1. Separator Types Overview
Midstream operations use several types of separation vessels, each optimized for specific fluid compositions and process requirements. Selecting the correct type is the first and most important decision in separator design.
| Separator Type | Phases Separated | Typical GOR (SCF/bbl) | Primary Application |
|---|---|---|---|
| Two-phase separator | Gas + total liquid | 1,000–100,000 | Gas-condensate separation, gas gathering |
| Three-phase separator | Gas + oil + water | 500–50,000 | Wellhead production, oil processing |
| Gas scrubber | Gas + trace liquid | > 50,000 | Compressor suction, process inlet |
| Filter separator | Gas + mist/aerosols | > 100,000 | Custody transfer, fuel gas |
| Slug catcher | Gas + liquid slugs | Variable | Pipeline receipt, slug absorption |
| Cyclone separator | Gas + liquid (compact) | 5,000–200,000 | Offshore, weight-limited applications |
| Free water knockout | Oil + free water | N/A (liquid-liquid) | Water removal before oil treatment |
| Electrostatic treater | Oil + emulsified water | N/A (liquid-liquid) | BS&W reduction to pipeline spec |
First question: How many phases need to be separated? If only gas and total liquid, use a two-phase separator or scrubber. If oil and water must be separated, use a three-phase separator. If only fine mist removal is needed, use a filter separator or coalescer.
2. Selection Flowchart
Follow this decision tree to select the appropriate separator type based on the operating conditions and process requirements:
Decision Step 1: Number of Phases
| Feed Composition | Direction |
|---|---|
| Gas only (mist removal needed) | Go to Filter Separator / Coalescer |
| Gas + single liquid phase | Go to Step 2 (Two-phase selection) |
| Gas + oil + water | Go to Step 3 (Three-phase selection) |
| Oil + water only (no gas) | Go to Free Water Knockout / Treater |
Decision Step 2: Two-Phase Selection (Gas + Liquid)
| Condition | Recommended Type |
|---|---|
| GOR > 50,000 SCF/bbl (gas dominant) | Gas scrubber (vertical) |
| GOR 5,000–50,000 (moderate liquid) | Two-phase separator (vertical or horizontal) |
| GOR 1,000–5,000 (significant liquid) | Two-phase separator (horizontal) |
| Slug flow expected from pipeline | Slug catcher + two-phase separator |
| Custody transfer gas quality needed | Filter separator (downstream of primary separation) |
| Compact/lightweight required (offshore) | Cyclone separator |
Decision Step 3: Three-Phase Selection (Gas + Oil + Water)
| Condition | Recommended Type |
|---|---|
| Water cut < 10%, no emulsion | Three-phase separator (weir type) |
| Water cut 10–50% | Three-phase separator (bucket and weir) |
| Water cut > 50% | Free water knockout + oil treater |
| Tight emulsion, BS&W spec < 1% | Three-phase separator + electrostatic treater |
| High GOR with minor water | Two-phase separator + free water knockout |
Simplicity rule: Always use the simplest separator type that meets the process requirements. A two-phase separator is simpler, cheaper, and easier to operate than a three-phase. If oil-water separation can be deferred to a downstream vessel, use a two-phase separator for initial gas-liquid separation.
3. GOR-Based Selection
The gas-to-oil ratio (GOR) is the primary indicator for separator type selection. It determines whether the separator design is gas-controlled, liquid-controlled, or balanced.
GOR Ranges and Separator Types
| GOR (SCF/bbl) | Classification | Separator Type | Design Priority |
|---|---|---|---|
| < 500 | Oil-dominant | Three-phase separator or FWKO | Liquid retention time |
| 500–3,000 | Liquid-heavy | Three-phase or two-phase horizontal | Liquid retention time |
| 3,000–10,000 | Balanced | Two-phase horizontal | Both gas and liquid capacity |
| 10,000–50,000 | Gas-heavy | Two-phase (vertical or horizontal) | Gas capacity (vessel diameter) |
| 50,000–200,000 | Gas-dominant | Gas scrubber (vertical) | Gas capacity |
| > 200,000 | Dry gas | Filter separator or coalescer | Mist removal efficiency |
GOR Calculation
GOR Calculation:
GOR = Total gas production (SCF/day) / Total liquid production (bbl/day)
For wells producing gas and condensate:
GOR = Gas rate (MSCFD) × 1,000 / Condensate rate (bbl/day)
For wells producing gas, oil, and water:
GOR = Gas rate (MSCFD) × 1,000 / Total liquid rate (bbl/day)
(Use total liquid for initial separator selection;
use oil rate for three-phase sizing)
Changes in GOR Over Time
GOR is not static. Consider how it will change over the facility life:
- Gas wells: GOR typically increases over time as condensate yield decreases. A separator designed for current GOR may become oversized for liquid.
