improved oil recovery by waterflooding - university of wyoming

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

Improved Oil Recovery by Waterflooding

Nina LoahardjoPetrophysics and Surface Chemistry Group

Chemical and Petroleum Engineering

University of Wyoming

18 January 2011


Project Personal

• Norman Morrow

• Carol Robinson (administration)

• Winoto Winoto, Ph.D.

– Low salinity, removal of water blocks, rate effect, and core properties for screening cores

• Nina Loahardjo, Ph.D.

– Low salinity, sequential waterflooding, and interfacial properties

• Siluni Wickramatilaka, Ph.D.

– Spontaneous Imbibition – scaling of viscosity ratio etc., gravity dominated imbibition, MRI imaging of an imbibition front, low salinity imbibition at Sor, surfactant enhanced imbibition

• Pu Hui, Ph.D.

– Low salinity flooding of reservoir cores including CBM water, chemical analysis and in-line monitoring of pH and conductivity of effluent brine

• Behrooz Raeesi, Ph.D. Student

– Drainage/imbibition capillary pressure data, theory and experiments on surface energy, wetting and surface roughness

EORI staff

• Peugui Yin

– Petrophysics: thin section analysis and data acquisition: surface areas, clay analysis, cationexchange capacities (Susan Schwapp)

• Shaochang Wo

– Data analysis, modelling, simulation

Machine shop

• Ron Borgialli, George Twitchell, and Dean Twitchell


Adjunct Professors

• Jill Buckley

• Crude oil characterization, wetting, low salinity and sequential

waterflooding recovery mechanisms, adhesion, interfacial

tension, asphaltene phase behavior

• Koichi Takamura

• Recovery mechanisms, surfactants, emulsions, dispersions,

DLVO theory, fundamentals of interfacial tensions including

effect of pH and salinity for crude oils

• Geoff Mason

• Spontaneous imbibition, pressures at imbibition front and core

face, viscosity ratios – correlations and theory, bubble snap-off

and capillary back pressure for precise pore geometries, nuclear

tracer imaging and interpretation (with U Bergen)


Collaborations

•Australian National University

•Digital Core Consortium for Wettability : Mark Knackstedt, Andrew Fogden, Munish Kumar, Evgenia

Lebedevia and Tim Senden

Micro X-ray CT Imaging and Surface Chemical Techniques Related to Recovery Mechanisms for Crude Oil

and Core (Tensleep and Minnelusa) Which Complement UW Coreflood and Imbibition Studies

•University of Manitoba: Doug Ruth

Simulation and Theory of Imbibition

•University of Bergen: Arne Graue and Martin Fernø

Nuclear Tracer Imaging of Imbibition

•ConocoPhillips: James Howard and Jim Stevens

MRI Imaging of Sequential flooding, Spontaneous Imbibition, and Low Salinity Flooding

•University of Kyoto

Application of Molecular Simulation to Interpretation of the Interfacial and Surface Properties of Crude Oil

•University of Edmonton: David Potter

Tracking the Movement of Clay Particles Within Porous Media from Magnetic Properties

•Chevron: Guoqing Tang

Low Salinity Waterflooding – Industrial X-Ray Imaging


Presentations

July 2010 onward

• Morrow, N:” Interfacial Properties and Improved Oil Recovery by Waterflooding”, presented at Technical Advisory Board for

Enhanced Oil Recovery Institute, University of Wyoming, July 2010

• Loahardjo, N., Xie, X., Winoto, W., Buckley, J., and Morrow, N.R., “Improved Oil Recovery by Sequential Waterflooding”,

presented at the 14th Annual Gulf of Mexico Deepwater Technical Symposium, New Orleans, LA, Aug. 19-19, 2010.

• Xie, X., Pu, H., Buckley, J., Morrow, N.R., and Carlisle, C., “Low Salinity Waterflooding and Improved Oil Recovery”, presented

at the 14th Annual Gulf of Mexico Deepwater Technical Symposium, New Orleans, LA, Aug. 19-19, 2010.

