Abstract:
The present disclosure is related to apparatuses and methods for estimating a phase offset in earth formations. The method may include estimating the phase offset by comparing signals generated and received by a first sub, the second signal being transmitted by a second sub that has been synchronized by the signal generated by the first sub. The signals may be exchanged using a first antenna on the first sub and a second antenna on the second sub. The signals may use a selected frequency. Synchronization may take place without electrical communication between the first and second subs. The method may include compensating for a propagation delay in the signals using the phase offset. The method may include using a time stamp during the synchronization. The apparatus may include a first antenna and a second antenna on first and second subs, respectively, both configured to transmit and receive electromagnetic signals.

Description:
FIELD OF THE DISCLOSURE 
     The present disclosure is related to exploration and production of hydrocarbons involving investigations of regions of an earth formation penetrated by a borehole. 
     BACKGROUND OF THE DISCLOSURE 
     Hydrocarbon exploration and production typically involves using downhole tools in boreholes penetrating earth formations. These downhole tools may include multiple subs. Operation of the subs, particularly in borehole logging, may be improved by synchronization of two or more subs. The downhole conditions and tool configurations may not allow direct electrical, hydraulic, or acoustic communications between two or more of the subs. It would be advantageous to have the ability to synchronize subs under conditions where conventional downhole communications are unreliable or prevented. 
     SUMMARY OF THE DISCLOSURE 
     In aspects, the present disclosure generally relates to exploration and production of hydrocarbons involving investigations of regions of an earth formation penetrated by a borehole. More specifically, the disclosure relates synchronizing subs without the need for electrical communication between the subs. 
     One embodiment according to the present disclosure includes a method of estimating a phase offset between signals generated by subs positioned downhole in an earth formation in at least one borehole penetrating an earth formation, comprising: estimating the phase offset by comparing a first signal with a second signal, the first signal being generated by a first sub and configured to synchronize a second sub with the first sub, the second signal being received from the synchronized second sub. 
     Another embodiment according to the present disclosure includes an apparatus for synchronization in an earth formation, comprising: a first sub configured for downhole conveyance; a first antenna disposed on the first sub and configured to generate a first signal at a selected frequency; a second sub configured for downhole conveyance; a second antenna disposed on the second sub and configured to generate a second signal at the selected frequency; and at least one processor configured to synchronize the first sub with the second sub using the first signal and configured to estimate a phase offset using the first signal as transmitted by the first antenna and the second signal as received by the first antenna. 
     Another embodiment according to the present disclosure includes a non-transitory computer-readable medium product having instructions stored thereon that, when executed by at least one processor, perform a method, the method comprising: estimating the phase offset by comparing a first signal with a second signal, the first signal being generated by a first sub and configured to synchronize a second sub with the first sub and the second signal being received from the synchronized second sub. 
     Examples of the more important features of the disclosure have been summarized rather broadly in order that the detailed description thereof that follows may be better understood and in order that the contributions they represent to the art may be appreciated. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       For a detailed understanding of the present disclosure, reference should be made to the following detailed description of the embodiments, taken in conjunction with the accompanying drawings, in which like elements have been given like numerals, wherein: 
         FIG. 1  depicts an exemplary bottom hole assembly (BHA) with at least two subs deployed within a borehole according to the present disclosure; 
         FIG. 2  shows the at least two subs in more detail; 
         FIG. 3  depicts an exemplary pair of BHAs for communication between two boreholes according to the present disclosure; and 
         FIG. 4  is a flow chart illustrating some of the steps of a method of one embodiment according to the present disclosure; and 
         FIG. 5  shows a graph illustrating transmitted and received electromagnetic signals for one embodiment according to the present disclosure. 
