Types of packers

Retrievable tension packer

The tension packer (Fig. 1) is typically used in medium- to shallow-depth (LP/LT) production or injection applications. The tension packer has a single set of unidirectional slips that grip only the casing when the tubing is pulled in tension. Constant tubing tension must be maintained to keep the packer set and the packing element energized. Tension packers, typically, are set mechanically and are released by means of tubing rotation. Most models also have an emergency shear-release feature should the primary release method fail.

Fig. 1—Tension packer.

The tension packer does not have an equalizing (or bypass) valve to aid in pressure equalization between the tubing and annulus to facilitate the retrieval of the packer. This seldom presents a problem with the tension packer, because the packer is run at relatively shallow depths, and differential pressures across the packer during retrieval should be low. The use of packers without bypass valves should be avoided in deeper applications for which hydrostatic and differential pressures can be greater. High differential pressures can make packers difficult or impossible to release because of the forces created by the pressure acting on the cross-sectional area of the packer. In packers with no bypass feature, the pressures must be equalized at the surface by adding fluid or pressure to the tubing or annulus and, in some extreme cases, swabbing the tubing string.

The tension packer is suited for applications in which pressure below the packer is always greater than the annulus pressure at the tool. Pressure from below the tool boosts the packing element into the slip assembly, which is designed to hold in tension and capture this force. Conversely, when annular pressure is higher than tubing pressure at the tool, the element is boosted downward away from the slips, and packoff force is lost. Therefore, care must be taken to ensure that sufficient tension is applied to keep the element energized to contain differentials in favor of the annulus.

Consideration should be given to the type of wellhead and Christmas tree that will be employed when using tension packers in extremely shallow operations. After the packer is set and tubing is pulled in tension, it is difficult or impossible for the tubing to stretch enough to facilitate installation of some types of wellheads.

Retrievable compression packer with bypass

The retrievable compression packer with fluid-bypass valve (Fig. 2) is recommended for low- to medium-pressure/medium-temperature oil- or gas-production applications. The retrievable compression packer is prevented from setting by means of a mechanical interlock while it is being run in the hole. Once the packer has been run to the desired depth, the tubing string is rotated to initiate the setting sequence. As the tubing is being rotated, the drag blocks on the packer are used to hold the packer in place and provide the resistance to set it. Once the interlock system is released, the tubing string is lowered to close the bypass seal and set the slips. The continued application of slackoff force energizes the packing-element system and creates a seal. The packer is released by simply picking up on the tubing string—a desirable feature.

Fig. 2—Compression packer with fluid bypass.

The packing-element system is enhanced over that of the tension packer to make it suitable for moderately higher pressures and temperatures. The addition of the integral bypass valve assists equalization of pressures in the tubing and annulus and aids in releasing the packer. The valve can be opened by picking up on the tubing string without releasing the packer. Constant compression or tubing weight must be maintained to sustain the packoff and keep the bypass valve closed. Because of this design constraint, compression packers generally are not suitable for injection wells or low-volume pressure-treating operations. The bypass valve could open or the packer may fail if pressure limitations are exceeded from below, or a decrease in temperature because of operational changes may result in a reduction of tubing length and a loss of packoff force on the packer.

More common models of the compression packer with bypass have an additional set of hold-down slips, or an anchor system above the packing-element system (Fig. 3). This packer sets and releases in much the same manner as the compression packer discussed previously. In this model, however, the addition of the hold-down slip helps to keep the packoff force and bypass valve locked in place when pressure below the tool is greater than the pressure in the annulus. This variation can be used in limited treating operations, in gas lift applications, or in production applications in which tubing pressures are greater than annular pressures. However, there are limitations to the ability of the anchor to keep the bypass closed, and any operational modes that will result in loss of set-down weight must be planned carefully.

Fig. 3—Compression packer with fluid bypass and hold-down anchor.

