CA2348670A1 - Nmr logging apparatus and methods for fluid typing - Google Patents

Nmr logging apparatus and methods for fluid typing Download PDF

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CA2348670A1
CA2348670A1 CA002348670A CA2348670A CA2348670A1 CA 2348670 A1 CA2348670 A1 CA 2348670A1 CA 002348670 A CA002348670 A CA 002348670A CA 2348670 A CA2348670 A CA 2348670A CA 2348670 A1 CA2348670 A1 CA 2348670A1
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nmr
measurement
parameters
oil
fluid
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French (fr)
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George R. Coates
Lei B. Hou
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Numar Corp
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    • GPHYSICS
    • G01MEASURING; TESTING
    • G01NINVESTIGATING OR ANALYSING MATERIALS BY DETERMINING THEIR CHEMICAL OR PHYSICAL PROPERTIES
    • G01N24/00Investigating or analyzing materials by the use of nuclear magnetic resonance, electron paramagnetic resonance or other spin effects
    • G01N24/08Investigating or analyzing materials by the use of nuclear magnetic resonance, electron paramagnetic resonance or other spin effects by using nuclear magnetic resonance
    • G01N24/081Making measurements of geologic samples, e.g. measurements of moisture, pH, porosity, permeability, tortuosity or viscosity
    • GPHYSICS
    • G01MEASURING; TESTING
    • G01VGEOPHYSICS; GRAVITATIONAL MEASUREMENTS; DETECTING MASSES OR OBJECTS; TAGS
    • G01V3/00Electric or magnetic prospecting or detecting; Measuring magnetic field characteristics of the earth, e.g. declination, deviation
    • G01V3/18Electric or magnetic prospecting or detecting; Measuring magnetic field characteristics of the earth, e.g. declination, deviation specially adapted for well-logging
    • G01V3/32Electric or magnetic prospecting or detecting; Measuring magnetic field characteristics of the earth, e.g. declination, deviation specially adapted for well-logging operating with electron or nuclear magnetic resonance
    • GPHYSICS
    • G01MEASURING; TESTING
    • G01RMEASURING ELECTRIC VARIABLES; MEASURING MAGNETIC VARIABLES
    • G01R33/00Arrangements or instruments for measuring magnetic variables
    • G01R33/20Arrangements or instruments for measuring magnetic variables involving magnetic resonance
    • G01R33/44Arrangements or instruments for measuring magnetic variables involving magnetic resonance using nuclear magnetic resonance [NMR]
    • G01R33/46NMR spectroscopy
    • G01R33/4625Processing of acquired signals, e.g. elimination of phase errors, baseline fitting, chemometric analysis

Abstract

A novel method and apparatus is disclosed for the separation of fluid phases in NMR borehole measurements (1, 8). The method is based on selecting an optimum contrast mechanism and a corresponding set of measurement parameters for a particular borehole environment. The contrast mechanism can be based on diffusion, relaxation time or hydrogen index differences between different types of fluids (2). Once an initial measurement is made, the measurement parameters are compared to a predetermined set of values to broadly the types of fluids present in the geologic environment. If necessary, the measurement is repeated to obtain optimal fluid typing for the estimated fluid types.

