Geoscience Reference
In-Depth Information
(A)
(B)
100
100
10
10
Facies S
PS
n
= 544
Porosity:
p
= 13%,
s
p
= 3%
Permeability:
k
h
= 1.51 mD,
s
k
= 3.50 mD
Facies S
RL
n
= 559
Porosity:
p
= 13%,
s
p
= 3%
Permeability:
k
h
= 0.92 mD,
s
k
= 1.99 mD
1
1
0.1
0.1
0.01
0.01
0
10
20
Porosity (%)
30
40
50
0
10
20
Porosity (%)
30
40
50
(C)
(D)
100
100
Facies S
HS
n
= 19
Porosity:
p
= 12%,
s
p
= 3%
Permeability:
k
h
= 1.4 mD,
s
k
= 4.36 mD
Facies S
CS
n
= 341
Porosity:
p
= 13%,
s
p
= 4%
Permeability:
k
h
= 2.03 mD,
s
k
= 6.24 mD
10
10
Facies S
SS
n
= 19
Porosity:
p
= 13%,
s
p
= 3%
Permeability:
k
h
= 0.68 mD,
s
k
= 0.81 mD
Facies S
M
n
= 1
Porosity:
p
= 12%
Permeability:
k
h
= 0.32 mD
1
1
0.1
0.1
Facies S
HS
Facies S
SS
Facies S
M
0.01
0.01
0
10
20
Porosity (%)
30
40
50
0
10
20
Porosity (%)
30
40
50
Fig. 13.
Porosity and horizontal permeability of the Garn Formation sandstones of: (A) facies S
HS
; (B) facies S
RL
; (C) facies S
HS
,
S
SS
and S
MA
; and (D) facies S
CS
. Core-plug data from wells 64
06
/2-5, 6406-2-5AT2, 6406-2-R-4H, 6406-2-3-T3 and
6
406-11-
N-H3 in the Kristin Field. Letter symbols:
n
- number of data;
p
- mean porosity;
s
p
- porosity standard deviation;
k
h
- mean
horizontal permeability; and
s
k
- permeability standard deviation.
facies define, in turn, three main types of 'mega-
blocks' (facies associations). The megablocks of
type A consist chiefly of facies S
CS
(dune cross-
strata sets), whereas the megablocks of type B and
C are dominated by facies S
PS
(planar-parallel strata
sets). The other facies are volumetrically subordi-
nate (facies S
RL
) or minor components (facies S
HS
and S
SS
), although some of the units of ripple cross-
laminated sandstone contain mudstone drapes or
flasers and may be extensive; possibly from tens to
hundreds of metres in lateral extent. Facies S
M
is of
local occurrence and volumetrically negligible and
hence is disregarded in the model.
An upscaled model for reservoir flow simulation
usually consists of a few hundred thousand grid
cells (Fanchi, 2006; Keogh
et al
., 2007) and hence
the reservoir heterogeneity model here is devel-
oped at the 'megablock' scale of facies associations
(Fig. 12) in order to meet this practical limitation.
Each megablock type is characterised in terms of
the relative percentage (Table 2) and internal het-
erogeneity (Fig. 13) of its component facies. The
net effect of facies heterogeneities and their spatial
configuration should be assessed further for each
type of megablock through flow simulation, as
there may be an interdependence of the effects of
different anisotropies (Weber, 1986).
Facies heterogeneity
The sandstone facies (Table 1) differ markedly in
their internal characteristics, which bears directly
on their permeability variation and anisotropy.
This issue is reviewed below on the basis of
detailed laboratory studies of analogous shallow-
marine sandstone facies (Rosvoll, 1989; Corbett,
Search WWH ::
Custom Search