Engineering Encyclopedia: Piping Maintenance and Repair
Engineering Encyclopedia: Piping Maintenance and Repair
Engineering Encyclopedia: Piping Maintenance and Repair
Chapter : Piping & Valves For additional information on this subject, contact
File Reference: MEX10111 K.S. Chu on 873-2648 or R. Hingoraney on 873-2649
Engineering Encyclopedia Piping & Vlaves
Piping Maintenance & Repair
Identifying the Typical Types of Piping System Defects and Their Acceptance
Criteria
Once a defect is identified through the examination methods that were discussed in MEX
101.09, the engineer must reference the applicable ASME/ANSI B31 Code to determine the
acceptability of the defect. The piping codes provide acceptance criteria for the various types
of defects. However, their focus is on new piping systems and the quality level required
before a piping system can be placed into service for the first time. In existing piping
systems, engineering evaluations are necessary to determine if the system still can be safely
operated with unrepaired defects. The applicable piping code is normally the starting point
for such evaluations, but it is often necessary to go further. Discussion of the evaluations that
are needed to operate systems with defects that do not meet piping code requirements is
beyond the scope of this course.
This section discusses the primary types of defects and their acceptance criteria based on
ASME/ANSI B31 Code requirements.
Weld Defects
The types of weld defects that were discussed in MEX 101.09 are as follows:
• Undercut.
Acceptance criteria for weld defects are specified in the applicable code and are discussed in
the sections that follow.
ASME/ANSI B31.3, Table 341.3.2A, identifies acceptance criteria for welds by type of
imperfection, weld type, service conditions, and required examination methods. This table is
illustrated as Figure 1.
Criteria (A to M) for Types of Welds, for Service Conditions, and for Required Examination Methods [Note (1)]
Normal Fluid Service Severe Cyclic Conditions Category D Fluid Service
Methods Types of Weld Methods Types of Weld Methods Types of Weld
Kind of
Imperfection
Crack X X A A A A X X X X A A A A X A A A A
Lack of Fusion X X A A A A X X - - A A A A X A NA A
C
Incomplete X X B A NA B X X - - A A NA A X A NA B
Penetration
Internal Porosity - X E E NA E - X - - D D NA D - - - - -
(a) Undercutting X - H A H H X X - - A A A A X I A H H
Surface Porosity or X - A A A A X - - - A A A A X A A A A
Exposed Slag
Inclusion [Note (5)]
Surface Finish - - - - - - X - - - J J J J - - - - -
Source: ASME/ANSI B31.3 -1988. With permission from the American Society of Mechanical Engineers.
FIGURE 1
Source: ASME/ANSI B31.3 -1988. With permission from the American Society of Mechanical Engineers.
FIGURE 1, CONT'D
• The presence of cracks of any kind or size is completely unacceptable for all weld types.
Note that the requirements for longitudinal-groove welds are more stringent. No amount
of incomplete penetration is at all acceptable. This greater conservatism is
understandable since the longitudinal weld resists the circumferential pipe pressure
stress, and that typically determines the required wall thickness of the pipe. Thus, any
incomplete penetration of a longitudinal weld could easily result in pipe overstress.
• Depth of undercut is limited to 0.8 mm (1/32 in.) and Tw/4 in girth-groove welds, but no
undercut is permitted in longitudinal-groove welds.
ASME/ANSI B31.4 requires that API 1104, Welding of Pipelines and Related Facilities, be
used as weld acceptance criteria for inadequate penetration and incomplete fusion, burn-
through, slag inclusions, porosity or gas pockets, cracks, accumulation of discontinuities, and
undercut. ASME/ANSI B31.4 requires that all arc burns, cracks, and other defects exceeding
the acceptance criteria be removed or repaired.
For ASME/ANSI B31.8 piping systems, the degree of weld inspection and associated
inspection criteria is based on the intended operating conditions of the system.
For welds on piping systems intended to operate at less than 20% of the specified minimum
yield strength:
No specific weld acceptance criteria are provided, indicative of the low-risk nature of the
services involved.
For piping systems operating at higher stress levels, more stringent criteria are specified. The
minimum extent of weld inspection is specified based on Location Class, and acceptance
criteria are to be per API-1104.
Dents
A dent is a gross disturbance in the curvature of the pipe wall that typically is caused by an
external blow or pressure. Acceptance criteria for dents is specified best in ASME/ANSI
B31.4, Paragraphs 434.5 and 451.6.2, and ASME/ANSI B31.8, Paragraph 841.243.
