Co SO4 FL#7-5 at 130°C

0.0

0.5

1.0

0.5 1.0 1.5 2.0 2.5 PV

C/C

o

C/Co Ca2+ Test #7/1 SW at 23°C

C/Co Ca2+ Test #7/2 SW at 40°C

C/Co Ca2+ Test #7/3 SW at 70°C

C/Co Ca2+ Test #7/4 SW at 100°C

C/Co Ca2+ Test #7/5 SW at 130°C

separation of SCN- and SO42-)

14

Affinities of Ca2+ and Mg2+ towards the chalk surface

2.00

T=23 oC T=130 oC

NaCl-brine; [SCN-] = [Ca2+] = [Mg2+]= 0.013 mole/l

CaCO3(s) + Mg2+ = MgCO3(s) + Ca2+

0.00

0.25

0.50

0.75

1.00

0.6 0.8 1.0 1.2 1.4 1.6 1.8 2.0 2.2 2.4 2.6PV

C/C

o

C/Co SCN (Brine with Mg andCa2+) at 23C [Magnesium] A=0.084C/Co Mg2+ (Brine with Mg2+and Ca2+) at 23°C

C/Co Ca2+ (Brine with Mg2+and Ca2+) at 23°C

0.00

0.25

0.50

0.75

1.00

1.25

1.50

1.75

2.00

0.6 0.8 1.0 1.2 1.4 1.6 1.8 2.0 2.2 2.4 2.6 2.8 3.0PV

C/C

o

C/Co SCN (Brine with Mg and Ca2+)at 130°C

C/Co Mg2+ (Brine with Mg2+ andCa2+) at 130°C

C/Co Ca2+ (Brine with Mg2+ andCa2+) at 130°C

15

Effects of potential determining ions and temperature on spontaneous imbibition

Imbibition at 70 & 100oC (with/without Ca & Mg)

40

60

Re

co

ve

ry, %

OIIP

25:SWx0CaMg(+Mg@43days)

26:SWx0Sx0CaMg(+Mg@ 53 days)

27:SWx2Sx0CaMg(+Ca@43 days)

28:SWx4Sx0CaMg(+Mg@53 days)

0

20

40

0 20 40 60 80 100 120Time, days

Re

co

ve

ry, %

OIIP

70°C

100°C 130°C

16

Suggested wettability mechanism

17

Can SO42- compensate for low Tres ?

30

40

50

60

70

oil

recovery

(%

OO

IP)

100°C (Oil A, AN=2.07)

130°C (Oil A, AN=2.07)

0

10

20

30

SSW-US SSW-½S SSW SSW×2S SSW×4S

Imbibing fluids

Maximum oil recovery from chalk cores when different imbibing fluids

were used (SW with varying SO42- conc.). Oil: AN=2.07 mgKOH/g).

18

Ion composition in PW from Ekofisk

0.04

0.05

0.06

Co

ncen

trati

on

(m

ole

/l)

(PW)calc*

(PW)exp

PW contained 73.6 vol% SW and 26.4 vol%FW

0

0.01

0.02

0.03

Ca2+ Mg2+ SO42-

Component

Co

ncen

trati

on

(m

ole

/l)

Fig. 3 Calculated and measured component concentration in

PW linked to substitution of Ca2+

by Mg2+

at the rock surface,

adsorption of SO42-

onto the rock and precipitation of CaSO4.

19

Can modified SW be an even “Smarter” EOR-fluid

Spontaneous imbibition: Tres=90 oC; Crude oil AN=0.5; Swi=10%

•Formation water: VB•Seawater: SW•Seawater depleted in NaCl•Seawater depleted in NaCl and spiked with 4x sulfate

20

Effect of Salinity and Ion concentration

21

The access of potential determining ions to the calcite surface

is affected by the concentration of non active ions in the double layer

Forced displacement using «Smart SW Water»

20

30

40

Re

co

ve

ry,

% O

OIP

22

0

10

0 3 6 9 12 15

Re

co

ve

ry,

% O

OIP

Injected PV

FW-0S

SW

SW-0NaCl

Oil recovery by forced displacement from the composite

limestone reservoir core. Successive injection of FW, SW and

SW-0NaCl. Ttest: 100°C. Injection rate: 0.01 ml/min (≈0.6 PV/D).

