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SYSTEM AND METHOD FOR IDENTIFICATION OF HYDROCARBONS
USING ENHANCED DIFFUSION
Field of the Invention
The present invention relates to nuclear magnetic
resonance (NMR) borehole measurements and more particularly
to separation of signals from different fluids using user-
adjusted measurement parameters.
Background
One of the main issues in examining the petrophysical
properties of a geologic formation is the ability of the
measuring device to differentiate between individual fluid
ties. For example, in the search for oil it is important to
separate signals due to producible hydrocarbons from the
signal contribution of brine, which is a fluid phase of
little interest. However, so far no approach has been
advanced to reliably perform such fluid separation.
Various methods exist for performing measurements of
petrophysical parameters in a geologic formation. Nuclear
magnetic resonance (NMR) logging, which is the focus of this
invention, is among the best methods that have been developed
for a rapid determination of such parameters, which include
formation porosity, composition of the formation fluid, the
quantity of movable fluid, permeability among others. At
least in part this is due to the fact that NMR measurements
are environmentally safe and are unaffected by variations in
the matrix mineralogy.
To better appreciate how NMR logging can be used for
fluid signal separation, it is first necessary to briefly
examine the type of parameters that can be measured using NMR
techniques. NMR logging is based on the observation that
when an assembly of magnetic moments, such as those of
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hydrogen nuclei, are exposed to a static magnetic field they
tend to align along the direction of the magnetic field,
resulting in bulk magnetization. The rate at which
equilibrium is established in such bulk magnetization upon
provision of a static magnetic field is characterized by the
parameter T1, known as the spin-lattice relaxation time.
Another related and frequently used NMR logging parameter is
the spin-spin relaxation time T2 {also known as transverse
relaxation time?, which is an expression of the relaxation
due to non-homogeneities in the local magnetic field over the
sensing volume of the logging tool. Both relaxation times
provide information about the formation porosity, the
composition and quantity of the formation fluid, and others.
Another measurement parameter obtained in NMR logging is
the diffusion of fluids in the formation. Generally,
diffusion refers to the motion of atoms in a gaseous or
liquid state due to their thermal energy. Self-diffusion is
inversely related to the viscosity of the fluid, which is a
parameter of considerable importance in borehole surveys. In
a uniform magnetic field, diffusion has little effect on the
decay rate of the measured NMR echoes. In a gradient
magnetic field, however, diffusion causes atoms to move from
their original positions to new ones, which moves also cause
these atoms to acquire different phase shifts compared to
atoms that did not move. This contributes to a faster rate
of relaxation.
NMR measurements of these and other parameters of the
geologic formation can be done using, for example, the
centralized MRILm tool made by NUMAR, a Halliburton company,
and the sidewall.CMR tool made by Schlumberger. The MRIL~
tool is described, for example, in U.S. Pat. 4,710,713 to
Taicher et al. and in various other publications including:
"Spin Echo Magnetic Resonance Logging: Porosity and Free
Fluid Index Determination," by Miller, Paltiel, Millen,
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Granot and Bouton, SPE 20561, 65th Annual Technical
Conference of the SPE, New Orleans, LA, Sept. 23-26, 1990;
"Improved Log Quality With a Dual-Frequency Pulsed NMR Tool,"
by Chandler, Drack, Miller and Prammer, SPE 28365, 69th
Annual Technical Conference of the SPE, New Orleans, LA,
Sept. 25-28, 1994. Details of the structure and the use of
the MRIL~ tool, as well as the interpretation of various
measurement parameters are also discussed in U.S. patents
4,717,876; 4,717,877; 4,717,878; 5,212,447; 5,280,243;
5,309,098; 5,412,320; 5,517,115, 5,557,200 and 5,696,448, all
of which are commonly owned by the assignee of the present
invention. The Schlumberger CMR tool is described, for
example, in U.S. Pats. 5,055,787 and 5,055,788 to Kleinberg
et al. and further in "Novel NMR Apparatus for Investigating
an External Sample," by Kleinberg, Sezginer and Griffin, J.
