Tension-Set Packer

Key Takeaways

• Setting mechanism differences between tension-set and compression-set packers determine the operational procedures required to set each type and the wellbore conditions in which each type is preferred: a compression-set packer (the most common type in vertical wells) is set by applying downward compressive force to the packer by slacking off a specified weight from the drill pipe or tubing string onto the packer mandrel, which causes the setting sleeves to compress the packer elements radially and simultaneously engage the anchor slips; in a vertical well with a long tubing string above the packer, slacking off 20,000-40,000 lb of tubing weight onto the packer is straightforward, but in a highly deviated wellbore where the tubing string is lying against the low side of the wellbore, the available weight that can be transmitted to the packer is reduced by friction between the tubing and the casing (the axial component of the string weight minus the friction force may be insufficient to provide the required compression); a tension-set packer avoids this problem by using the upward pull force applied to the string from the surface (which is transmitted efficiently regardless of wellbore inclination because the tensile force is independent of friction direction) to set the tool; tension-set packers are therefore the preferred type for horizontal wells, extended-reach wells, and other highly deviated completions where compression-set packers would require excessively high set down forces to overcome friction and achieve the required setting load on the packer mandrel.
• Retrievable versus permanent tension-set packer design affects the operational procedures for removal and the reusability of the packer after it has been set and the well has been produced or tested: a retrievable tension-set packer can be released and pulled from the well at the end of the production period or after a well test by applying a specific pull or rotate sequence at surface that reverses the setting mechanism, retracts the anchor slips, and allows the packer to be pulled out of the casing with the tubing string; the retrievable design allows the completion to be reconfigured after initial production (adding or removing zones, changing the packer depth), permits the packer to be inspected and reused on another well if it is in good condition, and avoids the need for a milling or fishing operation to remove the packer if the well is to be recompleted; a permanent tension-set packer (which has a non-reversible setting mechanism) cannot be retrieved by pulling on the tubing string and must be milled out with a drilling or workover assembly if the well is to be reconfigured; permanent packers are used when the highest possible pressure rating and mechanical integrity are required (because the permanent non-reversible setting mechanism can provide higher contact force between the slips and casing than a retrievable mechanism) and when the packer is intended to remain in place for the entire producing life of the well without any anticipated recompletion that would require packer retrieval.
• Load rating and pressure differential capacity of tension-set packers must be matched to the anticipated wellbore conditions throughout the producing life of the well, including the production phase (where the packer must seal against the reservoir pressure differential), the stimulation phase (if hydraulic fracturing or acid stimulation is performed through or above the packer), and any emergency pressure conditions: the pressure rating of a tension-set packer is specified as two differential pressure ratings, the upward differential (the maximum pressure that can be applied from below the packer, which tends to push the packer upward) and the downward differential (the maximum pressure from above the packer, which tends to push it down), with the upward rating typically higher than the downward rating because the anchor slip design generates higher holding force when loaded upward (the slips are typically designed to bite harder into the casing when pulled upward); the tension rating of the packer (the maximum axial tensile load that can be applied to the tubing above the packer without distorting or releasing the packer) must be sufficient to support the weight of the tubing string below the packer in a deviated completion where the lower tubing hangs in tension from the packer, plus any additional tensile loads from thermal expansion or test pressures; packers are rated according to API 11D1 (which specifies test procedures and performance requirements for production packers) and the service conditions must be matched to the packer's rated temperature, pressure, and load specifications.
• Anchor slip engagement geometry in tension-set packers is designed so that the upward tensile load applied during setting causes the slips to grip the casing wall more tightly as the load increases, providing a self-reinforcing grip that increases with the differential pressure across the packer: the slips are wedge-shaped inserts with wicker teeth that dig into the casing wall, mounted on a cone-shaped mandrel so that as the slips are pushed upward by the packer setting mechanism, they ride up the cone and are forced radially outward against the casing; under upward load (tension above, pressure from below), the slips are loaded further up the cone, increasing the contact pressure between the slip teeth and the casing and the grip force; this load-reinforcing mechanism means that higher differential pressure (which represents a higher functional requirement on the packer's sealing) produces a proportionally higher grip force (which provides the required holding capacity), making the tension-set packer self-compensating for varying differential pressure; the interaction between the packer elements (rubber seals) and the anchor slips must be designed so that the elastomeric element is not extruded past the slips into the casing-mandrel clearance under high differential pressure, which requires backup rings (metal or rigid polymer rings adjacent to the rubber element) that prevent extrusion while maintaining the elastomeric seal under load.
• Tubing movement effects on tension-set packers during production operations must be considered because thermal expansion and contraction of the tubing string with temperature changes during production and shut-in cycles cause the tubing to try to move relative to the fixed packer, creating forces on the packer that can either release it (if the movement exceeds the range allowed by the packer's design) or cause fatigue loading of the tubing-packer connection: a producing well with hot wellbore temperatures has longer tubing (due to thermal expansion) than when the well was completed at lower surface temperatures, and the thermal expansion force on a fixed packer (which does not allow tubing movement) creates compressive load in the tubing above and tensile load in the tubing below the packer; for long tubing strings with significant temperature changes between static and producing conditions, the tubing movement design (using a seal assembly that allows the tubing to move within the packer's bore while maintaining the pressure seal, or pre-stressing the tubing during completion to compensate for the expected thermal movement) is a critical element of the completion engineering that prevents packer loads from exceeding design limits during normal production operations; the Lubinski et al. tubing movement equations (developed in the 1960s and still used in modern completion design software) quantify the tubing movement from ballooning, buckling, thermal expansion, and pressure-related effects as a function of the well geometry and completion design parameters.