Oil & Gas Separators
What Is an Oil & Gas Separator
An oil and gas separator is a pressure vessel used at or near the wellhead to separate the multiphase wellstream into its constituent phases: gas, crude oil (or condensate), and produced water. The wellstream arriving from the reservoir is a turbulent mixture of hydrocarbons in vapor and liquid form, free water, dissolved gases, and often entrained solids such as sand.
Separation is one of the first and most critical unit operations in surface production facilities. Without effective phase separation, downstream equipment such as compressors, pumps, pipelines, and treating systems cannot operate efficiently or safely. Separators are found in virtually every oil and gas production facility worldwide, from simple wellhead installations in onshore fields to complex topsides modules on floating production storage and offloading (FPSO) vessels.
The fundamental principle behind separation is straightforward: given sufficient time and a quiescent environment, immiscible fluids of different densities will stratify under the force of gravity. Gas, being the lightest phase, rises to the top; oil occupies the middle; and water, the densest liquid, settles to the bottom. The separator vessel provides the residence time and calm flow conditions needed for this natural stratification to occur.
Modern separators incorporate a range of internal devices to accelerate and enhance the separation process. These include inlet diverters, coalescing plates, weir plates, vortex breakers, and mist extractors. The design of a separator must account for the specific fluid properties, flow rates, operating pressure and temperature, and the degree of separation required by the downstream process.
3-Phase Horizontal Separator Cross-Section
Separation Principles
Gravity Separation
The most fundamental mechanism in oil and gas separation is gravity settling. When the wellstream enters the separator, the sudden reduction in velocity and the absence of turbulence allow the different phases to separate based on their density differences. Gas, with a density typically in the range of 1 to 10 kg/m3 at operating conditions, rises rapidly to the top. Crude oil (750 to 900 kg/m3) occupies the middle layer, and produced water (1,000 to 1,150 kg/m3 depending on salinity) sinks to the bottom.
The settling velocity of a liquid droplet in a gas phase (or a water droplet in an oil phase) can be estimated using Stokes’ Law:
Vt = (g x d2 x (rho_l - rho_g)) / (18 x mu)
Where Vt is the terminal settling velocity (m/s), g is gravitational acceleration (9.81 m/s2), d is droplet diameter (m), rho_l is liquid density (kg/m3), rho_g is gas density (kg/m3), and mu is viscosity of the continuous phase (Pa.s).
Stokes’ Law applies to the laminar regime (Reynolds number < 1) and shows that separation efficiency depends heavily on droplet size (proportional to d2), density difference between phases, and the viscosity of the continuous phase. This is why heavy oils (high viscosity) are much harder to separate than light crudes.
Retention Time
Retention time (also called residence time) is the average time a given volume of liquid spends inside the separator. It is a critical design parameter because gravity separation is a time-dependent process. The longer the liquid remains in the vessel, the more complete the separation.
Typical retention times by service:
| Service | Retention Time |
|---|---|
| Gas-oil separation, light crudes | 1 to 3 minutes |
| Gas-oil separation, heavy or foaming crudes | 5 to 20 minutes |
| Oil-water separation | 3 to 10 minutes (varies with emulsion stability and chemical treatment) |
| 3-phase separators, total liquid | 5 to 10 minutes |
Retention time is calculated as:
t = V_liquid / Q_liquid
Where V_liquid is the volume of the liquid section of the separator and Q_liquid is the liquid volumetric flow rate at operating conditions.
Coalescence
Small droplets of one liquid phase dispersed in another (for example, tiny water droplets in oil, forming a water-in-oil emulsion) may be too small to settle by gravity alone within reasonable retention times. Coalescence is the process by which small droplets merge to form larger ones, which then settle more rapidly.
Several factors promote coalescence. Coalescing plates — parallel plates or corrugated packs — force droplets into close contact, accelerating the merging process. Low velocities reduce turbulence and allow droplets to merge naturally. Chemical demulsifiers (surface-active agents injected upstream) break the interfacial film around droplets. Elevated temperatures reduce oil viscosity and further weaken that film. In practice, most production facilities rely on a combination of these mechanisms working together.
