Abstract:
A method and apparatus provide a time-dependent calibration to essentially eliminate pipe effect in pulse-induction logging while drilling. Use of two receivers to provide calibration and measurement information allows determination of formation properties in a downhole environment while eliminating the effect of tool effects.

Description:
FIELD OF THE INVENTION 
     The invention concerns reduction of the drill effect on transient induction measurements by use of a calibration technique. 
     BACKGROUND OF THE INVENTION 
     Use of pulse induction logging while drilling (“LWD”) resistivity measurements in downhole environments provides information about formations surrounding the borehole. Use of such techniques allows the continuation of drilling while acquiring information needed for drill steering, or to determine proximity to formation interfaces, such as gas-oil, gas-water, or water-oil interfaces. 
     U.S. Pat. No. 7,167,006 (“the &#39;006 patent”) to Itskovich, the specification of which is incorporated herein by reference, describes an apparatus and method for a pulse induction LWD system using a multi-receiver array. Use of that invention provides improved resolution of signals, allowing resolution of signals that would otherwise be unresolvable. This improved resolution is accomplished in that case by acquiring a calibration signal while the measurement tool is outside of the formation, and subtracting the calibration signal from the measurement signal obtained while the tool is in the downhole environment. 
     While the calibration technique of the &#39;006 patent provides improved resolution, still further improvements in pulse induction LWD measurements are possible. Use of two receivers in the tool can allow time-dependent calibration signals to be acquired from both receivers. These calibration signals can then be combined to create a time-dependent calibration coefficient. When pulse induction LWD measurements are taken downhole, the measurement signals received by the two receivers can be combined with the calibration coefficient to generate a time-dependent differential measurement signal. This high resolution signal provides an improved ability to resolve interfaces in the formation surrounding the borehole. 
     Accordingly, it is an object of the invention to provide improved resolution of boundary locations in formations surrounding boreholes. 
     It is another object of the invention to provide measurements of boundaries in formations for use in real-time geo-steering of drilling operations. 
     It is yet another object of the invention to provide measurements to determine the location of interfaces in a formation, such as gas-water, gas-oil, or water-oil interfaces. 
     SUMMARY OF THE INVENTION 
     The invention comprises a method and apparatus for substantially eliminating the drill effect in pulse induction LWD resistivity measurements. A multi-stage method comprises a first calibration stage and a second measurement stage. The apparatus used in performing these measurements comprises a transmitter and two receivers. The receivers are longitudinally separated from the transmitter on the tool, and may be placed on the same side of the transmitter or may be placed on opposite sides of the transmitter. In a preferred embodiment, the transmitter and the receivers are mounted on a conductive section, covered with a ferrite shield. 
     Spacing between the receivers and the transmitter is primarily a matter of engineering choice. However, if the tool is to be used in a geo-steering application, it is important to avoid symmetrical placement of the receivers relative to the transmitter. In the event that the borehole runs parallel to a boundary, such as a water-oil boundary, symmetrical placement of the receivers relative to the transmitter could result in a zero-signal result using the calibration method of this invention. 
     In accordance with the invention, while outside of the formation, the tool is placed in the presence of a pipe and pulse induction measurements are made by inducing a time-dependent current in the transmitter. Time-dependent calibration signals are obtained and recorded from each of the receivers. These calibration signals provide information reflecting the effects of the pipe at the receivers. The calibration phase thus provides time-dependent calibration signals C 1 (t) and C 2 (t). These signals can be recorded in a processor, such as a computer. 
     Once the calibration information is recorded, the tool may be run downhole to a position within a formation to be tested. Pulse induction resistivity measurements can then be made, again by inducing a time-dependent current in the transmitter, and utilizing the same pulse heights and timing as with the calibration phase. The two receivers will thus produce time-dependent measurement responses S 1 (t) and S 2 (t). Providing these signals to the processor storing the calibration information allows the resolution of a time-dependent differential signal ΔS(t)=S 2 (t)−(S 1 (t)·C 2 (t)/C 1 (t)). This differential signal is substantially unaffected by the pipe and allows determination of parameters of the surrounding formation. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
         FIG. 1  is a schematic drawing of one embodiment of a tool of the present invention. 
         FIG. 2  is a graph depicting modeling results of a pulsed induction measurement for a tool with a transmitter and a single receiver at a spacing of 0.5 meter. 
         FIG. 3  is a graph depicting modeling results of a pulsed induction measurement for a tool with a transmitter and a single receiver at a spacing of 2 meters. 
         FIG. 4  is a graph depicting the results of applying the present invention by combining the results of the tests depicting in  FIGS. 2 and 3 . 
     
