ppl700 inspection and testing

700 Inspection and Testing

AbstractThis section discusses the nondestructive inspection methods used for line pipe, from mill purchase to installation in the ground. It provides guidance on the purpose, the suitability, and the application of mill surveillance and field inspection (pipeyard). The makeup and duties of inspection and/or monitoring crews are detailed. Pipeline welding inspection and pipeline coatings inspection are covered.

This section also covers the construction activities of hydrotesting, dewatering and drying, and the organization of large and small field inspection activities.

For inservice inspection of pipe wall thickness conditions using electronic inspec-tion pigs, see Sections 453 and 832.

Contents Page

710 Inspectors and Inspection Methods 700-3

711 Types of Inspectors

712 Inspection Methods

713 Acceptance Criteria

720 Mill Surveillance 700-17

721 Recommendations for Use of Mill Surveillance

722 Mill Surveillance Teams

723 Mill Inspector Duties

724 Qualifications of Mill Inspectors

730 Post-Mill Inspection 700-22

731 Types of Field Inspection Services for Line Pipe

732 Qualification of Inspectors and Inspection Companies for Line Pipe

733 Recommendations for Pipe Inspection

740 Pipeline Welding Inspection 700-27

741 Duties and Qualifications of Welding Inspectors

742 Qualification of Welding Procedures and Welders

Chevron Corporation 700-1 November 1994

700 Inspection and Testing Pipeline Manual

743 Documentation and Quality Control

744 Visual Examination

745 Radiography of Field Welds

750 Pipeline Coating Inspection 700-36

751 Inspection Methods for External Coating

752 Plant Inspection of Internal FBE Coatings

753 Plant Inspection of Internal Cement Linings

754 Field Inspection Methods for External Coatings

755 Field Inspection of FBE Coated Field Joints

756 Field Inspection of Heat Shrink Sleeves

757 Protection of Coating During Laying

760 Completion Testing 700-42

761 Completion Scraper Run

762 Completion Hydrotesting

763 Test Procedure and Program

764 Line Rupture and Leakage

770 Dewatering and Drying 700-62

771 Dewatering

772 Drying and Dehydrating

773 Gelled-Fluid Pigs

780 Typical Field Inspection Organization 700-64

781 Objectives

782 Selection of Field Inspection Personnel

783 Inspection Functions and Staffing

784 Inspection Reports

790 References 700-67

November 1994 700-2 Chevron Corporation

Pipeline Manual 700 Inspection and Testing

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710 Inspectors and Inspection Methods

711 Types of InspectorsInspection of line pipe materials (Sections 720-723), pipeline welding (Sections 740-745) and installing (laying), and line pipe coating (Sections 750-757) involves many inspection methods, and several types of inspectors with different expertise. It is done at various stages of the project from production of pipe in the mill to laying of pipe in the ditch. Figure 700-1 shows a schematic of the various inspection sites.

The various inspectors and inspection agencies fall into several groupings:

• Company Inspectors. Company inspectors, including CRTC’s Quality Assurance Team Engineers may be used to oversee supplier or contracted inspeor actually inspect pipe, and may be involved throughout the project, from production of the pipe to welding and pipe laying.

• Supplier Inspectors. Employed by the supplier or manufacturer, supplier inspectors are the line pipe mill, coating company, or welding contractor’s inspectors.

• Service Company Inspectors. These individuals and/or service companies usually have special inspection equipment. They are contracted by CRTC’sQuality Assurance Team or the project staff to perform specific tasks such ainspection of butt welds, ultrasonic inspection on the line pipe weld seam, athickness measurements on coatings.

• Third-Party Inspectors (Monitors). Contracted by Chevron (not contractors or suppliers), third-party inspectors independently monitor the inspection wof others. Third-party inspectors perform mill surveillance by monitoring themill inspectors and/or inspecting the final product. In the field they monitor tfield inspection. In the coating plant they verify coating integrity.

712 Inspection MethodsThis section presents a general overview of inspection procedures and techniqthat are used for inspection of line pipe and field welds. Specific procedures forinspection and the criteria for acceptance are discussed in Section 730, 750, an770.

Consult the latest editions of the following sources for more details:

• Company Welding Manual

• API RP 5L8, Recommended Practice for Field Inspection of New Line Pipe

• Metals Handbook, Vol. 17, Nondestructive Evaluation and Quality Control, ASM International

• Nondestructive Testing Handbook, American Society for Nondestructive Testing (several volumes)



Fig. 700-1 Inspection Points and Methods

Numbers in ( ) refer to sections of the manual, as follows:

(710) Visual (730) Pipe Yard Inspection

(710) Magnetic Particle (740) Weld Radiography

(710) EMI - Flux Leakage (750) Shop-Applied Coating

(710) Radiography (750) Over-the-Ditch Coating

(710) Ultrasonics (750) Field Joints

(720) Mill Surveillance (750) Protection During Laying

(710)(730)

(710)(730)

(720)(730)

(710)(710)(710)(730)

(710)(730)(710)(730)

(750)(730)

(710)(730)

(710)

(710)(740)

(710)(750)(750)

(750)



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• API STD 1104, Standard for Welding Pipelines and Related Facilities

See Section 790 for additional references.

Visual InspectionVisual examination is the first level of material inspection. It involves the use of eyes, either unaided or with a low power magnifier, to look for imperfections anflaws.

Visual inspection has obvious advantages: it is easy, straightforward, fast, and pensive; it requires little special equipment and provides important information wregard to pipe surfaces. Its limitations include an inability to evaluate metal inteso other methods such as radiography and ultrasonics must sometimes complevisual examination.

On bare pipe, visual inspection detects gouges, ERW weld irregularities (excestrim or flash), SAW weld irregularities (contour, high-low, undercuts), dents, scapits, scores, notches, and sometimes laps or seams. For butt welds, visual exation is useful for detecting surface porosity, high-low (with access to inside surfabead contour, and severe undercutting. Visual examination of the weld bevel careveal damage, seams and laminations.

The typical tools for visual inspection are magnifying glasses, flashlights, and mirrors. To look down the ID of pipes and tubes, an instrument called a borescope is used. Flexible fiber optic scopes are also available that permit the transmissilight and images around corners or through twisted or crooked channels.

Gages, micrometers, calipers, rulers, tapes, etc., are also used for visual inspeThese devices are used to verify dimensions such as bevels, thickness and diaExperience is required in the use of some of these tools.

Magnetic Particle Inspection

GeneralMagnetic particle inspection (MPI) is a nondestructive method for detecting surdiscontinuities or cracks in magnetic materials. MPI using AC current can also detect defects that are slightly subsurface, but is not totally reliable for this purp

Basic PrincipleThe basic principle of magnetic particle inspection involves the following steps:

• Creating a magnetic field in the material so that magnetic poles are set up discontinuities

• Applying magnetic particles to the surface of the material

• Visually examining the surface for any concentrations of the particles and euating the cause of the concentration (indication)



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Let us consider these stages in turn.

Establishing a Magnetic FieldA suitable magnetic field can be established in the object by using a central conductor, coils, permanent magnets, yokes or prods (see Figure 700-2 and 700-3). Flaws that are perpendicular to the field set up local poles and form a leakage flux, thus attracting magnetic particles. Surface discontinuities are thus outlined by a buildup of magnetic particles (powder).

The type of current can either be DC, AC, or rectified AC current. DC produces a deeper field and can, therefore, detect subsurface defects more effectively. AC is most effective for surface discontinuities but is ineffective for subsurface defects. Single-phase current (half-wave rectified AC) provides optimum sensitivity, and is the most commonly used on newer, portable equipment.

Magnetic Particles—Dry and WetOnce a suitable magnetic field is set up within the material, the magnetic particles are applied to show the leakage fields or discontinuity indications. Particles can either be dry powders or wet suspensions. In addition, particles suspended in liquid can be coated with a dye that makes them fluoresce brilliantly under ultraviolet light. This is known as black light or wet fluorescent mag particle inspection (WMPI).

Dry magnetic particles should contrast with the pipe surface. Grey, yellow, and white magnetic particles are typically used.

The WMPI method is a more sensitive method than the dry method.

InterpretationInterpretation of magnetic particle inspection is usually done by eye. The cause of indications can usually be seen unaided, but sometimes a magnifying glass is required. Indications are marked with a waxed crayon or paint. Depending upon the job specifications, indications are sometimes probed to investigate depth or to deter-mine if the indication is merely superficial.

Magnetic Flux Leakage InspectionMagnetic flux leakage inspection, commonly referred to as electromagnetic inspec-tion (EMI), is a variation of magnetic particle inspection. It is employed for full body pipe examinations either in the manufacturer’s mill, the field or pipeyard.

Pipe inspection is performed automatically in an inspection unit. The pipe is matized either by passing it over a current-energized central conductor that inducecircular field in the pipe, or by passing the pipe through a coil which induces a longitudinal field in the pipe. See Figure 700-3. The circular field finds longitudi-nally oriented imperfections, such as seams and long cracks, while the longitudfield finds circumferential imperfections, such as cracks and gouges. Instead ofparticles, EMI uses electronic sensors to detect the flux leakage. This allows a continuous inspection of the full pipe body excluding 6 inches to 12 inches of thpipe ends.



Fig. 700-2 Magnetic Field Induction Methods (From ASM Handbook, Vol 11; "Nondestructive Inspection and Quality Control", 8th Ed., (1976). Courtesy of ASM International)



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EMI inspection is sometimes included in the mill’s quality control line. These unare adjusted for mill production speeds (which may exceed 200 feet per minuteare generally not as accurate as field EMI units which operate at approximatelyfeet per minute. EMI services can also be purchased in the field. This inspectiovery common for downhole casing and tubing but is performed on line pipe onlyspecial cases.

One cautionary note is necessary. Any residual magnetism in the pipe will causwelding difficulties. The surveillance inspection should ensure the EMI unit doenot leave residual magnetism greater than 30 gauss when measuring with an etronic magnetometer (gaussmeter). If a mechanical magnetometer is used, theresidual magnetism should not exceed 8-10 gauss.

Radiographic Inspection

IntroductionRadiography (also called RT) is a nondestructive test method that uses X-rays gamma rays to detect defects in solid materials. A radiograph is a shadow pictuproduced by passing the rays through an object and onto a film. Thin sections ometal absorb less radiation and, therefore, make a dark pattern on the film. Thisections allow less of the radiation energy to reach the film, producing a lighter image. For example, where porosity exists in a weld, there is effectively less somaterial to absorb the radiation, resulting in characteristic dark round spots on film. See Figure 700-4 for a simplified sketch of the technique.

Fig. 700-3 Pipe Body Magnetization Methods (From ASM Handbook, Vol 11; "Nondestruc-tive Inspection and Quality Control", 8th Ed., (1976). Courtesy of ASM Interna-tional)



Radiography is the most commonly used weld inspection method for evaluating weld integrity; it is not generally used on the line pipe body. One advantage is that RT provides a permanent record of a weld which can be examined and evaluated by more than one person. The method is limited in that certain types of planar defects, such as cracks, can be missed if they are oriented at an angle to the beam of radia-tion or are tight and do not present enough change in density. Other drawbacks are that special equipment, training, and techniques are required, and it is somewhat slower and more expensive than other methods. However, in spite of these limita-tions, it is still a widely used method for evaluating the quality of a weld.

Equipment and Basic PrinciplesThe most common radiographic sources are X-ray machines and artificially-produced radioactive isotopes of certain metallic elements, such as Iridium 192. The isotopes emit gamma ray radiation. X-ray machines are used in the mill and, some-times, portable units are used in the field. Gamma ray sources are used primarily on pipeline and field construction jobs where the source must be mobile.

X-rays and gamma rays differ primarily in wavelength. The energy level (wave-length) of each isotope is fixed, while the energy level of an X-ray machine is a function of its tube and applied voltage. Also, the strength (number of rays per area, or flux) of an isotope source decays with time, but the strength of an X-ray machine is constant and controllable.

The thickness of metal that can be penetrated by the radiation depends on wave-length. Shorter wavelengths (higher energy) permit deeper penetration.

Fig. 700-4 Basic Elements of a Radiographic System (From ASM Handbook, Vol 11; "Nonde-structive Inspection and Quality Control", 8th Ed., (1976). Courtesy of ASM Inter-national)



Exposure time for radiographing a thickness of metal depends on the energy level (or wavelength) of the source (see Figure 700-5), the type and thickness of the metal, the strength of the source, the film type, the use of intensifying fluorescent screens, and the source-to-film distance. The inverse square law, which states that the intensity of radiation varies inversely with the square of the distance from the source, governs exposure time. Figure 700-6 shows the effect of changes in vari-ables such as radiation source and film type on radiograph quality.

Contrast and FilmsA number of factors control contrast, but the two most important are the energy level of the radiation and the type of film. Regardless of film type, contrast decreases as the energy level increases. Since Iridium 192 has a lower energy level than Cobalt 60, a radiograph from Iridium 192 will have higher contrast. This is also true of X-rays, the higher energy machines producing radiographs of lower contrast. Generally, X-rays produce more contrast than any gamma-ray service.

Radiographic films have various degrees of speed. The faster the film, the less exposure is needed to produce a chosen density. However, fast films are grainy, and the grains become increasingly coarse as the speed of the photographic emulsion increases. Extreme coarseness does not record detail, and Company specifications do not allow the use of fast, coarse-grained films. For the best quality, ASTM E 94 type 1 or 2 film should be used. These are, respectively, low and medium speed films. For example, Kodak AA is a type 2 film, while Kodak Industrexm is a type 1 film. Type 3 and 4 films have high and very high film speeds, respectively, and should not be used.

ScreensRadiographic film is held in a cassette, sandwiched between two screens. The two principal screen types are lead foil and fluorescent.

Lead foil screens are the most widely used and give higher quality exposures than fluorescent screens. Lead screens serve a dual purpose: they act as intensifiers by emitting electrons and characteristic rays under the action of the primary radiation that aid in producing the radiograph. At the same time, they act as filters to absorb

Fig. 700-5 Radiographic Sources and Approximate Applications

Source Energy Steel Thickness Range, inches

X-rays 80-120 Kev 0 to 1/4

120-150 Kev 0 to 1/2

150-250 Kev 0 to 1

250-400 Kev 1/4 to 2

6-31 Mev 1 to >8

Iridium 192 0.38 Mev 1/2 to 2 1/2

Cobalt 60 1.2 Mev 1 to 4



the scattered radiation that tends to fog the film. Lead screen thicknesses vary with source strength from 0.001 inch to 0.01 inch.

Fluorescent screens are usually made of calcium tungstate crystals deposited on a thin background material. The X-rays or gamma rays cause these crystals to emit light that intensifies the film image. They decrease the necessary exposure time, compared with lead, but give less image sharpness. Most authorities and Company specifications discourage the use of fluorescent screens, since the sacrifice in film quality can result in the masking of significant defects.

Either type of screen must be in close contact with the film during the exposure for good image sharpness. Also, the screens must be free from blemishes, scratches, dents, and any dirt that could be recorded on the film and misinterpreted as a defect in the weld.

