OMV Exploration & Production

Determination of the I it P lIn-situ Polymer Viscosity from Fall-Off T tOff Tests

Ajana Laoroongroj, Imperial College*; Markus Zechner, OMV E&P; Torsten Clemens OMV E&P;Torsten Clemens, OMV E&P; Alain Gringarten, Imperial College

*Now with OMV E&P

Outline

Newtonian Versus Non-Newtonian Fluid Problem Statements Welltest Applications Fi ld I t d ti Field Introduction Workflow Results Results Summary and Conclusions

2

Newtonian VS Non-Newtonian

Power law model (Jennings et al 1971):1 nK

K = Consistency Index, cp.sn-1

n = Power law Exponentn Power law Exponent

Find n from the slope of the plot of shear rate and viscosity on logarithmic scales

Shear rate in porous media (Teew and Hesseling 1981):

knnu 8

13

Hesseling 1981):

3

polymer viscosity decreases at near the wellbore region.

Problem Statements

Surface µ can be measuredSurface µp can be measured

µp at reservoir condition

Reservoir qReservoir qinj

• Shear-thinning characteristic• Polymer degradation

4

Welltest Application:Radial Composite Modelp

Polymer Viscosity is calculated by inner region

Rr

mobility. Front radius can be estimated by the time match.

re

rw

i

k

k

M

rwR

o

h

5

re

Field Introduction

8 TH Horizon, Matzen Field, Austria1951: 1st oil production1951: 1st oil production1956: Peak oil production1960: Start waterflooding2009: Design polymer injection due to high

permeability and medium viscosity (20 cP)permeability and medium viscosity (20 cP)2010: Perform water injection falloff tests

Current recovery factor 26%Current water cut 90%Current reservoir temperature 30°CCurrent reservoir temperature 30°C

Parameter Fall-off#1 Fall-off#2Reservoir Homogeneous Homogenousg gBoundary Infinite RectangleInitial pressure, pi(psia)

1577 1512

Permeability, k (md) 550 55010

100

Pre

ssur

e [p

si]

10

6

y, ( )Skin, S 0.26 0.52Wellbore storage, C (bbl/psi-1)

0.0394 8.69e-61E-3 0.01 0.1 1 10 1001

Time [hr]

Falloff test#1 Falloff test#2

Model Description:Workflow

Water Simulated Adjust initial E linjection fall-

off tests databottom-hole

pressurepressure in Eclipse

Match Match Well test analysis Well test analysis

injection?

Match historical

water injection?

N

Reservoir properties:-

k & S

p & RStatic reservoir

Y

k & S

Eclipse black oilCompare p & R

with reservoir Polymer

model

7

Eclipse black oil with reservoir simulation

injection scenarios

Model Verification:

The models areThe models are Cylindrically reservoir with the well

located at the centre One layer system One-layer system Five-layer system

Effective permeability at 550 md 27% constant porosity Total permeability thickness is

2750 md-m Initial Pressure at 1550 psia History water injection rate

8

Newtonian Fluid Results:Analysis of Different Injecting Periodsy j g

Injection periods1 da R 10 m- 1 day, R = 10 m

- 6 days, R = 20 m- 23 days, R = 40 m- 51 days, R = 60 m- 90 days, R = 80 m 100

1000 Dominate 2nd line by boundary effect

y- 141 days, R = 100 m

10

Reservoir Model Data Cannot observe1st straight line

0.1

11Reservoir Model Data- qinj = 300 m3/d- C = 0.75 kg/m3

- Newtonian fluids- µp = 17 cP

0 8 P

g

1E-3

0.01

- µw = 0.8 cP- Re = 1000 m- Pi = 1550 psia- k = 550 mD- Φ = 27%

9

1E-4 1E-3 0.01 0.1 1 10 100 1000

Time [hr]

1E-4

- ct = 6.2 x 10-6

- Swi = 1.00

Newtonian Fluid Results:Analysis of Different Injecting Periodsy j g

Injection periods1 da R 10 m- 1 day, R = 10 m

- 6 days, R = 20 m- 23 days, R = 40 m- 51 days, R = 60 m- 90 days, R = 80 m

Parameter SimulationInput

Volumetric Front Radius

20m 40 m 60 m 80 m

Pi (psia) 1550 1556 1542 1533 1541y- 141 days, R = 100 m k (md) 550 550 550 550 550

Mobility 0.047 0.048 0.048 0.048 0.047

Storativity 1 000 1 021 1 021 0 980 0 940Reservoir Model Data Storativity 1.000 1.021 1.021 0.980 0.940

μP (cp) 17 16.7 16.7 16.7 17.1

R (m) - 22 41 61 81

Reservoir Model Data- qinj = 300 m3/d- C = 0.75 kg/m3

- Newtonian fluids- µp = 17 cP

0 8 P Re (m) 1000 981 982 981 970

μP Error(%) - -2% -2% -2% 1%

R Error (%) - 11% 2% 1% 2%

- µw = 0.8 cP- Re = 1000 m- Pi = 1550 psia- k = 550 mD- Φ = 27%

10

- ct = 6.2 x 10-6

- Swi = 1.00

Newtonian Fluid Results:Effect of Heterogeneityg y

Models1 one la er s stem- 1: one-layer system

- 2: five-layer system550 mD - 3: five-layer system330, 440, 550, 660 100

1000

and 770 mD- 4: five-layer system100, 400, 550, 600and 1000 mD

10

Reservoir Model Data- qinj = 300 m3/d- Newtonian fluids- µ = 17 cP

0 1

1

0.1

µp 17 cP- µw = 0.8 cP- Re = 1000 m- Pi = 1550 psia- kh = 2750 mDΦ 27%

1E-3

0.01

11

- Φ = 27%- ct = 6.2 x 10-6

- Swi = 1.00 1E-3 0.01 0.1 1 10 100

Time [hr]

