2. 1 | P a g e
Reservoir Characteristics Ahmed Sha’ban Gaber
Content… Page
Abstract …………………………………………………..……………..…. 2
Introduction ………………………………………………..……………… 2
Porosity ……………………….............................................................. 2
I. Definition ……………..……………................................................. 2
II. Porosity Classification ……………………………………..…………. 2
III. Typical Reservoir Porosity Values …….......................................... 2
IV. Porosity Measurement from Well logs …………...…………………. 3
a) Density Log ……………………………………….......…...………… 3
b) Sonic Log (Acoustic Log) ……………......................................... 3
c) Neutron Log ……………………………….……………….………… 4
d) Combination Porosity Logs ……..……….………………………... 5
Measurement Challenges ……………………………………………….. 5
Case Study ……………………………………………………………...... 6
Conclusion ………………………………………………………………. 7
3. 2 | P a g e
Reservoir Characteristics Ahmed Sha’ban Gaber
Abstract
In this paper, I propose a full description for reservoir
porosity measurement methods that significantly help to
measure the main reservoir characteristics needed to
identify and quantify hydro-carbon resources in the
subsurface and evaluate rock properties.
To porosity, I propose the main three logs used to
identify the reservoir porosity attached with a case study.
Each method is proposed with its environment challenges.
Introduction
Generally, reservoir characterization can be defined as it’s
determining the physical properties of a reservoir
(porosity, permeability, fluid saturation, etc.) and changes
in their distribution throughout the reservoir.
The field of reservoir characterization routinely involves
disciplines of geology, geophysics, petro-physics, petro-
leum engineering, geochemistry, biostratigraphy, geo-
statistics, and computer science.
Reservoir characterization is quite comprehensive and
challenging. In fact, definitions of reservoir characteriza-
tion now vary according to the technologies available for
characterization.
The characterization of reservoirs has evolved, during the
past 15 or so years, from a simple engineering evaluation,
to multidisciplinary teams of geologists, geophysicists,
petro-physicists, and petroleum engineers working
together.
As exploration and production companies try to
understand more and more about their assets, it is evident
that no single discipline can provide a full description of
the reservoir characteristics. In order to create the most
comprehensive reservoir understanding, an integrated
reservoir model has become increasingly important.
The integrated reservoir model compiles geological,
geophysical, petro-physical, and engineering data into one
environment, where they can be used to create the most
realistic geologic model available.
The measure of the void space is defined as the porosity
of the rock. A knowledge of this property is essential
before questions concerning types of fluids, amount of
fluids, rates of fluid flow, and fluid recovery estimates can
be answered.
Porosity
I. Definition
It is defined as the ratio of the pore volume to the bulk
volume of the porous medium. Porosity gives an
indication of the rock’s ability to store fluids.
II. Porosity Classification
Porosity may be classified as total or effective porosity.
Total porosity accounts for all the pores in the rock
(interconnected and isolated pores) whereas effective
porosity only accounts for the interconnected pores.
Therefore, effective porosity will be less than or equal
to total porosity depending on the amount of isolated
pores in the rock. From a reservoir engineering
standpoint, it is the effective porosity that matters, not
the total porosity.
Porosity may also be classified as primary or secondary.
Primary porosity is that which was formed at the time of
deposition of the sediments whereas secondary porosity
was developed after deposition and burial of the
formation.
III.Typical Reservoir Porosity Values
Sandstones have porosities that typically range from 8%
to 38%, with an average of 18%. About 95% of sandstone
porosity is effective porosity. Sandstone porosity is
usually mostly inter-granular porosity “primary”.
Carbonates have porosities that typically range from 3%
to 15%, with an average of about 8%. About 90% of
carbonate porosity is effective porosity. Carbonate
porosities are much more difficult to be characterized.
4. 3 | P a g e
Reservoir Characteristics Ahmed Sha’ban Gaber
IV. Measurement from Well log
Conventional logging techniques for measuring porosity
are the Density, Neutron and Sonic logs. All of these logs
provide an indication of total porosity.
a) Density Log
The Density log measures the electron density of the
formation by using a pad mounted chemical source of
gamma radiation and two gamma detectors. The medium-
energy gamma rays emitted into the formation collide
with electrons in the formation. At each collision, a gamma
ray loses some, but not all, of its energy to the electron
and then continues with reduced energy. This type of
interaction is known as Compton scattering. The scattered
gamma rays reaching the detector, at a fixed distance
from the source, are counted as an indication of the
formation density. Fig. 1
The number of Compton scattering collisions is related
directly to the number of electrons in the formation.
Therefore, the response of the density tool is
determined essentially by the electron density (the
number of electrons per cubic centimeter) of the
formation. Electron density is related to the true bulk
density in gm/cc, which in turn depends on the density of
the rock matrix, the formation porosity and the density of
the pore fluids.
