Study of Imbibition Mechanisms in the Naturally Fractured Spraberry Trend Area Yan Fidra Petroleum and Chemical Engineering Department New Mexico Institute.

Study of Imbibition Mechanisms in the Naturally Fractured Spraberry Trend

Area

Yan Fidra

Petroleum and Chemical Engineering DepartmentNew Mexico Institute of Mining and Technology

Outline

• Introduction

• Laboratory Experiments

• Modeling

• Conclusions

• Recommendations

Outline

• Introduction– Problem statement– Literature review– Objectives– Overview of the study

• Laboratory Experiments• Modeling• Conclusions • Recommendations

Problem Statement

Lack in understanding of upscaling

laboratory imbibition experiments to

field dimensions

- Low rock permeability that represent real thing

- Static and dynamic process

- Reservoir conditions

Wetting behavior

Literature Review

rock characteristics (Mattax and Kyte, 1962; Torsaeter, 1984; Thomas 1984; Hamon and Vidal, 1988)

fluid properties (Iffly et al., 1972; Cuiec et al., 1990; Keijzer and De Vries, 1990; Ghedan and Poetmann, 1990; Schechter et al., 1991; Babadagli, 1995; Al-Lawati and Saleh, 1996)

low permeability of Chalk reservoir (Torsaeter, 1984; Bourbiaux and Kalaydjian, 1990; Cuiec et al., 1990)

wettability (Anderson, 1986; Hirasaki, et al, 1990; Zhou et al., 1995; Buckley, et al , 1995)

aging time and temperature and initial water saturations (Zhou et al., 1993; Jadhunandan and Morrow, 1991)

scaling of imbibition data (Mattax and Kyte, 1962; Lefebvre du Prey, 1978; Ma, 1995; Zhang et al, 1996)

Objectives

• To investigate wettability of Spraberry Trend Area at reservoir conditions.

• To upscale the laboratory imbibition results to field-scale dimensions.

• To investigate the contribution of the capillary imbibition mechanism to waterflood recovery.

• To determine the critical water injection rate during dynamic imbibition.

Overview of the Study

Static imbibition

Dynamicimbibition

Field dimension

Determine rock wettability

Upscaling Upscaling

Determine laboratory critical

injection rate

Fracture Capillary Number

Scaling equations

Capillary pressure curve

Outline• Introduction

• Laboratory Experiments– Static Imbibition Tests

• Verify the effect of P & T on recovery mechanisms• Determine rock wettability index

– Dynamic Imbibition Tests• Investigate the effect of injection rate on recovery

mechanism• Determine critical injection rate

• Modeling• Conclusions • Recommendations

Static Imbibition Experiments

• Materials• Experimental apparatus• Results

Porous Media

FluidsCrude Oil

Synthetic Reservoir Brine

(TDS = 130,196 ppm)

Berea sandstone

Low permeabilitySpraberry rock

Materials

Schematic Diagram of the Static Imbibition Process in Laboratory

coreoiloil

water

Imbibition model with one end closed

1.5” X 2.5 - 3.0”Core

Syntheticbrine

beaker

138oF

Experimental Set-up for Imbibition Tests under HPHT

BVBV

BV

NV

PR

Graduated Cylinder

Brine Tank HighPressure

ImbibitionCell

N2 Bottle(2000 psi)

Air Bath

BV = Ball ValveNV = Needle ValvePR = Pressure Regulator

Top View

Inlet for creatingtangential flow

Side View

core

Brine Pump Oil Pump

Air Bath

Core holder

Confining pressure gauge

Graduated cylinder

Oil tank Brine tank

Flooding Apparatus

0

10

20

30

40

50

60

70

0 1 100 10000Time, hours

Oil

Rec

over

y, %

IO

IP

B-13, P = 13.5 psiB-10, P = 13.5 psiB-11, P = 1000 psiReference

7 days aging

Texp = 138oFSwi = 0 %

Effect of Pressure and Temperature on Static Imbibition Rate and Recovery using Berea Sandstone

0

10

20

30

40

50

60

-100 400 900Time, hours

Rec

over

y, %

IO

IP

Increased to

temperature 138oF

No agingP = 13.5 psiSwi = 0%

Tres = 138oF

Troom = 70oF

0

5

10

15

20

25

0.1 10 1000 100000

Time, Hours

Oil

Rec

ove

ry,

% I

OIP

Core SPR-1HRCore SPR-12HCore SPR-13RCore SPR-14R

138oF

70oF

138oF

70oF

0

5

10

15

20

25

-100 400 900 1400 1900

Time, Hours

Oil

Rec

ove

ry,

% I

OIP

Core SPR-1HR

Core SPR-12H

Core SPR-15R

Extended to reservoir temperature

Effect of Temperature on Static Imbibition Rate and Recovery using Spraberry Reservoir Rock