Description

WO 00/26696 PCT/US99/2539'7 NMR LOGGING APPARATUS AND METHODS FOR FLUID TYPING
Field of the Invention The present invention relates to nuclear magnetic resonance (NMR) borehole measurements and more particularly to fluid typing based on separation of signals from different fluids using user-adjusted measurement parameters.
Background l0 The ability to differentiate between individual fluid types is one of the main concerns in the examination of the petrophysical properties of a geologic formation. For example, in the search for oil it is important to separate signals due to producible hydrocarbons fiom the signal contribution of brine, which is a fluid phase of little interest.
Extremely valuable is also the capability to distinguish among different fluid types, in P~icular, among clay-bound water, capillary-bound water, movable water, gas, light oil, medium oil, and heavy oil. However, so far no approach has been advanced to reliably perform such fluid typing in all'. cases.
In evaluating the hydrocarbon production potential of a subsurface formation, the formation is described in terms of a set of "petrophysical properties." Such properties may 2o include: (1) the lithology or the rock type, e.g., amount of sand, shale, limestone, or more detailed mineralogical description, (2) the porosity or fraction of the rock that is void or pore space, (3) the fluid saturations or fractions of the pore space occupied by oil, water and gas, and others. Various methads exist for performing measurements of petrophysical properties in a geologic formation. Nuclear magnetic resonance (NMR) logging, which is ~e f°cus of this invention, is among the best methods that have been developed for a rapid determination of such properties, which include formation porosity, composition of the formation fluid, the quantity of movable fluid and permeability, among others.
At least in part this is due to the fact that TfMR measurements are environmentally safe.
Importantly, NMR logs differ from conventional neutron, density, sonic, and resistivity logs in that NMR
logs are essentially unaffected by matrix mineralogy, i.e., provide information only on formation fluids. The reason is that NMR signals from the matrix decay too quickly to be detected by the current generation NMR logging tools. However, such tools are capable of directly measuring rock porosity filled with the fluids. Even more important is the unique capability of NMR tools, such as NUMAR's MRIL~ tool, to distinguish among different fluid types, in particular, clay-bound water, capillary-bound water, movable water, gas, light oil, medium oil, and heavy oil by applying different sets of user-adjusted measurement parameters.
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 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 T" known as the spin-lattice relaxation time. Another related and frequently used NMR logging parameter is the spin-spin relaxation time. TZ (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 2 o site 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 c°mpared to atoms that did not move. This effect contributes to a faster rate of relaxation in a gradient magnetic field.
NMR measurements of these and other parameters of the geologic formation can be done using, far example, the centralized MRIL~ 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, 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, 1!94. Details of the structure and the use of the MRIL~ tool, as well as the interpretation of various measiuement parameters are also discussed in U.S.
patents 4,717,876; 4,717,877; 4,717,8'18; 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 ;~1. and further in "Novel NMR Apparatus for Investigating an External Sample," by Kleinberg, Sezginer and Griffin, J. Magn. Reson. 97, 466-485, 1992.
The content of the above patents is hereby incorporated by reference; the content of the publications is incorporated by reference for background.
It has been observed that the mechanisms determining the measured values of T,, TZ
and diffusion depend on the rnolecular 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, molecuilar 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 T,, TZ and diffusivity values. On the other hand, molecular dynamics 2 0 m 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 the measured signals can provide valuable information relating to the types of fluids involved, the structure of the formation and other well-logging parameters of interest.
It should be clear that th.e quality of the fluid typing depends on the magnitudes of the contrasts between measurement signals from different fluid types.
Generally, as the contrasts increase, the quality o:f the typing improves. Table 1 below shows the ranges of the characteristic parameters for brine, gas, and oil measured by an MRIL~-C
tool under ~'plcal reservoir conditions (i.e., pressure (P) from 2,000 to 10,000 psi, and temperature (T) from 100 to 350'F). Table 2 shows typical parameter values for a Gulf of Mexico sandstone reservoir. The information in the tables clearly reveals a broad distribution for T,, T2, D, and hydrogen index (HI) that is used in accordance with the present invention in fluid typing.
Table I-Ranges of the characteristic parameters of water, gas, and oil measured with an MRIL~-C
tool under typical reservoir conditions Free Bound Gas Oii Water Water Hydrogen -.1 -i <I <-I
Index (Hn Diffusion medium very very low (D) low high Rela:anon medium short long long Time (T,) Relaxation medium short short long 'rime (T,) Table 2-Typical values of characteristic parameters for fluids in a Gulf of Mexico sandstone reservoir T, T, HI De : 10' De T, (ms) (ms) cm'/s cm' Briee i-500 0.67-200 1 7.7 0.0077-4.0 Oil 5,000 460 I 7.9 40 Gas 4,400 40 0.38 I00 440 Despite the existing contrasts, a 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 for a particular measurement parameter there is an overlap in the ranges of the measured 2 o signals from these fluids.
Several methods for acquiring and processing gradient NMR well log data have been proposed recently that enable tlhe 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 T, contrast is due to the fact ~t light hydrocarbons have long T, times, roughly 1 to 3 seconds, whereas T, values longer than 1 second are unusual for vrater-wet rocks. In fact, typical T,'s are much shorter than 1 sec, due to the typical pore size encountered in sedimentary rocks, providing an even better contrast.
Diffusion in gradient magnetic fields provides a separate contrast mechanism applicable to T~ measurements that can be used to further separate the long T, signal discussed above into its gas anti oil components. In particular, at reservoir conditions the WO 00/26696 PCTNS99/2539'7 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 ryas no effect on the T, measurements, the resulting diffusion contrast can be used to separate oil from gas.
The T, and diffusion contrast mechanisms have been used to detect gas and separate fluid phases in what is known as the differential spectrum method (DSM) proposed first in 1995. There are several problems associated with prior art methods, such as DSM. For example, generally DSM requires a logging pass associated with relatively long wait times (TW approximately 10 sec) so that DSM-based logging is relatively slow.
Further, the io required T, contrast may disappear in wells drilled with water-based rnud, even if the reservoir contains light hydrocarbons. This can happen because water from the mud invades the big pores 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 Ph~es are too close and can not be picked robustly. 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 2 o 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.
No single technique seems to solve these and other problems encountered in standard logging practice.
It is apparent, therefore, that there is a need for a flexible apparatus and methods, using different contrast mechanisms, in which these and other problems associated with fluid typing in t:he prior art are obviated.
Summary of the Invention The present invention ins based on using a combination of several different contrast mechanisms in NMR fluid typing measurements of a geologic formation. To this end, in accordance with the present invention, dependent on the specifics of the geologic formation the measurement tool uses different sets of NMR measurement parameters so as to select the optimum contrast mechanism for fluid typing. The contrast mechanisms used in a preferred embodiment include T~, 'rl, D, HI, and viscosity t~ contrasts, which are fundamental to fluid typing. Ire a preferred embodiment, the present invention uses Numar Corporation's MRIL~ tool because of its capability to make mufti-contrast measurements.
io Appropriate selection of pulse sequences, such as CPMG, and acquisition parameters, such as pulse waiting time (TW ) and echo spacing time (TE), allows the acquisition of weighted spin echo data with different contrasts.
In particular, in accordance with a preferred embodiment, a method for fluid typing of a geological environment is disclosed, using nuclear magnetic resonance (NMR) measurements. The method comprises: determining a set of parameters for a gradient NMR
measurement, obtaining a pulsed NMR log using the determined set of parameters; and selecting from the NMR log an optimum contrast mechanism and corresponding measurement parameters for fluid typing of the geological environment. In a preferred embodiment, the set of determined parameters comprises the interecho spacing TE of a 2 0 Pulsed NMR sequence, the magnetic field gradient G and the wait time TW of the NMR
measurement. 1~urther, in a pre:Perred embodiment, the optimum contrast mechanism used in the method is based on diffusion, relaxation or hydrogen index contrast.
In another aspect of this invention, a method for fluid typing of a geological environment is disclosed using nuclear magnetic resonance (NMR) measurements, where ~e method comprises: conducting a first NMR measurement using a first predetermined set of measurement parameters; comparing the first NMR measurement results to a predetermined set of criteria applicable for different fluid types to estimate candidate types of fluids that may have produced the first NMR measurement results; selecting an appropriate type: of contrast mechanism and a corresponding second set measurement 3 o p~~eters for the estimated types of fluids; and conducting a second NMR
measurement using the second set of parameters to increase the accuracy of the fluid typing determination in case the second set of parameters is different from said first set of parameters. In a preferred embodiment, the first and the second set of parameters correspond to one or more of the DSM, E;DM, SSM, TPAZ, and ICAM fluid typing methods, as described below.
In another aspect, the present invention is directed to a computer storage medium storing a software program to ~be executed on a computer, comprising: a first software application for capturing NMP; data concerning a first measurement; a second software application, for comparing the first measurement data to pre-set rules determining the optimum contrast mechanism for use in the environment; and a third software application, for providing a predetermined set of measurement parameters according to the determined optimum contrast mechanism.
In another aspect, the present invention is an apparatus for fluid typing of a geological environment using nuclear magnetic resonance (NMR) measurements comprising: a logging tool capable of conducting NMR measurements in a borehole; data storage for storing NMR log data corresponding to one or more NMR measurements each measurement using a predetern~ined set of measurement parameters; a computer processor configured to execute a software application program for selecting from NMR
log data an optimum contrast mechanism and corresponding measurement parameters for fluid typing of the geological environment; and a measurement cycle controller providing control signals to the logging tool for conducting NMR measurements based on input from said processor.
~ 0 In a preferred embodiment, the apparatus comprises a display for indicating the selection of measurement parameters to a human operator, and the logging tool has a dual wait-time sequencing capability.