ASME/ANSI B31.3 does not contain acceptance criteria for dents.
• The depth of a dent is measured as a gap between the lowest point of the dent and a
prolongation of the original pipe contour in any direction.
• Dents which affect the pipe curvature at the pipe seam or any girth weld shall be
removed as a cylinder by cutting out the damaged portion of the pipe.
• Dents that contain a stress concentrator, such as a scratch, gouge, groove, or arc burn,
shall be removed by cutting out the damaged portion of the pipe as a cylinder.
• Dents that exceed a depth of 6 mm (0.25 in.) in pipe NPS 4 and smaller, or 6% of the
nominal pipe diameter in sizes greater than NPS 4, shall be removed in pipelines that
operate at a hoop stress greater than 20% of the specified minimum yield strength of the
pipe.
• Insert patching, overlay, or pounding out of dents are not permitted in pipelines that
operate at a hoop stress greater than 20% of the specified minimum yield stress.
• Dents that exceed a depth of 6 mm (0.25 in.) in pipe NPS 12 and smaller, or 2% of the
nominal pipe diameter for pipe over NPS 12, are not permitted in pipelines that operate
at a hoop stress greater than 40% of the specified minimum yield strength.
• When dents are removed, the damaged pipe section is to be removed as a cylinder.
Cracks
Cracks represent linear separations of metal under stress. Although sometimes large, cracks
are often very narrow separations within the weld or adjacent base metal. Typical cracks are
illustrated in Figure 2.
FIGURE 2
Cracks of any kind or extent are always unacceptable in new piping system construction.
However, as noted earlier, it is sometimes acceptable to continue operating an existing piping
system on a temporary basis with the cracks unrepaired, provided that a thorough engineering
evaluation has found this to be safe.
Corrosion
Uniform Corrosion
This is the most common form of corrosion and is characterized by uniform attack over the
entire surface of the metal. Uniform corrosion most prominently occurs in acid, caustic, and
hydrocarbon services. The rate of uniform corrosion commonly is expressed as penetration in
mils (.001 in.) per year (MPY) or millimeters (mm) per year (mm/a). This is the only form of
corrosion for which the corrosion rate (MPY or mm/a) is significant.
Pipe shall be replaced, repaired if the area is small, or operated at a reduced pressure if
general corrosion has reduced the wall thickness to less than the calculated required design
thickness (as discussed in MEX 101.03). The actual pipewall thicknesses, determined by
measurement, are compared to the required value in order to make this
replacement/repair/downrating decision. Ideally, the needed inspections and engineering
evaluations are done periodically so that these needs can be anticipated and planned for.
Pitting
This is a form of localized corrosion that occurs at small areas randomly located on a metal
surface. The initiation period that is required for visible pits to appear depends on both the
specific metal and the corrosive environment. This period can extend from several months to
years. However, once a pit is initiated, rapid penetration of the metal may occur.
Detection of pits can be difficult because of their small initial size, and because pits are often
covered by corrosion products. Detection difficulty, coupled with the highly localized nature
of pitting, often results in the sudden failure of components.
Pitting is most likely to occur in stagnant or low-velocity fluids where there is a break in the
electrical continuity of a metal surface in contact with an electrolyte. Examples of such
discontinuities are rough spots, scratches, or indentations.
ASME/ANSI B31.4 is the only B31 Code that has specific criteria for evaluating pitting.
These are discussed below.
L = 1.12B D tn
c/ t n 2
B= -1
1.1 c/ t n - 0.15
B = A value not to exceed 4.0, which may be determined from the above equation or
Figure 3.
Source: ASME/ANSI B31.4 - 1989. With permission from the American Society of Mechanical Engineers.
FIGURE 3
Hydrogen Blisters
Another type of corrosion phenomenon which can occur in piping is hydrogen blistering. In
this case, hydrogen, in atomic form, diffuses into the surface of the carbon steel pipe. The
atomic hydrogen then collects in discontinuities of the metal and forms molecular hydrogen.
Because molecular hydrogen will not diffuse through the steel, the pressure builds up inside
the voided area and causes a rupture of the metal. The ruptured area is confined to a local
area and appears on the surface of the metal in the form of blisters or fissures. Hydrogen
blistering occurs most commonly in an aqueous medium which contains cyanides and a mild
corrosive.
Evidence of hydrogen activity can sometimes be detected on the external surfaces of pipe by
the blistering or flaking of paint films, or even by blistering of the steel itself. If test probes
are, or can be, located in the suspect areas, hydrogen activity can be confirmed by cleaning
the surface back to bare metal and applying two coats of a flexible paint.
