Condensate Recovery from a Fractured Carbonate Field

Move & More.

SPE EUROPEC 4-7 June 2012

Catalin Paraschiv OMV E&P

Joseph Abdev OMV E&P

Torsten Clemens OMV E&P

SPE 153349

Condensate Recovery from a

Fractured Carbonate Field

2 SPE153349, C. Paraschiv, J. Abdev, T. Clemens

Overview

Reservoir type

Fractured gas condensate reservoir

What was investigated

Condensate recovery for depletion cases and gas injection cases keeping

the pressure above dew point with and without diffusion option activated

What parameters were changed during runs

Fracture spacing, fracture permeability

Matrix porosity

Gas injection type, gas injection rate

Main conclusion

Neglecting diffusion in fractured reservoirs can results in errors in the

condensate recovery of more than 50%


Outline

Basic parameters of the fluid and reservoir

Numerical model

Simulation results for depletion and gas injection cases with and

without diffusion


Fracture network – theoretical model

Effective permeability = ∑KHmatrix + ∑KFfractures

Inj

Prod

Inj

Prod

Fracture corridors

Matrix

Simulation

areas


Diffusion law

Diffusion is described by Fick’s law:

J – mass flux (moving of objects from one

point to another in a given time)

D – Diffusivity (the constant that describe

how fast or slow an object diffuse)

C – Concentration (the amount of mass in a

given volume)

X – Distance (refer to the distance the object

is diffusing)

x

CDJ

*


Basic reservoir and fluid parameters

Reservoir location: Middle East

Reservoir type : Fractured carbonates reservoir

Hydrocarbon type: Gas condensate

Permeability :

from cores: 0.2 - 1 mD

from well test: 10 mD

Porosity (avg): 6.5%

Initial reservoir pressure: 360bar

Saturation pressure: 342 bar

Maximum liquid drop out: 37%

Reservoir temp: 121°C


Numerical model

Matrix

Fra

ctu

re

Producer

Injector

For all cases it was used:

Km = 1;

Φm = 0.15

Kfr*dxfracture_cell = Km*dxmatrix_cell*no_cells

Φfr = Kfr*dx/10

Qinj = 3 m³ / day / perforated meter

100 m

0.16-10m

1HK

HK frfr

Base

case

Producer is

BHP constrained

at 347bar

X direction

Y d

irectio

n


Fluid and rock properties

Fluid properties

A 15 components EoS was created and diffusion

coefficients were calculated using Silva and Belery

method. Dewpoint pressure is 342bar.

.

0

0.2

0.4

0.6

0.8

1

0 0.2 0.4 0.6 0.8 1

kr

Sw

Water-Oil Relative Permeabilities

k…

Rock properties

Connate water saturation was 30% in the matrix, 5%

residual oil sat, 15% trapped gas saturation, end points

of 1 and straight lines for fracture rel perms

0

0.2

0.4

0.6

0.8

1

0 0.2 0.4 0.6 0.8 1

kr

Sg

Gas Oil Rel. Perms

Krg…


Diffusion coefficients

Diffusion coefficients decrease with increasing

molecular weight

Inj

Prod

N2

C1

C2

C3

C4

C30+

fracture coridor matrix


Depletion – homogenous reservoir


N2 injection - homogenous reservoir

Diffusion activated


N2 injection - fractured reservoir


N2 injection - fractured reservoir

diffusion activated


N2 concentration vs

time for the previous 3

cases after 340 days

of production

1. no fracture

2. fractures

3. fractures with diffusion

option activated

1 2 3


N2 concentration for above 3 cases


Components concentration into the matrix

Sampling

row of cells


Fracture spacing

1m fr spacing, no cells = 50, Km=1, Kfr= 50mD

2m fr spacing, no cells = 100, Km=1, Kfr=100mD

4m fr spacing, no cells = 200, Km=1, Kfr=200mD

matrix poro = 15%

matrix perm = 1 mD

fracture poro = 10%

fracture perm = 50 mD

N2 inj

Inj rate = 3 m³/d


Effect of porosity change for N2 injection

matrix perm = 1 mD

fracture poro = 10%

fracture perm = 50 mD

N2 inj

Inj rate = 3 m³/d

Fr spacing = 2 m

Normalised plot


CO2 vs N2 injection into a fractured reservoir


Fracture spacing vs. Diffusion length

L = sqrt (D * t)

Diffusion

distance

(L)

Time

Scale

Displa-

cement

Half space

Fracturing (Fs)

N2 c

on

c

N2

co

nc

N2 c

on

c

Time Time Time

I I I

P P P

L >> Fs

High fracture

density

Low fracture

density

L ~ Fs L << Fs


Conclusions

Gas injection into fractured reservoirs leads to early breakthrough of injected

gas

If a gas injection is considered, first a good reservoir characterization has to

be performed. Fracture spacing, effective permeability, fracture and matrix

porosity have to be determined.

Next EoS, diffusion coefficients, relative permeabilities have to be

determined.

Then, diffusion distance has to be calculated. If diffusion distance is small

compared with half fracture spacing then diffusion can be neglected. If the

diffusion distance is large compared with fracture spacing then the reservoir

might be treated as non-fractured. In the intermediate cases, diffusion has to

be considered.

The larger the porosity or lower injection rate, the more important is diffusion.

Injection of different gases change the composition of reservoir gas by

diffusion having a change in dew point pressure. (N2 increases dew point

pressure while CO2 decreases it)


Acknowledgments

OMV E&P for the permission to publish the paper

Move & More.

Thank you!

SPE EUROPEC 4-7 June 2012

Condensate Recovery from a Fractured Carbonate Field

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