In search of saturation
The importance of saturation
measurements is reflected by
the time and effort which has
been devoted to gathering them.
The most fundamental reservoir
parameters - oil, gas and water
content - are critical factors in
determining how each oilfield
should be developed.
In this article Jean-Louis Chardac,
Mario Petricola, Scott Jacobsen and
Bob Dennis outline the importance
of saturation measurements and
reveal how the latest techniques are
he lp in g re s e rv o ir e n g in e e rs a n d
geoscientists to maximize production
and improve total recovery.
S
aturation, the proportion of oil, gas,
water and other fluids in a rock, is a
crucial factor in formation evaluation. Without saturation values, fluid distribution can not be evaluated and no
informed decision can be made on the
development of an oil or gas reservoir.
When geologists and reservoir engineers talk about oil ‘pools’, it sounds as
though there are large ‘bubbles’ of oil in
the rock sequence. In reality, the oil and
gas in hydrocarbon reservoirs is distributed through the pore space between
the sand or carbonate grains which comprise the reservoir layer (figure 2.1). In
the best reservoirs this porosity amounts
to between 25% and 35% of total volume.
This fraction of the reservoir is filled with
fluids in variable proportions and, as
reservoir conditions change through production, the volumes which each occupies will alter accordingly. For example,
as oil is produced, internal fluid pressure
drops and, in many reservoirs, this
releases gas from solution.
Saturation changes are critical to fluid
flow and must be carefully monitored to
optimize reservoir management, and
delay gas or water coning.
A great deal of effort has gone into the
collection and improvement of saturation measurements. The wide range of
equations and models developed over
the years underlines the importance of
these measurements, and the complexity
of interactions between drilling mud,
rock, water and hydrocarbons around a
borehole.
Native metals and graphite conduct
electricity, but the vast majority of rockforming minerals are insulators. Electrical
current passes through a formation mainly
by the movement of ions in pore water.
Clearly, therefore, porosity is a critical factor determining resistivity - in short, high
porosity means low resistivity values.
Fluid saturation can be assessed indirectly by measuring the resistivity or electrical resistance of a rock layer. Some
fluids (e.g. gas and oil) have very high
resistivities while formation water and
shales have low resistivities. These variations can help to discriminate between fluids, but the borehole and surrounding
rock layers are complex environments
where mixtures of mud, mud filtrate,
hydrocarbon, formation water and rock of
varying resistivity are encountered.
Attempts to understand and model
this situation would be difficult enough if
the mixture stayed in one place, unfortunately it does not. Fluid properties
around every borehole change with time.
(a)
Invasion plans
One of the major problems with saturation measurements is invasion - the
movement of drilling mud and mud filtrate into the formation (figure 2.2).
During drilling, mud is circulated from
the surface. Initially the formation is
invaded by a process referred to as
‘spurt’ invasion. This occurs as soon as
the drill bit exposes fresh rock surfaces,
with whole mud flowing directly into the
formation, replacing the water which
was present in the pore space.
However, within a few seconds, the
second stage of invasion begins. The
drilling mud forms a deposit (mud-cake)
on the side of the borehole and mud filtrate (a liquid filtered through the mudcake layer) oozes into the formation. The
depth and extent of invasion is controlled
by the physical properties of the mud,
the original formation fluid, and factors
such as porosity and permeability.
The mud filtrate invasion can be
modelled by resistivity measurements
which follow the ‘invasion front’
through the rock. This front is often represented as a single straight line but, in
(b)
Fig. 2.1: Oil and gas fills the pore space
between sand or carbonate grains. The
interactions between fluids and grains are
critical to oil and gas production. Initial fluid
saturation and wettability must be determined
to predict reservoir behaviour. Rocks may be
either water-wet (a) or oil-wet (b).
(a)
(b)
(c)
(d)
Formation water
Quartz grains
Oil
Mud
Fig. 2.2: Fluid distribution within a reservoir changes through time (a to d). Saturation, the relative
proportions of fluids in the reservoir will change with time and to model this change correctly it is
essential to measure initial oil and water saturations as accurately as possible. This measurement is
complicated by mud invasion - during drilling the undisturbed formation is modified by a rapid influx
of drilling muds which push oil and formation water away from the well.
22
Middle East Well Evaluation Review
(a)
(b)
thin beds
(c)
(d)
Fresh mud filtrate
Original pore fluids
reality, the edges of the invasion zone
are usually ragged and its shape varies
in response to changing mud properties,
formation conditions and borehole
geometry, etc. (figure 2.3).
During the 1950s, when modern logging
techniques and tools were in their infancy,
the problem of invasion and water saturation first became apparent. At that time,
invasion was seen as an inconvenient
environmental effect. The invaded zone (a
rock volume around the borehole which
has been filled by mud filtrate) affected all
shallow-reading tools such as density, neutron porosity and micrologs. When waterbased oil was believed to have displaced
oil or gas, the logs from these tools had to
be interpreted very carefully. Even deep
resistivity logs, designed to record beyond
the invaded zone, could not be relied
upon in every well and corrections were
often necessary to evaluate the true formation resistivity (Rt).
In recent years technical advances
have helped to change attitudes to invasion. The flushing of oil and gas away
from the wellbore presents a perfect
opportunity to study fluid displacement
within the reservoir. A technique - the
‘moved oil plot’ - has been developed to
take advantage of this. This plot compares the volume of water in the invaded
and virgin zones. The difference
between these values is the volume of
hydrocarbon displaced.
Number 17, 1996.
Fig. 2.3: INVASION
PLANS: In vertical
wells the invasion zone
is more or less
symmetrical around
the borehole, with mud
filtrate reaching a
similar depth in similar
formations either side
of the hole (a). In
horizontal wells the
situation is more
complex. Thin beds
above and below the
borehole will be
invaded to a different
extent (b) while, in
other cases, invasion
may be controlled by
permeability variations
within a reservoir (c)
or by gravitational
effects (d).
THE LONG ROAD TO SATURATION
In 1942 Gus Archie revolutionized the
way the oil industry looks at fluid saturation in reservoirs. Before the publication of his ground-breaking paper
geoscientists found it difficult and
expensive to evaluate water saturation
and hydrocarbon reserves. The only
reliable method involved coring the formation using oil-base mud and measuring water saturation in the laboratory.
Logs measuring a formation’s electrical
resistivity were used to identify hydrocarbon-bearing formations but could
not evaluate them quantitatively.
Archie’s equation relating saturation
to porosity and resistivity changed that.
Rt
R
= φm wSn
w
Where Rt = rock resistivity, Rw = water
resistivity, φ = porosity, S w = water
saturation, m = porosity exponent and n =
saturation exponent.
Electrical conduction in rocks is
mainly through ion movement in pore
filling brine. In rocks with open pores
ions move easily, giving low resistivity
values. In sinuous and restricted pore
systems, and those which contain hydrocarbons, the flow of ions is reduced leading to higher resistivity values.
Archie’s equation quantifies these
phenomena for clean, consolidated
sands with intergranular porosity. While
this provides a good solution in clastic
rocks, many carbonates, with their different pore geometries and variable size
are more difficult to evaluate.
