PEH:Completion Systems

Publication Information

Petroleum Engineering Handbook

Larry W. Lake, Editor-in-Chief

Volume IV - Production Operations Engineering

Joe Dunn Clegg, Editor

Chapter 2 - Completion Systems

By David Ruddock, SPE, Baker Oil Tools

Pgs. 41-103

ISBN 978-1-55563-118-5
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There are many completion options available to oil and gas producers. Today’s cased-hole completion systems vary from relatively simple single-zone low-pressure/low-temperature (LP/LT) designs to complex high-pressure/high-temperature (HP/HT) applications that were unthinkable with the technology available 50 years ago. Many of the basic components appear similar to those used in the past, yet they have been vastly improved, and their performance has been optimized to suit numerous environments.

There are several keys to designing a successful completion system and selecting components that are fit for purpose for both the downhole environment and application. Consideration must be given to the various modes under which the completion must operate and the effects any changes in temperature or differential pressure will have on the tubing string and packer. Ultimately, the system must be both efficient and cost-effective to achieve production and financial goals. A key factor in the completion design is the production rate; see other chapters in this section of the Handbook for additional information on this topic. The intention of this chapter is to familiarize the reader with the common components that make up the completion system and to understand their applications and constraints.

Packers

The packer forms the basis of the cased-hole completion design. The packer is a sealing device that isolates and contains produced fluids and pressures within the wellbore to protect the casing and other formations above or below the producing zone. This is essential to the basic functioning of most wells.

In addition to providing a seal between the tubing and casing, other benefits of a packer are as follows:

Prevent downhole movement of the tubing string.
Support some of the weight of the tubing.
Often improve well flow and production rate.
Protect the annular casing from corrosion from produced fluids and high pressures.
Provide a means of separation of multiple producing zones.
Limit well control to the tubing at the surface for safety purposes.
Hold well-servicing fluid (kill fluids, packer fluids) in the casing annulus.

Packers have four key features: slip, cone, packing-element system, and 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: retrievable and permanent. Permanent packers can be removed from the wellbore only by milling. The retrievable packer may or may not be resettable; however, 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 LP/LT applications or very complex in 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 and 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.

Retrievable Tension Packer

The tension packer (Fig. 2.1) 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. 2.1—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. 2.2) 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. 2.2—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 2.3). 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. 2.3—Compression packer with fluid bypass and hold-down anchor.

Wireline Set—Tubing Retrievable

There are several retrievable packers designed to be installed in the wellbore on electric wireline and retrieved on the tubing string (Fig 2.4). 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. 2.4—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.

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. 2.5) 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. 2.5—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. 2.6) 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. 2.6—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 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. 2.7). 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. 2.7—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); however, 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. 2.8) and retrievable (Fig. 2.9) 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.

Fig. 2.8—Permanent sealbore packer.
Fig. 2.9—Retrievable sealbore packer (left) and releasing tool (right).

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. 2.10), which allows seal movement during production and treating operations, or an anchor type (Fig. 2.11), 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, as well as 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.

Fig. 2.10—Locator type seal assembly.
Fig. 2.11—Anchor type seal assembly.

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.

Landing Conditions

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.

Packer design, operational modes, and hydraulics dictate the optimum landing condition. 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.

Through-Tubing Operations

Consideration should be given to future through-tubing operations such as coiled-tubing operations, swabbing, slickline, or electric wireline work to ensure that the internal diameter of the completion equipment is adequate to allow passage of the tools. 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 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 (1) tubing landing conditions that require compression on the packer; (2) an overall increase in tubing temperature, which will cause the tubing to elongate; (3) an increase in internal tubing pressure; and (4) 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.^[1]

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 2.12).

Fig. 2.12—Casing scraper (left); wireline junk basket and gauge ring (right).

Before running any packer on electric wireline, it is advisable to run a wireline junk basket and gauge ring (Fig 2.12). The gauge ring has a slightly larger 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.

Metallurgy

Ideally, the packer should be built out of materials that will last the life of the well. Also, in the case of retrievable packers that may be reconditioned and used elsewhere, the advantage of being able to reuse the packer may be lost if the well environment corrodes or damages the tool beyond repair. In potentially corrosive environments, material failure can lead to a packer leak or difficulty in removing a retrievable packer from the wellbore. In these cases, corrosion-resistant alloy materials must be properly selected that are best suited to the downhole well environment. The Natl. Assn. of Corrosion Engineers (NACE) Standard MR-01-75 establishes guidelines and acceptance criteria for material selection for sour service in H₂S environments.^[2]

Metallurgical requirements are dictated both by the downhole well environment and the design and performance requirements of the packer. Consideration must be given to both when selecting and specifying materials for corrosive environments. Many types of materials that are applicable for tubing and casing in corrosive environments are not always suitable (or practical) for packer manufacture.

Some commonly used materials for manufacture of downhole equipment are as follows:^[3]

Low-alloy steels with minimum yield strengths of 110 ksi are used for standard service in noncorrosive environments. These materials are similar in property to P110 tubing and do not meet NACE MR-01-75 requirements for sour service.^[4]
Low-alloy steels with a maximum hardness of Rockwell 22C, which meet NACE MR-01-75 requirements, are intended for use in both standard service and service in sour H₂S environments. Materials that fall into this range would be similar in properties to J-55 to L-80 grades of tubing.
Martensitic steels such as 9% chromium, 1% molybdenum, and 13% chromium alloy steels are used in some wet CO₂ environments. Certain grades of these steels meet NACE MR-01-75 requirements and can be used in limited H₂S applications.^[5]
22% chromium and 25% chromium duplex stainless steel are commonly used in some wet CO₂ and mild H₂S environments.
Austenitic stainless steels, cold worked 3% Mo high-nickel alloy steels, and precipitation-hardening nickel-based alloys are suitable for some environments containing high levels of H₂S, CO₂, and chlorides at moderately high temperatures.

The successful application of any of these materials depends strongly on the specific downhole well environment. Many factors such as temperature, pH, chlorides, water, H₂S, and CO₂ concentrations can have adverse effects on the material performance and can lead to failures associated with pitting, corrosion, chloride stress cracking, or hydrogen embrittlement. Because of this and the vast number and variations of packer designs and tensile requirements of their components, the consumer cannot know which materials are appropriate for each particular design. Ultimately, the user must rely on the packer manufacturer to help make the determination as to which materials will meet the downhole requirements without sacrificing packer performance and reliability.

Elastomers

There are many suitable elastomers on today’s market to match almost any downhole condition. Care must be taken to ensure that the elastomer selected for the packer and seal assembly meets all the downhole conditions to which it will be subjected. Things that must be considered are the downhole operating temperature; exposure to produced or injected fluids and gases; exposure to completion fluids such as oil-based mud, brine, bromides, high pH completion fluids, and amine base inhibitors; and exposure to solvents such as xylene, toluene, and methanol. There is no single best elastomer that will perform under all conditions combined, and selection must be tailored to suit individual well requirements and application.

By far, the most common elastomer used in downhole completion packers is nitrile. Nitrile is used in low- to medium-temperature applications for packers and packer-to-tubing seal assemblies in one form or another. It shows good chemical resistance to oils, brines, and CO₂ exposure. However, its use is limited in wells that contain even small amounts of H₂S, amine inhibitors, or high-pH completion fluids. Exposure to high concentrations of H₂S and bromides generally is not recommended.^[3],^[6]

Hydrogenated nitrile or HNBR (chemical name: hydrogenated acrylonitrile butadiene) has a somewhat higher temperature rating and shows slightly better chemical resistance to H₂S and corrosion inhibitors than standard nitrile. HNBR is more prone to extrusion than standard nitrile and, as a result, requires a more sophisticated mechanical backup system similar to that found on most permanent and higher-end retrievable packers.

Two fluoroelastomers that are commonly used in the oil and gas industry are hexafluoropropylene (vinylidene fluoride, commonly known by the trade name Viton* and tetrafluoroethylene (propylene, trade name Aflas**). These compounds are used in medium- to high-temperature applications. Both compounds show excellent resistance to H₂S exposure in varying limits, CO₂, brines, and bromides. However, the use of Viton should be questioned when amine inhibitors are present in packer fluids and in the case of high-pH completion fluids.

