Source: http://www.google.com/patents/US7557579?dq=6,163,776
Timestamp: 2014-11-27 23:07:32
Document Index: 746723816

Matched Legal Cases: ['Application No. 00908351', 'Application No. 00908351', 'Application No. 01096', 'Application No. 01096', 'Application No. 2', 'Application No. 2', 'Application No. 2', 'Application No. 2', 'Application No. 2', 'Application No. 01', 'Application No. 01', 'Application No. 01', 'Application No. 01', 'Application No. 00']

Patent US7557579 - Electromagnetic wave resistivity tool having a tilted antenna for ... - Google PatentsSearch Images Maps Play YouTube News Gmail Drive More »Sign inAdvanced Patent SearchPatentsThis invention is directed to a downhole method and apparatus for simultaneously determining the horizontal resistivity, vertical resistivity, and relative dip angle for anisotropic earth formations. The present invention accomplishes this objective by using an antenna configuration in which a transmitter...http://www.google.com/patents/US7557579?utm_source=gb-gplus-sharePatent US7557579 - Electromagnetic wave resistivity tool having a tilted antenna for determining the horizontal and vertical resistivities and relative dip angle in anisotropic earth formationsAdvanced Patent SearchPublication numberUS7557579 B2Publication typeGrantApplication numberUS 12/127,634Publication dateJul 7, 2009Filing dateMay 27, 2008Priority dateJan 28, 1999Fee statusPaidAlso published asCA2359371A1, CA2359371C, EP1155343A1, EP1155343A4, EP1155343B1, EP2108981A2, EP2108981A3, EP2108981B1, EP2110687A2, EP2110687A3, EP2110687B1, US6163155, US7557580, US7948238, US8085049, US20080258733, US20080278169, US20090224764, US20100123462, US20110199088, WO2000045195A1, WO2000045195A8Publication number12127634, 127634, US 7557579 B2, US 7557579B2, US-B2-7557579, US7557579 B2, US7557579B2InventorsMichael S. BittarOriginal AssigneeHalliburton Energy Services, Inc.Export CitationBiBTeX, EndNote, RefManPatent Citations (99), Non-Patent Citations (55), Referenced by (7), Classifications (8), Legal Events (2) External Links: USPTO, USPTO Assignment, EspacenetElectromagnetic wave resistivity tool having a tilted antenna for determining the horizontal and vertical resistivities and relative dip angle in anisotropic earth formationsUS 7557579 B2Abstract This invention is directed to a downhole method and apparatus for simultaneously determining the horizontal resistivity, vertical resistivity, and relative dip angle for anisotropic earth formations. The present invention accomplishes this objective by using an antenna configuration in which a transmitter antenna and a receiver antenna are oriented in non-parallel planes such that the vertical resistivity and the relative dip angle are decoupled. Preferably, either the transmitter or the receiver is mounted in a conventional orientation in a first plane that is normal to the tool axis, and the other antenna is mounted in a second plane that is not parallel to the first plane. Although this invention is primarily intended for MWD or LWD applications, this invention is also applicable to wireline and possibly other applications.
