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US20120039151A1 - Mud pulse telemetry synchronous time averaging system - Google Patents

Mud pulse telemetry synchronous time averaging system Download PDF

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Publication number
US20120039151A1
US20120039151A1 US12/855,213 US85521310A US2012039151A1 US 20120039151 A1 US20120039151 A1 US 20120039151A1 US 85521310 A US85521310 A US 85521310A US 2012039151 A1 US2012039151 A1 US 2012039151A1
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Prior art keywords
strobe
cyclical
signal
component
pulse
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Abandoned
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US12/855,213
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English (en)
Inventor
Steven Reid Farley
Michael Louis Larronde
Robert Anthony Aiello
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Precision Energy Services Inc
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Precision Energy Services Inc
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Application filed by Precision Energy Services Inc filed Critical Precision Energy Services Inc
Priority to US12/855,213 priority Critical patent/US20120039151A1/en
Assigned to PRECISION ENERGY SERVICES, INC. reassignment PRECISION ENERGY SERVICES, INC. ASSIGNMENT OF ASSIGNORS INTEREST (SEE DOCUMENT FOR DETAILS). Assignors: FARLEY, STEVEN REID, LARRONDE, MICHAEL LOUIS, AIELLO, ROBERT ANTHONY
Priority to CA2747272A priority patent/CA2747272A1/en
Priority to EP11175593A priority patent/EP2418351A1/en
Priority to AU2011205110A priority patent/AU2011205110A1/en
Priority to MX2011008370A priority patent/MX2011008370A/es
Priority to BRPI1104009-2A priority patent/BRPI1104009A2/pt
Priority to RU2011133822/03A priority patent/RU2011133822A/ru
Publication of US20120039151A1 publication Critical patent/US20120039151A1/en
Abandoned legal-status Critical Current

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    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B47/00—Survey of boreholes or wells
    • E21B47/12—Means for transmitting measuring-signals or control signals from the well to the surface, or from the surface to the well, e.g. for logging while drilling
    • E21B47/14—Means for transmitting measuring-signals or control signals from the well to the surface, or from the surface to the well, e.g. for logging while drilling using acoustic waves
    • E21B47/18—Means for transmitting measuring-signals or control signals from the well to the surface, or from the surface to the well, e.g. for logging while drilling using acoustic waves through the well fluid, e.g. mud pressure pulse telemetry
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B7/00—Special methods or apparatus for drilling
    • E21B7/04—Directional drilling
    • E21B7/06—Deflecting the direction of boreholes
    • E21B7/067—Deflecting the direction of boreholes with means for locking sections of a pipe or of a guide for a shaft in angular relation, e.g. adjustable bent sub