Hydrogen blisters do not necessarily affect the strength or integrity of a pipe. However, there
are no simple criteria that may be used to evaluate their acceptability. An engineering
evaluation is required to determine if there is adequate local strength remaining in the pipe
with the blisters. Discussion of this evaluation is beyond the scope of this course. Blisters
typically will be vented to the inside or outside of the pipe to prevent a continuing pressure
buildup, which could cause more extensive damage.
Of more concern is whether blisters are accompanied by cracking, since this condition could
lead to a more extensive pipe failure. GI No. 434 provides general guidelines and a decision
tree regarding hydrogen blisters. The following highlights several aspects of this.
• Inspect the affected areas by radiography and/or ultrasonic examination to determine the
extent and depth of internal cracking or laminations.
Once an unacceptable defect is found, it must be repaired, the pipe must be replaced, or the
piping system must be downrated. There are several options available, and the choice of
which one to use is based on the type of defect, service conditions, and individual
circumstances. For example, repair options that require welding may not be suitable for
services with a flammable fluid. Saudi Aramco General Instructions 434 and 441 specify
safety requirements for specific repair methods. These are beyond the scope of this course
and will not be discussed in this module; however, the Saudi Aramco engineer must refer to
GI 434 and 441 for special repair instructions.
The table below summarizes the various repair methods that may be considered with each
type of defect. Work Aid 1 outlines a process for determining a suitable repair method for a
particular situation. The paragraphs that follow discuss specific repair techniques.
Weld Repairs
If a weld defect is not acceptable, it must be repaired. Weld repair is similar to new-
construction welding. The same procedures and safety guidelines must be followed. General
weld repair procedures are specified in the appropriate ASME/ANSI B31 Code and Saudi
Aramco standards. However, a detailed discussion of weld repair is beyond the scope of this
course. In general, weld repair is performed in the following manner:
• Remove or grind out the defective portion to get to sound base metal.
• Using an appropriate weld procedure, repair the weld in the same manner as used for
new-construction welding.
Weld repair sleeves with a corrugation to accommodate the girth weld may be used for repair
of leaking girth welds for nominal pipe sizes 150 through 1,200 mm (6 in. through 48 in.).
Pipe Plugs
• Temporarily block off the contents of a pipe from the remainder of the system to permit
needed repairs or modifications.
• Repair holes that are caused by corrosion through a pipe that result in leaks.
To stop relatively small leaks, a metal plug may be driven into the opening and secured by
welding.
There are three types of pipe plugs that may be considered for system isolation:
• Balloons
• Mud
• Mechanical
- For NPS 3 through 12, with larger sizes available on special order.
Saudi Aramco GI 434.000 specifies use and acceptance criteria for each type of system
isolation plug. For example, a mud plug can be located close to the end of a line where
welding is done, where the location would be a fire hazard for a balloon plug.
Repair Clamps
• Temporary repair of pipe operating at a temperature between -7°C (20°F) and 107°C
(225°F) if authorized by the Operations Superintendent. However, in many areas, an
ordinary steel plug, or a gasket applied with banding strap, may be more economical and
effective.
• Permanent repairs of water lines, or oil and product lines. In the case of water lines, the
unwelded clamp may be left as a permanent repair. In the case of oil and product lines,
the clamp may not be left as a permanent repair unless it is installed and welded based
on GI 441.013 requirements using a weld-cap-type cover. In this case, the welded cap
becomes a primary pressure-containing boundary placed over the plug/clamp assembly.
A permanent repair must be made within three months of installing the repair clamp on
oil or product lines.
Refer to Figure 4. A repair clamp is installed by loosely bolting the clamp onto the pipe near
the leak, positioning the plug over the leak, inserting the pilot pin into the leak, tightening the
clamp, and screwing the steel packing force-screw down into the leak. The pointed cone of
the elastomeric material, such as Buna-N, seals the leak by acting as packing. The thrust
washer permits the force-screw to turn without also rotating the cone.
FIGURE 4
Welded pipe sleeves shall be used to provide full-encirclement reinforcement for corroded
areas larger than those that can be covered with patches, and to stop leaks that cannot be
plugged. Either standard or field-fabricated sleeves may be used per GI 434.000.
