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PEH:Tubing Selection, Design, and Installation

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Petroleum Engineering Handbook

Larry W. Lake, Editor-in-Chief

Volume IV - Production Operations Engineering

Joe Dunn Clegg, Editor

Chapter 3 – Tubing Selection, Design, and Installation

Joe Dunn Clegg, Consultant and Erich F. Klementich, Consultant

Pgs. 105-148

ISBN 978-1-55563-118-5
Get permission for reuse

Tubing is the normal flow conduit used to transport produced fluids to the surface or fluids to the formation. Its use in wells is normally considered a good operating practice. The use of tubing permits better well control because circulating fluids can kill the well; thus, workovers are simplified and their results enhanced. Flow efficiency typically is improved with the use of tubing. Furthermore, tubing is required for most artificial lift installations. Tubing with the use of a packer allows isolation of the casing from well fluids and deters corrosion damage of the casing. Multicompletions require tubing to permit individual zone production and operation. Governmental rules and regulations often require tubing in every well. Permission may be obtained for omission of tubing in special cases (tubingless completions). These special completions typically are flowing wells with relatively small casing. Tubing strings are generally in outside diameter (OD) sizes of 2 3/8 to 4 1/2 in. but may be as large as 20 in. or as small as 1.050 in.

The proper selection, design, and installation of tubing string are critical parts of any well completion. See the chapter on inflow and outflow in this section of the handbook for more information. Tubing strings must be sized correctly to enable the fluids to flow efficiently or to permit installation of effective artificial lift equipment. A tubing string that is too small causes large friction losses and limits production. It also may severely restrict the type and size of artificial lift equipment. A tubing string that is too large may cause heading and unstable flow, which results in loading up of the well and can complicate workovers. The planned tubing must easily fit inside the installed casing. When selecting the material, environmental conditions, the projected corrosivity of the well fluids, the minimum and maximum pressures and temperature, safety aspects, and cost-effectiveness must be considered.

The tubing must be designed to meet all stresses and conditions that occur during routine operation of the well and should have an adequate margin for unusual load conditions. It must withstand the stresses caused by tension, burst, and collapse, and it must resist the corrosive action of well fluids throughout the well life. In addition, the tubing must be handled and installed so that the tubing produces the well without failure or without causing undue operating problems.

Oilfield Tubing

The American Petroleum Institute (API) developed Specifications, Recommended Practices, and Bulletins for steel tubing that meet the major needs of the oil and gas industry.[1][2][3][4][5][6][7][8][9][10][11][12][13]API documents are reviewed and updated every 5 years. This effort continues, and many of these documents (with modifications) have become International Organization for Standardization (ISO) documents. Currently, API and ISO are the international standards for products intended for worldwide use in the petroleum and natural gas industry. The information in API and ISO documents is covered here in some detail. API tubing sizes range from ODs of 1.050 to 4.500 in. For high-rate wells, tubing larger than 4 1/2 in. may be beneficial. API and ISO specifications contain provisions when casing is used as tubing.

In addition to API steel tubing, there are hostile well conditions that may be better served by other materials. There are proprietary steel grades that do not conform to all aspects of the API specifications but are used in the petroleum-producing industry for resistance to weight-loss corrosion, higher strengths, less susceptibility to sulfide stress corrosion cracking (SSC), and wear resistance. Corrosion-resistant alloy (CRA) is a special material that is sometimes used in hostile environments. These special materials are usually expensive but may prove worthwhile over the life of the well; however, CRA tubing does not always eliminate corrosion and may be incompatible with some completion fluids. See ISO 13680 for information on CRA seamless tubes. [14]

Thermoplastic (fiberglass) tubing has been used successfully in corrosive wells. Most thermoplastic tubing has good tension properties and burst resistance, but has relatively small collapse-pressure resistance and poorer wear resistance properties than steel tubing. If temperatures exceed 150°F, a derating service factor may be required. Other metals and materials have been used as tubing but rarely are used in current oil and gas completions either because of their cost or because of limited applicability.

API/ISO Tubing Requirements

API has numerous manufacturing requirements for tubing. The tubing purchaser and designer should be aware of these requirements and of API testing procedures (see API Spec. 5CT). [10] All tubing should meet API minimum requirements. In critical wells, the purchaser may want to receive and review the manufacturer’ s test results. For tubing used in sour wells (wells with H2S content greater than 0.05 psi partial pressure), the specific sour service requirements should be reviewed.

When placing orders for tubing to be manufactured in accordance with API Spec. 5CT, the purchaser should consult API Spec. 5CT Sec. 4. At a minimum, the following requirements should be specified on the purchase order: the specification (API/ISO), quantity, size designation (OD, normally in inches), weight designation, grade and type, end finish (type of connection), range length, seamless or electric weld, delivery date, and shipping instructions.

API tubing specifications contain several provisions that are optional for the purchaser and other stipulations that are by agreement between the purchaser and the manufacturer. Some of these added provisions may be critical to a particular application; therefore, familiarity with API/ISO tubing specifications is needed.

Tubing Connectors/Tubing Joints

API developed specifications for three different connectors for use as tubing joints: external-upset tubing and coupling, non-upset tubing and couplings, and integral-joint tubing. See API Spec 5CT[10] for an illustration of API tubing joint connections. [Figure shown in printed volume, but removed here because API did not provide permission for its use in PetroWiki.] All three connections have tapered and round thread forms with either 8 or 10 threads/in., depending on the size. When casing is used as tubing, long-thread coupling/short-thread coupling and buttress-thread coupling connections can be specified.

The API external-upset-end (EUE) tubing connection is widely used because it is a good, serviceable connection in most wells. The EUE joint has a designed joint strength in tension and pressure strength greater than that of the pipe body and, therefore, is considered a 100% joint efficient connection. For proper lubrication and sealing, the joint requires a good thread compound as outlined in API RP 5A3. [1] To improve the seal performance of API EUE tubing in high-pressure service, a grooved coupling, which accepts nonmetallic seal rings, is sometimes used in the coupling (see API Spec. 5CT SR 13). To provide more clearance, API special clearance EUE couplings are available. API EUE joints come in OD sizes of 1.050 to 4.500 in.

API nonupset (NUE) tubing is used much less than EUE tubing. The cost of NUE is only slightly less than EUE, and the joint strength is substantially less. The coupling joint diameter of NUE is less than EUE, which offers some advantages when clearance is small. API NUE joints are available in sizes of 1.050 to 4.500 in.

API integral-joint tubing is available in OD sizes of 1.315 to 2.063 in. API integral-joint tubing has a 10-round form with a joint strength that is less than the body minimum yield, which restricts its use. The small OD of integral-joint tubing permits its use inside larger tubing strings or in wells as unloading or vent strings. See API Spec. 5CT. [10] for a table listing API tubing size, designations, ODs, wall thickness, grade, and applicable end finish. Additional tables list coupling dimensions, weights, and tolerances for NUE and EUE tubing couplings. The couplings should meet all the minimum requirements outlined in API Spec. 5CT. [10] API Spec. 5B[3] and API RP 5B1[4] cover threading, gauging, and thread inspection. Tables showing EUE tubing thread gage, NUE tubing thread gage, and integral-joint-tubing thread gage dimensions will be found in those sources. [Tables shown in printed volume, but removed here because API did not provide permission for their use in PetroWiki.]

Several proprietary (non-API) connections are available. These joints are useful when greater leak resistance or more clearance is needed than that provided by the standard API joints. These specialty joints obtain their improved properties through unique thread profiles, a torque shoulder, metal-to-metal seals, seal rings, internal upsets, external upsets, integral joints, etc. Tubing reference tables, which summarize the available non-API tubing joints and tubing, are published yearly in trade magazines such as World Oil. Many operators commonly use these proprietary connections in critical wells. Before ordering or using a specific proprietary tubing connection in a critical well, the suitability of such a connection for a particular application must be assessed by either a review of service history or a comprehensive connection test program such as ISO 13679. [15] Sec. 3.7 discusses the use of coiled tubing in some well completions. See API RP 5C7[9] for guidelines on its use. For information on workovers with coiled tubing, review the chapter on workover design and procedures in the Drilling Engineering section of this Handbook.

Process of Manufacture

Tubing made to API specifications uses seamless or electric-weld processes. Seamless pipe is defined as a wrought steel tubular product made without a welded seam. It is manufactured by hot-working steel or, if necessary, by subsequently cold-finishing the hot-worked product to produce the desired shape, dimensions, and properties. Because of the nature of the manufacturing, the cross section of the tubing wall area may be slightly eccentric and the tubing slightly oval and not perfectly straight.