    
    
     DETAILED DESCRIPTION 
     Referring to  FIG. 1 , a schematic representation of a tool of the present invention is shown. Tool  10  comprises a mandrel  12 , preferably with a conductive body of a material such as ferrite. A transmitter  14  is spaced longitudinally away from a first receiver  16  and a second receiver  18 . Transmitter  14  is electrically connected via connection  20  to a processor, such as a computer,  22  which provides the current pulses used in the LWD resistivity measurements. First receiver  16  and second receiver  18  are connected to processor  22  via connections  24  and  26 , respectively. Processor  22  stores calibration information and processes received signals during pulsed induction measurements, and may optionally be used to control the steering of a drill bit. Those of skill in the art will recognize that processor  22  may embody one or more computers, and may be controlled via a user interface or programmed for automatic operation. 
     First receiver  16  and second receiver  18  are oriented along the same direction. The spacing d between first receiver  16  and second receiver  18  is a matter of engineering preference, and these receivers may optionally be placed on opposite sides of transmitter  14 . However, as noted above, the receivers should not be symmetrically placed about transmitter  14  in a geo-steering application, because application of the present invention may result in zero signal in this configuration if the borehole parallels a water-oil boundary. 
     Referring to  FIG. 2 , modeling results are shown for a first receiver (such as first receiver  16  of  FIG. 1 ) spaced at 0.5 meter from a transmitter (such as transmitter  14  of  FIG. 1 ). The results are modeled for a boundary between two layers of resistivities of 50 Ω·m and 2 Ω·m, respectively. The model includes a conductive pipe with resistance of 0.714·10 −6  Ω·m, and a ferrite nonconductive shield of length 1.5 m and μ=400. First calibration curve  210  reflects the signal from the pipe alone in the absence of a formation. First measurement curve  212  reflects the signal from the formation with a boundary spaced four meters from the tool. Second measurement curve  214  reflects the signal from the formation with a boundary spaced six meters from the tool. Third measurement curve  216  reflects the signal from the formation with a boundary spaced eight meters from the tool, and fourth measurement curve  218  reflects the signal from the formation with a boundary spaced ten meters from the tool. The second, third, and fourth measurement curves are insufficiently resolved to provide meaningful information. 
     Similarly, referring to  FIG. 3 , measurement curves are modeled for the same formation and pipe parameters as in  FIG. 2 , but with a second receiver (such as second receiver  18  of  FIG. 1 ) spaced at 2 meters from a transmitter (such as transmitter  14  of  FIG. 1 ). Second calibration curve  310  reflects the signal from the pipe alone in the absence of a formation. Fifth measurement curve  312  reflects the signal from the formation with a boundary spaced four meters from the tool. Sixth measurement curve  314  reflects the signal from the formation with a boundary spaced six meters from the tool. Seventh measurement curve  316  reflects the signal from the formation with a boundary spaced eight meters from the tool, and eighth measurement curve  318  reflects the signal from the formation with a boundary spaced ten meters from the tool. Similarly to  FIG. 2 , the sixth, seventh, and eighth measurement curves are insufficiently resolved to provide meaningful information. 
     However, application of the method of the present invention to the data of  FIGS. 2 and 3  provides a more meaningful result, as reflected in  FIG. 4 . Four calculated curves  410 ,  412 ,  414 , and  416  are depicted as calculated for the boundary spacings of 4, 6, 8, and 10 meters, respectively. These curves are calculated by determining, for each curve,
 
Δ S ( t )= S   2 ( t )−( S   1 ( t )· C   2 ( t )/ C   1 ( t )).
 
     For example, for the four meter boundary distance curve, S 1 (t) is depicted by first measurement curve  212  of  FIG. 2 , and S 2 (t) is depicted by fifth measurement curve  312  of  FIG. 3 . For each of the four curves, C 1 (t) is first calibration curve  210  of  FIG. 2 , and C 2 (t) is depicted by second calibration curve  310  of  FIG. 3 . The time-dependent calibration coefficient C 2 (t)/C 1 (t) is shown in  FIG. 4  as curve  418 . As reflected in  FIG. 4 , application of the present invention to these curves produces adequate resolution to allow determination of boundary locations at each of the 4, 6, 8, and 10 meter positions. 
     The above examples are included for demonstration purposes only and not as limitations on the scope of the invention. Other variations in the construction of the invention may be made without departing from the spirit of the invention, and those of skill in the art will recognize that these descriptions are provide by way of example only.