Halliburton Energy Services, Inc.

Conocophillips Company

Mark Elliott Willis

Xiang Wu

Andreas Ellmauthaler

Amit Padhi

Michel Joseph LeBlanc

David Andrew Barfoot

Xiaomin Zhao

Glenn Andrew Wilson

Sonali Pattnaik

Pedro William Palacios

Yue Du

Oscar Augusto Barrios

Simon Shaw

Baishali Roy

Henry Clifford Bland

Wei-Bin Ewe

Kristoffer Thomas Walker

John Philip Granville

Robert Eric Epstein

Tatiana Gilstrap

Tianrun Chen

Arthur Chuen Hon Cheng

Ali Can Tura

Michael Paul Davidson

Norm Warpinski

Dongjie Cheng

Michel Joseph Leblanc

Jose David Carrillo Rangel

Oscar Augusto Barrios Lopez

Victor K Leung

Cemal Erdemir

Victor King Hong Leung

Erkan Ay

Kary Darnell Green

An active fiber stretcher assembly can be used for data acquisition systems. A time-break signal can be detected that coincides with a seismic event emitted from a seismic controller. A predetermined waveform can be generated in response to detecting the time-break signal. The predetermined waveform may be encoded onto a fiber optic cable using a fiber stretcher. A data acquisition system connected to the fiber optic cable may detect the predetermined waveform on the fiber optic cable and initiate acquisition operations including: receiving, during the seismic event, light signals returning from a portion of the fiber optic cable in a subterranean environment; determining one or more characteristics of the subterranean environment from the light signals; and storing the one or more characteristics.

Triggering distributed acoustic sensing downhole using an active fiber stretcher assembly

Various embodiments include apparatus and methods implemented to take into consideration gauge length in optical measurements. In an embodiment, systems and methods are implemented to interrogate an optical fiber disposed in a wellbore, where the optical fiber is subjected to seismic waves, and to generate a seismic wavefield free of gauge length effect and/or to generate a prediction of a seismic wavefield of arbitrary gauge length, based on attenuation factors of a plurality of wavefields acquired from interrogating the optical fiber. In an embodiment, systems and methods are implemented to interrogate an optical fiber disposed in a wellbore, where the optical fiber is subjected to seismic waves, and to convert a seismic wavefield associated with a first gauge length to a seismic wavefield associated with a different gauge length that is a multiple of the first gauge length. Additional apparatus, systems, and methods are disclosed.

Gauge length effect and gauge length conversion

A wellbore system includes a logging unit having a retrievable logging cable coupled to a downhole tool within a wellbore and a depth correlation unit in the downhole tool that provides current depth data for the wellbore through the retrievable logging cable for recording of a current depth by the logging unit. The wellbore system also includes a distributed acoustic sensing unit that includes a seismic processing unit and a seismic profiling unit connected to a separate optical cable of the retrievable logging cable having distributed acoustic sensing channels, wherein an assignment of the distributed acoustic sensing channels along the separate optical cable is determined by an offset distance between the current depth of a formation reference region within the wellbore and a previous reference depth of the formation reference region within the wellbore. A distributed acoustic sensing method is also included.

Retrievable fiber optic vertical seismic profiling data acquisition system with integrated logging tool for geophone-equivalent depth accuracy

Systems and methods relate to borehole seismic studies. Traditionally, borehole seismic studies are conducted using geophones. Seismic acquisition can be performed using fiber optic Distributed Acoustic Sensing (DAS). Because DAS measures dynamic relative displacement over a gauge length, which is different from particle velocity, DAS data can be converted into an equivalent geophone output response. Operations include converting DAS data into distributed velocity, and then, converting the velocity output into an equivalent geophone response. Various aspects include separating the data into interleaving subsets, integrating each subset along the spatial coordinates, selecting a window width over which the median of each subset will be calculated and subtracted from the data, performing a spatial average or low-pass filtering over contiguous values, performing a time-domain low-pass filtering, and performing the velocity-to-geophone conversion operation.

Distributed acoustic sensing to geophone seismic data processing

Embodiments disclosed herein include components, devices, systems, and operations and functions for generating a seismic profile. An optical signal is generated in an optical signal medium disposed in proximity to a formation. A seismic source induces seismic signals within the formation. A backscatter response corresponding to the seismic signals from the optical signal medium is detected and quadrature modulated to generate a quadrature trace. A seismic response is generated by determining phase differences in the backscatter response based on the quadrature modulated backscatter response. Portions of the seismic response above or below a response threshold are removed to generate a threshold seismic response. The threshold seismic response is correlated with at least one of the seismic signals to generate a correlated seismic response.

De-spiking distributed acoustic sensor seismic profile

The disclosed technology provides solutions for identifying noise in seismic profile data sets. In some aspects, a process of the disclosed technology includes steps for receiving wellbore data including seismic measurements, processing the wellbore data to generate a seismic input image including visual representations of the one or more seismic measurements, and processing the seismic input image to identify a noise region in the seismic input image. Systems and machine-readable media are also provided.

Mitigation of fiber optic cable coupling for distributed acoustic sensing

A distributed acoustic sensor is positioned within a wellbore of a geologic formation. Seismic waves are detected using the distributed acoustic sensor. A raw seismic profile is generated based on the detected seismic waves. Resonant noise is identified and reduced in seismic data associated with the raw seismic profile.