The carbonate reservoirs of the
Middle East are characterized by mixed
wettabilities - micropores are water-wet
and filled with irreducible water, while
macropores contain oil and may be oilwet. The microporosity systems often
dominate resistivity measurements
from logs, giving apparent saturation
calculations which are inconsistent with
production data, e.g. dry oil from a zone
with computed Sw greater than 70%.
To overcome this problem both
porosity systems (and their wettabilities) must be combined in a single equation for carbonate sequences. Recent
work in the Middle East has focused on
reliable measurements of the proportions of micro- and macro- pores using
Nuclear Magnetic Resonance techniques to evaluate pore size distribution
(see Microporosity Makes Sense) .
G.E. Archie (1942) The Electrical Resistivity Log as an
Aid in Determining Some Reservoir Characteristics.
Petroleum Transactions of the AIME 146, pp 54-62.
23
In reservoir zones where there is fresh
mud invasion a characteristic low resistivity zone, a ‘resistivity annulus’, develops. Moving out from the wellbore, logs
initially encounter a zone of high resistivity (containing oil and fresh mud filtrate),
then the annulus itself (a low resistivity
zone containing oil and saline formation
water displaced from the previous zone)
and finally, the high resistivities of the
original formation water/oil mixture.
A resistivity annulus probably exists
in every pay zone which is drilled with
fresh and oil-based mud - so it is vital
that the annulus is identified. If the
annulus is missed an oil or gas zone
may be overlooked. In wells where
saline mud is used the low resistivity
annulus does not develop.
Simplified models indicate the reasons
for a low resistivity anomaly (figure 2.4)
but do not represent the complex threedimensional distribution of oil, formation
water and fresh mud filtrate that mark the
saturation and salinity fronts. If detected,
the annulus is a clear indication that
hydrocarbons are present. However, if
the annulus effect develops beyond the
detection range of resistivity tools, Rt can
not be measured directly and a hydrocarbon zone may be overlooked.
This ‘high-low-high’ profile is very
important - when successfully recorded
it provides values for Rxo and Rt and,
more importantly, it indicates the presence of a ‘pay zone’. However, the low
resistivity annulus moves away from the
wellbore through time (as the mud filtrate continues to push low resistivity
formation water away from the well)
and, unfortunately, this movement presents yet another obstacle to resistivity
measurements.
How can we ensure that the annulus
is identified (to guarantee seeing a
hydrocarbon layer) and measure R t as
the undisturbed reservoir zone is
pushed further from the well?
An annulus located a long way into
the formation (70 in. to 80 in. from the
wellbore) would give artificially low
readings on other deep reading induction curves and, in some cases, may be
beyond the maximum depth of investigation (figure 2.5). Fortunately, the AIT*
(Array Induction Imager Tool) can
record data from a zone centered 90 in.
from the borehole - much further than
any other deep resistivity logging tool.
This depth of penetration increases the
probability of identifying an annulus and
of obtaining a good value for Rt.
A deep induction log taking measurements from the annulus would give values that were too low and an invasion
correction would probably be made to
account for these low values. However,
this would simply push the resistivity
value even lower.
24
Fig. 2.4: In reservoir
zones invaded by fresh
mud a characteristic
low resistivity zone,
or ‘resistivity
annulus’, develops.
When an annulus is
detected, we can be
sure that
hydrocarbons are
present. However, if
the annulus effect
develops beyond the
detection range of
resistivity tools, Rt
can not be measured
directly and a
hydrocarbon zone
may be overlooked.
Salinity
front
Saturation
front
Oil
Fresh
mud
filtrate
Water
Rxo
Rt
Resistivity
A ring of resistivity
Rannulus
Distance from wellbore
Medium
Deep
AIT 5
AIT 4
AIT 3
AIT 2
AIT 1
0
20
40
60
80
100
Depth of investigation (inches)
Fig. 2.5: DEEPER UNDERSTANDING: A resistivity annulus located 70 in. to 80 in.
from the wellbore could not be identified using deep induction. The deep induction
value recorded would be too low and if an invasion correction is made to account
for the low reading it will drive the resistivity value even lower.
Middle East Well Evaluation Review
RESOLUTION REVOLUTION
Thin beds (figure 2.6) present some
unique logging problems. Enhancements
and elaborate processing of logs have
gone some of the way to overcoming the
thin bed problem. Induction measurements are fundamental to formation
evaluation and, because of this, a great
deal of effort has been focused on
enhancing these logs. The methods
involved generally concentrate either on
signal processing or hardware improvements. One of the most important signal
modification methods is deconvolution.
The measurement which appears on
a log is a convolved or ‘smoothed’ average of formation property variations
(figure 2.7a). Deconvolution extracts
actual depth variation of a formation
property (such as resistivity) by using
information on tool physics to sharpen
this vertically averaged measurement
(figure 2.7b). The key to this process is
knowing how the tool responds to a
vanishingly thin bed - the tool's vertical
response function (VRF). Once this has
been identified, it can be reversed and
the log deconvolved to reveal unaveraged formation properties.
Deconvolution must be carried out
with care. The process usually increases
noise and inaccurate results can be generated by mathematical instabilities.
Egyptian vision
Many of the oil and gas reservoirs in
Egypt's Western Desert are complex.
The Bahariya Formation, one of the
most important hydrocarbon units in
the region, is a prime example. The formation is heterogeneous, mineralogically complex and very thinly layered
(figure 2.8).
50
(a)
1
Depth (ft)
100
Standard induction
ohm-m
1000
Fig. 2.6: THINK THIN: Thin beds can be a major problem in reservoir sequences. Alternations of
porous and tight rock types can alter well and reservoir performance dramatically - leading to
unpredictable early water production in some zones.
Agiba Petroleum Company overcame these problems by adopting the
latest advanced logging and interpretation techniques. High-resolution resistivity imaging, coupled with saturation
imaging, gave a clearer indication of
radial fluid distribution around the
borehole. The radial coverage gave
good permeability indications and contributed to a more realistic invasion
model. The AIT tool provides more
than resistivity measurements, it also
monitors borehole environment. This
has two benefits; the inputs required
by the environmental correction algorithms are measured rather than estimated and output logs are corrected in
real-time.
These real-time environmental corrections and R t calculations allow rapid
decisions based on high-quality data.
(b) Enhanced induction
ohm-m
1
1000
Fig. 2.7: MODEL
PERFORMANCE:
Formation model
with marked
changes in
resistivity. The
standard log (a)
can not identify
subtle changes and
misses some peaks
completely. The
enhanced log (b)
identifies almost
every bed; the
thinnest being
about 2 ft thick.
The ability to do all necessary processing at the wellsite helps to accelerate
the entire evaluation process in complex reservoirs.
As vertical resolution improves,
borehole effects become more pronounced. This is a major problem in
bad borehole conditions, particularly if
very saline (conductive) borehole fluids are present.
