Alkali-Surfactant-Polymer Process Shunhua Liu George J. Hirasaki Clarence A. Miller 02.14.2006

Alkali-Surfactant-Polymer Process

Shunhua Liu

George J. Hirasaki

Clarence A. Miller

02.14.2006

Outline• Surfactant adsorption

• IFT measurement and ultra-low IFT region

• Characteristics of Alkali-Surfactant-Polymer process

• Implementation of ASP in dolomite and silica sand pack

Adsorption of 4:1 N67:IOS on Calcite in Varying Salinity and Alkalinity

0.0

0.5

1.0

1.5

2.0

2.5

3.0

3.5

4.0

4.5

5.0

0.0 0.5 1.0 1.5 2.0Residual Surfactant Concentration (mmol/L)

Ad

so

rptio

n D

en

sity

, 10 -3

mm

ol/m

2

5% NaCl, 0% Na2CO3 5% NaCl with 1.21% Na2CO3

3% NaCl, 0% Na2CO3 3% NaCl, 1.21% Na2CO3

1% NaCl, 0% Na2CO3 1% NaCl, with 1.0% Na2CO3

0% NaCl, 0% Na2CO3 0% NaCl, with 1.0%Na2CO3

Adsorption of 4:1 N67:IOS on Calcite at 5% NaCl

0.0

0.5

1.0

1.5

2.0

2.5

3.0

3.5

4.0

4.5

5.0

0.0 0.2 0.4 0.6 0.8 1.0 1.2 1.4 1.6 1.8 2.0Residual Surfactant Concentration (mmol/L)

Ad

so

rpti

on

Den

sit

y, 10 -3 m

mo

l/m

2

5% NaCl, 0% Na2CO3 5% NaCl with 0.178% Na2CO3

5% NaCl with 0.404% Na2CO3 5% NaCl with 1.21% Na2CO3

the contour of maximal adsorption for N57 IOS(4:1)

Adsorption of N67 on Calcite (17.851 m2/g)

0.0

0.5

1.0

1.5

2.0

2.5

3.0

3.5

4.0

0.0 0.5 1.0 1.5 2.0

Residual Surfactant Concentration (mmol/L)

Ad

so

rptio

n D

en

sity, 1

0 -3

mm

ol/m

2

0% NaCl, 0% Na2CO3 0% NaCl, 1% Na2CO3

Adsorption of IOS on Calcite (17.851 m2/g)

0.0

1.0

2.0

3.0

4.0

5.0

6.0

7.0

8.0

9.0

10.0

0.0 0.5 1.0 1.5 2.0 2.5 3.0 3.5 4.0

Residual Surfactant Concentration (mmol/L)

Ad

so

rptio

n D

en

sity, 1

0 -3

mm

ol/m

2

0% NaCl, 0% Na2CO3 0% NaCl, 1% Na2CO3

Adsorption of 4:1 N67:IOS and Na Oleate on Calcite

0.0

0.5

1.0

1.5

2.0

2.5

3.0

3.5

4.0

4.5

0.0 0.5 1.0 1.5 2.0Residual Surfactant Concentration (mmol/L)

Ad

so

rptio

n D

en

sity, 1

0 -3 m

mo

l/m 2

No Na Oleate, 0% NaCl (1:2 mol)(Na Oleate: Surfactant), 0% NaCl

Without Na2CO3

Adsorption of N67IOS with sodium naphthenates on Calcite

0.0

1.0

2.0

3.0

4.0

5.0

0.0 0.2 0.4 0.6 0.8 1.0 1.2 1.4 1.6Residual Surfactant Concentration (mmol/L)

Ad

so

rptio

n D

en

sity, 1

0 -3 m

mo

l/m 2

NI Blend only (1:2 weight) (sodium naphthenates:NI Blend

Without Na2CO3

Both alkali concentration and salinity influence the surfactant adsorption significantly. The presence of Na2CO3 can reduce the surfactant adsorption. However, higher salinity increases surfactant adsorption and counteracts the adsorption reduction by alkali.

The concentration domain with low surfactant adsorption for the current surfactant is: [Na2CO3]>0.2% and [NaCl]<3%.

The presence of Na2CO3 reduces the adsorption for N67 and IOS respectively significantly.

The presence of sodium oleate and sodium naphthenates from Fisher Scientific does not reduce the synthetic surfactant adsorption on calcite, in the absence of Na2CO3.

Conclusions 1





What is the oil-rich emulsion?

oil-rich emulsion

lower-phase

excess oil

microemulsion

oil-rich emulsion

lower-phase

excess oil

microemulsion

Photos of spinning drop at

different time.

