Downhole Gas Separators: How a Gas Anchor Works and Which to Run
Short answer: a downhole gas separator, usually called a gas anchor, is a short assembly at the bottom of the tubing that lets free gas break away from the liquid before it reaches the rod pump. It works by gravity alone: if the liquid flows down to the pump intake more slowly than gas bubbles rise, the bubbles escape up the casing annulus and the pump gets mostly liquid. The best separator is the wellbore itself, with the intake set below the perforations. Where that isn't possible, poor-boy, collar-size and packer-type designs each trade capacity against cost and risk. 127
Why free gas at the intake hurts a rod pump
A rod pump is built to move liquid. Every cubic inch of free gas drawn into the barrel on the upstroke is a cubic inch of liquid the pump doesn't lift, and the gas has to be compressed on the downstroke before the traveling valve opens. The result is incomplete fillage, lost production and, in the worst case, gas lock. 138
Gas interference is one of the most common sources of inefficiency in pumping wells, and production lost to it often far exceeds the loss to leaking pump parts. 210 The standard correction is a bottomhole separator or gas anchor. 8
With the intake above gas-producing perforations, the separator sets pump fillage: the barrel can't hold a larger share of liquid than the separator delivers. 1 For gas taking over the barrel completely, see the gas-locked rod pump guide; for how fillage becomes lost barrels, see pump fillage and pump efficiency.
How does a gas anchor work?
A gas anchor slows the liquid down. Inside the separator, liquid flows downward to the dip tube while gas bubbles slip upward relative to it. Bubbles that rise faster than the liquid falls escape through the ports into the annulus; smaller, slower bubbles get dragged down into the pump. Lower downward velocity means less gas reaches the barrel. 12
A typical separator is a ported outer barrel (often the mud anchor) with a small dip tube inside it that carries fluid up to the pump intake. 16 Most of the gas flows past the ports and up the casing-tubing annulus; liquid and some gas enter the ports and flow down toward the bottom of the dip tube. 1
Each bubble's upward slip velocity depends on its size: bubbles under about 1/16 inch may be dragged into the dip tube, while bubbles over about 1/4 inch can rise out through the ports. 1
The working limit the field uses: field experience and laboratory studies show that when the downward liquid velocity in the separator annulus is at or below about 6 inches per second, most of the large bubbles overcome the drag and mainly liquid reaches the dip tube. Above that, more gas is carried into the pump and fillage drops. 1 The patent literature gives the same figure as the rate bubbles rise through oil or water. 5
Two variables set that velocity: the actual pump displacement rate and the annular area between the outer barrel's inside diameter and the dip tube's outside diameter. 1 A pump rate of 53.4 bbl/day through a cross-section of 1 square inch gives an average velocity of 6 inches per second. 1 That is why separator capacity is mostly a question of annular area, not length.
Flow is intermittent: bubbles are pulled down on the upstroke and rise again on the downstroke. Small bubbles that lose ground each stroke reach the dip tube in the end, whatever its length. 1
Natural separation: set the intake below the perforations
The most efficient gas separator is the wellbore. With the pump intake below the lowest point of fluid entry and an open casing-tubing annulus, liquid falls to the bottom, gas rises up the annulus, and practically all liquid enters the pump. It only works if the well has room below the perforations. 29
One field and laboratory study compares this completion to a vertical surface separator, with gas leaving at the top and liquid collecting at the bottom where the pump draws it. 2 A pump set above the perforations is the same separator connected backwards: bubbles move past the intake and many are drawn in. 2
The usual reasons natural separation isn't possible are too little rathole, liners or gravel packs in the way, or fear of sanding up and sticking the pump. 23 Where the intake can't go below the perforations, the separator has to do the work instead.