• Morrow, N. and Mason, G:”Areas of Crude Oil/Rock Contact That Govern The Development of Mixed Wet Rocks”, presented at

11th International Symposium on Reservoir Wettability Calgary, AB, Canada, September 2010

• Loahardjo, N., Xie, X., Winoto, W., Buckley, J. and Morrow, N.:”Mechanism of Improved Oil Recovery by Sequential

Waterflooding”, ”, presented at 11th International Symposium on Reservoir Wettability Calgary, AB, Canada, September 2010

• Buckley, J. and Morrow, N.:”Improved Oil Recovery by Low Salinity Waterflooding: A Mechanistic Review”, presented at 11th

International Symposium on Reservoir Wettability Calgary, AB, Canada, September 2010

• Morrow, N. and Mason, G:”Spontaneous Imbibition Into Cores with Different Boundary Conditions”, presented at 11th

International Symposium on Reservoir Wettability Calgary, AB, Canada, September 2010

• Wickramatilaka, S., Mason, G., Morrow, N., Howard, J. and Stevens.:” Magnetic Resonance Imaging of Oil Recovery during

Spontaneous Imbibitions”, presented at 11th International Symposium on Reservoir Wettability Calgary, AB, Canada, September

2010

• Loahardjo, N.: “Mechanism of Improved Oil Recovery by Sequential Waterflooding” Chemical & Petroleum Engineering Graduate

seminar, Nov. 8, 2010.

• Takamura, K., Loahardjo, N., Buckley, J., Morrow, N, Kunieda, M., Liang, Y. and Matsuoka, T.:” Preferential Accumulation of

Light End Alkanes and Aromatics at The Crude Oil/Air and Crude Oil/Water Interfaces: Potential Mechanism of Accelerated Tar

Ball Formation from Spilled Crude Oil”, be presented at the Annual SME Meeting, Denver, February 27 – March 2, 2011


Publications

July 2010 onward

• Mason, G., Fisher, H., Morrow, N.R., and Ruth, D.W.: “Correlation for the Effect of Fluid Viscosities on Counter-Current

Spontaneous Imbibition”, JPSE. 72, (August) 2010, 195-205.

• Loahardjo, N., Xie, X., and Morrow, N.R., “Oil Recovery by Sequential Waterflooding of Mixed-Wet Sandstone and Limestone”,

Energy Fuels 24 (9) 5073-5080, Web published August 30, 2010.

• Pu, H., Xie, X., Yin, P. and Morrow, N.:”Low Salinity Waterflooding and Mineral Dissolution”, SPE 134042, SPE Annual Meeting

Technical Conference and Exhibition, Florence, Italy, September 2010

• Pu, H., “Recovery of Crude Oil from Outcrop and Reservoir Sandstone by Low Salinity Waterflooding”, PhD Defense, Sept. 27,

2010

• Wickramatilaka, S., G., Morrow, N. and Howard, J.:”Effect of Salinity on Oil Recovery by Spontaneous Imbibition”, 24th

International Symposium on the Core Analysts, Halifax, Nova Scotia, Canada, October 2010

• Kumar, K., Fodgen, A., Morrow N. and Buckley J.:”Mechanisms of Improved oil Recovery from sandstone by Low Salinity

Flooding”, 24th International Symposium on the Core Analysts, Halifax, Nova Scotia, Canada, October 2010

• Loahardjo, N., Morrow, N., Stevens, J. and Howard, J.:”Nuclear Magnetic Resonance Imaging: Application to Determination of

Saturation Changes in a Sandstone Core by Sequential Waterflooding”, 24th International Symposium on the Core Analysts,

Halifax, Nova Scotia, Canada, October 2010

• Morrow, N., and Buckley, J. ” Improved Oil Recovery by Low Salinity Waterflooding”, SPE Distinguished Author Series, October

2010

• Morrow, N.:” Low salinity Waterflooding”, EORI Newsletter, Wyoming, October 2010

• Fogden, A., Kumar, M., Morrow, N.R., Buckley, J.S.: “Mobilization of Fine Particles during Flooding of Sandstones, and Possible

Relations to Enhanced Oil Recovery”, Energy Fuels, submitted November, 2010.

