Travelling Snubbers

Key Takeaways

• The snubbing force calculation that determines whether a well is in the pipe-heavy or pipe-light condition governs the entire snubbing operation design, because the direction of the net force on the pipe string determines whether the pipe tends to fall into the well (pipe-heavy, when the string weight exceeds the upward pressure force) or must be pushed into the well against the upward pressure force (pipe-light, the condition where snubbing is required to force the pipe through the stripper): the snubbing force equals the wellhead pressure multiplied by the cross-sectional area of the pipe body (not the OD, but the cross-sectional area of the steel), which for a 2-7/8 inch OD pipe with 0.217 inch wall thickness is approximately 1.8 square inches; at 3,000 psi wellhead pressure, the snubbing force is approximately 5,400 lb pushing the pipe upward; for a tubing string weighing 6.5 lb/ft, the string must be at least 831 feet long (5,400 / 6.5) before the string weight exceeds the snubbing force and the string becomes pipe-heavy; as pipe is added and the string becomes longer, the transition from pipe-light to pipe-heavy occurs at this critical depth, which changes during the operation as more pipe is added to the string; the travelling snubbers must provide gripping and stroking force sufficient to push the pipe downward against the snubbing force while the string is pipe-light, then switch to a holding role as the string becomes pipe-heavy and the stripper rubber seals prevent the wellbore pressure from escaping while the pipe falls by its own weight.
• Slip bowl and die configuration in the travelling snubbers determines the pipe gripping mechanism and the pipe rotation capability of the snubbing unit, with two fundamentally different grip designs used depending on the operational requirements: wrap-around or collet-type slips that grip the pipe from three or four sides (similar to conventional rotary table slips) and provide gripping force from the hydraulic actuator closing the slip assembly against the pipe surface; and rotary snubbing units that use a rotating slip bowl driven by a hydraulic motor, allowing the pipe to be rotated while being run or pulled (critical for making and breaking threaded connections under pressure and for milling or whipstock operations in live wells); the stationary snubbers use the same slip designs but are fixed to the wellhead frame and rely on the pipe load (either the string weight or the pressure force in the pipe-light condition) to engage the slips rather than a separate actuator; the die inserts in both the travelling and stationary snubber slips must be matched to the pipe OD and connection type to avoid crushing or marking the pipe body and to provide sufficient grip force without slippage, with hardened die inserts for plain pipe body grip and softer inserts or full-circumference pads for gripping over upset connections or couplings.
• Stripper rubber selection and management in snubbing operations is critical because the stripper is the pressure seal that prevents wellbore gas, oil, or brine from escaping around the pipe while the travelling and stationary snubbers move the string through the wellhead, and stripper failure during snubbing represents an immediate well control emergency: the stripper rubber (an elastomeric element that seals around the moving pipe by hydraulic compression from the stripper housing's clamping mechanism) must seal against both the wellbore pressure and the annular space between the pipe and the stripper bore under the dynamic conditions of pipe movement, requiring rubber compounds that resist the wellbore fluid chemistry (H2S-resistant elastomers for sour gas wells, high-temperature compounds for HPHT applications), pipe movement velocity (too-fast pipe running causes excessive stripper wear and premature failure), and contact pressure that seals effectively without generating so much friction that it increases the travelling snubber force requirements or causes the stripper to grip the pipe and prevent movement; snubbing engineers monitor stripper wear by tracking the increase in pull/push force required for a constant pipe velocity as the stripper degrades and its sealing contact pressure increases, or by visually inspecting the stripper for cuts, extrusion, or tearing during pipe connection changes when the wellbore pressure is momentarily isolated by the stationary snubbers.
• Pipe connection procedures under pressure in snubbing operations require a specific sequence using both the travelling and stationary snubbers to isolate the live wellbore from the open pipe end while the connection is made up or broken, because each joint of pipe must be added or removed from the string at the surface without allowing wellbore gas to escape through the open pipe end: when running pipe into the well, the stationary snubbers grip the pipe already in the hole, the travelling snubbers are raised to their top stroke position, a new joint of pipe is stabbed into the box connection of the string below, the connection is torqued up using power tongs, the travelling snubbers grip the new joint above the connection, the stationary snubbers release, and the travelling snubbers stroke downward to advance the string one joint length; the open end of the new pipe joint at the surface is exposed to atmospheric pressure during the makeup operation only when the wellbore is isolated by the stationary snubbers and the pipe end is above the stripper, so a back-pressure valve (BPV, a check valve run inside the tubing to prevent backflow through the pipe bore) is required in many snubbing operations to prevent wellbore pressure from flowing up through the inside of the pipe string and out through the open end during connection makeup.
• Coiled tubing versus jointed pipe snubbing reflects two different implementations of the travelling snubber concept that are optimized for different wellbore conditions and operational objectives: jointed pipe snubbing units (using the alternating travelling/stationary snubber design described above) handle conventional 2-3/8 to 4-1/2 inch jointed tubing in wells requiring workover operations (perforating, plug setting, fishing, milling) that cannot be performed with coiled tubing due to pipe size or connection requirements; coiled tubing injector heads use the same fundamental travelling grip concept but replace the alternating snubber pairs with continuous chain-driven grippers that clamp the coil from both sides and inject it at a controlled rate, allowing continuous tubing movement without the stop-and-go sequence of jointed pipe snubbing; the choice between jointed pipe snubbing and coiled tubing depends on the required pipe size (coiled tubing is limited to smaller diameters than jointed pipe for a given injector capacity), the need for pipe rotation (coiled tubing cannot be rotated), the required depth and pressure rating, and the specific wellbore operations to be performed; in practice, coiled tubing is used for the majority of live well interventions where its operational speed and continuous pipe movement capability outweigh the limitations of smaller pipe diameter and no rotation.