Electric-welded pipe has one longitudinal seam formed by electric-resistance or electric-induction welding without the addition of filler metal. The edges to be welded are pressed together mechanically, and the heat for welding is generated by the resistance to flow of electric current. The weld seam of electric welded pipe is heat-treated after welding to a minimum temperature of 1,000°F or processed so that no untempered martensite remains. See API Spec. 5CT for exceptions. [10]

Both seamless and electric-weld processes are acceptable for most oil and gas services, but some prefer seamless tubulars for sour service because the electric-weld process may result in a slightly different grain structure near the weld. Such differences are usually eliminated if the electric-weld tubing is heat-treated by the quenched-and-tempered process, which is mandatory for API grades L80, C90, T95, and P110. Couplings usually are made of seamless tubular product of the same grade and type as the pipe.

API Grades

API standardized several grades of steel that have different chemical content, manufacture processes, and heat treatments and, therefore, different mechanical properties. API organized these tubing grades into three groups. Group 1 is for all tubing in grades H40, J55, and N80. Group 2 is for restricted-yield tubing grades L80, C90, and T95. Group 3 is for high-strength tubing in seamless grade P110. The API grade letter designation was selected arbitrarily to provide a unique name for various steels. Numbers in the grade designation indicate the minimum yield strength of the steel in thousand psi. API defines the yield strength as the tensile stress required to produce a specific total elongation per unit length on a standard test specimen. API Spec. 5CT[10] includes tables listing the manufacture process and heat treatment of API tubing, the chemical requirements, and the API tubing strength and hardness requirements. [Tables shown in printed volume, but removed here because API did not provide permission for their use in PetroWiki.]

API Tubing Grade Guidelines. The following guidelines apply to the use of API tubing grades.

  • H40—Although an API grade, H40 is generally not used in tubing sizes because the yield strength is relatively low and the cost saving over J55 is minimal. Suppliers do not commonly stock this grade.
  • J55—A commonly used grade for most wells when it meets the design criteria. Some operators recommend it be full-length normalized or normalized and tempered after upsetting when used in carbon dioxide or sour service (ring-worm corrosion problems); however, such heat treatments increase costs. J55 has been the "standard" grade for tubing in most relatively shallow (< 9,000 ft) and low-pressure (< 4,000 psi) wells on land.
  • C75—No longer an official API grade and generally not available. It was developed as a higher-strength material for sour service but was replaced by L80 tubing.
  • N80—A relatively old grade with essentially open chemical requirements. It is susceptible to H2S-induced SSC. It is acceptable for sweet oil and gas wells when it meets design conditions. The quenched-and-tempered heat treatment is preferred. The N80 grade is normally less expensive than L80 grades.
  • L80—A restricted yield-tubing grade that is available in Type 1, 9 Cr, or 13 Cr. Type 1 is less expensive than 9 Cr and 13 Cr but more subject to weight-loss corrosion. L80 Type 1 is used commonly in many oil and gas fields because of higher strength than J55. L80 is satisfactory for SSC resistance in all conditions but may incur weight-loss corrosion. Though popular in the past for CO2- and mild H2S-contaminated wells, Type 9 Cr largely has been replaced by Type 13 Cr. L80 13 Cr tubing has gained popularity because it has good CO 2 -induced weight-loss corrosion resistance properties; however, it is more costly. Type 13 Cr may not be suitable in sour service environments. Typically, the H2S partial pressure should be less than 1.5 psi for safe use of L80 Type 13 Cr. The user should consult National Assn. of Corrosion Engineers (NACE) MR-01-75. [16]
  • C90—A relatively new API grade with two different chemical requirements: Type 1 and Type 2. Only Type 1 is recommended for use in sour service. Typically, this grade must be special ordered; its use has been generally supplanted by T95.
  • T95—A high-strength tubular grade that has different chemical requirements: Type 1 and Type 2. Only Type 1 is recommended for sour service. T95 is SSC resistant but not weight-loss resistant.
  • P110—The old P105 tubing grade, which allowed a normalized and tempered heat treatment, was discontinued, and the casing P110 grade, which is restricted to quench-and-tempered heat treatment, was adopted. This high-strength tubing typically is used in deep sweet oil and gas wells with high pressures. This grade is sensitive to SSC failures unless the temperatures are relatively high (> 175°F). The P110 grade is slightly more expensive than L80 Type 1 but usually less expensive than the C90 and T95 API restricted-yield grades.
  • Q125—Although not a specific API tubing grade, users can order Q125 API tubing. Type 1 chemistry is preferred.

API Markings

API products (tubing, pup joints, and couplings) should be stenciled or a combination of stamping and stenciling as per API Spec. 5CT. The sequence of stencil marking is as follows: manufacturer’ s name, monogram marking, end finish, size designation, weight designation, grade and type, impact test temperature, heat treatment, manufacture process, supplementary requirements, hydrostatic test pressure, type of thread, size of drift, serialization of Grades C-90 and T-95, and plating of coupling. Impact test temperature, heat treatment, supplementary requirements, type of thread, and plating of coupling are included if applicable. API Spec. 5CT[10]includes a table showing color coding used for tubing, pup joints, and coupling.

Tubing Range (Length) and Size Tolerances

API acknowledges two tubing length ranges: Range 1 from 20 to 24 ft and Range 2 from 28 to 32 ft. Range 2 is normally used. Shorter tubing joints (pup joints) are available in 2-, 3-, 4-, 6-, 8-, 10-, and 12-ft lengths with a tolerance of ± 3 in. A complete set of tubing pups with the same connections as the tubing string typically is purchased for each well. API Spec. 5CT[10]includes a table showing the tolerances on dimensions and weight.

API Test Pressures

API requires that plain-end pipe be tested only to 3,000 psi maximum, except by agreement between the purchaser and the manufacturer. Various tubing grades and sizes can be tested hydrostatically to higher values as listed in API Spec. 5CT. The API hydrostatic test pressures specified are inspection test pressures. They do not necessarily have any direct relationship to working pressures but should be considered when establishing design factors. Care should be taken if test pressures are to be exceeded in well operations. The following equation is used to determine the maximum hydrostatic test pressure.


where ph = the 80% hydrostatic test pressure (rounded to the nearest 100 psi); σy = yield strength for pipe body, psi; t = wall thickness, in.; and do = tubing OD, in.

A maximum test pressure during manufacturing of 10,000 psi is imposed because of test equipment limitations. Manufacturers also can conduct hydrostatic tests at a fiber stress not exceeding 80% of the specified minimum yield strength. The hydrostatic test pressures are calculated from Eq. 3.1, except when a lower pressure is required to avoid leakage because of insufficient coupling strength or interface pressure between pipe and coupling threads. The lower pressures are based on formulas given in API Bull. 5C3. [7] The production hydrostatic test pressure for threaded pipe are standard pressures listed in the API tables or a higher test pressure as agreed on by the purchaser and the entity performing the threading.

Tubing Design Factors

A design factor is the specific load rating divided by the specific anticipated load. A design factor less than 1.0 does not necessarily mean the product will fail, and neither does a design factor in excess of 1.0 mean that the product will not fail. As a result, design factors are generally selected on the basis of experience. The designer has the responsibility to select the design factors to suit particular needs and to reflect field experience. The condition of the tubing and the severity of a failure should have a significant effect on the design factors used. Design factors greater than 1.0 are recommended. Table 3.10 contains design factor guidelines.

The internal-yield pressure rating for tubing is based on an API variation of Barlow’ s formula and incorporates a 0.875 factor that compensates for the 12.5% reduction tolerance in wall thickness allowed in manufacturing.


In general, these values should not be exceeded in operation. To be on the safe side, a minimum design factor of 1.25 based on the internal-yield pressure rating is suggested; however, some operators use different values.

In medium to high pressure wells, especially in sour service when L80, C90, and T95 API grades are used, the general stress level in the tubing should not exceed the minimum yield strength for L80 or the SSC threshold stress (generally 80% of the minimum yield strength) for C90 and T95 grades.

The joint or body yield strength for the tension design factor varies widely in practice. A simple approach is to assume a relatively high design factor of 1.6 based on the tubing weight in air and ignore other loading conditions. The calculations for loads in tension are usually for static conditions and ignore dynamic loads that may occur in running and pulling the tubing. They also may ignore collapse loads that reduce tension strengths. The pulling or drag loads are not commonly known. These may be relatively high in directional wells. Typically, the highest loads in tension occur in unsetting the packer during pulling operations. In some cases, shear pins in packers result in substantial loads in unsetting that should be accounted for in design.

The condition of the tubing after several years of service in the well is another unknown that needs to be compensated for either in design or by use of a higher tension design factor. When considering all these factors and making adjustments for drag, shear pins, and collapse pressures, a minimum design factor of 1.25 in tension for pulling is suggested. However, field experience has shown, in general, that tubing in new condition (meets API minimum requirements) can be loaded in tension to its minimum yield joint strength during pulling operations without a tension failure. Tension failures during pulling operations should be avoided because the results usually are costly. It is better to cut or back off the tubing rather than have a tension failure. Table 3.11 shows approximate setting depths for various API grades.