Aflas will swell when exposed to oil-based fluids and solvents. Swelling because of exposure of Aflas to hydrocarbons is generally only a concern when running the tool in the well. Element swell may cause the packer to become stuck on the trip in the hole, and swelling of the seals can result in seal damage during stab-in. After the packer is set and seals are in place, the swelling generally is no longer a concern.

The use of Kalrez^† and Chemraz^‡ in the packer industry is by and large limited to chevron-type "vee" seals and o-rings. On the cost scale, they are by far some of the most expensive materials used in these designs. Kalrez and Chemraz show good resistance to most chemicals found in oilwell and gas-well environments. Because of their ability to maintain stability at extreme temperatures, they are normally recommended for use in HP/HT applications and in most environments in which high levels of H₂S are encountered.

Ethylene propylene (EPDM) is an elastomer commonly used in steam-injection operations. EPDM exhibits poor resistance to swelling when exposed to oil and solvents; however, EPDM can operate in pure steam environments to temperatures of 550°F.

* Viton is a registered trademark of Dupont Dow Elastomers.

*

Aflas is a registered trademark of Ashai Glass Co. Ltd.

^†Kalrez is a registered trademark of Dupont Dow Elastomers.

^‡Chemraz is a registered trademark of Green, Tweed and Co.

Packing Element

The term "packing element" is used to describe the elastomeric sealing system that creates the seal between the OD of the packer and the ID of the casing. The ability of the packing element to hold differential pressure is a function of the elastomer pressure, or stress across the seal. To form a seal, the elastomer pressure must be greater than the differential pressure across the packer. The elastomer pressure is generated by the packoff or setting force applied to the packer.

The packing-element system consists of the seal or packing element and a packing-element backup system. When energized, the packing element expands to conform to the ID of the casing wall. The packing-element backup system contains the energized packing element and restricts the element from extruding or losing its elastomer pressure.

There are many different packing-element-system designs. Each element-system design is suited to a specific application and covers a myriad of well environments. The most basic packing-element system consists of a single packing element with fixed metal backup rings located above and below the element. More sophisticated designs may consist of multidurometer elastomers using a lower durometer element between two elements of a higher durometer. In this design, the lower durometer, or softer-center element, creates the working seal while the higher durometer, or harder-end, elements expand to the casing ID to restrict extrusion. Fixed metal backup rings also may be replaced with flexible or expandable backup rings to further restrict the extrusion of the elastomer.

Packer-to-Tubing Seal Stacks

Permanent and retrievable sealbore packers contain a honed sealbore to accept packer-to-tubing seals or seal assembly to connect the tubing string to the packer. This seal assembly, or stinger, consists of a seal sub with multiple packing units or seal stacks fixed on its OD. The packing units come in a variety of configurations and elastomeric compounds to suit a wide range of downhole conditions. There are two basic types of packing units: bonded and chevron.

The bonded packing unit is composed of one or more metal rings, with a specific elastomer compound bonded or molded to the ring. The bonded seal by design is slightly larger than the ID of the sealbore, and a predetermined amount of stress on the elastomer is created when the seals are inserted into the honed packer bore. The elastomer pressure generated by this stress in turn creates a seal between the seal assembly and the honed packer bore.

Because the bonded seals are self-energized, they are particularly useful in LP/LT gas-injection operations such as CO₂ flood projects. The bonded seals are also less susceptible to dynamic unloading damage and should be selected any time that the seals must leave the honed bore under pressure.

Only a few elastomer compounds are suitable for use in bonded seal designs. The three most common compounds found on bonded seal stacks are Nitrile, Viton, and Aflas. Also, because the bonding tends to fail at higher temperatures, most bonded seals are generally not recommended for service above 300°F.

Chevron seal stacks come in a wide variety of designs and elastomeric compounds. They consist of a number of "vee"-shaped chevron seal rings supported by metal (or a combination of metal and nonelastomeric) backup rings such as Ryton* or Teflon.** Each individual chevron seal ring holds pressure in one direction only, so each seal stack must contain a number of seal rings facing in either direction.

The chevron seal stacks are the most versatile and widely used. They are available with various elastomers and designs. Common materials used for the vee-type seal rings include nitrile (the most common), Viton, Aflas, and Kalrez. Some specialized premium seal stacks can handle pressures up to 15,000 psi (and beyond) at temperatures approaching 550°F. Each has its own environmental application, as well as temperature and pressure rating. Matching the proper elastomer to the environment is a key to long-term sealing success.

The chevron seal stacks do not lend themselves well to differential unloading conditions that might be experienced during fracturing or treating operations in which locator-type seal assemblies are used in sealbore packers. The temperature and piston effects will cause the tubing to shorten, and the seal assembly will move upward out of the packer bore. Any chevron seal that is allowed to leave the polished sealbore will be subject to severe damage because of the sudden change in differential pressure. Because of this, locator-type seal-assembly designs should be such that the working seals are never allowed to leave the polished packer bore under differential pressure.^[7]

To reduce the possibility of seal failure and greatly extend the life of the seal assembly, it is recommended that seal movement be restricted whenever possible. While both chevron and bonded seals are designed to hold pressure under dynamic conditions, completion designs that allow continuous seal movement over the life of the well can significantly shorten the life of the seal. Seal movement should be eliminated altogether if possible by anchoring the seals in the packer bore. Locator seal assemblies should be landed so that the locator sub will be in constant compression when the well is producing, thus limiting movement to those cases in which the well is either treated or killed.

* Ryton is a registered trademark of Chevron Phillips Chemical.

**

Teflon is a registered trademark of E.I. DuPont Co.

ISO and API Standards

The Intl. Organization for Standardization (ISO) and the American Petroleum Inst. (API) have created a standard [reference ISO 14310:2001(E) and API Specification 11D1]^[8], ^[9] intended to establish guidelines for both manufacturers and end users in the selection, manufacture, design, and laboratory testing of the many types of packers available on today’s market. Perhaps more importantly, the standards also establish a minimum set of parameters with which the manufacturer must comply to claim conformity. The International Standard is structured with the requirements for both quality control and design verification in tiered rankings. There are three grades, or levels, established for quality control and six grades (plus one special grade) for design verification.

The quality standards range from grade Q3 to Q1, with grade Q3 carrying the minimum requirements and Q1 outlining the highest level of inspection and manufacturing verification procedures. Provisions are also established to allow the end user to modify the quality plans to meet his specific application by including additional needs as "supplement requirements."

The six standard design-validation grades range from V6 to V1. V6 is the lowest grade, and V1 represents the highest level of testing. A special V0 grade was included to meet special acceptance criteria requirements. The following is a brief summary outlining the basic requirements of the various levels of test-acceptance criteria.

Grade V6 Supplier/Manufacturer Defined

This is the lowest grade established. The performance level in this instance is defined by the manufacturer for products that do not meet the testing criteria found in grades V0 through V5.

Grade V5 Liquid Test

In this grade, the packer must be set in the maximum ID casing it is rated for at the maximum recommended operating temperature. The testing parameters require that it be set with the minimum packoff force or pressure as specified by the manufacturer. The pressure test is performed with water or hydraulic oil to the maximum differential-pressure rating of the packer. Two pressure reversals across the tool are required, meaning it must be proved that the packer will hold pressure from both above and below. The hold periods for each test are required to be a minimum of 15 minutes long. At the end of the test, retrievable packers must be able to be removed from the test fixture by using the procedures of its intended design.

Grade V4 Liquid Test + Axial Loads

In this grade, all parameters covered in Grade V5 apply; however, in addition to passing V5 criteria, it also must be proved that the packer will hold differential pressure in combination with compression and tensile loads, as advertised in the manufacturer’s performance envelope.

Grade V3 Liquid Test + Axial Loads + Temperature Cycling

All test criteria mandated in Grade V4 apply to V3; however, to achieve V3 certification, the packer also must pass a temperature cycle test. In the temperature cycle test, the packer must hold the maximum specified pressure at the upper and lower temperature limits in which the packer is designed to work. The test is started at maximum temperature, as in V4 and V5; however, after passing this segment of the test, the temperature is allowed to cool to the minimum, and another pressure test is applied. After successfully passing the low-temperature test, the packer also must pass a differential-pressure hold after the test-cell temperature is raised back to the maximum temperature.