Brief Description of the Drawvings 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 illustrates the principles used for fluid typing in the Differential Spectrum Method (DSM) of the present invention.
FIG. 2 shows log data and DSM data obtained through TZ-domain processing.
FIG. 3 is an example of using Time Domain Analysis (TDA) of DSM data to find gas, oil, and water-wet zones.
FIG. 4 illustrates the principles used for fluid typing in the Enhanced Diffusion 1 o Method (EDM) of the present invention.
FIG. 5 shows an EDM application using TZ dornain analysis.
FIG. 6 is a comparison between the TZ domain and TDA approaches for determining residual oil saturation (ROS) in accordance with the present invention.
FIG. 7 chows a typical application range of EDM in accordance with the present invention.
FIG. 8 illustrates the principles used for fluid typing in the Shift Spectrum Method (SSM) used in accordance with the present invention.
FIG. 9 illustrates pulse sequences used in accordance with the present invention for the Total Porosity Method (TP:M).
2 0 FIG. 10 illustrates a data processing mechanism used in accordance with the present invention as part of the TPM.
FIG. 11 illustrates a TZ spectrum obtained through TPM.
FIG. 12 is an example of using MnCl2 in an Injecting Contrast Agent Method (ICAM) used in accordance with the present invention for obtaining Residual Oil Saturation 2 5 (ROS) and porosity.
FIG. 13 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. 14 is a block diagram of the apparatus in accordance with a preferred 3 o embodiment, which shows individual block components for controlling data collection, processing the collected data arid displaying the measurement results.
_ g _ DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS
A. The System Reference is first made. to Fig. 13, which illustrates an apparatus constructed and operative in accordance with a specific embodiment of the present invention for obtaining multi-contrast nuclear magnetic resonance (NMR) measwements. 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 barehole.
The first portion 106 comprises a magnet or a plurality of magnets 108, which l0 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 8i'adient at the volume of investigation 109. This additional contribution to the magnetic field, which is essential for the fluid typing methods of the present invention using diffusion, has a field direction :preferably collinear with the substantially uniform field and has a substantialy uniform magnetic field gradient. The magnetic field gradient may or may not be pulsed, i.e., switche;d on and off by switching the do current flowing through the 2 0 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 field gradient generating coils 1.10. 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 3 o 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 _ g 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. RecE;iver 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 S0. Some or all of the elements described hereinabove as 1o being disposed in an above-ground housing, may instead be disposed below ground.
Fig. 13 depicts one embodiment of the apparatus used in accordance with the present invention. In an alternative preferred embodiment, in accordance with the present invention, various models of the MRIL~ tool to Numar Corporation, or other tools known in the art, can be used instead. Fig. 14 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., 14 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 relocation characteristics of the material being investigated.
2 0 The output of the data processor 52 is provided to the parameter estimator 54. In accordance with the present invention, data processor 52 operates in conjunction with parameter estimator 54 to detei~nine an optimal contrast mechanism to be used for fluid typing in the particular borehole environment. As discussed in more detail below, several different contrast mechanisms can be used in a preferred embodiment. The selection of a sm~ble contrast mechanism by the data processor is then translated into the selection of a corresponding data acquisition technique, and/or a different set of measurement parameters.
Dependent on the selecl:ed data acquisition technique, 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, ~'~'~ch is capable of providing a graphical display of one or more measurement parameters, possibly superimposed on display data from data storage 56. Accordingly, the selection of the optimal contrast mechanism for a particular measurement can be done by a human operator, or automatically, pursuant to a pre-set number of rules.
The components of the system of the present invention shown in Fig. 14 can be implemented in hardware or software, or any combination thereof suitable for practical s purposes. Details of the structure, the operation and the use of logging tools, as illustrated in Figs. 13 and 14 are also discussed, for example, in the description of the MRIL~ tool to Numar Corporation, and in U.S. patents 4,717,876; 4,717,877; 4,717,878;
5,212,447;
5,280,243; 5,309,098; 5,412,3 20; 5,517,115, 5,557,200 and 5,696,448, the contents of which are incorporated herein for all purposes.
In a prefen:ed embodirr~ent of the present invention the selection of the optimum contrast mechanism for use in fluid typing in a particular borehole environment is done by comparing resats from a first IVMR measurement to a predetermined set of criteria applicable for different fluid types. The criteria used in a preferred embodiment are based on the theoretical models, which are discussed in further detail next, as well as other types of measurements, prior experience, and other available information. At this stage, the apparatus of this invention determines broadly the type of fluids that may have produced the first NMR measurement results and then, if necessary, selects the appropriate type of contrast mechanism and con es,ponding measurement parameters to possibly increase the accuracy of the fluid typing determination. In some instances, this may lead to a second 2 0 measurement pass with a different set of measurement parameters. In a preferred embodiment, the selection criteria can be implemented in software, using a rule based (i.e., if.... then) approach in accordance with the models discussed next.
Preferably, the software used in the present invention is stored in a computer storage medium for execution on a computer, such as data processor 52.
In a specific embodiment, the fluid typing program of the present invention comprises: a first software application for capturing NMR data concerning a first measurement; a second software application, for comparing the first measurement data to pre-set rules determining the oFrtimum contrast mechanism for use in the environment; and a third software application, for providing a predetermined set of measurement parameters 3 0 according to the determined optimum contrast mechanism.

B. The Methods in accordance with the present invention, fluid typing for detecting and quantitatively measuring volumes occupied by brine, gas, and oil is done using several different methods, which are based on nuclear magnetic resonance (NMR) logging data. In particular, the methods of the present invention include Differential Spectrum Method (DSM), Enhanced Diffusion Method (EDM), Shifted Spectrum Method (SSM) in transverse relaxation time; (TZ) domain or in spin-echo time domain (i.e., Time Domain Analysis;
TDA), Total Porosity Measurement (TPM), and Injecting Contrast Agent Method (ICAM).
Generally, DSM is used in accordance with the present invention for gas and light oil; EDM
is used for medium oil; SSM for gas and oil; TPM for bound water, including clay-bound water and capillary-bound water, and movable fluids; and ICAM for residual oil saturation (ROS) measurements. Each of these methods and the associated contrast mechanisms are discussed in more detail next. A brief summary of the contrast mechanisms used in accordance with the present invention is presented next to help understand the individual fluid typing methods.
Contrast Mechanisms (a7 The HI Contrast The HI contrast associated with a particular molecule is a function of the molecule's 2 0 mss density, as well as the nwnber of hydrogen nuclei (protons) in the molecule. For a pure hydrocarbon, it has been shown (see, e.g., Kleinberg, R.L., and Vinegar, H.J.: "NMR
Properties of Reservoir Fluids," The Log Analyst (November-December, 1996) that HI = p*nH/0.11*'MW (1) where p, MW, and nH are mass density, molecular weight, and number of hydrogen atoms in ~e molecule, respectively. Thc: above Eq. (1) has been modified the equation for oil:
HI = p*[R/(12.011 ~ 1.008 R)] /0.11 (2) where R is the ratio of hydrogen atoms to carbon atoms in the oil. For additional information, see, for example, Lo, S.W., et al.: "Some Exceptions to Default NMR Rock and Fluid Properties," paper FF presented at the 39'" Annual SPWLA Logging Symposium, Keystone, Colorado, U.S.A., 2629 May 1998, which is incorporated herein for backgound.

