GB2346915A - Method of determining formation properties while drilling a borehole - Google Patents

Abstract

A method of determining a parameter of interest of the formation surrounding a borehole during drilling with a drilling assembly 90 comprises using a plurality of sensors (301, Fig 3C) at known positions on the assembly to obtain data relating to the parameter, transmitting from a surface control device 40 information about the depth of the drilling assembly to a telemetry device 286 on the drilling assembly, obtaining the orientation of the plurality of sensors by using a directional sensor 271 disposed in the assembly, processing the data about the parameter in a processor 272 disposed in the drilling assembly by using the orientation of the sensors and the information about the depth of the drilling assembly to give processed data about the parameter, and transmitting said processed data about the parameter to the surface using the telemetry device on the drilling assembly.

Description

2346915 WASUREMENT-W-EME-DRILLING DEVICESWUH PAD MQUNTED SENSOLZS TWs

invention relates to the acquisition and processing of data acquired by a measurement-while-drilling (NOWD) tool during the drilling of a wellbore. More particularly, the invention relates to methods and devices for acquiring data downhole using sensors in contact with the, borehole wall, processing the data and transmitting to the surface, in real-time, parameters of the formation penetrated by the borehole as the borehole is beir,.S drilled using M-WID telemetry.

Modern well drilling tecliriques, particularly those concemed with the drilling of oil and gas wells, involve the use of several different measurement and telemetry systerns to provide petrophysical data and data regarding drilling mechanics during the driffing process. Data -is acquired by sensors located in the drill string near the bit and eltber stored in downhole memory or transmitted to the surface using NM telemetry devices. Prior axt discloses the use of a downhole device incorporating resistivity, gravity and magnetic measurements on a rotating drillstring. A downhole processor uses the gravity and magnetic data to determine the orientation of the drill string and, using measurernewts from the resistivity device, makes measurements of formation resistivity at time intervals selected to give measurements spaced around the borehole. These data are compressed and transmitted uphole by a mud pulse telemetry system. The I depth of the resistivity sensoris computed at the surface and the data are dicornpressrzd to give a resistivity image of the face of the borehole wall with an azimuthal resolution of 30 0 -.

Prior art methods are limited to making resistivity measurements in the subsurface and fail to address the issue of other useful measurements that could be made using an NIVvrD device. Prior art devices are also limited to measurement devices that rotate with the drill string and do not take advantage of current dHUing methods wherein a mud motor is used and the drill bit could be rotating at a different speed from the drill string or wherein a non-rotating sleeve may be available on which substantially non-rotating measuring devices could be located- The rate at which measurements are rnade is selected to be constrained by the data u-ansmission rate of the telemetry system. Prior aft systems thus fdtl to take advantage of the inherently higher capability of measuring devices and the ability to use redundant data to improve -6he signal-to-noise (SIN) ratio. Prior art also relies on an uphole determination of the d2pth of the too[, wherm if the determination of the depth of the tool were made downhole intelligent decisions- could be made about the amount of data to transmit uphoic. The present invendon overcomes these inadequ.a6es.

The present invention is an apparatus and method of making measurements of a plurality of parameters of interest of the formation surrounding a borehole. In one aspect of the invention, the drill bit is mounted on a rota!-Inq drillstring, and the downhole assembly is provided with sensors that rotate with the drillstring to make 2 meaureinents of the parameters of interest. The assembly is provided with magnetic and'inertial sensors to provide information on the orientation of the measurement sensors. A telemetry system sends information downhole about the depth of the drilling assembly. A processor downhole combines the depth and azimuth information with the measurements made by the rotating sensors, uses redundancy in the data to improve SIN ratio, compresses the data'nd sends it uphole by a telemetry system or stores it downhole for later retrieval.

In another aspect of the invention, the drill bit is driven by a downhole chilling motor. The motor may be on a rotating drillstring or on coiled tubing. The sensors for measuring the parameters of interest could be rotating with the drill bit. Alternatively, the sensors could have one of several configurations. Tn one configuration, the sensors are mounted on a substantially non-rotating sleeve; in another configuration, the sensors are mounted on pads that could be rotating or non-rotating, the pads being hydraulically or mechanically actuated to make contact with the borehole wall, in yet another configuration, the sensors are mounted on substantially non- rotatins rib sTeering devices used to control-the direction-of Ihe downhole d tool. In any of these arrangements, the downhole assem1bly is provided with sensors that make measurements of the parameters of interest. The assembly is provided with magnetic ana irlerlial sensors to provide information on the oiieatation of the measurement sensors. A telemetry system sends information downhole about the depth of the drilling assembly. A microprocessor downhole co,-nbin.s the depth and azimuth information with the measurements made by the rotating sensors, uses redundancy in the data to improve S/N ratio, compresses the data and sends it uphole by a telemetry system. The parameters of interest miclude resistivity, density, Compressional and shear wave velocity and structure, dipmeter, acoustic porosiry, NrMR proper-ties and seismic images of the formation..