at least a first receiver antenna extending around a portion of the tool body, the first receiver antenna configured to receive an electromagnetic wave from the formation, wherein the receiver antenna has its maximum magnetic moment sensitivity along a line that intersects the tool axis at a second angle, wherein the first and second angles are unequal, and wherein one of the first and second angles is 0�;
receiving an electromagnetic wave from the formation with a receiver antenna, wherein the receiver antenna is a loop antenna mounted in a cutout in the logging tool and extending around the axis of the logging tool, and placed so as to have its maximum magnetic moment sensitivity along a line that intersects the tool axis at a second angle, wherein the first and second angles are different, and with at least one of said first and second angles being approximately 0�; and
39. The method of claim 38, wherein the relative orientation of a subsurface formation boundary to the borehole comprises a relative dip angle. Description
This application is a continuation of U.S. application Ser. No. 11/745,822, filed May 8, 2007 now abandoned, which in turn is a continuation of U.S. application Ser. No. 11/457,709, filed on Jul. 14, 2006 now U.S. Pat. No. 7,265,552, which in turn is a continuation of U.S. application Ser. No. 11/198,066, filed on Aug. 5, 2005 now U.S. Pat. No. 7,138,803, which in turn is a continuation of U.S. application Ser. No. 10/616,429, filed on Jul. 9, 2003 now U.S. Pat. No. 7,019,528, which in turn is a divisional of U.S. application Ser. No. 10/255,048, filed on Sep. 25, 2002 now U.S. Pat. No. 6,911,824, which in turn is a divisional of U.S. application Ser. No. 09/615,501, filed on Jul. 13, 2000 now U.S. Pat. No. 6,476,609, which in turn is a continuation-part of U.S. application Ser. No. 09/238,832 filed Jan. 28, 1999now U.S. Pat. No. 6,163,155, all of which are hereby incorporated by reference. The present application relates to concurrently-filed U.S. patent application Ser. No. 12/127,672, entitled �Electromagnetic Wave Resistivity Tool Having A Tilted Antenna for Geosteering Within A Desired Payzone� by inventor Michael Bittar.
The relative dip angle, θ, is the angle between the borehole axis (tool axis) and the normal to the plane of the formation. If the axis of an electromagnetic wave resistivity tool is perpendicular to the plane of an anisotropic formation (i.e., θ=0�), both the phase shift and amplitude attenuation measurements reflect only the horizontal resistivity. However, if the axis of the tool is inclined with respect to the normal of the formation plane (i.e., for non-zero relative dip angle), the rock anisotropy affects the resistivity derived from phase shift measurements (�phase shift resistivity� or RΦ) differently than it affects the resistivity derived from amplitude attenuation measurements (�amplitude attenuation resistivity� or RA). For small relative dip angles (e.g., θ less than about 45�), the difference between phase shift and amplitude attenuation resistivities is relatively small. However, this difference becomes significant for relative dip angles greater than about 50�, and the difference is large for horizontal boreholes (i.e., θ=90�).
In a technical paper entitled �A New Method to Determine Horizontal Resistivity in Anisotropic Formations Without Prior Knowledge of Relative Dip,� 37th SPWLA 37th Annual Logging Symposium, New Orleans, Jun. 16-19, 1996, Hagiwara discloses a method to determine the horizontal resistivity for deviated boreholes or dipping formations using two conventional induction-type resistivity measurements. However, Hagiwara's method does not provide the relative dip angle. To obtain the relative dip angle, the formation anisotropy must be known. Moreover, Hagiwara showed that, for conventional induction logging tools (in which the transmitter and receiver antennas are oriented co-axially with the tool), it is impossible to obtain all three parameters (horizontal resistivity, vertical resistivity, and relative dip angle) simultaneously. The reason such a simultaneous solution is not possible using conventional induction logging tools is that, in the response of such tools, the vertical resistivity and the relative dip angle are coupled (i.e., they are not independent).
SUMMARY OF THE INVENTION Accordingly, this invention is directed to an improved downhole method and apparatus for simultaneously determining the horizontal resistivity, vertical resistivity, and relative dip angle for anisotropic earth formations. The present invention accomplishes this objective by using an antenna configuration in which a transmitter antenna and a receiver antenna are oriented in non-parallel planes such that the vertical resistivity and the relative dip angle are decoupled. Preferably, either the transmitter or the receiver is mounted in a conventional orientation in a first plane that is normal to the tool axis, and the other antenna is mounted in a second plane that is not parallel to the first plane. Although this invention is primarily intended for MWD or LWD applications, this invention is also applicable to wireline and possibly other applications.