A collapse resistance design of 1.1 is suggested. Collapse resistance for tubing is covered in API Bull. 5C3. [7] This standard provides conservative values for design, assuming the tubing cross section is not abnormally elliptical (oval). Any mechanical deformity in the tubing resulting in an out-of-round cross section may cause a considerable reduction in its collapse resistance. The collapse resistance value for a given tubing size, weight, and grade is based on numerous experimental tests and strength of material equations. The minimum value is designated as the API collapse resistance rating. Collapse ratings are reduced by tension loading. For example, a 23% yield stress in tension reduces the collapse resistance by approximately 14%. The biaxial effect should be used to design the tubing for critical tension and collapse conditions. Fig. 3.2 shows an ellipse of biaxial yield stress.

Tubing Design Considerations

Tubing string design must consider all reasonably anticipated loads imposed during running, producing, stimulation, workovers, and pulling operations. The design must ensure that failures will not occur under these operations; however, the designer typically selects the most economical weight and grade that meets the performance requirements. Computer software is available for tubing design, but the designer must ensure that all design conditions are met adequately.

A reasonable approach must be taken to prevent overdesign. The design need not prevent worst-case scenario failures but rather for all cases that have a reasonable probability of occurring. For instance, assume that there is a shallow tubing leak in which the shut-in tubing pressure is applied in the casing annulus on top of a column of heavy annulus fluid and, subsequently, that the tubing pressure at bottom is reduced quickly to a low value. This event would require tubing with a very high collapse pressure rating. If such a condition is considered to have a reasonable probability of occurring, the tubing string should be designed accordingly or adequate steps should be taken to prevent such a series of events.

The highest tensile loads normally occur at or near the top (surface) of the well. Collapse loads reduce the permitted tension loads, as shown by the biaxial graph in Fig. 3.2, and should be considered when applicable. Fortunately, the casing annulus pressure is normally low at the surface; thus, collapse pressure effects at the surface often can be ignored, but not in all cases. Buoyancy, which reduces the tensile loads, is sometimes ignored on shallow wells, but it should be considered on deeper wells. A condition that frequently determines the required tension yield strength of the tubing occurs when unsetting a partially stuck packer or using a shear-pin-release type packer in wells in which buoyancy is not applicable.

High-burst tubing loads typically occur near the surface with little or no annulus pressure under shut-in tubing conditions or during well stimulation treatments down the tubing. High-burst conditions also may occur deep in the hole with high surface pressures imposed on top of relatively high-density tubing fluid and when the annulus is empty or contains a light-density annulus fluid. Both of these conditions must be evaluated during the design of a tubing string for a specific well.

The burst resistance of the tube is increased because of tension loading up to a certain limit. In tubing- and casing-design practice, it is customary to apply the ellipse of plasticity only when a detrimental effect results. For a conservative design, this increase in burst resistance normally is ignored. Compression loads reduce burst resistance and must be considered when they occur. Such a condition can occur near the bottom of the well with a set-down packer and a relatively high internal tubing pressure and a relatively low annulus pressure. A typical design case in burst is to assume that the tubing is full of produced fluid and that the annulus is empty, which is a common situation for pumped wells.

Because tension loading reduces collapse resistance, the biaxial effect should be used to design for problem regions. A common practice in tubing design is to assume that the tubing is empty and that the annulus is full of fluid. Such conditions are common in low-pressure gas wells or oil wells that may be swabbed to bottom. Typically, the highest collapse pressures are near the bottom of the well. For combination tubing-string design, the collapse and tensile loads should be evaluated at the bottom and top of any tubing size, weight, or grade change.

In directional wells, the effect of the wellbore curvature and vertical deviation angle on the axial stress on the tubing body and couplings/joints must be considered in the tubing design. Current design practice considers the detrimental effects of tubing bending, but the favorable effect (friction while running) is neglected. Wall friction, which is unfavorable for upward pipe movement, generally is compensated for by addition of an acceptable overpull to the free-hanging axial tension. Overpull values are best obtained from field experience but can be calculated with available commercial software computer programs.

Single and Combination/Tapered Tubing Design

Many operators prefer one uniform weight (constant ID) and API grade tubing from top to bottom. Thus, it is not possible to mix different sections of the tubing during running or pulling operations throughout the life of the well. Most relatively shallow (< 9,000 ft), low-pressure (< 4,000 psi) wells have noncombination strings. As the pressures and depths increase, there comes a point at which a higher grade (stronger) or heavier weight (increased wall thickness) tubing must be used to meet load conditions and achieve acceptable design factors. For the same size diameter tubing, a higher grade normally is preferred over an increase in tubing weight. Such a choice is usually less expensive and maintains a constant internal diameter, which simplifies wireline operation inside the tubing.

Unlike casing design, which often has numerous grades and weights in a combination design, tubing design seldom has more than two different grades or weights. Such restriction may increase the cost of the tubing string but simplifies the running and pulling procedures. Deep and high-pressure wells may require more than two weights, grades, or diameters. When more than one grade or weight are used, each should be easily identifiable. To separate different weights and grades, a pup joint or different collar types may be used. For example, one section could use standard couplings and another could use beveled couplings. Painted and stenciled markings on the outside of the tubing are inadequate once the tubing is used because such markings are often obliterated.

The use of two or three different diameter sizes is sometimes advantageous. The larger tubing size may have high-joint-yield strength and permit a higher flow rate. The largest diameter is run on the top and a smaller tubing size on bottom. In such cases, the surface wellhead valves often are sized to permit wireline work in the larger tubing to prevent operational problems. A smaller tubing OD size on bottom may be necessary because of casing diameter restrictions.

Tubing Outside Diameter Limitations

The tubing OD must have adequate clearance with the casing ID. The tubing size selected should permit washover and fishing operations, in case the tubing becomes stuck and requires recovery. A wash pipe must be available that has an outside coupling dimension less than the casing drift diameter and an internal drift diameter that is greater than the tubing coupling OD plus provide a minimum of 1/8-in. clearance for adequate circulation. Also, the tubing OD should permit use of an overshot inside the casing, which limits the tubing OD size and/or the coupling OD. For example, 3 1/2-in. OD tubing with regular API EUE couplings (OD = 4.500 in.) inside 5 1/2-in., 17.00 casing (drift diameter = 4.767 in.) could not be washed over with available wash pipe. Even 3 1/2-in. specialty joint tubing with a joint OD of 3.875 in. would be an impractical, risky washover operation because the couplings would require milling. Nevertheless, special circumstances may require special proprietary tubing in close tolerance applications. Special wash-pipe sizes often can be rented from the tool service companies. The tubing designer should check the success of washover and fishing operations for their particular planned condition and the area of operation.

Multicompletions with parallel tubing strings often result in limiting the tubing and/or coupling size. If two tubing strings are to be run and pulled independently, the sum of the tubing coupling ODs should be less than the casing drift diameter. For example, inside 7-29.00 casing with a drift diameter of 6.059 in., parallel 2 3/8-in. tubing strings with EUE couplings may be planned. In such a case, beveled and special-clearance couplings with an OD of 2.910 in. typically are used. The sum of the two ODs is 5.82 in. Experience shows that if the couplings are beveled (top and bottom), these strings can be run and pulled independently. The auxiliary tubing equipment such as gas lift mandrels and safety valves often cause more clearance problems than the tubing couplings.

If two tubing strings are to be run clamped together, then the sum of the smaller tubing body OD and the OD of the coupling of the second or larger string must be less than the casing drift diameter. In these cases, a full-size drawing of the cross sections of the tubulars used may be helpful. The actual clearance may depend on the clamp design. The use of parallel strings of 3 1/2-in. tubing inside 9 5/8-in. casing is another common practice, and tubing OD limitations must be considered in such installations.

API Minimum Performance Properties of Tubing

Tubing performance properties are found in API Bull. 5C2, [6] and the formulas used in the following examples are found in API Bull. 5C3.[7] API Bull. 5C2, includes tables showing minimum tubing performance properties. [Tables shown in printed volume, but removed here because API did not provide permission for their use in PetroWiki.]

Example 3.1
Design a tubing string for a 9,000-ft hydropressured vertical well that is relatively straight, that will be used to flow 500 BOPD, and that will be completed inside 4 1/2-11.60-K55 casing. The well is to be completed with compression-set type packer and 9.0 ppg inhibited salt water in annulus. An overpull to free the packer of 15,000 lbf is anticipated. A maximum surface-treating pressure of 3,000 psi is expected.

Select 2 3/8-4.70-J55 EUE tubing (see tables in API Bull. 5C2[6] ). The 2 3/8-in. size is suitable for the flowing rates (see the chapter on inflow in this section of the handbook), and larger EUE tubing sizes cannot be run and washed over inside this size and weight casing. Smaller OD sizes of tubing will save no significant investment and will complicate wireline work. Select the lightest standard weight available for the initial design and check to ensure that it meets all design conditions. The J55 grade is the most cost-effective grade available. It typically is used as a first selection for most relatively shallow, low-pressure, and low-rate design cases.

