COATINGS MANUAL
CHEVRON RESEARCH AND TECHNOLOGY COMPANY RICHMOND, CA
December 1998
Manual sponsor:
For information or help regarding this manual, contact R.A. (Rich) Doyle, (510) 242-3247
Printing History Coatings Manual First Edition First Revision Second Revision Third Revision Fourth Revision Second Edition First Revision
October 1988 December 1990 February 1992 August 1992 January 1995 September 1996 December 1998
Restricted Material Technical Memorandum This material is transmitted subject to the Export Control Laws of the United States Department of Commerce for technical data. Furthermore, you hereby assure us that the material transmitted herewith shall not be exported or re-exported by you in violation of these export controls.
The information in this Manual has been jointly developed by Chevron Corporation and its Operating Companies. The Manual has been written to assist Chevron personnel in their work; as such, it may be interpreted and used as seen fit by operating management. Copyright 1988, 1990, 1992, 1995, 1996, 1998 CHEVRON CORPORATION. All rights reserved. This document contains proprietary information for use by Chevron Corporation, its subsidiaries, and affiliates. All other uses require written permission.
December 1998
Chevron Corporation
List of Current Pages Coatings Manual The following list shows publication or revision dates for the contents of this manual. To verify that your manual contains current material, check the sections in question with the list below. If your copy is not current, contact the Technical Standards Team, Chevron Research and Technology Company, Richmond, CA (510) 242-7241.
Section 50 100 200 300 400 500 600 700 800 900 Quick Reference Appendix A Appendix B Index 2000 COM-MS-4042 COM-MS-4732 COM-MS-4738 COM-MS-4739 COM-MS-4743 COM-MS-4771 COM-MS-5005 COM-MS-5006 List of Drawings
Chevron Corporation
Date September 1996 November 1998 September 1996 September 1996 September 1996 September 1996 September 1996 September 1996 September 1996 September 1996 November 1998 None Given January 1995 September 1996 September 1996 January 1996 January 1996 January 1996 January 1996 January 1996 January 1996 January 1996 January 1996 See the list in the Standard Drawings and Forms section of this manual. Current revision dates are shown for Forms. Current revision numbers are shown for Standard Drawings.
December 1998
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December 1998
Chevron Corporation
Maintaining This Manual Coatings Manual If you have moved or you want to change the distribution of this manual, use the form below. Once you have completed the information, fold, staple, and send by company mail. You can also FAX your change to (510) 242-2157. ❑ Change addressee as shown below. ❑ Replace manual owner with name below. ❑ Remove the name shown below. Previous Owner:
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Send this completed form to: Document Control, Room 50-4328 Chevron Research and Technology Company 100 Chevron Way (P.O. Box 1627) Richmond, CA 94802
CRTC Consultants Card The Chevron Research and Technology Company (CRTC) is a full-service, in-house engineering organization. CRTC periodically publishes a Consultants Card listing primary contacts in the CRTC specialty divisions. To order a Consultants Card, contact Ken Wasilchin of the CRTC Technical Standards Team at (510) 242-7241, or email him at “KWAS.”
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December 1998
Chevron Corporation
Reader Response Form Coatings Manual We are very interested in comments and suggestions for improving this manual and keeping it up to date. Please use this form to suggest changes; notify us of errors or inaccuracies; provide information that reflects changing technology; or submit material (drawings, specifications, procedures, etc.) that should be considered for inclusion. Feel free to include photocopies of page(s) you have comments about. All suggestions will be reviewed as part of the update cycle for the next revision of this manual. Send your comments to:
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December 1998
Chevron Corporation
Coatings Manual Sponsor: R.A. (Rich) Doyle / Phone: (510) 242-3247 / E-mail:
[email protected] This document contains extensive hyperlinks to figures and cross-referenced sections. The pointer will change to a pointing finger when positioned over text which contains a link.
List of Current Pages 50
Using this Manual
50-1
100
General Information
100-1
200
Environment, Health & Safety
200-1
300
Coatings Selection
300-1
400
Surface Preparation
400-1
500
Application
500-1
600
Coating Concrete
600-1
700
Downhole Tubular Coatings & Linings
700-1
800
Offshore Coatings
800-1
900
Pipeline Coatings
900-1
Quick Reference Guide Appendices Appendix A Appendix B
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QR-1
Conversion Charts Color Chips
December 1998
50
Using this Manual Abstract In this manual, you will find procedures for coating steel and other metal substrates. Additionally, there are individual sections for those surfaces and logistics requiring special consideration: concrete, downhole tubulars, offshore, and pipeline coatings. This section offers broad, general information: the reasons for coatings, the components of a coating and coatings systems, a successful coatings program, and the structure of this manual. Contents
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Page
51
Scope and Application
52
Organization
60
Reasons for Coating
61
External Coatings
62
Under Thermal Insulation and Fireproofing
63
Internal Coatings
70
Components of Coatings and Coating Systems
71
Components of Coatings
72
Coating Systems
80
The Successful Coating Program
50-7
90
References
50-7
50-3
50-1
50-5
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50 Using this Manual
51
Coatings Manual
Scope and Application The Coatings Manual is intended: •
For Company personnel who are responsible for selecting, applying, or inspecting coatings
•
For both entry-level personnel and non-specialists regardless of experience
•
As a source of practical, useful information based on the Company's experiences
Your input and experience are important for improving subsequent revisions and keeping this manual up-to-date; therefore, we have included a form in the front of the manual to facilitate your suggesting changes. Note
52
Do not use this manual as a substitute for sound engineering judgment.
Organization The colored tabs in the manual will help you find information quickly. In summary: White tabs are for table of contents, introduction, appendices, index, and general purpose topics. Blue tabs denote Engineering Guidelines. Gray tabs are used for Specifications and related forms. Red tab marks a place for you to keep coatings documents that are developed at your facility.
Engineering Guidelines The Engineering Guidelines cover: •
An overview of coatings
•
General information about selecting coatings; preparing surfaces; and applying, inspecting, and maintaining coatings
•
Specific information about surfaces and logistics that require special consideration—concrete, downhole tubulars, offshore, and pipelines
Specifications The specifications include:
September 1996
•
A Quick Reference Guide (for selecting coating systems; coatings system data sheets; list of acceptable brands; and Coating Compatibility Chart)
•
The Company's specifications in commented form
•
Standard Forms
50-2
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Coatings Manual
50 Using this Manual
Other Company Manuals Within this manual, there are references to documents in other Company manuals (example: COM-MS-4738 in this manual). These documents carry the prefix of the particular manual. These prefixes are as follows:
60
Prefixes
Company Manuals
CIV
Civil and Structural
CMP
Compressor
COM
Coatings
CPM
Corrosion Prevention
DRI
Driver
ELC
Electrical
EXH
Heat Exchanger and Cooling Tower
FFM
Fluid Flow
FPM
Fire Protection
HTR
Fired Heater and Waste Heat Recovery
ICM
Instrumentation and Control
IRM
Insulation and Refractory
MAC
Machinery Support Systems
NCM
Noise Control
PIM
Piping
PMP
Pump
PPL
Pipeline
PVM
Pressure Vessel
TAM
Tank
UTL
Utilities
WEM
Welding
Reasons for Coating The Company coats structures and equipment for several reasons. Many of these reasons are discussed below.
61
External Coatings External coatings are generally for aesthetics, corrosion prevention, evaporation reduction, and safety.
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Aesthetics Coatings improve the appearance of objects, which contributes to good employee morale, advertising, neighborhood relations, and civic pride.
Corrosion Protection Atmospheric corrosion is a significant problem in humid, warm, coastal locations; in chemical and fertilizer plants; and on offshore structures. Regardless of the geographical location, coating is essential for protection against corrosion in most plant areas.
Evaporation Reduction Painted in light colors, the roofs of storage tanks reflect rather than absorb the sun's energy thus reducing evaporative loss of the stored material.
Safety Special coatings mark fire equipment, traffic lanes, and piping that carries hazardous materials.
62
Under Thermal Insulation and Fireproofing A properly designed coating system, applied to the substrate under thermal insulation and fireproofing systems, gives the best long-term protection against chloride stress-corrosion cracking (CSCC) of stainless steel and reduces corrosion of carbon steel. CSCC and increased corrosion occur: •
When moisture permeates the insulation or fireproofing system and condenses against the substrate, creating a condition similar to immersion service
•
Because steel operating temperatures affect the corrosivity of water
•
As long as the temperature of the water remains below its boiling point: the hotter the steel, the hotter the water, the higher the rate of corrosivity
•
When moisture leaches soluble salts that contain chloride or sulfide ions
Again, the hotter the solution, the greater the effect. Because they develop under insulation and fireproofing, these conditions are very hard to detect. Maintenance and inspection are very difficult and usually require removing the insulation or fireproofing. Often the first indication of a problem is an equipment failure. For guidance on choosing coatings, refer to “Coatings Under Insulation and Fireproofing” in the System Number Selection Guide (part of the Quick Reference Guide).
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50 Using this Manual
Internal Coatings Internal coatings can maintain product purity, reduce stockside and underside corrosion, and affect potable water.
Product Purity Even at low corrosion rates, some corrosion occurs. An internal coating may be necessary to prevent the products of corrosion—such as iron oxide (rust) or scales— from contaminating the stock and causing problems.
Stockside Corrosion Internal coatings extend the life of the tank or vessel and reduce the chance of leaks, especially in storage tank bottoms. The water layer which settles out in the bottom of the tank causes most of the tank bottom internal corrosion.[1]
Underside Corrosion For tanks, the corrosion rate of the underside depends mainly on soil composition and moisture content. Based on experience, you can predict when underside corrosion may be a problem.[1]
Potable Water The U.S. Food and Drug Administration regulates coatings for lining potable water tanks.
70
Components of Coatings and Coating Systems 71
Components of Coatings A coating consists of a pigment, a vehicle (binder plus solvent), and additives. Pigments give color and protective properties to the paint. The vehicle provides curing to form a continuous film and adhesion to the substrate. The vehicle is made of the binder (which forms the film) and the solvent (which dissolves the binder and adjusts viscosity to improve application). The solvent also partly controls drying rate. Additives are drying and wetting agents, ultraviolet screening agents, etc.
Methods of Film Formation Understanding how binders work is critical when choosing a coating system. For most coatings, film forms in one of several ways. Thermoplastic. The solid resin, melted for application, resolidifies when it cools. Example: Tar in roof coatings.
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Solvent Evaporation. The coating dries as the solvent evaporates (or dries at lower temperatures than those which involve a chemical reaction). If re-exposed to the same solvent, the coating can redissolve. Example: Vinyls, chlorinated rubbers and lacquers. Oxidation. Coatings composed of drying oils cure by reacting with air. Oxygen cross links the resin molecules into a solid gel. Example: Alkyds. Cross Link. Dual-component products cross link at room temperature, either with or without a catalyst. Example: Epoxies (two polymers react, no catalyst), polyesters (catalyzed) and urethanes (catalyzed). Heat Cure. Heat causes direct cross-linking between filmformer molecules, or activates a catalyst to cause cross-linking. Normally, these coatings are shop-applied only, because of the special heating requirements. Example: Baked phenolic linings. Emulsion. When the water evaporates from an emulsion of resin particles and water, the resin particles coalesce to form a film. Example: Latex acrylics.
72
Coating Systems A coating system refers to the layers that make a complete coating: primer, tiecoat or intermediate coat, and topcoat.
Primer Coats Primer coats adhere well to the substrate and inhibit corrosion and undercutting at defects, such as pin holes or holidays (breaks) in the film. Note that holidays are pinholes or thin spots which either develop during application or nicks and scrapes which occur later. Corrosion will start at these spots. Primer coats also bond well to the intercoat, tolerate variations in application conditions and handling, and resist weathering (helpful because delays may occur between priming and topcoating).
Tiecoats Tiecoats (or intermediate coats) build film thickness, bond the primer to the topcoat, and protect substrate and primer from aggressive chemicals in the environment.
Topcoats Topcoats protect the substrate and undercoats from the environment, provide chemical resistance, enhance the surface appearance, and provide non-skid and other properties.
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Some coatings are incompatible. Before choosing coatings to apply over previously coated surfaces, see the Coating Compatibility Chart in the Quick Reference Guide.
80
The Successful Coating Program The successful coating program has four elements: • • • •
Selection Surface preparation Application Quality control (inspection and on-going maintenance)
Each of these elements is described in more detail in this manual.
90
References 1.
Chevron Corporation
Chevron Corporation. Corrosion Prevention Manual, “Corrosion of Storage Tank Bottoms,” Chevron Research and Technology Company. Richmond, CA: January, 1994.
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100 General Information Abstract Among the general information in this section is a description of the coatings and coating systems, which includes the advantages, disadvantages, and uses. Coatings are also described in the individual sections for special surfaces such as: concrete, downhole tubulars, and pipelines. Note This manual does not contain information about coatings for architectural surfaces. Quality control is essential for any project. Among the key elements of quality control for coatings are inspections, monitoring progress, and protecting the Company’s equipment. For assistance with specific questions about coatings, see the listing of the Company’s specialists and coating manufacturers in the Quick Reference Guide.
Chevron Corporation
Contents
Page
110
Coating Descriptions (A-E)
100-3
111
Acrylics
112
Alkyds
113
Epoxies
114
Elastomers
120
Coatings Descriptions (P–Z)
121
Phenolics
122
Polyesters
123
Polyurethanes
124
Silicones
125
Vinyls
126
Zinc-rich Coatings
130
Petroleum-based Tapes
100-21
140
Water-based Coatings
100-21
150
Coating Systems for Immersion Service
100-22
100-1
100-13
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100 General Information
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151
Non-reinforced Thin-film Coatings
152
Glass-flake-reinforced Coatings
153
Laminate-reinforced Coatings
160
Quality Control
161
General Information
162
Inspection Programs
163
Inspectors
164
Monitoring Progress
165
General Inspection Procedures
166
Specific Inspection Procedures
167
Instruments, Tools, and Equipment
168
Protecting the Company’s Equipment
170
References
100-27
100-46
100-2
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100 General Information
110 Coating Descriptions (A-E) The following coatings are described in this section: • • • •
Acrylics Alkyds Epoxies Elastomers
For details about each type of coating, read the following descriptions. See also Figure 100-1, Summary of Properties in Coatings.
111 Acrylics Acrylic ester resins are polymers and co-polymers of the esters of acrylic and methacrylic acids. As thermoplastics, they soften at high temperatures. Advantages: • •
Good moisture and mild chemical resistance Either fast-drying solvent evaporation or coalescence
Disadvantages: •
Poor resistance to aromatic solvents
Uses: • • •
Solvent acrylic: truck and machinery finishes Latex emulsions: stucco, wood, and masonry By Company: as architectural coatings
112 Alkyds Alkyd resins are basically modified polyesters. An alkyd is the reaction product of a polyhydric alcohol and a polybasic acid. A common alkyd resin uses glycerol as the alcohol and phthalic acid as the polybasic acid. Oxidation in the air cures alkyd coating resins. Adding drying oils to pure alkyd modifies the alkyd into alkyd coating resins. These resins are classified by oil length (long, medium, and short). The alkyd resin without oil modification is hard and brittle. As the oil length increases (more oil added), the film becomes softer and more flexible. Advantages: • • • •
Chevron Corporation
Perform well in moderate environments Easy-to-handle, single-component coatings Inexpensive Fair-to-good performance in most of the Company's environments
100-3
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100 General Information
Fig. 100-1
Coatings Manual
Summary of Properties in Coatings (1 of 2)
Coatings Acrylic
Alkyd
Type of Cure
Effect of Sunlight
Solvent Evaporation
Chalk Resistant
Good
Oxidation
Slow Chalk
Amine-cured & Amine Adduct Epoxy
Cross Linked
Polyamide Epoxy
Cross Linked
Coal-tar Epoxy Polyamide
Cross Linked
Chlorinated Rubber
Solvent Evap.
Epoxy Phenolic
Cross Linked
1. Atmosphere 2. Splash/Spillage
Wet Atmosphere
Acid
Heat Cured
Moisture-cured Urethane (II)
Cross Linked
Silicone
Heat Cured Cross Linked
Oxidizing
Solvent
1. Good
1. Good
1. Good
1. Fair
2. Poor- Fair
2. Poor-Fair
2. Poor-Fair
2. N/R
Poor-Good Yellows
1. Fair- Poor
1. Poor
1. Fair
1. Fair
2. N/R
2. N/R
2. N/R
2. N/R
Chalks Yellow
Excellent
1. Good
1. Excellent
1. Limited
1. Excellent
2. Fair
2. Excellent
2. N/R
2. Excellent
Chalks Yellow
Excellent
1. N/R
1. N/R
1. N/R
1. N/R
2. Poor-Fair
2. Excellent
2. N/R
2. Very Good
Chalks, Cracks
N/R
1. Excellent
1. Excellent
1. Excellent
1. Poor
2. Good
2. Good
2. N/R
2. N/R
Slow Chalk
Excellent
1. N/R
1. N/R
1. N/R
1. N/R
2. Very Good
2. Very Good
2. Good
2. N/R
N/R
N/R
1. N/R(1)
1. N/R(1)
1. N/R(1)
1. N/R(1)
2. Good Baked Phenolic
Alkali
N/R
(1)
1. Good(1)
N/R
Aromatic Yellows; Aliphatic Excellent
Very Good
Excellent
Very Good
2. Very Good 1. Good(1)
2. Lid Mineral Acids(1)
2. N/R
(1)
2. N/R
(1)
N/R(1)
(1)
2. Very Good(1) 1. Poor(1) 2. Outstanding(1)
1. Good
1. Good
1. Poor
1. Excellent
2. Fair
2. Fair
2. N/R
2. Good
1. Good
1. Good
1. Fair
2. Poor
2. Poor
1. Very Good
2. Fair
2. Poor Silicone Alkyd
Vinyl
Organic Zinc-rich Post-cured Inorganic Zinc Solvent-based Self-cured Inorganic Zinc
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Oxidation
Solvent Evap.
Cross Linked
Cross Linked
Cross Linked
Excellent
Very Good
Slow Chalk
Excellent
Chalk
Excellent(2)
None
None
Excellent
Excellent
(2)
(2)
1. Good
1. Good
1. Good
1. Good
2. Poor
2. Fair
2. Poor
2. Good-Poor
1. Excellent
1. Excellent
1. Excellent
1. Poor
2. Very Good
2. Good
2. Good
2. N/R
1. Topcoat
1. Topcoat
1. Topcoat
1. Excellent
2. N/R
2. N/R
2. N/R
2. Very Good
1. Topcoat
1. Topcoat
1. Topcoat
1. Excellent
2. N/R
2. N/R
2. N/R
2. Excellent
1. Topcoat
1. Topcoat
1. Topcoat
1. Excellent
2. N/R
2. N/R
2. N/R
2. Excellent
100-4
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Coatings Manual
Fig. 100-1
100 General Information
Summary of Properties in Coatings (2 of 2)
Coatings
Tank Linings
Immersion
Physical Properties Abrasion
Heat
Hardness
Gloss
Range of Color
Acrylic
N/R
N/R
Good
Limited
Good
High to Semi
Full
Alkyd
N/R
N/R
Fair
Fair
Fair
Chalks to Flat
Full
Amine-cured & Amine Adduct Epoxy
Very Good
N/R
Good
Good
Very hard
Chalks to Flat
Full
Polyamide Epoxy
Very Good
Solvents Water
Good
Good
Hard
Chalks to Flat
Full
Coal-tar Epoxy Polyamide
Excellent
Water
Limited
Excellent
Very Hard
Flat
Black, Red
Chlorinated Rubber
Very Good
Water
Fair-Poor
Poor
Good
Semi to Flat
Wide
Epoxy Phenolic
Very Good
Widerange Solvent
Good
Outstanding
Very Hard
High
Dark
Baked Phenolic
1. Excellent(1)
Wide Resistance
Good
Excellent
Excellent
Excellent
Clear Dark
2. Very Good Moisture-cured Urethane (II)
N/R
N/R
Excellent
Good
Excellent
High
Full
Silicone
N/R
N/R
Good
Excellent
Good
High
Full
Silicone Alkyd
N/R
N/R
Good
Very Good
Good
High
Full
Vinyl
Very good
Water
Fair-Poor
Poor
Good
Semi to Flat
Wide
Organic Zinc-rich
Good(3)
N/R
Good
Good
Very Good
Semi to Flat
Some
Post-cured Inorganic Zinc
Good(3)
Fuels Solvent
Excellent
Excellent
Excellent
Flat
Earth Tones
Solvent-based Self-cured Inorganic Zinc
Good(3)
Fuels Solvent
Excellent
Excellent
Very Good
Flat
Earth Tones
(1) As tank lining (2) When top-coated (3) With epoxy topcoat
•
Good service on large, flat surfaces
Example: Good service is exemplified by this coating’s almost 20 years on Hawaiian refinery tanks. Disadvantages:
Chevron Corporation
•
Long drying time
•
Not chemically resistant; unsuitable for highly corrosive areas such as chemical and fertilizer plants or offshore structures
•
Unsatisfactory for water immersion
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•
Not suited to highly alkaline surfaces such as fresh concrete, galvanized steel, and inorganic zinc
•
Chalk in sunlight
•
Usually fail within a few years on piping and structural components
•
Not VOC-compliant
Uses: •
In external primers and finish coatings
Long-oil Alkyds (60 to 70 Percent Oil) Advantages: •
Good flexibility and wetting properties
Disadvantages: •
Very slow drying
Uses: •
Over poorly prepared steel where the oil penetrates rust and develops adhesion
Medium-oil Alkyds (45 to 60 percent oil) Advantages: •
Hard, tough films
•
Dry faster, generally, than long-oil alkyds
Uses: •
Finish coats
Note
The Company’s most popular choice of alkyd
Short-oil Alkyds (35 to 45 percent oil) Uses: •
Fast air drying and baking enamels for hardness and mar resistance
Note
The Company uses very little of these.
113 Epoxies The most common epoxy resins are formed by the reaction of epichlorhydrin and bisphenol-A. This reaction can be controlled to produce resins ranging from liquids of low-molecular weight to solids of high-molecular weight.
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100 General Information
Complete curing gives epoxies their chemical and water resistance. Curing time increases at temperatures below about 70°F, essentially stopping below about 50°F unless it is a specially formulated low-temperature epoxy. Epoxies have very good resistance to bases and many solvents. Epoxies have poor acid resistance unless modified with a phenolic. Advantages: • • • •
Resist water and chemicals, especially caustics, superbly Resist weather well Adhere well, particularly to concrete Apply easily
Disadvantages:
☞
•
Do not retain color and gloss as well as alkyds
•
Tend to chalk rapidly
•
Do not have good acid resistance
•
Need surfaces between layers of epoxy roughened by solvent or blasting when applying multiple coats as many epoxies cure with a hard, slick surface
•
Need successive coats of epoxy applied as soon as possible to obtain satisfactory adhesion between coats. Manufacturers normally recommend a maximum time between coats.
•
Need long cure time. For epoxy linings at 70°F, curing may take one week. In the field, coatings applicators often accelerate the curing of an internal coating with a low-temperature bake (100 to 150°F).
Caution
Do not put internal coatings into service until they are fully cured.
Uses: •
Epoxy resins are the most popular resin for thin-film coatings on concrete.
There are six groups of epoxy coatings in this section: amine cured, amine adduct, polyamide, coal tar, epoxy mastics, and epoxy novolac.
Amine-cured Epoxies These coatings are epoxy resins cross-linked with one of several amine compounds.
☞
Caution Because the amines can present a health hazard, apply them according to manufacturers’ safety recommendations.
Amine Adduct Epoxies Amine adducts are stable intermediate products resulting from the reaction of a portion of the epoxy resin with an amine curing agent. The amine adduct, instead of the amine, is added to the epoxy coating to cure it.
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Advantages: • •
Same properties as liquid amines, but much less hazardous Very good resistance to oils, solvents, and chemicals
Disadvantages: •
Ultraviolet degradation causes rapid chalking
Uses: • •
Lining gasoline storage tanks, chemical tanks Corrosion-resistant primer under polyurethane foam insulation
Polyamide Epoxies Polyamide resins are produced from polyamines and fatty acids. Epoxy coatings for atmospheric exposures are usually polyamides. Mastic coatings which adhere to wet surfaces and which will cure under water are formulated with polyamide epoxies. Advantages: •
Good surface-wetting properties
•
Longer pot life, more flexibility and better water resistance than amine or amine-adduct cured epoxies
•
Good resistance to alkalies, petroleum products, and salt water
Disadvantages: •
Not quite as chemically resistant as amine adduct epoxies.
Uses: •
Topcoats and tiecoats in severe exposures
Coal-tar Epoxies As the name suggests these coatings are blends of epoxy resins and coal tar. Note Coal tar is a suspected carcinogen but is tied up sufficiently in the polymer so that manufacturers consider the cured film safe. Coal-tar epoxies can be either polyamide- or amine-adduct cured. Usually applied in two heavy coats of eight mils each, these coatings are normally self-priming. Advantages: •
Outstanding for water-immersion service
Disadvantages: •
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Chalk rapidly and fail in (ultraviolet) sunlight
100-8
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100 General Information
Uses: •
Underwater, in water tank linings (except potable water tanks), and on buried structural steel
Note Although coatings manufacturers continue to use them for municipal watertank linings, the Company prefers FDA-approved polyamide or amine-adduct epoxies for potable-water tank linings.
Epoxy Mastics Advantages: • • • •
Perform better than alkyds Adhere to a variety of surface preparations, including tightly adhered rust Adhere to any old coating firmly attached to the substrate VOC compliant
Disadvantages: •
More expensive than alkyds
Uses: •
For less-than-perfectly prepared surfaces
Epoxy Novolac Epoxy novolac resins are second-generation epoxies with greater cross-linking density. Advantages: •
Greater resistance to chemical attack and high temperatures than standard epoxies
Disadvantages: •
More expensive and less flexible than standard epoxies
Uses: •
Common coating for concrete
114 Elastomers An elastomer is a polymeric substance with more than 100 percent elongation in a tensile test. Included in this category are natural- and synthetic-rubber products (which also have the physical characteristics of natural rubber). The chemical, oil, and water resistance of elastomers vary widely. Coatings applicators can apply modified elastomers as coatings. The Company uses many elastomeric coatings, such as chlorinated rubber and hypalon, alone over steel and other surfaces or, as required, with special primers such as inorganic zinc.
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There are two classes of elastomers: cross-linking and air-drying.
Catalyzed Cross-linking Elastomers Neoprene, butyl, thiokol, silicone, and hypalon are the most common, catalyticsetting, elastomer coatings. Neoprene. A synthetic rubber, produced by polymerizing chloroprene, neoprene is either pigmented or clear and is manufactured as thin flexible films or mastics. Advantages: • •
Good heat and flame resistance Good acid, alkali, and water resistance
Disadvantages: •
Softened by aromatic solvents
Uses: •
Block insulation coatings
Butyl. A copolymer of isobutylene and isoprene, butyl is polymerized with an aluminum chloride catalyst. Advantages: • •
Exceptionally low water permeability Better sunlight and weather resistance than most rubbers
Disadvantages: •
Unknown
Uses: • •
Coating urethane foam and block insulation Piping tape wrap primers and tape mastics
Thiokol. Thiokol is a polysulfide rubber. Advantages: •
Excellent gasoline and water resistance
Disadvantages: •
Unknown
Uses: • • •
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Caulking compounds Flexible seal over leaking rivet seams in oil tanks Pond and tank linings (in sheet form)
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Silicone Rubber. Silicone rubber is a room-temperature vulcanizing (RTV) silicone. Advantages: •
Good for hot service
Disadvantages: •
Poor solvent resistance
Uses: • • •
Gaskets in hot services Caulking Potting materials
Hypalon. Hypalon is a chlorinated polyethylene resin. Advantages: • •
Excellent sunlight resistance Good chemical resistance
Disadvantages: •
Unknown
Uses: • • • •
Flexible coating vehicles or mastics and sheet lining Mild acid spill protection for concrete (the Company's most popular use) Topcoat over polyurethane foam or block insulation Pond and tank linings
Air-drying Elastomers Chlorinated rubber, an air-dried formulation of hypalon, and butadiene-styrene are the most popular elastomers for air-drying coatings. Chlorinated Rubber. Chlorine and natural rubber latex produce chlorinated rubber resins. When suitably plasticized and pigmented, these resins exhibit outstanding resistance to a broad range of corrosive chemicals and environments. Advantages: •
Shows outstanding resistance to severe chemical environments such as acids, alkalies, salt fog, water, oxidizing agents, bleaches, and cleaning compounds
•
Dries rapidly, allowing application of several coats in one day
•
Produces excellent bond between old and new coats as the solvents in the new coat penetrate the old coat
Disadvantages:
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• • •
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Does not resist sunlight damage as well as alkyds and acrylics Causes alkyd or oil coatings to blister if applied over them Dissolves in oils and solvents
Caution
Oil spills could potentially soften these coatings.
Uses: • •
Offshore platforms Humid coastal refineries
Hypalon. The air-drying hypalon is a chlorosulfonated polyethelene. Advantages: •
Good weatherability
Disadvantages: •
Unknown
Uses: •
Topcoat elastomers to improve weather resistance
Butadiene-Styrene. The most widely used type of synthetic rubber, butadienestyrene is a copolymer of three parts butadiene and one part styrene. Advantages: • •
Good resistance to alkali, water, and mild acids Excellent external durability if pigmented properly
Disadvantages: •
Embrittles with age if formulated improperly
Uses: •
Vehicles in coatings and mastics for stucco and masonry
Polyurethane Elastomers. Polyurethane elastomers are thermal plastic polymers. Advantages: •
Aliphatic—Excellent color and gloss retention
Disadvantages: •
Aromatic—Yellows badly in sunlight
Uses:
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•
Vehicles for thin or semi-mastic coatings for sealing polyurethane foam insulation
•
Deck and floor coatings
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120 Coatings Descriptions (P–Z) The following coatings are described in this section: • • • • • •
Phenolics Polyesters Polyurethanes Silicones Vinyl Zinc rich
121 Phenolics Phenolic resins, formed by the reaction of phenol with formaldehyde, produce a range of coatings from hard plastics (Bakelite) to oil-soluble resins and from heatreactive varnishes to air drying oils. The Company uses two phenolic resins in coatings: a baked pure phenolic and an air-drying epoxy phenolic.
Baked Phenolics Baked phenolics are almost exclusively shop-applied due to a complicated baking procedure. They contain resins which are polymerized by being heated above 300°F. The reaction time and temperature depend on the modifying oils and resins. Note The Company uses baked phenolics only in the most severe immersion services where no other material will work, such as container inner-coatings and tank car linings. Advantages: • • •
Excellent chemical and water resistance Withstand immersion in almost all petroleum products Good abrasion resistance
Disadvantages: • • • •
Poor wetability (the ability of a coating to flow over a surface) Require maximum surface preparation Poor adhesion Embrittles
Note To overcome poor adhesion and brittleness, some formulas are modified with epoxy resins, giving them better caustic resistance than pure phenolics but not equal resistance to strong solvents.
Epoxy Phenolics Catalytic setting (non-baking) phenolics are usually composed of phenolic resins and epoxies.
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Advantages: •
Better chemical and solvent resistance than pure epoxies
Disadvantages: •
Lower resistance to chemicals and solvents than pure baked phenolics
Uses: •
Lining tanks, vessels, containers, etc.
122 Polyesters While there are two major classes of polyester resins, the Company uses only isophthalic. Isophthalic polyesters, the resin preferred for corrosion protection, is also the main resin in laminate-reinforced systems. While the chemical and temperature resistance of polyester is usually poorer than any of the other resins, they are also the least expensive.
123 Polyurethanes Polyurethane resins are formed by the reaction of isocyanates with polyols and are used for a variety of purposes from foam insulation to air-drying coatings and varnishes. The isocyanate may be either aromatic or aliphatic. There are literally thousands of polyurethane formulations—from hard roller skate wheels to elastomeric materials that stretch like rubber bands—which have many different properties. Some of these properties are: • • • • •
☞
Abrasion resistance Chemical resistance Elasticity Impact resistance Tensile strength
Caution Remember that increases in one property result in decreases in another. Because of this, many elastomeric polyurethanes are not as chemically resistant as the more rigid polyurethanes. The most common polyols are acrylics and polyesters, although there are epoxies, vinyls, and alkyds. Advantages: • • • • •
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Highly resistant to abrasion and impact Catalyzed urethanes are highly chemical resistant Better performance than alkyds Aliphatic—For atmospheric coatings, usually as easy to overcoat as epoxies Aromatic—More chemically resistant than aliphatic urethanes
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Disadvantages: •
More expensive than alkyds
•
Aromatic—Not designed for external exposure as they chalk and yellow; difficult to overcoat because adhesion is poor
Uses: •
Aliphatic—Non-fading, non-chalking external finishes
•
Aromatic—Tank linings, chemically resistant coatings, flexible elastomeric coatings for polyurethane foam insulation coverings
Classifications. Urethane coatings cure by a variety of mechanisms as classified by ASTM D16-75 types. Types II, IV, and V are considered high performance and are described below. Most of the Company's experience has been with Type V, the twopackage polyol-cured urethane. Type II, One-package Moisture-cured. The Company has limited experience with these urethanes which cure by reacting with moisture in the air. The moisture reacts with a prepolymer containing isocyanate so that the isocyanate is released for crosslinking. The reaction also releases CO2 which must migrate to the surface before the film sets up.
☞
Caution In high humidity areas, such as offshore, the reaction can occur so rapidly that the CO2 cannot escape; and the film is filled with gas bubbles and pinholes. Type IV, Two-package Catalyzed. These urethanes cure by reacting with a lowmolecular-weight-reactive catalyst. They cure in a similar way not only to moisturecure (although the catalyst is in a separate package), but also to epoxy coatings. Type V, Two-package Polyol-cured. These urethanes are the Company's most common choice for high-performance coating systems such as for offshore platforms and chemical plants. To cure, polyol-cured coatings react with pre-reacted (adduct) hydroxyl-bearing polyols. They require no additional curing agent; however, coatings applicators may add an agent to promote low-temperature curing.
124 Silicones Silicones are a group of various organo-silicon-oxide polymers available as fluids, elastomers, and resins. Because of their chemical composition, silicones have excellent resistance to heat, weathering, and moisture. Note Repairing silicone coatings is very difficult because almost nothing will adhere to them. For small repairs, sand the failure and apply fresh silicone coating with a brush. For large repairs, remove the coating by abrasive blasting and recoat. The Company uses both classes of silicone coating resins: heat-reactive and modified.
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Heat-reactive Silicone resins are cross-linked polymers which require a high-temperature cure to produce heat-stable films. Catalyzed formulations which cure at room temperature are now available. Non-catalyzed formulations remain tacky until heated above about 300 to 400°F. For this reason, most field applications use the catalyzed, roomtemperature cure. The film thickness of baked silicone coatings is low compared to that of other coatings. A self-primed two-coat application usually produces only 1½ to 2 mils dry film thickness (DFT). Advantages: • •
Excellent sunlight resistance Good durability at high temperatures
Disadvantages: •
Apply only on abrasion-blasted surfaces
Uses: Furnaces and stacks up to 600°F (up to 750°F for aluminum and black colors)
Note
The color and gloss retention of baked silicones depends on the pigments.
Modified or Air-drying Modified or air-drying silicones are produced by reaction with organic resins such as alkyds or acrylics. Advantages: • • •
Excellent gloss and color retention Good weather and sunlight resistance Many resist temperatures up to 300°F
Disadvantages: •
Tend to cure quite slowly even at ambient temperature, taking weeks to harden and resist damage in cool weather.
Note
Topcoat inorganic zinc with an epoxy or silicone acrylic.
125 Vinyls Vinyl resins are formed from the reaction of acetylene with acetic or hydrochloric acids. Varying this process produces resins consisting of 100 percent vinyl chloride, or 100 percent vinyl acetate. The resins in protective coatings are usually co-polymers containing 80 to 90 percent vinyl chloride and 5 to 15 percent vinyl acetate.
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Vinyl resins are hard and brittle and must be combined with plasticizers and dissolved in solvents to form vehicles for coatings. Vinyl solutions contain only 15 to 40 percent solids depending on the co-polymers. The various vinyl-resin solutions are compatible and may be blended to emphasize desired properties. Some blends adhere very well to concrete and metal and are used in formulating primers. Other blends are pigmented and plasticized to produce highbuild films. Used for finish coats, some blends have low solids and adhere poorly to steel but have very good chemical and weather resistance. The Company uses vinyls for many services, often where water exposure is expected such as on floating tank roofs, docks, and on offshore platforms near the water. Advantages: • • • • • •
Excellent chemical, water, and aliphatic oil resistance Excellent shelf life Ready bond to weathered vinyl films Removable with a solvent wash when desired Easy to patch old coatings without blistering or wrinkling Easy to apply by spray
Disadvantages: •
May lose their plasticizer over time and embrittle, a problem with vinyl as a weathercoat over polyurethane-foam insulation
•
Do not have good gloss retention or stain resistance
•
Dissolved by ketones, esters, chlorinated solvents, and some aromatics
•
Need good ventilation to avoid prolonged (solvent evaporation) drying
•
Tend to lift and blister because of the strong solvents
•
Difficult to brush or roll because of their rapid drying
•
Tend to bubble and pinhole when applied over porous inorganic zinc
Uses: •
With alkyds or epoxy esters to improve film build, gloss, and adhesion which are excellent as vehicles: – – –
•
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In rust-inhibiting primers for ferrous metals In seal or tiecoats over inorganic zinc primers to improve adhesion of vinyl, alkyd, chlorinated rubber In epoxy ester topcoats
In formulae ranging from thin-bodied, air-drying coatings to semi-mastic putties and air-drying, baking plastisols
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•
To formulate a wide variety of latex materials in glues, paper sizes, and emulsion coatings
•
In vinyl-emulsion-latex coatings for both internal and external services. The retention of deep colors by vinyl latexes is superior to that of most other coatings.
Vinyl Ester Vinyl ester resin is a reaction product between polyesters and epoxies and shares many of the attributes of polyesters. Advantages: •
Resistance to acid, solvent attack, and high temperatures
Disadvantages: •
More expensive than an isophthalic polyester or normal epoxy
Uses: •
Coating concrete
126 Zinc-rich Coatings Zinc-rich coatings, which have zinc dust as the pigment and inorganic or organic vehicles, are divided into two classes: inorganic and organic zinc. Zinc-rich coatings offer good corrosion resistance for steel due to the sacrificial nature of the zinc pigment. The zinc acts as an anode to protect the steel galvanically and prevent corrosion. This coating is applied alone or as a primer under a variety of topcoats. Under suitable topcoats, all of these primers greatly enhance the life of the coating system in many exposures, especially in marine services. When testing to determine the benefit of zinc in a coating, the Company found the quality of performance to be rated (best to worst) as follows: 1.
Inorganic zincs
2.
Zinc-rich organic coatings
3.
Organic coatings
Inorganic-zinc Coatings Inorganic-zinc coatings consist of two components: •
A pigment composed solely or principally of zinc powder
•
Any of a variety of patented and proprietary inorganic or semi-inorganic vehicles to form the matrix of the coating
Post-cured inorganic zincs have a third component: a curing agent such as phosphoric acid. Among the vehicles are ethyl and sodium silicate, phosphates, and other complexes.
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When properly mixed, applied to blasted steel surfaces, and allowed to cure, the resultant coatings have outstanding resistance to weathering, humidity, elevated temperatures, organic solvents, animal and vegetable oils, both fresh and salt water, and most petroleum products. In addition, these coatings (especially post-cured) have excellent abrasion resistance. The corrosion resistance of the cured film is similar to that of galvanized iron; the weather resistance is superior to galvanized iron. Two types of inorganic zinc coatings are self-cured and post-cured.
Self-Cured Inorganic Zinc Coatings Self-cured inorganic zinc coatings are either solvent- or water-based vehicles. While both produce an inorganic film, their methods differ. Current technology is almost all solvent-alkyl-silicate-resin based. Solvent-based Coatings. The Company uses self-cured, solvent-based, inorganic zincs in many places such as piping, tanks, and offshore. Although manufacturers have used several inorganic silicate vehicles such as ethyl silicate and bi-metallic alkoxide complexes to make these coatings, almost all self-cured inorganic zincs are now alkyl silicates such as ethyl silicate. Ethyl-silicate-based coatings convert to an inorganic, insoluble state in reaction to moisture. Some formulae require long periods (three to four weeks) of high humidity to reach ultimate hardness. Many manufacturers now claim their ethyl silicates can be topcoated almost immediately since enough moisture permeates through the topcoats to cure the primer. Solvent-based coatings are popular because their vehicles show superior wetting ability, they dry fast and resist water immediately, and their film thickness is less critical than for post-cured inorganic zinc coatings. Some self-cured inorganic zincs are modified to include some organic resin for more rapid film formation and increased flexibility. Properly formulated, they can perform as well as normal alkyl silicates.
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Caution The Company does not recommend single-component inorganic zincs. Laboratory tests and experience show that these zincs do not perform as well as the two-component zincs. One reason is that the zinc settles in the can and is not easily put back in suspension. The applied coating is, therefore, deficient in zinc. Coatings applicators mix the multi-component zincs at the time of application and agitate them continuously to avoid the settling problem. Water-based Coatings. Tests show that, for weather resistance, water-based coatings are inferior to solvent-based and post-cured inorganic zincs. Note Future changes to clean air regulations may force us to use water-based or new, presently untested, formulations of inorganic zincs. Composed of zinc dust pigment and vehicles containing sodium silicate, or phosphates, the vehicles are water solutions similar to those of the post-cured coatings. After application, the film is water sensitive for some time, the length of which depends on the formula. The vehicle’s reaction with moisture in the air converts the
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water-soluble film to an insoluble film. Conversion time depends on the vehicle and the relative humidity and temperature. Some of these coatings undergo a color change as they cure, indicating when they are completely cured.
☞
Caution Do not topcoat or place these coatings in water-immersion service until they are thoroughly cured.
Post-Cured Inorganic Zinc Coatings Post-cured inorganic-zinc coatings are composed principally of zinc powder and sodium silicate. When mixed, the zinc-dust pigment and sodium silicate produce a water-soluble coating. coatings applicators must keep the applied film dry until it has cured by a chemical curing agent, such as phosphoric acid, which converts the film to a water insoluble coating. Advantages: •
Long life under extreme service conditions such as exposure to marine environments
Disadvantages: •
Sensitivity to moisture until cured
•
White-metal surface preparation
•
Necessity of removing the powder-like post-cure reaction chemicals (by washing very thoroughly) before topcoats will adhere
Uses: •
Extreme conditions such as offshore structures in marine environments.
Note While post-cured inorganic zinc coatings have a long, successful field history, the Company limits post-cured zincs to extreme services where their long life is needed such as near the water on offshore platforms. Today, however, because self-cured inorganic zincs can last almost as long and are much easier to apply properly, you may choose them instead.
Zinc-rich Organic Coatings Epoxies, urethanes, chlorinated rubbers, phenolics, styrenes, silicones, and vinyls are vehicles for zinc-rich organic coatings. Epoxies are most common. The zinc content of these coatings should generally be about 80 percent by weight of total solids. The mechanism for curing zinc-rich organic coatings depends on the binder. (See Section 70 of this manual for methods of film formation.) The coatings can be either single- or multi-component. Performance tends to be a function of the durability of the binder, and epoxies are generally considered superior.
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Advantages: • • •
Excellent water and weather resistance Better wetting ability, because of their organic vehicles, than inorganic zinc Usable over a broader range of surface preparation conditions than inorganic zinc
Disadvantages: •
Not as oil resistant as the inorganic coatings
Uses: • • •
Touch up for inorganic-zinc-primed systems Subsea equipment primers As primers under other coatings
Note Often one coat of IOZ alone gives excellent performance. For higher performance or aesthetics, topcoat with epoxy or epoxy plus urethane. Example: One coat of IOZ has lasted 15 plus years on a Richmond Long Wharf line. Pascagoula successfully used a two-coat system of Carboline Coating Company’s IOZ with Carboline high-build urethane.
130 Petroleum-based Tapes Petroleum-based tapes, such as denso, work well in severe service as a wrapping for pipe and structural components. Advantages: • •
Adheres to moist surfaces with minimum surface preparation Adheres to irregular shapes, valves, and pipe fittings
Disadvantages: •
Could shield cathodic protection if tape fails
Uses: •
Reinforce heavily corroded lines
140 Water-based Coatings Chevron Corporation OpCos are required to use coating systems that meet both federal and local regulations controlling the emissions of VOCs. Because water-based coatings use water instead of solvents as the pigment carrier, they typically do not contain any “Volatile Organic Compounds” (VOC) that could be released into the air. Many OpCos may, in the future, be required to use water-based coating systems in order to meet these regulations. After 6 months of testing the major manufacturers’ water-based coatings, Chevron has concluded that several are acceptable for inclusion in the Coatings Manual. However, since these coatings do not perform as well as solvent based coatings, we
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cannot recommend them for severe exposure environments (ie: offshore or industrial environments). Refer to the “System Number Selection Guide” in the Coatings Manual Quick Reference Guide for a listing of the acceptable brands of water-based coatings for both new construction and maintenance systems.
