studies of reservoir rock wettability and low salinity ... - presentation_xie.pdf · studies of...

Studies of Reservoir Rock Wettability and Low Salinity Waterflooding

Sheena XieEnhanced Oil Recovery Institute

University of WyomingDenver, Colorado

January 15, 2009

Project personnelNorm Morrow, Carol Robinson, Sheena (Xina) Xie, Li Yu Nina Loahardjo, Siluni Wickramathilaka, Hu Pui, Wei Wang (students)

Ron Borgialli, George Twitchell (Machine shop)

Ligang Yu, Xuanqi Zhang (visiting professors)

Jill Buckley, Geoff Mason, Koichi Takamura (adjunct professors)

CollaborationPegui Yin, Shaochang Wo, et al. (EORI staff)Mark Knackstedt (Australian National University rock physics group)Arne Graue (U. of Bergen)Doug Ruth (U. of Manitoba)

EORI and company supportEnhance Oil Recovery Institute, University of WyomingIndustry: ARAMCO*,BP*,Chevron, ConocoPhillips, Shell, StatoilHydro*, Total*, INL* includes provision of reservoir rock and crude oil

Recent Publications Low salinity/cyclic flooding/spontaneous imbibition

Society of Core Analysts, Calgary, 2007J. Coll. Int. Sci. 2007aAm. Soc. Min. and Reclam., Gillette, 2007. SPE, ATCE, Anaheim, 2007Trans. in Porous Media, 2007SPE REE, 2007SPE IOR, Tulsa, 2008 SPE REE, 2008Int. Symp. Res. Wettability, Abu Dhabi, 2008 Trans. in Porous Media, in press 2009aSPE REE, in press, 2009 Trans. in Porous Media, in press, 2009bJPSE in press, 2007Langmuir, in press, 2009

Papers can be downloaded from: http://wwweng.uwyo.edu/economic/psc/

Ongoing Projects

Reservoir Rock Wettability Studies –◊

evaluate reservoir rock wettability

◊

chemical stimulation to improve oil recovery Low Salinity Waterflooding

◊

Wyoming reservoirs ◊

rocks and oils provided by oil companies

◊

cyclic waterflooding

Reservoir rock wettability studies –vital to all EOR processes◊

Evaluation of reservoir rock wettability♣

Muddy sandstone from the Grieve Field♣

Hatfield sandstone♣

Other crude oil/brine/rock combinations as needed◊

Chemical stimulation to improve recovery by

spontaneous imbibition from fractured reservoirs

♣

Tensleep reservoir rock oil recovery ♣

Cottonwood Creek reservoir rock oil recovery◊

Removal of water blocks ♣

Wamsutter tight gas deliverability

Spontaneous imbibition

0

20

40

60

80

100

1 10 100 1000 10000 100000

Oil

reco

very

, %

Dimensionless imbibition time

very strongly water-wet

F-A 6827F-A 6960F-A 6515F-A 6972

0

20

40

60

80

100

1 10 100 1000 10000 100000

Oil

reco

very

, %


very strongly water-wet

F-C/B F-C/B F-C/B F-C/B

Spontaneous imbibition - Grieve muddy sandstone/crude oil/formation brine (2177 ppm) –Used to estimate initial water saturation prior to CO2 injection

Permeability < 1 md Permeability < 1 md

Wettability of Grieve Field Sandstone

0

20

40

60

80

100

1 10 100 1000 10000 100000

Oil recovery, %

OOIP

Dimensionless Imbibition time

#6073, Phi = 5.9%

#5952, Phi = 2.9%

#6095, Phi = 3.4%

#5839, Phi = 1.3%

VSWW

Strongly water‐wet curve

Spontaneous imbibition of Hatfield reservoir rock/crude oil/Tensleep formation brine in Hatfield (5590 ppm) – Reservoir response better to low pump rate, concluded that imbibition is the main production mechanism for this low permeability fractured reservoir

Hatfield Sandstone

Tensleep Sandstone – Crude oil recovery by spontaneous imbibition

Cores from a dry well (water saturated) Cores from an oil well

0

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0 20 40 60 80 100 120 140 160

Oil recovery, %

OOIP

Imbibition time, day

5501B

5501A

0

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60

0 5 10 15 20 25

Oil

rec

ove

ry,

%O

OIP


T1AT1CT2BT2C

Surfactant enhanced imbibition –Surfactant screening*

Compatibility with formation/injected brine salinityCompatibility at reservoir temperature

Rock types: Tensleep sandstoneCottonwood Creek dolomite

* Surfactants provided by Stepan, AkzoNobel Help from Dr. George Hirasaki and his group

Tensleep formation water solutions

RatioSurfactant +

Co‐Surfactant

Precipitation @

Room Temp.