Calculate the fluid gradient, gf.


0.052 psi/ft/lbm/gal is obtained from 0.433 psi/ft/8.32 lbm/gal, which is the conversion factor from lb/gal to psi/ft.

Check design conditions for tension. Calculate the resulting hook load for a 9,000-ft length of tubing in air from


The value of wn is obtained from Minimum Performance Properties of Tubing tables in API Bull. 5C2 [6]. This calculation results in a superimposed tubing tension axial (hook) load at the surface in air of 42,300 lbf.

The weight of the tubing string in a fluid is the tubing weight in air minus the axial buoyancy load(s):


The results of the tubing cross-section metal area,


times the hydrostatic pressure at depth,


are used to calculate the axial buoyancy load,


In this example,


Eq. 3.5 can now be used to calculate the hook load in fluid at surface before setting the packer.


Compare these values to the tubing performance properties. With a joint-yield strength rating, Fj, of 71,700 lbf (see Minimum Performance Properties of Tubing tables in API Bull. 5C2 [6]) the design factor in tension in air is


which is an acceptable design factor in tension in air, whereas the design factor in fluid is


which is an acceptable design factor in tubing considering buoyancy.

Consider pulling conditions. With a stuck packer requiring 15,000 lbf of overpull, Fop, at packer to free, assume no buoyancy contribution because the packer is stuck.


The design factor when considering overpull is


which is an acceptable design factor in tension during pulling operations.

An overpull any greater than 15,000 lbf would not be acceptable because Dt would be less than 1.25.

Check burst and collapse loads and compare to the tubing performance properties. The maximum allowed internal pressure differential is


With an internal-yield burst-pressure rating, pyi, of 7,700 psi (see Minimum Performance Properties of Tubing tables in API Bull. 5C2 [6]) and a wellhead surface pressure, pwh, of 3,000 psi, calculate the design factor in burst.


which is an acceptable design factor in burst and is much higher than the 1.25 suggested.

The minimum collapse pressure without axial stress, pcr, = 8,100 psi (See Minimum Performance Properties of Tubing tables in API Bull. 5C2 [6]). Assume an annulus full of 9.0 ppg fluid and an empty tubing string. With Eq. 3.7, pbh = 9,000 ft × (9.0 × 0.052) psi/ft = 4,212 psi.


which is an acceptable design factor in collapse and is much higher than the 1.1 suggested.

Check burst at bottom of hole under pumping conditions. Assume tubing filled with 9.0 ppg salt water with 100 psi surface tubing pressure and empty annulus.



which is an acceptable design factor in burst.

Select and order tubing material. Order per API Spec. 5CT : 9,000 ft plus 300 ft of 2 3/8;-4.70-J55 EUE-8R, range 2, seamless or electric weld, and one set of pups with standard EUE couplings. In addition, order one container of API-modified thread compound and specify delivery date and shipping instructions.

Example 3.2
Design tubing for relatively deep high-pressure gas well with CO2 and H2S. Assume the following conditions: casing designation = 5 1/2-23.00-L80; measured depth, Dm, = 14,000 ft; true vertical depth, DtV, = 13,000 ft; gas rate = 15 MMcf/D, 10 bbl of condensate per MMcf, 40 ppm hydrogen sulfide resulting in a partial pressure of 0.40 psi for the H2S and a 2% (20,000 ppm) carbon dioxide; pwh = 10,000 psi during stimulation; pbh = 9,000 psi; Tbh = 250°F; Tsf = 125°F; completion fluid weight = 14.0 ppg of inhibited solids free salt water; fluid gradient = 0.728 psi/ft; anticipated drag on tubing when pulling = 5,000 lbf; and packer shear pins setting = overpull = 25,000 lbf.

Because of the anticipated rate of 15 MMcf/D, 2 7/8-in. tubing will permit flow at a significantly higher rate than 2 3/8-in. tubing. The use of 3 1/2-in. tubing is not normally recommended within 5 1/2-in. casing because fishing operations would be difficult. On the basis of experience, the use of 3 1/2-in. tubing rather than 2 7/8-in. tubing would not significantly improve the production rate in this case.

Select the tubing weight and grade. Because surface pressures of 10,000 psi are anticipated, the tubing must have a minimum internal-yield pressure greater than 10,000 psi. With a design factor of 1.25 in burst, the required minimum internal-yield pressure is 12,500 psi (1.25 × 10,000). Because the partial pressure of H2S is 0.40 psi (greater than 0.05 psi), a sour service tubing grade must be used. See NACE MR-01-75. [16]

The obvious choice in the design is 2 7/8-7.90-L80 tubing with an inside diameter (ID) of 2.323 in. (For 2 7/8-in. tubing, the lightest weight of 6.5 lbm/ft for J55 and L80 grades do not have an adequate internal-yield pressure rating.) See Minimum Performance Properties of Tubing tables in API Bull. 5C2 [6]. The 2 7/8-7.90-L80 tubing has a 13,440 psi internal-yield pressure value, which is more than adequate. Because of the high gas pressure, a proprietary connection joint with 100% joint strength and with metal-to-metal seals should be considered.

Investigate tension load conditions. Use Eq. 3.4 to calculate Fa = Lp × wn = 14,000 ft × 7.9 lbm/ft = 110,600 lbf. Use Eq. 3.7 to find the hydrostatic pressure at depth, pbh = 13,000 × 14 × 0.052 = 9,464 psi. Use Eq. 3.8 to calculate the buoyancy effect in 14 ppg fluid, Fb = Am × pbh = 2.254 in. 2 × 9,464 psi = 21,332 lbf. Use Eq. 3.5 to calculate Ff = FaFb = 110,600 lbf – 21,332 lbf = 89,269 lbf. With Fj = 180,300 lbf, use Eqs. 3.9 and 3.10 to calculate Dt = Fj/Fa = 180,300/110,600 = 1.63, which is an acceptable design factor in tension in air, and Dt = Fj/Ff = 180,300/89,269 = 2.02, which is an acceptable design factor in tension considering buoyancy.

Consider pulling conditions. Buoyancy is neglected because the packer is set.


This is the required hook load to unset the packer. Use Eq. 3.12 to calculate Df = Fj/Ps = 180,300/140,600 = 1.28, which is an acceptable design factor in tension.

Check collapse conditions. pcr = 13,890 psi for 2 7/8-7.9-L80 tubing (see Minimum Performance Properties of Tubing tables in API Bull. 5C2 [6]). Assume the casing annulus is filled with 14 ppg fluid with no surface pressure and the tubing pressure is bled off after a plug was set in the bottom of the tubing or a tubing safety valve at bottom is closed, which is a reasonable possibility over the life of the well. Use Eq. 3.7 to calculate pbh = DtV × gf = 13,000 ft × (14.0 × 0.052) psi/ft = 9,464 psi, and use Eq. 3.15 to calculate Df = pcr / pbh = 13,890/9,464 = 1.47, which is an acceptable value. Ensure that the surface annulus pressure is kept less than 3,163 psi [ (13,890/1.1) – 9,464] in the event that the tubing pressure is bled off.

Select and order the tubing material. Request that the tubing meet API Spec. 5CT. Order 14,500 ft of 2 7/8-7.90-L80 Type 13 Cr, Range 2, seamless tubing with a proprietary connection and one set of pup joints with same type connections as tubing. In addition, order all accessories with the same connection and an appropriate thread lubricant. State the required delivery and follow API RP 5C1 on tubing handling.

Example 3.3
Design tubing for a relatively deep sweet-oil well. Make a dual grade tubing-string design (to reduce cost). Assume the following conditions: casing designation = 7-26.00-N80; Dm = 11,000 ft; DtV = 11,000 ft; desired flow rate under gas lift conditions = 1,500 B/D from 10,000 ft; pww = 5,000 psi; pwh = 5,000 psi; pbh = 6,200 psi; Tbh = 200°F; Tsf = 125°F; completion fluid in annulus, wf, = 11.0 ppg of inhibited solids free salt water; fluid gradient, gf, = 0.052× wf = 0.572 psi/ft; packer shear pins setting = overpull (Fop) = 50,000 lbf. The well is relatively straight with small drag forces while pulling, and it is to be circulated with salt water before pulling tubing. Assume Fd = 0.

Select tubing size. Because of the anticipated flow rate, 3 1/2-in. tubing was selected. There is no clearance problem with 3 1/2-in. tubing inside the 7-in. casing. Smaller tubing sizes would result in high friction losses and loss in production rate. Larger tubing sizes would not increase production rates sufficiently and would result in clearance problems inside the 7-in. casing. EUE tubing with modified couplings (see API SR13 seal ring) are selected to provide adequate leak resistance.