The depth of investigation of the density log is relatively
shallow. Therefore, in most permeable formations, the
pore fluid is the drilling mud filtrate, along with any
residual hydrocarbons. Usually, the fluid density
is assumed to be 1.0 gm/cc. When residual hydrocarbon
saturations are fairly high, this can cause the calculated
porosity values to be greater than the true porosity, and
should be corrected for this effect. Fig.
2 shows a typical presentation of a
density log where formation density
and the porosity derived from it are
presented.
b)Sonic Log
The Sonic log measures the time Δt
required for compressional sound
wave to traverse one foot of
formation. Known as the interval
transit time, Δt is the reciprocal of
the velocity of the compressional
sound wave. To avoid fractions, the
interval transit time is scaled by 10^6
and reported in micro-seconds per ft
(μsec/ft). Thus,
where Δt is the interval transit time in μsec/ft and v is
the compressional wave velocity in ft/s. The interval
transit time in a formation depends upon lithology and
porosity. generally, the denser or more consolidated a
formation, the lower the interval transit time.
An increase in travel time indicates an increase in
porosity. Based on laboratory measurements, Wyllie
(1956) concluded that in clean and consolidated
formations with uniformly distributed small pores, there
is a linear relationship between porosity and interval
transit time as follows:
where Δt is the interval transit time measured by the
log, Δtf is the interval transit time in the pore fluid, Δtm
is the interval transit time in the rock matrix, and φ is
the formation porosity. This equation can be solved for
porosity as
Fig 1
Fig 2
5. 4 | P a g e
Reservoir Characteristics Ahmed Sha’ban Gaber
To calculate porosity from
the last equation, the
transit times for the rock
matrix and the pore fluid
must be known or assumed.
Table 1 gives the sonic
speeds and interval transit
times for common rock
matrices.
The depth of investigation
of the sonic log is relatively
shallow. Thus, the pore fluid
is usually assumed to be
mud filtrate with an interval
transit time of 189 μsec/ft,
corresponding to a fluid
velocity of 5300 ft/sec.
Fig. 3 shows a typical pre-
sentation of the sonic log.
c) Neutron Log
The Neutron log measures induced formation radiation
produced by bombarding the formation with fast moving
neutrons.
The tool responds primarily to the hydrogen present in
the formation. Thus, in clean formations, whose pores
are filled with water or oil, the neutron log reflects the
amount of liquid-filled porosity. Neutrons are electrically
neutral particles with a mass almost identical to the mass
of a hydrogen atom. High-energy (fast) neutrons are
continuously emitted from a radioactive source mounted
in the logging tool. These neutrons collide with the nuclei
of the formation materials. With each collision, a neutron
loses some of its energy.
The amount of energy lost per collision depends on the
relative mass of the nucleus with which the neutron
collides. The greatest energy loss occurs when the
neutron collides with a nucleus of practically equal
mass, i.e., hydrogen. Collisions with heavy nuclei do not
slow the neutrons down very much. Thus, the slowing
down of neutrons depends largely on the amount of
hydrogen in the formation.
Within a few microseconds, the neutrons have been
slowed down by successive collisions to thermal
velocities, corresponding to energies of around 0.025
electron volt (eV). They then diffuse randomly, without
losing any more energy, until they are captured by the
nuclei of atoms as chlorine, hydrogen, silicon and
others. The capturing nucleus becomes intensely
excited and emits a high-energy gamma ray of capture.
Depending on the type of Neutron logging tool, either
these capture gamma rays or the slow neutrons
themselves are counted by a detector in the tool.Fig 3
Table 1
Fig 4
6. 5 | P a g e
Reservoir Characteristics Ahmed Sha’ban Gaber
When the hydrogen concentration of the material
surrounding the neutron source is large, most of the
neutrons are slowed down and captured within a short
distance from the source. However, if the hydrogen
concentration is small, the neutrons travel farther from
the source before they are captured. Accordingly, the
counting rate at the detector increases for decreased
hydrogen concentration and decreases for increased
hydrogen concentration. The porosity based on the
neutron count is given by
where N is the slow neutrons counted, a and b are
empirical constants determined by appropriate calibra-
tion and φ is the porosity.
Since there is very little difference in the concentration
of hydrogen in oil or water, neutron logs measure the
liquid filled porosity. A high neutron counting rate
indicates low porosity and a low neutron counting rate
indicates high porosity. Fig. 4 shows a typical presentation
of the Neutron log. The neutron count is presented in API
(American Petroleum Institute) units. The porosity is in
neutron porosity units based on calibration with
limestone or sandstone. Two additional factors should be
considered in the interpretation of neutron logs. First,
shales and zones containing a significant amount of shale,
will indicate a high neutron porosity due to the bound
water associated with the shale. Secondly, because of the
lower concentration of hydrogen in gas than in oil or
water, a zone containing gas will indicate a neutron
porosity that is lower than it should be. These features are
really an advantage since a comparison of the neutron
porosity to cores and other porosity logs provides a
convenient method for determining shale volumes and
for distinguishing gas zones from oil or water zones. In a
gas zone, the fluid density is very much lower than the 1.0
gm/cc. As a result, the density porosity in a gas zone is
higher than it should be. Thus, in a gas zone, the neutron
porosity is too low and the density porosity is too high.
