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Casing and tubing
Casing and tubing strings are the main parts of the well construction. All wells drilled for the purpose of oil or gas production (or injecting materials into underground formations) must be cased with material with sufficient strength and functionality.
Casing is the major structural component of a well. Casing is needed to:
- Maintain borehole stability
- Prevent contamination of water sands
- Isolate water from producing formations
- Control well pressures during drilling, production, and workover operations
Casing provides locations for the installation of:
- Blowout preventers
- Wellhead equipment
- Production packers
- Production tubing
The cost of casing is a major part of the overall well cost, so selection of casing size, grade, connectors, and setting depth is a primary engineering and economic consideration.
There are six basic types of casing strings:
- Conductor Casing
- Surface Casing
- Intermediate Casing
- Production Casing
- Liner tieback casing
Conductor casing is the first string set below the structural casing (i.e., drive pipe or marine conductor run to protect loose near-surface formations and to enable circulation of drilling fluid). The conductor isolates unconsolidated formations and water sands and protects against shallow gas. This is usually the string onto which the casing head is installed. A diverter or a blowout prevention (BOP) stack may be installed onto this string. When cemented, this string is typically cemented to the surface or to the mudline in offshore wells.
Surface casing is set to provide blowout protection, isolate water sands, and prevent lost circulation. It also often provides adequate shoe strength to drill into high-pressure transition zones. In deviated wells, the surface casing may cover the build section to prevent keyseating of the formation during deeper drilling. This string is typically cemented to the surface or to the mudline in offshore wells.
Intermediate casing is set to isolate:
- Unstable hole sections
- Lost-circulation zones
- Low-pressure zones
- Production zones
It is often set in the transition zone from normal to abnormal pressure. The casing cement top must isolate any hydrocarbon zones. Some wells require multiple intermediate strings. Some intermediate strings may also be production strings if a liner is run beneath them.
Production casing is used to isolate production zones and contain formation pressures in the event of a tubing leak. This casing can either be run through the production zone or is set above the production zone. It may also be exposed to:
- Injection pressures from fracture jobs
- Downcasing, gas lift
- The injection of inhibitor oil
A good primary cement job is very critical for this string.
Liner is a casing string that does not extend back to the wellhead, but is hung from another casing string. Liners are used instead of full casing strings to:
- Reduce cost
- Improve hydraulic performance when drilling deeper
- Allow the use of larger tubing above the liner top
- Not represent a tension limitation for a rig
Liners can be either an intermediate or a production string. Liners are typically cemented over their entire length.
LIner Tieback string
Liner tieback string is a casing string that provides additional pressure integrity from the liner top to the wellhead. An intermediate tieback is used to isolate a casing string that cannot withstand possible pressure loads if drilling is continued (usually because of excessive wear or higher than anticipated pressures). Similarly, a production tieback isolates an intermediate string from production loads. Tiebacks can be uncemented or partially cemented. An example of a typical casing program that illustrates each of the specified casing string types is shown in Fig. 1.
Tubing is the conduit through which oil and gas are brought from the producing formations to the field surface facilities for processing. Tubing must be adequately strong to resist loads and deformations associated with production and workovers. Further, tubing must be sized to support the expected rates of production of oil and gas. Clearly, tubing that is too small restricts production and subsequent economic performance of the well. Tubing that is too large, however, may have an economic impact beyond the cost of the tubing string itself, because the tubing size will influence the overall casing design of the well.
Properties of casing and tubing
The American Petroleum Inst. (API) has formed standards for oil/gas casing that are accepted in most countries by oil and service companies. Casing is classified according to five properties:
- The manner of manufacture
- Steel grade
- Type of joints
- Length range
- The wall thickness (unit weight)
Almost without exception, casing is manufactured of mild (0.3 carbon) steel, normalized with small amounts of manganese. Strength can also be increased with quenching and tempering. API has adopted a casing "grade" designation to define the strength of casing steels. This designation consists of a grade letter followed by a number, which designates the minimum yield strength of the steel in ksi (103 psi). Table 1 summarizes the standard API grades.
The yield strength , for these purposes, is defined as the tensile stress required to produce a total elongation of 0.5% of the length. However, the case of P–110 casing is an exception where yield is defined as the tensile stress required to produce a total elongation of 0.6% of the length. There are also proprietary steel grades widely used in the industry, which do not conform to API specifications. These steel grades are often used in special applications requiring high strength or resistance to hydrogen sulfide cracking. Table 2 gives a list of commonly used non-API grades.