150 Coating Systems for Immersion Service Coating systems usually include a first coat (primer), second coat (tiecoat), and a final coat (topcoat). There are three types of coating systems for immersion service and each is described below along with its advantages, disadvantages, and cost. The coatings described are: • • •
Non-reinforced, thin-film coatings Glass-flake-reinforced coatings Laminate-reinforced coatings
151 Non-reinforced Thin-film Coatings Typically only 10 to 20 mils thick (thin films), these non-reinforced coatings: •
Contain no glass flakes or fibers or laminates for reinforcement
•
Usually have inert fillers such as silica or carbon to reduce shrinkage during cure and to improve abrasion resistance
•
Resemble some of the high-build layers of external coating systems
•
Usually are spray applied in two or more coats: a primer/sealer and one or two high-build topcoats
•
Have recommended dry film thickness (DFT) of 15 to 20 mils—thicker systems for more severe services
Most thin-film coatings for tanks are based on epoxy resins, although vinyls, inorganic zinc, and other types of coatings have been used. Advantages: • • • • •
Low cost Use least amount of material Require no expensive hand work Easiest to apply Product purity
Disadvantages:
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Lack of thickness leads to no resistance to abrasion, severe chemical attack, physical abuse
•
Absence of reinforcement means inability to bridge existing cracks
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•
Always have some damaged areas, called holidays
Uses: • •
Temporary service Protection from mild corrosion, splash, or spillage environments
Note Apply and inspect this coating system properly to ensure that there are relatively few holidays. The small amount of corrosion which occurs will not be a problem in mild-corrosion environments if the product is pure. If the corrosion environment is severe, however, the holidays will initiate pits that quickly become unacceptable leaks. For severe corrosion service, pre-coated tanks may have similar problems if they are scratched or damaged while being erected. For severe corrosion applications, select a thin film coating if the tank’s interior is also cathodically protected to prevent corrosion at damaged areas of the coating. [1]
Life Expectancy The expected life of a thin-film internal coating is approximately ten years. After ten years, the coating commonly blisters, and corrosion at holidays is usually occurring over enough of the surface that blasting and replacing the entire coating are required. Note Early failure due to blistering often indicates either a problem with the surface preparation or an incorrect coating selection. Periodic inspection and repair (touch-up) of the internal coating may extend its life. As the Company inspects tanks on a ten-year cycle, periodic inspection and touchup is usually not possible.
Limitations and Cost Because they can be sprayed, thin-film coating systems are generally the easiest and fastest to apply, and also the least expensive. Example: For a tank over 50,000 bbls, it might take a total of four weeks at a minimum to carry out the entire project: • • •
Approximately two weeks to clean, blast, and prime Approximately one week to apply the coating An additional week for final curing
Ease of application and cost also vary among different categories of thin film coatings. Factors which make a coating easier or more difficult to apply include: • • • • •
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Its ability to flow smoothly and form an even film How well it “hangs” on vertical surfaces without running or sagging Its tendency to form pinholes Its tolerance to inadequate surface preparation The amount of drying time required between coats
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These factors also vary from product to product within a category, so it is difficult to make general statements. Coal-tar epoxies are, however, usually very easy to apply and relatively inexpensive, but the black color makes them difficult to inspect. Straight epoxies (polyamides or amine adduct) are also fairly easy to apply and only slightly more expensive than the coal tars. Epoxy-phenolics are often significantly more expensive and more difficult to apply.
152 Glass-flake-reinforced Coatings Glass flakes in coatings, available in spray and trowel formulae: • •
Make the coating less permeable and more abrasion resistant Reinforce the resin, allowing thicker film buildup
Note
Epoxy and polyester resins are used for glass-flake-reinforced coatings.
The main difference between these two formulae is that the trowel coatings have larger reinforcing glass flakes than the spray. The layers are therefore as follows: • •
Trowel: Two 20 to 40 mil (DFT) coats for a total of 60 to 80 mils (DFT) Spray: Two 15 to 20 mil (DFT) coats for a total of 30 to 40 mils (DFT)
Coatings applicators must roll each layer of both spray and trowel formulae to orient the glass flakes parallel to the surface. Rolling reduces the permeability of the coatings. Cathodic protection should not be required with glass-flake-reinforced coatings (especially trowel-applied types) because they are so thick and are not easily damaged. Advantages: •
Both (trowel and spray) are more protective than thin-film coatings because they are thicker and have fewer holidays.
•
Both are highly advantageous in services where erosion or abrasion would damage thin-film coatings.
•
Spray can be applied at twice the thickness of thin-film systems, and over more uneven surfaces—because of the coating's thickness—than thin film.
•
Trowel is more resistant to chemical attack, abrasion, and physical abuse than either spray formula or thin-film coatings.
Disadvantages:
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Spray is marginally more expensive than thin-film coatings and rolling is required to improve resistance to chemical attack.
•
Trowel is much more expensive than thin-film coatings; it is considerably more difficult and time-consuming to apply than either the spray formula or thin films, and hand smoothing and rolling is required.
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Note The cost of glass-flake-reinforced coating may be justified if corrosion rates are expected to be relatively high but not severe, or permeation through the coating is a potential problem. Uses: Recommended for both mild and severe corrosion applications. Generally, select: •
Spray for mild corrosion and for uneven surfaces
•
Trowel for severe corrosion (as an alternative to a thin-film coating with cathodic protection)
Note This coating system is the most widely used one for concrete because of its excellent properties for most environments and lower cost than laminate systems.
Life Expectancy Expect glass-flake-reinforced coatings to last at least ten years before inspection. Depending on the condition of the coating and the service, making necessary repairs may allow the coating to last another ten years. Frequently, however, it will be necessary to replace the coating after only ten years, especially for sprays. Trowel applications have a better chance of lasting through a second decade.
Limitations and Cost The spray-applied glass-flake-reinforced coatings are usually only slightly more difficult to apply than non-reinforced coatings. Rolling the glass flake properly takes additional time during application. Spray-applied glass-flake coatings are more costly than non-reinforced coatings. Trowel-applied glass-flake coatings are considerably more difficult and time consuming to apply than sprays. The coating is hand smoothed and rolled to orient the glass flakes. Coating application may take two to three weeks for an average size tank (increasing the total time to five to six weeks), and the total installed cost will be higher than sprayed glass-flake coatings. Epoxy-glass-flake coatings are generally easier to apply than polyesters or vinyl esters, both of which require a final wax coat to obtain full surface curing. If the coating is premixed with wax, common for sprays, the coatings applicator must apply the second coat within the manufacturer-specified time (known as the maximum allowable time) because the second coat will not adhere well if the wax layer has fully cured the first coat.
153 Laminate-reinforced Coatings The coatings applicator applies laminate reinforced coatings by hand, alternating layers of resin and fiberglass mat to a total thickness of typically 80 to 125 mils. Generally, they apply three layers of resin and two layers of mat. For some services, specifications call for an additional layer of a special surfacing veil of chemical grade glass or polyester and another coat of resin.
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Note The veil prevents any glass fibers from protruding through the resin surface, which could allow wicking or chemical attack of the glass itself. After the completed laminate is inspected, the coatings applicator applies a final coat of resin. For epoxy resins, this gel coat simply provides additional protection from chemical attack. For polyester resins, the coatings applicator adds a wax to the final resin coat to obtain full curing. Without the wax coat the surface of a polyester coating always remains slightly tacky and lacks its optimum chemical resistance, and the body of the laminate cures very slowly. Advantages: •
A laminate-reinforced coating provides the best protection against severe corrosion.
•
Laminates should not require cathodic protection as they should not contain any holidays.
•
A laminate is the only type of internal coating which has significant structural strength by itself.
•
Because it does not need to be as thick, epoxy-resin laminates are less expensive than polyester or vinyl ester laminates.
Disadvantages: •
Compared to thin-film and glass-flake-reinforced coatings, laminates are the most expensive coating.
•
Laminate-reinforced coatings are the most difficult and time consuming to apply.
Uses: •
Laminates are generally used for stockside corrosion only when there is severe corrosion or when underside corrosion is expected or has occurred.
Life Expectancy Laminate reinforced coatings will last for 20 years, but inspect and repair them after 10 years. Eventually, the laminate will start to crack and lose its adhesion to the steel, especially if the tank bottom flexes or settles significantly. If underside corrosion occurs, remove the coupons to check the condition of the steel bottom. Replace the laminate and the bottom if the bottom is essentially corroded through.
☞
Caution
Never apply a second laminate over a failed laminate.
Limitation and Cost Laminate-reinforced coatings are the most difficult and time consuming to apply. The hand layering of fiberglass mat is a slow process, normally requiring at least three weeks for an average-size tank, increasing the total time to a minimum of six
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weeks. Laminates are also expensive. The total cost per square foot is equal to or higher than that of trowel-applied glass-flake coatings. Because it does not need to be as thick, epoxy-resin laminates are less expensive than polyester or vinyl ester laminates. Polyesters and vinyl esters require a final wax coat to obtain full surface curing; however, as they remain fluid longer before starting to cure, they are easier to use. Note
The time between mixing and cure is called the gel time.
The coatings applicator can adjust the gel time by mixing different amounts of catalyst and promoter into the resin. After the resin sets, it will reach 90 percent of full cure in a short time. As epoxy resins do not have a gel time, they cure at a relatively constant rate, starting immediately after mixing, and therefore do not remain as fluid for as long as laminates.
160 Quality Control 161 General Information Do the job right the first time. Essentially a system of checks and balances, quality control helps ensure that a project’s participants fulfill the specification’s requirements. For coatings projects, the process should yield a high-quality result that: • •
Contributes to the maximum service life of the structure and equipment Reduces future expenditures for field maintenance
Offshore Achieving high-quality coatings is more difficult offshore than onshore due to some of the following conditions: •
Adverse weather
•
Simultaneous operations with other platform activities
•
Congested platform areas
•
Limited availability of transportation
•
Existing substrate surfaces that can be deeply pitted and contaminated with soluble surface salts
•
Inaccessible items
Careful design and planning help to minimize the effects of these conditions. A major component of quality for offshore coatings includes cure and recoat times before returning a facility to service. Critical areas are the +/- 10-foot splash zone, work decks and helidecks, and sweating equipment and piping. See detailed information about quality control for offshore coatings in Section 800 of this manual.
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Keys to Successful Projects Comprehensive quality control activities are, however, key to any successful project. The quality control for a specific project depends not only on type of project but also on available resources: financial and personnel. Most projects have the best financial result over the structure’s life by involving qualified individuals in the project at the most appropriate time for as long as necessary to ensure that the specifications are prepared properly and met. Regardless of the size, among the keys to success of any coating project are the specifications, specialists and inspectors, and the Company’s Project Development and Execution Process (CPDEP).
Specifications
☞
Caution Avoid the pitfall of writing specifications so vague and general that they confuse everyone and allow the contractor to provide substandard work. A well-written specification includes: • • • • •
Requirements for the pre-job conference Coating schedule for all items Work schedule Materials, including coatings and abrasive Minimum standards for equipment
Example: Equipment such as moisture traps on coating and blast pots, coating gun types and hose sizes, and quality of compressed air.
Coating Specialists and Inspectors Industrial coating applications are highly specialized work processes that require support from individuals with particular knowledge and experience: the coating specialist and inspector. Coating Specialist. A coating specialist provides the project's engineering team with: •
Advice about selecting, inspecting, and applying coatings
•
Information about premature failures
•
Technical and tactical recommendations for day-to-day activities and interaction with the contractor
Coating Inspector. The goal of the project's coating inspector, usually a contractor, parallels the program's objectives to ensure that all surfaces are prepared and all coatings applied within specification. The inspector: • •
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Enforces the specification during each phase of the work activities Maintains detailed records of the coating activities
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Note These records are extremely important in case of litigation and provide the engineering team with daily work updates and recommendations. See also the sections below on Inspections and Inspectors.
Company’s Project Development & Execution Process (CPDEP) By taking the Front End Loading (FEL) approach of CPDEP (adding coating experts to the team during the design-and-fabrication phases), the projects team eliminates the problem of materials leaving the fabrication yard with an aesthetically acceptable, yet otherwise short-term and non-corrosion-resistant coating. Example: During the 1980’s, one of the Company’s profit centers spent over $15MM to repair fabrication work that had failed prematurely (needing major re-work in four years or less). Costly replacement of corroded equipment/structures and repair of premature coating failures are often attributable to the work in fabrication yards.
162 Inspection Programs An inspection adage states: People do not as you expect. People do as you inspect. Inspecting a coating ensures that it meets specifications for the particular project and provides maximum protection over the coating’s expected life. In the Company, there are three inspection programs: one complete and two levels of partial inspections (Figures 100-2, 100-3, 100-4). The three inspection programs require inspectors of varying levels of qualification. The level of inspection chosen for a coating project is primarily a function of the acceptable risk involved if a coating fails prematurely. Corrosion and aesthetics are the two main reasons for applying an external coating. The engineer must choose the best inspection program to meet the needs of the particular project cost effectively. •
For external coating projects where corrosion is a concern, the Company recommends a complete inspection program, the most conservative, reliable, and costly method of inspection.
•
If aesthetics are the only concern, then either of the two partial inspection programs may be adequate; but some of these projects may require complete inspection.
The Company's representative and the inspector (if different) should agree on a method of reporting the test results and observations of the inspection. A copy of the Company's recommended form, COM-EF-844, is available in this manual. The inspector files a copy of reports with the Company's representative.
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Complete Inspections A complete inspection requires a full-time, qualified inspector. The most conservative and costly of the three programs, a complete inspection is recommended when a coating’s reliability is critical. The complete inspection checklist (Figure 100-2) is a compilation of items the inspector should examine to ensure that the work satisfies all requirements of the specification. While all items are important, they are ranked in terms of relative importance: c—critical, n—necessary, and a—applies. Missing an “a” item has lower potential effect on the life of the coating than missing the others. Fig. 100-2
Inspection Checklist—Complete Inspection (1 of 2)
A qualified coatings inspector ensures the lining work meets the Chevron Specification. The inspector keeps records (using the Company's Standard Form COM-EF-844 or another form agreed upon by the Chevron representative and the inspector) and files a copy of the report with the Chevron OPCO. Each inspection item below has a code letter that indicates its relative importance. Items marked with a (c) are critical, those with an (n) are necessary, and those with an (a) apply. All items are important; but, if an (a) item is missed, the potential impact on the coating life would not be as great as missing a (c) or an (n) item. I. Pre-Job Check Out
❏
A.
(c)
Review Chevron OPCO Specifications.
❏
B.
(c)
Check tank for inaccessible areas, laps, patches, rough welds, weld spatter, etc.
❏
C.
(c)
Check surface for grease, oil, moisture, etc.
❏
D.
(c)
Check abrasive for cleanliness, dryness, etc.
❏
E.
(a)
Check abrasive for type and size.
❏
F.
(c)
Check compressed air for oil and moisture.
❏
G.
(a)
Check nozzle air pressure.
❏
H.
(n)
Check that proper coatings and thinners are present.
❏
I.
(c)
Check to see the coating has not passed its shelf life.
❏
J.
(a)
Record product name, manufacturer, and batch number.
II. Surface Preparation
❏
A.
(n)
Check ambient conditions.
❏
B.
(c)
Check degree of surface cleanliness.
❏
C.
(c)
Check surface for salts or other contaminates.
❏
D.
(n)
Check surface profile.
❏
E.
(c)
Check dust and abrasive removal.
❏
F.
(a)
Take magnetic base reading.
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Fig. 100-2
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Inspection Checklist—Complete Inspection (2 of 2)
III. Application—First Coat
❏
A.
(c)
Check surface for flash rusting.
❏
B.
(c)
Check ambient conditions.
❏
C.
(n)
Check steel temperature.
❏
D.
(c)
Check proper mix ratio observed.
❏
E.
(n)
Check for proper thinner addition (when necessary).
❏
F.
(a)
Check wet film thickness.
IV. Application—Subsequent Coats
❏
A.
(c)
Check dry film thickness of preceding coats.
❏
B.
(c)
Check recoat times observed.
❏
C.
(c)
Check intercoat cleanliness.
❏
D.
(c)
Check ambient conditions.
❏
E.
(n)
Check steel temperatures.
❏
F.
(c)
Check proper mix ratio observed.
❏
G.
(n)
Check for proper thinner addition (when necessary).
❏
H.
(a)
Check wet film thickness.
❏
I.
(c)
Repeat for every coat.
V. Final Inspection
❏
A.
(c)
Check visual appearance.
❏
B.
(c)
Check dry film thickness.
❏
C.
(c)
Holiday test. (Required only for interior coatings)
❏
D.
(c)
Cure test.
❏
E.
(c)
Verify all touch-up and repair work.
❏
F.
(c)
Complete records and copy Chevron OPCO.
❏
1.
Verify compliance to specification.
❏
2.
List work, if any, not in compliance and why.
Partial Inspections The Company has two levels of partial inspection, Level 2 being the more limited. Partial Inspection Level 1. Partial Inspection Level 1 (Figure 100-3) differs from a complete inspection not only in the inspector’s qualifications and time on the project, but also in the number of tests required. The inspector examines or tests particular items—highlighted on the checklist— during and on completion of the work. Time and cost permitting, the inspector may
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also verify the critical and necessary items on the Checklist For Complete Inspection (Figure 100-2) as any extra inspection improves the coating’s reliability. Partial Inspection Level 2. Partial Inspection Level 2 (Figure 100-4) is the minimal inspection for any tank or vessel coating project and is recommended only if the Company is willing to accept the risk of premature failure of the coating
☞ Fig. 100-3
Caution Select Level 2, the lowest recommended level, only after evaluating the project carefully and considering the risks of a premature failure.
Inspection Check List—Partial Inspection—Level 1 (1 of 2)
All items listed are critical to Level 1 Partial Inspection and should be conducted by someone familiar with coatings inspection. This person may be a qualified inspector, an experienced Chevron inspector, or an engineer with a good knowledge of coatings inspection. The inspector should keep records (using the Company's Standard Form COM-EF-844 or another form agreed upon by the Chevron representative and the inspector) and should file a copy of the report with the Chevron OPCO. I. Pre-Job Check Out
❏
A.
Review Chevron OPCO Specification.
❏
B.
Check tank for inaccessible areas, laps, patches, rough welds, weld spatter, etc.
❏
C.
Check surface for grease, oil, moisture, etc.
❏
D.
Check abrasive for cleanliness, dryness, etc.
❏
E.
Check to see the coating has not passed its shelf life.
II. Surface Preparation
❏
A.
Check degree of surface cleanliness.
❏
B.
Check dust and abrasive removal.
III. Application—First Coat
❏
A.
Check surface for flash rusting.
❏
B.
Check ambient conditions.
❏
C.
Check steel temperature.
IV. Application—Subsequent Coats
❏
A.
Check dry film thickness of preceding coats.
❏
B.
Check recoat times observed.
❏
C.
Check intercoat cleanliness.
❏
D.
Check ambient temperatures.
❏
E.
Check steel temperatures.
❏
F.
Repeat for every coat.
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Inspection Check List—Partial Inspection—Level 1 (2 of 2)
V. Final Inspection
❏
A.
Check visual appearance.
❏
B.
Check dry film thickness.
❏
C.
Holiday test.
❏
D.
Cure test.
❏
E.
Complete records and copy Chevron OPCO.
❏
1. Verify compliance to specification.
❏
2. List work, if any, not in compliance and why.
Fig. 100-4
Inspection Checklist—Partial Inspection—Level 2 (1 of 2)
All items listed are critical to Level 2 Partial Inspection. This is the minimum inspection to be performed when lining a tank or vessel. With a little planning and thought, an OPCO engineer or construction representative can carry out all of these tests. The inspector should keep records (using the Company's Standard Form COM EF-844 or another form agreed upon by the Chevron representative and the inspector) and should file a copy of the report with the Chevron OPCO. I. Pre-Job Check Out
❏
A.
Review Chevron OPCO Specification Know what the specification requires so you can discuss it with the coating contractor.
❏
B.
Check tank for inaccessible areas, laps, patches, rough welds, weld spatter, etc. Linings will not cover irregular or rough surfaces adequately. Welds should be ground smooth and sharp corners rounded. If not possible, apply a stripe coat of the lining material after surface preparation.
❏
C.
Check surface for grease, oil, moisture, etc. The biggest cause of premature lining failures is a contaminated surface. Cleanliness is the single most important step in the lining of a tank or vessel.
❏
D.
Check to see the coating has not passed its shelf life. This is a simple step; old coatings are hard to apply and will not perform properly.
II. Surface Preparation
❏
A.
Check degree of surface cleanliness. Linings require abrasive blast cleaning the surface to a “White Metal Blast” (SSPC-SP5). See Abrasive Blast Coating Guide for Aged or Coated Steel Surfaces in the Coatings Manual for a visual guide to judging degrees of abrasive blast cleaning.
❏
B.
Check dust and abrasive removal. Visually check to see there is not any dust or abrasive residue on the surface to be lined. Dust or residue can cause the lining to have poor adhesion.
III. Application—First Coat
❏
A.
Check surface for flash rusting. After abrasive blasting, the surface can flash rust due to high humidity or salts on the surface. Linings applied over a rusted surface will fail prematurely.
❏
B.
Check surface for moisture. Do not apply linings if the surface is damp. This usually happens when the surface is below the dew point. Linings applied over moisture will not adhere.
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Inspection Checklist—Partial Inspection—Level 2 (2 of 2)
IV. Application—Subsequent Coats
❏
A.
Check recoat times observed. Most linings have a maximum and minimum recoat time. The times are dependent on the temperature; higher temperatures equal shorter times. The lining manufacturer’s data will give you the recoat time at a standard temperature. If your temperature is different, call the manufacturer’s representative.
❏
B.
Check intercoat cleanliness. Make sure the first coat has not been contaminated before applying subsequent coats.
❏
C.
Repeat Sections III & IV for every subsequent coat.
V. Final Inspection
❏
A.
Check appearance. Visually check for runs, sags, skips, etc. If the job looks good, then the contractor probably did a good job. If not, you might want to do some of the testing listed in Partial Inspection, Level 1.
❏
B.
Check dry film thickness. While present, have the contractor calibrate his dry film thickness gage and randomly check the lining to see if it meets the specified dry film thickness.
❏
C.
Final Cure. Check with the lining manufacturer on how long to wait before putting the tank or vessel in service. Circulating hot air through the tank or vessel will shorten the time.
❏
D.
Verify all touch-up and repair work. There will usually be some touch-up or repair work, so verify that it has been done.
❏
E.
Complete records and copy Chevron OPCO.
❏
1. Verify compliance to the specification.
❏
2. List work, if any, not in compliance and why.
163 Inspectors To carry out a thorough inspection, the inspector may be a Company employee or a contractor but must be trained, experienced, and familiar with a variety of coating methods and equipment. Whether full- or part-time, the inspector should participate in all inspections at the completion of the coating contract and must inspect the finished project before the end of the contractor’s guarantee.
Qualifications Full-time Inspector. A qualified, full-time coatings inspector must have one of the two backgrounds below: Certified and experienced. • •
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National Association of Corrosion Engineers (NACE)-certified Level III Experience inspecting tank and vessel coatings
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Uncertified, trained, and experienced. •
No certification
•
Some industry-accepted training
•
At least five years of verifiable experience inspecting coatings on tanks and vessels
Example: Industry training coating courses are offered by KTA-Tator, S.G.Pinney, or Bechtel. Part-time Inspector. A qualified, part-time inspector must be: • • •
Familiar with the different methods of inspection Capable of identifying potential problems and analyzing results Experienced in coating inspections
This inspector may be • • •
A qualified third-party inspector An experienced Company inspector An engineer familiar with coating inspections
Responsibilities Full-time inspector. The full-time inspector reviews the project prior to start up and is present whenever the fabricator is working offsite or the contractor onsite and during hold points in the project, normally: • • • • •
Prior to starting work After preparing the surface Prior to applying each coating Following application of the final coating Following the final cure
Part-time inspector. The part-time inspector must be available to examine the coating during the project's hold points.
Guidelines for all Inspectors The inspector: •
Should remain unchanged for the duration of the project
•
Must be able to reject work on any area which satisfies neither the specification nor good practice
•
Should not relax the requirements in the specification without written instructions from the Company's representative
•
Should conduct business in a professional manner at all time and: – –
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– – •
Interact with the foreman on all matters concerning coatings applicator and work practices—not supervising coatings applicators directly Anticipate problems; initiating preventive action
Must have a reasonable period of time to review and become familiar with the specifications, contract documents, and the worksite before the project begins
Note Familiarity with the worksite means learning about the accessibility to and condition of the structure for the coating project.
Evaluation Reports The Company's representative should prepare an evaluation report about the inspector's work.
164 Monitoring Progress The time it takes a coatings applicator to move from one operation to another affects the cost of a project.
Initial Setup Time The first transition period begins when the coatings applicators start work and ends when they begin the first daily activity; usually blasting, coating, or rigging. If a coatings applicator consistently requires more than the allotted time to set up, the inspector should investigate and take appropriate corrective action.
Transition Times Transition time may demonstrate the foreman and crew's effectiveness and the overall organization of the operation. Example: If an eight-man crew has one hour of excessive transition time, the effect is equal to an additional eight-and-a-half manhours for the project. See Figure 100-5. Fig. 100-5
Transition Times for Coating Crews Exceeds Normal Transition By
Additional Man Hours
Setup
30 Minutes
4
Blowdown
20 Minutes
2.5
Paint Pot Refill
5 Minutes (each refill)
2(1)
Activity
Total
8.5
(1) Based on 30 gal (114L) with two 5-gal (19L) setups
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165 General Inspection Procedures See the Quick Reference Guide of this manual for information about ordering inspection tools and standards.
Daily The following should be completed on a daily basis: •
Conduct pre-inspection of work area before blasting and coating, checking for protection of equipment, inaccessible areas, and hazardous areas
•
Meet with the foreman of the coatings applicators to plan daily work schedule, discuss positive aspects and potential problem areas of project, compare paperwork
•
Coordinate work with production activities
•
Order materials on timely basis
•
Check contractor's equipment
•
Check work and safety practices for compliance
•
Ensure that work area is square and clean
•
Prepare and submit reports; report to the Company's representative, as required
Before Surface Preparation Surface preparation is critical to any coating project. Faulty surface preparation is estimated to contribute to 75 to 80 percent of all premature failures of coatings. Example: Surface preparation factors that affect the life of the coating include: •
Residues of oil or grease
•
Residues of chemical salts, rust, and loose or broken mill scale which lead to early failure
•
Tight mill scale, which leads to longer term failure, and surface condensation
•
Defects found before or after surface preparation
Before surface preparation begins, the inspector should:
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•
Examine surfaces to decide how much preparation is required; good lighting during examination is very important
•
Record the condition of steel surfaces and include all information on such defects as rolling laps, cracks and pitting
•
State the condition of surfaces other than steel
•
Check for protection of equipment, inaccessible and hazardous areas
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Weather Conditions. The weather required for abrasive blasting is the same as for coating. To ensure that rust does not form on the abrasive-blasted surface before a coating is applied, specify that the area blasted with abrasive be no larger than can be coated within the same day or within eight hours of blasting. The inspector should: • • •
Determine the weather window needed to prepare the surface and apply coatings Check the weather forecast Read the coating data sheets for acceptable temperature and humidity ranges
Air Compressors for Blasting. Air compressors for blasting should supply oiland water-free air at the correct pressure. The inspector should check the compressor regularly (daily, unless tests show the equipment to be in good working order) by releasing air into a white cloth and checking it for moisture or contamination. If surface cleaning is poor or proceeding slowly, the inspector should: •
Test the nozzle's air pressure by inserting a hypodermic needle air-pressure gage into the hose as close to the nozzle as possible
•
Check the nozzle with a nozzle-throat gage to ensure that the orifice is the proper diameter
•
Not rely on pressure readings at the compressor as these differ from nozzle pressure due to pressure loss in the hose. Typically, 100 psig is required at the nozzle to obtain adequate cleaning and productivity.
Abrasive material. Abrasive material should be clean, dry, and the correct type and size for the specific work. The inspector should ensure it meets these criteria.
After Surface Preparation The inspector should check all surfaces when the preparation is completed and immediately before coatings applicators apply any coating. The surface must meet the preparation requirements for the specified coating system. The inspector should judge the preparation quality: •
Of hand-cleaned steel against the relevant SSPC (Steel Structures Painting Council) standard
•
Of blast-cleaned steel against the relevant SSPC or NACE standard
•
By visual comparison against the Swedish standards, NACE Pictorial Standards, or the SNAME (Society of Naval and Marine Engineers) standards
The inspector should measure the roughness of the surface to ensure that the blast profile complies with the specifications. Note Testex Press-o-Film Replica Tape with a spring micrometer is the best way to measure surface profile.
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Before Applying Coatings The coatings applicator arranges for repair and reblast of all surface defects exposed by preparation before applying coating. The Company’s engineer should review and approve the repair method. Coating Supplies. The inspector should check supplies at the jobsite to ensure that: •
The correct coating is on hand
•
Sufficient quantities are available
•
The shelf life is not exceeded
•
The correct thinners are available for thinning the coating material, if required, and for cleaning equipment
•
Storage conditions are adequate
Method of Application. The coating contractor is usually free to choose the method of application; however, it must comply with one of the manufacturer's recommended procedures. If there is doubt, the Company's representative should require the contractor to run a test, proving that the coating film of the proposed method complies with the specification. The inspector should be present during tests and should judge the results. Mixes, Proportions, Incubation. Before the coating is applied, the coating inspector should ensure that: • • •
All coatings are properly mixed Multi-component coatings are in the correct proportions Proper incubation periods are met
Note Inadequate mixing or improper proportioning of multi-component coatings can cause soft spots which may dry a slightly different shade of color.
During Coating The inspector should check that each layer of a coating system meets the specifications for: • • •
Coating thickness General quality of the coating, such as hardness, freedom from pinholes, or sags Dry film thickness (DFT)
The coatings applicator should:
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•
Thin the coating according to the supplier's data sheets
•
Check viscosity before applying thinned coatings
•
Check the coating's film thickness with a wet film thickness gage immediately after applying it
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The coating contractor must know the thickness of films specified by the manufacturer. The specifications usually give normal DFT and place a limit on maximum thickness; some give maximum and minimum values. Although coating manufacturers specify only DFTs, inspectors should: •
Use wet film measurements for control during actual application Multiply wet film thickness by the volume percent solids of the coating; the result gives the actual DFT of the coating
•
Measure the thickness of wet-coating films with comb gages A representative from the Company, not the contractor, should approve gages for measuring dry film thickness. The coatings applicator should calibrate the gage daily according to the National Bureau of Standards' Calibration Standards. If films are not the correct thickness, the coatings applicator must adjust both the technique and equipment appropriately to meet the specification and to avoid rework.
Note Refer to industry standard SSPC-PA2, “Measurement of Dry Paint Thickness With Magnetic Gages.”
Five Critical Subjects of a Final Inspection The five critical subjects in the final inspection of a coating project are appearance, dry film measurement, curing tests, touch-up and repair verification, and inspection records. Appearance. The appearance of a coating can highlight problems with aesthetics or suggest probable, premature failures of the coating. The inspector can assure that there are no runs, sags, blistering, or pinholes by checking the appearance of the coating. Dry Film Measurement. The inspector must measure the dry film thickness to ensure that coatings applicators have applied the specified proper amount of coating. Curing Tests. Surface temperature, ambient conditions, coating formulation, and film thickness affect the curing rate. Laboratory testing of coating chips is the only true means of verifying cure. Field techniques include the following: •
☞
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Solvent rub—On epoxy coatings, the inspector rubs the surface of the coating with a clean cloth saturated in a strong solvent, such as methyl ethyl ketone (MEK) or methyl isobutyl ketone (MIBK). If the material is mixed and cured properly, no color will transfer to the cloth. If the coating is mixed or cured improperly, it will redissolve and the color will transfer to the cloth.
Caution
Do not use the solvent rub test for alkyds and vinyl.
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•
Sandpaper test—The inspector abrades the coating with fine sandpaper. If properly cured, it produces a fine powdery residue; if not, a slightly tacky coating remains on the sandpaper.
•
Hardness test—The inspector checks the coating's cure with a Barcol hardness tester or pencil hardness tester by: – – –
•
Exerting a light, perpendicular pressure on the instrument which holds a hardened steel indentor, ground to microscopic accuracy. Reading the spring-loaded indentor's level of penetration directly from a scale's dial which is divided into 100 graduations. On soft materials, this device takes the highest reading because cold flow permits the spring-loaded indentor to continue penetrating. It is available in several models, according to the relative hardness of the test material.
Thumbnail test (can the coating be scraped or removed?) - Popular with experienced inspectors, the thumbnail test is an effective means of determining the need for more qualitative testing methods.
Touch-up and Repair Verification. The inspector verifies all touch-up and repair work and includes this information in the final report. Inspection Records. The inspector gives copies of all records to the Company's representative and completes the following: •
Daily, written reports of all items checked and verifying that the coating project complies with any specifications, giving reasons for any work that does not
•
A final report not only giving comments on repairs, overall assessment of the project, and ideas for improvement, but also with all daily reports attached
Both the Company's representative and the inspector should sign the final report.
166 Specific Inspection Procedures Downhole Tubular Coatings The inspection section of specification COM-MS-4732 contains the recommended inspection program for coatings projects involving downhole tubulars. Those who need assistance interpreting the specification or have any questions pertaining to the specification should contact the Company's coating specialist listed in the Quick Reference Guide.
Internal Coatings In addition to the general inspection procedures, the following items apply to internal coatings. Temperature and Humidity. Weather conditions are critical to the application and curing of coatings. The inspector must make sure the surface is dry and temperature is above the dew point to avoid condensation. Almost all internal coatings cure by a chemical reaction which produces heat and will not cure properly if the
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ambient temperature is too low. The guidelines for temperature and humidity in COM-MS-4738 are acceptable for most internal coatings, but always check the manufacturer’s instructions too. The inspector must read and then record atmospheric conditions in the daily reports to verify that no moisture is present on the surface to be coated. Film Thickness. Inspectors measure dry film thickness (DFT) with a magnetic filmthickness gage or a Company-approved equivalent. They should check film thickness of each coat and the final thickness of the coating. Each coat should be within the specified range because an extra heavy coat (applied to correct another coat’s insufficient thickness) may crack or cure improperly. The inspector should ensure that the coatings applicator repairs any defects after applying each coat.
☞
Caution
Using a subsequent coat to cover defective areas is unacceptable.
Pinholes and Holidays. The inspector must examine 100 percent of the finished coating for pinholes and holidays. •
Check thin films (1 to 20 mils) with a low-voltage (67-volt), sponge holiday detector, which sounds an alarm if the fluid in the sponge comes in contact with the underlying steel.
•
Check thick-film coatings (20 to 200 mils) with a high-voltage (nondestructive voltages of usually 100 to 150 volts per mil) holiday detector. This voltage gives the spark enough energy to jump across the gap between the coating surface and the underlying steel if a holiday exists, but not enough energy to break through the coating.
Most coating resin materials (epoxies, isopolyesters, vinyl esters) have a dielectric strength of 300 to 350 volts per mil. It is important to have sufficiently high voltage to bridge the pinhole's air gap to the steel substrate without burning through the solid coating. The voltage recommendations of the coating suppliers are normally acceptable. Note If a final wax or gel coat is required, the inspector should carry out the holiday test and require coatings applicators to make any repairs before the final coat is applied. This requirement prevents the wax or gel coat from covering up possible holidays in the underlying coats. If the coatings applicators make any repairs after applying the wax or gel coat, they must remove that coat and re-apply it after completing the necessary repairs. Water Test. Scheduled after the voltage test, the water test involves filling the tank with water (sometimes salt water) and leaving it for several days. After the tank is drained, rust spots on the coating reveal pinholes. The test is more complete than the voltage test because water touches all surfaces of the tank; the low-voltage sweeper may miss some parts. Note The Company runs the water test infrequently as it is expensive and time consuming.
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Testing for Final Surface Cure. The inspector must test the final surface cure of laminates with a Barcol hardness tester and an acetone wipe test. This requirement is particularly important for isopolyester and vinyl ester resins which will not fully cure without a wax coat. Note The coatings applicator must sand off the wax layer to obtain an accurate test because full surface curing is essential for the coating to have its optimum chemical resistance.
Offshore Coatings The inspection process for offshore coatings is detailed in specification COM-MS-4771. Those who need assistance with interpreting the specifications or have other questions pertaining to the specification should contact the Company’s coating specialist (see the Quick Reference Guide).
Pipeline Coatings There are many different types of pipeline coatings, each with many completely different properties and application procedures. The Company therefore recommends following the inspection procedures written as part of the various specifications for each type of coating system. Those who need assistance with interpreting the specifications or have other questions pertaining to the specification should contact the Company’s coating specialist.
☞
Caution Due to the environmental risk associated with the failure of a pipeline coating, the Company recommends following the most complete inspection program available, which includes having a full-time, qualified inspector.
167 Instruments, Tools, and Equipment The inspector must have available all of the instruments, tools, and equipment necessary to perform the inspection tasks properly. The following is a list of coating tests and test tools: •
Ambient Coating Condition –
•
Psychrometer—For determining temperature, humidity, and dew point at the jobsite
Surface Temperature Gage—For measuring the temperature of steel
168 Protecting the Company’s Equipment Many of a project's methods, costs, and problems are related to protecting the Company's equipment. The following are simple, efficient, and cost-effective procedures for protecting common equipment items. The inspector must monitor these procedures closely and ensure the coatings applicators perform them before and throughout blasting and coating operations.
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Wrapping Lights Problem:
Protective light lenses are sensitive to overblast and overspray.
Solution:
Wrap in plastic sheeting and duct tape.
Problem:
Sheeting melts on the protective lenses.
Solution:
Wrap lenses in chicken wire before wrapping in the sheeting. This will prevent sheeting from melting and provide more permanent protection for the entire job.
Plugged Drains Problem:
How to prevent sand from clogging drains while allowing small amounts of water to drain through when raining or when washing area.
Solution:
Stuff filter media (woven polyester fibers, and adhesives for filtering air intakes on engines) into the drain and tie to the cover with a piece of manila twine.
Problem:
Drains surrounded by troughs. Can coatings applicator remove sand without shoveling out each trough?
Solution:
Lay a sheet of filter media over the trough in addition to plugging the drain.
Protecting Sensitive Equipment A common misconception is that, during dry blasting, you cannot filter air intakes on compressors and other engines; therefore, costly wet blasting is necessary. Problem: How to prevent sensitive equipment from the contamination of blasting by taking oil samples, installing filter media, and installing filters. Solution 1 – Oil Samples: 1.
Before blasting operations begin, take an oil sample from each engine and send it to a lab for analysis to identify any previous sand or other particle contamination.
2.
When blasting has started, take an oil sample from each engine at least every two weeks for the duration of the project to identify any potential problems and allow time for corrective action before any major damage occurs.
Solution 2 – Filter Media:
November 1998
1.
Install filter media (to trap particles of five microns or less) with the adhesive side on the outside to catch small abrasive and dust particles and to prevent the unit from sucking the sticky side into the primary filters.
2.
Ensure coverage of all possible air passageways into the equipment, covering each corner and edge of the filter housing.
3.
Install two layers of media, where possible, to ensure 100 per cent filtration at all times and to eliminate unnecessary downtime during blasting. Change the
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100 General Information
outer layer only; leave the inner layer to filter dust during the several-minute changeout process. 4.
Monitor the filtration closely to ensure that it is adequate and installed properly.
Containment Screens Problem:
Isolate particular areas to keep the remainder of a facility clean during blasting (reduces cleaning time).
Solution:
Strategically position containment screens, usually square or rectangular polypropylene solid or mesh screens of various sizes from 40 ft. × 40 ft., to collect spent blast abrasive, dust, and airborne particles of coating.
Protection from Overblast Problem:
How to reduce overblast significantly (and premature failure of coatings) with proper blasting and coating techniques and preventive wrapping and shielding.
Solution 1– Keep your work area square means completely blasting and Squaring Work coating an entire group of items without having to return to the Area: area for additional blasting. Requires proper planning, thorough inspection, and precise instructions to blasters. Note Items in square work area include the tops and bottoms of all piping, braces and stiffeners, the interior of the wide flange beam webs and flanges, and the bottom side of the beam flanges. Solution 2 – Blasting Procedures:
Re-sweep before squaring work area after carrying out several days of rough blasting with appropriately sized blast nozzles and abrasive. Proper blasting technique ensures the blast nozzle is pointed away from previously coated surfaces and toward the surfaces to be blasted, especially during touch-up feathering and spot blasting.
Note Rough or high-productivity blasting calls for larger nozzles, orifice sizes of 5/16 inch or larger venturi; spot and touch-up blasting require smaller nozzles, 3/16 inch or smaller, with straight-bore orifices. Solution 3 – During blasting and coating, wrap to protect all items that will Protective Wrap-neither be blasted nor coated. The cost of the labor and materials ping: necessary to add protective wrapping results in a far superior job and minimizes costs for rework of prematurely failed areas.
Common Shielding Plastic sheeting, tarpaulins, and burlap sacks are some of the more common shielding materials. Problems: •
Chevron Corporation
Plastic sheeting is susceptible to overblast damage.
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• •
Coatings Manual
Tarpaulins are expensive and damage easily. Burlap holds blowdown abrasives which could fall on cleaned areas.
Solution: Rubber sheeting and plywood. Both have distinct advantages over common shielding. Rubber Sheeting. Although the initial cost of rubber sheeting is relatively high, $3 to $4, per linear foot ($8 to $10 per linear m) for a 36-inch (90 centimeter) wide section, its purchase is justified because of its many advantages. One-eighth-inchthick (three-millimeter thick) rubber sheeting is •
Pliable – –
•
Works into tight spaces on vessels Wraps around piping and flanges
Resilient, so that abrasive – –
Simply bounces off Causes little damage to sheeting
•
Easy to cut as needed
•
Re-usable
Plywood Sheeting. Normally, most coatings applicators do not use plywood to its full potential. Plywood makes: •
Good flooring material in the mixing area to protect areas such as platform decks from coating spillage
•
Dividers for several men working in a confined area. Drill holes around the perimeter for air circulation and observation, then stand plywood boards upright in a zigzag manner to help keep the boards upright.
•
A suspended ceiling to protect overhead items from overblast and overspray. Tie sections together to form the ceiling.
170 References 1.
November 1998
Chevron Corporation. Corrosion Prevention Manual. Chevron Research and Technology Company. Richmond, CA, January, 1994.
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Chevron Corporation
200 Environment, Health & Safety Abstract This section discusses considerations for coating projects involving environment and health, and includes standards and practices for lead and volatile organic compounds, surface preparation processes such as abrasive blasting, and proper disposal of wastes from coating projects. Information about workers' safety which focuses on the responsibilities of both the Company and contractors' personnel when working on Company projects is also provided along with descriptions of coating-related hazards—fire, explosion, and equipment—and their prevention.
Chevron Corporation
Contents
Page
210
Environment & Health
200-2
211
Air Quality
212
Lead in Coatings
213
Volatile Organic Compounds
220
Safety
221
Workers' Safety
222
Fire and Explosive Hazards
223
Equipment Hazards
230
References
200-17
200-21
200-1
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200 Environment, Health & Safety
Coatings Manual
210 Environment & Health The vehicles of many coatings described in this manual contain organic solvents which are volatile and are released to the atmosphere as the coating dries and cures. The Federal Environmental Protection Agency (EPA) has set standards limiting the amount of volatile organic compounds (solvents) that coatings may contain. These standards are not uniform throughout the U.S.; urban areas have the most stringent requirements. As a result of these regulations, manufacturers are developing new technologies and alternative products. Currently, they are taking two approaches: water-based coatings and high-solids coatings. To date, evaluations of these compliance coatings show their performances to be definitely inferior to existing products, with the exception of some higher-cost highsolids coatings. The Company now applies some high-performance, high-solids coatings that could substitute for other regulatory-restricted coatings. To help establish a history for new compliance coatings, it would be helpful if all users would: •
Keep records of their durability, application characteristics, and compatibility with existing coatings
•
Report findings to the coating specialist and CRTC's Materials and Equipment Engineering group (see list of Company contacts in the Quick Reference Guide)
211 Air Quality Coatings containing solvents contribute to air pollution during application and drying. It is important, therefore, that those who specify, purchase, or apply coatings know the air pollution-control regulations for the local area.