Welded patches may be used to repair nonleaking sections of pipe that have experienced
excessive external thinning. The patch must be fabricated from a material grade that is equal
to or higher than that of the pipe. The patch dimensions must not exceed 152 mm (6 in.), it
must have rounded corners, its thickness must be at least 1.25 times the nominal pipewall
thickness, and conform to the pipe curvature. Refer to Standard Drawing AE-036265 and GI
434.000 for fabrication and welding requirements.
Weld Overlays
Weld metal overlays may be used to repair small areas of pipe or fittings that have
experienced excessive external corrosion, nicks, scratches, gouges or grinding. The
maximum length or width of any individual repair area is 102 mm (4 in.). The deposited weld
metal shall be at least three passes wide and 50 mm (2 in.) long. Each weld-repaired area
must be at least 102 mm (4 in.) from any other weld-repaired area.
Plidco Weld+Ends
Weld+Ends couplings are used when it is virtually impossible to make a quick and safe repair
by other means. Weld+Ends join pipe as shown in Figure 5 so that flow can be resumed in
the fastest possible time without the need for preparing the pipe ends for welding and then
making the circumferential closure weld. Weld+Ends couplings are high in cost compared to
other methods of connecting pipe ends. However, their use permits the rapid installation of a
replacement pipe section and resumption of flow without welding. Welding may be done
after resuming the operation. GI 441.011 contains installation requirements, temperature and
pressure limitations. The MAOP of an installed Weld+Ends coupling depends on the specific
coupling design details, and whether it is welded to the pipe.
Refer to Figure 5. The clamping screws are initially used to tighten the coupling to each of
the pipe ends. The thrust screws are then tightened against each thrust ring. The thrust ring
advances to compress the packing against both the central portion of the coupling body and
the pipe surface. The compressed packing forms a tight seal and prevents leakage.
Thrust Ring
Thrust Screw
Pipe
FIGURE 5
Packing
FIGURE 6
• Permanently repair small splits, holes, or ruptures which cannot be plugged or patched
readily and where downtime for draining oil from a line is excessive.
• Provide quick, temporary repairs without welding on urgently required pipelines, which
can be removed from service later for permanent repairs.
• Provide temporary repairs to process lines within plant limits where economically
justified. However, in these cases, sleeve pressure and temperature limitations must be
considered, and the sleeve must be removed for permanent repair in approximately three
months.
As referenced in Figure 6, the split sleeve halves are positioned around the pipe such that the
leak is located between the two rings of packing. When the sleeves are bolted, the packing is
compressed against the pipe surface which contains the leak.
Plidco split sleeves are high in cost compared to other methods of repair. Therefore, their use
should be restricted to those cases where speed of repair will provide sufficient economic
justification. GI No. 441.012 contains installation instructions, and pressure and temperature
limitations for split sleeves. Split sleeves cannot be used to connect two sections of pipe.
Pipe Replacement
If a pipe cannot be repaired by any of the repair methods discussed, it must be replaced. Pipe
replacement is necessary if:
In most cases, the pipe may be replaced using the same material, diameter, and wall thickness
as in the original installation. However, in some cases, the nature of the defect may indicate
that some change is necessary. For example, if a pipe section must be replaced due to general
corrosion in half of its anticipated design life, then thicker and/or different pipe material may
be required.
Sample Problem 1
A 305 m (1000 ft.) long section of an aboveground 900 mm (36 in.) outside diameter crude
oil pipeline has recently been inspected. Decisions are required regarding what to do with the
inspection results, i.e., nothing, repair, or replace. If repair will be done, an appropriate
approach must be determined in each case. If any pipe sections must be replaced, the line
cannot be taken completely out of service since it is critical. Minimum crude oil flow needs
can be provided if a temporary 600 mm (24 in.) diameter bypass is placed around the pipeline
section that is to be removed.
• The nominal (new) wall thickness of the 900 mm (36 in.) pipeline was 15.9 mm (0.625
in.), and the minimum required thickness for pressure is 13.5 mm (0.53 in.)
• If a new 600 mm (24 in.) bypass line is required, it will have a nominal wall thickness of
14.3 mm (0.562 in.) and a minimum required thickness for pressure of 9.1 mm (0.36
in.).
• A 30 m (100 ft.) section of pipe has been corroded to a relatively uniform thickness of
12.2 mm (0.48 in.).
• There are pitted sections of the pipe in areas of otherwise sound metal having the
original design thickness. This occurs in small sections of the line where the flow is
sometimes stagnant. The maximum pit depth is 10 mm (0.4 in.) over a maximum length
along the pipe axis of 50 mm (2 in.).
