This article looks at pipeline natural gas metering station design but does not address the equations and empirical data used to calculate gas flow rates and volumes for custody transfer.
Nor does it cover the different standards of particular flow measuring devices, such as AGA-3 for differential pressure measurement; AGA-7 for turbine meters and vortex meters; and AGA-8 which provides equations to compute compensation factors for measured rates. Pipeline gas metering stations are designed for simultaneous, continuous analysis of the quality and quantity of natural gas being transferred in a pipeline, as follows:
- Upper calorific value, which is the latent energy content of a gas that is released during combustion. It is the major variable when defining the price.
- Concentration of sulphur compounds. Hydrogen sulphide and mercaptans are partially present as natural compounds and sometimes are mixed with the gas together with other sulphur compounds as odorants.
- Hydrocarbon dew point, which is a temperature at which higher hydrocarbons condense. Liquid phase is produced in the gas pipeline if the product temperature falls below the hydrocarbon dew point. The accumulation of liquid in the pipelines can lead to a plug flow and may destroy the compressors in the pumping station
- Water dew point is the temperature at which water condenses out. Water, together with hydrocarbons, favors the generation of solids, in particular during the decompression of gas from high-pressure pipelines. The solids block gas fittings, and the water is corrosive.
- The fiscal effects of natural gas volume and mass flow measurement and calculations.
The system consists of a multi-path ultrasonic flowmeter, process gas chromatograph and computer workstation installed, pre-wired and pre-piped in a special air-conditioned shelter with all auxiliary equipment and utilities.
Each gas metering station branches off of the pipeline and is used to reduce pressure and meter the gas to the various users. For the pressure reduction and metering stations, the main equipment includes filters, heaters, pressure reducers and regulators, and flow metering skids. In addition, each station is generally equipped with drains for collection and disposal, instrument gas system and storage tanks.
Natural gas filter units are installed at each station to remove any entrained liquids and solids from the gas stream. The filters may comprise cyclonic elements to centrifuge particles and liquids to the sides of the enclosing pressure vessel. These particles and liquids will then drop down for collection in a sump, which can be drained periodically.
A station inlet filter-separator should be installed upstream of the meter. The filter separator is normally a horizontal unit with a full-size, quick-opening closure and access platform for element change out. The vessel should be equipped with level gauges, high liquid level switches and a differential pressure transmitter across the filter elements. The filter-separator sumps should have automatic drain valves.
A condensate tank is installed for atmospheric storage of any liquids removed by the filter separator. Most tanks installed for this purpose are double-walled and installed on a concrete pad. The tank should contain a level gauge and a high liquid level switch.
A control valve should be installed downstream of the meter run to control both the flow through the meter and the delivery pressure. This valve will primarily operate to limit the station throughput in order to prevent the incoming gas volume from exceeding the meter capacity or the nominated volume but will also be equipped with a pressure override.
The control valve is generally controlled by a gas flow computer (GFC) based upon set points provided by the gas control center. The control valve will normally operate in the fully open position to minimize pressure losses through the station and should have a positioner, position indicator and position transmitter.
The GFC would also monitor and control the facilities as well as perform custody transfer quality measurement. The GFC communicates all data to a central control console via the SCADA system.
At custody transfers, a gas chromatograph is generally used to determine the gas composition for purposes of calculating the gas gross heating value. This data is provided to the GFC for use in calculating the total gas heating value in the metered gas. A gas sample is taken from a continuously flowing location on the meter and regulator skid. The gas sample is secured at low pressure to minimize lag time utilizing a self-regulating sample probe and routed to the gas chromatograph and moisture analyzer. The moisture analyzer is provided to measure the water content of the gas. Depending on sulphur content of the gas, a sulphur analyzer may be required.
Meter Skid Piping
The piping configuration on the meter skid should allow for bi-directional gas flow through the station by an appropriate piping and valving manifold. However, the gas flow through the meter and regulator should be in one direction only.
The control valve is installed between isolation ball valves to allow maintenance. It is prudent to install a manual bypass valve to allow continued operation during control valve maintenance activities.
Automatic Shutdown Valve
An automatic shutdown valve is normally installed at the pipeline connection. This valve should be remotely operated from the main operating system and equipped with local pneumatic controls, a hydraulic manual override and open/close limit switches.
Blowdown of the meter station piping is accomplished by a vent stack located on the station inlet piping and vents on the meter skid located downstream of the meter and downstream of the flow control valve. Vent stacks may or may not include silencers, depending on the noise levels at the closest noise sensitive area (NSA).
Natural gas heaters are installed to avoid the formation of hydrates, liquid hydrocarbons, and water as a result of pressure reduction. The gas heater is designed to raise the temperature of the gas so that after pressure reduction, the temperature of the gas will be above the dew point temperature at operating conditions and maximum flow. The heater is a water bath natural circulation type maintained at a temperature between 158-176 degrees F. Where gas cost is high, an alternative is to use high-efficiency or condensing furnaces for the purpose of preheating the gas rather than the water bath heater.