For one well in the Meleiha Field,
Agiba processed their data at all three
resolutions. The well was drilled with
water base mud. Borehole conditions
were fine and the logs were free from
unwanted borehole effects. At 4 ft resolution the logs are characterized by a very
smooth response, similar to conventional
induction logs, with few of the Bahariya
Formation's thin layers being detected.
At 2 ft resolution the logs show a lot
more detail, including the thin beds that
were missing in the 4 ft log. The 1 ft resolution gives the thin bed information
and provides a more accurate estimate
of resistivity.
150
200
Number 17, 1996.
Fig. 2.8: THIN BED BAHARIYA: The Bahariya
Formation in Egypt's Western Desert is a
heterogeneous, mineralogically complex
sequence of thin beds - in other words, a log
analyst's nightmare.
25
Fig. 2.9: Borehole
corrections must be
carried out on the AIT
tool's 28 signals
before they can be
combined to form
logs. The corrections
are encoded as tables
for various borehole
conditions. The tables
were developed by
finite element
modelling of the
correction. This
complex 3D problem
required two years of
Cray computer time
to solve.
Using the AIT tool, a resistivity annulus can be identified more readily, and
the use of Tornado charts for correction
can be avoided.
The AIT tool was designed to tackle
three important problems:
• caving/borehole effects;
• invasion description;
• poor vertical resolution.
The AIT tool offers five fixed depths
of investigation, but the measurements
are not taken from single points in the
formation, but from areas that centre on
points 10, 20, 30, 60 or 90 inches into it.
Sampling at five depths of investigation offers many advantages over results
from just three depths. The high-low-high
resistivity variations we need to define
an annulus are more likely to be identified by five separate measurements
which can ‘see’ deeper into the formation. The AIT tool eases the analyst’s burden - making 28 measurements and using
built-in borehole correction tables for
various borehole conditions (figure 2.9).
The latest development in AIT tool
technology has been specifically designed
for the Platform Express* system. It offers
the same five depths of measurement
but total tool length is only 16 ft. The
problem of erratic ‘stick-slip’ motion
encountered in some multiarray induction tools has been solved by adding an
accelerometer to provide real-time depth
correction for every tool on the string;
this also ensures that the tools are ‘ondepth’ with each other.
New algorithms have been developed
and tested for a range of difficult logging
conditions. One of these gives better
readings in rugose boreholes and conductive (saline) mud. Additional features
include correction to the resistivity logs
for dip or deviation up to 60°, and more
accurate estimates of Rt in the presence
of annulus.
26
However, when the annulus has
moved too far into the formation and has
passed beyond the maximum depth of
investigation for any available tool,
direct measurement of Rt is prevented.
Clearly, if R t cannot be measured
directly, an estimation technique must
be devised. Experts are currently working on methods which will allow them to
invert resistivity profiles to obtain Rt and
Rxo mathematically, using five measurements to evaluate five unknowns. At present, this cannot be done quantitatively.
In addition to annulus identification,
the AIT tool helps to identify thin beds.
Many geoscientists are reaching the conclusion that thin bed analysis is important
in every reservoir. The majority of ‘thick’
reservoir intervals are usually layered made up of similar, but distinct thinner
units (figure 2.10). By identifying the
minor lithological contrasts which define
thin layers, it is possible to improve reservoir models and so enhance the predictions which are based upon them.
When the resistivity of the invaded
zone is much lower than in the undisturbed reservoir, the ARI* (Azimuthal
Resistivity Imager) tool or standard dual
laterolog will give a more accurate determination of resistivity than the AIT tool.
It is, therefore, important to assess resistivity contrasts before selecting tools.
In many Middle East reservoirs resistivity contrasts mean that induction readings are needed in the water layer, to
determine Rw (water resistivity) as accurately as possible. When this is the case,
induction tools give the best results for
deep true resistivity. Accurate resistivity
measurements in water zones can be
vital. Indications of saturation within the
zone will influence major economic decisions in the development of a reservoir.
For complete evaluation both types of
tool can be run together and this
arrangement would be of benefit in most
Middle East reservoirs. In practice, however, a choice is generally made and one
or other measurement is given priority.
Fig. 2.10: The majority
of ‘thick’ reservoir
layers are actually
sequences of
lithologically similar
thin beds. Identifying
the minor differences
between these layers
improves the reservoir
model and, therefore,
the quality of
predictions and
simulations based
upon it. (Denise Stone,
AMOCO.)
Middle East Well Evaluation Review
The AIT tool acquires data at three
vertical resolutions, but it is usually displayed at the highest (1 ft) resolution
(figure 2.11). In wells where conditions
are not good for resistivity determination, for example where borehole conductivity is high or the borehole is
extremely rugose, there are no benefits
from processing data to display the highest resolution and logs are usually displayed at 2 ft or 4 ft resolution. However,
even at a vertical resolution of 4 ft, the
AIT is about twice as good as other standard fixed focus induction tools, an
important factor when investigating thin
beds with high resistivity.
The choice of vertical resolution at
which the log will be processed depends
on factors such as hole size and shape,
and the expected range of deep resistivities. In difficult environments the operator may decide to select a lower
processing resolution to make the data
more robust.
Sense and sensitivity
Calibration of the AIT tool requires a
‘zero conductivity’ environment, or conditions which approximate this as closely
as possible. The process is carried out at
special facilities, using equipment which
contains no metallic components. During
calibration there must be no metal within
28 ft of the tool and there should be no
stray electrical signals (e.g. the charges
which build up during a thunderstorm)
to affect the settings. This extreme sensitivity may seem inconvenient above
ground, but when the tool is where it
belongs - in the borehole - it can detect
the smallest fluctuations.
In many cases it could be beneficial to
run a FMI* (Fullbore Formation
MicroImager) or FMS (Formation
MicroScanner*) below the induction
tool. The AIT is the only induction tool
that can function in this configuration.
A through-wire sonde was specially
developed for the AIT tool which allows
other tools to be run below it in the
string. This seemingly simple task
required a great deal of engineering
effort. The AIT tool's conductivity measurements detect minute voltage
changes and electrical connections running through the sonde were likely to
cause major problems unless the tools
could be shielded to eliminate their influence. Schlumberger has developed a
method which allows other tools to be
linked below the AIT tool without affecting the very low signal levels measured
by the induction tool. This allows for
greater flexibility when a tool string is
being put together.
Number 17, 1996.
For the first time, tools such as the FMI
or FMS can be run in conjunction with an
induction log. Careful choice of scales
allows the operator to incorporate FMI or
FMS images into AIT images of resistivity,
Rwa or saturation without excessive distortion.
In too deep
In vertical wells, the assumption of symmetry around the borehole encouraged
the development of tools that looked
deeper into the formation as analysts
sought to measure values beyond the
zone invaded by mud filtrate. This
‘deeper is better’ philosophy is justified
in vertical wells, where the AIT tool can
‘see’ beyond the mud filtrate and measure R t directly. Unfortunately, the
radial symmetry that is assumed in vertical wells simply does not exist in highlydeviated and horizontal wells (see figure
2.3). This asymmetry around the tool is
a problem. Induction tools measure σ
(the conductivity of a bed) and interpretation is based on a constant induced
conductivity along the measurement
loop. However, when the tool cuts different layers (each having different conductivities) a polarisation effect distorts
the readings.
