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The packer (more accurately described as the 'upper completion production packer') is a key piece of downhole equipment in many completions - a sealing device that isolates and contains produced fluids and pressures within the tubing string; it is a well barrier element, usually part of the well's primary well barrier, protecting the casing and creating an A-annulus. The packer is essential to the basic functioning of most wells, injectors or producers. Alternatives to using a production packer include a dynamic seal assembly, a cemented completion and a packerless completion.
- 1 Uses of packers
- 2 Packer components
- 3 Packer classification
- 4 Types of packers
- 4.1 Retrievable tension packer
- 4.2 Retrievable compression packer with bypass
- 4.3 Retrievable tension/compression set—versatile landing
- 4.4 Retrievable hydraulic-set single-string packer
- 4.5 Dual-string packers
- 4.6 Permanent and retrievable sealbore packers
- 5 Methods of conveyance
- 6 Packer rating envelopes
- 7 References
- 8 Noteworthy papers in OnePetro
- 9 External links
- 10 General references
- 11 See also
- 12 Category
Uses of packers
In addition to providing a seal between the tubing and casing, other aspects of a packer are as follows:
- Prevent downhole movement of the tubing string, generating considerable axial tension or compression loads on the tubing string.
- Support some of the weight of the tubing where there is significant compressive load on the tubing string
- Allows the optimum size of well flow conduit (the tubing string) to meet the designed production or injection flowrates
- Protect the production casing (inner casing string) from corrosion from produced fluids and high pressures
- Can provide a means of separating multiple producing zones
- Provided the tubing string and packer maintain integrity, well control is focussed on the tubing flow, allowing the downhole safety valve to shut-off flow fron the reservoir.
- Hold well-servicing fluid (kill fluids, packer fluids) in the casing annulus.
- Facilitate artificial lift, such as continuous gas lifting through the A-annulus.
Packers have four key features:
- Packing-element system
- Body or mandrel.
The slip is a wedge-shaped device with wickers (or teeth) on its face, which penetrate and grip the casing wall when the packer is set. The cone is beveled to match the back of the slip and forms a ramp that drives the slip outward and into the casing wall when setting force is applied to the packer. Once the slips have anchored into the casing wall, additional applied setting force energizes the packing-element system and creates a seal between the packer body and the inside diameter of the casing.
Production packers can be classified into two groups:
Permanent packers can be removed from the wellbore only by milling. The retrievable packer may or may not be resettable, but removal from the wellbore normally does not require milling. Retrieval is usually accomplished by some form of tubing manipulation. This may necessitate rotation or require pulling tension on the tubing string.
The permanent packer is fairly simple and generally offers higher performance in both temperature and pressure ratings than does the retrievable packer. In most instances, it has a smaller outside diameter (OD), offering greater running clearance inside the casing string than do retrievable packers. The smaller OD and the compact design of the permanent packer help the tool negotiate through tight spots and deviations in the wellbore. The permanent packer also offers the largest inside diameter (ID) to make it compatible with larger-diameter tubing strings and monobore completions.
The retrievable packer can be very basic for low pressure/low temperature (LP/LT) applications or very complex in high pressure/high temperature (HP/HT) applications. Because of this design complexity in high-end tools, a retrievable packer offering performance levels similar to those of a permanent packer will invariably cost more. However, the ease of removing the packer from the wellbore as well as features, such as resettability and being able to reuse the packer often, may outweigh the added cost.
Before selecting either tool, it is important to consider the performance and features of each design, as well as the application in which it will be used. Perhaps in some instances, the permanent packer is the only option, as may be the case in some HP/HT applications. However, in those instances in which either will suffice, the operator must decide which features offer the best return over the life of the well.
When selecting a packer for a cased-hole completion, the differential pressure and temperature requirements of the application must be considered. The well depth, deployment and setting method desired, and final tubing landing conditions are also factors that come into play. The various operational modes (flowing, shut-in, injection, and stimulation) that are anticipated over the life of the well are critical and must be considered carefully in the design phase. The changes in the operational modes that influence changes in temperature, differential pressure, and axial loads all have a direct impact on the packer. Understanding the uses and constraints of the different types of packers will help clarify the factors to consider when making a selection.
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.
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.
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.
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.
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.
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.
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 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.
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.
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.
Permanent and retrievable sealbore packers
The permanent (Fig. 8) and retrievable (Fig. 9) sealbore packers are designed to be set on electric wireline or hydraulically on the tubing string. Wireline setting affords speed and accuracy; however, the one-trip hydraulic-set versions offer the advantage of single-trip installations and allow the packer to be set with the wellhead flanged up.
Sealbore packers have a honed and polished internal sealbore. A tubing seal assembly with elastomeric packing forms the seal between the production tubing and the packer bore. Well isolation is accomplished by the fit of the elastomeric seals in the polished packer bore. To accommodate longer seal lengths, a sealbore extension may be added to the packer.