Low salinity EOR-effects in carbonates

SPE 137634 Ali A. Yousef et al. (Saudi Aramco)

23

Codition for observing low salinity EOR-effects in carbonates

• The carbonate rock must contain anhydrite, CaSO4(s)

• Chemical equilibrium:

CaSO4(s) ↔ Ca2+(aq) + SO42-(aq) ↔ Ca2+(ad) + SO4

2-(ad)

• The concentration of SO42-(aq) depends on:4

– Temperature (decreases as T increases)

– Brine salinity (Ca2+ concentration)

• Wettability alteration process:

– Temperature (increases as T increases)

– Salinity (increases as NaCl conc. decreases)

• Optimal temperature window

– 90-110 oC ?

24

Presence of CaSO4

Concentration profiles of Ca2+, Mg2+, and SO42- when flooding

reservoir limestone core with DI water, after aging with FW.

Ttest: 100°C, Injection rate: 0.1 ml/min.

25

Low salinity EOR-effect

20

30

40

50

60

Re

co

ve

ry,

% O

OIP

22% of OOIP

6

8

10

12

14

16

18

20

Su

lfa

te c

on

cen

tra

tio

n,

mM

FW-0S

10× dil. FW-0S

100× dil. FW-0S

0

10

0 3 6 9 12 15 18 21 24

Re

co

ve

ry,

% O

OIP

Injected PV

FW-0S 100× dil. FW-0S

Oil recovery by forced displacement from a

reservoir limestone core containing anhydrite.

Successive injection of FW, and 100× diluted FW.

Ttest: 100°C. Injection rate: 0.01 ml/min (≈1 PV/D).

0

2

4

0 50 100 150

Su

lfa

te c

on

cen

tra

tio

n,

mM

Temperature, °C

Simulated dissolution of CaSO4(s) when exposed to

FW-0S, 10× and 100× diluted FW at different

temperatures.

26

“Smart Water” in Sandstone

• Some experimental facts

– Porous medium

• Clay must be present

– Crude oil– 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+)

27

General information

Adsorption onto clay

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

30

Suggested mechanism

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 6

31

Clay minerals

• Clays are chemically unique

– Permanent localised negative charges

– Act as cation exchangers

• General order of affinity: • General order of affinity:

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

32

Adsorption of basic materialQuinoline

Kaolinite

Nonsweeling(1:1 Clay)

Burgos et al.

Evir. Eng. Sci.,

19, (2002) 59-68.

Montmorillonite

Swelling (2:1 clay, similar in structure to illite/mica)

33

Kaolinite: Adsorption reversibility by pH

5,00

6,00 Adsorption pH 5

Desorption pH 8-9

QuinolineSamples 1-6: 1000 ppm brine.Samples 7-12: 25000 ppm brine

0,00

1,00

2,00

3,00

4,00

5,00

0 5 10 15

Ad

so

rpti

on

(m

g/g

)

Sample no.

Readsorption pH 5.5

Desorption pH 2.5

34

Adsorption of acidic components onto Kaolinite

pHinitial ΓΓΓΓmax

µµµµmole/m2

Adsorption of benzoic acid onto kaolinite at 32 °C from a NaCl brine

(Madsen and Lind, 1998)

µµµµmole/m2 5.3 3.7 6.0 1.2 8.1 0.1

Increase in pH increases water wetness for an acidic crude oil.

35

Oil: Acidic or Basic

50

60

Total oil: AN=0.1 and BN=1.8 mgKOH/g

Res 40: AN=1.9 and BN=0.47 mgKOH/g

0

10

20

30

40

0 2 4 6 8 10 12 14

PV Injection

Reco

very

(%

)

B-15 TOATL Oil

B-11 Res-40 Oil

36

Lower initial pH by CO2 increses the low salinity effect

70

80

Low Salinity

10

Core No.

Swi %

TAging ° C

TFlooding ° C

Oil LS brine Formation Brine

B18 19.76

60 40 TOTAL Oil

Saturated With CO2

at 6 Bars

NaCl: 1000 ppm

TOTAL FW 100 000 ppm

B14 19.4 60 40 TOTAL Oil NaCl:1000 ppm

TOTAL FW

100 000 ppm

0

10

20

30

40

50

60

70

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

High Rate

4

5

6

7

8

9

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

CO2 + H2O ↔ H2CO3 + OH- ↔ HCO3- + H20 37

LS water increases oil-wetness

38

Adsorption of Quinoline vs. pH at ambient temperature for LS (1000 ppm) and HS (25000 ppm) fluids.

