chemical flood design - university of wyoming · •ongoing fresh waterflooding have changed...

E N H A N C E D O I L R E C O V E R Y I N S T I T U T E

Chemical Flood

V L A D I M I R A LV A R A D O

C H E M I C A L A N D P E T R O L E U M E N G I N E E R I N G

J A N U A R Y 2 0 1 2

Design


• Project objective

• Fluid characterization

• Design challenge

• ASP Evaluation

• First Attempt

• Second Attempt

• Closing remarks

Outline


Project Objective

• To develop an effective alkaline-surfactant-polymer (ASP) blend for the DC field based on based behavior studies in the lab and coreflooding experiments.

• No rock samples from this field were available

• Fluid samples and data on the reservoir were collected by UW-PETE team


Brine Analysis

• Calcium: 456 mg/L

• Magnesium: 63 mg/L

• Sodium: 1315 mg/L

• Potassium: 71 mg/L

• Bicarbonate: 509 mg/L

• Chloride: 360 mg/L

• Sulfate: 3400 mg/L

• TDS: 6094 mg/L

• Calcium: 433mg/L



• Potassium: 79 mg/L




• TDS: 6730 mg/L

Reservoir Brine Synthetic Reservoir Brine

Synthetic brine optimized for sulfate and bicarbonate concentrations


Brine Analysis

• Calcium: 6.3 mg/L

• Magnesium: 1.7 mg/L


• Potassium: 2.6 mg/L




• TDS: 1600 mg/L

• Calcium: 13 mg/L



• Potassium: 0.5 mg/L




• TDS: 1500 mg/L

Injection Water Synthetic Injection Water

Synthetic brine optimized for sulfate and bicarbonate concentrations


Interfacial Tension

• IFT measured with pendant drop = 26 dynes/cm

0

5

10

15

20

25

30

35

40

45

50

0 20 40 60 80 100 120

IFT

(dyn

es/

cm)

Time (s)

Deadman Creek Oil with Deadman Creek Injection Water at 25°C

IFT

IFT = 26 dynes/cm

drop released


• Ongoing fresh waterflooding have changed

current reservoir water chemistry. The

challenge is to find surfactant blends that reach

optimum salinity at a TDS < 12,000 ppm.

• Solution: Use of surfactants with PO groups

and blend them with the main surfactant

Design Challenge


SUBOPTIMUM DESIGN (ONE SURF.) First Attempt


Surfactant Selection

• Prepared solutions with:

– 1 wt% surfactant

– 1 wt% Alkali • NaOH

• Na2CO3

– NaCl salinity varying from 1 wt% to 7 wt%



• Flame seal pipettes

• Inject Alkali-Surfactant solutions with each salinity

• Combine with DC Oil

• Cap pipettes and purge with argon gas

• Placed in oven at 120°F, mixed gently


Surfactant Selection • Record initial

oil/water interface

• Measure the volume of oil and water in microemulsion

• Determine optimum salinity by plotting solubilization ratio vs salinity

0

10

20

30

40

50

60

70

80

90

1 2 3 4 5 6 7SR

cc/

cc

[NaCl] (wt%)

P S-13 B

SRw

SRo

Optimum Salinity = 5 wt%


Surfactant Selection Surfactant Activity (%) Yes No Maybe

P S-13 B 89.51 X

P S-13 C 84.32 X

P S1-HA 89.96 X

P M-2 59.29 X

P S-13D HA X

P A-6 X

P C-2 46 X

A-F X

P C-1 39.11 X

P S-12 67.06 X

Yes = Optimum Salinity below brine salinity, less than 2 days to achieve


Surfactant Selection • Tested P S-13B and P S-

13C with synthetic field brines

• Tested P S-13C for critical micellar concentration (CMC)


Core Flooding – ASP # 1(NaOH) • Core: Minnelusa Core W R741 D7215’ • D=3.735 cm • L=7.364 cm • A=10.9565 cm2