Cleaning Spraberry core plugs

Dean Stark Extraction

Chloroform Displacement

Drying (2 days) Evacuation (24 hours) Weight

Evacuated Spraberry brine Measure brine density and viscosity

Saturation of core samples

Ionic equilibrium (3 days) Porosity calculation

Brine permeability Recheck the porosity

Oil viscosity, density and

IFT measurementsOil floodingOil flooding

Establish Swi Establish Swi i

Aging core samples in oil

Aging time (days)Aging time (days)

0 3 7 14 21 30

at reservoir temperatureat reservoir temperature

Aging time (days)Aging time (days)

0 7 14

at reservoir temperatureat reservoir temperatureNo aging timeNo aging time

Imbibition tests (21 days)at reservoir temperature

Imbibition tests (21 days) at reservoir temperature

Imbibition tests (2 months)at ambient condition

Brine displacementBrine displacementat room temperatureat room temperature

Brine displacementBrine displacementat reservoir temperatureat reservoir temperature

Brine displacementBrine displacementat room temperatureat room temperature

Results

Experimental Procedures for determining WI using Spraberry Cores

DisplacementDisplacement

A

B

Static imbibitionStatic imbibition

Amott Wettability Index

WIRA

RA RB

0 1

Water-wetmoreless

0

2

4

6

8

10

12

14

16

18

20

0.01 0.1 1 10 100 1000 10000Time, Hours

Oil

Rec

over

y, %

IO

IP

Core SPR-1HR

Core SPR-2HR

Core SPR-6HR

Core SPR-5HR

Core SPR-7HR

Core SPR-3HR

No aging

7 days aging

14 days aging

21 days aging

30 days aging

Static imbibition

A

Oil Recovery Curves Obtained from Static Imbibition Experiments at Reservoir

Temperature

Spraberry cores

0

10

20

30

40

50

60

0 10 20 30 40

Aging Time, ta (days)

Oil

Rec

over

y, %

IOIP

Recovery from imbibition process

Total Recovery

DisplacementDisplacement

A

B

StaticStaticimbibitionimbibition

Total recovery vs aging time shows that 7 days aging time is adequate to start the

experiments

Spraberry cores

Displacement

A

B

Static imbibition Wettability index vs aging time

for different experimental temperatures

WIRA

RA RB

Spraberry cores0.0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

1.0

0 10 20 30Aging Time, ta (days)

Wet

tabil

ity I

ndex

to W

ate

r, W

I

Process A = 138F and Process B = 138F

Process A = 70F and Process B = 70F (without aging)

Process A = 138F and Process B = 70F

Dynamic Imbibition Experiments

•Schematic of displacement process

•Experimental apparatus•Results

MATRIX BLOCK

MATRIX BLOCK

FRACTUREWater Oil + Water

Oil saturated matrix

Imbibed water

Capillary imbibition

Viscous flow

Oil produced

Schematic Representation of the Displacement Process in Fractured Porous Medium

MatrixFracture

Artificially fractured core

Air BathAir Bath

Core holderBrine tank

Confining pressure gauge

Graduated cylinder

N2 Tank(2000 psi)

RuskaPump

Experimental Apparatus for Dynamic Imbibition Tests

0

10

20

30

40

50

60

70

0.001 0.01 0.1 1 10 100

PV Water Injected

Oil

Rec

over

y, %

IO

IP

Qinj = 1 cc/hr

Qinj = 2 cc/hr

Qinj = 4 cc/hr

Qinj = 8 cc/hr

Qinj = 8 cc/hr (repeated)

Qinj = 16 cc/hr

Qinj = 40 cc/hr

Oil Recovery from Fractured Berea Cores during Water Injection using Different Injection Rates

0

10

20

30

40

50

60

0.00 0.50 1.00 1.50 2.00 2.50 3.00 3.50

PV Water Injected

Oil

Rec

over

y

Unfractured core, Qinj = 0.2 cc/hr

Fractured core, Qinj = 0.2 cc/hr

Fractured core, Qinj = 0.5 cc/hr

Fractured core, Qinj = 1.0 cc/hr

Unfractured core

Fractured core

Oil Recovery from Fractured Spraberry Cores during Water Injection using Different Injection Rates