Pressure Reduction And Regulation
The pressure-reduction system controls the supply pressure to the gas users at a regulated value. Each system consists of at least two trains of pressure reduction – one operating and the other standby. Each train will normally comprise two regulator valves in series.
Regulator valves should be sized for the maximum anticipated volumes at the minimum anticipated inlet pressure during those times of maximum volume. For stations serving multiple residential customers or other non-interruptible services, sufficient regulator capacity needs to be provided so the failure of one regulator valve run will not reduce the facility capacity below required demand. Regulator valves in custody transfer stations are typically of the type that fail in the open position.
Sound pressure levels at all service conditions should be considered. High noise levels (generally defined at greater than 110 dbA) can result in damage to regulators, control valves, control valve accessories, instrumentation and downstream piping. Following are standard measures that can be taken to reduce sound pressure levels or to reduce the effects in the path:
- Install noise attenuating trim or diffusers on the regulator,
- Install heavy wall pipe,
- Install insulation,
- Install silencers,
- Bury the regulators.
Stations do not require an overpressure relief device if a monitor regulator is installed in series in each regulator run or if a monitor regulator is installed in series with and common to all regulator runs.
Station relief device capacity should be the largest relief capacity requirement determined from the following criteria using the flow and pressures:
- Failure of the single or largest capacity run that does not include a monitor regulator, or
- Failure of all runs in which the regulators would fail to open upon failure of a single common instrument or instrument line.
Minimum relief device capacity for the failed regulator(s) should be the maximum total flow at the differential pressure between the inlet and outlet of the regulator(s), in the case where inlet pressure is the upstream line MAOP or maximum source pressure, whichever is less, and the outlet pressure is the downstream MAOP plus allowed overpressure.
The flow rate of the gas has to be measured at a number of locations for the purpose of monitoring the performance of the pipeline system and more particularly at places where custody transfer takes place. Depending on the purpose for metering, whether for performance monitoring or for sales, the measuring techniques used may vary according to the accuracy demanded.
Potential for future expansion should be considered when sizing the meter skid length.
Typically, a custody transfer metering station will comprise one or two runs of pipe with a calibrated metering orifice in each run. Should an ultrasonic meter be required, it should be designed to meet or exceed the requirements established for ultrasonic meters in AGA-9. Typically, the ultrasonic meter will be a multi-path meter and the meter tubes will be equipped with a flow conditioner. The fully assembled meter tubes should be calibrated at line pressure and full-flow conditions prior to use. Normally, the ultrasonic meter tubes will be designed for a minimum 10D upstream length from the flow conditioner to the meter and 5D lengths downstream of the meter. Further, the meter tube should be honed.
The elimination of pulsation through the use of pulsation control devices is an important step to take. Pulsation has a tendency to introduce meter errors. Computer analogs are used in the design of pulsation-control equipment. There are several methods of determining if levels of pulsation will cause meter errors, but assessment of square-root error remains the best rule of thumb in determining if pulsation-control equipment is needed to improve absolute accuracy.
The square-root error is very predictable and is always positive. This error will always indicate a flow that is greater than the actual flow. Instability errors (which are pulsations that change the orifice coefficient) can vary in magnitude and can also be either positive or negative. A system with severe pulsation only needs a slight change in frequency (as little as a few Hz) to result in an error of several percent.
It is typical to separate the cathodic protection systems of the pipeline and meter station. This is normally done by installing insulation kits at the flange connections at the meter skid. Buried piping within the meter station, either upstream or downstream of the meter skid, should be cathodically protected from the associated pipeline’s cathodic protection system.
When conditions or regulations require a building to be utilized, typically a pre-engineered type building designed in accordance with the International Building Code is used and is mounted on the meter skid to enclose the ultrasonic meter and flow control valve area only. Normally, the building will not be heated or insulated. Buildings are sized to allow use of a meter-sensor removal tool.
The EFM and GC buildings are normally two separate buildings mounted on a common skid. As opposed to the meter building, the EFM building should be climate controlled (heated and air conditioned) and sized for the flow-control equipment and associated uninterrupted power supply (UPS). The GC building is not required to be climate controlled, but should have a hazardous gas detector with warning strobe light.
Saeid Mokhatab, with Tehran Raymand Consulting Engineers in Iran, specializes in the design and operations of natural gas transmission pipelines. He has participated as a senior consultant in various international pipeline/compressor station projects and published several academic and industry oriented papers and books. He is a frequent contributing editor to Pipeline & Gas Journal.
Greg Lamberson is the principal consultant of International Construction Consulting, LLC, USA, Tulsa, OK. He has more than 25 years of experience in all phases of business, project, engineering and construction management for upstream onshore and offshore oil, gas, and energy-related facilities and pipelines in North, Central and South America, the Caribbean, the Middle East, Central Asia, China, Russia, the Far East, and Africa.