EOR by “Smart Water” Why · 2010-03-01 · • Water based EOR by “Smart Water” – How to optimize the ion composition of injection w ater to promote wettability alteration

EOR by “Smart Water”Why ???Why ???

Outline

• Background– Wettability

• Capillary pressure curve• Relative permeability of oil and water

• “Smart Water” in Carbonates– Chemical mechanism– Chemical mechanism– EOR-potential

• “Smart Water” in Sandstones– Chemical mechanism – EOR-potential

Research direction

• Water based EOR by “Smart Water”

– How to optimize the ion composition of injection water to promote wettability alteration to improve oil recovery by water flooding.flooding.

– Detailed knowledge about the chemical mechanism in order to be able to evaluate actual field candidates for “smart” water.

– Carbonates and Sandstones

What is “Smart Water”?

• “Smart water” can improve initial wetting properties of the reservoir and optimise fluid flow/oil recovery in porous medium during production.

• “Smart water” can be made by modifying the ion composition. No expensive chemicals are added.composition. No expensive chemicals are added.

• Wetting condition dictates– Capillary pressure curve; Pc=f(Sw)– Relative permeability; ko and kw = f(Sw)

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-

Spontaneous imbibition into chalk

Imbibition temperature 40 °C

50

60

70

80

Oil

prod

uctio

n, %

OO

IP

Oil A. AN=0, Test 1

0

10

20

30

40

50

1 10 100 1000 10000 100000 1000000

Time, min.

Oil

prod

uctio

n, %

OO

IP

Oil A. AN=0, Test 1

Oil D. AN=0.055, Test 7

Oil B. AN=0.06, Test 5

Oil E. AN= 0.41, Test 8

Oil C. AN=0.52, Test 6

Oil F. AN=1.73, Test 9

Wettability alterationStandnes and Austad, J. Pet. Sci Eng. 28 (2000) 123-143

Cationic surfactant: n-C 12N(CH3)3Br termed C12TAB• Chalk: 2 mD, T=40 oC• Oil: AN=1.0 mgKOH/g

Imbibition temperature 40 °C

0

10

20

30

40

50

60

70

0 20 40 60 80 100 120Time, days

Oil

prod

uctio

n, %

OO

IP

C12TAB, Test 1

C12TAB, Test 2

C12TAB, Test 4

Brine, Test 3

Can SW change wetting conditions of Chalk ??

• SO42- was important as a catalyst for

wettability alteration by C12TAB.– The efficiency increased as the temperature

increasedincreased

• Can seawater act as a wettability modifier at high temperature without using expensive surfactants ???!

Question:

• 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– Low matrix permeability, 1 -2 mD– Wettability:

• Tor-formation: Preferential water-wet• Lower Ekofisk: Low water-wetness• Upper Ekofisk: Neutral to oil-wet

Oil recovery prognoses

400

OIL

RA

TE

, MS

TB

D (

GR

OS

S)

2001: Goal: 46%

NPD;2002: 50%

0

1972

1976

1980

1984

1988

1992

1996

2000

2004

2008

2012

2016

2020

2024

2028

OIL

RA

TE

, MS

TB

D (

GR

OS

S)

OOIP∼∼∼∼18 %

OOIP∼∼∼∼46 %

2007: Goal 55 %

Model brine compositionComp. Ekofisk Seawater

(mole/l) (mole/l)Na+ 0.685 0.450K+ 0 0.010Mg2+ 0.025 0.045Ca2+ 0.231 0.013Ca 0.231 0.013Cl- 1.197 0.528HCO3

- 0 0.002SO4

2- 0 0.024

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

2-]

[Mg2+]~4 [Ca2+]

Effects of Sulfate and T

100 oC 130 oC

• Crude oil: AN=2.0 mgKOH/g•Initial brine: EF-water•Imbibing fluid: Modified SSW

0.0

10.0

20.0

30.0

40.0

50.0

0 5 10 15 20 25 30 35 40 45

Time (days)

Rec

over

y (%

OO

IP)