0.00

0.10

0.20

0.30

0.40

0.50

0.60

0.70

0.80

0.90

1.00

0 10 20 30 40 50 60

Injection Rate, cc/hr

Oil

Pro

du

ced F

rom

Matr

ix, P

V

Tota

l W

ate

r In

ject

ed, P

V

Experimental data from Berea cores

Experimental data from Spraberry cores

Critical Injection rate for Spraberry cores, 10 cc/hr

Critical Injection rate for Berea cores, 20 cc/hr

Injection rate versus oil-cut curve for Berea and Spraberry cores

Outline• Introduction• Laboratory Experiments

•Modeling– Static imbibition data

• Investigate Pc from matching of experimental data.• Scale up of static imbibition data.

– Dynamic imbibition data• Obtain Pc curves from matching of experimental data.• Scale up of dynamic imbibition data.

• Conclusions • Recommendations

Modeling of Static Imbibition

• Numerical Analysis of Static Imbibition Data

• Scaling of static imbibition data

• Results

Matching between Laboratory Experiments and Numerical Solution

0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

1.0E+00 1.0E+02 1.0E+04 1.0E+06 1.0E+08

Time (Sec)

Volu

me

Oil

(cc

)

Numerical Solution

SPR-8H

SPR-9H

SPR-7HR

SPR-11H

Capillary Pressure Curve Obtained as a Result of Matching

Experimental data

0.000

0.005

0.010

0.015

0.020

0.025

0.0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1.0

Water Saturation, Sw (%PV)

Capil

lary

Pre

ssure

, Pc (p

si)

Numerical Analysis of Static Imbibition Data

Scaling of Imbibition Data“Concept of Imbibition Flooding Process”

( Brownscombe, 1952 )

WaterWaterMatrixMatrix

FractureFracture

InvadeInvadedd

zonezone

Oil productionOil production

Oil production by water imbibitionOil production by water imbibition

water

oil

Capillary force

fracture matrix

Matrix fracture fluidexchange mechanism

Viscous force

To investigate the contribution of a static imbibition process to waterflood recovery

Imbibition

A

Complete Oil Recovery Curves Obtained from Imbibition Experiments

0

2

4

6

8

10

12

14

16

18

20

0.01 0.1 1 10 100 1000 10000Time, Hours

Oil

Rec

over

y, %

IO

IP

Core SPR-1HRCore SPR-8HCore SPR-9HCore SPR-12HCore SPR-10HCore SPR-2HRCore SPR-6HRCore SPR-5HRCore SPR-7HRCore SPR-3HRCore SPR-11HSPR-13SPR-14SPR-15

No aging

7 days aging

14 days aging

21 days aging

30 days aging

70oF

Spraberry cores

No aging

0.0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

1.0

1 10 100 1000 10000

Dimensionless Time

Nor

mal

ized

Rec

over

y Reservoir Condition

Ambient Condition

Without aging

With aging

Oil Recovery Curves in Terms of Dimensionless Variables

t C tk

LD

m

g c

cos( )2

RR

Rnimb

0.00

0.10

0.20

0.30

0.40

0.50

0.60

0.70

0.80

0.90

1.00

0.01 1 100 10000 1000000

Dimensionless Time, tD

Norm

ali

zed R

ecovery

SWW Core"reference curve"(Ma & Morrow, 1995)

Spraberry Coresat Reservoir Condition

= 0.0053

Spraberry Coresat Ambient Condition

= 0.0015

Aranofsky Eq. : R n = 1 - exp (-t D)

Averaging of imbibition curves

Equations for Scaling of Static Imbibition Data

t Ct yeark md dyne cm

cp L ftD

m

g c

( )( ) ( / )

( )

cos( )

( )

2 2

R R timb D 1 exp

g b o

q V eo ot

C = 10.66;

0 00532

.cos( )

Ck

Lm

g c

0.000

0.020

0.040

0.060

0.080

0.100

0.120

0.140

0.160

7080 7082 7084 7086 7088 7090 7092 7094 7096 7098

Depth in Shackelford 1-38A, feet

Poro

sity

, fr

act

ion

0.01

0.10

1.00

10.00

Abso

lute

Perm

eabil

ity, m

d

Porosity

Absolute Permeability

Non-pay muddy zone

Flourescing pay zone

Rock Properties of Upper Spraberry 1U Unit

7080

7082

7084

7086

7088

7090

7092

7094

0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15

Calculated Recovery Based on Imbibition Model, % IOIP

Dep

th in

Wel

l Sha

ckel

ford

1-3

8A, f

eet

1 year 5 year > 10 year

Ls = 3.79 ft

h = 10 ft

Recovery Profile

Upper SpraberryUpper Spraberry1 U Formation1 U Formation

(Shackleford-138)(Shackleford-138)