Fig. 700-6 Effects of Changes in Variables on Radiographic Quality



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Image SharpnessOther factors being equal, fine grained film produces the sharper image, but the size of the source is also a factor: the smaller the source size, the sharper the image. Increasing the source-to-film distance compensates for a large source. In general, the source-to-film distance should be at least seven times the thickness of the mate-rial being radiographed. Most radiographic work is done at much higher ratios, such as 30:1. Vibration or movement of the source or film during an exposure will cause a fuzzy image.

PenetrametersA penetrameter indicates the image quality or sensitivity of the radiograph and is the true test of a radiographic procedure. In the United States, penetrameters usually consist of thin strips of metal with various size holes. In other countries, fine wires or small spheres may be used. Penetrameters are placed on the part being radio-graphed, and the ability of the radiograph to show a particular hole size or wire establishes the image quality. Figure 17 in API STD 1104 details the configuration of a penetrameter.

The penetrameter image is the inspector’s most important tool for evaluating thquality of the radiograph. He should know the penetrameter requirement for thework or item he is inspecting and make sure the proper type is used in an acceable manner. The applicable specification or code usually requires that penetraters be properly shimmed to compensate for weld reinforcement and be placedthe source side of the weld.

Film ProcessingMany factors are important during film processing to assure quality radiographsThe most important are fresh, clean, properly mixed solutions, proper developebath temperature (68°F is ideal), appropriate development time, and proper agition, washing, fixing, and drying.

Viewing of RadiographsTo properly interpret a radiograph, the viewing equipment should be in a darkenroom. To prevent films placed against it for viewing from overheating and curlinthe illuminator should have an adjustable cold fluorescent light or incandescentbulbs with forced ventilation.

Commercially available variable intensity viewers are more versatile and providparticular advantages when viewing high or low density negatives. The film shobe placed on the viewer and all light visible around the edges masked off. The thing an inspector should look for is the penetrameter, to see if it is the proper sand shows evidence of good film quality, i.e., the outline of the penetrameter antwo-thickness (or 2T) hole are visible.

Quite often a film artifact is mistaken for a weld defect. The principal causes of such artifacts are:

• Dirty, scratched, or bent screens, which cause imperfections in the image



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• Localized pressure on a film, which causes easily recognizable pressure marks when the film is processed

• Poor processing techniques, such as water marks from improper drying andscratches from handling

It is the inspector’s duty to learn to recognize film artifacts. Most film artifacts become obvious when the film surface is viewed at an oblique angle under whilight.

Interpretation and Acceptance StandardsThe ability to interpret the radiograph is a demanding skill that the inspector mubecome proficient in and strive to keep informed on, so that he can judge the welding according to the applicable standards.

Radiographs fall into one of three evaluation categories: unquestionably acceptclearly rejectable, and borderline. In the last category honest differences of opinwill occur. Experienced interpreters will assess image sharpness, film type, idencation, location markers, and proper density as indicators of film quality. The intpretation of the significance of a discontinuity is sometimes influenced by the interpreter’s knowledge of the film quality. For example, a serious defect may appear insignificant in a poor quality film, and an experienced interpreter will tathis into account. In addition, of course, he must be thoroughly familiar with theapplicable specifications and acceptance standards. Acceptance limits for partidefects in pipelines are specified in API STD 1104, Standard for Welding Pipeliand Related Facilities. API STD 1104 is also referenced by ANSI/ASME CodesB31.4 and B31.8. See Section 742.

An alternate approach for acceptance standards based on a defect’s true threastructural integrity is called fitness-for-purpose. This approach is more lenient withrespect to pipeline welding quality, focusing rather on detailed engineering analof each case and knowledge of actual weld metal and base metal toughness. Because it is more cumbersome than arbitrary workmanship standards, it is hajustify except in special situations. See API STD 1104 Appendix A.

Note Amendment 195-52, page 33388 of the Federal Register, dated June 28, 1994, now allows pipeline operators to use Appendix A of API STD 1104, 17th edition.

Ultrasonic InspectionUltrasonic (UT) inspection methods use sound waves to detect internal, externaand subsurface defects including those in ERW and SAW pipe weld seams, thedepth of surface imperfections, and wall thickness. A transducer which can bottransmit and receive a sound wave is placed on the material. With the aid of a couplant, such as grease, oil, or water, the sound beam penetrates the materiatravels in a straight line until it hits a reflecting surface. This may be the oppositsurface of the material, a crack or seam penetrating from the OD or ID, a subsuface crack or seam, a lamination in the material, weld porosity, undercutting, higlow, or lack of weld fusion. The beam reflects off this surface and is detected byreceiver portion of the transducer. Electronics convert the time it takes the beam



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traverse the material to a length dimension. Note that flaws must be approximately perpendicular to the sound beam (plus or minus 10 to 15 degrees) to reflect effec-tively back to the transducer.

Longitudinal or Compression Wave InspectionA longitudinal (compression) wave is transmitted normal to the surface of the pipe and reflects off the internal wall. This method is useful for determining pipe wall thickness and internal laminations.

Several types of instruments are available for longitudinal wave inspection, as follows:

• A cathode ray tube (CRT) displays a horizontal line with a peak on the far left-hand side. This peak is the initial pulse of the sound wave. When the trducer is placed on a surface, a peak will appear on the right. The distance between the two peaks is proportional to the thickness of the material. Withproper calibration, the CRT displays wall thickness. Figure 700-7 shows thetechnique on a normal pipe wall. Figure 700-8 shows the display when a midwall lamination is present. Figure 700-9 shows the display for pipe with eccentric wall thickness.

• A meter display can be calibrated to show full thickness at full scale. The wthickness is read directly from the meter.

• A digital display, properly calibrated, will directly indicate wall thickness.

Transverse or Shear Wave InspectionTransverse (shear) wave UT inspection uses a transducer to transmit a sound into the material at an angle. The wave will reflect at defects that are normal ornormal to the wave. Defects such as cracks, rolled-in seams, weld root defectstoe cracks can be detected by this method. The transducer is mounted in a plahead that is machined at a prescribed angle (normally 45° to 60°). The wave re

Fig. 700-7 Compression Wave Ultrasonics, Normal Pipe Wall



off a defect and, in part, back into the receiver portion of the transducer. Figure 700-10 shows the principle involved.

A CRT screen is used for readout. Unlike longitudinal waves, the display consists of an initial peak and a small peak to the right which will move as the transducer is moved. When the transducer is moved a greater distance from the flaw, the indica-tion disappears from the screen. Interpretation of the results of shear wave inspec-tion requires a very knowledgeable, experienced operator.

UT Applications for Line PipeThere are several methods of applying UT to the field inspection of line pipe. Refer to Section 731 for the basic descriptions of UT weldline (crab) units, full body UT units, or compression wave UT (including pipe end area inspection).

Fig. 700-8 Compression Wave Ultrasonics, Mid-wall Lamination

Fig. 700-9 Compression Wave Ultrasonics, Wall Thinning, Showing CRT Display



713 Acceptance CriteriaThe acceptance of defects found by UT, magnetic particle, visual, or EMI inspec-tion is based on API SPEC 5L, API STD 1104 or Chevron specification require-ments. API SPEC 5L only requires mandatory full body pipe inspection (seamless pipe only) using any one of three alternative inspection methods (MPI, EMI, UT) when Supplementary Requirement SR4 is specified. Model Specification PPL-MS-1050 suggests API SPEC 5L SR 4 inspection, using ultrasonics (UT) only, as a supplemental requirement (see Section 310 for pipe selection criteria). Model Speci-fication PPL-MS-1050 also requires UT weldline inspection of ERW line pipe with walls thicker than 0.188 inches, and further requires the UT be done per API 5L SR 17 after hydrostatic testing using an N10 notch (10% of specified wall thickness) for calibration. This is much more stringent than the basic API 5L which allows ERW

weldline inspection to be performed using UT or EMI, does not define location (e.g., after hydrostatic testing), and allows V10 or Buttress notches or a drilled hole as calibration standards.

Fig. 700-10 Shear Wave Ultrasonic Inspection



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720 Mill SurveillanceMill surveillance (third-party inspection or monitoring) is performed on new line pipe at the manufacturer’s facility. Contract pipe inspectors are retained by CRTQuality Assurance Team or by project management to perform the following: monitor critical pipe production operations, such as welding, sizing, heat treatmand testing; and/or (2) monitor the mill’s internal nondestructive examination (NDE) inspections. At times, the third party inspectors may also perform extensdimensional checks and visual examinations (these duties are performed by “beinspectors” - see Section 723); however, most surveillance activities are currentypically limited to production and NDE monitoring with some random dimen-sional checks and visual examinations. Specific duties and responsibilities are gin Section 723.

Mill surveillance provides assurance that the requirements of API Specification and Company specifications are met. It increases the probability of culling defetive joints that may be missed by the mill’s inspection and minimizes defective pdelivered to the jobsite.

721 Recommendations for Use of Mill SurveillanceFigures 700-11 and 700-12 summarize suggested inspections for line pipe.

Fig. 700-11 Inspection Recommendations for Mill-Order Pipe, Chevron, or API Specifications

General Service Critical Service(1)

Mill Surveillance: Yes, if >50 tons(2) Yes, all orders

Inspection If Had Surveillance If Had No Surveillance If Had Surveillance If Had No Surveillance(3)

SMLS ERW SAW SMLS ERW SAW SMLS ERW SAW SMLS ERW SAW

Visual(4) No No No Yes Yes Yes No No No Yes Yes Yes

Weld Seam UT - (5) No - (5) (6) - (5) No - (5) (6)

Full-Body UT (or EMI)

No No No (7) No No No No No (7) (8) No

Job Site Visual(9) Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes

Review MTR’s(10) No No No Yes Yes Yes No No No Yes Yes Yes

(1) Critical service is defined as high pressure gas >1440 psig, offshore, populated areas, or sour service.(2) Example: 3400 ft of 12-3/4 inches x 0.219 wall.(3) Not usually applicable, since mill surveillance is recommended for critical service.(4) This could vary from a random visual to 100% visual depending on the extent of other inspection(s) done. (It may also include dimen-

sional checks such as ring gaging pipe ends.)(5) See decision tree in Section 312 - refer to the mill class definition explanation which denotes when and how much weld seam UT may be

required. For API pipe, additional weld seam UT may be required - consult with CRTC’s Quality Assurance Team.(6) Case by case basis; consult with CRTC’s Quality Assurance Team.(7) Consider if previous problems with mill occurred or pipe is in critical service as defined in (1). In the case of mills which do not perform

any EMI or UT, a minimum of 10% (General Service) or 25% (Critical Service) is recommended.(8) See decision tree in Section 312 and supplemental specification requirements noted therein.(9) For pipe body and bevel handling damage; inspection typically done by welding Contractor personnel.(10) The material test reports (MTR’s) should be reviewed for conformance to API and/or Chevron requirements for all pipe not subjected to

mill surveillance. Special emphasis is placed on the Carbon Equivalent (for weldability) and mechanical properties.



722 Mill Surveillance Teams

Figure 700-13 shows the recommended minimum mill surveillance team size and makeup for seamless, electric weld (ERW), and submerged arc weld (SAW) mills.

723 Mill Inspector Duties

Duties of SupervisorThe supervisor or shift leader (lead inspector) carries out the duties listed below. Typically, if there are two (or more) mill inspectors per shift, one will be designated the shift leader, and if there is more than one shift per day, one shift leader will be designated as the overall job supervisor. The supervisor may also be the NDE inspector. This typically occurs when there is only one inspector per shift and only one shift per day. In this case, that inspector would perform the duties listed below, as time permits, but would typically concentrate 60 - 80% of his/her efforts on NDE surveillance as described under “Duties of NDE inspectors”.

• Completely familiarizes him or herself with the requirements of the order.

Fig. 700-12 Inspection Recommendations for Distributor Stock Pipe from Approved Sources(1) (2)

(Post Mill at Pipeyard)

Inspection General Service Critical Service(3)

SMLS ERW SAW SMLS ERW SAW

Visual (4) Yes Yes Yes Yes Yes Yes

Weld Seam UT - (5) (6) - (5) (6)

Full-Body UT or EMI (7) No No (7) (8) No

Job Site Visual (9) Yes Yes Yes Yes Yes Yes

Review MTR’s(10) Yes Yes Yes Yes Yes Yes

Other (11) (11) (11) (11) (11) (11)

(1) An approved source is a mill that CRTC’s Quality Assurance has audited and approved.(2) This pipe will be API with no chance of mill surveillance.(3) Critical service is defined as high pressure gas > 1440 psig, offshore, populated areas, or sour service.(4) This could vary from random visual to 100% visual depending on the extent of other inspection(s) done. (It may also include dimen-

sional checks such as ring gaging pipe ends.)(5) See decision tree in Section 312 - refer to the mill class definition explanation which denotes when and how much weld seam UT may

be required. For API pipe, additional weld seam UT may be required - consult with CRTC’s Quality Assurance Team. (From nonap-proved sources a minimum 25% frequency for General Service; a minimum 50% frequency for Critical Service.)

(6) Case by case basis; consult with CRTC’s Quality Assurance Team. (From nonapproved sources a minimum 25% frequency for Critical Service.)

(7) Consider if previous problems with mill occurred or pipe is in critical service as defined in (3). In the case of nonapproved sources or approved sources which do not perform any routine EMI or UT, a minimum 10% frequency for General Service; a minimum 25% frequency for Critical Service.

(8) See decision tree in Section 312 and supplemental specification requirements noted therein.(9) For pipe body and bevel handling damage; inspection typically done by welding contractor personnel.(10) The material test reports (MTR’s) should be reviewed for conformance to API and/or Chevron requirements for all pipe not subjected

to mill surveillance. Special emphasis is placed on the Carbon Equivalent (for weldability) and mechanical properties.(11) Other inspection methods may also be appropriate on a case by case basis. These include: full length MPI; Pipe end MPI; UT of ERW

or SAW pipe ends for laminations; and so on. Consult CRTC’s Quality Assurance Team for guidance.



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• Meets with pipe mill quality control personnel before the start of productionreview the specifications, review, discuss, and agree upon mill procedures,to establish the proper lines of communication.

• Completely informs him or herself concerning the production and quality control operations and procedures of the mill.

• Establishes the work schedule of NDE and/or Bench inspectors.

• Conducts a safety meeting for each shift once per week.

• Provides NDE and/or Bench inspectors with written inspection instructions contain the applicable tolerances for the order and any special instructionspertaining to the order.

• Maintains surveillance over all operations in the pipe mill.

• Periodically visits the mill inspection bench to review problems, determine ttype of defects occurring most frequently, and follow up on them to determithe cause.

Fig. 700-13 Team Makeup for Mill Surveillance of Line Pipe

The most typical mill surveillance team makeup currently used for APPROVED mills with some documented Chevron knowledge/history is indicated below. These team makeups are the minimum typically used. An increase (or decrease) in coverage may be warranted based on an analysis of the many factors listed below.(1)

Mill TypeMinimum Number of Mill

Inspectors/Shift Duties

Seamless ONE (2)

Electric Weld (ERW) TWO (3)

Submerged Arc Weld (SAW)

TWO (4)

(1) Some factors which affect team makeup are:a. Mill layout/general practices: compact or spread out facility; mechanical testing done concurrently with mill run or subsequently; NDT prove-up near inspection unit or at a remote location.b. Seamless mill: typically do not monitor pipe rolling or steel making.c. Specific order requirements: diameter of pipe; general or critical service; sweet or sour service; quantity of pipe in order; number of supplemental requirements specified; Chevron specifications or API.d. Other: approved or nonapproved source; well-documented history on mill or no information.