15 Magn. Reson. 97, 466-485, 1992.
It has been observed that the mechanisms which. determine
the measured values oi= T1, Tz and diffusion depend on the
molecular dynamics of the formation being tested and on the
types of fluids present. Thus, in bulk volume liquids, which
typically are found in large pores of the formation,
molecular dynamics is a function of both molecular size and
inter-molecular interactions, which are different for each
fluid. Water, gas and different types of oil each have
different T1, Tz and d:Lffusivity values. On the other hand,
molecular dynamics in a heterogeneous media, such as a porous
solid that contains liquid in its pores, differs
significantly from the dynamics of the bulk liquid, and
generally depends on the mechanism of interaction between the
liquid and the pores of the solid media. It will thus be
appreciated that a correct interpretation of t;he measured
3a signals can provide valuable information relating to the
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types of fluids involved, the structure of the formation and
other well-logging parameters of interest.
One problem encountered in standard NMR measurements is
that in some cases signals from different fluid phases cannot
be fully separated. For example, NMR signals due to brine,
which is of no interest to oil production, cannot always be
separated from signals due to producible hydrocarbons. The
reason is that there is an overlap in the spectra of the
measured signals from these fluids (see, for example, Figs.
4a and 4b showing this overlap in the case of standard brine
and hydrocarbon TZ amplitude spectra}.
Several methods for acquiring and processing gradient
NMR well log data have been proposed recently that enable the
separation of different fluid types. These separation
methods are based primarily on the existence of a T, contrast
and a diffusion contrast in NMR measurements of different
fluid types. Specifically, a T1 contrast is due to the fact
that Light hydrocarbons have long T1 times, roughly 1 to 3
seconds, whereas T1 values longer than 1 second are unusual
for water-wet rocks. In fact, typical T1's are much shorter
than 1 sec, due to the typical pore sizes encountered in
sedimentary rocks, providing an even better contrast.
Diffusion in gradient magnetic fields provides a
separate contrast mechanism applicable to Tz measurements
that can be used to further separate the long T1 signal
discussed above into its gas and oil components. In
particular, at reservoir conditions the self-diffusion
coefficient Do of gases, such as methane, is at least 50
times larger than that of water and light oil, which leads to
proportionately shorter TZ relaxation times associated with
the gas. Since diffusion has no effect on the Tl
measurements, the resulting diffusion contrast can be used to
separate oil from gas.
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The T1 and diffusion contrast mechanisms have been used
to detect gas and separate different fluid phases in what is
known as the differential spectrum method (DSM) proposed
first in 1995. The original DSM uses two standard single-
echo spacing logs acquired at different wait times in two
separate passes. The short wait time TWS is chosen large
enough to allow full recovery of the brine signal, i.e., TWS >
3 max (T1 Water) ~ while the long wait time TWL is selected such
that TWL > T1 of the light hydrocarbon, usually assumed to be
gas. At each depth, the differential spectrum is formed by
subtracting the T2 distribution measured at TWS from the one
measured at TWL. Because T1 recovery of the water signal is
essentially complete at both wait times, this signal is
eliminated following the substraction, and the differential
spectrum is therefore due only to a hydrocarbon signal.
While the DSM method has been applied successfully for the
detection of gas and the separation of light hydrocarbons,
there are several problems associated with it that have not
been addressed adequately in the past.
First, DSM requires a logging pass associated with
relatively long wait times (TW approximately 10 sec).
Accordingly, DSM-based logging is by necessity relatively
slow.
DSM's use of T1 contrast may cause additional problems.
For example, the required T1 contrast may disappear in wells
drilled with water-based mud, even if the reservoir contains
light hydrocarbons. This can happen because water from the
mud invades the big pares first, pushing out the oil and thus
adding longer TZ's to the measurement spectrum. In such
cases, DSM or standard NMR time domain analysis (TDA) methods
have limited use either because there is no separation in the
TZ domain, or because the two phases are too close and can
not be picked robustly.