Definitions

  • This invention is related to the directional drilling of a well borehole. More particularly, the invention is related to minimizing adverse effects, in mud pulse telemetry, of drilling fluid pressure fluctuations used to operate directional drilling apparatus.
  • the complex trajectories and multi-target oil wells require precision placement of well borehole path and the flexibility to continually maintain path control. It is preferred to control or “steer” the direction or path of the borehole during the drilling operation using measurement-while-drilling (MWD) methodology. It is further preferred to control the path rapidly during the drilling operation at any depth and target as the borehole is advanced by the drilling operation. In addition, it is preferred to alter the path of the borehole while maintaining rotation of the drill string, and to simultaneously telemeter borehole information to the surface of the earth.
  • MWD measurement-while-drilling
  • directional steering assemblies comprising a motor disposed in a housing with an axis displaced from the axis of the drill string, are known in the prior art.
  • the motor can be a variety of types including electric, or hydraulic.
  • Hydraulic turbine motors are operated by circulating drilling fluid and are commonly known as a “mud” motors.
  • a rotary bit is attached to a shaft of the motor, and is rotated by the action of the motor.
  • the axially offset motor housing commonly referred to as a bent subsection or “bent sub”, provides axial displacement that can be used to change the trajectory of the borehole.
  • Borehole steering assemblies are typically disposed near the drill bit, which terminates the lower or “down hole” end of a drill string.
  • the most common MWD telemetry system uses mud pulse methodology to transmit data between the BHA and the surface of the earth.
  • Directional drilling systems alter or perturb one or more drilling parameters during a portion of a revolution of drill string. This periodic perturbation removes a disproportional amount of material from the wall of the borehole resulting in a deviation of the borehole path.
  • U.S. patent application Ser. No. 11/848,328 discloses a directional drilling system that periodically increases the bit rotation rate over a predetermined arc of each drill string rotation. This results in the desired disproportional removal of borehole wall material thus resulting in borehole deviation in the azimuthal direction of the predetermined arc.
  • the periodic increase in bit rotation is accomplished by periodically increasing the mud flow through the mud motor which, in turn, induces a pressure pulse in the stand pipe of the drilling rig.
  • U.S. patent application Ser. No. 12/344,873 discloses another type of directional drilling system that periodically increases the rate of penetration of the bit over a predetermined arc of each drill string rotation. This again results in the desired disproportional removal of borehole wall material thus resulting in borehole deviation in the azimuthal direction of the predetermined arc.
  • the periodic increase in rate of penetration is again accomplished by periodically increasing the mud flow as the bit rotates through the predetermined arc, and again results in a pressure pulse in the stand pipe.
  • a two-way telemetry system between the BHA and the surface of the earth is required, and the most common MWD telemetry system is a mud pulse system.
  • Data from downhole sensors and from surface commands are encoded for transmission by varying the pressure or “pulsing” the pressure of the drilling mud column. These pressure pulses are subsequently decoded to extract transmitted data.
  • the above described directional drilling systems are also controlled by drilling mud pressure pulses, with these pressure pulses resulting in drilling fluid standpipe pressure fluctuations.
  • the steering system pressure fluctuations will typically occur once per revolution of the drill string, but steering systems can use multiple periodic pressure fluctuations per revolution. Drilling fluid pressure variations caused by the steering system interfere with pressure variations induced by the mud pulse telemetry system. It is, therefore, necessary to remove the effects of periodic steering system pulses to allow the mud pulse telemetry system to operate properly.
  • This invention comprises apparatus and methods for removing the effects of directional drilling systems drilling fluid pulses to allow a MWD mud pulse telemetry system to operate without interference.
  • the methodology is based upon Synchronous Time Averaging (STA) which has been used to remove cyclical (or synchronous) “noise” in electromagnetic telemetry system as disclosed in U.S. Pat. No. 7,609,169, which is herein entered into this disclosure by reference.
  • STA Synchronous Time Averaging
  • any pressure fluctuation that is cyclical (or synchronous) with a measurable event can be profiled and subsequently subtracted from a mud pulse telemetry signal.
  • STA functions by placing a strobe in such a manner that the strobe is triggered for each cyclical event.
  • the cyclical event in this disclosure is one (or more) revolution(s) of the drill string. If there is a pressure fluctuation that correlates to that cyclical event, it will be identified by a stable profile of that pressure fluctuation. This pressure profile is then used to remove the cyclical pressure fluctuation from the mud pulse telemetry signal thereby allowing normal operation of the mud pulse telemetry system.