Reducing resonant noise in seismic data acquired using a distributed acoustic sensing system

A DAS VSP technique is used to determine the induced fracture height and fracture density of an induced fracture region. The DAS VSP technique obtains pre-hydraulic fracturing DAS VSP survey time-lapse data to establish a baseline reference for the direct acoustic wave travel time. The DAS VSP technique obtains one or more time-lapse data corresponding to the subsequent monitor surveys conducted after each hydraulic fracturing stage along the well. Forward modeling is used to determine a theoretical acoustic wave travel time difference. The forward modeling uses seismic anisotropy to describe the behavior of seismic waves traveling through the induced fracture regions. An inversion scheme is then used to invert for the induced fracture height and the fracture density using the forward modeling. The two extracted induced fracture characteristics may then be used to determine optimal hydraulic fracturing parameters.

Anisotropy model guided fracture properties extraction from VSP data

A system for processing DAS VSP surveys in real-time is provided. The system includes a DAS data collection system coupled to at least one optical fiber at least partially positioned within a wellbore and configured to repeatedly activate a seismic source of energy. The system further includes an information processing system connected to the DAS data collection system. A seismic dataset is received from the DAS data collection system. The seismic dataset includes a plurality of seismic data records. Two or more of the plurality of seismic data records are combined into a stack. A quality metric indicative of a desired signal-to-noise ratio or incoherence of the stack is determined for each processed seismic dataset collected from a repeated source. Instructions are sent to the DAS data collection system to stop activating the seismic source, in response to determining that the quality metric has reached a predefined threshold.

Real-time processing and control of DAS VSP surveys

A seismic source is positioned at the surface of a geologic formation and a plurality of seismic receivers is positioned in a wellbore of the geologic formation. Seismic wavefield data is obtained based on the seismic source outputting seismic energy into the wellbore and the plurality of seismic receivers receiving the seismic energy. A velocity profile is determined along the wellbore based on the seismic wavefield data. P and S wave data in a downgoing direction is separated from the seismic wavefield data based on an inversion and the velocity profile. The P and S wave data in the downgoing direction is adaptively subtracted from the seismic wavefield data to form residual wavefield data. The P and S wave data in a upgoing direction is separated from the residual wavefield data based on the inversion and an updated velocity profile. The P and S wave data in the upgoing and downgoing direction is output.

Borehole seismic wavefield data separation

An apparatus obtains measurements from a seismic sensor, wherein the seismic measurements include a set of seismic waves having at least a subset of seismic multiples and a machine-readable medium having program code executable by a processor to cause the apparatus to determine seismic measurements of the seismic waves, fit reflectivity model based on a set of reflectivity models using a nonlinear scheme to the seismic measurements, and identify a subset of the seismic measurements corresponding to the subset of seismic multiples. The apparatus also includes program code to cause the apparatus to generate a set of reduced-noise seismic measurements based on attenuation of the subset of the seismic measurements.

Mitigation of seismic multiples in seismic data using inversion

A method and system for determining a deployment profile of a fiber optic cable. The method may comprise disposing a fiber optic cable into a tubular structure, opening and closing a valve to form a pressure pulse, wherein the pressure pulse travels within the tubular structure, sensing the pressure pulse within the tubular structure with the fiber optic cable and at least one pressure transducer, recording data from the pressure pulse with the fiber optic cable and the at least one pressure transducer, and sending the data to an information handling system from the fiber optic cable. A well measurement system may comprise a tubular structure, a fiber optic cable, a valve, and an information handling system, wherein the information handling system is configured to open and close the valve to form a pressure pulse and record data from the pressure pulse.

Depth and distance profiling with fiber optic cables and fluid hammer

To mitigate zigzag noise and increase the quality of data provided from DAS VSP in wells with significant vertical sections, zigzag noise characteristics are identified and quantified. The zigzag noise properties can be extracted from an analysis of an autocorrelation of DAS VSP traces. The zigzag noise has a characteristic time period or repeat time delay that is the time period for the noise to propagate along the wireline through a zone of the wellbore with poor acoustic coupling between the fiber optic cable and formation. This period can be identified from analysis of the autocorrelation referred to herein as a crosswise lag summation function. The crosswise lag summation function identifies groups of DAS data traces containing zigzag noise and outputs zigzag noise periodicity for each group of traces. Once it has been identified, the zigzag noise can be removed from the VSP data and improve formation evaluation.

Fiber optic noise mitigation for distributed acoustic sensing

Various embodiments include apparatus and methods implemented to simulate geophone data from distributed acoustic sensing data, such as simulating vertical component geo phone waveform data from distributed acoustic sensing data. Embodiments include measuring vertical component of strain at a plurality of vertical positions along an optical fiber disposed along a wellbore at a well site. The measured vertical component of strain can be processed to generate a vertical component of displacement. The vertical component of displacement can be used to generate a vertical component of velocity from which a waveform simulating a waveform of geophone data can be output. Additional apparatus, systems, and methods are disclosed.

Simulation of geophone data from distributed acoustic sensing data

A method to generate a vertical seismic profile includes acquiring a set of distributed acoustic sensing measurements from a set of overlapping measurement channels on an optical fiber, wherein each of the set of distributed acoustic sensing measurements are measured at a gauge length. The method also includes generating a set of virtual seismic measurements corresponding with subdivisions in the set of overlapping measurement channels based on the set of distributed acoustic sensing measurements and generating the vertical seismic profile based on the set of virtual seismic measurements.

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Katy, TX, United States of America

Mark Elliott Willis