Piping Interview Tips

Inspection Engineer Interview points Piping Commonly used Construction codes: ASME B 31.1 (Power piping) ASME B31.3 Process Piping, ASME B31.4 Liquid transportation piping ASME 31.8 Liquid petroleum transmission piping API 1104 Welding of pipeline What are the main deference between ASME B 31.3 & ASME B31.4? The allowable stress is not the same. Minimum thickness formula is not same. One is for the piping inside the plant and the other one is for transportation. Inspection: API 570, API RP 574 Material: ASTM A53, ASTM A106, SA 135, SA 333, SA 671, SA 672, API 5L, SA 268, SA 213, SA 312, SA 790, etc., a) Carbon Steel Pipe API 5L, Grade A or B, seamless API 5L, Grade A or B, SAW, str. seam, Ej ≥ 0.95 API 5L, Grade X42, seamless API 5L, Grade X46, seamless API 5L, Grade X52, seamless API 5L, Grade X56, seamless API 5L, Grade X60, seamless ASTM A 53, seamless ASTM A 106 ASTM A 333, seamless ASTM A 369 ASTM A 381, Ej ≥ 0.90 ASTM A 524 ASTM A 671, Ej ≥ 0.90 ASTM A 672, Ej ≥ 0.90 ASTM A 691, Ej ≥ 0.90 (b) Low and Intermediate Alloy Steel Pipe ASTM A 333, seamless ASTM A 335 ASTM A 369 ASTM A 426, Ec ≥ 0.90 ASTM A 671, Ej ≥ 0.90

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ASTM A 672, Ej ≥ 0.90 ASTM A 691, Ej ≥ 0.90 (c) Stainless Steel Alloy Pipe ASTM A 268, seamless ASTM A 312, seamless ASTM A 358, Ej ≥ 0.90 ASTM A 376 ASTM A 451, Ec ≥ 0.90 (d) Copper and Copper Alloy Pipe ASTM B 42 ASTM B 466 (e) Nickel ASTM ASTM ASTM ASTM

and Nickel Alloy Pipe B 161 B 165 B 167 B 407

(f) Aluminum Alloy Pipe ASTM B 210, Tempers O and H112 ASTM B 241, Tempers O and H112 Low temperature service material & fittings Product Form

ASTM Spec. No.

Pipe

A 333

Tube

A 334

Fittings

A 420

Forgings

A 350

Castings

A 352

Bolting

A 320

Plate

A 20

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The primary elements in determining the minimum acceptable diameter of any pipe network are system design flow rates and pressure drops. The design flow rates are based on system demands that are normally established in the process design phase of a project. The hydraulic design of a piping system is premised on selecting the optimum pipe size (diameter) and thickness (schedule), for the design flow rate and the allowable pressure drop in the system. 89358063.doc

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For a specific flow rate, as the pipe diameter increases, the pressure drop increases at a fast rate (pressure drop varies approximately with the square of the velocity). This means that the pumping horsepower required would increase resulting in a higher pump cost and on-going operating energy costs. On the other hand, as the pipe diameter decreases, the installed cost of the piping system (pipe, fittings, valves) also decreases. The optimal solution is to find the pipe size that would result in the lowest life cycle costs (initial installed cost plus operating costs over the life of the piping system. Piping and Instrumentation Diagram (P&ID) The primary element of a piping design is the piping and instrumentation diagram (P&ID). Both the process engineer and the instrument and controls engineer provide design information. The first version should represent all major equipment, process piping with sizes, utility piping with sizes, and line-mounted instrument hardware. The piping design team is responsible for drafting the P&ID. The P&ID is commonly referred to as the control document for design and construction and subsequently for operation and maintenance. For the pipe designer, the diagram is a complete mechanical description. It is an engineering expression of the processscope of work. It is imperative to maintain the P&ID up to date and to control and communicate the revisions to the design group to ensure that the design is based on the latest revision. Piping components shall be designed for an internal pressure representing the most severe condition of coincident pressure and temperature expected in normal operation. This condition is by definition the one that results in the greatest required pipe thickness and the highest flange rating