In the case of the one-trip hydraulic-set sealbore packer system, the production tubing, tubing seal assembly, and packer are made up together and run as a unit. However, if the packer is to be installed on electric wireline or set on a work string, the seal assembly is run on the production tubing after the packer is installed and stabbed into the packer bore downhole.
The seal assembly may be a locator type (Fig. 10), which allows seal movement during production and treating operations, or an anchor type (Fig. 11), which secures the seals in the packer bore and restricts tubing movement. The decision about the best seal assembly to run depends on tubing movement and hydraulic calculations based on:
- Initial landing
- Flowing or shut-in conditions
- Any stimulation or treatment that may be planned for the well.
The removable seal assembly allows tubing to be retrieved for workover without the need of pulling and replacing the packer.
Generally, the permanent sealbore packers, both wireline and hydraulic set, afford much higher performance in both temperature and pressure ratings than do any of the retrievable packers. The one disadvantage is that the permanent packer must be milled over to remove the packer from the wellbore. For the most part, milling is not prohibitive and, in many cases, may never be required. However, removal may be necessary if subsequent workover operations require full-bore access to the casing below the packer or if a packer failure should occur.
Because of the complexity of their design, retrievable sealbore packers usually have a higher cost associated with them (as well as lower pressure and temperature ratings) than do the permanent versions. However, they are in most cases easily removable from the wellbore without milling. Normally, removal is accomplished in two trips: the first to retrieve the seal assembly, and the second with a releasing tool to retrieve the packer. Like the permanent sealbore packer, the retrievable models are available in both wireline and one-trip hydraulic-set versions.
When making the determination of which type of packer to use, careful consideration must be given to the completion design, wellbore geometry, and packer-performance requirements. The contingency plans for packer removal must be developed and reviewed. While many technical advances in milling techniques have been achieved, it ultimately may prove more cost-effective to use a retrievable sealbore packer in horizontal applications in which packer milling is not desirable, or in low-fluid wells in which circulating cuttings to the surface is not possible. In applications in which it is known that the packer must be removed at some point in the life of the well and packer milling may be prohibitive, the retrievable sealbore may be recommended.
Methods of conveyance
For the most part, both permanent and retrievable packers can be run and set on the production tubing string, requiring no additional trips for installation. This one-trip system is both cost-effective and efficient. However, at times it may be necessary or desirable to install the packer in the wellbore first and then run the production tubing. In these instances, a packer is selected that can be run and set either on a workstring or on electric wireline. Once the packer is installed, a sealing device is attached to the end of the production tubing and connected to the packer downhole to form a seal.
Electric wireline setting of the packer affords several benefits. First, it offers fast installation and accurate placement of the packer. This is important in instances in which the packer must be set in a very short interval (perhaps because of damaged casing) or in cases in which the zones are very close together. Electric wireline deployment also can allow the packer to be installed and set under pressure in a live well without the need for a snubbing unit. In this case, a temporary plugging device is used in conjunction with the packer to allow the well pressure above the packer to be bled off once it is installed.
Running and setting the packer on a work string may be necessary in highly deviated wells in which the hole angle is too high to run the packer in on electric wireline. Although this method requires the most time for packer installation, it does afford the benefit of being able to hydraulically pressure test the packer and ensure that it is properly set before picking up and running the production tubing.
Consideration should be given to the run-in speed of the packer, whether run on tubing or electric line. Too fast of a run-in speed in fluid can cause the rubber element to begin to pack off or swab. This will inflict damage to the element and lead to packer failure. Slower speeds also afford the operator a chance to prevent damage to the packer should an obstruction in the wellbore be encountered.
The tubing string is attached to the packer by two methods:
- It is latched or fixed to the packer by means of an anchor seal assembly (in the case of a sealbore packer) or tubing thread (most retrievable packers).
- The tubing is landed with a seal assembly and locator sub in the polished bore of a permanent or retrievable sealbore packer. In this case, the upward tubing movement at the packer is limited only by the length of the seal assembly. Any downward movement is restricted by the locator sub.
There are basically three tubing landing conditions associated with completion packers. The term “landing condition” refers to the amount of slackoff weight or tension that is left on the packer when the tree is landed and the wellhead is flanged up. In these three cases, the tubing can be landed in either tension or compression, or it can be left in neutral with no axial loads on the packer.
The optimum landing condition is dictated by:
- Packer design
- Operational modes
Many types of retrievable packers, for example, often require either constant tension or compression to maintain their seal because of design. Other models of retrievable packers mechanically lock the packoff force in place and allow the tubing to be landed in tension, compression, or neutral. The permanent or retrievable sealbore packer is extremely versatile and can accommodate any of the three landing conditions.
To ensure that the internal diameter of the completion equipment is adequate to allow passage of the tools, consideration should be given to future through-tubing operations such as:
- Coiled-tubing operations
- Electric wireline work.
Operational modes and tubing landing conditions can cause helical buckling of the tubing string, which also may interfere with running longer lengths of tools through the tubing string.