CS100-5 - SSW*4S

CS100-2 - SSW*3S

CS100-4 - SSW*2S

CS100-1 - SSW

CS100-3 - SSW/2S

CS100-6 - SSW/US

0.0

10.0

20.0

30.0

40.0

50.0

60.0

70.0

0 2 4 6 8 10 12 14

Time (days)

Rec

ove

ry (

%O

OIP

)

CS3-1 - SSW*4S

CS3-2 - SSW*2S

CS3-8 - SSW*2S

CS3-3 - SSW

CS3-4 - SSW/2S

CS3-5 - SSW/US

Parallel tests!

Sulfate adsorption-Temp. effects

0.75

1.00

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

�Chromatographic separation of SCN- and SO42-

0.00

0.25

0.50

0.75

0.6 0.8 1.0 1.2 1.4 1.6 1.8 2.0 2.2PV

C/C

o

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*(Extrapolert2.6PV)C/Co SO4 FL#7-5 at 130°C

Is Ca2+ active in the wettability alteration??

• Crude oil: AN=0.55 mgKOH/g• Swi = 0; Imbibing fluid: Modified SSW• Temperature: 70 oC

60.0

70.0

Oil

reco

very

(%

OO

IP)

0.0

10.0

20.0

30.0

40.0

50.0

0.0 10.0 20.0 30.0 40.0 50.0 60.0

Time (day)

Oil

reco

very

(%

OO

IP)

CS100-1 - SSW*4Ca

CS100-2 - SSW*3Ca

CS100-3 - SSW

CS100-4 - SSW/2Ca

CS100-5 - SSW/UCa

Affinities of Ca 2+ and Mg 2+ towards the chalk surface

0.75

1.00

C/Co SCN (Brine with Mg andCa2+) at 23C [Magnesium] 1.25

1.50

1.75

2.00

T=20 oC T=130 oC

•NaCl-brine,[Ca 2+]= [Mg 2+]= 0.013 mole/l

0.00

0.25

0.50

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

Ca2+) 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

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

/Co

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

CaCO3(s) + Mg 2+ = MgCO3(s) + Ca2+

Effects of potential determining ions on spontaneous imbibition

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

40

60

Rec

over

y, %

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

Rec

over

y, %

OIIP

70°C

100°C 130°C

Suggested wettability mechanism

High T

Test by BP on Valhall(Webb et al. IPTC 10506, Doha, 2005)

• Complete reservoir conditions, Tres=90 oC• Oil recovery using FW and SW

– Imbibition at Pc=0: FW: 22.4 %PV and SW: 31 %PV; 40% increase– Forces imbibition at Pc=-1 psi: FW: ~45%PV and SW: ~60%PV

Flow conditions

• Fractured vs. non-fractured reservoir– Spontaneous imbibition– Forced imbibition

• What is the efficiency of “Smart Water” • What is the efficiency of “Smart Water” ???

Spontaneous vs. forced imbibition

90 oC

110 oC 120 oC

Environmental aspects

• Can PW water be co-injected with SW and still act as a “Smart” EOR-fluid ???– Compatibility between SW and PW

• Precipitation of CaSO4, SrSO4, and BaSO4• Precipitation of CaSO4, SrSO4, and BaSO4

Mixtures of PW with SW at 110 oC

40

50

60

70R

ecov

ery

(%O

OIP

)

0

10

20

30

0 10 20 30 40 50Time (Days)

Rec

over

y (%

OO

IP)

SI PW1SSW8

SI PW1SSW2

SI PW1SSW1

SI PW

"FI PW"

"FI SSW"

Crude oil: AN = 1.9 mgKOH/g. Chalk

”Smart Seawater” in Chalk

110 oC 120 oC

50%

60%

70%

80%

Re

co

ve

ry F

acto

r (%

OO

IP

)

40%

50%

60%

70%

80%

Re

co

ve

ry F

acto

r (%

OO

IP

)

0%

10%

20%

30%

40%

0 10 20 30 40 50 60 70

Time (days)

Re

co

ve

ry F

acto

r (%

OO

IP

)

SSW SSW0NaCl Dil SSW 20000 Dil SSW 10000

Fig. 3. Spontaneous imbibition at 110 ºC

0%

10%

20%

30%

0 5 10 15 20 25 30 35

Time (days)

Re

co

ve

ry F

acto

r (%

OO

IP

)

SSW SSW0NaCl DilSSW 1600

DilSSW 1600 SSW4NaCl

Fig. 4. Spontaneous imbibition at 120 ºC using different imbibing fluids with different salinities and ionic composition.