Grade V2 Gas Test + Axial Loads

The same test parameters used in V4 apply to Grade V2, but in this instance, the test medium is replaced with air or nitrogen. A leak rate of 20 cm³ of gas over the hold period is acceptable; however, the rate may not increase during the hold period.

Grade V1 Gas Test + Axial Loads + Temperature Cycling

The same test parameters used in V3 apply to Grade V1, but again in this instance, the test medium is replaced with air or nitrogen. Similar to the V2 test, a leak rate of 20 cm³ of gas over the hold period is acceptable, and the rate may not increase during the hold period.

Special Grade V0 Gas Test + Axial Loads +Temperature Cycling + Bubble Tight Gas Seal

This is a special validation grade that is added to meet customer specifications in which a tight-gas seal is required. The test parameters are the same as those for V1; however, a gas-leak rate is not allowed during the hold period.

If a packer is qualified for use in a higher grade, it may be deemed suitable for use in any of the lower validation grades. For example, if tested to grade V4, it is accepted that the packer meets or exceeds the service requirements of V4, V5, and V6 applications.

Packer Rating Envelopes

Packers are not only designed and required to hold differential pressure at various downhole temperatures, but 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.^[10], ^[11]

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. 2.13). 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.

Fig. 2.13—Typical packer-rating envelope.

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.

Flow-Control Accessories

Flow-control accessories add to the flexibility of the cased-hole completion design and perform a multitude of tasks, from temporarily plugging off the tubing string to establishing temporary communication between the tubing and the annulus. Profile seating nipples and sliding sleeves have a special locking groove and a honed sealbore to allow a flow-control device to lock in the nipple and seal off when installed. By design, the sleeves and nipples will have a smaller ID than that of the tubing string. For this reason, careful consideration must be given to the overall application and completion design when selecting and sizing the various models of profile seating nipples and sleeves. This is especially true in any case in which through-tubing operations or perforating are planned.

Correct application of flow-control accessories can greatly reduce the time and money spent on diagnosing well problems (such as tubing or leaks) should they occur. Strategically placed profile seating nipples above and below the packer aid in isolating the leak to the packer or the tubing string. Once the source of the failure is known, a plan can be formulated to resolve the problem. Not much can be done to fix a packer leak without well intervention; however, special flow-control devices are available to straddle across sections of leaking tubing and deter workovers. In either case, the knowledge gained by being able to use flow-control accessories and devices to perform downhole diagnostics is extremely valuable in planning corrective action to be addressed in the subsequent workover.

Wireline Re-Entry Guides

In some operations, it is necessary to run electric wireline, slickline tools, or coiled-tubing assemblies past the end of the tubing string and into the casing below (Fig. 2.14). Upon retrieving these tools, there may be problems pulling them back into the tubing string if the tubing is run open-ended and unprotected. Sharp edges and square shoulders of pin threads, couplings, or muleshoes can cause the tools to snag or hang up on re-entry. The wireline re-entry guide is run on the end of the tubing string (or the tailpipe below the packer) and is designed to facilitate re-entry into the tubing string of those electric-line or slickline assemblies. It has an internally beveled, bell-shaped ID that eliminates any sharp edges or square shoulders and helps align the tools as they are pulled back up into the tubing string.

Fig. 2.14—Wireline re-entry guide.

Profile Seating Nipples

Profile seating nipples are often referred to as "top no-go," "bottom no-go," and "selective" types. As the names indicate, each has a unique machined profile with a locking groove to accept a flow-control device that is run and installed on slickline or coiled tubing. The profile seating nipple also has a honed and polished sealbore to allow the slickline device to not only land and lock into the nipple, but also to seal off, assuming the accessory item to be installed also has a packing stack.

Profile seating nipples are positioned at strategic locations within the tubing string to allow the accurate placement of slickline plugs, check valves, bottomhole chokes, downhole flow regulators, and bottomhole pressure recorders. At least one profile seating nipple is recommended near the bottom.

Top No-Go Profile Seating Nipple

The "top no-go" nipple accepts a lock assembly with a no-go shoulder located on the lock itself (Fig. 2.15). When the lock assembly is run in the hole, the no-go shoulder on the lock engages or locates on top of the nipple. Once located, the locks are engaged into the locking groove, and the installation process is complete. Care must be taken when designing the completion to ensure that there are no ID restrictions above the nipple to prevent passage of the lock assembly. The "top no-go" nipple is generally run when a single nipple is required in the hole and the largest ID possible is required through the nipple profile. However, more than one "top no-go" may be run if the IDs of the profiles are reduced sufficiently as the nipples progress in the hole to allow passage of the appropriate locking assembly through the nipple located immediately above the intended target nipple.

Fig. 2.15—Top no-go profile nipple and lock assembly.

Bottom No-Go Profile Seating Nipple The "bottom no-go" nipple has a no-go shoulder located in the bottom of the nipple (Fig 2.16). The lock assembly or slickline device landed in this type of nipple locates the nipple by landing on the bottom no-go. Once landed and located in the nipple, the locks can be engaged and the installation completed. Because its ID will not allow passage of any flow-control device through the nipple, the bottom no-go nipple is always run as the lowermost nipple in the completion. Another benefit of having a no-go nipple in the completion is that any other slickline tools or tubing swabs that are lost in the tubing string should not fall to the bottom. The lost equipment usually can be fished out of the tubing string or, in cases when it cannot, the tubing can be pulled to recover the tools.

Fig. 2.16—Bottom no-go profile nipple and lock assembly.

Selective Profile Seating Nipple "Selective" type profile nipples are perhaps the most versatile of the three (Fig 2.17). In such a design, an unlimited number of the same size and type profile seating nipples may be run in the hole because the locking assembly or flow-control device is able to find and selectively land in any of them. In most systems, either the packing stack or a collett indicator is used to help the slickline operator locate the nipple, and alternately picking up and slacking off through the nipple actuates the locks and sets the flow-control device. The benefit of this type system is a larger ID through the completion and fewer slickline accessory items that must be inventoried. Generally, it is still advised that a no-go nipple be run on the bottom of the tubing string to prevent any lost tools from falling into the cased hole below the completion.

Fig. 2.17—Selective profile nipple.

Sliding Sleeves

In oil- and gas-well completions, the sliding sleeve provides a means of establishing communication between the tubing and annulus for fluid circulation, selective zone production, or injection purposes (Fig 2.18). The sliding sleeve is ported from ID to OD and has an internal closing sleeve that can be cycled multiple times using slickline or coiled-tubing shifting tools. When in the open position, the sleeve allows communication from tubing to annulus, and when closed, pressures are once again isolated.

Fig. 2.18—Sliding sleeve (shown in closed position).

The sliding sleeve also incorporates a nipple profile and polished sealbore above and below the ports to allow the landing of various flow-control devices or an isolation tool should the sleeve fail to close. The isolation tool locks into the profile in the upper end of the sleeve, and seal stacks on the tool straddle the ports to achieve isolation. The success of sliding sleeves depends on well conditions. High temperature, sour gas, scale, and sand may cause operational problems in the opening and closing of sliding sleeves.

Blast Joints

The blast joint is used in multiple-zone wells in which the tubing extends past a producing zone to deter the erosional velocity of the produced fluids and formation sand from cutting through the tubing string. In most cases, the blast joint is simply a thick, heavy wall joint of steel pipe; however, there are also more sophisticated designs that use materials such as Carbide^® for severe service applications. Care must be taken when running and spacing out the tubing string to position the blast joint evenly across the open perforations. It is wise to run enough length of blast joint to provide 5 to 10 ft of overlap across the perforations to allow for errors in tubing measurements.

Flow Couplings

Flow couplings are usually the same OD as the tubing couplings and have the same ID as the tubing string with which they are run. They are run above and below any profile seating nipple and sliding sleeve in which it is anticipated that the turbulence created by the flow through the nipple restriction can reach erosional velocity and damage the tubing string. The flow coupling does not stop the erosion; however, because of its thick cross section, it can and will extend the life of the completion because more material must be lost to erosion before failure occurs than in the case of the tubing string alone. Flow couplings are recommended when a flow-control device is to be installed on a permanent basis (i.e., safety valve or bottomhole choke).

