Abstract: The present invention relates to a sensing system, in particular to sensing system for sensing undersea seismic events. A vibration sensor is provided for sensing seismic vibrations on the sea bed is provided. The vibration sensor is electrically coupled to a transmitter unit, the transmitter unit being arranged to transmit, in use, an acoustic wave from which the presence of a seismic vibration can be inferred. The acoustic wave modulates light travelling along a nearby optical cable, the modulation being recovered at a distant monitoring station. A flotation arrangement is provide for retaining the transmitter unit in a raised position relative to the sea bed to facilitate the coupling of the acoustic wave to the optical cable.

Abstract: Methods are described for actively steering a towed marine seismic component using one or more actively controllable control members; reducing the actively steering of the control members during duration of a time window of recording seismic reflections from a sub-surface geological feature of interest; and resuming the actively steering of the control members after the time window. The marine seismic component may be a streamer, a source, or both. Other methods allow measuring initial orientation of a streamer based on measuring static control surface angle of a control surface of an inline steerable bird. This abstract is provided to comply with the rules requiring an abstract, and allow a reader to ascertain the subject matter of the technical disclosure. It will not be used to interpret or limit the scope or meaning of the claims.

Abstract: An apparatus and method for seismic data acquisition is provided, which, in one aspect, define a plurality of attributes relating to acquisition of seismic data by the apparatus, determine a value of each attribute when the apparatus is deployed for acquiring seismic data, generate a message for each attribute whose determined value meets a selected criterion, and transmit wirelessly each generated message to a remote unit without solicitation of such a message by the remote unit. It is emphasized that this abstract is provided to comply with the rules requiring an abstract which will allow a searcher or other reader to quickly ascertain the subject matter of the technical disclosure. It is submitted with the understanding that it will not be used to interpret or limit the scope or meaning of the claims.

Abstract: A system and method is provided that uses signals from a plurality of seismic sensors to define an acoustic lens for subsurface imaging. More specifically signals provided by an array of sensors/geophones may be utilized to form an acoustic lens that can be focused on a subterranean point by properly adjusting the signals recorded at each sensor prior to summation of those signals. To form such an acoustic lens, each of the seismic sensors is moved onto a hypothetical acoustic lens surface (e.g., spherical surface) having a focal point located on the subterranean point of interest in order to calculate a time delay for each signal. Once the signals for each sensor is time-delayed, information in the time-delayed signals, which is received from the point of interest, may be temporally aligned. Accordingly, the time delayed signals may be combined to generate reflection information for the point of interest.

Abstract: A seabed region (18) that lies under a seabed surface area of over one square meter, is analyzed by comparing a core sample taken near the middle of the region and/or data from a geotechnical insitu cone penetrometer installed at the middle of the region, to an acoustic analysis of the region. Locations of the acoustic analysis are precisely correlated to the location of the core test sample or cone test by mounting an acoustic imaging apparatus (16) that holds acoustic transducers (44, 46), on a carriage (26) that is positioned on the core drill (12) or cone penetrometer barrel staff. The carriage of the acoustic imager apparatus is clamped to the core drill when the core drill is not rotating. An arm (30 and/or 32) is supported on the carriage through a frame (28), with at least one acoustic generator (44) and one acoustic echo detector (46) mounted on the arm. The arm can be rotated to positions lying about the drill axis (14) to accurately scan a wide area.

Abstract: Measurements of acoustic velocities are made through a case borehole in the absence and presence of an applied magnetic field. A formation resistivity parameter may be estimated from differences in the acoustic velocities.

Abstract: A seismic velocity profile in a region of interest in a subsurface formation is determined using at least the following steps. (a) Activating a seismic source at a location n, thereby exciting a wave in the subsurface formation. (b) Recording a wave signal trace unm(t) against time t, at a seismic receiver m. (c) Recording a wave signal trace unk(t) against time t at a seismic receiver k. (d) Cross correlating the wave signal traces unm(t) and unk(t) to obtain uconvnmnk(t). (e) Repeating these steps, for different locations n; (f) Summing uconvnmnk(t) over all locations n, to obtain a signal trace uvsmk(t) which corresponds to the signal received by the seismic receiver k from the virtual source at the position of seismic receiver m; (g) Deriving the seismic velocity based on the time of first arrival of the wave in uvsmk(t) and the predetermined distance between the seismic receiver m and the seismic receiver k.