Fig. 2.11: This figure
shows a saturation
map obtained from the
AIT tool and porosity
logs. The option of
running borehole
imaging tools, such as
the FMI and FMS, in
conjunction with an
induction log will
improve downhole
efficiency.
27
MICROPOROSITY MAKES SENSE
28
z
B0 field
z
Precessing
magnetic
moments
B0 field
B1 field
Net magnetization
along z-axis
y
y
x
x
Rock grain
Fig. 2.13: Aligned protons are ‘tipped’ 90° by a
magnetic pulse oscillating at the resonance or
Larmor frequency.
Rock grain
Rock grain
Fig. 2.12: Proton alignment is the first step in
NMR measurement. Spinning protons are
aligned using powerful permanent magnets.
The protons precess around an axis parallel to
the B0 direction. In logging, B0 is perpendicular
to the borehole axis.
Rock grain
Rock grain
Rock grain
Small pore
Large pore
Amplitude
Amplitude
Over the past year a new generation of
Nuclear Magnetic Resonance (NMR)
tools has been introduced in the Middle
East. These tools, in contrast to the previous generation, no longer require mud
doping to kill the borehole signal and
this makes the technique applicable in
many more wells.
NMR measurements are made by
manipulating hydrogen protons in fluid
molecules. In a sense, the protons
behave as small bar magnets - their orientations can be controlled by changes
in a magnetic field. A measurement
sequence starts with alignment of protons using powerful permanent magnets
(figure 2.12). The next step is spin tipping. With the strong magnetic field B0
still applied, the aligned H nuclei are
tipped away from B0 by applying a highfrequency oscillating magnetic field B1,
perpendicular to B0 (figure 2.13).
The H nuclei, now tipped in a plane
perpendicular to B0, rotate or ‘precess’
around the B0 axis. If the field B0 was perfectly homogeneous, all of the nuclei
would rotate in phase at a frequency
called the Larmor frequency. In reality,
some of the nuclei will collide with pore
walls (figure 2.14) and move back towards
the B0 direction while others may stay in
the plane of precession but be completely
out of phase with the rest of the nuclei. A
measurement of the small magnetic field
generated by the nuclei rotating in phase
will, therefore, decay as more and more
nuclei slip out of phase. In the laboratory
the longitudinal relaxation time (T1) is
usually evaluated but in the wellbore the
transverse relaxation time (T2) is measured instead. Both are directly related to
pore size (figure 2.14) but T2 is easier to
measure in a logging environment.
The theory set out above is complicated by conditions in the oilfield.
Homogeneous magnetic fields can be
approximated in the laboratory, but not in
a borehole. The frequency of precession
is controlled by the magnitude of B0 and it
varies as B0 changes. Consequently, inhomogeneities in the field strength create
regions where the nuclei rotate at different
frequencies and are no longer in phase.
To counteract this ‘dephasing’ problem special sequences called CPMG
have been designed to re-focus those
nuclei which were no longer contributing to the measured signal, even though
they remained in the plane perpendicular to B 0 and were precessing without
interacting with the rock surface.
Time, msec
Time, msec
Fig. 2.14: COLLISION COURSE: Precessing protons move about the pore space colliding with other
protons and with the grain surfaces. At every collision there is a possibility of a relaxation interaction.
Grain surface relaxation is the most important process affecting T1 and T2 relaxation times.
Fig. 2.15: TIME TO
RELAX: Water in a
test tube has a long
T2 relaxation time,
3700 msec at 40°C.
Relaxation in a vuggy
carbonate might
approach this value
but water in normal
pore space has
shorter relaxation
times. In sandstones
relaxation times
range from 10 msec to
500 msec.
Middle East Well Evaluation Review
Bound fluid
Water
Possible free water
Water
Moved hydrocarbon
Volume of water from RT
Moved hydrocarbon
0.0
25.0
Oil
CMR bound fluid
Perfs
1:200ft
X800
(PU)
0.0
Oil
50.0
(PU)
(IN)
3000
Porosity
0.0
Calcite
20
Anhydrite
T2 AMPLITUDE
Dolomite
Diff. Caliper
0.25 -20
Moved oil
X900
T2 THRESHOLD
3
Fig. 2.16: UNTROUBLED
WATER: The high water
saturations recorded in some
reservoir zones can be
misleading. In this example,
conventional logs would
suggest that water might flow
from this zone. However, the
CMR tool shows that the water
is bound in the micropores and
the zone should flow dry oil.
The perforated zone, which
included porous zones with
high water saturations,
produced oil free of water.
Residual oil
Residual oil
Bound
irreducible water
Fluid situations
In 1995 a comprehensive campaign of
NMR measurements was conducted in
Abu Dhabi. This involved eight wells and
four different operating companies. The
project was intended to evaluate the
NMR response of Cretaceous and
Jurassic carbonates which are the major
oil reservoirs across the region. In
parallel to the logging campaign, core
analysis was performed on samples from
five wells.
The main application of NMR measurements in the Abu Dhabi study was
to understand pore size distribution in
reservoir zones, to determine bound
fluid volumes and, from this information,
improve predictions of the fluids which
will flow from any given zone.
However, there are a number of
major obstacles. Although the relaxation
time T2 is faster in rock pores than in a
test tube (figure 2.15), reduced logging
speeds were necessary to ensure full
characterization of the pore volume. The
average logging speed for the Abu Dhabi
project was between 200-300 feet per
hour. Faster logging rates (up to 900 feet
per hour) were possible when only
bound fluids were assessed; reflecting
the fact that these fluids are typically
contained in smaller pores.
Number 17, 1996.
Middle East carbonate reservoirs often
display mixed wettabilities - their micropores are water wet and filled with irreducible water, while macropores in the
rock contain oil and are oil-wet. The
microporosity systems often dominate
resistivity measurements from logs, giving
apparent saturation calculations which
are inconsistent with production data, e.g.
dry oil may flow from a zone with a computed water saturation greater than 70%.
To overcome this problem both porosity systems (and their wettabilities) must
be considered for carbonate sequences.
This is achieved using the Combinable
Magnetic Resonance (CMR*) tool.
When saturations are computed using
an equation which accounts for the effect
of microporosity on the resistivity log a
different picture emerges.
Ct = Cw φMmM/X Sw nM/X + fmod SwM φµmµ/X Swµnµ/X
The profiles match so well that adjusting the cut-off to get the best possible fit
would seem a very good way to select
the correct value. This means that any
porous interval in this sequence can be
perforated and should flow oil without
any obvious risk of producing water.
When the interval in this example was
perforated it flowed dry oil for several
months. In the future, for a more complete analysis, it may be advisable to
consider the relative permeabilities of
the various fluids as a function of saturation but at this early stage simple empirical approaches are more likely to yield
useful results than more sophisticated
and theoretically rigorous methods.
X
Where:
Ct = total conductivity, Cw = water conductivity,
φ = porosity, Sw = water saturation, M denotes macroporosity and µ microporosity.