1E-4

Newtonian Fluid Results:Effect of Heterogeneityg y

Models1 one la er s stem

Parameter SimulationInput

Model

1 2 3 4

Pi (psia) 1550 1542 1540 1541 1542

- 1: one-layer system- 2: five-layer system550 mD - 3: five-layer system330, 440, 550, 660

Mobility 0.047 0.046 0.046 0.048 0.048

Storativity 1 0.979 0.979 0.960 1.021

μP (cp) 17 16 7 16 7 16 7 16 7

and 770 mD- 4: five-layer system100, 400, 550, 600and 1000 mD

μP (cp) 17 16.7 16.7 16.7 16.7

R (m) 40 40.8 40.8 40.2 41.6

Re (m) 1000 982.0 982.0 825.6 725.1

Reservoir Model Data- qinj = 300 m3/d- Newtonian fluids- µ = 17 cP

μP Error(%) - -2% -2% -2% -2%

R Error (%) - 2% 2% 1% -1%

Re Error(%) - -2% -2% -17% -28%

µp 17 cP- µw = 0.8 cP- Re = 1000 m- Pi = 1550 psia- kh = 2750 mDΦ 27%

12

- Φ = 27%- ct = 6.2 x 10-6

- Swi = 1.00

Results:Effects of Relative Permeability Reductiony

RRF- RRF = 1.0- RRF = 1.5- RRF = 2.0

1000

Reservoir ModelData

100

- qinj = 300 m3/d- C = 0.75 kg/m3

- Newtonian fluids- µp = 17 cP

1010

RRF = 1.0 RRF = 1.5 RRF = 2.0 p

- µw = 0.8 cP- Re = 2000 m- Pi = 1550 psia- k = 550 mD

1

13

- Φ = 27%- ct = 6.2 x 10-6

- Swi = 1.00

0.01 0.1 1 10 100

Time [hr]

0.1

Results:Effects of Relative Permeability Reductiony

RRF RRF- RRF = 1.0- RRF = 1.5- RRF = 2.0

Parameter1.0 1.5 2.0

Pi (psia) 1544 1539 1543

M bilitReservoir Model Data- qinj = 300 m3/d- C = 0.75 kg/m3

- Newtonian fluids Well test Analysis

Mobility 0.047 0.032 0.024

Storativity 0.979 1.000 0.960

k (md) 550 367 275- µp = 17 cP- µw = 0.8 cP- Re = 2000 m- Pi = 1550 psia

AnalysisμP (cp) 17 16.7 16.7

R (m) 41.2 38.7 38.4

R (m) 2011 1909 1930- k = 550 mD- Φ = 27%- ct = 6.2 x 10-6

- Swi = 1.00

Re (m) 2011 1909 1930

ErrorμP Error(%) 0% -2% -2%

R Error (%) 3% -3% -4%

14

Non-Newtonian Results:Analysis of Shear-Thinning Behavioury g

C (kg/m3)C 0 5 C (kg/m3)- C = 0.5

- C = 0.75- C = 1.00

ParameterC (kg/m )

0.50 0.75 1.00

Simulation Input

μavg 3.71 6.62 9.55

Reservoir Model Data

InputPi (psia) 1542 1543 1547

Mobility 0.209 0.115 0.081

Storativity 0 925 0 975 1 025Reservoir Model Data- qinj = 300 m3/d- Non-Newtonian fluids- µw = 0.8 cP- R = 60 m

R 2000

Well test Analysis

Storativity 0.925 0.975 1.025

μP (cp) 3.84 6.98 9.91

R (m) 66.5 64.5 61.6- Re = 2000 m- Pi = 1550 psia- Φ = 27%- ct = 6.2 x 10-6

- Swi = 1.00

Re (m) 1947 1950 1980

E

μP Error(%) 4% 5% 4%

R Error (%) 11% 8% 3%

15

wi Error (%) 11% 8% 3%

Re Error (%) -3% -3% -1.0%

Non-Newtonian Results:Analysis of Shear-Thinning Behavioury g

C (kg/m3)C 0 5- C = 0.5

- C = 0.75- C = 1.00

Reservoir Model DataReservoir Model Data- qinj = 300 m3/d- Non-Newtonian fluids- µw = 0.8 cP- R = 60 m

R 2000

1000

- Re = 2000 m- Pi = 1550 psia- Φ = 27%- ct = 6.2 x 10-6

- Swi = 1.00

1010

100

16

wi

0.01 0.1 1 10 100

Time [hr]

0.1

1

Field Data: 3 Pressure Fall Off testsAug-1-2012.ks3 - Analysis 1Feb-02-2012.ks3 - Analysis 1 (ref)16-Sep-2011.ks3 - Analysis 1

1000

Pre

ssur

e [p

si]

100

17

1E-3 0.01 0.1 1 10Time [hr]

Summary and conclusionsy

Polymer front radius and in-situ polymer viscosity can be determined by pressure transient analysis.

Shear-thinning fluid pressure transient analysis gives a good g p y g gestimate of the polymer fluid front and in-situ viscosity.

The reservoir uncertainty is reduced by performing water injection The reservoir uncertainty is reduced by performing water injection fall-off tests.

Multiple polymer injection fall off tests should be performed Multiple polymer injection fall-off tests should be performed.

18

Acknowledgements

OMV E&P for the permission to publish the paper.

Wei Chun Chu and Martin Kornberger for the discussions.

Gery Verient for the welltest data.

19

Q&A

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