As a backup to, or independently ot obtaining the depth information by downhole telemetry, the present invention also provides a capability in the downhole microprocessor to use measurements ft6m sensors at more than one depth to provide a rate of penetration.

Various embodiments of the present invention will now be described, by way of example only, and with reference to the accompanying drawings in which: FIG. I is a schematic illustration of a drilling-system. FIG. 2 illustrates a drilling assembly for use with a surface rotary system for drilling boreholes wherein the drilling assembly has a non-rotating sleeve for effecting directional changes downhole. FIG. 3A illustrates the arrangement of resistivity sensors on a pad. FIG 313 illustrates the overlap between pads on a rotating sensor arrangement. FIG. 3C illustrates the pads oria non-rotating sleeve used for resistivity measurements. FIG. 3D Mustrates the a pad used for resistivity measurements that rotates with the drilling shaft. FIG. 3E illustrates the arrangement of density sensors according to the present invention. FIG. 3F illustrates the arrangement of elastic transducers on a pad.

4 FIG. 4 illustrates the acquisition of a s I et of reverse VSP data according to the present invention. FIGS. 5A- 5B show a method by which depth is calculated downhole. FIG. 6A and 6B are schematic illustrations of the sequence of data flow in processing the data. FIGS. 7A - 7D are schematic illustrations of the invention in which NMR measurements are made using pad mounted sensors, FIG. 8 illustrates an arrangement of permanent magnets on the housing according to one aspect of this invention. FIGS. 9A - 9C are schematic illustrations of the. invention in which electromagnetic induction measurements are made at various azimuths.

FIG. I shows a schematic diagram ofa drilling system 10 having a drilling assembly 90 shown conveyed in a borehole 26 for drilling the wellbore. The drilling system 10 includes a conventional derrick 11 erected on a floor 12 which supports a -rbtary table 14 that is roaed -by a prim.c. mover such as an electric motor (not shown) at a desired rotational speed. The drill string 20 includes a drill pipe 22 extending downward ftom the rotary table 14 into the borehole 26. The drill bit 50 attached to the end of the dTill string break's up the geological formations when it is rotated to drill the borehole 26. The drill string 20 is coupled to a drawworks 30 via a Kelly joint 21, swivel, 29 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 affecis the rate of penetration. The operation of the drawworks is well known in the art and is thus not described in detail herein.

During drilling operations, a suitable drilling fluid 31 from a tnud pit (source) 32 is circulated under pressure thoiigh the drill string by a mud pump 34. The drilling fluid passes from the mud pump 34 into the drill string 20 via a desurger 36, fluid line 28 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. drill string.20 and the borehole 26 and returns to the mud pit 32 via a return line 35. A sensor S, preferably placed in the line 38 provides information about the fluid flow rate. A surface torque sensor S, and a sensor S3 associated with the drill string respectively provide information about the torque and rotational speed of the drill string. Additionally, a sensor (not shown) associated with line 29 is used to provide the hook load of the drill string 20.

in one embodiment. of the invention, the drill bit 50 is rotated by only rotating the dffll pipe 52. 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 driU pipe 22 is rotated usually to supplement the rotational power, if required, and to effect changes in the drilling direction.

In the preferred 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 5-1, under pressure, The bearing assembly 57 supports the radial and a)dal forces of the 6 drill bit. A stabilizer 58 coupled to the bearing assembly 57 acts as a centralizer for the lowermost poriion 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 serisor.,module contam-is'"sen'sors, circuitry and processing software and algorithms relating to the dynamic drilling parameters. Such parameters preferably include bit bounce, stickslip of the drilling assembly, backmwd rotation, torque, shocks, borehole and annulus pressure, acceleration measurements and other measurements of the drill bit condition. The drilling sensor module processes the sensor information and transmits it to the surface control unit 40 via a suitable telemetry system 72.

