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BACKGROUND OF THE INVENTION
1. Field of the Invention
The present invention relates to well logging tools and methods, and more particularly to methods for analyzing extracted formation fluids by magnetic resonance techniques, especially nuclear magnetic resonance (NMR) and electron spin resonance
(ESR).
2. Background Information
Downhole formation fluid sampling tools, such as the Schlumberger Modular Formation Dynamics Tester (MDT), withdraw samples of fluids from earth formations for subsequent analyses. These analyses are needed to characterize physical properties
such as water and oil volume fractions, oil viscosity, and water salinity, among others. This knowledge is needed to interpret wireline well logs, and to plan for the efficient exploitation of the reservoir.
In an undisturbed reservoir, formation fluids sometimes partially support the overburden pressure of the earth. When a fluid-bearing formation is penetrated by drilling, formation fluids will flow into the borehole if it is at a lower pressure.
The uncontrolled escape of combustible hydrocarbons to the surface ("blowout"), is extremely dangerous, so oil wells are drilled under pressure. During drilling, fluid ("mud") is circulated through the well to carry rock chips to the surface. The mud
is densified with heavy minerals such as barite (barium sulfate, 4.5 g/cm.sup.3) to ensure that borehole pressure is higher than formation pressure. Consequently, fluid is forced into the formation from the borehole ("invasion"). Usually particles are
prevented from entering the formation by the filtering action of the porous rock. Indeed, the filtration process is self-limiting because solids, purposely mixed in the drilling fluid, form a filter cake ("mud cake") at the surface of the borehole.
Nonetheless liquid ("mud filtrate") can penetrate quite deeply--as much as several meters into the formation. The filtrate can be either water with various soluble ions, or oil, depending on the type of mud used by the driller. Therefore, the fluid
samples withdrawn are mixtures of native formation fluids (including gas, oil and/or water) and the filtrate of mud that was used to drill the well.
Sample contamination of formation fluids by mud filtrate is universally regarded as the most serious problem associated with downhole fluid sampling. It is essential that formation fluid, not mud filtrate, is collected in the sample chambers of
the tool. Therefore fluid from the formation is pumped through the tool and into the borehole until it is believed contamination has been reduced to an acceptable level. Thus it is necessary to detect mud filtrate in the fluid sample, to decide when to
stop pumping the fluid through the tool and to start collecting it for analysis.
Several measurements are routinely made in fluid sampling tools to detect mud filtrate contamination:
Resistivity indicates the presence of water. The measurement uses the low frequency electrode technique. Unless there is a continuous conducting path between the electrodes, there is no sensitivity to the presence of water. Even with a
conducting path, the method is unable to separate the effects of water volume, salinity, and flow geometry. The measurement is simple and often useful, but inherently nonquantitative.
Dielectric constant can distinguish oil from water, but not one oil from another. Moreover the dielectric constant measurement depends on the flow regime of oil/water mixtures.
Flow line pressure and temperature provide no information on fluid properties.
Optical Fluid Analyzers (e.g. Schlumberger OFA) can detect contamination in many cases. It is particularly effective when the mud filtrate is aqueous and the flowing formation fluid is pure hydrocarbon, since there is a large contrast between
water and oil in the near infrared band. However, it does less well when the filtrate is oil based, or when the formation fluid is a mixture of oil and water.
Thus, no presently deployed system is generally useful for determining the contamination level of sampled formation fluids. There is a clear need for an apparatus and method which monitors contamination while the sample is being taken, and
indicates when contamination has been reduced to an acceptably low level.
Downhole formation fluid sampling tools can withdraw samples of fluids from earth formations and transport them to the surface. The samples are sent to fluid analysis laboratories for analysis of composition and physical properties. There are
many inefficiencies inherent in this process.