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MATERIAL SELECTION Materials selection is an optimization process, and the material selected for an application must be allowed by the applicable code; and chosen for the sum of its properties (strength, toughness, corrosion resistance, etc), availability, and cost. Thus, the selected material may not rank first in each evaluation category; but it should be the best overall choice In practice it is usual to select materials which corrode slowly at a known rate and to make an allowance for this in specifying the material thickness. Material Selection Process Piping material is selected by optimizing the basis of design. 1. Eliminate from consideration those piping materials that: a. Are not allowed by code or standard; b. Are not chemically compatible with the fluid; c. Have system rated pressure or temperatures that do not meet the full range of process operating conditions; and d. Are not compatible with environmental conditions such as: external corrosion potential, heat tracing requirements, ultraviolet degradation, impact potential, and specific joint requirements. 2. The remaining materials are evaluated for advantages and disadvantages such as capital, fabrication and installation costs; support system complexity; compatibility to handle thermal cycling; and cathodic protection requirements. The highest ranked material of construction is then selected. 3. The design proceeds with pipe sizing, pressure integrity calculations and stress analyses. If the selected piping material does not meet those requirements, then the second ranked material is used and the pipe sizing, pressure-integrity calculations and stress analyses are repeated.

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PRESSURE-INTEGRITY DESIGN The pressure-integrity design of a piping system normally requires the consideration of at least two issues. The first is the determination of the minimum or nominal pipe wall thickness, and the second is the determination of the pressure rating of the in-line components such as valves and fittings. The design process for consideration of pressure integrity uses allowable stresses, thickness allowances based on system requirements, and manufacturing wall thickness tolerances to determine minimum wall thickness Current Basis for Determining the Allowable Stress (S) As a result of the introduction of new materials and increases in service temperatures, use of “Safety factors” was abandoned and the factor became part of the allowable stress for a material at any temperature. The allowable stress is based on the least of the following: • • • • •

Room-temperature tensile strength / 3.5 Room-temperature yield strength / 1.5 The stress required to cause a creep rate of 0.0001%/1000 hours The average stress to cause rupture at 100,000 hours / 1.5 The minimum stress to cause rupture at 100,000 hours / 1.25

Today, fracture mechanics allows an engineer to establish the minimum toughness required in a material based on the stress applied and the maximum credible size flaw. These changes eliminated concern over brittle fracture. In addition, Section VIII requires that hydrostatic testing be performed at the minimum design metal temperature plus atleast 30°F, ensuring that brittle failure will not occur during hydrostatic testing

Design Margin (“Safety Factor”) in the ASME Boiler and Pressure Vessel Code In the 1999 addenda of the ASME Boiler Code, the design margin (formerly known as the “Safety Factor”) was changed from 4.0 to 3.5. ASME B31.3 has had a design margin of 3.0 for more than 20 years ASME B31.1 is in the process of changing to 3.5, but may change to 3.0.

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PIPING SYSTEM DESIGN PROCEDURE The following flowchart shows the typical procedure used in designing piping systems

PIPING LAYOUT AND ISOMETRIC DRAWINGS Flow diagrams, line lists and design specifications are all used by the piping designer to lay out the piping and generate design drawings. Piping of the size and schedule must be routed between the appropriate pieces of equipment as shown on the flow diagrams. Routing will be affected by system operating temperature, pipe weight, installation and material costs, applicable code requirements, pressure drop requirements and equipment and building structure locations. Piping isometrics are three-dimensional representations of the piping system using a ±30° orientation of the two horizontal axes. Piping not running parallel to one of the main axes is shown by its components in each direction. Isometrics need not be drawn to scale; the piping segments may be drawn as long as is necessary for clarity