     
    
    
     DETAILED DESCRIPTION 
     In the disclosure that follows, in the interest of clarity, not all features of actual implementations are described. It will of course be appreciated that in the development of any such actual implementation, as in any such project, numerous engineering and technical decisions must be made to achieve the developers&#39; specific goals and subgoals (e.g., compliance with system and technical constraints), which will vary from one implementation to another. Moreover, attention will necessarily be paid to proper engineering and programming practices for the environment in question. It will be appreciated that such development efforts may be complex and time-consuming, outside the knowledge base of typical laymen, but would nevertheless be a routine undertaking for those of ordinary skill in the relevant fields. 
       FIG. 1  is a schematic diagram of an exemplary drilling system  100  that includes a drill string having a drilling assembly attached to its bottom end that includes a steering unit according to one embodiment of the disclosure.  FIG. 1  shows a drill string  120  that includes a drilling assembly or bottomhole assembly (BHA)  190  conveyed in a borehole  126 . The drilling system  100  includes a conventional derrick  111  erected on a platform or floor  112  which supports a rotary table  114  that is rotated by a prime mover, such as an electric motor (not shown), at a desired rotational speed. A tubing (such as jointed drill pipe)  122 , having the drilling assembly  190 , attached at its bottom end extends from the surface to the bottom  151  of the borehole  126 . A drill bit  150 , attached to BHA  190 , disintegrates the geological formations when it is rotated to drill the borehole  126 . The drill string  120  is coupled to a drawworks  130  via a Kelly joint  121 , swivel  128  and line  129  through a pulley. Drawworks  130  is operated to control the weight on bit (“WOB”). The drill string  120  may be rotated by a top drive (not shown) instead of by the prime mover and the rotary table  114 . Alternatively, a coiled-tubing may be used as the tubing  122 . A tubing injector  114   a  may be used to convey the coiled-tubing having the drilling assembly attached to its bottom end. The operations of the drawworks  130  and the tubing injector  114   a  are known in the art and are thus not described in detail herein. 
     A suitable drilling fluid  131  (also referred to as the “mud”) from a source  132  thereof, such as a mud pit, is circulated under pressure through the drill string  120  by a mud pump  134 . The drilling fluid  131  passes from the mud pump  134  into the drill string  120  via a desurger  136  and the fluid line  138 . The drilling fluid  131   a  from the drilling tubular discharges at the borehole bottom  151  through openings in the drill bit  150 . The returning drilling fluid  131   b  circulates uphole through the annular space  127  between the drill string  120  and the borehole  126  and returns to the mud pit  132  via a return line  135  and drill cutting screen  185  that removes the drill cuttings  186  from the returning drilling fluid  131   b . A sensor S 1  in line  138  provides information about the fluid flow rate. Herein, the term “information” may related to, but is not limited to, raw data, processed data, and signals. A surface torque sensor S 2  and a sensor S 3  associated with the drill string  120  respectively provide information about the torque and the rotational speed of the drill string  120 . Tubing injection speed is determined from the sensor S 5 , while the sensor S 6  provides the hook load of the drill string  120 . 
     In some applications, the drill bit  150  is rotated by only rotating the drill pipe  122 . However, in many other applications, a downhole motor  155  (mud motor) disposed in the BHA  190  also rotates the drill bit  150 . The rate of penetration for a given BHA  190  largely depends on the WOB or the thrust force on the drill bit  150  and its rotational speed. 
     The mud motor  155  is coupled to the drill bit  150  via a drive shaft disposed in a bearing assembly  157 . The mud motor  155  rotates the drill bit  150  when the drilling fluid  131  passes through the mud motor  155  under pressure. The bearing assembly  157 , in one aspect, supports the radial and axial forces of the drill bit  150 , the down-thrust of the mud motor  155  and the reactive upward loading from the applied weight-on-bit. 
