EOR in Fractured Carbonate Reservoirs – low salinity low temperature conditions

By

Aparna Raju Sagi, Maura C. Puerto, Clarence A. Miller, George J. Hirasaki

Rice University

Mehdi Salehi, Charles Thomas

TIORCO

April 26, 2011

Outline

• EOR strategy for fractured reservoirs

• Evaluation at room temperature (~25 °C)o Phase behavior studies – surfactant selectiono Viscosity measurementso Imbibition experimentso Adsorption experiments

• Evaluation at 30 °C and live oilo Phase behavior experimentso Imbibition experiements

• Conclusions

2

3

EOR strategy

• Reservoir description o Fractures – high permeability pathso Oil wet – oil trapped in matrix by capillarityo Dolomite, low salinity, 30 °C

• Recover oil from matrix spontaneous imbibitiono IFT reduction

• Surfactants

o Wettability alteration• Surfactants

• Alkali

EOR strategy

4Ref: Hirasaki et. al, 2003

Current focus – IFT reduction – surfactant flood

• Surfactant flood desirable characteristicso Low IFT (order of 10-2 mN/m)o Surfactant-oil-brine phase behavior stays under-

optimumo Low adsorption on reservoir rock (chemical cost)o Avoid generation of viscous phases o Tolerance to divalent ionso Solubility in injection and reservoir brineo Easy separation of oil from produced emulsion

5

6

Phase behavior studies at ~ 25 °C

Parameter• Salinity• Surfactant blend ratio• Soap/surfactant ratio

Optimal parameter

Winsor Type - I

Winsor Type - II

Varying parameter

Winsor Type - III

mic

ro

mic

ro

Procedure

7

Pipette (bottom sealed)

Brine + surfactant

Oil

Initial interface

Seal open end

24 hr

Phase behavior, IFT, solubilization parameter

8Reed et al. 1977Salinity, wt% NaCl

IFT

, mN

/m

So

lub

iliza

tion

pa

ram

ete

r

𝜎mo

𝜎mw

Vo/Vs Vw/Vs

middle

upper

lower

Phase behavior

• Purpose of phase behavior studieso Determine optimal salinity, Cø

• transition from Winsor Type I to Winsor Type II

o Calculate solubilization ratio, Vo/Vs and Vw/Vso Detect viscous emulsions (undesirable)

• Parameterso Salinity – 11,000 ppm (incl Ca, Mg)o Surfactant type, Blend ratio (2 surfactants)o Oil type – dead oil vs. live oilo Water oil ratio (WOR)o Surfactant concentration

9

4wt%1 1.1 1.2 1.3 1.4 1.5 1.6 1.7 1.8 1.9 Brine2

S13D Salinity scan (Multiples of Brine2)WOR ~ 1

0.5wt%

0.25wt%

op

tim

al

sa

lin

ity

op

tim

al

sa

lin

ity

op

tim

al

sa

lin

ity

Vo/Vs~ 10 at reservoir salinity

10

11

Viscosity studiesat ~ 25 °C

Viscosities of phases – function of salinity

12

0.84 0.94 1.05 1.15 1.26 1.36 1.47

Multiples of Brine 2

Op

tima

l sa

linity

rese

rvo

ir s

alin

ity

op

tim

al s

alin

ity

Oil

0.5 wt% S13D

13

Imbibition studiesat ~ 25 °C

Imbibition results – S13D reservoir cores (1”)

14

S13D 0.5wt% 126md

S13D 0.25wt% 151md

Mehdi Salehi, TIORCO

S13D candidate for EORo under-optimum at reservoir salinityo stays under-optimum upon dilutiono Vo/Vs~10 (at 4wt% surfactant concentration)

indicative of low IFToNo high viscosity phases at reservoir salinityo ~ 70% recovery in imbibition tests

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Adsorption studiesat ~ 25 °C

Dynamic adsorption – procedure

• Sand pack o Limestone sand ~ 20-40 mesh o Washed to remove fines & dried in oven

• Core holdero Core cleaned with Toluene, THF, Chloroform, methanolo Core holder with 400 – 800psi overburden pressure

• Vacuum saturation (~ -27 to -29 in Hg) o measure pore volume

• Permeability measurement

17

Dynamic adsorption - setup

18

Sample collection

Bromide concentration reading

Bromide electrode

Pressure transducer

Pressure monitoring

Core holder/ Sand pack

Syringe pump/ ISCO pump

Limestone sandpack ~ 102D

• Injection solution: Brine 2 with 1000ppm Br - + 0.5wt% S13D• Flow rate: 12.24ml/h• Pore volume: 72 ml, Time for 1PV ~ 6hrs

