|Publication number||USRE40167 E1|
|Application number||US 10/231,412|
|Publication date||Mar 25, 2008|
|Filing date||Aug 29, 2002|
|Priority date||Mar 2, 1998|
|Also published as||CA2264204A1, CA2264204C, US6111409|
|Publication number||10231412, 231412, US RE40167 E1, US RE40167E1, US-E1-RE40167, USRE40167 E1, USRE40167E1|
|Inventors||Carl M. Edwards, Otto N. Fanini, Stanislav W. Forgang|
|Original Assignee||Baker Hughes Incorporated|
|Export Citation||BiBTeX, EndNote, RefMan|
|Patent Citations (13), Non-Patent Citations (3), Referenced by (4), Classifications (9), Legal Events (2)|
|External Links: USPTO, USPTO Assignment, Espacenet|
This application is a reissue application of U.S. Pat. No. 6,111,409 issued on Aug. 29, 2000.
1. Field of the Invention
The invention is related to the field of electric wireline formation fluid testing instruments, and to apparatus and methods for characterizing samples of connate fluids withdrawn from earth formation by such formation fluid testing instruments.
2. Description of the Related Art
Electric wireline formation fluid testing instruments are used to withdraw samples of connate fluids from earth formations penetrated by a wellbore. Certain characteristics of the fluid samples can be used to infer the nature of the connate fluids in the formations, particularly whether the fluid samples include petroleum, and the physical properties of the petroleum if it is present in the fluid samples. Formation testing instruments typically include one or more sample tanks to transport some of the connate fluid to the earth's surface where the sample may be characterized in a laboratory. See for example, U.S. Pat. No. 5,473,939 issued to Leder et al which describes one such formation fluid testing instrument.
A particular difficulty associated with fluid sampling using electric wireline instruments known in the art has been determining the extent to which the fluid samples placed in the tank contain connate fluids from the earth formation, and the extent to which the samples contain the liquid phase (“mud filtrate”) of a fluid (“drilling mud”) used to drill the wellbore. The mud filtrate enters (“invades”) the pore spaces of the earth formation proximal to the wellbore due to hydrostatic pressure and therefore frequently contaminates samples of fluid withdrawn from the formation.
Wireline formation testing instruments known in the art include various apparatus to overcome this limitation. Generally, the formation testing instruments include a means for withdrawing fluid from the formation and selectively discharging the fluid to the wellbore, rather than to the sample tanks, until it is determined that the fluid being withdrawn consists substantially of connate fluid. See the Leder et al '939 patent, for example, which describes a so-called “pump-through” capability. While withdrawing the fluid from the formation and pumping the fluid through the instrument, one or more properties of the fluid can be monitored. The point at which the nature of the withdrawn fluid changes from mud filtrate to connate fluid can generally be inferred from changes in the properties being monitored. The monitored properties include dielectric constant and electrical resistivity. For example, U.S. Pat. No. 5,677,631 issued to Reittinger et al describes a waveguide which enables making measurements related to the electrical conductivity and/or dielectric constant of the fluid being withdrawn. If water forms the liquid phase of the drilling mud, changes in the conductivity and/or dielectric constant can be related to changes in the nature of the withdrawn fluid. Using conductivity and/or dielectric constant to characterize the fluid being withdrawn from the formation has several limitations. First, the liquid phase of the drilling mud may be hydrocarbon-based rather than water-based, making characterization difficult if the connate fluid includes oil. Second, the connate fluid may contain substantially no hydrocarbons and may have an electrical conductivity very nearly the same as that of the mud filtrate, making determination of the nature of the fluid sample difficult. Finally, if the fluid sample contains both hydrocarbons and water, measuring electrical conductivity and/or dielectric constant in a relatively small volume waveguide, as is necessary within the confines of a typical electric wireline formation testing instrument, can result in noisy and unstable measurements, making accurate fluid characterization difficult.