• Φ=22.99 % • Kg=516.6 md • PV=18.5491 cm3

• Wt dry=161.528 g • Wt wet=180.110 g • Diff=18.582 g

Core was initially cleaned with toluene and methanol, then dried in the oven


Core Flooding – ASP #1 (NaOH)

• Test for reduction in residual oil saturation

• Core aged in synthetic DC reservoir brine

• Flooded with DC oil to Swi and aged

• 10 PV waterflood with synthetic DC injection brine

• 3 PV ASP flood – 500 ppm P S-13C – 2000 ppm Floppam 3330S

polymer – 1 wt% NaOH – 1L synthetic DC injection brine

• 10 PV chase waterflood with synthetic DC injection brine


Core Flooding #1 – (NaOH)

0

0.2

0.4

0.6

0.8

1

0

2

4

6

8

10

12

14

16

0 5 10 15 20 25

ΔP

(p

si)

PV Injected

ASP Experiment # 1

DP

Oil Recovered


Core Flooding – ASP # 2 (Na2CO3) • Core: Minnelusa Core W R741 D7212.5’ • D=3.728 cm • L=7.557 cm • A=10.9155 cm2

• Φ=22.73 % • Kg=510.1 md • PV=18.7495 cm3

• Wt dry=166.482 g • Wt wet=185.271 g • Diff=18.789 g

Core was initially cleaned with toluene and methanol, then dried in the oven


Core Flooding – ASP #2 (Na2CO3)

• Test for reduction in residual oil saturation

• Core aged in synthetic DC reservoir brine

• Flooded with DC oil to Swi and aged

• 10 PV waterflood with synthetic DC injection brine

• 3 PV ASP flood – 500 ppm P S-13C – 2000 ppm Floppam 3330S

polymer – 1 wt% Na2CO3

– 1L synthetic DC injection brine

• 10 PV chase waterflood with synthetic DC injection brine


Core Flooding #2 – (Na2CO3)

0

0.2

0.4

0.6

0.8

1

0

1

2

3

4

5

6

7

8

9

0 5 10 15 20 25

ΔP

(p

si)

PV Inj

ASP Experiment # 2 (Na2CO3)

DP

Oil Production


Core Flooding Comparison

Test φ K (md) Swi (%)

Waterflood Recovery (%OOIP)

Tertiary ASP

Recovery (%OOIP)

Pressure Drop Return to

Waterflooding

ASP#1 (NaOH) 22.99 516.6 19.67 67.35 20.96 Yes

ASP#2 (Na2CO3) 22.73 510.1 23.2 62.66 12.92 No


ASP #1 – Relative Permeability Curves

0.00

0.20

0.40

0.60

0.80

1.00

kr

- re

lative p

erm

eabili

ty

0.00 0.20 0.40 0.60 0.80 1.00Sw

krw vs Sw krow vs Sw


ASP #1 (NaOH) History Match (WF)

0

10

20

30

40

50

60

70

80

0 2 4 6 8 10 12

OO

IP%

Inj. PV

CMG-STARS

Measured

-0.2

0

0.2

0.4

0.6

0.8

1

1.2

0 5 10 15

Oil

Cu

t

Inj. PV

CMG-STARS

Measured

0

0.5

1

1.5

2

2.5

3

3.5

4

0 5 10 15

Pre

ssu

re d

rop

(p

si)

Inj. PV

CMG-STARS

Measured

0

2

4

6

8

10

12

0 5 10 15

Cu

mu

lati

ve o

il p

rod

uce

d (

ml)

Inj. PV

CMG-STARS

Measured


OPTIMUM DESIGN (+1 SURF.) Second Attempt


• Connate brine

• Injection brine

Just 1600 ppm NaCl

Component Wt (gr)

MgSO4 0.313

KCl 0.136

CaCl2.2H2O 1.676

NaCl 0.697

Na2SO4 4.661

TDS 7100 ppm

Materials and Methods


Dead man Creek Crude Oil Viscosity at 48oC = 83 cP

Surfactant 0.75wt%PS13-D + 0.25wt%PS3B

Polymer

Flopaam-3330s

2000 ppm (ASP) 1000 ppm (P)

