Both onshore and offshore oil and gas production facilities include production equipment to separate and condition produced well fluids for transport to downstream production facilities. Transport can be over land or sea, by truck, railcar, pipeline or shuttle tanker.
When production fluids reach the surface they are separated into oil, water and gas streams and measured to determine the volume of each. The separation of these streams is accomplished using a primary separator (or wellhead separator). A metering skid is typically located downstream of the separator to measure the fluids before sending them on for further processing.
Primary wellhead separation occurs downstream of the wellhead inside a pressure vessel called a production separator, sometimes referred to as an oil and gas separator. Since oil, gas, and water have different densities, gravity allows bulk separation of these streams to occur inside the primary separator. Proper design and sizing of the primary separator is critical to the operation and capacity of the entire process facility. Separators typically include various mechanical devices, commonly referred to as separator internals, to assist in the separation process.
If the separator is only required to separate the produced fluid into natural gas and liquid, it is called a two-phase separator (or oil and gas separator). The degree of initial separation of the liquid and gaseous components depends on the temperature and pressure of the two-phase separator. Two-phase separators are also used in many downstream applications. Gas pipelines may consolidate production into a gathering center where liquids are removed from gas in a 2-phase separator, often referred to as a production trap. Two-phase separators that liquids immediately upstream of a compressor are called gas scrubbers.
Two-phase separators can be configured as either horizontal or vertical, depending on the volume of gas and liquid to be separated, the plot space available for surface production facilities, and the gas-to-oil ratio (or gas-to-liquids ratio). Horizontal separators allow more interfacial area for entrained gas to separate and can easily accommodate liquid slugging. Vertical separators are often used as gas scrubbers or as two-phase separators in offshore applications. If the separator is liquid packed, it is called an oil water separator.
A three-phase separator (3-phase separator) is used when the operating facility needs the production fluids to be split into separate gas, water, and oil streams. While seldom used in a vertical configuration, 3-phase separators can be oriented vertically or horizontally. A horizontal three-phase separator typically includes a fixed or variable weir to separate the oil from the water. Some designs use a flooded oil weir while others use an oil overflow weir. The bucket and weir configuration is an alternative, but less frequently used, design.
Special Design Considerations
Separators on floating production systems must account for mechanical accelerations and liquid sloshing inside the separator that results from wave intensity and frequency. Only companies with engineers experienced in layout and operation of process equipment for floating production systems should be trusted to design separators for these applications. For this special application, longitudinal and transverse anti-motion baffles are used in horizontal separators to mitigate the effects of motion. Other separator internals must also be designed for the acceleration loads and the fatigue caused by offshore movements.
Basic Separator Configuration
Regardless of its orientation or configuration, each separator is composed of three main sections – the inlet section, the gravity settling section, and the outlet section.
The inlet section is where the production fluids enter the separator (via the inlet nozzle) and the gas begins to separate from the liquid. Many engineers and designers also consider the upstream piping to be part of the inlet section of the separator. Inside the vessel and just after the inlet nozzle, the fluids pass through or make contact with an inlet device (inlet diverter) which transfers the fluid’s momentum into mechanical or cyclonic forces, thus enhancing bulk-phase separation.
The volume and length of the inlet section inside the separator can vary based on the type of inlet device used. An inlet section utilizing a plate deflector or half-pipe distributor may only require two to three linear feet while a cyclonic inlet device may require four or more linear feet.
[tweet_box design=”box_09″]Regardless of its orientation or configuration, each separator is composed of three main sections – the inlet section, the gravity settling section, and the outlet section.[/tweet_box]
Gravity Settling Section
The gravity settling section often takes up the most space in the separator. Its size depends upon the physical properties of the fluids being separated, the volume of these fluids, the residence time required to achieve gravity settling, and whether or not there are any separator internals to assist the gravity separation.
The liquid begins to settle to the liquid interface (or the respective oil and water interface) as it leaves the inlet section of the separator. Even with the assistance of an inlet device to separate the free associated gas, the liquid typically contains a substantial volume of solution gas. The gravity settling section and the normal liquid interface level are designed to allow sufficient time and surface area for the solution gas to escape the liquid phase. In a three-phase separator, the process engineer must allow sufficient volume and residence time to allow for liquid slugs and droplet migration to the proper liquid phase. In the settling section, the liquid level settings and elevation between the oil and water phase also depends on the product specification for the outlet streams.
The outlet section of the separator is the final area where the fluids are collected before flowing through their respective outlet nozzles. Depending on the specific application, the separator is typically equipped with an overflow weir (or oil bucket), a liquid collection area and a gas outlet nozzle. The outlet section isolates the separated phase and provides sufficient holdup time before allowing the fluid to exit the vessel. Vortex breakers are often used over or near the liquid outlet nozzles and a mist eliminator is incorporated before the gas is removed from the top of the separator.