FIG. 2 shows a schematic diagram of a rotary drilling assembly 255 conveyable downhole by a drill pipe (not shown) that includes a device for changing drilling direction without stopping the drilling operations for use in the drilling system 10 shown in FIG. 1. The drilling assembly 255 has an outer housing 256 with an upper joint 257a for connection. to. the-drill pipe (49i shown) and a lower joint 257b for accorrirriodating the drill bit 55. During drilling operations, the housing, and thus the drill bit 55, rotate when the drill pipe is rotated by the rotary table at the surface. The lower end 258 of the housirig 256 has ieduced outer dimensions 258 and bore 259 therethrough. The reduced-dimensioned end 258 has a shaft 260 that is connected to the lower end 257b and a passage 26 for allowing the drilling fluid to pass to the drill bit 55. A nonrotating sleeve 262 is disposed on the outside of the reduced dimensioned end 258, in that when the housing 256 is rotated to rotate the drill bit 55, 11-0 7 the non-rotating sleeve 262 remains in its position. A plurality of independently adjustable or expandable pads 264 are disposed on the outside of the non-rotating sleeve 262. Each pad 264 is preferably hydraulically operated by a control unit in the dril4ng assembly 256. A plurality of formation sensors is located on each of the pads 264. Those versed in the art would also recognize that these pads, because they are provided with the abifity for selectively extending or retracting during drilling operations, can also be used as stabilizers -and for controlling the drilling directionMechanisrns for extending the pads to make contact could be operated by hydraulic, meclianical or electrical devices. A commonly used mechanical arrangement is to hav the pads mounted on springs that-.keep the pads in contact with the borehole wall, Such devices would be familiar to those versed in the art. Alternatively, the drUling assembly could be provided with separate stabilizer and steering assemblies. The arTangernent of the formation sensors is discussed below in reference to FIG. 3A- 3F The drifling assembly also includes a directional sensor 271 near the upper end 257a and sensors for deterrnining,the temperatum, pressure e.v fluid flow rate, weight on bit, rotational speed of thedTilLhit, radial anda.xi.al vibrAtions, shock and whirl, Without lirniting the scope of the invenftior the directional sensors 271 could be of the magnetic or inertial type- The drilling assembly 255 preferably includes a number of C non-magnetic stabilizers 276 near the upper end 257a for providing lateral or radial stability to the driU string during drilling operations. A flexible joint 278 is disposed between the section 280 and the section containing the non-rotatin$ sleevc 262. A control unit designate by 284 includes a control circuit or circuits having one or more processors. The processing of signals is performed generally in the manner described below in reference to FIG. 5A-5B. A telemetry device, in the form of an electromagnetic device, an acoustic devise, a mud-pulse device or any other suitable device, generally designated herein.by 286 is disposed ki the drilling assembly at a suitable place. A microprocessor 272 is also disposed in the drilling assembly at a suitable location.

FIG. 3A illustrates the arrangement of-aplurality ofresistivity sensors on a single pad 264. The electrodes are arranged in a plurality of rows and columns: in FIG. 3A, two colu=s and four rows are shown, with the electrodes I identified from 301aato3OIdb. Ina typical arrangement, the buttons would bean inob apart. Having a plurality of columns iftereases. the a;dmuthal resolution of resistivity measurements while having a plurality of Tows increases the vertical resolution of resistivity measurements.

FIG 3B illustrates how a plurality of pads, six in this case, can provide resistivity measurements around the borehole. In the figure, the six pads are shown as 264 at a particular depth of"the. drilhng assembly. For illustrative purposes, the borehole wall has been "unwrapped" with the six pads spread out over 3 60') of azimuth. As noted above, the pads are on arms that extend outward from the tool body to contact the wall. The gap between the adjacent pads will depend upon the size of the borehole: in a larger borehole, the gap will be larger. As the drilling proceeds, the tool and the pads will move to a different depth and the new position of the pads is indicated by 264'. As can be seen, there i s an overlap between the positions of the pads in azimuth and in depth. The tool orientation is determined by the microprocessor 9 272 from the directional sensors 271. This overlap provides redundant measurements of the resistivity that are processed as described below with reference to FIG. SA and 5D.

Those versed in the art would recognize that even with a substantially nonrotating sleeve on the drilling assembly, some rotation of the sleeve will ocwr. With a typical drilling rate of 60 fet p'e:r'- hour, mi one; mi-nute, the tool assembly will advance one foot. With a typical rotary speed of 150 rpm even a sleeve designed to be substantially non rotating could have a complete revolution in that one minute, providing for a complete overlap. Those versed in the art would also recognize that III an alternate disposition of the sensor that rotates with the drill bit, a complete overlap would occur in less than one second.

FIG. 3C illustrates the: arTangernent of the sensor pads in one embodiment of the present invention. Shown-ate the drillingshaft 260 with the non-rotating sleeve 262 mounted thereon. Pads 264 -%ith sensors 301 are attached to sleeve 262. The mechanism for moving the pads. out to contact the borehole, whether it be hydraulic, a spring mechanism or another mechanism is not shown. Two toroids 305 that are wound with a current cm-rying conductor (not shown) surround the shaft. The toroids are arranged with same polarity, so that upon passage of a current in the toroid, a magnetic circumferential magnetic field is induced in the two toroids. This magnetic field, in turn, induces an electric field along. the axis of the shaft. The leakage current measured by the sensors 301 is then a measure of the -.-esistivity of the formation ad I acent to the sensors, with the leak-age current being substantially radial. Such an arrariggernent has been used before in wireline logging but has not been attempted before in measurement while drilling, applications. The shaft 260 is provided with stabilizer ribs 303 for controllina the direction of drilling.

