CA2324015C - System and method for identification of hydrocarbons using enhanced diffusion - Google Patents
System and method for identification of hydrocarbons using enhanced diffusion Download PDFInfo
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- CA2324015C CA2324015C CA002324015A CA2324015A CA2324015C CA 2324015 C CA2324015 C CA 2324015C CA 002324015 A CA002324015 A CA 002324015A CA 2324015 A CA2324015 A CA 2324015A CA 2324015 C CA2324015 C CA 2324015C
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- G—PHYSICS
- G01—MEASURING; TESTING
- G01N—INVESTIGATING OR ANALYSING MATERIALS BY DETERMINING THEIR CHEMICAL OR PHYSICAL PROPERTIES
- G01N24/00—Investigating or analyzing materials by the use of nuclear magnetic resonance, electron paramagnetic resonance or other spin effects
- G01N24/08—Investigating or analyzing materials by the use of nuclear magnetic resonance, electron paramagnetic resonance or other spin effects by using nuclear magnetic resonance
- G01N24/081—Making measurements of geologic samples, e.g. measurements of moisture, pH, porosity, permeability, tortuosity or viscosity
Abstract
A method and system is disclosed for the separation of fluid phases in NMR borehole (107) measurements. The invention is specifically applicable to separation of brine from hydrocarbons, using enhanced diffusion to establish an upper limit for the T2 spectral distribution of the brine.
Parameters that can be modified to enhance the diffusion relaxation during the measurements include the inter-echo spacing TE and the magnetic field gradient G (110) of the measurement tool.
Parameters that can be modified to enhance the diffusion relaxation during the measurements include the inter-echo spacing TE and the magnetic field gradient G (110) of the measurement tool.
Description
WO 99/47939 PC1'/US99/06027 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 SUBSTITUTE SHEET (RULE 26) 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, SUBSTITUTE SHEET (RULE 26) 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 _ 3 _ WO 99/47939 PC'TNS99/06027 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.
SUBSTITUTE SHEET (RULE 26) 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 >
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 SUBSTITUTE SHEET (RULE 26) 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, SUBSTITUTE SHEET (RULE 26) 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 _ 3 _ WO 99/47939 PC'TNS99/06027 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.
SUBSTITUTE SHEET (RULE 26) 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.
SUBSTITUTE SHEET (RULE 26) 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 -s-SUBSTITUTE SHEET (RULE 26) 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.
SUBSTITUTE SHEET (RULE 26) 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.
_ g _ SUBSTITUTE SHEET (RULE 26) WO 99/47939 PC1'NS99/06027 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 SUBSTITUTE SHEET (RULE 26) 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 SUBSTITUTE SHEET (RULE 2B) 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.
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 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 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 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, 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 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 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 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 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):
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 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.
3 () -- 2~ -
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.
SUBSTITUTE SHEET (RULE 26) 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 -s-SUBSTITUTE SHEET (RULE 26) 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.
SUBSTITUTE SHEET (RULE 26) 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.
_ g _ SUBSTITUTE SHEET (RULE 26) WO 99/47939 PC1'NS99/06027 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 SUBSTITUTE SHEET (RULE 26) 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 SUBSTITUTE SHEET (RULE 2B) 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.
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 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 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 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, 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 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 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 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 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):
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 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.
3 () -- 2~ -
Claims (27)
1. A method for nuclear magnetic resonance (NMR) measurements of petrophysical properties of a geologic formation comprising the steps of:
determining a set of parameters for a gradient NMR
measurement, which set of parameters establishes an upper limit in the apparent transverse relaxation T2A of a brine phase of the formation;
obtaining a pulsed NMR log using the determined set of parameters; and estimating from the NMR log the contribution of the hydrocarbon phase as distinct from brine on the basis of the established upper limit.
determining a set of parameters for a gradient NMR
measurement, which set of parameters establishes an upper limit in the apparent transverse relaxation T2A of a brine phase of the formation;
obtaining a pulsed NMR log using the determined set of parameters; and estimating from the NMR log the contribution of the hydrocarbon phase as distinct from brine on the basis of the established upper limit.
2. The method of claim 1 wherein the set of determined parameters comprises the interecho spacing TE of a pulsed NMR
sequence.
sequence.
3. The method of claim 2 wherein the interecho spacing TE is determined at least on the basis of the expected viscosity of the oil in the formation.
4. The method of claim 2 wherein the interecho spacing TE is longer than about 0.3 msec.
5. The method of claim 1 wherein the set of determined parameters comprises the magnetic field gradient G of the NMR
measurement.
measurement.
