Snub

Key Takeaways

• The critical weight transition from snubbing to stripping defines the crossover point at which the weight of pipe in the hole exceeds the upward balloon force from wellbore pressure, changing the pipe's tendency from floating upward (requiring the unit to push it in) to sinking downward (requiring the unit to brake its descent): below the crossover, the pipe is "light" (buoyant due to wellbore pressure) and the snubbing unit must push the pipe in against the net upward force; above the crossover, the pipe is "heavy" (the accumulated weight of all pipe in the hole exceeds the balloon force on the exposed cross-section) and the unit must control the rate of descent to prevent the pipe from running away into the hole under its own weight; for 3.5-inch tubing (string weight approximately 9.3 lb/ft) in a well with 3,000 psi wellhead pressure, the crossover depth is approximately 3,000 psi times 9.62 in2 (end area) divided by 9.3 lb/ft, or approximately 3,100 feet of pipe in the hole; before reaching the crossover, every stroke of the snubbing cylinder pushes the pipe downward against the net upward force; after crossover, the operation becomes conventional stripping with the unit providing braking rather than driving force.
• The snubbing unit's mechanical design uses two sets of opposing slips (pipe grippers): a stationary set (the stationary slips, mounted on a fixed structure at the wellhead) and a traveling set (the traveling slips, mounted on a hydraulic cylinder that moves up and down); during the push stroke (snubbing), the traveling slips grip the pipe and the hydraulic cylinder extends downward, pushing the pipe into the well; at the end of the stroke, the stationary slips grip the pipe to hold it in place (preventing the well pressure from pushing it back up), the traveling slips release, and the hydraulic cylinder retracts to start the next stroke; the stripper rubber assembly (a series of rubber elements mounted above the slips that conform tightly around the pipe OD) provides the pressure seal throughout the operation, with the rubber elements designed to wipe the pipe clean and maintain a gas-tight seal even as different diameter components (tubing joints, tool joints, and downhole tools) pass through; specialized stripper rubbers with different bore diameters are required for each pipe size and OD change in the string, and the pressure rating of the stripper rubber assembly limits the maximum wellbore pressure at which snubbing operations can be safely conducted.
• Applications for snubbing that justify its significantly higher cost compared to conventional workover include wells that cannot be safely killed due to high formation pressure, wells with formation damage risk from kill fluids, wells in environmentally sensitive areas where kill fluid injection is prohibited or restricted, high-value wells where production deferral during conventional kill-and-workover is economically unacceptable, and wells with failed downhole equipment that must be retrieved to restore production: offshore platform wells with high shut-in tubing pressure (above 3,000 to 5,000 psi) are frequent snubbing candidates because killing these wells requires heavy brine or mud that can permanently damage the reservoir or take days of pump time; shale oil and gas wells that have been hydraulically fractured are particularly good snubbing candidates because the fractured matrix is extremely sensitive to kill fluid invasion, and re-perforating or replacing a failed pump in a fractured well on snubbing preserves the stimulation that made the well productive in the first place.
• Snubbing unit capacity selection and wellbore pressure calculations are critical engineering steps before any snubbing operation to ensure that the unit's hydraulic cylinder force exceeds the maximum upward force the wellbore can exert on any component of the pipe string during the operation: the worst case is typically when the heaviest downhole tool (a workover packer, a bridge plug, or a mill) is at the surface (inside the lubricator above the wellhead) and experiencing full wellbore pressure on its full cross-sectional area (not the pipe OD but the tool OD, which may be significantly larger than the pipe body); for a 4.750-inch OD packer being run through 5,000 psi wellhead pressure, the upward force is 5,000 times 17.72 in2 (area of 4.750-inch circle) = 88,600 pounds, which must be added to the simultaneous weight of the pipe in the hole (which may be subtracted from the required snub force at depth) to determine the maximum snubbing unit capacity required; regulatory standards (API RP 54 in North America and equivalent standards in other jurisdictions) provide guidance on snubbing unit capacity, testing, and safe operating procedures.
• Live well snubbing well control is managed by the snubbing unit's BOP stack and stripper assembly, which form the pressure barrier system during the operation and must be capable of closing on the pipe string to shut in the well if a loss of control event begins: the snubbing BOP stack typically includes a set of annular preventers (which close around the pipe body), pipe rams (sized to the pipe OD being run), and blind rams or shear rams (which can close on open hole if the string must be severed in an emergency), all rated to the maximum anticipated wellbore pressure; well control contingency planning for snubbing operations must address scenarios including stripper rubber failure (loss of annular seal), dropped pipe (partial loss of string into the wellbore), and unexpected wellbore pressure increase (gas kick during open perforations); snubbing crews are trained in well control specific to the snubbing environment and must demonstrate competency in the well-specific emergency response plan before any snubbing operation commences.