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Separation problems similar to the one described above
can also occur in carbonate rocks. In carbonates an overlap
between the brine and hydrocarbons phases is likely because
the surface relaxivity in carbonates is approximately 1/3
that of sandstones. In other words, for the same pore size,
the surface relaxation in carbonates is about 3 times longer
than that for a sandstone, such weak surface relaxation
causing an overlap between the observable fluid phases.
Additional problem for carbonates is the presence of
vugs. Water bearing vugs, because of their large pore sizes,
have long TZ's and can easily be interpreted as oil by prior
art techniques.
It is apparent, therefore, that there is a need for a
new system and method for NMR borehole measurements in which
these and other problems are obviated, and better separation
is provided between NMR signals from producible oil and
interfering signals from brine-type fluids.
Sumanary of the Invention
The present invention is based on forcing diffusion as
the dominant relaxation mechanism for the brine phase in NMR
measurements of a geologic formation. To this end, in
accordance with the present invention certain measurement
parameters are changed as to enhance the role of diffusion
relaxation in the brine phase. The enhanced diffusion
relaxation in turn establishes an upper limit for the TZ
distribution of the brine phase, which limit can be
calculated. Once this upper limit is found, any phase having
a longer TZ can be identified unambiguously as not being
brine, i.e., as a hydrocarbon.
The measurement parameters which are varied in
accordance with the present invention to establish an upper
limit in the TZ distribution of the brine phase are the
interecho time TE and the magnetic field gradient G of the
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tool. In addition to the TZ spectral domain, in accordance
with this invention the brine phase can be separated from
hydrocarbons using time domain analysis techniques based on
performing enhanced diffusion measurements.
In particular, in accordance with a preferred
embodiment, a method for nuclear magnetic resonance
measurements of the petrophysical properties of a geologic
formation is disclosed, comprising the steps of: providing a
set of NMR measurement parameters that establish an upper
limit in the apparent transverse relaxation TZA of a brine
phase of the formation; obtaining a pulsed NMR log using the
provided set of measurement parameters; determining from the
NMR log a distribution of transverse relaxation times; and
estimating from the distribution of transverse relaxation
times the contribution of the hydrocarbon phase as distinct
from brine.
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Brief Description of the Drawings
The present invention will be understood and appreciated
more fully from the following detailed description taken in
conjunction with the drawings in which:
FIG. 1 is a partially pictorial, partially block diagram
illustration of an apparatus for obtaining nuclear magnetic
resonance (NMR) measurements in accordance with a preferred
embodiment of the present invention;
FIG. 2 is a block diagram of the system in accordance
with a preferred embodiment which shows individual block
components for controlling data collection, processing the
collected data and displaying the measurement results;
FIG. 3 illustrates the use of diffusion-dominated
relaxation in accordance with the present invention to
establish an upper limit in the apparent relaxation time TZn
in a NMR measurement;
FIGS. 4(a-c) are Tz plots that illustrate the separation
of the brine phase using enhanced diffusion.
FIG. 5 is laboratory data from a Berea sandstone at 100
water saturation, illustrating the shift in the TZ spectra as
the interecho time TE increases.
FIGS. 6 and 7 provide examples of using the enhanced
diffusion method in accordance with the present invention to
separate different fluid phases.
30
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Detailed Description
The System
Reference is first made to Fig. 1, which illustrates an
apparatus constructed and operative in accordance with a
preferred embodiment of the present invention for obtaining
nuclear magnetic resonance (NMR) measurements. The apparatus
includes a first portion 106, which is arranged to be lowered
into a borehole 107 in order to examine the nature of
materials in the vicinity of the borehole.
The first portion 106 comprises a magnet or a plurality
of magnets 108, which preferably generate a substantially
uniform static magnetic field in a volume of investigation
109 extending in the formation surrounding the borehole. The
first portion 106 also comprises an RF antenna coil 116 which
produces an RF magnetic field at the volume of investigation
109.