• Li, Y., Mason, G., Morrow, N. and Ruth D.:” Capillary Pressure at A Saturation Front during Restricted Counter-Current

Spontaneous Imbibition with Liquid Displacing Air”, Transport in Porous Media, November, 2010

• Siluni Wickramathilaka, “Oil Recovery by Spontaneous Imbibition,” Dec. 1, 2010, PhD. Defense

15 Manuscripts in Preparation for 2011


TOPICS

• Screening outcrop cores for model rocks for low

salinity waterflooding

• Low salinity waterflooding with mineral dissolution

– Eolian sandstones containing dolomite and anhydrites

but without clays (Tensleep, Minnelusa, and Phosphoria)

• Sequential waterflooding

– Mechanisms of Sequential waterflooding

– Field test applications


Oil Recovery: Waterflooding

Single 5-Spot Well Pattern


Laboratory Measurement of

Oil Recovery by Waterflooding

brinecore

0

20

40

60

80

100

0 2 4 6 8 10 12

Oil

Re

cove

ry, %

OO

IP

Brine Injected, PV

Target for Tertiary Recovery

Oil Recovery by Waterflood


Definitions

• Low Salinity Waterflooding (LSW) at Sor

– Low salinity waterflooding of watered-out reservoir, nominally at residual oil saturation, Sor, after High Salinity Waterflooding (HSW) (common approach)

0

20

40

60

80

100

0 2 4 6 8 10 12

Rw

f(%

OO

IP)

Brine Injected, PV

HSW

LSE

LSW

Core U : R1/C1

LC Crude Oil

Loahardjo et al., 2007


Definitions (cont’d)

• Low Salinity Waterflooding (LSW) at Swi

– secondary mode low salinity waterflooding that begins at initial water saturation, Swi (growing interest)



Low Salinity Waterflooding

0

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ers UW

Other

# o

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& P

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nta

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Figure 3. Histogram of Low Salinity Papers and Presentations

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Figure 3. Histogram of Low Salinity Papers and Presentations

EORI Newsletter Fall 2010

Mechanism of Low Salinity Waterflooding ?SPE Distinguished Author article on LSE (Morrow and Buckley, 2010)


Main Hindrances to Systematic Investigation of Low Salinity Flooding

• The type of Berea sandstone which

responded to low salinity waterflooding is

no longer available

• Currently available Berea shows little

(< 2% OOIP increase) if there is any

response to low salinity flooding


Solutions/work in progress

A. Work with reservoir crude oil/brine/rockReservoir cores are generally more responsive than outcrop

cores but :• coring are expensive

• duplicate core plugs are not usually available because of heterogeneity

• core quality, history, cleaning and re-use of cores are problematic.

• quality of crude oil samples can be uncertain

Papers on reservoir sandstone and carbonate results are in

preparation, covering:• Step changes in salinity

• Injection flow rate

• Intermissions in flow

• Effluent brine analysis

• Etc.



B. Total has identified a responsive outcropThree groups have reported response (U. of Wyoming, U.

Bordeaux, and U. of Stavanger)• Cost, heterogeneity, and logistics of supply are still a problem