Other methods for characterizing fluid samples include determining various relationships between the pressure and the volume of the fluid sample, such as described in U.S. Pat. No. 5,635,631 issued to Yesudas et al. A limitation to using the method described in the Yesudas et al '631 patent is that withdrawing the fluid from the formation must necessarily be stopped while the pressure/volume relationship of the fluid sample is carefully determined. Using this method to determine the point at which the fluid sample consists of connate fluid would therefore be impracticable because of the amount of time needed. Further, if the connate fluid were to consist mainly of water, the method in the Yesudas et al '631 would not readily indicate whether the fluid sample contained mud filtrate, connate fluid or any combination thereof.
Near infrared (“NIR”) photospectroscopy has also been used to characterize the fluid being withdrawn from the earth formation. U.S. Pat. No. 4,994,671 issued to Safinya et al describes a system for NIR photospectroscopy of fluid samples to determine their nature. It has proven difficult in practice to maintain the quality of optics necessary to reliably perform NIR photspectroscopy in a wireline formation testing instrument, primarily because of the opacity of typical crude oils. Further, photospectroscopic methods are generally unable to determine the nature of the fluid sample if the fluid sample and the mud filtrate are both water-based.
Carbon-13 nuclear magnetic resonance (“NMR”) spectroscopy is used to determine the chemical structure of carbon containing compounds. Carbon-13 NMR spectroscopy measures frequency shifts in the nuclear magnetic resonant frequency of carbon-13 resulting from combination of carbon atoms in chemical compounds having specific structures. Determining chemical structures of carbon compounds using NMR spectroscopy requires an NMR spectrometer having a resolution of about 1 part per million. This degree of resolution would require an instrument structure having a static magnetic field which is more homogeneous than would be practical for use in a well logging instrument.
The invention is a method for characterizing a fluid sample withdrawn from an earth formation. The fluid sample is withdrawn through a probe on an electric wireline formation testing instrument. The method includes performing nuclear magnetic resonance spin echo measurements on the fluid sample at a nuclear magnetic resonant frequency of carbon-13. Amplitudes of the spin echo measurements are summed. The summed measurements are spectrally analyzed. The fluid is characterized by determining whether aromatic hydrocarbons are present by measuring an amplitude of the spectrally analyzed spin echo measurements at about 130 part per million frequency shift from the carbon-13 resonant frequency. The fluid is also characterized by determining whether aliphatic hydrocarbons are present by measuring an amplitude of the spectrally analyzed spin echo measurements at about 30 parts per million frequency shift.
A nuclear magnetic resonance sensor according to the invention includes a permanent magnet for inducing a substantially homogeneous static magnetic field in at least a portion of the fluid sample, and a first antenna for inducing a radio frequency magnetic field in the fluid sample. The radio frequency magnetic field is substantially perpendicular to a magnetization direction of the static magnetic field. Circuits are coupled to the antenna for performing nuclear magnetic resonance spin echo measurements at a nuclear magnetic resonant frequency of carbon-13. The circuits include means for stacking the spin echo measurements over a measurement sequence. The apparatus includes a spectral analyzer for measuring amplitudes of components of the spin echo measurements at frequency shifts of 30 and 130 parts per million from the carbon-13 resonant frequency. A preferred embodiment includes shim coils proximal to the fluid sample. A controllable DC source is connected to the shim coils. The output of the DC source is adjusted in response to the output of a Hall sensor or the like to maintain a substantially constant static magnetic field amplitude in the fluid sample even while the permanent magnet field strength changes with temperature. The entire sensor assembly including the permanent magnet, shim coils and antennas can be included in fluid flow lines in an electric wireline formation testing instrument.