Blanking Plugs

Blanking plugs may be landed in profile seating nipples or sliding sleeves to temporarily plug the tubing string, allowing pressure to be applied to the tubing string to test tubing or set a hydraulic packer, or to isolate and shut off the flow from the formation. The basic blanking plug consists of a lock subassembly, a packing stack, and a plug bottom. Each size and type of blanking plug is designed to fit a specific size and type of profile seating nipple or sleeve. Slickline blanking plugs always have an equalizing device incorporated into the design to allow pressure above and below the plug to equalize before releasing the lock from the nipple to prevent the toolstring from being blown up the hole.

Bottomhole Choke

Bottomhole chokes are flow-control devices that are landed in profile seating nipples. The bottomhole choke restricts flow in the tubing string and allows control of production from different zones. It can be used to prevent freezing of surface controls. The choke assembly consists of a set of locks, packing mandrel, packing assembly, and choke bean. The choke bean is available with orifices of varying sizes. The orifice size must be predetermined and sized specifically for the intended application.

Subsurface Safety Systems

If a catastrophic failure of the wellhead should occur, the subsurface safety valve provides a means to automatically shut off the flow of the well to avoid disaster. There are basically two types of downhole safety valves—subsurface-controlled safety valves and surface-controlled subsurface safety valves (SCSSV).^[12]

Subsurface-Controlled Safety Valves

The subsurface-controlled safety valves (often called velocity valves or Storm^® chokes) are wireline retrievable and are installed in standard profile seating nipples in the tubing string below the surface tubing hanger (Fig 2.19). A subsurface safety valve requires a change in the operating conditions at the valve to activate the closure mechanism. There are two models of subsurface controlled safety valves. The velocity valve contains an internal orifice; the orifice is specifically sized to the flow characteristics of the well. The valve is normally open and is closed by an increase in flow rate across the orifice. This creates a pressure drop, or differential pressure, across the valve that causes it to close. The velocity valve reopens when the pressure is equalized across the valve.

Fig. 2.19—Subsurface-controlled safety valve—velocity type.

Another type of subsurface-controlled valve is the gas-charged or low-pressure valve. This valve is normally closed, and the bottomhole pressure must be higher than the preset pressure valve for the valve to remain open. If the flow rate of the well becomes too great and the bottomhole pressure falls below the preset value of the valve, the valve will automatically close. It is reopened by applying pressure to the tubing string to raise the pressure above the preset pressure value of the valve.

For either valve to work properly, the well must be capable of flowing at sufficient rates to close the valve, and the catastrophe must be severe enough to create the conditions necessary to actuate the closing system. The settings of the valves are critical to success, and they must be checked periodically.

SCSSVs

The SCSSVs are also installed in the tubing string below the surface tubing hanger; however, they are controlled by hydraulic pressure through a capillary (control) line that connects to a surface control panel (Fig 2.20). Most SCSSV designs today use a flapper to form a seal. Both elastomeric and metal-to-metal seal designs are available.

Fig. 2.20—Surface-controlled safety valve.

The SCSSV is a normally closed (failsafe) valve and requires continuous hydraulic pressure on the control line to keep it open. The pressure acts upon an internal piston in the valve, which pushes against a spring. When the hydraulic pressure is relieved, the internal spring moves a flow tube upward and uncovers the flapper. The flapper then swings closed, shutting the well in. Ball valves work similarly. The surface control panel, because of a change in flowing characteristics that exceed predetermined operating limits, generally initiates the closing sequence. However, any failure of the system that results in loss of control-line pressure should result in the valve shutting in the well.

To open the SCSSV, the pressure above it must be equalized (usually by pressuring up on the tubing string), and hydraulic pressure must be reapplied to the control line. Some models have a self-equalizing feature and can be reopened without the aid of pressuring up on the tubing. Whether the valve is working or not, most models have a pump-through kill feature that allow fluids to be pumped down the tubing to regain control of the well.

The SCSSV is available in a tubing-retrievable model and a wireline-retrievable type. The wireline-retrievable SCSSV is installed in a special ported safety-valve nipple. The capillary line is connected from the surface control panel to the ported nipple. The hydraulic pressure applied at the surface communicates to the valve through the ported nipple. The wireline-retrievable SCSSV can be pulled and serviced without pulling the tubing string out of the hole. However, because of the design and the use of elastomeric seals, they are somewhat less reliable than the tubing-retrievable version. Because of its smaller ID, the wireline-retrievable valve has a reduced flow area for production to pass through. The reduction in ID can create a pressure drop across the valve and turbulence in the tubing above it. In high-flow-rate wells, the turbulence can lead to erosion of the valve or tubing string. Access to the tubing string below the valve is restricted when the wireline-retrievable SCSSV is installed. The valve must be removed before performing any through-tubing workover or wireline operations below the valve.

The tubing-retrievable model is more robust and offers a larger internal flow diameter. This helps eliminate turbulence and increases production capabilities. It also allows full-bore access to the tubing string below the valve. One disadvantage, in some instances, is its large OD. This may limit the size of tubing that can be run into certain sizes of casing. To service the tubing-retrievable SCSSV, the tubing string must be retrieved. However, to avoid this and extend the life of the completion, it is possible to disable the valve permanently by locking it open. A new wireline-retrievable SCSSV can then be inserted into the sealbore of the retrievable valve, enabling the well to continue production without interruption.

Cased-Hole Applications

Matching the correct equipment to the application is critical to the success of the completion. The equipment must meet or exceed the temperature, pressure, and axial-load conditions created by the various operating modes anticipated over the life of the well, and material selection should match the well environment. Most of all, the completion design should be fit for purpose and meet the production objectives in an efficient and cost-effective manner.^[13]

Single-String LP/LT Wells

Single-string low-pressure (less than 3,000 psi) flowing or injection wells completed at relatively shallow depths (less than 3,000 ft) generally use a retrievable tension packer (Fig 2.21). This is largely out of necessity because the tubing weight is not sufficient to energize the element of a compression set packer, but it is also driven by the economics of the lower cost and simplistic design of the tension set packer. Another consideration in injection applications is that the tubing will contract as cold fluid or gases are pumped into the tubing. This contraction can remove any available set-down weight on a packer that requires constant compressive loads to maintain its packoff and cause the packer to fail.

Fig. 2.21—LP/LT completion.

A wireline entry guide below the packer but above the perforations should be used to facilitate any through-tubing operations that are planned. It is advisable, but not mandatory, to run a profile seating nipple either above or below the packer. The addition of the seating nipple allows a blanking plug to be run to test tubing if a leak occurs, and the nipple will act as a stop should tools be lost in the hole.

Single-String Medium-Pressure/Medium-Temperature Wells

In median pressure and temperature applications, a retrievable compression/tension set versatile landing-condition packer may be used. In these applications, pressures typically will range from 3,000 to 10,000 psi, and bottomhole temperatures (BHTs) may be anywhere between 100 and 300°F (Fig 2.22). These types of tools are generally suited for the higher pressures and temperatures that will be encountered because of the more sophisticated packing-element systems they have. Also, in deeper installations, the addition of a bypass system aids in equalizing the tubing and annular fluids to facilitate retrieval of the packer. In these applications, the longer tubing length presents a different challenge from that in the shallow applications, in which a tension packer would have been used. In flowing wells, the tubing will heat up and elongate and add weight to the packer if landed with compression on the packer, or it will lose tension if landed in tension. In injection wells, the opposite will be true. Careful consideration should be given to these conditions and to future planned pumping or stimulation operations and their effects on tubing movement when making a packer selection.

Fig. 2.22—Single-string medium-pressure/medium-temperature completion.

As for most wells equipped with packers, a wireline entry guide on the bottom of the packer will aid in guiding electric-line and coiled-tubing tools back into the tubing string when performing through-tubing operations. A profile seating nipple is run below the packer to facilitate the running of bottomhole-pressure recorders or to allow a blanking plug to be installed for temporary well control. A second profile seating nipple may be run above the packer to test and verify tubing integrity or to land a bottomhole choke. The addition of a sliding sleeve or gas-lift mandrel with a dummy to the tubing string allows the tubing to be displaced with lighter fluid to bring the well in or circulate kill-weight fluid into the tubing string during subsequent workover operations while the wellhead is flanged up.

