Abstract: A method and apparatus for seismic sensing is described. The apparatus includes an outer cable coupled to a formation and an outer fiber component proximate to the outer cable. When seismic P- and S-waves propagate from the formation to the outer cable, strain is placed on the outer fiber cable, which may be measured by a distributed acoustic sensing system coupled to the outer fiber cable. An inner cable positioned within the outer cable includes a corresponding inner fiber component. The innerduct between the outer and inner cables is filled with a gas or fluid which allows only P-waves to propagate to the inner cable. Those P-waves induce strain on the inner fiber component, which may be measured by the distributed acoustic sensing system. By measuring the seismic P- and S-waves at the outer fiber component, and the isolated seismic P-wave at the inner fiber component, it is possible to calculate an isolated seismic S-wave measurement. Methods for deploying the seismic sensing apparatus are also described.

Abstract: The present invention relates to a system for vortex energy harvesting for downhole applications and a method thereof, the system comprising: one or more electro acoustic technology assemblies mounted downhole in close proximity to a fiber optic cable that is part of a fiber optic distributed acoustic sensing system connected back to a surface distributed acoustic sensing interrogator; and one or more vortex energy harvesters attached to each of the electro acoustic technology assemblies and exposed to a fluid flow in the downhole application.

Abstract: A method and system for using a distributed electromagnetic sensing system in horizontal hydraulic fracturing wells to monitor fracture growth in real time.

Abstract: A fiber optic sensor interrogation system with inbuilt passive power limiting capability that provides improved safety performance for use in explosive atmospheres.

Abstract: Various embodiments include methods and systems structured to transmit data from downhole sensors to the surface at a well site. The transmission can be implemented to overcome downhole connections that can act as obstructions to direct electrical and optical communication in a wellbore. Electrical signals from one or more sensors in a sensor unit, located on a side of a downhole connection in a wellbore opposite the surface of the wellbore, can be used to drive an acoustic transmitter to transmit an acoustic signal via a production string or casing or fluid in the production string or casing across the downhole connection, where the acoustic signal is received on the surface side of the downhole connection. Data correlated to the received acoustic signal can be provided to a surface location of the wellbore. Additional apparatus, systems, and methods can be implemented in a variety of applications.

Abstract: A cable introduction assembly that can include: a spool assembly including a spool having a first axis, the spool configured to retain a cable wound around the first axis in an undeployed mode; and a spool mount assembly configured to retain the spool and introduce the cable in a deployed mode into a conduit configured for a downhole environment, the conduit having a proximal end and a distal end, the cable in the deployed mode extending from the proximal end towards the distal end, wherein the spool assembly is configured to provide a handedness to the cable in the deployed mode.

Abstract: A system is described for reliably detecting leaks in a distributed manner in intermittent use pipelines by making use of thermal or acoustic events triggered by the leak. The system can work in pressurized or unpressurized pipelines and in high flow or no flow conditions.

Abstract: A device and method is described for either launching or retrieving wireline electro acoustic technology (EAT) sensor assemblies downhole.

Abstract: A device is described for downhole seismic sensing utilizing electro acoustic technology in conjunction with moveable downhole seismic sources.

Abstract: A cable protector can include a first side bar welded along a length of a casing section. A second side bar can be welded along the length of the casing section. The second side bar can be positioned substantially parallel to the first side bar. A cable can be positioned between the first side bar and the second side bar. The cable can be positioned while the casing section is being run-in-hole. A cover strip can be welded on top of first side bar and the second side bar. The cover strip can be welded in place while the casing section is being run-in-hole.

Abstract: A method is described for compensating measurement errors of fiber Bragg grating (FBG) sensors installed in fiber cables in downhole oil and gas environments due to hydrogen darkening. The method involves loading a fiber of known length and multiple FBG sensors in a hydrogen chamber with control of temperature, hydrogen concentration, pressure, and time and adjusting each of the variables through a test matrix while continuously measuring and recording the fiber transmission loss and FBG spectrum changes, then creating a correlation map of fiber transmission loss vs. Bragg wavelength shift, and using that map for compensating the wavelength shift of downhole installed fiber cables as a function of their hydrogen induced transmission loss through time.