The invention is a nuclear magnetic resonance sensor disposed in an electric wireline instrument for withdrawing fluid samples from earth formations penetrated by a wellbore. One such instrument for withdrawing fluid samples is described, for example, in U.S. Pat. No. 5,635,631 issued to Yesudas et al. A feature of the instrument described in the Yesudas et al '631 patent which is particularly useful with this invention is a so-called “pump-through” capability. An electric wireline formation testing instrument having pump-through capability can withdraw fluid from the earth formation and selectively discharge the withdrawn fluid into the wellbore until which time as it has been determined that the fluid being withdrawn from the earth formation consists substantially of connate fluid, rather than the liquid phase of the drilling mud (“mud filtrate”). When the fluid being withdrawn is determined to consist substantially of connate fluid, the fluid being withdrawn can then be selectively redirected into one or more sample tanks for transportation of a predetermined volume of the fluid to the earth's surface. It should be noted that pump-through capability is not necessary for this invention, however having pump-through capability makes it more likely to be able to direct a substantially uncontaminated sample of connate fluid into the one or more sample tanks.
The electric wireline formation test tool is generally shown in
The tool 113 comprises a back-up shoe and a mechanism for laterally extending the shoe, as shown generally at 117, both of which are disposed within a housing 116. The housing 116 also contains a tubular probe 118 which can be selectively extended and put into contact with the wall of the wellbore 110. A sample tank 115 can be attached to the lower end of the housing 116 and can be selectively hydraulically connected to the probe 118 in order to store samples of fluids withdrawn from the earth. The probe 118, the back-up shoe 117 and selective valves (not shown) disposed within the housing 116 for operating the probe 118 and the shoe 117 can be of types familiar to those skilled in the art, and can receive hydraulic operating power from an hydraulic power unit 109 attached to the upper end of the housing 116. A nuclear magnetic resonance sensor 10 can be included in the instrument 113 for measuring characteristics of fluids withdrawn from the earth. The sensor 10 will be explained in more detail.
The various operating functions of the tool 113, including extension of the shoe 117 and extension of the probe 118, can be controlled by the system operator entering command signals into control circuits 123 which are located at the earth's surface and are electrically connected to the cable 112, as is understood by those skilled in the art. The command signals can be decoded in an electronics unit 114 disposed within the housing 116. As will be further explained, the tool 113 comprises sensors (not shown in
As the tool 113 is lowered into the wellbore 110, the depth at which the tool is located is indicated by a depth indicator 120 which is in contact with the cable 112 and measures the amount of cable 112 extended into the wellbore 110. When the tool 113 is positioned adjacent to a formation of interest, shown generally at 111, the system operator enters commands into the control circuits 123 to lock the tool 113 in position by extending the back-up shoe 117. The probe 118 is then extended, and withdrawal of a fluid sample can be initiated.
The means by which a fluid sample can be withdrawn from the formation of interest (111 in
The pump 124 comprises a drive cylinder 144, inside which is located at drive piston 146. The drive piston 146 is sealed against the inner wall of the drive cylinder 144 by an o-ring 148 or similar sealing device. The drive piston 146 is connected on one side to a first drive link 154, and on the other side is connected to a second drive link 156. The first drive link 154 is connected to one side of a first pumping piston 158. The second drive link 156 is similarly connected to a second pumping piston 160 disposed on the opposite side of the drive piston 146 to the first pumping piston 158. The first 158 and the second 160 pumping pistons are each respectively positioned within first 166 and second 168 pump cylinders disposed on opposite ends of the drive cylinder 144. Axial motion of the drive piston 146 is translated into equivalent axial motion of both the first 158 and second 160 pumping pistons.
