Abstract:
A correction for pileup of measurements made by a nuclear detector is applied by selecting the energy of the first signal in a pileup, ignoring the remaining signals in the pileup, and correcting the count rate by a factor related to the total pulse widths within a unit time interval. It is emphasized that this abstract is provided to comply with the rules requiring an abstract which will allow a searcher or other reader to quickly ascertain the subject matter of the technical disclosure. It is submitted with the understanding that it will not be used to interpret or limit the scope or meaning of the claims.

Description:
CROSS-REFERENCES TO RELATED APPLICATIONS 
   This application claims priority from U.S. provisional patent application Ser. No. 60/813,736 filed on Jun. 14, 2006. 

   FIELD OF THE INVENTION 
   This invention relates generally methods processing logging-while-drilling (LWD) measurements. More particularly, this invention relates to improving the accuracy and resolution made with nuclear logging instruments. 
   Oil well logging has been known for many years and provides an oil and gas well driller with information about the particular earth formation being drilled. In conventional oil well logging, after a well has been drilled, a probe known as a sonde is lowered into the borehole and used to determine some characteristic of the formations which the well has traversed. The probe is typically a hermetically sealed steel cylinder which hangs at the end of a long cable which gives mechanical support to the sonde and provides power to the instrumentation inside the sonde. The cable also provides communication channels for sending information up to the surface. It thus becomes possible to measure some parameter of the earth&#39;s formations as a function of depth, that is, while the sonde is being pulled uphole. Such “wireline” measurements are normally done in real time (however, these measurements are taken long after the actual drilling has taken place). 
   A sonde for borehole applications usually transmits energy into the formation as well as a suitable receiver for detecting the same energy returning from the formation. These could include resistivity, acoustic, or nuclear measurements. The present invention is discussed with reference to a density measurement tool that emits nuclear energy, and more particularly gamma rays, but the method of the present invention is applicable to other types of logging instruments as well. Gamma ray density probes are well known and comprise devices incorporating a gamma ray source and a gamma ray detector, shielded from each other to prevent counting of radiation emitted directly from the source. During operation of the probe, gamma rays (or photons) emitted from the source enter the formation to be studied, and interact with the atomic electrons of the material of the formation by photoelectric absorption, by Compton scattering, or by pair production. In photoelectric absorption and pair production phenomena, the particular photons involved in the interacting are removed from the gamma ray beam. 
   In the Compton scattering process, the involved photon loses some of its energy while changing its original direction of travel, the loss being a function of the scattering angle. Some of the photons emitted from the source into the sample are accordingly scattered toward the detector. Many of these never reach the detector, since their direction is changed by a second Compton scattering, or they are absorbed by the photoelectric absorption process of the pair production process. The scattered photons that reach the detector and interact with it are counted by the electronic equipment associated with the detector. 
   By obtaining the gamma ray spectrum of the received gamma rays, it is possible to infer something about the formation properties, such as density. The objective is to sort each pulse according to its amplitude. Every pulse from a linear amplifier is sorted into one of a large number of bins or channels. Each channel corresponds to signal pulses of a specific narrow amplitude range. As the pulses are sorted into the channels matching their amplitude, a pulse-height spectrum is accumulated. In this spectrum, peaks correspond to those pulse amplitudes around which many events occur. Because pulse amplitude is related to deposited energy, such peaks often correspond to radiation of a fixed energy recorded by the detector. By noting the position and intensity of peaks recorded in the pulse-height spectrum, it is often possible to interpret spectroscopy measurements in terms of the energy and intensity of the incident radiation. Additionally, the total count rate within a band of energy levels is indicative of the formation porosity. 
   Ideally when the measurement is completed the sum of all the counts that have been recorded in the channels equals the total number of pulses produced by the detector over the measurement period. In order to maintain this correspondence at high counting rates corrections must be applied to account for the dead time of the recording system and/or the pileup of two (overlapping) pulses spaced so closely in time that they appear to be only one pulse to the multichannel analyzer. The present invention addresses this problem. 