Centrifugal Force
Some separator designs use centrifugal force to enhance separation, particularly for gas-liquid separation. When the inlet stream enters tangentially or passes through a cyclonic device, the rotational motion generates centrifugal forces many times greater than gravity. Heavier liquid droplets are thrown outward to the vessel wall, where they coalesce and drain by gravity, while the gas continues through the center.
Centrifugal devices are especially effective for removing fine liquid mist from gas streams, handling high gas-to-oil ratio (GOR) streams, and building compact separator packages where space is limited — a common constraint on offshore platforms.
Types of Separators
2-Phase Separators (Gas-Liquid)
A 2-phase separator separates the wellstream into a gas phase and a combined liquid phase (oil plus water mixed together). The liquids are not separated from each other within the vessel; oil-water separation occurs downstream in a separate vessel such as a free-water knock-out (FWKO) or a heater treater.
2-phase separators are used when the wellstream contains little or no free water, when downstream equipment handles oil-water separation more effectively, or when space and weight constraints limit the number of vessels on compact offshore facilities.
Common configurations of 2-phase separators include:
Scrubbers (Gas Scrubbers) are vertical vessels installed upstream of compressors or gas dehydration units to remove liquid carryover from gas streams. They typically have short liquid retention times (30 seconds to 2 minutes) because the liquid volume is small relative to the gas volume.
Knock-Out Drums (KO Drums) are similar to scrubbers but often larger, sized to handle surge or slug conditions. They are frequently found in flare systems to prevent liquid carryover to the flare tip, and at pipeline receipt points.
Inlet Separators serve as the first separator in a gas processing plant, removing bulk liquids from the incoming pipeline gas.
3-Phase Separators (Gas-Oil-Water)
The 3-phase separator is the most common vessel in oil and gas production facilities. It separates the wellstream into three distinct phases: gas, oil, and water. This requires two interfaces to be maintained: the gas-oil interface and the oil-water interface.
A weir plate divides the water section from the oil collection section; oil flows over the weir while water is retained upstream. Two level controllers manage the process — one for the oil-water interface (controlling the water dump valve) and one for the oil level (controlling the oil dump valve). A pressure controller regulates the gas outlet valve to maintain operating pressure. The total liquid retention time is typically 5 to 10 minutes, providing adequate time for oil-water separation.
3-phase separators are the standard first-stage separation vessel on wellhead platforms, production facilities, and central processing facilities (CPFs). They handle the bulk separation of the wellstream, reducing the load on downstream treating equipment.
Vertical vs. Horizontal Separators
The choice between a vertical and horizontal separator depends on the flow rates, gas-to-oil ratio, space constraints, and specific process requirements.
Horizontal separators provide a larger gas-liquid interface area for a given vessel volume, promoting faster gas breakout. They handle high liquid flow rates and 3-phase separation well, offer a longer and calmer flow path that suits foaming crudes, and accommodate slug flow more effectively because of their larger liquid surge volume. Their lower profile simplifies transport and installation. For these reasons, horizontal orientation is the most common configuration for production separators.
Vertical separators suit applications where the gas-to-oil ratio is very high (predominantly gas stream), the liquid volume is small and scrubbing is the primary function, or the available footprint is limited while vertical clearance exists. Vertical vessels also handle sand and solids production well, since solids settle directly to the bottom sump. Most scrubbers and knock-out drums use vertical orientation. The small footprint works well on platforms where deck space is at a premium, with the liquid collecting in the bottom section and gas flowing upward through the mist extractor at the top.
Test Separators
Test separators are dedicated vessels used to measure the flow rates of oil, gas, and water produced by individual wells during well testing. Unlike production separators that commingle production from multiple wells, a test separator receives flow from one well at a time.
| Feature | Details |
|---|---|
| Metering instrumentation | High-accuracy flow meters on each outlet (gas, oil, water) for individual phase rate measurement |
| Sample ports | Allow collection of fluid samples for laboratory analysis (PVT, BS&W, salinity) |
| Sizing | Must handle the full range of well rates, from low-rate marginal wells to high-rate flush production |
| Portability | Often trailer- or skid-mounted for onshore operations, allowing transport between well locations |
Test separators are required for reservoir surveillance, production allocation, and well performance monitoring. They are used during initial well testing (drill stem tests, extended well tests) and periodically throughout field life to update individual well production profiles.