A magnetic field gradient coil, or plurality of coils,
110 generates a magnetic field gradient at the volume of
investigation 109. This additional contribution to the
magnetic field, which is essential for the enhanced diffusion
method of the present invention, has a field direction
preferably collinear with the substantially uniform field and
has a substantially uniform magnetic field gradient. The
magnetic field gradient may or may not be pulsed, i.e.,
switched on and off by switching the do current flowing
through the coil or coils 110. The magnet or magnets 108,
antenna 116 and the gradient coil 110 constituting portion
106 are also referred to as a probe.
The antenna together with a transmitter/receiver (T/R)
matching circuit 120, which typically includes a resonance
capacitor, a T/R switch and both to-transmitter and
to-receiver matching circuitry, are coupled to an RF power
amplifier 124 and a receiver preamplifier 126. A power
supply 129 provides the do current required for the magnetic
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field gradient generating coils 110. All the elements
described above are normally contained in a housing 128 which
is passed through the borehole. Alternatively, some of the
above elements may be located above ground.
Indicated in a block 130 is control circuitry for the
logging apparatus including a computer 50, which is connected
to a pulse programmer 60 that controls the operation of a
variable frequency RF source 36 as well as an RF driver 38.
RF driver 38 also receives input from the variable frequency
source 36 through a phase shifter 44, and outputs to RF power
amplifier 124.
The output of RF receiver amplifier 126 is supplied to
an RF receiver 40 which receives an input from a phase
shifter 44. Phase shifter 44 receives an input from variable
frequency RF source 36. Receiver 40 outputs via an A/D
converter with a buffer 46 to computer 50 for providing
desired well logging output data for further use and
analysis. Pulse programmer 146 controls the gradient coil
power supply 129 enabling and disabling the flow of current,
and hence the generation of static or pulsed field gradients,
according to the commands of the computer 50. Some or all of
the elements described hereinabove as being disposed in an
above-ground housing, may instead be disposed below ground.
Fig. 1 depicts a preferred embodiment of the system used
in accordance with the present invention. Other systems may
also be used in alternative embodiments. Fig. 2 is a block
diagram of a generic system used in accordance with the
present invention, and shows individual block components for
controlling data collection, processing the collected data
and displaying the measurement results. In Fig. 2 the tool's
electronic section 30 comprises a probe controller and pulse
echo detection electronics. The output signal from the
detection electronics is processed by data processor 52 to
analyze the relaxation characteristics of the material being
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investigated. The output of the data processor 52 is
provided to the parameter estimator 54. Measurement cycle
controller 55 provides an appropriate control signal to the
probe. The processed data from the log measurement is stored
in data storage 56. Data processor 52 is connected to
display 58, which is capable of providing a graphical display
of one or more measurement parameters, possibly superimposed
on display data from data storage 56.
The components of the system of the present invention
shown in Fig. 2 can be implemented in hardware or software,
or any combination thereof suitable for practical purposes.
Details of the structure, the operation and the use of
logging tools, as illustrated in Figs. 1 and 2 are also
discussed, for example, in the description of the MRIL~ tool
to Numar Corporation, and in U.S. patents 4,717,876;
~5 4,717,877; 4,717,878; 5,212,447; 5,280,243; 5,309,098;
5,412,320; 5,517,115, 5,557,200 and 5,696,448, and
6,242,912.
The Method
The present invention is based on forcing diffusion as
the dominant relaxation mechanism for the brine phase in NMR
measurements of a geologic formation. As known in the art,
the main relaxation mechanisms that affect the TZ relaxation
times in rocks are molecular motion in fluids, surface
relaxivity at the pore walls, and molecular diffusion in
magnetic field gradients.
The first relaxation mechanism, known as bulk
relaxation, is due to local motions, such as molecular
tumbling and typically is observed in relatively large pores.
Hulk relaxation TzH for brine is on the order of several
seconds and for the purposes of this invention is assumed to
have negligible effect on the apparent T2A relaxation for the
brine phase.