• A 13 mm (0.5 in.) deep dent was made in one portion of the line by a piece of
construction equipment. There are no scratches, gouges, grooves, or other stress risers
in the dent. The dent is 3 m (10 ft.) from the nearest circumferential-weld seam, and on
the opposite side of the pipe from the longitudinal-weld seam.
Solution
The inspection results identified three defects in the pipeline: uniform corrosion, pitting, and
a dent. These must be evaluated individually for acceptance.
• The uniform corrosion to a depth of 12.2 mm (0.48 in.) is not acceptable since the
minimum required pipe thickness for pressure is 13.5 mm (0.53 in.). The pressure in the
pipeline should be downrated until this situation is resolved. Since the minimum
required thickness for the 5,171 kPa (750 psig) design pressure is known, a safe
downrated pressure can be calculated from the following equation, based on the current
amount of corrosion.
0 . 48
P = x 750
0 . 53
P = 679 psig
However, if the cause of the corrosion cannot be eliminated, the pressure must be
further reduced to account for future corrosion.
• A calculation must be made to determine if the length of the pitted area is acceptable.
c / tn
2
B = - 1
1. 1 c / t n - 0 . 15
0 . 4 / 0 . 625
2
B = - 1
1. 1 x 0 . 4 / 0 . 625 - 0 . 15
B = 0 . 57
L = 1 . 12 B Dt n
L = 1 . 12 x 0 . 57 36 x . 625
L = 3 . 03 in .
The maximum length of the pitted area is 50 mm (2 in.) and is less than L. Since the
maximum pit depth of 10 mm (0.4 in.) is less than 80% of the pipe nominal thickness, nothing
needs to be done immediately. However, the cause of the pitting should be found and
corrected, the inspection interval shortened, and/or repair of the line planned before the pipe
holes through.
• This is an ASME/ANSI B31.4 piping system since it is a crude oil pipeline. For such a
system, a dent may be up to 6% of the pipe diameter before it must be removed, 0.06 x
36 = 2.16 in. in this case, if the system is operating at over 20% of the pipe specified
minimum yield strength. Since the dent is smaller than this, it is acceptable. Note also
that the pipe stress did not need to be calculated in this case since the dent is well below
the limit anyway. However, for completeness, the hoop stress can be calculated from
the following equation.
PD
S =
2 Et n
750 x 36
S =
2 x 1 x 0 . 625
S = 21600 psi
S 21, 600
= = 0 . 617 = 61. 7% of the yield strength .
Sy 35, 000
• Of the three defects found and evaluated, only the 30 m (100 ft.) section of unacceptable
uniform corrosion requires immediate attention. The only practical repair alternative in
this case is to replace the section of pipe.
Hot tapping is another method that is used for repair, maintenance, or making system
modifications. Hot taps provide a means to add connections to piping, pressure vessels, and
other process equipment and tankage without disrupting normal operating conditions. Hot
taps can also be used to make connections into equipment where it would be impractical to
prepare the equipment for hot work, such as for large pressure vessels or storage tanks, or
long runs of piping. Connections that are attached by hot tapping can also be used for
plugging or stoppling to isolate sections of piping. Stoppling, or pressure plugging for the
installation of plugs, is performed for repairs on (or to remove) a section of line without
interrupting service. However, hot taps should be used only where it is impractical to take the
equipment out of service.
A hot tap is performed by:
• Welding a suitably sized and reinforced nozzle to the pipe. This nozzle has a flanged
end.
• Bolting a full-port valve to the flanged nozzle, and bolting a hot-tap machine to the
valve.
• Opening the valve and using the hot-tap machine cutter to cut an opening in the pipe and
to hold the cut piece.
• Extracting the cut piece of pipe (i.e., the coupon) through the valve and into the cutting
machine housing.
Figure 7 illustrates the basic arrangement for making a hot tap and illustrates the primary
components. These are highlighted as follows:
• Stopple or tapping fitting: A specially designed branch connection that is welded to the
pipeline.
• Tapping Valve: A full-bore valve that permits closing off the branch connection after
the hot tap has been completed. A new pipe section can be bolted on to the flanged
valve as required after the hot tap has been completed.
• Pilot: A relatively small-diameter drill that is attached to the cutter and makes the initial
cut into the pipeline. The pilot also contains the mechanism that will retain the coupon
after the cut has been made.
• Cutter: The drill bit that makes the required diameter hole into the pipeline.
• Cutter Holder: The end of the boring bar to which the cutter is attached. This
arrangement permits the attachment of different sized cutters to the boring bar.