Slug Catchers
A slug catcher is a specialized vessel or piping arrangement that receives and absorbs liquid slugs traveling through pipelines. Slugs are large volumes of liquid that form in multiphase flowlines due to terrain effects, pigging operations, flow rate changes, or pipeline shutdown and restart. A single slug can contain hundreds of barrels of liquid arriving at the processing facility in a short burst.
Without a slug catcher, these liquid surges would overwhelm the production separator, causing liquid carryover into the gas system (compressor damage, flare liquid carryover) and process upsets throughout the facility.
There are three main types of slug catchers:
Finger-Type Slug Catchers consist of multiple parallel large-diameter pipes (“fingers”) connected to a common inlet header at one end and a common liquid collection header at the other. The fingers provide the surge volume needed to absorb the slug. Gas separates at the top of each finger and exits through a gas header. This is the most common type for large onshore pipeline receiving facilities.
Vessel-Type Slug Catchers are conventional horizontal pressure vessels, typically oversized to provide the required slug volume. They are simpler than finger type but become impractical for very large slug volumes due to vessel wall thickness limitations.
Pipeline Segment Slug Catchers use a section of large-diameter pipe as the slug-receiving volume, with a liquid trap at the low point. This approach is economical for moderate slug volumes.
Vertical Separator Schematic
Slug Catcher (Finger Type) Plan View
Separator Internals
The performance of a separator depends not only on its overall geometry and size, but critically on the internal devices that promote efficient phase separation. These internals accelerate the natural settling process and prevent re-entrainment of separated phases.
Inlet Devices
The inlet device is the first internal component encountered by the wellstream as it enters the separator. Its purpose is to absorb the momentum of the incoming fluid, break up slugs, and initiate the separation process by distributing the flow evenly across the vessel cross-section.
Diverter plates are flat or curved plates positioned directly opposite the inlet nozzle. The incoming stream impacts the plate, which dissipates kinetic energy and causes an initial gross separation of gas and liquid. They are simple, durable, and widely used.
Half-pipe inlets are sections of pipe cut in half along their length, mounted horizontally inside the vessel at the inlet. The wellstream enters the half-pipe and spreads along its length, distributing flow uniformly and reducing localized turbulence. They are commonly used in horizontal separators.
Cyclonic inlet devices (such as the Schoepentoeter or similar proprietary designs) impart a spinning motion to the inlet stream. Centrifugal force separates the bulk liquid from the gas phase before the fluid enters the main separation section. These devices are highly effective but more complex and expensive than flat diverters.
Vane-type distributors use a series of angled vanes that spread the incoming flow across the vessel cross-section. They provide good flow distribution and some degassing but are more susceptible to fouling than diverter plates.
Mist Extractors (Demisting Devices)
Mist extractors are installed near the gas outlet to remove fine liquid droplets (mist) that are entrained in the gas stream and too small to settle by gravity within the vessel. Without a mist extractor, liquid carryover into the gas system can cause corrosion, hydrate formation, fouling of downstream equipment, and off-specification gas.
| Demister Type | Construction | Droplet Removal | Pressure Drop | Notes |
|---|---|---|---|---|
| Wire mesh (knitted mesh pad) | 100-150 mm thick pad of knitted stainless steel or alloy wire | Down to ~10 micrometers | 0.25 to 1.0 kPa | Most common type; droplets impact wire surfaces, coalesce, and drain back by gravity |
| Vane-type (chevron packs) | Closely spaced corrugated or chevron-shaped plates | Moderate to fine | Moderate | Handles higher gas velocities than wire mesh; less susceptible to plugging by solids or viscous liquids |
| Cyclonic (multi-cyclone decks) | Banks of small-diameter cyclone tubes on a deck plate | Finest droplets | Lowest | Highest gas capacity per unit area; most expensive option |
Weir Plates and Baffles
Weir plates are vertical barriers inside horizontal 3-phase separators that maintain the oil-water interface at a specific location and direct oil flow to the oil collection section. The height of the weir determines the position of the oil-water interface.