Background In 1963, the U.S. Congress passed the first regulatory Clean Air Act. Subsequent amendments created the Environmental Protection Agency (EPA) with the power to establish national ambient air quality standards (NAAQS). The Clean Air Act also required each State to create its own State Implementation Plan (SIP). The plan must ensure that all areas of the State meet the national standards. As motor vehicle exhaust and solvent evaporation are two of the biggest contributors to air pollution, the strictest regulations affect densely populated areas. (Many rural areas can meet the national air quality standards without regulation.) Direction. Air-pollution-control regulations are becoming more restrictive and widespread. In some areas, the sale or use of non-compliant coatings can result in fines of up to $1000 for each day of violation. Also, for those who knowingly continue to violate the law, the penalty can escalate to $25,000 a day.
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200 Environment, Health & Safety
Note Several good sources of information about those regulations are local enforcement agencies, coating vendors, coating contractors, and CRTC's coating specialists. Contact information for all except local agencies is listed in the Quick Reference Guide.
Blast Cleaning For dry, unconfined, blast cleaning, consider health and environmental safety restrictions when selecting the type and brand of abrasive. Many sand abrasives contain free silica, which, upon prolonged inhalation, can cause silicosis, a condition of massive fibrosis of the lungs that results in shortness of breath. For this reason, regulations often limit the acceptable amount of free silica in abrasives. Example: The Richmond Refinery limits free silica to 1 wt percent which eliminates the use of sand abrasive but not most grit, slag, and shot abrasive. Some abrasives cause a fine dust to form a dust cloud which some government agencies classify as visual-smoke pollution. Example: The State of California Air Resources Board (CARB) restricts the amount of fine particles in abrasives both before and after blasting.[1] Certain California counties also restrict the type of abrasives. Abrasives are tested in accordance with California Test Method No. 371-A, Method of Test for Abrasive Media Evaluation, and must meet the following criteria: • •
Before Blasting: 90%
16/30
1.9
Sand, medium
High
> 90%
12/25
2.5
Sand, large
Abrasive
High
> 90%
10/20
2.8
Steel grit No. G-80(1)
Very low
None
40
1.3
Iron grit No. 50(1)
Very low
None
25
3.3
Iron grit No. 40(1)
Very low
None
18
3.6
Iron grit No. 25(1)
Very low
None
16
4.0
Iron grit No. 16(1)
Very low
None
12
8.0
Steel shot NO. S-170(1)
Very low
None
20
1.8
Iron shot No. S-230(2)
Very low
None
18
3.0
Iron shot No. S-330(2)
Very low
None
16
3.3
Iron shot No. S-390(2)
Very low
None
14
3.6
Flint sand
Moderate
> 90%
8/30
3.4
Granite sand
Moderate
< 5%
12/40
3.0
Garnet sand(1)
Moderate
< 1%
12/40
3.3
Slag
Moderate
< 1%
8/40
3.6
Slag
Moderate
< 1%
10/50
3.5
Slag
Moderate
< 1%
16/30
3.8
Slag
Moderate
< 1%
20/40
2.5
Slag
Moderate
< 1%
16/50
1.5
(1) Only used in blast rooms and cabinets so abrasive can be contained, recycled and reused. (2) Generally used in automatic blast cleaning facilities using centrifugal wheels.
While protective clothing reduces hazards from dust and spray, vapors are harder to control. All solvents vaporize in air, but the degree of toxicity varies with the type of solvent, temperature, degree of confinement, and amount of ventilation. OSHA sets permissible exposure limits for many materials.[2] A permissible exposure limit (PEL) is defined as the maximum-permitted, eight-hour, time-weighted, average concentration of an airborne contaminant in ppm in air.[3] Adequate ventilation is essential to operate within these values. Figure 200-2 shows the PEL for commonly-used solvents in the coating industry.
September 1996
200-4
Chevron Corporation
Coatings Manual
Fig. 200-2
200 Environment, Health & Safety
Flammable and Toxic Properties of Commonly Used Solvents (1 of 2) Flashpoint °F of Open Cup
Toxicity P.E.L.(1), PPM in Air
Explosive Limits % of Volume in Air Lower
Upper
6.0
36.5
200
Alcohols Methanol (Methyl Alcohol)
60
Ethanol (Ethyl Alcohol)
60
3.3
19.0
1000
Normal Propyl Alcohol
96
2.6
13.5
200
Isopropyl Alcohol
55
2.5
400
Secondary Butyl Alcohol
74
1.7
150
Normal Butyl Alcohol
115
1.7
50
Cyclohexanol
154
50
Polyols Ethylene Glycols, Vapors
240
3.2
Propylene Glycol
215
2.6
Dipropylene Glycol
260
100 12.6
100 100
Esters Ethyl Acetate
30
2.0
11.5
400
Isopropyl Acetate
60
1.8
7.8
250
Normal Propyl Acetate
65
1.7
8.0
200
Isobutyl Acetate
105
1.6
Secondary Butyl Acetate
89
1.6
15.0
Normal Butyl Acetate
105
1.6
15.0
Amyl Acetate
80
1.1
Acetone
15
2.9
13.0
1000
Methyl Ethyl Ketone (MEK)
35
1.8
11.5
200
Methyl Isobutyl Ketone (MIBK)
75
1.2
8.0
100
Diacetone Alcohol
155
Cyclohexanone
129
Diisobutyl Ketone (DIBK)
115
50
Methyl Iso-Amyl Ketone (MIAK)
110
100
Isophorone
205
5
Ethyl Butyl Ketone
115
50
200 150 150 100
Ketones
50 1.1
50
Miscellaneous Active Solvents Tetra Hydro Furan (THEF)
6(2)
Dimethyl Formamide
153
Ethyl Ether
-40
11.8
200
1.8
36.5
400
10
Isopropyl Ether
Chevron Corporation
2.0
250
200-5
September 1996
200 Environment, Health & Safety
Fig. 200-2
Coatings Manual
Flammable and Toxic Properties of Commonly Used Solvents (2 of 2) Flashpoint °F of Open Cup
Toxicity P.E.L.(1), PPM in Air
Explosive Limits % of Volume in Air Lower
Upper
1.2
6.9
Aliphatic Petroleum Napthas Hexane
0
100
Rubber Solvent
0
1.3
6.1
400
Heptane
25
1.1
6.0
400
VM&P Naptha
54
1.1
6.0
Mineral Spirits(3)
110
300 200
Stoddard Solvent
105
1.0
6.0
200
Kerosene(3)
140
0.9
6.0
100
Pentane
-55
1.4
8.0
600
5
1.5
8.0
10
Aromatic Hydrocarbon Solvents Benzene Toluene
41
1.3
6.7
100
Xylene
81
1.0
5.3
100
Hi-flash Coal Tar Naptha
100
1.1
6.0
100
Styrene Monomer
106
1.1
6.1
100
Terpene Hydrocarbons Gum Turpentine
93
100
Steam Distilled Turpentine
91
100
Chlorinated Solvents Carbon Tetrachloride Dichloroethyl Ether Ethylene Dichloride Methylene Chloride, Technical
None
None
None
None
131 59
6.2
15.9
200
None
None
None
None
Glycol Ethers Ethylene Glycol Methyl Ether
120
25
Ethylene Glycol Ethyl Ether
115
115
Propylene Glycol Methyl Ether
100
100
Dipropylene Glycol Methyl Ether
185
100
(1) Permissible exposure limit per OSHA General Industry Safety Order Title 8, Table AC-1 (2) Closed Cub (3) OSHA gave no date. This date is from Chevron's Materials Safety Data Sheets No. 38 for Kerosene and No. 59 for Chevron 350 Thinner (Mineral Spirits).
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200 Environment, Health & Safety
212 Lead in Coatings Lead is a basic chemical element (Pb) that: •
Exists as a heavy metal at room temperature and pressure
•
Can combine with other substances to form many lead compounds, such as those found in lead-based coating (LBC)
•
Has been used in coating for many years to improve its effectiveness
Alternative primers are, however, more common today than LBC. The Consumer Product Safety Commission (CPSC) Lead Paint Act of 1971 has determined a coating to be lead-containing if the dried coating contains more than 0.06 percent lead by weight. In most Company facilities, specially trained and equipped contractors work in large lead-abatement construction projects with potentially high exposures to lead. The Company's employees are usually involved in short-duration maintenance tasks such as welding equipment with LBC or grinding and chipping to remove LBC from equipment before welding or applying new coatings. Other activities can be a source of lead exposure. •
Abrasive-blast cleaning of steel tanks and other structures with LBC generates high levels of dust.
•
Welding, cutting, and torch burning equipment coated with LBC may cause lead fumes.
•
Spraying LBC to recoat surfaces generates an LBC mist.
Health Hazards Lead adversely affects numerous body systems after periods of exposure from as short as days to as long as several years. Exposure to Lead. Human beings can inhale and absorb lead from dust, fumes, or mist through the lungs and upper respiratory tract. Inhalation of airborne lead is generally the most significant source of occupational lead absorption. People can also ingest lead and absorb it through their digestive systems. Consequences of Exposure to Lead. A significant portion of the lead inhaled or ingested reaches the bloodstream. Once in the bloodstream, lead circulates through the body and is stored in various organs and body tissues, affecting the nervous system, blood system, and kidneys. Chronic overexposure to lead also significantly impairs the reproductive systems of both men and women. Children born of parents exposed to excess levels of lead are more likely to have birth defects, mental retardation, behavioral disorders, or die during the first year of childhood. Some commons symptoms are listed in Figure 200-3.
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200 Environment, Health & Safety
Fig. 200-3
Coatings Manual
Alphabetic List of Common Symptoms from Overexposure to Lead in Coatings
Anxiety
Insomnia
Colic with severe abdominal pain
Loss of appetite
Constipation
Metallic taste in mouth
Dizziness
Muscle and joint pain or soreness
Excessive tiredness
Nervous irritability
Fine tremors
Numbness
Headache
Pallor
Hyperactivity
Weakness
Test Methods In Company facilities, conduct surveys to identify and quantify LBC in major equipment such as storage tanks, reactors, vessels, and even pilings. An inventory of leadcoated equipment could help to save time and money, protect Company and contract workers, and reduce Company liabilities. Both laboratory and field tests may then determine whether or not lead is present in the coatings. Note See the Quick Reference Guide of this manual for a list of some laboratories that analyze coating and air samples for lead. Atomic Absorption Spectrometry. A common laboratory test for lead in coatings is Atomic Absorption Spectrometry (AAS). AAS requires scraping a coating chip sample (e.g., about 0.5 square centimeter or the size of a dime) and sending it to a laboratory for analysis. The lab scrapes the surface down to the matrix material (i.e., bare metal, wood) because the analysis is based on weight. Processing time normally takes a few days unless the sample is rushed. The AAS method expresses results as weight-to-weight percentage of lead in the dry coating. Portable X-Ray Fluorescence Spectrum Analyzer. A non-destructive fieldtesting method, the portable X-Ray Fluorescence (XRF) Spectrum Analyzer, detects lead in the coating (including all layers of coating and the primer) and expresses the lead concentration in milligrams of lead per square centimeter (mg/cm2) of coated surface. The analyzer displays the result within a minute.
☞
Caution Because these instruments have a radiation source, only trained and licensed users may operate them. Note For information about the XRF spectrum analyzer, contact CRTC's Occupational Safety and Health Team. Chemical Spot Tests. Field-run chemical spot tests provide only qualitative results. These tests may, however, be useful as a screening tool in conjunction with the other test methods.
☞
September 1996
Caution Because the results are not as accurate as those from the AAS and XRF methods, chemical spot tests offer a much higher risk of false positives and negatives.
200-8
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200 Environment, Health & Safety
Exposure Standards and Assessment The OSHA Construction Lead Interim Final Rule (29 CFR 1926.62) establishes a Permissible Exposure Limit (PEL) of 50 micrograms of lead per cubic meter of air (50 g/m3) averaged over an 8-hour period, and an action level of 30 g/m3 averaged over an 8-hour period. Note The action level triggers requirements for exposure monitoring, medical surveillance, and training. This rule applies to construction, alteration, or repair, including coating and decorating This rule includes, but is not limited to, removing or encapsulating materials containing lead. For certain tasks, OSHA requires the employer to assume employees are exposed to lead over the PEL until exposure monitoring shows otherwise. Monitoring Requirements. OSHA requires exposure monitoring initially: • • •
For each job classification In each work area Either for each shift or for the shift with the highest exposure level
Note The samples must be full-shift personal samples and representative of daily exposures. Interim Protective Measures. As noted, for certain tasks, OSHA requires the employer to assume employees are exposed over the PEL until exposure monitoring shows otherwise. These tasks, and their assumed exposure level, are shown in Figure 200-4. Fig. 200-4
LBC-Removal Tasks by Exposure Levels. OSHA Construction Lead Interim Final Rule (29 CFR 1926.62)
Exposure Level
LBC-Removal Tasks 3
Above the PEL and not in excess of 500 mg/m (10 times the PEL):
Above 500 mg/m3 and not in excess of 2,500 mg/m3 (50 times the PEL)
Above 2,500 µg/m3
Chevron Corporation
•
Manual demolition of structures
•
Heat-gun applications
•
Power-tool cleaning with dust-collection systems
•
Spray coating with LBC
•
Lead burning
•
Use of lead-containing mortar
•
Power-tool cleaning without dust collection systems
•
Rivet busting
•
Cleanup activities where dry, expendable abrasives are used
•
Moving and removing abrasive-blasting enclosures
•
Abrasive blasting
•
Welding, cutting, and burning on steel structures
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200 Environment, Health & Safety
Coatings Manual
The following interim protective measures are required for these three groups of LBC-removal tasks: •
Personnel must wear appropriate respirators, personal protective clothing and equipment
•
The employer must provide hygiene facilities, biological monitoring, and training
In many cases for jobs of short duration, exposure monitoring can demonstrate that a respirator with a lower protection factor can be used. Figure 200-5 summarizes the Company's lead-exposure monitoring data for LBC. This information can help determine what level of respiratory protection may be needed. Exposure monitoring often demonstrates that a respirator with a lower protection factor is adequate for projects of short duration. Fig. 200-5
Summary of Coating-Related Occupational Lead Exposures at Chevron’s Facilities Number of Short-Term Air Samples (< 2 Hours)
Exposure Range of Short-Term Samples
Geometric Mean of Short-Term Samples
Number of Long-Term Air Samples (> 2 Hours)(1)
Exposure Range of Long-Term Samples
Geometric Mean of Long-Term Samples
Welding on metal parts or equip-ment which most likely contained some leadbased paint. In some cases, the paint may have been removed prior to the welding.
13
< 1 to 140
15
23
< 1 to 40
4
Short tasks of chipping or buffing to remove old paint from flanges or other equipment before applying new paint or before welding.
8
< 1 to 27
6
Torch burning, arc gouging, and cutting up scraps during demolition of tanks, vessels and towers.
69(2)
140°F, strong acids, bases, solvents
Severe coating loss due to abrasion, heavy equipment wear. Definite potential for impact on coating.
N/A
Continuous
N/A
N/A
Exposed to the corrosive medium for longer than 24 hours.
Intermittent
N/A
N/A
Exposed to the corrosive medium for less than 24 hours— usually splash or spillage that is cleaned up within 24 hours
Chevron Corporation
600-9
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600 Coating Concrete
Coatings Manual
631 Defining Conditions Before calling the Company's coating specialists, know the following information about the conditions anticipated for the concrete coating. Refer to Figure 600-1 for definitions, and also Figures 600-2 through 600-5 Environment. To what temperature and corrosive media is the coating exposed: aggressive, moderate, mild? Physical Abuse. To what extent is the coating exposed to abrasion such as from foot traffic, light cleaning, automobile traffic: aggressive, moderate, mild? Exposure. Is the coating exposed to chemicals continuously or intermittently? Fig. 600-2
Coating Recommendations for Continuous Immersion
640 Assessing and Repairing Concrete All concrete must be clean, dry, and in sound condition to receive a coating or lining system. While this surface may be easy to achieve with new construction, it may be expensive for existing structures. Before concrete can be prepared to accept a coating, ensure that the substrate:
September 1996
•
Is properly cured and dry. The coatings applicator should tape a black plastic sheet over the substrate and check for moisture after 24 hours (ASTM D-4263).
•
Has a minimum compressive strength of 3,000 psi
600-10
Chevron Corporation
Coatings Manual
Fig. 600-3
600 Coating Concrete
Coating Recommendations for Continuous Immersion Service
Recommendation #1: Use a laminate reinforced system to resist physical abuse and chemical attack. The resin selection should be reviewed with the coating manufacturer to ensure it is resistant to the corrosive media. It will probably be an epoxy novalac or vinyl ester resin. Because of the severe service obtain the assistance of a specialist knowledgeable in repairing and coating concrete. See the Quick Reference Guide for a list of recommended specialists.
Obtain the assistance of a specialist in coating concrete. By evaluating specifics of your project, he may be able to recommend a flake reinforced system instead. Depending on the size of your project this could result in considerable cost savings. Recommendation #5: Use a flake reinforced system to resist the chemical attack. The resin selection should be reviewed with the coating manufacturer to ensure it is resistant to the corrosive media. It will probably be an epoxy, epoxy novalac, or vinyl ester resin.
Recommendation #2: Use a flake reinforced system to resist chemical attack and the reduced physical abuse. A laminate system would work here but at twice the cost. The resin selection should be reviewed with the coating manufacturer to ensure it is resistant to the corrosive media. It will probably be a novalac epoxy or vinyl ester resin. Because of the aggressive corrosive media, obtain the assistance of a specialist knowledgeable in repairing and coating concrete. See the Quick Reference Guide for a list of recommended specialists. Recommendation #3: Use a flake reinforced system to resist chemical attack. Even with the mild physical abuse do not use a thin film system. The thicker flake reinforced system is required to resist the severe environment. The resin selection should be reviewed with the coating manufacturer to ensure it is resistant to the corrosive media. It will probably be a novalac epoxy or vinyl ester resin. Because of the aggressive corrosive media, obtain the assistance of a specialist knowledgeable in repairing and coating concrete. See the Quick Reference Guide for a list of recommended specialists. Recommendation #4: Use a laminate reinforced system to resist physical abuse. A flake reinforced system would be adequate to resist the chemical attack. The resin selection should be reviewed
Chevron Corporation
with the coating manufacturer to ensure it is resistant to the corrosive media. It will probably be an epoxy, novalac epoxy, or vinyl ester resin.
Recommendation #6: Use a flake reinforced system to resist the chemical attack. The resin selection should be reviewed with the coating manufacturer to ensure it is resistant to the corrosive media. It will probably be an epoxy, epoxy novalac, or vinyl ester resin. Recommendation #7: Use a laminate reinforced or a textile reinforced urethane system to resist the physical abuse. The resin selection should be reviewed with the coating manufacturer to ensure it is resistant to the corrosive media. It will probably be a polyester, epoxy, or modified urethane resin. Recommendation #8: Use a flake reinforced or a textile reinforced urethane system to resist the physical abuse. The resin selection should be reviewed with the coating manufacturer to ensure it is resistant to the corrosive media. It will probably be a polyester, epoxy, or modified urethane resin. Recommendation #9: Use a flake reinforced or a textile reinforced urethane system. Because this is immersion service, use a reinforced system. The resin selection should be reviewed with the coating manufacturer to ensure it is resistant to the corrosive media. It will probably be a polyester, epoxy or modified urethane resin.
600-11
September 1996
600 Coating Concrete
Fig. 600-4
Coatings Manual
Coating Recommendations for Intermittent Immersion/Splash/Spillage
•
Has a surface strength of at least 200 psi. To measure the surface strength, the inspector or Company's representative should attach a metal piece to the concrete with adhesive and measure the force needed to remove it (ASTM Standard Method M-4541).
•
Has a uniform surface free of excessive defects and laitance. To finish new concrete, the coatings applicator should smooth once over the surface with a wood float and then use a steel trowel.
Note Laitance is the film caused when a water-rich cement rises to the surface during finishing. Remove this 5- to 50-mil-thick film before applying any coating.
641 Assessing the Surface New Structures During the initial design of a new structure, investigate potential problems involving coatings or linings to reduce costs and premature failures. If laid properly, new concrete requires only cleaning of surface dirt, oil, laitance, etc., before abrading. There may, however, be other items to consider such as vibration, agents and slivers, and curing.
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Coatings Manual
Fig. 600-5
600 Coating Concrete
Coating Recommendations for Intermittent Immersion Service
Recommendation #10: Use a laminate reinforced system to resist the physical abuse and chemical attack. The resin selection should be reviewed with the coating manufacturer to ensure it is resistant to the corrosive media. It will probably be an epoxy, novalac epoxy, or vinyl ester resin.
selection should be reviewed with the coating manufacturer to ensure it is resistant to the corrosive media. It will probably be an epoxy, novalac epoxy, or vinyl ester resin.
Depending on the type of physical abuse, a flake reinforced system could be used. This should be confirmed with someone experienced with coating concrete.
Recommendation #15: Use a thin film system to resist the chemical attack. The resin selection should be reviewed with the coating manufacturer to ensure it is resistant to the corrosive media. It will probably be an epoxy, novalac epoxy, or vinyl ester resin.
Recommendation #11: Use a flake reinforced system to resist the chemical attack and the reduced physical abuse. The resin selection should be reviewed with the coating manufacturer to ensure it is resistant to the corrosive media. It will probably be an epoxy, novalac epoxy, or vinyl ester resin.
Recommendation #16: Use a laminate reinforced or a textile reinforced urethane system to resist the physical abuse. The resin selection should be reviewed with the coating manufacturer to ensure it is resistant to the corrosive media. It will probably be a polyester, epoxy, or modified urethane resin.
Recommendation #12: Use a flake reinforced or thin film system to resist the chemical attack. The selection of reinforced or thin film will depend on the amount of mild physical abuse. The resin selection should be reviewed with the coating manufacturer to ensure it is resistant to the corrosive media. It will probably be an epoxy, novalac epoxy, or vinyl ester resin.
Depending on the type of physical abuse, a flake reinforced system could be used. This should be confirmed with someone experienced with coating concrete.
Recommendation #13: Use a laminate reinforced system to resist the physical abuse and chemical attack. The resin selection should be reviewed with the coating manufacturer to ensure it is resistant to the corrosive media. It will probably be an epoxy, novalac epoxy, or vinyl ester resin. Depending on the type of physical abuse, a flake reinforced system could be used. This should be confirmed with someone experienced with coating concrete. Recommendation #14: Use a flake reinforced or thin film system to resist the chemical attack. The selection of reinforced or thin film will depend on the amount of moderate physical abuse. The resin
Chevron Corporation
Recommendation #17: Use a flake reinforced or elastomeric urethane system to resist the moderate physical abuse. The resin selection should be reviewed with the coating manufacturer to ensure it is resistant to the corrosive media. It will probably be a polyester, epoxy, or modified urethane resin. Depending on the type of physical abuse, a thin film system could be used. This should be confirmed with someone experienced with coating concrete. Recommendation #18: Use a thin film or elastomeric urethane system. The resin selection should be reviewed with the coating manufacturer to ensure it is resistant to the corrosive media. It will probably be an epoxy or modified urethane resin.
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Vibration. Vibration consolidates the concrete but can also cause water and air bubbles to move out to the face of the form, resulting in tiny voids or holes in the concrete surface. Before coating or lining concrete, fill all holes, including those opened during surface preparation. Agents and Slivers. Many forms are built with commercially available plywood or wood planks. When removed, these forms may leave other materials in the concrete such as release agents that facilitate the removing forms, or large slivers of wood. Remove these materials, then repair and smooth the area before coating it. Curing. Unless the concrete cures properly, it may crack; if so, repair all cracks before coating or lining.
Existing Structures Attacked by chemicals, contaminated by hydrocarbons, and damaged by mechanical means, existing concrete may require extensive repairs and surface preparation. A careful inspection should determine whether or not the existing concrete is structurally sound. Corrosion. Depending on the amount of corrosion in the steel reinforcement, the concrete will require the following: •
Corroded - Coating or cathodic protection in aggressive environments
•
Severely corroded - Replacement of steel reinforcing and the affected concrete or epoxy-polymer material
Contamination. Depending on the level of contamination, concrete that has been exposed to oils or other impurities may require high-pressure detergent-and-water cleaning. It also may require replacing as many inches of concrete as necessary to remove the contaminants.
642 Repairing Non-structural Damage There are several common kinds of non-structural damage to concrete, such as cracks, holes, expansion joints, and drain and pipe penetrations.
Cracks Among the choices for repairing concrete based on the size and activity (still moving) are the following: • • •
Filling them with a sealer Making them into expansion joints Filling them by pressure injection
Begin with the basic procedures for filling concrete cracks, regardless of size.
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Basic Procedure for All Cracks. To repair all cracks, begin by:
☞
1.
Blowing any standing water out of the crack
2.
Removing oils or chemicals in the crack
Caution Do not inject solvents into cracks to remove oils or chemicals because this process actually dilutes the contaminants and carries them further into the concrete surface. Instead use an injection grout that will solubilize the oils and water, bond to the concrete, and cure with suitable properties for the intended purpose. Continue the repair—depending on the size of the crack—by following the steps either for small or for large cracks, below. Additional Steps for Small Cracks. alternatives.
To repair small cracks, there are two
Alternative One: Filling with Sealer 1.
Grind the crack into a V shape with an opening that is a minimum of ½-inch wide at the surface of the concrete.
2.
Pour or trowel the sealing grout into the crack.
3.
Scrape off excess grout.
Alternative Two: Creating Expansion Joints. Convert small cracks into expansion joints, which allow concrete to expand and contract with changes in temperature or movement of the substrate. See Figure 600-6, Detail “C.” This figure also covers corrosion control of floor-to-wall expansion joints and floor-to-wall control joints. As they are highly susceptible to premature failures, design expansion joints carefully ½- to 1-inch wide and as shown in Figures 600-6, 600-7, and 600-8. Note Figure 600-7 shows sealant system for corrosion control in mild environment; Figure 600-8, for more severe environments. The steps for creating expansion joints are as follows:
Chevron Corporation
1.
Place sufficient joint material between the concrete surfaces to allow the closed-cell foam-backing rod to come within ½- to 1-inch of the concrete surface.
2.
Pour or trowel on a flexible joint sealant to bring the joint up to the level of the concrete surface.
3.
Place 2-inch-wide, vinyl, electrical tape over the joint to provide a bond breaker.
4.
Place a ½-ounce glass mat, saturated with resin, over the tape.
5.
Apply the corrosion coating system over the mat.
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Fig. 600-6
Corrosion Control Treatment of Sealed Expansion Joints, Control Joints, and Cracks in Concrete Foundations
Additional Steps for Large Cracks. To repair larger cracks, fill them by pressure injection. The steps for pressure injection are as follows:
September 1996
1.
Grind the crack into a V shape.
2.
Select an appropriate size of copper tubing.
3.
Drill holes along the crack 1/8-inch larger than the tubing and to the depth of desired penetration.
4.
Insert the tubing into the crack.
5.
Grout the crack on the surface to seal it and hold the tubing in place.
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600 Coating Concrete
Fig. 600-7
Corrosion Control Treatment of Exposed Expansion Joints in Concrete Integral with Monolithic Floor/Lining System
6.
Install a grease fitting in the first tube when the grout is cured.
7.
Inject grout into the tube with a pump.
8.
Allow the grout to flow out of the next tube until the color approaches the original mixture to ensure removal of all contaminants.
9.
Repeat the process, filling all tubes.
Holes This section provides information on filling both small and large holes. Small Holes. During blasting, air pockets open in or just below the surface of most formed concrete. There are two mixes for filling these holes.
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Fig. 600-8
September 1996
Corrosion Control Sealing of Expansion Joints, in Concrete Integral with Monolithic Floor/Lining System
•
Resin-based material is the Company's preferred method of repair. Some are powders mixed with the primer and trowel applied which gives a smooth surface for good coating adhesion. Others are epoxy grouts.
•
Portland-cement materials require expert installation and generally need an additive to reduce shrinkage during cure and to improve adhesion to the old surface. The problems with this cement are that it does not bond well to cured concrete; does not cure well in thin layers; and usually leaves a carbonate layer on the surrounding concrete which can, if not removed, cause coating failures.
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Large Holes. There are two main choices of fill for larger holes, both of which need special handling: •
Concrete - Undercut the hole to guarantee mechanical bonding or apply a chemical bonding agent.
•
Compatible resinous grout - Treat forms with a release agent for easy removal. As formed resinous grouts usually cure with a glazed surface, abrasive blast or grind this glazing to roughen it to ensure that the coating adheres well.
Drain and Pipe Penetrations Drain and pipe penetrations are almost as vulnerable to failure as expansion joints. Usually, they are not concrete and have very different thermal coefficients of expansion. Improper design can cause leaking at the penetrations. For drains, see Figure 600-9. Figure 600-10 shows details of installing a corrosioncontrol system for pipes. Fig. 600-9
Chevron Corporation
Floor System Termination at Floor Drain
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Coatings Manual
Fig. 600-10 Corrosion Control Treatment of Pipe Penetration through Concrete Wall or Floor
In either case:
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1.
Dig a groove ¾-inches wide and ¼-inch deep around the drain or pipe penetration.
2.
Fill the groove with sealant.
3.
Butt the corrosion control system against the sealant for mild environments or extend it to the drain cover in more aggressive environments.
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600 Coating Concrete
650 Surface Preparation The life of a coating is directly related to surface preparation. After designing joints and penetrations and repairing all cracks, holes, and other defects, establish the method of surface preparation necessary to clean away all loose concrete, oil, grease, dust, laitance, grime, and other foreign materials. There are several methods of surface preparation for coating concrete. The mechanical methods—abrasive blasting, scarifying, and blastracking—produce the best surface for coating adhesion.
651 Pre-application Requirements See Assessing and Repairing Concrete (above) for the four conditions required of a concrete substrate to be ready to accept a coating.
☞
Caution Do not accept broom finishing as it can leave an irregular surface with excess laitance; and, in the case of air-entrained concrete mixes, it can open large holes at the surface.
652 Precleaning To preclean a concrete surface, follow the ASTM D4258 method: 1.
Remove: – – –
2.
Dirt and caked grease manually or with an acid wash Grease and oils with low-foaming detergents Animal fats or vegetable oils with saponifying agents
Patch test to determine the best cleaning procedures for the surface.
Clean or remove the surface until it meets the pre-application requirements.
653 Mechanical and Chemical Cleaning Abrasive-blast Cleaning Abrasive-blast cleaning is the Company's preferred method of surface preparation. Note There is additional information about abrasive-blast cleaning in Section 400; and, although that section relates to surface preparation for steel substrates, some details are applicable to concrete. Advantages: • •
Chevron Corporation
Gives high production rates for all surface configurations Leaves an excellent surface condition for coating
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Disadvantages: •
Creates excessive dust and waste material as the abrasive breaks down
Blastracking Blastracking is similar to abrasive blasting but uses metal shot instead of abrasive Advantages: •
Produces comparable surfaces to abrasive blasting with less dust and waste material
Disadvantages: •
Restricted to horizontal surfaces because it is a fairly large machine
Scarifying (Air Hammer) Scarifying is often the alternative when field or other conditions prevent blasting of concrete surfaces. Note A scarifier is an apparatus with steel hammers that hit a surface, removing loose material. Advantages: •
Produces an acceptable surface with less clean-up, set-up, and dust.
Disadvantages: •
Produces a rougher surface than abrasive blasting.
Acid Etching Acid etching is the least acceptable cleaning method, but may be used if needed. The steps for acid etching are:
☞
1.
Mix one part of concentrated hydrochloric acid with two parts water to form the etching solution.
2.
Brush the solution on the concrete.
Caution If the etch does not produce a 60-grit, sandpaper-like profile, repeat the etch. Diluted acid permeates the concrete surface dissolving salts and other contaminants. There is, however, an undesirable side effect; as it dries, the acid deposits the contaminants on the surface, adversely affecting the bond between the coating and the concrete.
660 Application Because of the complexity of coating concrete and the different systems and resins available, it is impossible to have one uniform application procedure.
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661 Recommended Process The recommended application process is to: 1.
Select the coating system and resin. Either refer to the Quick Reference Guide (for mild environment) or obtain the assistance of the coating manufacturer and the Company's concrete coating specialist (for other environments).
2.
Request detailed application procedures from the manufacturer for the coating selected.
3.
Review application procedures with the coatings applicator and the coating manufacturer, resolving differences until the procedure is acceptable to all.
662 Reviewing an Application Procedure Here are some points to consider when reviewing or writing an application procedure: •
Many concrete coating systems require a primer for optimum application results.
•
The temperature of concrete slabs should be between 50°F and 85°F when coating; the slab's temperature must be 5°F above the moisture dew point.
•
For optimum results from the application: – –
Apply the primer coating out of direct sunlight. Apply the primer and topcoat when the slab's temperature is cooling rather than rising.
•
An order of cost (low to high) for coating systems is thin films, flakereinforced films, and laminate-reinforced films.
•
An approximate order of cost (low to high) for resins is as follows: polyesters, epoxies, novolac epoxies, vinyl esters, and polyurethanes.
•
Epoxy resins are the easiest to apply, followed by novolac epoxy, polyester, polyurethane, and vinyl ester.
•
Polyester and vinyl ester require a final wax coat (mixture of wax and resin) to obtain full surface cure.
•
Thicker is not always better. All coatings and linings have a maximum allowable thickness.
670 Inspection Inspection is an integral part of the quality of a coatings project. The following references offer guidance about the degree of inspection needed and how to select a quality inspector.
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•
Coatings Manual, Section 100 The inspection procedures for steel can be used for inspecting concrete, in most cases.
•
National Association of Corrosion Engineers RP0288, Inspection of Linings on Steel & Concrete.
•
American Society for Testing and Materials D453786, Procedures to Qualify and Certify Inspection Personnel for Coating Work in Nuclear Facilities. (Good information about qualifying any coating inspector.)
Some construction details in concrete may need particular attention from the inspector.
Concrete-to-Steel Interface In addition to penetrations, other potential concrete-and-steel interfaces need coating. See Figure 600-11, Detail “A,” for one example of sealing a pedestal/pipe stand in a concrete pit. Fig. 600-11 Corrosion Control Treatment of Steel-to-Concrete Interface
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600 Coating Concrete
680 References The following publications give additional information for repairing and coating concrete.
Chevron Corporation
1.
American Society for Testing and Materials. Standard Practice for Surface Cleaning Concrete for Coating (R 1992). ASTM D4258. 1983.
2.
———. Standard Practice for Abrading Concrete (R 1992). ASTM D4259. 1988.
3.
———. Standard Test Method for Indicating Moisture in Concrete by the Plastic Sheet Method (R 1993). ASTM D4263. 1993.
4.
———. Standard Practice for Determining Coating Contractor Qualifications for Nuclear Powered Electric Generation Facilities. ASTM D4286. 1990.
5.
———. Standard Guide for Establishing Procedures to Qualify and Certify Inspection Personnel for Coating Work in Nuclear Facilities. D4537. 1991.
6.
———. Standard Test Method for Pull-off Strength of Coatings Using Portable Adhesion Testers. ASTM D4541. 1995.
7.
National Association of Corrosion Engineers. Monolithic Organic Corrosion Resistant Floor Surfacing. NACE RP-03-76.
8.
———. Inspection of Linings on Steel and Concrete. NACE RP-02-88.
9.
———. Linings for Concrete Surfaces in Non-Immersion and Atmospheric Services. RP-0591-91.
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700 Downhole Tubular Coatings & Linings Abstract In this section, there is general information about coatings and linings—selecting, purchasing, handling, installing, and operating guidelines—drawn from field experience, industry publications, and vendors. Internal coatings and linings are two choices for preventing corrosion in the steel base metal of downhole equipment. Internal coatings enhance the flow of fluids and may help prevent the build up of paraffin. Linings can salvage tubing. The purpose of a coating or lining for downhole equipment influences both its selection and the means of achieving the desired performance. Connections are an important consideration. For downhole tubing in oil and injection wells, the American Petroleum Industry's (API) eight-round connections are commonplace, coated routinely, and difficult to install holiday free A high-integrity internal coating may be more difficult to achieve on premium connections and typically requires more intensive evaluation and attention. Consider selecting connections designed specifically for IPC and lined tubing. See also Section 120 of this manual—for information on inspections and inspectors, including specific procedures for downhole tubing—and the Quick Reference Guide—for contacting Company's coating specialists, who are a primary resource for these specialty coatings and linings.
Chevron Corporation
Contents
Page
710
Coated Tubing Versus Linings
700-3
711
Wells Suitable for Coating or Lining
720
Descriptions
721
Coatings
722
Linings
723
Connections
730
Selection
731
Economics
700-4
700-10
700-1
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700 Downhole Tubular Coatings & Linings
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732
General Guidelines
740
Application
741
Steps in Application
742
Holiday-free Coated Tubing
743
Used Tubing
750
Handling Coated or Lined Tubing
751
Coated Tubing
752
Lined Tubing
760
Installation
761
Coated Tubing and Accessories
762
Guidelines for Installing IPC Accessories
763
Guidelines for Installing Lined Tubing
770
Guidelines for Well Operation
700-19
780
References
700-21
700-12
700-13
700-16
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710 Coated Tubing Versus Linings Coated tubing, commonly called internally plastic-coated (IPC) tubing, has liquid or powder coating applied to the inside diameter (ID) to a thickness of 5- to 30-mils dry film thickness (DFT). The coated surface reduces the frequency of corrosion-related failures by a factor of five (average). IPCs limit damage to local areas, avoid expensive fishing jobs, and increase the percentage of salvageable tubing. Note
Fishing jobs refers to retrieving parted tubing.
Plastic-coated tubing may also reduce rig time. Corrosion can thin the walls of uncoated tubing so badly that multiple parting failures occur when tubing is pulled during workovers. One hundred percent holiday-free coated tubing adds about ten percent to the cost of a coating project but is justified for the following: • •
Waterflood, water-disposal, and CO2 wells Corrosive services when anticipating long life and expensive rework
Lined tubing has much thicker internal-corrosion barriers which, with one exception, are physically inserted into the tubing. The exception is cement lining which is spun centrifugally on the ID surface. Linings offer truly holiday-free systems.
711 Wells Suitable for Coating or Lining The following types of wells are suitable for coated or lined tubing: Wells that produce a separate water phase. At 25 to 50 percent watercut, a well usually becomes corrosive. Note Watercut is the percentage of water to total fluids produced, such as oil plus water. Marginal wells. Wells in these circumstances may not justify a workover. While installing a coated tubing string may allow depletion of reserves, an uncoated string may fail before reserves are depleted. Note
A succession of joints of tubing makes a string of tubing.
Waterflood or water-disposal wells. Gas-condensate and high GOR (gas/oil ratio) wells. Gas wells are usually corrosive, particularly when producing connate water. Note
Connate water is defined as water trapped in a rock matrix.
Gas-lift wells with high-watercut. The well is especially susceptible to corrosion if the gas contains carbon dioxide or hydrogen sulfide. Note Gas-lift wells are those into which we inject gas to lift the oil out of the reservoir.
Chevron Corporation
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Offshore wells. Wells located in remote or offshore areas make workover and chemical treatment expensive. The cost of a coated string is usually a fraction of the cost of a well or workover.
☞
Caution Because the constant rubbing damages the coating/lining, wells using sucker-rod pumps for artificial lift are not typically considered candidates for coatings or linings.
720 Descriptions All coatings are available as 100 percent defect (holiday) free; however, damage may occur during handling, installing, and well operations. For maximum corrosion protection, coated tubing may need a suitable corrosion inhibitor.
721 Coatings Thin-film coatings are generally 5 to 9 mils DFT; thick-film coatings generally 10 to 30 mils DFT. See Figure 700-1. Properties of Coatings
Fig. 700-1
Chemistry
Type
Thickness (mils)
Phenolic
Liquid
5–9
Modified Phenolic
Liquid
5–9
Epoxy-Phenolic
Liquid
5–9
Epoxy
Liquid
8–15
Epoxy
Powder
12–20
Epoxy-Cresol-Novolac
Powder
12–20
Nylon
Powder
12–25
Phenolics The Company has the longest history with phenolic coatings. Advantages: • •
Resistant to chemical attack (from pH 2 to pH 12) Withstand temperatures up to 300°F or higher
Disadvantages: • • • •
September 1996
Brittleness which limits their usefulness in preventing corrosion Limited DFT; not to exceed 9 mils DFT as brittleness worsens Gas-decompression problems, especially above 7,000 psi and if the coating is thick Susceptibility to mechanical damage from hitting or bending the pipe
700-4
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700 Downhole Tubular Coatings & Linings
Uses: • •
As a primer under other thicker, more flexible coatings In high-temperature environments
Note Phenolics may be the only available coating material that can withstand very high temperatures. •
☞
Primarily for flow enhancement
Caution When using phenolics for corrosion control, consider a corrosioninhibitor-injection program to protect the steel in areas of coating damage.
Modified Phenolics Modified phenolics were developed to overcome the blistering of phenolics in highpressure gas wells. Decompressing high-pressure gas caused straight phenolics to blister because the gas could not escape from the coating fast enough. Modified phenolics contain calcium silicate to enable them to outgas more quickly. Advantages: •
More resistant to decompression damage than straight phenolics
•
High temperature, chemical, and H2S/CO2 resistance similar to the straight phenolics
Disadvantages: •
Brittleness
Epoxy Phenolics Adding epoxy to the phenolics reduces the brittleness of the coating. Advantages: • • •
Improved flexibility Improved alkali resistance Temperature resistant to about 250°F (some brands, even higher)
Disadvantages:
☞
Chevron Corporation
•
Reduced temperature and chemical resistance
•
Reduced acid resistance
•
Susceptible to mechanical damage or defects from handling, installation, and operations such as wirelining
Caution Consider applying corrosion inhibitors to protect steel exposed by damaged coatings.
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Modified Epoxies Two types of modified epoxies are discussed below: powder-applied and cresol-novolac. Powder-applied epoxies. Powder-applied epoxies are more flexible and tougher than liquid-applied epoxies, which are being phased out in the industry. Advantages: • •
Temperature limit of about 150–200°F Good chemical resistance to both acids and alkalis
Disadvantages: • •
Somewhat brittle Corrosion inhibitors necessary if primarily for corrosion control
Cresol-novolac-modified epoxy. Adding cresol-novolac to epoxy results in cresol-novolac-modified epoxy or epoxy-cresol novolac. To optimize overall performance, vendors have varied the amount of cresol-novolac for chemical resistance and flexibility. The propensity for mechanical damage may limit this coating's usefulness in service. Advantages: • •
Greater chemical resistance than straight epoxies Temperature resistant to approximately 250°F
Disadvantages: •
Brittleness increases in relationship to increased chemical resistance
Nylon Nylon is a relatively new coating for downhole tubing and accessories. A thermoplastic, rather than the thermoset of most IPCs, nylon has superior flexibility. Advantages: • • • •
Easy to apply One hundred percent holiday free Good chemical resistance up to about 180°F Very flexible and durable
Disadvantages: • •
Extremely poor resistance to damage from wire-line tools Deterioration from acidizing when HCI above 15 percent or for extended periods
Uses: •
September 1996
Excellent for a low-temperature line pipe (small diameter) in corrosive service
700-6
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700 Downhole Tubular Coatings & Linings
722 Linings Linings are holiday-free systems and have thicker internal corrosion barriers than coatings. Except for cement, which is spun centrifugally on the ID surface, all linings are physically inserted into the tubing. The four lining materials presently available are cement, fiber-glass, PVC, and polyethylene. Suppliers are also investigating other materials such as carbon fiber. See Figure 700-2. Properties of Linings
Fig. 700-2
Lining
Thickness (mils)
Cement
150–210
Fiberglass
60–80
PVC
60–80
Polyethylene
130–150
Cement Cement lining has been available for many years. Advantages: • • • •
Cost effective Resists chemicals Withstands normal handling and installation Tolerates wireline work
Disadvantages: •
At a thickness of 150 to 210 mils, cement causes a significant reduction of the tubing ID.
•
Acids (HCl and mud acid) can damage cement.
Note
Special additives are available to improve the acid resistance of cement.
•
The weight of the cement limits the depth at which it can be used, with a practical limit of about 10,000 feet.
•
For wells between 7,000 and 10,000 feet deep, the weight of the cement can influence tubing selection.
•
The temperature limit is about 300°F, primarily because of the plastic inserts installed in the connections.
•
Availability may be a problem in remote areas.