Select tubing weight and grade. 3 1/2-9.30-J55 tubing is checked to determine if all design conditions are met.

Check collapse on bottom. pcr = 7,400 psi (see Minimum Performance Properties of Tubing tables in API Bull. 5C2 [6]) for the selected tubing. Assume worst/maximum collapse design condition occurs at bottom where annulus is full of 11 ppg fluid and tubing pressure is zero (possible under completion conditions if well is swabbed down.) Use Eq. 3.7 to calculate pbh = DtV × gf = 11,000 ft × 0.572 = 6,292, and use Eq. 3.15 to calculate Dc = pcr / pbh = 7,400/6,292 = 1.176, which is adequate because 1.1 is acceptable.

Check burst at bottom. Assume casing annulus is empty and tubing is full of produced water. This is possible under gas lift conditions if the annulus injection pressure is bled off with tubing full of produced fluid plus surface wellhead pressure. Use Eq. 3.16 to calculate the burst pressure on bottom, 11,000 × 0.465 + 100 = 5,115 + 100 = 5,215 psi. With an internal-yield pressure for 3 1/2-9.30-J55 of 6,980 psi, use Eq. 3.17 to calculate 6,980/5,215 = 1.34, which is adequate because 1.25 is acceptable. With a maximum stimulation burst pressure at surface of 5,000 psi, use Eq. 3.14 to calculate Db = 6,980/5,000 = 1.396, which is adequate for burst.

Check tension loads at surface. For 3 1/2-9.30-J55 or N80 tubing, use Eq. 3.4 to calculate 11,000 ft × 9.3 lb/ft = 102,300 lbf. Use Eqs. 3.7 and 3.8 to calculate the axial buoyancy load, Fb = 2.590 in.2 × (11,000 × 11.0 × 0.052) psi = 16,296 lbf. Use Eq. 3.5 to calculate the weight in 11 ppg fluid, 102,300 – 16,296 = 86,004 lbf. For 3 1/2-9.30-J55 EUE tubing (100% joint efficiency), Fj = 142,500 lbf. Use Eq. 3.9 to calculate the design factor in tension, Dt, for 3 1/2-9.30-J55 EUE tubing in air, 142,500/102,300 = 1.39, which does not account for necessary overpull. The recommended design factor for weight in air is 1.6; therefore, the design factor is not adequate. A higher grade at top must be used for adequate tension design conditions.

Check worst possible tension design case. Pull at surface to overcome drag and shear pins in packer with no buoyancy effect on tubing above packer. Use Eq. 3.4 to calculate Fa, and use Eq. 3.18 to calculate Ft = 11,000 × 9.3 + 50,000 + 0 = 102,300 + 50,000 = 152,300 lbf. Use


to calculate 152,300 × 1.25 = 190,375 lbf. Use Minimum Performance Properties of Tubing tables in API Bull. 5C2 [6] to find Fj = 207,200 lbf for 3 1/2-9.30-N80 tubing, which is acceptable. Suggest the use of as much J55 as feasible to reduce tubing string cost. For maximum pull load on 3 1/2-9.3-J55, applying the acceptable design factor = 142,500/1.25 = 114,000 lbf. Calculate the maximum feet of 3 1/2-9.30-J55 from


Assume Lp = 6,800 ft for 3 1/2-9.30-J55, and Lp = 11,000 – 6,800 = 4,200 ft for 3 1/2-9.30-N80 tubing. Use Eq. 3.12 to calculate the design factor in tension, Dt, for 3 1/2-9.30-N80, 207,200/152,300 = 1.36, which is acceptable. For Fa = 152,300 lbf, the design factor for 3 1/2-9.30-J55 can be calculated as 142,500/(152,300 – 4,200 × 9.3) = 1.26. Do not exceed the 50,000-lbf overpull load, because this would over load the top of the J55 tubing.

Select and order tubing material. Request that tubing meet API Spec. 5CT. Order 4,400 ft of 3 1/2-9.30-N80 with EUE modified API SR13 beveled couplings and S or EW, range 2; one set of pup joints for 3 1/2-9.30-N80 EUE modified API SR 13 standard couplings; 7,000 ft of 3 1/2-9.30-J55 with EUE modified API SR 13 standard couplings and S or EW, range 2; and one container of API modified thread compound as per API RP 5A3. Specify delivery date and shipping instructions. Some operators might prefer to use L80 rather than N80 3 1/2 tubing and to heat-treat the J55 after upsetting. Both these options increase the cost of the tubing string but may increase the operating life.

Example 3.4
Design tubing for a deep high-pressure gas well. Complete the well with 7-29.00-P110 casing to 13,900 ft and a 5-in. liner (4.031 in. ID) from 13,800 to 16,650 ft. Perforations are to be from 16,530 to 16,570 ft with a permanent packer at 16,500 ft. The bottomhole pressure is estimated to be 14,850 psi with a bottomhole temperature of 340°F and a surface-flowing temperature of 150°F. The well has a surface shut-in pressure of 12,445 psi with a gas gradient, gg, of 0.146 psi/ft. The well initially will produce approximately 10 MMcf/D of gas with a 10 BC/MMcf and 10 BW/MMcf into a 1,000-psia sales system. The gas gravity is 0.7 and contains 1% of nitrogen and 1% carbon dioxide, but the H2S is only 1 ppm. The formation may require acid stimulation with a maximum surface-treating pressure of 10,000 psi. Before perforating, the 17.4 ppg mud will be circulated out and replaced with 10 ppg clean inhibited salt water. After perforating, the well will be killed, the packer and tubing installed, and the annulus filled with 10 ppg clean inhibited salt water. If needed, batch inhibition is planned to protect the tubing from erosion/corrosion.

Select tubing sizes. The type of completion and the size of the tubing string must be selected before making the tubing design. Fig 3.3 shows an inflow performance and outflow performance graph comparing the production with 2 3/8-, 2 7/8-, and 3 1/2-in. tubing strings. This graph shows that a full string of 2 3/8-in. tubing would restrict production significantly; thus, the amount of 2 3/8-in. tubing should be limited. The 2 7/8-in. tubing produces the well near its maximum rate, whereas the use of 3 1/2-in. tubing results in only a small production rate increase and will cost substantially more. The 5-in. liner (4.031 in. ID) will make washover and fishing 2 7/8-in. tubing difficult; therefore, 2 3/8-in. tubing will be used in the liner section of the well. Thus, the top portion of the tubing string will be 2 7/8-in. tubing and the lower portion inside the liner will be 2 3/8-in. tubing.

Now that the approximate sizes of tubing have been determined, the tubing design can be made for tension, collapse, and burst conditions. In general, select the lowest weight per foot and grade that is acceptable. This will normally result in the most economical design.

Select weights and grades. The most common approach in casing and tubing design is to start at the bottom and work your way back to the surface; however, in this high-pressure well, burst is a major consideration. Draw a pressure-depth graph as shown in Fig. 3.4.

To control the shut-in surface tubing pressure of 12,445 psi with a design factor of 1.25, calculate the suggested minimum internal-yield pressure rating required, pyi = 12,445 × 1.25 or 15,556 psi. As the Minimum Performance Properties of Tubing tables in API Bull. 5C2 [6] show, 2 7/8-7.90-P110 is suitable, which has an internal yield of 18,480 psi. API grades C90 and T95 could also be used, but these grades are usually more costly than P110. Because the H2S partial pressure is less than 0.05 psi, the nonsour service grade N80 and P110 can be used.

Because tension reduces the collapse rating and collapse reduces the tension rating, start at the bottom where tension is small and collapse is normally high. Actually, at the bottom (because of buoyancy forces), the tubing is in compression when run in fluid. Draw a schematic tubing depth chart as shown in Fig. 3.5.

Check collapse and tension stresses. Start at the bottom of the hole and work to the surface-checking tension and collapse at any size, weight, or grade change. The tensile load increases moving upward, but the collapse differential pressure decreases.

To calculate the collapse differential, use


With the annulus full of 10 ppg salt water and assuming that the tubing pressure bled to zero, a 0.52 × 16,500 = 8,580 psi collapse differential would result on the bottom of the hole. The 23/8;-4.70-N80 tubing has a collapse of 11,780 psi, resulting in a design factor 11,780/8,580 = 1.37, which is acceptable. Keep the annulus pressure at the surface to a maximum of 1,500 psi in normal operations to avoid possible collapse if the tubing pressure at bottom is bled down to zero.

From above the top of the liner at 13,800 ft to the permanent packer at 16,500 ft, 2,700 ft of 2 3/8-4.70-N80 tubing is tentatively selected. Use 2,800 ft of 2 3/8-in. tubing to avoid interference with the liner top. At 13,700 ft, the tubing size can be increased safely to 2 7/8 in., which will allow a higher flow rate. To simplify wireline operations, the tubing weight for all 2 7/8-in. tubing is the same.