Only about six samples can be collected on each descent ("trip") of the tool into the borehole. Because fluid sampling tools are deployed from drilling rigs, and because the rental charge for such rigs can exceed $150,000 per day in the areas
where fluid sampling is most often conducted, economic considerations usually preclude multiple trips in the hole. Thus, oil producing formations are almost always undersampled.
The samples undergo reversible and irreversible changes as a result of the temperature and/or pressure changes while being brought to the surface, and as a result of the transportation process. For example, gases come out of solution, waxes
precipitate, and asphaltenes chemically recombine. Irreversible changes eliminate the possibility of ever determining actual in situ fluid properties. Reversible changes are deleterious because they occur slowly and therefore impact sample handling and
measurement efficiency.
The transportation and handling of fluids uphole entails all the dangers associated with the handling of volatile and flammable fluids at high pressure and temperature. After analyses are complete, the samples must be disposed of in an
environmentally acceptable manner, with associated financial and regulatory burdens.
Because fluid analysis laboratories are frequently distant from the well site, there is substantial delays--often several weeks--in obtaining results. If a sample is for some reason corrupted or lost during sampling, transportation, or
measurement, there is no possibility of returning to the well to replace it.
Thus there is a clear need for immediate analysis of fluid samples at formation temperature and pressure within the downhole sampling tool.
SUMMARY OF THE INVENTION
Magnetic resonance, e.g., nuclear magnetic resonance (NMR) and electronic spin resonance (ESR) can be used to monitor contamination and analyze fluid samples in fluid sampling tools as fluid draw-down proceeds. Measurements are performed in the
flow line itself. The methods are inherently noninvasive and noncontacting. Since magnetic resonance measurements are volumetric averages, they are insensitive to flow regime, bubble size, and identity of the continous phase. Nuclear magnetic
resonance of hydrogen nuclei (protons) is preferred because of the ubiquity and good NMR characteristics of this nuclear species. However, magnetic resonance of other nuclear and electronic species is useful and so included within the scope of the
present invention. In general, the methods of analyzing a fluid according to the invention include introducing a fluid sampling tool into a well bore that traverses an earth formation. The fluid sampling tool extracts the fluid from the earth formation
into a flow channel within the tool. While the fluid is in the flow channel, a static magnetic field is applied, and an oscillating magnetic field applied. Magnetic resonance signals are detected from the fluid and analyzed to extract information about
the fluid.
These are other features of the invention are described in more detail in figures and in the description below.
Furthermore, a downhole NMR instrument installed in fluid sampling tools can make some of the most important measurements now being made in fluid analysis laboratories. The purpose of the downhole measurements is to provide means of making a
partial analysis when the sample is taken, after which the sample can be saved for further analysis or discarded to the borehole. In this manner an unlimited number of fluid samples can be analyzed on each trip in the hole. The measurements are made at
formation temperature and pressure, after minimum manipulation, thus helping to ensure sample integrity. Transportation and disposal problems are minimized or eliminated.
Magnetic resonance, e.g., nuclear magnetic resonance (NMR) is a powerful fluid characterization technique. The volumes of individual components of fluid mixtures, and some physical properties of each component, can be measured. The method is
inherently noninvasive and noncontacting. Since NMR measurements are volumetric averages, they are insensitive to flow regime, bubble size, and identity of the continuous phase. The method comprises the steps of:
a) obtaining a sample of formation fluid, having an acceptably low level of mud filtrate contamination; p1 b) performing magnetic resonance measurements of the fluid sample to quantitatively determine its physical properties;
c) sending the sample to a sample bottle within the tool for transportation to the surface for further analysis; or
d) discarding the sample to the borehole.
It is therefore an object of this invention to provide an improved method and apparatus for measuring an indication of contamination of fluid samples obtained by downhole tools.
It is another object of the invention to measure various physical properties of formation fluids using magnetic resonance.