Perforated baffles are sometimes installed along the length of the separator to calm the flow and prevent wave action and re-mixing of separated phases. They are particularly useful in separators subject to vessel motion (e.g., on FPSOs and semi-submersibles).
Plate packs (coalescing plates) are stacks of parallel inclined plates installed in the liquid section to promote coalescence and reduce retention time. Water droplets in oil settle onto the plate surfaces, coalesce, and slide down the plates to the water layer. Plate packs can reduce the required separator size significantly but are susceptible to fouling with waxy or asphaltic crudes.
Sand Handling
Wells that produce sand (unconsolidated formations) require separators with sand handling provisions to prevent sand accumulation, which can reduce effective vessel volume, block internals, and cause erosion.
Sand jets are high-pressure water nozzles installed in the bottom of the vessel that fluidize accumulated sand and direct it toward the sand outlet. Sand pans are collection troughs at the bottom of horizontal separators that concentrate sand for periodic or continuous removal. Sand probes (acoustic, nuclear, or capacitance type) monitor sand accumulation levels and trigger jetting or draining operations.
In severe sand production scenarios, a desander (hydrocyclone) may be installed upstream of the separator to remove sand before it enters the vessel.
Separator Type Comparison
| Feature | 2-Phase Horizontal | 3-Phase Horizontal | Vertical | Test Separator | Slug Catcher (Finger) |
|---|---|---|---|---|---|
| Phases Separated | Gas + Liquid | Gas + Oil + Water | Gas + Liquid | Gas + Oil + Water | Gas + Liquid (bulk) |
| Orientation | Horizontal | Horizontal | Vertical | Horizontal or Vertical | Horizontal pipes |
| Gas Capacity | High | High | Moderate | Moderate | Very High |
| Liquid Capacity | Moderate to High | High | Low to Moderate | Low to Moderate | Very High |
| Footprint | Large | Large | Small | Moderate | Very Large |
| Slug Handling | Good | Good | Poor | Moderate | Excellent |
| Sand Handling | Moderate | Moderate | Good | Moderate | Poor |
| Typical Application | Gas scrubbing, inlet separation | Production separation | Scrubbers, KO drums | Well testing, metering | Pipeline receiving |
| Cost (relative) | Moderate | Moderate-High | Low-Moderate | Moderate | High |
Standards and Specifications
Oil and gas separators are designed, fabricated, inspected, and tested in accordance with a range of international codes and standards:
| Standard | Description |
|---|---|
| ASME Section VIII, Div. 1 & 2 | Pressure vessel design, fabrication, and inspection. The primary code for separator vessel shells. Division 2 allows higher allowable stresses with more rigorous analysis. |
| API 12J | Specification for Oil and Gas Separators. Covers functional design, sizing, and selection of production separators. |
| API 12F | Specification for Shop Welded Tanks for Storage of Production Liquids. Applicable to atmospheric and low-pressure separator tanks. |
| API 2000 | Venting Atmospheric and Low-Pressure Storage Tanks. Relevant for atmospheric separators and tanks. |
| GPSA Engineering Data Book | detailed design guidelines for gas processing equipment, including separator sizing methods and design criteria. |
| NACE MR0175 / ISO 15156 | Materials for sour (H2S-containing) service. Mandatory when the wellstream contains hydrogen sulfide above threshold levels. |
| NFPA 30 | Flammable and Combustible Liquids Code. Governs the storage and handling of flammable liquids in separator systems. |
| PED 2014/68/EU | Pressure Equipment Directive (European Union). Required for separators installed in EU member states. |
| EN 13445 | European standard for unfired pressure vessels. An alternative to ASME VIII for European projects. |
| API 14C | Recommended Practice for Analysis, Design, Installation, and Testing of Safety Systems for Offshore Production Facilities. Covers safety system requirements for separators. |
Materials Selection
Carbon Steel (Most Common)
The majority of oil and gas separators are fabricated from carbon steel to ASME SA-516 Grade 70 (or equivalent SA-285, SA-455). Carbon steel provides an excellent balance of strength, weldability, availability, and cost. Typical wall thicknesses range from 12 mm to over 100 mm depending on the design pressure and vessel diameter.