Uses: •
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Holiday-free service in injection wells or non-rod-pumped producing wells
700-7
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700 Downhole Tubular Coatings & Linings
•
Coatings Manual
Good choice for salvaging used tubing
Fiberglass Fiberglass-lined tubing is made by inserting a fiberglass tube of an aromatic aminecured epoxy inside the steel tube and then filling the annular space between the two with cement grout. The resulting liner is about 60 to 80 mils thick. Advantages: • •
Holiday-free service Chemical resistance up to a maximum operating temperature of 350°F
Disadvantages: • •
Some ID reduction Additional restrictions at flares on tubing ends
Uses: • • •
Primarily in injection wells Good service in non-rod-pumped producing wells Good choice for salvaging used tubing
PVC PVC-lined tubing is similar to fiberglass-lined tubing, with either a cement grout or an adhesive between the PVC and the steel tube. The thickness of the liner is 60 to 80 mils. Advantages: •
Holiday free
Disadvantages: • • •
ID reduction Unsuitable for gas wells (the risk of liner collapse from gas permeation) Unsuitable with solvents (such as paraffin cutting agents)
Uses: • •
Most suited to water injection wells up to about 150°F Good choice for salvaging used tubing
Polyethylene Polyethylene-lined tubing is a recent development and has little proven field experience. The polyethylene liner is swaged down and pushed or pulled through the tubing. It then re-expands into the tubing, leaving the polyethylene liner in compression. The end of the liner is molded to fit within the connection J area. The coating industry is addressing concerns about gas permeation, softening at maximum service temperature, and connection integrity.
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700 Downhole Tubular Coatings & Linings
Check with the CRTC's coating specialists (listed in the Quick Reference Guide) for the latest information on the status of polyethylene linings. Advantages: • •
Extremely rugged Holiday-free and mechanical-damage-free service
Disadvantages: • • • • •
Significant ID reduction (150 mils thick) Temperature limit of about 150°F Concerns about gas permeation Softening at maximum service temperature Concerns about connection integrity
Uses: • •
Most suited to water injection wells up to about 150°F Good choice for salvaging used tubing
Carbon Fiber An ultra-high-temperature carbon-fiber liner and premium connection system is presently undergoing testing. This product may have a working temperature of up to 450°F.
723 Connections Most downhole tubing in oil wells and injection wells have API eight-round connections. They are easy to coat but difficult to install 100 per cent holiday free. Premium connections may be more difficult to coat internally.
Coated Tubing Connections There are basically two approaches for coating tubing with API eight-round connections: •
Coat the exposed threads on the coupling ID with Ryton (the best-known method).
•
Select specially made couplings that have a Teflon or reinforced-elastomer insert in the J-section.
Some premier connections with external torque shoulders do not require torque gages for make up. Both couplings use a marking system to make up the coupling to position; they may also solve the following problems: • • •
Chevron Corporation
Turbulent flow or sand-impingement damage at the J-section Moderate wirelining Failed Ryton-coated couplings
700-9
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Advantages: •
Connection with a flush ID instead of the discontinuous J-section in standard API eight-round couplings
•
Better seal
•
Protection for the coating on the pin-ends in the J-section from wireline tool damage
Disadvantages: •
Cost about three times as much as a standard coupling
Lined Tubing Connections Each lining has a different technique for protecting the coupling and pin-ends. •
For cement-lined tubing, polypropylene inserts are cemented into the end of the tubing; and pin-ends are embedded in an acrylic putty.
•
For fiberglass- and PVC-lined tubing, a nitrile rubber ring is fitted between the two pin-ends.
•
For polyethylene-lined tubing, an integral portion of polyethylene covering the pin faces mates when connected.
Premium Connections Non-API premium connections are highly specialized. Evaluate their suitability for coating or lining on a case-by-case basis with the connection manufacturer and the coating or lining applicator. Some premium connections may be unsuitable for holiday-free coating application. Surface preparation (e.g., abrasive blasting), coating, and make-up procedures must comply with the connection manufacturer's recommendations.
730 Selection For help in selecting coatings or linings, contact the coatings specialists listed in the Quick Reference Guide.
731 Economics Costs for coated or lined tubing and accessories vary significantly depending on the size of the order, the location of the job, market conditions, and other factors.
Purchasing Guidelines •
September 1996
For coated tubing and accessories, refer to Specification COM-MS-4732, Oilfield Tubular Goods and Accessories—Internal Coating Application.
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•
For cement-lined tubing, refer to API RP 10E There are no Company or industry specifications for purchasing cement-lined or fiberglass-lined tubing. Industry participants purchase these products from major suppliers and accept their specifications. See the Quick Reference Guide for a list of suppliers.
•
For PVC-lined tubing, refer to API Specification 15LT
•
There are no Company or industry specifications for purchasing polyethylenelined tubing.
732 General Guidelines In this manual, there are only general guidelines for selecting coatings and linings as it would be impossible to cover every conceivable well condition.
Environmental or Operating Conditions In some situations, downhole environmental conditions or planned operating criteria and procedures preclude effective use of coatings or linings. In such circumstances and if corrosion is anticipated, the only alternatives may be to install either bare-steel tubing with corrosion inhibitors or alloy tubing.
Influences of Materials on Selection Coating names are often different in the US market and overseas; some coatings with the same name exist but may be a modified version. Manufacturing space and equipment limit some manufacturer-owned application facilities so that they cannot apply their full product line of coatings. As few applicators offer cement linings in the US, the limitations of local applicators' facilities influence the choice of coating system.
Assistance For guidance on selecting coatings and linings, consult the Company's coating specialists (listed in the Quick Reference Guide). The following databases are also available: • • •
Company-purchased database of ARCO's lab test of coated tubing The Company's field-experience database The Company's lab-test database
The Company's databases are updated periodically to reflect the latest experiences with tubular coatings and linings. Please send relevant field experience or lab test information to the Company's coating specialists listed in the Quick Reference Guide.
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740 Application See Figure 700-1 which lists common coatings for tubing.
741 Steps in Application To apply coatings, follow these steps: 1.
Bake at about 700°F to burn off oil and loosen scale.
2.
Abrasive-blast the surface to white-metal finish (NACE No. 1 or SSPC-SP 5).
3.
Apply primer, if appropriate, and cure.
4.
Apply the coating. – –
Apply multiple coats of liquid coating with a spinning spray head. Apply powder coatings with a vacuum or blow-in process, from one or both ends of the tubing.
5.
Bake at about 400°F to cure the coating.
6.
Visually inspect the coating; check thickness.
7.
Holiday test.
8.
Install couplings and thread protectors.
742 Holiday-free Coated Tubing Refer to Figure 1 of Specification COM-MS-4732 and follow this procedure to guarantee 100 percent holiday-free coatings: 1.
Round the end of the threaded tube to a smooth radius.
2.
Coat and holiday test the end of the tubing to the first major thread.
3.
Repair any holidays according to the specification.
743 Used Tubing Use any of the existing linings (see Figure 700-2) rather than coatings for used tubing. Fiberglass lining can bridge small holes in steel pipe (up to about ½-inch in diameter) and withstand pressure up to several thousand psi. Polyethylene liners also have this capability but to a lower pressure. Because coatings are relatively thin, they are not as effective for protecting used tubing if the ID surface is roughened from corrosion. Thick-film powder-applied coatings, especially nylon coatings, are better than thin-film coatings for recoating corroded used tubing. It is possible, however, that both types of coatings may fail to cover all peaks or bridge all gaps or pits on severely corroded steel surfaces. As a result, these uncoated or unbridged areas become exposed to the corrosive environment and cause premature failure of the coating and the steel.
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The roughness of the surface (and not necessarily the depth of corrosion) determines the difficulty in applying a good coating. A uniform 50 percent wall loss from generalized corrosion is easier to coat than a wall loss of only 5 percent covered with sharp-edged pits. To determine whether or not the tubing is NSC (Not Suitable for Coating), the coatings applicator should inspect each length of tubing after cleaning and blasting and again after coating and holiday testing.
750 Handling Coated or Lined Tubing 751 Coated Tubing Because of the brittle nature of coatings, damage to coated tubing and accessories is virtually inevitable with the possible exception of those coated with nylon. The guidelines in this section are intended to minimize damage to plastic coatings from handling, installation, and well operations. Minimizing coating damage prolongs tubing life by decreasing both the number and extent of locations subject to corrosion attack and the number of locations that need protection from corrosion inhibitors. As long as defects are small (i.e., the coating is not coming off in large chunks or sheets), the life of a coated tubing string can be significantly longer than a baresteel string. Proper handling of IPC tubing and accessories prevents or minimizes damage to the coating, metal, and threads. Excessive bending, deflection, or impact can damage the coating.
☞
Caution Do not place clamps, hooks, bars, rods, or other foreign objects inside the tubing or other coated equipment. Either make drifts or rabbits from rubber, plastic, or wood, or rubber- or plastic-coat them. The tubing must be free of debris that could damage the coating during drifting. Note Drifting means testing the tubing for roundness; rabbits help test for and clear obstructions in the tubing. The coatings applicator spreads API-modified thread compound (or alternative thread compound, when specified) on exposed threads with a soft-bristle brush (not a wire brush) to clean threads or apply thread compound. The coatings applicator also installs closed-end plastic or steel-reinforced plastic thread/end protectors, which remain in place during handling, storage, and transportation.
Storing Coated Tubing and Accessories Note the following guidelines when storing coating tubing and accessories. Guidelines for Yard Storage. •
Chevron Corporation
Rack the tubing to prevent excessive bending and damage during loading and unloading.
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•
Place pipe racks on stabilized soil.
•
Do not pyramid-stack (cradle) tubing.
•
Support tubing by three evenly spaced pipe racks that keep the pipe at least 18 inches above the ground.
•
Place bolsters (hardwood stripping) between pipe layers, perpendicular to the pipe.
•
Align bolsters vertically one above the other and directly over the pipe racks.
•
Place stripping on the racks to prevent direct contact between the pipe and pipe rack.
•
Install chocks (about one- or two-inch wood or plastic blocks) at both ends of each bolster to keep the pipe from moving.
•
Do not stack pipe higher than ten feet.
•
Rack the pipe with all couplings at one end.
•
Stagger adjoining lengths about the length of the coupling.
•
Store IPC accessories on wood pallets, concrete pads, or other suitable installations that keep the accessories off the ground.
•
Apply an external protective coating to control external corrosion.
•
Inspect tubular goods (both IPC and non-IPC) stored outside at least every six months to check for detrimental external attack from atmospheric corrosion. Coastal areas may require more frequent inspection.
Guidelines for Job- or Wellsite Storage. •
Store IPC tubing on properly loaded flatbed trailers, wooden sills, or prefabricated steel pipe racks.
•
Do not use old drums or other thin-walled materials as pipe racks.
•
Use proper pipe chocks on both sides of the bottom tier to prevent rolling.
•
Do not stack pipe higher than five tiers (layers).
•
Do not stack other equipment on top of racked IPC tubing.
•
Do not use racked tubing as a workbench.
•
Rack tubing with the couplings facing toward the well.
•
Store IPC accessories on wood pallets, concrete pads, or other suitable installations that will keep the accessories off the ground.
Loading and Unloading Tubing. •
September 1996
Do not allow IPC tubing to drop or experience long, fast rolls.
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•
Do not use cheaters to move or roll the pipe.
•
Do not strike the pipe with any metal object.
Transporting Coated Tubing Note the following guidelines when transporting coated tubing. In General. •
Rack IPC goods for transport to prevent excessive bending and damage during loading and unloading.
•
Do not pyramid-stack (cradle) them.
•
Load and unload tubing carefully, supporting each piece firmly and gently lifting or gradually rolling them down sills.
•
Avoid high-speed rolling to protect the coating and the threads.
•
Do not hoist tubing from a single point.
•
Use nonmetallic slings when loading or unloading with cranes; do not use spreader bars.
•
Select forklifts with forks of sufficient spread to avoid excessive bending of the pipe.
•
Never insert pry bars or similar objects inside the pipe.
Guidelines for Trucking. •
Use flatbed trailers.
•
Do not use pole trailers.
•
For Range 2 or longer tubing, use at least three bolsters on the truck bed and between layers. Align bolsters vertically.
•
Use nonmetallic tiedowns for accessories.
•
Load tubing with all couplings facing the same direction.
•
Re-tighten tiedowns to remove slack due to settling after traveling a short distance. Add bolsters if more tiedowns are needed. Do not pull tiedowns so tight that they bend or bow the tubing or accessories.
Guidelines for Rail Transport.
Chevron Corporation
•
Transport IPC goods and accessories in open gondola cars, following rules of American Association of Railroads (AAR).
•
Secure the load according to AAR rules to prevent coating damage when in transit or from excessive bending with bolsters, stakes, headers, high-tension banding.
•
Do not allow the height of the load above the car floor to exceed ten feet.
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Guidelines for Sea Transport. •
Do not store IPC goods in or near bilge water, chemicals, or other corrosive materials.
•
Prevent excessive bending or coating damage in transit with proper dunnage, such as bolsters, stakes, headers, high-tension banding, and clips.
752 Lined Tubing Most of the information about handling coated tubing also applies to lined tubing. While linings (especially polyethylene linings) are generally more rugged and damage-resistant than coatings, they must still be handled with care. Treating lined tubing in the same manner as bare-steel tubing can ruin a potentially holiday- and damage-free installed tubing string. The following are key points about coated tubing that also apply to lined tubing: •
Keep protectors in place until the pipe is about to be made up. Do not remove thread protectors when the pipe is being hauled or handled.
•
Do not insert bars, hooks, or any unloading tools inside the pipe.
•
Do not drop the pipe or turn it loose to roll on the sticks.
•
Do not hit the pipe with a hammer or other metal object, or in any way subject the pipe to impact.
API RP 10E also gives guidelines on handling cement-lined tubing.
760 Installation 761 Coated Tubing and Accessories • •
Arrange to have a vendor's representative present. Visually inspect IPC tubing before running. – –
• •
September 1996
Reject joints with damage to coating, metal (body, upset, or coupling), or thread. Remove the thread protectors for the inspection and then reinstall them, leaving them on until ready to make up the connection.
Pick up the tubing gently with the rig. Assign a person to tail the rigged tubing to the derrick.
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762 Guidelines for Installing IPC Accessories •
Visually inspect IPC accessories before installation. – –
•
Leave thread/end protectors in place until immediately before make up of the connection. – – –
•
Unless impractical, reject pieces with coating, metal, or thread damage. Remove the thread protectors to inspect the threads, and then reinstall them.
Visually inspect the threads again after removing the protectors. Clean and lubricate (re-dope) the threads in a way that will not damage the coating. Apply thread compound.
For connection make up, use equipment and follow procedures to protect coating. – – –
Do not use pipe wrenches. For threaded connections, use large contact surface-area tongs, wrenches, and backups. Start the make up of the connections by hand, and then follow with the tongs in low gear.
•
The guidelines for proper make up of API and premium connections for tubing also apply to accessories.
•
For drift bars or rabbits, use wood, plastic, or hard rubber or plastic- or rubbercoated. Do not use steel, aluminum, or other metal drifts. – –
•
For both running and pulling pipe, use elevators, slips, and tongs (including backups) that have 360-degree wrap-around surface-contact areas. – –
Note •
Verify that the drift diameter is correct. Refer to API RP 5A5, Section 4.8, for verification of procedures and recommended drift diameters.
Ensure that the equipment is in good condition and the proper size to grip the tubing. Repair or replace any equipment showing excessive wear or sharp contact surfaces. Slip-and-tong damage (e.g., crushing) can crack the coating.
Leave the thread protectors on until the pipe is vertical, and you are ready to stab the joint. When tubing is being pulled, install the thread protectors immediately after breaking each stand or joint.
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•
After removing the thread protector, clean and lubricate (re-dope) the threads, being careful not to damage the coating. – – –
•
–
Stab each connection with a properly sized rubber, plastic, or plasticcoated stabbing guide. Lower the tubing into the stabbing guide slowly to prevent coating or thread damage.
Start tubing make up by hand; then use the tongs in low gear, at less than 25 rpm. – – –
•
Use a soft-bristle brush to clean connections. Never use a wire brush. Visually inspect each pipe end again and reject damaged joints.
Always use stabbing guides to prevent damage to the coating on the pin end. –
•
Coatings Manual
Use backup tongs during make up, set only on the box. Do not use pipe wrenches for make up. Do not use slips for back up.
To ensure contact of the pin and the coating in the standoff area of the coupling, make up API connections properly. – – – –
Unless an alternate procedure is required, make up API connections to position while monitoring the torque to API specifications. Expose no more than 1½ threads after make up. Use a torque gage that reads directly in ft-lbs. Calibrate the torque gage every three months.
•
Make up premium connections according to the connection manufacturer's written recommendations.
•
Stop travel of the IPC string completely before setting the slips. Lower the string gently into the slips.
•
Do not strike the pipe with any metal object (e.g., a hammer or pipe wrench) even when breaking out connections. Do not allow the pipe to hit any metal object (e.g., the mast).
•
To pull the tubing and set it in stands in the derrick, install thread protectors on the pin-ends or place a resilient pad or carpet on the rig floor to protect the coated end of the tubing while it rests on the rig floor. If we are to lay the tubing down through the V-door, install thread protectors on all pin-ends.
763 Guidelines for Installing Lined Tubing The guidelines for installing coated tubing also apply to lined tubing. Linings are generally more damage-tolerant than coatings; however, mishandling can cause damage that will spoil an otherwise holiday-free, damage-free tubing string installation. Key points are noted or repeated below:
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• • •
Arrange to have a supplier's representative on site during installation. Always use a stabbing guide. Run power tongs at low speed. This is especially critical when: – –
The pin-end starts to contact the corrosion barrier ring (CBR) on fiberglass- or PVC-lined tubing. The pin contacts the plastic insert on cement-lined tubing.
•
Follow the supplier's instructions to insert CBR, Permitek, and so on.
•
For linings with a CBR, run a properly sized (nonmetal) drift through each made-up joint to ensure proper clearance through the CBR.
•
When running cement-lined tubing, use a sinker bar to smooth out the acrylic putty applied to the plastic insert in the box end.
•
When pulling lined pipe, install a thread protector before laying the pipe on a rack or standing it on end.
•
Do not stand lined pipe on end—not even on a cushioned mat—without thread protectors in place.
•
Do not hammer on the pipe to loosen collars.
API RP 10E also has installation guidelines for cement-lined tubing, similar to those listed above.
770 Guidelines for Well Operation The following guidelines are based on the National Association of Corrosion Engineer'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.
☞
Chevron Corporation
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.
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•
When a workover requires fishing, squeezing, drilling, or caustic or acid treatments, 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: – – – –
– –
– – –
– •
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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-reinforced, 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.
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•
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 Materials 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 Engineers. 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.
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800 Offshore Coatings 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 highquality 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 information 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.
Chevron Corporation
Contents
Page
810
In General
800-3
811
Background Information
812
Comparing Off- and Onshore Coatings
820
Quality Control
821
Design Solutions
822
Platform Maintenance
823
Project Planning [1]
824
Protecting Coatings Materials & Equipment Offshore [1]
830
Protecting Human Health & the Environment
831
Typical Hazards Offshore
832
Environmental Issues
840
Selection
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Surface Preparation
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860
References
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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.
811 Background Information Offshore structures and wharves represent a very severe, if not the worst, coating service. Coating systems are selected to balance service life, and assure ease of maintenance, local availability, quality, and suitability for application under prevailing climatic conditions. The relative importance of these factors differs from location to location.
812 Comparing Off- and Onshore Coatings Offshore coating systems are comparable to onshore high-performance systems, except that frequent wetting and high humidity make some upgrading necessary offshore. Example: Splash-zone areas subject coatings to intermittent immersion. Mechanical equipment, valves, pumps and motors are a particular problem offshore if manufacturers of these items coat them with materials adequate for inland or coastal environments, but which fail quickly offshore. Normally, you can purchase larger pieces of equipment and custom-fabricated equipment, such as compressors and vessels, with the Company's coating system already applied. The Company highly recommends doing so. It is generally not economical, however, for the equipment manufacturer to offer custom coatings for commodity items such as pumps or motors. Therefore, apply the complete system at the fabrication yard according to the Company's specifications.
820 Quality Control High-quality and cost-effective coatings are essential, but much more difficult to achieve offshore than onshore. Offshore, there are some adverse factors over which you have little or no control; but you can recognize them and reduce their effects with good planning.[1] Some of these factors are: • • • •
Adverse weather conditions Simultaneous operations with other platform activities Limited availability of transportation Substrate surfaces that are deeply pitted and contaminated by soluble surface salts
You can reduce the costly re-work of prematurely failed coatings by promoting quality control and quality assurance during fabrication. To perform work offshore
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costs approximately ten times as much as the same work in fabrication yards. Design solutions are, therefore, key considerations for offshore coating projects.
Maintenance An effective maintenance program for offshore coatings begins with comprehensive quality assurance and quality control (QA/QC) when applying the initial coating during fabrication. Ensuring that the fabrication yard has applied the coating properly and according to specifications allows you to: •
Obtain a high-quality coating that contributes to the maximum service life of the platform and equipment
•
Reduce future expenditures for field maintenance
New Construction For new construction, the offshore QA/QC program is a team effort among the project engineers, contractors, coating suppliers, third-party inspectors, and inhouse coating personnel. A system of checks and balances, this QA/QC program makes certain that—regardless of the size of the project—the services of all participants fulfill the requirements of the specification.
The Successful Project A successful project includes quality control, particularly as it relates to the following items (discussed below): • • • •
Design Solutions Platform Maintenance Project Planning Protecting Materials & Equipment Offshore
The remaining essential elements of a successful project are surface preparation (discussed below) and application (Section 500 of this manual). One definition of a successful project is that all the work meets the specification at the lowest cost possible, with no accidents, minimal turnover of personnel, and within budgetary constraints.[1]
821 Design Solutions Good design can minimize and repair defects in fabrication and therefore reduce the costs of future coating maintenance by reducing areas which lead to the failure of a coating and resulting corrosion damage. Good design also reduces the cost of current coating projects by correcting problems before or during surface preparation that will improve the ease and efficiency of application. The basic principle of corrosion-resistant design is to keep structures as simple as possible and reduce the surface area to be coated as much as practical. Balance these considerations against necessary engineering requirements for safe and effective service regardless of the coating problems.
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Detailed below are problems and solutions for the following design issues: beams, congested and inaccessible areas, decks, elevated structures, sharp edges, stainless steel bands and tubing, surface laminations, welds, and u-bolts.
Angle, Channel, H- and I-Beams Problem: The angles and edges on these basic structural shapes cause many problems. They often receive inadequate dry film thickness (DFT) because proper spray technique is hard to achieve in these areas. The web/flange interface is also a difficult area to coat. Most high-performance coatings exhibit considerable surface tension upon drying which can cause the coating to pull away from corners. These areas are also susceptible to dry spray and overspray which break the bond between the applied coating and the substrate. As flat surfaces generally allow proper application technique, they receive better deposits of film. Note For a proper spray technique, hold coating guns perpendicular to substrates, approximately eight to ten inches from the surface. Solution: To achieve adequate film on angles and interfaces of all hard-to-coat areas, specify a brush coat (extra coat) of the first intermediate—usually of contrasting color—over the primer before applying the remaining coats.
Congested and Inaccessible Areas Problem: Congested and inaccessible areas are primary contributors to coating failures and increased costs of maintenance. Problems begin at the fabrication yard and continue throughout the life of the platform. These areas are extremely costly because space restrictions: •
Limit movement of the coatings applicators
•
Prevent many items from receiving adequate coating
•
Cause the work to proceed slowly
•
Contribute to the high risk of substandard coatings as adequate coating coverage is difficult to achieve
Congested and inaccessible areas are the first to fail, requiring more frequent maintenance cycles at escalated costs. Many congested areas involve production equipment and piping, which are the most critical items on the platform. Example: Inaccessible areas that seldom receive adequate coating protection include: • • •
Non- or skip-welded back-to-back angles Box beams Through-deck piping surrounded by pollution rings, and under-deck piping
Maintenance of under-deck piping is costly as it requires erecting a scaffold for all work, including routine, non-destructive testing.
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Solutions: The following solutions are intended to reduce coatings problems in congested/inaccessible areas: •
Do not design, if at all possible, any structure with items that are congested and inaccessible.
•
Route all piping at least six inches above solid decks.
•
Design pollution rings to include at least a six-inch clearance from throughdeck piping.
•
Do not design box beams and back-to-back angles, if possible. (If back-to-back angles are necessary, specify seal welds.)
Decks—Diamond Plates Problem:
Any of the following problems can occur with diamond deck plates:
•
Rust may form at the peak of elevated diamonds where the coating is sheared by equipment placed on or dragged across the surface.
•
The angles of the diamonds can trap moisture and salt, causing the coating to undercreep to the flat area of the plate. Entire decks begin to rust and coatings de-laminate. This often requires 100 per cent blasting as surface preparation to remove the lifted coating.
•
Diamond decks can become expensive to maintain in terms of time and abrasive to blast each elevation from different angles to remove loose scale and oxidation.
•
Diamond decks can require up to two times the amount of coating for flat plate because of the greater surface area.
Solution: Install flat plates whenever possible. The service life of a coating is longer on flat plates than on diamond deck plates.
Decks—Solid Problem: Depending on their height above water, solid decks need recoating every three-to-five years. Solid deck coatings are expensive to maintain in terms of time, labor, equipment, and materials needed to blast and coat both the top and underside. Solution:
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The following are two suggested solutions:
•
Install galvanized grating, which performs well except at waterlines. (This is the standard on most of the Company's platforms.) Service life at the 10-foot level is about four-to-five years.
•
Install fiberglass grating, which has given excellent results at several of the Company's locations after 12 years of service.
Caution Although environmental and containment concerns restrict grating decks, install them whenever possible.
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•
Solid decks are used around production equipment to prevent spills into the water.
•
Grating decks are used on the bottom levels of the platform where water could cause a solid floor to be slippery.
•
Solid floors are typically used on the upper decks where crew living quarters are located.
Elevated Structural Members at +10-foot Level Problems: The waterline is the most corrosive and most difficult area to maintain on the platform. •
Structural members (horizontals and diagonals that are close to the water) are more susceptible to corrosion and are more expensive to maintain than higher ones.
•
Boat landings present major problems. In the Company's older designs, boat bumpers also serve as support members and are usually installed on three sides of the platform. The bumpers' elevations range from five-to-eight feet above the tidal area. The bottom third is in water much of the time and is covered with marine growth so that only the top portion is accessible for blasting and coating. Boat bumpers are in congested areas with vertical members spaced every several feet. Adequate blasting and recoating is possible only for the top portion; and, at best, those areas require extensive recoating at least every five years.
Solutions: The following solutions are designed to reduce maintenance of +10-foot areas. •
Design +10-foot areas as high as possible from the tidal zone and minimize the surface areas of boat bumpers.
•
Include horizontal members 15 feet above the tidal area (as compared to older ones, which are 5-to-8 feet above the tidal area).
•
Keep the size and number of boat bumpers to a minimum.
Note Surveys indicate that the service life of coating systems on newer designs is at least double the service life of older designs; service life of bumpers is unchanged. Analysis of past coating jobs on deep-water four- and six-pile platforms indicates that coatings of elevated designs are completed in half the number of days of lower designs, resulting in substantial savings of maintenance costs.
Sharp Edges Problem: Sharp edges left on overlapping plates or edges by shearing or cutting will cause coatings to fail, almost without exception. Surface tension and shrinkage during curing pulls the coating away from the edges, leaving areas of low DFT or holidays (or both). Additional film defects occur when, as is normal, the crew applies the coating on tangent to the edges rather than perpendicularly.
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Solution:
To achieve the best protection, the design should stipulate:
•
Grinding the edges smooth or increasing the thickness on the edge areas (or both) to help achieve the best protection
•
Applying an additional coating to the edge before each coat, followed by the normal coating that is extended over the edge with several inches of overlap
Stainless Steel Bands/Tubing Problem: Stainless-steel bands, holding emergency shut-down (ESD) tubing in place on vessels and piping, are primary causes of corrosion damage. The protective coating on vessels and piping is usually damaged during installation when the bands are crimped to the item. The remaining bands eventually rub off the coating. Any small coating defect causes dissimilar metal action between the bands and the carbon steel substrate. Pitting begins in a relatively short time after moisture and salts are trapped at the interface. Stainless-steel tubing produces similar results. Solution: To prevent pitting, specify bands with neoprene or similar lining and elevate tubing from the substrate on either rubber or Teflon blocks.
Surface Laminations Problem: Difficult to coat, surface laminations include sharp, jagged protrusions with gouges and voids on the undersides. Solution: To facilitate applying the coating, the design should stipulate grinding/ removing laminations before abrasive blasting and coating.
Welds—Flux Problem: Highly alkaline and hydroscopic, residual weld flux eventually delaminates from the surface, causing blisters—the site of early coating failure—in the coating. Solution: To help prevent residual weld flux from delaminating, the design should stipulate removing weld flux before abrasive blasting and coating.
Welds—Rough Problem: Surface irregularities on rough welds make it difficult to apply coatings in a continuous film, free from voids and pinholes. Small defects in a coating allow moisture to penetrate to the surface, causing localized corrosion cells. These cells, combined with the weld's being a heat-affected area, accelerate the corrosion rate. Solution: To achieve a smooth surface without voids and pinholes, the design should stipulate grinding all rough welds before coating.
Welds—Skip Problem: Skip welding is a common technique for reinforcing areas where a continuous weld is not necessary. It is impossible to coat the resulting crevices— between the welds at the interfaces of the metal pieces—adequately.
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Example: On offshore platforms, constant vibration can cause the coating—bonded at the interfaces—to rub off and the surface to accumulate moisture and salt deposits, which accelerate corrosion rates. Solution: For coated surfaces which are exposed to vibration, specify continuous seal welds instead of skip welds.
Welds—Splatter Problem: Weld splatter is small balls of metal that adhere to the surface. The applied coating literally flows off the splatter, leaving exposed areas which eventually undercreep to the coated item. Small crevices also develop around the bases of the splatter, creating voids where coatings cannot penetrate. Coating applied to weld splatter will eventually fail. Solution: To prevent splatter from exposing areas of surface and causing crevices in the coating, the design should stipulate removing weld splatter before blasting and coating.
U-bolts Problem: Galvanized or cadmium-plated u-bolts which support piping on metal supports cause damage to the coating when subjected to platform vibration and other movement. The rubbing action results in metal-to-metal contact which causes pitting. Solution: To prevent pitting, specify neoprene-coated u-bolts with neoprene pads or Teflon blocks on the support bracing to prevent metal-to-metal contact.
822 Platform Maintenance Long-range planning optimizes overall expenditures and timing in the following ways: •
Distributes expenditures over the life of the platform
•
Keeps facilities in good condition by arranging for appropriate levels of maintenance
•
Reduces the need for major maintenance (50 percent top to bottom) in a given year
•
Limits the need for major coating projects toward the end of a platform's producing life
•
Realizes savings by reducing platform downtime and preventing premature failures from corrosion
A maintenance program should begin as soon as a platform is in service. As a platform nears the end of its producing life, critical cost factors such as time, labor, equipment requirements, materials, etc. become increasingly important, sometimes over-shadowing service life.
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Work Priorities The priorities of platform maintenance change as service conditions change, often being revised several times over the producing life of a platform. Setting work priorities for an offshore coating project involves the following factors which are also important when assessing a coating to determine repair procedures and costs: • • • •
Coating type and existing condition Percentage of surface breakdown Degree of corrosion Type of item (structural or equipment)
Condition of the Existing Coating. Judge the corrosion on structural members and equipment to establish priorities, define the scope of work, and forecast expenditures. Severity of Corrosion and Recommended Repairs. The following examples are typical offshore coating failures and recommended repair procedures. •
Zinc/epoxy/urethane systems tend to be brittle, to chalk, and to exhibit topcoat delamination from the zinc primer. Corrosion, usually local during early failure mode, tends to undercreep the epoxy topcoats by sacrificial action of the zinc primer. Limit maintenance to selective spot blasting and coating with compatible epoxy and urethane topcoats before the system is badly damaged. Otherwise, the surface may need complete blasting and recoating.
•
Solvent-based vinyl coating systems tend to remain soft and flexible, with relatively good adhesion. Most vinyl coating failures are the result of osmotic blistering (water penetrating to the substrate), mechanical damage or application defects such as holidays (breaks or flaws) in the wash primer, low dry-film thickness (DFT), and overblast damage. Corrosion is usually uniform over a larger surface area, but pitting is not as severe as with zinc/epoxy/urethanes. Vinyls are easy to spot blast, sweep, and topcoat with other vinyl systems because solvents redissolve easily, allowing for easy tie-in or adhesion of the new coating to the existing coating.
Operating Service of Equipment and Structural Items. For cost-effective coatings maintenance, avoid complete top-to-bottom work by developing evaluationand-ranking criteria for platform items such as those shown in Figure 800-1. In this figure, priorities are determined by varying degrees of coating breakdown and rust and by safety, type of service, and location of the item. Safety and Environmental Concerns. Normally, safety-related items such as vessels, piping, stairwells, and heliports take priority over others when coating and corrosion are equal. Adequate wall thickness, however, is always an overriding concern. If wall thickness of a given item does not meet minimal requirements, replace that item. For more information, refer to Protecting Human Health & the Environment later in this section.
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Sample Platform Survey Report
Fig. 800-1
❒ Major
Platform type (check one)
Date
Location
9/1/95
Typical Platform
❒ Satellite
❒ MW Caisson
❒ SW Caisson
❒ Monopod
❒ 8 Pile
❒ 4 Pile
❒ 3 Pile
❒ Wellguard
Job type (check one)
❒ Deck
Heliport size 20/60
❒ Boat
Capacity Crane 30 tons
Capacity Quarters 15 man
Condition Evaluation Scale
Priority Percent Breakdown
1—Light rust only
A—0 to 10
1—Work in 1 year
2—Light to medium rust
B—11 to 25
2—Work in 2 years
3—Light to medium scale
C—26 to 40
3—Work in 3 years
4—Light pits/light scale
D—41 to 60
4—Work in 4 years
5—Light pits/medium scale
F—over 60
6—Light pits/severe scale 7—Medium pits/medium scale 8—Severe pits/severe scale 9—New construction item Item
Coating Type
Condition
Priority
Est. # Days
1. Heliport a. Top b. Underside
Polyester
C5
1-2
6
ZN/EP/URE
B2
3
N/A
2. Top Deck Level a. Deck Plates
Comments Condition warrants work in near future
No work needed this year; fair condition; no estimate needed Coating undercreepage and delamination
Polyester
D7
1
10
b. Escape Capsule Davit
ZN/EP/URE
A9
1
3
New addition; welds need touchup
c. Skid Beams
ZN/EP/URE
C6
1-2
5
Severe impact damage on topsides; severe scale under flange; needs work soon
d. I-Beams/STR. MEM
ZN/EP/URE
A1
4
Looks good; no est. required
e. Grating Areas
Galvanized
F8
1
Several sections need changeout schedule for welding
a. Overhead Piping
ZN/EP/URE
C5
1
14
Coating in failure mode; needs work
b. New 2" Fuel Gas Lines
ZN/EP/URE
A-9-2
1
4
New items - welds need TU and remainder needs spot blast and paint
c. Vessels
ZN/EP/URE
A1
4+
Good shape; no work needed
d. Top Deck Supports
ZN/EP/URE
A1
4+
Ditto
e. I-Beams
ZN/EP/URE
A1
4+
Ditto
f. Grating
Galvanized
B2
3-4
Needs changeout 3-4 years
4. Under Superstructure
ZN/EP/URE
C5
2-3
5. Risers
ZN/EP/URE
A1
4
6. Waterline
ZN/EP/URE
F8
1
3. Under Top Deck
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Coating undercreepage; scale on beams & piping Looks good; no est. required
21
Severely corroded; needs work ASAP
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Remaining Life of the Facility. See Figure 800-2. Fig. 800-2
Priority 1 Coating Maintenance Items Based on Facility’s Life Expectancy and Existing Condition Based on Life Expectancy & Existing Condition Long Term (7+ years)
Priority 1 Items
Medium Term (5-7 years)
Short Term (less than 5 years)
All primary safety items, including process vessels, interconnecting piping, risers, stairwells, walkways, and heliports
C4 or worse
C5 or worse
D7 or worse
Structural items such as waterline members, decking, I-beams, support trusses, plate girders, and legs
D5 or worse
D7 or worse
Defer until the facility depletes, is sold, or changes to another category.
Recommend plugging and abandoning or selling any property that does not meet the economic criteria to perform the necessary maintenance to operate safely. In all cases (except for certain short-term properties), touch up bare welds and scar damage on new installation items. Before deferral, if conditions equal or exceed C4, or if the item’s integrity is in question, verify by non-destructive evaluation (x-ray or ultrasonic testing) that the remaining wall thickness of vessels, piping, and structural steel remain within safe operating limits.
Prevailing Economic Conditions. Coating maintenance programs vary depending on the prevailing economy. Protective coating maintenance programs are vulnerable during difficult economic conditions. A selective deferral strategy: •
Postpones non-critical, borderline work and concentrates on critical work
•
Reduces overall expenditures in the short term and in locations that have a number of platforms and facilities
•
Allows spot maintenance on more platforms (providing adequate levels of maintenance levels, although less than desirable in some cases)
The disadvantages of selective deferral are that deferred items: •
Continue to deteriorate
•
Cost more to repair after several years because of additional mobilization costs, inflation, and increased work scope
Favorable economic conditions may justify greater expenditures: •
Accomplishing more work on necessary items, including those deferred from previous periods
•
Reducing the number of spot-maintenance cycles
Forecasting Work A forecaster needs the following information to prepare budgets, project future work, and make adjustments: • •
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Both short- and long-term field economic strategies Conditions of the platform
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– –
Historical—timing and quality of the previous coating Current—existing coating system, service conditions, comprehensive annual or bi-annual topside coating surveys about the platform's current condition
Often, you need to prepare a pre-project survey before you can establish detailed work and coating schedules and arrange for equipment and personnel.[4] See Figure 800-1 for forecasts; Figure 800-3 for pre-job planning.
Background Information for Forecasting For onshore projects, effective quality control during fabrication helps to ensure the longest service life from the initial coating work (exceeding offshore work by 25 to 30 percent). Achieving the same degree of quality offshore is difficult because the surface becomes contaminated by salts, oils, grease, or pitting, and access to work items is limited. The higher the quality of each fabrication, the longer the coating lasts. A long-lasting coating minimizes future work and lowers cost. Structural members and piping at the +10-foot waterline areas and superstructure undersides generally require more frequent maintenance intervals (every five to seven years) than upper elevations for the following reasons: •
Coating damage can be severe due to high levels of exposure to saltwater, spray, and salt deposits.
•
The waterline area is subject to wave action, floating debris, and damage from the impact of cargo and crew boats.
•
Production risers at the +10-foot level are more critical than structural members because of high operating pressures, product volume, and potential for pollution.
•
Metal loss of 40 mils or more per year can occur near the waterline.[3]
Elevated structural members, piping, and other items may require maintenance intervals of 7 to 12 years. Mechanical damage occurs in coatings of high-traffic, high-impact areas such as helidecks and production decks, requiring maintenance intervals of 5 to 7 years.
Annual Surveys Survey reports provide information on the conditions of a platform, enabling the forecaster to: • • • • •
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Adjust forecasted expenditures Establish priorities for specific tasks over the next three-to-five years Provide options for scheduling critical or deferring non-critical tasks Optimize expenditures by scheduling tasks appropriately Estimate the cost of projects
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Fig. 800-3
Coatings Manual
Questionnaire for Pre-Job Platform Inspection Offshore Coatings Category/Item
Yes
No
Comments
Percentage of Coating Breakdown and Severity of Corrosion Do the platform and equipment items need to be spot or 100% blasted & painted? Are there any severely corroded items that need changeout? What is the condition of the clamps and u-bolts? What is the condition of sight glasses, valves, etc.? Type of Existing Paint System What is the general condition of the coating? Is the specified system compatible? Can this system be feather-edged and tied into the new system? Do any items need specialty coatings (e.g. hot or submerged equipment & piping?) Platform Layout Is there sufficient space for equipment and supplies? What type of rigging will be required? Are there any special considerations for rigging? What is the crane’s capacity? What is the fuel capacity? Are there sufficient living accommodations for the crew? What is the potable water capacity? Is the platform a high traffic area? Platform Equipment Setup Do any equipment items need filtration or wrapping? Is any shut-in time needed for blasting and painting? If so, what is the estimated down time? Do any areas require wrapping for overblast and overspray prevention? Are there any drains which need plugging? Are there any special safety concerns (e.g. hot piping, confined spaces, fall hazards)? Are there any sweating lines which will require shut-in for blasting and painting?
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Candidates for conducting annual surveys include NACE International Certified Coating Inspectors who have a sound working knowledge of offshore coatings operations, coating systems, and general corrosion principles and who can assess platform conditions, priorities, and estimates. A thorough survey includes the following information: • • •
Platform type (major, satellite, multi- or single-well caisson, or other) Number of piles Crew set-up needed for proposed work (e.g., deck crew, boat crew, jack-up barge) • Heliport size and weight limitations • Capacity of the crane • Capacity of quarters • Coating system on specific areas/items • Coating condition on specific areas/items • Work priority (estimated time of next maintenance work) • Estimated number of days required • General comments (e.g., change-out items, type of crew base camp set-up, type of surface preparation, coating required) • A comprehensive pictorial of each platform to document items that may soon require attention Figure 800-1 is a typical completed survey report form.
823 Project Planning [1] Of the key considerations in project planning, there are two of special interest to offshore coating projects: • •
Pre-inspecting the Platform Coordinating Jobs
Pre-Inspecting the Platform Pre-inspecting the platform helps to determine work and coating schedules and assists in overall project coordination. The following tasks should be part of a prejob inspection: •
Inspect the platform to determine the specific job scope and plan for personnel and equipment set-up.
•
Consult platform operators about operating routines and production equipment, preferably with the designated inspector and crew foreman present.
•
Check the platform and its operating equipment.
See Figure 800-3: Questionnaire for Pre-job Platform Inspection.
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Coordinating Jobs Job coordination is a cost-saving practice that eliminates unnecessary downtime, keeps the coatings applicator on a favorable work routine, and helps prevent potential problems. For example, offshore platforms have logistical limitations—each flight and supply boat run adds to the job cost—so forethought results in a much smoother project. Schedule flights and supply runs: •
To minimize transportation costs
•
In the morning, to minimize disruption of coating operations during critical project phases in the afternoon
Ensure that the inspector and crew foreman maintain updated and accurate inventories of material and anticipate needs for materials. In addition: •
Replenish fuel and water on each boat run.
•
Maintain ample supplies of abrasive and coatings in the event of extended periods of bad weather.
Transition times—during which the coatings applicators change from one operation to another—can also make a significant difference to the cost of a project. See Section 100 of this manual.
824 Protecting Coatings Materials & Equipment Offshore [1] The condition of abrasives and coating materials affects the service life of applied coatings. Offshore, abrasives and coatings are subject to a harsh environment— baked in sun, flooded in high seas, contaminated by saltwater, banged, broken, or dropped. As these materials also have unique transportation requirements, take special precautions to preserve their integrity. Proper handling and storage are high priorities. Realize short-term savings by replacing bad material infrequently (including reducing downtime while waiting for re-supply and additional boat runs). Handled and stored properly, the materials stay in good condition and result in long-term savings from the increased service life of the coating.
Abrasives For high-production blasting, large-volume bulk blast pots require massive amounts of abrasive. A typical, high-production, 100-per-cent blasting needs 25 to 30 tons of workboat-transported abrasive weekly. Good planning is essential to maintain sufficient quantity on board. It is important to store the abrasive in bulk containers to keep it dry and uncontaminated. Each bulk container holds about two tons of abrasive and may be any of three major kinds: vinyl, disposable bulk bags, or metal hoppers. The first two are most common.
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Follow these procedures to keep bags safe and functional: •
Check for damage before and after each use. Look for wear and for holes in the sides, tops, or funnels. Note any missing or worn tie ropes on the top and bottom funnels. Replace as necessary.
•
Report all damaged bags to the appropriate authority.
•
Remove damaged bags from circulation until repaired; or, if disposable bags, discard altogether.
•
Prepare accurate use-and-damage reports for each bag.
•
Identify the number of uses for disposable bags by coating a slash or mark on the outside. Do not use disposal bags more than the recommended number of times.
•
Transport and store both empty and full bags on pallets to prevent contamination by seepage.
•
Store empty bags away from sunlight and in a dry place. Immediately after emptying, fold the ends of the bags inward, roll lengthwise, and tie each bag separately with manila twine. Tie a bundle of bags to a pallet for shipment.
Coatings Coating containers begin to deteriorate from sunlight and salt as soon as they arrive at the shorebase. Proper storage of coatings is essential because coatings must be mixable, sprayable, and free from contamination. Follow these procedures for storing coatings:
Chevron Corporation
•
Store coating cans in a well-ventilated area.
•
Keep cans away from direct sunlight in a coating-storage building dockside, and in the shade at the job site.
•
Store cans on pallets. They should not come into direct contact with solid decks (which can reach 130ºF in summer months) and should not sit in salt water for extended periods of time during shipping.
•
Do not cover coating cans with tarpaulins during hot months; the oven-like effect literally cooks the material.
•
Maintain tight inventory control. Keep cans in one area; do not allow them to be scattered around the platform.
•
Rotate the coating stock weekly.
•
Apply the coating material as soon as possible after opening a container.
•
Remove coating residue from empty cans before disposing of them.