(b) Relaxation Times Contrasts The contrasts of the relaxation times (T, and Tz) result from different relaxation mechanisms that dominate in the fluids. The Tz of a fluid in a rock has been expressed as l /Tz = 1 /Tzs + 1 /Tz~ + 1 /TzD 3 where Tzs is the contribution from the surfaces of the pore wall and the clays, TzB is the contribution fr°m the bulk fluid, and T~ is a term related to molecular diffusion in a magnetic gradient field. This gradient is either an external gradient, such as the lineal gradient produced by an MRIL~tool, or an internal gradient from clays. Bulk relaxation (TzB) is from either the magnetic dipole-dipole (DD) interaction for liquids or the spin-to rotation (SR) interaction for gases. For a liquid in a low magnetic field from the MRIL~
tool, the TzB component is given by (1/Tz)Db "' Y4 * ~:~* r ~ (4 where y is the proton gyromagnetic ratio, i~ is the rotational correlation time, and r is the distance between the spins.
For a gas, the Tza component is given by the expression (1/Tz)sx "' I * T * Cz~~,* ~:r where I is the moment of inertia of the molecule, C~n is the effective spin-rotational coupling constant, and i1 is the angular-momentum correlation time. For background ~°~ation, see Bloembergen, N., Purcell, E.M., and Pound, R.V.:
"Relaxation Effects in Nuclear Magnetic Resonance A.bsorption," Physical Review, ( 1948) 73, 679.
The bulk relaxation of oil is a main contribution to T2 for a water-wet reservoir. The relationship between the Tz of an oil and the viscosity of the oil has been expressed as Tz = 1.2 *(T /298 *r)) °.9 (6) See Morriss, C.:E., et al.: "Hydrocarbon Saturation and Viscosity Estimation from NMR
Logging in the Belridge Diatomite," The Log Analyst (March-April, 1997) .
Equation 6 is valid only for dead oil and for oil with uni-exponential decay. For oil having a distribution of Tz values, Tz in the equation should be considered as the geometric mean of the distribution.
The surface term Tzs in Eq. (3) above is given by the expression:
Tzs - (Pz*S/Vp) -' (7) where p2 is the NMR surface relaxivity for T2, Vp is the pore volume, and S is the surface of the pore or clay. For a sphere, S/Vp is 3/r, and r is the pore radius. In a fast-diffusion case, this equation sets up a relationship between the TZ distribution and a pore size distribution.
For background, see, e.g. Kenyon, W. E.: "Petrophysical Principles of Applications of NMR
Logging," The Log Analyst (March-April 1997).
When using a Carr-Purcell-Meiboom-Gill (CPMG) pulse sequence and existing a linear gradient G, the diffusion term in Eq. (3) is given by T2D = 12/[D*(~'°"TE*G)2] (8) where D is a self diffusion coefficient, and TE is an echo-spacing time.
The T2~, term shown in Eq. (8) is the only term in Eq. {3) that can be controlled by the user of an MRIL~ tool. In particular, in accordance with the present invention, the user can change TZD by adjusting the TE and G parameters of the tool. Details concerning the modification of these parameters are discussed in several patents to the assignee of the present application, which are incorporated by reference herein.
is In accordance with the present invention, in a water-wet reservoir, the Tz parameter of the brine ph~cse is generally determined by TZS; the TZ of oil is obtained from T2B, and the T2 of gas is approximately equal to TZD~
The T, of a formation fluid is described by 1/T, = 1/T,s + 1~'T,B (9) A diffusion term is not included in this equation because diffusion involves a spin dephasing process, which is a TZ process.
The equations for T,B for bulk liquids and gas in the low magnetic field are analogous to Eq. 4 and 5 for'r2,~. T,s is the surface relaxation contribution, and is given by ~~~s - (Pc*S/Vp) w' (10) where p, is the surface relaxivit;y for T,. For a gas, T, is generally controlled by the T~B
component. As. known in the art, T, can also be described by the following equation:
'.C, =2.5*103 *p/T'~" (11) where T, is in seconds, the density p is in g/cm', and the temperature (T) in degrees Kelvin.
This equation reveals that temperature and pressure (the density term in the equation is related to pressure) have opposite effects on T,.

T, of gas is very long because of the small angular-momentum correlation time (i~) of gas. In a water-wet reservoir, T, of oil is obtained from bulk relaxation and can be written as T, = 1.2*T/298*rl (12) T, of brine is determined by the surface term. The T,/TZ ratio of brine ranges from approximately 1 to 1.5. For additional background, see for example Kleinberg, R.L., et al.:
"Nuclear Magnetic Resonance of Rocks: T, vs. T2," paper SPE 26470 presented the 1993 SPE Annual Technical Conference and Exhibition, Houston, Texas, U.S.A., 3-b October 1993.
(cl Diffusion Contrast It is known in the art that the contrast of D generally depends on molecular mobility.
Hence, D is a function of tempE:rature T, pressure P, and the environment, in which the diffusion molecule exists. The diffusion relaxation mechanism depends on the diffusion of molecules in magnetic field gradients, such as those generated by the MRIL~
tool.
Ordinarily, diffusion is a predominant relaxation mechanism only for gas. For the fast-diffusion case, :D of gas is given by the known expression DB = 8.5* 10'' *T °.9/P 13 ( ) D of oil is 2 0 loo = 1.3 T/298*y ( 14) and D of movable water (mw) is DmW = 1.2 T/298*'1~ (15) Generally, gas and water each have only one value of D for a certain T and P.
However, an oil has a distribution of D because of the many different types of molecules in 2 5 ~e oil. In oil, the Do in Eq. ( 14) should be considered, in accordance with the present invention, as the value of the geometric mean of this distribution.

1. The Differential Spectrum Method fDSMI
In principle, DSM is a T,-contrast weighed method. The information in Tables 1 and 2 shows that gas and light oil each have a T, much larger than that of brine.
Hence, in accordance with the present invention, the method is used for typing gas and light oil. For a detailed discussion of aspects of this method, the reader is directed to U.S.
Patent No.
5,497,087 and 5,498,960 to Vinegar et al., and to co-pending patent applications Ser. Nos.
08/822,567 and 09/270,616 to the assignee of the present application, which are hereby incorporated by reference.
Magnetization in a CPMG spin echo train for a reservoir having three phase (brine, io gas, oil) can be; described by M(n*TE) ~ [1 - exp(-Tw /T,b)]*exp(-n*TEIT~b) +
HIg*[1 - exp(-Tw /T,g))*exp(-n*TE/TZAg) +
I-IIo*[1 - exp(-Tw /T~o)]*exp(-n*TE/T2Ao) (16) where A, b, g, and o in the subscripts represent apparent, brine, gas, and oil, respectively, and n is echo number. According to this equation and the values in Table 2, the brine phase can be eliminated and the oil and gas phases can be still left in a differential echo train from two CPMG acquisition data if'Tw, » T,b and Tw2 » T,bbut Twl > Twz ~ Tig and Tw, >
Twz ..,.. Tao.
For a Gulf of Mexico sandstone reservoir, it has been suggested that optimum Two ~d Twz values are 1 second and 8 seconds, respectively. This experimental result has been suggested in, for example, Akkurt, R., Prammer, M.G., and Moore, M.A.:
"Selection of Optimal Acquisition Parameters for MRIL Logs," The Log Analyst (November-December 1996) . When such Tws are used in CPMG pulse sequences, the brine signal can be eliminated by taking the difference of the two echo trains. The resulting hydrocarbon signals in the difference can be still large. The remaining oil and gas signals are very well separated from each other in a 'r~ spectrum.
Fig. 1 illustrates the principle of the DSM used for fluid typing in accordance with the present invention. In Fig. 1 (a), all three phases have a fully polarized Tz spectrum at the long Tw,. In Fig. 1(b), the brine is still fully polarized, but the oil and gas are partially 3 o p°l~zed at the Tw2 Fig. 1 (c) is the difference between the spectra in Figs. 1 (a) and 1 (b), and shows the reduced and separated oil and gas signals.

