success in surfactant eor: avoid the failure mechanisms

Success in Surfactant EOR: Avoid the Failure Mechanisms

George J. HirasakiPetroleum Engineering, Texas A&M

November 9, 2010

Requirements for Surfactant EOR

• Ultra-Low IFT• Mobility Control• Transport Across Reservoir

Phase Behavior of Anionic Surfactant, Brine, and OilReed and Healy, 1977

Interfacial Tension Correlates with the Volume Ratios in the Microemulsion

Healey, Reed, and Stenmark, 1975

Capillary Number Required for Displacement Depends on Wettability

Stegemeier, 1975

Waterfloods

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 1.50Injected Pore Volumes

A successful ASP Process Dolomite sand pack

0.2% NI, 0.5 PV, 2% NaCl, 1% Na2CO3, 5000ppm polymer,MY4 crude oil (19cp)

Displacement profiles with ASP and foam drive

Layered sandpack with 19:1 permeability contrast about half-swept with water only but about completely swept with

surfactant-alternated-gas (SAG)

0.0 TPV

0.2 TPV

0.4 TPV

0.6 TPV

0.8 TPV

1.0 TPV

SAG, 6 psi, fg=1/3 Water only, 4 psi

Oil Recovery by Gravity Drainage

0

10

20

30

40

50

0.01 0.1 1 10 100 1000

Time, days

Oil

Reco

very

, %O

OIP

0.05% TDA-4PO/0.3M Na2CO3, aged, 90 md, Soi=0.71, Sor=0.51

0.05% Blend/0.3M Na2CO3, aged, 122 md, Soi=0.68, Sor=0.38

0.05%Blend/0.3M Na2CO3, 40 md, Soi=0.82, Sor=0.70

9 months in F.B. 0.05% Blend/0.3M Na2CO3

Conditions Favorable or Challenging for Surfactant EOR

Favorable• Low – moderate salinity• Moderate temperature• Clean sandstone• No anhydrite (CaSO4)• Water-wet• Med - high permeability• Homogeneous• High Sorw

• On shore• Do ASP flood ASAP

Challenging• High salinity• Low or high temperatures• Carbonate• Anhydrite• Oil-wet• Low permeability• Fractured• Low Sorw

• Off shore• Do research

Challenges to Ultra-Low IFT (1/4)

• System becoming over-optimum because– Mixing with higher salinity formation brine– Ion exchange with clays– Dissolution of anhydrite– Live oil different from STO; GOR dependent– Oil/water ratio is parameter in ASP

Clays Act Like an Ion-Exchange Bed and Micelles as Mobile Ion-Exchange Media

Hirasaki, 1982; Gupta, 1980


• System becoming over-optimum because– Mixing with higher salinity formation brine– Ion exchange with clays– Dissolution of anhydrite– Live oil different from STO; GOR dependent– Oil/water ratio is parameter in ASP

Optimal salinity of alkaline surfactant system is function of surfactant concentration and water/oil ratio

0

2

4

6

8

10

12

14

0.01 0.1 1 10

Surfactant Concentration, %

Opt

imal

NaC

lCon

c, %

WOR=1WOR=3WOR=10

0

2

4

6

8

10

12

14

0.01 0.1 1 10

Surfactant Concentration, %

Opt

imal

NaC

lCon

c, %

WOR=1WOR=1WOR=3WOR=3WOR=10WOR=10

Optimal salinity correlates with soap/surfactant ratio

0

2

4

6

8

10

12

14

1.E-02 1.E-01 1.E+00 1.E+01Soap/Synthetic surfactant Mole Ratio

Opt

imal

NaC

l Con

c., %

. WOR=1 (TC Blend)

WOR=3 (TC Blend)WOR=10 (TC Blend)NI blend

NI BlendTC Blend

SorSoapX

1.0

2.0

3.0

4.05.0

0.5

90%

70%

50%

30%

Optimum Curve

30%50%70%

90%

Simulations show high recovery possible with combinations of injected salinity and system soap/surfactant ratio

Soap/(Soap+Surfactant)


• Injected under-optimum because– Surfactant precipitation at optimal salinity– Polymer separates at optimal salinity– Surfactant retention high at optimal salinity– Soap generated in situ with ASP

There is synergism in blending surfactants.