  • FIG. 1 illustrates a MWD system comprising a directional drilling system and a synchronous time averaging system to eliminate steering pressure fluctuations at the surface;
  • FIG. 2 a depicts a strobe increment of 360 degrees
  • FIG. 2 b depicts strobe increments of 90 degrees
  • FIG. 2 c depicts a strobe increment of 720 degrees
  • FIG. 3 is a conceptual flow chart of one embodiment of STA system for minimizing cyclical noise in a mud pulse telemetry system
  • FIG. 4 a is a plot of pressure representing a composite signal R measured over a single strobe increment for one revolution of the drill string;
  • FIG. 4 b is the plot of a sum of pressures measured over a plurality of strobe increments
  • FIG. 4 c shows a normalized plot of a cyclical pulse used to operate a directional drilling system
  • FIG. 4 d shows a mud pulse telemetry signal from which the directional drilling system pulse has been removed.
  • a preferred embodiment of this invention comprises apparatus and methods for removing the effects of directional drilling system drilling fluid pulses to allow a MWD mud pulse telemetry system to operate without interference.
  • the methodology is based upon Synchronous Time Averaging (STA) techniques, although the same methodology can be used in synchronous rotational arc averaging as will be subsequently illustrated.
  • STA Synchronous Time Averaging
  • Synchronous time averaging is used to identify cyclical noise in mud pulse telemetry response.
  • This telemetry response which comprises a “signal” component and a “noise” component, will hereafter be referred as the “composite” signal.
  • the signal component typically represents response data from one or more sensors disposed within a borehole assembly (BHA), or data transmitted from the surface to the BHA.
  • the noise component can represent any type of cyclical or synchronous noise.
  • the noise component represents one or more cyclical pressure pulses used in previously defined directional drilling systems.
  • a strobe is triggered by a cooperating trigger, responsive to a stimulus, to record during a predetermined “strobe increment”, a plurality of “increment composite noise signals”.
  • the stimulus can be a switch, reflector, magnet, protrusion, indention, time signal, or any suitable means to operate the trigger and cooperating strobe.
  • These increment composite noise signals are algebraically summed Any non cyclical pressure pulse components (such as random pulses representing BHA sensor responses) occurring during the strobe increment will approach a constant value in the summing operation. Any cyclical noise occurring during the strobe increment and in synchronization with the strobe increment (such as pressure pulses used in directional drilling systems) will be emphasized by the algebraic summing.
  • the trigger-strobe-summing methodology produces a signature or “picture” of any cyclical noise component occurring synchronously with the strobe increment. This noise component is then combined with the measured composite signal to remove, or to at least minimize, cyclical noise allowing the mud pulse telemetry system to operate optimally.
  • the technique is not limited to time averaging.
  • Strobe increments can be defined in units of degrees of an arc as well as an increment of time.
  • the process would actually comprise “arc” averaging rather than “time” averaging.
  • the averaging process will be generally referred to as STA although arc averaging will be used to conceptually illustrate the system.
  • the directional drilling system exemplified by U.S. patent application Ser. No. 11/843,382 utilizes one or more pressure variations per revolution of the drill string.
  • the strobe and cooperating trigger are controlled by the rotation of the rotary table. More specifically, the strobe increment is initiated and terminated by the rotational passage of stimuli comprising predetermined azimuth points on the rotary table.
  • the strobe increment is in degrees, and can comprise a partial arc of the rotary table or even multiple rotations of the rotary table. As an example, the strobe increment can be a single rotation of the rotary table.
  • Other strobe increments are applicable as will be illustrated in a subsequent section of this disclosure.
  • FIG. 1 illustrates a borehole assembly (BHA) 10 suspended in a borehole 29 defined by a wall 51 and penetrating earth formation 36 .
  • the upper end of the BHA 10 is operationally connected to a lower end of a drill pipe 33 by means of a suitable connector 20 .
  • the upper end of the drill pipe 33 is operationally connected to a rotary drilling rig, which is well known in the art and represented conceptually at 31 .
  • Elements of the steering apparatus are disposed within a bent sub 16 of the BHA 10 . More specifically, a rotary drill bit 18 is operationally connected to a mud motor 14 by a shaft 17 .
  • the mud motor 14 is disposed within a bent sub 16 .
  • the BHA 10 also comprises an auxiliary sensor section 22 , a power supply section 24 , an electronics section 26 , and a downhole telemetry section 28 .
  • the auxiliary sensor section 22 typically comprises directional sensors such as magnetometers and inclinometers that can be used to indicate the orientation of the BHA 10 within the borehole 29 . This information, in turn, is used in defining the borehole trajectory path of the borehole.