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–
– –
Dispose of empty coating cans by removing the bottoms, crushing the cans, and tying them in bundles to save trash basket space and minimize handling time after removing cans from the work site. Store empty cans separately from regular trash because they will probably require special handling for disposal. Ensure that the proper Material Safety Data Sheets (MSDS) and Hazardous Material Shipping Manifests accompany the coating at all times.
Equipment Nav-aid lights make the platform visible to boat traffic at night. They need protection from overblast or overspray because even small amounts distort the light beam and affect visibility. Even minor damage to these lenses requires costly replacement. During a coatings project, crews must cover and uncover these lights. To cut costs of material and manpower, they can use a cylinder-shaped cover of chicken wire wrapped with plastic. These covers are inexpensive, easy to install and remove, and durable. For additional information about protecting the Company's equipment, see Section 100 of this manual.
830 Protecting Human Health & the Environment Workers' safety and the environment are among the foremost concerns of any coatings project. General information on these subjects is provided in the Section 200 of this manual, however, there are some special considerations for offshore work.
831 Typical Hazards Offshore Many hazards are associated with offshore coatings activities, some with job-site conditions that change daily. In general, offshore safe practices for coatings projects should include: •
Ensuring that the Company's representative has a good understanding of offshore work processes, equipment set-up, and potential hazards [2]
•
Choosing contractors who specialize in offshore coatings work and who have high-quality safety and training programs, good equipment, and competent personnel[2]
Some typical hazards offshore are offloading equipment and supplies; lead and other regulated, hazardous, heavy metals in the existing coating; and scaffolding.
Offloading Equipment & Supplies Offloading equipment for a crew of 8-to-10 workers takes up to 12 hours and requires about 60 lifts from a cargo boat. Equipment can include 750-CFM or larger air compressors, 8-ton bulk abrasive blast pots, air-volume tanks, scaffolding,
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hoses, 4,000-pound bulk-abrasive bags, cargo baskets filled with coating materials, portable bunkhouses, or galley buildings.[1] Concern. •
Transferring equipment, material, and personnel from the cargo boat safely
Factors to Consider. •
Weather and sea conditions
•
Qualifications of coatings applicators (should be rigger-certified)
•
Qualifications of the crane operator and boat captain
•
Organization and coordination of the loading activities
•
Level of communication among all involved, especially the crew foreman, crane operator, hook-up personnel on the boat and the platform, and the boat captain
Lead and Other Regulated, Hazardous, Heavy Metals Exposure to elevated levels of lead/heavy metals can have adverse and chronic effects on the human central nervous and reproductive systems. Concerns. •
The degree of lead/heavy metals in coating systems on offshore platforms
•
Workers' exposure to elevated levels of lead/heavy metals when removing the coating with abrasive blasting, hand tools, or power tools
Safe Practices. •
Inform the contractor of any potential for exposure to lead/heavy metals to ensure that the contractor provides necessary monitoring and appropriate protection for workers as mandated by OSHA, 29 CFR 1926.62, 1926.63, and 1926.55. The Company's representative should contact local ES&H authority for guidance and assistance.
•
Determine the exposure level from workers' personal monitors worn in a particular work area or platform.
•
Require a degree of protection for workers corresponding to the level of exposure. (Workers' protection includes respirators, protective clothing, and changeand-wash facilities.)
Refer to OSHA guidelines about lead in industrial protective coatings [5, 7].
Scaffolding Crews often perform blasting and coating from scaffolding. Cable scaffolding is generally set up for work on deck undersides (under heliports and superstructures. Cable scaffolding consists of 1- by 16-foot wooden timbers or aluminum boards
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tied by manila rope to cable strands. Cable clamps and net hooks secure the cables and nets. Concerns. •
Possibility of falling from scaffolding above deck, under the superstructure, or at the +10-foot waterline level
•
Inadequate offshore scaffolding techniques
Safe Practices. •
Require that personnel wear full-body harnesses to prevent back injury in case of a fall.[2]
•
Ensure that rigging follows accepted practices of five cables—two to support the timbers, two to support the nets, and one as a safety line for safety lanyards.
•
Secure cables with double cable clamps; position the live end on the U-bolt side of the clamp.
•
Do not use old, rusted cables.
•
Do not splice cables.
832 Environmental Issues Environmental issues have a significant effect on offshore coatings programs as regulatory agencies become increasingly concerned about offshore activities. Many operators are reviewing their onshore programs and adopting applicable environmental protection practices for offshore work. Those responsible for overseeing coatings activities should be thoroughly familiar with the applicable laws to ensure that the Company is operating in compliance with them. Local environmental, safety, and health specialists are a good resource of information about environmental protection offshore.
840 Selection See the Quick Reference Guide for the selection process and selection guides for offshore coating systems.
850 Surface Preparation Achieving the surface preparation outlined in the Company's specification is crucial.[8] While this is really no different than for any other coating job, the greater expense of offshore repairs makes it even more important to pay close attention to this vital part of a coatings job.
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860 References 1.
Conlin, T.M. “Fundamentals of Offshore Coating Operations: It's the Little Things that Really Make the Difference.” Journal of Protective Coatings & Linings, Vol. 7, No. 9. Steel Structures Coating Council. September 1990.
2.
Loss Prevention Guide No. 25 - Health, Environment & Loss Prevention. Chevron Corporation. May 1991.
3.
Munger, Charles G. Corrosion Prevention by Protective Coatings. National Association of Corrosion Engineers. 1986.
4.
National Association of Corrosion Engineers. NACE Coating Inspector Training and Certification Program - Session 1, Organizational Development Systems, Inc. Houston, Texas: 1982.
5.
Office of the Federal Register, National Archives and Records Administration. Special Edition of the Federal Register. OSHA Safety and Health Standards, 29 CFR 1910/1926, U.S. Department of Labor, 1991 and 1993.
6.
Roebuck, A.H., T.M. Conlin, and Durwood Broussard. ”Offshore Coatings Work.” Proceedings of Steel Structures Coating Council. 1991.
7.
Office of the Federal Register, National Archives and Records Administration. Special Edition of the Federal Register. Safety and Health Standards, 29 CFR 1926.62, Construction Industry Standard. United States Government Printing Office. Washington: 1995.
8.
Chevron Corporation. “Specification COM-MS-4771 Offshore Structures Coatings.” Coatings Manual Chevron Research and Technology Company. Richmond, CA: January, 1995.
9.
Office of the Federal Register, National Archives and Records Administration. Special Edition of the Federal Register. OSHA 29 CFR 1926.63. United States Government Printing Office. Washington: 1995.
10. ———. Special Edition of the Federal Register. OSHA 29 CFR 1926.55 United States Government Printing Office. Washington: 1995.
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900 Pipeline Coatings Abstract This section contains general information about external and internal pipeline coatings. External pipeline coatings are described in figures which highlight the definition, recommended services, and other key elements of a coating. Quality control is viewed from the standpoint of specifications, planning (based on a coating's service conditions, durability and resistance, construction factors, and application factors), and inspection. The selection section covers new construction and rehabilitation coatings. Pipe is coated or lined internally to prevent corrosion or to increase flow rates by reducing friction losses. In some cases by installing linings through existing piping, a corroded line which would otherwise have to be replaced can be salvaged. In this section, the term, coatings, means the relatively thin paint, while linings are much thicker cement or plastic. Field-applied means applying a lining or coating to an existing pipeline. Internally coated pipe is the main issue, with linings introduced only in terms of alternatives to internally coated pipe. Both linings and coatings can be shop- or field-applied. For general information about: • • •
Surface preparation, see Section 100. Environment, health, and safety as they relate to coatings, see Section 200. The economics and colors of Company coatings, see Section 300.
For more detailed information about cement- and plastic-lined pipe, refer to the Company's Pipeline and Piping Manuals.
Chevron Corporation
Contents
Page
910
Pipeline Coatings in General
900-3
920
External Pipeline Coatings
900-3
921
Selection
922
Quality Control
930
Internal Pipeline Coatings
931
Shop-applied Internal Pipeline Coatings
900-1
900-54
September 1996
900 Pipeline Coatings
September 1996
Coatings Manual
932
Field-applied Internal Pipeline Coatings
933
Weld-joint Application & Inspection
940
References
900-59
900-2
Chevron Corporation
Coatings Manual
900 Pipeline Coatings
910 Pipeline Coatings in General The information in this section about pipeline coatings is general in nature. For assistance with specific projects, contact the Company's coating specialists listed in the Quick Reference Guide.
920 External Pipeline Coatings The figures at the end of this section describe external coatings, both pipeline and girth-weld protection. These figures highlight the definition, recommended services, status, maximum service temperature, surface preparation, application, thickness, small repairs, handling/storage, protection, discussion, brands, and references of these coatings. Quality control is viewed from the standpoint of specifications, planning (based on a coating's service conditions, durability and resistance, construction factors, and application factors), and inspection.
921 Selection There are numerous factors to consider when selecting a pipeline coating. Figure 900-1 is a selection flowchart for choosing an appropriate mill-applied coating. Figure 900-2 lists recommended external pipeline coatings for new construction projects. The coatings in Figure 900-2 are listed in order of preference. Figure 900-3 compares advantages and disadvantages of several types of external pipeline coatings. For detailed information on various types of coatings, consult Figures 900-4 through 900-21. Splash-zone Coating for Offshore Platform Risers. See Figure 900-22 for operating temperatures of splash-zone coatings for offshore platform risers. Valves, Fittings, Tie-ins. Their unique shape makes valves, fittings, tie-ins, and other buried objects of irregular geometry hard to coat. As FBE is a shop-applied coating, choose a spray or hand-applied coating from the list in Figure 900-23 Pipeline Fitting & Valve Coating Systems. Protection. •
Girth Weld See Figure 900-24 for a list of generic coatings for girth-weld protection. Figures 900-4 through 900-21 contain more detailed information on girth weld protection for specific coatings.
•
Rock Choose any acceptable rockshield material (Tuff-N-nuff, Ametek, Rock Shield, Armor Rock) to protect coatings from mechanical damage from rocks or backfill in a ditch. The rock protection is: –
Chevron Corporation
Wrapped around the pipe and bound with plastic straps
900-3
September 1996
900 Pipeline Coatings
Coatings Manual
– –
Installed just before the pipe is put into the ditch Perforated to prevent cathodic shielding
See also comments about rock protection in the Protection portion of Figures 900-4 through 900-21. •
Construction Boring
Topcoat FBE with Protegal UT 23-10 or Powercrete to give the coating added protection from damage during slick-bore construction, particularly where rocks in the soil may abrade the FBE. Both Protegal and Powercrete have greater abrasion resistance than FBE coatings. Fig. 900-1
Mill-Applied Coating Selection Flowchart
September 1996
900-4
Chevron Corporation
Coatings Manual
Fig. 900-2 Rank 1.
2.
3.
4.
900 Pipeline Coatings
Recommended External Pipeline Coatings for New Construction—Ranked in Order of Preference (1 of 2) Buried Onshore Line
Extruded Plastic with FBE • Service temp. to 200°F •
All soils except hydrocarbon contaminated
•
Coating thickness per pipeline's operating temperature
In-plant Short Buried Lines(1)
Subsea Line
Elevated Temperature
Extruded Plastic with FBE Primer • Higher service temperature to 230°F
Extruded Plastic with FBE Primer(2) • Higher service temperature to 230°F
Liquid Epoxy • Some have same chemical and temperature resistance as FBE
•
Moisture resistant
•
Moisture resistant
•
•
Field experience currently limited
•
Field experience currently limited
•
Hydrocarbon damages outer plastic jacket
•
Hydrocarbon damages outer plastic jacket
Also can be field applied; so, suitable for high and ambient temperature lines, especially for in-plant lines
•
Cure can be up to 24 hours before service, per temperature during application
FBE • Service temp. between -76°F and 200°F
FBE • Higher service temperature to 200°F
FBE(3) • Service temperature up to 200°F(4)
Plastic-backed Tape Wraps • Mixed success with butyl adhesives as most are:
•
All soils
•
•
•
Not resistant to hydrocarbons
•
Coating thickness per use
•
Poor resistance to soil stress and pipe movement
•
Not applied generally under ideal conditions
•
Least cost, easy to apply
Extruded Plastic with Butyl Rubber or Asphalt Adhesive • Very economical •
Service temp. to at least 100°F, some to 180°F
•
Suitable for low-soil stress areas
•
Not resistant to hydrocarbons
Coating thickness per temperature
Coal-tar Enamel • Service temp. 140°F • •
Good if selected and applied correctly Hard to handle: brittle when cold, soft when hot
Coating thickness per temperature
Extruded Plastic with Butyl Rubber Adhesive • Very economical •
Service temp. to maximum of 180°F
•
Suitable for low-soil stress areas
Coal-tar Enamel • Service temp. 140°F
Tape Wrap(5), (6) • Low soil-stress areas
•
Good if applied correctly
•
•
Hard to handle: brittle when cold, soft when hot
Select only specialty, high-temperature tape wraps for service over 140°F(7)
•
Not resistant to hydrocarbons
Chevron Corporation
900-5
September 1996
900 Pipeline Coatings
Fig. 900-2 5.
Coatings Manual
Recommended External Pipeline Coatings for New Construction—Ranked in Order of Preference (2 of 2)
Tape Wrap(7) • For low-soil-stress areas •
Not resistant to hydrocarbons
Concrete (Weight) Coating—Normally, we apply a concrete (weight) topcoat to FBE and other offshore coatings for negative buoyancy and coating protection. For small-diameter lines, FBE does not need protection; therefore, extra steel can provide negative buoyancy. A weighted topcoat not only protects coal tar from UV rays before we lay the pipeline but also prevents handling damage. See the CRTC Pipeline Manual for additional information about concrete (weight) coatings. Extruded Plastic—Continuous plastic coating (either polyethylene or polypropylene) is extruded on a pipe at elevated temperatures. There are two distinct subcategories of coatings: plastic coatings with a soft-extruded-butyl rubber of flood-coated-asphalt rubber-mastic adhesive, and plastic coatings with a cured-hard-epoxy adhesive. Sometimes, a copolymer adhesive bonds the plastic outer layer to the epoxy inner layer. There are also two methods of extruding the plastic coating portion of the coating system: a side or T-shaped die, or a crosshead or circular die [3]. (1) The cost of materials is proportionally higher than for a large project. Weigh the cost against the importance of the pipeline, its access, its location (populated area vs. wilderness), and soil conditions. Lower costs of future repairs or refurbishing may offset the initial expense of high-quality coatings. (2) For abrasion protection against thermal expanding and contracting of elevated temperature lines, increase the thickness of the polyethylene or polypropylene coating. (3) FBEs permeability to water increases with temperature; but this problem has been solved to date by increasing the thickness of the FBE according to service temperature. Consider the cost of the increase in thickness. (4) Currently, FBE is the only economical line coating for temperatures over 180°F. Aramco has successfully pushed FBE to 225°F (22 mils) in sandy soil; but, the coating softens notably above 210°F. There is a cohesion failure if a knife can remove the coating. Company recommends only three brands for service over 150°F: Nap-Gard (7-2501 and 7-2504), Valspar D1003, and Scotchkote 206N based on field experience and test data. (5) Company recommends only shop-applied Rayclad 120 for protecting new pipelines. (6) The high cost of good-quality, high-temperature, tape wraps restricts them to large-radius bends. (7) Check the service history of non-specialty tapes for service temperatures above 100°F. Manufacturers often overstate the upper limits.
September 1996
900-6
Chevron Corporation
Coatings Manual
Fig. 900-3
900 Pipeline Coatings
Advantages and Disadvantages of External Pipeline Coatings (1 of 2) Coating
Fusion Bonded Epoxy
Liquid Epoxies (Thermosets)
Extruded Plastic with Butyl Rubber Adhesive (Pritec)
Extruded Plastic (Mapec, Elf Atochem, and Himont FBE/PE or PP brands)
Extruded Plastic (Du Val FBE/PE or PP)
Chevron Corporation
Advantages
Disadvantages
•
25+ years experience
•
Near white metal surface preparation required
•
Low current required for cathodic protection
•
High application temperatures
•
Good resistance to cathodic disbondment
•
Thinnest coating
•
-40°F to 200°F temperature range
•
Difficult to apply holiday free
•
Available in all pipe sizes
•
Difficult to apply consistently
•
Excellent hydrocarbon resistance
•
Not susceptible to cathodic shielding
•
Excellent adhesion to steel
•
Continuous coating
•
Temperature resistance up to 200°F
•
Long cure time (minutes to 24 hours)
•
Spray or hand apply in field
•
May need near white blast surface
•
Good chemical resistance
•
Expensive
•
Use for odd shapes
•
Can be applied while pipe is in service
•
Low current required for cathodic protection
•
High initial costs for small diameter pipe
•
Minimum holidays on application
•
Susceptible to cathodic shielding
•
-40°F to 180°F temperature range
•
Do not use on spiral-welded pipe
•
Self-healing adhesive
•
Hard to handle when warm
•
Wide range of sizes
•
•
Excellent adhesion to steel
Susceptible to damage from thermal expansion and contraction
•
Continuous coating
•
Cannot be used on bends
•
Limited hydrocarbon resistance
•
15+ years experience
•
Limited hydrocarbon resistance
•
Minimum holidays on applications
•
•
Low current required for cathodic protection
Limited experience with high temperature service
•
Excellent adhesion to steel
•
-40°F to 180°F temperature range
•
Continuous coating
•
Wide range of pipe sizes
•
Low water absorption
•
200°F + temperature resistance
•
Limited experience (less than 5 years)
•
Low water absorption
•
High cost
•
Coating for girth welds and shop bends is the same as for lines
•
Girth welds difficult to coat
•
•
Minimum holidays on application
Coating damage hard to patch but progress is being made
•
Low current required for cathodic protection
•
Excellent adhesion to steel
•
Excellent adhesion FBE to PE or PP
•
Continuous coating
900-7
September 1996
900 Pipeline Coatings
Fig. 900-3
Coatings Manual
Advantages and Disadvantages of External Pipeline Coatings (2 of 2) Coating
Advantages
Extruded Plastic, Asphalt Adhesive (Plexco, Bredero Price, and Shaw)
Tape Wraps (services < 140°F)
Coal/Tar Enamel
Fig. 900-4
Disadvantages
•
29+ years experience
•
Minimum adhesion to steel
•
Minimum holidays on application
•
Do not use above ground
•
Low current required for cathodic protection
•
Limited storage life
•
-40°F to 160°F temperature range
•
Tears in jacket can go length of pipe
•
Adhesive flows at low temperatures
•
Poor hydrocarbon resistance
•
Susceptible to cathodic shielding
•
Hard to handle when hot
•
30+ years experience
•
Susceptible to cathodic shielding
•
Easy to apply
•
Poor coating-to-coating bond at overlap
•
Can be used for bends
•
Must be applied at proper tension
•
Can be used to coat all sizes of pipe
•
Susceptible to soil stresses
•
Can be applied to pipe while in service
•
Temperature limited
•
Non-continuous coating
•
Poor service history
•
65+ years experience
•
Carcinogenic fumes when applied
•
Minimum holidays on application
•
Poor UV resistance
•
Low current required for cathodic protection
•
Cracking problem below 32°F
•
Good resistance to cathodic disbondment
•
Soft when hot (100°F)
•
Good subsea experience with weight coating
•
Poor hydrocarbon resistance
•
Available for all sizes of pipe
Description of External Pipeline Coating—Asphalt Wrap Coatings
Definition
Asphalt wrap coatings consist of filled, air-blown, asphalt enamel that is reinforced with asphalt-embedded glass cloth or felt and covered with felt
Holiday Detection 1250
coating thickness ( mils )
Note: Lower holiday detection voltages may be required to prevent coating damage. Recommended Service Status
☞Caution
The Company no longer recommends this coating because of its poor service history.
In the recent past, no-one has applied asphalt-wrap coatings; therefore, pipeline grades of asphalt are no longer available in the United States. Asphaltic wraps have a poor service history and are susceptible to hydrocarbon attack and general deterioration in the ground. The Company has deleted the standard drawing for these wraps from the Piping Manual because these coatings are now obsolete.
Small Repairs
Choose an asphalt-based mastic to patch an asphalt (P-2) wrap.
☞Caution
Coal-tar mastics usually are not compatible with asphalt coatings.
The American Asphalt Institute had a classification system for coding asphaltic pipeline coatings that they have discontinued. P-2 identified the number of wraps and type of asphalt. this system of classification was similar to the NAPCA (National Association of Pipe Coating Applicators) system in which TGF-3 is an example for coat-tar-enamel pipe coating.
September 1996
900-8
Chevron Corporation
Coatings Manual
Fig. 900-5
900 Pipeline Coatings
Description of External Pipeline Coating—Asphalt Mastic (1 of 2)
Definition
Somastic—an asphalt mastic—is a tar-like mixture of •
Inert mineral fillers - 13 per cent
•
Sand aggregate - 64 per cent
•
Fiberglass fibers - 0.1 per cent
•
Asphalt binder
Recommended Service
Offshore and onshore ambient-temperature lines where hydrocarbon-soaked soils are not present.
Status
Limited availability and marketing have affected Somastic's popularity.
Max. Service Temp
Surface Prep
Field experience has found manufacturers’ temperature limits to be very optimistic.
☞Caution
The Company does not recommend Somastic for temperatures above 140 °F.
Abrasive Blast Other
Holiday Detection 1250
Application
coating thickness ( mils )
•
Heat and mix Somastic ingredients
•
Continuously extrude the mixture over primed pipe to form a thick, seamless coating
•
Whitewash the black mastic to prevent its softening and aging in sunlight
Girth-weld Coating •
Melt Somastic chips and pour the fluid into a mold that compresses the hot mixture around the girth weld.
•
Taper the Somastic joint coating at the ends to accept heat-shrink wraps for coating the girth welds.
Thickness
> 250 mils
Small Repairs
Heat-shrink sleeves UT.
☞Caution
Select mastics that are compatible with asphalt for repairing coating damage. Coal-tar mastics are usually incompatible with asphalt coatings such as Somastic.
Handling/Storage
Aboveground Storage Limit: One year
Protection/Resistance
UV Resistance: Poor See also Advantages and Disadvantages under Discussion below.
Chevron Corporation
900-9
September 1996
900 Pipeline Coatings
Fig. 900-5
Coatings Manual
Description of External Pipeline Coating—Asphalt Mastic (2 of 2)
Discussion
Three grades of Somastic are currently available, differing in chemical makeup of the asphalt and temperature ratings. •
Somastic I - 120°F
•
Somastic II - 150°F
•
Somastic III - 190°F
Choosing a higher grade (higher temperature limit) decreases flexibility at low temperatures. Service History Originally developed in 1922 by Standard Oil Company of California, Somastic has been selected for offshore and high-temperature onshore service. Its thickness and toughness make it especially resistant to mechanical damage; however, Somastic will fail in hydrocarbon-contaminated soils. FBE has replaced asphalt enamels because of poor performance. FBE and Pritec have replaced it as an onshore hot-oil pipeline coating because Somastic has performed poorly in this service. Most of Somastic's failures occur at elevated temperatures. One of these failures occurred at the Company's Hawaii Refinery on a 180°F line; however, the Company and other operators have had many successful Somastic applications at long-term ambient temperatures. Several failures have also occurred on hot-oil pipelines in California. Poor quality control inspection during pipeline construction or incompatible mastics may have caused some failures of Somastic-coated girth welds. Advantages •
A good coating with a long service history
•
Adheres well
•
Flexible
•
Good resistance to impact, penetration, and cathodic disbonding
Disadvantages •
Not always available
•
Susceptible to hydrocarbon attack
•
Brittle when cold (< 40°F)
•
Soft when hot
•
Heavy (expensive to ship)
•
Not performed well as a hot-oil pipeline coating
As asphalt-wrap coatings absorb water, there have been questions about applying Somastic offshore. Water absorption could increase the current requirements for cathodic protection and cause a coating failure. Shell Oil recently reported that one of their Somastic-coated offshore pipelines was only 5 percent bare after 20 years of service. At present, there is no evidence that Somastic coatings are unsuitable for offshore service. Girth-weld Coating
Heat-shrink sleeves (Taper Somastic coating transition area to 45 degree angle.)
Brands
Somastic I and III. Currently available only from Bredero Price International (formerly Energy Coating) in Harvey, Louisiana.
See Also
September 1996
NACE International Standard RP-0276 (Discontinued)
900-10
Chevron Corporation
Coatings Manual
Fig. 900-6
900 Pipeline Coatings
Description of External Pipeline Coating—Coal Tar Enamel (1 of 2)
Definition
Coal-tar enamel is a hot, shop-applied, black tar-like coating of iron-mill-coke byproducts. It is layered with inner or outer wraps (or both) of glass fiber or asbestos felts.
Recommended Service
On subsea lines with concrete (weight) coatings.
Status
For onshore lines, operators are replacing coal-tar enamels with FBE and extruded plastic; offshore, coal-tar is very popular.
Max. Service Temp
140°F
Surface Prep
Abrasive Blast: SSPC SP6 Other
Holiday Detection
12,000 to 18,000 volts
Application
Although we can field- or shop-apply coal-tar enamels, field application is rare because of problems with inadequate pipe surface preparation, inspection [8], and air quality when melting the coating. The coating mill sprays or pours heated coal-tar enamel (400°F) on a pipe primed with coal-tar primer. Simultaneously, they layer two or three glass-fiber, felt-reinforcement wraps that improve the coating's strength, uniformity, and resistance to soil stresses and mechanical damage.
☞Caution Thickness
Solvent emissions during application can be an environmental problem.
156 mils The total thickness of the coating including the outer wrap is about 100 mils. Typically ranges from 62 to 188 mils.
Small Repairs
The following repair methods are acceptable in the United States, except melted enamel which is prohibited in some states with strict air quality regulations. The melted enamel repair is expensive and is only warranted if there are many repairs. •
Coal-tar mastic
•
Cold- or hot-applied tape made for coal tar (must first remove the damaged coal-tar enamel completely)
•
Melted coal-tar enamel is granny ragged (the process followed to handwrap hot coal-tar enamel on the bottom half of the pipe’s surface) or poured into a mold formed around the pipe
☞Caution
Make all mastic repairs with a coal-tar mastic because asphalt mastics are incompatible with coal-tar coatings.
Many gas-transmission pipeline operators do not approve of any mastics as this substance has failed in service, allowing corrosion to develop. Handling/Storage
Aboveground Storage Limit: Six months +
Protection/Resistance
Protection For an outer coating, we recommend fiberglass filler mat and a felt or kraft paper (or both) outer wrap. The outer wrap protects the coal tar from mechanical damage when it is soft. Coating applicators usually give the pipe a reflective outer coating of kraft paper, whitewash, or white emulsion to protect it unless it is concrete (weight) coated. Any of these outer coatings will reduce the temperature of the coal tar to a minimum in the sun and protect it from UV rays. Hydrocarbon Resistance: Poor
Chevron Corporation
900-11
September 1996
900 Pipeline Coatings
Fig. 900-6
Coatings Manual
Description of External Pipeline Coating—Coal Tar Enamel (2 of 2)
Discussion
Choosing mineral rather than asbestos felts affects both the cost and the quality of the coating. Mineral felts are generally comparable with asbestos and cost more as they come from eastern Canada. Regardless, select mineral felts because repairs to coal-tar-enamel lines with asbestos felts would be more costly due to asbestos-handling procedures. Service History Coal-tar enamels have been popular for over 70 years. For offshore service, coal-tar enamel is common as 33 percent of the companies responding to an Oil and Gas Journal survey [9] report using it. For more than 20 years, Aramco has applied coal tar enamel successfully offshore [10]. While this coating has also been applied successfully onshore, it is hard to handle, becoming brittle at about 40°F and soft above about 90°F. The concrete-weight coating applied over the coal tar for subsea applications protects the coal tar and eliminates the handling problem.
Girth-weld Coatings
Shrink wraps or cold applied tape wraps.
Note: The materials of heat-shrink wraps are generally more expensive than cold-applied tape, but heatshrink wraps are quicker to apply and less sensitive to an inexperienced worker. Heat-shrink wraps also reduce the possibility of water ingress as it eliminates the overlap inherent with cold-applied tape wraps. Brands
The coating material is available from Reilly Tar and Chemical Corp., but the number of coal-tar coating applicators is decreasing because of strict air quality regulations. Per NAPCA specifications, CUSA production typically orders this coating system as TGF-3.
See Also
•
Company’s Pipeline Manual for information on weight coatings
•
NAPCA Bulletin 1-65-94 “Recommended Specification Designations for Coat Tar Enamel Coatings”(1)
•
NAPCA Bulletin 2-66-94 “Standard Applied Pipe Coating Weights for NAPCA Coating Specifications” (1)
•
NAPCA Bulletin 3-67-94 “External Application Procedures for Hot Applied Coal Tar Coatings to Steel Pipe”(2)
•
NAPCA Bulletin 6-69-94-1, “Suggested Procedures for Hand Wrapping Field Joints Using Hot Enamel.”(3)
•
AWWA Standard C-203
•
COM-MS-5006, Coal-tar Enamel Corrosion Coating of Submarine Pipelines, in this manual for application specifications
•
Application specifications for coal-tar enamel and concrete (weight) coatings in Figure 900-21: Coating Specifications for Buried Pipelines.
(1) Chevron USA follows these specifications when ordering coal-tar-enamel coatings (2) Chevron USA Production typically follows this specification when ordering coal-tar-enamel-coated pipe. (3) Although this NAPCA specification is for coating girth welds, we follow the same technique for making repairs with hot coal-tar enamel.
September 1996
900-12
Chevron Corporation
Coatings Manual
Fig. 900-7
900 Pipeline Coatings
Description of External Pipeline Coating—Coal Tar Epoxies
Definition Recommended Service
A two-part liquid epoxy compound containing coal-tar pitch Refurbishing old pipelines, girth weld coatings, tie-ins, valves, and fittings.
☞Caution
Unsuitable for hot-oil pipelines.
Status
More commonly used as a tank lining, coal-tar epoxy has seen limited use as a buried pipeline coating system; however, most coal-tar epoxies are incompatible with cathodic protection current.
Max. Service Temp
140°F
Surface Prep
Abrasive Blast SSPC SP-10
☞Caution
Any less than SSPC SP-10 for buried pipeline may result in cathodic disbondment.
Other Holiday Detection 1250
Application
coating thickness ( mils )
Spray, brush, or roll Cure time: Very slow
Thickness
16-20 mils
Small Repairs
Patch with same material per manufacturer’s guidelines
Handling/Storage
—
Protection/Resistance
Cathodic Disbonding A zinc primer may improve resistance to cathodic disbonding of the coal-tar epoxy's outer layer. Applying high-built coal-tar epoxies in two coats increases resistance to cathodic disbondment. Soil Stress & Hydrocarbon Resistance: Excellent
Discussion
Applied correctly, coal-tar epoxies are excellent coating systems for buried pipelines; but they are unsuitable for hot-oil pipelines.
Girth-weld Coatings
—
Brands
International Tarset Maxi-Build 7080 and Corroguard EP are the only coal-tar epoxies currently recommended, but there are many other coal-tar epoxies on the market that make excellent buried pipeline coatings.
See Also
NAPCA Bulletin 14-83-94, External Application Procedures for Coal Tar Epoxy Protective Coatings to Steel Pipe
Chevron Corporation
900-13
September 1996
900 Pipeline Coatings
Fig. 900-8
Coatings Manual
Description of External Pipeline Coating—Cold-Applied Tapes (1 of 2)
Definition
Recommended Service
There are two types of tape wraps: hot- and cold-applied. Hot-applied wraps generally have a higher bond strength. Cold-applied tapes can be field- or shop-applied by machine or by hand. Cold-applied tape wraps are: •
Continuous strips of a plastic-backing material, either polyethylene (PE) or polyvinylchloride (PVC)
•
Coated with a butyl-rubber adhesive (Polyken or Tapecoat) or modified bituminous compound (Polyguard RD-6)
•
Spirally wound on primer-coated pipe
Tapes are still viable because otherwise we cannot accomplish the following tasks economically: •
Repairing damaged coatings (FBE, extruded plastic, and coal-tar epoxy)
•
Coating bends that cannot be FBE coated in the field
•
Refurbishing old lines that must stay in service
•
Refurbishing short new lines in dry, low-soil-stress areas more economically than with extruded plastic or FBE
☞
Caution Because PVC embrittles badly and shrinks at temperatures of 104 °F or higher, we recommend PE for all tape applications [6, 7].
☞Caution
Our experience does not substantiate manufacturers' claims that cold-applied tapes are suitable for hot-oil pipelines.
Status
Introduced about 40 years ago [5] as an over-the-ditch system, tapes replaced coal-tar enamels and asphalts that required heating. The tape on thousands of miles of pipe has given mixed results and is now being replaced with extruded plastic or FBE as the main mill-applied coating for pipelines.
Max. Service Temp
Elevated-Temperature Service Most high-temperature tape systems are hot-applied tape systems. The temperature limits of coldapplied tapes, depending on the manufacturer, include: •
140°F for most polyethylene-backed tapes with butyl adhesives
•
150°F for polypropylene-backed tape with bituminous compound (Polyguard RD-6)
•
Above 140°F for specialty tapes
A cold-applied tape may suffer thermoshock when raised to the service temperatures of hot-oil pipelines. Surface Prep
Abrasive Blast: SSPC SP-2 Other While an abrasive blasted surface is ideal, coatings applicators most often field-apply tapes, making surface preparation difficult. Over-the-ditch cleaning machines have rotating wire brushes to clean the pipe ahead of primer application. Power tools are essential if cleaning by hand. There are coatings with minimum sensitivity to surface preparation.
Holiday Detection
3000 to 8000 volts per manufacturer’s guidelines
Application
Whether mill- or field-applied: •
Prepare the pipe surface
•
Apply a primer
•
Spirally apply one layer of tape
•
Spirally apply one or more offset layers of tape over the first.
When wrapping the tape around a pipe, there are three critical elements for success: pipe surface preparation, tape tension, and amount of tape overlap. (Check with the tape manufacturer for recommendation). In a two-layer system, it is also important to stagger the overlaps of each tape layer so that water has no direct path to the pipe surface. Before applying the first tape layer, the coating applicators tape any weld seams (girth and longitudinal) that are not flush with the surface of the pipe. This base layer of tape prevents the spirally applied tape wrap from leaving a void at the weld seam that may become filled with moisture and create a shielded corrosion cell. The primer causes a chemical reaction in the adhesive, which helps bond the adhesive or compound on the inner layer of tape to the pipe's surface, thus increasing its bonding strength. In a two-layer system, the first layer of tape provides corrosion protection; the second, and any subsequent layers, provide mechanical protection for the first layer.
September 1996
900-14
Chevron Corporation
Coatings Manual
Fig. 900-8
900 Pipeline Coatings
Description of External Pipeline Coating—Cold-Applied Tapes (2 of 2)
Application (continued)
The outer wrap (or rock shield) over the tape system must be bonded or not bonded to the tape depending upon the recommendation of the tape manufacturer. Non-bonded outerwraps create a slip plane between the inner and outer wraps that helps protect the inner wrap from soil stresses. A nonbonded outerwrap may cause a cathodic protection shielding problem if it is a solid plastic coating. Shop-applied tapes outperform field-applied tapes because quality control and inspection are easier in the coating mill. To improve field application of cold-applied tapes, relatively small and lightweight wrapping machines are now commercially available that are power or hand operated. They can also be equipped with a constant tension brake system to provide uniform tension across width of rolls and through its entire length.
Thickness
Varies with coating system. The average thickness (not including a rock shield or outer wrap) of a two-layer tape wrap is about 70 mils; of a single-layer tape system, 50 mils.
Small Repairs
Generally, coating applicators repair tapes by taping over the damaged tape or by using a mastic. In the Northwestern Business Unit, Chevron Pipe Line has been successful with Tapecoat's 10/40W system using a one-inch overlap.
Handling/Storage
—
Protection/Resistance
UV and Hydrocarbon Resistance: Poor
Discussion
Service History Many early tapes •
Were applied with poor surface preparation, no primer, no tension, and no protective overwrap
•
Failed in service
•
Have given tapes the reputation of being poor pipeline-coating systems
Advantages Cold-applied tapes are easy and inexpensive to apply in the field. If applied properly and used in the proper environment, cold applied tapes are an acceptable pipeline coating. Tapes are still viable because of the tasks listed under Recommended Service, above. Disadvantages Tapes may encounter problems in long-term service, because of improper application, service conditions, pipe diameter, or product design. As they are not a continuous coating, the tape's overlaps greatly increase the chance of water penetration. Also, the overlaps may bond poorly, catch on the soil (stress), and pull open. The Company has not verified the suggestion that some new tapes have resolved these problems. Some tapes are pressure sensitive (Tek-Rap, Royston) and depend primarily upon mechanical means, memory, to keep the overlaps closed. If outside forces such as soil stress disturb this memory, the tape may loosen. Too much or too little tension during application can cause a coating failure from loss of memory. For protecting buried pipelines, pressure-sensitive tapes are not as desirable as tapes with an adhesive that bonds at overlaps to the pipe's metal surface and the coating. Most failures of tapes occur on large-diameter pipe (greater than 12 inches in diameter). Soil stress becomes a greater problem as the pipe's diameter increases because the soil has more coating surface area to grab. Girth-weld Coatings
For coating-mill-applied tape wraps (through 12 inches in diameter), shrink sleeves or hand-wrapped tape
Brands
Tapecoat’s 10/40W, Polyken, Polyguard RD-6
See Also
•
NAPCA Bulletin 16-94, “External Application Procedures for Plant Applied Tape Coating to Steel Pipe”
•
NAPCA Bulletin 6-69-94-9, “Suggested Procedures for Coating Field Joints, Fittings, Connections, and Pre-fabricated Sections Using Tape Coatings”
Chevron Corporation
900-15
September 1996
900 Pipeline Coatings
Fig. 900-9
Coatings Manual
Description of External Pipeline Coating—Extruded Plastic with FBE or Liquid Epoxy Primer (1 of 2)
Definition
Continuous plastic coating (either polyethylene or polypropylene) with an epoxy primer.
Recommended Service
Buried onshore and offshore pipelines up to 200°F.
Status
Although this coating system is quite new to the United States, it has been available in Europe for a long time. Himont, DuVal, and Elf Atochem are the suppliers; Bredero Price (formerly Encoat) has two coating mills that apply this coating in the United States.
Max. Service Temp
•
Himont, an Italian company, is forming an alliance with 3M and Shell Chemical to enter the U.S. pipecoating market.
•
DuVal is an alliance between Du Pont Canada and Valspar.
•
Du Pont Canada and Shaw manufacture polyethylene three-layer systems in Canada. Shaw's has a liquid-epoxy primer.
200°F Polypropolene; 180°F Polyethylene
☞Caution
We do not recommend polypropylene for service temperatures above 200°F without additional laboratory or field testing.
Surface Prep
Abrasive Blast: SSPC SP10 Other: Blast clean the pipe and then transfer it to the extrusion line.
Holiday Detection 1250
Application
coating thickness ( mils )
To produce a bonded, overlapped coating to a specified thickness: •
Apply an epoxy primer with or without a co-polymer adhesive (Mapec, Himont, Du Pont Canada, DuVal, Elf Atochem).
•
Immediately extrude overlapping layers of melted plastic on the pipe, followed by water quenching.
Apply Shaw YJII by the crosshead-extrusion process over a liquid-epoxy adhesive layer; apply other coatings with the side-extrusion process over an FBE primer. Quality control standards are more rigid for multi-layer coating systems such as DuVal, Himont, Du Pont Canada, and Elf Atochem as the adhesive (FBE) must still be tacky when we apply the plastic topcoat.
☞Caution Thickness
Applying the topcoat:
•
Too quickly results in improper curing of the FBE and poor bonding to the pipe's surface.
•
Too slowly may produce an improper bond between the plastic and FBE layers.
The thickness of the plastic topcoat may be 1.5 to 3 mm or more depending upon the pipe's diameter and the service requirements. DuVal has a standard 14-mil thickness of FBE as compared to the 75 to 125 microns in the three-layer systems. Elf Atochem: 59 to 118 mils; DuVal: 20 to 45 mils.
Small Repairs
Heat-shrink sleeves
Handling/Storage
Aramco has had good experience with Mapec, which is reportedly easier to ship and handle than FBE.
Protection/Resistance
UV Resistance: Excellent See also Discussion below
Discussion
Considered the best pipeline coating system available. Company has limited experience with it. Resistance and Strength Extruded plastic coatings generally have good impact strength, resist water penetration well, and do not shrink at elevated temperatures. Physical properties of polyethylene vary with density, high-density polyethylene having superior resistance to impact and moisture. The shear strength of butyl or asphalt adhesives is poor and decreases substantially with increases in temperature [4]. This situation allows the pipe to move inside the coating during thermal expansions and contractions and subjects the outside of the coating to soil stresses. The resulting problems are loss of adhesion, wrinkling, and, eventually, exposed steel. The adhesives in Elf Atochem, Himont, Du Pont Canada, DuVal, and Shaw YJII coating systems have greater shear strengths and temperature resistance than butyl or asphalt adhesives. Mapec gave excellent results in the early 1980's testing, but did not equal thick FBE in hot (250°F) subsea testing in the late 1980's [15].
September 1996
900-16
Chevron Corporation
Coatings Manual
Fig. 900-9
900 Pipeline Coatings
Description of External Pipeline Coating—Extruded Plastic with FBE or Liquid Epoxy Primer (2 of 2)
Discussion (continued)
Operating Temperatures •
Service Temperatures < 150°F Acceptable—30214 Mapec's low-density polyethylene plastic.
•
Service Temperature of 180°F – Uninspected but in service (Shaw YJII and a thermo-insulation outer jacket. /DuVal polypropylene with no thermo-insulated outer jacket – Chevron Canada Resources has a hot-oil pipeline operating at 180°F, which is coated with Shaw YJII and a thermo-insulation outer jacket. The girth welds were coated with liquid epoxy and Raychem high-temperature heat-shrink sleeves. To date, this pipeline has not been inspected and has been in service for four years. – The Chevron Pipe Line Western Business Unit has DuVal polypropylene on a hot-oil pipeline operating at 180°F. This pipeline has no thermo-insulated outer jacket, has not yet been inspected, and has been in service for about two years. They experienced quality control problems during the coating's mill- production run and when CCSI field coated the girth welds. While Mobil Pipeline reports that most of these problems have been corrected, a British Petroleum project also had quality control problems in South America during 1993-94.
Elf Atochem's coating system has three plastic (polyolefin) top coats that they rate for the following service temperatures: •
Low-density polyethylene (-40 to 149°F)
•
Medium-/high-density polyethylene (-40 to 167°F)
•
Polypropylene (-4° to > 212°F)
☞
Caution We do not recommend DuVal Polypropylene for service temperatures above 200 °F without additional laboratory or field testing. Du Pont Canada and Valspar rate their DuVal Polyethylene at a maximum operating temperature of 180°F and their DuVal Polypropylene at a maximum operating temperature of 230°F. Layers Because of higher costs of materials, two-layer coatings (e.g., DuVal) are more expensive than threelayer systems (e.g., Mapec, Elf Atochem, Du Pont Canada, and Himont). Valspar is considering changes for DuVal to bring its maleic anhydride content nearer the levels of three-layer coating systems. DuVal must have the proper concentration of maleic anhydride to bond the two layers to each other. Bredero Price (formerly Encoat) performs a test on DuVal’s raw, modified, plastic material to verify that there is a proper concentration of maleic anhydride. The middle adhesive layer of the Elf Atochem multilayer system bonds the top plastic and FBE layers with maleic anhydride and other chemicals such as terpolymer of ethylene and acrylic ester. DuVal and Elf Atochem coatings are not as easy to apply as other pipeline coatings such as FBE and Pritec. Although it is possible to field-apply a two-layer system over girth welds, field conditions can make it difficult to achieve a quality coating. Girth-weld Coatings Brands
•
Induction-heat-applied FBE and plastic is recommended.
•
Shrink sleeves
☞Caution
Many pipeline operators are using Himont, DuVal, and Elf Atochem polypropylene coating system at operating temperatures up to 230°F on both offshore and onshore pipelines. The Company has limited experience with this coating system at temperatures above 200°F. We do not recommend Elf Atochem Polypropylene or DuVal polypropylene for service temperatures above 200°F without additional laboratory or field testing. The following systems offer superior performance often equal to or better than FBE alone at a premium price.
See Also
Chevron Corporation
•
Mapec’s low-density polyethylene plastic is acceptable for maximum service temperatures of 150°F.
•
The Mapec, Du Pont Canada, Himont, DuVal, and Elf Atochem systems have an FBE primer, and either a polypropylene or polyethylene jacket.
•
Shaw YJII has a liquid-epoxy primer with a polyethylene outer jacket.
•
The Mapec, Du Point Canada, Himont, Shaw YJII, and Elf Atochem systems bond the epoxy and outer plastic with a copolymer adhesive
•
The DuVal system has an adhesive copolymer incorporated in the plastic top coat formula.
