Velocity String
A velocity string is a small-diameter production tubing string — typically 1 to 2 inches in nominal diameter — installed inside the existing production tubing of a gas well that has experienced liquid loading, designed to restore gas production by reducing the flow cross-sectional area available to the gas stream, thereby increasing the actual gas velocity above the critical velocity required to continuously lift liquid droplets from the wellbore and prevent liquid accumulation that kills the well.
Key Takeaways
- Liquid loading occurs in gas wells when the gas velocity in the wellbore falls below the critical velocity (Turner's critical velocity) required to lift water or condensate droplets to surface — the liquid drops fall back, accumulate in the wellbore, increase bottomhole pressure, and further reduce gas production in a self-reinforcing cycle that can kill the well entirely if not addressed.
- Turner's critical velocity equation calculates the minimum gas velocity needed to continuously transport the largest liquid droplets upward against gravity, accounting for liquid density, gas density, and interfacial surface tension — for water in a typical gas well at reservoir conditions, critical velocity is approximately 1 to 4 metres per second depending on wellbore pressure and temperature.
- A velocity string reduces the flow cross-sectional area for gas by installing a smaller-diameter tube inside the existing tubing, concentrating the same gas flow rate (in standard cubic metres per day) into a smaller area, increasing the actual flowing velocity above the critical velocity and restoring continuous liquid lifting.
- Velocity string installation is a lower-cost alternative to other liquid unloading methods (gas lift, plunger lift, beam pump, ESP installation) in wells with sufficient reservoir deliverability to sustain production above the minimum velocity in the velocity string bore — wells with very low reservoir pressure or very low permeability may not sustain adequate gas rate through the velocity string and require an active artificial lift method instead.
- The velocity string typically bypasses the existing production packer, with the velocity string inlet below the perforations and the outlet to surface through the existing wellhead, requiring a special hanger and wellhead modification to run the smaller tube through the existing completion without a workover rig in many cases.
Fast Facts
Turner's critical velocity model, published in 1969 by Robert Turner and colleagues at Shell, is the fundamental equation for liquid loading analysis in gas wells. The model calculates the minimum gas velocity to lift a spherical liquid droplet against gravity, given the gas and liquid densities and interfacial tension. Turner's equation gives critical velocity as approximately v_crit = 1.593 × [σ(ρL − ρG)/ρG²]^0.25 in SI units (σ = surface tension, ρL = liquid density, ρG = gas density). For a typical natural gas well producing water at 1,000 psia bottomhole pressure and 200°F, the critical velocity is approximately 2 to 3 m/s. A standard 2-3/8 inch (73 mm OD) tubing with 2.441 inch ID provides about 30 cm² of flow area; a velocity string with 1-1/4 inch OD and approximately 1.5 inch ID provides about 7 cm² — increasing velocity by a factor of 4 for the same flow rate.
What Is a Velocity String?
Natural gas wells typically produce with some associated liquid — either formation water from the reservoir, condensate (liquid hydrocarbons that condense from the gas stream as it travels up the cooler wellbore), or both. When a gas well is flowing vigorously at high rates, the gas velocity is sufficient to continuously lift these liquids to surface and the well produces cleanly. As the reservoir depletes and gas rates naturally decline over the well's production life, the flowing gas velocity eventually falls below the critical value needed to carry liquids upward, and the liquids begin to accumulate in the wellbore.
This condition — liquid loading — is one of the most common production problems in late-life gas wells and in low-permeability (tight) gas wells that produce at inherently low rates from the start. Once loading begins, the liquid accumulation increases the bottomhole flowing pressure, which reduces the pressure differential driving gas from the reservoir into the wellbore, further reducing gas rate, further reducing velocity — a positive feedback loop that can cause complete well kill within days to weeks if not addressed.
A velocity string is the simplest mechanical solution: by reducing the available flow area, the same gas volume rate produces a higher actual velocity, restoring continuous liquid lifting without requiring any external energy input (as gas lift or electric pump methods would). The technique works when the well still has sufficient gas deliverability to sustain production above the critical velocity in the smaller-bore tube — it simply refocuses the available gas energy into a smaller channel to maximize velocity.
Velocity String Design and Installation
Velocity string sizing requires calculating the critical velocity for the expected wellbore conditions (pressure, temperature, gas and liquid composition) and then determining what tubing ID is needed to exceed that velocity at the minimum expected gas rate. The calculation: TFA_required = Q_gas / v_crit, where Q_gas is the minimum gas rate (in actual cubic metres per second at wellbore conditions) and v_crit is the Turner critical velocity. The tubing size is then selected from available commercial tubing sizes with ID corresponding to the required TFA.
Common velocity string sizes are 1-inch nominal (0.824 inch ID), 1-1/4 inch (1.050 inch ID), and 1-1/2 inch (1.380 inch ID) in coiled tubing or jointed pipe. Coiled tubing velocity strings are preferred for installation because they can be installed without a workover rig — the coiled tubing unit runs the small-diameter tube through the existing wellhead and existing production tubing, allowing installation with minimal surface intervention. Jointed pipe velocity strings require a smaller workover rig to handle the joints and make connections.