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The second relaxation mechanism is surface relaxation at
the pore walls. This relaxation mechanism is very
significant in small pores and for fluid molecules, such as
water, that wet the rock surfaces. This relaxation is
generally much more rapid than the bulk relaxation -- in the
case of brine, the component T2S due to surface relaxation
varies between submilliseconds to several hundreds of
milliseconds.
The third relaxation mechanism is the diffusion of
molecules in magnetic field gradients, such as those
generated by Numar Corporation's MRIL° tool. Ordinarily,
diffusion is a predominant relaxation mechanism only for gas.
The apparent TaA for brine is given by the expression:
_1 _1 I
'
TzA Tzs TzD
where Tzs is associated with surface relaxation, TzD reflects
the contribution of the diffusion relaxation mechanism and,
as stated above, it is assumed that bulk relaxation for brine
is negligible.
It can be readily appreciated that when T2p is much
larger compared with '.C2S, the contribution of the diffusion
component in the above equation becomes negligible, and the
expression for T2A collapses to the following approximation:
2 !5
_1 1
Tz~ - Tzs .
Alternatively, however, under certain conditions which
are described below, t:he contribution of the diffusion
component 1/TZn can be substantial, in which case it is simple
to show that
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max~TzA~ <- Tz~ ( 1 )
A closer examination of Eqn. (1) shows that if diffusion
is forced to be the dominant relaxatiorn mode, an upper limit
of the apparent TzA relaxation of the brine phase can be
established. Therefore, any fluid that has transverse
relaxation time Tz > 'F2D is not brine.
To see how this observation can be used in practical
measurements to separate the contribution of different fluid
phases, it is first noted that TzQ is a function of the
interecho time TE used in the measurement, of the diffusion
coefficient for water D, and the magnetic field gradient G
generated by the measurement device. This function is given
by the well known Carr-Purcell equation for the diffusion-
induced relaxation 1/'T2D:
Tzp = ~ (Y'C'Tfi) z (2)
where Y is the gyromagnetic ratio (=2nx4258 rad/sec/Gauss for
2 0 protons ) .
The present invention is more specifically based on the
observation that the interecho spacing TE and the magnetic
field gradient G are user-controlled parameters, so that by
changing them the user can affect the dominant relaxation
2,~ mode, forcing it to be of diffusion type. For this reason,
the approach is referred to in this application as enhanced
diffusion (ED). In particular, with reference to Fig. 1, the
TE parameter can be modified by the pulse programmer 60.
Furthermore, the gradient G is a function of the operating
frequency, which is also user-adjustable. Therefore, by
3« adjusting operator-controlled parameters of the NMR
measurement, using the relationship expressed in Eqn. (2) one
can establish an upper limit for the apparent relaxation Tza
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of the brine phase, so that the hydrocarbon signal can be
isolated in the TZ range.
Specifically, as shown in Fig. 3, there are distinct
areas where either surface relaxation car diffusion relaxation
dominate the apparent T~, relaxation. As expected, when
surface relaxation is dominant, the apparent relaxation curve
closely tracks the surface relaxation. On the other hand,
when diffusion is the dominant relaxation mechanism, there is
an upper limit to the apparent relaxation TzA of the brine.
Importantly, this upper limit can be computed using Eqn. (2)
above.
Fig. 3 shows two specific examples: the top curve is for
the case when TZD = 100 ms; the bottom curve is for the case
when T2p = 50 ms. In either case, the apparent T2's for brine
are not longer than the imposed limit.
1'~ Acco:rdingly, in the area where diffusion is the dominant
relaxation mechanism for brine, an upper limit for the
longest Tz for the brine phase can be determined as a
function of TE, G, DW, such that any phase with T2' s longer
than this upper limit is unambiguously identified as not
being brine, i.e., as hydrocarbon. In practical
applications, for diffusion to become a dominant mechanism,
the interecho spacing 'TE must be large, and tree magnetic
field gradient G must also be large.