• Boring Bar: The shaft that is attached to the tapping machine which transmits the
applied force and rotation from the machine to make the cut.
• Tapping Machine: The powered or hand-operated unit that performs the hot tap
operation.
• Adapter: A fitting which provides a flanged interface between the standard flange
diameter at the bottom of the hot-tap machine and the required flange diameter of the
new branch connection.
FIGURE 7
• Four hot taps are made such that the section of pipeline that is repaired or replaced is
located between them.
• A temporary bypass line is installed between the two outer hot-tapped connections. The
bypass line is used to continue flow while the pipeline section is repaired or replaced.
• The inner two hot-tapped connections are used to install stopple-plugging machines.
These machines insert plugs into the pipeline which block flow. The section of pipeline
may be repaired or replaced once the flow has been blocked and the bypass line is in
operation.
• After the new or repaired section of pipeline has been installed, the plugs and bypass
line may be removed.
The Saudi Aramco Engineer may be asked to approve a hot tap, identify if a hot tap is
necessary, or develop the hot tap design details. Therefore, he must know the design,
inspection, and testing requirements for a hot tap. This information can be found in SAES-L-
052, ADP-L-052, GI 441.010, GI 441.015, and Form A-7627.
FIGURE 8
The following are general procedural and design requirements for a hot tap.
• The Initiating Engineer completes Section 1 of Form A-7627, Hot Tap/Stopple &
Reinforcement Calculation Request, by providing general descriptive information. The
form is routed to the Area Operations Engineer.
• The Initiating Engineer forwards completed Form A-7627 to the controlling party, who
assigns responsibility to the appropriate engineering group.
• The Initiating Engineer is responsible for revising existing drawings, or preparing new
ones, as required due to the hot tap.
• The Engineering Group is responsible for preparing all needed calculations, drawings
and specifications, obtaining needed approvals, and completing Section 4 of the form.
A later section discusses these calculations.
The following design information is needed for a hot tap and Form A-7627:
• Hot-tap location.
- Horizontal
- Vertical
- Inclined
• Flange rating.
• Fluid.
- Diameter, mm (in.)
- Nominal Thickness, mm (in.)
- Material
The following summarizes several additional design considerations. Participants are referred
to ADP-L-052 and SAES-L052, Hot Tap Connections, and GI 441.010, Installation of Hot
Tapped Connections, for more details.
• Hot taps are not performed in cases where the welding or cutting operations can cause
fires, explosions, detrimental changes in material properties (such as hardness, impact
strength, or yield strength), damage to linings or coatings, accelerated corrosion, burning
through thin pipe or vessel walls, or brittle fracture. Quenched and tempered steels,
chromium alloy steels, and 400-series stainless steels are examples of materials that
require special consideration.
• Hot taps on hydrocarbon tanks are performed at least 1 m (3.3 ft.) below the liquid level
to reduce the risk of fires and explosions in the vapor space.
• Air lines must not be hot tapped nor welded on while in service. A flammable mixture
may exist in the line due to air compressor lubrication oil that might be present. This
mixture could be ignited by the heat generated by cutting or welding.
• Test pressure in the hot-tap nozzle should not cause buckling of the pipe or equipment
being tapped. Therefore the allowable differential external pressure should be checked.
This is discussed in a later section.
• Fluid flow velocity in a pipe during the hot tap must be within the following ranges:
However, no-flow conditions are acceptable for hot tapping if there is definitely no
possibility of a hydrogen and oxygen mixture, such as for seawater injection lines.
However, additional conditions that are specified in GI 441.010 must be satisfied.
• The minimum flow velocity is set to provide adequate heat dissipation during welding
and cutting. The maximum flow velocity is set to help prevent spinning of the coupon
after cut-through, which could cause it to drop into the line.
• Hot taps shall not be made upstream of rotating machinery or inline rotating instruments,
unless chips and shavings from the cutting can be prevented from entering the
equipment.
• The Consulting Services Department shall be contacted if a hot tap is being considered
in the following situations:
- Carbon steel pipe with a minimum specified yield strength over 414 MPa
(60,000 psi).
- Situations where welding preheat is required due to hardenable or high
strength steels, or wall thickness.
• Hot taps that are within 450 mm (18 in.) of a flange or threaded connection, or 19 mm
(0.75 in.) of a girth-weld seam, are to be avoided.