ZZ, In an alternate arrangement shown in FIG. 3D, the pad 324 is coupled to the shaft 340 by the mechanism for engaging the shaft to the borehole (not shown), so that it rotates with the shaft rather: than bging nonrotating. The stabilizer 333 serves the same function as in FIG. X while the current carrying toroids 323 produce an electric field that operates in the same manner as in the discussion above with respect to FIG. 3C.

FIG, 3E illustrates the arrangement of density sensors according to the present invention. Shown is a cross section of the borehole with the wall designated as 324 and the tool generally as 258. The pads engage the walls of the borehole with a radioactive source in pad 364a and receivers on pads 364b and 364c. This arrangement is similar to that used in wireline tools except that in wireline tools, the source is located in the body of the tool.

The pads could also have elastic ( commonly reflerred to as acoustic) transducers mounted on them. In the simplest arrangement shown in FIG. 3F, each pad has a three component transdaceT ( or, equivalentily, three single component transducers) mounted thereon. The transducer is actapTed to engage the borehole wall and capable of pulsating or vibratory motion in three directions, labeled as 465a, 465b and 465c. Those versed in the art would recognize that each of these excitations I I generates compressional and shear waves into the formation. Synchronized motion of trazsducers on the plurality of pads introduces seismic pulses of different polarization into the formation that can be detccted at other locations in the simplest configuration, the detectors arelocated on the surface (not shown) and can be used for imaging the subsurface formAtions of the earth. Depending upon the direction of the pulses on the individual pads, compressional and polarized shear waves are preferentially radiated in differept. directions.

FIG. 4 illustrates the acquisition of a set of reverse VSP data according to the present inveption. A plurality of seismic detectors 560 are disposed at the surface 510. A borehole 526 drilled by a drill bit 550 at the end of a drillstring 520 is shown. The downhole drilling assembly, includes seismic sources 564 on pads that engage the walls of the borehole. Seisnic waves 570 radiating ftorn the sources 564 are reflected by boundaries such as 571 and 573 and detected at the surfare by the detectors 560, The detection of these at the surface for. different depths of the. drilling assembly gives what is called a reverse Vertic,,d Seismic Profile CVSP) and is a powerful method of imaging formations ahead of the drill bit. Processing of the data according to known methods gives a seismic 1-ma-ge-of the subsurface. While reverse VSPs using the drill bit itself as a seismic source have been used in the past.. results are generally not satisfactory due to a lack of knowledge of the charazt-istics of the seismic signal and due to poor S/N ratio. The present invention, in which the source is well characterized and is in essentWly the same posiTion on a non-rotating sleeve has the ability to improve the S/N ratio considerably by repeatedly exciting the sources in essentially the same position. Those versed in the seismic art would be familiar with the pattern of 12 energy radiated into the formation by the different directions of motions of the transducers 465 and their arrangement on a circular array of pads.

Those versed in the art would also recognize that instead of seismic pulses, the seismic transmitters could also generate swept-frequency signals that continuously sweep through a selected range of frequencies. The signals recorded at the transmitters can be correlated with the swept frequency signal using well known techniques to produce a response equivalent to that of an impulsive selsmic soutee. Such an arrangement requires less power for the transmitters and is intended to be within the scope of the invention.

The VSP configuration could be reversed to that of a conventional VSP, so that downhole sensors on a non-rotating sleeve measure seismic signals from a plurality of sufface source positions. Such an arrangement would suffer from the disadvantage that a considerahiy greater.amount of data would have to be transmitted uphole by telemetry.

In an alternate uranc,,,,ement (not shown), two sets of axially spacedapart pads are provided on the non-rotating sleeve, The second set of pads is not illustrated but it has an arrangement of detectors that measure three components of motion similar to the excitation produced by the sources 465. Those versed in the art would recognize that this gives the ability to measure compressional =%," shear velocities of the formation between the source and the receiver. In particular, because of the ability to directly couple a seismic source to the borehole wall, shear waves of different I') polarization can be generated and detected. Those versed in the art would know that in an anisotropic formation, two different shear waves vnith different polarization and velocity can be propagated (called the fast and the slow shear wave). Measurement of the fast and slow shear velocities gives information about fracturing of the formation and would be familiar to those versed in methods of processing the data to obtain this fracturing information.