WO 00/26696 PCT/US99/2539?
DSM Data Acguisition and Data Processin,.g The data needed for DS~M processing in accordance with the present invention consists of two spin echo trains acquired with two different Tw CPMG pulse sequences. The TW' s that are used must satisfy the following conditions: Tw, » Twz » T,b , Tw2 < ~T,o, Tw2 < ~T,g , TWO, ~ 2T,o , and Tw, ~- 2T,g. The TE parameter is chosen in a preferred embodiment to be approximately 1 ms to limit diffusion influences on T2. The number of echos depends on the longest T'2 (TZ~) in the formation, and is chosen in a preferred embodiment to satisfy the condition (n*TE) z TzL.
As known in the art, in the DSM, data is processed either in a T2 domain or in a time 1o domain. The processing done in a time domain is referred to as a time domain analysis (TDA).
In accordance with the present invention, processing in the TZ domain analysis involves inverting two spin echo trains to two T~ spectra and then subtracting one spectrum from the other. The process is ;~.s illustrated in Fig. 1. The inversion algorithm used in a preferred embodiment is known in the art and is discussed, for example in Prammer, M.G.:
"NMR Pore Size Distributions .and Permeability at the Well Site," paper SPE

presented at the 1994 SPE Annual Technical Conference and Exhibition, New Orleans, Louisiana, U.S.A., 25-28 September 1994.
In accordance with the present invention, TDA processing method is preferred to 2 o T2-domain processing for detecting gas. The first step in the TDA
processing method is to obtain the echo difference from two Tw spin echo trains. Careful Tw selection ensures that the echo difference contains only gas and light-oil signals. In a preferred embodiment, two matched filters are built based on the T,s and the TZs parameters of the oil and the gas:
f(t)o - (exP(- Twn'm) - exp(-Tw2/T,o]*exp(-t/T~) (17) 2 5 ~d f(t)g = HIB* (exp(-Tw,/T,g) - exp(-Tw2/T,B]*exp(-t/T2g) (18) Use of these filters on the echo difference d(t) allows oil-filled porosity (Po) and gas-filled porosity (f J to be obtained through the matrix equation (f(t)o f(t)8] * (Po Pg] ~' = d(t) ( 19) 30 For a more detailed description of the method, the reader is directed to U.S. Patent application Ser. No. 08/822,567 to the assignee of the present application, which is incorporated herein for all puposes. The oil and gas porosities obtained through Eq. 19 are more robust than those from T;, domain analysis, which usually uses more than ten T2 values (bins) to obtain ten corresponding porosity solutions.
In accordance with the ;present invention, DSM can be used for determining gas volume. See A.kkurt et al. "NMR Logging of Natural Gas Reservoirs," Paper N
presented at the 36'" Annual SPWLA Logging Symposium, Paris, France, 2b-29 June 1995, which reported using data from a gradient-based MRIL~-C logging tool, to identify the gas phase in a Gulf of Mexico sandstone reservoir. Fig. 2 shows some of the log data and some of the DSM data obtained through TZ -domain processing. The first three tracks (from the left) contain the gamma ray (GR), induction resistivity, and neutron and density logs, respectively. The TZ distributions (spectra) for TW = 6 and 3 seconds are displayed in Tracks 4 and 5, and the; difference of the two Tz spectra (differential spectrum) is shown in Track 6.
The signals in the differential spectrum range from approximately from 32 to 64 ms, which is in the range of gas signal for this tool with acquisition parameter {TE) used and formation temperature that was encountered. All information indicates a gas-bearing zone in the top section of this presentation.
In accordance with the present invention, the TW selections must be optimized for the specific case. For example, it was determined that the 3 and 6 seconds in the case illustrated above must be replaced with data obtained with TW values of 8 seconds and 1 2 0 seconds for better results for gas detection in the Gulf of Mexico.
Generally, Tz domain analysis on DSM data is not sensitive to the gas signal because the signal is weak and is usually suppressed in the bound water region of a TZ
spectrum.
TDA has been applied on DSM data from a highly laminated Gulf of Mexico turbidite invaded with synthetic oil filtrai:e. It has been determined that the conventional TZ domain 2 5 ~ysis did not clearly detect flue gas signal. However, TDA did show unambiguously both heavy filtrate invasion and the presence of gas where gas saturation was very low.
Fig. 3 is an example of using TDA of DSM data to find gas, oil, and water-wet zones in accordance with a specific embodiment of the present invention. In this figure, the first two tracks of the log present logging-while-drilling (LWD) gamma ray and resistivity 3 o data' and the third track plots effective porosity obtained by TDA. The gas/oil contact (GOC) and oil/water contact (O'WC) were identified by TDA. The echo difference for the WO 00/26696 PC'T/US99/25397 gas, the oil, and the brine zone are shown in Figs. 3(a), 3(b), and 3(c), respectively. The echoes in 3(a) and 3(b) were fitted by the matched filters shown as Eqs. 17 and 18 for the porosities occupied by the gas and the oil.
Because the DSM requires a large T, contrast, a large diffusion contrast, and a good signal-to-noise ratio (S/N), viable candidates for DSM applications are gas and light-oil reservoirs. In accordance with the present invention, the bulk viscosity of the reservoir oil should preferably be less than about 1 cp, and the apparent gas porosity should be greater than about 1 porosity unit (p.u.) for optimal results.
io 2. The Enhanced Diffusion Method (EDM_) In accordance with the present invention, the EDM is used for typing medium oil.
In principle, the EDM uses diffusion contrast for determining the porosity occupied by a medium oil (i.e., 1 cp < ~ <50 c;p). According to Eq. 3, TZ is smaller than each of T2B, TZS, and TzD. In accordance with the present invention, the parameters G and TE of the measurement device can be adjusted to make TZD a small value for any fluid phase.
Through such an adjustment, an upper bound for the TZ spectrum of any phase can be established. Because TZD depends on D, which is a function of temperature and phase, the upper bound shifts according to~ the phase. For example, at 200'F, the values of D for brine, gas, and 10 cp c»1 are 7.7x 10'5, 100x 10's, and 0.1598X 10'5 cm2/s, respectively. If G = 18 2 o gauss/cm and TE = 4.8 ms, Eq. 8 shows that the upper bounds for TZD for brine, oil, and gas are TZD,b = 29.2 ms, TZD,o - 1,406 ms, and TZD,g = 2.25 ms. Hence, TZD,g is located toward the low end of a TZ spectrum and T,,~,o is located the high end of the spectrum, and there is a gap between the TZC,,o and the TZn,b~ Because of the influence of noise, the actual upper bound for a brine phase can be ~2*TZD,b~
2 5 In the numerical example being considered here, the oil and the brine are well separated because TZ,o = [(1/TZD,o) + (1/TZH,o)~ = 140 ms » 60 ms = ~2*T2n,b-Oil-filled porosity is obtained by integrating the area under the peak.
In summary, the EDM uses differences in diffusion coefficients among the phases for setting up T~. upper bounds fbr the phases. As long as the TZ of an oil is larger than 30 ~2*TZD,b' ~e oil-filled porosity c;an be obtained from its separated peak.