Inspection Requirements
• Inspect weld areas, and 50 mm (2 in.) on each side of them, using continuous ultrasonic
examination to determine minimum pipewall thickness. The measured thickness must
be at least that calculated for the hot tap conditions, and no less than 5 mm (0.2 in.).
• Inspect connection before and during installation for compliance with specification.
• Confirm that the connection is opened, drained, and vented after completing hydrostatic
test.
• Inspect the removed coupon. Evaluate the extent of header internal corrosion and verify
wall thickness.
Testing Requirements
The engineer responsible for testing must apply the following test requirements:
• Pressure test the branch-to-pipe weld, and then pressure test the final branch assembly.
• The reinforcing pad of a welded branch shall be tested with air at 173 kPa (25 psig)
through a tapped vent hole.
• The pressure for the test of the hot-tap connection shall be 1.5 times the system design
pressure (1.25 times for cross-country pipelines), however, not to exceed the following:
- The design hydrostatic test pressure of the pipe or vessel being hot tapped, or
- The minimum pressure in the pipe or vessel being hot tapped, while the test is in
progress, plus a calculated differential pressure. The differential pressure shall be
1.25 times the allowable external pressure calculated per the ASME Code Section
VIII Division 1. The length, L, that is used in this calculation shall be the total
length of a split tee, or the inside diameter of the welded nozzle, based on the
actual design detail used.
• The test pressure of the hot-tap connection may be lower than the original hydrostatic
test pressure. This is acceptable since the purpose of the test is to provide some
assurance of the integrity of the connection weld, not a proof test of the weld. The
system being tapped need not be downrated if a lower test pressure is used at a hot-
tapped connection.
Calculations
P max = 2 SEt
D
This lower than normal allowable stress is used to account for some local heating of the
pipewall during welding, with resultant strength reduction. "P" must be greater than or
equal to the actual operating pressure of the hot tap in order to perform the hot tap. It
may be necessary to reduce the system operating pressure, while maintaining flow, to
meet this requirement.
If the previous formula results in an unacceptably low allowable pressure, the following
formula may be used. This second formula is based on experimental tests, but its use
requires more extensive thickness measurements that are specified in GI 434.000.
P max =
2 S ( t − 0. 1) F
D
The normal hydrostatic test pressure causes a hoop stress of 90% of the specified
minimum yield stress, and ranges from 1.25 to 1.5 times the system design pressure,
depending on the applicable piping code. However, this may be reduced as previously
discussed if the original hydrotest pressure was less, or if there could be a problem with
buckling the pipe due to external pressure. Determining the maximum allowable
external pressure is required for pressure testing. Work Aid 2 provides tables from
ADP-L-052. These tables provide the maximum allowable test pressure less the internal
header pressure (i.e., the net external pressure) for various sizes of nozzles welded to
headers. These tables may be used for carbon steel material through 1,050 mm (42 in.)
header diameter, and Type 405 and 410 stainless steel through 149°C (300°F). External
pressure calculations must be made for other materials or higher temperatures. These
calculations were discussed in MEX 101.03.
Sample Problem 2
Based on the evaluations done in the earlier problem, it is known that the uniformly corroded
section of pipeline must be replaced. Since maintaining a certain amount of flow through the
pipeline is critical, it is necessary first to install a 600 mm (24 in.) diameter bypass line around
the section of pipeline to be removed. To do this, two 600 mm (24 in.) diameter hot taps must
be made into the pipeline to permit installation of the bypass. Refer to Work Aid 2 in solving
this problem.
If pre-engineered hot-tap fittings are used at the branch connections, no branch reinforcement
design calculations are necessary. If welded-on branch reinforcement will be used, design
calculations as discussed in MEX 101.05 are necessary to design the reinforcement. This
aspect of the hot-tap design will not be discussed here, and Participants are referred to MEX
101.05 for additional information.
The two other calculations that are necessary for a hot-tap installation are to determine the
maximum allowable operating pressure during the hot tap and the required hydrotest pressure.
2 SEt
P max =
D
where: S = 35% of the specified minimum yield stress of the pipe material at the
operating temperature during the hot tap.
Since the operating temperature is only 49°C (120°F), the yield stress may be taken as
241.3 MPa (35,000 psi). Note that ASME/ANSI B31.4 does not require considering any
strength reduction up to 121°C (250°F). The reduction in yield strength with
temperature must be considered for higher temperatures.
S = 0.35 x 35,000.
= 12,250 psi.