Note: fmod Sw depends on the distribution of microporosity in the rock
This calculation reduces the water
saturation value slightly and, more
importantly, indicates that all of the
water is bound. Plotting the CMR-derived
bound fluid against the volume of water
computed from resistivity, with the special saturation equation, shows a very
convincing match (figure 2.16).
M.J.C. Petricola and M.Watfa (1995) Effect of
Microporosity in Carbonates: Introduction of a Versatile
Saturation Equation. SPE paper 29841 presented at the
SPE Middle East Oil Show, Bahrain 1995.
M.J.C. Petricola and H. Takezaki (1996) Nuclear
Magnetic Resonance Logging: Can it minimize well
testing? 7th Abu Dhabi International Petroleum
Exhibition and Conference, SPE 36328 1996.
29
In addition to the polarisation effect
there is an anisotropy effect. In horizontal wells the hole is often situated at the
top of a reservoir zone - within a few feet
of an oil-shale interface - and deep resistivity readings, influenced by the formation above the interface, are not helpful.
The effects of a shale cap rock, for
example, will distort the resistivity measurements being taken in an oil reservoir
(figure 2.17). In this case a shale with a
resistivity of 4 Ωm lies above the reservoir
layer. The oil has a resistivity of 200 Ωm,
but measurements in a horizontal well
located less than 10 ft below the interface
would record a value between 40 Ωm and
170 Ωm. There are two possible solutions.
• Selection of deep readings in the appropriate direction (e.g. using the Azimuthal
Resistivity Imager, ARI* tool).
• Shallow readings taken before the
effects of invasion have pushed original
formation water away from the borehole
wall (e.g. using the Resistivity-at-the-Bit,
RAB* tool).
A sense of direction
Some tool developments have overcome the asymmetry problem in horizontal wells by offering directional
measurement. The ARI, for example,
makes 12 azimuthal (directional) readings around the circumference of the
tool. Where the geometry of the well is
understood, it is possible to select readings in the appropriate direction.
Resistivity readings of the LLd and
LLhr logs can be strongly affected by
azimuthal heterogeneities. In heterogeneous formations the ARI tool’s
azimuthal imaging can greatly improve
resistivity log interpretation - azimuthal
resistivity values can be selected and
the values obtained used in a model for
formation evaluation. This is particularly
important in horizontal wells, where the
selected measurement can be for the
zone below the well or, as is more likely,
along the target layer.
Figure 2.18 shows ARI and FMI
images, displayed with ARI resistivity
curves, in a formation which contains
some azimuthal heterogeneities.
The low resistivity readings at
x91.4 m and x92.2 m are clearly different.
This reflects the causes - the shallow low
reading is a continuous event (a lowresistivity bed) whereas the deeper low
resistivity reading is due to a small heterogeneity which is almost certainly confined to the area around the wellbore.
This resistivity low would almost certainly be mis-interpreted on a standard,
azimuthally-averaged, resistivity log.
1
Depth
1
in
feet 1
Input model resistivity
1000
Computed deep induction
1000
Computed medium induction
1000
-10
-5
Shale 4Ωm
0
5
Oil 200Ωm
10
Fig. 2.17: In a horizontal well the effects of nearby layers (in this case a shale cap rock) can
distort the resistivity measurements being taken in the oil or gas layer. The shale cap rock
with a resistivity of 4 Ωm lies approximately 5 ft above the reservoir layer. The oil resistivity is
200 Ωm, but a horizontal well less than 10 ft below the interface would record a value
somewhere between 40 and 170 Ωm.
Looking down
The ARI can differentiate between resistivity above, below and in the plane of
the borehole. This is extremely useful
where anomalous resistivity conditions
30
Fig. 2.18: The combination of ARI and FMI images with ARI resistivity curves clearly indicates that
the low resistivity readings at 91.4 m and 92.2 m are caused by different types of heterogeneity.
Standard, azimuthally-averaged logs would not reveal this difference.
Middle East Well Evaluation Review
Number 17, 1996.
RHOB vs DLT (LLD)
Frequency crossplot
100
100
LLD
RHOB vs ARI (LLHR down)
Frequency crossplot
LLHR
are encountered - for example when the
borehole is approaching a layer where
water breakthrough has occurred or is
close to a shale layer or crossing tight
layers, etc.
One benefit of using the ARI tool is
illustrated in figure 2.19. The first crossplot shows the ‘ARI down’ resistivity
plotted against bulk density while the
second shows standard LLd resistivity
versus bulk density. The ARI down correlation is clearly better than that from
the LLd. The main reason for this is that
the ARI down is affected by the same formation as the density since in a horizontal well such as this the weight of the
density pad makes it very likely that it
will be facing the lower side of the hole.
The LLd is reading an average resistivity
from around the borehole and produces
a resistivity reading which is too low
when the formation under the borehole
has a high-resistivity and too high when
the formation below has a low resistivity.
Saturation estimates rely on accurate
resistivity values. Using the ARI tool the
operator can select the most appropriate
direction and, therefore, most realistic
value for formation resistivity.
The ARI tool has been used in the
Middle East to examine low resistivity
fractures in an effort to characterize porosity. The challenge of logging horizontal
wells remains and ongoing research is
aimed at providing the answers.
Azimuthally averaged readings are of
little use in horizontal wells. LLd, LLs
and induction logs, for example, are
influenced by beds which are parallel
and close to the borehole. This can be
crucial to interpretation when a well is
steered close to the top of a reservoir.
Tools having different depths (or volumes) of investigation may give very different results in the same horizontal
well. A density tool, which takes a very
shallow reading may indicate sands
while a neutron detector may indicate
an overlying shale. The quantitative
azimuthal image from the ARI tool helps
to detect and identify these beds and so
allow the most representative reading to
be selected from the azimuthal deep
resistivity measurements.
In practice, resistivity tools are seldom
run alone for complete formation evaluation. Laterologs are often combined with
microresistivity tools and porosity tools
to produce the so-called ‘triple-combo’.
These combined strings are often
more than 90 ft long and, while they
improve efficiency by reducing the number of logging runs, they pose problems
in an extended rig up/rig down period,
reduced logging speed and the need to
drill more rathole (additional depth at
bottom of the well) to ensure complete
coverage by all three sections of the
‘triple-combo’.
10
10
2.6
2.8
3.0
2.2
2.4
2.0
2.4
2.6
2.8 3.0
RHOB
RHOB
Fig. 2.19: If a horizontal well is drilled accurately and is located close to the top of a reservoir zone,
the important formation properties are those below the well, not an average of properties above
and below. These graphs clearly indicate the value of the ARI tool.
2.0
2.2
Flex joint
Fig. 2.20: Flexible
joints allow the HALS
to ‘hug’ the borehole
wall, thereby
ensuring accurate
measurement as the
tool body moves in
and out of rough
sections. The shorter
pad also improves
logging results in
deviated holes.
Flex joint
A new laterolog tool, the HALS* (High
Resolution Azimuthal Laterolog Sonde)
has been developed to overcome these
problems. Only 16 ft long, HALS is half
the length of the dual laterolog, and has
an azimuthal resistivity array. Used correctly, directional measurements help to
clarify the situation in horizontal wells.