BRIEF DESCRIPTION OF THE DRAWINGS This invention may best be understood by reference to the following drawings:
DETAILED DESCRIPTION OF A PREFERRED EMBODIMENT FIG. 1 illustrates a logging tool 10 in accordance with the present invention suspended in a borehole 12 within an earth formation 13 on a string of drill pipe 14. Drill string 14 includes one or more drill collars 11. Electromagnetic transmitters (antennas) 16, 18, and 20 (sometimes referred to herein as transmitters T1, T2, and T3, respectively) are spaced along the length of logging tool 10 from electromagnetic receivers (antennas) 22 and 24 (sometimes referred to herein as R1 and R2, respectively). Preferably, transmitters 16, 18, 20 and receivers 22, 24 are mounted in recesses in tool 10 (as indicated in FIG. 2) and are covered with a non-conductive material (not shown), as is well known in the art. If a transmitter is designed to operate at more than one frequency, for example, f1=2 MHz and f2=1 MHz, each receiver may comprise a pair of coils, with one coil tuned to f1 and one coil tuned to f2. Additionally, if desired, each pair of such receiver coils may be located side by side around the periphery of tool 10 or may be concentrically stacked. Transmitters 16, 18, 20 and receivers 22, 24 may be fabricated in accordance with the teachings of U.S. Pat. No. 4,940,943, which is assigned to the assignee of the present invention and is incorporated herein by reference. It should be appreciated that the body of tool 10 is preferably made of steel in order to prevent tool 10 from becoming a weak link in the drill string 14. Typically, and in a manner well known in the art, one or more drill collars 11 are threadably connected to the lower end of logging tool 10, and a drill bit (not illustrated) is threadably connected to the lowest drill collar 11.
Referring to FIG. 2, well logging tool 10 is illustrated as having a plurality of transmitters T1, T2, T3 . . . Tn. Although a preferred embodiment comprises only three such transmitters (T1, T2 and T3), Tn is illustrated for purposes of showing that additional transmitters may be used, if desired. It should be appreciated that T1, T2, T3 . . . Tn are successively further spaced from the receiver pair R1 and R2. The distance between the coils used for R1 and R2 is preferably six inches along the longitudinal axis of tool 10, but other receiver spacings may also be used. The distance between the receiver pair and the successively spaced transmitters will vary in some applications, as discussed hereinafter in greater detail. A preferred configuration contains a distance between T1 and R1/R2 of 12 inches/18 inches; a distance between T2 and R1/R2 of 24 inches/30 inches; and a distance between T3 and R1/R2 of 36 inches/42 inches. In the foregoing sentence, it should be understood that the term �12 inches/18 inches,� for example, indicates that the distance between T1 and R1 is 12 inches and that the distance between T1 and R2 is 18 inches, based upon R1 and R2 being six inches apart. Such spacing configurations are sometimes referred to herein using an abbreviated expression of, for example, �12/18.�
It should also be appreciated that the frequencies F1, F2, F3 . . . Fn could all be the same frequency except for the practical considerations of power loss in the formation due to the increased distance the signals have to travel through the formation. However, the conventional multiplexer circuitry 60 used with this system enables time separation between the sequential pulsing of the transmitters T1, T2, T3 . . . Tn. For example, as illustrated in FIG. 3, transmitter T1 can be pulsed for one second, followed by no pulse for one second, followed by the pulsation of transmitter T2 for one second, followed by no pulse for one second, followed by a pulsing of transmitter T3 for one second, and so on. Quite obviously, the duration of the pulsing for each transmitter can be varied, as well as the duration of no pulsing in between, for example, as illustrated in FIG. 4. It should be appreciated that the expression �time separation� between pulses includes the preferred embodiment of having one pulse commence immediately with the termination of the immediately preceding pulse. As desired, the duration of the pulses controlling T1 may vary from the duration of the pulses for T2, which may vary from the duration of the pulses for transmitter T3, and so on, in order to provide a signature of the received pulses at receivers R1 and R2 to better identify the transmitters and thus the depth of investigation for the particular pulses being received. Thus, measurements are made to different depths into the formation by activating each transmitter at a different time such that only one transmitter is active at any one time and by recording or telemetering the received phase difference and/or amplitudes (amplitude ratio) corresponding to each transmitted signal. Alternatively, the transmitters T1, T2, T3 . . . Tn could all be operated at different frequencies and could be pulsed simultaneously, with the separation of signals being a function of frequency difference rather than time separation in accordance with a preferred embodiment of this invention. However, those skilled in the art will recognize that simultaneous transmission of all of the transmitter signals will usually require additional filters and processing circuitry to enable the instrument to properly discriminate between the different frequencies.