Precipitation

@ 75 0C

1 to 1 A1+C8 Y YA1+C1 N YS3A+S2 Y YS3A+C1 Y YS1+S2 Y YS1+C1 Y YS1+C3 Y Y

B. PAS‐8S+S3A Y YT91‐8+S3A Y YT91‐8+S2 Y Y

3 to 1 S3A+S2 N YS3A+C1 N YS1+S2 N Y

B. PAS‐8S+S3A Y YT91‐8+S3A Y Y

RatioSurfactant +

Co‐Surfactant

Precipitation

@ Room

Temp.

Precipitation

@ 75 0C

1 to 1 A1+C8 Y YA1+C1 N YS3A+S2 Y YS3A+C1 N YS1+S2 Y YS1+C1 Y YS1+C3 Y Y

B. PAS‐8S+S3A Y YT91‐8+S3A Y YT91‐8+S2 Y Y

3 to 1 S3A+S2 N YS3A+C1 N YS1+S2 N Y

B. PAS‐8S+S3A Y YT91‐8+S3A Y Y

2 wt.% Surfactant/ Co‐Surfactant, 2 wt.%

Co‐Solvent (DGBE), and 1 wt.% NaB(OH)4



Tensleep formation water: 3030 ppm (Ca + Mg = 340 ppm, HCO3 = 70 ppm)

Cottonwood Creek formation water solutions

RatioSurfactant + Co‐

Surfactant

Precipitation @

Room Temp.

Precipitation

@ 75 0C

1 to 1 S1+C1 Y YS1+C3 Y Y

B. PAS‐8S+S3A Y YT91‐8+S2 Y YT91‐8+S3A Y YS1+S2 N Y

3 to 1 S1+S2 Y YT91‐8+S3A N Y

B. PAS‐8S+S3A Y Y



Cottonwood Creek formation water: 23,740 ppm (Ca + Mg = 4,000 ppm, HCO3 = 2,200 ppm)

Tensleep Sandstone

Imbibition at reservoir temperature 75°C for cores from dry wells

0

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30

40

0 10 20 30 40 50

Oil recovery, %

OOIP


5517B: 168.4 md

Surfactant: Petrostep S1 (3000 ppm) + NaB(OH)4 (0.1 wt%)

5523A: 194.2 md

Formation brine imbibition

Surfactantimbibition

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30

40

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Oil recovery, %

OOIP


5523E: 146.8 md

5517C: 130.6 md

Surfactant: Petrostep S2 (3000 ppm) + NaB(OH)4 (0.1 wt%)


Surfactantimbibition

0

10

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30

40

0 20 40 60 80

R, %

OO

IP


Surfactant: T91-8

1T

2T

3T

4T

5T

6T

%5.22%,12,11:6

%0%,4.15,56:5

%1.13%,5.10,06.0:4

%3.1%,6.16,83:3

%0%,42.11,2.14:2

%89.31%,26.17,456:1

===

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===

wig

wig

wig

wig

wig

wig

SmdkT

SmdkT

SmdkT

SmdkT

SmdkT

SmdkT

φ

φ

φ

φ

φ

φ

Surfactant enhanced imbibition - Cottonwood Creek Dolomite

60°C


Surfactant imbibition

In brine

In T91-8 solution

Fundamentals of surfactant enhanced imbibition

◊

Surfactants interact with the adsorbed materials from the crude oil, resulting in the release of the adsorbed organic materials. The rock surface becomes less oil-wet and imbibition rate increased (effect of surfactant and adsorption on capillary driving forces on imbibition are being investigated in detail)

◊

Interfacial tension between oil and brine decrease (or increase in the Bond number) can contribute to improved oil recovery through gravity segregation.