Wireline set — tubing retrieval

There are several retrievable packers designed to be installed in the wellbore on electric wireline and retrieved on the tubing string (Fig. 4). On the top of the packer is located a special nipple. The nipple has a polished seal surface on its OD and has j-lugs that are used to anchor a seal housing or washover shoe in place. The polished nipple also has a landing nipple profile in its ID. This allows the installation of a slickline retrievable blanking plug if desired.

Fig. 4—Wireline-set tubing retrievable packer. Shown set with plug in place (first view) and with tubing connected and plug retrieved (second view).

The packer is first run and set on electric wireline. The electric wireline setting tool provides the force necessary to anchor the slips in the casing wall and energize the packing element. Once the packer is installed and the wireline is retrieved, a seal housing (similar to an overshot) is run in the hole on the bottom of the production tubing. The housing has internal seals that, when landed on the polished nipple, create a seal between the tubing and the annulus. The housing also has an internal j-profile that engages the lugs of the nipple and anchors the tubing string to the packer.

The tubing can be retrieved from the wellbore at any time without disturbing the packer by unjaying the seal housing from the polished nipple, or (if desired) the packer can be released and retrieved mechanically with the tubing.

Advantages and application

The main advantage of this system is that it can be run and set under pressure on electric wireline (with a blanking plug preinstalled in the nipple profile) in a live oil or gas well. Once the packer is set, the electric line is removed, and the pressure above the packer can be bled off. With the plug in place, the packer will act as a temporary bridge plug for well control while the tubing string and seal housing are run and landed. Because the plug is located near the top of the packer assembly, it can be circulated free of any debris before landing the tubing. Once the tree has been installed, the plug is removed with slickline, and the well is placed on production.

Common applications are for completion of the well after a high-rate fracture is performed down the casing or after underbalanced perforating with a casing gun. This underbalanced completion method is especially useful in applications in which formation damage may occur if kill-weight fluid is introduced into the wellbore.

Retrievable tension/compression set—versatile landing

Tension- or compression-set packers that allow the tubing to be landed in tension, compression, or neutral are the most common types of mechanical-set retrievable packers run today. This group of mechanical-set retrievable packers (Fig. 5) will vary greatly in design and performance and may require tension, compression, or a combination of both to set and pack off the element. The exact setting method depends on the design of the tool. Various packing-element systems and differential ratings are available, making this type of packer suitable for a large number of applications—up to and including some HP/HT completions.

Fig. 5—Tension/compression-set versatile landing.

The one common feature found in this style of packer is that, once the element is sealed off and the packoff force is mechanically locked in place, the tubing string may be landed in compression, tension, or neutral. Slips located above and below the packing element (or a single set of bidirectional slips) are designed to hold axial tubing loads from either direction to keep the packer anchored in place. An internal lock system mechanically traps the packoff force and keeps the elements energized until the packer is released. A bypass valve is present to aid in equalization and the release of the packer. It is locked from accidentally opening until the packer-releasing sequence has been initiated.

Because the packer does not rely on constant tubing forces to maintain its packoff, this tool is much more versatile in application. It can be used in production or injection applications, as well as in completions for which well stimulation is planned, and it is almost universal in application. The only constraint is in deep deviated wells, where tubing manipulation or getting packoff force to the tool may present a problem. Extreme shallow depth setting is achievable in models that allow the elements to be energized with tension.

Care must be taken to ensure that tubing movement during production or injection operations does not exceed the tensile or compression limitations of either the packer or the tubing string.

Retrievable hydraulic-set single-string packer

The hydraulic-set packer (Fig. 6) has a bidirectional slip system that is actuated by a predetermined amount of hydraulic pressure applied to the tubing string. To achieve a pressure differential at the packer and set it, a temporary plugging device must be run in the tailpipe below the packer. The applied hydraulic pressure acts against a piston chamber in the packer. The force created by this action sets the slips and packs the element off. Some models have an atmospheric setting chamber and use the hydrostatic pressure of the well to boost the packoff force. Regardless of design, all of the force generated during the setting process is mechanically locked in place until the packer is later released. Once the packer is set, the tubing may be landed in tension (limited by the shear-release value of the packer), compression, or neutral.

