Petroleum engineering, from well to export.

Liquid loading is the inability of a producing gas well to remove its co-produced liquids from the wellbore. Liquid flowing as droplets or film builds up at the well bottom, imposing back-pressure at the sand face until the well can no longer sustain stable production.

We monitor production curves for each well on a regular basis. Liquid loading is indicated when the curve for a normally declining well turns erratic and the production rate drops. From there we compute the critical gas velocity, the flow rate below which liquid can no longer be lifted in the tubing, and plot it against flowing tubing pressure across different tubing diameters.

Well cycling regulates intermittent gas production through automated on/off control of the wellhead choke. When a well shows signs of liquid loading, we address it by temporarily stopping and restarting production. During the shut-in period, pressure builds around the wellbore and some liquid is forced back into the formation, reducing the liquid level before the well returns to production.

Cycling works effectively in wells with high productivity index and a constant liquid rate. It is a short-term option, useful for prolonging a well rather than solving the underlying problem.

A smaller tubing size can produce a liquid-loaded well, since it needs a lower gas rate to operate above the critical flow rate. We use a candidate selection process before recommending one:

• Good remaining reserves
• Conventional workover is not viable
• No easy water shut-off opportunities
• No aquifer influx, and a low water rate
• Existing tubing diameter above 3.5 inches

With very small tubing, even a small amount of liquid can create high back-pressure and reduce production rates, and access to the wellbore becomes limited. Candidate selection matters as much as the string itself.

Wellhead compression lowers the flowing wellhead pressure, which reduces bottomhole flowing pressure and increases flow rates. Reciprocating, screw-type and other compressor designs are available depending on well conditions.

Flowing wellhead pressure can be lowered below 50 psi depending on productivity index and fluid production rates. In wells with aquifer support, water production increases, which calls for separation equipment at the wellhead.

Microstring technology has proved successful for wells suffering from liquid loading. A surfactant is injected near the perforations to help lift produced fluids, at a lower cost than a velocity string, a progressive cavity pump or a rod pump. It achieves higher rates than cycling and can work in wells that do not respond to cycling at all.

A small tubing string, around a quarter inch, hangs from the top of the wellhead through the master valves and can be sheared by closing the valves in an emergency. A check valve and back-pressure valve keep well fluids out and support the chemical’s hydrostatic pressure, and a stand-alone solar-powered pump with a simple timer controls the injection rate. The hardware has a long usable life and relocating it to another well is low cost.

In oil wells, the same approach works with a condensate foamer in place of soap. Well selection still matters: tubing size, reservoir gas and a water cut under 10 percent, confirmed by bench testing the chemical foamer against an oil sample before it goes downhole.