(2) Seamless pipe inspectors. Concentrate mill surveillance on final full body NDE (60%). Balance of inspectors time spent monitoring the following, as applicable: hydrostatic testing (5%); final inspection bench (15%); mechanical testing (10%); verify length and marking requirements, pipe handling (damage), collecting /tabulating daily reject figures, report writing, and so on (10%).

(3) ERW pipe inspectors. Concentrate mill surveillance on two areas: the pipe welding/seam normalizing operations; and the final weld seam UT. There is typcially a shift leader and a full time UT weldline inspector for each shift. The shift leader monitors pipe welding/seam normalizing (70%). Balance of monitoring time spent on the following, as applicable: final bench inspection; hydrostatic testing; mechanical testing; verify length and marking requirements, pipe handling (damage), collecting/tabulating daily reject figures, report writing, and so on. The UT weldline inspector monitors final UT weldline inspection (70 - 90%) and utilizes balance of time to monitor UT of pipe ends (if applicable), and assists shift leader at final bench inspection.

(4) SAW pipe inspectors. Concentrate mill surveillance on two areas: the pipe welding operations; and the final weld seam UT. There is typically a shift leader and a full time UT weldline inspector for each shift. The shift leader monitors pipe welding (60%). Balance of monitoring time spent on the following, as applicable: final bench inspection; hydrostatic testing; pipe expansion; mechanical testing; verify length and marking requirements, pipe handling (damage), collecting/tabulating daily reject figures, report writing, and so on. The UT weldline inspector monitors final UT weldline inspection (70%) and utilizes balance of time to review radiographs, monitor UT of pipe ends (if applicable), and assists shift leader at final bench inspection.



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• Verifies that mill Bench inspectors are performing final visual and dimensioinspections in a competent manner.

• Verifies dimensions are done and recorded per the frequencies and procedagreed upon in the pre-production meeting. These dimensional checks inclpipe body outside diameter (o.d.), pipe end o.d., wall thickness, end squareness, bevel, root face, internal taper (seamless), and straightness.

• Verify length, marking, demagnetization, ERW weld flash or trim, SAW weldcontour, etc., meet order requirements.

• Verify that pipe to be subsequently coated is free of mill varnish, grease, slivers, sharp protrusions, etc.

• Witnesses the periodic calibration of the nondestructive testing equipment assure its proper operation.

• Reviews the radiographs on a spot check basis to assure proper interpretaThe number of radiographs reviewed will vary depending upon the results othe spot check.

• Periodically witnesses the fluoroscopic inspection and assures that the spetravel and settings are such that the penetrameter can be clearly defined.

• Periodically checks railcars, trucks or ship holds before loading for debris aattachments that may damage pipe.

• Periodically checks the loaded cars, trucks or ship holds to assure that theyloaded in accordance with API RP 5L1, Railroad Transportation of Line PipAPI RP 5LW, Transportation of Line Pipe on Barges and Marine Vessels, oother specified recommended practices approved by the purchaser. This intion should include a spot check for body and bevel damage due to improphandling during loading.

• Checks hydrostatic testing charts and operation for conformance to order requirements. Includes verification that test gages and recorders are in curcalibration.

• Checks the welding and repair welding operation for compliance with the mprocedures. This includes a review of the procedure qualification test recorand the performance test records of each welder to assure that the requireof Appendix B of the API SPEC 5L are met. Particular attention should be taken to assure that low hydrogen electrodes, if used, are stored in an elecdry rod box.

• Checks loading crane hooks to assure that they are properly designed to enate bevel damage.

• Witness as many mechanical tests as possible to assure that the test procecorrect and all test equipment is in current calibration. This should include aspot check of the test specimen measurements.



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• Assures that the proper number of tests are made and the chemical and mical properties meet the required specifications.

• Assures that all shipping documents and mill chemical and mechanical tescertificates are collected by the mill and forwarded to the Company office atimmediate completion of pipe production. If they are not then available, the mill personnel must be advised to forward them to the Company purchasinagent or project engineer.

• Immediately reports any serious problems to the Company for review.

• Collects the daily reject figures including types of rejects from all applicablesources, checks them for accuracy and forwards a summary of them to theCompany at the required frequency (sometimes daily) and at the completiothe inspection assignment.

• Tabulates the total number of feet of each size and wall thickness of pipe accepted each day, and keeps a cumulative record so that the status of theis known at all times.

Duties of NDE InspectorsThese are contract inspectors assigned to witness the final UT (or EMI) on sealess pipe or the final UT weldline inspection on ERW or SAW pipe. (Refer to Figure 700-13). In some cases, the NDE Inspector may also be the Supervisor/Leader (when only one contract inspector per shift required). In this case, the NInspector would concentrate his or her efforts on the final NDE (60 - 80%), but also perform other mill surveillance activities included under “Duties of the Supvisor”.

The NDE Inspector typically performs the following duties:

• Witness the periodic calibration of the NDE unit

• Witness NDE inspection of all pipe

• Verify calibration and operation of the NDE unit per approved mill procedur

• Verify all pipe with indications exceeding the acceptance limit is thoroughlyproven up, etc

• Verify any defects (or imperfections) removed by grinding are completely removed and the remaining wall thickness is verified

• Verify the weld line on ERW or SAW pipe ends not covered by automated Uis manually UT’d

• As time permits, assist the Shift Leader monitoring the mill bench inspector

• As time permits, also monitor end area UT or MPI inspections

Duties of Bench InspectorsThe previous (January 1990) edition of this manual detailed the duties of BenchInspectors. As noted in Section 720, the extensive dimensional checks and visu



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examinations included such duties as checking the outside diameter of each end of each pipe, checking out of roundness on each end of each pipe larger than 20 inches NPS, checking the wall thickness of each pipe, close visual examination of each pipe, and so on. These duties essentially duplicated everything randomly checked by the mill bench inspectors and much more. This type of extensive dimensional and visual examination would now only be considered for nonapproved mills (or substandard mills) with whom Chevron has no previous experience or knowledge. Some of these duties may still be applicable for very critical orders. Consult with CRTC’s Quality Assurance Team for guidance.

ReportingContract inspectors forward all reports, tallies, and problems to the Chevron PrEngineer or Quality Assurance Engineer who is handling the order.

724 Qualifications of Mill InspectorsMill inspectors usually are certified by the American Society for Nondestructive Testing (ASNT) as Level II inspectors for specific inspection techniques such amagnetic particle, ultrasonics, etc. The inspection agency may also carry out cecation and training programs on their own. A Level II inspector has demonstratethrough tests and experience that he or she knows the principles of the inspecttechnique, can apply the technique with the desired results, and can interpret thindications that are found.

Inspectors normally have worked for manufacturers in the inspection departmefor a pipe user in a materials laboratory, quality assurance, or other similar posiIt is the responsibility of CRTC’s Quality Assurance Team to confirm that the inspectors being used for mill inspection and surveillance are qualified and holdappropriate certifications. Periodic requalifications are required to maintain certcation.

Resumes of the inspectors are usually reviewed by CRTC’s Quality Assurance to assess their level of experience, dates of last testing, and certification and pemance. Inspectors that have performed poorly in the past are not permitted to won Company jobs or projects.

730 Post-Mill InspectionPost-mill inspection of line pipe, commonly called field or pipeyard inspection, idone to detect transit damage, and defects missed by the mill inspection. The inspection is done visually, or by magnetic particle, EMI or ultrasonics. Radiog-raphy is not used. Field or stockyard inspection will not add to the quality of the pipe, but will minimize defective pipe delivered to the jobsite.

Field or pipeyard inspection can be done at any location from the time the pipe leaves the mill production line to the time it is welded into the pipeline. Figure 700-1 shows inspection points and relevant sections of this manual.



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In some cases, post-mill inspection is done on the mill property by nonmill parties. It is not to be confused with mill surveillance, because it involves inspection with nonmill equipment and personnel. Post-mill inspection is also typically done in a pipeyard near the staging area for pipe shipment or stringing.

Company inspection practice is summarized in Figures 700-11 and 700-12. Basic practice calls for mill surveillance on large pipe orders out of the mill. Post-mill inspection is recommended for some general service and all critical service pipe that has not undergone mill surveillance. On projects involving critical service applica-tions, see Model Specifications PPL-MS-1050 and PPL-MS-4041.

Pipeyard inspection should also be considered for API SPEC 5L pipe that is purchased from a non-Chevron-approved mill or from distributors stock.

API RP 5L8, Recommended Practice for Field Inspection of New Line Pipe discusses inspection procedures and qualification of inspectors, and makes recom-mendations on good practices for carrying out inspections. This document should be used as a reference when specifying inspection procedures.

731 Types of Field Inspection Services for Line PipeAPI RP 5L8 discusses standard inspection techniques and procedures for line pipe, including visual and dimensional inspection, magnetic particle inspection, electro-magnetic inspection, and ultrasonic inspection. It details the procedures for evalu-ating inspections for pipe mill defects, pipe seam welds, mill grinds, wall thickness, dents, laminations, straighteness, diametrical parameters, etc. A discussion of the advantages and descriptions of the various inspection techniques are presented in Section 712.

Figure 700-1 summarizes recommended inspection methods and points. Field inspection service companies perform any of the following inspections:

• Visual and dimensional inspection. Searches for visual imperfections, such adents, gouges, pits, corrosion, wall thinning, and seam weld appearance. Dimensional parameters such as diameter, wall thickness, and bevel dimensions are monitored. Pipe markings are verified.

• Magnetic particle inspection. Done on bevels to detect and evaluate defectssuch as cracks, mill seams, weld defects, and laminations. The procedure involves dragging a yoke along the bevel.

• EMI electromagnetic inspection. EMI scans the entire pipe body for OD andID defects such as seams, wall thickness eccentricity, gouges, pits, and scEMI is usually only done on seamless pipe.

• Ultrasonic inspection. Shear wave ultrasonic inspection is used to evaluate weld seams. Angle transducers are mounted on a crawler or crab unit whicmoves along the weld seam. The signal is translated into a printout or a ch

• Compression ultrasonics. Used to check for wall thickness. This is done withhand-held units such as the Krautkrauer-Branson D-Meter. Also used to ch



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pipe ends for laminations using either hand-held units or special semi-auto-mated units.

• Combined shear and compression wave UT. These units are typically perma-nently mounted under roof units. although there are one or two such units aable which are mobile, which are capable of scanning both the pipe body apipe weld seam. They use angle transducers for detecting longitudinal andcircumferential defects and straight (compression) wave transducers for wathickness.

• Radiographic inspection. Radiography is not done in the field to inspect pipeIt is, however, the most common method to inspect girth welds during pipelconstruction and is discussed in Section 712 and 740.

Large companies providing field inspection services include the following:

• Tuboscope Vetco InternationalP.O. Box 808Houston, TX 77001-0808Ph: 713-456-8881Fax: 713-456-6197

• Ico, Inc.9400 BambooHouston, TX 77041Ph: 713-462-4622Fax: 713-462-4821

Small companies providing field inspection include the following:

• A&A Tubular Inspection, Inc.3075 Walnut AveLong Beach, CA 90807Ph: 310-981-2351Fax: 310-981-2354(Also have a Houston, TX., location)

(UT Weldline Inspection ONLY)

• Reliant Oilfield Services, Inc.Rt. 1, Box 143Linden, TX 75563Ph: 903-756-5656Fax: 903-756-5283

732 Qualification of Inspectors and Inspection Companies for Line PipeThere are generally two categories of field inspection personnel, as follows:

• Service companies. Field inspection services are provided by large inspectiocompanies such as Tuboscope Vetco International, Ico Inc, or small compa



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such as A&A Tubular and Reliant Oilfield Services. These companies provide the equipment and inspection personnel.

• Third parties. Third party inspections provide surveillance over service company crews. They may be useful when inspection service companies dless qualified crews or deploy crews unfamiliar with typical Chevron field inspection requirements, e.g., calibration notch requirements, frequency ofbration, etc., and therefore third party surveillance helps assure that inspecare conducted properly. Consult with CRTC’s Quality Assurance Team for guidance.

Field Inspection CompaniesCRTC’s Quality Assurance Team maintains lists of qualified inspection companincluding qualified equipment and equipment operators. These companies are fied on the basis of their ability to do the job, the services they offer, the experieof their personnel, past performance, test joint evaluations, location of inspectiounits, and the cost of their services.

An inspection service which has done acceptable work in one area, for examplthe Gulf Coast, may not be acceptable in the Rocky Mountains or West Coast. engineer is encouraged to consult with CRTC’s Quality Assurance Team for accable service companies in the area where the job will be performed.

Field Inspector QualificationThe inspection service company internally qualifies their employees in the varioinspection services that are offered. Documentation concerning the specific traiexaminations and experience of the inspectors should be available upon reque

Inspector qualification documentation should show:

• Training programs or courses attended on each of the inspection methods which the inspector is qualified

• Records of written examinations

• Records of hands-on examinations on calibration, operation, and interpretaof the various types of equipment the inspector is qualified on

• A written record or resume of inspection experience

Field Inspection CrewsA field inspection crew generally consists of two to four individuals. The job funtions are as follows:

• The supervisor or crew leader is responsible for the inspection unit equip-ment and supervises the crew. This person requires the highest qualificatiosince he or she is actually responsible for the job. This person has the ultimresponsibility of accepting or rejecting the joint of pipe, based on the speciftion.



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• The inspection helper is responsible for locating flaws and confirming whetheor not these meet the specifications. He or she is supervised by the crew leThe helpers qualifications should include written and hands-on examinationwell as inspection experience, although he or she will usually be less experenced than the supervisor.

• One or two laborers are generally part of the inspection crew. They may be employees of the inspection agency or hired out of the local labor pool. Thedo not usually have any inspection qualifications, and should not perform ainterpretations.

Third-Party InspectorsThese inspectors monitor the service company inspection crews. They may be employed by an inspection agency such as Moody-Tottrup, or may be independcontractors. Typically, a few small independent contractors, which have been doped over many years, are used for monitoring. The experience of these individmay include former employment with an inspection service company, line pipe uor manufacturer. These individuals may have formal test certifications from the American Society of Nondestructive Testing (ASNT).

A list of qualified third-party surveillance inspectors is maintained by CRTC’s Quality Assurance Team, which should be contacted if these services are requi

Duties of the Third PartyThe third-party inspector has a responsibility to:

• Represent the Company at the jobsite and aid in the interpretation of defecThe third-party inspection provides a link between the Company and serviccompany, but is not involved in changing work orders or scheduling

• Assure that the inspections are properly performed

• Witness all calibration checks and assure that equipment is working proper

• Monitor each new inspector to assure that they have the proper qualificatio

• Be present during the whole job or as directed

• Review each rejected joint to assure that the cause of rejection is valid

• Communicate the job status daily to the Company representative

• Communicate difficulties with interpretation or inspection personnel to the Company representative

733 Recommendations for Pipe InspectionRecommendations for pipe inspection are given in Figures 700-11 and 700-12.Chevron has commonly performed mill surveillance inspections on line pipe forcritical service. Critical services are defined as high pressure (>1440 psi), popuareas, offshore, and sour gas.



