Geoscience Reference

In-Depth Information

(Cosentino
2001
), in which it is the ratio of

permeability, k, to viscosity,

net-to-gross method and a more general total prop-

erty modelling approach.

, that defines the

flow potential (the mobility ratio). For example,

the following cut-offs are equivalent:

ʼ

3.5.2 The Net-to-Gross Method

gas

oil

0

:

01
md

1
md

5
cp

ð

3

:

30

Þ

0

:

05
cp

From a geological perspective, the ideal case of a

reservoir containing clean (high porosity) sand-

stone set in a background of homogeneous

mudstones or shale does not occur in reality.

However, for certain cases the pure sand/shale

assumption is an acceptable approximation and

gives us a useful working model. When using

this N/G ratio approach it is important that we

define net sand on a geological basis making

clear and explicit simplifications. For example,

the following statements capture some of the

assumptions typically made:

We assume the fluvial channel facies is 100 %

sand (but the facies can contain significant

thin shale layers).

If the net-sand volume fraction in the model

grid is within 2 % of the continuous-log net-

sand volume fraction, then this is considered

as an acceptable error and ignored.

The estuarine bar facies is given a constant sand

volume fraction of 60 % in the model, but in

reality it varies between about 40 and 70 %.

Tightly-cemented sandstones are included

with the mudstone volume fraction and are

collectively and loosely referred to as “shale”.

Having made the geological assumptions

clear and explicit, it is important to then proceed

to an open discussion (between geologists,

petrophysicists, reservoir engineers and the eco-

nomic decision makers) in order to agree the

definition of net reservoir cut-off criteria. For

example, a typical decision might be:

We assume that net reservoir is defined in the

well-log data by: IF (Gamma

Worthington and Cosentino (
2005
) argue that

the most consistent way to handle cut-offs is to

cross plot porosity versus the k/

ratio to decide

on an appropriate and consistent set of cut off

criteria (Fig.
3.29
). The cut-off criterion (k/

ʼ

)
c
is

arbitrary but based on a reservoir engineering

decision concerning the flow rate that is eco-

nomic for the chosen production well concept

and the design life of the oil field. It may be the

case that later on in the field life the appropriate

(k/

ʼ

)
c
criterion is revised (to lower values) on

account of advances in oil recovery technology

and introduction of enhanced oil

ʼ

recovery

methods.

Because of these difficulties with terminology

and the underlying arbitrary nature of the cut-off

assumptions, the key guideline for good reservoir

model design is to:

Use net-to-gross and cut-off criteria in a consistent

way between geological reservoir descriptions,

petrophysical interpretations and reservoir flow

simulations.

In the following discussion, we consider two end

members of a range of possible approaches - the

Log(k/
m)

<

40API AND

(k/
m)
c

(Poro

>

0.05 OR Perm

>

0.1 mD) THEN

N/G
reservoir
)

After averaging, reservoir modelling and

upscaling, the simulation model N/G
reservoir

may differ from average well-data N/G
reservoir

by a few percent and will be adjusted to

ensure a match.

Hidden within the discussion above is the

problem of upscaling. That is, the N/G estimate

(Interval

¼

f

f
c

Fig. 3.29
Cross plot of porosity, ø, versus the k/

ʼ

ratio to

define a consistent set of cut-off criteria,

ϕ

c
and k
c

(Redrawn from Ringrose
2008
,

2008, Society of Petro-

leum Engineers Inc., reproduced with permission of SPE.

Further reproduction prohibited without permission)

#