•
CAN/CSA-Z245.21-M92 L’Association Francaise De Normalization NF A49-710
•
Mobil Pipeline Specification CM-251-880
900-17
September 1996
900 Pipeline Coatings
Coatings Manual
Fig. 900-10 Description of External Pipeline Coating—Extruded Plastic—Crosshead-Extruded Plastic with Asphalt Adhesive (1 of 2) Definition
Continuous plastic coating (either polyethylene or polypropylene) extruded on a pipe at elevated temperatures.
Recommended Service
Onshore pipelines operating below 160°F where FBE is uneconomical or unavailable. Prices and the performance of the systems (particularly at higher temperatures) vary substantially. See Discussion below
Status
Extruded polyethylene and polypropylene coatings of various costs and qualities are very popular and readily available in the United States and Canada.
Max. Service Temp
Varies with manufacturer. Onshore, < 160°F. (100°F for some brands)
Surface Prep
Abrasive Blast: SSPC SP-6 Other
Holiday Detection 1250
Application[3]
coating thickness ( mils )
The crosshead extrusion method involves: •
Flooding the pipe with a hot asphalt-rubber adhesive
•
Passing the pipe through a wiper ring to maintain a nominal ten-mil adhesive thickness
•
Passing the pipe through the center of the crosshead die where the plastic is uniformly extruded in a cone shape around the pipe
•
Water quenching that causes the plastic to shrink tightly to the adhesive and pipe
☞Caution ☞Caution
Unlike side-extrusion, crosshead extrusion limits size of pipe diameter. Never apply soft adhesives to spiral-welded pipe.
Thickness
35-70 mil
Small Repairs
•
Heat-shrink sleeves
•
Tapes, if soil stress not a problem
Handling/Storage
Above-ground Storage Limit: One year
Protection/Resistance
Disbonding Tests of the early 1980's show differences in adhesive strengths and resistance to cathodic disbonding. Plexco and Encoat (now Bredero Price International) were not as good as Pritec (extruded plastic with butyl rubber mastic) and Mapec (extruded plastic coating with FBE primer). [2, 4, 13, 14]. Recently Bredero Price (Encoat) improved the mastic in its Entec coating. Plexco will supply a superior mastic if requested. UV Resistance: Fair. The orange (polypropylene) and yellow (polyethylene) coatings do not resist UV damage well. They became brittle and cracked when stored for a year in the Californian sun. (This is not a problem with Yellow Jacket). Impact, Moisture, Shrink, and Temperature Resistance Extruded-plastic coatings generally have good impact strengths, resist water penetration well, and do not shrink at elevated temperatures. Physical properties of polyethylene vary with density, high-density polyethylene having superior resistance to impact and moisture. Polypropylene offers superior temperature resistance in hot-oil pipeline service, but the mastic has the lowest temperature limit.
September 1996
900-18
Chevron Corporation
Coatings Manual
900 Pipeline Coatings
Fig. 900-10 Description of External Pipeline Coating—Extruded Plastic—Crosshead-Extruded Plastic with Asphalt Adhesive (2 of 2) Discussion
Costs Wide range in costs. The former X-Tru-Coat coatings (Plexco Plexguard, Bredero Price (Encoat), Entec, Shaw Yellow Jacket, and Shaw Black Jacket) are inexpensive and work well at ambient temperatures [12]. Temperature A Company product, the Plexco coating is very economical. Chevron Canada Resources reports that the high-temperature grade of Yellow Jacket (maximum 185°F limit) works well at 140-160°F. Although current Plexco and Bredero Price (Encoat) literature places maximum temperature limits of 140°F (polyethylene) to 170°F (polypropylene), be cautious with these products in temperatures above 100°F without additional testing or documented high-temperature field experience. Yellow Jacket should work up to 160°F, based on the Canadian experience. Black Jacket is a new coating with a mastic superior to Yellow Jacket, but the Company has no experience with Black Jacket. Strengths The shear strength of hot-melt-asphalt adhesives is poor and decreases substantially with increasing temperature [4]. This situation allows the pipe to move inside the coating during thermal expansions and contractions and subjects the outside of the coating to soil stresses. The resulting problems are loss of adhesion, wrinkling, and, eventually, exposed steel.
Girth-weld Coating
Heat-shrink sleeves
Brands
The crosshead extrusion method was formerly licensed under X-Tru-Coat but current brands are Bredero Price (Encoat) Entec, Shaw Yellow Jacket and Black Jacket, and Plexco (Plexguard). Shaw, Bredero Price (Encoat), and Plexco apply this coating system.
See Also
Chevron Corporation
•
The former X-Tru-Coat coatings (Plexco Plexguard, Bredero Price (Encoat)
•
Entec, Shaw Yellow Jacket, and Shaw Black Jacket) are inexpensive and work well at ambient temperatures [12].
•
The Plexco coating is very economical.
•
Chevron Canada Resources reports that Yellow Jacket works well at 140-160°F.
•
NAPCA Bulletin 15-83-94, “External Application Procedures for Polyolefin Pipe Coating Applied by the Cross Head Extrusion Method of the Side Extrusion Method to Steel Pipe”
•
ANSI/AWWA C215
900-19
September 1996
900 Pipeline Coatings
Coatings Manual
Fig. 900-11 Description of External Pipeline Costing—Extruded Plastic—Side-Extruded Polyethylene with Butyl-Rubber Adhesive (1 of 2) Definition
Continuous plastic coating (polyethylene) with butyl rubber adhesive.
Recommended Service
Onshore pipeline operating below 180°F rather than FBE for cost or supply reasons
Status
Bredero Price (Encoat) applies Pritec at several coating mills in the United States.
Max. Service Temp
180°F
Surface Prep
Abrasive Blast: SSPC SP-10 Other: Blast clean the pipe and then transfer it to the extrusion line.
Holiday Detection 1250
Application
coating thickness ( mils )
The side-extrusion method produces a bonded, overlapped coating to a specified thickness and involves: •
Running a rotating pipe past the extrusion die at the side of the pipe
•
Applying a butyl-rubber-adhesive mastic
•
Immediately extruding overlapping layers of melted plastic on the pipe, followed by water quenching
☞Caution
Never apply soft adhesives to spiral-welded pipe.
Thickness
Typically, plastic top layer is 40 mils, but it can be up to 240 mils. Offshore, Pritec has been applied at a nominal thickness of 15 mils for the butyl rubber layer and 60 mils for the polyethylene layer. See Protection, Rocks, below.
Small Repairs
Patches work well and are cheaper than shrink wraps but be sure that the edges of a patch adhere tightly to the surface. Coating Removal With a knife, scribe the area to be removed, freeze the coating with CO2 or liquid nitrogen, and jerk the coating off quickly. (In cold weather, it may be possible to remove the coating without artificial cooling.)
Handling/Storage
Aboveground Storage Limit: One year Ship all plastic coated pipe with rubber spacers between (or 5/8-inch rope rings around) the pipes to prevent rubbing when the pipe is not nested. When nesting the pipe, use padded skids and handle the coated pipe with padded equipment and slings. Cinch-lifting methods apply a torque force to the coating and can damage it.
Protection/Resistance
Disbonding Pritec's polyethylene coating system has significantly superior adhesion and resistance to cathodic disbonding because of the butyl-rubber adhesive [2,4]. Pritec is specified by its mastic and polyethylene thickness; e.g., Pritec 10/40 is 10 mils of adhesive and 40 mils of PE. While Bredero Price, Inc., recommends Pritec 10/40 up to 180°F, CRTC's M&EE Unit has run cathodic disbonding tests that show thicker coatings being more resistant to disbondment [2]. Pipe Supports As polyethylene expands and contracts with temperature changes much more than steel, the supports for the pipe and welded line can damage the coating. On the Rangely CO2 line, gunny sacks full of pine needles or sawdust provided the best support, while rubber strips or tires and sand bags did not work well.[4]
September 1996
900-20
Chevron Corporation
Coatings Manual
900 Pipeline Coatings
Fig. 900-11 Description of External Pipeline Costing—Extruded Plastic—Side-Extruded Polyethylene with Butyl-Rubber Adhesive (2 of 2) Protection/Resistance (continued)
Rocks Backfill with soil or sand as Pritec 10/40 does not resist the impact of rock. Be careful of rocks protruding from the side of the ditch that would damage the coating as the pipe is being lowered into the ditch. Increase the thickness of the polyethylene layer from its normal 40 mils to 50, 60, 70, 80, 90, or 100 mils when expecting rocky backfill to prevent damage to this coating. From experience, the Company and others have learned that Pritec 10/40, a common choice, may not be thick enough in a rocky or high-soil-stress environment. UV Resistance: Excellent Hydrocarbon Resistance of butyl rubber mastic & heat-shrink sleeves: Lacking Impact, Moisture, Shrinkage Extruded-plastic coatings generally have good impact strengths, resist water penetration well and do not shrink at elevated temperatures. Physical properties of polyethylene vary with density, high-density polyethylene having superior resistance to impact and moisture.
Discussion
Shear Strength The shear strength of butyl-rubber adhesives is poor and decreases substantially with increasing temperatures [4]. This situation allows the pipe to move inside the coating during thermal expansions and contractions and subjects the outside of the coating to soil stresses. The resulting problems are loss of adhesion, wrinkling, and, eventually, exposed steel.
Girth-Weld Coating
Shrink sleeves
Brands
Entec Pritec 10/40
See Also
•
Girth-weld Protection Coatings, Figures 900-19 to 900-21
•
NAPCA Bulletin 14-83-94, “External Application Procedures for Polyolefin Pipe Coating Applied by the Cross Head Extrusion Method of the Side Extrusion Method to Steel Pipe”
•
NACE International RP0185
•
COM-MS-5005, “Side Extruded Plastic/Butyl Rubber Adhesive Line Pipe Corrosion Coating,” in this manual
Chevron Corporation
900-21
September 1996
900 Pipeline Coatings
Coatings Manual
Fig. 900-12 Description of External Pipeline Coating—Fusion-Bonded Epoxy (1 of 3) Definition
A thermosetting powder sprayed on a hot pipe. The heat melts the powder and causes chemical reactions, converting the epoxy into a hard, continuous coating.
Recommended Service
•
Onshore and subsea pipelines
•
Drilled crossings (Pipe pushed through drilled hole under river or road.)
•
Field joints and fittings up to 200°F
Choose FBE over all other coatings for buried onshore lines. Status
Max. Service Temp
Currently, FBE is one of the most widely-used pipeline coatings. Many applicators are available worldwide. Its cost is significantly lower now because of its popularity and the reduced level of pipeline construction. 150°F to 200°F depending on coating. Currently, FBE is the only economical coating to withstand pipeline temperatures up to 200°F.
Surface Prep
Abrasive Blast: SSPC SP-10 Near-white Finish Other: •
Pretreat with phosphoric acid or a chromate surface to enhance FBE/pipe bond, if necessary. Both pretreatments are recommended especially for pipeline operating temperatures > 150°F.
•
Heat surface 425°F to 475°F
☞Caution
Keep the preheat below 500 °F to prevent possible changes in properties of the pipe.
Holiday Detection
125 volts/mil
Application
When the surface reaches the specified temperature, apply the FBE powder by one of these methods: •
Electrostatic spraying (pipe, elbows, or tees)
•
Dipping the part (elbows or tees) in a bed of (fluid) powder
The heat already in the steel is normally sufficient to cure the coating; if not, heat it again, depending on coating thickness, pipe-wall thickness, and type of epoxy powder. Thickness
Depends on the pipeline's service. Rules of thumb
Small Repairs
•
Subsea or dry lines: (150°F, 14 mils (min.) > 150°F, 30 mils (min.)
•
River /drilled crossings; highly irrigated / continuous wet-and-dry areas; or areas with agricultural chemicals: (150°F, 20 mils (min.) > 150°F, 30 mils (min.)
Melt-on Patch Stick Thermoplastic materials that soften with increasing temperature, the patch stick is a quick, effective repair method; but, if applied improperly, the patch falls off. To check the bond, pick at the repair with a knife.
☞Caution
Do not use patch sticks on pipelines operating at > 100 °F.
Two-part Epoxy Patching Compound Thermoset that does not soften when heated, the two-part epoxy chemically decomposes when heated above a certain temperature but can match the temperature limits of the FBE. A much-higher-quality coating that has properties closer to FBE than the patch stick, two-part epoxy has a relatively long cure time (from 30 minutes up to 24 hours, depending on the pipe's temperature); and so contractors do not like it.
Note: For large repairs, use heat-shrink sleeves if soil conditions permit.
September 1996
900-22
Chevron Corporation
Coatings Manual
900 Pipeline Coatings
Fig. 900-12 Description of External Pipeline Coating—Fusion-Bonded Epoxy (2 of 3) Handling/Storage
Aboveground Storage Limit: Two years Handling Move FBE-coated pipe carefully with padded equipment or wide slings. Separate coated pipe that is to be stacked with: •
Nylon rope rings for small-diameter thin-wall pipe
•
Rubber spacers for heavy pipe
☞Caution
Do not use rubber spacers with lightweight pipe Lightweight pipe cannot compress rubber spacers, and the stack of pipe will become unstable.
Storage Stored FBE pipe has
Protection/Resistance
•
Relatively good UV resistance, losing about one mil per year from UV chalking.
•
A tendency to blister if stored in humid sea air for over a year without protection from the atmosphere
UV Protection Excellent; protect pipe if it is to be stored in hot, humid, sea-air areas (e.g., climate similar to Gulf Coast) for more than six months. Concrete (Weight) Coating Apply concrete (weight) coating by one of two methods: compression coating or impingement. •
Compression coating involves rotating the pipe above a conveyor belt while the belt compresses concrete on the pipe. The rotating pipe moves perpendicularly to the conveyor during the application.
•
Impingement involves spraying the concrete on the pipe after applying an intermediate coating to protect the corrosion coating from the sprayed concrete.
Note: This process is preferred because it does not damage the coating.
Note: Typically we should apply a barrier coating or increase the FBE thickness to 30 mils or more to avoid creating holidays in coating during the impingement process. Cathodic Disbonding At thicknesses greater than 15 or 16 mils, Aramco has found significant improvement in FBE's resistance to ambient-temperature cathodic disbondment. Aramco specifies 17-22 mils thickness because they have regions where power supplies do not exist and they often try to throw cathodic protection down the line to these spots. Moisture-resistant Pipeline Coatings While all pipeline coatings absorb moisture during service, plastic coatings do so less than FBE coatings. Multi-layer coatings are designed with an epoxy as a primer and a plastic topcoat. Increasing the thickness of FBE for hot-oil pipelines does decrease the moisture absorption rate but creates other problems such as higher cost and reduced flexibility. Suitable for a pipeline operating temperature of up to 200°F, thicker coatings of FBE do not appear practical for higher operating temperatures. Lower-moisture-absorbing FBE coatings do exist, but many are inflexible and unacceptable for pipe that may be field bent. British Gas Pipeline in the United Kingdom uses 3M's Scotchkote 226N. The claim is that this coating has a greater resistance to moisture absorption than Scotchkote 206N. As this coating system became commercially available only recently in the United States, there is limited information about it.
Chevron Corporation
900-23
September 1996
900 Pipeline Coatings
Coatings Manual
Fig. 900-12 Description of External Pipeline Coating—Fusion-Bonded Epoxy (3 of 3) Discussion
Bends Bends are not easy to coat with FBE. There are two possibilities: •
Heat bends with induction coils and hand spray them in a shop.
•
Coat bends that are small enough in a bed of (fluid) powder.
In order of preference, options for coating bends in the field are two-part liquid epoxies or tape wraps. High-temperature Pipeline Coatings High-temperature pipeline coatings for hot-oil service need a pipeline coating for a wet-soil environment at operating temperatures over 200°F. Existing FBE coatings cannot meet this need. Although both DuVal and Elf Atochem’s polypropylene coatings claim to have operating temperatures up to 230°F, there is limited field experience with these coatings. It seems unlikely that any polypropylene coating can survive at continuous operating temperatures over 210°F.
Caution! Presently, the Company does not recommend any polypropylene pipeline coating for operating temperatures more than 200 °F without additional laboratory testing or field experience. Nap-Gard's new FBE coating may be suitable for hot-oil service temperatures over 180°F. This coating is the first dual or polymer-powder-modified FBE coating system [24]. The FBE primer is Nap-Gard 7-2501. The water-penetration-resistant FBE topcoat, Nap-Gard 7-2504 (also called Nap-Gard Gold) will bond directly to steel pipe. Any FBE-pipe-coating mill can apply this system which is easier to apply than any existing multi-layer coating system.
☞Caution
The Company does not recommend the Nap-Gard 7-2501/7-2504 coating system for operating temperatures over 180 °F without additional laboratory testing or field experience.
In California, Shell Pipe Line applied FBE with Pritec as an outer jacket for hot-oil service. This may be the first multi-layer coating system of this type in the USA. The Pritec protects the FBE from moisture, but the Pritec mastic is the weak link in this multi-layer coating system.
☞Caution
The Company does not recommend using FBE with Pritec for operating temperatures over
180 °F.
Girth-weld Coating
•
Induction, heat-applied FBE is the best.
•
Liquid epoxies may be used.
•
Heat-shrink sleeves acceptable in low-soil-stress areas.
☞Caution Brands
In hydrocarbon-contaminated soil, use FBE or liquid epoxies.
By Temperature •
> 150°F: 3M Scotchkote 206N, 3M Scotchkote 226N, Valspar D1003LD, Josun D1003LD, Nap-Gard 7-2501, and Nap-Gard 7-25014
•
> 180°F: Nap-Guard’s new FBE coating (7-2504) may be suitable for hot-oil service.
Multi-layer Brands DuVal, Elf Atochem, Himont, Mapec, Du Pont Canada, and Shaw YJII See Also
September 1996
•
COM-MS-4042 for specifications about purchasing and installing FBE-coated pipe.
•
Extruded plastic film for information about multi-layer coating systems with epoxy primers
•
Company’s Pipeline Manual for additional information about concrete (weight) coatings.
•
AWWA C213
•
NAPCA 12-78-94
•
CAN/CSA Z245.20-M92
900-24
Chevron Corporation
Coatings Manual
900 Pipeline Coatings
Fig. 900-13 Description of External Pipeline Coating—Hot-Applied Tapes Definition
Depending on its type, a hot-applied tape is coated on a pipe that is either •
Heated in a furnace
•
Heated with a torch or the tape itself may be heated with a torch
Recommended Service
The Company has very limited experience with hot-applied tape systems; therefore, we cannot report any field experience or provide much detail about them.
Status
—
Max. Service Temp
160°F Raychem states that Rayclad 120 accepts a temperature of 248°F (120°C).
☞Caution
The Company has no experience with Rayclad 120 and gives it a temperature rating of 200 °F until there is additional data from laboratory testing or field experience.
Surface Prep
Abrasive Blast: SSPC SP-3 Other
Holiday Detection
10,000 to 18,000 volts
Application
Coating applicators can use torches for field-installing hot-applied tapes such as Raychem Flexclad and Canusa Wrapid tape.
Thickness
> 27 mils
Small Repairs
Heat-shrink sleeves or tape
Handling/Storage
—
Protection/Resistance
UV Resistance: Poor Soil-Stress/Hydrocarbon Resistance Raychem Flexclad and Canusa Wrapid tapes have better soil stress resistance than cold-applied tapes, but they have poor hydrocarbon resistance Disbonding Initially, Polyken Synergy had problems with thermoshock that caused the coating system to disbond in service. Coating applicators using Synergy report a solution: preheat the tape before applying it to the pipe's surface.
Discussion
Advantage Tend to resist soil stresses better than cold-applied tapes. Disadvantage More expensive than cold-applied tapes. In General Polyken Synergy is less expensive than FBE, about the same cost as Pritec, and more expensive than Plexguard and Entec. It has no marketable characteristics that make it superior to existing mill-applied coating systems. Synergy has to be mill applied, and it cannot be applied by a portable coating plant due to its thermoshock problems.
☞Caution
The Company does not recommend Polyken Synergy because we carried out all of our laboratory testing on thermoshocked samples that failed. CRTC's M&EE specialists will reconsider Synergy if it passes testing by an acceptable independent coating laboratory or if pipeline operators report favorable field experience after five years of service. A high-temperature, hot-, mill-applied tape that other pipeline operators report to be successful is Raychem's Rayclad 120. A portable coating mill helps coating applicators to apply this tape properly in the field. Raychem Rayclad 120 have radiation-crosslinked hot-melt adhesives and polyethylene-based backings. The fact that the polyethylene plastic is radiation-crosslinked gives it greater temperature resistance and lower moisture-absorption rates than other non-radiated plastic tapes. The radiation-crosslinked hotmelt adhesives have lower moisture absorption, higher temperature resistance, and higher bond physical properties than the non-radiated mastics of other hot- and cold-applied tape systems. Girth-weld Coatings
—
Brands
Examples of heat-applied tapes are Canusa Wrapid Tape, Raychem Flexclad, Polyken Synergy, and Raychem Rayclad 120.
See Also
—
Chevron Corporation
900-25
September 1996
900 Pipeline Coatings
Coatings Manual
Fig. 900-14 Description of External Pipeline Coating—Petrolatum and Petroleum-Wax Tapes Definition
Petrolatum tape, a synthetic fiber, is coated with petrolatum compound containing inert fillers and thermal extenders. Petroleum wax tapes are petrolatum-based corrosion-preventative waxes, impregnating a synthetic fabric backing, and applied over a petroleum-wax primer.
Recommended Service
•
Coating pipes in the splash zone underneath wharves
•
Field coating irregularly shaped, buried, pipe fittings (i.e., valves, ties, bends, etc.)
•
Protecting transition zones where buried piping comes above ground
•
Coating buried pipe in areas where soil stress is not a problem
•
Filling shorted pipeline road casings (petroleum wax)
Note: Excellent for fittings and irregular shapes as long as soil stress is not a problem. Status
This specialty pipe coating has proven very successful for specific applications for over 50 years.
Max. Service Temp
135°F
Surface Prep
Abrasive Blast Other
Holiday Detection
Use wet spronge jeep
Application
Hand apply •
Brush or wipe the surface clean of dirt and all other foreign matter
•
Apply a thin film of primer
•
Apply the wax tape
☞Caution
If the pipe's surface is wet, rub and press the primer to displace the moisture and ensure that the primer is adhering to the pipe's surface.
Thickness
45 mils
Small Repairs
Patch with same material per manufacturer’s guidelines
Handling/Storage
—
Protection/Resistance
UV Resistance: Good Hydrocarbon Resistance: Poor Add a rock shield material to protect the coating from penetration by rocks or soil-stress activity. Without a rock shield, add special backfill (sand) to a minimum thickness of six inches (150 mm).
Discussion
Advantages •
Conforms to irregular shapes
•
No drying or curing time required before backfilling
•
Easy application with minimum surface preparation
•
Easily removed
•
Can be applied over wet surfaces
•
Excellent resistance to moisture absorption
Disadvantages Low soil-stress resistance; not recommended for soil-stress areas. Girth-weld Coatings
—
Brands
Major manufacturers include Trenton, and Denso North America, Inc. Recently, Tapecoat introduced some petrolatum products.
See Also
—
September 1996
900-26
Chevron Corporation
Coatings Manual
900 Pipeline Coatings
Fig. 900-15 Description of External Pipeline Coating—Phenolic Epoxies Definition
A solvent-free, ultra-high-build, high-solids content, amine-cured, phenolic epoxy A solvent-free epoxy requires no evaporation in the curing process and has advantages for elevated temperature service because it is not as susceptible to solvent retention, which can cause the coating to break down on high-temperature lines [22].
Recommended Service
Field- or mill-applied coating system for high-temperature pipeline service
☞Caution
The Company has no experience with this coating system; it is included here as an introduction only.
Status
In Australia, Vessey Chemical manufactures Vepox CC703, reportedly an excellent high-temperature pipeline coating. Coating mills apply other phenolic-epoxy systems as a powder similar to FBE.
Service Temp
This coating system is rehabilitating Australian high-temperature gas pipelines with operating service temperatures as high as 248°F (120°C).
Surface Prep
Abrasive Blast: SSPC SP-10 with surface profile of 70-100 microns Other
Holiday Detection
Vendor’s recommendation.
Application
May field apply this coating system with conventional spray equipment using premixed material or with airless spray equipment [22].
Thickness
—
Small Repairs
—
Handling/Storage
—
Protection/Resistance
—
Discussion
Bends Phenolic epoxies are superior to FBE in temperature resistance, but typically we cannot field bend them. Coatings applicators can field coat field bends with a liquid-phenolic epoxy.
Girth-weld Coatings
—
Brands
—
See Also
—
Chevron Corporation
900-27
September 1996
900 Pipeline Coatings
Coatings Manual
Fig. 900-16 Description of External Pipeline Coating—Polyester Epoxies Definition Recommended Service
Flake-reinforced polyester epoxies are two-part liquid-epoxy coatings. Refurbishing old pipelines, tie-ins, valves, and fittings.
☞Caution ☞Caution
Where hydrocarbon contamination or soil stress present, use cold-applied tapes. Polyester epoxies are not recommended for hot oil pipeline service.[22. 23]
Status
Although this coating has had limited pipeline use because of the high cost of raw materials, it is an excellent coating system for pipeline valves both atmospheric and buried.
Max. Service Temp
160°F
Surface Prep
Abrasive Blast: SSPC SP-10 Other
Holiday Detection
4,000 volts
Application
•
Spray, brush, or roll
•
Very slow cure time
Note: Spray recommended; brush acceptable for patching small areas. Thickness
35-40 mils
Small Repairs
Patch with liquid epoxy per manufacturer’s guidelines.
Handling/Storage
—
Protection/Resistance
—
Discussion
Polyester epoxies have excellent resistance to UV, hydrocarbon, and soil stress.
Girth-weld Coatings
—
Brands
Master Builder's Ceilcoat Flakeline 251 is one recommended brand, but other excellent polyester epoxies are available.
See Also
—
September 1996
900-28
Chevron Corporation
Coatings Manual
900 Pipeline Coatings
Fig. 900-17 Description of External Pipeline Coating—Polyurethane (1 of 2) Definition
The reaction of isocyanates with hydroxyl-containing compounds makes the resins in polyurethane coatings. Two types of urethanes are available for buried pipelines: elastomeric and highly crossed linked. •
Elastomeric Polyurethane—Generally has tensile and elongative properties, producing elongation in excess of 20 percent.
•
Highly Cross-linked Polyurethane—Molecular cross linking takes place in a thermoset material during cure. High cross-linked materials generally have better resistance to chemicals; lower crosslinked materials have lower resistance to chemicals but often have very high elongation.
Other forms include
Recommended Service
•
Moisture-cure Polyurethane—Single component, generally TFT, systems applied in thin-film depositions; rely on a level of moisture for curing.
•
Single-component Polyurethane—Base and activator exist as mix; remain fluid until applied.
•
Dual- or Plural-component Polyurethane—Separate base resin and an activator are mixed just before applying.
•
All services up to temperature limits of the coating system
•
Refurbishing old pipelines where hydrocarbon contamination or soil stress prevent use of cold tapes
•
Field recoating pipelines
•
Mill-coated protection for FBE-coated pipe from construction damage during boring or as a rock shield
☞Caution ☞Caution Status
Do not select elastomeric polyurethane as a primary pipeline coating Not recommended for hot-oil pipeline service
Under the tradename, Protegal, TIB Chemie makes most polyurethane coatings applied during pipeline rehabilitation projects. Others are Madison Chemical's Corropipe and Valspar's Valpipe 100.
Max. Service Temp
☞Caution
Surface Prep
Abrasive Blast: SSPC SP-5
Not recommended currently for service temperatures above 180 °F [22].
Other Holiday Detection Application
125 volts per mil of coating thickness Type of Polyurethane •
Moisture-cure single-component polyurethanes: brush or roll on the pipe's surface.
☞Caution •
TDI, an isocynate, makes it dangerous to spray moisture-cure polyurethanes.
Dual-component polyurethanes: spray for major projects; brush or roller for spot touchup and small repairs to coatings; also, trowel.
Method •
Spray: Typically, coating applicators spray dual-component polyurethanes on a pipe's surface with special plural-component equipment that helps combat difficulties with temperature and ensures better adhesion.
•
Brush, trowel, roller: Cure time of dual-component polyurethanes is typically longer when it is applied this way. Tack-free condition is normally 30 minutes to 4 hours depending on ambient temperatures; hot air accelerates the cure cycle.
Thickness
25-30 mils
Small Repairs
Use manufacturer’s recommended polyurethane patching material
Handling/Storage
—
Protection/Resistance
See Discussion below.
Resistance
UV & Hydrocarbon: Excellent See also Discussion below.
Chevron Corporation
900-29
September 1996
900 Pipeline Coatings
Coatings Manual
Fig. 900-17 Description of External Pipeline Coating—Polyurethane (2 of 2) Discussion
Most moisture-cure polyurethanes are •
Slow in curing
☞Caution
The curing process combines with oxygen in the atmosphere; do not use in production runs.
•
Sensitive to high-low humidity
•
Lower in mechanical/abrasive resistance than dual-component polyurethanes, FBE, and liquid epoxy coatings
•
Not high build and several coats (4-6 mils) needed to reach the desired total thickness
Elastomeric polyurethanes have •
Higher moisture-absorption rates than highly crossed-linked polyurethanes
•
Higher mechanical/abrasive resistance that may make them desirable as rock shields for other pipe coatings.
Advantages The high solids, high build, and fast cure properties make dual-component polyurethane suitable for pipeline-rehabilitation projects. Highly crossed-linked polyurethanes have low rates of moisture absorption. The exothermic nature of the iso/polyol reaction allows us to spray aromatic polyurethanes at temperatures as low as -20°F (-29°C) and as high as 140°F (60°C). While cure time is temperature dependent, urethanes are less temperature dependent than other systems such as liquid epoxies. To accelerate cure time, normal practice is to pre-heat the pipe to 180°F in the mill; to 150°F by induction coil in the field. Disadvantages Existing pipe-coating mills are not equipped to apply this coating system economically. Dual-component polyurethanes require special, plural-component, heated, spray equipment that has a pot life of less than 30 seconds. Service History In Texas, some major, large-diameter, gas-transmission pipelines were recoated with TIB Chemie's Protegal. Soil stresses had damaged the original asphalt or coal-tar enamel. There has been no report of any coating failures to date. Girth-weld Coating
As we typically field-apply polyurethane, the coating applicators coat the girth-weld and joint surfaces at the same time. They may coat girth welds at coating transitions with cold-applied tapes or heat-shrink sleeves.
Brands
TIB Chemie Protegal UT32-10, Madison Chemical Corropipe, Valspar Valpipe 100
See Also
—
September 1996
900-30
Chevron Corporation
Coatings Manual
900 Pipeline Coatings
Fig. 900-18 Description of External Pipeline Coating—Thermoset Epoxies Definition
A two-part, liquid, thermosetting compound that cures without heat.
Recommended Service
Liquid epoxies are good for repairing FBE coatings and for refurbishing old pipelines, girth-weld coatings, tie-ins, valves, and fittings.
Status
Two-part liquid epoxies have worked well in accelerated laboratory tests and in limited field use. Both Hempel Epoxy 8553 and Hempel Nap-Wrap Epoxy 8553 passed CRTC's hot-subsea-coating test. Previously, only 20+ mil-thick FBE coatings passed it consistently. The hot-subsea-coating test subjects a coated pipe to 250°F internal temperature and -0.90 volts of cathodic protection while the pipe is suspended in 65°F sea water for 90 days. Aramco is replacing tape wraps with Hempel Epoxy 8553 as their primary refurbishing and tie-in coating. They apply the coating to a 20-25 mil thickness in two coats.
Max. Service Temp
225°F
Note: Aramco has had success applying Hempel Nap-Wrap Epoxy 8553 to 200°F lines in operation. Surface Prep
Abrasive Blast: SSPC SP-10 Other
Holiday Detection
125 volts/mil
Application
•
Spray, brush, or roll
•
Can be field applied
•
Cure time very slow
Thickness
20-30 mils
Small Repairs
Patch with Hempel Nap-Wrap Epoxy 8553 per manufacturer’s guidelines.
Handling/Storage
—
Protection/Resistance
The tape wrap or membrane in Hempel Nap-Wrap Epoxy 8553 gives the coating added strength and resistance to abrasion. High-temp (225°F) Hydrocarbon & UV Resistance: Excellent Chemical Resistance: Good
Discussion
Advantages Because it is a thermoset, this epoxy does not soften with temperature; but, it has chemical, temperature, and mechanical properties similar to FBE. Tape We can apply Hempel Epoxy 8553 either alone or with a tape wrap (Hempel Nap-Wrap Epoxy 8553).
Girth-weld Coatings
—
Brands
Hempel Epoxy 8553 and Hempel Nap-Wrap Epoxy 8553
See Also
—
Chevron Corporation
900-31
September 1996
900 Pipeline Coatings
Coatings Manual
Fig. 900-19 Description of External Pipeline Coating—Girth-Weld Protection—Heat-shrink Sleeves (1 of 2) Definition
Shrink sleeves are tubes or wraparound strips of a heat-shrinkable backing of cross-linked polyethylene. The backing has either a butyl-rubber adhesive or a semi-crystalline adhesive.
Recommended Service
Field joints, tie-ins, small pipeline recoating jobs, and mechanically damaged mill-applied coatings
Status
Heat shrink sleeves are readily available from manufacturers in pre-sized or bulk (cut-to-fit) packages.
Max. Service Temp
—
Surface Prep
Abrasive Blast: SSPC SP-3 for most sleeves. Refer to manufacturer’s guidelines. Other
Holiday Detection 1250
coating thickness ( mils )
or Vendor’s recommendation Application
Basic •
Prepare the surface (minimum: clean with hand power tools).
•
Bevel the edge of the pipeline coating (only for thick coatings such as coal-tar enamel and asphalt mastic).
•
Position the shrink sleeve.
•
Apply heat by torch or induction, depending on the adhesive.
Tubes •
Place tubes loosely on the pipe near the girth-weld area before fit-up and welding.
•
Apply tubes over the girth-weld area as soon as possible after welding is completed because adhesive is exposed to the atmosphere.
Strips (Wraparound sleeves) •
Apply the strips any time after welding is completed and before the pipe is buried.
•
Wrap the strips around the field joint until the ends overlap.
•
Seal the overlapping seam with a strip of the coating.
•
Apply heat to shrink the coating into place.
Aramco uses induction coils to apply heat shrink wraps at a rate of 120 per day.
☞Caution
Consult the manufacturer for instructions on application procedures.
Thickness
70 to 80 mils
Small Repairs
—
Handling/Storage
—
Protection/Resistance
Shrink sleeves are thick, therefore, abrasion resistant. When heated, the adhesive melts and the polyethylene backing shrinks. This forces the adhesive to flow into the irregularities of the area to be coated. The shrunken wrap is an abrasion-and- penetration-resistant coating. CRTC's Materials and Equipment Engineering group conducted dragging tests to simulate an offshoretow installation. The leading edge peeled and eroded, and tape wraps failed at overlaps because every protruding surface eroded. Because of these tests, the Company bonded a sacrificial half-sleeve in front of the actual shrink sleeves of a Pritec-coated offshore line. The Company installed this pipeline successfully, despite dragging it across an ocean floor. See also Disadvantages and Selection in Discussion, below.
September 1996
900-32
Chevron Corporation
Coatings Manual
900 Pipeline Coatings
Fig. 900-19 Description of External Pipeline Coating—Girth-Weld Protection—Heat-shrink Sleeves (2 of 2) Discussion
Advantages •
Quick and easy to apply, requiring a minimal surface preparation and skill
•
Service temperature ratings between -30°F and 230°F
•
Compatible with FBE, extruded plastic, tape wraps, coal-tar enamels, asphalt mastics, liquid epoxies, and polyurethane coatings.
Disadvantages •
The polyethylene backings expand when exposed to hydrocarbons.
•
A torch, required for the applying the wraps, can damage the primary coating.
•
Some heat shrink sleeves have low resistance to damage from soil stress.
Selection
Choice of Adhesive: The adhesive establishes two categories of temperature limits for sleeves, each having specific characteristics: •
150°F or lower: typically a butyl-rubber adhesive which – Can flow when heated by torch which causes no damage to the PE backing or line coating. – Generally changes color at the proper temperature, allowing less-experienced workers to apply the sleeves properly.
•
150°F or higher: typically a semi-crystalline adhesive which – Needs greater heat to melt the adhesive than butyl-rubber adhesives. – Needs induction coils for a more even, consistent heat and to prevent damage to the pipeline coating and sleeve from the flame of the torch. Torches are also acceptable for heating the pipe.
The properties of the adhesive may also affect the sleeve's selection: •
Semi-crystalline or hot-melt adhesives have good physical properties and bond strengths but generally have poorer resistance to cathodic disbonding than butyl-rubber adhesives.
•
Butyl-rubber adhesives are generally more susceptible to soil stresses but have a higher resistance to cathodic disbonding.
Other Selection Factors: The choice of sleeve may also depend on the pipe's size, construction schedule, and the experience of the people applying it. •
Wraparound – Less costly – No time constraints for application (can apply after creating any weld) – Bulk, cut-to-fit sizes
•
Tube – Must place loosely over pipe before creating weld – Only for 3/4-inch- to 12-inch-diameter pipe – Quicker and easier to apply than wraparound sleeves – Superior to wraparound because there are no seams
Brands
In the U.S., the Company usually selects Raychem and Canusa sleeves. Other brands currently available are UBE Industries, Ltd., Tokyo and Nitto Electric Industrial, Ltd. For DuVal, Himont, and Elf Atochem polyethylene girth welds, there are heat-shrink sleeves compatible with the coating and rated for the operating temperature of the pipeline. Canusa has developed a multilayer heat-shrink sleeve for coating the girth welds of multi-layer coatings such as Shaw YJII, Mapec, Himont, Elf Atochem, and DuVal. Raychem is developing heat-shrink sleeves for polypropylene pipe coated with Elf Atochem, Himont, and DuVal brands.
See Also
Chevron Corporation
—
900-33
September 1996
900 Pipeline Coatings
Coatings Manual
Fig. 900-20 Description of External Pipeline Coating—Girth-Weld Protection Coating—Induction Heat-Applied FBE Definition
Applying FBE to the girth-weld area by induction heat
Recommended Service
To protect girth welds of FBE- coated pipelines
Status
Common on large projects, critical lines, and high-temperature lines. It was expensive, but the cost now nearly equals heat-shrink sleeves due to improved application techniques on large projects.
Max. Service Temp
—
Surface Prep
Abrasive Blast SSPC SP-10 Near-white Metal Finish Other After welding, clean the pipe chemically and then blast it to SSPC SP-10. Brush blast the field joint and two inches of FBE on either side of the joint to clean and roughen the coating's surface.
☞Caution
Proper surface preparation is critical to this type of coating. Also, protect the pipe's surfaces from high humidity, rain, or surface moisture [9, 11].
Holiday Detection
125 volts/mil
Application
•
Induction heat the weld zone to approximately 500°F (depending on the coating manufacturer's specifications).
•
Immediately apply the FBE powder so that residual heat in the pipe cures the coating. A motorized unit, called a powder application ring, sprays the powder on the joint as the sprayer rotates around the pipe.
☞Caution
Do not force cool or quench, which means that the pipe must be out of service during the coating process to prevent cooling too quickly.
Thickness
—
Small Repairs
—
Handling/Storage
—
Protection/Resistance
—
Discussion
Advantages Induction heat-applied FBE is the best girth-weld area protection coating for FBE-coated pipelines because it is the same material as on the pipe's joint. Disadvantages Application requires abrasive blasting and accurate heat control. It is sensitive to environmental effects such as humidity.
Brands
Commercial Resins Company, Commercial Coating Services Incorporated (CCSI), and Pipeline Induction Heat Ltd. (PIH) are among the contractors who have equipment and trained personnel for field applying FBE over pipeline girth welds.
See Also
•
September 1996
Figure 900-3 Advantages and Disadvantages of External Pipeline Coatings
900-34
Chevron Corporation
Coatings Manual
900 Pipeline Coatings
Fig. 900-21 Description of External Pipeline Coating—Girth-Weld Protection—Induction Heat-Applied Plastic with FBE Primer Definition
Induction heat-applied plastic with FBE primer is a field-applied process for coating EPHA girth welds.
Recommended Service
For joints coated with extruded plastic with hard adhesive (EPHA) In EPHA, hard adhesive is liquid epoxy or FBE primer.
Status
Common on high-temperature pipelines Coating the girth welds on pipe joints coated with Elf Atochem, Himont, and DuVal polypropylene is difficult; however, Raychem is developing a heat-shrink sleeve for coating girth welds on these joints.
Max. Service Temp
Vendors claim up to 230°F.
Surface Prep
Abrasive Blast: SSPC SP-10 Near-white Metal Finish Other: Chemical cleaning and blasting to an SSPC SP-10
Holiday Detection
—
Application
•
Heat the weld and adjoining FBE coating from 438°F to 463°F with an induction coil.
•
Apply the FBE powder to the heated surface.
•
Apply the top, plastic layer(s), at the proper time, over the FBE primer.
Note: Post heating of the plastic layer may be required depending upon the coating thickness Timing Requires excellent timing when applying the plastic layer over the FBE layer. •
Too quick: improper curing of the FBE and poor bonding to the pipe's surface
•
Too slow: improper bonding between the plastic and FBE
Thickness
—
Small Repairs
—
Handling/Storage
—
Protection/Resistance
—
Discussion
Advantage The best girth-weld protection for EPHA- coated pipelines because it is the same material as the pipe joint Disadvantages
Brands
See Also
Chevron Corporation
•
Requires abrasive blasting
•
Requires accurate heat control; otherwise, the joint coating near the girth-weld may become damaged
•
Requires excellent timing during application
•
Is sensitive to environment, such as humidity
There are two companies experienced with applying specific brands of these coatings: •
Commercial Coating Services Incorporated (CCSI) with DuVal
•
Pipeline Induction Heat Ltd. (PIH) with DuVal, Himont, and Elf Atochem
—
900-35
September 1996
900 Pipeline Coatings
Coatings Manual
Fig. 900-22 Operating Temperature for Splash-Zone Coating for Offshore Platform Risers Temperature
Coating
Below 140°F
Sprayable (Tidegard 171)
Up to 180°F
Vulcanized Neoprene
Up to 250°F
Monel Sheathing
Fig. 900-23 Pipeline Fitting and Valve Coating System Generic Type
Coating Name
Max Svc Temp °F
Holiday Detector Voltage
Coating Thickness (Mils)
Surface Prep
Hydrocarbon Resistant
Soil Stress Resistant
300 V
16-20
SSPC SP-10
Yes
Yes
20-45
SSPC SP-10
Yes
Yes
14-30
SSPC SP-10
No
Yes
>27
SSPC SP-3
No
No
>27
SSPC SP-3
No
No
Coal Tar Epoxy
Tarset Maxi-Build 7080
14
Extruded Plastic with FBE Primer
Du Val
200
Fusion Bonded Epoxy (FBE)
Scothkote 206N
200
Heat Shrinkable Tape
Canusa Wrapid Tape
135
Heat Shrinkable Tape
Raychem FlexClad
135
Petroleum Tape
Denso HT
120
use wet spronge jeep
45
SSPC SP-2
No
No
Polyester
Flakeline 251
160
4000V
35-40
SSPC SP-10
Yes
Yes
Polyurethane
Protegal UT 32-10RG
180
150 V/Mil
25-30
SSPC SP-5
Yes
Yes
Polyurethane
Protegal UT 32-50RG
180
150 V/Mil
25-30
SSPC SP-5
Yes
Yes
Polyurethane
Protegal UT 32-10
135
150 V/Mil
25-30
SSPC SP-5
Yes
Yes
Polyurethane
Valpipe 100
160
125 V/Mil
25-30
SSPC SP-5
Yes
Yes
Polyurethane
Madison Corropipe 2TX
135
125 V/Mil
25-30
SSPC SP-5
Yes
Yes
Thermoset Epoxy
Nap-Wrap Epoxy 8533
225
125 V/Mil
20-30
SSPC SP-10
Yes
Yes
Wax Tape
Trenton #1 Wax
120
use wet spronge jeep
70-90
SSPC SP-2
No
No
1250
September 1996
coating thickness ( mils )
125 V/Mil
1250
coating thickness ( mils )
1250
coating thickness ( mils )
900-36
Chevron Corporation
Coatings Manual
900 Pipeline Coatings
Fig. 900-24 Generic Coatings for Girth Weld Protection Suggested Coating Material for the Girth Weld Preferences Original Coating Asphalt Enamel
Joining Coating
1
2
3
4
Asphalt Enamel
Heat Shrink Wrap
Asphalt Enamel
FBE
Heat Shrink Wrap
Tape
EPSA
Heat Shrink Wrap
Tape
Polyester Epoxy
Heat Shrink Wrap
Tape
Polyester Epoxy
Tape
Tape
Coal Tar Enamel
Heat Shrink Wrap
Coal Tar Epoxy
Tape
Coal Tar Enamel
FBE
Heat Shrink Wrap
Tape
Liquid Epoxy
Coal Tar Enamel
EPSA
Heat Shrink Wrap
Tape
Asphalt Enamel
Heat Shrink Wrap
Tape
Coal Tar Epoxy
Asphalt Enamel
Polyester Epoxy
Heat Shrink Wrap
Polyester Epoxy
Tape
Tape
Tape
EPHA
EPHA
EPHA
Heat Shrink Wrap
Tape
EPSA
EPSA
Heat Shrink Wrap
Tape
EPHA
Heat Shrink Wrap
Tape
Polyester Epoxy
Heat Shrink Wrap
Tape
Tape
Tape
FBE
FBE
Heat Shrink Wrap
EPSA
Heat Shrink Wrap
Tape
EPHA
FBE
Polyester Epoxy
Heat Shrink Wrap
Tape
Tape
Tape
Tape
Coal Tar Enamel
FBE
Tape Note:
Liquid Epoxy
5
Asphalt Enamel
Liquid Epoxy
Tape
EPHA
Heat Shrink Wrap
Liquid Epoxy
Polyester Epoxy
Tape
Mastic
Tape
EPSA = Extruded Plastic with Soft Adhesive EPHA = Extruded Plastic with Hard Adhesive
Note:
Chevron Corporation
900-37
September 1996
900 Pipeline Coatings
Coatings Manual
Rehabilitation Coatings There are two ways to refurbish an old line: replace the pipeline or remove the old coating and recoat. Replacing the Pipe (Coating the Transition Girth Welds). Consider cold-applied tapes or heat-shrink sleeves to coat tie-in girth welds because these coatings are compatible with almost all coating systems. Note Tie-in girth welds connect the replacement section of pipe to the existing pipe. If soil stress is not a problem, apply either heat-shrink sleeves or cold-applied tape to girth welds on the tie-in (coating transition). If soil stress is a problem, apply heat-shrink sleeves on the tie-in. If the soil has hydrocarbon contamination, select FBE-coated pipe over extruded plastics. Avoid heat-shrink wraps or cold-applied tapes on the girth welds, and select liquid epoxy for the girth welds of the pipe replacement. If there is both soil stress and hydrocarbon contamination, select liquid epoxy rather than cold-applied tapes or heat-shrink sleeves. Replacing the Coating. Pipeline recoating may be carried out in-the-ditch or overthe-ditch. Note In-the-ditch means that the pipeline is neither removed from its site nor from service and may still be under pressure. Over-the-ditch means that the pipeline is taken out of service and the pipe removed from the ground.