* Cloudy after 9 months.

Phase boundary

Precipitation

Clear solution2 clear phases

Cloudy solution%N

aCl

0123456789

10

IOSN67

1:1 4:1

N67:IOS (w/w)

9:1

1-Phase Region

**

**

Multi-Phase Region

Phase boundary

Precipitation

Clear solution2 clear phases

Cloudy solution%N

aCl

0123456789

10

IOSN67

1:1 4:1

N67:IOS (w/w)

9:1

1-Phase Region

**

**

Multi-Phase Region

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

Concentration profiles show soap/surfactant ratio passing across optimal with resulting ultra-low IFT

Surfactant

Soap

Soap/surfactant

IFT

Oil saturation

0.5 PV 1.0 PV


• Salinity gradient versus constant salinity– Constant salinity can have divalents change

• Mineral dissolution• Ion exchange

– Salinity gradient dependent on mixing

Mixing with Formation Water and Polymer Drive Govern Transport Across Formation

Nelson, 1981

Surfactant is Retarded by High Salinity Ahead of Slug and Mobilized by Low Salinity Behind Slug

Hirasaki, 1983, Nelson, 1982


• Minimum IFT not ultra-low; >10-2 mN/m– Low solubilization ratio– Poor surfactant activity– To much co-solvent, e.g. alcohol– Minimum IFT based on transient value

Minimum Dynamic IFT

Dynamic IFT of fresh oil and 0.2%NI-1%Na2CO3-1%NaCl

1.E-04

1.E-03

1.E-02

1.E-01

1.E+00

0 50 100 150 200 250 300Time, minutes

IFT,

mN

/m

Challenges to Mobility Control• Polymer gels• Polymer degradation

– Bio- or thermal degradation of xanthan– Shear degradation of polyacrylamide, PAM– Chemical degradation of PAM

• Oxygen• Iron• Free radicals

• Polymer-surfactant interactions– Colloidal interaction– Addition of high MW oil– Surfactant in middle phase, polymer in excess brine– Microemulsion with viscosity

Challenges to Mobility Control (2/2)

• Viscous emulsions and gels– Usually associated with over-optimum conditions– Liquid crystal – low temperature, possible need for

alcohol – Linear versus branched surfactant (e.g., IOS, i-TD,

N67)• Reservoir wettability• Underestimate reservoir heterogeneity• Foam destabilized by oil

Transport Across Reservoir (1/2)• Chemical stability

– Hydrolysis of sulfate surfactant– Polymer stability

• Alkali consumption– Anhydrite (calcium sulfate) can consume alkali– Clays exchange divalent and hydrogen ions

• Surfactant retention– Partition into oil phase (over-optimum)– Adsorption on rock (opposite charge)

• Sandstone versus carbonate• Redox potential; siderite, pyrite

– Alkali can reduce adsorption and sequester divalent ions– Nonionic for carbonate formation

Alkali (Na2CO3) reduces adsorption of surfactant on calcite

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 2.0Residual Surfactant Concentration (mmol/L)

Adso

rptio

n D

ensi

ty, 1

0 -3 m

mol

/m 2

3% NaCl

5% NaCl

Surfactant: NI Blend

5% NaCl

without alkali

3% NaCl

with ~1% Na2CO3

0.0

0.2

0.4

0.6

0.8

1.0

1.2

0.00 0.02 0.04 0.06 0.08 0.10 0.12 0.14

Residual Surfactant Concentration(Wt%)

Ads

orpt

ion

Den

sity

(mg/

m2 )

Anionic surfactant on dolomite without alkali, plateau=83 Å2/molecule

Anionic surfactantwith Na2CO3(0.2M,0.3M,0.4M)plateau = 830 Å2/molecule

Nonionic surfactant on dolomite plateau=714 Å2/molecule

Comparisons of Anionic Surfactant (CS330+TDA-4PO 1:1) and Nonionic Surfactant (Nonylphenol-12EO-3PO) Adsorption on DOLOMITE Powder

0.0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

0.00 0.02 0.04 0.06 0.08 0.10 0.12

Residual Surfactant Concentration(Wt%)

Ads

orpt

ion

Den

sity

(mg/

m2 )

Nonionic surfactant on silica

CS330 on silica5000 Å2/molecule

Plateau 184 Å2/molecule.

