Provided is a tangible, non-transitory, machine-readable medium storing instructions that when executed by one or more processors effectuate operations including: obtaining, with one or more processors, a plurality of user-supplied optimum operating values corresponding to a plurality of operating parameters in an oil and gas facility, obtaining, with one or more processors, a plurality of measured operating parameters.

Provided is a tangible, non-transitory, machine-readable medium storing instructions that when executed by one or more processors effectuate operations including: obtaining, with one or more processors, a plurality of user-supplied optimum operating values corresponding to a plurality of operating parameters in an oil and gas facility, obtaining, with one or more processors, a plurality of measured operating parameters.

The present disclosure provides methods and systems for assessing a pipeline failure based on a smart gas Internet of Things (IoT). The method is implemented by a smart gas safety management platform of an IoT system for smart gas pipeline network safety management, and the method includes obtaining at least one first failure risk in a gas pipeline and a downstream user feature, generating a plurality of candidate gas processing schemes based on the at least one first failure risk, and determining at least one second failure risk based on the at least one first failure risk and at least one of the candidate gas processing schemes.

The present disclosure provides methods and systems for assessing a pipeline failure based on a smart gas Internet of Things (IoT). The method is implemented by a smart gas safety management platform of an IoT system for smart gas pipeline network safety management, and the method includes obtaining at least one first failure risk in a gas pipeline and a downstream user feature, generating a plurality of candidate gas processing schemes based on the at least one first failure risk, and determining at least one second failure risk based on the at least one first failure risk and at least one of the candidate gas processing schemes.

A system, method and apparatus to transport and distribute hydrogen, store energy at scale, and interconnect locations where large quantities of “green” hydrogen can be produced most advantageously, with cities, towns and rural communities where hydrogen is needed as a clean transportation fuel, industrial feedstock, power source, and for long-term storage of electrical power. A hydrogen distribution pipeline enables use of natural gas, oil and other existing pipelines to transport hydrogen to one or more distribution points; and in one embodiment, integrates a lighter-than-air airship to transport hydrogen between locations where pipelines don't exist or are impractical. The disclosed hydrogen distribution pipeline also enables use of water, sewer, storm drain and other existing pipelines for local distribution, thereby saving time and money, and reducing construction disruption to the local community, in establishing these infrastructure components necessary to the widespread use of hydrogen in helping address climate change.

Dynamic pressure wave propagation can be used in pipelines to provide information about the available, unobstructed diameter and any partial or complete blockages in the pipeline. Certain aspects and features can be used to locate a pipeline inspection gauge (pig) that may be deployed in the pipeline, since in terms of a pressure profile, the pig is no different than any other type of pipeline blockage. Regular pulsing of the pipeline with a pressure wave can further be used to track a blockage over time. A valve or any other suitable device such as an air gun can be used to generate the pressure wave. A time series analysis can be carried out to determine and track the location of the blockage.

Techniques for implementing a system that includes a pipe segment and a monitoring apparatus. The pipe segment includes tubing that defines a pipe bore and a fluid conduit within a tubing annulus of the pipe segment. The monitoring apparatus includes a plurality of bore sensors fluidly connected to the pipe bore of the pipe segment, an annulus sensor fluidly connected to the fluid conduit defined within the tubing annulus of the pipe segment, and a control sub-system. The control sub-system determines whether a breach is present in the tubing of the pipe segment based at least in part on first sensor data determined by the bore sensors to be indicative of a bore fluid parameter present within the pipe bore of the pipe segment and second sensor data determined by the annulus sensor to be indicative of an annulus fluid parameter present within the tubing annulus of the pipe segment.

Techniques for implementing a system that includes a pipe segment and a monitoring apparatus. The pipe segment includes tubing that defines a pipe bore and a fluid conduit within a tubing annulus of the pipe segment. The monitoring apparatus includes a plurality of bore sensors fluidly connected to the pipe bore of the pipe segment, an annulus sensor fluidly connected to the fluid conduit defined within the tubing annulus of the pipe segment, and a control sub-system. The control sub-system determines whether a breach is present in the tubing of the pipe segment based at least in part on first sensor data determined by the bore sensors to be indicative of a bore fluid parameter present within the pipe bore of the pipe segment and second sensor data determined by the annulus sensor to be indicative of an annulus fluid parameter present within the tubing annulus of the pipe segment.

A method of evaluating the quantity of fluid that is lost in a fluid distribution network includes steps of: for each time interval of a given measurement period, acquiring a main measurement taken by the main fluid meter and representative of the quantity of fluid distributed via the main pipe during said time interval, and, for each secondary fluid meter, acquiring a secondary measurement taken by said secondary fluid meter and representative of the quantity of fluid that is distributed during said time interval via the secondary pipe to which said secondary fluid meter is connected; calculating a measurement difference equal to the difference between the main measurement and the sum of the secondary measurements; determining a minimum value of the measurement differences over the given measurement period; and evaluating the quantity of fluid lost over the given measurement period on the basis of the minimum value.

A method of evaluating the quantity of fluid that is lost in a fluid distribution network includes steps of: for each time interval of a given measurement period, acquiring a main measurement taken by the main fluid meter and representative of the quantity of fluid distributed via the main pipe during said time interval, and, for each secondary fluid meter, acquiring a secondary measurement taken by said secondary fluid meter and representative of the quantity of fluid that is distributed during said time interval via the secondary pipe to which said secondary fluid meter is connected; calculating a measurement difference equal to the difference between the main measurement and the sum of the secondary measurements; determining a minimum value of the measurement differences over the given measurement period; and evaluating the quantity of fluid lost over the given measurement period on the basis of the minimum value.