For moderately corrosive service (CO2 corrosion, mild produced water), a corrosion allowance of 3 to 6 mm is added to the calculated minimum wall thickness.
Stainless Steel Internals
While the vessel shell is usually carbon steel, many internal components are fabricated from stainless steel or high-alloy materials to resist the more aggressive corrosive conditions at the fluid contact surfaces:
| Internal Component | Typical Materials |
|---|---|
| Wire mesh demisters | 304 or 316 SS; Alloy 825 or Alloy 625 for sour service |
| Weir plates and baffles | 304L or 316L SS |
| Inlet diverters | Wear-resistant SS or hardfaced carbon steel (erosion resistance for sand-laden fluids) |
| Nozzle internals (vortex breakers, distributors) | 316L SS |
Clad and Lined Vessels for Sour Service
When the wellstream contains significant concentrations of hydrogen sulfide (H2S) or carbon dioxide (CO2), the internal surfaces of the separator must be protected against sulfide stress cracking (SSC), hydrogen-induced cracking (HIC), and general corrosion.
Three principal options exist. Clad plate uses a carbon steel base with a metallurgically bonded layer of corrosion-resistant alloy (CRA) such as 316L stainless steel, Alloy 625, or Alloy 825, at a typical clad thickness of 3 mm. Weld overlay applies a CRA weld deposit to the internal surfaces of the carbon steel vessel, most commonly at nozzle bores and manway seating surfaces. Solid CRA construction is reserved for small vessels or extremely corrosive conditions, since it is cost-prohibitive for large separators.
All materials in sour service must comply with NACE MR0175 / ISO 15156, which specifies maximum hardness limits, acceptable alloy compositions, and heat treatment requirements to prevent sulfide stress cracking.
Internal Coatings
For less severe corrosive environments where CRA cladding is not justified, internal coatings provide a cost-effective corrosion barrier.
| Coating Type | Description | Typical Thickness / Notes |
|---|---|---|
| Epoxy coatings | High-build epoxy or novolac epoxy systems applied to internal surfaces | 300 to 500 micrometers DFT |
| Glass flake coatings | Epoxy or vinyl ester coatings reinforced with glass flakes | Excellent chemical resistance and low permeability |
| Rubber lining | Natural or synthetic rubber bonded to the vessel interior | Good for abrasive and acidic conditions; limited to below ~80 degrees C |
Internal coatings require careful surface preparation (Sa 2.5 blast finish), controlled application conditions, and holiday (pinhole) testing before the vessel enters service.
Design Considerations
Gas Capacity (Souders-Brown Equation)
The gas handling capacity of a separator is determined by the maximum allowable gas velocity through the vessel. If the gas velocity is too high, liquid droplets are carried upward by the gas flow rather than settling by gravity, resulting in liquid carryover.
The critical gas velocity is estimated using the Souders-Brown equation:
V_max = K x sqrt((rho_l - rho_g) / rho_g)
Where V_max is the maximum allowable gas velocity (m/s), K is an empirical constant (typically 0.035 to 0.107 m/s, depending on the mist extractor type and separator configuration), rho_l is liquid density (kg/m3), and rho_g is gas density at operating conditions (kg/m3).
Typical K-factor values:
| Configuration | K-Factor (m/s) |
|---|---|
| Vertical separator without demister | 0.035 to 0.05 |
| Horizontal separator without demister | 0.04 to 0.06 |
| With wire mesh demister | 0.085 to 0.107 |
| With vane-type demister | 0.10 to 0.12 |
Liquid Retention Time
As discussed earlier, adequate liquid retention time is required for effective gravity separation of oil and water. The required retention time depends on the crude oil properties:
| Crude Type | API Gravity | Retention Time (minutes) |
|---|---|---|
| Light crude | > 35 API | 1 - 3 |
| Medium crude | 25 - 35 API | 3 - 5 |
| Heavy crude | 15 - 25 API | 5 - 10 |
| Foaming crude | Any | 10 - 20+ |
| High water cut | Any | 5 - 10 |
The liquid section volume is calculated as:
V_liquid = Q_liquid x t_retention
Where Q_liquid is the total liquid flow rate (m3/min) and t_retention is the required retention time (minutes).