This tool has been designed to cope
with rough sections and deviated boreholes (figure 2.20). The flexible jointed
construction and short pad length help
to keep the tool pressed against the borehole wall.
In some sequences, the complexity of
lithological variation makes results from
a single tool almost useless. In future,
efforts may focus on running several
resistivity tools during the same logging
run; and cross-referencing between them
to construct a clear picture of reservoir
lithology and relative bed thicknesses.
This 3D modelling will require advanced
software packages and a better understanding of reservoir geometry.
31
The shallow end
One alternative to directional or deep
measurement of resistivity is to take shallow measurements during drilling - in the
very early stages of invasion. It is now
possible, using Logging While Drilling
(LWD) technology, to measure resistivity
at the bit.
Field tests conducted with the RAB*
(Resistivity-at-the-Bit) tool show that
measurements made using the ring electrodes (figure 2.21a) record Rt accurately
when run close to the bit (i.e. when the
formation is logged before significant
invasion effects develop). Its performance has been assessed using deep
resistivity tools such as Laterologs.
Fig. 2.21:
BUTTONS AND
RINGS: Using a
ring electrode Rt
can be measured
accurately when
the RAB tool is
run close to the
bit (i.e. when it
logs the formation
before significant
invasion effects
develop). The
button electrodes
measure
resistivity at
different depths
and can help to
identify the zones
where invasion
starts. In the right
conditions, they
can be used to
compute invasion
diameter.
When the RAB tool is run some time
after the drill bit, the resistivity value is
affected by invasion. However, ‘tornado’
charts can provide a reasonable correction in order to determine Rt and calculate saturation.
When run directly at the bit and making measurements using the bit itself, the
RAB tool provides critical information
for geosteering, or for selection of casing
and coring points as soon as the formation of interest is penetrated.
Sensors located very close to the drill
bit detect changes which indicate when a
well is about to leave the target zone and
move into adjacent shale or water layers.
This allows the driller and geologist to
steer a well in real-time, ensuring that as
much of the well as possible stays within
the reservoir layer. The RAB tool was
designed to perform this task and to measure Rt accurately in saline muds with
high resistivity formations. In these situations, borehole and invasion effects on
the tool are small.
The RAB tool has greatly extended
the range of conditions where accurate
formation resistivity measurements can
be made while drilling. It is suitable for
very high-resistivity formations, and can
make multiple measurements at four
depths of investigation.
(a)
Transmitter
axial
Ring
measure
current
Receiver
measure
current
(b)
Ammeter
Collar
Insulation
Ring
electrode
Button
electrode
Ammeter
Cross-section view
32
Fig. 2.22: The RAB tool's ring electrode
induces a voltage difference in the string,
causing current to flow into the formation.
As this returns (arrows), it is measured to
derive formation resistivity. Button resistivity
(red area) delivers good vertical resolution
and allows the borehole to be scanned as the
tool rotates.
Middle East Well Evaluation Review
Fig. 2.23: DOWNHOLE
NAVIGATION:
Detailed images of the
borehole can be
recorded and stored
downhole in the RAB
tool for later analysis.
The imaging facility
can be switched on or
off, allowing the
operator to select
specific well intervals
for detailed
examination.The data
transfer rate from tool
to surface is the only
obstacle to real-time
resistivity imaging.
Right on the button
The RAB tool’s button electrodes (figure
2.21b) measure resistivity at different
depths and can help to identify the
zones where invasion starts. In the right
conditions, they can be used to compute
invasion diameter.
As the tool rotates, the RAB buttons
take resistivity measurements from
around the wellbore (figure 2.22). This
azimuthal resistivity data is stored in the
RAB tool and can be retrieved when it
returns to surface. The image which is
generated allows computation of dips,
fracture detection and estimation of fracture aperture and orientation. The features shown are similar to those
obtained using the ARI tool, but offer
better resolution.
The RAB button measurements provide a good indication of movability
when a sufficient break is allowed after
drilling. This, however, conflicts with the
objectives of early logging - to establish a
value for Rt. One solution is to run two
RAB passes, one close to the bit to
assess Rt and another after invasion to
evaluate movability.
Additional resistivity data, including
detailed images of the borehole (figure
2.23) can be recorded and stored downhole for later inspection. Detailed resistivity imaging using the button electrodes is
possible because the resistivity measurements are made in the very early stages
of invasion (figure 2.24).
The restricted data transfer rate
between tool and surface is the only
obstacle to real-time resistivity imaging.
Horizontal drilling can be compared
to driving your car or taking a bus across
a city. The RAB tool offers the freedom
of the car driver - the driller and geologist can stop at any time to consult a
‘map’ of changing borehole conditions,
take pictures of the borehole as they
pass through and change direction to
reach the right destination. Traditional
horizontal drilling, by comparison, is like
falling asleep on the bus and arriving
somewhere you may not want to be,
with no idea of how you got there.
x015
x020
x025
x030
x035
x040
x045
x050
x055
Drilling mud
Invasion front
Fig. 2.24: High quality
measurements are
possible with the
RAB tool because it
examines the
formation almost as
soon as it is drilled while invasion effects
are at a minimum.
RAB tool
Number 17, 1996.
33
Cased hole choices
In cased holes, reservoir evaluation and
saturation monitoring are performed in
one of two ways. The first method TDT*
(Thermal Decay Time principle) measures the decay of thermal neutron populations and the other uses tools such as
the RST* (Reservoir Saturation Tool) to
assess changes in a reservoir’s fluid saturations.
The RST tool contains a minitron - an
electronic neutron source - which fires
high energy neutrons through the casing
and into the rock layers around the
borehole. These neutrons interact with
the borehole and formation fluids, producing gamma rays. The RST tool measures the returning gamma rays to
identify water and oil saturations.
Neutron capture
Slow neutron
γ-ray
Nucleus
Excited nucleus
Inelastic scattering
γ-ray
Nucleus
Fast neutron
Setting your sights on sigma
34
Fig. 2.25: In neutron capture, neutrons are
incorporated into the nucleus of the fluid atoms
- the gamma-rays released are recorded to
derive the Σ measurements. Inelastic scattering
with fast neutrons (where the neutron strikes
the rock or fluid nucleus but is not captured by
it) and associated gamma-ray release, is the
basis for C/O measurements.
Excited nucleus
Saline Formation Fig. 2.26: Capture crosssections for various
Water
100
Capture cross-section
There are two basic mechanisms which
help to identify saturation values - neutron capture and inelastic scattering (figure 2.25). In neutron capture, the high
energy neutrons from the minitron
source, after slowing down to a thermal
energy level, are incorporated into the
nucleus of rock or fluid atoms - this is
the basis for Σ (sigma) measurements.
Inelastic scattering with fast neutrons
(where the neutron strikes the rock or
fluid nucleus but is not captured by it) is
the basis for C/O measurements (see
below).