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Factors (in addition to critical service) which are important in making a judgment to perform further field inspections are as follows:

• Grade. Higher grades (X-60 and greater) are used for high pressure lines ahave thinner walls

• Weld Method. ERW versus SAW

• Mill Origin. Some mills have better equipment for producing and inspectingpipe than others

Groups within Chevron that may be consulted to give guidance on pipe inspectinclude the following:

• CRTC, Materials and Equipment Engineering, Quality Assurance

– 510-242-4612 (Richmond)– 510-242-3381 (Richmond - alternate)

• CRTC, Materials and Equipment Engineering, Metallurgy

– 510-242-3245

740 Pipeline Welding InspectionThis section discusses the requirements and procedures for inspection of pipelgirth welds. Normally, the Company’s arrangements for pipeline welding inspection are independent of the pipeline contractor’s organization. The contracts forwelding inspection and nondestructive examination (radiography) are based onapplicable codes, regulations, and Company requirements. However, the Compquality assurance responsibilities must be carefully coordinated with the pipelincontractor to avoid lessening his sense of responsibility for the quality of the pipline welding. The Company’s responsibilities include:

• Preparation of clearly written specifications for the inspection and nondestrtive examination (NDE) of the pipeline welds

• Providing qualified welding inspectors

• Assuring that welding procedures and welders are properly qualified

• Documenting or assuring documentation of all inspection results and providquality control feedback to the pipeline contractor

• Spot visual examination of pipeline fit-up before welding, the welding in progress, and the completed welds

• Providing radiographic inspection through an inspection organization whospersonnel are qualified to the American Society of Nondestructive Testing (ASNT) Recommended Practice No. SNT-TC-1A



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National regulations and codes that have requirements concerning pipeline welding are listed in Section 630 of this manual. Pipeline maintenance welding is discussed in Section 860.

741 Duties and Qualifications of Welding InspectorsWelding inspectors should be thoroughly familiar with API STD 1104, Standard for Welding Pipelines and Related Facilities, (or applicable local code) and Company specifications for welding and inspection of pipelines. API RP 1107 pertains to maintenance welding.

The duties of a welding inspector for pipeline welding include but are not limited to the following:

• Witnessing welding procedure qualifications and assuring that the welding procedure specification is followed during the qualification. When required,witnessing the mechanical tests for the procedure qualifications and verification of the results provided by the testing laboratory

• Witnessing welder qualification tests and assuring that the welding proceduspecification is followed; documenting the test conditions and the welders taking the test. Terminating the test as soon as it is obvious that a welder lathe skill to pass the test, particularly after the root and hot pass. Checking agrading test specimens and documenting results

• Witnessing pipeline fit-up and checking for correct joint preparations, align-ment, cleaning of the weld prep, and use of fit-up equipment

• Witnessing pipeline welding and checking that all details of the procedure abeing followed properly, including preheat, use of electrodes, time allowed between root and hot pass, weld cleaning and welding technique, verifyingwelds are marked with the welder’s identification in a manner not injurious the pipe

• Checking of radiographs for repairs and proper identification as to weld joinnumber and welder symbols

• Working with the chief inspector to identify and eliminate substandard weldthrough the quality assurance program

Qualification of Welding InspectorsAPI STD 1104 requires that welding inspectors be qualified on the basis of expence and training but does not provide specific requirements. The Company, thhas to establish its own requirements. In the past, inspection jobs tended to be to more senior pipeline personnel and emphasized experience in pipeline weldWhile welding experience is still important, a highly recommended alternative isthat the welding inspector be certified by the American Welding Society (AWS).be certified by AWS the welding inspector must take a written examination and have five years’ welding experience. The written examination requires under-standing of code and nondestructive testing, and a broad background in weldin



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Certification renewal is required every three years, and includes an eye examina-tion, maintenance of welding experience, and payment of a fee. In addition, AWS requires reexamination every nine years.

Additional training should be considered for pipeline welding inspectors on major jobs to increase their familiarization with the codes and regulations. One organiza-tion offering a one-week training course is the National Pipeline Welding Inspec-tion School, located in Houston, Texas.

API STD 1104 requires that the documentation of a welding inspector’s qualifictions include at least the following:

• Education and experience• Training• Results of any qualification examinations

Qualification of NDE PersonnelASNT Recommended Practice SNT-TC-1A, for certification of personnel, assigthree levels of proficiency in various NDE methods (radiography, liquid penetranmagnetic particle, etc.) based on training and experience. The levels are categoas I, II, and III in ascending order of qualification. Contract inspection companieperforming radiography are required to have their personnel certified to SNT-TCas explained in Section 745. Welding inspectors who grade and interpret radio-graphs are also required to be certified to Level II or III.

742 Qualification of Welding Procedures and WeldersQualification of welding procedures and welders is the Company’s responsibility(see Section 630 and Model Specification PPL-MS-1564). API STD 1104 shoulused for this purpose. The pipeline contractor may submit welding procedures fqualification or use procedures previously qualified by the Company. Welder qufication tests should be witnessed by the Company. Testing should be terminateany time it is apparent the welder cannot make a sound weld.

743 Documentation and Quality ControlDocumentation and quality control for pipeline welding should include both welding and radiographic inspection. Documentation should cover a minimum othe following:

• Welding Procedure Qualifications. Each welding procedure should be quali-fied and recorded as described in API STD 1104.

• Welder Qualifications. Each welder should be qualified to use the procedurwithin the essential variables as described in API STD 1104. Requalificatiorequired any time a welder has not used a given process of welding for a pof six months or more. ANSI/ASME B31.8 imposes additional restrictions fogas transmission piping.



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• Radiographic Procedure. Qualification of each radiographic procedure is required as described in API STD 1104 and in Section 745 following. The procedure should be signed by a level III radiographer.

• Radiographic Inspection. Results of radiographic inspection should be documented for each weld and signed by a level II or III radiographer. The weld number, radiographic procedure, and welder identification should be clearlystated.

• Welder Identification. Each welder should be given a unique identification number or mark for his work which is traceable to his welder qualification records.

• Weld Marking. Each weld should be given a unique identification number thcan be traced to its location from the as-built drawings. Crayon or paint shobe used for marking, not metal stamps.

Quality control for pipeline welding should be based on the results of the radio-graphic inspection of each welder’s work. Easy identification of a substandard quality record is important for weeding out poorly performing welders. Perfor-mance should be based on the percentage of welds requiring repair for each wThis varies depending upon pipe size and wall thickness. A repair record of mothan 2 to 5% is generally cause for warning, and for dismissal if poor welding continues.

744 Visual ExaminationVisual examination before, during, and after welding is one of the welding inspector’s most important jobs. Visual examination includes both the pipe and welds. Documentation of visual examinations can vary from a minimum of dailyfield notes to formal checklists, depending upon the size of the job. The frequenof visual examinations can vary from 100% surveillance to selective spot checkdepending upon the location of the pipeline (i.e., urban, rural, crossing, etc.) anrisks to pipeline operations. The following is a list of the visual examinations whshould be made or verified by the welding inspector:

• The pipe is in good condition and free of defects

• Cold bends have been made properly without damaging the pipe or coatingthe pipe is free of wrinkles, flat spots, and excessive out-of-roundness

• Each joint of pipe has been swabbed clean of trash and debris before it is pin the line

• Bevels and lands are satisfactory for welding and are:

– Free of material defects (e.g., laminations)– Properly cleaned and free of weld contaminants such as rust, grease, a

other foreign material– Dimensionally correct and within tolerances

• The pipe is free of handling damage, or has been repaired



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• The pipe is properly supported by studs for welding

• The welding is performed as required by the procedure and has been checfor:

– Pipe fit-up and alignment. Offset and gap dimensions are within toleran– Correct preheat– Sound stringer pass without cracks, undercut, or excessive porosity. P

grinding for the hot pass– Adherence to the maximum time permitted between the stringer and ho

pass– Interpass cleaning (power wire bushing) and grinding starts and stops

needed– Fit-up clamps used as specified in the procedures– Correct types (AWS classification) and diameters of electrodes. Electro

are in good condition for welding (i.e., free of damage and contaminatio– Correct welding polarity. (Generally DC+, but DC- is sometimes used f

the root pass with certain electrodes, such as Lincoln 5P and HYP)– Staggered starts and stops to avoid alignment with other passes– No cracks, undercut, or excessive porosity in any bead– Minimum number of passes as specified in the procedure for the thickn

(but not less than three)– Correct reinforcement and width of the cap pass and no excessive und

of the pipe– Welder identification marked in a manner not injurious to the pipe but

permanent enough for pickup by the X-ray crew– Weather, wind, and dust conditions not adverse to good welding practic

• Defect repairs do not exceed more than one repair at any given location in pipe weld, and the welder contributing to the defect is identified

745 Radiography of Field WeldsThe use and frequency of radiographic inspection is established by the CompaRadiography is performed to the acceptability standards in Section 6.0 of API S1104 and additional requirements of the Company (see PPL-MS-1564). Fundatals of radiography are discussed in Section 712 of this manual.

Radiographic ProcedureBefore any radiography can be performed on a pipeline, a detailed procedure foproduction of radiographs must be prepared, recorded, and demonstrated by thradiographic contractor to produce acceptable radiographs, in accordance withSection 8.0 of API STD 1104. API STD 1104 requires demonstration on test shthat the radiographic procedure produces acceptable radiographs. A written produre is required that includes at least the following:



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• Radiation source. Covers type of radiation source, effective source or focal spot size, and voltage rating of X-ray equipment.

• Intensifying screens. Describes the type and placement of screens, and leadscreen thickness (see Section 712). Lead screens are preferred for pipelinework. An exception is offshore construction from a lay barge, where remoteoperated, battery-powered, crawler-mounted internal X-ray heads are frequently used. These generally employ fluorescent screens to minimize esure times and battery recharging frequency. Intermediate speed fluoresceintensifying screens (e.g., Du Pont Conex NDT 5) with fine grain medium speed film have proved satisfactory for this application. Fluorescent screenvery sensitive to dirt, dust, and scratches, and must be kept immaculately cand replaced more frequently than lead screens.

• Film. Film brand rather than film type should be specified, along with the number of films per cassette. Where more than one film per cassette is spefied, how they will be viewed should be stated (e.g., single film viewing or double film viewing). In the past film type designations (Type 1 or 2) have baccepted in lieu of brand names. However, because of significant variationthe grain size and speed of films meeting the same type, this designation snot be used to obtain equivalent radiographic quality by substitutions madesolely on the basis of film type.

• Exposure Geometry. Exposure geometry refers to the relative placement of source of radiation, pipe weld, film, penetrameters and lead markers (for filintervals and reference). The number of exposures per weld is also stated.ations include the following:

– SWE/SWV. Single-wall exposure with single-wall viewing. The radiationsource is positioned for single-wall penetration. A typical setup would bwith the source on the inside and the film on the outside. When the souis centered inside of the pipe, a single 360-degree exposure of the weldbe made.

– DWE/SWV. Double-wall exposure with single-wall viewing. The radia-tion source is positioned for double wall penetration, but only the weld from “one” wall (i.e., one side of the pipe) is recorded on the film. A typical setup is with the source on the outside of the pipe and the film othe opposite side. A minimum of three 120-degree exposures are requif the source is positioned within 1/2 inch of the pipe, otherwise four 90degree exposures are required (see Figure 700-14).

– DWE/DWV. Double-wall exposure with double-wall viewing. The radia-tion source is positioned for double wall penetration, with welds on “botwalls recorded on the film. NPS 3 and smaller pipe requires this techniwith the radiation beam offset so that the source side and film side portof the weld do not overlap in the area of the radiograph to be evaluatedTwo or more exposures (N) are required with each shot, separated by degrees divided by N.

• Exposure Conditions. The exposure conditions depend on the exposure parameters of the radiation source (either X-ray or radioisotope). For X-ray



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units, they are measured in milliamperes, peak X-ray voltage (KVP), and expo-sure time. For radioisotopes they are measured in curie minutes.

• Processing. The radiographic procedure should specify:

– Automatic or manual processing– Time and temperature of solutions for development, stop bath (or rinse

fixation, and washing– Drying method

• Materials. Type and thickness range of material for which the procedure is suitable

• Penetrameters. The type of penetrameter (API STD 1104 or ASTM E142), material, identifying number, and essential hole to meet the required sensitlevel should be specified. Shim material and thickness should also be givenThe minimum sensitivity level is 2% unless otherwise stated

Double-Jointing Yard InspectionAt double-jointing yards the pace of welding and radiography is quite rapid. Attetion must be given to providing and achieving required radiographic inspection coverage.

• Repairs to rejected welds must be re-radiographed. Otherwise only the radiograph films of the defective weld will appear in the final documentationand the missing record of the satisfactory repair will not be available to the authority inspecting and certifying the pipeline.

Fig. 700-14 Double-Wall Single-Image Radiography



Weld Acceptance StandardsSection 6.0 of API STD 1104 covers the standards of acceptability for radiographs. These are summarized in Figure 700-15 for easy reference.

Fig. 700-15 Summary of Standards of Acceptability for Radiographic Weld Inspection

Type of Defect API Standard 1104 Notes

Cracks None allowed except shallow crater cracks in the cap pass with maximum length of 5/32".

(1)

Incomplete Penetration at Root Pass Max 1" length in 12" of weld, or 8% of weld length for welds less than 12" long. Max individual length 1".

(2)

Incomplete Penetration Due to High-Low Flow

Max individual length 2". Max total length of 3" in 12" of continuous weld. (2)

Incomplete Fusion at Root Pass Max of 1" length in 12" of weld, or 8% of weld length for welds less than 12". Max individual length 1".

(2)

Incomplete Fusion at Sidewall or Cold Lap

Max individual length of 2". Max total length 2" in 12" of continuous weld.

Burn-Through (NPS 2 and Larger) Max 1/4" or wall thickness, whichever is less, in any dimension. Max total length of 1/2" in 12" of weld.

Internal Concavity If radiographic image of internal concavity is less dense than base metal, any length is allowable. If more dense, then see burn-through above.

Undercut at Root Pass or Cap Pass (Radiograph Plus Visual)

Max allowable depth is 1/32" or 12 1/2% wall thickness, whichever is less. Max 2" length in any 12" or 1/6 of weld length, whichever is less, for depth of 1/64" to 1/32" or 6 to 12% of wall thickness, whichever is less. Depths less than 1/64" acceptable regardless of length.

(3)

Slag Inclusions (NPS 2 and Larger) Elongated: Max width 1/16". Max length 2".

Parallel slag lines: considered separate if width of either exceeds 1/32".

Isolated slag inclusions: max width 1/8" and 1/2" total length in any 12" of weld. No more than four isolated inclusions of 1/8" max width in any 12".

Porosity Spherical and piping: Max dimension 1/8" or 25% of wall thickness, whichever is less (6.61, 6.63). Max distribution shown in API STD 1104.

