High-rate gas wells impose tubing design challenges that oil wells do not. Gas velocity through the tubing can exceed 30 m/s, creating erosion, vibration, and pressure-drop concerns that constrain the usable tubing size to a narrower optimum window. Selecting tubing that is too small restricts deliverability; too large allows liquid loading and flow instability.
The Tubing Size Dilemma
In an oil well, tubing sizing is relatively forgiving: the objective is to provide a conduit for the liquid to flow to surface with acceptable friction loss. In a gas well, the physics are different. Gas is compressible, so velocity increases as the gas decompresses from bottomhole to surface. A tubing string that provides acceptable velocity at the bottom may experience erosional velocity at the top where the gas has expanded.
Turner’s critical velocity model and its derivatives define the minimum gas velocity needed to continuously lift liquids (water and condensate) from the tubing. If the gas velocity falls below the critical velocity at any point in the tubing, liquids accumulate, increasing the hydrostatic head and further reducing gas velocity in a downward spiral that eventually kills the well. This minimum velocity constraint sets a maximum tubing diameter for a given gas rate.
Erosional Velocity Limit
At the other extreme, API RP 14E defines an erosional velocity limit: V_e = C / sqrt(ρ), where C is an empirical constant (typically 100–150 for continuous service) and ρ is the gas mixture density at flowing conditions. Exceeding the erosional velocity causes material loss at elbows, restrictions, and tubing-to-casing transitions, eventually thinning the wall to failure. This upper velocity constraint sets a minimum tubing diameter for a given gas rate.
The design window is therefore bounded: tubing must be large enough to keep velocity below erosional limits, and small enough to maintain velocity above the critical liquid-lifting threshold. For many high-rate gas wells, only one or two standard tubing sizes fall within this window.
Grade Selection for Gas Wells
Gas well tubing operates at higher internal pressures than oil well tubing because gas wells typically flow at higher wellhead pressures. The burst rating of the tubing must exceed the maximum shut-in tubing head pressure (SITHP) with an adequate design factor (typically 1.25 for API design). For deep gas wells with SITHP exceeding 5000 PSI, N80 or P110 grades are standard; shallower gas wells with moderate pressures may use J55 or L80.
Sour gas wells require L80 or C90 per NACE MR0175 regardless of depth. The combination of H₂S partial pressure and total pressure determines the NACE severity level, which in turn constrains the allowable material grades and hardness limits.
Velocity String Design
In depleting gas wells where the production rate has declined below the critical velocity for the installed tubing, a velocity string (smaller-diameter tubing run inside the existing tubing) restores gas velocity above the critical threshold. Common velocity string sizes are 1.315″ and 1.66″ OD coiled tubing or jointed tubing, sized to maintain velocity above Turner’s critical rate at the current and projected future production rates.
The velocity string approach extends the well’s flowing life by several years and defers the cost of compression or deliquification equipment. Proper velocity string design requires nodal analysis modelling to optimise the string diameter and depth for the specific well’s IPR (inflow performance relationship) and expected decline profile.
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