C. Screening Outcrop Cores

for Model Rocks for Low

Salinity Waterflooding



0.1

1

10

100

1000

10000

0 5 10 15 20 25 30 35 40 45

Klin

ke

nb

erg

Pe

rme

ab

ility,

mD

Porosity, %

Torrey Buff

Idaho Gray

Edwards

Georgetown

Cordova Cream

Austin Chalk

ParkerBandera Brown

Bandera GrayKirby

Idaho HardBerea Edwards Brown

Sister Gray

Berea Stripe

Berea Buff

Silurian Dolomite

Leopard

Castle Gate

Boise

Bentheimer

Briar Hill

Stephen Xtra

Wisconsin

Screening of commercially available outcrop

0.1

1

10

100

1000

10000

0 5 10 15 20 25 30 35 40 45

Klin

ke

nb

erg

Pe

rme

ab

ility,

mD

Porosity, %

Torrey Buff

Idaho Gray

Edwards

Georgetown

Cordova Cream

Austin Chalk

ParkerBandera Brown

Bandera GrayKirby

Idaho HardBerea Edwards Brown

Sister Gray

Berea Stripe

Berea Buff

Silurian Dolomite

Leopard

Castle Gate

Boise

Bentheimer

Briar Hill

Stephen Xtra

Wisconsin


Castle Gate, Kklink=1,140–1,300 mD, f=25.0–25.6%

Berea Stripe,Kklink=382–457 mD, f=20.1–20.5%

Briar Hill, Kklink=5,500–5,900 mD, f=23.7–24.2%

Idaho Gray, Kklink=5,600–7,200 mD, f=28.6–29.7%


0 5 10 15 20 25 30 35 400

20

40

60

80

100

0 5 10 15 20 25 30 35 400

2

4

6

8

10

12

14

20x Dilution of Seawater

pH

P (psi)

pH

an

d

P (

psi

)

Rw

f (%

OO

IP)

Berea Stripe (WP Crude Oil)

Ta = 60

oC ; T

d = 60

oC

kg = 463 mD ; kb = 282 mD

Swi

= 23%

Injected Brine, PV

Seawater

2.3% OOIP

Low Salinity Waterflooding for Berea Stripe Outcrop


Low Salinity Waterflooding for Idaho Gray Outcrop

0 5 10 15 20 25 300

20

40

60

80

100

0 5 10 15 20 25 300

2

4

6

8

10

12

14

16

p


P (psi)

pH

an

d

P (

psi

)

Rw

f (%

OO

IP)

Idaho Gray (WP Crude Oil)

Ta = 60

oC ; T

d = 60

oC

kg = 7.2 D ; kb = 700 mD

Swi

= 22%

Injected Brine, PV

Seawater

3.3% OOIP


Low Salinity Waterflooding for Briar Hill Outcrop

0 5 10 15 20 25 300

20

40

60

80

100

0 5 10 15 20 25 300

2

4

6

8

10

12

14


pH

P (psi)

pH

an

d

P (

psi

)

Rw

f (%

OO

IP)

Briar Hill (WP Crude Oil)

Ta = 60

oC ; T

d = 60

oC

kg = 5.6 D ; kb = 700 mD

Swi

= 27%

Injected Brine, PV

Seawater

3.7% OOIP


Low Salinity Waterflooding for Castle Gate Outcrop

0 5 10 15 20 250

20

40

60

80

100

0 5 10 15 20 250

2

4

6

8

10

12

14

pH


P (psi) pH

an

d

P (

psi

)

Rw

f (%

OO

IP)

Castle Gate (WP Crude Oil)

Ta = 60

oC ; T

d = 60

oC

kg = 1.3 D ; kb = 460 mD

Swi

= 24%

Injected Brine, PV

Seawater

4.6% OOIP


Low salinity Effect

0

5

10

15

20

25

30

35

40

be

ne

fit

co

mp

are

to

w

ate

rflo

od

re

su

lts

(%

)

1 2 3 4 5 6Endicott core

8 9 10 11

Endicott field average

12 13 14 15 16 17 18

Reservoir cores

(Lager et al., 2006)

0

5

10

15

20

25

30

35

40

Berea Stripe

Idaho Gray

Briar Hill

Castle gate

Outcrop

cores

% 100%or HSW or LSW

oi or LSW

S Sbenefit

S S

(Seccombe et al., 2008)


LSW from LC Reservoir Core

0

10

20

30

40

0

20

40

60

80

100

0 2 4 6 8 10 12

Pre

ssu

re D

rop

(p

si)

an

d p

H

Rw

f(%

OO

IP)