Single-String HP/HT Wells

In HP/HT applications, where the pressure can exceed 10,000 psi and temperatures are above 300°F, a permanent sealbore packer is generally used (Fig. 2.23). However, there are some specialized retrievable packers that can work in these applications under limited conditions.

Fig. 2.23—Single-zone permanent packer completion using locator type seal assembly.

The permanent sealbore packers are very versatile and are designed to accommodate the extreme tubing movement and high axial packer-to-tubing forces encountered in HP/HT completions. Tubing-movement calculations should be performed to determine the length changes and stresses on the tubing string in the production, shut-in and treating, or injection modes. Depending on the length changes and stress created on the tubing, a permanent packer with a located (floating) or fixed (anchored) seal assembly may be required.

As before, a wireline-entry guide on the bottom of the packer will aid in guiding electric-line and coiled-tubing tools back into the tubing string when performing through-tubing operations. One, and in some instances two, profile seating nipples are run in the tailpipe below the sealbore packer for landing bottomhole-pressure recorders and facilitating well control during completion and workover operations. The seal assembly may be anchored into the packer or a locator type with additional seal length to accommodate tubing movement. A profile seating nipple is run above the seal assembly for tubing-test purposes or for landing a bottomhole choke.

Multiple-Zone Single-String Selective Completion

Multizone single-string completions with median temperatures and differential pressures will likely use hydraulic-set single-string retrievable packers (Fig 2.24). This style of completion allows all the available zones in the well to be completed at once and produced individually or commingled. Sliding sleeves are positioned between each isolation packer. There is no limit to the number of packers and sliding sleeves that may be run; however, each addition should be justified. When one zone depletes, the workover is accomplished with slickline by landing a blanking plug in the lowermost profile nipple or opening and closing one or more of the sliding sleeves. It should be noted that complex completion designs with multiple packers and accessories cost more and often increase major workover costs significantly. The designer should have a feasible plan for pulling the well’s tubing string(s).

Fig. 2.24—Multiple-zone single-string selective completion.

The hydraulic-set retrievable packers can be run in on one trip and set simultaneously by applying pressure to the tubing against a plug set below the lowermost packer. After setting the packers, the plug may be retrieved and the lowermost zone may be produced or, alternately, one of the sliding sleeves may be opened to produce one of the corresponding upper zones.

A profile seating nipple is run below the lowermost packer to accept a blanking plug (or check valve) to set the hydraulic-set packers and to provide well control for the lower zone. Sliding sleeves are positioned between each packer for zonal isolation. Blast joints should be positioned across the perforations between the isolation packers to reduce the risk of erosion damage to the tubing string from well fluids and produced sand. A sliding sleeve or gas-lift mandrel with dummy may be positioned above the uppermost hydraulic-set packer to aid in circulating kill fluid in the hole or circulating lighter fluid or gas in the tubing to bring the well on production.

Dual-Zone Completion Using Parallel Tubing Strings

The dual-zone completion method generally is used in applications in which it is desirable to produce two zones simultaneously while keeping them isolated from each other (Fig 2.25). In this completion, two strings of tubing are run from the surface to the dual packer. One string terminates at the dual packer, and the other string of tubing extends from the dual packer to the lower single-string packer. The tubing string that produces the upper zone is referred to as the "short string" (or upper tubing), and the tubing string that produces the lower zone is called the "long string" (or lower tubing).

Fig. 2.25—Parallel-string dual-zone completion.

In cases in which the zones are of equal pressure and crossflow is not an issue during the completion stage, a single-string hydraulic-set packer may be used as the lower packer. This allows the entire completion to be run in a single trip and both packers to be set after the wellhead is flanged up.

In parallel string completions in which the zones are subject to crossflow because of unequal pressures, the lowermost single-string packer is generally a sealbore packer. The sealbore packer is set with a temporary plug in place for well control before perforating and running the upper completion. The plug keeps the two zones separated until the upper completion is installed and the wellhead is flanged up.

The upper packer in this example is a hydraulic-set dual-string retrievable packer. Models exist that can be set by applying pressure to the long string, but the more common models require the short string to be pressurized to accomplish packer setting. The decision about which type depends on the various operations that are planned.

A profile seating nipple is run below the lowermost packer and below the dual packer on the short string to accept a blanking plug (or check valve) to set the packer and to provide well control. A sliding sleeve is positioned between the packers for aid in circulating kill-weight fluid in the hole or circulating lighter fluid or gas in the tubing strings to bring the well on production. A blast joint should be positioned across the perforations of the zone between the packers to reduce the risk of erosion damage to the long string from well fluids and produced sand. Profile seating nipples should be run above the dual packer on both strings for well control or testing tubing for well-diagnostic purposes.

Big-Bore/Monobore Completions

In highly prolific reservoirs, tubing of 6 ⁵/₈ in. and larger diameters is required to meet cost-effective production and injection objectives. The use of big monobore-completion techniques can increase production rates significantly while decreasing both capital and operating expenses. The advantages of the big monobore completion systems include the elimination of gas-turbulence areas and restrictions on production while providing access for well-intervention purposes. This can translate to fewer wells required for optimized reservoir production, resulting in a faster return on initial investments and lower long-term operating expense.^[14]

Big monobore completions are basically liner-top completion systems. The key is the large ID tubing that allows increased production rates and provides full-bore access to the production liner. This full-bore access gives the operator the ability to run conventional tools through the tubing to perform remedial work in the production liner without disturbing the completion or pulling the production tubing. There are many styles of monobore completions from which to choose. The selection of the type system that is used depends largely on the pressure integrity, and the pressure capability, of the liner top and intermediate casing string.

In the most basic monobore-completion design (Fig 2.26), the production liner is run and cemented in the hole. At the top of the liner hanger is a polished bore receptacle (PBR) to accept a seal assembly. The production tubing that is used has basically the same ID as the liner. When the completion is run, a seal assembly is run on the bottom of the production tubing and landed in the PBR. The seal assembly and liner top provide the annular barrier for the tubing string. The constraints of this system are that the ID of the polished bore receptacle can become damaged during liner cleanout trips and fail to seal, and the ability of the liner top to hold pressure is totally dependent on the quality of the cement job. Remedial work to the liner may be required before running the completion.

Fig. 2.26—Basic monobore liner-top completion.

A more reliable monobore system (Fig 2.27) will use a packer above the liner top. In this system, the liner is run and cemented as before; however, when the completion is run, a large-bore hydraulic-set permanent packer is installed. The packer will have a PBR located above it, with the tubing seals run in place. There is also a seal assembly on the tailpipe below the packer, which is stabbed into the liner top. The packer provides a more positive annular barrier, and a new PBR has been installed.

Fig. 2.27—Monobore completion with liner-top isolation packers.

Multilateral Completions

Multilateral completion systems allow the drilling and completion of multiple wells within a single wellbore. In addition to the main wellbore, there are one or more lateral wells extending from the main wellbore. This allows for alternative well-construction strategies for vertical, inclined, horizontal, and extended-reach wells. Multilaterals can be constructed in both new and existing oil and gas wells. A typical installation includes two laterals; the number of laterals would be determined by the number of targets, depths/pressures, risk analysis, and well-construction parameters.

Multilateral systems combine the advantages of horizontal-drilling techniques with the ability to achieve multiple target zones. The advantages of horizontal drilling include higher production indices, the possibility of draining relatively thin formation layers, decreased water and gas coning, increased exposure to natural fracture systems in the formation, and better sweep efficiencies. Depending on the type of multilateral design used, the target zones can be isolated and produced independently—or produced simultaneously, if commingled production is allowed or if a parallel string completion is used.