EOR-potential by ”Smart Seawater” (depleted in NaCl) in Ekofisk may increase recovery by 10 % of OOIP: Money .. Money !!!!!

Forced Imbibition

• Smart SW in a tertiary process

50%

60%

70%

80%

Re

co

ve

ry F

acto

r %

0%

10%

20%

30%

40%

0.00 1.00 2.00 3.00 4.00 5.00 6.00 7.00 8.00

PV Injected (ml)

Re

co

ve

ry F

acto

r %

F.W. SSW SSW0NaCl

Fig. 11. Forced Displacement at 120ºC at the rate of 1.0 PV/day; forced displacement by formation brine, seawater and seawater without NaCl

Low Salinity

0.3

0.4

0.5

0.6

0.7

Oil

Pro

duct

ion

(Tot

al P

ore

Vol

ume)

0.535 PV

0.61 PV

N. Morrow and later BP

0

0.1

0.2

0 5 10 15 20 25 30

Water Throughput (Pore Volumes)

Oil

Pro

duct

ion

(Tot

al P

ore

Vol

ume)

High Salinity Low Salinity(15,000 ppm) (1,500 ppm)

By: Webb et al. 2005.(By: Larger et al. 2007)

The average LowSal effect is ~14 %

Important parameters

• Initial wetting– Clay

• Different clays have different pH range for optimum adsorption

– Initial FB

• LowSal fluid– Composition

• Less important ?• Low ionic strength

important• Gradient in active ions– Initial FB

• Divalent vs. mono valent ions, important ??

• pH~5 (dissolved CO2)– Crude oil

• BN important• AN important

– Temperature• High and low T, OK

• Gradient in active ions– pH change

• Local increase in pH at the clay surface important ?

– Dynamic process• Flooding rate• Irreversible desorption

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 • 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)• “Salting in” effects

Presentation linked to:

SPE 129767-PPChemical Mechanism of Low Salinity Water

Flooding in Sandstone ReservoirsFlooding 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.

Is Low Sal effect a “salting in” effect ?Adsorption/desorption onto kaolinite

• Quinoline

1.50

2.00

2.50

mg

PTB

BA

ads

orbe

d / g

kao

linite

Ads isotherm

Desorption HS#1

Desorption HS#2

Desorption LS#1

~25000 ppm

~25000 ppm

~11200 ppm

pH ~6.3

pH ~5.4

• Carboxylic acid

1.50

2.00

2.50

mg

Qui

nolin

e ad

sorb

ed /

g ka

olin

ite

25000 ppm

16000 ppmpH ~5

11000 ppmpH ~5.27200 ppm

pH ~5.3

pH ~5

2200 ppmpH ~5.1

3100 ppmpH ~5.1

4900 ppmpH ~5.2

2000 ppmpH ~5.6

3000 ppmpH ~5.6

4900 ppmpH ~5.3

1100 ppmpH ~5.3

1000 ppmpH ~6.0

0.00

0.50

1.00

0.0000 0.0010 0.0020 0.0030 0.0040 0.0050 0.0060

Equilibrium [PTBBA], mol/l (M)

mg

PTB

BA

ads

orbe

d / g

kao

linite

Desorption LS#1

Desorption LS#2

~4600 ppm

~2300 ppm~1300 ppm

pH ~6.1

pH ~4.5

0.00

0.50

1.00

0.0000 0.0005 0.0010 0.0015 0.0020 0.0025 0.0030 0.0035

Equilibrium [Quinoline], mol/l (M)

