Oil and gas separators

Oil/gas separators are typically pressure vessels used for separating a well stream into gaseous and liquid components. They can be installed at various locations such as individual well pads, central gathering facilities, onshore processing stations, offshore platforms, or a subsea facilities.  Based on the vessel configurations, the oil/gas separators can be divided into horizontal, vertical, inline/pipe, or spherical separators. In terms of fluids to be separated, the oil/gas separators can be grouped into gas/liquid two-phase separator or gas/oil/water three-phase separator. Solids can separate as well and can accumulate in the vessel. Based on separation function, the oil/gas separators can also be classified into primary phase separator, test separator, high-pressure separator, intermediate pressure separator, low-pressure separator, demisting gas, degassing liquid, etc.

Depending on a specific application, oil/gas separators are also called scrubbers or liquid degassers. The scrubbers are used to remove dispersed droplets from a bulk gas stream to protect compressors, gas treating (dehydration and amine treating), metering, other gas systems, while the liquid degassers are designed to remove contained gas bubbles from the bulk liquid stream for pump protection and metering.

Separator functions

Separators function to divide a mixed phase of gasses and liquids into individual streams, either for processing or to protect equipment which is unable to handle a mixed phase. Stage recovery of liquid hydrocarbons - staged separation (depressurization) - to maximize the liquid hydrocarbon volumes while degassing the oil to reduce its vapor pressure is one of the most typical uses for separators.  Figure 1 shows a representative deepwater Gulf of Mexico (GOM) process train. There are three main stages of depressurization plus a final fourth degassing stage and oil polishing prior to storage:

1. High Pressure (HP) – highest pressure production delivered to the facility
2. Intermediate Pressure (IP) – combination of any intermediate pressure production  delivered to the facility and oil from the HP Separator
3. Low Pressure (LG) - combination of any low-pressure production delivered to the facility and oil from the IP Separator
4. Degasser – oil from the LP separator
5. Bulk Oil Treater (BOT) – oil from the degasser

The BOT is typically an electrostatic type. Typical pressures are: HP~1500 psig, IP ~750 psig, LP ~<250 psig, degasser ~<50 psig, and Oil Treater ~20 psig.

Figure 1 - Typical GOM production separation train consisting of HP, IP, LP, Degasser, Oil Treater, and gas compression.

In Figure 1, the HP and IP Separators are gas/liquid separators, and the LP Separator is a gas/oil/water separator. Any of the three can be gas/liquid or gas/oil/water separator designs. The requirements of the facility along with expected production water cuts and operating pressures will dictate the design. For example, in the North Sea and other locations, water may be removed in the HP or LP vessels.

Heating can be added upstream of any of the separators. Typically, inlet heating to the HP Separator is only done if required for separation (reduce viscosity). Inlet heating prior to the pressure drop upstream of the IP and LP Separators may be required to prevent hydrates and facilitate separation.

The gas from separation is typically routed to compression and treating. Figure 1 is based on compression of the HP gas not being required. In some cases, additional compression is required. Depending on the design, liquids from the scrubbers can flow to a lower pressure scrubber or production separator.

The scrubbers designed to protect the compressors from liquid mist are typically vertical vessels with low inlet liquid loads. Downstream of compression in the gas treating facility, there will be inlet separators protecting the gas treating processes. Typically, the inlet separators for gas treating are:

Dehydration

-TEG Unit – inlet scrubber and/or inlet gas coalescer

-Molecular Sieve – inlet gas coalescer

Acid Gas Treating

-Amine Treating – inlet gas coalescer

Mercury Treating

-Dependent on the treater design

The type and design details of the separators are dependent on the requirements of the downstream facilities. The selection can be based on mechanical protection requirements, process efficiencies, or many other application specific requirements, and the design of the separators cannot be done without this context. The location of the vessel in the facility flow scheme, the source of the feed streams, and the routing of the outlet streams (gas, liquid: oil, water, or oil/water) all impact the requirements of the separation and therefore the design of the separator.

For effective design, the following data (Table 1) is essential. The engineer must have a clear understanding of the separation process.

Table 1.  Separator design input data.