☞
Caution While recoating a pipeline that is under pressure, follow all pipeline safety guidelines. Be aware that machinery for recoating pipe may be unsafe for a pressured pipeline. When replacing the coating, grit or sand blast to remove the old one completely if local air quality regulations permit. If the old coating system contains asbestos, follow special asbestos-handling procedures such as work wet, use plastic containment, and wear special protective clothing. Asbestos-containing coatings include Somastic, most asphaltics such as P2, Modified P2, P3, and P4 Wraps, and coal-tar enamel. Note To identify asbestos-containing coatings on Company pipelines, research construction records and pipeline inventory line sheets for coating information. CRTC's M&EE Unit has project files that may also contain information about pipeline coating projects. For the latest information about asbestos-removal techniques for pipelines, contact Chevron Pipe Line Company's Health, Environment, & Loss Prevention personnel.
September 1996
900-38
Chevron Corporation
Coatings Manual
900 Pipeline Coatings
☞
Caution Government regulations about removing asbestos vary across the United States and change periodically. Review the current asbestos-removal regulations before starting a pipeline-rehabilitation project. Selecting the Coating. Factors involved in choosing a field-applied rehabilitation coating system include consideration of the following: • •
Soil Temperatures – – –
Operating temperature of the pipe Temperature of the pipe during recoating Dew point temperature during coating
See Figure 900-25 for a brief description of field-applied, pipeline coating systems for rehabilitating pipelines. The coating systems are listed in order of preference.
922 Quality Control Among the elements of quality control for external pipeline coatings are specifications and standards, planning, service conditions, durability and resistance, construction factors, application factors, and inspection.
Specifications and Standards The following figures list specifications to help ensure the success of an external coatings project. • •
Coating Specifications for Buried Pipelines (Figure 900-26) Industry Standards for Pipeline Coatings (Figure 900-27)
Planning There are many factors involved in planning an external coatings project for pipelines. The main ones are as follows: •
Service Conditions – – –
•
Durability and Resistance of Coatings – – – – – –
Chevron Corporation
Maximum continuous service temperature Soil conditions Accessibility of the line for field application and repair
Durability Chemical Resistance Ultraviolet (UV) Resistance Resistance to Mechanical Damage Resistance to Temperature Cathodic Shielding and Disbonding
900-39
September 1996
900 Pipeline Coatings
Coatings Manual
Fig. 900-25 Field-Applied Rehabilitation Coating Systems in Order of Preference Rank 1.
System Liquid Epoxies • Excellent resistance to chemicals and temperatures •
Poor (long) cure times
•
Dust and insects can contaminate this coating while it is curing, causing holidays
•
Poor choice during winter, more practical during ideal dry summer weather
•
Brush, roll, or spray with standard spray equipment
There are basically four types of liquid epoxies: coal-tar, thermoset, phenolic, and polyester epoxies.
2.
3.
4.
•
For all services: thermoset and phenolic
•
Not for hot-oil pipelines: polyester and coal-tar epoxies
•
For temperatures up to 220°F: phenolic and some thermoset epoxies
Polyurethane • Excellent resistance to chemicals and temperature •
Preferred over liquid epoxies for faster cure time
•
Summer: Fast-cure urethane coatings may be buried within 15 minutes
•
Winter: Fast cure urethane coatings can take from one to five hours to cure enough for burial, depending on the method of application
•
Spray with required, heated, plural-component, spray equipment
•
For temperatures up to 180°F
Hot-Applied Wraps and Tapes(1) • Recoating for short sections of pipe •
Needs a rock shield in high-soil-stress environment
•
Too labor intensive for rehabilitating major pipelines
•
Low resistance to hydrocarbon – not for hydrocarbon-contaminated soils
•
Available as high-temperature heat shrinkable wraps and tapes
•
May not be applied to pipelines in service if flowing product prevents pipe surface from being heated properly
Cold-Applied Tapes(1) • Very economical •
Needs proper tension during application
•
Needs an outer wrap of rock shield in high-soil-stress areas
•
Low resistance to hydrocarbon and temperature
(1) If this coating fails, it may cause a shielded corrosion cell, creating a corrosion leak on a cathodic protected pipeline
September 1996
900-40
Chevron Corporation
Coatings Manual
900 Pipeline Coatings
Fig. 900-26 Coating Specifications for Buried Pipelines Coating
Spec Number(1)
Fusion Bonded Epoxy (FBE)
COM-MS-4042
Fusion Bonded Epoxy for External Coating
Company's Standard Spec
3/31/88
09-AMSS-089
Shop-Applied External FBE Coatings
Aramco Spec
8/10/85
PA 131
Fusion Bonded Epoxy External Line Pipe Corrosion Coating
Mesquite Pipe Line Project
6/30/87
P-I-002
Fusion Bonded Epoxy Corrosion of Submarine Pipelines
Western Producing Spec (Platform Gail)
8/21/84
PA 129
Extruded Polyethylene Corrosion Coating with Butyl Adhesive
Point Arguello Pipeline and Natural Gas Companies
7/6/84
09-AMSS-090
Shop-Applied Extruded PE External Coating System
Aramco Mapec and Pritec Spec
3/27/85
COM-MS-5005
Side Extruded Plastic/ Butyl Rubber Adhesive Line Pipe Corrosion Coating
Company's Standard Spec
1996
Coal Tar Enamel Wrap
Point Arguello Pipeline and Natural Gas Companies
1/3/85
Spec for TGF-3 Pipeline Coating
Northern Producing Spec
9/17/87
Water Line Coal Tar Enamel Corrosion Coating
Point Arguello Pipeline Company
12/20/85
Coal-Tar Enamel Corrosion Coating of Submarine Pipelines
Company's Standard Spec
1996
PA 136
Pipe Weight Coating
Point Arguello Pipeline and Natural Gas Companies
2/20/85
PA 176
Pipe Weight Coating Quality Assurance
Point Arguello Pipeline and Natural Gas Companies
4/15/85
Pipeline Continuous Concrete Coating
Sudan Petroleum Development Project
2/24/84
PA 132
Polymer Cement Barrier Coating (over FBE Powder Pipe Coatings)
Point Arguello Pipeline and Natural Gas Companies
7/6/84
E-4512
Concrete Weight Coating for Submarine Pipelines
Richmond Deep Water Outfall Project
9/23/86
—
Spec for Over-the-Ditch Application for Mainline Pipe and Facility Piping
Rangely
2/26/85
PA 150
Polyethylene Tape Wrap with Butyl Adhesive
Point Arguello Pipeline and Natural Gas Companies
7/6/84
09-AMSS-095
Hand-Applied Pressure Sensitive Tape Wrap for Temperatures up to 55°C (130°F)
Aramco Spec
9/22/85
09-AMSS-096
High-Temperature Heat Shrink Sleeves
Aramco Spec
9/22/85
Extruded Plastic
Coal Tar Enamel
PA 171 NR-2510 PA 155 COM-MS-5006
Concrete Weight Coating
—
Field-Applied Tape Wrap
Shrink Sleeves
Spec Title
Project
Date Written
(1) See CRTC's Materials Engineering File 6.55.70 Specifications PA Specifications were written by Chevron Pipe Line Company
Chevron Corporation
900-41
September 1996
900 Pipeline Coatings
Coatings Manual
Fig. 900-27 Industry Standards for Pipeline Coatings (1 of 2) Spec. No.
Description American Petroleum Institute (API) Standards
RP 10E
Application of Cement Lining to Steel Tubular Goods, Handling, Installation, and Joining
RP 5L1
Recommended Practice for Railroad Transportation of Line Pipe
FP 5L5
Recommended Practice for Marine Transportation of Line Pipe American Water Works Associated (AWWA)
ANSI/AWWA C203
CT Protective Coating & Lining for Stl. Water Lines
ANSI/AWWA C205
Cement Mortar Lining for Steel Pipe 4" & Larger
ANSI/AWWA C209
Cold-Applied Tape Coatings for Special Sections
ANSI/AWWA C210
CTE for the Interior & Exterior of Steep Pipe
ANSI/AWWA C213
FBE for the Interior & Exterior of Steep Pipe
ANSI/AWWA C214
Tape Coating for the Exterior of Steel H20 Pipes
ANSI/AWWA C215
Extruded Polyolefin for Exterior of Steel H20 Pipes
AWWA C602
Cement Lining Water Lines 4" & Larger—in Place British Standard
BS 4164
Coal-Tar Protective Coatings and Linings for Steel Water Pipelines, Enamel, and Tape Hot-Applied British Gas Standards
PS/PA3
Painting at Site of New Components for Long Term Protection
PS/CW1
External Wrap of Line Pipe using Coal Tar
BGC/PS/CW2
Cold-Applied Wrapping Tapes & Tape Systems
PS/CW3
External Wrap Operations using Hot-Applied Bitumen
PS/CW5
Code of Practice for the Selection and Application of Field-Applied External Coating (Other than Resin)
MR0274
Material Requirements for Polyolefin Cold-Applied Tapes for Underground Submerged Pipeline Coatings
PUB. 6H189
A State-of-the-Art Report of Protective Coatings for Carbon Steel and Austenitic Stainless Steel Surfaces Under Insulation and Cementitious Fireproofing Canadian Standards
CAN/CSA-Z245.20-M90
External FBE Coating for Pipe
CAN/CSA-Z245.21-M92
External Polyethylene Coating for Pipe German Standards (DIN)
DIN 30670
Polyethylene Coating of Steel Pipes and Components
DIN 53516
Determination of Abrasion Resistance L'Association Française De Normalisation (AFNOR) Standard
NFA 49-710
Steel Tubes External Triple-Layer Polyethylene-Based Coating Application by Extrusion NACE International Standards
RP0169
Control of External Corrosion on Underground or Submerged Metallic Piping Systems
RP0285
Control of External Corrosion on Metallic Buried or Submerged Liquid Storage Systems
RP0181
Liquid Applied Internal Protection Linings and Coatings for Oil Field Production Equipment
RP0185
Extruded Polyolefin Resin Coating Systems for Underground or Submerged Pipe
RP0188
Discontinuity (Holiday) Testing of Protective Coatings
September 1996
900-42
Chevron Corporation
Coatings Manual
900 Pipeline Coatings
Fig. 900-27 Industry Standards for Pipeline Coatings (2 of 2) Spec. No.
Description NACE International Standards (continued)
RP0190
External Protective Coatings for Joints, Fittings, and Valves on Metallic Underground or Submerged Pipelines and Piping Systems
RP0274
High Voltage Electrical Inspection of Pipeline Coatings Prior to Installation
RP0490
Holiday Detection of Fusion Bonded Epoxy External Pipeline Coatings of 10 to 30 Mils (0.25 to 0.76 MM)
RP0675
Control of External Corrosion on Offshore Steel Pipelines
TM0170
Visual Standard for Surfaces of New Steel Airblast Cleaned with Sand Abrasive
TM0174
Laboratory Methods for the Evaluation of Protective Coatings used as Lining Materials in Immersion Services
TM0175
Control of Internal Corrosion in Steel Pipelines and Piping Systems
TM0183
Evaluation of Internal Plastic Coatings for Corrosion Control of Tubular Goods in an Aqueous Flowing Environment
TM0185
Evaluation of Internal Plastic Coatings for Corrosion Control of Tubular Goods by Autoclave Testing
TM0186
Holiday Detection of Internal Tubular Coatings of 10 to 20 mils (0.25 to 0.76 MM) Dry Film Thickness
TM0375
Abrasion Resistance Testing of Thin Film Baked Coatings and Linings using the Falling Sand Method
TM0384
Holiday Detection of Internal Tubular Coatings of less than 10 mils (0.25 MM) Dry Film Thickness National Association of Pipe Coating Applicators (NAPCA) Standards
Bulletin 1-65-94
Designation for Coal Tar Enamel Coatings
Bulletin 2-66-94
NAPCA Coating Specifications for Standard Applied Pipe Coating Weights
Bulletin 3-67-94
External Application Procedures of Hot Applied Coal Tar Coatings to Steel Pipe
Bulletin 5-69-94
NPACA Specifications for Pipeline Wrappers
Bulletin 12-78-94
External Application Procedures for Plant-Applied Fusion Bonded Epoxy (FBE) Coatings to Steel Pipe
Bulletin 13-79-94
External Application Procedures for Coal Tar Epoxy Protective Coatings to Steel Pipe
Bulletin 14-83-94
External Application Procedures for Polyolefin Pipe Coating Applied by the Cross Head Extrusion Method for the Side Extrusion Method to Steel Pipe
Bulletin 15-83-94
External Application Procedures for Plant-Applied Tape Coating to Steel Pipe
Bulletin 6-69-94-1
Suggested Procedures to Hand Wrap Field Joints using Hot Enamel
Bulletin 6-69-94-2
Suggested Procedures for Coating of Girth Welds with Fusion Bonded Epoxy
Bulletin 6-69-94-3
Suggested Procedures for Coating Field Joints, Fittings, Connections, and Pre-Fabricated Sections using Tape Coatings
Bulletin 6-69-94-4
Suggested Procedures for Field Joint Application using Mastic Mix and Field Mold
Bulletin 6-69-94-5
Suggested Procedures for Coating Field Joints using Heat Shrinkable Materials
Chevron Corporation
900-43
September 1996
900 Pipeline Coatings
Coatings Manual
•
Construction Factors – – – – – –
•
Impact Resistance Flexibility in Cold Weather Field Repair Limitations of Temporary Storage Climate During Construction Project Construction Methods During Project
Application Factors – –
Cost Site
Service Conditions Note FBE has the widest range of operating temperatures, greatest resistance to chemicals and soil stress of all pipe-coating systems. •
Maximum Continuous Service Temperature Figures 900-23, 900-28, and 900-29 list information about service conditions of various field- or mill-applied coatings and coatings for fittings and valves.
•
Soil Conditions (sand vs. clay, wet or dry, hydrocarbon or other chemical contamination, pipe-soil stresses, soil resistivity data) –
Hydrocarbon or Chemical Contamination To combat hydrocarbon or chemical contamination, it is necessary to apply a pipe coating that is resistant to the chemicals in the soil.
–
Soil Stresses Soil stresses occur mainly in clay soils; not usually in sandy soils. Soil stresses resulting from wet/dry or freeze/thaw seasonal cycles can, however, damage pipe coatings.
–
Soil Corrosivity Typically, soil corrosivity increases with decreasing soil resistivity. In highly corrosive soils, you may need to apply a high-performance coating system to the pipe.
–
Microbiologically Influenced Corrosion (MIC) Activity Some pipe coatings, such as cold-applied tapes, have low resistance to bacteria-generated, chemical byproducts that are also corrosive to the steel pipe.
•
Accessibility of the Line for Field Application and Repair Pipe laid under river crossings, offshore, or in other hard-to-access locations may need low-maintenance pipe coatings.
September 1996
900-44
Chevron Corporation
Coatings Manual
900 Pipeline Coatings
Fig. 900-28 Mill-Applied Pipeline Coating Systems (1 of 2) Surface Prep Generic Type Asphalt Mastic
Asphalt Mastic
Coal Tar Enamel
Trade Name Somastic Type I
Somastic Type III
Reilly #230A Enamel
Max Svc Temp. °F
Holiday Detector Voltage
140 1250
coating thickness ( mils )
1250
coating thickness ( mils )
1250
coating thickness ( mils )
1250
coating thickness ( mils )
1250
coating thickness ( mils )
1250
coating thickness ( mils )
1250
coating thickness ( mils )
140
140
Resistance
SSPC SP-
Hydrocarbon
Soil Stress
Black
6
No
Yes
Yellow
6
No
Yes
Black
6
No
No
Black
6
No
Yes
Yellow
6
No
Yes
Yellow
6
No
Yes
Orange
6
No
Yes
Color
Crosshead-Extruded Plastic with Asphalt Adhesive
Shaw Black Jacket (Polyethylene)
150
Crosshead-Extruded Plastic with Asphalt Adhesive
Shaw Yellow Jacket (Polyethylene)
160
Crosshead-Extruded Plastic with Asphalt Adhesive
Encoat Entec (Polyethylene)
100
Crosshead-Extruded Plastic with Asphalt Adhesive
Encoat Entec (Polypropylene)
100
Crosshead-Extruded Plastic with Asphalt Adhesive
Plexco Plexguard (Polyethylene)
100
10,000 V
Yellow
6
No
Yes
Crosshead-Extruded Plastic with Asphalt Adhesive
Plexco Plexguard (Polypropylene)
100
10,000 V
Orange
6
No
Yes
Dual FBE
O'Brien Nap-Gard “Gold” 7-2501 & 7-2504
200
125 V/Mil.
Gold
10
Yes
Yes
Extruded Plastic with FBE Primer
Elf Atochem (Polyethylene)
180
Black
10
No
Yes
Extruded Plastic with FBE Primer
Elf Atochem (Polypropylene)
200
Gray
10
No
Yes
Extruded Plastic with FBE Primer
Du Val (Polyethylene)
180
Blue
10
No
Yes
Chevron Corporation
1250
coating thickness ( mils )
1250
coating thickness ( mils )
1250
coating thickness ( mils )
900-45
September 1996
900 Pipeline Coatings
Coatings Manual
Fig. 900-28 Mill-Applied Pipeline Coating Systems (2 of 2) Surface Prep Generic Type
Trade Name
Max Svc Temp. °F
Holiday Detector Voltage
Resistance
SSPC SP-
Hydrocarbon
Soil Stress
Blue
10
No
Yes
Color
Extruded Plastic with FBE Primer
Du Val (Polypropylene)
200
FBE
3M ScotchKote 206N
200
125 V/Mil.
Green
10
Yes
Yes
FBE
O'Brien Nap-Gard 7-2501
200
125 V/Mil.
Red
10
Yes
Yes
FBE
Valspar D1003LD
200
125 V/Mil.
Beige
10
Yes
Yes
FBE
Lilly Pipeclad 1500
150
125 V/Mil.
Green
10
Yes
Yes
Heat-Applied Tape
Raychem Rayclad 120
20
Black
3
No
Yes
White
6
No
No
Black
10
No
Yes
Heat-Applied Tape
Ygill
Side-Extruded Polyethylene with Butyl Rubber Adhesive
1250
coating thickness ( mils )
1250
coating thickness ( mils )
1250
coating thickness ( mils )
140
Pritec 10/40
180
14,000 V
Durability & Resistance Durability. Proper surface preparation is essential to prevent premature failure of coatings. Minimum specifications for the surface preparation of pipeline are listed in Figures 900-23, 900-28, and 900-29 for mill- and field-applied pipeline coating systems and for pipeline fittings and valve coating systems. See also the list of standards for surface preparation in Figure 900-30. In the Company's pipe-coating specifications, there are details about the quality control inspections necessary during the coating mill's production run. Chemical Resistance. Chemical resistance is important in a coating if: • •
There was a spill where the pipe will be laid The location has a high potential for a spill
Figures 900-23, 900-28, and 900-29 give the rates of hydrocarbon resistance for various pipeline coatings. The rating for extruded plastic and tape wraps is based on the following: Polyvinylchloride (PVC) is more resistant than polypropylene which, in turn, is more resistant than polyethylene.
September 1996
900-46
Chevron Corporation
Coatings Manual
900 Pipeline Coatings
Fig. 900-29 Field-Applied Pipeline Coating System
Manufacturer
Trade Name
Generic Type
Surface Prep
Resistance
Max Svc Temp °F
Holiday Detector Voltage
Color
SSPC SP-
Hydrocarbon
Soil Stress
Hempel
Nap-Wrap Epoxy 8553
Thermostat Epoxy
225
125 V/Mil
Gray
10
Yes
Yes
Celcoat
Flakeline 251
Polyester Epoxy
160
4000V
White
10
Yes
Yes
Porter Int'l
Tarset MaxBuild 7080
Coal Tar Epoxy
140
3000V
Black
10
Yes
Yes
TIB Chemie
Protegal 32-10
Polyurethane
135
150 V/Mil
Black
5
Yes
Yes
TIB Chemie
Protegal 32-10RG
Polyurethane
180
150 V/Mil
Black
5
Yes
Yes
TIB Chemie
Protegal 32-50RG
Polyurethane
180
150 V/Mil
Red
5
Yes
Yes
Valspar
Valpipe 100
Polyurethane
160
125 V/Mil
Gray
5
Yes
Yes
Madison Chemical
Corropipe 2TX
Polyurethane
140
200 V/Mil
Black
5
No
No
Reilly Tar & Chemical
#230 A Enamel
Coal Tar Enamel
140
Black
6
No
No
Raychem
Flexclad
Black
3
No
No
Yellow
3
No
No
Canusa
Wrapid-Tape
Applied Tape
Applied Tape
1250
coating thickness ( mils )
1250
coating thickness ( mils )
1250
coating thickness ( mils )
135
135
Tapecoat
10/40W
Cold-Applied Tape
120
8,000 V
Black
2
No
No
Tapecoat
H-50
Cold-Applied Tape
120
6,500-8,500 V
Black
2
No
No
Tapecoat
CT
Cold-Applied Tape
120
7,000 V
Black
2
No
No
Polyguard
RD-6
Cold-Applied Tape
120
3,000-5,500 V
Black
2
No
No
Polyken
900 Series
Cold-Applied Tape
120
10,000 V
White
2
No
No
Denso
HT
Petrolatum Tape
120
Wet Spronge Jeep
Brown
2
No
No
Trenton
#1 Wax Tape
Petroleum Wax Tape
120
Wet Spronge Jeep
Brown
2
No
No
Chevron Corporation
900-47
September 1996
900 Pipeline Coatings
Coatings Manual
Fig. 900-30 Standards for Surface Preparation Description
SSPC
NACE Internt'l
Short
SP 1
—
Solvent Cleaning
SP 2
—
SP 3
—
SP 5
Foreign Standards Long
Canadian
Swedish
British
Removal of oil, grease, dirt, soil, salts, and contaminants by cleaning with solvent, vapor, alkali, emulsion, or steam.
—
—
—
Hand Tool Cleaning
Removal of loose rust, loose mill scale, and loose paint to a degree specified, by hand chipping, scraping, sanding, and wire brushing.
31 GP-401
St. 2 (Approx.)
—
Power Tool Cleaning
Removal of loose rust, loose mill scale, and loose paint to degree specified, by power tool chipping, descaling, sanding, wire brushing, and grinding.
31 GP-402
St. 3
—
NACE #1
White Metal Blast Cleaning
Removal of all visible rust, mill scale, paint, and foreign matter by blast cleaning by wheel or nozzle (dry or wet) using sand, grit, or shot. (For very corrosive atmosphere where high cost of cleaning is warranted.)
404 Type 1
Sa. 3
BS 4232 First Quality
SP 10
NACE #2
Near-White Blast Cleaning
Blast cleaning nearly to white metal cleanliness, until at least 95% of each element of surface area is free of all visible residues. (For high humidity, chemical atmosphere, marine or other corrosive environment.)
—
Sa. 2-1/2
BS 4232 Second Quality
SP 6
NACE #2
Commercial Blast Cleaning
Blast cleaning until at least two-thirds of each element of surface area is free of all visible residues. (For rather severe conditions of exposure.)
31 GP-404 Type 2
Sa. 2
BS4232 Third Quality
SP 7
NACE #4
Brush-off Cleaning
Blast cleaning of all except tightly adhering residues of mill scale, rust, and coatings, exposing numerous evenly distributed flecks of underlying metal.
31 GP404 Type 3
Sa. 1
Light Blast to Brush Off
SP 8
—
Pickling
Complete removal of rust and mill scale by acid pickling, duplex pickling, or electrolytic pickling. May passify surface.
—
—
—
•
Plastic coatings swell and eventually fail under prolonged exposure to hydrocarbons.
•
Hydrocarbons attack and dissolve the soft adhesive that holds plastic coatings to the pipe. Typically, soft adhesives have a lower resistance to hydrocarbon than the plastic jacket.
Ultraviolet (UV) Resistance. While all coatings degrade in sunlight, there are some practical solutions: •
September 1996
To prevent degradation of coatings on pipes that are stored outside, whitewash the coatings if they have poor UV resistance.
900-48
Chevron Corporation
Coatings Manual
900 Pipeline Coatings
Consult the manufacturer of the coating for recommended procedures for UV protection and for help with determining the condition of coated pipe already stored outside. If the degree of degradation is unknown in a stack of pipe, use unexposed pipe; as only the top and outside joints are exposed to UV rays. •
Plastic coatings, such as extruded and tape wrap, degrade in the sun, hardening and often splitting. Thermal expansion-and-contraction problems occur because plastic expands much more than steel.
•
FBE coatings chalk in sunlight, but the chalk protects the coatings. Millage loss is only a problem when rain and wind remove the chalk steadily for a long time. FBE coatings can also blister if stored too long in hot, humid climates such as is found in the Gulf Coast.
For information about the outdoor storage life and UV resistance for external pipeline coatings, see Figure 900-31. Resistance to Mechanical Damage. Coated pipe is subject to damage during handling, shipping, installing, or servicing. As a result, consider taking these preventive measures: •
Make the coating thicker to improve its resistance to mechanical damage.
•
Handle coated pipe with padded equipment, and stack and ship it with rubber spacers between each pipe. Set the spacers to separate the pipe far enough so that gravel and cinders thrown up from the road or rail tracks are not caught between pipes and abrade the coating.
•
Consider wrapping the pipe in plastic or installing pillowed supports.
•
Store the pipe on sand wind-rows and cover it with tarps.
See Section 921 of this manual, Selection, for information regarding Rock Protection. Cathodic Shielding. When a coating separates from a cathodically protected pipe, it can shield the pipe from the protection of the cathodic current. Significant localized corrosion occurs where earth or water (or both) becomes trapped between the separated coating and the pipe's surface. The current from cathodic protection does not increase to give a warning. The only way to determine the amount of corrosion on a cathodically shielded line is with metal-loss inspection tools which detect changes in the thickness of the pipe's wall. Note the following about cathodic shielding:
Chevron Corporation
•
Tape wraps are most susceptible because water has a greater chance of penetrating the overlaps (often poorly bonded and susceptible to soil stresses) and because they have high electrical resistivity.
•
Water can seep under continuous, extruded plastic coatings at field joints or mechanically damaged areas.
900-49
September 1996
900 Pipeline Coatings
Coatings Manual
Fig. 900-31 Pipe Storage and Ultraviolet (UV) Resistance Generic Type
Trade Names
Resistance
Storage Limit (Years)
Remarks
Asphalt Mastic
Somastic
Poor
1
Protect from sunlight.
Coal Tar Enamel
Reilly Tar and Chemical
Poor
1
Protect from sunlight.
Coal Tar Epoxy
International Tarset Maxi-Build 7080
Good
1
—
Cold-Applied Tapes
Tapecoat 10/40W, H-50, and CT Polyguard RD-6, Polyken 900 series
Poor
—
Normally applied in ditch and immediately buried.
Crosshead-Extruded Plastic with Asphalt Mastic
Bredero Price Entec Plexco Plexguard Shaw Yellow Jacket and Black Jacket
Fair
1
Fair except for Plexco Plexguard, which may be poor.
Fusion Bonded Epoxy (FBE)
3M 206N and 226N Nap-Gard 7-2501 and
Excellent
2
Excellent except in hot, humid sea atmospheres where blistering of coating occurs.
7-2504 (Gold) Lilly Pipeclad 1500 Valspar-D1003LD Heat-Applied Tapes
Canusa Wrapid Tape Raychem Flexclad
Poor
—
Normally applied in ditch and immediately buried.
Multi-Layer Extruded Plastic with FBE Primer
Elf Atochem Du Val Himont Mapec, Du Pont Canada
Excellent
2
—
Petrolatum Tapes
Denso MT
Good
—
Use as an atmospheric pipe coating.
Polyester Epoxies
Master Builder's Oilcote Flakeline 251
Excellent
—
Use as an atmospheric pipe coating.
Polyurethanes
TIB Chemie Protegal UT32-10 Valspar Valpipe 100
Excellent
—
Use as an atmospheric pipe coating.
Radiation Cross-Linked HeatApplied Tapes
Raychem Rayclad 120
Poor
1
Protect from sunlight.
Side-Extruded Polyethylene with Butyl Rubber Mastic
Bredero Price Pritec
Excellent
1
—
Thermoset Epoxies
Hempel Nap-Wrap Epoxy 8553
Excellent
—
Use as an atmospheric pipe coating.
Wax Tape
Trenton #1 Wax-Tape
Good
—
Use as an atmospheric pipe coating.
•
The adhesive strength of FBE (also a continuous coating) is greater than its cohesive strength, resulting in complete rupture of the film rather than disbonding[1].
Note Adhesive strength means metal to coating; cohesive strength means coating to coating. Cathodic Disbonding. Excessive currents can cause free hydrogen to form at holidays. Hydrogen bubbles form on and break away from the exposed pipe metal,
September 1996
900-50
Chevron Corporation
Coatings Manual
900 Pipeline Coatings
exerting high pressure between the coating and the metal. Pressure occurring under the edges of a damaged coating disbonds the coating from the pipe, exposing more metal. This phenomenon causes the rapid disbonding of an otherwise good coating. Note Excessive current are amounts that exceed the hydrogen-over-voltage potential. Note Holidays are minor areas of damage—breaks or flaws—in an applied coating. Run a laboratory test to determine the relative resistance of a coating to cathodic disbonding. While it is often difficult to relate laboratory results to field conditions, this particular test is an excellent tool for judging whether or not some coatings, such as FBE, have been applied properly. Example: A 24-hour, 150°F test for cathodic disbonding of FBE provides a good, quick check for undercure, under thickness, surface contamination, and poor surface preparation. Problems with the coating process show up as a sudden increase in the amount of coating that disbonds during the test. See also Section 6.0 of Specification COM-MS-4042.
Construction Factors Impact Resistance. Pipe coatings with high impact resistance are less likely to be damaged during transportation and construction. In general, resistance to impact decreases in this order: 1.
Extruded plastics with hard adhesives
2.
FBE
3.
Extruded plastics with soft adhesives
4.
Asphalt mastics
5.
Coal-tar enamel
Flexibility in Cold Weather. Coated pipe is sometimes bent in the field in weather conditions that make coatings more brittle. The Canadian Standards Association (CSA) Pipe Bend Test shows that FBE and extruded-plastic coatings with hard adhesives have the widest temperature range during construction of all pipe-coating systems. Both FBE and extruded-plastic coatings with hard adhesives pass the CSA Pipe Bend Test as they can survive bending during typical Canadian winter weather. Coal-tar enamels can, however, soften in warm weather and fail during the field-bending process. Field Repair. Some pipe coatings are harder to repair in the field than others. FBE is the easiest to patch. While extruded plastics with hard adhesives can be difficult to repair, manufacturers are making progress with these coatings. For information about recommended field repair methods, contact CRTC’s coating specialists (listed in the Quick Reference Guide) or review pipe-coating specifications.
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Coatings Manual
Limitations of Temporary Storage. Most pipe coatings have maximum storage limits depending on the climate of the storage area. Storage is usually a problem only if the pipe is coated and stored for longer than one year before construction starts. Climate during Construction Project. The climate during the construction project may affect coatings. •
Some coatings, such as coal-tar enamels and asphalt mastics, become soft and difficult to handle during hot weather.
•
See Flexibility in Cold Weather (above).
•
Some field-applied coatings have temperature dependent cure times.
Construction Methods during Project. Coatings for pipe laid in the ditch need to be less abrasion resistant than coatings for pipes used in trenchless construction techniques such as slick-bore, drilled, or pushed methods.
Application Factors The application factors that most often affect coating decisions are cost, site, and field support from the manufacturer and coatings applicator. Cost. The following project components affect cost: • • • • • • •
Size of project Coating materials Surface preparation Application Transportation Girth-weld coating (field joints) Field repairs
Balance the costs of the initial installation against the reliability expected. •
Select premium-quality coatings where failures are especially costly (e.g., subsea, congested areas, hard-to-access lines, and lines where leaks are intolerable).
•
Consider that less-expensive coatings are generally poorer in quality and tend to fail prematurely, resulting in higher maintenance costs and possible early corrosion failure of the line.
In Figure 900-32, there is a list of approximate costs for the various pipeline coatings. The cost of transporting pipe from the mill to the ditch can become significant for heavier coatings such as coal-tar enamels and Somastic. Site. While shop-applied coatings are inherently of higher quality than field-applied coatings, their handling costs are generally higher, and they are susceptible to shipping damage. For large coating projects, consider setting up portable coating plants near the job site to reduce costs, time, and potential shipping damage. You should also ensure
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Fig. 900-32 Costs (1988)—External Pipeline Coatings Material(1) Cost/Ft2 $
Coating (3)
Total Applied Ft(2)
Comments
(4)
10 ¾" OD 0.219" wall; 12 mil min. coating thickness
—
(4)
0.41
10 ¾" OD 0.219" wall; 14 mil min. coating thickness
—
0.36(4)
12 ¾" OD 0.219" wall; 14 mil min. coating thickness
—
—
(4)
12 ¾" OD 0.219" wall; 14 mil min. coating thickness
—
—
0.52-0.56
KLMR line bid range, 16 mil avg., 14 mil min. of polyethylene, 18" OD, 0.250" wall, 80,000 feet of pipe
—
0.42-0.48
KLMR line bid range, 10 mil adhesive, 40 mil of polyethylene, 18" OD, 0.250" wall, 80,000 feet of pipe
(Plexco P.E)
—
0.39
12
(Plexco P.P)
—
0.42
12
Coal Tar Enamel
—
0.45-1.00
Liquid Epoxies (Thermosets)
0.66
—
For 20 mils
0.80-0.90
—
Does not account for overlap
1.40
—
Does not account for overlap
2.00
—
30./weld
—
Includes delivery, cleaning, and application
Protegal 3210
6.00
—
25 mils
Denso Tape
0.65
—
Does not account for overlap
Porter Tarset
0.24
—
16 mils
Hempel
0.66
—
20 mils
Fusion Bonded Epoxy (FBE) — —
Extruded Plastic
—
0.38
0.38
(Pritec brand)
Tape Wrap; < 140°F Raychem Hotclad
Wide variation is due to application and locale. The $1.00/ft2 is for the Richmond Effluent Project, 5960 feet of 36" OD pipe
Field Coating of Weld Joints Shrink Sleeves FBE Valves and Fittings
Epoxy 8553 (1) Costs in this column where obtained from applicators without consideration of job size. These numbers do not take into account the cost of labor, surface preparation and plant location. (2) See Company's Cost Estimating Manual for additional cost information. (3) Material costs on small project of 16 mils; add 5 percent of cost for additional mils over 16. (4) Mesquite project; 168 miles of pipe.
that the pipe receives proper surface preparation and is neither dirty nor corroded when the coating is applied.
☞
Caution Consider over-the-ditch applications only when refurbishing old lines that cannot be taken out of service or for new lines at remote locations. Field Support from Manufacturer and Coatings Applicator. If construction delays occur due to coatings problems, determine the level of field support received from the manufacturer or coatings applicator or both.
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Inspection Refer to the coating specification for information about inspecting a given pipeline coating.
930 Internal Pipeline Coatings Pipe is coated on the inside to prevent corrosion or to increase the efficiency of flow by reducing losses from friction. There are other alternatives—cement and plastic linings—which are critiqued as a comparison to coatings in Figure 900-33 Internal Coating/Lining Alternatives for Pipelines. Fig. 900-33 Internal Coating/Lining Alternatives for Pipelines Material
Recommended Services
Advantages
Limitations
Approximate Cost(1)
Cement Lining
Produced water Salt water Almost always for new lines
Thick, usually very reliable against water corrosion
Joints are potentially a weak link, not good in many chemicals Min. pipe diameter: 2-3 inches Temp. approx. 250°F Pressure approx. 5,000 psig. Velocity approx. 10 fps
Shop = $1.60/ft
Plastic Liner (shop-applied)
Process chemicals
Excellent corrosion resistance to a variety of services
Typically comes in 20-ft flanged lengths Flange joints can leak Pipe diameter 1-16 inches Temp. approx. 200°F (PPL) to approx. 500°F (Teflon)
Include pipe and flanges = $80/ft (PPL) to $300/ft (Teflon)
Plastic Liner (field-applied) (HPDE)
Produced water Salt water New existing lines
Very reliable Very few joints Can salvage existing lines
Pipe diameter 3-16 inches (but larger sizes can be done) Temp. ± 200°F
$9.20/ft
Coatings (shop-applied)
Produced water Salt water Flow friction reduction
Fair to good corrosion resistance
Joints are potentially a weak link Relatively thin film (may give shorter, less reliable life)
Coatings (field-applied)
Produced water Salt water Flow friction reduction New or existing lines
Fair to good corrosion resistance
Good chance of field foul-ups Spotty history of quality control Relatively thin film (may give shorter, less reliable life)
(1) Except as noted, costs are for lining an 8-inch pipe at the shop location. Pipe costs extra. Costs are for rough comparative purposes only.
Note For detailed information about lining pipelines, see also the Company's Pipeline and Piping Manuals. Shop- or mill-applied coatings control corrosion of known aggressive systems or help reduce friction. Field-applied coatings primarily extend the service life of pipelines by preventing additional damage from corrosion. If internal damage from corrosion results in an unacceptable operating pressure, replace the pipeline or install a plastic liner to increase the pipeline's maximum operating pressure (MOP).
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931 Shop-applied Internal Pipeline Coatings This section discusses the following issues regarding shop-applied internal pipeline coatings: • • • • •
Quality control Coatings selection Surface preparation Application Inspection
Quality Control Specifications. Although the Company does not have a specification for internal pipeline coatings, information is available from CRTC specialists in M&EE. Coating Quality. If holidays occur, you should not repair FBE coatings and liquid coatings with a primer but you must burn the material off and recoat. You can patch FBE and liquid-epoxy coatings that do not have primers by following the manufacturers' recommendations. If the specification requires a 100-percent-holiday-free coating, the coatings applicators must make the pipe smooth enough, clean enough, and capable of being coated to this requirement. The Company's representative is responsible for specifying proper surface preparation.
Coatings Selection As liquid coating systems need a furnace bake, there is no known method to apply them to internal weld joints; therefore, there are two, basic, internal coating systems: heat-cured powder and baked-on liquid. Heat-cured Powder. The heat-cured powder is a thermosetting resin, applied by FBE process, with or without primer. Typically, select unprimed FBE for environments requiring improved flow efficiency or having mild internal corrosion, and primed FBE for environments with severe internal corrosion. Baked-on Liquid. Baked-on liquid may be epoxy, epoxy-phenolic, or possibly a polyurethane. For fresh water, saltwater, and production water at temperatures up to about 150°F, select straight epoxies such as O'Brien NapGard, Scotchkote 134, Scotchkote 206N, and Scotchkote 150. For very corrosive environments with higher temperatures (200°F to 400°F), choose epoxy-phenolic or epoxy-modified phenolics. Note
Phenolics tend to be brittle and will crack when bent.
For internal coating of girth welds in the field, the Company typically chooses Scotchkote 206N because it cures in less than one minute from the residual heat of the weld joint.
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The range for field-and-mill application of FBE is a 25- to 48-inch diameter and up to a maximum wall thickness of 0.750 inches.
Surface Preparation All pipe needs the same surface preparation: cleaning and abrasive blasting, followed in some cases, by priming. Cleaning. Chemical treatment is the best cleaning method, but costly disposal is a factor. Thermal burnoff at 600°F to 800°F is particularly important for a heavy mill scale/rust. Abrasive Blasting. Suitable abrasive is necessary to obtain the desired anchor profile and a white metal (SSPC SP5) finish. Finish is checked visually with a highintensity light. Priming. In water service, internal FBE does not usually require a primer; however, you should alert the coatings manufacturer if the water is aggressive (contains CO 2 or H2S, is hot, or at high pressure).
Application See the list of current contractors in the Quick Reference Guide.
Inspection Virtually all shops inspect and test internally coated pipe, for holidays, adhesion, and bends. Holidays. The inspector checks 100 percent of the coating against an agreed-upon standard (e.g., 100 percent holiday free, or 4 holidays maximum per length of pipe). Typical voltage is 100 to 125 volts per mil of coating thickness. Adhesion. Typically, the inspector cuts an x pattern into the coating and prods it with a knife to check adhesion. The inspector conducts the test every two hours on the weld cutback area of a section of pipe that is left deliberately unmasked for this test. Bends. Typically, once per shift, often at a cool temperature, the inspector tests the flexibility of the coating by bending a strip of coated metal over a specified mandrel and checks it for holidays and cracks.
932 Field-applied Internal Pipeline Coatings Liquid epoxy is the only internal coating that the Company field applies (in situ), generally for one or more of the following reasons: • • •
To prolong the life of a line For product purity To reduce friction loss
Brands of field-applied, internal pipeline coatings include Hempel 233U, Hempel 458U, Sigma In-Situ Pipecoating 15, Sigmaguard HTR.
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Factors affecting field-applied coating are its limitations, the coating contractors and applicators, acceptable brands, surface preparation, application, and inspection.
Limitations Field application of internal pipeline coatings is less likely to produce pinhole-free coatings than shop-applied systems. Field application is also unsuccessful with slip-on flanges because the ID discontinuity at the pipe ends causes excess coating deposits which rapidly disbond in shingles to plug the line or create a site for corrosion.
Coating Contractors and Applicators Select coating contractors and applicators carefully because they can have a profound affect on the success of a project. Improperly applied coatings may result in inadequately protected lines, delays in returning the line to service, and complete loss of the line. Before choosing a coatings applicator, review in detail the work history (resume) of the foreman and personnel proposed for the job. See the list of contractors who field-apply pipeline coatings in the Quick Reference Guide.
Acceptable Brands Sigma Coatings In-Situ Pipecoating 15 and Hempel 233U have longer pot lives, but Sigmaguard HTR and Hempel 458U have better high-temperature resistance. All products have the same chemical resistance. Note For more detailed background on field-applied coatings, see the references at the end of this section [16, 17, 18, 19, 20, 21].
Surface Preparation Prepare an internal steel pipe by cleaning it in one of two ways: • •
Inhibited acid Abrasive blasting
Existing pipelines may also require initial cleaning by scraper pigs and with solvents.
Application See list of current contractors for pipeline coatings in the Quick Reference Guide.