Depending on the production facilities, the liquids content, and the operating pressure of the wellhead stream, multiple separators may be used in series to maximize liquid production. The increased project economics of adding an additional stage of separation is typically justified after accounting for the increased liquid recovery. When warranted, flashed gas from downstream separators is recovered and recompressed for export or further treatment.
Multi-stage separation may also be used when separating and stabilizing hydrocarbon liquids upstream of a storage tank regardless of the wellhead pressure. A low temperature separator, sometimes referred to as a free-water knock vessel, can be used to flash off associated gas while also removing free water from the hydrocarbon liquids. In such application, the hydrocarbon liquid is heated and separated in subsequent stages to either allow better oil-water separation or to stabilize the vapor pressure of the hydrocarbon liquid before storage.
In a multi-stage separation train, the first stage separator is often referred to as the high-pressure separator (or HP separator). The high pressure gas can be further conditioned for removal of acid gas and is typically dehydrated before being transported to downstream facilities.
The second or last stage separator in a separation train is called the low pressure separator (or LP separator). LP gas is typically compressed and combined with HP gas for further treatment while the liquids are transferred to a stock tank or sent for liquids stabilization.
While design principles and good engineering practices are relatively common, the physical characteristics of the reservoir, the component analysis of the production fluids, and the production methods utilized often make the design of separators for surface equipment facilities quite challenging to the inexperienced engineer. But with proper design information and knowledge of surface production operations, an experienced process company can provide standardized or custom designs to fit the application.
Using actual sample analysis of the fluids to be separated is the most helpful to the design engineer. The designer should be careful to understand the source of the design information by asking questions, such as:
- Is the data a combined sample from a core analysis?
- Is the produced water analysis from the production well?
- Is the design data for the liquid hydrocarbons simulated or from sampled stock tank?
Knowing the source of the information is crucial because separator sizing depends on the viscosity and surface tension of the fluids, the operating conditions of the arriving fluids, and the amount of sediment and water in the sample. Are there chemicals or solids in the production process that would portend to emulsification problems? Is there a potential for foam generation in the primary or LP separator? All these considerations should be in the mind of the design engineer when sizing a separator.
[tweet_box design=”box_09″]It is a good practice to assume that the reservoir characteristic will change over the life of the field production. [/tweet_box]
It is a good practice to assume that the reservoir characteristic will change over the life of the field production. With this in mind, the engineer can include vessel clips and account for separator internals that can account for current or future problematic areas.
- Does the separator have enough sampling and instrumentation nozzles?
- Are the nozzles properly located to get representative levels settings?
- Has the design engineer accounted for liquid holdup between level settings?
- Does the separator need to allow for slugging conditions?
- Will solids deposition or asphaltenes make for difficult detection of interface levels?
- Have the proper level transmitters been selected?
The design engineer must consider upstream and downstream equipment. Are there compressors or pumps downstream? Separator design should allow for removal of liquid droplets before compressors and must have sufficient liquid holdup before exiting the separator to avoid pump cavitation. Engineers and designers can comb public sources for information on good engineering practices and design standards, a few of which include the API’s Specification for Oil & Gas Separators (API Spec 12J), Process system design NORSOK P002, Shell’s Manual on Gas/Liquid Separators, and PetroWiki.
Even properly designed and operated separators (or other process equipment as part of surface production facilities) can encounter operational upsets followed by alarms and flickering lights that demand operator attention. These upset conditions can cause separator performance to deteriorate and eventually cause off-spec streams.
Three factors that can increase the corrosion rates in downstream piping systems or cause the products to be diverted to slop tanks where the off-spec product has to be re-processed or blended are:
- Produced water outlet containing an ominous amount of oil
- Exiting wet gas with appreciable liquids
- Hydrocarbon liquids with voluminous amounts of emulsified water
Some operating problems can be further mitigated by maintaining accurate liquid-gas or oil-water interface levels. One recently published article is devoted entirely to level design and control in separators.
Pump cavitation can be caused by maintaining a low NPSH (net positive suction head) or by choking the flow in the suction line due to blockage or undersized suction piping. The former operational problem may be corrected by raising the liquid interface, thereby increasing the suction pressure, while the later may be a matter of poor hydraulic piping design.
Production facilities and wellhead sites often divert a portion of the production fluids to a test (or metering) separatorso that the streams can be separated and measured. Test separators can be permanently installed, skid-mounted, or trailer mounted depending on the particular site needs. The separator can utilize several different types of meters to measure the separated well fluids. Test separators are often used for performing production tests and confirming fluid properties. Data is collected for streams such as pressure, temperature, water content, flow rates, solids content and fluid properties. If the production facility uses a multi-phase flowmeter, then a metering skid is used which can eliminate the need for a permanent test separator.
Offshore production facilities are typically provided with at least one test separator as multiple producing wells are tied back to the production platform. Just like a production separator, a test separator can be configured as a two-phase or three-phase separator and can be oriented vertically or horizontally. Horizontal test separators installed offshore will also be equipped with anti-motion baffles and other separator internals as needed to insure accurate measurement. Vertically-oriented test separators, however, do not require anti-motion baffles.