The different atoms which comprise
oils, formation water, rock etc. capture
different amounts of neutrons. This capture value is referred to as the material's
capture cross-section. The capture crosssection for formations which contain a
lot of high-salinity water is large. Rocks
that contain oil and little or no saline
water have a low capture cross-section.
Typical capture cross-section (Σ) values
for salt water are in the range 80 to 100,
while the values for oil are usually
around 20 (figure 2.26).
There is a simple, linear relationship
between saturation and Σ which, in ideal
conditions, allows a quick and accurate
determination. However, there are possible complications. For example, if there is
mud filtrate behind the pipe, the Σ values
will reflect this and, in non-perforated
zones, there is no way to estimate the
effect of any residual mud. In perforated
zones it is likely that the mud has been
removed by the perforation process and
the pressure of flowing hydrocarbon, but
even here the Σ values can not be relied
on entirely. The measured values at and
around the perforation reflect a disturbed
reservoir state and may not be characteristic of the rest.
This problem is particularly acute in
the Middle East where perforated zones
are often acidized to improve permeability. The acid reacts with the formation car-
80
60
Oil
Injected Water
40
atoms can help to
characterize the fluid
content of formations.
The difference between
oil’s capture crosssection (around 20)
and water (in the range
80 to 100) is a simple
way to distinguish
reservoir zone from
aquifer. However, it is
impossible to
differentiate between
oil and injected water
using this method.
20
0
Salinity of pore fluid
bonate to give a high capture cross-section
reading with the TDT tool. Consequently,
potential oil zones in acidized wells can
give a typical water zone reading. This
‘acid effect’ is one of the main reasons
why saturation monitoring should take
place in observation wells - not producers.
In most wells, the Σ values provide a
good approximation of saturation. The
high-salinity formation water is easily distinguished from hydrocarbons. However,
fresh water injected into the well (and, in
comparison to formation water, seawater
can be considered ‘fresh’) will give values
close to those for oil. So, in places where
fresh water is being injected another type
of measurement is required.
Carbon and oxygen
In C/O logging the relative concentrations of carbon and oxygen atoms in the
formation fluids are measured to assess
saturation. In the past, this method was
restricted to relatively shallow depths of
investigation, producing results which
were difficult to interpret (influenced by
the carbon in carbonate minerals,
cement etc.) as well as being relatively
slow (about 20 ft/hour).
Middle East Well Evaluation Review
107
Relative counts
Hydrogen
Carbon
106
Oxygen
105
Inelastic
water
Fig. 2.27: Inelastic
burst spectra. This
example shows a test
set-up with the tool's
far detector immersed
in tanks of oil and
water. Peaks for
carbon atoms (in the
oil) and oxygen
atoms (in the water)
are easily identified.
Inelastic
oil
104
0
2
4
6
Energy (MeV)
Fig. 2.28:
ELEMENTAL
FINGERPRINTS: This
plot of standard
spectra for the RST
tool can be used to
‘finger print’ the five
elements shown.
Although oxygen and
carbon are the most
important elements
for saturation
monitoring, the
presence of carbon
and oxygen in rocks
(e.g. limestones) and
in cement means that
formation corrections
may have to be made
in order to identify
true saturation effects.
Oxygen
Relative counts
Silicon
Calcium
Iron
Carbon
2
4
5
Energy (MeV)
Dual detector COR model
for 21/2 in RST tool
1
0.8
0.6
oil
ion
yo so
0.2
o-w
w-w
0
0
0.2
0.4
0.6
0.8
Near carbon/oxygen plots
Number 17, 1996.
water in formation
water in formation
oil in formation
oil in formation
Fig. 2.29: This type of plot is used for
interpretation of RST results. This plot shows
the expected range of values for a 43 porosity
unit limestone formation, with the tool in an
8 1/2 in. borehole with 7 in. casing. All data
should fall within the box.
rm
at
w-o
0.4
7
o-o
il
ole o
h
Bore
6
w-w: water in borehole
o-w: oil in borehole
o-o: oil in borehole
w-o: water in borehole
Fo
Far carbon/oxygen ratio
1.2
3
1
The previous generation of logging
tools were large and operated at very
slow speeds. An additional problem was
their sensitivity to borehole fluid which
restricted the use of carbon-oxygen logging. In cases where C/O logging was
required, the well usually had to be
killed and the production tubing pulled.
Given all of these problems and limitations it is not surprising that time and
effort was devoted to improving the technique. When there is fresh water in the
formation this is the only method that
can be used.
Hardware improvements and the
development of systems, such as the
RST tool, have been the main focus of
research efforts.
The compact design of the RST tool
means that a well can be logged quickly
without killing the well or pulling the production tubing. The tool can compensate
for borehole fluid composition; allowing
formation oil saturation to be measured
and borehole oil/water fraction to be
assessed while the well is flowing.
All the right elements
The RST tool can analyze the energy of
returning gamma rays to identify chemical elements in the formation. A standard
spectrum has been obtained for the tool
as a result of extensive testing and this
can be used to identify the elements present in the formation. For saturation monitoring, the most important elements are
oxygen and carbon which provide information on the presence of water and
hydrocarbons respectively (figure 2.27).
However, since many rock types contain carbon and oxygen (e.g. limestones CaCO 3 and organic-rich shales), it is
important that the elements contained in
rock-forming minerals can be identified.
Some of the most important rock constituents are calcium, silicon and iron.
The RST tool can identify these elements
(figure 2.28), give an indication of lithology and, therefore, provide a more accurate assessment of saturation.
A slimhole tonic?
The RST tool is available in two sizes small and smaller. The standard RST tool
has a diameter of 21/2 inches, while the
slim RST tool, measures just 111/16 inches Eliminating the need to kill a well and
pull the tubing cuts out the associated
risks and minimizes production loss.
Interpretation is enhanced because kill
fluids do not invade the formation. The
smaller RST tool does not offer all of the
larger tool’s features, but it is designed
for use in shut-in wells.
The carbon/oxygen ratios from RST
analysis are plotted to assess the probable saturation values for rocks of a particular porosity (figure 2.29). All data should
fall within the box defined by the four oil
and water values (w-w, o-w, o-o and w-o).
35
THE CATOOSA DRILLING PROJECT
In gas-bearing sandstones, mud filtrate
invasion is often very deep. When this
occurs it can be difficult to discriminate
gas-bearing intervals from those containing oil or water. Shaliness and the
extreme effects of invasion can mask
the familiar ‘gas crossover’ between
neutron and density logs. Recorded
water saturations can reach 80% in
some formations, even with deep resis-
870
AIT resistivity (ohm-m)
10
0.3
tivity measurements. The low resistivity
annulus has long been considered a
good hydrocarbon indicator, but in some
formations the time delay between
drilling and logging can mean a very
deep annulus which is beyond the investigation depth of standard resistivity logging tools. The resulting low recorded in
deep resistivity can lead to an unduly
pessimistic evaluation of the well.
Fractional volume
0.2
0.1
0.0
DIL resistivity (ohm-m)
10
880
Depth (ft)
890
900
ϕ
Vsh/2
AO10
AO20
AO30
AO60
AO90
910
SFL
IMVR
IDVR
920
100
Fig. 2.30: A direct comparison of AIT and Phasor Induction logs in the
Bartlesville sandstone. Porosity and Vshale logs for reference.