The drive piston 146 is moved axially by selective application of hydraulic pressure to either one side or to the other side of the drive piston 146. Hydraulic pressure is provided by an hydraulic pump 204 which is disposed in the hydraulic power unit (shown in
The discharge from the regulator 206 is provided to hydraulic lines 202. The lines 202 connect to a first 186 and to a second 188 selective hydraulic valve. The selective valves 186, 188 can be operated by control signals sent from the control circuits (shown as 123 in
When the first valve 186 is opened, hydraulic pressure is applied through a first hydraulic control line 182 to a first chamber 150 in the drive cylinder 144, which is bounded at one end by the drive piston 146 and at the other end by the first pumping piston 158. The diameters of the first pump cylinder 166, and therefore, the first pumping piston 158 (and consequently their cross-sectional areas) are smaller than the diameter (and cross-sectional area) of the drive piston 146. Hydraulic pressure within the first drive chamber 150 therefore exerts more force on the drive piston 146 than on the first pumping piston 158, which causes motion of the drive piston 146, and all the previously described components that are attached to it, in the direction of the second pump cylinder 168. Hydraulic oil (not shown) is also present in a second drive chamber 152 disposed on the opposite side of the drive piston 146 and axially bounded by the drive piston 146 on one end and the second pumping piston 160 on the other end. As the drive piston 146 moves toward the second pump cylinder 168, the hydraulic oil in the second drive chamber 152 is displaced through a second hydraulic line 184 into a second discharge line 192 connected to a hydraulic oil supply tank (not shown) through a pilot operated check valve 196. The check valve 196 is held open by the operating hydraulic pressure from the line 202 applied through a control line 198 connected to the first hydraulic line 182. A similar, oppositely connected check valve, shown at 194, is connected through a control line 200 to the second hydraulic line 184 and vents the first hydraulic line 182 to the supply tank (not shown) when the drive piston 146 is moved in the opposite direction.
Motion of the drive piston 146 can be reversed by closing the first valve 186 and opening the second valve 188, thereby applying hydraulic pressure through the second hydraulic line 184 to the second drive chamber 152. The operation of the two valves 186, 188 can be performed automatically if the system operator instructs the control circuits 123 to operate the pump 124 continuously. The second pumping piston 160 can be substantially the same diameter as the first pumping piston 158, and thereby be smaller in diameter than the drive piston 146. Therefore hydraulic pressure applied to the second drive chamber 152 will cause motion of the drive piston 146 towards the first pump cylinder 166. As previously explained, the pressure on the second line 184 is also conducted through the control line 200 to open the pilot operated check valve at 194, which enables venting of the first drive chamber 150 to the supply tank (not shown).
Axial motion of the drive piston 146, which as previously explained is translated into equivalent axial motion of the first 158 and second 160 pumping pistons, results in corresponding changes in volume of a first 162 and of a second 164 pump chamber. The pump chambers 162, 164 can be selectively hydraulically connected to the probe 118 in order to withdraw fluid from the formation (111 in FIG. 1).
A particular feature of the pump 124 which enables direct determination of the volume of the first 162 and the second 164 pump chambers is a displacement sensor, which in the present embodiment can be a linear potentiometer 211 disposed inside the drive cylinder 144 and connected by a link 209 to the drive piston 146. Axial motion of the drive piston 146 results in directly corresponding change in the resistance of the potentiometer 211 as applied to a signal line 207. The resistance as applied to the signal line 207 is converted into a corresponding signal in the electronics unit (shown in
When withdrawal of a sample from the formation (shown at 111 in
The first 162 and second 164 pumping chambers are connected, respectively to a first 172 and a second 174 inlet check valve, both of which enable flow from the probe (shown as 18 in
During the discharge stroke on one chamber 162 or 164, corresponding to an expansion stroke in the opposing chamber 164 or 162, discharge from the compressing chamber 162 or 164 is conducted, respectively, through a first 178 and second 180 discharge check valve into a discharge line 176. The discharge line 176 can be selectively hydraulically connected to the sample tank (shown in
The invention provides, among other things, a means for determining the nature of the fluid being withdrawn from the formation, particularly whether the fluid consists partially or entirely of mud filtrate. The invention uses nuclear magnetic resonance (NMR) spectroscopy to determine the presence and the general type of hydrocarbon compounds in the fluid being withdrawn from the formation.