The various degrees of multilateral systems have been categorized by the Technology Advancement of MultiLaterals (TAML), a group of operators and suppliers with experience in developing multilateral technology. The TAML system for multilateral-well classification is based on the amount and type (or absence) of support provided at the lateral junction. There are six industry levels defined by TAML; this categorization system makes it easier for operators to recognize and compare the functionality and risk-to-reward evaluations of one multilateral completion design to another. As the TAML level increases, so does the complexity and cost of the system.^[15]

TAML Level 1

The most fundamental multilateral system consists of an openhole main bore with multiple drainage legs (or laterals) exiting from it (Fig 2.28). The junction in this design is left with no mechanical support or hydraulic isolation. The integrity of the junction is dependent on natural borehole stability; however, it is possible to land a slotted liner in the lateral or the main bore to help keep the hole open during production. The production from a Level 1 system must be commingled, and zonal isolation or selective control of production is not possible. Re-entry into either the main bore or the lateral may be difficult or impossible should well intervention be required in the future.

Fig. 2.28—TAML Level 1: openhole main bore and lateral; unsupported slotted liner or screen may be set in lateral or main bore.

TAML Level 2

This system is similar to Level 1, with the exception that the laterals are drilled off of a cased and cemented main bore (Fig 2.29). The cased main bore minimizes the chances of borehole collapse and provides a means of hydraulic isolation between zones. As with Level 1, there is no actual mechanical support of the lateral junction; however, it is possible to run a slotted liner into the lateral to maintain borehole stability.

Fig. 2.29—TAML Level 2: cased and cemented main bore with an openhole lateral; an unsupported slotted liner or screen may be installed in the lateral.

TAML Level 3

The Level 3 system again uses a cased and cemented main bore with an openhole lateral (Fig 2.30). However, in this design, a slotted liner or screen is set in the lateral and anchored back into the main bore. This system offers mechanical support of the lateral junction, but the advantage of hydraulic isolation is lost, and the zones must be commingled to be produced. The production from the zone below the junction must flow through the whipstock assembly and past the slotted liner to reach the main bore. This system provides easy access into the lateral for coiled-tubing assemblies, but re-entry into the main bore below the junction is not possible.

Fig. 2.30—TAML Level 3: cased and cemented main bore with an openhole lateral; slotted liner or screen is set in the lateral and anchored in the main bore, offering mechanical support of the junction.

TAML Level 4

This system offers both a cased and a cemented main bore and lateral (Fig 2.31). This gives the lateral excellent mechanical support, but the cement itself does not offer pressure integrity at the junction. While the cement does protect the junction from sand infiltration and potential collapse, it is not capable of withstanding more than a few hundred psi of differential. There is a potential for failure if the junction is subjected to a pressure drawdown, as might be experienced in an electrical submersible pump (ESP) application. Zonal isolation and selectivity is possible by installing packers above and below the junction in the main bore. Systems are available that also offer coiled-tubing intervention, both into the lateral and into the main bore below the junction.

Fig. 2.31—TAML Level 4: cased and cemented main bore and lateral; cemented lateral provides mechanical support, but the cement does not provide pressure integrity for the junction.

TAML Level 5

The Level 5 multilateral is similar in construction to the Level 4 in that it has both a cased and a cemented main bore and lateral, which offers the same level of mechanical integrity (Fig 2.32). The difference is that pressure integrity has now been achieved by using tubing strings and packers to isolate the junction. Single-string packers are placed in both the main bore and lateral below the junction and connected by tubing strings to a dual-string isolation packer located above the junction in the main bore. This system offers full access to both the main bore and the lateral. The zones can be produced independent of one another, or the completion can be designed to allow them to be commingled.

Fig. 2.32—TAML Level 5: cased and cemented main bore and lateral; pressure integrity across the junction is achieved through use of tubing and isolation packers.

2.11.6 TAML Level 6 In the Level 6 multilateral system, both mechanical and pressure integrity are achieved by using the casing to seal the junction (Fig 2.33). Cementing the junction, as was done in the Level 4 system, is not acceptable. The Level 6 system uses a premanufactured junction. In one type of system, the junction is reformed downhole. In yet another, two separate wells are drilled out of a single main bore, and the premanufactured junction is assembled downhole.

Fig. 2.33—TAML Level 6: mechanical and pressure integrity at the junction is achieved by using casing to seal the junction.

Operational Well Modes

There are four modes of operation that any given well might experience: shut-in; producing (liquid, gas, or a combination); injecting (hot or cold liquids, or gases); or treating (high, low, or intermediate pressures and volumes). It is important that all planned operations be considered when designing the completion and selecting a packer. While the primary application may be oil or gas production, any subsequent operations (such as acidizing or fracturing the well) and their associated pressure and temperature changes are extremely important to packer utilization success.^[16], ^[17]

Typical temperature vs. depth profiles are illustrated in Figs 2.34 through 2.37. These profiles are similar to those measures in wells operating in the shut-in, producing, injecting, or treating modes.

Fig. 2.34—Shut-in.
Fig. 2.35—Producing.
Fig. 2.36—Injecting.
Fig. 2.37—Treating.

Fig. 2.34 depicts a typical geothermal gradient, with the temperature increasing with depth to that of the BHT. Every time a well is shut in, the operating temperature will begin to move toward the shape of the natural geothermal profile.

Producing-well-temperature profiles for both oil and gas wells are shown in Fig. 2.35. The wellhead temperature of an oil well will be somewhat less than the BHT. The amount of cooling as crude flows to the surface will depend on several factors: the relative amounts of oil and water, the specific heats of oil and water, the flow rate, the gas/liquid ratio, the vertical-flow pressure drop that controls the gas liberated and the attendant cooling effect, and the thermal heat transfer rate from the wellbore.

The temperature profile of a gas well may have a wellhead temperature lower than ambient. In any case, the wellhead temperature of a gas well will depend on the BHT, the flow rate, the pressure drop in the tubing, the specific heat of the gas, and other factors.

Injection-temperature profiles can be quite varied (Fig 2.36). The profile will depend on such factors as the nature of the injection fluid (liquid or gas), the rate of injection, and the injected-fluid temperature (cold or hot liquids or gas, or even steam). Initial temperatures of injected fluids are also subject to seasonal changes. These changes can become more severe depending on the local geography and climate in which the operation is being performed. Injected liquids will tend to have little heat gain or loss as they are pumped down the tubing string, while injected gases will tend to pick up or lose heat to approach the BHT.

While treating is simply a special case of the injection mode and is temporary in nature, it is considered important enough to be discussed separately. As with the liquid-injection profile [for rates above 1 barrel per minute (BPM)], the treating liquid will not pick up any appreciable amount of heat as it moves down the tubing, and the treating temperature is essentially vertical (Fig 2.37).

As illustrated in some examples later, the important thing about these profiles is not their shape but how much the shape and temperature change from one operation mode to another, and how those temperature changes affect the tubing and packer system. It is strongly recommended that anticipated temperature profiles for each operational mode be drawn accurately when planning the various steps of any completion or major workover.

Figs. 2.38 through 2.41 show the pressure profiles of the four modes of well operation. Fig. 2.38 illustrates a typical shut-in well with well-servicing fluid in the wellbore. The slope of the profile and the height to which the fluid level rises on the depth scale (and in the wellbore) will depend on the average reservoir pressure, p_R, and the gradient of the well-servicing fluid. Fig. 2.39 shows the profiles of typical producing oil and gas wells. A liquid-injection profile (Fig. 2.40) is similar to the shut-in profile, the difference being that the bottomhole injection pressure, (p_i)_bh, is greater than the average reservoir pressure, p_R. The wellhead pressure, p_wh, can have any value, from a vacuum to several thousand psi. The gas-injection profile may have a reverse slope on it, or it may have a normal but steep slope, depending on the rate, tubing size, and bottomhole injection pressure.

Fig. 2.38—Shut-in.
Fig. 2.39—Producing.
Fig. 2.40—Injecting.
Fig. 2.41—Treating.

The treating pressure (Fig. 2.41) is a special temporary case of the injection profile. The bottomhole treating pressure, (p_t)_bh, often will be greater than the injection pressure, especially in a fracturing job. The surface pressure will be constrained by the burst strength of the tubing and casing and the safety considerations. The slope of the pressure profile will depend on the tubing size, the treating rates, and the treating pressure downhole, (p_t)_bh.