   SUMMARY OF THE INVENTION 
   One embodiment of the invention is a method of evaluating an earth formation. Radiation measurements indicative of a property of the earth formation are obtained using a logging tool conveyed in a borehole. The measurements include at least one pileup signal of at least two pulses. A peak of the first one of the two pulses is detected and the value of the peak is used for determining the property of the earth formation. The radiation measurements may be gamma ray measurements. There may be more than one pileup signal. A peak of the second pulse of a pileup may be disregarded. A waveform corresponding to the first of the two pulses may be subtracted from the pileup signal. The determination of the property may be based on deconvolving the at least one pileup signal. The determination of the property may be done using the value of the first peak to produce a count rate spectrum. The property may be the formation density. A baseline correction may be applied to the measurements. There may be more than one pileup signal. 
   Another embodiment of the invention is an apparatus for evaluating an earth formation. The apparatus includes a radiation source on a logging tool that is conveyed into a borehole. The radiation source irradiates the formation. A radiation detector on the logging tool obtains radiation measurements resulting from the radiation. The measurements include at least one pileup signal of at least two pulses. A processor detects a peak of the first of the two pulses and uses a value of the peak for determining a property of the formation. The radiation detector may be a gamma ray detector. There may be more than one pileup signal. The processor may disregard a peak of the second of the two pulses. The processor may subtract a waveform corresponding to the first of the two pulses from the pileup signal. The processor may determine the formation property by deconvolving the pileup signal. The processor may determine the formation property by using the value of the peak to produce a count rate spectrum. The property determined by the processor may be density. The processor may apply a baseline correction to the measurements. The apparatus may include a wireline, drilling tubular or a slickline for conveying the logging tool into the borehole. 
   Another embodiment of the invention is a computer-readable medium for use with an apparatus for evaluating an earth formation. The apparatus includes a radiation source on a logging tool conveyed in a borehole. The radiation source irradiates the formation. A radiation detector on the logging tool obtains radiation measurements resulting from the irradiation. The measurements include at least one pileup signal of at least two pulses. The medium includes instructions which enable a processor to detect a peak of the first of the two pulses and use the value of the peak for determining a property of the earth formation. The medium may include a ROM, an EPROM, an EAROM, a flash memory, and an optical disk. 

   
     BRIEF DESCRIPTION OF THE FIGURES 
     The present invention and its advantages will be better understood by referring to the following detailed description and the attached drawings in which: 
       FIG. 1  (prior art) shows a schematic diagram of a drilling system having a drill string that includes an apparatus according to the present invention; 
       FIG. 2  shows the components of a gamma ray logging tool used for measurements while drilling; 
       FIG. 3  shows an idealized situation in which a rotating tool in a wellbore has a minimum standoff when the tool is at the bottom of the wellbore; 
       FIG. 4A  is a schematic diagram of the pre-processing of the output of an exemplary detector; 
       FIGS. 4B and 4C  show exemplary signals at different steps of the preprocessing; 
       FIGS. 5A and 5B  illustrate the processing of pulse signals to a histogram of energy counts; 
       FIG. 6  shows an example of pileup; and 
       FIG. 7  illustrates methods by which the effect of pileup can be corrected. 