To design a reliable casing string, it is necessary to know the strength of pipe under different load conditions. The most important mechanical properties of casing and tubing are:
- Burst strength
- Collapse resistance
- Tensile strength
API connection ratings
While a number of joint connections are available, the API recognizes three basic types:
- Coupling with rounded thread (long or short)
- Coupling with asymmetrical trapezoidal thread buttress
- Extreme-line casing with trapezoidal thread without coupling
Threads are used as mechanical means to hold the neighboring joints together during axial tension or compression. For all casing sizes, the threads are not intended to be leak resistant when made up. API Spec. 5C2, Performance Properties of Casing, Tubing, and Drillpipe, provides information on casing and tubing threads dimensions.
Coupling internal yield pressure
The internal yield pressure is the pressure that initiates yield at the root of the coupling thread.
PCIY = coupling internal yield pressure, psi,
Yc = minimum yield strength of coupling, psi,
W = nominal outside diameter of coupling, in.,
d1 = diameter at the root of the coupling thread in the power tight position, in.
This dimension is based on data given in API Spec. 5B, Threading, Gauging, and Thread Inspection of Casing, Tubing, and Line Pipe Threads, and other thread geometry data. The coupling internal yield pressure is typically greater than the pipe body internal yield pressure. The internal pressure leak resistance is based on the interface pressure between the pipe and coupling threads because of makeup.
PILR = coupling internal pressure leak resistance, psi,
E = modulus of elasticity, (3.0 × 107 psi for steel)
T = thread taper, in.,
N = a function of the number of thread turns from hand-tight to power-tight position, as given in API Spec. 5B, Threading, Gauging, and Thread Inspection of Casing, Tubing, and Line Pipe Threads,
pt = thread pitch, in.,
Es = pitch diameter at plane of seal, in., as given in API Spec. 5B, Threading, Gauging, and Thread Inspection of Casing, Tubing, and Line Pipe Threads.
This equation accounts only for the contact pressure on the thread flanks as a sealing mechanism and ignores the long helical leak paths filled with thread compound that exist in all API connections.
In round threads, two small leak paths exist at the crest and root of each thread. Buttress threads have a much larger leak path along the stabbing flank and at the root of the coupling thread. API connections rely on thread compound to fill these gaps and provide leak resistance. The leak resistance provided by the thread compound is typically less than the API internal leak resistance value, particularly for buttress connections. The leak resistance can be improved by using API connections with smaller thread tolerances (and, hence, smaller gaps), but it typically will not exceed 5,000 psi with any long-term reliability. Applying tin or zinc plating to the coupling also results in smaller gaps and improves leak resistance.
Round-thread casing-joint strength
The round-thread casing-joint strength is given as the lesser of the fracture strength of the pin and the jump-out strength. The fracture strength is given by
The jump-out strength is given by
Fj = minimum joint strength, lbf,
Ajp = cross-sectional area of the pipe wall under the last perfect thread, in.2,
= π/4 [ (D – 0.1425)2 – d2] , D = nominal outside diameter of pipe, in.,
d = nominal inside diameter of pipe, in.,
L = engaged thread length, in., as given in API Spec. 5B, Threading, Gauging, and Thread Inspection of Casing, Tubing, and Line Pipe Threads,2
Yp = minimum yield strength of pipe, psi,
Up = minimum ultimate tensile strength of pipe, psi.
These equations are based on tension tests to failure on 162 round-thread test specimens. Both are theoretically derived and adjusted using statistical methods to match the test data. For standard coupling dimensions, round threads are pin weak (i.e., the coupling is noncritical in determining joint strength).
Buttress casing joint strength
The buttress thread casing joint strength is given as the lesser of the fracture strength of the pipe body (the pin) and the coupling (the box). Pipe thread strength is given by
Coupling thread strength is given by
Uc = minimum ultimate tensile strength of coupling, psi,
Ap = cross-sectional area of plain-end pipe, in.2 ,
Ac = cross-sectional area of coupling, in.,
= π/4(W 2 – d12).
These equations are based on tension tests to failure on 151 buttress-thread test specimens. They are theoretically derived and adjusted using statistical methods to match test data.