6. The method of claim 1 wherein the upper limit in the apparent transverse relaxation T2A of a brine phase of the formation is established using the expression:
max{T2A} <= T2D
where T2D is the transversal relaxation time component reflecting a diffusion relaxation mechanism, which value is found using the expression:
where Y is the gyromagnetic ratio (=2.pi.×4258 rad/sec/Gauss for protons), D is the brine diffusion coefficient, G is the magnetic field gradient and TE is the interecho time used in the NMR measurement.
max{T2A} <= T2D
where T2D is the transversal relaxation time component reflecting a diffusion relaxation mechanism, which value is found using the expression:
where Y is the gyromagnetic ratio (=2.pi.×4258 rad/sec/Gauss for protons), D is the brine diffusion coefficient, G is the magnetic field gradient and TE is the interecho time used in the NMR measurement.
7. The method of claim 1 wherein the step of estimating comprises the step of determining from the NMR log a distribution of transverse relaxation times.
8. The method of claim 1 further comprising the step of detecting vugs in the formation on the basis of the estimate of the hydrocarbon contribution.
9. The method of claim 1 wherein the step of estimating is done in the T2 spectrum domain, regardless of T1 relaxation properties of brine and hydrocarbon phases.
10. The method of claim 1, wherein the step of estimating is done in the T2 spectrum domain, regardless of weaker surface relaxation property of carbonates.
11. The method of claim 1, wherein water-filled vugs are excluded from estimated hydrocarbon contributions, independent of the size of the vugs.
12. The method of claim 1, further comprising the step of obtaining residual oil saturations directly without forcing T2 shortening agents into the formation.
13. The method of claim 1, further comprising the step of providing a correction to the estimated hydrocarbon-phase contribution to account for an overlap with brine-phase contributions, using laboratory T2 oil-spectrum measurements.
14. A method for separating hydrocarbons from brine in NMR measurements of a geologic formation, comprising the steps of:
determining a set of parameters for a gradient NMR
measurement, which set of parameters establishes an upper limit max(T2A) in the apparent transverse relaxation of the brine;
obtaining a pulsed NMR log using the determined set of parameters; and processing the pulsed NMR log to limit the contribution of brine to components falling below the established upper limit max (T2A)
determining a set of parameters for a gradient NMR
measurement, which set of parameters establishes an upper limit max(T2A) in the apparent transverse relaxation of the brine;
obtaining a pulsed NMR log using the determined set of parameters; and processing the pulsed NMR log to limit the contribution of brine to components falling below the established upper limit max (T2A)
15. The method of claim 14 wherein the set of parameters is determined so as to force diffusion as the dominant relaxation mechanism of the brine.
16. The method of claim 14 wherein the brine separation is established in the T2 spectrum domain, regardless of T1 relaxation properties of the brine and hydrocarbon phases.
17. The method of claim 14 wherein the upper limit max(T2A) is obtained using the expression:
where y is the gyromagnetic ratio (=2.pi.×4258 rad/sec/Gauss for protons), D is the self-diffusion coefficient of the brine phase, G is the magnetic field gradient and TE is the interecho time used in the NMR measurement.
where y is the gyromagnetic ratio (=2.pi.×4258 rad/sec/Gauss for protons), D is the self-diffusion coefficient of the brine phase, G is the magnetic field gradient and TE is the interecho time used in the NMR measurement.
18. The method of claim 17 wherein for NMR measurements in which the magnetic field gradient in the measurement zone is characterized by a distribution of values such that Gmin < G < Gmax, the, upper limit max(T2A) is computed using the expression:
19. The method of claim 14 wherein the set of determined parameters comprises the interecho spacing T E of a pulsed NMR sequence.
20. The method of claim 19 wherein the interecho spacing T E is determined at least on the basis of the expected viscosity of the oil in the formation.
21. The method of claim 19 wherein the interecho spacing T E is longer than about 0.3 msec.
22. An apparatus for measuring petrophysical properties of a geologic formation, comprising:
a probe adapted to be deployed in a borehole, the probe capable of generating a gradient magnetic field and of imparting one or more pulsed NMR sequences having predetermined parameters in said formation;
means for determining an upper limit max (T2A) in the apparent transverse relaxation of a brine phase of said formation; and means for estimating the contribution of a hydrocarbon phase of said formation on the basis of said upper limit max(T2A) and a NMR log obtained using said gradient magnetic field and said one or more pulsed NMR sequences.
a probe adapted to be deployed in a borehole, the probe capable of generating a gradient magnetic field and of imparting one or more pulsed NMR sequences having predetermined parameters in said formation;
means for determining an upper limit max (T2A) in the apparent transverse relaxation of a brine phase of said formation; and means for estimating the contribution of a hydrocarbon phase of said formation on the basis of said upper limit max(T2A) and a NMR log obtained using said gradient magnetic field and said one or more pulsed NMR sequences.