Cluster: Max area of 1/2" diameter with individual pore dimension of 1/16 in. Max total length is 1/2" of weld.

Hollow bead: Max individual length 1/2 “.<R>Max 2" total length in 12" of weld with individual discontinuities exceeding 1/4" in length separated by at least 2".

Weld Reinforcement at Finish Bead Max 1/16" by approximately 1/8" wider than original groove.

Excessive Root Penetration Not covered.

Misalignment Maximum 1/16".

Accumulation of Discontinuities Maximum of 2" in any 12" or 8% of weld length excluding high-low and undercut condition.

General Rights of rejection: “Since NDT methods give two-dimensional results only, the Company may reject welds which appear to meet these standards of acceptability, if in its opinion the depth of the defect may be detrimental to the strength of the weld.”

(1) Cracks of any kind are detrimental and should not be allowed.(2) For sour service (partial pressure of H2S ≥ 0.5 psi (0.35 kPa)) Chevron Canada Resources specifies none allowed. CAN3-Z183 and

CAN/CSA-Z184 codes suggest “additional restrictions on internal surface imperfections may be warranted for sour service.”(3) As for Note 2, but only at the root pass.



Company Weld Acceptance StandardsThe Company generally follows the API STD 1104 standards. Some Operating Companies, such as Chevron Canada Resources, specify more stringent standards for acceptance of girth welds. This is especially true for critical or sour services,

where the concern is crevice corrosion. The notes to Figure 700-15 show the more stringent requirements.

The use of more stringent standards should be carefully considered for each project. In some areas it may be impossible to enforce higher standards because the welder expertise is not available. Inability to meet higher specified standards after the project has started could lead to disputes with regulatory agencies.

Fig. 700-16 Code Mandatory Radiographic Weld Inspection Frequency

ANSI/ASME Code Canadian Standard

B31.4 B31.8 Z183 Z184

Weld Category hoop stress >20% SMYS ≤Gr 290 >Gr 290 ≤Gr 290 >Gr 290

Production Welds 10% — 15% 15% visual sample

15%

Sour Service Welds <20% SMYS — — 15% — — —

Sour Service Welds >20% SMYS — — 100% 100% 100% 100%

Populated Areas 100%(1) — — — — —

Location Class 1 — 10% — — — —

2 — 15% — — — —

3 — 40% — — — —

4 — 75% — — — —

Water Crossings 100%(1) 100% 100% 100% — —

Rail & Highway Crossings 100%(1) 100% — — — —

Offshore & Inland Coastal Waters 100%(1) 100% — — — —

Old Welds in Used Pipe 100%(1) — — — — —

Tie-in Welds 100%(1) — — — 100% 100%

Uncased Railway Crossings — — 100% 100% — —

Cased Crossings w/ F = 0.72 — — — — 100% 100%

Crossings w/ F = 0.60, 0.50 or 0.40 — — — — 100% 100%

Notes: 1. All percentages are minimums. All inspection for 100% of circumference.2. Sour service is 0.5 psi (0.35 kPa) partial pressure of H2S.

(1) Minimum 90% if some welds are inaccessible.



Radiographic Inspection FrequencyANSI/ASME Codes B31.4 and B31.8 and CAN3-Z183 and CAN/CSA-Z184 specify similar but slightly different inspection frequencies, depending on class location, design safety factor, installed location and fluid carried. See Figure 700-16.

Section 434.8.5(a)(4) of Code B31.4 and Section 826.2(b) of Code B31.8 stipulate these frequencies. Section 6.2.8.2 of CAN3-Z183 and Section 6.2.8.2.2 of CAN/CSA-Z184 provide similar frequencies.

For noncritical lines the basic code frequency is quite low. In some cases this means the radiographic crew is underworked. It is therefore usual to have the crew work steadily for the full shift (if the crew is onsite anyway). For a small extra expense for added film, you can thus achieve up to 50% inspection coverage and greatly increased confidence.

750 Pipeline Coating InspectionInspection of pipeline coatings is done at coating application plants and at the pipe-line construction site. Because coatings are susceptible to damage in handling, visual inspection should be done at various stages in shipping the pipe from the application plant to final lowering into the ditch. Inspection of coating application at permanently established plants may be done by Company inspectors or contracted inspection agencies under the general supervision of a Company Quality Assurance organization. Inspection at field plants and as the line is laid is normally done by the Company field organization, with the Company inspectors or contracted inspectors reporting directly to the Company lead inspector.

The National Association of Corrosion Engineers (NACE) offers an International Coating Inspector Training and Certification Program that is the only established qualification procedures for coating inspectors. Training by experienced Company inspectors and field engineers and by Materials Specialists will prepare an inspector for coating inspection, with emphasis on the particular coating systems for a project. Much valuable information on coating quality is available in industry publications (Oil and Gas Journal, Pipeline Industry, Pipeline, etc.) and in standards established by NACE. The CRTC Materials and Equipment Engineering Unit can provide classes on coatings inspection, tailored to the needs of individual projects. NACE also conducts regional and national meetings and seminars which include topics on coating quality and inspection, by which inspectors can gain inspection expertise and knowledge of coating application.

Established coating applicators and suppliers of coating materials have testing methods and laboratory equipment for quality control of their production and for product development. Standard test procedures for many elements of coating quality have been developed by ASTM, NACE, API, AWWA, and DIN. Applicators, suppliers, and major pipeline operating companies have their own test procedures and modified standard procedures. The Richmond Materials Laboratory of the Chevron Research and Technology Company is equipped to perform a number of tests to evaluate coatings, and is available to conduct tests on coatings on request.



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Results of these test procedures are very helpful in evaluating the performance of coating systems and materials for a particular project, but generally these proce-dures are not applicable for inspection of coating application.

This section presents guidelines for inspection of production coatings and girth weld field joint coatings. For descriptions of these coatings see Sections 340 and 350 of this manual, and the Coatings Manual. Coating systems covered here are:

External• Fusion-bonded epoxy• Extruded plastic film• Coal tar enamel• Tape• Shrink sleeves

Internal• Fusion-bonded epoxy• Cement-lining

For guidelines on other external and internal coatings consult with nonmetallic pipeline coating specialists in the CRTC Materials and Equipment Engineering

751 Inspection Methods for External Coating

SystemsExcept for over-the-ditch application of tape or enamel coatings, careful coatinginspection must be conducted at least two times:

• When the coating is initially applied• When the pipe is lowered into the ditch

The same inspection methods should be used for each inspection.

The inspector must have full knowledge of the method of coating application foeach coating system. Descriptions of specific application methods are availablethe Coatings Manual, in Specification PPL-MS-1800, and in manufacturer’s product literature.

Generally, inspection involves all of the following methods:

• Visual inspection of the entire coating surface to detect imperfections and flaws, lack of coverage, damage, etc.

• Holiday detection utilizing specialized equipment by the applicator’s crew atthe plant, and by the pipeline construction crew in the field, and closely motored by the Company inspector. Holiday detectors are manufactured by Piline Inspection Company (SPY), Houston, TX; D. E. Stearns Co., ShrevepoLA; Tinker & Rasor, San Gabriel, CA; and others.



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• Production sample examination using destructive testing by several means described below.

SpecificationsThese specifications are typical of those used for external coating inspection:

• COM-MS-4042, Fusion Bonded Epoxy for External Pipeline Coating.

• COM-MS-5006, Coal-Tar Enamel Corrosion Coating of Submarine Pipeline

• NACE T-10D-10, Proposed Standard, Application Performance and QualityControl of Plant-applied Fusion Bonded Epoxy External Pipe Coating.

• NACE RP-02 74-74, High Voltage Electrical Inspection of Pipeline CoatingsPrior to Installing.

• NACE T-10D-9C, Proposed Standard, Holiday Detection of Fusion BondedExternal Pipeline Coating of 10 to 30 mils.

• NACE RP-01 85-85, Extruded Polyolefin Resin Coating Systems for Underground or Submerged Pipe.

• PA-129, Chevron Point Arguello Specification, Extruded Polyethylene Corrosion Coating with Butyl Adhesive. (CRTC Materials Division File No. 6.55.7

Shop Quality Assurance• Fusion bonded epoxy: Refer to Section 6.0 of COM-MS-4042 and Section 9

of proposed NACE Standard T-10D-10.

• Polyethylene: Refer to NACE RP-01 85-85 and Section 6.0 of Chevron Spefication PA-129.

• Coal tar enamel wrap: Refer to Section 8.0 of COM-MS-5006.

• Shop-applied tapes: Holiday inspection in accordance with NACE RP-0274-74. The Inspector should inspect visually over 100% of the wrapped area, ainclude visual lap observation. The inspector should use a window-type pattest of the tape to pipe adhesion. Test frequency should be at the inspectordiscretion. The test is acceptable if the plastic backing peels off leaving a complete adhesive cover on the pipe or if strings of adhesive appear as theis peeled back from the pipe and no areas of zero adhesion are encounterethe event of a failure, additional window tests should be made until acceptabond is found. All the defective areas shall be cleaned to bare steel and rewrapped.



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752 Plant Inspection of Internal FBE Coatings

SpecificationsThe Company does not have a specification for internal coating of pipelines with fusion bonded epoxy (FBE). API has a recommended practice, and an Aramco spec-ification is available from CRTC.

• API RP 5L7, Recommended Practice for Unprimed Internal FBE Coating oLine Pipe

• Aramco 09-AMSS-91, Shop-Applied Internal FBE Coating

Shop Quality AssuranceRefer to Section 5.0 of API RP 5L7 and Section 7.0 of 09-AMSS-91.

753 Plant Inspection of Internal Cement Linings

SpecificationsThe recommended specifications for cement lining of pipe used for produced wreinjection water, brine, and salt water service are:

• PPL-MS-1632, Cement-Lined Pipe

• API RP 10E, Recommended Practice for Application of Cement Lining to Tubular Goods, Handling, Installation, and Joining

Shop Quality AssuranceFollow these sections of API RP 10E for guidance on inspection during shop facation:

• Section 4, Inspection and Rejection of Cement-Lined Pipe

• Section 7, Typical Problems Experienced with Cement-Lined Tubular Good

754 Field Inspection Methods for External Coatings

Specifications• Fusion Bonded Epoxy: Holiday inspection per NACE Proposed Standard T-

10D-9C.

• Polyethylene: Holiday inspection per NACE RP-0274-74

• Over-the-Ditch Applied Tapes: Field inspection of over-the-ditch applied tapes is essentially the same as for shop-applied tapes.

• Concrete Weight Coating: Refer to Specification PPL-MS-4807.



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Holiday Detection for All CoatingsInspection for holidays should be in accordance with NACE RP-0274-74. The coated pipeline should be 100% inspected with a pulse-type DC holiday detector employing an audible signalling device. Inspection is performed immediately prior to burial, i.e., after the last lowering-in side-boom. The electrode used for locating holidays must be in direct contact with the coating (with no visible gaps) and provide complete coverage of the whole coated surface. All holidays should be repaired and the repairs should all be checked with a holiday detector to verify that they are adequate. This final inspection procedure should be monitored by a Company Inspector.

The holiday detector requires an electrical ground. In most cases, this is a flexible bare wire approximately 30 feet long which is attached to the detector and trailed along the ground. Wet or damp ground is best. Dry ground may not complete the circuit; in this case attach the wire to a sideboom tractor. The travel rate of the detector’s electrode should not exceed 1 ft/sec nor should it remain stationary wthe power is on.

The calibration of the holiday detector should be checked at least twice per 8-hshift against a calibrated voltmeter and adjusted as necessary. The functional otion of the holiday detector may be checked in the field by making a small artificholiday in the coating (not more than 1/8 inch in diameter.) If the detector is working properly, it will reliably signal the presence of the artificial holiday.

Holidays should be clearly marked with a crayon immediately upon discovery. TInspector should certify that the defective areas have been repaired prior to burThe Inspector usually keeps a daily record of the number of coating repairs perjoint.

755 Field Inspection of FBE Coated Field JointsThe inspector should check the following details for FBE field joints. If a joint coating fails any of these tests, test adjacent (in both directions) girth weld coatuntil acceptable coatings are found. All defective coatings should be completelyremoved and the areas recoated. At least one of the repaired areas should be spected and the subsequent inspection frequency should be as given below.

Thickness. Check the thickness on each coated weld joint using an approved, cbrated magnetic dry film thickness gage (e.g., Microtest, Elcometer or equivaleThe instrument should be zeroed before use with calibrated insulating shims ofthickness comparable to the coating film thickness to be measured.

A minimum number of six readings should be taken on each field joint coating tverify compliance with the thickness requirement above. The readings should include the weld seam.

Cure. On the first five joints of the job and twice each day thereafter, the qualitycure should be checked by maintaining a MEK-soaked pad in contact with the coating surface for 1 minute and then rubbing vigorously for 15 seconds. Thereshould be no softening of the coating or substantial color removal from the coa



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Holiday Detection. Perform detection in conjunction with the regular holiday detection for the coating, before lowering into the ditch.

Destructive Testing. Using a sharp knife with a narrow flexible blade, make two, approximately 1/2-inch long incisions through to the metal substrate to form an X.

Starting at the intersection of the X, attempt to force the coating from the steel substrate with the knife point. Refusal of the coating to peel constitutes a pass. Partial or complete adhesion failure between the coating and the metal substrate constitutes a failure. Cohesive failure caused by voids in the coating leaving a honeycomb structure on the specimen surface also constitutes failure.

Perform this test once every hour. When five consecutive tests are successful, the frequency should be reduced to once every 2 hours.

756 Field Inspection of Heat Shrink SleevesThe following inspection methods and acceptance criteria are applicable to all heat-shrink sleeve applications. Additional inspection requirements (if any) for specific types of sleeves should be given in the sleeve manufacturer’s recommended intion procedure.

Nondestructive Inspection. The shrunk-on sleeves should exhibit the following characteristics:

• Both ends of the sleeves must be bonded around the entire circumference

• The sleeve should be smooth. There should not be any dimples, bubbles, ptures, burnholes, or any other signs of holidays in the coating or of entrapmof foreign matter in the underlying adhesive

• For wrap-around sleeves, the total slippage of the closure patch during apption should not exceed 1/2 inch

• The sleeve should overlap the adjacent mill coating by at least 2 inches onside

Holiday Detection. Perform detection in conjunction with the regular holiday detection for the coating, before lowering into the ditch.

Destructive Inspection. Perform window testing on one sleeve of every 50 installed or twice per shift, whichever is the greater. On each sleeve tested, cutleast one window in each of the overlap area, across the field girth weld, and inbody of the sleeve. There should be no evidence of either voids extending to bametal (or mill coating) or areas of no adhesion. The girth weld should be complecovered by adhesive.

Sleeve application is acceptable if both of the following requirements are met:

• The maximum dimension of any of these defects does not exceed 2 inches

• At least 95% of the adhesive layer is free of voids and/or lack of adhesion



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If the sleeve does not meet the acceptance criteria above, the adjacent sleeves in both directions should be destructively tested until acceptable installations are found.

757 Protection of Coating During LayingTo ensure coating integrity, inspection during pipeline laying operations should be a joint effort between the coating inspector, lowering-in inspector, and backfill inspector. They should:

1. Inspect the ditch to ensure proper depth and sufficient width so as to provide cover and clearance after lowering-in is complete.

