Jacking Frame

Key Takeaways

• The jacking frame's load capacity determines the maximum depth and tubing size that can be deployed in a given well, and these limits drive all aspects of coiled tubing program design — heavier tubing (larger outer diameter, thicker wall) has greater depth capacity before buckling and can deliver more hydraulic horsepower to downhole tools, but also weighs more, requiring greater injector head force and jacking frame structural capacity to handle the string; larger coiled tubing units (capable of handling 2-inch to 3.5-inch OD tubing) are required for deep gas wells, stimulation operations requiring high flow rates, and extended-reach applications where gravity and friction loads on the tubing string approach the injector head's capacity; the maximum depth a specific coiled tubing unit can safely reach in a given wellbore (with the selected tubing size) is calculated from the tubing weight per foot, the wellbore geometry and inclination (which affects friction), and the jacking frame's rated capacity, and must include a safety margin for stuck pipe scenarios where the retrieval force required may significantly exceed the injection force during run-in; depth-capacity limitations of small coiled tubing units have historically been a significant constraint on the application of coiled tubing in deep wells, driving the development of progressively larger jacking frame and injector head assemblies.
• Snubbing force requirements in high-pressure wells can exceed the jacking frame's injection capacity, limiting coiled tubing operations in live well environments — when coiled tubing is injected into a pressurized wellbore, the wellbore pressure acts on the cross-sectional area of the tubing (the "snubbing area") and creates an upward force that the injector head must overcome to push the tubing downhole; for a 2-inch OD coiled tubing string in a well with 5,000 psi wellbore pressure, the upward force is approximately 5,000 × π/4 × (2)² = approximately 15,700 lbs — and this upward force must be subtracted from the injector head's available gripping force before any useful downward injection force remains; in high-pressure gas wells where wellbore pressure may be 10,000-15,000 psi, the snubbing force can exceed the injector head's capacity for the tubing size required for the operation, necessitating either a larger unit with more injection force, a smaller tubing size (reducing the snubbing area at the cost of flow rate and depth capacity), or a well kill operation before deploying coiled tubing; jacking frame and injector head selection for high-pressure coiled tubing operations requires careful force balance calculation that accounts for snubbing forces throughout the planned depth range.
• The transition from injecting (where the tubing is in compression above the depth where the weight of the tubing equals the snubbing force) to pulling (where the tubing is in tension throughout the string) is called the neutral point, and managing it is critical for avoiding helical buckling — when coiled tubing is injected into a pressurized well, the tubing string is in compression in the upper section (where snubbing force exceeds tubing weight) and in tension in the lower section (where tubing weight exceeds snubbing force); the neutral point — the depth at which the axial load transitions from compressive to tensile — is where the tubing is most susceptible to helical buckling (if the compressive load in the upper section exceeds the critical buckling load for the tubing size and wellbore geometry); helical buckling of coiled tubing inside the casing causes lockup (where the friction from the helically buckled tubing against the casing prevents further injection) and can cause fatigue damage or casing damage from the lateral contact forces; jacking frame operation must therefore be coordinated with tubing string load monitoring to maintain the neutral point at a safe position in the wellbore and to recognize when the string is approaching a locked-up configuration that requires a change in operational parameters or wellbore pressure management.
• Surface pressure testing of the jacking frame, stripper assembly, and wellbore pressure control equipment is mandatory before any live well coiled tubing operation — before running coiled tubing into a producing or pressurized well, the entire wellbore pressure control string (from the blowout preventer at the base of the lubricator to the stripper/stuffing box that seals around the moving coiled tubing at the top of the jacking frame) must be pressure-tested to the maximum anticipated wellbore pressure (the maximum wellhead shut-in pressure plus a test factor, typically 1.25×) to verify that all seals are intact and capable of containing wellbore pressure during the operation; the jacking frame structure itself must be load-tested to verify that its hydraulic cylinders and structural members can safely support the maximum anticipated string weight and retrieval loads; any defect discovered during surface pressure or load testing must be repaired before the operation begins — coiled tubing operations in live wells that start with compromised pressure control equipment or with jacking frame components that have not been tested to their rated capacity are at high risk of catastrophic failure, as the jacking frame is the last mechanical barrier between wellbore pressure and the surface working environment when the coiled tubing is in the well.
• Jacking frame rigging and height requirements create unique logistical challenges for offshore platform and tight surface location operations — a coiled tubing jacking frame on a large onshore unit may stand 20-30 feet above the wellhead, requiring adequate vertical clearance above the wellhead for the lubricator (which must accommodate the maximum tool string length below the stuffing box) and the injector head assembly; on offshore platform wells where vertical clearance is limited by rig floor structure or overhead obstructions, specialized low-profile jacking frames and split-frame injector designs are used to minimize the installed height while maintaining the necessary load capacity; on subsea wells, wireline-deployable coiled tubing units (with jacking frames deployed through a riser from a surface vessel) have been developed for cases where conventional coiled tubing operations from the surface are not possible due to water depth or riser pressure constraints; the logistics of rigging the jacking frame to the wellhead — including the crane lifts required to position the heavy equipment, the anchoring system needed to resist the jacking loads, and the integration with the surface wellbore pressure control equipment — are often underestimated in coiled tubing operation planning and can add significant rig-up time and cost to operations.