SANDSTONE HETEROGENEITY
Heterogeneity (essentially nonuniformity) in sandstone reservoirs
is controlled by the following factors; (modified from Weber, 1986;
Schenk, 1988, 1992):
The geometry of sandstone bodies (lens-shaped, tabular, etc.),
Faulting and fracturing of the reservoir intervals; this influences
oil trapping and retention, as well as influencing fluid flow at field
and well scales,
Mudstone and other low-permeability baffles that direct flow of
fluids through the rocks,
Vertical and lateral distribution of facies, and interbedding
characteristics of the sandstone, mudstone, and other rock
types,
 Sedimentary structures (cross-bedding, burrowing...),
Laminae, (such as thin mudstone layers and calcite-cemented
intervals), and
Influence of diagenetic history on porosity/permeability
preservation, destruction, and enhancement.
Reservoir quality sandstone is a function of
sedimentologic and petrologic heterogeneity.
Increase in porosity and permeability is tied to increase in
depositional energy. This results from:
 Better grain sorting and associated decrease in amounts of
fine-grained sediment within pore throats and spaces,
 Greater vertical and lateral communication between
porous/permeable beds,
 Fewer and thinner mudstone layers and other permeability
barriers, and
 Decrease in low-permeability calcite-cemented (mainly finegrained) sandstone.
 Diagenetic/petrologic/depositional processes strongly
influence porosity and permeability destruction, preservation,
and creation; these are of course critical to migration of oil
into the field and its subsequent recovery.
Geometry and interbedding behavior of reservoir
and non-reservoir facies controls fluid flow at well
and bedform scales. Permeability boundaries to
fluid flow occur at microscopic through
megascopic scales.
Connectivity and vertical- and lateral-continuity of
oil-productive facies influences how much
petroleum can be produced both from individual
wells and from the field.
FLOW-UNIT RATING, PERMEABILITY (mD), POROSITY (PERCENT), AND
PETROLOGIC CHARACTERISTICS
E. Trough- and planar cross-bedded fine- to medium-grained
sandstone that represents the highest depositional energy and
greatest reservoir potential.
>15 mD,
10 to 22 percent
G. While tabular, wavy-bedded, and ripple-laminated sandstones
(flow unit G) near the tops of reservoir sand ridges may exhibit
similarly high porosity and permeability values, fluid flow and
other factors are different.
G,
12 to 40 mD, 8 to 18 percent,
F. Ripple-laminated, tabular, and wavy-bedded fine-grained
sandstones that are commonly interbedded with thin trough-crossbedded fine- to medium-grained sandstones Interbedding of flow
units E and G, and to a lesser extent F, results from highly variable
depositional energy conditions across the field.
F,
5 to 20 mD,
8 to 18 percent,
P5. Ripple-laminated, tabular, and wavy-bedded very-fine and finegrained sandstones. Reservoir favorability is further decreased by
the interbedded, thin, calcite-cemented sandstones, numerous
mudstone drapes, and biologic reworking.
P5,
.01 to 2 mD, 1 to 13 percent,
P6. Burrowed and bioturbated mudstone and very-fine-grained
sandstones that bound reservoir sandstones. This flow unit contains very
low porosity and permeability and forms updip and overlying reservoir
seals.
P6,
.01 to 15 mD, 1 to 16 percent,
P7. Thinly bedded mudstone and calcite-cemented, fine-grained
sandstones comprise P6. These form permeability barriers that are
laterally continuous and separate upper and lower sand ridges, primarily
ridges 1 and 2. P6 thickness is as much as 10 ft (3.5 m), but is generally
less than 5 ft (1.5 m).
P7,
.01 to 19 mD, 1 to 16 percent,
This low-porosity and low-permeability unit is composed of thin
mudstones and calcite- and quartz-cemented sandstones. Thickness
ranges from inches to less than 5 ft (1.5 m). P7 forms numerous
discontinuous permeability baffles.
Megascopic and Macroscopic (Field and Well) Scales
sandstone heterogeneity -------results mainly from the following
factors.
The lens shape of the reservoir interval (figure 19), which has
different fluid flow and petroleum production characteristics
than, for example, a tabular reservoir. -----" sandstone
production is concentrated along the axes of the field, and from
the thickest intervals of stacked reservoir sandstones.
 The lensate form of the reservoir is distinct from the lens and
tabular forms of individual reservoir sandstones that comprise
the reservoir intervals. Each of these has its
porosity/permeability/fluid flow-characteristics.
The reservoir sandstone intervals (green, yellow, orange,
and red) are essentially lens shaped. These are composed of
many thin, laterally discontinuous, interbedded sandstone
and mudstone beds. The sandstone intervals pinch out along
the eastern (seaward) margin and grade into non-reservoir
(blue) and lower quality reservoir facies along the western
field boundary. Datum is the basal disconformity (erosional
surface).
This 3-D distribution of porosity slice (figure 19) reveals;
The lower (1) sand ridge exhibits the greatest porosity close to the
seaward (eastern) margin of the field with porosity decreasing
westward,
The upper (2) sand ridge is composed of two separate sandstone
units, close to the eastern and the western field margins. These
sandstone bodies separate further and pinch out entirely a few slices
to the north, and
Lowest porosity intervals are basal and landward (westward) facies
of most sandstone bodies. These low-porosity intervals
compartmentalize the reservoir in this view and across much of the
field. What this means is, in order to produce oil from both
sandstones, both intervals must be perforated.
Macroscopic and Microscopic (Well and
Sample) Scales
Processes of porosity and permeability destruction
from pervasive early cementation by calcite and
(or) quartz, precipitation of clays, or by
compaction are shown in figure 22 (cmts4sm.gif).
----sandstone primary and secondary porosity, and microporosity are shown on the
following thin-section photomicrograph and SEM images. Pore spaces in all
photomicrographs are filled with blue epoxy. Ferroan carbonates are stained blue
(ferroan dolomite has dark blue crystals). Unless otherwise indicated, photomicrographs
are with transmitted light. Scale bars on most images are 0.1 mm. Porosity in the thin
section is partially decreased by early diagenetic cementation of quartz grains. The
original rounded quartz grains are outlined by green-colored chlorite crystals. Early
diagenetic cementation preserves porosity and permeability in the Sussex "B" sandstone
by supporting the grain framework and decreasing porosity loss through compaction.
Figure 23. A. Thin-section photomicrograph from 8,012 ft (2,442 m)
depth, No. 1 Empire Federal "C" well (fdissols.gif). Dissolution of the
large feldspar (F) grain, located near the center of the image, results
in secondary porosity. The crystal structure and outline of the feldspar
grain is still apparent. Primary (depositional) porosity borders this and
other grains. Quartz grains are labeled Q. Microporosity results
primarily from breakdown of feldspar into kaolinite (K on large-scale
view) and other clay minerals; this causes a mottled appearance of
the blue epoxy that fills pore spaces. MS is a mudstone clast. Scale
bar is 0.1 mm. The full-scale 1.5 MB thin-section photomicrograph of
feldspar dissolution B. Scanning electron microscope (SEM) image of
kaolinite shows partings between booklets and minor amounts of
"wispy" illite-smectite clay from the No. 1-23 House Creek Federal well
(semkaosm.gif). Scale bar, below the illite-smectite label, is 4
micrometers. The 656 KB SEM full-scale image of kaolinite booklets