mg

Qui

nolin

e ad

sorb

ed /

g ka

olin

ite

Ads isotherm

Desorption HS#1 pH adj

Desorption HS#2 pH adj

Desorption HS#3

Desorption HS#4

Desorption LS#1 pH adj

Desorption LS#2 pH adj

Desorption LS#3

Desorption LS#4

Suggested mechanismInitial situation Low salinity flooding Final situation

Clay

NH Ca2+

O

H

H

Clay

NH Ca2+

Clay

NCa2+

H+HO

H

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.

C HO

H

Clay

Ca2+H+

R

HO

O H

OH

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– Basic material

• Clay-NHR3+ + OH- = Clay + R3N + H2O

• Acidic material• Clay-RCOOH + OH- = Clay + RCOO- + H2O

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)

Desorption of quinoline

Kaolinite

Burgos et al. Evir. Eng. Sci.,19, (2002) 59-68.

Montmorillonite

Adsorption reversibility by pH

5,00

6,00 Adsorption pH 5

Desorption pH 8-9

Readsorption pH 5.5

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

Ads

orpt

ion

(mg/

g)

Sample no.

Readsorption pH 5.5

Desorption pH 2.5

What is the role of the acidic components ??

• Adsorption of benzoic acid onto kaolinite at 32 °C in a NaCl brine (Madsen and Lind, 1998)

pHinitial Γmax µmole/m2 µmole/m

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.)

Acid – base properties similar

• BaseBH+ = H+ + BpKa=4.7

[ ][ ]B

BHpKpH a

+

+= lg [ ]B

•Acid

HA = H+ + A-

pKa = 4.9[ ]

[ ]B

BHpKpH a

+

+= lg

Fig 4. Supposed adsorption of R–COOH onto clay by H-bonding at pH 4-5. Analogue to a dimeric complex of carboxylic acid.

O C

Clay

H+

R

HO C

H

OR C

O

OR

H

O

Decrease in pH by CO 2 and H2S

5

6

7

8

pH

2

3

4

1.00E-10 1.00E-08 1.00E-06 1.00E-04 1.00E-02

mol added H2S or CO2

Varg H2SVarg CO2DW H2SDW CO2Seawater H2SSeawater CO2

Fig. 6. Simulated change in pH when CO 2 or H2S is dissolved into 200000 ppm Varg reservoir brine under pressure at 7 5 °C. Pressure was 100 atm to keep the gas in solution.

Important clay properties

Table 5 Properties of actual clay minerals (International Drilling Fluids (IDF), 1982)

Property Kaolinite Illite/Mica Montmorillonite Chlorite

Layers 1:1 2:1 2:1 2:1:1 Layers 1:1 2:1 2:1 2:1:1

Particle size (micron) 5-0.5 large sheets to 0.5 2-0.1 5-0.1

Cation exchange cap. (meq/100g)

3-15 10-40 80-150 10-40

Surface area BET-N2 (m2/g) 15-25 50-110 30-80 140

General order of affinity: Li+<Na+<K+<Mg2+<Ca2+<H+

Adsorption/desorption of cations

• Kaolinite and Chlorite– Non-swelling– Adsorption at edge surfaces– Great selectivity for Ca2+ over Na+– Great selectivity for Ca over Na– FW: significant amount of Ca2+ needed

• Illite/Mica and Montmorillonite/Smectite– Lattice substitutions are the main mechanism– Lower selectivity for Ca2+ over Na+

– FW: Low sal effect without Ca2+ possible ???

Optimal condition for low sal effect

• Balanced adsorption onto clay– Organic material– Cations

• Key process• Key process– Local increase in pH close to the clay-water

interface promoted by desorption of cations.