Abstract: Various embodiments include methods and systems structured to transmit data from downhole sensors to the surface at a well site. The transmission can be implemented to overcome downhole connections that can act as obstructions to direct electrical and optical communication in a wellbore. Electrical signals from one or more sensors in a sensor unit, located on a side of a downhole connection in a wellbore opposite the surface of the wellbore, can be used to drive an acoustic transmitter to transmit an acoustic signal via a production string or casing or fluid in the production string or casing across the downhole connection, where the acoustic signal is received on the surface side of the downhole connection. Data correlated to the received acoustic signal can be provided to a surface location of the wellbore. Additional apparatus, systems, and methods can be implemented in a variety of applications.

Abstract: Example systems and methods are described for performing multilateral well sensing in a downhole environment. In an example system, a cased parent wellbore and a cased lateral wellbore intersect at a lateral junction. A sensor is deployed within the cased lateral wellbore that communicably couples to a transmitter module, wherein the transmitter module is deployed within the cased lateral wellbore downhole of the lateral junction and configured to generate acoustic signals. An optical fiber cable is deployed within the cased parent wellbore and configured to receive acoustic signals transmitted by the transmitter module in the cased lateral wellbore.

Abstract: A system and method to minimize the likelihood of cable damage due to downhole operations such as perforating is disclosed. The system includes at least one transducer and at least one orientation device positioned adjacent a cable. A wireless signal from the transducer and/or orientation device is transmitted towards the cable. The wireless signal influences a wired signal transmitted in the cable. The influenced wired signal is used to identify the axial and radial orientation of the cable. The transducer may be secured to a mid-joint collar on the casing string in a portion of the wellbore to be perforated. The transducers are identified and located by the control system and a perforating tool can be adjusted to point away from the cable before firing of the perforating tool.

Abstract: Disclosed are pump-down sensor devices that operate in conjunction with a fiber-optic sensing system to take downhole measurements and communicate them to the surface while moving untethered through a borehole. A pump-down sensor device in accordance with various embodiments includes one or more flow baffles configured for a specified buoyancy, and an electronics module for measuring one or more downhole parameters and transmitting an acoustic signal encoding the measured parameter(s). The acoustic signal can be detected using the fiber-optic sensing system. Additional embodiments are disclosed.

Abstract: The use of a distributed fiber optic strain sensor system in horizontal hydraulic fracturing wells to determine several measurements of hydraulic fracture system geometry including number of far-field fractures, hydraulic and propped fracture length, fracture azimuth, and multi-planar fracture complexity.

Abstract: Example apparatus, methods, and systems are described for performing bottom hole measurements in a downhole environment. In an example system, a bridge plug is deployed at a downhole location of a cased well, An optical fiber cable is deployed exterior to the casing of the well. The bridge plug includes a sensor and an acoustic signal generator, which transmits acoustic signals through the casing to the optical fiber cable.

Abstract: A sensory assembly and system can be used in a wellbore to detect and characterize the earth strata and formations around the wellbore, where a signal emitting sensory tool is part of a tool string deployed in the wellbore, and where weighted fiber optic cable is deployed in an extended position below the signal emitting sensory tool. The fiber optic cable is also part of wire-line, slickline, or coiled tubing injector head connected to the signal emitting sensory tool, thereby providing fiber optic cable both above and below the signal emitting sensory tool in position to collect backscatter signals from earth strata and formations around the wellbore. The collection of backscatter signals, particularly from below the signal emitting sensory tool, allows for more precise characterization of formations and fractures within the earth strata.

Abstract: A system and method for a higher speed auto-correcting temperature measurement in a system using a fiber optic distributed sensor.

Abstract: A system and method for effective seismic monitoring of large area subsurface reservoirs, for instance, the system comprising: multiple electro acoustic technology assemblies comprising electrical seismic sensing elements, electronic circuits for converting the electrical seismic sensing signals to frequencies, amplification circuitry to amplify the frequencies, an acoustic source that converts the amplified frequencies to an acoustic frequency signal; a fiber optic Distributed Acoustic Sensing (DAS) system comprising a fiber optic cable deployed in the subsurface reservoir and in close proximity to the multiple electro acoustic technology assemblies and exposed to the generated acoustic frequency signals from the acoustic sources of the multiple electro acoustic technology assemblies, a surface based distributed acoustic sensing interrogator connected to the fiber optic cable; a source of electrical power to the multiple electro acoustic technology assemblies.