1U

0

2

4

6

8

10

12

14

0 5 10 15

Time, Years

Calc

ula

ted O

il R

ecover

y, %

IOIP

Parameters : IOIP = 712,404 - 735,957 rb Rimb = 13% Porosity = 10.02% Bo = 1.294 rb/STB

Fracture spacing, Ls = 2.86 ft

Swi = 0.2 + 0.13e-0.6(k-0.1)

k = 0.3 md

k = 0.1 md

k = 0.03 md

k = 0.01 md

0

2

4

6

8

10

12

14

0 5 10 15

Time, Years

Parameters : IOIP = 712,404 - 735,957 rb Rimb = 13% Porosity = 10.02% Bo = 1.294 rb/STB Matrix permeability = 0.1 mD

Swi = 0.2 + 0.13 e-0.6(k-0.1)

Ls = 1.62 ft

Ls = 2.86 ftLs = 3.17 ft

Ls = 3.79 ft

Effect of Matrix Permeability and Fracture Spacing on Oil Recovery

Modeling of Dynamic Imbibition Data

• Numerical analysis of dynamic imbibition data to obtain capillary curves.

• Concept of fracture capillary number.

• Upscaling of dynamic imbibition data to determine critical water injection rate.

Matching Between

Experimental Data and

Numerical Solution

Berea Core

Spraberry Core

Cumulative water production vs. time Cumulative oil production vs. time

Cumulative water production vs. time Cumulative oil production vs. time

0.0

0.2

0.4

0.6

0.8

1.0

1.2

1.4

1.6

1.8

2.0

0.0 0.5 1.0

Water Saturation, Sw (%PV)

Pc

for

Bere

a C

ore

, (p

si)

0

1

2

3

4

5

6

7

8

9

10

Pc for

Spra

berr

y C

ore

, (p

si)

0

5

10

15

20

25

30

0.0 0.2 0.4 0.6 0.8 1.0

Water Saturation (PV)

Capil

lary

Pre

ssure

(psi

g)

Pc detemined experimentally at roomtemperature

Pc determined by numerically at reservoirtemperature

Drainage

Imbibition

Pc Curves Obtained as Result of Matching Experiment Data

Spraberry core

Berea core

Pc from Numerical Model and Laboratory

Experiment

NViscous Forces

Capillary Forces

v A

Af caw f

m, cos

Nq cc hr cp

P psi

J SA cm

k mdf cainj w

c

wim

m

m

,,max

. ( / ) ( )

( )

( )( )

( )

0 0127

2

Nq STB day cp

P psi

J SA ft

k mdf cainj w

c

wim

m

m

,,max

. ( / ) ( )

( )

( )( )

( )

0 0905

2

Field Units :

Lab Units :

Fracture Capillary Number

Am

w

dz

Af

Capillary force

( cos Am)

Viscous force

(v w Af )

h

0.00

0.10

0.20

0.30

0.40

0.50

0.60

0.70

0.80

0.90

1.00

0 10 20 30 40 50 60

Injection Rate, cc/hr

Oil

Pro

du

ced F

rom

Matr

ix, P

V

Tota

l W

ate

r In

ject

ed, P

V Experimental data from Berea cores

Experimental data from Spraberry cores

Critical Injection rate for Spraberry cores, 10 cc/hr

Critical Injection rate for Berea cores, 20 cc/hr

2 Capillary and viscous forces dominant

1 Capillary force dominant

3 Viscous force dominant

Injection Rate versus Oil-cut

0.00

0.05

0.10

0.15

0.20

0.25

0.30

0.35

0.40

0.45

0.50

0 0.0001 0.0002 0.0003 0.0004 0.0005 0.0006

Fracture Capillary Number, Nf,ca

Oil

Pro

duce

d F

rom

Matr

ix, P

V

Tota

l W

ate

r In

ject

ed, P

V

Experimental data from Berea cores

Experimental data from Spraberry cores

Series3

Power ( Experimental data from Bereacores)