2. When padding or rockshield are used, ensure that the pipe is placed on the padding or rockshield when lowered into the trench. If rockshield is the encir-clement type, ensure that it is correctly installed.

3. Ensure that all rocks, skids, roots and other damaging material are removed from the ditch.

4. Ensure that all weld rods are removed from the ditch. They can cause mechan-ical and corrosion damage.

5. Ensure that all field joint coating and line pipe is free of holidays or torn mate-rial. Witness 100% of final jeeping.

6. Verify twice daily the calibration, voltage settings, battery charge, correct speed, and grounding of the holiday detector.

7. Verify that all damaged areas in coating are properly repaired.

8. Record total footage of pipe jeeped and coating repaired daily.

9. Ensure the overall safety of personnel, and suitability of equipment used in the lowering-in and backfill operations.

10. Ensure that mechanical equipment does not damage the pipe during back-filling, and that backfill material has no rocks or hard objects that may damage coating.

760 Completion TestingCompletion testing of a pipeline after construction normally involves:

• A scraper run of a series of pigs propelled by water• Hydrostatic pressure testing of the line with water

ProcedureAlong with the source of water, the most important concern in developing a produre for testing a long cross-country pipeline is the test pressures for different sections of the line. These depend on design operating pressures, maximum aable pipe pressures for various wall thicknesses, and ground elevations.



A procedure may be incorporated in the construction specification, but is more often developed by the Company field organization in coordination with the construction contractor. The procedure needs to be carefully thought through to achieve an effi-cient and safe testing program.

Water SupplyBecause of the large volume of water usually needed to fill the line, the source of water establishes the point from which scrapers are run. Appropriate arrangements must be made for acquisition of water supply. Booster pumps from a river or lake and a temporary line to the pipeline may have to be installed. Often, temporary scraper traps are needed to send and receive the construction completion test pigs. The pressure test pump will normally be located with the pump for the scraper run and line fill, but subsequently may need to be relocated down the line for sections that require higher test pressures. If the flow for scraper run and line fill should be the reverse of the direction of flow for normal operating, attention should be given to check valves that might stop the reverse flow or block the pigs.

Water should be free from silt (screened with 200 mesh and filtered if necessary), and noncorrosive and non-scale-forming for the period of time before the line is dewatered and displaced with oil or gas. An oxygen scavenger is not usually warranted, since, once free oxygen in the fill water is consumed by a negligible amount of corrosion of the pipe wall, no further corrosion takes place. However, if water is to be left in the line for a long period, it should be treated with a biocide (such as glutaraldehyde) to prevent growth of anaerobic bacteria, which can produce H2S and cause sulfide cracking of the pipe steel.

Biocides are often toxic and arrangements for their use and disposal should be made well in advance. You should consider refilling the line after hydrotesting and injecting the biocide into the second fill to avoid uncontrolled spills should pipe failure occur during hydrotesting. Application to environmental authorities for disposal of water containing biocide should be made early in the project. Neutral-izing may be required, and testing and modelling may take four to six months before approval is granted.

In cold climates, the hydrotest media is often a mixture of water and alcohol (meth-enol or glycol). The cost of alcohol is significant and sometimes the pipeline contractor or a local supplier will have a premixed supply on hand. Disposal of this mixture must be carefully arranged.

Preliminary TestingPreliminary testing of pipe strings before installation is recommended for sections of line that may not be accessible later, such as major river crossings. Similarly, it may be prudent to test short sections of line immediately after installation in cases where later pipe or weld replacement would be difficult (and much more costly) after the installation crew and equipment have left the site; for instance, at major highway and main line railroad crossings, main irrigation canal crossings, etc.



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ContractorsConstruction contractors may perform testing operations with their own personnel and equipment, or may subcontract to testing specialist contractors. In some cases, the Company has conducted testing with assistance from contractor personnel.

CommunicationsRadio communications should be available during testing, connecting all personnel with a central location, either directly or through relayed message links. A Company engineer who is well acquainted with the testing program and basic hydraulic calcu-lations should be on duty or on call throughout the period of completion testing to initiate or approve modifications to the program and respond to line failures if they occur.

RecordsClear and accurate records should be kept of all testing procedures and data. This is required for lines under governmental jurisdiction and also by ANSI/ASME Codes. See Section 830 for guidelines on inservice inspection and testing.

761 Completion Scraper RunThe pigs run for the completion test serve to:

• Displace air in the line with water. A line “packed” with water, without air pockets, is needed for reliable hydrotesting.

• Push construction debris ahead of them out of the line. The pigs will partialclean mill scale, weld spatter, and dirt from the line, as well as larger trash,rocks, etc., that were not removed by spread crews.

• Check the internal cross-section of the line. A pig equipped with a gaging pwill confirm that the line does not have dents, buckles or excessive ovallingbends. If any such are present, the pig will either be stopped by the deformpipe, or will arrive at the incoming scraper trap with a severely bent gagingplate.

Pumping equipment and water supply for a typical completion scraper run shouhave a flow capacity corresponding to a velocity of roughly two miles per hour ithe pipeline, at a discharge pressure sufficient to overcome hydrostatic head anfluid friction loss plus at least 100 psi to move the pigs. If debris in the line is expected, higher pressure may be needed. A typical sequence of pumping andmight be as follows:

• Approximately one-half mile of “wash” water (since dry dirt, dust, and mill scale, even without larger trash, tends to pack and plug the scraper)

• A three- or four-cup displacement pig

• Approximately one-half mile of water, or at least 15 minutes’ pumping

• A second three- or four-cup displacement pig



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• A three- or four-cup pig with a gaging plate in front of the first cup or in the center of the pig

• Water to fill the line, unless additional brush scrapers at intervals of at leastminutes are used to further clean pipe walls because of service requiremenadditional multicup pigs are considered necessary to displace air pockets inparticularly rough (up-and-down) terrain

Gaging PlatesThe gaging plate diameter should be 93% of the minimum nominal internal diameter of pipe in the particular section of line being tested. The plate should be acrately machined, and the diameter, measured by micrometer calipers, should bstamped on the plate. Three-eighths inch minimum thickness is suggested for aplate (one-half inch if aluminum), so that it is not likely to be deformed by a restricted pipe cross-section. The leading edge of the plate should be chamferelarge-diameter lines a steel reinforcing plate slightly smaller than the gaging plamay be advisable.

If after running through the line, the gaging plate is deformed, nicked, or gougepossible causes should be reviewed and judgment made on accepting the line satisfactory. A gaging plate may catch on weld “icicles,” small pebbles, or otheracceptable irregularities at line appurtenances, as well as unacceptable deformpipe.

Monitoring ProgressWhile running the pigs, it is strongly recommended that the water volume pumpinto the line be metered and pressures at the pump continuously observed at cnient locations down the line. Meter and pressure data versus time should be recorded at a minimum of 15-minute intervals and whenever any sudden rise odrop in pressure occurs. A pressure recorder should also be used. These data used to analyze the location of the series of pigs should they hang up or plug. Srepeated pressure variations are normal, since the pigs often momentarily slowdown until pressure builds up behind them, and then speed up.

It is also strongly recommended to follow the scrapers, continuously if the terraallows, or, otherwise, wherever the line is readily accessible. A scraping of the inside the pipe can be heard while walking along the line but is likely to be drowout by vehicle engine noise. Sound-amplifying devices are very helpful, with detector probes set into the ground or directly on the pipe, where accessible, aintermediate line block valves. A record should be kept of location versus time when following the pigs. The temperatures of the water pumped into the line anthe water that arrives with the pigs in the incoming scraper trap should be recorthis information is not pertinent to the scraper run, but may be useful in analyzinhydrotest data. All this documentation may seem unnecessary after an uneventsatisfactory scraper run, but can be vital when trying to analyze locations of suspected bad pipe or stuck pigs.



Pigs equipped with sonic transmitters can be detected and precisely located from ground level. Because of cost and logistics they are not often used, but may be warranted in situations where exploratory excavations to locate bad pipe or stuck pigs would be very costly or impractical.

On long downhill slopes where pigs with a relatively small amount of water behind them will run away from the line-fill water, an attempt should be made to hold a back-pressure at the incoming scraper trap equivalent to the elevation head behind the pigs.

Water DisposalArrangements for disposal of water received with the pigs, and later the displaced line-fill water, should be carefully planned, particularly if environmental conditions control disposal into natural drainage. In any case the water received with the pigs should be run to a settling pond to catch mill scale and debris before it is released.

When the first displacement pig arrives at the incoming scraper trap, pumping should be stopped until the pig and any debris are removed from the trap. Providing the trap barrel is long enough to hold them, several of the following pigs can be received without stopping flow, since there will be no large debris with them. Should a pig stop at plugged or deformed pipe and have to be cut out of the line, it is usually necessary to repeat that series of pigs from the outgoing scraper trap, unless the plug is near the end of the section tested and little water has been lost and little air has entered the line behind the pigs.

762 Completion HydrotestingAfter displacing the air and filling the line with water during the completion scraper run, hydrostatic testing of the line (or section) can proceed. This involves pumping with suitable pressuring pumps to raise line pressure to a specified test pressure, blocking the line in to hold pressure, and observing line pressure for a period of time to determine if the line is tight.

Code RequirementsSection 437.4 of ANSI/ASME Code B31.4 covers hydrotesting of liquid lines, and requires proof testing of every point in the system to not less than 1.25 times the internal design pressure at that point for not less than 4 hours, followed by a reduced pressure of not less than 1.1 times the internal design pressure for not less than 4 hours. In other words, where lines are designed for maximum design pressures stressing the pipe to 72% of specified minimum yield strength (SMYS), the test pressure produces stresses of 90% of SMYS. API RP 1110, Recommended Practice for Pressure Testing of Liquid Petroleum Pipelines, gives guidelines for hydrotesting procedures and equipment, and a test record and certification form.

Section 841.3 of ANSI/ASME Code B31.8 covers testing of gas lines, and requires testing for at least 2 hours to the pressures tabulated in Code B31.8 Table 841.322 (e). Depending on the Location Class the test pressure ranges from 79% to 56% of SMYS if the maximum design pressure is based on design factors 0.72 to 0.40. See Section 443 of this manual. Code B31.8 allows testing with air or gas in Location



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Class 1 and air in Location Class 2, as well as with water. Code B31.8 has other provisions for special circumstances.

Company PracticeCompany practice is to test liquid lines to a pressure corresponding to 90% of SMYS regardless of maximum design operating pressure, unless limited to a lower pressure by valve or flange test pressure, and holding for a minimum of 24 hours or as long as needed to determine that there is no unaccounted-for line leakage. Stabili-zation of water temperature at ground temperatures and absorption of air remaining in the line into the water take some time, usually much longer than the 4-hour Code minimum, and affect the pressure in the line. After these effects have stabilized, pressure will hold constant in a tight line. Occasionally, very slight leakage at a flange, valve packing, or gage connection cannot be corrected, and this loss of water can be related to a continuing loss of line pressure.

For gas lines Company practice is to test them hydrostatically with water to at least the Code minimum test pressures and usually higher—up to 90% of SMYS, depending on location, service, and cost of repairs in event of pipe or weld failuThe test period should be a minimum of 24 hours, or as long as needed to detemine that there is no unaccounted-for line leakage. For station piping which is mostly aboveground, the shorter test periods allowed by the Codes are satisfac

Establishing Hydrotest PressuresThe objective in establishing completion hydrotest pressures is to stress as muthe line as is feasible to 90% of SMYS, taking into account the effects of differepipe grades and wall thicknesses, and different ground elevations along the linewell as expected operating pressures. Where the line is designed for a maximuallowable operating pressure (MAOP) of 72% of SMYS, the line hydrotest presis rarely limited by valve or flange test pressure (nominally 1.5 times maximum allowable operating pressure for the valve or flange), but this should be checke

For a short line having the same pipe grade and wall thickness for the entire lenin level terrain, the hydrotest pressure P (psi) is readily calculated as follows:

P = 0.90 × SMYS × (2t/D)(Eq. 700-1)

where:t = wall thickness, in.

D = outside diameter, in.

This will be the hydrotest pressure at the pressuring pump discharge, unless limby valve or flange test pressure.

This situation is rarely found on long cross-country pipelines. Rather, pipe is likto be of several wall thicknesses and, possibly, different grades. Also, ground etion differentials will produce hydrostatic head differentials. The hydraulic profilecan be used to represent hydrostatic pressures along the line at no-flow. The h



test

, the sign

feet va-

low e to st hen

OP that

static head at any point is the difference between a horizontal line (the test pressure for that section of line) and the ground elevation (see Figure 400-4 in Section 420).

For a given pipe grade and wall thickness, the pipe will be most highly stressed at the lowest ground elevation, and less highly stressed at other points along the section. The hydrotest pressure should be the pressure that will stress the pipe at the lowest ground elevation to 90% of SMYS. In some cases, a test pressure higher than 90% of SMYS at the lowest ground elevation may be used, to more closely approach 90% at other locations. In such cases the risk of potential pipe failure (since mill hydrotests were probably to 90% of SMYS) and repair and delay costs should be evaluated by comparing the SMYS value against actual mill test yield strength for the pipe. It is recommended that in no case should 100% of SMYS be exceeded in hydrotesting.

In establishing hydrotest pressures for different sections along a cross-country pipe-line, it is helpful to include a line on the hydraulic profile representing the calcu-lated head producing 90% of SMYS for each of the pipe grades and wall thicknesses along the line, as well as design hydraulic gradients and pipe MAOP based on 72% of SMYS. Keep in mind that all heads shown on the diagram are in feet of the design fluid, not water. (See Figure 700-17.)

For the example in Figure 700-17:

• Section A-B. A is the point where the pipe is stressed to 90% SMYS. Hydropressure is elevation A-B minus elevation PS, in feet of design fluid.

• Section B-C. B is the point for 90% SMYS. Hydrotest head is elevation B-Cminus ground elevation at B. If the section is pressured by a test pump at Atest pressure at the pump is elevation B-C minus elevation PS, in feet of defluid.

• Section C-D. The low point downstream of C is the point for 90% SMYS. Hydrotest pressure is elevation C-D minus the elevation at the low point, inof design fluid. With the test pump at A, the test pressure at the pump is eletion C-D minus elevation PS, in feet of design fluid.

Sections C-D, B-C, and A-B could be pressured in sequence at their respectivehydrotest pressures. However, if the test pump were at a source of water at thepoint near C, section C-D could be pressured but the test pump would then havbe moved first to C to test section B-C, then to B to test section A-B, with the tepressures at the pump taking into account the ground elevations at the pump wpressuring the section.

The permissible maximum allowable operating pressure (MAOP) for the pipe-line is established by the hydrostatic test. For pipelines in liquid service, the MAat each point along the line is 1/1.25—or 0.80—times the hydrotest pressure atpoint, as indicated for location x on Figure 700-17. A more convenient calculationfor the MAOP at location x in psi, established by hydrotest, is given by the following:



di-

rdi-

MAOPat x = 0.80 (Ptest at A - 0.4328 × ∆ Elevation)(Eq. 700-2)

where:Ptest at A = test pressure at location A, psi

∆ Elevation = ground elevation at x minus ground elevation at A, ft

Thus, although hydrotest head is represented on the diagram by a horizontal line, a line for the permissible MAOP will be above a horizontal line representing 0.80 times the hydrotest head at the low-point location where the pipe is stressed to 90% of SMYS. This can be significant in establishing maximum pump discharge pres-sures at station locations or suitability of “telescoped” pipe for pump shutoff contions.