It is recommended that pressure profiles for each operational mode be drawn for each step of the completion or major workover. As the examples will point out, the importance of pressure changes from one well mode to another and their effects on the tubing and packer system cannot be overemphasized.

Impact of Length and Force Changes to the Tubing String

Changing the mode of a well (producer, injector, shut-in, or treating) causes changes in temperature and pressure inside and outside the tubing. After the packer is installed and the tubing landed, any operational mode change will cause a change in length or force in the tubing string. The resultant impact on the packer and tubing string is dependent on (1) how the tubing is connected to the packer, (2) the type of packer, (3) how the packer is set, and (4) tubing compression or tension left on the packer.

The length and force changes can be considerable and can cause tremendous stresses on the tubing string, as well as on the packer under certain conditions. The net result could reduce the effectiveness of the downhole tools and/or damage the tubing, casing, or even the formations open to the well. Failure to consider length and force changes may result in costly failures of such operations as squeeze cementing, acidizing, fracturing, and other remedial operations.

Potential tubing-length changes must be understood to determine the length of seal necessary to remain packed off in a polished sealbore packer, or to prevent tubing and packer damage when seals are anchored in the packer bore. Potential induced forces need to be calculated to prevent tubing and packer damage, unseating packers, or opening equalizing valves.

There are four factors that tend to cause a change in the length or force in the tubing string^[1], ^[18]: the temperature effect, which is directly influenced by a change in the average temperature of the string; the piston effect, caused by a change in the pressure in the tubing or annulus above the packer acting on a specific affected area; the ballooning effect, caused by a change in average pressure inside or outside the tubing string; and the buckling effect, which occurs when internal tubing pressure is higher than the annulus pressure.

Buckling will shorten the tubing string; however, the others may tend to lengthen or shorten the string depending on the application of the factors. As long as the tubing is allowed to move in the packer bore, the temperature and ballooning effects will only have an impact on tubing-length changes, but if movement is prevented (or restrained) at the packer, these two factors would then create a force.

It is important to remember that a string of tubing landed in any packer is initially in a neutral condition, except for any subsequent mechanical strain or compression loads applied by the rig operator. After the tubing is landed, the factors that cause changes in length or force are always the result of a change in temperature and pressure.

Piston Effect

The length change or force induced by the piston effect is caused by pressure changes inside the annulus and tubing at the packer, acting on different areas (Fig. 2.42). The length and force changes can be calculated as follows:

Fig. 2.42—Areas acted upon by pressure in the tubing and the annulus.

....................(2.1)
and

....................(2.2)

where ΔL₁ = length change because of the piston effect, F₁ = force change because of the piston effect, L = tubing length, E = modulus of elasticity (30,000,000 for steel), A_s = cross-sectional area of the tubing wall, A_p = area of the packer bore (values for common sizes can be found in Table 2.1), A_i = area of the tubing ID, A_o = area of the tubing OD, Δp_i = change in tubing pressure at the packer, and Δp_o = change in annulus pressure at the packer.

Table 2.1

Note that the length change ΔL₁ is a product of L/EA s and the piston force (F₁). The piston force is the sum of two pressures acting on two areas—one for the tubing and one for the annulus. The area acted upon by changes in pressure in the tubing is the cross-sectional area between the area of the packer bore and the area of the tubing ID in square inches (A_p –A_i). The area acted upon by changes in pressure in the annulus is the cross-sectional area between the area of the packer bore and the area of the tubing OD in square inches (A_p –A_o).

Fig. 2.42a shows a large-bore packer with a tubing string that has both a smaller OD and ID than the packer bore. In this instance, annulus pressure causes downward force, while tubing pressure causes an upward force. For a small-bore packer, this situation is reversed (Fig. 2.42b). The force greatest in magnitude will determine the resulting direction of action. An accurate schematic of the tubing and packer bore for each case should be made for proper determination of areas, forces, and the resulting direction of action.

It is possible to eliminate the forces generated on the tubing string by the piston effect by anchoring the seals in the packer bore. In a string that is restrained at the packer from movement in either direction, the piston effect on the tubing string is zero. All the forces are now being absorbed or contained completely within the packer.

Buckling Effects

Tubing strings tend to buckle only when the internal tubing pressure (p_i) is greater than the annulus pressure (p_o). The result is always a shortening of the tubing string, but the actual force exerted is negligible. The decrease in length occurs because of the tubing string being in a spiral shape rather than straight. The tubing-length change is calculated with the following:

....................(2.3)

where ΔL₂ = length change because of the buckling effect; r = radial clearance between tubing OD and casing ID, [(ID_C – OD_t)/2]; A_p = area of the packer bore; A_i = area of the tubing ID; A_o = area of the tubing OD; Δp_i = change in tubing pressure at the packer; Δp_o = change in annulus pressure at the packer; E = modulus of elasticity (30,000,000 for steel); I = moment of inertia of tubing about its diameter [I = π/64 (D⁴ – d⁴, where D is the tubing OD and d is the tubing ID*]; W_s = weight of tubing per inch*; W_i = weight of fluid in tubing per inch*; and W_o = weight of displaced fluid per inch.* (* = values for common tubing sizes can be found in Tables 2.2 and 2.3).

Table 2.2
Table 2.3

Ballooning and Reverse Ballooning

The ballooning effect is caused by the change in average pressure inside or outside the tubing string. Internal pressure swells or "balloons" the tubing and causes it to shorten. Likewise, pressure in the annulus squeezes the tubing, causing it to elongate. This effect is called "reverse ballooning." The ballooning and reverse ballooning length change and force are given by

....................(2.4)
and
....................(2.5)

where ΔL₃ = length change because of ballooning/reverse ballooning, F₃ = force change because of ballooning/reverse ballooning, L = tubing length, γ = Poisson’s ratio (0.3 for steel), E = modulus of elasticity (30,000,000 for steel), Δp_ia = change in average tubing pressure, Δp_oa = change in average annulus pressure, A_i= area of the tubing ID, A_o = area of the tubing OD, and R = ratio of tubing OD to ID (given in Table 2.2) for common tubing sizes and weights.

The ballooning effect will always result in tubing-length changes, but it does not become a force unless the tubing movement is restrained at the packer.

Temperature Effect

Thermal expansion or contraction causes the major length change in the tubing. Heated metal expands, and cooled metal contracts. In a long string of tubing with a temperature change over its entire length, this contraction or elongation can be considerable. The three operational modes that influence temperature effect are producing, injecting (water, gas, or steam), and treating.

The change in tubing length because of temperature effect is calculated as follows:

....................(2.6)

where ΔL₄ = change in tubing length, L = tubing length, β = coefficient of thermal expansion (0.0000069 for steel), and Δt = change in average temperature.

Length changes are calculated readily if the average temperature of the tubing can be determined for the initial condition and then again for future operations. The average string temperature in any given operating mode is approximately one-half the sum of the temperatures at the top and the bottom of the tubing. Thus, in the initial condition, the average temperature would be based upon the mean yearly temperature and the BHT. The mean yearly temperature is generally considered to be the temperature 30 ft below ground level; Δt is the difference between the average temperatures of any two subsequent operating modes.

If tubing movement is constrained, forces will be introduced as a result of the temperature change. The temperature-induced force is

....................(2.7)

where F₄ = pounds force (tensile or compression, depending on the direction of Δt ), A_S = cross-sectional area of the tubing wall, and Δt = change in average tubing temperature.

Net Results of Piston, Buckling, Ballooning, and Temperature Effects

The net or overall length change (or force) is the sum of the length changes (or forces) caused by the temperature, piston, and ballooning effects. The direction of the length change for each effect (or action of the force) must be considered when summing them. It follows that for a change in conditions, the motion (or force) created by one effect can be offset, or enhanced, by the motion (or force) developed by some other effect.

Mosely^[19] presented a method for graphically determining the length and force changes as a result of buckling and ballooning (L₂ , L₃, and F₃). This method is particularly useful on a fieldwide basis, where wells have the same-size tubing, casing, and packers.

When planning the sequential steps of a completion or workover, care should be taken to consider the temperatures and pressures in each step once the tubing and packer systems become involved. By careful selection of the packer bore and use of annulus pressures, one pressure effect (or a combination of pressure effects) could be used to offset the adverse length or force change of another effect.