     A surface control unit or controller  140  receives signals from the downhole sensors and devices via a sensor  143  placed in the fluid line  138  and signals from sensors S 1 -S 6  and other sensors used in the system  100  and processes such signals according to programmed instructions provided to the surface control unit  140 . The surface control unit  140  displays desired drilling parameters and other information on a display/monitor  142  that is utilized by an operator to control the drilling operations. The surface control unit  140  may be a computer-based unit that may include a processor  142  (such as a microprocessor), a storage device  144 , such as a solid-state memory, tape or hard disc, and one or more computer programs  146  in the storage device  144  that are accessible to the processor  142  for executing instructions contained in such programs. The surface control unit  140  may further communicate with a remote control unit  148 . The surface control unit  140  may process data relating to the drilling operations, data from the sensors and devices on the surface, data received from downhole, and may control one or more operations of the downhole and surface devices. The data may be transmitted in analog or digital form. 
     The BHA  190  may also contain formation evaluation sensors or devices (also referred to as measurement-while-drilling (“MWD”) or logging-while-drilling (“LWD”) sensors) determining resistivity, density, porosity, permeability, acoustic properties, nuclear-magnetic resonance properties, formation pressures, properties or characteristics of the fluids downhole and other desired properties of the earth formation  195  surrounding the drilling assembly  190 . Such sensors are generally known in the art and for convenience are generally denoted herein by numeral  165 . The BHA  190  may further include a variety of other sensors and devices  159  for determining one or more properties of the BHA (such as vibration, bending moment, acceleration, oscillations, whirl, stick-slip, etc.) and drilling operating parameters, such as weight-on-bit, fluid flow rate, pressure, temperature, rate of penetration, azimuth, tool face, drill bit rotation, etc.) For convenience, all such sensors are denoted by numeral  159 . 
     The drilling assembly  190  includes a steering apparatus or tool  158  for steering the drill bit  150  along a desired drilling path. In one aspect, the steering apparatus may include a steering unit  160 , having a number of force application members  161   a - 161   n , wherein the steering unit is at partially integrated into the drilling motor. In another embodiment the steering apparatus may include a steering unit  158  having a bent sub and a first steering device  158   a  to orient the bent sub in the wellbore and the second steering device  158   b  to maintain the bent sub along a selected drilling direction. 
     The MWD system may include sensors, circuitry and processing software and algorithms for providing information about desired dynamic drilling parameters relating to the BHA  190 , drill string  120 , the drill bit  150  and downhole equipment such as a drilling motor, steering unit, thrusters, etc. Exemplary sensors include, but are not limited to, drill bit sensors, an RPM sensor, a weight on bit sensor, sensors for measuring mud motor parameters (e.g., mud motor stator temperature, differential pressure across a mud motor, and fluid flow rate through a mud motor), and sensors for measuring acceleration, vibration, whirl, radial displacement, stick-slip, torque, shock, vibration, strain, stress, bending moment, bit bounce, axial thrust, friction, backward rotation, BHA buckling and radial thrust. Sensors distributed along the drill string can measure physical quantities such as drill string acceleration and strain, internal pressures in the drill string bore, external pressure in the annulus, vibration, temperature, electrical and magnetic field intensities inside the drill string, bore of the drill string, etc. Suitable systems for making dynamic downhole measurements include COPILOT, a downhole measurement system, manufactured by BAKER HUGHES INCORPORATED. Suitable systems are also discussed in “Downhole Diagnosis of Drilling Dynamics Data Provides New Level Drilling Process Control to Driller”, SPE 49206, by G. Heisig and J. D. Macpherson, 1998. 
     The drilling system  100  can include one or more downhole processors at a suitable location such as  193  on the BHA  190 . The processor(s) can be a microprocessor that uses 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, EEPROMs, Flash Memories, RAMs, Hard Drives and/or Optical disks. Other equipment such as power and data buses, power supplies, and the like will be apparent to one skilled in the art. In one embodiment, the MWD system utilizes mud pulse telemetry to communicate data from a downhole location to the surface while drilling operations take place. The surface processor  142  can process the surface measured data, along with the data transmitted from the downhole processor, to evaluate formation lithology. While a drill string  120  is shown as a conveyance system for sensors  165 , it should be understood that embodiments of the present disclosure may be used in connection with tools conveyed via rigid (e.g. jointed tubular or coiled tubing) as well as non-rigid (e.g. wireline, slickline, e-line, etc.) conveyance systems. A downhole assembly (not shown) may include a bottomhole assembly and/or sensors and equipment for implementation of embodiments of the present disclosure on either a drill string or a wireline. 