BRIEF DESCRIPTION OF THE DRAWINGS
A complete understanding of the present invention may be obtained by reference to the accompanying drawings, when considered in conjunction with the subsequent detailed description, in which:
FIG. 1 illustrates a schematic diagram of a fluid sampling tool utitilized in extracting formation fluid in accordance with the invention;
FIG. 2 shows a schematic axial section of a flow line NMR apparatus that can be utilized in the sampling tool depicted in FIG. 1;
FIG. 3 shows a schematic cross sectional view of a flow line apparatus depicted in FIG. 2.
FIG. 4 depicts a flow chart of the method of this invention;
FIG. 5 depicts a graph showing the logarithmic mean T.sub.2 plotted versus viscosity for crude oils;
FIG. 6 shows T.sub.2 distributions for a number of crude oils having a variety of physical properties.
FIG. 7 shows an axial section of a flow line ESR apparatus that can be utilized in the sampling tool depicted in FIG. 1.
DESCRIPTION OF THE PREFERRED EMBODIMENT
Apparatus
Modern fluid sampling tools, such as Schlumberger's Modular Dynamics Testing Tool (MDT) are composed of several parts which enable extraction of fluids from permeable earth formations. Referring to FIG. 1, with the tool identified by 10, the
following modules are in the prior art [Schlumberger Wireline Formation Testing and Sampling, SMP-7058 (1996), published by Schlumberger Wireline and Testing]: the electric power module 11 and the hydraulic power module 12 power the tool; the probe
module 13 is deployed so as to make a hydraulic seal with the formation; and the pumpout module 17 lowers the pressure in the flow line in a controlled manner so as to extract fluid from the formation while maintaining the pressure near the original
formation pressure. Samples are optionally monitored by an optical fluid analyzer (OFA) 14 and are retained for transportation to surface laboratories in the multisample module 16.
The NMR module which is the subject of this invention is shown at 15 in FIG. 1. It is built around the flow line, and provides no obstructions to the flow of fluid within the tool.
More detailed drawings of the NMR apparatus 15 are shown in FIGS. 2 and 3. Fluid withdrawn from the formation flows through a flow channel 21. In non-instrumented sections of the tool, the channel is defined by a thick-wall metal tube 24
capable of withstanding formation pressure of at least 20,000 pounds per square inch.
In the NMR-instrumented section of the flow line, the channel is defined by the inside diameter of an antenna support 22. The antenna support must be made of a nonconductive and preferably nonmagnetic material. The antenna support must be
capable of resisting chemical attack by formation fluids. It must also be capable of resisting erosion by solids which may enter the flow line from the formation or borehole. Ceramics or hard polymeric materials are suitable materials for the antenna
support.
The NMR antenna 23 is embedded in the antenna support. The NMR antenna must be capable of radiating magnetic field at the Larmor frequency (see below), typically 40 MHz. This radiated magnetic field is conventionally called B.sub.1. In one
illustrative implementation, the NMR antenna is a solenoidal coil which generates an oscillating magnetic field parallel to the axis of the flow channel. The B.sub.1 field need not be particularly uniform over the volume of the flow channel.
The antenna support is enclosed by an enlarged portion of thick-wall metal tube 24, so as not to obstruct the flow channel 21. The tube 24 and antenna support 22 are able to contain the high pressure formation fluids in the flow channel. High
frequency magnetic fields cannot penetrate metals, so the NMR antenna must be placed inside the metal tube of the flow line.
An array of permanent magnets 25 is placed outside the thick-wall metal tube. These create a constant magnetic field, conventionally called B.sub.o, substantially perpendicular to the B.sub.1 field generated by the antenna. To make chemical
shift measurements (see below) B.sub.o is preferably substantially uniform in the volume occupied by fluid. However, to measure relaxation time, diffusion coefficient, or spin density of hydrogen or other elements, B.sub.o need not be particularly
uniform. One suitable arrangement of permanent magnets is described by Halbach [K. Halbach, Nuc. Inst. Methods 169, 1-10 (1980); K. Halbach, Nuc. Inst. Methods 187, 109-117 (1981)].