Downhole gas separator types: poor-boy, collar-size, packer-type
Separators come in two families: packer-less designs, which sit in the casing annulus and rely on a ported outer barrel and dip tube, and packer-type designs, which seal the casing and force all produced fluid through a dedicated separation path. Capacity rises with annular area, and so do cost and installation risk. 146
| Type | How it works | For | Against |
|---|---|---|---|
| Natural (intake below perforations) | The casing annulus is the separator | The largest separation area there is | Needs rathole; sand, liners or gravel packs can rule it out 23 |
| Poor-boy | Perforated nipple or ported tubing joint with a dip tube inside; the space below is the mud anchor 6 | The usual first fix 3; the mud anchor catches solids 6 | Small annular area means high liquid velocity and low capacity 36 |
| Collar-size | Outer barrel as large as the tubing collar, thin wall 1 | Several times the annular area of a poor-boy on the same tubing 1 | Wall strength must be checked 1; less room left in the casing annulus 26 |
| Packer-type | A packer or cup seal routes all fluid up into the casing annulus, then down to an intake just above the seal 46 | Widely regarded as the most efficient downhole separator 34 | Packer restricts tubing movement and needs a set-and-release procedure 5; solids can settle on the packer and stick it 6 |
Poor-boy and collar-size separators
The poor-boy is an outer joint of tubing with openings near the top and a closed bottom, and a dip tube inside it. 6 Its limit is geometry: the casing caps the outer diameter and the wall eats into the annular area, so liquid velocities run high. 6 A collar-size separator wins area back with a larger, thin-walled barrel, as long as the walls keep the strength they need. 1 One published table, at the 6 in/s limit: 1
| Separator | Annular area | Efficient capacity |
|---|---|---|
| 2-3/8 in. poor-boy | 1.76 sq in | 94 bbl/day |
| 2-3/8 in. collar-size | 4.57 sq in | 244 bbl/day |
| 2-7/8 in. poor-boy | 2.51 sq in | 134 bbl/day |
| 2-7/8 in. collar-size | 7.45 sq in | 398 bbl/day |
A bigger barrel leaves less room in the casing annulus, though, and one study notes that the largest mud anchor that fits may not separate best. 2
Packer-type separators
A packer or cup seal above the perforations sends all produced fluid into the casing annulus, where the large area slows the liquid before it turns down to the intake. 46 The costs are mechanical: the packer constricts tubing movement and takes a specialised procedure to set and pull, 5 and sand can settle on it and stick it. 6 Standard tools are made in lengths of no more than 24 ft, which limits how much gas the separation chamber can handle. 3 In small casing, such as the 5.5-inch strings common in horizontal wells, the annulus is tight to begin with. 4
Setting depth relative to the perforations
Set the separator ports below the bottom perforation when the well allows it; a few feet is enough. With the ports at or above the perforations, which is the most common field position, performance depends on both the liquid velocity inside the separator and the gas velocity in the annulus around it. 2
- Below the perforations. A few feet below the bottom perforation is enough; very little gas then enters as long as the downward liquid velocity stays below the bubble rise velocity. 2
- Opposite or above the perforations. As the gas velocity in the casing annulus rises, the liquid velocity inside the separator has to fall to keep separation efficient. 2 One design guideline is to keep the casing-annulus gas velocity below about 10 ft/s, because faster gas stops liquid entering the separator ports. 1
- Dip tube length. Longer is not better. A 5.5-ft dip tube gave efficient separation in the tests, and the guidance is for it to reach about 4–5 ft below the inlet ports. 12 A long, narrow dip tube adds pressure drop, and that releases gas from the oil inside the tube. 124
- Ports. Extra rows of ports didn't help in testing unless plugging is expected, 12 and small open areas accelerate the fluid and drag bubbles in. 4
How separation problems show on cards and fluid-level shots
A failing separator shows as low fillage on the dynamometer card while a fluid-level shot finds plenty of liquid above the pump. A pumped-off well shows the same low fillage with the fluid level down at the intake. The two readings together tell you whether to fix separation or pump rate. 289
- G1 Gas interference
The bottom-right corner rounds off: gas compresses until the traveling valve opens.
- G2 Gas lock
So much gas the traveling valve never opens: the card collapses into a thin loop.
- G3 Fluid pound
Full load held into the downstroke, then a sharp drop where the plunger hits liquid.
- The card. Gas interference shows as a gradual load release on the downstroke, because the traveling valve opens as the gas compresses instead of all at once. 8 The dynamometer card guide shows the shape against fluid pound and gas lock.
- The fluid level. The fluid level gives pump submergence, the height of liquid over the intake. 9 High submergence with low fillage means gas is getting past the separator. Low submergence means the well is pumped off and the fix is rate, not hardware; see fluid pound.
- The restart test. One published case had liquid above the pump and fillage around 30% with a poor-boy separator. After a 10-minute shutdown, even the first card after restart showed an incompletely filled pump, which pointed at the separator, not pump-off. 2
- Casing pressure. Fluid-level records with a casing pressure buildup measurement estimate how much of the annulus is gas. 1
Troubleshooting checklist
Before you change separator hardware, confirm the problem is gas and not inflow, then work from the intake outward: can the pump go below the perforations, is the separator big enough for the rate, and is anything else restricting flow into the pump? 12
- Shoot a fluid level and pull a card together. Low fillage with high submergence is a separation problem. Low fillage with low submergence is pump-off. 29
- Check the setting depth. If there is rathole and nothing rules it out, lower the intake below the perforations. 23
- Compare pump rate to separator capacity. Check the downward liquid velocity, from pump displacement and annular area, against the 6 in/s guideline. 1
- Look for restrictions. A small strainer nipple, a screen, an over-long narrow dip tube, or paraffin and scale at the intake cut fillage on their own. 1
- Check casing-annulus gas velocity. Very high annular gas flow keeps liquid out of the separator ports. 12
- Consider the fluid. In one field case, foaming oil released bubbles so small that the 6 in/s rule didn't hold and a new separator did no better than the old one. Gas separates from water more predictably than from oil. 2
- Only then upsize or change type. Poor-boy to collar-size gains annular area; packer-type gains more, with the packer's mechanical risks. 136
Where SRABS fits
A separator works only when pump rate stays inside its capacity, and that takes fillage and fluid level read together, per well. That pairing is what SRABS is built around. SRABS Echo is "an automated acoustic edge device" that reads fluid level, fully remote, and "Brain reads every dynamometer card, motor current and Echo fluid level, and checks them against the physics of your rod string." For gas-locked wells, the solutions page puts it in one line: "Echo sees the gas and the fluid level, and Brain adjusts speed and idle time before the pump starts to pound." See the platform, how it works and the glossary entry for gas separators.