Extreme-line casing-joint strength
Extreme-line casing-joint strength is calculated as
Fj = minimum joint strength, lbf,
Acr = critical section area of box, pin, or pipe, whichever is least, in.2.
When performing casing design, it is very important to note that the API joint-strength values are a function of the ultimate tensile strength. This is a different criterion from that used to define the axial strength of the pipe body, which is based on the yield strength . If care is not taken, this approach can lead to a design that inherently does not have the same level of safety for the connections as for the pipe body. This is not good practice, particularly in light of the fact that most casing failures occur at connections. This discrepancy can be countered by using a higher design factor when performing connection axial design with API connections.
The joint-strength equations for tubing given in API Bull. 5C3, Formulas and Calculations for Casing, Tubing, Drillpipe, and Line Pipe Properties, are very similar to those given for round-thread casing except they are based on yield strength. Hence, the ultimate tensile strength/yield strength (UTS/YS) discrepancy does not exist in tubing design.
If API casing connection joint strengths calculated with the previous formulae are the basis of a design, the designer should use higher axial design factors for the connection analysis. The logical basis for a higher axial design factor (DF) is to multiply the pipe body axial design factor by the ratio of the minimum ultimate tensile strength, Up, to the minimum yield strength, Yp.
Tensile property requirements for standard grades are given in API Spec. 5C2, Performance Properties of Casing, Tubing, and Drillpipe, and are shown in Table 3 for reference along with their ratio.
Special connections are used to achieve gas-tight sealing reliability and 100% connection efficiency (joint efficiency is defined as a ratio of joint tensile strength to pipe body tensile strength) under more severe well conditions. Severe conditions include:
- High pressure (typically > 5,000 psi)
- High temperature (typically > 250°F)
- A sour environment
- Gas production
- High-pressure gas lift
- A steam well
- A large dogleg (horizontal well)
Also, efficiency in flush joint, integral joint or other special clearance applications improves connections. A large diameter (> 16 in.) pipe improves the stab-in and makeup characteristics; galling should be reduced (particularly in CRA applications and tubing strings that will be re-used); and connection failure under high torsional loads (e.g., while rotating pipe) should be prevented.
The improved performance of many proprietary connections results from one or more of these features not found in API connections:
- More complex thread forms
- Resilient seals
- Torque shoulders
- Metal-to-metal seals
The “premium” performance of most proprietary connections comes at a “premium” cost. Increased performance should always be weighed against the increased cost for a particular application. As a general rule, it is recommended to use proprietary connections only when the application requires them. “Premium” performance may also be achieved using API connections if certain conditions are met. Those conditions are:
- Tighter dimensional tolerance
- Plating applied to coupling
- Use of appropriate thread compound
- Performance verified with qualification testing
The performance of a proprietary connection can be reliably verified by performing three steps:
- Audit the manufacturer’s performance test data (sealability and tensile load capacity under combined loading)
- Audit the manufacturer’s field history data
- Require additional performance testing for the most critical applications
When requesting tensile performance data, make sure that the manufacturer indicates whether quoted tensile capacities are based on the ultimate tensile strength (i.e., the load at which the connection will fracture, commonly called the “parting load”) or the yield strength (commonly called the “joint elastic limit”). If possible, it is recommended to use the joint elastic limit values in the design so that consistent design factors for both pipe-body and connection analysis are maintained. If only parting load capacities are available, a higher design factor should be used for connection axial design.
Most casing failures occur at connections. These failures can be attributed to:
- Improper design or exposure to loads exceeding the rated capacity
- Failure to comply with makeup requirements
- Failure to meet manufacturing tolerances
- Damage during storage and handling
- Damage during production operations (corrosion, wear, etc.)
Connection failure can be classified broadly as:
- Structural failure
- Galling during makeup
- Yielding because of internal pressure
- Jump-out under tensile load
- Fracture under tensile load
- Failure because of excessive torque during makeup or subsequent operations
Avoiding connection failure is not only dependent upon selection of the correct connection, but is strongly influenced by other factors, which include:
- Manufacturing tolerances
- Storage (storage thread compound and thread protector)
- Transportation (thread protector and handling procedures)
- Running procedures (selection of thread compound, application of thread compound, and adherence to correct makeup specifications and procedures)
The overall mechanical integrity of a correctly designed casing string is dependent upon a quality assurance program that ensures damaged connections are not used and that operations personnel adhere to the appropriate running procedures.