       FIG. 2  shows the BHA  190  with sensor/evaluation devices  165  separated into multiple subs  240 ,  250 ,  260 ,  270 . A first sub  240  may include an antenna  245  configured to transmit and receive electromagnetic signals. The first sub  240  may include a first transceiver  247  configured to transmit and receive signals through antenna  245 . The first transceiver  247  may include a synchronizable clocking circuit  249 . A second sub  270  may also include an antenna  275  configured to transmit and receive electromagnetic signals. The second sub  270  may include a second transceiver  277  configured to transmit and receive signals through antenna  275 . In operation, the first transceiver  247  may be configured to transmit a first electromagnetic signal, such as but not limited to a radio signal, at a selected frequency. The second transceiver  277  may be configured to receive the first electromagnetic signal and transmit a second electromagnetic signal at the same selected frequency. First transceiver  247  may be configured to estimate a phase shift between the first electromagnetic signal and the second electromagnetic signal. Phase shifting may be due propagation delays a result of the distance between the first transceiver  247  and the second transceiver  277 . In some embodiments, second transceiver  277  may also include a clocking circuit  279 . The intervening subs  250 , 260  may be configured such that electrical communication is not available between the first sub  240  and the second sub  270 . In some embodiments, there may not be intervening subs  250 ,  260 . In some embodiments, the first sub  240  and the second sub  270  may be separated by a length of the drill string  120 . In some embodiments, the first sub  240  may include a formation evaluation (FE) sensor  243  in communication with first transceiver  247 . In some embodiments, the second sub  270  may include an FE sensor  273  in communication with second transceiver  277 . 
       FIG. 3  shows embodiment according to the present disclosure with synchronization between boreholes.  FIG. 1  shows exemplary hydrocarbon wells  300 ,  305 . The hydrocarbon wells  300 ,  305  may include a derrick  310 ,  315  configured to support a carrier  320 ,  325 . The carriers  320 ,  325  may be configured to convey BHAs  390 ,  395  in a borehole  330 ,  335  penetrating earth formation  395 . The BHA  390  may include multiple subs  340 ,  350 ,  360 ,  370  that may be configured to house downhole investigation devices. Similarly, BHA  395 , may include multiple subs  345 ,  355 ,  365 ,  375  that may be configured to house downhole investigation devices. A first sub  370  on BHA  390  may include an antenna  371  configured to transmit and receive electromagnetic signals. A second sub  375  on BHA  395  may also include an antenna  376  configured to transmit and receive electromagnetic signals. One or more of intervening subs  340 ,  350 ,  360 ,  345 ,  355 ,  365  may be configured such that electrical communication is not available between the first sub  370  and the second sub  375 . In some embodiments, there may not be intervening subs  340 ,  350 ,  360 ,  345 ,  355 ,  365 . In some embodiments, the first sub  370  and the second sub  375  may be separated by a length of the carrier  320 . While a wireline conveyance system has been shown, it should be understood that embodiments of the present disclosure may be utilized in connection with tools conveyed via rigid carriers (e.g., jointed tubular or coiled tubing) as well as non-rigid carriers (e.g., wireline, slickline, e-line, etc.). Some embodiments of the present disclosure may be deployed along with LWD/MWD tools. 