The same arrangement of having seismic transmitters and receivers on nonrotating pads in the drilling assembly makes it possible to record reflections from surfaces in the vicinity of the borehole. In particular, it enables the device to obtain distances to seismic reflectors in the vicinity of the borehole. This information is useful in looking ahead of the drillbit and in guiding the drillbit where it is desired to follow a particular geologic formation.

Those versed in the art would recognize that by having an arrangement with four electrodes substantially in a linear arrangement on a number of non-rotating pads, the outer electrodes being a transmitter and, a receiver respectively, and by measuring the potential difference between the inner electrodes, a resistivity measurement of the formation can be obtained. Such an arrangement is coa:Jdered to be conventional in '%ireline logging applications but has hitherto not been used in measurement-whiledriffing applications because of the difficulty in aligning the electrodes on a rotating drillstring.

14 The formation sensor assembly discussed above with respect to FIG. 2 is locaTed on a nori-rotating sleeve that is part of a drilling assembly which includes a downhole mud motor. Those versed in the art would recognize that an equivalent arrangernent can be implemented)Wherein instead of a drillstring, coiled tubing is used. This arrangement is intended to be within the scope of the present invention.

in an alternate embodiment of the invention, the formation sensor assembly could be directly mounted on the rotating drill-string without detracting from its effectiveness. This was discussed above with respect to resistivity sensors in FIG. 3D The method of processing of the acquired data from any one of these arrangements of formation sensors is discussed with reference to FIGS 5A- 5B- For illustrative purposes, FIG. 5A illustrates the "unwrapped" resistivity data that might be recorded by a first resistivity sensor rotating in a vertical borehole as the well is being drilled. The horizor)W axis 601 has values from 00 to 3600 corresponding to azimuthal angles from a reference direction determined by the directional sensor 271. The vertical axis 603 is the time of measurement. As the resistMty sensor rotates in the borehole while it is moved along with the drill bit, it traces out a spiral path. Indicated in. FIG 5A is a sinusoidal band 604 corresponding to, say, a bed of high resistivity intersecting the borehole at a dippinly angle.

In one embodiment of the invention, thc. downhole processor 272 uses the depth information from dowril-iole telemetry available to the Telemetry device 286 and sums all the data within a specified depth and azimuth sampling interval to improve the S/N ratio and to reduce the amount of data to be stored. A typical depth sampling interval would be one -inch and a typical azimuthal sampling interval is 150. Another method of reducing the amount of data stored would be to discard redundant samples within the depth and azimuth sampling interval. Those versed in the art would recoanize that a 2-D filtering of the data set by known techniques could be carried out 0 prior to the data reduction. The data after this reduction step is displayed on a depth scale in FIG 5D where the vertical axis 605 is now depth and the horizontal axis 601 is still the azimuthal angle with respect to a refereace direction. The dipping resistive bed p. osition is indicated by the sinusoid 6041, Such a depth image can be obtained ftom a time image if at times such as 607 and 609, the absolute depth of the resistivity sensor, 607' and 609' were known.

As a backup or as a substivote for communicating depth information downhole, the microprocessor uses data ftom the additional resistivity sensors on the pads to determine a rate of penetration during the drilling. This is illustrated in FIG SA by a second resistivity band 616 corresponding to the same dipping band 604 as measured at a second resistivity sensor directly above the first resistivity sensor. The spacing between the first and second resistivity sensors being known, a rate of penetration is computed by the microprocessor by measuring tne time shift between the bands 604 and 616. The time shift between thc bands 604 and 606 could be determined by one of many methods, including cross-cori-elation techniques. This knowledge of the rate of penetration serves as a check on the del3th information communicated downhole and, in the absence of the downhole telemetry datz can be used by itself to calculate the depth of the sensors.

16 The method of processing discussed above works equally well for resistivity,zeasurements made by sensors on a non-rotating sleev As noted above w th reference to FIG. 3B, there is r.ill 9 slow _otation of the sensors that provides redundancy that can be utilized by the processor 272 as part of its processing-beforetransmission.

FIG. 6A illustrates the flow of data in one embodiment of the invention, The plurality of azimuthal data sensors (301 in FIG. 3A) are depicted at 701. The output 701a of the azimuthal data sensors 701 is azimuthal sensor data as a function of time. The direction sensors (271 in FIG. 2) are denoted at 703. The output 703a of the direction sensors 703 is the azimuth of the drilling assembly as a function of time. Using timing information 705a from a clock 705 and the information 709a from the drilling ahead indicator 709,, the.proc essor first. carries out an optional data decimation and compression step at 707. The drilling ahead indicator uses a plurality of measurements to estimate the rate of advance of the drill bit. A sensor for measuring the weight on the drill bit gives measurements indicative of the rate of penetration: if the weight on the drill bit is zero, then the rate of peneTration is also zero. Similarly, if the mud flow indicator indicates no flow of the mud, then too the drill bit is not advancing. Vibration sensors on the drill bit also give Signalsindicative of the forward movement of the drill bit. A zero value for weight on the drill bit, mud flow or drill bit vibration means that the sensor assembly is at a consmat depth, This step of data decimation and compression may stack data from multiple rotations of the sensor assembly that fallwithin a predeten-nined resolution required in the imaging of the data. This information 707a consisting of data as a finiction of azimuth and depth is stored:in a memory buffer 711. A memory buffer with 16 IvMyte size is used, adequate to store the data acquired using one segment of drill pipe. As would be known to those versed in the art, the drill pipe comes in segments of 30 feet, successive segments being added at the wellhead as d rilling progresses.