It is to be clearly understood that the formation testing instrument shown in
Referring now to
The sensor 10 can include permanent magnets 2A, 2B preferably made from Samarium-Cobalt or similar magnetic material having remanence magnetization which is relatively stable with respect to temperature. In this embodiment of the invention, the magnets 2A, 2B can be surrounded by a substantially cylindrical flux closure or “yoke” 3. Each magnet 2A, 2B can have its own pole piece 4A, 4B on the respective face of each magnet directed towards the center of the sensor 10. The magnets 2A, 2B, yoke 3, and pole pieces 4A, 4B provide a substantially homogeneous static magnetic field in the center of the sensor 10 having a magnitude of about 5,708 Gauss. The direction of magnetization of the magnets 2A, 2B is substantially perpendicular to the longitudinal axis of the sensor 10. Three radio frequency antenna 16A, 16B, 16C are disposed along the axis of the sensor 10 in between the magnets 2A, 2B. The antennas 16A, 16B, 16C as will be further explained, are used for sequential NMR experiments on the fluid in the center of the sensor 10. The sensor 10 can include a Hall probe 18 or similar device for measuring the magnitude of the static magnetic field induced by the magnets 2A, 2B so that the magnitude of the field can be adjusted for changes in the strength of the 2A, 2B magnets with temperature, as will be further explained.
The structure of the sensor 10 can be better understood by referring to an end view in FIG. 4. The magnets 2A, 2B are each polarized as shown by an arrow thereon, generally perpendicular to the longitudinal axis of the sensor 10. The axial length of the sensor 10 should be much longer than the diameter of the region in the center of the sensor 10 having substantially homogeneous static magnetic field, so that NMR experiments can be performed in different locations along the length of the sensor by each of the three antennas (16A, 16B, 16C in
The arrangement of magnets, yokes and antennas shown in
Operation of the sensor 10 can be better understood by referring to FIG. 5. The antennas 16A, 16B, 16C can be connected to a transceiver circuit 20 through a switching circuit 22. The transceiver circuit 20 generally can include a radio frequency power source which generates controlled-duration pulses or RF power, and switching circuits for selectively connecting the selected antenna (16A, 16B or 16C) between the RF source and a receiver circuit (not shown separately). The receiver circuit is for detecting voltages induced in the selected antenna by nuclear magnetic resonance. Circuits suitable for the transceiver 20 are described, for example, in U.S. Pat. No. 5,712,566 issued to Taicher et al. The transceiver 20 also can include digital signal processing (“DSP”) circuits for performing certain calculations on the measurements which will be further explained.
Irrespective of the magnetic material from which they are made, the magnets (2A, 2B in
The invention is designed to identify the nature of the fluid disposed in the sensor 10 by carbon-13 NMR spectroscopy. As described in the Background section herein, laboratory carbon-13 NMR spectroscopy measurements require an instrument resolution of 1 part per million (ppm) to determine chemical structures of carbon compounds. This degree of resolution would make impracticable the construction of an NMR spectrometer for use in a wireline formation fluid testing instrument. It has been determined, however, that a resolution of about 50 ppm can be adequate to determine the relative presences of aliphatic and aromatic carbon compounds in the a fluid sample. Aliphatic and aromatic compounds are almost always present in crude petroleum, and aromatic compounds are commonly used in the liquid phase of oil based drilling fluids. Therefore determination of the presence of one or both of these types of carbon compounds can be used to characterize the fluid sample. The magnet structure shown in
Using the suggested static magnetic field magnitude of 5,708 Gauss, carbon-13 will have a Larmor (NMR resonant) frequency of about 6.12 MHz. At 6.12 MHz, an instrument resolution of 50 ppm would require a receiver bandwidth of about 900 Hz. The transceiver 20, if designed as described in the Taicher et al '566 patent, for example, can be programmed to conduct a Carr-Purcell-Meiboom-Gill (CPMG) pulse/measurement sequence using a radio frequency of about 6.12 MHz. CPMG sequences, as known in the art, include transmission of an initial RF pulse through the antenna (such as 16A in
While the number of 180° pulses and resulting spin echoes in the CPMG sequences is not critical, it is contemplated that adequate signal-to-noise ratio will be obtained if the CPMG sequence extends over a time span approximately equal to the transverse relaxation time of the fluid sample. 500 milliseconds, or about 50 spin echoes using an interecho spacing of 10 milliseconds should provide adequate signal-to-noise. The contemplated time of 10 milliseconds interecho spacing is selected for the expected decay time for each individual spin-echo, as will be further explained.