For burst considerations, the design requires a minimum of 7.9 lbm/ft tubing. There is a –11,188 buoyancy force because of the fluid acting on the bottom tubing area. At 13,700 ft, the 2 3/8-in. tubing will have a load of 4.7 lbm/ft × 2,800 ft = 13,160 lbf; however, the tensile load on the tubing is altered slightly because of the tubing area change at 13,700 ft. This results in an axial load at 13,700 ft of 13,160 – 11,188 + 7,929 – 14,690 = –4,789 lbf; thus, the effect of tension on collapse can be neglected because the tubing is in compression.

The maximum burst pressure on bottom may occur during stimulation. Calculate the burst differential from


Assuming a surface-treating pressure of 10,000 psi, the tubing full of acid (gradient = 0.45 psi/ft), and the annulus full of 10 ppg (gradient = 0.52 psi/ft) salt water, use Eq. 3.22 to calculate a burst differential on bottom of 10,000 + 0.45 × 16,500 – 0.52 × 16,500 = 8,845 psi. The use of a design factor of 1.25 in burst will require an internal-yield pressure of 8,845 × 1.25 = 11,056 psi. The 2 3/8-4.70-N80 tubing has an API internal yield of 11,200 psi (see Minimum Performance Properties of Tubing tables in API Bull. 5C2 [6]), which is acceptable.

Burst and collapse conditions now need to be checked at all depths where tubing size, weight, or grade changes are planned. Burst is of primary importance. Check burst at the changed over from 2 3/8 in. to 2 7/8 in. at 13,700 ft. Use Eq. 3.22 to calculate the tubing burst pressure differential during stimulation: 10,000 psi + 0.45 psi/ft × 13,700 ft – 0.52 psi/ft × 13,700 ft = 9,041 psi. The use of a design factor in burst, Db, of 1.25 would require a burst resistance rating of 9,041 psi × 1.25 = 11,301 psi. Thus, at this depth, the 2 3/8, 4.7, N80 tubing is acceptable and 2 7/8, 7.9, N80 tubing is acceptable because it has an API internal pressure rating of 13,440 psi (see Minimum Performance Properties of Tubing tables in API Bull. 5C2 [6].) and a collapse resistance of 13,890 psi. Using a design factor in burst, Db, of 1.25, the maximum burst differential for 2 7/8, 7.9, N80 should not exceed 13,440/1.25 = 10,752 psi.

At the surface during stimulation, 2 7/8-in., 7.9, P110 is required as shown previously. The depth of the crossover from P110 to N80 needs to be calculated. This depth is where the burst pressure differential is equal to 10,752 psi for 2 7/8-in., 7.9, N80 tubing. The worst case condition is during shut-in when a surface pressure of 12,445 psi occurs and the tubing is full of 0.146-psi/ft gas.


where ga is the annulus fluid gradient and gt is the tubing fluid gradient.

Using Eq. 3.23, Lp = (12,445 psi – 13,440/1.25 psi)/(0.52 psi/ft – 0.146 psi/ft) = 4,527 ft. Thus, 2 7/8-in., 7.9, P110 tubing is to be used from the surface to 4,527 ft and 2 7/8;-in., 7.9, N80 tubing is to be used from 4,527 to 13,700 ft. Table 3.13 summarizes the sizes, weights and grades selected.

Calculate the hook load of the tubing string in air and in fluid for the various tubing sizes, weights, and grades.

Hook load in air = 13,700 ft × 7.9 lbm/ft + 2,800 ft × 4.7 lbm/ft = 121,390 lbf.

Hook load in fluid = 121,390 + 7,929 – 14690 – 11,188 = 103,441 lbf.

Body/joint yield strength for 2 7/8, 7.9, P110 = 247,900 lbf.

Body/joint yield strength for 2 7/8, 7.9, N80 = 180,300 lbf.

Body/joint yield strength for 2 3/8, 4.7, N80 = 104,300 lbf.

Maximum allowed hook load at surface for 2 7/8, 7.9, P110 tubing = 247,900/1.25 = 198,320 lbf.

Maximum allowed hook load at surface for 2 7/8, 7.9, N80 tubing = 4,527 × 7.9 + 180,300/1.25=180,003 lbf.

Maximum allowed hook load at surface for 2 3/8, 4.7, N80 tubing = 13,700 × 7.9 + 104,300/1.25= 191,670 lbf.

Thus, the limiting condition is for pulling on the 2 7/8, 7.9, N80 tubing, which allows a hook load at the surface of 180,003 lbf. For this string design, an overpull over the weight in fluid would be 180,003 lbf – 103,441 lbf = 76,562 lbf.

Select and order tubing material. Order the tubing to API 5CT specifications, adding a few hundred feet of each type: seamless, range 2, and a proprietary connection integral joint or threaded and coupled with metal-to-metal seals. Also, order a set of grade P110 pup joints for the 2 7/8-in. tubing with the same proprietary connection integral joint. Order an appropriate thread compound. In addition, one special crossover 2 7/8-7.90 to 2 3/8-4.70 in grade N80 is required. (If an MTC connection is used, the crossover can be a pin × pin with a 2 7/8-N80 coupling.)

All auxiliary well equipment should have the same proprietary connection. Tubing should be hydrostatically tested to 80% of yield pressure. Ensure that proper running procedures are used.

Check with the manufacturer on ways to distinguish between the two grades of 2.875-in. OD tubing. Some operators would select 2 7/8-7.90-P110 and no 2 7/8-7.90-N80 tubing to ensure that accidental mixing of the 2.875-in. OD different grade tubing could not occur and to allow a slightly higher overpull value.

If pressures are greater than 7,000 psi and the depth is greater than 13,000 ft, a pipe-body load analysis should be performed. In sour service for L80, C90, and T95, triaxial stress intensity should be checked and a design factor greater than 1.25 maintained. See ISO 13679 Sec. B.5.2. [15]

Stretch in Tubing

When tubing is subject to an axial load, either in tension or compression, that does not exceed the elastic limit of the material, the stretch or contraction may be determined from


where ΔLt = total axial stretch or contraction, in.; F = superimposed tension or compression axial load, lbf; Lp = length of pipe, ft; E = Young ’ s modulus of elasticity for steel = 30 million psi, which is not affected significantly by tubing grade; and Am = cross-section metal area of pipe, in.2 = 0.7854 × (do2di2).

For multiple sizes or weights, calculate stretch for each section and sum the results. This formula also can be used to determine the length of free pipe by applying a load, F, and measuring the stretch, ΔLt.


Example 3.5
Find free point for a stuck string of 2 7/8-6.50 API steel tubing string in an 11,000-ft well.

With a block-hook load of 60,000 lbf, mark the tubing at the top of rotary table. An additional 10,000-lbf load was picked up and the measured increase in length (stretch) is 20.0 in. Calculate the tubing cross-section area with Eq. 3.6. Am = π × (2.8752 – 2.4412)/4 = 1.812 in.2 Use Eq. 3.25 to calculate Lp = ΔLt × E × Am / (12 × F) = 20.0 in. × 30,000,000 psi × 1.812 in.2 /(12 in./ft × 10,000 lbf) = 9,060 ft.

Tubing Buckling

Tubing buckling must be considered in design. See the chapter on completion design in this section of the Handbook.

Corrosion Considerations

Tubing selection for corrosive environments is a critical design responsibility. Both the inside and outside of the tubing can be damaged by corrosion. Weight-loss corrosion may be a serious problem with conventional tubing strings in wells producing salt water, especially when the water becomes the wetting phase. Acidity caused by the presence of acid gases (CO2 and H2S) normally increases the corrosion rate. When corrosion is minor, the common practice is to use standard API grades and to start batch inhibition when corrosion becomes a problem.

Corrosion/erosion, a major problem with steel tubing, occurs in most high-rate gas-condensate wells in which the gas contains CO2. The CO2 attacks the steel tubing, which creates an iron carbonate film (corrosion product); it is removed from the wall by erosion (impingement of well fluids). Rapid deep pit failure may occur from corrosion/erosion. Increasing fluid velocities and CO2 partial pressure are highly detrimental, as are increasing temperature or increasing brine production. There may be a region of conditions in which frequent batch or continuous inhibition is necessary. Gas wells with CO2 contents higher than 30 psi partial pressure and gas velocities greater than 40 fps normally require continuous or frequent batch inhibition to protect the steel tubing. CRA material is often the most cost-effective means of combatting erosion/corrosion. Some CRA material is subject to failure in brine water environments.