Fig. 4 illustrates the separation of the brine and oil
spectra in T2 space in accordance with the present invention.
2 ~i
Specifically, Fig. 4a shows a typical brine and oil Tz
spectral distribution. Fig. 4b shows the Tz spectrum when
surface relaxation is dominant for brine. Although the Tz
spectrum is bi-modal, indicating the presence of two fluid
phases, there is a clear area of overlap, so that the two
fluid phases cannot be fully separated. Finally, Fig. 4c
illustrates the case where all of the brine signal appears
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shorter than TZD, clearly identifying the signal due to the
hydrocarbon phase.
Although in the derivations above it has been assumed
implicitly that enhanced diffusion measurements are made
using single-value gradient, or for practical purposes a
spike-type magnetic field gradient distribution, as is the
case for the MRIL° tool, the approach can be extended easily
to tools characterized by a wider gradient distribution, such
as Schlumberger's CMR tool. In such cases, in accordance
with the present invention the TZ limit is determined by the
lowest G value for the gradient, because this value
determines the longest Tz due to diffusion.
More specifically, fo.r gradient-distribution tools,
assuming Gmin < G c Gmax, the upper limit of the apparent TZA
for brine can be found using the expression:
max(T2A) - ~ (Y' m~~~Ts) 2 (3)
which is obtained by rewriting Eqns. (1) and (2). Thus, it
is clear that enhanced diffusion measurements can be
performed using the CMR tool, even though some performance
degradation can be expected due to the gradient distribution.
Two observations are in order for practical applications
of the method of the present invention. First, for gradient-
distribution tools the actual gradient of the magnetic field
2a
may go down to zero at: certain locations. To avoid
mathematical uncertainty, a non-zero value for Gm;I, is used in
Eqn. (3), which value is selected from practical
considerations including an understanding of the distribution
of the magnetic field gradient of the tool.
3U Second, it should be understood that the upper limit in
the apparent transverse relaxation TzA used in accordance with
the present invention need not be a fixed number. Instead,
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this upper limit may take a range of values, and in a
specific application can be determined from actual
measurements parameters and various practical considerations.
For example, in a sp~~cifi~~ embodiment of the method of the
present invention, probabilities associated with a range of
transverse relaxation values are assigned, a:nd the selection
of an actual upper limit value is refined on the basis of
prior measurements and hypothesis testing.
Having described the enhanced diffusion (ED) approach
underlying the present invention, it is instructive to
:10
compare it to the pruor art, and to illustrate its operation
in practical applications. In this re~3ard, reference is made
to the description of. the differential spectrum method (DSM):
Akkurt et al., "NMR logging of Natural Gas Reservoirs", paper
N, presented at the 36th Annual Logging Symposium , Society
of Professional Well Log Analysts, F=~aris, June 26-29, 1995,
and U.S. patents 5,4~~7,087 and 5,498,970.
NMR Signal Ac uisition
In accordance with a preferred embodiment of the present
invention a dual waic.-time pulse sequence is run to collect
the required NMR measurement data. Dual wait-time sequencing
capability not requiY~ing separate loggLng passes is provided
by the MRIL~ tool as descz:~ibed, for ea~~mple, in United States
Patent No. 6,24'2,912, which issued on June 5,2001, assigned to
the assignee of the present application. In alternative
embodiments of the present invention, a single wait-time pulse
sequence can also be used, since there will be T2 separation
between the two phases regardless of an°~ T~ contrast.
The interecho times TE used in the enhanced-diffusion
measurements of the present invention are longer compared
with those used in standard DSM measurements (which typically
are less than about 1.2 msec). Preferably, the TE parameter
of the sequence is selected dependent on the temperature of
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the formation, the magnetic field gradient G generated by the
tool (which is a fun<:tion of the tool diameter, t:he
tempera t ure and the operating frequency for the tool), as
well as the expected viscosity of the oil. Generally, the
higher t he expected oil viscosity, the longer- the TE.