Fig. 4 illustrates the principle of the EDM. Fig. 4(a) depicts a Tz spectrum without diffusion influence (G*TE ~ 0). Fig. 4(b) shows the Tz spectrum with diffusion influence (G*TE » 0). The vertical line; in Fig. 4(b) is the TZD,b, to the right of which is a separated oil peak.
EDM Data Ac~c uisition and Processing If only a qualitative analysis is needed, EDM data are acquired in accordance with the present invention with TW -v~*T,,,~,8,~, where T,,M~ is the maximum value of a T, spectrum for all phases, and with a large TE for separating oil from the other phases.
However, for a quantitative analysis and a fast logging speed, in accordance with the present invention EDM are acquired with two TWs (typically, 5000 ms and S00 ms) and a long TE
(usually 4.8 ms) in two CPMG pulse sequences. In accordance with a preferred embodiment of the present invention a dual wait-time pulse sequence is run to collect the required NMR
measurement data. Dual wait-time sequencing capability not requiring separate logging Poses is provided by the MRIL,~ tool as described, for example, in co-pending application Ser. No. 08/822,567 assigned to the assignee of the present application, which is incorporated herein for all purposes. In alternative embodiments of the present invention, a single wait-time pulse sequence; can also be used, since there will be TZ
separation between the two phases regardless of any T, contrast. Because the method to acquire data is the 2 0 ~e as the one used in the DSlvi, the data processes are nearly identical except that a correction for the short component of T~ of oil must be considered. More detail concerning the EDM method is found in the co-pending patent application Ser. No.
09/270,616, filed March 17, 1999, the content of 'which is incorporated herein by reference.
Because the oil targeted for detection by this method usually has a T, distribution 2 5 fat includes a long component and a short component, two T, corrections must be made in accordance witr~ the present invention for whether the processing is performed in TZ domain or in time domain. In a specific embodiment, the first correction is applied to the long T, component of the oil, which has a large D. The second correction is applied to the short component (which has a small i)) so that it mixes with the water signal. In the second 3 0 correction, the T, distribution of the oil is needed to determine the contributions of the short components. Details of the T, corrections can be found, for example in the above application.
Applications An EDM application in which TZ domain analysis was used in accordance with the present invention is shown in F'ig. 5. In this figure, the gamma ray, resistivity, and porosity logs shown in '.Cracks 1, 2, and 4 suggest a possible hydrocarbon zone at around X036.
Track 3 contains the differential spectrum from the EDM logs acquired with TE
= 3.6 ms and TW = 300 ms and 3,000 ms. The dashed vertical line in Track 3 represents T2n,b- 44 io ms. The oil signal is clearly seen to the right of this line. From the differential spectrum, a water/oil contact is identified at around X036, and 10% oil is produced in the surrounding interval.
Fig. 6 is a comparison between the Tz domain and TDA approaches for determining residual oil saturation (ROS) in accordance with the present invention. Tracks l and 2 contain the gamma ray and resistivity logs, while Track 3 displays the differential spectrum for TW = 5,000 and 500 ms and TE = 4.8 ms. Three apparent oil volumes are plotted in Track 4. The solid and dotted curves represent the oil volumes obtained from TZ domain analysis using data acquired with TW = 5,00 ms and 5000 ms for TE = 4.8 ms and 3.6 ms, respectively. The dashed curve was obtained from TDA on the data sets of TE =
4.8 ms. In 2 0 ~s example, these curves demonstrate that the two processing methods yield almost the same oil volume.
It should be noted that from a quantitative point of view, the oil porosity from a TZ
domain analysis may not be very accurate because the value of TZn.b can be influenced by an internal gradient. Accuracy can also be adversely affected by noise. Portion of brine's TZ
2 5 c~ be larger than TZD,b. These considerations should be taken into account in practical applications.
As noted above, the DSIvI provides typing of gas and light oil. The EDM
expands the fluid-typing range to medium oil. Fig. 7 shows a typical application range of EDM. To plot this figure, Eq. 6, 8, and 14 are used with TE = 3.6 ms, G = 19.1 gauss/cm, T = 200° F.
3 o If the oil-water 'TZ contrast is chosen as 2, then the EDM can be applied to type oil with WO 00126696 PCT/US99/2539'7 viscosity from approximately ~0.4 to 40 cp, with the maximum contrast occurring between 4 and 10 cp.
In accordance with the present invention, the EDM can be applied in carbonate reservoirs. Note that DSM typing may not give good results in such reservoirs because of long TZ and T, components for the brine phase. This is an example of how the flexibility provided by the present invention enables accurate analysis of the formation fluids dependent on the particular conditions.
3. The Shift Spectrum Method to In accordance with the present invention, the SSM is used for gas and oil typing.
In principle, the SSM is also a diffusion contrast method and thus is suited for use with the gradient NMR tools. In a prefc;rred embodiment, it applies two different TEs and a long TW
z (2 to 3)*T,,Max in two CPMG pulse sequences. Relating to the TZ spectrum that results from the short 'TE, the TZ spect;rum from the long TE due to diffusion effect is shifted to the low end of the 'T2, and the spectrum is also compressed. If the gas signal is shifted to the dead time of an MRIL tool when collecting long TE data, then the gas signal cannot be detected in the :long TE data; however, the gas signal is present in the short TE data. By taking the difference between the long and short TE data and ignoring the diffusion influence of brine and oil, only gas signal is obtained.
2 0 The net magnetization for the difference of the two CPMG trains is L'M(t) = ~rM~,;,~,,,,g*
{exp{-t*[1/T2B,;+D~*(Y*TE,*G)2/12+1/T2S,;1} -exp {-t*,[ 1 /T2B, +D;*(Y *TEZ* G)2/ I 2+1 /TZS,;] } } 20 ( ) If TE,=1.2 ms and TEZ=2.4 ms, and the values of the parameters in Table 2 are used, 2 5 den L~M(t)g= Moa*exp{-t*[D;*(Y*TE,*G)2/12]} {21) t1M(t)o = Mforo*exp(-t* 1/TZH,o)*
{e;xp{-t*[Do*(Y*TE,*G)2/12]} -e~:p{-t*[Da*(Y*TEZ*G)Z/12]} }
3 0 ~ 0 (22) M(t)b ' Mo,b*exp(-t*1/TZS.n)*
{exp{-t[*Db*(y*TE,*G)Z/12]} -e:xp{-t* jDb*(y*TEZ*G)2/12] } }