Combination Tubing/Packer Systems

Uniform completions have been discussed previously (i.e., a single tubing and casing size). Hammerlindl20 presented a method for solving problems with combination completions. A combination completion consists of (1) more than one size of tubing, (2) more than one size of casing, (3) two or more fluids in the tubing and/or annulus, or (4) one or more of these. His paper in particular covered two items not previously addressed by Lubinski et al.18 He includes a direct mathematical method for calculating forces in uniform completions in which tubing movement is not permitted and a method of handling hydraulic packers is set with the wellhead in place.

There are several computer programs available today, modeled after Hammerlindl’s methods, that can easily calculate the length changes and forces generated by changes in temperature and pressure within the wellbore. These programs not only determine critical length changes but also the stresses generated on the tubing string and packer. The use of such programs is recommended. ===Tubing/Packer Forces on Intermediate Packers=== Intermediate packers are an integral part of the tubing string. Examples are dual packers and single-string selective-completion packers. The packer-to-tubing force on the intermediate packer is needed so that wells can be treated through the tubing string. Without proper design, it is possible to shear the release mechanism in the intermediate packer(s) or permanently corkscrew the tubing between the intermediate packer and lower packer, either of which would result in an expensive failure of the completion or workover.

Hammerlindl ^[20] wrote an extension of his^[21] and Lubinski et al. ’s ^[18] earlier works that developed a theory required to solve for the intermediate packer-to-tubing forces. The calculation procedure regarding pressure effects requires working the problem from the lowest packer to the surface in sections. The first section is the tubing between the bottom and second packers. The second section is the tubing between the second and third packers (or the surface if there are only two packers). The procedures are the standard ones for uniform completions. The only changes are those to determine the changes in length as a result of applied forces on the intermediate packers; in addition, the actual and fictitious force-calculation procedures are modified. After the results of each section have been resolved, the sections must be looked at as a whole to determine the net results on the packer(s). Interested readers are referred to Hammerlindl’s 1980 paper^[22] for additional information on the nebulous fictitious force of Lubinski et al.^[18]

Nomenclature

A_i = area of the tubing ID (in.²)

A_o = area of the tubing OD (in.²)

A_p = area of the packer bore (in.²)

A_S = cross-sectional area of the tubing wall (in.²)

E = modulus of elasticity (psi) (30,000,000 for steel)

F₁ = force change (pounds) because of the piston effect

F₃ = force change (pounds) because of ballooning/reverse ballooning

F₄ = pounds force (tensile or compression, depending on the direction of Δt)

I = moment of inertia of tubing about its diameter,I = π/64 (D⁴–d⁴) (in.⁴), where D is the tubing OD and d is the tubing ID

L = tubing length (in.)

p_i = internal tubing pressure

p_o = annulus pressure

(p_i)_bh = bottomhole injection pressure

(p_t)_bh = bottomhole treating pressure

p_R = reservoir pressure

p_wh = wellhead pressure

r = radial clearance between tubing OD and casing ID,[(ID_C–OD_t)/2] (in.)

R = ratio of tubing OD to ID

W_i = weight of fluid in tubing per inch (lb/in.)

W_o = weight of displaced fluid per inch (lb/in.)

W_s = weight of tubing per inch (lb/in.)

β = coefficient of thermal expansion (in./in./°F) (0.0000069 for steel)

ΔL₁ = length change (in.) because of the piston effect

ΔL₂ = length change (in.) because of the buckling effect

ΔL₃ = length change (in.) because of ballooning/reverse ballooning

ΔL₄ = change in tubing length (in.)

Δp_i = change in tubing pressure at the packer (psi)

Δp_o = change in annulus pressure at the packer (psi)

Δp_ia = change in average tubing pressure (psi)

Δp_oa = change in average annulus pressure (psi)

Δt = change in average temperature (°F)

γ = Poisson’s ratio (0.3 for steel)

References

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General References

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.

Glossary²³

Annulus. In a completion, the space between the ID of the casing and the OD of the tubing string.

Borehole. The uncased hole in the earth made by the drill.

Bypass Value. An internal unloaded packer valve that aids in equalization of the tubing and annulus pressures when the packer is released.

Casing. Normally, steel pipe used to seal off fluids from the borehole and prevent the hole from sloughing off or caving in.

Christmas Tree. The assembly of valves at the wellhead through which the well is produced. The valves provide a means of surface control for the well.

Coiled Tubing. A reel of continuous steel tubing mounted on a powered unit that may be run into the wellbore to perform various downhole tasks, such as milling, washing, circulating, and perforating.

Commingled Well. A well producing hydrocarbons or gas from two or more formations through a common string of tubing.

Durometer. The relative hardness of an elastomer.

Elastomer. Any number of various elastic compounds resembling rubber that are used in the construction of packing elements and tubing-seal stacks.

Electric Wireline. A stranded cable with an internal electrical conduit that is used for conveying logging tools, perforating, and setting packers or bridge plugs in a well.

HP/HT. High-pressure/high-temperature well environments, generally considered as being above 300°F and 10,000 psi differential pressure.

Liner. A length of casing used downhole to shut off a water or gas formation so that drilling can proceed. Several liners may be run into a well over the course of the drilling operation. The liner at the bottom of the hole may be referred to as the production liner because it generally sits in the pay zone.

Packer. A sealing device that isolates and contains produced fluids and pressures within the wellbore to protect the casing and other formations above or below the producing zone.

Packer-Rating Envelope. A graphical representation of the safe operating limits of a packer combining both differential pressure and axial loads.

Packing Element. The elastomeric seal found on the OD of a packer that, when energized, forms a pressure-containing barrier between the ID of the casing and the packer body.

Scraper. A mechanical device with scraping blades used to clean the inside of the casing string of scale and cement before installing a packer.

Slickline. A nonelectric wireline used for through-tubing work such as deploying and actuating flow-control devices.

Slip. In a packer, a wedge-shaped piece of metal with wicker teeth that grip the ID of the casing and anchor the packer in place.

Swabbing. The removal of fluid from the tubing string with a special tool on wireline (cable) to reduce the hydrostatic pressure sufficiently and allow the formation to flow into the wellbore.

Tubing. Normally, steel pipe that goes inside the well’s casing and reaches from the surface to the top of the pay zone. Produced or injected fluids and gases are contained inside the tubing string.

Tubing Buckling. The helical corkscrewing of the tubing string caused by internal tubing pressure or excessive compressive loads. If the yield strength of the tubing is exceeded, the buckling can become permanent.

Wellhead. The top of the casing and the attached control and flow valves.

Wireline Junk Basket. A device that is run into the well on electric line, or slickline, to clear the hole of any debris. It is usually run in conjunction with a "gauge ring" that gauges the hole ID to ensure passage of subsequent tools.

Workover. The operations performed on a well to restore or increase production; typically requires pulling the tubing using a workover or drilling rig.

Work String. A string of either drillpipe or tubing used to perform specific maintenance operations downhole (e.g., fishing, milling, squeeze cementing).

SI Metric Conversion Factors

ft	×	3.048*	E – 01	= m
ft³	×	2.831 685	E – 02	= m³
°F		(°F – 32)/1.8		= °C
gal	×	3.785 412	E – 03	= m³
in.	×	2.54*	E + 00	= cm
in.²	×	6.451 6*	E + 00	= cm²
in.³	×	1.638 706	E + 01	= cm³
lbf	×	4.448 222	E + 00	= N
lbm	×	4.535 924	E – 01	= kg
psi	×	6.894 757	E + 00	= kPa

*

Conversion factor is exact.

[r1-1] 1.0 ^1.1 _

[r2-2] _

[r3-3] 3.0 ^3.1 _

[r4-4] _

[r5-5] _

[r6-6] _

[r7-7] _

[r8-8] _

[r9-9] _

[r10-10] _

[r11-11] _

[r12-12] _

[r13-13] _

[r14-14] _

[r15-15] _

[r16-16] _

[r17-17] _

[r18-18] 18.0 ^18.1 ^18.2 _

[r19-19] _

[r21-20] _

[r20-21] _

[r22-22] _

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