       FIG. 4  shows a flow chart that summarizes an exemplary method  400  of one embodiment according to the present disclosure. In step  410 , first sub  240  and second sub  270  on BHA  190  may be conveyed in the borehole  126 . In the borehole  126 , a first sub  240  and a second sub  270  may be unable to communicate electrically. In step  420 , first transceiver  247  may transmit a first electromagnetic signal at a selected frequency using antenna  245 . In step  430  the first electromagnetic signal may be received by a second transceiver  277  using antenna  275  on a second sub  270 . In step  440 , a clock  279  associated with the second transceiver  277  may be synchronized using the first electromagnetic signal. The synchronization may include synchronizing one or more of: phase and time. In step  450 , the synchronized second transceiver  277  may transmit a second electromagnetic signal at the same selected frequency as the first electromagnetic signal. In step  460 , the first transceiver  240  on first sub  240  may receive the second electromagnetic signal via antenna  245 . In step  470 , first sub  240  may estimate a phase shift between the transmitted first electromagnetic signal and the received second electromagnetic signal. The phase shift may be due to a propagation delay. In step  480 , a phase offset may be estimated using the phase shift. The phase offset may be used to compensate for propagation delays in measurement information. In some embodiments, the synchronization may include using a time stamp including in the second electromagnetic signal. In some embodiments, the method may be reversed such that the second sub  270  and the first sub  240  may exchange roles. In embodiments including subs located in different boreholes, step  410  may include conveying the first sub in a first borehole and conveying a second sub in a second borehole. 
     In one embodiment of the disclosure, measurements made by a formation evaluation (FE) sensor on the first sub  240  may be transmitted with a timestamp to the second sub  270 . This makes it possible to ensure proper registration of measurements made by different FE sensors on different subs. The registration may be done by the downhole processor or a surface processor. 
       FIG. 5  shows a graph of the signals transmitted and received by the transceivers according to one embodiment of the present disclosure. The first electromagnetic signal, represented by curve  510 , may be sent from the first transceiver  247 . Curve  520  represents the first electromagnetic signal as received by the second transceiver  277 . Curve  530  represents the second electromagnetic signal transmitted from the second transceiver  277 , now synchronized, at the same frequency as the first electromagnetic signal. In some embodiments, the first and second electromagnetic signals may have substantially similar frequencies instead of identical frequencies. Curve  540  represents the second electromagnetic signal as received by the first transceiver  247 . The time delay  550  indicates the phase shift between the transmission curve  510  and reception curve  520 , and time delay  560  indicates the phase shift between transmission curve  530  and reception curve  540 . This phase shift may be indicative of the propagation delay. The actual propagation delay between the transmission of signal  510  and reception of signal  540  may be estimated by the combination of time delay  550  and time delay  560 . While the transmission curves indicate that the first and second electromagnetic signals were sent at the same amplitude, this is merely exemplary, and the electromagnetic signals may be sent with different amplitudes. 
     Using the electromagnetic reciprocity principle, if two transceivers operate at the same frequency f 0  and are separated by distance L while both are placed in a medium with propagation constant γ=α+iβ where α—attenuation constant and β—phase constant, both apparently frequency dependent (and, presumably, positive). The followings could be observed: 1) the phase shift due to propagation delay when the first transceiver is transmitting the first electromagnetic wave and the second transceiver is receiving could be expressed as ΔΦ 1-2 =β·L; 2) the phase shift due to propagation delay when the second transceiver is transmitting the second electromagnetic wave and the first transceiver is receiving could be expressed as Φ 2-1 =β·L; and 3) while the formation properties and geometry remain unchanged, ΔΦ 1-2 =ΔΦ 2-1  and, therefore, total propagation delay between electromagnetic waves emitted and received by the first transceiver may be expressed as 2·ΔΦ 1-2 . Thus, one of skill in the art would see that the time delay  550  may be equal to time delay  560 . With a known time delay/phase shift, the first transceiver may be used as a reference for other transceivers since the propagation delays in measurement information from the other synchronized receivers may be compensated for using a phase offset estimated through the disclosed synchronization method. 
     Implicit in the 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. The determined formation properties may be recorded on a suitable medium and used for subsequent processing upon retrieval of the BHA. The determined formation properties may further be telemetered uphole for display and analysis. 
     While the foregoing disclosure is directed to the one mode embodiments of the disclosure, various modifications will be apparent to those skilled in the art. It is intended that all variations be embraced by the foregoing disclosure.