(23) Hence, for these two T>r? values, when oil and brine diffusion influences on TZ can be ignored, only gas signal is left in OM(t).
Fig. 8 illustrates the principle of SSM used as a fluid typing method in accordance with the present invention. The: solid curve, shown as 'a' in the figure, represents the spectrum obtained when TE = 1.2 ms, and the dashed curve, shown as 'b', represents the 1 o spectrum obtained when TE = 4.8 ms. The 40 ms peak in the solid curve is gas and is shifted out in the 4.8 ms spectnun. The gas signal is found by subtracting the dashed curve from the solid curve.
Data Acquisition and Processing Data for use in the SSM are usually acquired with TE set at 1.2 and 3.6 ms and TW =
8s. This method has a much longer pulse cycle time, which is the time for acquiring two CPMG data set.5. The cycle time is approximately 16 seconds for SSM, but only 5.5 seconds for EDM. SSM data can be processed in accordance with this invention by either TZ domain analysis or TDA. In a preferred embodiment, the processing is the same as for 2 0 ~e DSM, except that the matched filter in TDA for gas is different because the diffusion influence on SS:M must be considered .
Applications In accordance with the present invention, the SSM can be applied to determine gas signals. See, e.g. Mardon, D., et al.: "Characterization of Light Hydrocarbon-Bearing Reservoirs by Gradient NMR Well Logging: A Gulf of Mexico Case Study," paper SPE
36520 presented. at the 1996 SPl? Annual Technical Conference and Exhibition, Denver, Colorado, U.S.A., 6-9 October :1996. In the above reference, TE =1.2 and 2.4 ms is used in CPMG pulse sequences to obtain two TZ spectra. Comparing the spectra and using gamma 3 0 ray, resistivity, and neutron-density logs, it was found that the water and light-oil signals remain, but the gas signal is shifted to below detectable levels for the 2.4 ms data.

WO 00/26696 PCTlUS99/25397 SSM dual-TE logging is more useful in a more viscous oil (rl ~ 20 cp). Such oil has a much smaller diffusion coefficient than water. By using the diffusion contrast between water and the more viscous oil, an empirical crossplot of TZI and D can be created, where TZI = [1/T~ +1/TZS]-'. See Coates, G.R., et al.: "Applying Log Measurements of Restricted Diffusion and Tz to Formation lEvaluation," paper P presented at the 36'"
Annual SPWLA
Logging Symposium, Paris, France, 26-29 June 1995. T'he following two equations were used to calculate Tz, and D from the data sets acquired with two TE values.
1;11T2).,.m = 1/T2, + D*(Y*TE,*G)2/12 (24) (:1/Tz).i.E2 = 1/Tz, + D*(Y*TEZ*G)z/I2 (25) Water saturation and pore size are determined from the crossplot. This crossplot is applied to determine oil-filled porosity in a well in western Canada. A
similar approach can be applied, but obtained TZI and D from the spin-echo time domain to determine oil-filled porosity.
4. The 'Total Porosity Method PM) The DSM, SSM, and EI)M are specially designed and used in accordance with the present invention for hydrocarbon typing. The TPM used in accordance with the present invention is good for distinguishing brine-related porosity components: clay-bound water, capillary-bound water, and movable water. See Prammer, M.G., et al.:
"Measurements of Clay-Bound Water and Total Porosity by Magnetic Resonance Logging", paper SPE

presented at the 199b SPE AnnL~al Technical Conference and Exhibition, Denver, Colorado, U.S.A., 6-9 October 1996; and Coates, G.R., et al.: "Applying NMR Total and Effective Porosity to Formation Evaluation," paper SPE 38736 presented at the 1997 SPE
Annual Technical Conference and Exhibition, San Antonio, Texas, U.S.A., 5-8 October 1997.
Bound water saturation is a very important parameter for estimating formation production. To accurately determine the volume of formation occupied by immovable water, in accordance with the present invention, the fast decay signal, which arises mainly from clay-bound-water, must be recorded. Recording this decay signal requires a short TE
3 0 ~d a good SNR.

In accordance with the present invention, a modified MRIL~-C tool can be used along with pulse sequences, as shown in Fig. 9 in a preferred embodiment for the TPM.
These pulse sequences have two parts.
The first part is a regular pulse sequence having a long TW for full recovery of magnetization between measurements. This part usually uses a 1.2 ms echo spacing time, and acquires 4(10 echoes. Effecaive porosity is obtained from the data.
The second part is desil;ned to obtain the clay-bound signal (TZ < 2.5 ms).
This part has a short TW (20 ms), a short TE (0.6 ms), a short echo train (8 to 10 echoes), and 50 pulse repetitions. The short TW can not provide a TZ spectrum with full recovery, but it is long 1o enough for full recovery of the clay-bound T2. The TE = 0.6 ms is primarily used to resolve TZ values less than or equal to 1. ms. The repetitions is used to increase S/N
of the clay bound signal.
The data acquisition process provides two data sets with different S/N. To obtain the total porosity, these two data sets must be combined. In a preferred embodiment, a Tz inversion algorithm for the data sets by using two inversions and a cutoff method is used.
Fig. 10 indicates how the data are processed. The data sets with high and low S/N are inverted separately by fixing different Tz values. Data combination is accomplished simply by using the first four TZ components (0.5, 1, 2, and 4 ms) from the short echo data and all of the components from 8 ms a~ld up obtaining from the inversion of the long echo data.
2 0 ~s method results in a TZ dist~~ibution that is discontinuous around the cutoff values, which are 4 and 8 ms.
Recently, an algorithm has been developed for simultaneous inversion of the data sets with dii~erent SNR. The resulting TZ spectrum for total porosity is continuous, and has more information on clay-bound water.
In the T;; distribution, the porosity occupied by clay-bound-water is proportional to the area where TZ < 2.5 ms. In <~ sandstone reservoir, the porosity occupied by capillary-bound-water is proportional to the area in which 2.5 ms s TZ s 35 ms; in a carbonate reservoir, these bounds are given by 2.5 ms s Tz s 100 ms. The remainder of the area under the spectrum (i.e., TZ > 35 ms for the sandstone and Tz > 100 ms for the carbonate) is 3 0 proportional to the porosity occupied by movable fluids.

Fig. 11 is a TZ spectrums obtained through TPM. This spectrum is divided into the regions that correspond to clay-bound, capillary-bound, and movable water.
If only information about bound-water is needed, a short TW and smaller echo number can be used because T, and TZ of bound-water are short. This application has been demonstrated with a CMR tool, using TE = 0.2 ms, TW = 0.25 s, and 165 echoes in a sandstone reservoir, and TE = 0.2 ms, TW = 0.75 s, and 500 echoes in a carbonate reservoir.
Logging with these parameters can be fast (3,600 ft/hr in sandstones and 1,200 ffi/hr in carbonates).
to g- The Infecting Contrast Agent Method (ICAM) The ICAM is a method for accurately determining residual oil saturation (ROS) in open hole, although the need to inject a contrast agent can sometimes be an inconvenience.
The most common agents used in the ICAM are Mn-EDTA and MnCl2. Through the invasion of dosed mud or through direct injection of the contrast agent, the agent mixes with formation brine. Because of thE; short TZ of the resulting mixture, the signal from the brine cannot be detected. However, the oil signal is not influenced by the agent and can be measured by an NMRL tool. Further details concerning this method can be found, for example in U.S. Pat. No. 3,657,730, which is incorporated herein for all purposes.
Recently, a cheaper contrast agent (MnCl2) and a faster NMR doping and logging procedure have been discoveredl. See Horkowitz, J.P., et al.: "Residual Oil Saturation Measurements in Carbonates With Pulsed NMR Logs," The Log Analyst (March-April 1997). In accordance with a preferred embodiment, this agent and procedure can be used to determine ROS in a carbonate reservoir in west Texas. Mn~ iron in the new contrast agent has greater relaxivity for water protons than Mn-EDTA, so less dope is required. The 2 5 reduction in time is possible because there is no need to pack off and inject in the target zoom.
For determining ROS, tt~e method of the present invention only reduces the TZ
of the MnClz-H20 mixture to separate the oil signal. From the oil and the mixture peaks, ROS and porosity can be obtained.