Using estimates of the drilling speed from 717, and a drilling section completed indicator 713 a depth - time correlation is performed '715. The drilling section completed indicator includes such infomistion as the number of drill string segmems. The drilling rate estimate is obtained, e. g., from the method given in the discussion of FIGS. SA and 5B above. The time-depth transformation function 715a obtained by this is used at'719 to process the data as a function of azimuth and time in the memory buffer 711 to give an image that is a function of azimuth and depth. This image is stored downhole at 721 in a rn.mory bufFer. With 16 Mbytes of memory, it is possible to store 17oo feet of data downhole with. a I inch resolution. This data is later rc,-Lrieved when tripping thc, weli, o,.couid be. transnatted uph ofe using the telemetry device 296. By processin-a the data downhole in this fashion, the demand on the telemetry device is greatiy reduced and it can be used for transmitting, other data relating to the drilling motor and the drill bit uphole.

The memory requirement for sioring the data are easily computed. For example, for an 8 1/2" hole, storage of one foot of data with a resolution of I" x I" 19 requires (12) x Ox x 8.5) x 4 1282 data points. (Those versed in the art would recognize the factor of 4 as arising from having to satisfy the Nyquist sampling critedon in two dimensions). For 5000 ft. of data and 16 bits (2 bytes) per data sample, this gives a total of 12.82 MBytes, This is a reasonable size for a memory with presently available hardware and can, of -course, be increased in the future as memory devices become more compact.

Where the depth data is not available downhole, the situation is changed due to the variability of the drilling rate. The system must be able to collect data at a fast 0 drilling rate of 200 ft./hr. as well as at a slow drilling rate of 20 ft. /hr., a factor of 10 variability. Systems that do not know the drilling rate will need to store data to accommodate the fastest drilling rate (200 ft./hr. in this example). If the hole is actually drilled at 20 ft/hr then the amount of data that.would have to be stored downhole -in the absence of any processing and decimation becomes ten times as large: 130 Mbytes in the present example, This amount of data storage is at present impractical with available hardware.

The arrangement shown in FIG. 6A does not use any telemetry data from the surface to cornpute depth. In an alternate arrangement shown in FIG. 6B, a depth calculation is performed downhole at 759 to give an act" position of the sensor assembly using infonnation ftom a number of sources including telemetry data. One is the timing information 755a from the clock 755. A drilling, speed sensor gives an indication of the drilling speed. Drilling speed 756a is obtained from one of two sources 756. In one embodiment, a downhole inertial sensor (not shown) is 19 initialized each titne that drilling is stopped for adding a section of drill pipe. The information from this inertial sensor provides an indication of drilling speed. In addition, or as an alternative, drilling speed transmitted orn the surface by the downlink telemetry could be used and received at the downhole telemetry device 286 is used.

An indicator of the drilling section completed 761, as discussed above "Nith reference to 713 in FIG. 6A is used as an additional input for the depth calculations, as is an estimate from the drilling ahead indicator 763, discussed above with reference to 709 in FIG. 6A. This depth calculation 759a"is used in data compression and decimation 757 (as discussed above with refer'enoc to FIG. 6A) to process data 751a from the azimuthal measurement sensors 751 and the data 753a orientation sensors 753. The image processing at 765 SiYes the image data as a function of depth 765a, this data being stored dommhole 767 with the same resolution as at 721 in FIG. 6A. The processing scheme of FIG. 6B does not require the memory buffer 711 that is present in FIG. 6A; however, it does require more depth data to be transmitted downhole, thus tying up the telemetry link to some extent.

As noted above in the discussion of FIGS. SA- 5B, a combination of both methods could also be used, i.e. perform depth calculations from sensor data downhole in addition tu using dowilnked data.

The discussion above was vAth respect to resist.ivity measurements. Any other scalar measurement made by a sensor can be treatea in the same fashion to improve the S/N ratio prior to transmitting it uphole by telemetry. Vector data, such as acquired by compressional and shear wave transducers requires somewhat more complicated processing that would be known to those versed in tb-- art.

