Halliburton Energy Services, Inc.

Halliburton Company

Ahlliburton Energy Services, Inc.

Carl A Robbins

James Robert Birchak

Eugene J Linyaev

John W Minear

Paul F Rodney

Vimal Vinod Shah

Wallace R Gardner

Robert L Malloy

Chenkang David Chen

David J Young

Li Gao

Harry D Smith, Jr

Batakrishna Mandal

Dan M Arnold

Dennis E Roessler

Denis P Schmitt

A J Mallett

Bruce Edward Cornish

Patrick Dennis Chesnutt

Sinan Sinanovic

Darrell Gordy

Bill Schaecher

Donald H Johnson

Bruce Mackie

David Chen

In some example embodiments, a system includes a drill string having a drill bit. The drill string extends through at least part of a well bore. The system also includes a first vibrational sensor, positioned on the drill bit to measure, at a first location on the drill string, an amplitude of one or more of an axial vibration and a lateral vibration. The system also includes a second vibrational sensor, positioned above the drill bit and on the drill string. The second vibration sensor is to measure, at a second location on the drill string, one or more of an axial vibration and a lateral vibration. The system includes a processor unit to determine a type of vibration based on a comparison of the amplitude at the first location to the amplitude at the second location, wherein the type of vibration is at least one of bit whirl of the drill bit and a while of a bottom hole assembly that is part of the drill string.

Vibration detection in a drill string based on multi-positioned sensors

Transmitting acoustic signals from a wellbore. At least some of the illustrative embodiments are methods including transmitting an acoustic signal comprising downhole data, receiving the acoustic signal (the receiving by a receiver disposed within the internal diameter of a casing in the wellbore) converting the acoustic signal to a corresponding first electromagnetic signal, and inducing a second electromagnetic signal in a tubing responsive to the first electromagnetic signal.

Method and system of transmitting acoustic signals from a wellbore

Enhanced symbol synchronization methods suitable for use in narrowband orthogonal frequency division multiplexed (OFDM) telemetry systems. In at least some embodiments, a logging while drilling (LWD) tool assembly communicates with the surface using low frequency electromagnetic (EM) signals. The telemetry transmitter employs OFDM modulation to fully exploit the narrow range of available bandwidth, resulting in signals that have relatively long frames. At the surface a receiver digitizes the receive signal and applies an enhanced symbol synchronization technique to identify frame boundaries before demodulation is attempted. The enhanced symbol synchronization technique employs a pulse train filter to clean up a cyclic prefix correlation signal that otherwise behaves badly in the narrowband regime. The improved timing information from the enhanced symbol synchronization significantly reduces the error rate in the demodulated signal.

Symbol synchronization for downhole OFDM telemetry

An embodiment includes a method comprising transmitting and receiving an acoustic signal that is modulated along a jointed tubing. The acoustic signal may be transmitted in multiple passbands of the jointed tubing and may be modulated differently in different passbands. A swept frequency signal may be used to determine transmission characteristics of the jointed tubing and to select the multiple passbands. Additional embodiments are disclosed.

Acoustic telemetry system using passband equalization

Acoustic telemetry devices and methods that provide directional detection. In one embodiment, a disclosed acoustic telemetry device comprises at least two acoustic sensors and an electronics module. The electronics module combines the detection signals from the acoustic sensors to obtain a combined signal that substantially excludes signals propagating in a direction opposite to the communication signal. The disclosed systems and methods can be trained in the field and will readily accommodate an irregular and unknown signal transmission medium between the two acoustic sensors.

Training for directional detection

A seismic acquisition system comprising a remote-controlled buoy for conducting seismic acquisition operations. The buoy comprises an operating system for operating a seismic wave production device on the buoy, a placement system, a communications system, and dynamic position locating system. The seismic acquisition system also comprises a remote control system for controlling the buoy systems. The seismic acquisition system also comprises receivers for receiving the seismic wave and generating a data signal indicative of the received seismic wave. The seismic acquisition system operates by controlling the placement system with the remote control system to position the buoy and then controlling the operating system with the remote control system to produce a seismic wave from the seismic wave production device. The receivers then receive the seismic wave and generate a data signal indicative of the seismic wave. The time of producing the seismic wave as well as the position of the buoy at the time of production are then analyzed with the data signal by a data processor.

Seismic acquisition system

A downhole crystal-based clock that is substantially insensitive to the factors that may cause frequency deviation as a result of downhole temperature. The clock may include a plurality of crystals, where a first crystal may be more stable, with respect to temperature, than a second crystal. The crystals may be thermally coupled together so that they may have substantially the same temperature. An error detector may monitor the differences between the frequencies associated with each crystal and provide this information to a storage device. This information may be determined prior to deploying the clock downhole. When deployed downhole, the signal from the error detector may be interpreted in light of the information in the storage device to provide a temperature measurement of the two crystals. The downhole temperature measurement then may be used to reduce frequency deviations in the downhole clock that may result from downhole temperatures.