WO 00/26696 PCT/US99/2539'7 Fig. 12 is an example of using MnCl2 in ICAM for obtaining ROS and porosity.
Track 1 is a T2 distribution (spectrum) for a "non-doped" well, and the Track 2 is a TZ
distribution (spectrum) for the "doped" well. Comparison of the two spectra reveals that the water signal is shifted to 10 ms. to 20 ms, while the oil signal is still at 500 ms after the doping with MnCl2. A TZ cutoff value for the oil signal is found from the TZ
distribution as 90 ms. The oil-filled porosity can be obtained from the total area of TZ > 90 ms. Because MnCl2 shifts only the water signal, the total signal from the oil and the water provides porosity. Therefore, the ROS is the ratio of the oil-filled porosity to the porosity.
1 o Miscellaneous Five NMR-based methods for fluid typing have been reviewed from the standpoint of principles, data acquisition and processing, and applications, as used in preferred embodiments of the present invention. By using a suitable combination of these methods, the individual porosities occupied by clay-bound water, capillary-bound water, movable water, gas, light oil, medium oil, and residual oil can be determined with high accuracy under different formation conditions.
It should be apparent that knowledge of formation conditions, such as formation temperature, formation pressure:, and fluid viscosity are crucial in obtaining high-quality logging data, and in selecting the optimum methods to be used in fluid typing.
In particular, 2 o wile the discussion above focuses solely on NMR-based methods, various other logging methods to enhance the accuracy of the measurement and data interpretation processes practiced in accordance with the: present invention. For example, conventional neutron, density, sonic and resistivity logs can be used in addition to or in combination with the methods described above for improved results.

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, alternatives, and equivalents as can be reasonably included within the spirit and scope of the invention as defined by the following claims.

WO 00/26b96 PCT/US99/25397 Nomenclature CMR = a magnetic resonance imaging logging tool from Schlumberger CPM = Carr-Purcell-Meiboom-Gill spin echo pulse sequence D = apparent diffusivity, cmZls DSM = differential spectrum method EDM = enhanced differential) method G = magnetic field gradient, G/cm HI = hydrogen index relative to water ICAM = injecting contrast agent method to M~L~ = a magnetic resonance imaging logging tool from NLTMAR.
mw = movable water MW = molecular weight NMRL = nuclear magnetic resonance logging ROS = residual oil saturation S/N = signal-to-noise ratio SSM = shift spectrum method T! = spin :lattice relaxation time, i.e., longitudinal relaxation time, s T1 = spin-spin relaxation time, i.e., transversal relaxation time, s TDA = time domain analysis;
TE = echo spacing time, m,s TPM = total porosity measurement TW = wait time, s Subscripts 0 = an equilibrium state A = apparent B = bulk b = brine 2 5 ~ = correlation D = diffusion DD = dipole-dipole interaction e, f~'' = effective g = gas H = hydrogen 3 o I = intrinsic J = angular momentum WO 00/2b696 PCTNS99/25397 L = longest Max = maximum o = oil p = pore S = surfac:e

Claims (20)

What is claimed is:
1. A method for fluid typing of a geological environment using nuclear magnetic resonance (NMR) measurements comprising:
determining a set of parameters for a gradient NMR measurement, obtaining a pulsed NMR log using the determined set of parameters; and selecting; from the NMR log an optimum contrast mechanism and corresponding measurement parameters for fluid typing of the geological environment.
2. The method of claim 1 wherein the set of determined parameters comprises the interecho spacing T E of a pulsed NMR sequence.
3. The method of claim 2 wherein the interecho spacing T E is determined at least on the basis of the expected viscosity of the oil in the formation.
4. The method of claim 1 wherein the set of determined parameters comprises the magnetic field gradient G of the NMR measurement.
5. The method of claim 1 wherein the set of determined parameters comprises the wait time T W, of the NMR measurement.
6. The method of claim 1 wherein said optimum contrast mechanism is based on diffusion.
7. The method of claim 1 wherein said optimum contrast mechanism is based on relaxation.
8. The method of claim 1 wherein said optimum contrast mechanism is based on hydrogen index contrast.
9. A method for fluid typing of a geological environment using nuclear magnetic resonance (NMR) measurements comprising:
conducting a first NMR measurement using a first predetermined set of measurement parameters;
comparing said first NMR measurement results to a predetermined set of criteria applicable for different fluid types to estimate candidate types of fluids that may have produced the first NMR measurement results;

selecting an appropriate type of contrast mechanism and a corresponding second set measurement parameters for the estimated types of fluids; and conducting a second NMR measurement using said second set of parameters to increase the accuracy of the fluid typing determination in case said second set of parameters is different from said first set of parameters.
10. The method of claim 9 wherein the first and the second set of parameters correspond to one or more of the: DSM, EDM, SSM, TPM, and ICAM. fluid typing methods.
11. A computer storage medium storing a software program to be executed on a computer, comprising:
a first software application for capturing NMR data concerning a first measurement;
a second software application, for comparing the first measurement data to pre-set rules determining the optimum contrast mechanism for use in the environment;
and a third software application, for providing a predetermined set of measurement parameters according to the determined optimum contrast mechanism.
12. An apparatus for fluid typing of a geological environment using nuclear magnetic resonance (NMR) measurements comprising:
a logging tool capable of conducting NMR measurements in a borehole;
data storage for storing NMR log data corresponding to one or more NMR
measurements each measurement using a predetermined set of measurement parameters;
a computer processor configured to execute a software application program for selecting from NMR log data an optimum contrast mechanism and corresponding measurement parameters for fluid typing of the geological environment; and a measurement cycle controller providing control signals to the logging tool for conducting NMR measurements based on input from said processor.
13. The apparatus of claim 12 wherein the set of determined parameters comprises the interecho spacing T E of a pulsed NMR sequence.
14. The apparatus of claim 12 wherein the interecho spacing T E is determined at least on the basis of the expected viscosity of the oil in the formation.
15. The apparatus of claim 12 wherein the set of determined parameters comprises the magnetic field gradient G of the NMR measurement.
16. The apparatus oil claim 12 wherein the set of determined parameters comprises the wait time T W of the NMR measurement.
17. The apparatus of claim 12 further comprising a display for indicating the selection of measurement parameters to a human operator.
18. The apparatus of claim 12 wherein the software application program is stored on a CD ROM..
19. The apparatus of claim 12 wherein the logging tool is capable of conducting multi-contrast NMR measurements.
20. The apparatus of claim 12 wherein the logging tool has a dual wait-time sequencing capability.
CA002348670A 1998-10-30 1999-10-29 Nmr logging apparatus and methods for fluid typing Abandoned CA2348670A1 (en)

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WO2000026696A1 (en) 2000-05-11
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