As mentioned above, the data transmitted from dovmhole is indicative of resistivities at uniformly sampled depths of layers of the formation. The data is transmitted in real time, The processes and apparatus described above providea relatively high resolution color in ag e I ge of th formation in real-time. The resolution of this image may be enhanced even finther by using various image enhancement algorithms. These image enhancing, algorithms would be familiar to those versed in the The basic sensor configuration of FIG. 3C is also used in another embodiment of the invention to make Nuclear Magnetic Resonance (NUR)measurernents. This is illustrated schematically in FIGS. 7A and 7B. The sleeve 862 is provided with at least one pad 880 that makes contact with the borehole wall. Included in the pad is a permanent magnet assembly $83 denoted here by.individual magnets 883a, 883b and 883c. In a preferred embodiment, the two magnets on the sides are oriented with like poles in the same direction and the magmet in the middle is oriented v4th its poles opposite to the poles of the side magnets. With the arrangement of magnets shown, a static magnetic field is produced Mthin the formation adjacent to the pad 280. As g would be known to those versed in the art, there is a region, known as the regior, of examination, within which the field strength is substantially constant and the field direction is radiaL

21 NMR measurements are made by inducing a Radio Frequency (RF) field in the formation that has a direction that is orthogonal to the static magnetic field and making measurements of the relaxation of the spin induced by the RF field. Fig. 7B shows one arrangement in which a conductor 886 is arranged in an axial direction in the pad 880 with a conducting sheath 889 and soft ferrite 887. By pulsing an RF current through the conductor 886 with a returnpah through the sheath 888, an RF magnetic field is induced in the formation with. a -substantially tangential field direction, i.e., circumferential with respect to the axis of the borehole. This is orthogonal to the static field in the region of examination. The transmitter is turned off and the arrangement is used to measure the RF field produced by the relaxation of the spin induced by the RIF field withi.-ti the formation,

An alternate arrangement of the permanent magnets is illustrated in perspective "ew in FIG. 7C. A pair ot permanent magnets 785a and 785b in the shape of arcuate segments of cylinders are disposed in an axial direction with the direction of I I magnetization of the two magnets in opposite directions. This, or similar arrangements comprising more than one pair of magnets, produces a region of examination in the formation with a substantially uniform field strength having a radial: field direction. Inclusion of a ferrite element 786 between the magnets helps in shaping the region of exam inat' ion. The PX, roll arrangenieni of FIG. 7B is used to produce an RF field with a tangential component within the region of e%animation.

FIG. 7D illustrates an alternate RF antenna arrangement that can be used with the permanent magnet arrangements of FIG. 7B or FIG. 7C- Sheet conductors 791a 22 and 791b are arranged in arcuate portions of the pad (not shown). When the antenna is pulsed with an RF signal, an RF magnetic field with a substantially longitudinal component is produced within the formation adjacent the pad. This field is orthogonal to the radial static field produced by the permanent magnet arrangements of FIG. 7B or FIG. 7C.

Those versed in the art would recognize that by using a single magnet (instead of a pair of opposed magnets) in the configuration of FIG. 7C, a static field that is substantially longitudinal is produced in the formation in the vicinity of the borehole. The RF antenna arrangement shown in FIG. 7B that produces an RF field in the formation having a substantially tangential component (circumferential with respect to the longitudinal axis) and could be used to make NMR measurements because of its orthogonality to the static field, -Alternatively, a circular RF coil with its axis in a radial direction (not shown) with respect to the, orehole a)ds can be used to produce a radial RF field that is orthogonal to the longitudinal staticifield to make NNM measurements,

Those versed in the art would also recognize that with any of the configurations discussed with reference to FIGS 7A- 7D, using a plurality of pads oriented in different directions, or by making measurements with a single pad at different azim-aths, azimuthal variations in the NMR properties of the formation can be detemined. Such an azimuthal variation could be caused by fractures in the formation that are aligned with fracture planes parallel to the axis of the borehole, so that the amount of fluid in the formation (which is what determines the NMR response) has an 23 azirnuthal variation. The azimuthal variations could also be measured on a single pad that is rotating sufficiently slowly that the region of examination does not change significantly during the time that thp N-TMR measurements are made.

In yet another embodiment of the invention shown in FIG. 8, the permanent magnet assembly is mounted on the rotating housing 96o.- i'ne RF transmitter/receiver assembly is included in at least orte sensor module 980 that is mounted on a substantially non-rotating sleeve 962. The permanent magnet assembly includes a pair of amnular Cylindrical magnets 964a,b that are longitudinally polarized. Such an arrangement produces a static magnetic field in the formation that is radial in direction and rotationally symmetric' around the borehole,. so that rotation of the magnet assembly itself would not affect the measurements (except for effects caused by vibration of the magnet assembly). The measurements made by the RF assembly would be azimuthally dependent if there is any azimuthal variation in the formation.