Bartlesville Sandstone
Petrophysical parameters
10
Rxo
Rann
RT
10 In
Fig. 2.31: AIT log
values as a function
of radial depth at the
annulus. The annulus
position, indicated by
the green vertical
line, most closely
matches the log
values in figure 2.30
at the well depth
indicated.
20 In
30 In
60 In
90 In
Annulus position
at 887ft
The Catoosa drilling project was set
up to investigate the effects of different
types of mud systems on invasion
depth. The drilling and logging were carried out under carefully controlled conditions. The gas-bearing formation
selected for the study was the
Bartlesville sandstone, a shallow, lowpressured (depleted) section at Amoco's
test drilling site in Oklahoma, USA.
Three test wells were drilled with different fluid loss control systems. However,
some important aspects of log analysis
in gas reservoirs were examined.
Three wells were drilled with potassium chloride (KCl) mud, one with a
high fluid loss, the second with a low
fluid loss, while the third was drilled
with a partially hydrolized polyacrylamide polymer system (PHPA) - an
inhibitive system used to prevent shale
sloughing, differential sticking and skin
damage. Although this mud system is
thought to limit mud filtrate invasion,
the invasion depth in this well was
greater than in the other test wells.
New generation logging tools with
new or additional measurements indicated that there were some fundamental problems with the ways in which
conventional logs are often used. The
neutron-density gas crossover is
affected by formation shaliness and can
be totally eliminated by an invasion
which exceeds 10 in.
The AIT resistivity logs indicated
that the invasion in all three test wells
had formed an annulus and an inversion of the logs allowed an accurate
estimate of R t . In one instance (the
Bartlesville sandstone) the resulting saturation proved to be one third less than
the value derived from the Phasor
Induction tool (figure 2.30).
In the Bartlesville sandstone the AIT
tool’s 60 in. and 90 in. logs are in reverse
order - indicating an annulus in this
zone. Figure 2.31 shows a plot of the
sweep of the annulus inner radius for
final saturation values in this unit at
887 ft. This point was chosen because it
represented the largest curve separation.
Differences in curve separation at other
depths are probably due to changes in
porosity and depth of invasion.
R.L. Terry, T.D. Barber, S. Jacobsen and K.C. Henry.The
Use of Modern Logging Measurements and New
Processing Algorithms to Provide Improved Evaluation in
1
10
20
30
40
50
60
r1 (in.)
70
80
90
100
Deeply Invaded Gas Sands. Presented at the 35th
SPWLA Logging Symposium, Tulsa, Oklahoma, USA.
June 19-22 1994.
Petrophysical parameters:
Sw = 0.35
Sxo = 1.0
36
Rw = 0.085
Rmf = 0.98
ϕ = 0.17
Vsh = 0.25
Rsh = 8.5
Rwlrr = 0.025
Middle East Well Evaluation Review
0.8
Fig. 2.32: This
crossplot compares
near and far
carbon/oxygen
ratios (with the test
well shut in and
flowing) with
laboratory data for
limestone saturated
with either oil or
water having a
density of
0.85 g/cm3.
0.7
Carbon/oxygen ratio (far)
In one example, a well producing from
a carbonate reservoir - with porosity
between 5pu and 30pu - produced oil with
a watercut of about 20%. Figure 2.32 shows
a crossplot of the near and far carbon-oxygen data from this well compared with laboratory data for a limestone saturated with
water or oil with a density of 0.85g/cm3.
The large bounded area shows the
dynamic range for a 43pu limestone and
the inner area that for a 17pu limestone.
Some of the data points fall outside the
bounded area - this is due to statistical
variations, a borehole which was slightly
larger than the assumed 6 in. diameter
and a low oil density (0.715g/cm 3 ) at
reservoir conditions.
The RST can be used for a variety of
tasks - reservoir monitoring, detection of
water breakthrough and fluid contact
monitoring.
0.6
0.5
0.4
0.3
Shut in
0.2
Flowing
Lab data 43 p.u.
0.1
Lab data 17 p.u.
0
-0.2
0
0.2
0.4
0.6
Carbon/oxygen ratio (near)
0.8
1
Gas and gravity
There are alternative methods for determining gas and oil saturations. In reservoirs where gas is present, gas neutron
measurement techniques are used to
evaluate the Hydrogen Index within a
layer. From this it is possible to derive
the gas-oil saturation value.
The density contrast between gas and
water is the key to the borehole gravimetry technique. It is used to measure gas
cap expansion or to track the entry of
gas from injection wells - gas displacing
oil, not water displacing oil.
As oil is produced from a reservoir it
is replaced by gas. However, the density
contrast to be assessed covers very
large areas and the changes which have
to be detected call for very accurate
measurements.
Fig. 2.33: The
combination of ARI
and AIT tools will
allow the user to
establish a 3D picture
of formation
resistivity, apparent
water resistivity and
hydrocarbon
saturation (from the
AIT) and to link these
values to wellbore
features recorded by
the ARI tool.
Enter the third dimension
Since the 1950s, research into resistivity
tools and techniques has continued without interruption. Many of the analyses
which can be made today would have
seemed impossible twenty or even ten
years ago. However, the oil industry’s
appetite for information, gathered more
rapidly and with greater accuracy than
before, has not yet been satisfied.
New software is under development
which will combine all of the resistivity
tools, including LWD measurements, to
derive the best possible resistivity value
in all borehole conditions - variable borehole size, formation resistivity, mud
resistivity Rt /Rxo contrast etc.
However, there are many more possibilities to be explored to make the most
of the 3D aspect of the new resistivity
measurements provided by tools such as
the AIT. For example, running the AIT
tool in combination with an ARI tool
would allow the use of ARI electrical
stand-off and calliper information to
refine the AIT borehole correction.
Number 17, 1996.
When running together, these tools
provide a radial description of resistivity
variations (from the AIT) and an
azimuthal measurement (from the ARI).
If these can be combined, a true 3D representation of resistivity around the wellbore might become available at some
future date (figure 2.33).
At present, however, there is no software capable of delivering a true 3D
resistivity image. Combining both types
of logs may be a starting point in the
development of this kind of system.
If a 3D method could be developed
one of the most obvious applications
would be in horizontal wells where the
resistivity measured on the lower side of
the borehole can generally be better correlated with the density/porosity measurements which are themselves affected
mainly by the petrophysical properties of
rocks and fluids in that location.
While it may be some time before true
3D imaging can be developed, the considered combination of radial and azimuthal
resistivity information we have at present
will greatly enhance our understanding
of invasion and reservoir heterogeneity.
Another possibility would be to combine ADN (Azimuthal Density Neutron)
and RAB tools. This arrangement has not
yet been run in the Middle East, but it
would provide four porosities and four
resistivity measurements which could be
combined to give four saturation values.
The pursuit of high-quality saturation
data has been a long and difficult process. The new generation of tools and
techniques offer a wealth of information
which is helping to transform our perceptions of reservoir behaviour.
37