Nf,ca = 0.0001

Nf,ca = 0.00028

Spraberry cores

Berea cores

Dimensionless fracture capillary number versus oil-cut

Porousmedium

Berea sandstone Spraberry

Dimension Core size Field scale Core size Field scale

Nf,ca 0.00028 0.00010

Area - 80 acre - 80 acrewater 0.68 cp 0.68 cp 0.68 cp 0.68 cp

L inj-prod 7.12 cm 1320 ft 6.8 cm 1320 ft

h 3.63 cm 10 ft 3.7 cm 10 ft

Am 25.81 cm2 13200 ft2 24.8 cm2 13200 ft2

k 63.41 md 63.41 md 0.1 md 0.1 md 16.6 % 16.6 % 10% 10%

Pcmax 1.2 psi 1.2 psi 7 psi 7 psi

J (Swi) 0.99 0.99 0.2 0.2

Critical WaterInjection Rate

20 cc/hr 1435 bbl/day 10 cc/hr 751 bbl/day

Upscaling of Critical Injection Rate

1000 0 1000 3000 2000 4000 5000 FEET

3

16

1-4

15

6

1A

1

1

5

14

9

1 13

14

10

4

7

1

28

23

2

1C

36 4

37

25

21

29 1

3

4

1B

PROPOSED CO2 INJECTION WELL

PROPOSED LOGGING OBSERVATION

WATER INJECTION WELL

PLUGGED AND ABANDONED

ACTIVE PRODUCER

SHUT IN WELL46

45

47

41

42

44

40

39

38 4

348

5U (N32E)

5U (N80E)

1U (N42E)

Fracture orientation

O’Daniel Pilot Layout

I njectionWell

Distanceto well-39

(ft)

Critical waterinjection rate

(STB/ D)w-45 1420 807

w-47 1450 824

w-48 1460 830

W-25 1450 824

Estimate Critical Water Injection Rates for Wells in O’Daniel Pilot Area

Outline

• Introduction• Laboratory Experiments

• Modeling

•Conclusions

• Recommendations

Conclusions• Wettability Determination

– Performing the imbibition tests at reservoir temperature and displacement tests at room temperature indicate that WI is 0.3 to 0.4.

– Performing both imbibition and displacement tests at the same temperature (i.e., reservoir temperature or at room temperature) lowers the WI in the range of 0.20 to 0.25; thus, the temperatures during the experimental sequence affect wettability index determination.

– Comprehensive experimental data clearly demonstrates that Spraberry reservoir rock is a very weakly water-wet system.

Conclusions (cont’d)

• Static Imbibition

– Effect of pressure is much less important than the effect of temperature on imbibition rate and recovery.

– Performing the imbibition tests at higher temperature results in faster imbibition rate and higher recovery due to change in mobility of fluids, expansion of oil, and change in IFT.

– The final recovery due to imbibition using Spraberry cores varies from 10% to 15% of IOIP, depending on aging time.

Conclusions (cont’d)

• Scaling of static imbibition data

– The contribution of the imbibition mechanism to oil recovery is up to 13% IOIP, depending on rock properties and wettability.

– Degree of heterogeneity in the matrix and natural fracture system controls the efficiency of Spraberry waterflood performance.

Conclusions (cont’d)

• Dynamic Imbibition– As the flow rate increases, contact time

between matrix and fluid in fracture decreases causing less effective capillary imbibition.

– The capillary pressure curve obtained from dynamic imbibition experiments is higher that of the static imbibition experiments due to viscous forces during the dynamic process.

• The limiting value of fracture capillary number for an efficient displacement process in this study was found to be 0.0001 and 0.00028 for Berea and Spraberry cores, respectively. Beyond this range, the displacement process is inefficient due to high water-cut.

Conclusions (cont’d)

Outline

• Introduction• Laboratory Experiments

• Modeling

• Conclusions

•Recommendations

Recommendations

• Necessary to correlate the static and dynamic tests in order to achieve proper upscaling.

• The capillary pressure curve obtained from dynamic imbibition experiments using artificially fractured core can be used as input data in naturally fractured reservoir simulations instead of using mercury injection capillary pressure curves.

Acknowledgement

I would like to express my sincere appreciation and gratitude to my advisor Dr. David S. Schechter and My committee members Dr. Robert L. Lee, Dr. H.Y. Chen and Dr. Donald Weinkauf for their advice and time spent on this thesis.

To PRRC for the financial support through research assistantship grant.

To my fellow students and the entire staff of the PRRC for their kindness and assistance.

Thank You…

Happy Thanksgiving

1000 0 1000 3000 2000 4000 5000 FEET

15

1

28

4

37

2546

45

47

41

42

44

40

39

38 4

348

5U (N32E)

5U (N80E)

1U (N42E)

Fracture orientation