When the two porosity logs are superimposed, the two
curves will agree in shales and in liquid zones and will
cross over in gas zones.
This cross over of the two logs can be used to identify gas
bearing zones as shown in Fig. 5.
Fig 5
A comparison of neutron and density porosities.
Shaded areas indicate gas zones.
7. 6 | P a g e
Reservoir Characteristics Ahmed Sha’ban Gaber
d) Combination Porosity Logs
In many areas, it is common practice to record more than
one porosity log on a well. Common combinations are
Density-Neutron, Density-Sonic and Sonic-Neutron.
Sometimes, all three logs are run in the same well.
Combination porosity logs are used to (1) differentiate oil
or water from gas zones, (2) calculate quantitative values
for lithology, and (3) determine volume of shale in the
rock matrix.
Measurement Challenges
Sometimes, well logs have to be performed under hard
environment conditions and this must be taken in
consideration to avoid false values for what you are
trying to measure.
To density log, the presence of a mudcake can seriously
affect formation density measurement so the tool is
constructed with the source and detectors mounted on a
skid which, when pushed against the borehole wall,
ploughs through the mudcake. The remaining mudcake
influence is corrected by comparing count rates at a short
and long spacing detector. The correction applied to the
density measurement is also displayed as a separate
curve on the log. If this correction exceeds 0.05 g/cc, it is
considered less reliable and confidence, attached to the
log reading at that point, is reduced. This situation
commonly occurs when the hole is rugose or washed out
so that low density mud is present between the tool and
the formation. High density barites laden mudcake can
also significantly affect the density reading in the
opposite sense. The density correction curve therefore
serves as a quality check on the density measurement.
To sonic log, in very large (or washed out) holes the first
compressional arrival may be through the mud,
effectively short circuiting the formation arrival. In such
cases the log will record a constant value, the mud transit
time. In some cases, the problem can be resolved by using
a longer tool. In gas bearing formations acoustic travel
times increase and the first arrival amplitude can fall
below detection level. If the tool triggers on a later arrival
the transit time recorded is much longer, a phenomena
described as cycle skipping.
To neutron log, although neutron tool is designed to be
run against the formation like the density tool, the source
and detectors are not mounted in a skid. As a result, the
tool is rather more vulnerable to high frequency borehole
rugosity and will record high apparent porosities when
contact with the formation is poor and a mud filled space
is created between tool and borehole wall.
Case study
This section describes a reservoir description technique
for computing porosity using both core and log data from
the Kuparuk formation, North Slope Alaska. Core porosity
is used as a calibration tool to define clay parameters
“properties” of the gamma ray and porosity logs.
A cored well is used to illustrate this reservoir description
technique. Fig. 6 shows the relative location of the well in
the Kuparuk field.
Fig 6
8. 7 | P a g e
Reservoir Characteristics Ahmed Sha’ban Gaber
All gamma ray logs were normalized first before
obtaining calibrated clay parameters. So what is gamma
ray normalization or generally log normalization?
Log normalization is based on the concept that
maximum and minimum log readings in a zone in an area
should have the same log reading. The assumption
includes the fact that there no major geological reasons
for the values to vary across space. Reasons for log
normalization are numerous: poor tool calibration, mis-
labeled scales, unconventional units of measur-ement,
mud weight, borehole size, temperature, rock alteration,
and many more. Log normalization is the process of re-
scaling a log so that it matches its neighbors, based on
some logical reasoning. Re-scaling can involve an equal
linear shift of the two scale end-points, or a "stretch" or
"squeeze" of the data values between the two scale end
points or between two arbitrary log values.
After matching log porosity to core porosity in well, this
result is obtained as showed in the Fig.
Conclusion
In this paper, I presented some methods to measure
one of the most critical reservoir parameters, porosity.
However, the main challenge may not be how to get the
petro-physical property value from each method apart.
The main challenge is to use these methods integrated
together to get the accurate value that is closest to the
actual one.
Some logs may get you a certain value for a certain
property, density for example. This density value may
not absolutely identify what is underground specifically
as this density value may be located into an overlapped
range between two different types of formation. Thus,
we need another log method to identify clearly what is
located underground.
We have to take in mind that reservoir porosity values
are usually attained by coring methods that provide us
with an accurate result for the reservoir parameter not
just porosity. I will cover this coring procedure to
measure reservoir porosity in my next paper.
References
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PRINCIPLES AND PRACTICE, 1986
5. Luca Cosentino-Integrated Reservoir Studies
(Collection Reperes)-Editions Technip (2001)
6. Prof. Dr. Jurgen Schon, Basic-well-logging-and-
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