Raw natural gas is composed of several gases. The main component is methane. Other components include ethane, propane, butane, and many other combustible hydrocarbons. Raw natural gas may also contain water vapor, hydrogen sulfide, carbon dioxide, nitrogen, and helium.
During processing, many of these components may be removed. Some such as ethane, propane and butane are completely removed processed and transported by TPDC loading ships. Other components such as water vapor and carbon dioxide are removed to improve the quality of the natural gas so as to make it easier to move the gas over great distances through pipelines.
The manufacturing process:
The methods used to extract, process, transport, store, and distribute natural gas depend on the location and composition of the raw gas and the location and application of the gas by the end users . Here is the flow sheet of typical natural gas plant.
Process flow diagram of natural gas processing
With the assistance of Christmas trees in well heads the well fluids from the two offshore wells SS-7 and SS-9 and three onshore Wells SS-3,SS-10 and SS-4 injected with mixture of corrosion inhibitor and water clarifier are transported in two individual 6” and two individual 4” buried flow lines respectively to the gas plant inlet skid where they tie into their individual inlet flow control valves. The flow lines then run to the gas plant inlet metering and manifold skid where each well’s production is measured in a meter run.
The inlet manifold consists of a 10” HP production header and a 10” test header for gas stream mixing which is done purposely to allow set up of production “well sets “so that for a given production level, the best reservoir utilization, well flow composition can be selected from the available wells. The gas from test header flows into the test separator. With valves assistance provided, the inlet manifold permits any or all producing wells to be diverted to test separator.
Test separator is a three-phase separator complete with a boot. Accounting type gas (senior orifice type fittings) and liquid metering (turbine flow meter) is provided in the outlet piping from the vessel to allow for periodic well testing. The gas stream flows from the test separator to the inlet separator (V-110) gas outlet line. The hydrocarbon liquid stream is metered and dumped under level control to the condensate flash tank. Produced water separated in the boot is metered and dumped under level control to the produced water handling system.
The gas from HP production header flows into a three phase Inlet Separator for separation. Inlet separator is a three-phase (gas, condensate and water) separator complete with a boot. The vessel is sized to handle any liquid slugs from the well flow lines. A high-level dump system is provided such that in the event of a large slug the liquids are automatically dumped to the closed drain drum. Hydrocarbon liquids are separated from the gas and water behind a weir in the main vessel and are dumped under level control to the condensate flash tank. Produced water is separated in the boot and is normally dumped under level control to the produced water handling system.
The gas from test and production separators is commingled and then the stream is split to enter two dew point control trains. The gas first enters the tube side of the gas-gas exchanger where it is pre-cooled by counter-current heat exchange with the outgoing dry sales gas. Lean glycol solution is sprayed onto the inlet tube sheet of each exchanger to absorb water and prevent the formation of hydrates. The gas from heat exchangers is further cooled by pressure drop across the Joule Thomson valves, upstream of cold separators. During this cooling process, hydrocarbon liquids are condensed. Cold separators are three phase Separators where gas, condensate and rich glycol are separated. The separated condensate flows under level control to the condensate stabilization unit and rich glycol flows under level control to the Glycol Regeneration units for re-concentration prior to re-injection at the gas-gas exchangers. The separated dry gas from the cold separator flows through the shell side of the gas- gas exchanger and leaves the plant as sales gas. The treated gas streams from both the dew point control trains are commingled. A portion of this gas is sent to the fuel gas system for make-up requirements and the remaining dry gas flows to the marine pipeline and onto the mainland. This fuel gas is metered, heated across Fuel Gas Heater and let down across a Pressure control valve to about 350 kPag and 30°C before entering the Low pressure fuel gas scrubber. The sales gas is metered in a metering unit (ultrasonic sales gas meter) and odorized prior to its entering the 12” marine pipeline for gas transportation.