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Introduction 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. 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. 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 This effort continues, and many of these documents (with modifications) have become International Organization for Standardization (ISO) documents.
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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. Pipe strength * 3 API connection ratings * 3.1 Coupling internal yield pressure * 3.2 Round-thread casing-joint strength * 3.3 Buttress casing joint strength * 3.4 Extreme-line casing-joint strength * 4 Proprietary connections * 5 Connection failures * 6 Connection design limits * 7 Nomenclature * 8 References * 9 See also * 10 Noteworthy papers in OnePetro * 11 External links * 12 General references * 13 Category Casing is the major structural component of a well. 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. 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 ofdrilling fluid).
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Inspection of tubing when received and following use are important to ensure that defects or wear do not prevent the tubing from performing as designed. Proper handling, both in transit and on site, are critical to avoiding damage to the tubing. This article provides an overview of inspection and handling considerations for tubing. API tubing is inspected at the mill in accordance with API Spec. Physical properties are checked and each length hydrostatically tested, normally to only 3,000 psi in the plain end (unthreaded) condition.
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Designing the tubing for a well requires consideration of strength, load, performance, stretch, corrosion, coatings and many other factors. This page introduces each of these factors and includes some example tubing designs. 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 1 contains design factor guidelines. * The internal-yield pressure rating for tubing is based on an American Petroleum Institute (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 minimumyield strength for L80 or the sulfide stress corrosion cracking (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.
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Summary Carbon-steel oil-country tubular goods, such as API 5AC Grade L-80, combine high strengths for deep-well applications with restricted hardness for resistance to sulfide stress-cracking in sour wells. Despite these general characteristics, field experience with such tubulars has not been completely trouble-free. Problems have been encountered with hardness control and testing. Metallurgical factors involved with heat treatment and upsetting have affected tubular performance. Problems associated with threaded connections and tool damage have occurred. Special considerations are required for electrical-resistance-welded (ERW) tubulars, field welding, and completion operations. Introduction Carbon steels generally contain only incidental amounts of alloying elements other than carbon, manganese, and silicon. Such tubulars have overwhelmingly dominated oil-industry needs for downhole casing and production tubing. With increased interest in deep hydrocarbon reserves, higher-strength tubulars have been required. Higher strengths also provide increased collapse resistance while maximizing wellbore diameter. However, a major limitation to the use of high-strength carbon-steel tubulars in sour wells (i.e., wells that contain more than 0.05-psia [0.35-kPa] hydrogen sulfide) is sulfide stress-cracking (SSC). This phenomenon is the cracking failure of steels under tensile loading in the presence of aqueous hydrogen sulfide. Although many factors influence the occurrence of SSC, increased steel strength and hardness generally result in decreased SSC resistance. Historically, SSC has been minimized by restricting carbon-steel maximum hardness to 22 Rockwell C (HRC). This practice has formed the basis for carbon-steel restrictions detailed in NACE Standard MR-01-75. The hardness restriction effectively limits the specified minimum yield strength (SMYS) of carbon steels to a maximum of about 85 ksi [586 MPa]. API tubulars within this SMYS limitation include Grades C-75 and L-80. Inclusion of hardness restrictions in API Specification 5AC on Grade L-80 have resulted in widespread use of this tubular grade in sour service because of easier hardness testing compared with tensile testing. Grade L-80 is further required to have quench-and-temper heat treatment, which results in increased SSC resistance. Proprietary versions of Grade L-80, referred to as Modified L-80, have been developed by manufacturers. These steels often offer enhanced collapse resistance or tighter hardness/ chemistry restrictions but generally maintain the carbon-steel classification and applicability to sour production. production. L-80-type (API 5AC L-80 and Modified L-80) tubulars offer high strength, good SSC resistance, and relative economy. Higher-strength tubulars (C-85, C-90, and C-100) can be obtained by alloying with chromium and molybdenum. However, heat treatment of these materials is critical and SSC resistance generally must be ensured by lengthy laboratory tests. Practically, Grade L-80 is probably at the upper strength limit for acceptable SSC resistance in carbon steels. Because of this, problems are encountered when such tubulars are used in sour service. This paper describes some of these problems, which generally pertain to SSC resistance. Internal corrosion, most often controlled by batch or continuous inhibitor treatments, is not substantially addressed.