Abstract: A method for constructing a model representative of a heterogeneous medium from data expressed in different time scales with application to hydrocarbon characterization. The method first estimates sequentially, from the data expressed in each different time scale, parameters or physical quantities of the model, described for each different time scale. Second, a scale factor allowing conversion of a model described in a time scale into a model described in another time scale is determined. This determination is carried out by minimizing the dissimilarity between a parameter estimated in a time scale and this parameter estimated in the other time scale. Finally, estimation of a single model is performed, by taking simultaneously an account of the data expressed in the various time scales, and using the scale factor found previously for the time scale conversions.

Abstract: Methods and apparatus for cable termination and sensor integration at a sensor station within an ocean bottom seismic (OBS) cable array are disclosed. The sensor stations include a housing for various sensor components. Additionally, the sensor stations can accommodate an excess length of any data transmission members which may not be cut at the sensor station while enabling connection of one or more cut data transmission members with the sensor components. The sensor stations further manage any strength elements of the cable array.

Abstract: A method and system for processing synchronous array seismic data includes acquiring synchronous passive seismic data from a plurality of sensors to obtain synchronized array measurements. A reverse-time data process is applied to the synchronized array measurements to obtain a plurality of dynamic particle parameters associated with subsurface locations. These dynamic particle parameters are stored in a form for display. Maximum values of the dynamic particle parameters may be interpreted as reservoir locations. The dynamic particle parameters may be particle displacement values, particle velocity values, particle acceleration values or particle pressure values. The sensors may be three-component sensors. Zero-phase frequency filtering of different ranges of interest may be applied. The data may be resampled to facilitate efficient data processing.

Abstract: A method for attenuating multiple reflections in seismic signals includes coherency filtering the seismic signals. The seismic signals are low pass filtered and high pass filtered seismic signals at a frequency selected such that substantially only multiple reflections exist in the seismic signals above the frequency. A mask is generated having unity value where the high pass filtered signal amplitude exceeds a selected threshold. The mask has unity zero value for all other filtered signals. The mask value is multiplied by the low pass filtered signals. The multiplied signals are added to the high pass filtered signals and a coherency filter is applied to remove remaining primary energy to generate a model of the multiple reflections. The multiple reflection model is subtracted from the coherency filtered seismic signals.

Abstract: A method and apparatus for generating an acoustic signal having a single mode of propagation along borehole walls. The method includes generating an n-pole (monopole, dipole, quadrupole, and so on) acoustic signal and calculating the tool position and borehole shape from the signals received at one or more receivers. If the tool contains matched sources and balanced receivers, is in the center of the borehole, and the borehole is circular, the pure, single mode acoustic signal will propagate along the borehole walls with a single mode of propagation. If the acoustic signal traveling along borehole walls does not have a single mode of propagation, the signal's amplitudes and time delays are adjusted to produce a second acoustic signal. The second acoustic signal's amplitudes and time delays are further adjusted until the signal traveling along the borehole walls has a single mode of propagation.

Abstract: Methods and systems for taking acoustic measurements related to subterranean formations. The methods and systems provide extracting a portion of the acoustic measurements based on predetermined parameters for selecting reflected arrival waves in the acoustic measurements; generating time projection of the extracted acoustic measurements versus borehole depth; and generating an indication or imaging of acoustic reflectors in the formation based on the time projected acoustic measurements.