Connection design limits
The design limits of a connection are not only dependent upon its geometry and material properties, but are influenced by:
- Surface treatment
- Metal plating (copper, tin, or zinc)
- Bead blasting
- Thread compound
- Makeup torque
- Use of a resilient seal ring (many companies do not recommend this practice)
- Fluid to which connection is exposed (mud, clear brine, or gas)
- Temperature and pressure cycling
- Large doglegs (e.g., medium- or short-radius horizontal wells)
|Ac||= cross-sectional area of coupling, in.2|
|Acr||= critical section area of box, pin, or pipe, whichever is least, in.2|
|Ajp||= cross-sectional area of the pipe wall under the last perfect thread, π/4[
( D – 0.1425)2 – d2] , in2
|Ap||= cross-sectional area of plain-end pipe, in.2|
|d1||= diameter at the root of the coupling thread in the power tight position, in.|
|d||= nominal inside diameter of pipe, in.|
|D||= nominal outside pipe diameter, in.|
s modulus (3.0 × 107 psi for steel)
|Es||= pitch diameter at plane of seal, in.|
|F||= constant in transition collapse equation, dimensionless|
|Fj||= minimum joint strength, lbf|
|L||= engaged thread length, in.|
|N||= API-defined thread-turns from Ref. 4 , dimensionless|
|pt||= thread pitch, in.|
|PCIY||= coupling internal yield pressure, psi|
|PILR||= coupling internal leak resistance pressure, psi|
|T||= thread taper, in./in.|
|Uc||= minimum ultimate tensile strength of coupling, psi|
|Up||= minimum ultimate tensile strength of pipe, psi|
|W||= nominal outside diameter of coupling, in.|
|Yc||= minimum yield strength of coupling, psi|
|Yp||= minimum yield stress of pipe, psi|
|φ||= wellbore angle with the vertical, radians|
- API Bull. 5C2, Bulletin for Performance Properties of Casing, Tubing, and Drillpipe, eighteenth edition. 1982. Dallas: API.
- API Spec. 5B, Specification for Threading, Gauging, and Thread Inspection of Casing, Tubing, and Line Pipe Threads, 14th edition. 1996. Dallas: API.
- API Bull. 5C3, Bulletin for Formulas and Calculations for Casing, Tubing, Drillpipe, and Line Pipe Properties, fourth edition. 1985. Dallas: API.
Noteworthy papers in OnePetro
Fowler, E.D. and Taylor, T.E. 1976. How to Select and Test Materials for –75°F. World Oil.
Galambos, T.V. and Ravindra, M.K. 1978. Properties of Steel for Use in LRFD. J. of the Structural Division, ASCE, 104 (9): 1459-1468.
Galambos, T.V., Ellingwood, B., MacGregor, J.G. et al. 1982. Probability-based Load Criteria: Assessment of Current Design Practice. J. of the Structural Division, ASCE, 108 (5): 959-977.
Klementich, E.F. and Jellison, M.J. 1986. A Service-Life Model for Casing Strings. SPE Drill Eng 1 (2): 141-152. SPE-12361-PA. http://dx.doi.org/10.2118/12361-PA.
Load and Resistance Factor Design Specification for Structural Steel Buildings. 1986. Chicago: American Institute of Steel Construction.
Mitchell, R.F.: “Casing Design,” in Drilling Engineering, ed. R. F. Mitchell, vol. 2 of Petroleum Engineering Handbook, ed. L. W. Lake. (USA: Society of Petroleum Engineers, 2006). 287-342.
Ruedrich, R.A., Perkins, T.K., and O'Brien, D.E. 1974. Precise Joint Length Determination Using A Multiple Casing Collar Locator Tool. Presented at the Fall Meeting of the Society of Petroleum Engineers of AIME, Houston, 6-9 October. SPE-5087-MS. http://dx.doi.org/10.2118/5087-MS.
Timoshenko, S.P. and Goodier, J.N. 1961. Theory of Elasticity, third edition. New York City: McGraw-Hill Book Co.
Weiner, P.D. et al.: “Casing Strain Tests of 13 3/8” N-80 Buttress Connections,” JPT (November 1976).
Wooley, G.R., Christman, S.A., and Crose, J.G. 1977. Strain Limit Design of 13 3/8-in., N-80 Buttress Casing. J. Pet Tech 29 (4): 355–359. SPE-6061-PA. http://dx.doi.org/10.2118/6061-PA.