- Oil wells: GOR typically increases as reservoir pressure declines and gas breaks out of solution. A separator may need to handle more gas later in field life.
- Water cut: Water production typically increases over time. Three-phase separator water sections should be sized for late-life water cuts.
- Commingled production: Adding new wells can change the overall GOR significantly. Design for the expected range, not just the initial conditions.
Design for the range: Size the separator for the full range of expected GOR over the facility life. If GOR is expected to increase significantly (common in gas condensate fields), consider a two-phase separator that handles the gas capacity range rather than a three-phase that becomes underutilized as water production declines.
4. Process-Based Selection
Beyond GOR, downstream process requirements and operating conditions influence separator type selection.
Downstream Process Requirements
| Downstream Process | Gas Quality Need | Separator Requirement |
|---|---|---|
| Reciprocating compressor | No free liquid | Scrubber with wire mesh demister |
| Centrifugal compressor | No free liquid, minimal mist | Scrubber or filter separator |
| Amine contactor | < 5 ppmw HC liquid | Coalescing filter separator |
| Glycol contactor | < 5 ppmw HC liquid | Coalescing filter separator |
| Molecular sieve | No free liquid | Coalescing filter separator |
| Custody transfer meter | Pipeline quality | Filter separator |
| Pipeline (sales gas) | Hydrocarbon dewpoint spec | Separator + dewpoint control |
| Oil pipeline | BS&W < 1% | Three-phase separator + treater |
Operating Condition Considerations
| Condition | Impact on Selection | Recommendation |
|---|---|---|
| High pressure (> 1,000 psig) | Wall thickness drives cost | Minimize diameter; vertical preferred |
| Low pressure (< 100 psig) | Large gas volume | Horizontal for gas capacity |
| High temperature (> 250°F) | Material selection | Verify gasket and trim materials |
| Sour gas (H2S) | NACE MR0175 compliance | Material restrictions; HIC-resistant steel |
| CO2 service | Corrosion concerns | CRA materials or corrosion allowance |
| Sand production | Erosion and accumulation | Sand jets; horizontal preferred |
| Paraffin/wax | Deposition and plugging | Heat tracing; easy-clean design |
System design: Separator selection should be part of the overall process design, not an isolated decision. Consider what goes upstream (wellhead, pipeline, slug catcher) and downstream (compressor, treating, metering) of the separator. The separator must deliver the required outlet conditions for all downstream equipment.
5. Special Separator Types
Slug Catchers
Slug catchers are specialized vessels designed to absorb liquid slugs from pipelines. They combine slug volume storage with primary gas-liquid separation:
- Finger-type: Multiple parallel pipes that provide large liquid volume in a compact arrangement. Common for large pipeline systems.
- Vessel-type: Horizontal separator designed for large liquid storage. Simpler piping but larger single vessel.
- Combined: Finger-type slug catcher feeding a conventional separator for final separation.
- Sizing: Based on predicted slug volume (piping simulation), not steady-state liquid rate.
Cyclone Separators (Inline)
Compact cyclonic devices that use centrifugal force for gas-liquid separation. Ideal for space-limited and weight-limited applications:
- 2–5x higher capacity than conventional separators per unit weight
- No moving parts; low maintenance
- Pressure drop: 2–10 psi (higher than conventional)
- Best for moderate to high GOR (5,000–200,000 SCF/bbl)
- Not suitable for three-phase separation or slug handling
Filter Separators
Two-stage separation devices combining filter elements with vane-type mist extractors. Provide the highest gas quality of any separator type:
- Stage 1: Coalescing filter elements (glass fiber or cellulose) capture droplets down to 0.3 microns
- Stage 2: Vane mist extractor removes coalesced droplets
- Gas quality: < 0.1 ppmw liquid at outlet
- Used for custody transfer, fuel gas, and process protection
- Requires element replacement when pressure drop reaches limits
Free Water Knockout (FWKO)
A gravity separator designed specifically to remove free (non-emulsified) water from oil:
- Horizontal vessel, usually operating at low pressure
- Long retention time (10–30 minutes) for gravity settling
- Handles water cuts up to 90%
- Does not break emulsions; handles only free water
- Often used as the first vessel in a production facility
Specialty separators: Slug catchers, cyclone separators, and filter separators are not replacements for conventional separators; they serve specific functions. A complete separation system typically combines a slug catcher (if needed), a primary separator, and a filter separator or scrubber downstream.