The velocity string inlet (bottom) is positioned below the bottom perforation to capture liquids before they enter the tubing. A standing valve or check valve at the inlet prevents liquid fallback through the velocity string during shut-in periods. The annulus between the velocity string and the existing production tubing is typically sealed with a packer or packerless seal assembly to prevent gas from bypassing the velocity string through the annulus, which would reduce the velocity benefit of the smaller bore.
Velocity Strings Across International Jurisdictions
Canada (AER / WCSB): Velocity strings are widely used in mature WCSB gas wells, particularly in shallow conventional gas pools (Medicine Hat, Belly River, Mannville formations) where declining gas rates from naturally depleting pools trigger liquid loading in thousands of wells annually. AER production reporting data shows characteristic liquid loading signatures — erratic production, increasing liquid-gas ratio, and declining gas rates — in many aging WCSB gas pools. Canadian well service companies and coiled tubing operators provide velocity string installation services as a routine offering for WCSB gas producers managing liquid loading in low-rate mature wells. AER does not specifically regulate velocity string installation, but the wellbore modification is documented in the completion records submitted to the AER.
United States (API / SPE): Velocity string applications are documented throughout the Appalachian Basin (shallow Devonian and Mississippian gas wells), Arkla Basin, and shallow Gulf Coast gas wells where aging conventional gas fields have many liquid-loaded wells. API RP 11 series (relating to artificial lift) provides guidance on liquid unloading methods for gas wells that encompasses velocity string analysis. SPE papers on liquid loading diagnostics and remediation are extensively documented from the extensive US conventional gas well inventory. Modern coiled tubing service companies in the US offer velocity string installation as a standard light workover service.
Norway (Sodir / NORSOK): NCS offshore gas production wells in the North Sea gas fields (Troll, Sleipner, Ormen Lange) can experience liquid loading in late-life well conditions. Equinor and other NCS operators have used velocity strings in smaller satellite gas fields where full workover interventions are expensive and where coiled tubing installation is feasible. NORSOK D-010 well integrity requirements apply to velocity string installations as with all downhole completion modifications — the velocity string is classified as a completion component that must meet the same well integrity barrier requirements as the primary completion equipment.
Middle East (Saudi Aramco): Saudi Aramco operates numerous gas condensate fields where liquid loading in wells producing from lower-pressure reservoir zones can reduce gas and condensate recovery. Velocity string applications in Aramco's gas field portfolio include both coiled tubing-installed velocity strings in offshore gas wells and workover rig-installed jointed pipe velocity strings in onshore gas fields. Aramco's production engineering standards include liquid loading diagnostic criteria and velocity string design guidelines based on Turner and modified Turner critical velocity calculations calibrated to the specific fluid and reservoir properties of Arabian Peninsula gas wells.
Synonyms and Related Terminology
A velocity string is also called a gas well velocity string, coiled tubing velocity string (when installed with CT equipment), or small-diameter insert string. Related terms include liquid loading, critical velocity, Turner's equation, gas lift, plunger lift, artificial lift, coiled tubing, and production tubing. The term "gas velocity string" distinguishes this application from other uses of the word "string" in oilfield parlance (drill string, casing string).
Tip: Before installing a velocity string, confirm with a detailed liquid loading diagnostic that the well is actually liquid-loaded rather than experiencing other production decline mechanisms. A well with a low productivity index (poor reservoir deliverability) will not benefit from a velocity string — the reduced tubing ID increases backpressure on the formation and may reduce gas rate further rather than increasing it. Run Turner's critical velocity calculation at the current gas rate and wellbore pressure/temperature, compare to the actual calculated annular velocity in the existing tubing, and plot the well's deliverability curve. If the current gas rate plots above the Turner critical velocity threshold in the existing tubing but the well is still loading, the problem may be scale, paraffin, or water coning from a specific zone rather than classical liquid loading, and a velocity string will not solve it.
FAQ
How is a velocity string different from plunger lift for liquid unloading?
Both address liquid loading in gas wells but through different mechanisms. A velocity string is a passive device — it increases the gas velocity in the smaller-bore tube to continuously lift liquids without any moving parts or external energy. Plunger lift uses a solid cylinder (plunger) that cycles between the wellbore tubing and the surface, driven by the gas pressure that builds during well shut-in, to mechanically lift the liquid column accumulated above it. Plunger lift is effective in wells with sufficient reservoir pressure to build up and slug gas for the plunger cycle (typically wells with reservoir pressure above 200 psi per 1,000 feet of depth), while velocity strings are better suited to wells with continuous gas production above the critical rate threshold. In wells with very low gas rates, neither method may be effective and an active artificial lift system (gas lift, ESP) is required.
What are the signs that a velocity string has failed or needs replacement?
Signs of velocity string performance deterioration include: progressive decline in gas rate back toward pre-installation levels, resumption of erratic production (surging, slugging) characteristic of liquid loading, increasing wellhead liquid production volumes indicating loading above the velocity string inlet, and elevated tubing head pressures relative to the theoretical flowing pressures for clean gas production. Velocity string failures include scale or paraffin deposition inside the small-bore tube (which reduces the effective ID and increases backpressure), scale or debris plugging the standing valve at the bottom, and corrosion or mechanical damage to the string from produced water or CO2. Routine coiled tubing cleanouts and periodic velocity string condition monitoring using production data analysis are the primary management tools.