As discussed above, due to the nature of sedimentary formations, practitioners in the art use the term �horizontal� to denote the plane of the formation (i.e., the x-y plane of FIG. 9), and practitioners use the term �vertical� to denote the direction perpendicular to the plane of the formation (i.e., the z direction of FIG. 9, which is the direction of sedimentary build-up). For convenience in distinguishing between these terms of art and the ordinary directions associated with the earth's gravity, FIGS. 5 and 6 utilize the following terms: �true vertical� indicates the direction of the earth's gravity; �true horizontal� indicates the direction perpendicular to the earth's gravity; �formation vertical� indicates the direction perpendicular to the plane of the formation; and �formation horizontal� indicates the plane of the formation. In this description, the terms �horizontal� and �vertical� are intended to have the meanings associated with �formation horizontal� and �formation vertical,� respectively. In FIGS. 5 and 6, δ is the hole deviation angle (the angle between the borehole/tool axis and the true vertical), and ψ is the bed dip angle (the angle between the formation bed plane and the true horizontal).
MT h =MT sin θ=ItAt sin θ [1]MT v =MT cos θ=ItAt cos θ [2]
It=the current in the transmitter coil, At=the cross-sectional area of the transmitter coil, and θ=the relative dip angle (the angle between the tool axis and the normal to the formation).
As shown by Luling, M. G., �Processing and Modeling 2-MHz Resistivity Tools in Dipping, Laminated, Anisotropic Formations,� SPWLA 35th Annual Logging Symposium, Jun. 19-22, 1994, the HMD produces magnetic fields Hhx and Hhz, and the VMD produces magnetic fields Hvx and Hvz as follows:
H hx = M T ⁢ sin ⁢ ⁢ θ 4 ⁢ π ⁢ ( ⅇ ⅈ ⁢ ⁢ k h ⁢ L L 3 [ 3 ⁢ ⁢ sin 2 ⁢ θ - 1 + k h 2 ⁢ L 2 ⁢ cos 2 ⁢ θ + ⅈ ⁢ ⁢ k h ⁢ L sin 2 ⁢ θ + ⅈ ⁢ ⁢ k h ⁢ L - 3 ⁢ ⅈ ⁢ ⁢ k h ⁢ L ⁢ ⁢ sin 2 ⁢ θ ] - ⅈ ⁢ ⁢ k h sin 2 ⁢ θ ⁢ ⅇ ⅈ ⁢ ⁢ k h ⁢ L ⁢ ⁢ β ) ⁢ ⅇ ⅈ ⁢ ⁢ k h ⁢ L [ 3 ] H hz = M T ⁢ cos ⁢ ⁢ θ 4 ⁢ π ⁢ ( ⅇ ⅈ ⁢ ⁢ k h ⁢ L L 3 ⁡ [ 3 ⁢ ⁢ cos ⁢ ⁢ θ ⁢ ⁢ sin ⁢ ⁢ θ - k h 2 ⁢ L 2 ⁢ cos ⁢ ⁢ θ ⁢ ⁢ sin ⁢ ⁢ θ - 3 ⁢ ⅈ ⁢ ⁢ k h ⁢ L ⁢ ⁢ cos ⁢ ⁢ θsin ⁢ ⁢ θ ] ) [ 4 ] H vx = M T ⁢ sin ⁢ ⁢ θ 4 ⁢ π ⁢ ( ⅇ ⅈ ⁢ ⁢ k h ⁢ L L 3 ⁡ [ 3 ⁢ ⁢ cos ⁢ ⁢ θ ⁢ ⁢ sin ⁢ ⁢ θ - k h 2 ⁢ L 2 ⁢ cos ⁢ ⁢ θ ⁢ ⁢ sin ⁢ ⁢ θ - 3 ⁢ ⅈ ⁢ ⁢ k h ⁢ L ⁢ ⁢ cos ⁢ ⁢ θsin ⁢ ⁢ θ ] ) [ 5 ] H vz = M T ⁢ cos ⁢ ⁢ θ 4 ⁢ π ⁢ ( ⅇ ⅈ ⁢ ⁢ k h ⁢ L L 3 ⁡ [ 3 ⁢ ⁢ cos 2 ⁢ θ - 1 + k h 2 ⁢ L 2 ⁢ sin 2 ⁢ θ - 3 ⁢ ⅈ ⁢ ⁢ k h ⁢ L ⁢ ⁢ cos 2 ⁢ θ + ⅈ ⁢ ⁢ k h ⁢ L ] ) [ 6 ] where
k h = ω 2 ⁢ μ ⁡ ( ɛ h - ⅈ ⁢ ⁢ σ h ω ) k v = ω 2 ⁢ μ ⁡ ( ɛ v - ⅈσ v ω ) β = cos 2 ⁢ θ + ( k v k h ) 2 ⁢ sin 2 ⁢ θ kh=the complex wave number in the horizontal direction
V = ⅈω ⁢ ⁢ A r ⁢ μ ⁢ ⁢ I t ⁢ A t 4 ⁢ π ⁢ ⁢ L 3 ⁢ ( [ 2 - ⅈ ⁢ ⁢ k h ⁢ L ] ⁢ ⅇ ⅈ ⁢ ⁢ k h ⁢ L - ⅈ ⁢ ⁢ k h ⁢ L ⁢ ⁢ ⅇ ⅈ ⁢ ⁢ k h ⁢ L ⁢ ⁢ β ) [ 9 ] Equation [9] shows that the induced voltage, V, depends on kh and β. In turn, kh depends on σh; and β depends on σh, σv, and θ. These relationships indicate that σv and θ are dependent, and this dependency prevents convergence of a simultaneous solution for σh, σv, and θ, as discussed above.
V = ⅈ ⁢ ⁢ ω ⁢ ⁢ A r ⁢ μ ⁢ ⁢ I t ⁢ A t 4 ⁢ π ⁢ ⁢ L 3 ⁢ ( + [ 2 ⁢ ⁢ sin ⁢ ⁢ θsinθ ′ + 2 ⁢ ⁢ cos ⁢ ⁢ θcos ⁢ ⁢ θ ′ ] ⁢ ⅇ ⅈ ⁢ ⁢ k h ⁢ L - [ 2 ⁢ ⅈ ⁢ ⁢ k h ⁢ L ⁢ ⁢ sin ⁢ ⁢ θsin ⁢ ⁢ θ ′ - 2 ⁢ ⅈ ⁢ ⁢ k h ⁢ L ⁢ ⁢ cos ⁢ ⁢ θcos ⁢ ⁢ θ ′ ] ⁢ ⅇ ⅈ ⁢ ⁢ k h ⁢ L + ⅈ ⁢ ⁢ k h ⁢ L ⁢ sin ⁢ ⁢ θ ′ sin ⁢ ⁢ θ ⁢ ⅇ ⅈ ⁢ ⁢ k h ⁢ L - ⅈ ⁢ ⁢ k h ⁢ L ⁢ sin ⁢ ⁢ θ ′ sin ⁢ ⁢ θ ⁢ ⅇ ⅈ ⁢ ⁢ k h ⁢ L ⁢ ⁢ β ⁢ ) [ 11 ] where
θ′=θ+ξR−90� ξR=the angle of tilt of the receiver antenna (i.e., the angle between the plane of the receiver antenna and the tool axis) ξT=the angle of tilt of the transmitter antenna (i.e., the angle between the plane of the transmitter antenna and the tool axis).