   

   DETAILED DESCRIPTION OF THE INVENTION 
     FIG. 1  shows a schematic diagram of a drilling system  10  with a drillstring  20  carrying a drilling assembly  90  (also referred to as the bottom hole assembly, or “BHA”) conveyed in a “wellbore” or “borehole”  26  for drilling the wellbore. The drilling system  10  includes a conventional derrick  11  erected on a floor  12  which supports a rotary table  14  that is rotated by a prime mover such as an electric motor (not shown) at a desired rotational speed. The drillstring  20  includes a tubing such as a drill pipe  22  or a coiled-tubing extending downward from the surface into the borehole  26 . The drillstring  20  is pushed into the wellbore  26  when a drill pipe  22  is used as the tubing. For coiled-tubing applications, a tubing injector, such as an injector (not shown), however, is used to move the tubing from a source thereof, such as a reel (not shown), to the wellbore  26 . The drill bit  50  attached to the end of the drillstring breaks up the geological formations when it is rotated to drill the borehole  26 . If a drill pipe  22  is used, the drillstring  20  is coupled to a drawworks  30  via a Kelly joint  21 , swivel  28 , and line  29  through a pulley  23 . During drilling operations, the drawworks  30  is operated to control the weight on bit, which is an important parameter that affects the rate of penetration. The operation of the drawworks is well known in the art and is thus not described in detail herein. For the purposes of this invention, it is necessary to know the axial velocity (rate of penetration or ROP) of the bottomhole assembly. Depth information and ROP may be communicated downhole from a surface location. Alternatively, the method disclosed in U.S. Pat. No. 6,769,497 to Dubinsky et al. having the same assignee as the present application and the contents of which are incorporated herein by reference may be used. The method of Dubinsky uses axial accelerometers to determine the ROP. During drilling operations, a suitable drilling fluid  31  from a mud pit (source)  32  is circulated under pressure through a channel in the drillstring  20  by a mud pump  34 . The drilling fluid passes from the mud pump  34  into the drillstring  20  via a desurger (not shown), fluid line  38  and Kelly joint  21 . The drilling fluid  31  is discharged at the borehole bottom  51  through an opening in the drill bit  50 . The drilling fluid  31  circulates uphole through the annular space  27  between the drillstring  20  and the borehole  26  and returns to the mud pit  32  via a return line  35 . The drilling fluid acts to lubricate the drill bit  50  and to carry borehole cutting or chips away from the drill bit  50 . A sensor S 1  typically placed in the line  38  provides information about the fluid flow rate. A surface torque sensor S 2  and a sensor S 3  associated with the drillstring  20  respectively provide information about the torque and rotational speed of the drillstring. Additionally, a sensor (not shown) associated with line  29  is used to provide the hook load of the drillstring  20 . 
   In one embodiment of the invention, the drill bit  50  is rotated by only rotating the drill pipe  22 . In another embodiment of the invention, a downhole motor  55  (mud motor) is disposed in the drilling assembly  90  to rotate the drill bit  50  and the drill pipe  22  is rotated usually to supplement the rotational power, if required, and to effect changes in the drilling direction. 
   In an exemplary embodiment of  FIG. 1 , the mud motor  55  is coupled to the drill bit  50  via a drive shaft (not shown) disposed in a bearing assembly  57 . The mud motor rotates the drill bit  50  when the drilling fluid  31  passes through the mud motor  55  under pressure. The bearing assembly  57  supports the radial and axial forces of the drill bit. A stabilizer  58  coupled to the bearing assembly  57  acts as a centralizer for the lowermost portion of the mud motor assembly. 
   In one embodiment of the invention, a drilling sensor module  59  is placed near the drill bit  50 . The drilling sensor module contains sensors, circuitry and processing software and algorithms relating to the dynamic drilling parameters. Such parameters typically include bit bounce, stick-slip of the drilling assembly, backward rotation, torque, shocks, borehole and annulus pressure, acceleration measurements and other measurements of the drill bit condition. A suitable telemetry or communication sub  72  using, for example, two-way telemetry, is also provided as illustrated in the drilling assembly  90 . The drilling sensor module processes the sensor information and transmits it to the surface control unit  40  via the telemetry system  72 . 
   The communication sub  72 , a power unit  78  and an MWD tool  79  are all connected in tandem with the drillstring  20 . Flex subs, for example, are used in connecting the MWD tool  79  in the drilling assembly  90 . Such subs and tools form the bottom hole drilling assembly  90  between the drillstring  20  and the drill bit  50 . The drilling assembly  90  makes various measurements including the pulsed nuclear magnetic resonance measurements while the borehole  26  is being drilled. The communication sub  72  obtains the signals and measurements and transfers the signals, using two-way telemetry, for example, to be processed on the surface. Alternatively, the signals can be processed using a downhole processor in the drilling assembly  90 . 