Downhole clock having temperature compensation

An axially extended downhole seismic source is disclosed. In one embodiment, the seismic source includes multiple pressure storage chambers, each having an inlet valve and an outlet valve. The inlet valve is coupled between the pressure storage chamber and the interior of the drill string, and the outlet valve is similarly coupled between the pressure storage chamber and the annular space around the drill string. A compressible fluid may be provided in the pressure storage chambers, and pistons may be positioned to contact the compressible fluid. For each pressure storage chamber, an inlet piston contacts the compressible fluid and fluid inside the drill string, while an outlet piston contacts the compressible fluid and fluid in the annular space around the drill string. When the outlet valve is closed, the inlet valve can be opened to allow pressure inside the drill string to compress the compressible fluid inside the pressure storage chamber. Subsequently closing the inlet valve and opening the outlet valve causes fluid to be ejected into the annular space, thereby generating seismic waves. The use of multiple pressure storage chambers allows the pressure front from the seismic source to be extended axially to advantageously increase the fraction of seismic energy transmitted into the formation while preventing damage to the formation.

Axially extended downhole seismic source

A system is disclosed for synchronizing a clock in a well containing a drill string with a clock located near the surface of the well. The system includes devices for transmitting and receiving a pair of acoustic signals between locations associated with each clock and processing those signals. The system determines the time of arrival of each acoustic signal by analyzing the shape of a function of the acoustic signal chosen from a group of functions suitable to determine a clock offset with millisecond accuracy.

Method for compensating for remote clock offset

A system based on a series of data accumulation hubs, connected together by high speed communication backbone for routing a limited number of data and power cables is suggested. Each hub is connected to arrays of sensor pods which contain the actual sensor elements and minimal, if any, interface electronics. Preferably, as many as 20 sensor pods can be connected to each single hub element wherein a system including five hub elements with 20 sensor pods each would comprise a 100 element array. The data from the individual sensors are accumulated in the hubs, buffered, and conditioned for transmission to the surface data acquisition system through the high speed metal backbone comprising multiple paths of transmission for redundancy in the event of failure. Provisions are made within each of the hubs so that if a hydrostatic leak were to occur, the fault can be isolated and the remainder of the system will function as designed. A power delivery network is also preferably encased within the backbone along with the high speed data link.

Sensor array suitable for long term placement inside wellbore casing

A vertical seismic profiling system includes seismic receivers for placement on a drillstring and surface seismic sources. One-way checkshot data may thus be measured without tripping the drillstring. A downhole acoustic tool measures the local interval transit time of the formation, and improves the detection of targets ahead of the drill bit. The local interval transit time may be applied to the time of travel from reflections in front of the bit to establish distance to the bit. The down-going wavetrain may be deconvolved with the total up-going wavetrain to extract the nearest reflector and the relative acoustic impedance at the reflector. A synthetic seismogram may also be created based on reflection depth data and corrected with checkshot data.

Vertical seismic profiling in a drilling tool

A system for eliminating the tool mode signal from a received combined signal comprising both tool mode and formation mode components, comprising: a formation receiver for receiving said combined signal, a reference receiver for receiving a tool mode reference signal, a filter for processing said tool mode reference signal and generating a predicted tool mode component of the combined signal, and a summation element for subtracting said predicted tool mode component from said combined signal and generating a predicted formation mode component. The filter preferably incorporates a portion of the output of the summation element as an error signal, enabling the filter to adapt to changing conditions and update the algorithm on which it makes its predictions. According to an alternative system, an average value for the tool mode signal is updated according to a moving average to which new data points are added as they become available. Tool mode signals are distinguishable from signals having both components because they have lower energies. When a signal is received having the lower energy that is indicative of the absence of a formation mode signal, the data point is treated as a purely tool mode signal and is added to the moving average.

Cancellation of tool mode signal from combined signal

A standoff compensation system is disclosed for use in an acoustic LWD system. An acoustic transducer is provided to measure the standoff distance between the logging tool and the borehole wall. The present invention includes a downhole processor for determining an index value which is used to align received acoustic formation signal measurements based upon the measured standoff distance. The index value can either be calculated by the downhole processor or can be retrieved from a pre-calculated look-up table in ROM. The processor then shifts the received acoustic formation signals based upon the index value assigned to each formation signal. The aligned acoustic formation signals are stacked, so that a single acoustic formation signal can be obtained for each firing period and either stored in downhole memory, used immediately, or transmitted by telemetry to the surface. The firing of the acoustic formation transmitters occurs in a rapid firing mode, followed by a relatively long idle. The rapid firing mode further minimizes the amount of data which must be stored, while providing an idle period for aligning and stacking the received signals.

Growing community of inventors

Houston, TX, United States of America

Carl A Robbins