Operating Pressure, P	X
Operating Temperature, T	X
		Gas	Liquid	Water
Flowrate	Mass or Volume	X(1)	X	X
Density	At T, P	X	X	X
MW		X
Viscosity	At T, P	X	X	X
Surface Tension	At T, P		X	X
Note 1. If gas rate is given at standard conditions (MMscfd), then compressibility (Z) is also required.

Additional information that may be required include transient flow (e.g. slugs) details, solids, wax, asphaltenes, inert gases, acid gases, foam, emulsion, etc.  Information on the contaminant can significantly impact the design of the separator, from simple equipment size (e.g. high intermittent liquid load may be addressed with additional residence time or larger vessel sizes) to a complete change of technology (e.g. waxes and asphaltenes can plug standard separators and would require a different design altogether).  Note that process information may change as the project progresses and should be revisited for final design.

For more detailed information regarding oil and gas facilities, see references. Further discussions of separator design input data including process design cases can be found in this reference:

Requirements of Separators

A processing facility is needed to provide oil/gas streams that meet pipeline sale specifications as disposal requirements. Some typical values are shown below; however sales contracts, transport, and storage requirements for each facility must be determined.

This level of separation is based on the entire facility including primary separation, oil treating, water treating, and gas treating.

• Oil has less than 1% (by volume) water.
• Gas has less than 5 lbm water/MMscf gas.
• In the Gulf of Mexico (GOM), water separation/treating is typically designed to have less than 20 ppm oil for overboard discharge. Newer facilities are being designed for < 10 ppm oil content. Government requirements are < 29 ppm oil monthly average and < 42 ppm oil daily maximum with no sheening on the ocean surface. Water injection specifications are facility/well design/reservoir specific.

In order to achieve the above specifications, performance requirements must be met for the individual separators of the facility.  However, the same separator performance requirements should not be used for all services. Separators in different applications and locations within a process do not necessarily require the same level of performance.  A better approach is to consider the requirements (liquid-in-gas, oil-in-water, and water-in-oil) of the downstream processing equipment.

For example, a scrubber upstream of a gas glycol dehydration unit requires a high level of liquid removal efficiency. Poor separation can result in excessive foaming in the dehydration unit, resulting in glycol losses and poor performance.  In contrast, a production separator can be designed for higher liquid carryover if the downstream scrubber is properly designed to handle the liquid volume.

A commonly used specification for scrubbers is a liquid volume not exceeding 0.1 USG/MMscf . Applying this specification to a production separator can be impractical or costly.  Furthermore, liquid carryover testing show that even scrubbers may not be able to meet this  0.1 USG/MMscf specification.

Appropriate and sufficient separator performance specifications should therefore be linked to the application of the separator.  Additional discussion of separator requirements can be found here.

Separator types

Separator types

Mist eliminators

Separator design

For design of horizontal and vertical separators, refer to Separator design

Noteworthy papers in OnePetro

Carios, E., Vega, L., Pardo, R., and Ibarra, J. 2013. Experimental Study of a Poor Boy Downhole Gas Separator Under Continuous Gas-Liquid Flow. Presented at the SPE Artificial Lift Conference-Americas, Cartagena, Columbia, 21-22 May 2013. SPE-165033-MS. http://dx.doi.org/10.2118/165033-MS.

Online multimedia

Georgie, Wally J. 2013. Foaming in Separators: Handling and Operation. https://webevents.spe.org/products/foaming-in-separators-handling-and-operation

Heijckers, Cris. 2012. Flow Conditioning Impact on Separations. https://webevents.spe.org/products/flow-conditioning-impact-on-separations

Matar, Omar K. 2013. Defoaming Additives in Horizontal Multiphase Flow—Impact on Flow Regime and Separations. https://webevents.spe.org/products/defoaming-additives-in-horizontal-multiphase-flow-impact-on-flow-regime-and-separations

SPE. 2020. Savvy Separator Educational Video Series. SPE Online Separator Training Course, https://webevents.spe.org/products/savvy-separator-educational-video-series#tab-product_tab_overview.

See also

PEH:Oil_and_Gas_Separators

Separator sizing

Separator types

Emulsion treating methods

Water treating facilities

Inlet

mist eliminators

Coalescers