   The surface control unit or processor  40  also receives signals from other downhole sensors and devices and signals from sensors S 1 -S 3  and other sensors used in the system  10  and processes such signals according to programmed instructions provided to the surface control unit  40 . The surface control unit  40  displays desired drilling parameters and other information on a display/monitor  42  utilized by an operator to control the drilling operations. The surface control unit  40  typically includes a computer or a microprocessor-based processing system, memory for storing programs or models and data, a recorder for recording data, and other peripherals. The control unit  40  is typically adapted to activate alarms  44  when certain unsafe or undesirable operating conditions occur. 
     FIG. 2  illustrates the arrangement of the nuclear sensors on a logging-while-drilling device.  FIG. 2  is a diagram of the basic components for an exemplary gamma-ray density tool used for evaluating an earth formation. This tool comprises an upper section of a bottom hole assembly including a drill collar  110 . The logging tool of the present invention contains a gamma-ray source  114  and two spaced gamma-ray detector assemblies  116  and  118 . All three components are placed along a single axis that has been located parallel to the axis of the tool. The detector  116  closest to the gamma-ray source will be referred to as the “short space detector” and the one farthest away  118  is referred to as the “long space detector”. Gamma-ray shielding (not shown) is located between detector assemblies  116 ,  118  and source  114 . Windows (ports) open up to the formation from both the detector assemblies and the source. An acoustic caliper  120  may be inline and close to the gamma detectors (LS &amp; SS). A layer of drilling fluid (mud) is present between the formation and the detector assemblies and source. Also shown in  FIG. 2  are the lower section of the bottomhole assembly  122  and drill bit  124  and the logging-while-drilling device may contain one or more additional sensor assemblies with additional carrier sections  112 . The source  114  irradiates the formation with gamma-ray radiation. The detectors obtain radiation measurements resulting from the irradiation. 
   Turning now to  FIG. 3 , the logging tool  150  is shown in a typical position in a deviated borehole  162 . The term “deviated” means that the axis of the borehole is inclined to the vertical. Depending upon the context, the vertical may be an absolute vertical defined by gravity, or in some cases, may be defined by the vertical to bedding planes of the formation. For the example shown in  FIG. 3 , the borehole is inclined to the gravity vertical and hence will commonly take up a position at or near the bottom of the borehole. Four quadrants may be defined as “top”, “right”, “bottom” and “left.” The use of four quadrants is for exemplary purposed only, and in reality, measurements made by the logging tool during rotation may be binned into more than four sectors. As discussed in U.S. Pat. No. 6,584,837 to Kurkoski having the same assignee as the present invention and the contents of which are incorporated herein by reference, the measurements made during rotation may be binned by sector as well as by standoff (as measured by the caliper). Fundamental to the method of Kurkoski or any other method of analyzing measurements made by a nuclear sensor is the nature of the measurements themselves. 
   In one embodiment of the invention, the detectors  114 ,  116  may be NaI detectors, though this is not to be construed as a limitation of the invention. Turning to  FIG. 4A , the output of the detector  200  is a current pulse and is converted to a voltage pulse by the current to voltage converter amplifier  201 . Shown in  FIG. 4B  is the waveform output of the preamplifier  202 . The output have very sharp rise time and narrow pulse width, thus it is necessary to pulse shaping this signal before it can be further process. This pulse is being filter and pulse shape by the Pulse Shaping Amplifier  203 . The analog to digital converter (ADC)  206  is unipolar which means it cannot process any signal that is below ground reference. Therefore, a DC bias level is added to the signal  204 . A final amplifier stage is to amplify the signal to the correct amplitude correspond to the energy level output by the detector for further processing  205 . The output of the final amplifier stage is shown in  FIG. 4C . This output signal is then converted to digital format by the ADC  206  and then further processed by the Digital Signal Processor (DSP)  207 . 