Inspection Compared to shop-applied internal coatings, inspection of field-applied internal coatings is relatively crude. The inspector often visually examines a flanged, removable spool located near the middle of the line and also tests it for holidays and thickness. Video cameras allow full-length inspection of the line for pipe sizes as small as 10 to 12 inches in diameter.
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933 Weld-joint Application & Inspection In Figure 900-34, Properties of Internal Pipeline Coatings, a method of weld-joint protection is recommended for each coating system, where applicable. Fig. 900-34 Properties of Internal Pipeline Coatings System
Recommended Services
Advantages
Limitations
Weld Joint Protection
Shop-Applied Heat-Cured Powder: Epoxy with Primer
Sour water Wet sour gas (CO2 up to 10%) Inspection and disposal wells
Good corrosion resistance
Resistant to low concentrations of H2S Girth weld cannot be coated
Mechanical joints
Epoxy without Primer
Produced water Fresh water Salt water (CO2 up to 10%)
Can coat girth weld with crawler Fair corrosion resistance
Low resistance to H2S
≥ 8-inch pipe diameter: crawler < 8-inch pipe diameter: mechanical joints
Sizes up to 20 inches: very low flexibility Temp. ± 150°F Cannot repair holidays
Mechanical joints
Cannot bend Maximum pipe diameter: 20 inches Temp. ± 400°F Cannot repair holidays
Mechanical joints
High chance of foul-up if wrong contractor has job
Does not apply
Baked Liquid: Epoxy
Produced water Fresh water Salt water
Epoxy-Phenolic
Sour water Wet sour gas (CO2/H2S)
Good corrosion resistance
Field-Applied In situ: Liquid Epoxy
Sour water Produced water Fresh water Salt water Flow friction reduction Gas lines
Good corrosion resistance High temp. service (+200°F) Extends serviceable life of existing line
Application The crawler is the method for applying internal pipeline coating systems. Mechanical joints are also available as an alternative for 2- to 12-inch-sized pipes. Crawlers. A self-propelled, in-line tool that performs a task under remote control, the crawler works in either field or shop. For the latter, that means that the shop can join pipe lengths to reduce the number of field-welded joints. Currently, the minimum pipe diameter for a crawler is ten inches. Some of the crawler's coating tasks are as follows:
September 1996
•
For non-primed FBE internal coatings, crawlers clean and coat the girth welds.
•
After welding, an abrasive-blasting crawler travels through the pipe to clean the cutback area of weld splatter slag and to degloss the powder.
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•
An induction coil, applied to the pipe's exterior, heats the girth weld area and a powder-coating crawler then travels through the pipe.
There are basically two circumstances under which shop or field coatings applicators cannot use a crawler: • •
The pipe requires a liquid primer or coating The pipe diameters are less than ten inches
Mechanical Joints. One alternative to the crawler is mechanical joints. There are at least a dozen mechanical joint systems that provide a continuous internal seal. Some, such as Crimp-Kote from Tuboscope Vetco International, are fully mechanical interference-fit joints. Some are elaborate mechanical sleeve systems, which may include welding. Most require special equipment for field installation. Mechanical joints are usually available in 2- to 12-inch sizes.
Inspecting Internal Pipeline Coatings Inspection varies with the coating material and the application method. For information about inspecting internal pipeline coatings, contact CRTC's specialists listed in the Quick Reference Guide.
940 References
Chevron Corporation
1.
O'Carroll, B. M., “The Performance of Pipe Coatings in Relation to Cathodic Protection,” 5th International Conference on the Internal and External Protection of Pipes, Innsbruck, Austria, October 25-27, 1983.
2.
Materials Laboratory Report, 150°F Cathodic Disbondment Tests of Pipeline Coatings, C.A. Shargay, September 17, 1982, File No. 6.55.5.
3.
Article, What's New in Distribution/Transmission Pipeline Coatings, Ron Sloan.
4.
Materials Laboratory Report, Rangley CO2 Pipeline Coating Tests, J. H. Kmetz, File: 6.55.75, December 21, 1984.
5.
Davis, J. A. and Thomas, S. J., “Properties and Application Procedures for Polyethylene Tape Coating Systems,” Pipeline, April 1985, p. 6.
6.
Materials Laboratory Report, Sudan Pipeline Coatings - Tape Wrap Tests, L. J. Klein, File 6.55.50.
7.
Materials Laboratory Report, Aramco Mastic Tape Tests, Final Report, C. A. Shargay, File 6.55.50, April 27, 1983.
8.
Choate, L. C., “New Coating Developments, Problems, and Trends in the Pipeline Industry,” Materials Performance, April 1975.
9.
O'Donnell, John P., “Coal-Tar Enamel Resins: Most-Preferred Pipe Coating,” Oil and Gas Journal, July 6, 1981.
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10. Ward, D. K., Moore, D. E., and Hawkins, P. J., “External and Internal Pipeline Coatings in the Arabian Gulf Area,” 5th International Conference on the Internal and External Protection of Pipes, Innsbruck, Austria, October 25-27, 1983, Paper C3. 11. Chevron Pipe Line Company Memo, Field Joint Coatings from P. T. Groff to R. G. Lueders, July 1, 1987. 12. Memo to CRTC File, Bakersfield Experience with Extruded Plastic Control Pipe, E. H. Niccolls, File 6.55.15, May 24, 1990. 13. Materials Laboratory Report, KLM Pipeline Reclamation Trial Coatings, K. K. Kirkham, File 6.55.15, January 4, 1984. 14. Materials Laboratory Report, KLM Pipeline Reclamation Trial Coatings, B. J. Cocke, File 6.55.15, October 25, 1983. 15. Materials Laboratory Report, Hot Subsea Pipeline Coatings Disbonding Tests, N. E. Daley, File 6.55.30, December 27, 1988. 16. E.H.Niccolls, InSituInternalPipelineCoatings, Materials Laboratory File N28.15, July 17, 1981. 17. S. E. Pfeiffer, “Fusion Bond Coated Girth Welds, External/Internal,” Corrosion 83 Paper 117, NACE International. 18. P. J. Bryant, “Internal In-Place Pipe Coating,” Pipeline Gas Journal, Volume 214, Pages 17-18, February 1987. 19. S. V. Daily, “An Alternative Surface Preparation Procedure for the Application of Internal In-Situ Pipeline Coating,” Corrosion 88 Paper 308, NACE International. 20. S. Selinek, “In Situ Internal Coating of Pipelines—North Sea Experience,” Corrosion 90 Paper 254, NACE International. 21. R. E. Carlson, Jr., “Internal Lining of Pipeline Weld Joints,” Material Performance, Volume 31, Number 9, pages 46-49, September 1992. 22. Dr. J. M. Leeds, “A High-temperature (120°C) Gas Pipeline CoatingRefurbishment Programme, Using High-solids Epoxy,” Pipeline Risk Assessment, Rehabilitation and Repair Conference, Houston, Texas, May 20-23, 1991. 23. P. Barrien, S. E. McConkey, M. A. Trzecieski, “Coating Evaluation Program for 116°C Service Temperature,” Corrosion 84 Paper # 358, NACE International, New Orleans, Louisiana, April 1984. 24. John Bethea and Adel Botros, “A New Approach to Fusion Bonded Epoxy Coatings for Pipeline Protection,” API Pipeline Conference, April 1994. 25. NAPCA Bulletin 1-65-91, “Recommended Specification Designations for Coat Tar Enamel Coatings.”
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26. NAPCA Bulletin 2-66-91, “Standard Applied Pipe Coating Weights for NAPCA Coating Specifications.” 27. NAPCA Bulletin 3-67-91, “External Application Procedures for Hot Applied Coal Tar Coatings to Steel Pipe.” 28. NAPCA Bulletin 6-69-90-1, “Suggested Procedures for Hand Wrapping Field Joints Using Hot Enamel.” 29. AWWA Standard C-203, “Coal-tar Protective Coatings and Linings for Steel Water Pipelines - Enamel and Tape Hot Applied.” 30. AWWA Standard C-213, “Fusion-bonded Epoxy Coating for the Interior and Exterior of Steel Water Pipelines.”
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Quick Reference Guide Contents
Page
Introduction
QR-2
Company Contacts
QR-3
CRTC’s Coatings Specialist Facilities for Analyzing Lead in Coatings Coating Manufacturers Suppliers Steps to Coating System Selection
QR-7
System Number Selection Guide
QR-8
Atmospheric Coatings for On- & Offshore Coatings for Concrete Coatings Under Insulation & Fireproofing Internal Vessel Coatings Coating Compatibility Chart
QR-11
Coating System Data Sheets
QR-12
Available System Data Sheets System Data Sheets Acceptable Brands by Generic Classification Acceptable Brands by Manufacturer
Chevron Corporation
QR-1
May 1998
Introduction
Coatings Manual—Quick Reference Guide
Introduction This Quick-Reference Guide from Chevron’s Coatings Manual has been designed to give you easy access to the selection process for certain types of coating projects: •
Atmospheric (both on- and offshore)
•
Concrete (mild environment only)
•
Internal vessel
•
Under insulation and fireproofing
By following the coating selection process, you will find a system data sheet which details the specifications and approved manufacturers for the coatings that fit your project. (See sample system data sheet below.) The design of the data sheet simplifies your preparation of a selection-and-specification package for a coating contractor: just photocopy the appropriate data sheet(s) and specification(s). Sample of a System Data Sheet Coatings Manual
Chevron Corporation
SYSTEM DATA SHEET
Two-Component Systems Self-Cured Inorganic Zinc | High-Temperature Silicone Surface Prep:
SSPC-SP10 (NACE No. 2) Near-white blast finish.
2.4
Touch Up: Use pure silicone topcoat only, two coats.
Anchor Pattern: 1.5 - 2.5 mils Total DFT (min) 4.5 mils Coat, Generic Classification, DFT
PRIMER Self-Cured Inorganic Zinc - Solvent Reducible 2.0 - 3.0 mils DFT
Manufacturer Ameron Ameron Ameron Carboline Carboline Dampney Devoe Hempel Hempel International PPG Industries Sherwin Williams Sherwin Williams Sigma Valspar
Product Designation Dimetcote 21-9 Dimetcote 6 Dimetcote 9 Carbozinc 11 Carbozinc 11 HS Thurmalox 245C Silicone Zinc Dust Primer Catha-Coat 304V Galvosil 1570.3 Galvosil 1578 Interzinc 311 Metalhide 1001 Primer 97-673/97-674 B69VZ1/B69VZ3/B69D11 Zinc Clad II B69V11/B69D11 Tornusil MC 58 7558 V13-F-12
VOC (G/L)
By Max Svc Temp
• 293 500 506 515 • 264 413 • 336 • 340 520 530 397 • 312 462 528 • 324
» Keep inorganic zinc silicate mixed, using agitated pot while applying.
TOPCOAT Silicone - High Temp Rated to 700°F 1.5 - 2.5 mils DFT
Ameron Carboline Dampney Devoe Hempel Hempel International PPG Industries Sherwin Williams Sherwin Williams Sigma Valspar
PSX 892HS Thermaline 4631WB Thurmalox 230C* HT-12 5690 5691 Intertherm 230 Pittherm High Heat Silicone Aluminum 100-A-518 Black 880-B-001 Sigmatherm 5267 37-A-1
• 324 • 108 360 572 400 586 612 554 420 514 600 599
» Non-catalyzed silicones remain tacky until exposed to heat above 300°F to 400°F. * Thumalox 230C topcoat will go over ONLY Thurmaloc 245C Silicone Zinc Dust Primer.
• VOC at or below 340 g/l is the anticipated regulatory limit. Check local standards for current VOC limits. Consult manufacturer's product data sheets for specific details about applying any coating. May 1998
Last Update:
5/15/98
Page 15
Note The system data sheets outnumber the references to coating systems in the selection criteria because Chevron has many coating systems in use. Do not choose a coating system unless you have been directed to do so by following either: •
The selection guide in this publication.
•
Instructions from one of the Company’s coating specialists or a coating manufacturer.
Also included in this Guide, the Coatings Compatibility Chart is a resource for projects involving maintenance coatings. For questions about the Guide, contact the CRTC specialists listed on the Contacts page.
May 1998
QR-2
Chevron Corporation
Coatings Manual—Quick Reference Guide
Introduction
Company Contacts CRTC’s Coatings Specialist Rich Doyle
CTN 242-3247
Atmospheric, Concrete, Internal Vessel Coatings, Downhole Tubular Coatings, Pipeline Coatings
Other Company Contacts Corporate Identity Colors
Company Identity Center, Corporation Public Affairs Department—CTN 894-0260
Chevron Color Chips
Additional copies from Technical Standards—CTN 242-7241
CRTC Environmental Resource
CTN 242-5696
CRTC Mat'ls & Equip. Engineering
CTN 242-3247
Facilities for Analyzing Lead in Coatings Clayton Environmental Consultants
800/294-1755
22345 Roethel Drive
Novi
MI
48375
Forensic Analytical Specialties
800/827-3274
3777 Depot Road, Suite 409
Hayward
CA
94545
Coating Manufacturers Manufacturers of Atmospheric and Internal Vessel Coatings Ameron
714/529-1951
201 North Berry Street
Brea
CA
92621
Ashland Chemical
800/643-1234
1851 E. First Street, #700
Santa Ana
CA
95705-4017
Carboline
314/644-1000
350 Hanley Industrial Court
St. Louis
MO
63144
Ceilcote
216/831-5500
23700 Chagrin Boulevard
Cleveland
OH
44122
Dampney Company, Inc.
617/389-2805
85 Paris Street
Everett
MA
02149
Devoe
502/897-9861
4000 Dupont Circle
Louisville
KY
40207
Dudick
216/562-1970
1818 Miller Parkway
Streetsboro
OH
44241
Glidden
216/344-8000
925 Euclid Avenue
Cleveland
OH
44115
Hempel
713/672-6641
6901 Cavalcade
Houston
TX
77028
International
800/525-6824
P. O. Box 4806
Houston
TX
77210-4806
PPG (Attn Dave Landry)
713/944-8550
P. O. Box 5772
Pasadena
TX
77502
Sherwin Williams
800/321-8194
101 Prospect Avenue NW Corporate Offices
Cleveland
OH
44115
Sigma
504/347-4321
1401 Destrehan Avenue
Harvey
LA
70058
Southern Coatings
800/845-0487
P.O. Box 160
Sumpter
SC
29151
Tempil
908/757-8300
2901 Hamilton Boulevard
So. Plainfield
NJ
07080
Valspar
800/638-7756
1401 Severn Street
Baltimore
MD
21230
Wisconsin Protective Coatings
414/437-6561
614 Elizabeth Street
Green Bay
WI
54302
Manufacturers of Concrete Coatings Dudick (Attn: Customer Service)
800/322-1970
P.O. Box 2550
Streetsboro
OH
44241
KCC Corrosion Control Co. (Attn: Sales Engineer)
800/395-5624
4010 Trey Road
Houston
TX
77084
Master Builders (Attn: Technical Support)
800/821-3582
23700 Chagrin Boulevard
Cleveland
OH
44122-5554
Sauereisen (Attn: Technical Service)
412/963-0303
160 Gamma Drive
Pittsburgh
PA
15238-2989
Sentry Polymers (Attn: Technical Support)
800/231-2544
P.O. Box 2076
Freeport
TX
77541
Chevron Corporation
QR-3
May 1998
Introduction
Coatings Manual—Quick Reference Guide
Sika (Attn: Technical Service)
800/933-7452
12767 E. Imperial Highway
Santa Fe Springs
CA
90670
Stonhard
800/854-0310
1 Park Avenue
Maple Shade
NJ
08052
Wisconsin Protective Coatings (Attn: Technical Service)
414/437-6561
614 Elizabeth Street
Green Bay
WI
54308-8147
TX LA LA
77060
Manufacturers of Pipeline Coatings 3M
Albert Schupbach
512/984-5683
Canusa
Ben Medley Hank Reuser
713/367-8866 713/974-7211
Carboline
John Montle
314/644-1000
Denso
(Carboline markets) 713/821-3355
DuVal
Trevor McClery
416/284-1681
DuPont Canada
Jamie Cox
416/338-3764
Elf Atochem
Igor Leclere
215/419-5610
Hempel
Michael Bentkjaer
713/672-6641
Lilly
Mark Schaneville
334/365-9454
Montell (Himont)
Ed Phillips
302/996-6236
OBrien Nap-Gard
John Bethea Sherill Miller
713/939-4000 713/939-4000
Polyguard
Bob Nee
918/749-3634
Polyken
Grover Marshall Bob Hayes
918/627-3635 510/284-1515
Power Marketing Group
James Power
303/741-3993
Raychem
Shiv Kumar Walt Greuel Joseph Merket
619/482-8306 619/482-8302 415/361-4095
Reilly Coal Tar
John Johnson
317/247-8141 (ext. 6771)
Sigma Coatings
Lou Cucker
800/221-7978
Tapecoat
John Ward
704/896-7803
Trenton
Thomas Weber
713/556-1000
Valspar
Trevor McClery
416/284-1681
Manufacturers of Pipeline Coating Applicators Bayou Pipe Coating Co
713/591-1614 (F) 713/591-0284
450 N. Sam Houston Parkway East #232 Plants:
Houston Baton Rouge New Iberia
Bredero Price International, Inc. (Domestic USA)
713/ 974-7211 (F) 713/260-4500
7211 Regency Square Bl. St. 104 Houston Plants: Fontana Harvey Pearland
TX CA LA TX
77036
Bredero Price International, Inc. (Foreign)
713/999-2600 (F) 713/999-6189
250 North Belt, Suite 220 Plants:
TX
77060
May 1998
QR-4
Houston Australia Indonesia Malaysia Nigeria Scotland Singapore U.A.E.
Chevron Corporation
Coatings Manual—Quick Reference Guide
Introduction
Commercial Coating Services, Inc. (CCSI)
409/539-3294 (F) 409/539-3073
Post Office Box 3296 Plants:
Conroe Bakersfield Conroe
TX CA TX
77305-3296
Commercial Resins Co.
918/438-6522 (F) 918/437-5410
2001 North 170th East Avenue Plants:
Tulsa Napa Valley Tulsa
OK CA OK
74116
Compression Coat, Inc.
713/353-8597 (F) 409/756-8599
3513 N. Frazer Conroe Plants: Uses portable equipment
TX
77303
Energy Coatings Co. (Encoat)
Now Bredero Price International, Inc.
Shaw Pipe, Inc.
713/367-8866 800/SHAW PIPE (800/742-9747) (F) 713/367-4304
TX
77380-1038
2408 Timberloch Place, Bldg C-8 The Woodlands Plants: Australia Canada New Iberia
LA
Suppliers Suppliers of Coated Tubing and Accessories Baker Hughes Tubular Service
(USA: Now owned by ICO, Inc.) (Overseas: Now owned by Tuboscope Vetco International)
Tuboscope Vetco Int’l
713/799-5100 (F) 713/799-5183
P. O. Box 808
Houston
TX
77001
ICO, Inc.
713/872-4994 (F) 713/872-9610
100 Glenborough, Suite 250
Houston
TX
77067
Shield Coat, Inc.
504/879-3539 (F) 504/868-3173
Station 1, Box 10185
Houma
LA
70363-5990
Midland
TX
79702
Great Bend
KS
67530
Suppliers of Cement Linings Permian Enterprises, Inc. (now owned by ICO Inc.)
915/683-1084 (F) 915/683-1319
P. O. Box 2745
Suppliers of Fiberglass Linings Rice Engineering Corp
800/533-5480 316/793-5483 (F) 316/ 793-5521
1020 Hoover
Suppliers of PVC Linings Rice Engineering Corp
800/533-5480 316/793-5483 (F) 316/ 793-5521
1020 Hoover
Great Bend
KS
67530
Sealtite
800/835-0133 (F) 316/331-6832
P. O. Box 965
Independence
KS
67301
Chevron Corporation
QR-5
May 1998
Introduction
Coatings Manual—Quick Reference Guide
Suppliers of Pipeline Coatings Canusa
713/367-8866 (F) 713/292-8571
2408 Timberlock Pl., Bdg C-8
The Woodlands
TX
77380-1038
Denso North America Inc.
713/821-3355 (F) 713/821-0304
18211 Chisholm Trail
Houston
TX
77060
DuPONT Canada, Inc. Modified Polymers Division
519/862-5700 (F) 519/862-5880
Albert Street
Corunna, Ontario
N0N 1G0 Canada
Elf Atochem
215/419-7000
2000 Market Street
Philadelphia
PA
19103-3222
North America Inc.
(F) 215/419-5305
Hempel Coatings (USA), Inc.
800/678-6641 (F) 713/674-0616
6901 Cavalcada
Houston
TX
77028
Kop-Coat Carboline Co.
314/644-1000 (F) 314/644-4617
350 Hanley Industrial Court
St. Louis
MO
63144-5199
Lilly Powder Coatings, Inc.
816/421-7400
1136 Fayette North
Kansas City
MO
64116
Pipe Clad Products Div
(F) 816/421-4563
3M Company
512/984-1800 (F) 512/984-3556
6801 River Place Boulevard
Austin
TX
78726-9000
Madison Chemical Industries, Inc.
905/878-8863 (F) 905/878-1449
490 McGeachie Drive
Milton, Ontario
L9T 3V5 Canada
Nap-Gard Pipe Coatings O’Brien Powder Products, Inc.
713/939-4000 (F) 713/939-4027
9800 Genard Street
Houston
TX
77041
Polyguard Products, Inc.
214/875-8421 (F) 214/875-9425
P. O. Box 755
Ennis
TX
75119
Polyken Technologies Kendall Co.
508/261-6200 800/248-7659 (F) 508/261-6271
15 Hampshire Street
Mansfield
MA
02048
Power Marketing Group, Inc.
303/741-3993 (F) 303/ 741-2548
6416 South Quebec St, Ste 41
Englewood
CO
80111
Raychem Corp., Ultratec Div.
619/482-8300 (F) 619/ 482-2813
1670 Brandywine Avenue
Chula Vista
CA
91911
Reilly Industries, Inc.
317/ 247-8141 (F) 317/248-6402
1500 South Tibbs Avenue
Indianapolis
IN
46241
Royston Laboratories, Chase Corp
412/828-1500 800/245-3209
128 First Street
Pittsburgh
PA
15238
Tapecoat Co., TC Manufacturing Co., Inc.
847/866-8500 (F) 708/866-8596
1527 Lyons Street
Evanston
IL
60201-3551
Valspar Inc.
416/284-1681 (F) 416/284-6549
645 Coronation Drive
West Hill, Ontario
M1E 4R6 Canada
Suppliers of Inspection Tools Paul N. Gardener Co., Inc.
954/946-9454 316 NE First Street (F) 954/946-9309 or -9375
Pompano Beach
FL
33060
KTA-Tator Inc.
412/788-1300
Pittsburgh
PA
15275
May 1998
115 Technology Drive
QR-6
Chevron Corporation
Coatings Manual—Quick Reference Guide
Introduction
Steps to Coating System Selection
Start
No
Type of Coating: Atmospheric Coating? Concrete Coating (Mild Environment)? Internal Vessel Coating?
Contact a CRTC Coating Specialist Yes
System Number Selection Guide Choose a system number by type of surface, service, voc units.
System Data Sheets
Locate the correct data sheet by system number
No Coating over an existing system?
Yes
No
Yes Compatibility Chart: Compatible?
Photocopy Coating System Fact Sheet. Attach to spec.
End
Chevron Corporation
QR-7
May 1998
System Number Selection Guide
Coatings Manual—Quick Reference Guide
System Number Selection Guide Note Pick a coating system number from one of the following tables then find that number in the System Data Sheets for Coating Systems. For coatings under insulation & fireproofing, see chart next page Atmospheric Coatings for On- & Offshore (1 of 2) Onshore Std
Type of Equipment
Hi Perf
Offshore
Code C/E: Vessels & Heat Exchangers Uninsulated below 200°F
2.2
3.1
3.1
Uninsulated to 200°F and steamed out
2.6
3.1
3.1
Uninsulated 200–600°F
N/R
2.4
2.4
Uninsulated 300-600°F
2.4
N/R
N/R
Uninsulated to 200°F
2.2
3.1
3.1
Wind girders
2.2
Floating roofs (Uninsulated)
2.6
3.1
N/R
Stairways & railings
2.2
Code D: Tanks
Code F: Furnaces Structural steel & platforms
2.6
2.6
Stacks, breeching, furnace body to 600°F
2.4
2.4
N/R Code G/K: Pumps, Turbines, Compressors & Drivers Uninsulated to 200°F
N/R
3.8
3.8
Uninsulated 200–600°F
2.4
2.4
2.4
3.8
3.8
N/R
1.4
2.2
2.6
3.1
N/A
N/A
N/R
N/R
Motors N/R Externally insulated exhaust ducts Code J: Instruments Field instrument panels (steel) Weatherproof housings (steel)
3.1
Instrument tubing (stainless) N/R Instruments (galvanized or aluminum)
Code L: Piping (including Valves & Fittings)
May 1998
Uninsulated to 200°F
2.2
3.1
3.1
Uninsulated below 200°F steamed out
2.6
3.1
3.1
Uninsulated 200–600°F
2.4
2.4
2.4
QR-8
Chevron Corporation
Coatings Manual—Quick Reference Guide
System Number Selection Guide
Atmospheric Coatings for On- & Offshore (2 of 2) Onshore Std
Hi Perf
Offshore
Concrete
N/R
N/R
N/R
Exposed steel, platforms, ladders, supports
2.2
3.1
3.1
Floor plate (smooth)
4.6
4.5
4.5
Galvanized floor grating repairs
1.6
1.6
1.6
Type of Equipment Code M: Structural
Galvanized stairways and railings
N/A
Jacket above splash zone; deck modules; boat landing
3.1
Jacket splash zone - structural members
4.2
Jacket splash zone - appurtenances
N/A
N/A
Risers, conductors: splash zone below 140°F not pressure treated
4.1
Risers, conductors: splash zone to 160°F
4.3
Risers, conductors: splash zones to 250°F
4.2
Code P: Electrical Equipment Galvanized or aluminum
N/R
N/R
N/R
Steel
2.2
3.1
3.1
Code R: Buildings and Control Houses (Exterior) Galvanized steel N/R
N/R
Steel
2.2
2.6
Wood
N/R
N/R
Masonry walls N/A
Code S: Miscellaneous Equipment Subsea completion equipment Standard: High Performance:
N/A
N/A
8.4 11.4
Coatings for Concrete Coating System by Exposure Item Oil/water Separator Secondary Containment
Temperature
Environment
< 140°F
Oil/water mixture
< 140°F
(2)
Hydrocarbons, caustics
dilute acids,
Physical Abuse
Continuous
Intermittent
Moderate(1)
20.1
N/A
(1)
20.2
20.2
20.1
20.1
Aggressive
20.3
20.3
(4)
N/A
20.2
Mild
Moderate(1) (3)
Equipment Foundations (1) (2) (3) (4)
< 140°F
(2)
Hydrocarbons , dilute acids, caustics
Mild
Moderate coating loss due to abrasion, light equipment wear. Possibility of impact on coating. Crude oil, jet fuel, gasoline, etc. Severe coating loss due to abrasion, heavy equipment wear. Definite potential for impact on coating. No coating loss due to abrasion, possible light foot traffic. No physical impact on coating
Chevron Corporation
QR-9
May 1998
System Number Selection Guide
Coatings Manual—Quick Reference Guide
Coatings Under Insulation & Fireproofing Substrate Carbon Steel
Temperature(1)
Exposure to Temperature
Coating System
Continuous
-50°F to 140°F
12.1
Continuous
140°F to 300°F
12.2
Cyclic (produce wet/dry conditions)
Stainless Steel
12.3
Continuous
Above 300°F
Do not coat
Special Conditions
Above 300°F
12.7
Continuous
-50°F to 140°F
12.4
Continuous
140°F to 300°F
12.5
Cyclic (produce wet/dry conditions)
12.6
Continuous
Above 300°F
12.7
(1) Actual temperature of steel not design temperature.
Internal Vessel Coatings High Temperature/Pressure
Non-Reinforced Thin Film
Reinforced Glass Flake
Laminate
Fresh Water
8.1
9.1
10.1
Demineralized Water
8.2
9.2
10.2
Potable Water
8.3
9.3
N/R
Salt Water & Brine
8.4
9.4
Produced Water
8.5
Crude Oil (sweet or sour)
High Temperature/ Cathodic
High Temperature/ Non Cathodic
11.2
11.2.1
10.4
11.4
11.4.1
11.4.2
9.5
10.5
11.5
11.5.1
11.5.2
8.6
9.6
10.6
11.6
11.6.1
11.6.2
Fuels (low aromatic)
8.7
9.7
10.7
Fuels (high aromatic)
8.8
9.8
10.8
Aromatic Hydrocarbon
8.9
9.9
10.9
Acetone
8.10
Ethyl & Methyl Alcohol
8.11
Services
High Pressure/ Non Cathodic
N/R
May 1998
QR-10
Chevron Corporation
Coatings Manual—Quick Reference Guide
Coating Compatibility Chart
Coating Compatibility Chart
Epoxy Mastic
Inorganic Zinc
Lacquer
Latex Emulsion
Phenolics
Polyamide Epoxy
Polyurethane
Silicone Alkyds
Vinyls
Vinyl Acrylic
Wash Primers
YES 3
N/R
YES 3
N/R
YES
N/R
YES
YES
YES
YES 3
YES 3
YES
YES
YES
YES
Amine Epoxy
N/R
YES 2
N/R
YES 2
N/R
N/R
YES
N/R
N/R
N/R
YES
YES 2
N/R
N/R
N/R
YES
Asphalt Mastic
YES
N/R
YES
N/R
YES
N/R
YES
N/R
YES
YES
N/R
N/R
YES
N/R
N/R
YES
Chlorinated Rubber
N/R
YES 3
N/R
YES 3
LTD
YES
YES
N/R
YES
YES
YES 3
YES 3
N/R
YES
YES
YES
Coal Tar Paints
N/R
N/R
N/R
N/R
YES
N/R
YES
N/R
YES
LTD
N/R
N/R
N/R
N/R
N/R
YES
Epoxy Mastic
YES
YES
YES
YES
YES
YES
YES
YES
YES
YES
YES
YES
YES
YES
YES
YES
Inorganic Zinc
N/R
N/R
N/R
N/R
N/R
N/R
YES
N/R
N/R
N/R
N/R
N/R
N/R
N/R
N/R
N/R
Lacquer
N/R
YES 1
N/R
YES 1
N/R
N/R
LTD
YES
YES
N/R
YES
LTD
N/R
YES
N/R
YES
Latex Emulsion
YES
YES 3
YES
YES 3
YES
YES
YES
YES
YES
YES
YES 3
YES 3
YES
YES
YES
YES
Phenolic
YES
YES
N/R
YES
N/R
YES
LTD
YES
YES
YES
YES
YES
YES
YES
YES
YES
Polyamide Epoxy
LTD
YES
N/R
YES
N/R
LTD
YES
N/R
N/R
LTD
YES
YES
LTD
N/R
N/R
YES
Polyurethane
N/R
YES 2
N/R
YES 2
N/R
N/R
YES
N/R
YES
N/R
YES
YES 2
N/R
N/R
N/R
YES
Silicone Alkyd
YES
YES 3
N/R
YES 3
N/R
YES
YES
YES
YES
YES
YES 3
YES 3
YES
YES
YES
YES
Vinyl
N/R
N/R
LTD
N/R
LTD
N/R
YES
N/R
YES
N/R
N/R
N/R
N/R
YES
YES
LTD
Vinyl Acrylic
LTD
YES
N/R
YES
LTD
YES
YES
N/R
YES
LTD
YES
YES
YES
YES
YES
YES
Wash Primers
N/R
N/R
N/R
N/R
N/R
N/R
YES
N/R
N/R
N/R
N/R
N/R
N/R
N/R
N/R
N/R
Asphalt Mastic
YES
Amine Epoxy
Alkyd
Coating Being Applied
Alkyd
Coal Tar Paint
Chlorinated Rubber
Coating Being Overcoated
Notes: YES: Applied coating will not lift, wrinkle, blister; will have reasonable bond; check in field with a test patch. LTD: Some formulae are compatible; some not. Consult manufacturer. N/R: Not recommended 1 Durability and use depend on type of lacquer. 2 Must apply topcoat before coated surface has hardened. 3 Gloss on paint being overcoated must be removed by weathering or sanding. 4 Topcoat may blister if high-solvent topcoat applied too thickly, too quickly.
Chevron Corporation
QR-11
May 1998
Coating System Data Sheets
Coatings Manual—Quick Reference Guide
Coating System Data Sheets Available System Data Sheets Primer Only Systems 1.1
Inhibited Alkyd (Primer Only)
1.2
Silicone Alkyd (Primer Only)
1.3
Self-Cured Inorganic Zinc–Solvent Reducible (Primer Only)
1.3.1
Self-Cured Inorganic Zinc–Water Reducible
1.4
Polyamide Epoxy (Primer Only)
1.5
Amine Adduct Epoxy (Primer Only)
1.6
Organic Zinc-Rich Primer for Galvanizing Repair
1.7
Vinyl Butyral Wash Primer
1.8
Epoxy Mastic–Surface-Tolerant Prime
1.8.1
Epoxy Mastic–Surface-Tolerant Primer–Aluminum Color Only
1.9
Temperature-Indicating Paint
Two-Component Systems
May 1998
2.1
Inhibited Alkyd | Alkyd Enamel
2.2
Inhibited Alkyd | Alkyd Enamel | Alkyd Enamel
2.3
Silicone Alkyd | Silicone Acrylic
2.4
Self-Cured Inorganic Zinc | High-Temperature Silicone
2.5
Self-Cured Inorganic Zinc | Silicone Acrylic
2.6
Self-Cured Inorganic Zinc | Polyamide Epoxy (High Build)
2.7
High-Temperature Silicone | High-Temperature Silicone
2.8
Manufacturer's Standard | Alkyd Enamel
2.9
Manufacturer's Standard | Alkyd Enamel | Alkyd Enamel
2.10
Manufacturer's Standard | Silicone Acrylic
2.11
Manufacturer's Standard | High-Temperature Silicone
2.12
Epoxy Mastic–Surface-Tolerant Primer | Polyamide Epoxy (Finish)
2.12.1
Epoxy Mastic–Surface-Tolerant Primer–Aluminum Color Only | Aliphatic Polyurethane
2.13
Epoxy Mastic–Surface-Tolerant Primer | Polyamide Epoxy (High Build)
2.13.1
Epoxy Mastic–Surface-Tolerant Primer–Aluminum Color Only | Polyamide Epoxy (High Build)
2.14
Polyamide Epoxy | Polyamide Epoxy
QR-12
Chevron Corporation
Coatings Manual—Quick Reference Guide
Coating System Data Sheets
2.15
Epoxy Mastic–Surface-Tolerant Primer | Aliphatic Polyurethane
2.15.1
Epoxy Mastic–Surface-Tolerant Primer–Aluminum Color Only | Aliphatic Polyurethane
Three-Component Systems 3.1
Self-Cured Inorganic Zinc | Polyamide Epoxy (High Build) | Aliphatic Polyurethane
3.1.1
Self-Cured Inorganic Zinc | Polyamide Epoxy (High Build) | Aliphatic Polyurethane
3.2
Zinc-Rich Epoxy | Polyamide Epoxy (High Build) | Aliphatic Polyurethane
3.3
Self-Cured Inorganic Zinc | Vinyl Tie-Coat | Vinyl (High Build) | Vinyl (High Build)
3.3.1
Self-Cured Inorganic Zinc | Vinyl Tie-Coat | Vinyl (High Build) | Vinyl (High Build)
3.4
Zinc-Rich Epoxy | Vinyl (High Build) | Vinyl (High Buid)
3.5
Epoxy Mastic | Polyamide Epoxy (High Build) | Aliphatic Polyurethane
3.5.1
Epoxy Mastic—Aluminum Color Only | Polyamide Epoxy (High Build) | Aliphatic Polyurethane
3.6
(reserved for future use)
3.7
Manufacturer's Standard | Universal Primer | Polyamide Epoxy (High Build) | Aliphatic Polyurethane
3.8
Manufacturer's Standard | Universal Primer | Aliphatic Polyurethane
Specialty Coating Systems 4.1
Splash Zone Coating—Sprayable
4.1.1
Splash Zone Compound—Asbestos Free Rated to Cure Underwater
4.2
Monel Sheath for Splash Zones
4.3
Vulcanized Neoprene for Splash Zones
4.4
Polyamide Epoxy | Fireproofing | Polyamide Epoxy (High Build) | Aliphatic Polyurethane
4.5
Polyester Non-Skid | 20–30 Mesh Grit | Polyester Non-Skid
4.6
Epoxy Non-Skid | Grit | Epoxy Non-Skid
Non-Reinforced Thin Film Internal Coatings
Chevron Corporation
5.1
FDA-Approved Epoxy (Polyamide or Amine Cured) for Potable Water
5.2
Polyamide Epoxy (Thin Film) | Polyamide Epoxy (Thin Film)
QR-13
May 1998
Coating System Data Sheets
Coatings Manual—Quick Reference Guide
5.3
Amine Adduct Epoxy (Thin Film) | Amine Adduct Epoxy (Thin Film)
5.4
Polyamide Coal Tar Epoxy | Polyamide Coal Tar Epoxy
5.5
Amine Adduct Coal Tar Epoxy | Amine Adduct Coal Tar Epoxy
5.6
Epoxy Phenolic | Epoxy Phenolic
Glass Flake Reinforced Internal Coatings 6.1
Polyamide Epoxy Glass Flake (Spray) | Polyamide Epoxy Glass Flake (Spray)
6.1.1
Polyamide Epoxy Glass Flake (Trowel) | Polyamide Epoxy Glass Flake (Trowel) | Glass Flake-Free Epoxy Resin Gel Coat
6.2
Amine Adduct Epoxy Glass Flake (Spray)| Amine Adduct Epoxy Glass Flake (Spray)
6.3
Isophthalic Polyester Glass Flake (Spray) | Isophthalic Polyester Glass Flake (Spray)
6.3.1
Isophthalic Polyester Glass Flake (Trowel) | Isophthalic Polyester Glass Flake (Trowel) | Wax Coat of Glass Flake-Free Isopolyester Resin
6.5
Vinyl Ester Glass Flake (Spray) | Vinyl Ester Glass Flake (Spray)
6.5.1
Vinyl Ester Glass Flake (Trowel) | Vinyl Ester Glass Flake (Trowel)
Laminate Reinforced Internal Coatings 7.1
Polyamide Epoxy Laminate
7.2
Amine Adduct Epoxy Laminate
7.3
Isophthalic Polyester Laminate
7.4
Bisphenol “A” Laminate
7.5
Vinyl Ester Laminate
Non-Reinforced Thin Film Coatings for Immersion Service
May 1998
8.1
Non-Reinforced Thin-Film Coatings for Fresh-Water Immersion Service
8.2
Non-Reinforced Thin-Film Coatings for Demineralized Water or Condensate Immersion Service
8.3
Non-Reinforced Thin-Film Coatings for FDA-Approved Potable Water Immersion Service
8.4
Non-Reinforced Thin-Film Coatings for Salt Water and Brine Immersion Service
8.5
Non-Reinforced Thin-Film Coatings for Produced-Water Immersion Service
QR-14
Chevron Corporation
Coatings Manual—Quick Reference Guide
Coating System Data Sheets
8.6
Non-Reinforced Thin-Film Coatings for Crude Oil (Sweet or Sour) Immersion Service
8.7
Non-Reinforced Thin-Film Coatings for Fuel (Low-aromatic) Immersion Service
8.8
Non-Reinforced Thin-Film Coatings for Fuel (High-Aromatic) Immersion Service
8.9
Non-Reinforced Thin-Film Coatings for Aromatic-Hydrocarbon Immersion Service
8.10
Non-Reinforced Thin-Film Coatings for Acetone Immersion Service
8.11
Non-Reinforced Thin-Film Coatings for Ethyl & Methyl Alcohol Immersion Service
Glass Flake Reinforced Coatings for Immersion Service 9.1
Glass-Flake-Reinforced Coatings for Fresh-Water Immersion Service
9.2
Glass-Flake-Reinforced Coatings for Demineralized Water or Condensate Immersion Service
9.3
Glass-Flake-Reinforced Coatings for FDA-Approved Potable Water Immersion Service
9.4
Glass-Flake-Reinforced Coatings for Salt Water and Brine Immersion Service
9.5
Glass-Flake-Reinforced Coatings for Produced Water Immersion Service
9.6
Glass-Flake-Reinforced Coatings for Crude Oil (Sweet or Sour) Immersion Service
9.7
Glass-Flake-Reinforced Coatings for Fuel (Low Aromatic) Immersion Service
9.8
Glass-Flake-Reinforced Coatings for Fuel (High Aromatic) Immersion Service
9.9
Glass-Flake-Reinforced Coatings for Aromatic Hydrocarbon Immersion Service
Laminate Reinforced Coatings for Immersion Service
Chevron Corporation
10.1
Laminate-Reinforced Coatings for Fresh-Water Immersion Service
10.2
Laminate-Reinforced Coatings for Demineralized-Water or Condensate Immersion Service
10.3
(reserved for future use)
10.4
Laminate-Reinforced Coatings for Salt-Water Brine Immersion Service
10.5
Laminate-Reinforced Coatings for Produced-Water Immersion Service
QR-15
May 1998
Coating System Data Sheets
Coatings Manual—Quick Reference Guide
10.6
Laminate-Reinforced Coatings for Crude-Oil (Sweet or Sour) Immersion Service
10.7
Laminate-Reinforced Coatings for Fuel (Low Aromatic) Immersion Service
10.8
Laminate-Reinforced Coatings for Fuel (High Aromatic) Immersion Service
10.9
Laminate-Reinforced Coatings for Aromatic Hydrocarbon Immersion Service
High-Temperature/High-Pressure Coating Systems 11.1
(reserved for future use)
11.2
Demineralized Water or Condensate Coatings Resistant to Temperature Gradients of 50°F & Compatible with Cathodic Protection
11.2.1
Demineralized Water or Condensate Coatings Resistant to Temperature Gradients of 50°F & Incompatible with Cathodic Protection
11.3
(reserved for future use)
11.4
Salt Water & Brine Service Coatings Resistant to Temperature Gradients of 50°F & Compatible with Cathodic Protection
11.4.1
Salt Water & Brine Service Coatings Resistant to Temperature Gradients of 50°F & Incompatible with Cathodic Protection
11.4.2
Salt Water & Brine Service Coatings Resistant to Temperature Gradients of 50°F & Incompatible with Cathodic Protection
11.5
Produced Water Service Coatings Resistant to Temperature Gradients of 50°F & Compatible with Cathodic Protection
11.5.1
Produced Water Service Coatings Resistant to Temperature Gradients of 50°F & Incompatible with Cathodic Protection
11.5.2
Produced Water High Temperature/High Pressure Service Coatings Resistant to Temperatures to 180°F, Pressures of 1000 PSI & Incompatible with Cathodic Protection
11.5.2
Crude Oil Service (Sweet or Sour) Coatings Resistant to Temperature Gradients of 50°F & Compatible with Cathodic Protection
11.6.1
Crude Oil Service (Sweet or Sour) Coatings Resistant to Temperature Gradients of 50°F & Incompatible with Cathodic Protection
11.6.2
Crude Oil (Sweet or Sour) High Temperature/High Pressure Service Coatings Resistant to Temperatures to 180°F, Pressures of 1000 PSI & Incompatible with Cathodic Protection
Coatings Under Insulation & Fireproofing 12.1
May 1998
Under Insulation & Fireproofing—Non-Reinforced Thin Film Epoxy Coatings for Continuous Carbon Steel Temperatures -50°F to 140°F
QR-16
Chevron Corporation
Coatings Manual—Quick Reference Guide
12.2
Under Insulation & Fireproofing—Non-Reinforced Thin Film Epoxy Coatings for Continuous Carbon Steel Temperatures 140°F–300°F
12.3
Under Insulation & Fireproofing—Non-Reinforced Thin Film Epoxy Coatings for Cyclic Carbon Steel Temperatures that Produce Wet/Dry Conditions
12.4
Under Insulation & Fireproofing—Non-Reinforced Thin Film Epoxy Coatings for Continuous Stainless Steel Temperatures -50°F to 140°F
12.5
Under Insulation & Fireproofing—Non-Reinforced Thin Film Epoxy Coatings for Continuous Stainless Steel Temperatures 140°F–300°F
12.6
Under Insulation & Fireproofing—Non-Reinforced Thin Film Epoxy Coatings for Cyclic Stainless Steel Temperatures that Produce Wet/Dry Conditions
12.7
Under Insulation & Fireproofing—Non-Reinforced Thin Film Inorganic Coatings for Carbon Steel or Stainless Steel Temperatures Above 300°F
(Series 13 through 19 Reserved for Future Use) Concrete Coatings
Chevron Corporation
20.1
Epoxy Coatings for Concrete: Service Temperatures