Comparisons of Anionic Surfactant (CS330) and Nonionic Surfactant (Nonylphenol-12EO-3PO) Adsorption on SILICA Powder

Transport Across Reservoir (2/2)

• Filtration and plugging– Injected surfactant solution must be clear– Nonionic surfactant may be added – Scaling with divalent, bicarbonate, and sulfate– Softening, chelating, or inhibiting scale– Polymer – iron interactions– Filtration plugging scales with volume/area

• Produced emulsions– Modify emulsion breaking

Bottle Tests: Cationic and Amphoteric Surfactants (50 ppm) & Demulsifier A (50 ppm) 21 hours equilibration

1 2 3 4 5 1 – No added chemicals 4 – Demulsifier A + Cocobetaine

2 – Demulsifier A + C8TAB 5 – Demulsifier A + Octylbetaine3 – Demulsifier A + capryl/capraamidopropyl betaine

C8TAB diluted to 2.5wt% in water, Amphoterics diluted to 5wt.% in water, and Demulsifier A diluted to 5 wt.% in Heavy Aromatic Naphtha.

Conclusions• Low tension, mobility control, and transport

across reservoir are required for success.• Surfactant EOR must be tailored for specific

reservoir conditions.• Some reservoirs are ideal for ASP.• Some reservoirs are challenging.• Over sight of a failure mechanism may result

in failure of the process.

Polymer Surfactant interaction paper with Tham

Show over-optimum system followed by low salinity

Ultra-low, equilibrium IFT over wide salinity range possible with Na2CO3

1.E-04

1.E-03

1.E-02

1.E-01

1.E+00

1.E+01

0 1 2 3 4 5 6Salinity(% NaCl)

IFT(

mN

/m)

Without Na2CO3With 1% Na2CO3

Sweep efficiency with SAG, WAG, and waterflood as function of PV liquid injected

0.0

0.2

0.4

0.6

0.8

1.0

0 0.5 1 1.5 2 2.5 3

PV's of Liquid Injected

Swee

p Ef

ficie

ncy

SAG fg=2/3, 8psi

SAG fg=2/3, 6psi

SAG fg=4/5, 4psi

SAG fg=2/3, 4psi

SAG fg=3/4, 4psi

SAG fg=2/3, 2psi

SAG fg=1/3, 6psi

SAG fg=1/2, 4psi

WAG fg=4/5, 4psi

WAG fg=3/4, 4psi

WAG fg=2/3, 4psi

WAG fg=1/2, 4psi

Water fg=0, 4psi

SAG

WAG

Waterflood

NI Surfactant Blends Improve Calcium Tolerance

1-Phase Region

Multi-Phase Region

N67-7PO S:IOS-15/18 (w/w)

0.5% N67-7PO&IOS, 2% NaCl

0.0%

0.5%

1.0%

1.5%

2.0%

2.5%

N67-7PO

CaCl

2 C

once

ntra

tion

Phase Separation

Precipitation

Clear

IOS 1:4 1:2 1:1 2:1 4:1 9:1

Lower-phase microemulsion at 2% NaCl has an oil-rich

layer of colloidal dispersion

Colloidaldispersion

Lower phasemicroemulsion

Excessoil

Colloidaldispersion

Lower phasemicroemulsion

Excessoil

Buoyancy Contributes to MobilizationPennell, Pope, Abriola, 1996

2 22 sin

cos

cos

T Ca Ca B B

w wCa

ow

rwB

ow

N N N N NuN

g k kN

success in surfactant eor: avoid the failure mechanisms

Documents

optimal salinitysoap

optimal salinity correlates

surfactant concentration

high recovery possible

asp clays act

overoptimum becausemixing

wateroil ratio

ionexchange bed