Objective: Evaluate the potential of low salinity waterflooding for Tensleep* and Cottonwood** Creek reservoirs using CBM water composition

*Minnelusa is the most prolific producer in Wyoming and has comparableorigin and mineralogy to the Tensleep

**Estimated that only about 10% of the oil in the Cottonwood Creek reservoirhas been produced

Low Salinity Waterflooding -Disposal of coal bed methane (CBM) water and improved recovery from Wyoming reservoirs

0

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100

0 5 10 15 20 25 30 35Brine injected, PV

R f, %

OO

IP

0

5

10

15

Δ P, p

si

Test A:R1/C1WP crude oil, Swi = 40.6%q = 2.6 ft/D

RIB(29,690 ppm)

R

ΔP

0

20

40

60

80

100

0 5 10 15 20 25 30 35Brine injected, PV

R f, %

OO

IP

0

5

10

15

ΔP, p

si

WP crude oil, Swi = 40.6%

RIB(29,690 ppm)

R

ΔP

LSB(1,480 ppm)

16.2%

0

20

40

60

80

100

0 10 20 30 40 50 60Brine injected, PV

Rf,

%O

OIP

0

5

10

15

ΔP, p

si

LC crude oil, Swi = 13.6% (LSB)

R

ΔP

RIB(29,690 ppm)

NaCl(8,000 ppm)

NaCl(1,500 ppm)

12.7%

LSB(1,480 ppm)

4%Divalent ions

removedSalinity

decreased Divalent ions

added

Low salinity waterflooding to improve oil recovery

CBM water Underground Injection Control: Class V restrictions

CBM water for oil and gas recovery: Class II (less restricted disposal)

Typical PRB CBM water: TDS ~ 1,800 ppmSAR (sodium adsorption ratio) ~ 25

Unsuitable for irrigation or surface discharge when: TDS > 3,000 mg/LSAR > 8

Wyoming CBM water disposal

Imbibition tests show Tensleep cores are very weakly water-wet

0

20

40

60

80

100

1.E+00 1.E+02 1.E+04 1.E+06 1.E+08 1.E+10

R, %

OO

IP


E2

VSWW (Ma et al., 1997)

1000 μm

0

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70

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Pre

ssur

e D

rop,

psi

Rec

over

y,%

Injected PV

CBM Brine1316ppm

T8104Swi=21.03%

+7.18%

Tensleep Brine3030ppm

Waterflooding of Tensleep brine followed by CBM water• Example of improved recovery from cores with very low clay content• Movement of dolomite was observed at ANU in real time micro-CT imaging• Tensleep rock properties: ongoing work

Kg = 20.7 mdφ

= 14.2%

0

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45

0102030405060708090

100

0 5 10 15 20 25 30 35 40

Pre

ssur

e D

rop,

psi

Rec

over

y, %

OO

IP

Brine Injected, PV

Tensleep H5Swi=18.62%

Recovery

Pressure

+4.57%

Waterflooding with Tensleep brine followed by CBM water

Tensleep brine3030 ppm

CBM water1316 ppm

Kg = 23.2 mdφ

= 8.8%

Results are in the range reported by BP for 18 tests on clastic rocks but response to salinity change for the Tensleep is generally slower (2%+ in oil recovery)

Spontaneous imbibition tests on Cottonwood dolomite /crude oil show cores are very weakly water wet

0

10

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30

40

0 2 4 6 8 10 12

R, %

OO

IP


1T

2T 3T4T

5T6T

%5.22%,12,11:6%0%,4.15,56:5

%1.13%,5.10,06.0:4

%3.1%,6.16,83:3%0%,42.11,2.14:2

%89.31%,26.17,456:1

===

===

===

===

===

===

wig

wig

wig

wig

wig

wig

SmdkTSmdkT

SmdkT

SmdkTSmdkT

SmdkT

φ

φ

φ

φ

φ

φ

Width = 132 μm

0

1

2

3

4

5

6

7

8

9

10

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0 3 6 9 12 15 18 21 24 27

Pre

ssur

e D

rop,

psi

Rec

over

y, %

OO

IP

Injected Volume, PV

30,755ppm 1,537ppm

Recovery

Pressure

+6.41%

Cottonwood 5800ASwi=48.89%

Waterflooding of Core 5800AFirst example of response to low salinity for dolomite

Waterflooding of Cottonwood dolomite Core 5800B

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14

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Pre

ssur

e D

rop

, psi

Rec

ove

ry, %

OO

IP

Injected Volume, PV

30,755ppm 1,537ppm

Recovery

PressureCottonwood 5800BSwi=36.27%

+6.79%

Cyclic water flooding

Unexpected high recoveries for high salinity brine after exposure to low salinity brine lead to investigation of reproducibility of waterfloods for high salinity brine. (No data has been reported previously on this topic.)