The entire NMR apparatus is enclosed in a sonde housing 26 which is attached to other similar housings in the tool string lowered into the well.
Gradient coils (not shown) can also be provided for the purpose of making pulsed field gradient measurements of diffusion coefficient and other quantities. If the static magnetic field is aligned with the z-axis, the most effective gradients are
dB.sub.z /dx, dB.sub.z /dy, and dB.sub.z /dz. A dB.sub.z /dz gradient can be generated by a pair of saddle coils potted together with the coil which provides the B.sub.1 field. Prescriptions for designing saddle coils that generate maximally uniform
gradients can be found in the literature [R. Turner, "Gradient Coil Systems", Encyclopedia of Nulear Magnetic Resonance, 1996].
NMR Technique
The techniques of nuclear magnetic resonance are well documented in the literature [E. Fukushima and S. B. W. Roeder, "NMR, A Nuts and Bolts Approach", Addison-Wesley (1981); T. C. Farrar and E. D. Becker, "Pulse and Fourier Transform NMR",
Academic Press (1971)]. The static B.sub.o and oscillating B.sub.1 magnetic fields should be substantially perpendicular to each other. The B.sub.1 antenna should be capable of transmitting and receiving signals at the Larmor frequency f,
where .gamma. is the gyromagnetic ratio of the nuclear species of interest, and Bo is the strength of the static magnetic field. For hydrogen nuclei, (.gamma.2.pi.)=4258 Hz/Gauss. For values of the gyromagnetic ratio of other nuclei, see e.g.
CRC Handbook of Chemistry and Physics [CRC Press], and the Table hereinbelow. Resonating nuclei other than .sup.1 H is accomplished by changing the frequency of operation to match the Larmor frequency of the nucleus of interest.
Before quantitative NMR measurements can be made on a fluid sample, it must be exposed to the static magnetic field Bo for a substantial time. The longer the exposure before the measurement begins, the more complete the alignment of nuclear
moments by Bo. The degree of alignment, also called polarization, is given by
In this equation, t is the time that the nuclei are exposed to Bo before the application of the B.sub.1 field, T.sub.1 is a time constant characteristic of the material, called the longitudinal relaxation time, P is the degree of polarization,
and Po is the degree of polarization in the limit that t goes to infinity. For an explanation of NMR relaxation times, see R. L. Kleinberg and H. J. Vinegar, "NMR Properties of Reservoir Fluids", Log Analyst November-December 1996, pg 20-32. For oil
field fluids, T.sub.1 can range from a few milliseconds (very viscous crude oils) to 10 seconds (very low viscosity crude oils with dissolved gas).
All standard NMR measurements cain be made using the apparatus described. These include measurement s of spin density (proportional to NMR signal amplitude), longitudinal and transverse relaxation times T.sub.1 and T.sub.2 and, more generally,
their distributions [R. L. Kleinberg, "Well Logging", Encyclopedia of Nuclear Magnetic Resonance, volume 8 pg 4960-4969, John Wiley & Sons, 1996]; diffusion coefficient and other q-space measurements [P. Callaghan, "Principles of Nuclear Magnetic
Resonance Microscopy", Clarend on Press, 1991]; flow velocity measurements [A. Capriban and E. Fukushima, "Flow Measurements by NMR", Physics Reports, 198, 195-235 (1990)]; and chemical shift spectroscopy when the B.sub.o field is sufficiently uniform
[H. J. Vinegar "Method of Determining Preselected Properties of a Crude Oil", U.S. Pat. No. 5,306,640 (1994)].
One particularly useful NMR pulse sequence is the Carr-Purcell-Meiboom-Till ("CPMG") pulse sequence, and its generalization, the Fast Inversion Recovery-CPMG pulse sequence [Kleinberg et al, U.S. Pat. No. 5,023,551]. Many other pulse sequences
are in common use, as cited in '551, and in the above book references.