Brine Injected, PV

HSW 14% OOIP

LSW

Core U : R1/C1

LC Crude Oil

P

pH

The result shows benefit to LSW compared to HSW is 43%



Importance of Laboratory Coreflood

Tests on Reservoir for LSW

• For any positive LSW effect, tests on reservoir core show substantial response (averaged at 14%) as opposed to low response (0-9.6%) on tested outcrop core to date

• Single well chemical tracer tests showed 13% OOIP reduction in residual oil, consistent with laboratory core test (McGuire et al. 2005)

• A candidate North Sea field that met the necessary condition for low salinity effect did not respond to LSW in either laboratory or pilot test (Skrettingland et al. 2010)

• The correlation between laboratory coreflood test and field test results confirms the need for individual laboratory tests for screening low salinity candidate;

The variability in response demonstrates the value of laboratory tests in screening candidate reservoirs


2. Low Salinity Waterflooding

with Mineral Dissolution

Studies on Wyoming Reservoirs using

Low Salinity - Coal Bed Methane Water


Target Formations

• Minnelusa (Gibbs) and Tensleep (Teapot Dome) eolian

sandstones

One half of Wyoming’s oil production

Abundant dolomite & anhydrite cement

Formation water salinity: 3,300 – 38,650 ppm

Low salinity water: Coalbed Methane Water (1,316 ppm)

• Phosphoria (Cottonwood) dolomite formation

Recovery factor as low as 10%

Patchy anhydrite

Formation water salinity: 30,755 ppm

Low salinity water: Diluted formation water (1,537 ppm)


Crude Oils

Oil samplen-C6 Asph

[%wt]Acid #

[mg KOH/g oil]Base #

[mg KOH/g oil]

Tensleep 3.2 0.16 0.96

Minnelusa 9.0 0.17 2.29

Phosphoria 2.9 0.56 1.83


Minnelusa Rock from Oil Zone

100 mm

Dolomite

Anhydrite

Dolomite

• Mineralogy: sandstone with abundance dolomite and anhydrites cements

• Porosity: 12.2 -18.1%

• Permeability: 63.7 – 174.2 mDPu et al., 2010


0

5

10

15

20

25

0

10

20

30

40

50

60

70

80

90

100

0 2 4 6 8 10 12 14 16 18

Pre

ssu

re d

rop

, p

si

Oil

reco

very

, %

OO

IP

Brine injected, PV

M1

Kg = 78.4 md, f = 14.6%

Swi = 8.2%,

MW (38,651ppm) CBMW (1,316ppm)

+5.8%

Pu et al., 2010

Low Salinity Waterflooding for Minnelusa Rock from Oil Zone


Phosphoria Rock from Cottonwood Creek Field

100 mm

DolomiteVugDolomite

Mineralogy: Crystallin dolomite and patchy anhydrites

Porosity: 9.5 -19.6%

Permeability: 0.25 – 294 mdPu et al., 2010


0

5

10

15

20

25

30

0

10

20

30

40

50

60

70

80

90

100

0 5 10 15 20 25 30 35 40 45 50

Pre

ssure

dro

p,

psi

Oil

reco

very

, %

OO

IP

Brine injected, PV

PW30,755ppm

5% PW dilute1,537ppm

P1

Kg = 6.8 md, f = 9.5%Swi = 22.7%

+8.1%

Kwe1 = 2.1 md

Kwe2 = 1.1 md

Low Salinity Waterflooding for Phosphoria Rock

Pu et al., 2010


Tensleep Rock from Oil Zone

100 mm

Dolomite

quartz

dolomite

anhydrite

• Mineralogy: sandstone with dolomite and anhydrites cements

• Porosity: 8.6 -15.7%

• Permeability: 7.0 – 42.7 mdPu et al., 2010


0

10

20

30

40

50

60

70

80

90

0

10

20

30

40

50

60

70

80

90

100

0 10 20 30 40 50 60 70

Pre

ssure

dro

p,

psi

Oil

reco

very

, %

OO

IP

Brine injected, PV

T4

Kg = 22.9 md, f = 12.5%Swi = 15.3%

MW38,651ppm

CBMW1,316ppm

Kwe2 = 0.55 mdKwe1 = 0.53 md

+5.2%

Low Salinity Waterflooding for Tensleep Rock from Oil Zone

Pu et al., 2010


Anhydrates dissolution in Tensleep rock – the green regions show the region

of cement dissolutions after flooding with CBM water (Lebedeva et al., 2009)