6. Separator Staging
Multi-stage separation is used when a single separator cannot achieve all required separation objectives. Each stage operates at a lower pressure, flashing additional gas from the liquid phase.
Stage Pressure Selection
| Stages | Pressure Ratio per Stage | Typical Application |
|---|---|---|
| Single stage | N/A | Low-pressure wells, gathering systems |
| Two stage | 3:1 to 5:1 | Most common for moderate-pressure wells |
| Three stage | 3:1 to 4:1 | High-pressure wells, API recovery optimization |
| Four+ stage | 2:1 to 3:1 | Rarely used; diminishing returns |
Benefits of Multi-Stage Separation
- Increased liquid recovery: Controlled pressure reduction reduces flash gas, recovering 10–25% more stock tank oil/condensate
- Better API gravity: Lighter components stay in liquid phase longer, improving product quality
- Lower BS&W: Multiple stages allow better water separation at each step
- Optimized gas compression: Gas from each stage can be compressed separately, reducing total compression horsepower
Typical Separator Train
Example: Three-Stage Separation System
Stage 1: High-pressure separator (HP)
- Pressure: 1,000 psig
- Type: Three-phase horizontal separator
- Purpose: Primary gas-liquid-water separation
- Gas: To sales gas or compression
Stage 2: Intermediate-pressure separator (IP)
- Pressure: 250 psig
- Type: Two-phase or three-phase horizontal
- Purpose: Flash gas recovery, additional water separation
- Gas: To compression (Stage 2 suction)
Stage 3: Low-pressure separator / stock tank
- Pressure: 25–50 psig
- Type: Two-phase horizontal or atmospheric tank
- Purpose: Final stabilization, vapor recovery
- Gas: To vapor recovery unit (VRU) or flare
Optimization: The stage pressures should be optimized to maximize liquid recovery and minimize total compression horsepower. As a rough guideline, equal pressure ratios between stages (geometric progression) provides a good starting point. Use flash calculation software (e.g., HYSYS, ProMax) for final optimization.
7. Selection Examples
Example 1: Gas Gathering Station
Conditions:
Gas flow: 20 MMSCFD
Condensate: 100 bbl/day
Water: 50 bbl/day
Pressure: 600 psig
GOR: 20,000,000 / 150 = 133,333 SCF/bbl
Selection:
GOR > 50,000 --> Gas scrubber
Pressure = 600 psig --> Vertical preferred
Water present but minor --> Two-phase scrubber + water dump
Result: Vertical gas scrubber with wire mesh demister
Example 2: Oil Production Facility
Conditions:
Gas flow: 5 MMSCFD
Oil: 2,000 bbl/day
Water: 3,000 bbl/day (60% water cut)
Pressure: 200 psig
GOR: 5,000,000 / 5,000 = 1,000 SCF/bbl
Selection:
GOR < 3,000 --> Liquid-heavy, horizontal
Water cut 60% --> Three-phase or FWKO + two-phase
Oil/water separation needed
Result: FWKO (for bulk water) + three-phase production separator
Example 3: Pipeline Receipt Station
Conditions:
Gas flow: 100 MMSCFD
Condensate: Occasional slugs (50–200 bbl)
Water: Trace
Pressure: 900 psig
Slug potential: High (30-mile pipeline)
Selection:
Slug flow expected --> Slug catcher required
Gas dominant --> Scrubber downstream
Custody transfer metering downstream --> Filter separator
Result: Finger-type slug catcher + vertical scrubber + filter separator
Example 4: Compressor Station
Conditions:
Gas flow: 50 MMSCFD
Liquid: Trace condensate from pipeline
Pressure: 400 psig suction
Downstream: Reciprocating compressor
Selection:
Gas dominant, trace liquid --> Scrubber
Compressor protection critical --> High-efficiency demister
Vertical preferred for compressor suction
Result: Vertical suction scrubber with wire mesh demister + HHLL shutdown
Validation: After selecting the separator type, verify the selection by sizing the vessel and confirming it meets all process requirements. If the vessel size becomes impractical (too large, too heavy, or too expensive), reconsider the separator type or staging arrangement.
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