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Bolting material: ASTM A 193 grade B7 bolting for ordinary service. ASTM A 193 grade B7M bolting for areas exposed to hydrogen sulfide service Hydro test pressure: 1.5 X design pressure What is the difference between pipe & tube? The word pipe is used, as distinguished from tube, to apply to tubular products of dimensions commonly used for pipeline and piping systems. Pipes NPS 12 (DN 300) and smaller have outside diameters numerically larger than their corresponding sizes. In contrast, the outside diameters of tubes are numerically identical to the size number for all sizes. Minimum required thickness calculation: Pipe the minimum required thickness is ‘t’, the nominal thickness is t + corrosion allowance The ‘t’ as per API RP 574 is t=PD / 2SE where P-Design Pressure, D-OD of pipe, S-allowable stress as per the code, E-quality factor (for Seamless pipe it is One). This formula is used for in-service piping. The ‘t’ as per ASME B31.3 is t=PD / 2(SE+PY) where P-Design Pressure, D-OD of pipe, S-allowable stress as per the code, E-quality factor (for Seamless pipe it is One), Y-0.4 for carbon steel upto 400°F. This formula is used only for new construction. For OD of piping up to 12” refer API RP 574 piping schedule table. Above 12” the OD is the size of the pipe.

ASME B 31.3 formula

tm =

PD +C 2( SE + Py )

Where S – Allowable Stress D - Outside diameter E - longitudinal joint factor obtained from relevant Table P - Design Pressure Y - temperature factor C - Corrosion & mechanical allowance ASME B 31.4 formula tm =

PD +C 2S

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API RP 574 formula tm =

PD +C 2 SE

Where S – Allowable Stress D - Outside diameter E - longitudinal joint factor obtained from relevant Table P - Design Pressure C - Corrosion & mechanical allowance

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What is PMI? Positive Material Identification by using isotopes, light or chemical. First two are portable. The code used is API RP 578. It is being used only for alloy steel verification. CUI Corrosion under insulation occurs at what temperature range? What are the NDT methods can be used to find the corrosion under insulation? What are all the possible locations where one can expect CUI? Piping components: Flanges: ASME B 16.5 upto 24” diameter, B16.47 for diameter above 24” Flange Material: SA 105, SA 694, Forged Fittings: SA 234, SA 403 Type of flanges: Weld neck, blind, slip on, orifice, threaded etc., Type of flanges: Weld neck, Lap, socket weld, slip on, blind & threaded

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Piping system hydrotest pressure Vs flange rating Flange rating 150# 300# 600# 900# 1500#

Hydrotest psi 425 1100 2175 3250 5400

pressure

in

How will you identify flange rating if in doubt? Look for punch marking on the flange sides & check the dimension against the code Where will you find the details of pipe fittings (elbows, reducers etc.,) On the sides of fittings (elbow-sides, reducers-sides, flanges-sides)

API Std.1160 Hydrotest (Page 25 & 26) Hydrostatic testing validates integrity at the time of the test by demonstrating the integrity of a pipeline with respect to the established MOP and the leak tightness of a pipeline. Within limits, the greater the ratio of test pressure to operating pressure, the more effective the test. ASME B31.4 currently requires a test pressure of not less than 1.25 times MOP for not less than four hours when the pipe is visually inspected during the test, and not less than an additional four hours at 1.1 times MOP when the pipe is not visually inspected during the test. An alternative test commonly called a ‘spike test’ is conducted at 1.39 times MOP for approximately 30 minutes to detect linear type defects associated with longitudinal seams Retesting Frequency (Page 26) The frequency of hydrostatic retesting required to assure continued serviceability of a pipeline segment depends on the test-pressure-to-operatingpressure ratio, and the rates of growth of the particular type of defects that exist in the pipeline. Typical defects that tend to become larger with the passage of time are: external and internal corrosion-caused metal loss, stress-corrosion cracks, and any longitudinally oriented crack-like defect that is subjected to pressure-cycle-induced Determination of Inspection Interval/ Frequency (Page 26) A hydrostatic test is one method to assess the integrity of a pipeline. When hydrostatic testing is selected to verify the integrity of a pipeline segment, tests should be conducted at intervals sufficient to eliminate or prove the absence of critical defects before they reach a condition that can cause an unintentional release

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Suggested Welding repair methods for piping according to API 1104 / API 570