A different type of tubing design problem is SSC. SSC and/or hydrogen embrittlement causes a brittle-type failure in susceptible materials at stresses less than the tubing yield strength. SSC is a cracking phenomenon encountered with high-strength steels in sour (H2S) aqueous environment. Cracking also occurs in austenitic stainless steels in caustic or chloride solutions and mild steel in caustic or nitrate solutions. Susceptibility to attack of most low-alloy steels is roughly proportional to its strength. In terms of hardness, most steels are not subject to SSC failure if the hardness is less than 241 Brinell Hardness number or 23 Hardness-Rockwell C. The potential harmful level of H2S for susceptible materials has been defined as 0.05 psi partial pressure of the H2S gas phase. Carbonate-induced cracking of mild steel can occur in freshwater environments.

Use of inhibition to prevent SSC is not completely reliable because 100% effective coverage of metal surface generally is not achieved. The best solution for tubulars subject to SSC is to use materials that are not subject to SSC failures. In general, follow NACE guidelines. [16]

Dissimilar metals close to each other can influence corrosion. Because corrosion can result from many causes and influences and can take different forms, no simple or universal remedy exists for its control. Each tubing well problem must be treated individually, and the solution must be attempted in light of known factors and operating conditions.

Internal Coatings

Plastic internal coating of a tubing string is sometimes used to deter corrosion or erosion/corrosion in oil and gas wells and may increase tubing life significantly. Such cases may be in high-water-cut oil wells or gas wells with high CO2 partial pressures. These coatings are usually thin wall film applications ( < 0.01 in. thick) that are baked (bonded) onto the inside walls of the tubing string. The film thickness is small enough to allow normal wireline operations. The key to plastic coatings is selecting the correct material and its proper application. Even if the specifications call for "100% holiday free," eventually the coating comes off and holidays occur because of poor application or handling practices, wireline work, caliper surveys, blisters caused by the environment, or other reasons. Coating should not be expected to stop all weight-loss corrosion over the life of the well. Typically, a few holes may develop in time but the bulk of the tubing stays intact. In such cases, workover costs are usually lowered because the tubing often can be retrieved without major fishing operations. Because such coatings increase the smoothness, they reduce pressure drop slightly in high-rate wells and, in some cases, may be helpful in reducing paraffin and scale problems. Besides thin wall film coatings, there are other kinds of interior coating or liners for tubing that have special application. Plastic liners and cement lining have been used successfully when the reduction in ID is not a major problem, primarily for water and carbon dioxide injection tubing or for sour service production.

Tubing Inspection

API tubing is inspected at the mill in accordance with API Spec. 5CT. Physical properties are checked and each length hydrostatically tested, normally to only 3,000 psi in the plain end (unthreaded) condition. Dimensions, weights, straightness, and lengths are also checked. Part of this inspection is to drift all lengths. API Spec. 5CT[10] specifies pipe body inspection requirements. [Table shown in printed volume, but removed here because API did not provide permission for its use in PetroWiki.]

Despite all the API specifications and testing, some tubing defects are still found after delivery; thus, some operators do further inspection of new tubing on critical wells. Used tubing frequently requires inspection. See API RP 5C1. [5]

There are several types of tubing inspection methods that may be beneficial. The common methods of inspecting the tubing currently in use in field operation are visual, calipers, hydrostatic, electromagnetic, magnetic particle, and ultrasonic. Typical defects are outside and inside pits and longitudinal cuts, transverse laps, and mechanical wear and erosion. API recommends that wall thickness measurements be made with pipe wall micrometers, sonic pulse-echo instruments, or gamma ray devices so that the operator can demonstrate the wall thickness within a 2% accuracy. In addition to the body, the tubing upset and threads often require inspection, typically by magnetic powder and use of thread gauges. The following guidelines are suggested for inspection normally at the well location:

  • Visual. The outside of each tubing joint should be inspected visually for mill defects such as seams, slugs, pits, cuts, gouges, dents, or cracks. Each connection should be checked for defective threads and seals. Wall thickness measurements should be considered on critical wells. Internal inspection of tubing requires the use of an optical device and an experienced operator. The operating crews, a manufacturer ’ s representative, the user ’ s personnel, or a service contractor typically does such visual inspections.
  • Calipers. Tubing calipers, both multifingered feeler and electronic types, normally are run while the tubing is installed in the well. Where significant wall loss is observed, the tubing can be pulled and the damaged joints replaced.
  • Hydrostatic. A commonly used inspection method is to test hydrostatically the tubing body and joint internally with water. Test pressures are usually based on 80% of internal yield. Hydrostatic tests of the body are performed on the pipe rack on location and the joints checked while running; however, both can be tested while running. A more stringent test of the joints is obtained by the use of nitrogen with a helium tracer rather than water.
  • Electromagnetic. To find pits, transverse and/or longitudinal defects in the pipe body, electromagnetic search coils, which find magnetic flux leakage, are typically used. This technique works for a uniform body and will typically not find defects in the upset and/or threaded area of the tube. The inspection equipment must be in good working order and an experienced and qualified operator is required. Eddy-Current, another electromagnetic inspection method, is used for grade verification.
  • Magnetic Particle. The magnetic particle inspection methods, both wet and dry, induce either a longitudinal or transverse magnetic field in the tubing and magnetic iron particles dusted on the tubing align at defects. This method is normally used to check the outside surface of upset and end area region for cracks. This method requires a qualified operator, excellent operating environmental conditions, and good operating procedures to be reliable.
  • Ultrasonic. Ultrasonic (high frequency sound) is used to find flaws and imperfections in the pipe body wall. The tool is usually stationary and the pipe is rotated and fed mechanically to examine the entire tubing body. The ultrasonic testing equipment must be in good working condition and an experienced and qualified operator is mandatory.
  • Hardness Testing. The hardness of tubing is often checked when it is to be used in sour service to ensure the tubing meets API Spec. 5CT or to sort mixed grades of tubing.

Inspecting Used Tubing

Used tubing should be classified according to loss of nominal wall thickness. API RP 5C1[17] shows the API color-coding suggestions. The color coding should consist of a paint band of the appropriate color approximately 2 in. wide around the body of the pipe approximately 1 ft from the box end. There is no standard method for calculating performance properties of used tubing. Tubing reconditioning should be done only in accordance with API specifications.

Tubing Handling

Tubing can be damaged during shipment, at the wellsite, and during running and pulling. API RP 5C1[5] Secs. 2 and 3 should be followed closely. For transportation, slightly different procedures are needed to prevent damage depending on whether shipped by water, rail, or truck. Care must be taken in unloading and storage. Thread protectors must be installed properly and rough handling avoided. Tubing should be stacked on racks following proper procedures, and tubing in storage should be inspected periodically and protected from corrosion. In general, the high-strength materials are more susceptible to handling damage.

Numerous factors must be considered when running and pulling tubing. The operating personnel should ensure that good practices are followed. Each length of tubing should be measured and drifted in compliance with API/ISO specifications. The tubing should be handled with thread protectors, which are not removed, until the tubing is ready to stab. Adequate thread cleaning is essential for proper connection makeup and pressure-tight strings. (See MR0175/ISO 15156[16].) Apply a good thread compound but avoid excessive amounts. Collar-type tubing elevators are adequate for API nonbeveled couplings; however, slip-type elevators are recommended when running tubing with beveled couplings, special clearance couplings, and integral joint tubing. Check spider slips to ensure they will not damage the tubing body.

Use of power tongs is necessary to obtain consistent makeup torque. Properly maintained, installed, and calibrated tongs are essential. Follow the API recommended tubing makeup torque in API RP 5C1[5] for nonupset, external-upset, and integral-joint tubing. Follow the manufacturer ’ s recommendations for specialty joints. However, the makeup torque may vary depending on the thread coatings and lubricant type; thus, adjustments in makeup torque values are sometimes required. Torque values listed in API RP 5C1 apply to tubing with zinc-plated or phosphate-coated couplings. For tin-plated couplings, use 80% of the listed values as a guide for proper makeup. To establish the correct torque for API tubing threads, make up the first few joints to the recommended values and examine the connection. There should be no excessive heat, approximately two turns beyond the hand-tight position with all threads buried. Back out the connection (noting torque) and check threads for galling. If needed, adjust torque and repeat. Use the established makeup torque for the remainder of the string. To obtain maximum leak resistance with the API-tapered thread, the pin end of the connection is made up to slightly beyond the point of yielding. Consequently, API EUE connections may make up slightly more on repeated operations. The problem of makeup is to use torque that is sufficient to provide the needed seal without permanently damaging the connection. Good experience has been reported with the torque-turn method with API EUE tubing. In the torque-turn method, the power tongs are calibrated to record both the number of turns and the torque to make up the API tubing coupling to the point of yielding. In many of the proprietary connections, there must be ample makeup torque so that the metal-to-metal seals are energized. Check with the manufacturer for makeup guidelines.