Tensleep Rock from Aquifer

100 mm

Dolomite

Dolomite

Mineralogy: sandstone with interstitial dolomite crystals and minimal anhydrates

Porosity: 17 -18.7%

Permeability: 50.8 – 228.5 mdPu et al., 2010


0

5

10

15

20

25

30

0

10

20

30

40

50

60

70

80

90

100

0 5 10 15 20 25 30

Pre

ssure

dro

p,

psi

Oil

reco

very

, %

OO

IP

Brine injected, PV

MW38,651ppm

CBMW1,316ppm

Core# Kg (md) f Swi (%)TA1 228.5 18.7 22.4TA2 50.8 18.1 20.4

RTA1

RTA2

PTA2

PTA1

Kwe = 10.4 md

Kwe = 1.1md

Low Salinity Waterflooding for Tensleep Rock from Aquifer

Pu et al., 2010


Silurian Dolomite Outcrop

Mineralogy: interstitial dolomite and no anhydrates

Porosity: 17 – 20%

Permeability: 100 mD – 1,000 md


0 5 10 15 20 25 30 350

20

40

60

80

100

0 5 10 15 20 25 30 350

5

10

15

20

25

30

35

20x Dilution

of Seawater

pH

P (psi)

pH

an

d

P (

psi

)

Rw

f (%

OO

IP)

Silurian Dolomite (WP Crude Oil)

Ta = 60

oC ; T

d = 60

oC

kg = 102 mD ; kb = 19 mD

Swi

= 24%

Injected Brine, PV

Seawater

Low Salinity Waterflooding for Silurian Dolomite Outcrop


Summary

• Tensleep and Minnelusa sandstones, and

Phosphoria dolomite all contained

anhydrites and all responded to low

salinity waterflooding

• Tensleep sandstone from an aquifer and

Silurian dolomite outcrop did not contain

any noticeable anhydrites and did not

respond to low salinity waterflooding


3. Sequential Waterflooding

Morrow, Xie, and Loahardjo, US Patent No. WO 2009/12663 A2, October 2009

Morrow, Xie, and Loahardjo, Pending Provisional Patent No. 61/226,709, July 2009


Effect aging at Sor and/or Swi

on sequential waterflooding


Recovery of Crude Oil

Medium Permeability Berea Sandstone

Aging at Sor after 3 cycles

Ta = 75 oC

Td = 60 oC


0 1 2 3 4 5 6 70

20

40

60

80

100

kg = 604 mD PH 2L H 02 (WP Crude Oil)

Ta = 75

oC ; t

a = 6 months

Td = 60

oC (m = 28.8 cP)

R1/C1 : Swi

= 26% : Sor = 44%

Rw

f (%

OO

IP)

PV Brine Injected0 1 2 3 4 5 6 7

0

20

40

60

80

100


Ta = 75

oC ; t

a = 6 months

Td = 60

oC (m = 28.8 cP)

R1/C1 : Swi

= 26% : Sor = 44%

R1/C2 : Swi

= 36% : Sor = 28%

Rw

f (%

OO

IP)


0

20

40

60

80

100


Ta = 75

oC ; t

a = 6 months

Td = 60

oC (m = 28.8 cP)

R1/C1 : Swi

= 26% : Sor = 44%

R1/C2 : Swi

= 36% : Sor = 28%

R1/C3 : Swi

= 46% : Sor = 19%

Rw

f (%

OO

IP)