Speed Effects
During pumpout, fluid may be moving at a high rate of speed through the flow line NMR apparatus. This limits polarization time and signal acquisition time, so some types of quantitative measurements may not be possible. However, there are a
number of methods by which contamination can be monitored qualitatively.
The rate that fluid moves through the tool depends on the permeability of the earth formation, the viscosity of the fluid, and the rate at which fluid can be pumped through the tool. For example, in the Schlumberger MDT, the flow control module
allows flows in the range 1-500 cm.sup.3 /s, while the pumpout module operates at speeds up to about 40 cm.sup.3 /s. ["Schiumberger Wireline Formation Testing and Sampling" (1996) pg. 4-29, 4-40]. The flow line has an inside diameter of 0.5 cm, so 500
cm.sup.3 /s corresponds to a flow speed of 25.5 m/s while 40 cm.sup.3 /s corresponds to a flow speed of 2 m/s. The effect of flow is similar to the speed effect of the Schlumberger CMR [J. M. Singer, L. Johnston, R. L. Kleinberg, and C. Flaum, "Fast NMR
Logging for Bound Fluid and Permeability", SPWLA 38th Annual Logging Symposium, 1997, Paper YY, Section 3].
Quantitative NMR measurements require that the spins be fully polarized by the static magnetic field prior to data acquisition. This requires that the spins be exposed to Bo for three to five times as long as the longitudinal relaxation time
T.sub.1. For water or light oils at high temperature, T.sub.1 can be several seconds; thus wait times of 10 seconds or more will be required. Since the NMR apparatus is typically 0.3 m long, even moderate flow speeds prevent quantitative measurements
from being made during pumpout. However, qualitative measurements to detect contamination can be made during pumpout. When contamination is at a sufficiently low level, pumping can be stopped or slowed and the full range of quantitative measurements
are made (see below).
Measurement Overview
A typical measurement sequence is shown in FIG. 4. Fluid is admitted into the tool flow line 41 and a measurement procedure initiated 42. An indication of magnetic resonance, of a group described below, is measured and recorded 43. While the
indication changes with time, the measurement loop is continued 44; when the indication stabilizes 45, contamination has been reduced to a minimum. Then the flow is stopped or slowed 46 and quantative analysis is undertaken 47. At the conclusiof of the
quantitative analysis, the fluid in the flow line is routed to storage bottles, or is expelled to the borehole.
There are a wide variety of measurements that can be used to monitor contamination, and another broad group of measurements that are useful in quantitatively analyzing fluid properties. These are described be low.
Contaminiation Monitoig Methods Using Flow Line NMR
Oil Base Mud Filtrate vs. Formation Oil
Many wells are drilled with muds in which oil is the continuous phase. These muds are comprised of hydrocarbons ("base oil"), typically hexadecanes, plus salt water, solids, and chemical additives. Usually only the base oil, together with
oil-soluble additives, enter the formnation and mix with formation oils. Water and solids remain in the borehole, or form a filter cake on the borehole wall. The oil entering the formation is called "oil base mud filtrate".
There are a number of NMR-detectable contrasts between oil base mud (OBM) filtrates and formation oils: (1) viscosity, (2) composition, (3) trace element content (natural or introduced), (4) diffusion coefficient, (5) proton density, and (6)
molecular conformation.
Viscosity: Extensive measurements on pure substances and crude oils have found an excellent correlation between fluid viscosity and the NMR relaxation times T.sub.1 and T.sub.2 [Bloembergen et al "Relaxation Effects in Nuclear Magnetic Resonance
Absorption", Physical Review 73, 679-712 (1948); Morriss et al "Hydrocarbon Saturation and Viscosity Estimation from NwM Logging in the Belridge Diatomite", Log Analyst, Mar-Apr 1997, pg 44-59]. Morriss et al suggest that the logarithmic mean value of
the relaxation time is strongly correlated with viscosity, see FIG. 5. Other relaxation time measures are also useful in qualitatively monitoring viscosity, including the time it takes for the NMR amplitude to fall to 1/e of its initial value.
