Process description
The oil train
The production plant can be considered to begin after the production wing valve on the oil well Christmas tree. The reservoir fluids from each well are piped through a flowline to a choke valve, which regulates the rate of flow and reduces the pressure of the fluids. [2] The flowlines from each well are gathered together at one or more inlet manifolds. These are provided for each train or operate at different pressures to match the wellhead pressure with various separator pressures. High pressure manifolds are routed into a first stage separator, which separates the three fluid phases. Produced water, the densest phase, settles out at the bottom of the separator, oil floats on the top of the produced water phase, and gas occupies the upper part of the separator. [8] The separator is sized to provide a liquid residence time of 3 to 5 minutes which is sufficient for light crude oil (>35° API) as produced in the North Sea. In the Gulf of Mexico the first stage separator operates as a 2-phase (gas and liquid) vessel, it is sized to provide a liquid residence time of 1 to 2 minutes.
Sand and other solids from the reservoir will tend to settle out in the bottom of the separators. If allowed to accumulate the solids reduce the volume available for oil/gas/water separation reducing efficiency. The vessel may be taken offline and drained down and the solids removed by digging out by hand. Or water sparge pipes in the base of the separator used to fluidize the sand which can be drained from the drain valves in the base.
Oil from the first stage separator may be cooled or heated in a heat exchanger to aid further separation. North Sea fields tend to operate at higher temperatures so heating may not be required. Gulf of Mexico fields tend to operate at lower temperatures so heat is required to achieve export vapor and BS&W specifications. Typical operating temperatures are 140 – 160 °F (60 – 71 °C). [4]
Oil is then routed either to a second stage separator, operating at a lower pressure than the first stage to further separate oil/gas/water, or to a coalescer to further remove water. [8] Several stages of separation, operating at successively lower pressures, aim to reduce the amount of dissolved gas and hence reduces the flash point of the oil to meet the export oil specification. [9] For higher oil flowrates parallel trains of separators may be necessary to handle the flow and to provide a turn-down capability. [2] The final stage of separation may be an electrostatic coalescer. These can achieve a 0.5% by volume water content, typical design fluxes are in the order of 200 bopd/ft2. [4]
A test separator (see diagram) enables the performance of individual wells to be determined. An individual well is connected to the test header which routes fluids to the test separator. Three phase separation into oil, vapour and produced water takes place. The flowrates of these phases are accurately measured as the fluids flow to lower pressure points in the oil train. The flowrates determine the performance of the well in terms of the maximum flow of the well, the gas-oil ratio, and the water cut of the fluids.
Some oil fields are sour, with high levels of carbon dioxide (CO2) and hydrogen sulphide (H2S). Operation of separation at high temperature drives these gases to the vapour phase. However, crude may still contain sour compounds above a typical H2S-in-crude specification limit of < 10 ppmw. A trayed column is used with sour crude fed in the top of the column and stripping gas introduced into the bottom of the column. [4]
From the final stage of separation, or from the coaleser, oil may be cooled to meet export specifications or to limit thermal stresses on the oil export riser. Oil is metered to accurately measure the flowrate [10] and then pumped via a pipeline to the onshore terminal. Some installations such as concrete gravity-base structures and floating production storage and offloading, FPSOs, have integral oil storage tanks which are continuously filled with oil and periodically discharged into oil tankers.
Produced water
Produced water from the separator(s) and coalescer is routed to a produced water degasser operating at near atmospheric pressure to remove dissolved gas from the water. In the early days of the offshore industry parallel plate separator units were used to clean produced water prior to overboard disposal. Hydrocyclones, which are more compact, were introduced in the 1980s. [1] A hydrocyclone removes entrained oil and solids from produced water which then passes to the degasser and can then either be re-injected into the reservoir or dumped overboard. Induced gas flotation plant is used when the hydrocyclone / degasser plant cannot achieve the oil-in-water specification. For overboard disposal the water should have an oil content of less than about 30 parts per million (ppm) oil-in-water. [11] On North Sea installations the higher operating temperatures allow an oil-in-water concentration of > 20 ppmw to be achieved. [4]
The gas train
The associated gas from the top of the separator(s) is also known as flash gas or wet gas as it is saturated with water and liquid hydrocarbons. The gas is typically routed through scrubbers, compressors and coolers to raise the pressure of the gas and to remove liquids. [2] Scrubbers are vertical vessels that allow the removal and separation of liquids from a gas stream. Coolers are located after a compressor to remove the heat of compression. Centrifugal compressors are often used offshore. They are more compact and lighter than reciprocating machines and maintenance costs are less. The latter are used where only small volumes of gas are handled. Centrifugal compressors my be driven by gas turbines or electric motors. [4]
The dry gas may be exported, used for gas lift, flared, used as fuel for the installation's power generators, or after further compression re-injected into the reservoir. Export gas is metered to accurately measure the flowrate before being sent to the onshore terminal via gas pipeline. Other treatment processes may be required.
Gas dehydration
Gas may be dried to reduce the water content to meet sales specification, to prevent condensation of water in the pipeline and the formation of slugs, or to avoid the formation of hydrates in the export pipeline. Gas is dried by counter-current contact with triethylene glycol in a glycol dehydration tower. [12] Typically dried gas has a water content of 2.5 to 7 lb of water /MMSCF. Glycol contactors generally operate at 1100–1200 psi (75 to 83 bar). [4] Water-rich glycol is regenerated by heating and stripping off the water. Enhanced regeneration uses DRIZO or Coldfinger to improve the regeneration performance. [4] Contactor towers formerly comprised bubble cap trays, since the 1980s structured packing has been used which provides the equivalent of 3 to 4 theoretical trays required to meet a water content of <4 lb/MMSCF. [4]
Hydrocarbon dewpointing
The export hydrocarbon dew-point specification (typically 100 barg at 5 °C [13] ) may be met by chilling the gas to remove the higher alkanes (butane, pentanes, etc.). This may be done by a refrigeration system, or passing the gas through a Joule-Thomson valve, or through a turbo-expander to condense out and separate liquids. The natural gas liquids (NGL) produced may be spiked into the oil export fluids where high vapor pressure fluids are exported. [1] Alternatively NGL fractionating columns may be used to produce a fluid for separate export. NGL fractionation columns are installed in Nkossa West Africa and Ardjuna Indonesia. [4]
Gas sweetening
Dry gas may be further treated to meet export gas specifications. [13] Excess carbon dioxide (CO2) can be removed by treatment in an amine gas treating process (e.g. Selexol), whereby CO2 is preferentially dissolved in a counter-current flow of amine in a contact tower. Hydrogen sulphide can also be removed using amine or by passing the gas through beds of zinc oxide absorbent.
