A device of determining pipes includes a memory unit, a processing unit and a communication interface, wherein the processing unit is connected to the memory unit and the communication interface. The memory unit has stored pipe names, reference pipe outside diameter values and orders of the pipe names corresponding to the reference pipe outside diameter values. The processing unit receives an outside diameter measuring data of a pipe, compares the outside diameter measuring data with the reference pipe outside diameter values, selects the pipe name corresponding to the reference pipe outside diameter value same as the outside diameter measuring data, and generates at least one the pipe name that matches the outside diameter measuring data according to the selected order of the pipe name. The communication interface outputs the pipe name that matches the outside diameter measuring data.

A system for determining a corrosion level of a pipeline includes a corrosion coupon received from the pipeline, a database, a first computer, a second computer, a neural network, and a third computer. The database includes existing data indicative of corrosion of a plurality of previously analyzed pipelines. The first computer receives corrosion data of the corrosion coupon and uploads the corrosion data to the database. The second computer uploads calculations performed on the corrosion data to the database. The neural network receives the corrosion data and the calculations from the database and outputs a corrosion level of the pipeline based on the corrosion data and the calculations. Further, the neural network is trained on the existing data from the plurality of previously analyzed pipelines so that the corrosion level is based on a combination of the corrosion data, the calculations, and the existing data. Finally, a third computer receives the corrosion level and generates a report of the corrosion level of the pipeline.

A system for determining a corrosion level of a pipeline includes a corrosion coupon received from the pipeline, a database, a first computer, a second computer, a neural network, and a third computer. The database includes existing data indicative of corrosion of a plurality of previously analyzed pipelines. The first computer receives corrosion data of the corrosion coupon and uploads the corrosion data to the database. The second computer uploads calculations performed on the corrosion data to the database. The neural network receives the corrosion data and the calculations from the database and outputs a corrosion level of the pipeline based on the corrosion data and the calculations. Further, the neural network is trained on the existing data from the plurality of previously analyzed pipelines so that the corrosion level is based on a combination of the corrosion data, the calculations, and the existing data. Finally, a third computer receives the corrosion level and generates a report of the corrosion level of the pipeline.

Cable guides that support a fiber optic cable relative to a tube, hydrocarbon conveyance systems including the cable guides, and methods of acoustically probing an elongate region. The cable guides include a cable retention structure with a first retention region configured to align a first diffraction grating along a first sensing axis and a second retention region configured to align a second diffraction grating along a second sensing axis that is nonparallel to the first sensing axis. The tube defines a tubular conduit configured to convey a hydrocarbon. The hydrocarbon conveyance systems include a tube, a distributed acoustic sensor, and a cable guide. The methods include transmitting an initiated optical signal and receiving a reflected optical signal that includes reflected portions that are reflected by a first diffraction grating and a second diffraction grating. The methods further include analyzing the reflected optical signal to detect an applied mechanical strain.

Cable guides that support a fiber optic cable relative to a tube, hydrocarbon conveyance systems including the cable guides, and methods of acoustically probing an elongate region. The cable guides include a cable retention structure with a first retention region configured to align a first diffraction grating along a first sensing axis and a second retention region configured to align a second diffraction grating along a second sensing axis that is nonparallel to the first sensing axis. The tube defines a tubular conduit configured to convey a hydrocarbon. The hydrocarbon conveyance systems include a tube, a distributed acoustic sensor, and a cable guide. The methods include transmitting an initiated optical signal and receiving a reflected optical signal that includes reflected portions that are reflected by a first diffraction grating and a second diffraction grating. The methods further include analyzing the reflected optical signal to detect an applied mechanical strain.

Methods and systems for modelling pipeline construction, include or implement steps of (a) obtaining ranging data of a pipeline construction location including a pipe; (b) processing the ranging data to produce a spatially organized point cloud; and (c) processing the point cloud to identify at least one geometric feature comprising a point or a two-dimensional feature representative of a pipe centreline, and associating the at least one geometric feature with the pipeline construction location. The ranging data may be data obtained from a lidar device. The pipeline construction may be underground construction, where pipe is laid in a ditch. Relevant information, such as depth-of-cover may be calculated from identified geometric features. Relevant information may be determined in real-time or near-real-time and displayed, communicated or recorded as desired.

Methods and systems for modelling pipeline construction, include or implement steps of (a) obtaining ranging data of a pipeline construction location including a pipe; (b) processing the ranging data to produce a spatially organized point cloud; and (c) processing the point cloud to identify at least one geometric feature comprising a point or a two-dimensional feature representative of a pipe centreline, and associating the at least one geometric feature with the pipeline construction location. The ranging data may be data obtained from a lidar device. The pipeline construction may be underground construction, where pipe is laid in a ditch. Relevant information, such as depth-of-cover may be calculated from identified geometric features. Relevant information may be determined in real-time or near-real-time and displayed, communicated or recorded as desired.

An electric field gradient sensor is presented, having a sensor body having an outer surface; and a plurality of electrodes distributed over the outer surface, each electrode having an electrode surface facing outward from the surface. The plurality of electrodes are arranged forming a plurality of electrode pairs, each electrode pair formed by a first electrode and a second electrode located on opposite sides of the sensor body. This sensor enables three-dimensional measurements of the electric field gradient along structures located in an electrically conductive medium, such as subsea structures, for example for monitoring the cathodic protection of such structure.

A method of vaporising liquefied natural gas (LNG) for measurement of its constituent components may include receiving LNG from a main pipeline into a pressurising device. The method may also include via the pressurising device, pressurising a the LNG beyond a critical pressure thereof. The method may further include directing a first portion of the pressurised LNG to a heater. The method may still further include via the heater, heating the first portion of pressurised LNG beyond a critical temperature thereof, and directing the pressurised and heated LNG to a vaporising device. The method may also include via the vaporising device, depressurising the heated LNG to a pressure below the critical pressure so as to vaporise the LNG.

A method of vaporising liquefied natural gas (LNG) for measurement of its constituent components may include receiving LNG from a main pipeline into a pressurising device. The method may also include via the pressurising device, pressurising a the LNG beyond a critical pressure thereof. The method may further include directing a first portion of the pressurised LNG to a heater. The method may still further include via the heater, heating the first portion of pressurised LNG beyond a critical temperature thereof, and directing the pressurised and heated LNG to a vaporising device. The method may also include via the vaporising device, depressurising the heated LNG to a pressure below the critical pressure so as to vaporise the LNG.