Operating Pressure and Temperature
The separator operating pressure is set by the stage separation optimization. Multi-stage separation (2 to 4 stages at progressively lower pressures) maximizes liquid recovery from the wellstream. Typical first-stage separator pressures range from 20 to 100 bar (300 to 1,500 psi), while final-stage (atmospheric) separators operate near ambient pressure.
Operating temperature affects fluid viscosity (higher temperature reduces oil viscosity, improving separation efficiency), gas solubility (higher temperature releases more dissolved gas from the oil), hydrate formation (separators must operate above the hydrate formation temperature or include hydrate inhibition), and wax deposition (low temperatures can cause wax precipitation, fouling internals and reducing performance).
Turndown Ratio
The turndown ratio describes the range of flow rates over which the separator can operate effectively. A typical turndown ratio is 3:1 to 5:1, meaning the separator can handle flow rates from 100% down to 33% or 20% of design capacity while still achieving adequate separation.
Turndown matters because well production rates decline over the field life. A separator that cannot turn down effectively at lower rates will suffer from liquid re-entrainment (gas velocity still too high relative to the reduced liquid level) or insufficient gas velocity to sustain demister performance.
Foaming Tendency
Certain crude oils foam excessively when gas breaks out of solution, creating a stable froth layer that is neither gas nor liquid. Foam dramatically increases the required separator volume because the effective gas-liquid interface is obscured, the foam occupies volume that would otherwise be available for liquid settling, and conventional level instruments may not function correctly in the froth zone.
Foaming is addressed by increasing separator size (retention time) by a factor of 2 to 4 compared to non-foaming crudes, installing foam breaker internals (inclined plates or cyclonic devices that mechanically collapse the foam), injecting antifoam agents (silicone-based defoamers) upstream of the separator, and avoiding excessive agitation at the inlet by using smooth inlet devices rather than aggressive diverters.
Applications
Wellhead and Production Separators
The most common application is the first-stage production separator located at or near the wellhead. This vessel receives the raw wellstream from one or more wells and performs the initial bulk separation. In onshore operations, this is typically a horizontal 3-phase separator mounted on a concrete foundation. Offshore, it occupies a major portion of the platform topsides or FPSO deck.
Multi-well production facilities often use a production manifold to commingle flow from several wells before routing it to the production separator, along with a test separator that can isolate individual wells for rate measurement.
Gas Processing Plants
Gas processing plants employ separators at multiple points in the process. The inlet separator removes bulk liquids from incoming pipeline gas. Interstage scrubbers, installed between compressor stages, remove condensed liquids that form during compression. A cold separator downstream of the gas chiller or J-T valve separates condensed natural gas liquids (NGLs) from the sales gas. The reflux drum in fractionation columns acts as a 2-phase separator for the overhead condenser products.
FPSO Topsides
Floating Production Storage and Offloading vessels present unique challenges for separator design. Vessel motion (roll, pitch, and heave) disturbs the liquid surface and causes sloshing, requiring anti-sloshing baffles and reliable level control strategies. Weight and space constraints favor compact separators, often with cyclonic internals, to minimize topsides weight. Equipment downtime on an FPSO has severe production and economic consequences, so high reliability is essential. FPSOs frequently process 100,000 to 200,000+ barrels per day, requiring very large separator vessels.
Pipeline Receiving Facilities
At the terminus of multiphase pipelines, slug catchers receive the pipeline flow and absorb liquid slugs before routing gas and liquid to the processing facilities. These are particularly important for long-distance subsea pipelines and gathering systems in hilly terrain, where terrain-induced slugging can produce very large liquid volumes.
The slug catcher feeds into downstream production separators, which perform the final gas-oil-water separation under controlled conditions.
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