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API 570 suggested repair methods EXAMPLES OF REPAIRS C.1 Repairs Manual welding utilizing the gas metal-arc or shielded metal-arc processes may be used. When the temperature is below 50°F (10°C), low-hydrogen electrodes, AWS E-XX16 or E-XX18, shall be used when welding materials conforming to ASTM A-53, Grades A and B; A-106, Grades A and B; A-333; A-334; API 5L; and other similar material. These electrodes should also be used on lower grades of material when the temperature of the material is below 32°F (0°C). The piping engineer should be consulted for cases involving different materials. When AWS E-XX16 or E-XX18 electrodes are used on weld numbers 2 and 3 (see Figure C-1 below), the beads shall be deposited by starting at the bottom of the assembly and welding upward. The diameter of these electrodes should not exceed 5/32 inch (4.0 mm). Electrodes larger that 5/32 inch (4.0 mm) may be used on weld number 1 (see Figure C-1), but the diameter should not exceed 3/16 inch (4.8 mm). The longitudinal welds (number 1, Figure C-1) on the reinforcing sleeve shall be fitted with a suitable tape or mild steel backing strip (see note) to avoid fusing the weld to the side wall of the pipe. Note: If the original pipe along weld number 1 has been checked thoroughly by ultrasonic methods and it is of sufficient thickness for welding, a backing strip is not necessary. All repair and welding procedures for on-stream lines must conform to API Publ 2201 for hot tapping

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C.2 Small Repair Patches The diameter of electrodes should not exceed 5/32 inch (4.0 mm). When the temperature of the base material is below 32°F (0°C), low-hydrogen electrodes shall be used. Weaving of weld beads deposited with low-hydrogen electrodes should be avoided. All repair and welding procedures for on-stream lines must conform to API Publication 2201. Examples of small repair patches are shown below in Figure C-2.

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Intelligent Pigging This method involves the movement of a device (pig) through the piping either while it is in service or after it has been removed from service. Several types of devices are available employing different methods of inspection. The line to be evaluated must be free from restrictions that would cause the device to stick within the line, i.e., usually five diameter bends are required (standard 90¡ pipe ells may not pass a pig). The line must also have facilities for launching and recovering the pigs. Most plant piping systems are typically not suited to intelligent pigging Underground piping Leak Testing Underground lines that cannot be visually inspected should be periodically tested for leaks. Several methods are available to achieve this objective: a. Pressure decay methods involve pressurizing the line to a desired amount, blocking it in, and then removing the source of pressure. Monitoring the line pressure over a period of time will provide an indication of system tightness. Tests may be conducted at a single pressure or multiple pressures b. Volume in/volume out methods make use of volumetric measuring meters at each end of the line c. A marker chemical (tracer) may be added to the line as a leak detection method. Soil gas samples near the line are collected and tested for the presence of the marker chemical. The absence of any marker chemical in the soil gas samples indicates the line is not leaking d. Acoustic emission technology detects and locates leaks by the sound created by the leak. Sensors must be spaced to allow the sound generated by a leak to be detected at the sensor locations. Sensors are attached directly to the pipe, so testing may require the removal of any protective coating

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Acceptable under tolerances as per API RP 574

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Check list from API 570 APPENDIX A—EXTERNAL INSPECTION CHECKLIST FOR PROCESS PIPING A.1 Leaks a. Process. b. Steam tracing. c. Existing clamps. A.2 Misalignment a. Piping misalignment/restricted movement. b. Expansion joint misalignment. A.3 Vibration a. Excessive overhung weight. b. Inadequate support. c. Thin, small bore, or alloy piping. d. Threaded connections. e. Loose supports causing metal wear. A.4 Supports a. Shoes-off support. b. Hanger distortion or breakage. d. Brace distortion/breakage. e. Loose brackets. f. Slide plates/rollers. g. Counterbalance condition. h. Support corrosion. A.5 Corrosion a. Bolting support points under clamps. b. Coating/painting deterioration. c. Soil-to-air interface. d. Insulation interfaces. e. Biological growth. A.6 Insulation a. Damage/penetrations. b. Missing jacketing/insulation. c. Sealing deterioration. d. Bulging. e. Banding (broken/missing). REVIEW OF RECORDS Records of previous inspections and of inspections conducted during the current operating period should be reviewed soon after the inspections are conducted to schedule the next inspection date. This review should provide lists of areas that are approaching retirement thickness, have previously shown high corrosion rates, and current inspection has indicated a need for further investigation. From these lists, a work schedule should be prepared for additional on-stream inspection, if possible, and for inspections to be conducted during the next shutdown period. Such a schedule will assist in determining the number of inspectors to be assigned to the work.