Using the above calculation method, the MAOP established by hydrotest for thepipe may be plotted as shown in Figure 700-18. Taking into account on the coonate scale for the conversion from feet to psi, the hydrotest pressure line on the

Fig. 700-17 Hydraulic Profile: Hydrotest Heads



diagram is the invert of the ground profile. The pipe MAOP is 0.80 times the value of the hydrotest pressure, and so does not parallel the hydrotest pressure line.

Similar calculations and diagrams can be developed for gas pipelines, taking into account the Code design and test factors for the various location classes.

Where an allowance has been provided in the pipe wall thickness for corrosion or erosion for pipelines in slurry service, the hydrotest pressure should be calculated to stress the pipe to the same stress as if it did not have the corrosion/erosion allow-ance. For a line tested at 1.25 times the design maximum allowable operating pres-sure, the hydrotest pressure would then be as follows:

Ptest = 1.25 Pdesign × (tn/tmin)(Eq. 700-3)

where:tn = actual nominal wall thickness of the pipe, in.

Fig. 700-18 MAOP Established by Hydrotest



sures

cu-d

le-

a on

psi, sme-per

of ed

ct

tmin = pressure design wall thickness, in. (equal to the nominal wall thickness less the corrosion/erosion allowance)

This hydrotest pressure should be used as a basis in selecting valve and flange ratings. Valves and flanges having lower test pressure than the pipe hydrotest pres-sure must be isolated so they are not overpressured.

Establishing hydrotest pressures for the line sections—and corresponding presfor the test pump discharge and for different locations along the line—does not involve complex calculations. It does require a logical analysis of pressures callated by the hoop stress equation, and a careful accounting for hydrostatic headifferentials for the different ground elevations along the line.

Equipment for HydrotestingTypical equipment for hydrotesting includes the following:

• Pumping system. The pumping system comprises the following:

– The water supply system, with a high-volume pump used for the comption scraper run

– A low-volume, variable-speed, positive-displacement test pump, with known volume per stroke, and a stroke counter. The pump should haverelief valve to protect the pump from overpressuring and a check valvethe pump discharge piping

– A tank on the suction line to the test pump, suitable for measuring the volume pumped into the line

• Instruments

– A Bourdon-tube pressure test gage, calibrated before the test, with a reading accuracy of 0.1% of full scale

– A deadweight pressure tester, capable of measuring increments of 1.5certified for accuracy and traceable to the National Bureau of Standard

– A 24-hour pressure recorder—checked using the deadweight tester imdiately before and after use—with a supply of properly ranged chart pa(test pressure should be about 80% of maximum scale)

– Pressure gages, calibrated before the test, with reading accuracy of 1%full scale for use at locations along the line where pressures are observ

– Thermometers for measuring water, ground and air temperatures– A 24-hour temperature recorder, with the temperature detector in conta

with the pipe at a point where it has normal cover



Typical Hydrotest SequenceWith air purged from the line and the line filled with water after a successful completion scraper run, a typical hydrotest sequence is as follows:

1. Pressure the line with the high-volume pump used for the completion scraper run line-fill, to the pump shut-off head (but not exceeding about 75% of the test pressure).

2. Verify that the line pressure recorder and underground pipe temperature recorder are in operation, set at real time.

3. Pressure the line with the pressure test pump to 70% to 80% of the test pres-sure. If it is late in the day it is preferable to stop pressuring until the next morning to allow time for water temperatures to stabilize at ground tempera-tures and to use daylight for final pressuring. However, often the contractor and sometimes the Company want to proceed with testing without any interruption.

4. Pressure the line gradually with the test pump in increments of about 2.5% of test pressure every ten minutes unless pump capacity is limiting. While pres-suring observe and record, at five-minute intervals, (1) pressures, using the deadweight tester and the test gage, (2) volume of water pumped as measured in the tank, and (3) pump stroke counter reading. At about 20-minute intervals check the pressure recorder readings against the deadweight pressures to confirm that the recorder is functioning properly. If there should be a sudden drop in pressure, indicating a line break, record the pressure just before the drop and stop pumping.

5. When the test pressure is reached, stop the test pump. Care must be taken not to exceed the maximum test pressure, particularly for short lines. If the pressure should drop below test pressure within a few minutes and then appear to stabi-lize, resume pumping to raise the pressure to test pressure again while continuing to observe and record data. Disconnect the pump from the line. Continue observing and recording deadweight pressures at 5-minute intervals for at least an hour, and 15 minutes thereafter until the end of the test.

6. In the event warm ground temperatures cause the line pressure to increase above the maximum test pressure, water must be bled slowly and carefully from the line to lower the pressure to test pressure. The water should be drained to the tank so that the volume can be accurately measured, using the dead-weight tester for pressure data while lowering the line pressure. If line pressure again rises to the maximum, this operation will need to be repeated.

7. In many cases the line pressure drops after first reaching test pressure, either because the water has cooled to ground temperature or because of air absorp-tion into the water at high pressure. If the drop is due to these effects, the rate of pressure drop will decrease and the pressure will eventually stabilize and hold. If pressure drops appreciably before finally stabilizing, the pressuring pump should be reconnected and the pressure raised to test pressure, again observing and recording data.



ents,

fill, r is

nec-

es-

re

ody ot be

8. If the pressure drop has stabilized and the pressure held steady for at least 4 hours, the test can be considered satisfactory after 24 hours, or after 4 hours of stabilized pressure if this takes longer than 24 hours.

9. At the end of a satisfactory test in which there are line block valves at the ends of the section under test, the line is depressured until there is a positive pres-sure of, say, 50 psi at the high point of the section. If it is necessary to make a welded or flanged connection to the next section of line, then the line will have to be drained sufficiently to make the connection.

While pressuring the line and holding pressure, all connections and manifolds in the test section should be closely monitored for leakage and failure. Where feasible work should be done to correct any leakage.

763 Test Procedure and ProgramA detailed procedure for completion testing should be prepared. This procedure should be carefully reviewed and agreed to by Company field personnel and contractor supervisory personnel involved in the testing. The procedure should include the following elements:

• A ground profile for the section of line to be tested, with a diagram showinglocations of scraper traps, block valves and check valves, pressure instrumand temperature instruments

• A diagram of the pumping and metering system for the scraper run and linefrom water source to the pipeline connection, including pressure-measuringinstruments, and a list of equipment data. If filtering or treatment of the wateneeded, the diagram should include this equipment

• A list of pigs to be run, gage plate diameter, and volumes of water to be pumped ahead of and between pigs

• A list of detection devices for following and locating pigs

• A diagram for the pressure test pump system, from water source to the contion to the pipeline, including equipment for measuring volume of water pumped into the line, pressure-measuring instruments, provision for overprsure relief, and a list of equipment data

• Maximum and minimum test pressures at the pump and the primary pressuinstrumentation

• Calculated test pressures at other locations along the line

• Minimum period for holding the line at test pressure

• Calculation methods for analyzing effects of water temperature change, airvolume in the line, and water compression

• Identification of connections and appurtenances on the line that must be blinded, plugged or disconnected. Mainline valves may be equipped with brelief valves that must be plugged or removed. Hydrotest pressure should n



bove

el r-g. A pig e nd

ur-

r and r

l

tion

ck

applied to a closed valve if the pressure differential across the valve exceeds the valve test shutoff pressure

• Precautions and measures required if ambient or night chill temperature is below freezing

• Procedures required if daytime temperature and solar radiation effects on exposed pipe or test equipment are likely to cause pressures to increase athe maximum

• Safety precautions

• Communications units for Company and contractor

• Test personnel organizations for Company and contractor

• Notification of government agencies, where test witnessing is required

• List of agencies to be notified in event of a water spill resulting from a line rupture

• Arrangement for aerial inspection service in event of line rupture or leak

The overall testing program should be described in outline form, with a tentativeschedule for the scraper run and pressure testing. This should indicate personnduties and work schedule for testing crews. Testing usually is done on a 24-houper-day basis, possibly with a short interval between line fill and pressure testindefinite hour-by-hour schedule for the program cannot be set, since the rate of travel and times to build up to pressure test and hold at test pressure can only bestimated. Allowances must be considered for maintenance of test equipment apossible pipe leaks and repairs.

Example Testing ProgramAn example of a pipeline testing program is given in Figure 700-19. This is the same system for which the hydraulic profile, pipe wall thicknesses, and line apptenances were shown in Section 430, Figure 400-9. A suitable water supply for scraper runs and line fill is available at two rivers. The pipe strings at these rivecrossings were hydrotested after installation, but not tied in at the upstream lineblock valves. A temporary launching scraper trap manifold has been fabricated,will be reused for each of the four scraper runs. The line block valves at the rivecrossings will be used to isolate the temporary trap manifold from the line. The sequence of testing is as follows:

1. Set up the fill and test pump facilities at the river crossing between the initiapump station and the intermediate pump station.

2. Make the scraper run from the river to the initial pump station. Pack this secwith the fill pump.

3. a. Make the scraper run from the river to the intermediate pump station. Pathis section with the fill pump.



ng a igh

e at

ad C een

D,

res-

res-

b. Concurrently, pressure test line section A at hydrotest head A above the ground elevation at the river.

4. Pressure test line section B at hydrotest head B (same as A).

5. After satisfactory tests on sections A and B and depressuring to a head some-what greater than the ground elevation difference between the river and the intermediate pump station, proceed as follows:

a. Tie in the line at the river crossing.

b. Move the fill and test pump facilities to the other river crossing, downhill from the ground high point. (“control point”)

6. Make the scraper run from the river to the intermediate pump station, holdibackpressure on the line at the intermediate pump after the pigs pass the hpoint. Pack this section with the fill pump.

7. a. Make the scraper run from the river to the terminal, holding backpressurthe terminal to keep the pigs from running away from the fill water.

b. Concurrently, pressure test line section F at hydrotest head F above the ground elevation at the river.

8. Pressure line sections E, D, and C in order to test section C at hydrotest heabove the ground elevation at the river, and close the line block valve betwsections D and C.

9. Pressure line sections E and D in order to test section D at hydrotest head and close the line block valve between sections E and D.

10. Pressure test line section E at hydrotest head E.

11. After satisfactory tests on sections C, D, E and F:

a. Depressure sections E and F to a head sufficient to maintain a positive psure at the high point of the route (“control point”).

b. Depressure sections C and D to a head sufficient to maintain a positive psure at all points in these sections.

c. Tie in the line at the river crossing.

12. Demobilize and clean up all test sites.

Analysis of Hydrotest DataSeveral effects must be considered in analyzing data observed while pressure testing:

• Elastic strain in the pipe due to internal pressure• Compressibility of water under pressure• Expansion/contraction of steel due to temperature changes• Changes in volume/density of water due to temperature changes



Fig. 700-19 Hydraulic Profile: Pipeline Testing Program



tion- be

e

the l (for

• Absorption of air into water under pressure, and remaining free air

For a pipeline filled with liquid under pressure at constant temperature (disre-garding effects of air absorption or free air in the line) the pressure-volume relaship (considering elastic strain in the pipe and compressibility of the water) mayexpressed as follows:

(Eq. 700-4)

where:dV = incremental volume in same units as V

V = fill volume of the section under test

dP = incremental pressure, psi

D = outside diameter, in.

t = wall thickness, in.

E = modulus of elasticity of steel, psi

= 30 x 106 psi

ν = Poisson’s ratio = 0.3

C = Bulk compressibility factor of liquid, per psi (the reciprocal of thbulk modulus). See Figure 700-20.

The above equation thus becomes:

(Eq. 700-5)

Approximate values of C for water are shown in Figure 700-20.

Temperature changes will cause pressure changes in a tight line. The effect of thermal expansion (or contraction) of water, offset by the thermal circumferentiaexpansion (or contraction) of the pipe, yields a volume-temperature relationshipa restrained line) as follows:

(Eq. 700-6)



ine is

res - er-

where:β = volumetric coefficient of expansion of liquid/°F. See

Figure 700-21.

α = linear coefficient of expansion of the pipe per °F

= 6.5 x 10-6 per °F for steel

dT = temperature change, °F

From Equations 700-5 and 700-6, a pressure-temperature equation for a tight las follows:

(Eq. 700-7)

Values of β for water are given in Figure 700-21.

For a long buried pipeline it is not feasible to measure the pipe/water temperatufor the length of the line, and difficult to predict the effect daily ambient temperature variations may have on pipe and water temperature. It is important to allowsufficient time after line fill for water temperatures to equalize with ground temp

Fig. 700-20 Compressibility Factor of Water



free

e s.

nge

atures. The time for equalizing will be a function of the differential between the source water temperature and ground temperatures, as well as of the pipe diameter.

For a relatively long section of line, the temperature of the fill water reaching the end of the section with the initial scraper run pigs will probably be close to the ground temperature. Thus, an approximate temperature differential between water entering the line and the ground can be estimated and used in judging the time needed for water temperatures to equalize with ground temperatures.

Any air remaining in the test section will complicate an analysis of the pressure-volume data obtained in hydrotesting. With increasing pressure, air is absorbed into the water at an indeterminate rate—probably fairly quickly—until the saturationpoint is reached. Once absorbed the air has no further effect, but any remainingair behaves as a compressed gas. The volume of this air can be calculated by comparing the actual pressure-volume relationship from the hydrotest data at thtest pressure range with the theoretical pressure-volume relationship, as followUsing test data:

∆V = actual volume of water into line between P1 and P2

Then the difference between actual volume change and theoretical volume chais:

Fig. 700-21 Volumetric Coefficient of Expansion for Water



fec-ani-

(Eq. 700-8)

A calculation for the percentage volume of free air in the test section then is:

(Eq. 700-9)

where P1 and P2 are absolute pressures, psia.

If there is some doubt whether sufficient time has been allowed for air absorption and water-ground temperature equalization, allow some time, then bleed a measured volume of water from the line, record the corresponding drop in pressure, and use these data to calculate the percentage volume of free air.

Temperature changes and air in a test section cannot be calculated with great preci-sion, but the calculations given can indicate the range of their effects for purposes of analyzing a very slow drop in pressure. Additional temperature measurements along the line may be warranted. Compressed free air hides the size of a slow leak, and so should not be overlooked if its volume is more than a few percent.