PV Brine Injected

20 days at Sor

0 1 2 3 4 5 6 70

20

40

60

80

100


Ta = 75

oC ; t

a = 6 months

Td = 60

oC (m = 28.8 cP)

R1/C1 : Swi

= 26% : Sor = 44%

R1/C2 : Swi

= 36% : Sor = 28%

R1/C3 : Swi

= 46% : Sor = 19%

R1/C4 : Swi

= 42% : Sor = 15%

Rw

f (%

OO

IP)

PV Brine Injected

Sequential waterflooding with wettability control

for medium permeability Berea sandstone



Low Permeability Berea Sandstone

Aging at Swi after 4 cycles

followed by aging at Sor

Ta = 75 oC

Td = 60 oC


0 1 2 3 4 5 6 70

20

40

60

80

100k

g = 84 mD k

g = 84 mD Ev 2L 02 (WP Crude Oil)

Ta = 75

oC ; t

a = 6 months

Td = 60

oC (m = 28.8 cP)

R1/C1 : Swi = 28% : S

or = 49%

Rw

f (%

OO

IP)


0

20

40

60

80

100k


Ta = 75

oC ; t

a = 6 months

Td = 60

oC (m = 28.8 cP)

R1/C1 : Swi = 28% : S

or = 49%

R1/C2 : Swi = 28% : S

or = 43%

Rw

f (%

OO

IP)


0

20

40

60

80

100k


Ta = 75

oC ; t

a = 6 months

Td = 60

oC (m = 28.8 cP)

R1/C1 : Swi = 28% : S

or = 49%

R1/C2 : Swi = 28% : S

or = 43%

R1/C3 : Swi = 31% : S

or = 38%

Rw

f (%

OO

IP)


0

20

40

60

80

100k


Ta = 75

oC ; t

a = 6 months

Td = 60

oC (m = 28.8 cP)

R1/C1 : Swi = 28% : S

or = 49%

R1/C2 : Swi = 28% : S

or = 43%

R1/C3 : Swi = 31% : S

or = 38%

R1/C4 : Swi = 38% : S

or = 29%

Rw

f (%

OO

IP)

PV Brine Injected

30 days at Swi

0 1 2 3 4 5 6 70

20

40

60

80

100k


Ta = 75

oC ; t

a = 6 months

Td = 60

oC (m = 28.8 cP)

R1/C1 : Swi = 28% : S

or = 49%

R1/C2 : Swi = 28% : S

or = 43%

R1/C3 : Swi = 31% : S

or = 38%

R1/C4 : Swi = 38% : S

or = 29%

R1/C5 : Swi = 34% : S

or = 38%

Rw

f (%

OO

IP)

PV Brine Injected

20 days at Sor

0 1 2 3 4 5 6 70

20

40

60

80

100k


Ta = 75

oC ; t

a = 6 months

Td = 60

oC (m = 28.8 cP)

R1/C1 : Swi = 28% : S

or = 49%

R1/C2 : Swi = 28% : S

or = 43%

R1/C3 : Swi = 31% : S

or = 38%

R1/C4 : Swi = 38% : S

or = 29%

R1/C5 : Swi = 34% : S

or = 38%

R1/C6 : Swi = 37% : S

or = 22%

Rw

f (%

OO

IP)

PV Brine Injected


for low permeability Berea sandstone



High Permeability Berea Sandstone – BS 4

Aging at Sor after 4 cycles

followed by aging at Swi, Sor , Sor and Sor

Restoration 2

Ta = 75 oC; ta = 1 year

Td = 60 oC


17 days at Sor

25 days at Swi24 days at Sor

21 days at Sor3 months at Sor


for high permeability Berea sandstone – Restoration 2


Summary

• Further investigation of oil recovery by sequential

waterflooding is needed, particularly for different types of

crude oil, because wettability, and changes in wettability,

depend on specific crude oil/brine/rock interactions

• Aging at high water saturation usually gave increase in

oil recovery, whereas aging at low water saturation

resulted in decreased oil recovery

• Sequential waterflooding without change in salinity and

without cleaning or re-aging between cycles usually

showed sequential reductions in residual oil saturation.