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In addition, from the review of the records of previous inspections, a list should be made of all predictable repairs and replacements. This list should be submitted to the maintenance department far enough in advance of the shutdown to permit any required material to be obtained or, if necessary, fabricated. This list will also assist the maintenance personnel in determining the number of personnel required during the shut-down period. THICKNESS DATA A record of thickness data obtained during periodic or scheduled inspections provides a means of arriving at corrosion or erosion rates and expected material life. Some companies use computerized record systems for this purpose. The data may be shown on sketches or presented as tabulated information attached to the sketches SKETCHES Isometric or oblique drawings provide a means of documenting the size and orientation of piping lines, the location and types of fittings, valves, orifices, etc. and the locations at which thickness measurements are to be taken. Although original construction drawings may be used, normally separate sketches are made by, or for, the inspection department. Sketches have the following important functions: a. Identify particular piping systems and circuits in terms of location, size, material specification, general process flow, and service conditions. b. Inform the mechanical department of points to be opened for visual inspection and parts that require replacement or repair. c. Serve as field data sheets on which can be recorded the locations of thickness measurements, serious corrosion, and sections requiring immediate replacement. These data can be transferred to continuous records at a later date. d. Assist at future inspections in determining locations that urgently require examination.

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ASME B 31.3 Acceptance Table 341.3.2 Acceptance Criteria for welds and Examination Methods for Evaluating Weld Imperfections

Liquid Penetrant

Magnetic particle

Radiography

(Note(4)Girth, Miter Groove & Branch Connection

Longitudinal Groove Note(2)

Girth, Miter Groove & Branch Connection (Note(4)

Branch Connection (Note(4)

Type of Weld Fillet Note(3)

Type of Weld

Longitudinal Groove Note(2)

Category D fluid Service

Fillet Note(3)

Severe Cyclic conditions

Fillet Note(3)

Longitudinal Groove Note(2)

Girth, Miter Groove & Branch Connection (Note(4)

Normal and Category M fluid Service Type of Weld

Examination Methods Visual

Criteria (A to M) for Types of Welds and for Service Conditions [Note(1)]

Weld Imperfection

A

A

A

A

A

A

A

A

A

A

Crack

√

√

A

A

A

A

A

A

C

A

N/A

A

Lack of fusion

√

√

√ …..

√ …..

B

A

N/A

A

A

N/A

C

A

N/A

B

Incomplete penetration

√

√

…..

…..

E

E

N/A

D

D

N/A

N/A

AN/A

N/A

N/A

Internal porosity

…..

√

…..

…..

G

G

N/A

F

F

N/A

N/A

AN/A

N/A

N/A

…..

√

…..

…..

H

A

H

A

A

A

I

A

H

H

Internal slag inclusion, tungsten inclusion, or elongated indication Undercutting

…..

√

…..

…..

A

A

A

A

A

A

A

A

A

A

√

…..

…..

…..

N/A

N/A

N/A

I

I

I

N/A

N/A

N/A

N/A

Surface Porosity or exposed slag inclusion [Note(5)] Surface finish

√

…..

…..

…..

K

K

N/A

K

K

N/A

K

K

N/A

K

Concave root surface (suck up)

√

√

…..

…..

L

L

L

L

L

L

M

M

M

M

Weld reinforcement or internal protrusion

√

…..

…..

…..

General Notes:

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a. b.

c. d.