In general, the viscosity of OBM filtrate is different (higher or lower) than that of the formation oil. Thus measurements of NMR relaxation time can distinguish these fluids from one another. Moreover, when OBM filtrate is mixed with formation
oil, the viscosity, and therefore relaxation time, of the mixture will be intermediate between the viscosities of the individual components.
As draw down continues, the time dependence of viscosity of the oil phase in the flow stream, .eta.(t), will vary as
where .eta..sub.mf is the viscosity of the mud filtrate under downhole conditions, which can be measured in advance in a laboratory if desired, and .eta..sub.n is the unknown viscosity of the native oil. f(t) depends on fluid and formation
properties and is therefore unknown. However, f(t) is expected to be subject to the conditions that f(0).gtoreq.0, df/dt>0, d.sup.2 f/dt.sup.2 <0 (at least at long time), and f(.infin.)=1. Given a sufficiently long acquisition of data,
.eta..sub.n can be estimated from the long-time asymptote of .eta.(t), and contamination level at any given time can be estimated.
Relaxation Time Distribution: Oil base mud filtrates are characterized by a narrow distribution of relaxation times. In contrast, crude oils have broad distributions of relaxation times, see FIG. 6 [Morriss et al, "Hydrocarbon Saturation and
Viscosity Estimation from NMR Logging in the Belridge Diatomite", Log Analyst, Mar-Apr 1997, pg 44-591]. Thus even if the OBM filtrate and native crude have the same viscosity, NMR T.sub.2 analysis can distinguish them based on the width of the
distribution of relaxation times.
Trace Element Content: Trace elements can be detected in two ways. (1) Paramagnetic ions or compounds dissolved in liquids shorten the NMR relaxation times of liquid protons. (2) The quantity of certain other nuclear or electronic species can
be measured directly by resonance measurements of those species.
Dissolved paramagnetic compounds will reduce the proton relaxation times of oils. Thus if two oils have the same viscosity, they will have different relaxation times if they have substantially different paramagnetic content. While many crude
oils and most oil base mud filtrates have negligible magnetic content, some crude oils have significant amounts of vanadium or nickel [Tissot and Welte, "Petroleum Formation and Occurrence", Springer-Verlag, 1978, Figure IV.1.20]. Because the rlaxation
effect is proportional to paramagnetic concentration, the proportions of two oils in a mixture can be m onitored. Deliberate introduction of an oil-souble paramagnetic substance into the oil base mud can considerably enhance this effect when the native
crude is relativly free of paramagnetic material.
NMR-active nuc lei can be monitored directly to determine contamination levels. OBM filtrates may differ from native oils by having substantiay different concentrations of oxygen, sulfur, or nitrogen. Of these, nitrogen is the best NMR target
because its NMR-active form, .sup.14 N, has good NMR sensitivity and a reasonable natural abundance, see Table hereinbelow. Considerably greater sensitivity to contamination can be attained if trace elements are mixed with the drilling mud to mark the
filtrate. For example, a fluorine-labeled organic compound can be detected directly by measuring the .sup.19 F resonance.
Diffusion Coefficient: The diffusion coefficient is closely related to the viscosity; they are related by the approximate relatio n [J. C. M. Li, P. Chang, "Self Diffusion Coefficient and Viscosity in Liquids", J. Chem. Phys. 23, 518-520 (1955)]
##EQU1##
where D is the diffusion coefficient, .eta. is the viscosity, c is an empirical constant, k is Boltzmann's constant, T is the absolute temperature, and (Nar) is the number of molecules per unit volume. Thus in many cases, measurements of
T.sub.2 and diffusion coefficient are duplicative. However, T.sub.2 is influenced by the presence of paramagnetics, whereas the diffusion coefficient is not. Thus diffusion measurements can be independently useful in determining contamination levels.