0.2% NI blend / 1% Na2CO3 / 2% NaCl

Photo of two different spinning drops with different amount of oil-rich emulsion 0.2% NI blend / 1% Na2CO3 / 2% NaCl

Comparison of phase appearance of 0.2% NI / 1% Na2CO3 / x % NaCl at different settling time

NaCl%= 2.0 2.2 2.6 3.0 3.4 3.6 3.8 4.0

23 days settling

4 hours settling

NaCl%= 2.0 2.2 2.6 3.0 3.4 3.6 3.8 4.0

23 days settling

4 hours settling

3 min 20 min

60 min

P=5.1

P=13.4 (Slower)

102 min

0.2% NI blend /1% Na2CO3 / 3.4% NaCl, 23 days settling with oil-rich emulsion

3 min 20 min

60 min

P=5.1

P=13.4 (Slower)

102 min

0.2% NI blend /1% Na2CO3 / 3.4% NaCl, 23 days settling with oil-rich emulsion

2 min

135 min

210 min

0.2% NI blend /1% Na2CO3 / 3.4% NaCl, 23 days settling Remove most oil-rich emulsion

2 min

135 min

210 min

2 min

135 min

210 min

0.2% NI blend /1% Na2CO3 / 3.4% NaCl, 23 days settling Remove most oil-rich emulsion

IFT of 0.2% NI blend / 1% Na2CO3 / 2% NaCl with different settling time

1E-04

1E-03

1E-02

1E-01

1E+00

0 100 200 300 400 500 600 700

Time, minutes

IFT

, dyn

e/cm

2 hours' settling 4 hours' settling1 hour's settling2 hours settling, clear aqueous + oil-rich emulsion

1E-04

1E-03

1E-02

1E-01

1E+00

0 100 200 300 400 500 600 700

Time, minutes

IFT

, dyn

e/cm

2 hours' settling2 hours' settling 4 hours' settling4 hours' settling1 hour's settling1 hour's settling2 hours settling, clear aqueous + oil-rich emulsion2 hours settling, clear aqueous + oil-rich emulsion

The standard spinning drop IFT procedure

1. Mix the crude oil with the alkaline surfactant solutions 2. Rotate the mixture for 24 hours to reach the equilibrium.3. After settling the mixture for 4 hours, oleic and aqueous phases were

taken out into different syringes. 4. Since these samples in the syringes may continue to settle and the

settling time in the syringe may be different, they were shaken before the IFT spinning drop measurement so that they can be considered as the same sample that was obtained after 4 hours settling.

5. Before the spinning drop measurement, the aqueous phase was centrifuged in the spinning tube. Some of the oil-rich emulsion was removed by syringe because the sample will be too dark if too much oil-rich emulsion is left. The remaining oil-rich emulsion should be slightly less volume than the volume of the excess oil drop that is added into the spinning drop tube.

6. Let the oil drop settle in the vertical tube for some time (~12 hours) so that the oil-rich emulsion can equilibrate with the oil and the lower phase microemulsion.

7. Begin the spinning drop IFT measurement.

Dynamic IFT of 0.2%NI-1%Na2CO3-0%NaCl

1.E-03

1.E-02

1.E-01

1.E+00

0 50 100 150 200 250Time, minutes

IFT

, dyn

e/c

m

0% NaCl with step 6 0% NaCl without step 6


1.E-03

1.E-02

1.E-01

1.E+00

0 50 100 150 200 250Time, minutes

IFT

, dyn

e/cm



1.E-03

1.E-02

1.E-01

1.E+00

0 100 200 300 400 500 600Time, minutes

IFT

, dyn

e/c

m



1.E-03

1.E-02

1.E-01

1.E+00

0 50 100 150 200 250 300 350Time, minutes

IFT

, d

yne/

cm



1.E-03

1.E-02

1.E-01

1.E+00

0 50 100 150 200 250Time, minutes

IFT

, dyn

e/c

m

4% NaCl With step6 4% NaCl Without step 6


1.E-03

1.E-02

1.E-01

1.E+00

0 20 40 60 80 100Time, minutes

IFT

, dyn

e/c

m

5% NaCl without step 6

IFT change with salinity for 0.2NI-1%Na2CO3/WOR=3

1.00E-03

1.00E-02

1.00E-01

1.00E+00

0 1 2 3 4 5Salinity(% NaCl)

IFT

(dyn

e/cm

)

1 day settling & remove all oi-rich emulsion by centrifugeIFT vs Salinity (standard procedure)4 hours settling in step 3 & no step 623 days settling in step 3 & no step 640 days settling in step 3 & no step 6

In the alkali-surfactant system, the oil-rich emulsion plays an important role in the low IFT.

A spinning drop IFT measurement procedure which can reach the equilibrium IFT quickly for alkali-surfactant system was introduced.

The NI Blend-MY4-Na2CO3 system has a wider low IFT region than normally seen for single surfactant systems.

Conclusions 2





The width of low-tension region

Log10 IFT

Over-optimum

Under-optimum

Narrow Low IFT contour (extrapolated from the synthetic surfactant only)

Wide Low IFT contour (extrapolated from experimental data)

Log10 IFT

Over-optimum

Under-optimum

Soap /synthetic surfactant ratio =0.35

Narrow low IFT regionWide low IFT region

Recovery=62.3%Recovery=95.0%



Recovery vs Injecting Brine Salinity

0%

20%

40%

60%

80%

100%

1 2 3 4 5 6Injecting Brine Salinity(%)

Reco

very

Wide low IFT region

Narrow low IFT region

2. The effect of viscosity

injecting solution viscosity=24cp

Mobility Ratio = 0.91


Mobility Ratio =0.54





Recovery=86.1%Recovery=95.0%





The width of the low IFT region is a key factor for recovery. Narrow low IFT region will have less recovery because oil will be trapped again when the IFT increases. When the low IFT region is wide enough, less oil will be trapped after the low tension region.