Weld imperfections are evaluated by one or more of the types of examination methods given, as specified in paras. 341.4.1, 341.4.2, 341.4.3 & M341.4 or by the engineering design “N/A’ indicates the Codes does not establish acceptance criteria or does not require evaluation of this kind of imperfection for this type of weld Check (√) indicates examination method generally used for evaluating this kind of weld imperfection. Ellipsis (…..) indicates examination method not generally used for evaluating this kind of weld imperfection

Criterion Value Notes for Table 341.3.2 Criterion Symbol

Measure

Acceptable Value Limits [Note (6)]

A

Extent of imperfection

Zero (no evident imperfection)

B

≤ ≤ ≤ ≤

D

Depth of incomplete penetration Cumulative length of incomplete penetration Depth of Lack of fusion & incomplete penetration Cumulative length of Lack of fusion & incomplete Penetration [Note (7)] Size and distribution of internal porosity

E

Size and distribution of internal porosity

For Ťw ≤ 6 mm (1/4”) limit is same as D For Ťw > 6 mm (1/4”) limit is 1.5 X D

F

H

Slag inclusion, tungsten inclusion, or elongated indication Individual length Individual Width Cumulative length Slag inclusion, tungsten inclusion, or elongated indication Individual length Individual Width Cumulative length Depth of undercut

I

Depth of undercut

≤ 1.5 mm (1/16”) and ≤ [Ťw/4 or 1 mm (1/32”)]

J

Surface roughness

≤ 500 min. Ra per ASME B46.1

K

Depth of root surface concavity

Total joint thickness, incl. Weld reinforcement, ≥ Ťw

L

Height of reinforcement or internal protrusion [Note (8)] in any plane through the weld shall be within limits of the applicable height value in the tabulation at right, except as provided in Note (9). Weld metal shall merge smoothly into the component surfaces.

For Ťw mm (in) ≤ 6 (1/4) >6 (1/4) ≤ 13 (1/2) >13 (1/2) ≤ 25 (1) >25 (1) Limit is twice the value applicable for L above

C

G

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1 mm (1/32”) and ≤ 0.2Ťw 38 mm (1.5”) in any 150 mm (6”) weld length 0.2Ťw 38 mm (1.5”) in any 150 mm (6”) weld length

See BPV Code, Section. VIII, Division 1, Appendix 4

≤ Ťw/3 ≤ 2.5 mm (3/32”) and ≤ Ťw/3 ≤ Ťw in any 12 Ťw weld length ≤ 2 Ťw ≤ 3 mm (1/8”) and ≤ Ťw/2 ≤ 4Ťw in any 150 mm (6”) weld length ≤ 1 mm (1/32”) and ≤ Ťw/4

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Height, mm (in) ≤ 1.5 (1/16) ≤ 3.0 (1/8) ≤ 4.0 (5/32) ≤ 5.0 (3/16)

Table 341.3.2 Acceptance Criteria for Welds and Examination Methods for Evaluating Weld Imperfections (Cont’d) NOTES: (1)

Criteria given are for required examination. More stringent criteria may be specified in the engineering design. See also paras. 341.5 and 341.5.3.

(2) Longitudinal groove weld includes straight and spiral seam. Criteria are not intended to apply to welds made in accordance with a standard listed in Table A-1 or Table 326.1. Alternative Leak Test requires examination of these welds; see para. 345.9.

(3)

Fillet weld includes socket and seal welds, and attachment welds for slip-on flanges, branch reinforcement, and supports.

(4)

Branch connection weld includes pressure containing welds in branches and fabricated laps.

(5)

These imperfections are evaluated only for welds ≤ 5 mm (3⁄16 in.) in nominal thickness.

(6)

Where two limiting values are separated by “and,” the lesser of the values determines acceptance. Where two sets of values are separated by “or,” the larger value is acceptable. T w is the nominal wall thickness of the thinner of two components joined by a butt weld. (7)

Tightly butted unfused root faces are unacceptable.

(8) For groove welds, height is the lesser of the measurements made from the surfaces of the adjacent components; both reinforcement and internal protrusion are permitted in a weld. For fillet welds, height is measured from the theoretical throat, Fig. 328.5.2A; internal protrusion does not apply. (9)

For welds in aluminum alloy only, internal protrusion shall not exceed the following values: (a) for thickness ≤ 2 mm (5⁄64 in.): 1.5 mm (1⁄16 in.); (b) for thickness > 2 mm and ≤ 6 mm (1⁄4 in.): 2.5 mm (3⁄32 in.) For external reinforcement and for greater thicknesses, see the tabulation for Symbol L.

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