764 Line Rupture and LeakageWhen the line hydrotest indicates a pipe rupture, (a sudden large drop in pressure) or leakage (a continuing gradual decrease in pressure) prompt action should be taken to locate and repair the failure. In nearly all cases, the failure will be due to defective or damaged pipe rather than a girth weld. Flange or valve packing leakage may also be a cause. Since the line pipe is usually furnished by the Company, costs for the contractor’s crew and equipment to stand by and make repairs due to detive pipe will be charged to the Company’s account, and the Company field orgzation should act to minimize these costs.



s-

e ll

Pipe RuptureIn the case of pipe rupture, pressures at the test pump and at available locations along the section under test should be reported as soon as possible. Analysis of hydrostatic heads will pinpoint the location of the rupture, or narrow the length of line in which the rupture must have occurred. For example (referring to Figure 700-19) the location of a pipe rupture that has occurred while testing section B, where the observed hydrostatic head at the test pump at the river crossing corre-sponds to the ground elevation differential between the river and the future pump station, would be in the vicinity of the future pump station. However, if the terrain is nearly level, line pressures will be essentially zero, and visual inspection along the entire length under test will be necessary to locate the rupture. Unless underwater, a pipe rupture is often easily spotted, as a wet area where the water has drained out and usually by a pit washed out by the sudden release of water.

Leak LocationIn the case of gradual loss of pressure, indicating a leak, the line should be repres-sured to the hydrotest pressure. If there are line block valves within the section under test, they should be closed to isolate shorter sections of line, and pressures observed to determine the section with the leak.

Finding a leak (see Figure 700-22) may be difficult and time consuming. The leak may or may not show as a wet spot on the ground, depending on the amount of leakage and nature of the soil. The rate of leakage (volume) should be correlated with the rate of pressure drop. This will give an indication of the amount of water that has leaked out, the rate of leakage as time goes on, and the likelihood of observing it. Sonic detection devices may be helpful in locating the leak (see Section 840). Leaks from small defects in the pipe or weld usually increase with time as the hole is enlarged by the “wire drawing” action of the water at high presure. On short lines it may be feasible to displace the water with air to which a mercaptan odorizer has been added, and locate the leak by odor.

In wet areas or swamp, if a preliminary hydrotest has not been performed on thpipe strings, addition of a biologically acceptable red or yellow dye to the line-fiwater may be warranted to help locate a leak.

Fig. 700-22 Leak Detection Alternatives

Leak Masked By Detection Method

Frozen ground Mercaptan (skunk gas)

Open water or swamp Biodegradable Dye

Gas Bubbles

Mercaptan

Vegetation Drive/Walk Line

Any condition Measure Input Volumes

Acoustic Detector

Sectionalize, Excavate, Test



Aerial ObservationAerial inspection of the route under test is a good way to quickly search for the location of a rupture or leak. Arrangements for aerial inspection and radio commu-nications between plane and ground should be made in advance of the test so that no time is lost if a rupture or leak occurs.

770 Dewatering and DryingAfter satisfactory hydrotesting, the pipeline should remain full of water until it is put into operation unless service conditions require displacement, drying or dehy-drating before operation. The water fill minimizes corrosion during the period before the line goes into service and facilitates effective and controlled displace-ment of the water. However, gas lines may require displacement with nitrogen or drying to prevent hydrate formation. Dehydrating may be necessary to prevent corrosion, as for CO2 service.

771 DewateringThe basic dewatering procedure involves running a series of displacement pigs or spheres propelled by the normal stock in the line, putting the pipeline system into operating readiness. Some important factors to consider are as follows:

Disposal of the Displaced Water. Disposal of the displaced volume or water at the intended flow rate should be planned carefully and must be acceptable to environ-mental authorities. If the volume of water presents a problem at the pipeline terminal, it may be feasible to release some of the water at intermediate points. If treatment chemicals have been added to the water, environmental consequences must be considered, particularly if biocides have been added to the fill water. See Section 760.

For Liquid Lines. An adequate inventory of stock should be available to displace the line or sections of line that can be isolated by block valves until another supply of stock can be accumulated and dewatering resumed. While displacing water with oil, the hydraulic profile for a two-stock system should be recognized (see Section 420).

For Heated Oil Lines. A procedure must be developed for raising ground tempera-tures sufficiently to avoid cooling heavy or waxy oil to temperatures that would cause plugging when initially introducing it into the system. This may involve startup with heated light oil or diluted heavy oil, or circulation of hot water. See Section 810 for precautions involving initial warmup of hot lines.

For Gas Lines. To displace the water in hilly or mountainous terrain, sufficient pressure must be available to overcome the hydrostatic head of the water. If there are appreciable elevation differences along the line, control of pressure, rate of gas flow into the line, and rate of water released should be carefully planned, with consideration of the expansion of gas when it overcomes hydrostatic head at high points and as fluid friction of the water decreases.



a-

drate

elow left d y-pres-

um -

g.

gs) igs ing, pig ch-

If gas pressure is not sufficient to overcome the hydrostatic head, the line must be drained to the extent practical and nitrogen used for further dewatering to avoid explosive gas-air mixtures. In calculating the required pressure and resultant volume of nitrogen needed for displacement, the cumulative effect of the water remaining in undrained low spots along the line must be taken into account.

Gas lines operating at pressures at which hydrate formation occurs must be dried or have methanol injected to prevent hydrate formation. See Section 820.

772 Drying and DehydratingFor certain services, removal of remaining quantities or traces of water is required to:

• Avoid formation of gas hydrates

• Minimize corrosive action where the presence of water is the contributing factor

• Maintain purity of stock, e.g., ethylene, propylene, ammonia

The degree and method of water removal required depend on the particular sitution. The usual methods of drying to remove traces of liquid are:

• Purging with available unsaturated gas at pressures below that at which hyformation occurs

• Purging with unsaturated nitrogen or unsaturated air

• Drying by evacuating air or gas from the line to a high vacuum

Dehydrating reduces the water content in the gas, nitrogen or air considerably bthe saturation point—to a few parts per million—so that the gas, nitrogen or air in the line prior to startup is at the specified level of dehydration. Trailer-mounteunits employing a molecular sieve or chilling process are generally used for dehdration, and a large number of foam displacement pigs are run, using large comsors to propel them through the line over a number of line displacements. Vacudrying may be suitable for relatively short lines with minimal trapped water. Pipeline Dehydrators, Houston, Texas, and Coulter Services, Houston, Texas, are specialist contractors capable of performing pipeline dehydrating and dewaterin

773 Gelled-Fluid PigsNew technology for using cohesive, highly viscous fluids as pigs (gelled-fluid pihas been developed by Dowell Schlumberger, Houston, Texas. These gelled pcan be used alone or in conjunction with mechanical pigs for cleaning, dewaterand drying with methanol and nitrogen, as well as for batch separation. A gelledwas used on the Ninian tie-in in the North Sea, and the industry has used the tenology in a number of applications for liquid and gas pipelines.



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t. th

780 Typical Field Inspection Organization

781 ObjectivesAlthough its primary function is to monitor and enforce the technical provisions of the construction specifications, the Company field inspection organization, as part of the construction supervision team, is responsible for achieving the overall project objectives outlined in Section 670. Because construction operations for cross-country pipelines extend over a considerable distance, individual inspectors and field engineers must act as Company representatives in dealing with landowners, tenants, governmental agencies and the public, in addition to inspecting craft work-manship. They also have a very important role in enforcing Contractor compliance with safe work practices (see Section 810).

Consistent high-quality workmanship, uniformly monitored by Company inspec-tors and engineers, is critical on a cross-country pipeline project for the following reasons:

• Once in the ground the line is truly buried—today’s work must be inspectedtoday, not tomorrow

• Pipeline design provides an adequate, but not generous, safety factor undeoperating conditions—flaws cannot be tolerated

• The pipeline is not on Company property—future maintenance access anddamages to facilities of others will be costly

• Consequences of line failures and resultant spills are serious and costly—eof injury, fire or property damage may be high

• Governmental and other agencies closely examine construction methods aoperation performance, and records—post-construction review of documention that reveals unacceptable work or faulty records can require immenselexpensive corrective work; (e.g., radiographs showing welding defects thatwere not repaired)

782 Selection of Field Inspection PersonnelSelection of the field inspection personnel should be based on the following strengths:

• Technical proficiency

• Reliability and motivation

• Confidence in making well-founded decisions

• Ability to work well with the Company field supervision team, the Contractosupervisory personnel, and the public

Pipeline construction inspectors should be fully qualified in the craft they inspecWhere technical competence is required, they should be completely familiar wi



oce-

ec- field

-end

e

gi-

ht-i-.

close f one se. A f

construction techniques and code requirements, and preferably certified by national technical organizations. For example, welding and tie-in inspectors should hold current American Welding Society (AWS) CW-1 certification to API Standard 1104 or to ANSI/ASME Codes; the backfill inspector should be knowledgeable in soil compaction techniques and testing. High motivation and a proprietary attitude toward the project and the Company are important qualities, but are no substitute for formal training and experience. Because of the linear nature of pipeline construc-tion every task is on the critical path. A pipeline construction job is not the place to provide training for inspection skills for a craft in which a man is not qualified.

783 Inspection Functions and StaffingInspection functions for pipeline construction are outlined in Appendix E, Field Inspection Guidelines, which were prepared for a 1987-89 Chevron Pipe Line Company project. Normally, an individual inspector or field engineer would be responsible for the combined functions of several of the separate “inspector” prdures in Appendix E. The circumstances for a particular pipeline construction project will naturally influence the makeup of the field supervision staff and insption organization and thus determine the appropriate number of inspectors andengineers. The following should be considered:

• Number of construction spreads for the project

• Length of line, or segment for each spread, and expected length from frontto cleanup-end activities for each spread

• Extent of developed areas and surface or underground congestion along throute

• Expected rate of construction progress for each spread

• Unusual aspects of construction: materials, terrain, climate, remote location

• Conditions of permit and right-of-way requirements that affect construction methods and reporting

• Experience and known capabilities of candidates for inspectors and field enneers

For a short line on properties with few natural obstructions or special permit/rigof-way conditions, construction inspection can well be covered by one field engneer and one inspector, one of whom should have welding inspection expertise

For a section of line in a very congested area, requiring a compact spread and contacts with agencies and owners, the inspection organization might consist ofield engineer and three inspectors, at least one with welding inspection expertifront-end inspector would cover excavation activities, particularly at crossings oroads, streets and existing buried lines, and stringing and bending. A pipeline inspector would cover line-up, welding, coating, and lowering-in. A tie-in and cleanup inspector would cover back-end work. The field engineer would probably



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devote his attention to contacts with agencies and owners, with less time for inspec-tion.

For a cross-country spread in open country, agricultural lands, and intermediate-density developed areas, a typical inspection organization might be:

• A front-end field engineer, covering general activities of the first half of the spread, including survey, receipt and storage stockpiling of pipe, and doubljointing yard and/or field coating yard if set up

• A front-end inspector, covering temporary fencing, clearing and grading, exvation, padding, and stringing

• A line-up and welding inspector, with welding inspection expertise, coveringbending, line-up and welding

• A coating and lowering-in inspector, covering coating, lowering-in, shading,and backfill

• A tie-in inspector, with welding inspection expertise, covering tie-ins, cathoprotection test stations, and crossings

• A back-end field engineer, covering general activities of the last half of the spread, including crossings, grade restoration, cleanup and revegetation

• If a double-jointing yard is set up, a double-jointing inspector, with welding inspection expertise, supported by full radiographic inspection services. If afield coating yard is setup, a coating inspector. If both double-jointing and ficoating yards are set up and are at the same location, one qualified inspecmay be able to cover both

As mentioned in the discussion on the field supervision organization in Sectionthe Company field inspection organization outlined in the above paragraph woube supported by a construction manager or spread engineer, a permit/right-of-wagent, and the construction office or home office accounting and clerical staff. Inspectors would have vehicles suitable for the terrain and two-way radios.

The work schedule for the field inspectors and engineers must correspond to thcontractor’s working hours. This nearly always requires an extended work day work week schedule, with occasional 7-day weeks for a portion of the inspectiogroup. Usually, completion testing is done after most spread activity is completethe inspection group can be assigned to cover the round-the-clock monitoring ocompletion testing. However, if full-spread work is proceeding while completed sections are being tested, arrangements should be made to supplement the instion team with additional personnel to provide Company coverage of completiotesting without affecting spread inspection.

Resources for staffing the inspection organization are Company-wide maintenaand inspection organizations, and inspection services contractors; see the discof construction and construction service contracts in Section 680.



784 Inspection ReportsA number of typical inspection audit report forms are included in Appendix E, Field Inspection Guidelines. Clear and concise reporting of technical and progress data is important. Also, factual accounts of working conditions, industrial injuries, discus-sions with contractor personnel, landowners of crossed facilities, etc., should be kept in diary form by each member of the field engineering inspection team. Diaries should be in a bound notebook with numbered pages, in ink, and dates and line station locations should be accurately noted.

790 ReferencesNote Consult the latest edition of each reference for information.

General1. Welding Inspection, American Welding Society. New York.

2. Guide for the Nondestructive Inspection of Welds, American Welding Society, AWS B1.10. New York.

3. API Recommended Practice 5L8 for Field Inspection of New Line Pipe.

Visual Inspection4. ANSI/ASME Boiler and Pressure Vessel Code, Section V, Article 9. New York.

5. ANSI/ASME B31.4., Liquid Petroleum Transportation Piping Systems, New York.

6. ANSI/ASME B31.8., Gas Transmission and Distribution Piping, New York.

7. API STD. 1104, Standard for Welding Pipelines and Related Facilities, Wash-ington, D.C.

Magnetic Particle InspectionAnnual Book of ASTM Standards, Volume 03.03 - Nondestructive Testing (Refer-ence No. 8 and No. 9):

8. ASTM E-709, Standard Guide for Magnetic Particle Inspection.

9. ASTM E-1316; Standard Terminology for Nondestructive Examinations, Section G: Magnetic Particle Examination.

10. ANSI/ASME Boiler and Pressure Vessel Code, Section V, Article 7. New York.

11. ANSI/ASME B31.4, Liquid Petroleum Transportation Piping Systems, New York.

12. ANSI/ASME B31.8, Gas Transmission and Distribution Piping, New York.



Radiographic InspectionAnnual Book of ASTM Standards, Volume 03.03 - Nondestructive Testing (Refer-ence No. 13 - 17):

13. ASTM E-94, Standard Guide for Radiographic Testing.

14. ASTM E-142, Standard Method for Controlling Quality of Radiographic Testing.

15. ASTM E-390, Standard Reference Radiographs for Steel Fusion Welds.

16. ASTM E-1316, Standard Terminology for Nondestructive Examinations, Section D, Gamma- and X-Radiology.

17. ASTM E-242, Standard Reference Radiographs for Appearances of Radio-graphic Images as Certain Parameters are Changed.

18. ANSI/ASME Boiler and Pressure Vessel Code, Section V, Article 2. New York.

19. See reference 5.

20. See reference 7.

Ultrasonic InspectionAnnual Book of ASTM Standards, Volume 03.03 - Nondestructive Testing (Refer-ence No. 21 - 24):

21. ASTM E-164, Standard Practice for Ultrasonic Contact Examination of Weld-ments.

22. ASTM E-1316, Standard Terminology for Nondestructive Examinations, Section I, Ultrasonic Examination.

23. ASTM E-213, Standard Practice for Ultrasonic Examination of Metal Pipe and Tubing.

24. ASTM E-587, Standard Practice for Ultrasonic Angle-Beam Examination by the Contact Method.

25. ANSI/ASME Boiler and Pressure Vessel Code, Section V, Articles 4 and 5. New York.


ppl700 inspection and testing

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