ASP process is more robust because of its large operational salinity region with wide low IFT region.

The injection solution viscosity has significant effect on recovery. Lower aqueous phase viscosity, i.e., higher mobility ratio, has lower oil recovery even with wide low IFT region. This is because the oil fractional flow increases with the aqueous phase viscosity.

Conclusions 3





Treatment before ASP

Oil Flooding Water Flooding

Aged in 60ºC for 60 hours

0.1PV 0.3PV 0.5PV 1.0 PV 2.0PV 3.0PV

Dolomite sand pack

Oil Recovery of Water Flooding

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0.1

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0.6

0.7

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1.0

0.0 0.5 1.0 1.5 2.0 2.5 3.0 3.5

Pore Volumes

Cu

mu

lative O

il R

eco

very

.

0.0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

1.0

Oil

Cu

t

Cumulative Oil Recovery Oil Cut

Dolomite sand pack

ASP Process

Injecting solution viscosity: 40 cp

Injecting surfactant concentration:0.2%

Surfactant slug size: 0.5PV

Injecting salinity: 2% NaCl

Injecting alkalinity: 1.0%Na2CO3

Initial oil saturation: 0.18

Dolomite sand pack

0.05 0.10 0.15 0.20 0.25 0.30 0.35 0.40 0.45 0.50 0.55 0.60 0.65 0.70 0.75 0.90 1.50

Injecting Pore Volumes

ASP ProcessDolomite sand pack

Oil Recovery of ASP Alkaline surfactant flooding after water flooding

0.0

0.1

0.2

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0.6

0.7

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0.9

1.0

0.0 0.2 0.4 0.6 0.8 1.0 1.2 1.4 1.6 1.8 2.0

Pore Volumes

Cu

mu

lative O

ilR

eco

very

0.0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

1.0

Oil

Cu

t

Cumulative Oil Recovery Oil Cut

Dolomite sand pack

History of pressure drop

0

0.5

1

1.5

2

2.5

3

3.5

0 0.2 0.4 0.6 0.8 1 1.2 1.4 1.6

Pore Volume (PV)

Pre

ssu

re d

iffe

ren

ce (p

si)

.

Surfactant Slug

Polymer Drive

Surfactant Breakthrough

Dolomite sand pack

Effluent of ASP

0.09 0.27 0.45 0.63 0.81 0.99 1.17 1.35 1.53 1.71 1.89 2.070.18 0.36 0.54 0.72 0.90 1.08 1.26 1.44 1.62 1.80 1.98

Effluent Pore Volumes

Dolomite sand pack

Comparison between simulation and experiments

Dolomite sand pack

ASP Experiment in 40 darcy Sandpack0.5% NI, 2% NaCl

0 PV 0.1 PV 0.2 PV 0.3 PV 0.4 PV 0.5 PV 0.6 PV 0.7 PV 0.8 PV 1.5 PV

Silica sand pack

0

0.5

1

1.5

2

2.5

3

3.5

0 0.2 0.4 0.6 0.8 1 1.2 1.4 1.6

Pore Volume

Pre

ssu

re d

iffe

ren

ce (

psi)

Surfactant Slug

Polymer Drive

Surfactant Breakthrough

Silica sand pack


Comparison between simulation and experiments

Silica sand pack

0 PV 0.17 PV 0.33 PV 0.5 PV 0.67 PV 0.83 PV 1.0PV 2.0 PV

Silica sand pack

0.5% NI, 4% NaCl

ASP Experiment in 40 darcy Sandpack

0

5

10

15

20

25

30

0 0.5 1 1.5 2

Pore Volume

Pre

ssu

re D

iffe

ren

ce (

psi)

Surfactant Slug Polymer DriveSurfactant Breakthrough


Silica sand pack

0.5% NI, 4% NaCl

Phase behaviors of different ASP solutions after 1 week

0.5% N67-7PO&IOS(4:1),

0.5% FLOPAM 3330S,

4% NaCl, 1% Na2CO3

0.5% N67-7PO&IOS(4:1),

0.5% FLOPAM 3330S,

2% NaCl, 1% Na2CO3

Separate layer

Experimental results show that the ASP process with only 0.2% surfactant recovers 98% of the oil that is trapped after water-flooding. Good recoveries (>95%) were obtained in both dolomite sand pack and silica sand pack.

High salinity causes the phase separation for alkaline surfactant polymer solution. This results in loss of mobility control.

The simulation matches the experimental data.

High salinity can cause the phase separation of ASP solutions. This may result in loss of mobility control.

Conclusions 4

Documents

Alkali-Surfactant-Polymer Process Shunhua Liu George J. Hirasaki Clarence A. Miller 02.14.2006