• Single-well field testing of sequential waterflooding is

justified


Single-Well Tests of Sequential Floods

Calculations are based on a simple

piston-like displacement model

f =20.9%, 30 ft reservoir oil-zone thickness


Reservoir at residual oil saturation after waterflood

(WF1)

SOR (WF1)=36.2%

target zone radius = 45 ft

0 10 20 30 40 50 ft

Day 0


Injection of oil into the target zone

SOR (WF1)=36.2%

target zone radius = 45 ft

SOR (WF1)=36.2%

oil injected = 100 bbl

Day 1

SO=64.9%

0 10 20 30 40 50 ft


START WATER INJECTION

SOR (WF1)=36.2%

oil bank minimum radial length= 4.5 ft

oil bank volume = 406 bbl

Displacement of injected oil by injection of brine

(WF2)

inner radial distance

oil bank radial length

Day 1Day 2

Radial length of oil reaches minimum before

growing upon more injection of brine

0 10 20 30 40 50 ft


SOR (WF1)=36.2%

Continuation of oil bank displacement by

injection of brine (WF2)

oil bank radial length= 5.9 ft oil bank volume = 1,149 bbl

SO=64.9%

SOR (WF2)=28.8%

Day 2Day 3Day 4Day 5Day 6

0 10 20 30 40 50 ft


The well is put on production and the oil bank

grows in volume and radial length

SOR (WF1)=36.2%

Day 6Day 8Day 9Day 10

0 10 20 30 40 50 ft


SOR (WF1)=36.2%SOR (WF2)=28.8%SOR (WF3)=24.0%

Day 10Day 11Day 12Day 13Day 14

0 10 20 30 40 50 ft

The well is put on production and the oil bank

grows in volume and radial length


Single Well Field Test

4,000 bbl oil in 62 days(as high as 15,000 bbl optimistically)

900 bbl oil in 14 days(as high as 3200 bbl optimistically)

2,000 bbl brine

100 bbl oil

10,000 bbl brine 100 bbl

oil


Single Well Field Tests

• Low cost: Injected brine and oil are directly available: Required oil volume is small

• Test should first be applied to reservoirs with flow conformance (responded well to waterflooding), oil viscosity close to that of the injected brine and low gas/oil ratio

• Single well tracer tests can be used to determine residual oil saturations before and after the process


Field Test ? 2011 ?

Discussion of potential field test

with James Seccombe and Scott Digert (BP Alaska) Laramie, Wyoming, October 13, 2010


Further Application of Sequential Waterflood

Improved Recovery by Injection of Small Volumes of Oil

1. Inject multiple oil banks

(single well or well to well)

2. Reversing production and injection well before breakthrough to avoid sand production, especially for less consolidated reservoir

3. Convert a tertiary mode low salinity flood into a more favorable/effective secondary mode low salinity waterfloodby pre-injection of oil

4. Establishing initial oil bank for other recovery methods, e.g. before flooding natural residual oil zone


Ongoing Topics and Future Work

1. Low Salinity Waterflooding

a. Tests on reservoir rocks

b. Screening outcrop cores, at Swi and Sor

c. Attempt to identify a mechanism for LSW

2. Sequential Waterflooding

a. Further laboratory tests

b. Field tests of Sequential Waterflooding

3. Waterblock Treatment


Acknowledgments• EORI, University of Wyoming

• Wold Chair

• Industry:

Saudi Aramco*, BP*,Chevron, ConocoPhillips, Shell,

StatoilHydro*, Total* (enquiries from Oxy, Kuwait, Maersk)

* includes provision of reservoir rock and/or crude oil

Thank You !


Improved Oil Recovery by Waterflooding

Nina LoahardjoPetrophysics and Surface Chemistry Group

Chemical and Petroleum Engineering

University of Wyoming

18 January 2011

improved oil recovery by waterflooding - university of wyoming

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