   One of the operations that is carried out by the DSP is the processing of the raw data (which consists of a time series of a plurality of “events” that have associated amplitudes to a “count rate” spectrum as a function of energy level. This is depicted schematically in  FIG. 5A  where there is a single pulse (or event) with an amplitude of  301 , two events with an amplitude of  303  and  5  events with an amplitude of  305 . The resulting count rate is shown in  FIG. 5B  where the counts of events having amplitudes  301 ,  303  and  305  are depicted by  301 ′,  303 ′ and  305 ′. The plot of  FIG. 5   b  is a histogram of the number of events (ordinate) plotted as a function of energy level (abscissa), the energy level being related to the amplitudes of the output the signal detector  200 . 
   One of the problems that commonly occurs is that of “pileup.” This is illustrated in  FIG. 6  when there are two pulses  321 ,  323  wherein the second pulse  323  arrives before the first pulse  321  has decayed to zero. In the example shown, the resulting peak of the second pulse  323  is higher than the peak of the first pulse. Prior art methods have attempted to treat this problem by ignoring the first peak and only using the magnitude of the second peak  323 . This results in a bias in the energy count distribution such as that of  FIG. 5B  for reasons discussed next with reference to  FIG. 7 . 
   Shown in  FIG. 7  are the same two overlapping pulses, shown here as  341  and  343 . Also shown in  FIG. 7  is the tail end of the first pulses. The tail end is denoted by  345 . Visual inspection of  FIG. 7  shows that for the example shown, the peak value of the second pulse is denoted by  351 , the difference between the peak  343  and the tail end of  345  at the peak. This is clearly seen to be less than the magnitude of the peak  343 . Thus, the signal level is overestimated which, in turn, skews the histogram of  FIG. 5B  to the right. This skewing of energy levels to higher values is interpreted as resulting from more hydrogen nuclei in the pore space of the formation, i.e., a higher porosity and an underestimation of density. 
   In the present invention, there are two ways of correcting for this underestimation of density. In one embodiment of the invention, the first peak is detected where there is a pileup and the second and later peaks are ignored. Detection of the peak is done by using a peak-finding technique. The time intervals such as  301 ,  303 ,  305 , when there is no signal are added up to give a total time DT within a one second interval. The measured count-rate CR is then adjusted by dividing it by DT. This is the same as dividing the measured count-rate by (one minus the accumulated pulse widths) within a one second interval. As would be recognized by those versed in the art, selecting the first peak has the result of skewing the count rate histogram to the left, and this division corrects for it by increasing the count rate. 
   In an alternate embodiment of the invention, the actual recorded signal is deconvolved by a known reference wavelet such as  222  that characterizes the response of the system to a single isolated event. When such a deconvolution filter is applied to a signal such as that shown in  FIG. 7 , the individual pulses will be resolved and can be detected. This deconvolution is equivalent to a procedure in which the tail end of an earlier pulse is subtracted before picking a peak value for a later pulse. 
   One aspect of the invention that is used with either of the two embodiments of the invention discussed above is that of base-line correction. This base-line correction may be done by averaging the recorded signals over time intervals in which no signal is detected. The spectrum is then defined using the value of the peak relative to this baseline. 
   As would be known to those versed in the art, each pileup signal may include more than two pulses. In addition, there may be more than one pileup signal. The process count rate spectrum may then be used to determine the density of the formation and the density may be recorded on a suitable medium. This may be in the form of a log of the density and the values may be recorded digitally on a recording medium. 
   The processing of the data may be accomplished uphole after the data have been retrieved from the NMR tool&#39;s memory, or may be accomplished by a downhole processor. In the latter case the averaged velocity must be available downhole, e.g., the averaged velocity may be obtained uphole and transmitted downhole by a suitable method of telemetry. Implicit in the control and processing of the data is the use of a computer program implemented on a suitable machine readable medium that enables the processor to perform the control and processing. The machine readable medium may include ROMs, EPROMs, EAROMs, Flash Memories and Optical disks. 
   While the foregoing disclosure is directed to the preferred embodiments of the invention, various modifications will be apparent to those skilled in the art. It is intended that all variations within the scope and spirit of the appended claims be embraced by the foregoing disclosure.