The transceiver 20 can include an analog-to-digital converter as part of the DSP circuits, as suggested in Taicher et al '566 patent. The amplitude of each spin echo can be measured using a digital sample rate of about 0.55 milliseconds between each sample, which represents a frequency of twice the receiver bandwidth. Each spin echo should be digitized over a time span related to the decay time of the individual echo. This time is known as the free induction decay time, represented by T2*, and is inversely proportional to the degree of homogeneity of the static magnetic field as shown in the following expression:
where the homogeneity is represented by Δ. At the 6.12 MHz Larmor frequency for carbon-13 in the static magnetic field of 5,708 Gauss, and a field homogeneity of 50 ppm, the digitization time for each spin echo should be no less than 3.12 milliseconds. therefore no fewer than six digital samples at a rate of 1,800 Hz should be made of each sample. The digital sample rate can be increased as long as the signal is band limited to about 900 Hz (this being the product of the sensor 10 resolution and the Larmor frequency). It should be noted that the required receiver bandwidth and corresponding spin echo sample times depend on the intended sensor resolution and the degree of homogeneity of the static magnetic field, so the figure of 900 Hz bandwidth only applies given the senor 10 construction shown herein and the sensor resolution described herein.
The digitized spin echoes can be formatted in the electronics unit (114 in
To process the digitized spin echoes into characterizing information about the fluid sample, each spin echo in each CPMG sequence can have time correspondent ones of the digitized amplitude measurements summed or averaged over each entire CPMG sequence. The result of the summing is a set of digital amplitude values for each CPMG sequence. In this embodiment of the invention, three antennas 16A, 16B, 16C are provided at different locations along the longitudinal axis of the sensor 10. By including a plurality of antennas each energizing a different volume within the fluid sample, it is possible to acquire NMR signals having improved signal-to-noise in a relatively short time period. The improved signal-to-noise is obtained by summing or “stacking” the spin echoes measured using each antenna 16A, 16B, 16C. The stacking can be performed in the signal processor (121 in FIG. 1). The antennas 16A, 16B, 16C can each be selectively energized for performing an CPMG measurement sequence by using the switching circuit 22. As is known in the art, nuclei which have been transversely polarized by NMR spin echo experimentation gradually “relax” or return to magnetic spin orientation aligned with the static magnetic field. During the longitudinal relaxation, no further experimentation on the particular sample is practical. The nuclei of the fluid samples in the location of the non-energized antennas, however, remain substantially polarized along the static magnetic field and can be subjected to NMR spin-echo experimentation during the longitudinal relaxation period (the “wait time”) of the previously transversely polarized (the “experimented on”) fluid sample. Spin echo amplitudes measured by each of the antennas 16A, 16B, 16C can also be summed to get spin echo amplitude values having improved signal-to-noise. Using three switched antennas is not a limitation on the invention, but is merely illustrative of the principle of multiple measurements made in different portions of the sample to conserve time. It is contemplated that five or more switched antennas can be used with the sensor 10 of the invention. It is further contemplated that two or more of the antennas can be used to conduct CPMG measurements sequences simultaneously where enough such antennas are used in the particular sensor to enable sufficient wait time between measurement sequences at any single antenna. For example, a measurement cycle for a six antenna system could include measuring CPMG sequences at the first and fourth antennas, next at the second and fifth antennas, and finally at the third and sixth antennas. The cycle can then be repeated at the first and third antennas, and so on for an appropriate number of cycle repetitions to obtain a sufficient signal-to-noise ratio.