Salinity of Low Sal fluid

Desoroption

FWAds

orp

LS

Fig. 7 Probable/Typical adsorption isotherm of Ca2+ from high saline brine onto clay minerals of a reservoir rock at pH 4-8.

eq. conc. Ca2+

LS

Solubility of Mg(OH) 2 and Ca(OH)2 vs. pH

1E-061E-05

0.00010.001

0.010.1

1

mol

Mg2

+ or

Ca2

+

1E-111E-101E-091E-081E-071E-06

5 6 7 8 9 10 11 12 13 14

pH

mol

Mg2

+ or

Ca2

+

Mg2+ 50 °CMg2+ 100 °CCa2+ 50 °CCa2+ 100 °C

Fig. 10. Solubility of Mg(OH)2 and Ca(OH)2 versus p H at 50 and 100 oC in a 50 000 ppm NaCl brine and 6 bars.

Change in Mg 2+ can be related to precipitation of Mg(OH) 2

[Mg2+]mol/l

10-3

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>9pH≤ 8 pH≤ 8

Low Salinity

Outcrop material

• Minerals– Clay content

• Kaolinite 0 wt%• Chlorite 1.9 wt%• Chlorite 1.9 wt%• Illite 8.5 wt%

– Quartz ~57 wt%– Albite ~ 32 wt%– CaCO3 0.3 wt%

Brine and oil used

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-3 0.0 0.0 0.0171 0.0

Low Salinity Brine-4 0.0034 0.0 0.0 0.0046

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

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

Effects if Low Sal brine composition

0

10

20

30

40

50

60

Rec

over

y (%

)

B15 - CaCl2 Brine

B14 - NaCl Brine

B16 - MgCl2 Brine

Total oil

0

0 2 4 6 8 10 12 14

PV Injected

0

20

40

60

80

100

0 2 4 6 8 10 12

Tho

usan

ds

Brine PV Injected

Sal

inity

(pp

m)

4

5

6

7

8

9

10

pH

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

Effect of oil properties

40

50

60

Rec

over

y (%

)

0

10

20

30

0 2 4 6 8 10 12 14

PV Injection

Rec

over

y (%

)

B-15 TOATL Oil

B-11 Res-40 Oil

Lower initial pH by CO 2

Core No.

Swi %

TAging ° C

TFlooding ° C

Oil Low Salinity

Flood Formation Brine

B18 19.76 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

80

Low Salinity

10

0

10

20

30

40

50

60

70

0 2 4 6 8 10 12 14 16

Oil

Rec

over

y F

acto

r (%

OO

IP)

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

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

Is EOR by LowSal flooding a LowSal effect? Core No.

Swi %

TAging ° C

TFlooding ° C

Oil Low Salinity

Brine Formation Brine

B01 20.0 60 40 TOTAL Oil Low Salinity-7

NaCl 40000

ppm

Pure CaCl2 25000 ppm

B14 19.4 60 40 TOTAL Oil

Low Salinity-1

NaCl 1000

ppm

TOTAL FW

60

Low Salinity

10

0

10

20

30

40

50

0 2 4 6 8 10 12 14

Brine PV Injection

Oil

Rec

over

y F

acto

r (%

OO

IP)

B01-Cycle-1B14-Cycle-1 Reference Test

High Salinity

Low Salinity

High Rate

4

5

6

7

8

9

0 2 4 6 8 10 12 14

Brine PV Injected

pH

B01-Cycle-1

B14-Cycle-1 Reference Test

High Salinity

Low Salinity

Gradient in the concentration of the most active ions, Ca2+, most important.

Ca2+ + OH- ↔ [Ca--OH]+

Conclusion

• The chemical mechanism for wettability modification in sandstones and carbonates is different.

• NPD:• NPD:– 1% increase in oil recovery (OOIP) will give net

100-150 billion NOK

• Arild Nystad (former resource dir. at NPD)– IOR programs can give 3000 new billions NOK

Ongoing projects

• Carbonates– BP: limestone in Abu Dhabi– Maersk / UiS: limestone in Qatar– Total/NFR: Outcrop limestone– Total/NFR: Outcrop limestone– Saudi Aramco: limestone

• Sandstone:– Talisman/Total: low salinity

Personnel: EOR-Group