  • the auxiliary sensor section 22 can also comprise other sensors used in Measurement-While-Drilling (MWD) and Logging-While-Drilling (LWD) operations including, but not limited to, sensors responsive to gamma radiation, neutron radiation and electromagnetic fields.
  • MWD Measurement-While-Drilling
  • LWD Logging-While-Drilling
  • the electronics section 26 comprises electronic circuitry to operate and control other elements within the BHA 10 .
  • the electronics section 26 preferably comprise downhole memory (not shown) for storing directional drilling parameters, measurements made by the sensor section, and directional drilling operating systems.
  • the electronic section 26 also preferably comprises a downhole processor to control elements comprising the BHA 10 and to process various measurement and telemetry data. Elements within the BHA 10 are in communication with the surface 45 of the earth via the downhole telemetry section 28 .
  • the downhole telemetry section 28 receives and transmits data to a surface telemetry section 39 .
  • the telemetry path is illustrated conceptually by the broken line 30 .
  • a power supply section 24 supplies electrical power necessary to operate the other elements within the BHA 10 .
  • the power is typically supplied by batteries.
  • drilling fluid or drilling “mud” is circulated by the mud system 32 from the surface 45 downward through the drill string comprising the drill pipe 33 and BHA 10 , exits through the drill bit 18 , and returns to the surface via the borehole-drill string annulus.
  • the drilling fluid system is well known in the art.
  • FIG. 1 illustrates a trigger 34 and a strobe 38 cooperating with the drilling rig 31 , and more particularly with an element such as the rotary table or top drive (neither shown) of the drilling rig.
  • a rotary table will be used for purposes of illustration and discussion.
  • a “strobe increment” is initiated or “triggered” and subsequently terminated by the rotational passage of stimuli comprising predetermined azimuth points on the rotary table.
  • the stimuli can comprise a switch, a reflector, a magnet, or any suitable means to operate the trigger and cooperating strobe.
  • Stimuli configured as azimuth points will be illustrated in detail in FIGS. 2 a - 2 c and related discussion.
  • the surface telemetry section 39 is connected at 37 to the stand pipe of the drilling rig, in addition to being connected to the strobe 38 , and a surface processor 40 .
  • the surface telemetry section 39 receives a “composite” mud pulse telemetry response from the downhole telemetry section 28 .
  • This response comprises a telemetry “signal” component representative of the response of the sensor package 14 and a “noise” component.
  • the signal represents mud pulse telemetry pulses and the noise component is a series of pressure pulses used to activate a directional drilling system.
  • the composite telemetry system responses are received at the surface by the surface telemetry section 39 . These composite signals are measured during the plurality of strobe increments and algebraically summed and stored in the processor 40 .
  • any non cyclical pressure pulse components (such as mud pulses representing BHA sensor responses) occurring during a plurality of strobe increment will sum to a constant or “average” pressure value “A” over a plurality of strobe increment. This is because the mud pulse telemetry pulses can occur at any point in the strobe increment.
  • a cyclical noise occurring during the predetermined strobe increment, and in synchronization with the strobe increment, will be enhanced by the algebraic summing of the plurality of strobe increments.
  • a signature or picture of any cyclical noise component occurring synchronously with the predetermined strobe increment is obtained preferably by subtracting the average pressure pulse value, preferably within the processor 40 .
  • the composite signal from a single strobe increment measured by the surface telemetry section 39 is simultaneously input directly into the processor 40 , as shown conceptually in FIG. 1 .
  • the noise signature, normalized to a single strobe increment, is then subtracted from the measured composite signal, within the processor 40 , to remove cyclical steering system pulse from the response of the telemetry system.
  • a mud pulse pressure signal that is free from any cyclical pressure pulses used to activate a directional drilling system.
  • the mud pulse signal is then converted, preferably within the processor 40 , into one or more parameters of interest using responses from sensor within the BHA 10 .
  • These results are typically output to a recorder 42 as a function of depth within the borehole 29 thereby forming a record of the one or more parameters in a form commonly known as a “log”.
  • the strobe 38 can be triggered by stimuli other than predetermined azimuth points on a rotating element of the drilling rig including a rotary table, a top drive or protruding drill string sections.
  • This capability is illustrated conceptually in FIG. 1 as an “auxiliary” input 35 cooperating with the trigger 34 .
  • a clock can be synchronized with the rotation of the drill string and all processing can be based upon time rather than degrees of rotation. Stated another way, synchronous time averaging and synchronous arc averaging are conceptually equivalent and will be considered equivalent in this disclosure.