The wait times Tw used in accordance with the present
invention are typically chosen between about 300 and 3000
milliseconds, but can. be made substantially shorter because
T1 separation is not used, and therefore is not an issue in
ED measurements. It should be noted that because the wait
1~0 times Tw for enhanced diffusion (ED) measurements in
accordance with the present invention are much shorter
compared. to conventional DSM or tame-domain analysis (TDA)
applicat ions (roughly about 3.~ seconds for ED compared to 11
seconds for DSM), logging speeds are much faster. This
presents a significant advantage of the system and method of
the present invention. It can be appreciated that because of
the shorter wait times used by ED measurements, the method of
the present invention can also result in increased vertical
resolution at a given logging speed, because more data can be
2~~ collected per unit length.
Additionally, the' number of echoes acquired in ED
measurements in accordance with the present invention is
significantly smaller compared with that for conventional
applications. In a specific embodiment, approximately about
150 echoes are acquired per CPMG sequence. This reduced
number of echoes eases power requirements and allows easier
operation of the tool, which features in turn provide
additional advantages of the ED-based approach of the present
invention.
30~ b) Applications
The ED system and. method of the present invention can be
used instead of or in addition to standard NMR measurements
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in a number of practical situations. The method of the
present invention is particularly well suited for
applications where the Tl contrast disappears or is reduced
for some reason, and the standard DSM approach would fail.
For example, as noted above, in wells drilled with
water-based mud Tl contrasts between brine and hydrocarbons
may disappear, even if the reservoir contains light
hydrocarbons. On the other hand, measurements conducted in
accordance with the present invention can be used
successfully in such cases because they do not rely on a T1
Contrast, but rather on a diffusion contrast, which remains
unaffected. Further, the separation problem encountered in
carbonate rocks where surface relaxivity is several times
lower than that far sandstone is a non.-issue far ED
measurements because diffusion and not surface relaxation is
the dominant relaxation mechanism.
Another application of the ED measurement in accordance
with the present invention is the determination of residual
oil saturation (ROS). Pricar art ROS measurements use a
dopant, such as MnCl2, mixed with water, which mixture is
injected in the borehole. The paramagnetic ions from the
manganese chloride solution shorten the T2 of the brine
phase, Causing separation between the brine and oil phases.
This separation is in effects similar to the ED approach in
accordance with the px-went invention. However, there are
certain problems associated with such prior art techniques
which are obviated by the use of ED measurements.
First, obviously there is no need to inject MnCl2, which
results in potentially significant cost savings. Next, in
the prior art approac~:c the formation has to be drilled with
an overbalance to ensure mud filtrate invasion. Invasion may
30 not occur in low permeability zones, resulting in too high
apparent oil saturatians since water is also interpreted as
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oil. As described above, this is not a problem in ED
measurements.
Another application of the ED measurements in accordance
with the present invention is dealing with vugs in
carbonates. Because ~~f their large pore sizes, water filled
vugs have long Tz's and can easily be misinterpreted as oil.
Given that T2 separat.i.on is achieved, <an oil-filled vug will
not be misinterpreted in ED, since it will have TZ's longer
than the upper limit. On r_he other hand, the T2 value from a
water-filled vug will be less than the determined upperbound
value using the present invention, regardless of whether a
vug is connected or d=Lsconnected. "The present invention
eliminates the possibility of including any water-filled
vuggy porosity in the hydrocarbon volume estimation.
Further, ED measurements in accordance with the present
invention are applicable in cases where the ail is more
viscous . It is well l~.nown that Tz' s for oil decrease as the
viscosity of the oil increases. Ordinarily, the separation
between brine and watE~r using, for example, DSM techniques
would become more difficult for more viscous oils. However,
2G using the ED approach in accordance with the present
invention, up to a limit separation can still be maintained
for high-viscosity oi:l.s by adjusting the user--controlled
parameters so that Eqn. (1) holds.