Ideally, the inside diameter (ID) of the packer should be equal to that of the tubing string to facilitate through-tubing operations. This is especially critical in monobore well designs, in which any restriction will limit access to the lower wellbore. In some high-pressure completion designs, obtaining a large packer ID is not always possible because of packer-design limitations required to achieve the higher pressures.
Excessive tubing buckling can severely limit the length and diameter of through-tubing tools that can be run through the tubing string. Tubing buckling is caused by:
- Tubing landing conditions that require compression on the packer
- An overall increase in tubing temperature, which will cause the tubing to elongate
- An increase in internal tubing pressure
- The piston effect on locator type seal assemblies.
These conditions can be minimized if the completion is designed properly. Care should be taken when planning the completion to thoroughly review the various operating conditions to which the well will be subjected and to select a packer to fit the operation.
Casing cleanup operations
Any debris or obstruction that is present in the wellbore can cause most packers to malfunction. Any cement that may have been left on the casing wall from previous cementing operations, as well as scale buildup in the case of old wells, can also lead to poor packer performance. To properly grip the casing and form a leakproof seal, the packer slip and element system must make 100% contact with the casing wall. It is advisable to run a casing scraper or other suitable casing cleanout tool and circulate the well clean before installing the production packer. A casing scraper should always be run in instances in which a packer is to be conveyed through new perforations (Fig. 12).
Before running any packer on electric wireline, it is advisable to run a wireline junk basket and gauge ring (Fig. 12). The gauge ring has a slightly larger outer diameter (OD) than the packer and “gauges” the hole to ensure that there are no tight spots that might cause the packer to become stuck, or accidentally set in the hole. The junk basket is also designed to collect any debris that is suspended in the completion fluid that otherwise might interfere with running the packer.
Other casing considerations
Before installing the packer, a cement bond log should be considered to verify the integrity of the primary cementing job on the casing string. If a poor cement bond exists in the interval in which the packer is to be set, the packer’s ability to serve as a barrier may be compromised should a leak in the casing string occur. Such a leak could allow the formation below to communicate to the annulus above the packer. If such a channel is created, the annulus could be exposed to high formation pressures, or the formation itself may be damaged. Either case could lead to a costly workover.
There are special applications in which the packer is intentionally set in unsupported or uncemented casing. Care should be taken in these instances to ensure that the design of the packer is such that radial loads and stresses created by setting the packer, and those anticipated to be encountered during various operating conditions, do not exceed the stress limitations of the casing.
Packer rating envelopes
Packers are not only designed and required to hold differential pressure at various downhole temperatures, they also must be able to maintain pressure integrity when subjected to various tensile and compression loads created by hydraulic and temperature effects on the tubing string. The rating envelope is a graphical representation of the safe operating limits of the packer in combination with both differential pressure and axial loads.
A packer may hold (for example) 10,000 psi differential from below with no axial loads, or it may hold 100,000 lbf tension at 0 psi, but when the forces are combined, the stresses on the components and the element system may become too great and cause the packer to fail. The combination of axial loading and differential pressure affects various packer models differently. Obviously, it is important to know what the various safe operating parameters of the packer are so that downhole failure can be avoided.
The envelope is a graph consisting of two axis lines. On the “X” axis, negative values represent tension, and positive values equal compression (Fig. 13). The values of the “Y” axis depict differential pressure from above the packer as negative and below the packer as positive. The maximum tested packer ratings under the all-combined load conditions are plotted on the graph and connected by boundary lines that more or less take the shape of a box. Any combinations of pressure and axial loads that fall within the box are considered safe and within the tested limits of the packer.
To use the rating envelope effectively, tubing-movement calculations must be done to determine the packer tubing loads and differential pressures to be encountered in any of the production, shut-in, injection, or treating modes to which the completion will be subjected. These points are then plotted on the rating envelope to see if the applications fall within the safe operating limits of the packer. If they do not, an alternate packer must be selected, or the operation must be tailored to suit the limits of the packer.
- Packer Calculations Handbook. 1992. Baker Oil Tools Div.fckLR
- Hopmann, M. and Walker, T. Predicting Permanent Packer Performance. Petroleum Engineering Intl. Hart Publications Inc.
- Fothergill, J. 2003. Ratings Standardization for Production Packers. Presented at the SPE Production and Operations Symposium, Oklahoma City, Oklahoma, USA, 22-25 March. SPE-80945-MS. http://dx.doi.org/10.2118/80945-MS.
Noteworthy papers in OnePetro
Allen, T. and Roberts, A.P. 1993. Production Operations, fourth edition, I and II.
Factors and Conditions Which Cause Seal Assemblies Used in Downhole Enviornments to Get Stuck. Baker Oil Tools—Engineering Tech Data Paper No. CS007.
Patton, L.D. and Abbott, W.A. 1985. Well Completions and Workovers: The Systems Approach, second edition, 57–67. Dallas: Energy Publications.