Ref. Fogden and Lebedeva, SCA 2011-15(Colloids and Surfaces A (2012)Adsorption of crude oil onto kaolinite

It is not a decrease in salinity, which makes the clay more water-wet, but it is an increase in pH

Snorre field

• Lab work– Negligible tertiary low salinity effects after flooding

with SW, on average <2% extra oil.

– Tres=90 oC

• Single well test by Statoil– Confirmed the lab experiments

• Question: – Why such a small Low Salinity effect after flooding

Snorre cores with SW ?

39

New study at UoS: Lunde formation

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

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

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

40

Plagioclase

• Anionic polysilicates give alkaline solution

– Albite as example:

NaAlSi3O8 + H2O ↔ HAlSi3O8 + Na+ + OH-

• At moderate salinities, the pH of FW will be • At moderate salinities, the pH of FW will be

above 7, which means low adsorption of polar

components onto clay; negligible LS EOR-effect.

• Due to buffer effects, the pH of FW was not

decreased significantly by adding CO2.

41

Snorre (Lunde) Core 13

CO2 was added

Low salinity effect of about 3-4 % of OOIP with SW as low salinity fluid

Fig. 3. Recovery vs. injected PVs for Core 13. Flooding rate of 2 PV/D; Tres = 90 oC.

42

Varg field: SPE 134459

• Reservoir temperature: 130 oC

• Salinity 201 000ppm

• Brine composition;

Ta=90 , Tf=130oC Ta=130 , Tf=130oC

43

Relationship: T and pH

• Wettability alteration of clay by LS water:

Clay-Ca2+ + H2O ↔ Clay-H+ + Ca2+ + OH- + heat

• Desorption of active cations from the clay surface is an

exothermic process, ∆H<0.– Divalent cations (Ca2+, Mg2+) are strongly hydrated in water, and as the – Divalent cations (Ca2+, Mg2+) are strongly hydrated in water, and as the

temperature increases the reactivity of these ions increases, and the

equilibrium is moved to the left.

– The change in pH should decrease as the temperature increases.

– Dissolution of anhydrite, CaSO4(s), will move the equilibrium to the left.

44

Gamage, P., Thyne, G. Systematic investigation of the effect of temperature during aging

and low salinity flooding of Berea sandstone and Minn, 16th European Symposium on

Improved Oil Recovery, Cambridge, UK, 12-14 April, 2011.

Temperatur – pH screening

8

9

10

11p

H

45

Change in effluent pH versus PV injection fluid in core RC2 at temperatures ranging from 40 °C to 130 °C. The brine flooding sequence was HS-LS-HS.

5

6

7

0 4 8 12 16 20 24

Injected PV

40 °C

90 °C

130 °C

Excellent LS EOR conditions(Quan et al. IEA EOR Symposium 2012, Regina, Canada)

Minerals: Plagioclase ≈ 22%, Total clay ≈ 25% (mostly Illite and kaolinite)

FW: Ca2+ : 0.061 mole/l, Total salinity 57114 ppm

Tres = 65 oC

k = 1-2 mD, Φ=0.11

14.5% LS EOR-effect

46

Summary

• «Smart water» EOR in Carbonates

– Optimal brine composition

• Modified SW: Depleted in NaCl and spiked with

SO42-: Active ions SO4

2-, Ca2+, Mg2+SO4 : Active ions SO4 , Ca , Mg

– Tres>70 oC

– Conditions for LS EOR-effects

• Formation must contain dissolvable anhydrite,

CaSO4.

47

Summary

• «Smart Water» EOR effects in Sandstone

– Formation water:

• pH < 6.5

• Reasonable high Ca2+ and total salinity.

– Clay must be present (Illite and kaolinite)– Clay must be present (Illite and kaolinite)

– Plagioclase can affect the pH both in a positive and negative way LS EOR effects depending on initial salinity.

– Combination of high Tres (>100 oC) and high conc. of Ca2+ can make the formation too water-wet.

– A pH-HS/LS scan can give valuable information of the potential for LS-EOR effects.

48

Acknowledgement

Statoil,

ConPhil,

NFR

Total,

Talisman, Talisman,

BP,

Maersk,

Shell,

Saudi Aramco,

DNO International.

49

EOR-group at UoS, 2010

50

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