Abstract: There is provided a method of processing geological data during drilling of a borehole for improving accuracy of the geological data. The method includes a first step of determining from instrumentation (100) associated with a string (50) of drilling pipes a spatial trajectory of a borehole (20, 200) in a subterranean region. A second step of the method involves determining from the spatial trajectory one or more points (P1, P2, P3) with reference to the geological data whereat the trajectory changes direction in one or more layers of strata (F) of the subterranean region. A third step of the method involves subdividing an offset log generated by the instrumentation (100) in response to the one or more points (P1, P2, P3) to generate corresponding sections of offset log. A fourth step involves mutually comparing the subdivided sections of offset log to find a condition of best comparison therebetween and thereby generate one or more error terms (E).

Abstract: A method for estimating seismic velocities in vertically transversely isotropic media includes generating an initial estimate of vertical interval velocity and interval normal moveout velocity with respect to depth from seismic data. An initial estimate is generated of a first anisotropy parameter with respect to depth. The first anisotropy parameter is related to the interval normal moveout velocity and the interval vertical velocity. An initial estimate is generated with respect to depth of a second anisotropy parameter. The second anisotropy parameter is related to the first anisotropy parameter and an interval anelliptic parameter. A first tomographic inversion is performed with respect to the interval normal moveout velocity and the second anisotropy parameter at a constant value of the first anisotropy parameter until travel time differentials reach minimum values. Layer depths are adjusted with the initial estimate of vertical interval velocity.

Abstract: Systems and methods for determining inline skew of one or more seismic streamers are disclosed. One system embodiment includes a seismic streamer including a plurality of receivers, a skew detector adapted to detect inline skew of the streamer, and a receiver selector adapted to select which receivers in the streamer to use in data acquisition based on the detected streamer inline skew. It is emphasized that this abstract is provided to comply with the rules requiring an abstract, which will allow a searcher or other reader to quickly ascertain the subject matter of the technical disclosure. It is submitted with the understanding that it will not be used to interpret or limit the scope or meaning of the claims.

Abstract: This invention pertains to the extraction of the slowness dispersion characteristics of acoustic waves received by an array of two or more sensors by the application of a continuous wavelet transform on the received array waveforms (data). This produces a time-frequency map of the data for each sensor that facilitates the separation of the propagating components thereon. Two different methods are described to achieve the dispersion extraction by exploiting the time frequency localization of the propagating mode and the continuity of the dispersion curve as a function of frequency. The first method uses some features on the modulus map such as the peak to determine the time locus of the energy of each mode as a function of frequency. The second method uses a new modified Radon transform applied to the coefficients of the time frequency representation of the waveform traces received by the aforementioned sensors.

Abstract: Determination of in-situ rock yield stress state of a geological formation surrounding a borehole includes determining a profile for each of an axial effective, a radial effective, and a hoop effective stress within at least one axial plane containing a borehole axis. A predicted radial shear response radial profile is calculated from the effective stresses within the at least one axial plane. A measurement-based estimate of a shear response radial profile within the at least one axial plane is determined from measured data. A maximum radial distance at which a difference between the predicted and measurement-based shear response radial profiles is identified within the at least one axial plane as being greater than a difference threshold. The respective axial, radial, and hoop stresses, are determined at the identified maximum radial distance. The identified stresses are indicative of an in-situ yield stress state of the rock.

Abstract: Marine towed streamer seismic data are combined from a first survey and a second survey, wherein the first survey and the second survey are shot with a bin size of L×L and the second survey is shot with a shooting direction rotated 90° relative to the shooting direction of the first survey. The combined seismic data from the first and second surveys are binned on a bin grid with a bin size of L 2 × L 2 and with a bin grid orientation rotated 45° relative to the shooting directions of the first and second surveys. Then, seismic data processing is applied to the binned seismic data to create an image of the Earth's subsurface.

Abstract: Pressure records and vertical particle velocity records from dual sensor towed streamer data are transformed to the inline wavenumber domain. A series of scaling filters are applied to the transformed vertical particle velocity records at each inline wavenumber, wherein each of the series of scaling filters is calculated for a different cross-streamer wavenumber range and in blocks of inline traces in which all seismic events are approximately linear. The pressure spectrum and the scaled vertical particle velocity spectrum are combined to separate upgoing and downgoing wavefield components. The separated upgoing and downgoing wavefield components are inverse-transformed back to the time-space domain.