  • the synchronous time averaging technique can be implemented using a variety of mathematical formalism with essentially the same end results of cyclical noise removal from a composite electromagnetic signal.
  • the following formalism is, therefore, used to illustrate basic concepts, but other mathematical formalisms within the framework of the basic concepts may be equally effective.
  • the telemetered composite pressure pulse signal “R” is represented conceptually by the broken line 30 in FIG. 1 .
  • R comprises a signal component “S” representative of the response of the mud telemetry system and a composite noise component “N” representing one or more pressure pulses used to operate a directional drilling system.
  • the strobe is triggered by the cooperating trigger to record, during a strobe increment (in units of time or degrees), a plurality (k-j) of increment composite signals “e i ”. These composite signals are algebraically summed initially as
  • any non cyclical pressure pulse component such as mud pulse telemetry pulses “S”
  • any non cyclical pressure pulse component such as mud pulse telemetry pulses “S”
  • Any cyclical noise component (such as cyclical pulses N used to activate a directional drilling system) occurring during the strobe increments, and in synchronization with the strobe increments, is enhanced by the algebraic summing R′. Equation (2) therefore yields a cyclical noise component superimposed on an average mud pulse pressure value A.
  • the value A is subtracted from R′ to obtain a signature or picture of the noise component N. That is
  • This cyclical noise component is normalized to a single strobe increment (N′) and then combined with a single strobe increment composite signal R to determine the mud pulse signal S.
  • N′ single strobe increment
  • R single strobe increment composite signal
  • the parameter S is, therefore, the telemetered signal in a single strobe increment with the cyclical noise removed, and is indicative of the response of the sensor package 14 or data transmitted from the surface to the BHA 10 .
  • a variety of methods can be used to combine the composite signal R and the measure of N including semblance and least squares fitting techniques.
  • FIGS. 2 a , 2 b and 2 c illustrates conceptually three strobe increments g, related to determining cyclical noise generated by a rotating element of a drilling rig such as a rotary table.
  • increment composite signals e i are measured during strobe increments “i” defined in units of degrees of rotation.
  • the rotary table (or top drive) is represented conceptually by the cylinder 50 in FIGS. 2 a - 2 c .
  • the cylinder 50 can also represent essentially any other rotating element providing appropriate strobe increments.
  • FIG. 2 a only a single predetermined azimuth point is shown at 52 .
  • the resulting strobe increment g i 360 degrees is illustrates conceptually by the arrow 54 .
  • FIG. 2 c again only a single predetermined azimuth point is shown at 60 , but the strobe increment g, is 720 degrees as indicated by the arrow 68 .
  • Strobe increments do not necessarily need to be equal or need to be contiguous. Using the mathematical formalism discussed above, the choice of strobe increment necessitates the normalization of the noise component N expressed mathematically in equation (3). That is
  • N′ KN, (5)
  • N′ is the normalized noise component discussed above and K is a multiplicative normalization factor.
  • K is a multiplicative normalization factor.
  • N′ is the normalized noise component discussed above
  • K is a multiplicative normalization factor.
  • FIG. 3 is a simplified flow chart illustrating how the concept of synchronous time averaging is used in a telemetry system to remove cyclical noise and to generate “logs” of parameters of interest as a function of borehole depth.
  • Increment composite signals e i are measured at 70 .
  • the composite signal R for a single strobe increment is simultaneously measured at 80 .
  • Increment composite signals e i are algebraically summed at 72 according to equation (2).
  • a normalized noise component N′ is computed at 74 according to equations (3) and (5).
  • the components R and N′ are combined at 76 to determine the signal component S according to equation (4).
  • the signal component S is then used to compute at least one parameter of interest at 78 using a telemetered sensor and a predetermined relationship, wherein the predetermined relationship is preferably resident in the processor 40 .
  • the procedure is incremented in depth at 82 and the previously described steps are repeated at a new depth.
  • the abscissa can, as discussed previously, be in units of time or degrees.
  • the curve 84 represents pressure recorded at the surface telemetry section 39 .
  • Excursions 86 represent data pulses from the mud pulse telemetry system.
  • the excursion 88 shown superimposed on a data pulse 86 , is a cyclical pressure pulse used to operate a directional drilling system.
  • the curve 90 of FIG. 4 b represents R′ which is the sum of R over a plurality of strobe increments as defined in equation (2). Over the span of the strobe increments in which random data pulses fall, the summation approaches an average pressure A as shown at 91 .
  • the cyclical pulse from the directional drilling system sums as shown at 88 a .
  • K 1/(k ⁇ j).
  • curve 84 of FIG. 4 d represents the pressure curve S from which the rotary steering pulse 88 b has been subtracted.
  • FIG. 4 d represents, therefore, mud telemetry pulses free from interference from a directional drilling system pulse.