Recoveries of crude oil for several rock types (reservoir sandstone, outcrop sandstone and outcrop carbonate) showed consistent trends of increase in recovery from one cycle* to the next.

* waterflooding and restoration to initial water saturation

Cyclic Waterflooding

Recovery of mineral oil Recovery of crude oil from a reservoir sandstone (same trends of increase in recovery wereobtained for outcrop sandstone and carbonate)

Cyclic flooding showed systematic increase in oil recovery.*

However, material balance after a few cycles was not satisfactory.

Now applying tracer test to provide independent check on residual oil and initial water saturations.***provisional patent filed

**with the help of Charlie Carlisle and co-workers

Ongoing work

• Rock and crude oil characterization• Testing of reservoir rocks and oil samples

supplied by EORI and Companies• Unconsolidated reservoir sands – laboratorytechniques

• Joint UW/Australia National University projecton fundamentals of oil recovery

♣

Distribution of connate water and residual oil in mixed-wet Tensleep rocks by micro X-ray CT imaging;

♣

Effect of brine (specific ions) on silica/carbonate interactions fromatomic force measurements;

♣

Plasma cleaning: a) limitations on size of cores, b) application to cleaning cores exposed to oil base mud.

Ongoing work continued …

Application of surfactants to improved oil recovery from fractured reservoirs by spontaneous imbibition.

Extend fundamental studies of imbibition to effects of salinity and mixed-wet imbibition (includes joint work with U. Bergen using radioactive tracers to monitor saturations during imbibition)

Tight gas sands - removal and prevention of water blocks – Wamsutter cores (joint with INL)

Thanks !

Questions?

Dissolution of Middle-eastcarbonate

0.0

50.0

100.0

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200.0

250.0

300.0

0 5 10 15 20

Ion concen

tration, ppm

PV injected

SO4

Mg

Ca

0.0

100.0

200.0

300.0

400.0

500.0

600.0

700.0

800.0

900.0

1000.0

0 5 10 15 20

Ion concen

tration, ppm

PV injected

SO4

Mg

Ca

Carbonate core saturated with 2883 ppm NaCl and displaced with the same brine

Carbonate core saturated with 57654 ppm NaCl and displaced first with the same brine and then with 2883 ppmbrine

Hide: mention ongoing workof Cottonwood carbonate

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900

0 10 20 30 40 50 60 70 80

EtA

c C

once

ntra

tion

(ppm

)

MeO

H C

once

ntra

tion

(ppm

)

Volume Produced (mL)

Tracer Concentration vs. Volume Produced

Berea sandstone

Tracer test to verify water content

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100

0 20 40 60 80

Oil

Rec

over

y, %

OO

IP

Brine Injected (PV)

OOIP

E-10 : R1/C3Swi = 18.39 %

29,000 ppm20,000 ppm15,000 ppm7,000 ppm5,000 ppm4,000 ppm3,000 ppm1,000 ppm

Gradual salinity increase for waterflooding

Constant pressure flooding, no extra oil recovery

0

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0 10 20 30 40

pH o

r Pre

ssur

e D

rop,

psi

Oil

Rec

over

y, %

OO

IP

time, hours

pH

ΔP

R

Minelusa Oil

0

5

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25

30

35

0 2 4 6 8 10 12 14

pH

IFT

[mN

/m]

0.01 [M]

0.1 [M]

1 [M]

0

5

10

15

20

25

30

35

0 2 4 6 8 10 12 14pH

IFT

[mN

/m]

0.01 [M]

0.1 [M]

1 [M]

Cotton Wood

Effect of salinity and pH on interfacial tensions

BEAKER

PRESSURE TRANSDUCER

BRINE

VOLT METER

CLOSED FUNNEL

OIL

CORE

Effect of surfactant on imbibition back pressure

0

0.2

0.4

0.6

0.8

1

0 20 40 60 80 100

t (hours)

Qo/Vφ

xf/Lc

0

2

4

6

8

10

Pend

(kPa)fab

Qo

/Vφ

Tested core: IS1

0

0.2

0.4

0.6

0.8

1

0 20 40 60 80 100

t (hours)

Qo/Vφ

xf/Lc

0

2

4

6

8

10

Pend

(kPa)

Pend

xf/Lc

Qo/Vφ

fab

Liquid changed

Brine imbibition alone

Brine imbibition to almost half way along the core; then switched to surfactant Imbibition

studies of reservoir rock wettability and low salinity ... - presentation_xie.pdf · studies of...

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