The following guidelines are based on the National Association of Corrosion Engi-neer's (NACE) recommended practices for coated tubing, many of which also apply to lined tubing.
Note Lined tubing is more common in injection wells rather than in producing wells.
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Caution At times, it is impossible or impractical to follow the guidelines given below. If so, expect damage to the coating and premature failure of the tubing. Even when following these guidelines, expect some damage to the coating.• Clearly identify those wells with coated or lined tubing and coated accessories in the well files, in workover procedure sheets, and at the wellsite. Include the coating/lining type and installation date.
• Make personnel aware that the well has coated or lined tubing so that they take proper precautions.
• Use rod guides in rod-pumped wells.
• When practical, install IPC tubing following completion of wireline work, perforating, cementing, etc.
• When a workover requires fishing, squeezing, drilling, or caustic or acid treat-ments, pull the IPC tubing and use a work string, if possible.
• Do not use a coated string as a work string if that string is later intended to be production or injection tubing in a corrosive well.
• If caustic or acid treatments through the IPC tubing are unavoidable, use the lowest possible concentrations of acid or caustic and minimize contact time with the coating.
– Do not shut in wells with unspent acid or caustic in the tubing.
– Consult the coating/lining manufacturer or the coatings applicator for information about coating chemical resistance.
– Keep records in the well file of chemical treatments through coated or lined tubing and accessories.
• Because severe corrosion can occur at locations of major coating damage caused by wireline tools, avoid wirelining through IPC tubing. (Using a work string may save your coated tubing.)
• If wireline work through IPC tubing is unavoidable, follow these procedures:
– Inform the wireline operator that the well has coated tubing.
– Use streamlined wireframe tools, sinker bars, and rope sockets with smooth, padded contours. Do not use angular or sharp-edged tools.
– Use single-strand, coated, nonbraided wireline. If you must use braided line, make sure it does not have splices or burrs, which tear the coating.
– Keep wireline speeds—both going into and coming out of the hole—at less than 100 feet per minute. The Company recommends a reduced speed of 50 feet per minute.
– Maintain a stiff line with weight on the indicator. Do not let the tool free-fall.
– Provide special protection—such as elastomeric shrink sleeves or plastic coating—for fishing necks, pressure bombs, temperature tools, etc. Use sufficient stand-off pieces in the tool string.
– Avoid knuckle joints, knuckle jars, tubing end locators, wireline grabs, explosive jars, paraffin cutters, or scrapers.
– Use swaging tools rather than gage cutters.
– If possible, avoid swabbing through IPC tubing strings. If unavoidable, swab as slowly as possible because the swab itself is usually braided line.
(Using a slick line would be better.) Swabs should be flexible, fabric-rein-forced, or all rubber; they should not be wire-reinforced. Use double cups or double mandrels, or both.
– Try to avoid downhole caliper surveys. If unavoidable, use calipers with feelers designed not to cut, mill, or damage the coating.
• If possible, avoid coil tubing workovers in coated tubing. If unavoidable, use plastic or aluminum centralizers and carefully manipulate the coil tubing. Do not use aluminum with acid or caustic because it will corrode severely.
• When hydrotesting IPC tubing, advise the testing company that the well has coated tubing. Obtain special hydrotest tools with rubber-encapsulated parts (seal rings). As an alternative, consider external pressure-testing devices.
• With coated tubing and accessories in gas service, depressure at a rate no greater than 2,000 psi per hour.
• Train crews involved in drilling, workover, pulling, wireline, and other field work in the proper handling of coated or lined tubing and accessories. Films, seminars, and other aids are available in the industry, and vendors are generally willing to provide training.
780 References
1. Boyd, J.L. and Al Siegmund. “Plastic Coated Tubular Goods: Proper Selection, The Key to Success.” NACE Paper 214: Corrosion ‘89.
2. L. J. Klein. “Database Package: Coatings for Downhole Tubular.” CRTC Mate-rials Engineering File 6.30. Chevron Corporation. March 5, 1990.
3. Mitchell, R.K., “Coated Tubular Testing, Field Test Results, Hobbs Division,”
June 18, 1987 and August 27, 1987.
4. Strickland, L.N., “Mitigation of Tubing and Mandrel Failures in High Volume Gas Lift Oil Wells, Thompson Field, Ft. Bend, TX.” NACE Paper 70:
Corrosion 1992.
5. Turnipseed, S.P. Internal Plastic Coatings Qualification Tests: Interim Report.
Chevron Corporation. April 15, 1992.
6. ———. Final Report. Chevron Corporation. December 16, 1992.
7. American Petroleum Industry. Recommended Practice for Application of Cement Lining to Steel Tubular Goods, Handling, Installation and Joining.
API RP 10E. Washington, DC.
8. ———. Specification for PVC Lined Steel Tubular Goods. API 15LT.
Washington, DC.
9. ———. API RP 5A5, Section 4.8, National Association of Corrosion Engi-neers. Care, Handling, and Installation of Internally Plastic-Coated Oilfield Tubular Goods and Accessories. NACE RP0291. 1991.
10. ———. The Application of Internal Plastic Coatings for Oilfield Tubular Gords and Accessories. NACE RP0191-91. 1991.
Abstract
The primary objective of any offshore coatings program is to preserve the structural integrity of platforms and producing facilities by preventing metal loss using high-quality protective coating systems coupled with systematic and routine maintenance.
Offshore coatings are very similar to high-performance (onshore) coatings in terms of selection, surface preparation, application, and inspection. This section contains information that is unique to offshore coatings programs. For basic coatings infor-mation that is applicable to offshore work, refer to the following sections in this manual:
• Section 50, Using This Manual
• Section 100, General Information
• Section 300, Coatings Selection
• Section 400, Surface Preparation
• Section 500, Application
To select offshore coating systems, refer to the Quick Reference Guide.
Contents Page
810 In General 800-3
811 Background Information
812 Comparing Off- and Onshore Coatings
820 Quality Control 800-3
821 Design Solutions 822 Platform Maintenance 823 Project Planning [1]
824 Protecting Coatings Materials & Equipment Offshore [1]
830 Protecting Human Health & the Environment 800-18 831 Typical Hazards Offshore
832 Environmental Issues
840 Selection 800-20
850 Surface Preparation 800-20
860 References 800-21
810 In General
As there are many similarities between offshore and high-performance onshore coatings, the focus of this section is on the aspects of coatings projects unique to offshore structures.