My Reading on OCTG-API5CT PDF

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My Reading on OCTG- API5CT The Key Points 13th May 2016 Charlie Chong/ Fion Zhang Charlie Chong/ Fion Zhang API5CT Fion Zhang/ Charlie Chong Land Drilling Charlie Chong/ Fion Zhang Land Drilling Charlie Chong/ Fion Zhang Offshore Drilling Charlie Chong/ Fion Zhang Offshore Drilling Charlie Chong/ Fi...

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My Reading on OCTG- API5CT The Key Points 13th May 2016

Charlie Chong/ Fion Zhang

Charlie Chong/ Fion Zhang

API5CT

Fion Zhang/ Charlie Chong

Land Drilling

Charlie Chong/ Fion Zhang

Land Drilling

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Offshore Drilling

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Offshore Drilling

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Charlie Chong/ Fion Zhang

Fion Zhang at Xitang 1st April 2016

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SME- Subject Matter Expert

我们的大学,其实应该聘请这些能干的退休教授. 或许在职的砖头怕被排斥. http://cn.bing.com/videos/search?q=Walter+Lewin&FORM=HDRSC3 https://www.youtube.com/channel/UCiEHVhv0SBMpP75JbzJShqw

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http://www.yumpu.com/zh/browse/user/charliechong http://issuu.com/charlieccchong

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http://greekhouseoffonts.com/

The Magical Book of Tank Inspection ICP

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数字签名 者：Fion Zhang DN：cn=Fion Zhang, o, ou=Academia, email=fion_zhang @qq.com, c=CN 日期：2016.05.16 17:44:01 +08'00' Charlie Chong/ Fion Zhang

闭门练功

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API5CT

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Specification for Casing and Tubing API SPECIFICATION 5CT NINTH EDITION, JULY 2011 EFFECTIVE DATE: JANUARY 1, 2012

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International standards for tubing The American Petroleum Institute (API) has numerous manufacturing requirements for tubing. Many API standards have also been adopted by the International Standards Organization (ISO). This article discusses these standards and considerations when selecting tubing.

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http://petrowiki.org/International_standards_for_tubing

Purchasing tubing The tubing purchaser and designer should be aware of API requirements and testing procedures (see API Spec. 5CT). 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.

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At a minimum, the following requirements should be specified on the purchase order: • • • • • • • • • • •

The specification (API/ISO) Quantity Size designation[ outside diameter (OD), normally in inches] Weight designation Grade and type End finish (type of connection) Range length Seamless or electric weld Delivery date 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. Fion Zhang/ Charlie Chong

Tubing connectors and joints API developed specifications for three different connectors for use as tubing joints:  External-upset tubing and coupling  Non-upset tubing and couplings  Integral-joint tubing API Spec. 5CT includes an illustration of API tubing joint connections. 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, longthread coupling/short-thread coupling and buttress-thread coupling connections can be specified.

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Figure D.1 .— Short round-thread casing and coupling

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Figure D.2 .— Long round-thread casing and coupling

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Figure D.3 .— Buttress-thread casing and coupling

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Figure D.4 .— Non-upset tubing and coupling

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Figure D.5 .— External-upset tubing and coupling

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Figure D.6 .— Rounded nose for external-upset tubing

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Figure D.7 .— Integral-joint tubing

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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. 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.

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API non-upset (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.

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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. The couplings should meet all the minimum requirements outlined in API Spec. 5CT. API Spec. 5B3 and API RP 5B14 cover threading, gauging, and thread inspection.

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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 the following:

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These specialty joints obtain their improved properties through the following: ■ 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. See API RP 5C7 for guidelines on use of Coiled Tubing.

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http://www.worldoil.com/magazine/current-issue

Process of manufacture Tubing made to API specifications uses (1) seamless SMLS or (2) electricweld processes EW. 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 (540°C) or processed so that no un-tempered martensite remains. See API Spec. 5CT for exceptions

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Both seamless and electric-weld processes are acceptable for most oil and gas services, but some prefer seamless tubular 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 (480°C), 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.

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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. ■ Group 4: All casing in Grade Q. 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 (Ksi) . API defines the yield strength as the tensile stress required to produce a specific total http://www.ndt.net/article/ENDTdays2007/nde_for_safety/appendix2.pdf elongation per unit length on a standard test specimen. (Rt0.5)

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API tubing grade guidelines The following guidelines apply to the use of API tubing grades.

Group 1 ■ 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. Fion Zhang/ Charlie Chong

■ N80—A relatively old grade with essentially open chemical requirements. It is susceptible to H2S-induced SSC (acronym). 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.

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Group 2 ■ 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 weightloss 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 CO2 -induced weightloss 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. Fion Zhang/ Charlie Chong

■ 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.

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Group 3 ■ 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.

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Table C.4 .— Chemical composition, mass fraction (%)

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Table C.4 .— Chemical composition, mass fraction (%) a The carbon content for L80 may be increased up to 0,50 % maximum if the product is oil-quenched. b The molybdenum content for Grade C90 Type 1 has no minimum tolerance if the wall thickness is less than 17,78 mm. c The carbon content for R95 may be increased up to 0,55 % maximum if the product is oil-quenched. d The molybdenum content for T95 Type 1 may be decreased to 0,15 % minimum if the wall thickness is less than 17,78 mm. e For EW Grade P110, the phosphorus content shall be 0,020 % maximum and the sulfur content 0,010 % maximum. NL = no limit. Elements shown shall be reported in product analysis.

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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 ■ End finish ■ Weight designation ■ Impact test temperature ■ Manufacture process ■ Hydrostatic test pressure ■ Size of drift ■ Serialization of Grades C-90 and T-95

■ Monogram marking ■ Size designation ■ Grade and type ■ Heat treatment ■ Supplementary requirements ■ Type of thread ■ Plating of coupling

Impact test temperature, heat treatment, supplementary requirements, type of thread, and plating of coupling are included if applicable. API Spec. 5CT[1] includes information on color-coding used.

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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.

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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.

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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. 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. 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.

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Nomenclature

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Tubing inspection and handling 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.

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http://petrowiki.org/Tubing_inspection_and_handling

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. The following are also checked: ■ Dimensions ■ Weights ■ Straightness ■ Lengths ■ Part of this inspection is to drift all lengths. Despite all the American Petroleum Institute (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.

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Inspection methods 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 ■ Ultrasonic

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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:

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■ 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.

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■ 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 inte...