In this context :it should be noted that the bulk oil
T1/Tz spectrum gets broader with higher viscosity. Given that
Tzo,min <=max(TZA) <_ 'r2o,max~ a portion Of the oil spectrum will
overlap with the water signal. Thus T,;'s longer than max(TZA)
will represent only a portion of the oil signal. However,
in a preferred embodiment of the present:: invention, given the
knowledge of the oil spectrum based on laboratory
3o measurements, the overlapping portion of the oil signal can
be estimated so that an appropriate corx-ection can be made to
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CA 02324015 2003-O1-14
the hydrocarbon volume estimations. This is another
important application of the method of: the present invention.
c) Experimental Data
FIG. 5 is laboratory data from a F~erea sandstone at 100%
water saturation, illustrating the shift in the Tz spectra as
the interecho time TE increases. T'he magnetic field gradient
is about 17 G/cm and temperature is about 60 degrees Celsius.
One can easily see the shift in the TZ spectra as the
interecho time TE inc~~eases. In each case, the longest T2 is
shorter than the theo:reticall.y predicted TzD for water. This
data set illustrates the concept that max(T2A) is predictable
for water.
FIGS. 6 and 7 provide examples of the use of the
enhanced diffusion method used in accordance with the present
1'S invention to separate different fluid phases. For the logs
in both figures, the following apply
GR and caliper in track 1,
Resistivity in Track ~?,
0.6 partial recovery TZ spectra in track 3 (shaded
area) ,
1.2 TE full recovery T~ spectra in track 4 (shaded area) ,
3.6 TE difference spectrum (300 and 3000 ms for wait
times Tw) from ED in track 5 (shaded area).
The perforated zones are shown in the depth track.
Track 2 shading indicates oil production from the test, the
2 !i
Shading in Track 1 indicates water with oil.
The line in the ED track 5 is the predicted TzD for the
TE, temperature and tool conditions. Army signal to the right
of the line is a definite indicator of oil. If all signal is
to the left of the line in Track 4, it is either all water,
3« or water with heavy oi.l, which is nat desirable.
Example 1 (FIG. 6):
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CA 02324015 2003-O1-14
The two zones apparent from the marked perforations show
significant signal to the right of the T2D line in Track 5.
The interpretation from ED was good quality oil and both
zones produced light oil during well tests.
Notice that there is no separation in the 1.2 TE spectra
in Track 4, and that conventional DSM would show a difference
due to both light oil and water.
Example 2 (FIG. 7):
The zone of interest is the sand whose top was
7. 0
perforated. Data from ED difference spectrum has
considerable energy t.o the right of the depth marked A in the
depth track, indicating light oil. There is no signal to the
right of the T2D line below this depth, indicating that there
is an oil/water contact. This is proven by the well test,
1.5 which produced water and oil. The we:Ll should have been
perforated well above the oil/water contact, which is obvious
from the ED data.
The method of the present invention was described above
20 with reference to a TZ spectral analysis. It should be
understood, however, that the principles of this invention
can be applied to time domain analysis techniques, as people
skilled in the art will appreciate. For example, the same
contrast principles can be applied in the acquisition time
domain, where pairs of echo trains can be formed from the
25 dual-TW data by matching corresponding data points, and later
processed by appropriate filters. Time-domain analysis
techniques for DSM that can be used by simple extension for
ED measurements have :been described, for example, in United
States Patent No. 6,242,912 which issued an June 5, 2001, as well as
30 in to Prammer et al., "Lithology-independent Gas Detection by
Gradient-NMR Logging", paper SPE 30562, presented at the 69th Annual
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CA 02324015 2003-O1-14
Technical Conference and Exhibition, :3ociety of Petroleum
Engineers, Dallas, TX, October "~2-25, 7995.
Although the present invention has been described in
connection with the preferred embodiments, it. is not intended
to be limited to these embodiments but: rather is intended to
cover such modifications, alternative:, and equivalents as
can be reasonably included within the spirit and scope of the
invention as defined by the :foll.owing claims.
15
25
3 ()
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