A timing diagram showing typical CPMG pulse sequences applied to each of the antennas (16A, 16b, 16C in
After summing, or “stacking”, the spin echo amplitude values from all the CPMG measurement sequences, the resulting stacked spin echo amplitude sample values can then be analyzed using a fast Fourier transform or similar spectral analysis, to generate a Fourier spectrum. The Fourier spectrum will include relative amplitude contributions of different frequency components present in the stacked spin echo amplitude values. The presence or absence of certain frequency components can be used to determine whether aromatic hydrocarbon components and/or aliphatic hydrocarbon compounds are present in the fluid sample. The resolution of the spin echo amplitude measurements in the method of the invention is sufficient to calculate relative amplitudes of signal components at 30 and 130 parts per million (ppm) from the base frequency (the frequency of the RF power used to perform the spin echo measurement sequences.
For example, carbon-13 in xylene generates characteristic spectral peaks in the range of about 130 ppm from the base frequency of 6.12 MHz. Carbon-13 in typical aliphatic (alkane) compounds including CH2 and CH3 molecular groupings therein has characteristic peaks in the 30 ppm range from the base frequency. See, for example, W. Simons, The Sadtler Guide to Carbon-13 Spectra, Sadtler Research Laboratories, 1984. As is known in the art, drilling fluids which include hydrocarbon as the liquid phase typically include aromatic compounds. Crude oils typically include some aliphatic compounds. After performing the Fourier transform on the stacked samples, the amplitude of the spectrum at 130 ppm can be measured, and the amplitude of the spectrum at 30 ppm can be measured. Absence of any substantial spectral amplitude at 130 or 30 ppm indicates that the fluid sample does not include any substantial amount of hydrocarbons, either aromatic or aliphatic type. If the amplitude of the 130 ppm portion of the spectrum shows substantial presence of aromatic hydrocarbons, and the drilling fluid contains such aromatics in the liquid phase, it may be inferred that the fluid sample includes a substantial fraction of mud filtrate. Presence of substantial amounts of aliphatic hydrocarbons, as indicated by substantial amplitude of the 30 ppm portion of the spectrum, indicates that the fluid sample in the sensor 10 includes some connate hydrocarbons. It is therefore possible using the spectroscopy technique of the invention, to discriminate between crude oil, and oil based mud filtrate by determining the relative presence of aliphatic and aromatic compounds in the fluid sample.
An example of analyses using the method of the invention is shown in graphs in
Referring once again to
As is known in the art, connate water typically includes some concentration of sodium ions in solution. The concentration of sodium ions is related to the resistivity (conductivity) of the connate water. Using the apparatus of the invention, it is also possible to determine the relative concentration of sodium ions in solution in the fluid sample. the following process steps can be used to determine the relative concentration of sodium in the fluid sample. The antennas 16A, 16B, 16C can be sequentially actuated for measuring CPMG sequences at the resonant frequency of sodium-23, which is about 6.41 MHz. A typical timing sequence for measuring CPMG sequences at each of the three antennas can be observed in FIG. 6. The only substantial difference between the CPMG sequences for carbon-13 and sodium-23 is the frequency of the RF magnetic field. The amplitudes of each spin echo in the CPMG sequences from each of the three antennas can then be summed or stacked. Sodium ions in solution will typically have only a single spectral amplitude peak (a single resonance “line”) whose amplitude is related to the relative concentration of sodium in the fluid sample. Therefore the value of the summed spin echo amplitudes will be directly related to the relative concentration of sodium ions in solution.
Those skilled in the art will devise other embodiments of this invention which do not depart from the spirit of the invention as disclosed herein. The invention should therefore be limited in scope only by the attached claims.
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|International Classification||G01V3/00, G01V3/32, G01R33/44, G01R33/20|
|Cooperative Classification||G01N24/081, G01V3/32|
|European Classification||G01N24/08A, G01V3/32|
|Apr 9, 2012||REMI||Maintenance fee reminder mailed|
|Aug 29, 2012||LAPS||Lapse for failure to pay maintenance fees|