Fig. 6—Hydraulic-set single-string packer.

Because no tubing manipulation is required to set a hydraulic packer, it can be set easily after the wellhead has been flanged up and the tubing has been displaced. This promotes safety and allows better control of the well while displacing tubing and annulus fluids. The hydraulic-set packer can be run in a single-packer installation, and because no packer body movement occurs during the setting process, it can be run in tandem as an isolation packer in single-string multiple-zone production wells. The hydraulic-set single-string packer is ideal for highly deviated wells in which conditions are not suitable for mechanical-set packers.

Special considerations include the following:

·         Well stimulation must be planned carefully to avoid premature shear release of the packer.

·         Maximum tensile capabilities of the tubing string when selecting the shear-release value of the packer are required.

·         A temporary plugging device must always be incorporated below the lowermost hydraulic-set packer to facilitate hydraulic setting of the packer.

Retrieval

Retrieval of the hydraulic-set single-string packer is accomplished by pulling tension with the tubing string to shear a shear ring, or shear pins, located within the packer. Most models also have a built-in bypass system that allows the pressures in the tubing and annulus to equalize, or balance, as the packer is released. The tension load required to release the packer must be considered carefully in the initial completion design and in the selection of the shear-ring value. The shear-release value must not be set too high so that it will not be beyond the tensile capabilities of the tubing string, yet it must be high enough so that the packer will not release prematurely during any of the planned operational modes over the life of the completion.

A variation of the hydraulic-set single-string retrievable packer, which can be furnished without the shear-release feature, is available for the larger-size casing and tubing combinations commonly used in big monobore completions. This design is better described as a “removable” packer because it is not retrieved by conventional means. The running and the hydraulic setting procedure remain the same, but to remove the packer from the wellbore, the inner mandrel of the packer must be cut. This is done either with a chemical cutter on electric wireline or by a mechanical cutter on drillpipe or coiled tubing. Once the mandrel is cut, retrieval is accomplished by picking up on the tubing string or the top of the packer. The packer is also designed to be millable should the cut-to-release feature fail. The elimination of the shear ring enables the packer to achieve higher tensile and differential-pressure ratings. This permits well-treating and well-injection operations to occur that were not possible with the conventional shear-release hydraulic-set packer.

Dual-string packers

This is basically a “mid-string” isolation packer that is designed to seal off approximately two strings of tubing (Fig. 7). The dual packer allows the simultaneous production of two zones while keeping them isolated. Most multiple-string packers are retrievable; however, some permanent models exist for use in HP/HT applications. Standard configurations have bidirectional slips to prevent movement and maintain packoff with the tubing landed in the neutral condition.

Fig. 7—Hydraulic-set dual-string packer.

For the most part, multiple-string retrievable packers are set hydraulically because the tubing manipulation required to set a mechanical packer is not desirable or (often) not feasible in a dual-string application. However, mechanical-set models do exist, and in applications in which the tubing strings are run independently, the mechanical-set dual packer can be set with applied slackoff force by the upper tubing string.

The dual-string hydraulic-set packer is set much the same as the hydraulic-set single-string packer. The setting pressure typically is applied to the upper tubing (short string), but some models are designed to be set with pressure applied to the lower tubing (long string). A temporary plugging device is required to be run below the dual packer on the appropriate string to allow the actuating pressure to be applied.

The hydraulic-set dual packers are released by applying tubing tension to shear an internal shear ring. The same considerations in shear-value selection that apply to the single-string hydraulic-set packer also apply to the dual packer. Too high of a value can overstress the tubing during retrieval, and too low a value can lead to a premature packer release during one of the various operational modes to which the packer will be exposed.

Other uses for multiple-string packers include electrical submersible pump applications in which both the electrical cable and the production tubing must pass through the packer. Multiple-string packers are also used in tandem to isolate damaged casing.