23. The apparatus of claim 22 wherein the upper limit in the apparent transverse relaxation T2A of the brine phase of the formation is determined using the expression:
max{T2A}<=T2D
where T2D is the transversal relaxation time component reflecting a diffusion relaxation mechanism, which value is found using the expression:
where .gamma. is the gyromagnetic ratio (=2.pi.×4258 rad/sec/Gauss for protons), D is the brine diffusion coefficient, G is the magnetic field gradient and T E is the interecho time used in the NMR measurement.
max{T2A}<=T2D
where T2D is the transversal relaxation time component reflecting a diffusion relaxation mechanism, which value is found using the expression:
where .gamma. is the gyromagnetic ratio (=2.pi.×4258 rad/sec/Gauss for protons), D is the brine diffusion coefficient, G is the magnetic field gradient and T E is the interecho time used in the NMR measurement.
24. The apparatus of claim 23 wherein said means for determining an upper limit provides input to a pulse programmer capable of varying the interecho time T E of said one or more pulsed NMR sequences.
25. The apparatus of claim 23 wherein said means for determining an upper limit provides input to a means for varying the magnetic field gradient G generated by the probe.
26. An apparatus for measuring petrophysical properties of a geologic formation, comprising:
a NMR measurement probe adapted to be deployed in a borehole, the probe being capable of generating a gradient magnetic field in the formation, and having one or more antennas for transmitting into and receiving from the formation of NMR signals;
means for determining an upper limit max(T2A) in the apparent transverse relaxation of a brine phase of said formation; and a controller for setting measurement parameters for the probe, which are based on the determined upper limit; and a computer processor for separating the contribution of the brine phase from hydrocarbons on the basis of the received NMR signals and the determined upper limit.
a NMR measurement probe adapted to be deployed in a borehole, the probe being capable of generating a gradient magnetic field in the formation, and having one or more antennas for transmitting into and receiving from the formation of NMR signals;
means for determining an upper limit max(T2A) in the apparent transverse relaxation of a brine phase of said formation; and a controller for setting measurement parameters for the probe, which are based on the determined upper limit; and a computer processor for separating the contribution of the brine phase from hydrocarbons on the basis of the received NMR signals and the determined upper limit.
27. The apparatus of claim 26 wherein said controller comprises a pulse programmer capable of varying the interecho time T E of said one or more pulsed NMR sequences.
Applications Claiming Priority (3)
| Application Number | Priority Date | Filing Date | Title |
|---|---|---|---|
| US7882198P | 1998-03-20 | 1998-03-20 | |
| US60/078,821 | 1998-03-20 | ||
| PCT/US1999/006027 WO1999047939A1 (en) | 1998-03-20 | 1999-03-19 | System and method for identification of hydrocarbons using enhanced diffusion |
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| Publication Number | Publication Date |
|---|---|
| CA2324015A1 CA2324015A1 (en) | 1999-09-23 |
| CA2324015C true CA2324015C (en) | 2004-04-06 |
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| Application Number | Title | Priority Date | Filing Date |
|---|---|---|---|
| CA002324015A Expired - Fee Related CA2324015C (en) | 1998-03-20 | 1999-03-19 | System and method for identification of hydrocarbons using enhanced diffusion |
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|---|---|
| AR (1) | AR014755A1 (en) |
| BR (1) | BR9908942A (en) |
| CA (1) | CA2324015C (en) |
| WO (1) | WO1999047939A1 (en) |
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| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| US6316940B1 (en) * | 1999-03-17 | 2001-11-13 | Numar Corporation | System and method for identification of hydrocarbons using enhanced diffusion |
| CN100349013C (en) * | 2005-05-27 | 2007-11-14 | 中国石油天然气股份有限公司 | Method for determining nuclear magnetic resonance logging T2 spectral T2 end value |
| CN103675722B (en) * | 2013-11-27 | 2016-05-25 | 中国石油大学(华东) | Rock T2-G experiment acquisition parameter automatic matching method |
| CN108062565B (en) * | 2017-12-12 | 2021-12-10 | 重庆科技学院 | Double-principal element-dynamic core principal element analysis fault diagnosis method based on chemical engineering TE process |
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| US4408161A (en) * | 1981-04-15 | 1983-10-04 | Chevron Research Company | Computer-controlled, portable spin echo NMR instrument and method of use |
| US5498960A (en) * | 1994-10-20 | 1996-03-12 | Shell Oil Company | NMR logging of natural gas in reservoirs |
-
1999
- 1999-03-19 CA CA002324015A patent/CA2324015C/en not_active Expired - Fee Related
- 1999-03-19 BR BR9908942-4A patent/BR9908942A/en not_active Application Discontinuation
- 1999-03-19 AR ARP990101239 patent/AR014755A1/en active IP Right Grant
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Also Published As
| Publication number | Publication date |
|---|---|
| BR9908942A (en) | 2000-11-28 |
| WO1999047939A1 (en) | 1999-09-23 |
| AR014755A1 (en) | 2001-03-28 |
| CA2324015A1 (en) | 1999-09-23 |
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