Equation [11] shows that the induced voltage, V, depends on kh, β, θ, and θ′. As long as θ is different from θ′, then θ can be calculated from three measurements using a multiple spacing or multiple frequency electromagnetic wave resistivity tool. By tilting either the receiver or the transmitter of an electromagnetic wave resistivity sensor (i.e., by making θ different from θ′), σv and θ are decoupled, which enables a solution for σh, σv, and θ as described below. Although the above formulation is for an untilted transmitter with a tilted receiver, the theory of reciprocity provides that the same result also applies to a tilted transmitter with an untilted receiver. Indeed, both the transmitter and the receiver may be tilted, provided that the respective angles of tilt are not the same, i.e., ξT≠ξR. For the general case in which both the transmitter and the receiver are tilted at arbitrary angles ξT and ξR, respectively, Eqs. [1] through [11] apply with the substitution of θ″ for θ, where θ″=θ+ξT−90�. FIG. 7 illustrates several possible transmitter/receiver pair combinations in accordance with the present invention.
Still referring to FIG. 8, after the parameters are initialized, these parameters are used to calculate theoretical �induced� voltages, V1 and V2, in receivers R1 and R2, respectively, for each transmitter according to Eq. [11]. Next, the calculated voltages are used to obtain computed resistivities Rc 1 , Rc 2 , and Rc 3 (computed log) corresponding to each transmitter/receiver pair combination, respectively. Again, the computed resistivities are obtained according to methods well known in the art using data such as that shown in FIGS. 10 and 11, and the phase shift resistivities are preferred over the amplitude attenuation resistivities. The computed resistivities are then compared to the measured resistivities, and the difference between the computed resistivities and the measured resistivities is used to form a suitable error measurement. If the magnitude of the error is less than or equal to an allowable error value, Eallow, then the current values for σh, σv, and θ are taken to be the solution. Otherwise, the values for σh, σv, and θ are incremented in an iterative optimization routine until the error is within the allowable error value. Any suitable optimization routine may be used, such as a least squares method. A preferred optimization method is the Levenberg-Marquardt method discussed by Tianfei Zhu and Larry D. Brown, �Two-dimensional Velocity Inversion and Synthetic Seismogram Computation,� Geophysics, vol. 52, no. 1, January 1987, p. 37-50, which is incorporated herein by reference.
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"Two Dimensional Velocity Inversion and Synthetic Seismogram Computation", Geophysics, vol. 52, No. 1, Jan. 1987, pp. 37-49.Referenced byCiting PatentFiling datePublication dateApplicantTitleUS7948238 *May 18, 2009May 24, 2011Halliburton Energy Services, Inc.Electromagnetic wave resistivity tool having a tilted antenna for determining properties of earth formationsUS8174265 *Aug 4, 2006May 8, 2012Halliburton Energy Services, Inc.Antenna cutout in a downhole tubularUS8264228 *Jul 11, 2007Sep 11, 2012Halliburton Energy Services, Inc.Method and apparatus for building a tilted antennaUS8347985Apr 25, 2008Jan 8, 2013Halliburton Energy Services, Inc.Mulitmodal geosteering systems and methodsUS8593147Aug 8, 2007Nov 26, 2013Halliburton Energy Services, Inc.Resistivity logging with reduced dip artifactsUS8749243May 26, 2011Jun 10, 2014Halliburton Energy Services, Inc.Real time determination of casing location and distance with tilted antenna measurementUS20110221443 *Aug 11, 2009Sep 15, 2011Halliburton Energy Services, Inc.High Frequency Dielectric Measurement Tool* Cited by examinerClassifications U.S. Classification324/337, 702/7, 324/339International ClassificationG01V3/30, G01V3/28, G01V3/38Cooperative ClassificationG01V3/28European ClassificationG01V3/28Legal EventsDateCodeEventDescriptionJan 2, 2013FPAYFee paymentYear of fee payment: 4May 28, 2008ASAssignmentOwner name: HALLIBURTON ENERGY SERVICES, INC., TEXASFree format text: ASSIGNMENT OF ASSIGNORS INTEREST;ASSIGNOR:BITTAR, MICHAEL S.;REEL/FRAME:021005/0631Effective date: 20061109RotateOriginal ImageGoogle Home - Sitemap - USPTO Bulk Downloads - Privacy Policy - Terms of Service - About Google Patents - Send FeedbackData provided by IFI CLAIMS Patent Services©2012 Google