Dolomite Perspectives on a Perplexing Mineral

Expanding the Scope
Despite efforts to determine environmental set-
tings, modes of origin and conditions that impact 
dolomite quality, exploration and production of 
these formations are fraught with uncertainty. 
Refinements in distinctly different approaches to 
formation evaluation technology are helping E&P 
companies to reduce some of these unknowns.
As previously discussed, petrophysical evalua-
tions of dolomite reservoirs require detailed min-
eralogy and matrix properties to correct density 
and neutron porosity calculations. These inputs 
depend, in part, on the ability to distinguish cal-
cite from dolomite. The first step in obtaining 
these inputs rests with the selection of logging 
tools used to investigate the reservoir; standard 
capture spectroscopy tools are not sensitive to pro-
portions of Mg and Ca in a formation. Although 
photoelectric factor measurements can be used 
for this purpose, the shallowness of the PEF mea-
surement makes it sensitive to borehole condi-
tions, barite muds, and invasion by drilling fluids.
However, ECS measurements obtained by the 
EcoScope multifunction LWD service are sensi-
tive to the proportion of Mg in a formation. This 
capability is key to determining calcite and dolo-
mite content in a carbonate formation. This LWD 
collar obtains a broad array of measurements. 
Designed around a pulsed neutron generator, the 
EcoScope tool measures resistivity, neutron 
porosity, azimuthal gamma ray, density, neutron 
gamma density and formation sigma, in addition 
to elemental capture spectroscopy.
Another approach, based on wellbore imag-
ing and high-resolution computed tomography 
(CT) scans, is helping E&P companies to better 
predict fractures and high-permeability trends 
in highly heterogeneous formations. With the 
aid of sophisticated conditional simulation algo-
rithms, this approach analyzes wellbore images 
to determine where pores and conductive 
patches lie in relation to rock matrix.
47
Gaps in 
the wellbore image—an inherent feature of pad 
coverage provided by imaging tools—are filled 
using a multipoint statistical (MPS) conditional 
simulation to create a fullbore image of the 
wellbore 
(below right)
. The multipoint condi-
tional simulation incorporates micron-scale CT 
scans of actual core to create digital rock sam-
ples that train the MPS program.
48
This pattern-
based approach honors all data obtained by the 
pad device; it also extends patterns from within 
the pad measurement into the gaps, thereby 
creating a 3D pseudocore.
49
The new fullbore 
image can then be divided into different petro-
physical facies that are used for estimating 
porosity and permeability.
>
Effect of dolomitization on reservoir quality. Core analysis data from a 
field in Kuwait were used to plot dolomite volume, core porosity and core 
permeability. These data showed strong correlations between increasing 
dolomite volumes and increases in porosity and permeability. The scatter 
within this 3D crossplot reflects the heterogeneous nature of the pore 
system within the dolomitic rock.
MattV_ORAUT09_Fig_15
Co
re po
rosity
, %
Core 
permeability
, mD
Volume
of dolomit
e
Core porosity
, %
Core permeability
, mD
Volume of dolomit
e
0.30
0
0.270
0.24
0
0.210
0.18
0
0.150
0.12
0
0.09
0
0.06
0
0.03
0
0.00
0
1,00
0
10
0
10
1
0.
1
0.0
1
0.0
1
0.
1
1
10
100
1,000
0.300
0
.0
0
.1
0
.2
0.3
0.
4
0.
5
0.
6
0.
7
0.
8
0.9
1.0
0.27
0
0.240
0.210
0.180
0.150
0.12
0
0.090
0.06
0
0.03
0
0.000
0.0
0.1
0.2
0.3
0.4
0.5
0.6
0.
7
0.
8
0.
9
1.
0
>
Filling the gaps. Images through a layered, fractured interval were 
obtained in a single pass (
left) of a pad-type borehole imaging tool. 
Data from one pad have been removed to emphasize the area 
normally measured by each pad (green dotted line, 
left). Gaps 
between pads have been filled in the fullbore image using MPS 
pattern-based geostatistical modeling (
center). Dark conductive 
patches are outlined by green contours (
right). These contours help 
identify complex 3D fluid-flow pathways in heterogeneous carbonates.
MattV_ORAUT09_Fig_16
X00
Depth,
ft
X02
X04
X06
X08
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11/5/09 3:54 PM

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Autumn 2009
45
For example, it can be used to evaluate 
vugs—large, irregular pores visible to the naked 
eye—commonly seen in carbonate rocks. Zones 
of enhanced porosity and permeability exist in 
the vicinity of vugs, as confirmed by thin sections, 
SEM images and minipermeability measure-
ments. Swarms of small vugs are commonly seen 
in the vicinity of large vugs. On borehole-imaging 
logs, small vugs that fall below the resolution of 
imaging pads appear as dark high-conductivity 
regions, rather than as discrete pores.
Fullbore images allow closed contours to be 
drawn around resistive or nonresistive regions in 
the image. Such regions provide important mea-
sures of reservoir heterogeneity and are gener-
ally much larger than the core plugs or digital 
models generated from CT scans of rocks. Thus, 
borehole images are critical for identifying flow 
model heterogeneities ranging from centimeters 
to meters in scale. By defining regions of high or 
low resistivity, the imaging technique can help 
determine whether the vugs form a connected 
and therefore permeable network.
Capillary pressure and relative-permeability 
curves can be assigned to different petrophysical 
facies, based on laboratory special core analysis 
and mercury-injection capillary pressure tests run 
on actual reservoir rock core samples. Numerical 
simulations using these results provide the key to 
quantifying the impact of carbonate rock hetero-
geneity on fluid flow during primary production, 
waterflooding or gasflooding. Such simulations are 
carried out on the previously constructed numeri-
cal pseudocores to estimate important effective 
parameters such as water cut, oil recovery factor 
and recovery efficiency on a pseudocore or well 
logging scale 
(left)
. 
CT scans and microscale observations can 
help geoscientists predict attribute characteris-
tics on a macroscale. The size, shape and height 
of the numerical pseudocore are limited only by 
the amount of computer memory that is avail-
able. This allows researchers to quickly perform 
numerical experiments on large samples that 
could not be duplicated in a laboratory, given any 
amount of time or money.
Although formation evaluation techniques 
can readily distinguish sandstones from carbon-
ates, the capability to identify and quantify dolo-
mite in reservoir rocks poses a distinct challenge. 
While laboratory-based measurements may not 
address ongoing controversies regarding dolo-
mite formation, they are able to accurately char-
acterize the wellbore to provide valuable insights 
that will help E&P companies develop these 
notoriously heterogeneous reservoirs.
—MV
>
Flow simulation. These results have been produced after 0.72 pore-volumes 
of water were injected through a numerical pseudocore in an oil-wet 
dolomite. Bulk remaining oil saturation is 58%; water cut is 77%. Water is 
injected through the pseudocore from outside to inside. Colors represent oil 
saturations. Heterogeneity is obvious in the nonuniform breakthrough of water 
(B) shown in some parts of the flow pseudocore, whereas in other areas the 
flood front (F) has barely moved into the rock.
MattV_ORAUT09_Fig_17
Reduce image 75% after placeing
Mike- place 20-40-60-80-100% along the top.