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  • Engineering & Computer Science (AREA)
  • Geology (AREA)
  • Life Sciences & Earth Sciences (AREA)
  • Physics & Mathematics (AREA)
  • Mining & Mineral Resources (AREA)
  • Geochemistry & Mineralogy (AREA)
  • Fluid Mechanics (AREA)
  • General Life Sciences & Earth Sciences (AREA)
  • Environmental & Geological Engineering (AREA)
  • Acoustics & Sound (AREA)
  • Remote Sensing (AREA)
  • Geophysics (AREA)
  • Geophysics And Detection Of Objects (AREA)
  • Earth Drilling (AREA)
  • Measuring Fluid Pressure (AREA)
  • Arrangements For Transmission Of Measured Signals (AREA)
US12/855,213 2010-08-12 2010-08-12 Mud pulse telemetry synchronous time averaging system Abandoned US20120039151A1 (en)

Priority Applications (7)

Application Number Priority Date Filing Date Title
US12/855,213 US20120039151A1 (en) 2010-08-12 2010-08-12 Mud pulse telemetry synchronous time averaging system
CA2747272A CA2747272A1 (en) 2010-08-12 2011-07-26 A mud pulse telemetry synchronous time averaging system
EP11175593A EP2418351A1 (en) 2010-08-12 2011-07-27 A mud pulse telemetry synchronous time averaging system
AU2011205110A AU2011205110A1 (en) 2010-08-12 2011-08-02 A mud pulse telemetry synchronous time averaging system
MX2011008370A MX2011008370A (es) 2010-08-12 2011-08-08 Sistema de promediacion de tiempo sincronico de telemetria de pulso de lodo.
BRPI1104009-2A BRPI1104009A2 (pt) 2010-08-12 2011-08-11 sistema sÍncrono de mÉdia de tempo de telemetria de pulso de lama
RU2011133822/03A RU2011133822A (ru) 2010-08-12 2011-08-11 Гидро-импульсная телеметрическая система с синхронным усреднением по времени

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US12/855,213 US20120039151A1 (en) 2010-08-12 2010-08-12 Mud pulse telemetry synchronous time averaging system

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EP (1) EP2418351A1 (pt)
AU (1) AU2011205110A1 (pt)
BR (1) BRPI1104009A2 (pt)
CA (1) CA2747272A1 (pt)
MX (1) MX2011008370A (pt)
RU (1) RU2011133822A (pt)