Fig. 9a shows an embodiment of the invention in which electromagnetic induction wisors are used to dettermine the.rcsigli-Vity ofthe formation. An electromagnetic transmitter -antenna 10.50 is used to induce an electromagnetic signal into the formation. Each of the stabilizers 1023 is provided with a recess 1035 into which an electromagnetic receiver module 1054 is set. Each elwromagnetic receiver module 1054 has a plurality of slots 1056 behind which the receiver coils (not shown) are set. The slots are axially spaced apart so that measurements may be made at at least two transmitter to receiver distances. The antenna 1050 is controlled by an electronics module 1052 at a suitable location. Using known electromagnetic 24, induction logging methods, the transmitter sends out a pulse at a frequency and the amplitude arld phase of the signal received by the receivers in the receiver modules is used to determine the resistivity of the formation. The frequency of the transmitted signal is typically between INTRz and 10 NlHz.. With the azimuthally disposed arrangement of the stabilizers 10033 and the receiver modules 1054 on the stabilizers, this embodiment makes it possibk to determine an azimuthal variation of resistivity, When multiple frequency signals are used, both the resistivity and the dielectric constant of the formation may be determined using known methods.

The embodiment slio' wiiiiii: F-ig. 9b has the electromagnetic receivers in a padmounted configuration. in an arrangement similar to that of Fig. 3C, the pads 1164 are mounted on a sleeve 1105. The pads may be extended to make contact with the formation using hydraulic, electrical or mechanical arrangements (not shown). The transmitter 1150 is also mounted on the sleeve. The electronics control for the transmitter and the receiver may be mounted at a suitable location 1152. As with the aebodimeritt disclosed inFig. 9a, azirnuthal variations of electrical properties may be determined by =plitude &nd-phaserneasurernentsof the received, s excitation of the transmitter. I ISO.

Fig. 9c shows transmitter-receiver module 1200 suitable for use for higber frequency induction logging with a signal at I GHz or more. This module may be mounted in the recess 1035 of a stabilizer 1033, as shown in Fig. 9a or on a pad, such as 1164 in Fig- 9b. The module is prcvlded vAth at Icast two transmitter slots 1202 and receiver slots 1204 with the respective transmitter and receiver coils (not shown) behind the slots. The transmitters are preferably disposed symmetrically about the 25 receivers. The transmitter to receiver distances in this module are considerably less than in the embodiments discloses in Fi-s. 9a, 9b necessitating the use of high frequency sigmals 0 GI-1z or more).

In another embodiment of the invention, induction measurements are obtained using the electrode arrangement of Fig. 3A. For example, referring to Fig 3A, the electrodes 301aa, 301ab could be used as a transmitter when pulsed simultaneously, as could the electrodes 301da, 30ldb. Similarly, the electrodes 301ba, 301bb constitute one receiver wUe the electrodes 301ca, 30leb constitute a second receiver.

The foregoing description has been limited to specific embodiments of this invention. It will be apparent, howe,,,er, that variations and modifications may be made to the disclosed embodiments, with the attainment of 'some or all of the advantages of the invention. In particular, the invention may be modified to make density and acoustic measurements.

26 - 27

Claims (7)

Claims

1. A method of determining, while drilling a borehole with a drilling assembly, a parameter of interest of the formation surrounding the borehole, comprising:

using a plurality of sensors at known positions on the assembly to obtain data relating to the parameter of interest; transmitting from a surface control device information about the depth of the drilling assembly to a telemetry device on the drilling assembly; obtaining the orientation of the plurality of sensors by using a directional sensor disposed in the assembly; processing the data about the parameter of interest in a processor disposed in the drilling assembly by using the orientation of the sensors and the information about the depth of the drilling assembly to give processed data about the parameter of interest; and transmitting said processed data about the parameter of interest to the surface using a telemetry device on the drilling assembly.

2. The method of claim 1, wherein the plurality of sensors rotate with a drill bit on the drilling assembly.

3. The method of claim 1, wherein the plurality of sensors are mounted on a substantially non-rotating sleeve on the drilling assembly.

4. The method of claim 1, 2 or 3, further comprising conveying the drilling assembly on one of: (i) a drillstring; and (ii) coiled tubing.

5. The method of any preceding claim, wherein the processing includes computing a rate of penetration of the drilling assembly.

6. The method of any preceding claim, wherein the processing comprises combining data measurements recorded within a depth and azimuth sampling interval.

7. The method of any preceding claim, Wherein the processing comprises discarding redundant data measurements recorded within a depth and azimuth sampling interval.