“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”

0

10

20

30

40

50

0 20 40 60 80 100Time, days

Oil

Re

co

very

, %

OO

IP

C#4 at 110°C

C#5 at 110°C

SI FW

SI SW

VF FW

VF SW

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

0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0 5 10 15 20 25 30

Water Throughput (Pore Volumes)

Oil

Prod

uctio

n (T

otal

Por

e Vo

lum

e)

High Salinity Low Salinity

0.535 PV Oil

0.61 PV

(15,000 ppm) (1,500 ppm)

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+

- - - -

- - - - -SO4

2- SO42- SO4

2-

Model composition of FB and SW

Comp. Ekofisk Seawater (mole/l) (mole/l)

Na+ 0.685 0.450K+ 0 0.010Mg2+ 0.025 0.045Ca2+ 0.231 0.013Cl- 1.197 0.528

HCO3- 0 0.002

SO42- 0 0.024

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

2-] ; [Mg2+]~4 [Ca2+]

• [Mg2+..SO42-]aq = Mg2+ + SO4

2-

– Stronger interaction as T increases.

Imbibition of modified SW

• Effects of SO42-

• Crude oil: AN=2.0 mgKOH/g

• Initial brine: EF-water

• Imbibing fluid: Modified SSW

• T = 100 oC

• Effcets of Ca2+

• Crude oil: AN=0.55 mgKOH/g

• Swi = 0;

• Imbibing fluid: Modified SSW

• Temperature: 70 oC

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

ove

ry (

%O

OIP

)

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

0.0 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

Affinity of Ca2+ and Mg2+ towards chalk

• NaCl-brine,

• T= 23 oC,

• [Ca2+]= [Mg2+]= 0.013 mole/l

• SCN- as tracer

• NaCl-brine,

• T= 130 oC,

• [Ca2+]= [Mg2+]= 0.013 mole/l

• SCN- as tracer

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 and Ca2+) at 23C[Magnesium] A=0,084

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

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

C/Co SCN (Brine with Mg and Ca2+) at 23C[Calsium] A=0,31

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

Substitution of Ca2+ by Mg2+

• Slow injection of SW

– 1 PV/D

• Slow injection of SW without Mg2+

– 1 PV/D

0.6

0.8

1.0

0.0 1.0 2.0 3.0PV

C/C

o

C/Co Ca2+ SW0Mg at 23°C

C/Co Ca2+ SW0Mg at130°C

C/Co SO4 SW0Mg at 130°C

0.8

1.0

1.2

1.4

1.6

0.0 1.0 2.0 3.0 4.0PV

C/C

o C/Co Ca2+ SW at 130°C

C/Co Ca2+ SW at100°C

C/Co Ca2+ SW at 70°C

C/Co Ca2+ SW at 23°C

C/Co SO4 SW at 130°C

Effects of potential determining ions and temperature on spontaneous imbibition

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

0

20

40

60

0 20 40 60 80 100 120Time, days

Re

co

ve

ry, %

OIIP

25:SWx0CaMg(+Mg@43days)

26:SWx0Sx0CaMg(+Mg@ 53 days)

27:SWx2Sx0CaMg(+Ca@43 days)

28:SWx4Sx0CaMg(+Mg@53 days)

70°C

100°C 130°C

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 finesadsorbed polar oil components

Adsorption of Polar Components from Crude Oil and Mobilized Clay Particles at Brine/Oil Interface

oil

water

solid

clays

a. adsorption onto clay surface

oil

b. clay particle

clay

oil

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

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0.1

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0.5

0.6

0 5 10 15 20 25 30

Water Throughput (Pore Volumes)

Oil

Prod

uctio

n (T

otal

PV)

Reservoir BrineSea Water EquivalentLow Salinity (1000 ppm)

Low Salinity (1000 ppm)

Sea Water Equivalent (30,000 ppm)

Reservoir Brine (80,000 ppm)

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)

• According to the hypothesis, the desorbed organic material must be partly soluble in water

• 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 ???

(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+, SO4

2-, 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.