Cited By (4)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US20130154845A1 (en) * 2010-08-26 2013-06-20 Schlumberger Technology Corporation Mud Pulse Telemetry Noise Reduction Method
US20150345287A1 (en) * 2014-05-30 2015-12-03 Scientific Drilling International, Inc. Downhole mwd signal enhancement, tracking, and decoding
US9644440B2 (en) 2013-10-21 2017-05-09 Laguna Oil Tools, Llc Systems and methods for producing forced axial vibration of a drillstring
CN115296752A (zh) * 2022-08-02 2022-11-04 中国石油天然气集团有限公司 泥浆脉冲数据编码和传输方法、装置和设备

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US20080068211A1 (en) * 2006-08-31 2008-03-20 Precision Energy Services, Inc. Electromagnetic telemetry apparatus and methods for minimizing cyclical or synchronous noise

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US3260318A (en) 1963-11-12 1966-07-12 Smith Ind International Inc Well drilling apparatus
GB1388713A (en) 1972-03-24 1975-03-26 Russell M K Directional drilling of boreholes
US4642800A (en) * 1982-08-23 1987-02-10 Exploration Logging, Inc. Noise subtraction filter
WO2007095111A1 (en) * 2006-02-14 2007-08-23 Baker Hughes Incorporated System and method for measurement while drilling telemetry

Patent Citations (2)

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Publication number Priority date Publication date Assignee Title
US5146433A (en) * 1991-10-02 1992-09-08 Anadrill, Inc. Mud pump noise cancellation system and method
US20080068211A1 (en) * 2006-08-31 2008-03-20 Precision Energy Services, Inc. Electromagnetic telemetry apparatus and methods for minimizing cyclical or synchronous noise

Cited By (8)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US20130154845A1 (en) * 2010-08-26 2013-06-20 Schlumberger Technology Corporation Mud Pulse Telemetry Noise Reduction Method
US9007232B2 (en) * 2010-08-26 2015-04-14 Schlumberger Technology Corporation Mud pulse telemetry noise reduction method
US9644440B2 (en) 2013-10-21 2017-05-09 Laguna Oil Tools, Llc Systems and methods for producing forced axial vibration of a drillstring
US20150345287A1 (en) * 2014-05-30 2015-12-03 Scientific Drilling International, Inc. Downhole mwd signal enhancement, tracking, and decoding
US9702246B2 (en) * 2014-05-30 2017-07-11 Scientific Drilling International, Inc. Downhole MWD signal enhancement, tracking, and decoding
US9938824B2 (en) * 2014-05-30 2018-04-10 Scientific Drilling International, Inc. Downhole MWD signal enhancement, tracking, and decoding
US10301933B2 (en) * 2014-05-30 2019-05-28 Scientific Drilling International, Inc. Downhole MWD signal enhancement, tracking, and decoding
CN115296752A (zh) * 2022-08-02 2022-11-04 中国石油天然气集团有限公司 泥浆脉冲数据编码和传输方法、装置和设备

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EP2418351A1 (en) 2012-02-15
BRPI1104009A2 (pt) 2013-05-21
CA2747272A1 (en) 2012-02-12
AU2011205110A1 (en) 2012-03-01
MX2011008370A (es) 2012-02-20
RU2011133822A (ru) 2013-02-20

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Owner name: PRECISION ENERGY SERVICES, INC., TEXAS

Free format text: ASSIGNMENT OF ASSIGNORS INTEREST;ASSIGNORS:FARLEY, STEVEN REID;LARRONDE, MICHAEL LOUIS;AIELLO, ROBERT ANTHONY;SIGNING DATES FROM 20100809 TO 20100810;REEL/FRAME:024829/0605

STCB Information on status: application discontinuation

Free format text: ABANDONED -- FAILURE TO RESPOND TO AN OFFICE ACTION