Thread Compound

API-modified thread compound generally has been accepted for a wide range of service conditions over many years. The placement of thread compound at the root of the rounded API threads with the bearing pressure on the thread flanks (the interference fit, power tight makeup) produces the sealing mechanism. The thread compound also provides the lubrication to deter galling. The compound is a mixture of metallic and graphite powders uniformly dispersed in a grease base. API RP 5A3[1] and ISO 13678[18] provide the means for evaluating the suitability of thread compounds for use on API round threads in high-pressure service. For specialty connections, consult with the manufacturer on the proper thread compound. Environmentally nondamaging thread compounds meeting API thread-compound performance requirements are available.

Evaluation Procedures for Tubing Connections

Evaluation procedures for casing and tubing connections tests to be performed to determine the galling tendency, sealing performance, and structural integrity of tubular connections, especially for high-pressure application are under study. See ISO/DIS 13679. [15] Table 3.17 shows example relationships between test classes and service applications. Other relationships may be more appropriate for individual users. Class IV connections are intended for the most severe application, and Class I connections are intended for the least severe application.

Coiled Tubing

Coiled tubing is defined as an electric-welded pipe with one longitudinal seam formed by high-frequency induction welding without the addition of filler material. Coiled tubing is used in special workover cases and as the completion tubing. A common use of coiled tubing is as vent strings, especially in low-rate gas wells. In general, the guidelines for jointed tubing should be followed for coiled tubing. The primary difference between coiled tubing and jointed tubing is that coiled tubing bends because it has no jointed connections (there may be a few butt welds). Coiled tubing is typically thin-wall tubing, which permits spooling and is slightly oval in shape. Coiled tubing has a tendency to coil up during running operations, especially in relatively large casing in deviated holes. As with all tubing operations, coiled tubing’s effectiveness depends on good job planning and equipment design along with proper handling, maintenance, and storage procedures. See API RP 5C7. [9]

Coiled tubing is currently available in 3/4- to 3 1/2-in. OD sizes. The API document covers materials that are high-strength, low-alloy steels with specified minimum yield strengths from 60 to 100 kpsi. A flat strip is formed into a round shape, the heat for welding is generated by the resistance to flow of electric current, and the edge is mechanically pressed together. The length of the flat strip material typically ranges from 1,000 to 3,000 ft, and a spool of coiled tubing may be in excess of 25,000 ft, depending mostly on the tubing diameter.

Tapered strings of coiled tubing can be manufactured by changing the wall thickness of the tubing within the length of a spool while maintaining a constant OD. These tapered designs can be manufactured with different weights (same OD but different ID segments) welded together or tapered sections that have a linear change in thickness over the section. Tapered coiled tubing can increase the operating depths and pressures. The manufacturer should provide mechanical properties of coiled tubing for each spool of coiled tubing.

The chemical requirements for API coiled tubing should conform to those listed in API RP 5C7 Table 3. [9] Table 3.18 shows tensile and harness requirements for coiled tubing. Sizes, grades, and ratings are available in API documents. [Tables shown in printed volume, but removed here because API did not provide permission for their use in PetroWiki.]

Coiled Tubing Design Considerations

When used as the permanent well completion tubing, coiled tubing should be designed for the tension, burst, or collapse stresses that typically occur during well operation. With small sizes ( < 2 3/8 in.) and relatively thin wall thickness, the overpull allowed will be low, which may be a limiting condition if the tubing becomes stuck or when a packer is used. Collapse pressures will be lowered if the tubing is oval. Care must be taken when tensile loads and collapse pressures are high. Burst rating may need to be reduced for the tubing after several cycles of spooling. Consult with the manufacturers and API RP 5C7. [9] With tapered strings, the design is fixed during the manufacturing to meet the well conditions and, once manufactured, the coiled-tubing design cannot be changed. All coiled tubing is subject to weight-loss corrosion, and plans should be made for corrosion inhibition. If thin-wall coiled tubing is used, pitting may result in an early failure of the tube. Because of spooling, which results in exceeding the body-yield strength and changing the steel properties, coiled tubing is not recommended in sour service.


Ai = inner pipe area enclosed by ID, L2, in.2
Am = cross-section metal area of tubing, L2, in.2
di = inside diameter, L, in.
do = outside diameter, L, in.
D = depth, L, ft
Db = design factor in burst
Dc = design factor in collapse
Dm = measured depth, L, ft
Dt = design factor in tension
DtV = true vertical depth, L, ft
E = Young’s modulus of elasticity, m/Lt2, psi
F = axial load, lbf
Fa = tubing hook load in air, lbf
Fb = axial buoyancy load, lbf
Fd = drag load, lbf
Ff = tubing hook load in fluid, lbf
Fj = joint yield strength, lbf
Fjr = minimum joint yield strength required, lbf
Fop = overpull load, lbf
Ft = tubing hook load in unsetting packer, lbf
ga = gradient in the annulus, m/Lt2/L, psi/ft
gg = gas gradient, m/Lt2/L, psi/ft
gf = fluid gradient, m/Lt2/L, psi/ft
gt = gradient in the tubing, m/Lt2/L, psi/ft
gw = water gradient, m/Lt2/L, psi/ft
Lp = length of tubing (L1 + L2...Ln), L, ft
n = number of thread turns
p = pressure, m/Lt2, psi
pi = initial pressure, m/Lt2, psi
pbh = hydrostatic pressure at depth, m/Lt2, psi
pbr = burst-pressure rating, m/Lt2, psi
pca = minimum collapse pressure under axial stress, m/Lt2, psi
pcr = minimum collapse pressure without axial stress, m/Lt2, psi
ph = hydrostatic test pressure, m/Lt2, psi
pwf = bottomhole pressure at the perforations, m/Lt2, psi
pwh = wellhead pressure, m/Lt2, psi
pww = wellhead working pressure, m/Lt2, psi
pyi = internal yield pressure, m/Lt2, psi
t = tube thickness, L, in.
T = temperature, T, °F
Tbh = bottomhole temperature, T, °F
Tsf = surface flowing temperature, T, °F
wf = fluid weight, lb/gal
wn = weight per foot of tubing, lbm/ft
w1, w2...n = weight of Sec. 1, Sec. 2...n, lbm
γg = specific gravity of gas
γo = specific gravity of oil
γw = specific gravity of water
ΔLt = total axial stretch or contraction, L, in.
Δpb = burst differential, m/Lt2, psi
Δpc = collapse differential pressure, m/Lt2, psi
ΔT = change in temperature, T, °F
ρ = density, m/L3, lbm/cu ft
ρs = density of steel, m/L3, 490 lbm/ft3
ρw = density of water, m/L3, 62.4 lbm/ft3
σ = unit stress, m/Lt2, psi
σz = axial stress in tubing, m/Lt2, psi
σt = tangential stress in tubing, m/Lt2, psi
σy = minimum yield strength of pipe, m/Lt2, psi


General References

Allen, T.O. and Roberts, A.P. 1993. Production Operations; Well Completions, Workover and Stimulation, fourth edition, 225. Tulsa, Oklahoma: OGCI.

ISO/ISO 10400, Petroleum and Natural Gas Industries: Formulae and Calculation for Casing, Tubing, Drill Pipe and Line Pipe Properties, first edition. 1993. Geneva, Switzerland: ISO.

ISO/ISO 10405, Petroleum and Natural Gas Industries: Care and Use of Casing and Tubing, second edition. 2000. Geneva, Switzerland: ISO.

ISO/ISO 10422, Petroleum and Natural Gas Industries: Threading, Gauging and Thread Inspection of Casing, Tubing and Line Pipe Threads, first edition. 1993. Geneva, Switzerland: ISO.

ISO/ISO 11960, Petroleum and Natural Gas Industries: Steel Pipes for Use as Casing or Tubing for Wells, second edition. 2001. Geneva, Switzerland: ISO.

ISO/DIS/CD 15156 Petroleum and Natural Gas Industries: Materials for Use in H 2 S Containing Environments in Oil and Gas Production: Parts 1–3, first edition. 2001. Geneva, Switzerland: ISO.

ISO/DIS 15463 Petroleum and Natural Gas Industries: Field Inspection of New Casing, Tubing and Plain-End Drill Pipe, first edition. 2003. Geneva, Switzerland: ISO.

ISO/WD 15464 Petroleum and Natural Gas Industries: Gauging and Inspection of Casing, Tubing and Line Pipe Threads—Recommended Practice, working document. 2003. Geneva, Switzerland: ISO.

ISO/DIS 14692, Petroleum and Natural Gas Industries: Glass-Reinforced Plastic (GRP) Piping: Parts 1–4, first edition. 2002. Geneva, Switzerland: ISO.

SI Metric Conversion Factors

bbl × 1.589 873 E–01 = m3
ft × 3.048* E–01 = m
ft3 × 2.831 685 E–02 = m3
°F (°F – 32)/1.8 = °C
in. × 25.4 E + 00 = mm
in2. × 6.451 6* E + 00 = cm2
lbf × 4.448 222 E + 00 = N
lbm × 4.535924 E–01 = kg
psi × 6.894 757 E + 00 = kPa


Conversion factor is exact.