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• 1PV = .38 ft3/ft2

• Lag ~ 0.14 PV• Adsorption

0.26 mg/g sand0.12 mg/g reservoir rock

1PV 2PV

Reservoir core – 6mD

20

• Injection solution: Brine 2 with 1000ppm Br - + 0.5wt% S13D• Flow rate: 2ml/h• Pore volume: ~12 ml, Time for 1PV ~ 6hrs

• 1PV = .035 ft3/ft2

• Effective pore size = 26.8𝜇m

• Lag ~ 0.54PV to 1.25PV

• Adsorption0.12 mg/g rock to0.28 mg/g rock

3PV 4PV

da

y 1

da

y 3

2PV1PV

Reservoir core – 6mD plugging

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Expected pressure drop @ 15ml/hr

Expected pressure drop @ 2ml/hr

Absence of surfactant

Presence of surfactant – dyn ads exp

day 1 day 11day 3 – no data

1PV 2PV 3PV 4PV 5PV

By Yu Bian

diff in area ~ 21 %

3PV 4PV

da

y 1

da

y 3

2PV1PV

HPLC sample

HPLC analysis of effluent

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3PV 4PV2PV1PV

Reservoir core – 15mD

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• 2 micron filter @ inlet – pressure monitored• Injection solution: Brine 2 with 1000ppm Br - + 0.5wt% S13D• Flow rate: 1ml/h, Pore volume: ~30 ml, Time for 1PV ~ 1.25 days

• 1PV = .103 ft3/ft2

• Effective pore size= 11.8𝜇m

• Lag ~ 0.67PV• Adsorption

0.29 mg/g rock

Surfactant

Pressure

Bromide

1PV 2PV 3PV 4PV 5PV

da

y1

2 3 4 6 7 8 9 10

14

15

16

HPLC sample

HPLC analysis of effluent

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diff in area ~ 25 %

By Yu Bian

Adsorption results comparison

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Experiment Material Equivalent adsorption on reservoir rock

(mg/g)

Residence time (hrs)

Dynamic Limestone sand 0.12 6

Dynamic Dolomite core 6mD

0.12 – 0.28 6 - overnight

Dynamic Dolomite core 15mD

0.29 30

Static (by Yu Bian)

Dolomite powder 0.34 24

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Phase behavior studies at ~ 30 °C

S13D phase behavior

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S13D 1wt% @ 25 °C

Type I microemulsion

S13D 1wt% @ 30 °C

Type II microemulsion

S13D 1wt% @ 30 °C with live oil (600 psi)

Type II microemulsion

S13D/S13B blend scan 30°C

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10/0 9/1 8/2 7/3 6/4 5/5 4/6 3/7 2/8 1/9 0/10

S13D S13D/S13B ratio S13B

Brine 2 salinity; 2 wt% aq; WOR = 1

Op

tim

al

ble

nd

29

5

4

3

2

1

0S13D 10 9 8 7 6 5 4 3 2 1 0S13B 0 1 2 3 4 5 6 7 8 9 10

5

4

3

2

1

0

% Cs

°C

50

40

30

20

10

0S13D 10 9 8 7 6 5 4 3 2 1 0S13B 0 1 2 3 4 5 6 7 8 9 10

50

40

30

20

10

0

Phase behavior S13D/S13B blend With dead oil @ 30 °C

Aqueous stability test ofS13D/S13B blend

S13D/S13B (70/30) – dead vs live crude @ 30 °C

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Dead oil – UNDER-OPTIMUM Live oil – OVER-OPTIMUM

After mixing & settling for 1 day

Before mixingAfter mixing & settling for 1 day

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Imbibition studiesat ~ 30 °C

Imbibition results –reservoir cores (1”)

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S13D 0.5wt% 126mD, 25 °C

S13D 0.25wt% 151mD 25 °C

Mehdi Salehi, TIORCO

S13D/S13B 70/30 1wt% 575mD, 30 °C

S13D/S13B 60/40 1wt% 221mD, 30 °C

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Conclusions

Conclusions

• Dynamic adsorption experiments (absence of oil)o Effluent surfactant concentration plateaus at ~80%

injected concentrationo Higher PO components are deficient in the effluent

sample (in plateau region)o Increase in pressure drop with volume throughput

• Sensitivity of phase behavior to temperature and oil

(dead vs. live)

• S13D/S13B 70/30 @ 30 °C performance poor

compared to S13D @ 25 °C34

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Questions