Controlling flow of gas in a gas pipeline network, wherein flow of gas within each of the pipeline segments is associated with a direction (positive or negative). Processors calculate minimum and maximum production rates (bounds) at the gas production plant to satisfy an energy consumption constraint over a period of time. The production rate bounds are used to calculate minimum and maximum signed flow rates (bounds) for each pipeline segment. A nonlinear pressure drop relationship is linearized to create a linear pressure drop model for each pipeline segment. A network flow solution is calculated, using the linear pressure drop model, comprising flow rates for each pipeline segment to satisfy demand constraints and pressures for each of a plurality of network nodes over the period of time to satisfy pressure constraints. The network flow solution is associated with control element setpoints used to control one or more control elements.

In various embodiments, a mobile, open-air, electrical skid may provide electrical power from high voltage power lines via one or more electrical components to natural gas compressors at a natural gas compressor site. In several embodiments, the open-air skid may be of a size that can fit on a flat-bed trailer so that the skid can be transported to the site, and the open-air skid may not have side walls to allow for air flowing across the components. The electrical components may include an electric variable frequency drive, a sync reactor, one or more motor relays, an input cabinet, one or more motor control cabinets, a remote cooling unit, and/or other electrical components utilized to start-up one or more natural gas compressors and keep the one or more natural gas compressors running.

In various embodiments, a mobile, open-air, electrical skid may provide electrical power from high voltage power lines via one or more electrical components to natural gas compressors at a natural gas compressor site. In several embodiments, the open-air skid may be of a size that can fit on a flat-bed trailer so that the skid can be transported to the site, and the open-air skid may not have side walls to allow for air flowing across the components. The electrical components may include an electric variable frequency drive, a sync reactor, one or more motor relays, an input cabinet, one or more motor control cabinets, a remote cooling unit, and/or other electrical components utilized to start-up one or more natural gas compressors and keep the one or more natural gas compressors running.

This disclosure describes a natural gas collection system utilizing a single compressor to manage collection of natural gas from both high-pressure and low-pressure sources. The operation of the single compressor is controlled by a PLC configured to receive pressure data from sensors and to direct compressor speed in order to maintain natural gas pressure at the user defined targets.

This disclosure describes a natural gas collection system utilizing a single compressor to manage collection of natural gas from both high-pressure and low-pressure sources. The operation of the single compressor is controlled by a PLC configured to receive pressure data from sensors and to direct compressor speed in order to maintain natural gas pressure at the user defined targets.

A system for automatically evacuating liquids from natural gas pipelines. An embodiment may be used for associated drip vessels and other containers and gas wells. The system includes a tank, a compressor, and an electric generator system. The system evacuates liquid from a pipeline by creating a pressure differential between the pipeline and the tank. When adequate pressure differential is achieved, liquids flow into the tank from the pipeline. When liquids are removed, the system shuts down and awaits a run signal. The system is suited for remote locations, due, in part, to the use of an automatic generator capable of providing power to the compressor and to the CPU as necessary. Liquid removal may be determined by measuring tank pressure at time intervals and determining a rate of change of tank pressure for indicating blow through. The system utilizes the same pipeline tap for liquid removal and gas injection.

A system for automatically evacuating liquids from natural gas pipelines. An embodiment may be used for associated drip vessels and other containers and gas wells. The system includes a tank, a compressor, and an electric generator system. The system evacuates liquid from a pipeline by creating a pressure differential between the pipeline and the tank. When adequate pressure differential is achieved, liquids flow into the tank from the pipeline. When liquids are removed, the system shuts down and awaits a run signal. The system is suited for remote locations, due, in part, to the use of an automatic generator capable of providing power to the compressor and to the CPU as necessary. Liquid removal may be determined by measuring tank pressure at time intervals and determining a rate of change of tank pressure for indicating blow through. The system utilizes the same pipeline tap for liquid removal and gas injection.

Controlling flow of gas in a gas pipeline network, wherein flow of gas within each of the pipeline segments is associated with a direction (positive or negative). Processors calculate minimum and maximum production rates (bounds) at the gas production plant to satisfy an energy consumption constraint over a period of time. The production rate bounds are used to calculate minimum and maximum signed flow rates (bounds) for each pipeline segment. A nonlinear pressure drop relationship is linearized to create a linear pressure drop model for each pipeline segment. A network flow solution is calculated, using the linear pressure drop model, comprising flow rates for each pipeline segment to satisfy demand constraints and pressures for each of a plurality of network nodes over the period of time to satisfy pressure constraints. The network flow solution is associated with control element setpoints used to control one or more control elements.

Controlling flow of gas in a gas pipeline network, wherein flow of gas within each of the pipeline segments is associated with a direction (positive or negative). Processors calculate minimum and maximum production rates (bounds) at the gas production plant to satisfy an energy consumption constraint over a period of time. The production rate bounds are used to calculate minimum and maximum signed flow rates (bounds) for each pipeline segment. A nonlinear pressure drop relationship is linearized to create a linear pressure drop model for each pipeline segment. A network flow solution is calculated, using the linear pressure drop model, comprising flow rates for each pipeline segment to satisfy demand constraints and pressures for each of a plurality of network nodes over the period of time to satisfy pressure constraints. The network flow solution is associated with control element setpoints used to control one or more control elements.

The gas compression system for a gas pipeline includes a reciprocating compressor arranged to compress the gas and a gas turbine engine arranged to drive the reciprocating compressor. The gas turbine engine has a turbine section with a high-pressure section and a low-pressure section, wherein only the low-pressure section is mechanically coupled through a mechanical connection to a reciprocating compressor arranged to compress the gas transported by the gas pipeline. The mechanical connection comprises a gearbox, an elastomeric coupling and a flywheel. The gas compression system is particularly suitable as a gas pipeline compression station using the gas transported by the gas pipeline as fuel. Advantageously, the gas turbine engine can reduce NOx formation during combustion by injecting diluent in the combustor, the diluent being advantageously demineralized water recovered from the inlet air of the gas turbine engine.