NMR Amplitude: Speed effects play an important role in the measurement of NMR amplitude, by reducing the time that the nuclear spins are exposed to the polarizing field B.sub.o. Hydrogen NMR amplitude is controlled by hydrogen index and the
effect of incomplete polarization:
V.sub.water, V.sub.oil, and V.sub.gas, are the relative volumes of water, oil, and gas in the NMR measurement section of the flow line. HI is the hydrogen index (proton density relative to pure water). W is the polarization time of the
measurement, which can be controlled either by the time between pulse sequences, or the flow rate.
Oils with API gravity greater than 20, and with no dissolved gas, have proton density equal to that of water [Vinegar et al, "Whole Core Analysis by 13C NMR", SPE Formation Evaluation 6, 183-189 (June 1991)]. Most oil mud filtrates also have
hydrogen densities equal to that of water. Gas is always a formation fluid; it is never a part of mud filtrates. A reduced proton density indicates gas, which is anticorrelated with the presence of mud filtrate in the flow line.
Medium-to-Heavy Oil/Oil Base Mud Filtrate: Medium to heavy oils have short T1, and are substantially polarized in the flow stream. Oil base mud filtrates have T.sub.1 's in the range of several hundred milliseconds, and thus are not completely
polarized in a rapidly moving stream. As the ratio of heavier formation oil increases, signal amplitude increases.
Light Oil and Gas/Oil Base Mud Filtrate: This is the most important contamination detection problem, and the one the optical fluid analyzer has the most trouble with. In this case, native oil has a longer relaxation time than OBM filtrate. Thus
as the proportion of native fluid increases, the proton signal amplitude will decrease. The presence of free gas associated with native oil accentuates the contrast. Signal level will stabilize at a low level when OBM contamination has been eliminated.
Spectroscopy: In ordinary laboratory practice, NMR spectroscopy can be used to distinguish families of hydrocarbons from each other. For example, protons in aromatic (ring) compounds such as benzene and naphthalene, have slightly different
resonant frequency than protons in alkanes [H. J. Vinegar "Method of Determining Preselected Properties of a Crude Oil", U.S. Pat. No. 5,306,640 (1994)]. OBM filtrates can be distinguished from formation oils when they have distinctive molecular
conformations. Monitoring the spectrum during pumpout provides fluid-selective information. For example, T.sub.1 changes in the oil phase can be monitored independent of the signal from water. Incomplete polarization and hydrogen index effects reduce
the amplitudes of individual spectral lines. The effects are the same as those affecting the amplitude measurement. Unlike the other techniques discussed, spectroscopy requires very good uniformity of the static magnetic field of the NMR apparatus:
typically 1 part per million or better over the sample volume.
Water Base Filtrate vs. Formation Water
Trace Element Content: NMR measurements can also help distinguish water base mud (WBM) filtrate from formation water. There will be little or no contrast in viscosity, diffusion coefficient, proton density, or molecular conformation. However,
the trace element content can be considerably different. Water soluble paramagnetic ions (either natural of introduced) will have a strong relaxing effect, which can be used to monitor proportions of filtrate and connate water.
The use of chromium lignosulfonate muds, or manganese tracers used for formation evaluation [Horkowitz et al, 1995 SPWLA Paper Q], add paramagnetic ions to the filtrate. These ions reduce the filtrate relaxation time. Thus they increase
contrast with light oils and gas, and decrease contrast with medium to heavy oils.
Paramagnetic ion can also be introduced in the flow line. 2.times.10.sup.18 ions cm.sup.3 of Fe.sup.3+ will reduce water T.sub.1 to 30 msec [Andrew, Nuclear Magnetic Resonance (1955)]. This is equivalent to 54 grams FeC | | |