The hot taps must be made in sections of the pipeline that have adequate wall thickness
for the service, i.e., not appreciably corroded. This is confirmed by ultrasonic thickness
measurements. For our purpose, assume that the hot taps will be made into pipe sections
that have the original wall thickness of 15.9 mm (0.625 in.).
P max =
2 x 12 , 250 x 1 x 0 .625
36
Therefore, the pipeline pressure must be reduced to a maximum of 2,930 kPa (425 psig)
during the hot tap. Note that if this pressure reduction causes operations difficulties, an
alternative value for Pmax may be calculated using the second formula that was
discussed, provided additional ultrasonic thickness measurements are made.
• Hydrotest pressure
The tentative hydrotest pressure is 1.25 times the design pressure or, in this case,
(1.25 x 750) = 938 psig. For now, we can assume that this is no higher than the original
system hydrotest pressure and does not need to be reduced for that reason. However, it
should be checked to confirm that it will not buckle the pipeline.
Note that the tables in Work Aid 2 may be used as a first step since the pipe material and
design temperature are within their limiting parameters. The only problem is that the
maximum header wall thickness contained in the table is 12.7 mm (0.5 in.) and this
pipeline is 15.9 mm (0.625 in.) thick. Thus, if we use the table for this problem, we will
be conservative (but safe).
Referring to the table for a 900 mm (36 in.) header that is 12.7 mm thick and for a 600
mm (24 in.) diameter nozzle, the allowable external differential pressure is 2,600 kPa.
Convert this to psi and get 2,600/6.895) = 377 psi. Therefore, in order to use the 938
psig test pressure, the pipeline pressure must be raised back up to (938-377) = 561 psig.
Raising the header pressure to this level now would be acceptable since no cutting or welding
is being done, and this is just under the original design pressure. If, for some reason, it is not
practical to raise the pipeline pressure to this level, then external pressure design calculations
may be made using the actual 15.9 mm (0.625 in.) pipeline wall thickness to arrive at a higher
acceptable external differential pressure. These calculations were discussed in MEX 101.03.
This checklist should be used in conjunction with Saudi Aramco General Instruction 434.000,
Pipeline Repair and Maintenance. Additional details and considerations are included in that
document and must be adhered to.
1. Identify location and design information for the damaged pipe section.
Location:_________________________________________
Pipe material:_____________________________________
Fluid:___________________________________________
If yes, immediate action is required to minimize hazardous conditions for both people
and motor traffic.
All internal coatings used by Saudi Aramco, except cement lining, are destroyed by
welding. Welding, brazing, and torch cutting are not permitted on internally coated
pipe, other than cement-lined pipe, without concurrence of the Operating Department.
[] Crack:
- Circumferential
- Longitudinal
[] Corrosion
[] Pitting
[] Hydrogen blistering
[] Hole
[] Nick, scratch, or gouge
Hydrogen blistering:
- Size: x mm (in.)
- Internal cracking? Yes No ___
If pipe is leaking, leak must be stopped or diverted before any welding is done.
Welded patch.
Weld overlay.
Repair sleeve.
Replace pipe.
If pipe repair is not possible, the damaged pipe section must be removed and a
replacement section installed.
11. Prepare detailed repair procedure based on established Saudi Aramco requirements.
General information:
Header Branch
Material specification
Nominal size, mm (in.)
Minimum measured thickness, mm (in.)
1. Calculate minimum required header thickness for design pressure, th. See MEX 101.03.
th = mm (in.)
2. Calculate minimum required branch thickness for design pressure, tb. See MEX 101.03.
tb = mm (in.)
3. Select nominal thickness for branch, Tb, considering tb, mill tolerance and corrosion
allowance. See MEX 101.03.
Tb = mm (in.)
If yes, then branch reinforcement calculations as discussed in MEX 101.05 are not
required and Steps 5 and 6 may be skipped. If No, then branch reinforcement evaluation
is necessary. See Steps 5 and 6.
6. If additional branch reinforcement is required, design the reinforcing pad. See MEX
101.05.
7. Set maximum permitted operating pressure during hot tap. Stress in header limited to
35% of the specified minimum yield stress at operating temperature. See MEX 101.03.
8. Set hot-tap hydrotest pressure. Consider original hydrotest pressure and limitations
contained in ADP-L-052. Tables providing maximum allowable external pressure from
ADP-L-052 are provided on the following pages. Note that the allowable pressure in psi
is obtained by dividing the pressure in kPa contained in the tables by 6.895. Tentative
hydrotest pressure is 1.5 times the system design pressure (1.25 for pipelines).
NOTES:
GLOSSARY