Alkali 1wt% NaOH

Core

Berea: (ASP 1)

L= 7.904 cm

D= 3.73 cm

PV= 22.12 cc

Φ= 25.62%

Kair= 366.9 md

Minnelusa: (ASP 2)

L= 7.017 cm

D= 3.728 cm

PV= 16.41 cc

Φ= 21.43%

Kair= 808.2 md

Materials and Methods


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

Pipette

(bottom sealed)

Brine +

surfactant

Oil

Initial

interface

24 hr

Winsor

Type - I

Winsor

Type - II

Winsor

Type - III


Salinity (NaCl ppm) increases

5000 10000 125000 15000 17500 20000 22500 25000 30000 35000

Only 1wt% Surfactant


29

1wt% Surf. + 1wt% Na2CO3 Salinity (NaCl ppm) increases

1500 2500 3500 5000 7500 10000 15000 20000

11500 12500 13500 25000 15000 17500 20000 30000


1wt% Surfactant + 1wt% NaOH Salinity (NaCl ppm) increases

1500 2500 3500 5000 7500 10000 15000

11500 12500 13500 25000 15000 17500 20000


Only 1wt% Surfactant

Opt_Sal > 35000 ppm Opt_Sal ~ 11500 ppm Opt_Sal ~ 30000 ppm

1wt% Surfactant + 1wt% NaOH 1wt% Surfactant + 1wt% Na2CO3


).().()( 21_ surfactntinjectedofsalinityoptLogxsoapinsituofsalinityoptLogxsalinityoptimalLog blendASP

Theory:

.

1

)()(surfactofnumbern

i

iiblend salinityoptimalLogxsalinityoptimalLog

),,( cationsoftypepHacidsorganicoftypeF

),,,( alkaliofionconcentratpHamountasphalteneTANF


Only 1wt% Na2CO3

Salinity (NaCl ppm) increases

5000 10000 12500 17500 20000 22500 25000 30000


Only 1wt% NaOH Salinity (NaCl ppm) increases

5000 10000 12500 17500 20000 22500 25000 30000


Results (ASP#1)


(sec-1)


2

4

6

8

10

12

14

0 5 10 15

pH

Inj. PV

pH at effluent

Inlet pH


0

10

20

30

40

50

60

0

5

10

15

20

25

30

0 2 4 6 8 10 12 14 16

Wat

er

visc

. (c

P)

Inj. PV

Water viscosity

Inlet viscosity

Emulsion

Em

uls

ion

vis

c.

(cP

)


Stage Permeability (md)

Initial air permeability 366

Initial brine permeability

(Sw=1)

55.5

Oil permeability at Swi 218.75

Brine permeability at Sor 24.11

Brine permeability at the end

of chemical flood

27.43


40

WF ASP P WF

Results (ASP#2)


41

pH and surfactant concentration at effluent:

Mostly stable W/O emulsion


Observed precipitation at effluent samples:

ClKSi

ClCa

K

Ca

KS

O

Na

Cl

Ca

0 1 2 3 4 5 6 7 8 9 10

keVFull Scale 4240 cts Cursor: -0.031 (82 cts)

Spectrum 1

ClKSi Cl

KCa

CaS

K O

Na

Cl

Ca

0 1 2 3 4 5 6 7 8 9 10 11

keVFull Scale 5549 cts Cursor: -0.009 (361 cts)

Spectrum 4

As we expected some secondary minerals was produced (here calcite, also some sulfur was produced which is a really evidence for anhydrite dissolution)


43

Results (ASP#2) (cont’d)

Permeability Changes (Minn.)

Stage Permeability (md)

Initial air permeability 808.2

Initial brine permeability

(Sw=1)

152

Oil permeability at Swi 428.9

Brine permeability at Sor 42.5

Brine permeability at the end

of chemical flood

78.75


44

Results (ASP#3)


45

Why does NaOH work better?

chemical flood design - university of wyoming · •ongoing fresh waterflooding have changed...

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