To estimate what fewer failures and pulls would mean on your own fleet, run the ROI calculator. Its default 100-well scenario is modelled, not a field result.
The bottom line
A gas anchor is a velocity problem in a small pipe. Set the intake below the perforations if the well allows it; that is the best separator there is. If not, size the separator's annular area for the pump rate, keep the dip tube short, and pick packer-type only when its capacity is worth the mechanical risk. Confirm every change with a card and a fluid level taken together.
If gassy wells keep running at low fillage with fluid over the pump, read the cards against a fluid level, then test closed-loop control on one well.
FAQ
How does a gas anchor work?
It slows the liquid down so gas can escape. Bubbles that rise faster than the liquid flows down to the dip tube leave through the ports into the casing annulus, and the pump draws mostly liquid.
What is the difference between a poor-boy gas anchor and a packer-type separator?
A poor-boy is a ported tubing joint with a dip tube inside and no seal: the usual first fix, but low capacity. A packer-type separator seals the casing and routes all fluid through the casing annulus, so it separates more gas, but the packer restricts tubing movement and can stick in sand.
How fast do gas bubbles rise in a well?
The common design figure is about 6 inches per second. Separators are sized so the downward liquid velocity stays at or below that. It is a guideline, not a law: small bubbles rise more slowly, and foamy oil can separate far worse than the rule predicts.
Where should a gas anchor be set relative to the perforations?
Below the bottom perforation if the well allows it. Laboratory work found that a few feet below is enough. With the ports above the perforations, which is common, separation depends on both the liquid velocity in the separator and the gas velocity in the annulus.
Why does my rod pump have gas problems with fluid above the pump?
Fluid above the pump with low fillage on the card means gas is reaching the barrel: the separator is too small for the pump rate, set in the wrong place, restricted, or fighting foamy fluid. If the fluid level is down at the intake instead, the well is pumped off.
Sources
- McCoy, J. N., Skinner, K., Rowlan, O. L., Marshall, K., Podio, A. L., "Down-Hole Gas Separator Performance Simulation Software," Southwestern Petroleum Short Course, 2014. https://www.swpshortcourse.org/paper/2014016-downhole-gas-separator-performance-simulation-software
- McCoy, J., Patterson, J., Podio, A. L., Lisigurski, O., "Downhole Gas Separators: A Laboratory and Field Study," Southwestern Petroleum Short Course, 2005. https://www.swpshortcourse.org/sites/default/files/papers/2005015.pdf
- Gonzalez, G., Vyas, S., Guanacas, L., Johnson, N., "Innovative Packer Type Gas Separator: Operating Principles and Design Criteria," Southwestern Petroleum Short Course, 2019. https://www.swpshortcourse.org/paper/2019020-innovative-packer-type-gas-separator-operating-principles-and-design-criteria
- Gonzalez, G., Guanacas, L., Portilla, C., "A Revolutionary Packer Type Gas Separator That Involves G-Force to Exceed Traditional Gas Separation Efficiency in Oil and Gas Wells," Southwestern Petroleum Short Course, 2022. https://www.swpshortcourse.org/paper/2022009-revolutionary-packer-type-gas-separator-involves-g-force-exceed-traditional-gas
- US Patent 9,022,106, "Downhole diverter gas separator" (J. N. McCoy, 2015). https://patents.google.com/patent/US9022106
- US Patent 10,119,383, "Down-hole gas and solids separation system and method." https://patents.google.com/patent/US10119383
- SLB Energy Glossary, "gas anchor." https://glossary.slb.com/en/terms/g/gas_anchor
- SLB Energy Glossary, "gas interference." https://glossary.slb.com/en/terms/g/gas_interference
- Acoustic Fluid Level Measurements, Chapter 8, "Applications of Fluid Level Measurements to Pumping Wells," Petroleum Extension Service (PETEX). https://utw10286.utweb.utexas.edu/images/flippingbooks/acoustic_fluid_measure/files/basic-html/page15.html
- Robles, J., Podio, A. L., "Effects of Free Gas and Downhole Separation Efficiency on the Volumetric Efficiency of Sucker Rod Pumps and Progressing Cavity Pumps," Southwestern Petroleum Short Course, 1999. https://www.swpshortcourse.org/paper/effects-free-gas-and-downhole-separation-efficiency-volumetric-efficiency-sucker-rod-pumps